GT & Gen. Manual [PDF]

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Gas Turbine Operations-9FA.03 Gas Fuel DLN 2 Electricity Generation Company of Bangladesh LTD Siddhirganj, Bangladesh

Turbine 299249 Generator 270T888

2015

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All rights reserved by the General Electric Company. No copies permitted without the prior written consent of the General Electric Company. The text and the classroom instruction offered with it are designed to acquaint students with generally accepted good practice for the operation or maintenance of equipment and/or systems. They do not purport to be complete nor are they intended to be specific for the products of any manufacturer, including those of the General Electric Company; and the Company will not accept any liability whatsoever for the work undertaken on the basis of the text or classroom instruction. The manufacturer’s operating and maintenance specifications are the only reliable guide in any specific instance; and where they are not complete, the manufacturer should be consulted. The materials contained in this document are intended for educational purposes only. This document does not establish specifications, operating procedures or maintenance methods for any of the products referenced. Always refer to the official written materials (labeling) provided with the product for specifications, operating procedures and maintenance requirements. Proprietary Training Material Property of GE. Use of these materials is limited to agents and GE employees, or other parties expressly licensed by GE. Unlicensed use is strictly prohibited.

© 2015 General Electric Company

GE Power & Water Gas Turbine Operations-9FA.03 Gas Fuel DLN 2 Electricity Generation Company of Bangladesh LTD Siddhirganj, Bangladesh Turbine 299249 Generator 270T888 2015 Tab 1 Introduction Course Description Course Schedule

GT_Ops_Descr_10Day 9FA_GF_Ops_10Day_Sched

Tab 2 Gas Turbine Description MS9FA Gas Turbine Cross-Section Gas Turbine Basics Name Plate Data, Turbine-Gas Fuel (A004) Outline, Mechanical-Gas Turbine and Generator (0306) 9FA Dual Fuel Piping Arrangement 9FA Component Identification 9FA Component list

9FA UNIT _Crosssection GT Basics _ 9FA_DLN2+_GF 105T5589 105T6819 9FA PIPING Overview GT9FA_B00293Q-r0 GT9FA_B00293A-r0

Tab 3 Reference Documents Gas Turbine Arrangement (ML 0406) Customer O&M Manual Users Guide Technical Communications-Controls Connect Connection and Line List, Customer Interface (4063) Diagram, GT Package Connection-Piping (0313) Diagram, GT Package Connection-Electrical

138E5399 GEK 116811 GEK 103591 145E4535 107T6779 107T7998

Tab 4 Turbine Control Device System (ML0415) Turbine Control Devices System Description GEK 116642 Schematic Diagram-PP Control Devices-Turbine (ML 0415) 143E2226 Instrumentation Arrangement, Unit (ML 0211) 112E6112 Tab 5 Inlet Filter and Exhaust System (ML 0471) Inlet Compartment Arrangement-Air Schematic Diagram-PP Inlet & Exhaust Flow (ML 0471) Filter Control Panel (JB78) (GB00219836) Pulse Filtration System Sequence of Operations Screw Convertor Exhaust Diverter Damper (073C) Exhaust Stack-Bypass Damper Arrangement Diverter Arrangement-Operations and Maintenance Drawing-Damper Arrangement

Gas Turbine Operations - 9FA.03 Gas Fuel DLN 2 Electricity Generation Company of Bangladesh LTD

IFH_Pulse_GA_ETT 145E4540 264B2554_1,2,5 GB00219848 A040_Screwcm_1,4 Exh_Div_Damper_Arr N045_Section1 N045_Section 3_PARTIAL

1

GE Power & Water Tab 6 Instrument Air System (ML 0419) Internal Arrangement Drawing (DIS-100-102-136) (1088760201) 411D1010 Schematic Diagram- PP Control Air (ML 0419) Air Processing Unit Description

143E2289 GEK 116681

Tab 7 Inlet Bleed (Air) Heating System (ML 0432) Inlet Air Heating Simplified Diagram 0017HIE-Compressor Inlet Bleed Heat System (9FA) Schematic Diagram-PP Inlet Air Heating (ML 0432) IBH Extraction Piping Arrangement (ML 0924) Inlet Air Heating Manifold Arrangement (ML A341)

IAH Schem GEK 116865 145E4571 119E9591 106t2206

Tab 8 Performance Monitoring System (ML0492) Performance Monitoring Schematic Diagram-PP Performance Monitor (ML 0492)

GEK 111323 146E4483

Tab 9 Lube Oil System (ML 0416) Accessory Module General Arrangement FA Oil Systems Configuration FA LO Simplified Schematic Lubrication System Description Schematic Diagram-PP Lube Oil (ML 0416) Lubrication Oil Piping Interconnect Arrangement (ML969A)

232D8032_1-6 FA-Oil-Systems-GF-r0 FA_LO_Schem-ME GEK 111768 145E4546 146E2636_1-4

Tab 10 Hydraulic / Lift Oil Supply (ML 0434) FA Hydraulic Oil System Summary Schematics Hydraulic Pump Pressure Compensators Hydraulic Module Hydraulic and Lift Oil System Description Schematic Diagram-PP Hydraulic Oil Supply (ML 0434) 0017HAE-Variable Inlet Guide Vane System Inlet Guide Vanes Variable Inlet Guide Vane Arrangement (ML 0811) VIGV Actuator Simplified Schematic Servovalve Operations

FA-Hyd-Sch-R1 VPR3-PVG Oilgear Hyd Pump HydModuleArr-r0 GEK 111787 145E4545 GEK 106910 IGV_Fund_04-2013 VIGV_Arr VIGV Hyd Schematic-Etrip ST-GT_Servovalves_01-14

Tab 11 Fuel Gas System (ML 0422) DLN 2-0+ Gas Fuel Systems Components Fuel Gas Process System Drawing (0482)

DLN 2-0 GF Simple Sch 207D3947

Fuel Gas Chromatograph Internal Arrangement (DIS-136) (715990-136)

100V0133

4035-Fuel Gas Chromatograph System Drawing Gas Chromatograph for Fuel Gas

145E4407 GEK 111865

Gas Turbine Operations - 9FA.03 Gas Fuel DLN 2 Electricity Generation Company of Bangladesh LTD

2

GE Power & Water 0017HAE-Controls SSOV (Safety Shut off Valve) System Testing

GEK 116384

Accessory Module Fuel Gas System Components Schematic Diagram-PP Fuel Gas (ML 0422) Dry Low Nox 2.0+ System Operation DLN2.0+ Combustion Modes Piping Arrangement-Fuel Gas (ML 0962)

GCV+PA_Valves 145E4544 GEK 116535 DLN2+Combustion Modes 100T6350

Fuel Nozzle End Cover & Casing Assembly-Gas Only (ML0513)

141E7385TP

DLN 2+ GF Comb Cover Fuel Nozzle End Cover Assembly-Gas (ML0513) DLN2+ Fuel Nozzle flow paths

DLN 2+GF Comb Cover 141E7384TP GT9FA_DLN2+Fuel Nozzle Flow Paths

0017CEE-Fuel Gas System-Gas Turbine Operational Best Practices and Troubleshooting Guide

GEK 116445

Tab 12 Gas Turbine Fuel Purge System (ML 0477) Fuel Purge System Description Schematic Diagram-PP Gas Turbine Fuel Purge (0477) Piping Arrangement-Purge Air (ML 0924)

GEK 110832 145E4554 139E7945

Tab 13 Cooling and Sealing Air System (ML 0417) Cooling & Sealing Air-Summary Schematic FA Compressor Arrangement MS9FA Cooling & Sealing Air Flows Cooling and Sealing Air System Description

Fa_Csa_Allflows 9F_Csa_Ejector_Schem GT9FA_9FACSA-R0 GEK 116682

Schematic Diagram-PP Cooling and Sealing Air (ML 0417)

145E4548

Cooling and Sealing Air Piping Arrangement (ML 0909)

100T7111

General Arrangement, 9FA Cooling Fan Module (DIS 100130-132) (020-0394)

232D7907_1

Exhaust Frame and #2 Bearing Cooling Air Piping (ML0972) Clearance Control Module General Arrangement

107T7375 232D7890

CTM Impingement Cooling Air Piping Arrangement (ML9019)

104T2780_1&6

Tab 14 Cooling Water System (ML 0420) Cooling Water System Description Schematic Diagram-PP Cooling Water (ML 0420)

GEK 110425 145E4550

Tab 15 Heat and Ventilation System (ML 0436) Ventilation and Heating System Description Schematic Diagram-PP Heat and Ventilation (ML 0436)

GEK 117015 145E4539

Gas Turbine Operations - 9FA.03 Gas Fuel DLN 2 Electricity Generation Company of Bangladesh LTD

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GE Power & Water Tab 16 Fire Protection System (ML 0426) Fire Protection Skid-Outline and Foundation Drawings Fire Protection System Description Schematic Diagram-PP Fire Protection (ML 0426) 0017CJE-FM-200 Fire Protection System Operation and Maintenance Manual / Fire Protection Skid

288D1036_1 GEK 111696 145E4547 GEK 110891 399A5169_FPSKID-OPS

Tab 17 Hazardous Gas Detection System (ML 0474) 0331-Outline, Hazardous Area Map-Gas Turbine and Load 107T5719 0017BTE-Aspirated Hazardous Gas Protection System Schematic Diagram-PP Gas Detection (ML 0474)

GEK 117012 103T1401

Installation Outline Drawing (DIS-102-112-113-120-130) (3054-946)

108T0812

Outline, Hazardous Area Map-Model 324 Generator (C908, 0331) 124E8574 Panel, Dual Flow, Ultima XE (ATEX), Installation Outline Panel, Single Flow, Ultima XE, (ATEX), Installation Outline Tab 18 Compressor/Turbine Water Washing System F Class Water Wash System Description Schematic Diagram-PP Compressor Washing (ML 0442) 0438-F-Class Gas Turbine Compressor Washing-Liquid Washing Recommendations for Gas Turbines with Pulsed Water Wash Systems

E5JP_3054-1015 E5JP_3054-1262 GEK 111898 145E4542

GEK 111895

Water Wash Unit-General Arrangement and Piping Layout 232D8459_3 Cabinet Layout Water Wash 281B5885 Description-Water Wash Unit WWSKIDDESC Tab 19 Starting System 0017CAE-Starting System LS2100e Static Starter Product Description Innovation Series LCI Liquid Cooling System Assembly Turning Drawing Triple S Clutch

GEK 107415 GEI 100792 GEH 6374 TG_KoenigM392 GEN_FH2_SSS Clutch-r0

Tab 20 Excitation Electrical One-Line Diagram (0444) Excitation System Schematic Excitation Fundamentals & EX2100 Overview

105T6628 Ex2100e Functional EX21K OV_Siddhirganj

EX2100e and LS2100e Control Systems Touchscreen Local Operator Interface Instruction Guide GEI 100787_pgs 1-27

Gas Turbine Operations - 9FA.03 Gas Fuel DLN 2 Electricity Generation Company of Bangladesh LTD

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GE Power & Water Tab 21 Generator Construction Hydrogen Generator Diagram Generator Description Nameplate Data, Generator (B7F0) Generator Requisition Summary Sheets (C907) Generator Mechanical Outline (A1B0) Rotor Assembly End Shield Assembly GENERATOR CLOSE PIPING (G4J0) Ventilation Hydrogen Cooled Generator

9FH2 Generator GEK 116371 105T6949 105T9715 102T5239_1-2 RA001 134E1123 102T5128 ST_STF11-7_9-12

IIBENG, IIBEXC-Shaft Grounding System, Operation and Maintenance

GEK116546a-9

IIBENG, IIBEXC-Collector and Carbon Brush Rigging Installation, Operation and Maintenance

ETTGEK116362_Pin

General Arrangement of 9FA GTE-LH Side Exit (63626346)

229D1756_6-9

Tab 22 Seal Oil System Schematic Diagram-H2 and Seal Oil Shaft-Sealing System for Hydrogen Cooled Generator Shaft Seaing Rings and Bearing Arrangement

145E4602 ST_STF11-14 2127124

IIBENG-Shaft Sealing System, H2 Cooled Unpackaged Generator

GEK 116742

Outline, Seal Oil Skid Generator Systems (G1C2) Outline Float Trap Arrangement (G1J2)

135E3653 110E7151

Tab 23 Hydrogen and CO2 Gas Control H2/CO2 System Simplified Schematics GEN_FH2_STF-11-26A-r0 Hydrogen & Carbon Dioxide Piping Manifolds (G1G0) (G2H0) 105T5012 IIBENG-Hydrogen and Carbon Dioxide Gas Control SystemOperation and Maintenance GEK103763 IIBACH-System Purging and Charging (Manual Purge) IIBACH-Valve Positions During Normal Operation LAB: Generator Purge Operations LAB: Normal MW Production Monitoring H2-in-Air

GEK 103611 2130754 ST-GT_LabGenPurge_01-14 ST-GT_LabNormOpH2inAir_01-14

Hydrogen Control Panel (HCP) Assembly Drawings (DIS102) (HD0357P01)

232D8994

Dual Hydrogen Control Panel (DHCP) (HA0385G03) (DIS201)

425A5454

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GE Power & Water Tab 24 SPEEDTRONIC Mark VIe Control Functional Description Assembly-Remote Control Systems (ML 4108) Fundamentals of Speedtronic-MK VIe Control Systems OpFlex ETS Operational Overview Human-Machine Interface (HMI)-Product Description Workstation ST Alarm Mgmt Tools Alarm Tracing

GEK 107358 106T5414_1-4 Fund_MK_Vie OpFlex ETS Operational Overview-ETT GEI 100485 Workstation ST Alarm Mgmt Tools Alarm Tracing_MKVIe_R1

Tab 25 Gas Turbine / Generator Operation GT Product Safety Unit Operation / Gas Turbine Start Check Definitions Generator Prestart Checklist Startup/Shutdown Sequence and Control GT Startup Curve and Events 9FA SU_FSD curves with IBH Synchronization Loading Characteristics Operation of Hydrogen Cooled Turbine Generators Schematic Diagram-Load Equipment (0440) Generator Electrical Data (C902) Periodic Operational Inspections and Tests Generator Alarms and Protection Recommendations

GEK 111309 GEK 116689 StartCheck_9FA_GFl_TYPICAL_2014 GEK 110608 GEK 111084 GT Starting Events-SP 9FA SU5FSD curves GEK 116369 GEK 106866 GEK 116772 106T7873 106T0341 GEI 74478 GEK 75512-Tables 1, 2

0438-Basic Combined Cycle Start-up Procedure from a Turbine Controls Point of View

GEK 107538

0438-Heavy Duty Gas Turbine Operating and Maintenance Considerations GER 3620 Tab 26 Controls Reference Documents Device Summary (ML 0414) HMI Screens

399A4822 HMI Screens

Alarm List

This information will be provided during the course

Process Alarms - 9FA Non Site Specific

Alarm Database

Tab 27 APPENDIX (This Information Provided Only On Separate CD) Safety Equipment Residual Risk Summary (Gas Turbine) (0124)

107T9923

Equipment Residual Risk Summary, Model 324 Generator (C909)

383A2063

Equipment Residual Risk Summary, Electrical EquipmentGenerator (C912)

106T3876

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GE Power & Water Hazardous Gas Outline, Hazardous Area Map-Gas Turbine and Load (0331) 107T5719 Notes, Hazardous Area Map (0331)

107T5718

Outline, Hazardous Area Map-A160/MS10 9FA Accessory Module (0331)

141E8017

Outline, Hazardous Area Map-G023 Fuel Gas Chromatograph (0331)

146E2561

Outline, Hazardous Area Map-Model 324 Generator (C908, 0331) 124E8574 Instruction Manual / Infrared Aspirated Gas Detection System (DIS-201)

108T0826

Section 1-Custom Products Instruction Manual-Aspirated Gas Detection System for Use In Gas Turbine Applications

E5JP_Section 1

Section 2-Ultima X Gas Monitor Instruction Manual, MSA Publication Number 10036101(FM)

E5JP_Section 2

Section 3-Ultima X Gas Monitor Instruction Manual, MSA Publication Number 10046690 (ATEX)

E5JP_Section 3

Reference Documents Gas Turbine Functional Description (MS9001FA, DLN-2+) Combustion Chamber Arrangement (ML 0701) Gas Turbine Glossary of Terms GE Gas Turbine Performance Characteristics

GEK 110494 123E9750TP C00023GT GER 3567

Gas Fuel Clean-Up System Design Considerations for GE Heavy-Duty Gas Turbines

GER 3942

IIBACH-Detection of Gas Leakage and Hydrogen Purity Formulas

GEK 117004

Specification, Schematics and P&ID's (0438)

372A3671

Specification, Piping & Instrumentation Diagram (P&ID) (0438)

334A3032

Specification, P&ID Symbols and Nomenclature (0438) Plant Instrument Air System (replaces GEK 106689) (0438)

213D1781 GEK 110727

Controls Specifications Settings-MKVI (ML A010) Mark VIe Turbine Control System-Product Description

100A1046 GEI 100600

OpFlex* Enhanced Transient Stability (ETS) for GE Gas Turbines User Guide

GEH 6810

Model-Based Control for GE Gas Turbines GEH 6740 Control System Toolbox for Configuring the Trend Recorder GEH 6408

Gas Turbine Operations - 9FA.03 Gas Fuel DLN 2 Electricity Generation Company of Bangladesh LTD

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GE Power & Water Excitation Excitation Ex2100e Product Description

GEI 100783

LCI Static Starter LS2100e Static starter Control, User Guide

GEH 6798

Schematic, LCI Cooling System Interconnecting Diagram (4023)

361B5013

Gas Turbine Fluid Specifications Lube Oil Recommendations-Turbine Oil Recommendations-Generator Process Specification-Fuel Gas Cooling Water Requirement for Closed Systems

GEK 32568 GEK 116372 GEI 41040 GEI 41004

Gas Turbine Operations - 9FA.03 Gas Fuel DLN 2 Electricity Generation Company of Bangladesh LTD

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Tab 1

GE Power and Water 

 

Gas Turbine - Generator Operation Course Course Description This site-specific course is designed to enable, supervisors, operations, and maintenance personnel to operate GE designed heavy-duty gas turbine generator units. The course develops a background in gas turbine generator support systems, and operations, which will enable participants to analyze operating problems and take the necessary corrective action. It will also detail the design and construction of the gas turbine generator. Emphasis is placed on the detailed description of the gas turbine - generator major components, the functions of their auxiliary systems, and the operator’s responsibilities with regard to systems operations, and operational data acquisition, and evaluation of anomalies thru the use of classroom instruction, class exercises, and use of a turbine - generator trainer. If the course is held at the customer’s location it will include site visits to familiarize personnel with the physical layout of the gas turbine - generator, and the location of the various system components, and provide personnel the opportunity to correlate the system piping schematics to the respective system hardware. Operators are instructed in how to interpret fault annunciation and how to determine if the annunciated fault can be remedied by operator action or with the assistance of instrumentation and/or maintenance personnel. The course focuses on the starting, loading, and specific operator checks of the various turbine support and auxiliary systems to ensure reliable operation of the gas turbine - generator unit, and the effect that operation has on major mechanical maintenance. 

g _________________________________________________________________________GE Energy Learning Center 2 Week Gas Turbine Generator Operations Training Schedule Gas Fuel WEEK #1 Day 1

Day 2

Gas Turbine • Introduction • Gas Turbine Theory & Construction • Operating Principles & Performance • GT Instruction Books & Reference Drawings

Day 3

Gas Turbine Systems • • • • •

Cooling & Sealing Air Inlet Air Systems Exhaust Stack / Damper Inlet Air (Bleed) Heating Performance Monitor

Gas Turbine Systems • • • •

Lube Oil Hydraulic / Lift Oil Inlet Guide Vanes Trip Oil

Day 4

Day 5

Gas Turbine Systems • DLN 2.6+ Combustion System • Gas Fuel Systems • Fuel Purge

Gas Turbine Systems • • • • •

Cooling Water Heating & Ventilation Fire Protection Hazardous Gas Compressor Water Wash

WEEK #2 Day 6

Day 7

Day 8

Day 9

Day 10

Generator

Electrical / Controls

Controls

Controls / Operations

GTG Operations

Generator • Design & Construction • Generator Devices • Seal Oil • Hydrogen System

Excitation Starting Means – LCI / Turning Gear

Mark VIe & HMI • MK VIe General Hardware and Software Overview

GT and Generator Operation & Protection

GT Operation

REVIEW

Turbine Devices Electrical One Line GT Control and Protection Functions

11/30/2014

GT Control and Protection Functions

HMI Screens • User Defined Displays • Toolbox Overview

Tab 2

MS9001FA Gas Turbine Assembly Major Sections COMBUSTION FUEL GAS LIQUID FUEL

LINER

TRANSITION PIECE

DIFFUSER

STEAM/WATER INJECTION VIGVS ATOMIZING AIR

GENERATOR

9FA UNIT

AIR INLET

COMPRESSOR

TURBINE

EXHAUST

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9FA Gas Turbine Basics

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Function

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Combustion

Fuel 2 Compressor

Work out

Turbine

4

1 Fresh Air Revision Date: 02/10/2000

3

Exhaust gasses Property of Power Systems University- Proprietary Information for Training Purposes Only!

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9FA Gas Turbine Flow

COMBUSTION 14 Chambers

AIR INLET

GE Power Systems

COMPRESSOR

EXPANSION TURBINE

EXHAUST

3 Stages

18 Stages 16.8:1 CPR

Power Output

FORWARD

Base

AFT

Shaft Rotation: Counter (anti) Clockwise – Viewed from Inlet Revision Date: 02/10/2000

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Note: For instructional purposes only

GAS TURBINE Temperature and Pressure Levels at Base Load

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Typical Gas Turbine Cycle Conditions Combustor Flame (140-245 psi) ( 9.5 – 17 Bar) (2400-3200 F) (1320 – 1760 C)

Stage 1 Bucket Inlet (90-160 psi) (6.2 - 11 Bar) (2000-2600 F) (1090 - 1430 C aka “Firing Temperature”” 4

Temperature

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Expand Burn

Exhaust Gas (0.2-0.7 psi) (1000-1200 F) 6

5 3

Compressor Inlet Face 2

1

Compressor Discharge (150-260 psi) (10 – 17 Bar) (650-800 F) (340 – 430 C)

Compress

Ambient 14.7PSIa 1Bar; 59F, 15C

Draw in Air

Pressure Revision Date: 02/10/2000

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1st Row of Rotating Blades Inlet Struts

Compressor

Bellmouth

Inlet Guide Vanes (Open Position)

Inlet Guide Vanes (Closed Position)

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Axial Compressor Arrangement

Compressor Rotor Blades Compressor Casings Compressor Stator Vanes

Variable Inlet Guide Vanes Revision Date: 02/10/2000

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Compressor Pressure Ratio Pressure Ratio =

absolute compressor discharge pressure absolute compressor inlet pressure

Absolute Pressure = gauge pressure + 14.7 PSIA

Example: Inlet Pressure = - 0.60 psig Discharge Pressure = 220 psig PR = (220+14.7) / (- 0.60+14.7) = 264.7/ 14.1 = 16.65

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Compressor Protection: 1 Inlet Guide Vanes 2 Compressor Bleed Valves 3 Inlet Air (Bleed) Heating 4 Compressor Pressure Ratio Fuel Limitations

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______ ___________ _________ _________ ________ _______ _______

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Turbine Section (Hot Gas Path) Buckets: 1st Stage _________________

1st Stage

2nd Stage

2nd Stage

3rd stage

_______

_______

3rd stage

Nozzles __________________ Revision Date: 02/10/2000

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9FA Air Flows

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#1 Journal and Thrust Bearing Assembly Active Thrust Bearing

Compressor --Æ Æ

____________________

_________________

#1 Journal Bearing ________________

Inactive Thrust Bearing

Rotor Thrust Collar (Runner) _________________________

_______________________ Revision Date: 02/10/2000

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e Tilting Pad Journal Bearing

Thermocouple _______________

Lift Oil Port ______________

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Thrust Bearing with Thermocouples

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#2 Bearing Arrangement

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FACTORS AFFECTING GAS TURBINE PREFORMANCE

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15oC 101.35 KpaA (1.013 bar)

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400F(4.40C) Typical limit when IBH antiicing comes on

Exhaust Temp.

Revision Date: 02/10/2000

Property of Power Systems University- Proprietary Information for Training Purposes Only!

e

GE Power Systems

• Heat rate is the measure of heat energy in BTU’s of fuel required to produce one kW-hr • Heat rate is inversely proportional to unit efficiency • The lower the Heat Rate, the better the performance of the unit Revision Date: 02/10/2000

Property of Power Systems University- Proprietary Information for Training Purposes Only!

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GE Power Systems

Revision Date: 02/10/2000

Property of Power Systems University- Proprietary Information for Training Purposes Only!

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GE Power Systems

Revision Date: 02/10/2000

Property of Power Systems University- Proprietary Information for Training Purposes Only!

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GE Power Systems

ISO Firing Temperature • Reference Turbine Inlet Temperature • A Calculated Temperature That Is Not Physically Measured • Always less Than Firing Temperature as Defined by GE Revision Date: 02/10/2000

Property of Power Systems University- Proprietary Information for Training Purposes Only!

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GE Power Systems

9FA = 2400oF up to 3200oF 1320oC– 1760oC

9FA = 2420oF = 1327oC

GE Firing Temperature

Revision Date: 02/10/2000

Property of Power Systems University- Proprietary Information for Training Purposes Only!

e

GE Power Systems

Temperature Control Curve Maximum Turbine Operating Temperatures Design Process

Process Output:

Process Inputs:

Isotherm

Exhaust Temperature

1) Current Cycle Design 2) Target Firing Temperature 3) Expected Site Ambient 4) Expected Fuel 5) Target NOX 6) Exhaust Temperature (TX ) Limit 7) “Special” Considerations - Humidity - Dry vs Wet - DLN TRISE Criteria - Base Load vs Part Load - Compressor Temp Bias

Compressor Discharge Pressure

Revision Date: 02/10/2000

Property of Power Systems University- Proprietary Information for Training Purposes Only!

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GE Power Systems

VIGVs Affect Exhaust Temperature and Flow

Revision Date: 02/10/2000

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GE Power Systems

Revision Date: 02/10/2000

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GE Power Systems

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REFERENCE FUEL

Revision Date: 02/10/2000

GER 3567H Page 11

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GE Power Systems

e

Revision Date: 02/10/2000

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GE Power Systems

e

GER 3567H Page 13

Revision Date: 02/10/2000

Property of Power Systems University- Proprietary Information for Training Purposes Only!

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GE Power Systems

Pressure Drop Effects – 9FA % Effect on

Effect on

Increase

Output Heat Rate

10 mbar water – Inlet

-1.19

0.21

0.7C (1.3 F)

10 mbar water – Exhaust

-0.21

0.21

0.7C (1.3 F)

Revision Date: 02/10/2000

Exhaust Temp

Property of Power Systems University- Proprietary Information for Training Purposes Only!

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GE Power Systems Note: For instructional purposes only

Effects of Fouling and/or Damage on Compressor Performance

Revision Date: 02/10/2000

Property of Power Systems University- Proprietary Information for Training Purposes Only!

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GE Power Systems

Revision Date: 02/10/2000

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GE Power Systems

GE Gas Turbine Design Philosophy

• Major Elements: – Evolution of Designs, – Use of Geometric Scaling, – Thorough Preproduction Development, – Use of Relatively Common Materials, – Fuel Flexibility, – Packaging, – Maintenance Revision Date: 02/10/2000

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GE Power Systems

END

Revision Date: 02/10/2000

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DWG Number 105T5589

Rev -

Released 12/14/2012

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DWG Number 105T6819

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Released 7/23/2013

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ML ITEM 0962 FUEL GAS

ML ITEM 0987 PERFORMANCE MONITORING

ML ITEM 0972 NO. 2 BEARING COOLING

ML ITEM 0964 FIRE PROTECTION

ML ITEM 0972 EXHAUST FRAME COOLING

ML ITEM 0907 NO. 2 BRG FEED & DRN

ML ITEM 0918 LIQUID FUEL PURGE

ML ITEM 0924 AIR EXTRACTION PURGE

ML ITEM 0965 ATOMIZING AIR ML ITEM 0909 COOLING & SEALING AIR ML ITEM 0953 COMPRESSOR WATER WASH ML ITEM 0976 EXH PLENUM DRN ML ITEM 0905 NO. 1 BRG FEED & DRN

ML ITEM 0969 LUBE OIL FEED & DRN INTERCONNECT

ML ITEM 0969 LIQUID FUEL PURGE INTERCONNECT

ML ITEM 0979 INLET PLENUM DRAIN

ML ITEM 0969 LIQUID FUEL INTERCONNECT

ML ITEM 0969 LUBE OIL FEED & DRN INTERCONNECT

ML ITEM 0906 LUBE OIL FEED & DRN LOAD

ML ITEM 0961 LIQUID FUEL

ML ITEM 0968 WATER INJECTION

ML ITEM 0915 / 0969 COOLING WATER

9FA DUAL FUEL

ML ITEM 0924 AIR EXTRACTION

ML ITEM 0920 / 0969 FALSE START DRN

ML ITEM 0969 ATOMIZING AIR INTERCONNECT

1 PGU – SDA & BOP Overview Dec. 13 ~ 15, 2005

MS9001FA Gas Turbine Assembly Major Sections

7

6

8

ÒÒÒÒÒÒÒÒÒÒÒÒÒ ÒÒÒÒÒÒÒ ÒÒÒÒÒÒ AIR ÒÒÒÒÒÒÒINÒÒÒÒÒÒ 9 ÒÒÒÒÒÒÒÒÒÒÒÒÒ ÒÒÒÒÒÒÒÒÒÒÒÒÒ 5 ÒÒÒÒÒÒÒÒÒÒÒÒÒ

10 12 11

13 17

16 15 14

ÒÒÒ ÒÒÒ ÒÒÒ EXHAUST

20

STARTING MOTOR & TORQUE CONVERTER

19

GENERATOR

18

1

B00293Q 1/94

2

3

4

MS9001FA Gas Turbine Components 1 – AIR INLET 2 – COMPRESSOR 3 – TURBINE 4 – EXHAUST 5 – VIGV’S 6 – FUEL GAS INLET 7 – LIQUID FUEL INLET 8 – STEAM / WATER INJECTION INLET 9 – ATOMIZING AIR INLET 10 – COMBUSTION 11 – LINER 12 – TRANSITION PIECE 13 – DIFFUSER 14 – 9th STAGE EXTRACTION 15 – 13th STAGE EXTRACTION 16 – 3rd STAGE NOZZLE 17 – 3rd STAGE BUCKET 18 – No. 1 BEARING 19 – No. 2 BEARING 20 – 17th STAGE INTERNAL EXTRACTION

BOO293A 1 / 99

Tab 3

DWG Number 138E5399

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Released 3/19/2012

GE Proprietary Information - Class II (Internal) US EAR - NLR

g

GEK 116811a Revised, October 2012 Grammatical Corrections Only

GE Energy

Customer O&M Manual Users Guide

These instructions do not purport to cover all details or variations in equipment nor to provide for every possible contingency to be met in connection with installation, operation or maintenance. Should further information be desired or should particular problems arise which are not covered sufficiently for the purchaser's purposes the matter should be referred to General Electric Company. These instructions contain proprietary information of General Electric Company, and are furnished to its customer solely to assist that customer in the installation, testing, operation, and/or maintenance of the equipment described. This document shall not be reproduced in whole or in part nor shall its contents be disclosed to any third party without the written approval of General Electric Company. © 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

GEK 116811a

Customer O&M Manual Users Guide

TABLE OF CONTENTS I. 

MANUAL PURPOSE .................................................................................................................................. 4  A.  General Information................................................................................................................................ 4  B.  Timeline .................................................................................................................................................. 4  C.  Translation .............................................................................................................................................. 4  D.  Exclusions............................................................................................................................................... 4  E.  Documentation Provided By Other Means ............................................................................................. 5  F.  Proprietary Considerations ..................................................................................................................... 5  G.  Responsibilities....................................................................................................................................... 5  H.  Revision Process ..................................................................................................................................... 6  II.  TYPICAL STRUCTURE AND CONTENTS OF THE CUSTOMER O&M MANUALS.................... 7  A.  Manual Front Matter............................................................................................................................... 7  1.  Letter ............................................................................................................................................... 7  2.  GEK Number .................................................................................................................................. 7  3.  Distribution List Section ................................................................................................................. 7  4.  Revision History Section................................................................................................................. 7  5.  Order Parts (Online Manual and CD’s only) .................................................................................. 8  6.  Repair Solutions (Online Manual and CD’s only) .......................................................................... 8  7.  Outage Optimizer (Online Manual and CD’s only) ........................................................................ 8  8.  Main Table of Contents................................................................................................................... 8  9.  Sub-supplier Equipment Cross Reference Index ............................................................................ 9  B.  Gas Turbine Operation and Maintenance Manual ................................................................................ 10  1.  Introduction................................................................................................................................... 10  2.  Safety ............................................................................................................................................ 10  3.  Gas Turbine................................................................................................................................... 10  4.  Gas Turbine Auxiliary Systems .................................................................................................... 10  5.  Gas Turbine Auxiliary System Modules....................................................................................... 11  6.  Acoustic (Fabricated) Enclosures ................................................................................................. 11  7.  Generator....................................................................................................................................... 11  8.  Generator Auxiliary Systems ........................................................................................................ 11  9.  Generator Excitation ..................................................................................................................... 12  10.  Electrical Starting Means .............................................................................................................. 12  11.  Electrical Energy Evacuation........................................................................................................ 12  12.  Power Distribution System ........................................................................................................... 12  13.  Control Equipment ........................................................................................................................ 12  14.  Monitoring Equipment .................................................................................................................. 12  15.  Technical Information Letters....................................................................................................... 13  16.  Bills of Material and Drawings ..................................................................................................... 13  C.  Steam Turbine Operation and Maintenance Manual ............................................................................ 13  1.  Introduction................................................................................................................................... 13  2.  Safety ............................................................................................................................................ 13  3.  Operation....................................................................................................................................... 13  4.  Control System.............................................................................................................................. 14  5.  General Information ...................................................................................................................... 14  6.  Turbine Maintenance .................................................................................................................... 14  7.  Stationary Parts ............................................................................................................................. 14  8.  Rotating Parts................................................................................................................................ 14  9.  Steam Seal..................................................................................................................................... 14  10.  Valves............................................................................................................................................ 15 

2

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

Customer O&M Manual Users Guide

GEK 116811a

11.  Bearings ........................................................................................................................................ 15  12.  Turning Gear ................................................................................................................................. 15  13.  Electrical ....................................................................................................................................... 15  14.  Exhaust Hood Spray System......................................................................................................... 15  15.  Lubrication .................................................................................................................................... 15  16.  Hydraulic System .......................................................................................................................... 16  17.  Monitoring .................................................................................................................................... 16  18.  Supervisory Instruments................................................................................................................ 16  19.  Generator....................................................................................................................................... 16  20.  Generator Excitation ..................................................................................................................... 16  21.  Generator Control Panel................................................................................................................ 16  22.  Accessory Compartments.............................................................................................................. 16  23.  Gas Control And Monitoring System ........................................................................................... 17  24.  Seal Oil System ............................................................................................................................. 17  25.  Technical Information Letters....................................................................................................... 17  26.  Bills of Material and Drawings ..................................................................................................... 17  III.  EXAMPLES FOR LOCATING INFORMATION ................................................................................. 18  A.  Locating Component Tab ..................................................................................................................... 18  B.  Locating Component within Tab .......................................................................................................... 19  C.  Using the Bill of Materials and Drawings Tab ..................................................................................... 20  1.  Bills of Material ............................................................................................................................ 20  2.  Drawings ....................................................................................................................................... 21  D.  Access to Online O&M Manuals.......................................................................................................... 21  1.  Use this URL for an SSO ID request: ........................................................................................... 21  2.  For direct access, the URL for the on-line Technical Manual application is:............................... 22  E.  Fully Engineered Quote (FEQ)............................................................................................................. 22 

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

3

GEK 116811a

Customer O&M Manual Users Guide

I. MANUAL PURPOSE GE Energy provides a comprehensive set of Customer Operation and Maintenance Manuals (O&M Manuals) as reference documentation to assist the final “User” in operating and maintaining the equipment provided under the scope of the contract. This document contains a brief description of the O&M Manual format and content, along with the intended customer utilization of the Manuals. A. General Information The Customer O&M Manual set is organized to provide the User with important project-specific reference information in addition to the User’s normal operation and maintenance procedures. Since Operating and Maintenance philosophies vary from customer to customer, GE Energy does not attempt to dictate specific procedures, but to provide basic limitations and requirements created by the type of equipment provided. The information found in the Manuals is intended to build on a User’s basic understanding of the operation and maintenance of complex equipment of this type. This O&M Manual is not intended to be a step by step operational guideline. It is expected that if the User needs additional assistance or further detail regarding their specific equipment, they should consult directly with their local GE representative. B. Timeline Due to the variation in equipment supply scope and the complexity of the equipment being provided, the O&M Manual documentation is established and published following the completion of the engineering and manufacturing phase of each project. The Manuals are created based on a standardized structure but developed to accurately reflect the actual equipment provided. The intended timeline for Manual delivery is: •

The standard comprehensive set of O&M Manuals are generally provided in English twelve (12) weeks following contract equipment ship date.

•

The translated O&M Manual, when required, has its own delivery schedule, which is generally 17-23 weeks after the English O&M Manual is issued.

C. Translation GE provides translated O&M Manuals as required by contract and/or local codes and standard compliance requirements. Translation does not begin until after the English O&M Manual is complete. D. Exclusions The Customer O&M Manual does not include documentation for and is not intended to be a guide for:

4

•

Partner Operation and Maintenance Manuals

•

Engineering and Design

•

Manufacturing

•

Shipping

•

Initial assembly and Installation © 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

Customer O&M Manual Users Guide

•

First commissioning

•

Training

•

Quality records

GEK 116811a

NOTE GE Energy may provide specific detailed documentation in separate Manuals for the subjects listed above. E. Documentation Provided By Other Means The following documentation is not included in the Customer O&M Manual, but may be provided by GE Energy Services as necessary: •

Lists of Spare Parts for Ordering The Customer O&M Manual is provided for the purpose of instructing the owner/operator in the operation and maintenance of the equipment provided under the requisition scope of supply. Information provided in the O&M Manual allows Users to locate and identify parts needed to plan for and perform equipment maintenance. The GE Energy Services parts organization is responsible for support required to either identify or order spare or replacement parts and to provide recommended spare parts list as required.

•

Dismantling at End of Service The Customer O&M Manual does not contain information to accomplish complete plant disassembly and provisions for long or short term storage after disassembly.

•

Comprehensive Lubrication Program The Customer O&M Manual does not provide a tailored lubrication program or list of specific brand lubricants. However, the necessary lubrication requirements and lubricant specifications for each system are provided in the appropriate system section of the O&M Manual. This information is provided so that the owner/operator can integrate the lubrication requirements into the overall plant maintenance program.

F. Proprietary Considerations The following statement is found in every Customer O&M Manual: “These instructions do not purport to cover all details or variations in equipment or to provide for every possible contingency to be met in connection with installation, operation or maintenance. Should further information be desired or should particular situations arise which are not covered sufficiently for the purchaser’s purposes, the matter should be referred to the GE Company.” G. Responsibilities The Customer O&M Manuals are written for operators that already have a general understanding of the requirements for safe operation of mechanical and electrical equipment in potentially hazardous environments. They are not designed for use by personnel with little or no operational/maintenance training or learned skills. Throughout the O&M Manual there are numerous references to model list codes. These codes are taken directly from the GE Engineering Bill of Material for the turbine or generator. For easier use of the O&M Manual, Users should have a general familiarity with the GE Engineering Bill of Material and its structure. © 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

5

GEK 116811a

Customer O&M Manual Users Guide

These instructions should be interpreted and applied in conjunction with sound engineering practice, and in accordance with all provided safety guidelines. It is imperative that all safety rules and regulations applicable at the site be followed to provide for safe operation of site equipment. Because Operating and Maintenance philosophies vary from customer to customer, GE Energy does not attempt to dictate specific procedures but to provide basic limitations and requirements created by the type of equipment provided. The information provided in the Manuals is intended to build on a user’s basic understanding of the operation and maintenance of complex equipment of this type. It is expected that if the user needs additional assistance or further detail regarding their specific equipment, they consult directly with their local GE representative. The information set out in the O&M Manual set has been developed from GE Energy standard equipment specifications. Where possible at the time of publication, modification information has been included for that equipment which is specific to the contract and also for additional equipment supplied by GE Energy which has been manufactured by others. The timing of publication and the ongoing nature of design improvements may mean that features of the equipment supplied may be different from those shown in this publication. No liability is accepted by GE Energy for errors, or omissions or discrepancies of this nature. No additional representations or warranties by GE Energy regarding the equipment or its use are given or implied by the issue of the O&M Manual. The rights, obligations and liabilities of GE Energy and the User are strictly limited to those expressly provided in the contract relating to the supply of the equipment. H. Revision Process GE Energy makes the on-line (webbook) and optional hard copy/DVD O&M Manuals available to the customer. GE does not update the original set of Manuals except: •

To add documents that were not available and were listed as shortages when the Manual was issued

•

To correct an error or omission

•

To reflect changes when an O&M Manual update is scheduled through Engineering (DCI/ECN)

•

To update with as installed drawings (as applicable)

Revisions covered under separate contracts (FMI, CMU, etc.) will be issued in the form of a separate addendum or as an update to the existing O&M Manual. For the on-line version of the Customer O&M Manual, GE drawings and GE turbine-generator publications are monitored for later revisions and updated to the latest revision on a regular basis. The automated update process applies only to the on-line O&M Manual, it does not apply to DVD or hardcopy sets. When an update is issued specifically for the hardcopy and/or DVD, a formal Revision Instruction Sheet is issued to communicate specific instructions on where to insert, remove, or replace the hardcopy documentation in each volume. This Revision Instruction Sheet is also included on the updated DVDs. The drawings in the Customer O&M Manuals are intended only to support the technical documentation in the Manual, and do not constitute the official issuance of the drawings to the

6

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

Customer O&M Manual Users Guide

GEK 116811a

customer. It is the role of the as-built drawing file, officially transmitted to the customer apart from the O&M Manuals, to reflect the installation modifications. II. TYPICAL STRUCTURE AND CONTENTS OF THE CUSTOMER O&M MANUALS The O&M Manuals are broken down by System, Sub System, MLI and then in some cases individual components. The structure of any section is determined by the equipment discussed in the section and content and level will vary to match equipment installed. The following sections are a brief description of what is typically contained in the O&M Manuals. A. Manual Front Matter The following front matter material is contained in gas turbine and steam turbine O&M Manuals. 1. Letter The letter section contains the letter delivered with initial delivery of the Manuals; it contains date of delivery and initial instructions. 2. GEK Number This section contains the Manual cover page. 3. Distribution List Section The distribution list contains the following information: •

Date of last shipment

•

Job or DM number

•

Customer

•

Equipment (Gas Turbine, Steam Turbine, Generator) serial numbers

•

Station Name and Location

•

Job Type (Combined Cycle, Simple Cycle, Etc)

•

Who and where Manuals were shipped

•

How many CD copies

•

How many paper copies

4. Revision History Section The Revision History contains the following information: •

Date of Revision

•

Design Memo Number

•

Customer

•

Station Name

•

Equipment (Gas Turbine, Steam Turbine, Generator) serial numbers

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

7

GEK 116811a

Customer O&M Manual Users Guide

•

Revision Number

•

Update information (what was added , removed, or changed), along with why (Design change number, As-built revision, Etc.) and the date of the change

5. Order Parts (Online Manual and CD’s only) This section contains a link that will direct you to GE Parts Edge, which offers a comprehensive, easy-to-use tool to access parts information and recommendations, as well as obtain quotes, convert quotes to orders and track your orders in real-time from placement to delivery. 6. Repair Solutions (Online Manual and CD’s only) This section contains a link that will direct you to GE Global Network of Repair Services where you can: •

Locate a service center

•

Request a quote for repair services

•

Check the status of your repair

7. Outage Optimizer (Online Manual and CD’s only) This section contains a link that will direct you to the Outage Optimizer which is designed to replace the many loose papers and confusing forms that were once a necessary part of the outage process, Outage Optimizer speeds planning, reduces quotation turnaround time and makes collaboration with the service team much more convenient. The Outage Optimizer tool allows you to: •

Review your technical data

•

Review your update options to improve performance

•

Benchmark your 7F, 9F or 7E Gas Turbine-generator performance

•

Request a quote for repair services

8. Main Table of Contents This section contains the Table of Contents for the Manual, which is broken down by tabs, and sections within the tabs that are further broken down by Model List Items (MLI) or cost codes (CC) and then to individual publications (component O&M Manuals, Drawings, Parts Lists, Etc). The Table of Contents functions as a broad general outline of the contents of the Manual set. It is constructed as a generic tool to lead you to a main system. When you have located the system you need, refer to the referenced tab number and volume. NOTE Throughout the O&M Manual there are numerous references to model list codes. These codes are taken directly from the GE Engineering Bill of Material for the turbine or generator. For easier use of the O&M Manual, Users should have a general familiarity with the GE Engineering Bill of Material and its structure.

8

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

Customer O&M Manual Users Guide

1.

GEK 116811a

Typical Table Of Contents

9. Sub-supplier Equipment Cross Reference Index This index contains the following information: •

MLI reference

•

Tabs the MLIs are located in

•

Description of the components or system contained in the MLIs

•

GE drawing number for the MLI and or component

•

Manufacturer or supplier of the components or systems

This section is provided to aid in component identification, while using the O&M Manuals.

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

9

GEK 116811a

Customer O&M Manual Users Guide

B. Gas Turbine Operation and Maintenance Manual The following sections pertain to a typical gas turbine O&M Manual. 1. Introduction This section contains the Customer O&M Manual Users Guide. 2. Safety This section contains information to assist in the safe operation of the plant and may specifically contain the following information: •

GE Product Safety Recommended Best Practices/Safe Site Work Practices

•

Standard Noise Assessment Procedures

•

Hazardous Areas

•

Equipment Residual Risk Summaries

3. Gas Turbine This section contains the following information for the gas turbine engine and the various components that make up the Gas Turbine: •

Functional Description

•

Performance Information

•

Operation

•

Settings, Device Summary, Control and Protection Articles

•

Maintenance and Inspection Information

•

Spare Parts Recommendations

•

Standard Reference Documents Including Test Instructions And Fluid Specifications

•

Component Information

4. Gas Turbine Auxiliary Systems This section contains the system description, operation, maintenance, component and spare parts reference information required to support gas turbine operation systems including, but not limited to:

10

•

Fuel Gas Systems

•

Liquid Fuel Systems

•

Atomizing Air

•

Water Injection

•

Diluent Injection Systems

•

Purge Air System

•

Cooling Water System © 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

Customer O&M Manual Users Guide

•

Cooling and Sealing Air System

•

GT Ventilation System

•

Lubrication System

•

Hydraulic oil System

•

Lift Oil System

•

Trip Oil System

•

Starting Means System

•

Fire Protection System

•

Hazardous Gas Detection System

•

Performance Monitoring System

•

Air Inlet System

•

Inlet Air Heating

•

Inlet Guide Vane System

•

Water Wash System

•

Inlet Temperature Suppression

GEK 116811a

5. Gas Turbine Auxiliary System Modules This section contains the Auxiliary System Modules required to support gas turbine operation systems including, but not limited to: •

Fuel Gas Module

•

Accessory Module

•

LF/AA Module

•

Syngas Module

6. Acoustic (Fabricated) Enclosures This section typically contains the gas turbine enclosure, load compartment, acoustical barrier, and inlet and exhaust enclosure. 7. Generator This section contains the generator operating and maintenance recommendations, and descriptive GEK’s. 8. Generator Auxiliary Systems This section contains the generator auxiliary system descriptions, operating and maintenance GEK’s and P&ID’s for the Following Systems: •

Hydrogen Cooling System (if applicable)

•

Seal Oil System (if applicable)

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

11

GEK 116811a

Customer O&M Manual Users Guide

•

Air Inlet Filters (if applicable)

9. Generator Excitation This section contains the excitation control equipment, supporting transformer and compartment information. 10. Electrical Starting Means This section contains the LCI systems control equipment, supporting transformers and compartments. 11. Electrical Energy Evacuation This section contains the electrical components and enclosures including, but not limited to: •

Switchgear

•

Bus Duct/Bus Accessory Compartment

•

Generator Auxiliaries Compartment

•

Generator Terminal Enclosure

•

Transformers

•

Neutral Ground

•

GNAC/GLAC

12. Power Distribution System This section contains the power distribution components including, but not limited to: •

Battery Chargers and Batteries

•

Motor Control Centers

•

Motor Starters

13. Control Equipment This section contains the control Equipment components including, but not limited to: •

PEECC

•

Turbine Control Panel

•

Generator Control Panel

•

Auxiliary Turbine Control Equipment

•

Network and Operator Interface Equipment

14. Monitoring Equipment This section contains the various monitoring equipment including, but not limited to: •

12

Vibration Monitoring © 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

Customer O&M Manual Users Guide

•

Hazardous Gas Monitoring System

•

PDA Monitor

GEK 116811a

15. Technical Information Letters Throughout the operational life of the equipment, GE Energy may periodically issue a Technical Information Letter (TIL) to inform Users of new or changed information relating to the operation or maintenance of equipment. In all cases, TIL documents are considered supplemental to existing O&M Manual documentation. This section contains a description of the Technical Information letter process. The appropriate TILs are provided to customers when published. 16. Bills of Material and Drawings The Bills of Material and Drawings Section (BOM&D) is designed to provide “project specific” information in support of the documents contained in the O&M Manual. It contains the Bills of Material (BOMs) and Assembly Drawings issued for each project as reference information for field maintenance activities. Additional reference drawings may be included such as clearance, nameplate and alignment drawings. As an example, the BOM&D is used to locate and identify parts needed to plan for and perform equipment maintenance, but it is not provided as the primary means for parts ordering. GE has provided the Web based, electronic portal GE Parts Edge for parts ordering purposes. You can access GE Parts Edge via GE's website or by selecting the “Order Parts” function provided in the On-Line, as well as the CD version of the BOM&D If, after using these methods, you need further parts assistance, contact your GE representative. C. Steam Turbine Operation and Maintenance Manual The following sections pertain to a typical steam turbine O&M Manual. 1.

Introduction This section contains the Customer O&M Manual Users Guide.

2. Safety This section contains information to assist in the safe operation of the plant and may specifically contain the following information: •

GE Product Safety Recommended Best Practices/Safe Site Work Practices

•

Standard Noise Assessment Procedures

3. Operation This section contains general information to for operation of the plant, which is contained in the following sections: •

General - Literature, general in nature, on the operation of the turbine and generator

•

Limits - Operational limits for safe operation of the turbine

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

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GEK 116811a

Customer O&M Manual Users Guide

•

Precautions - Literature with component/system safety precautions during operation

•

Prestart - Actions to be completed before starting the turbine

•

Testing - Required testing of the steam turbine for continued safe operation

4. Control System This section contains turbine control information, software testing associated with the control system and turning gear control and operation. 5. General Information This section contains general information that may include steam turbine device summary, supplemental design data, steam turbine mechanical outline, and other general information as required. 6. Turbine Maintenance This section contains information on formulating a turbine maintenance program, recommended turbine lubrication, cleaning requirements, some spare parts information and a fully engineered Quote, which consists of GE Energy Services spare parts recommendations. 7. Stationary Parts This section contains stationary components of the steam turbine including, but not limited to: •

Front Standard components

•

Steam turbine joint hardware and tightening instructions

•

Lifting devices

•

Packing assemblies

•

Special tooling

•

Diaphragms

•

Crossover piping

•

Exhaust hoods

•

Jacking devices

•

Limits - Operational limits for safe operation of the turbine

8. Rotating Parts This section contains rotating components of the steam turbine including, but not limited to: •

Rotor

•

Couplings

9. Steam Seal This section contains the steam sealing system components consisting of:

14

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

Customer O&M Manual Users Guide

•

Gland Exhauster System

•

Regulating Valves

•

Motor Operated Valves

•

Manual Valves

•

Piping and Instrumentation

GEK 116811a

10. Valves This section contains the steam turbine control valves including, but not limited to: •

Main Steam Stop and Control

•

Combined Reheat and Intercept

•

Admission Stop and Control

•

Reverse Flow Valve

•

Equalizer Valve

11. Bearings This section contains the steam turbine bearing drawings and reference documents. 12. Turning Gear This section contains the steam turbine turning gear operation, service Manuals, and drawings. 13. Electrical This section contains various drawings for the steam turbine electrical wiring connections to electrical sensors and control components. 14. Exhaust Hood Spray System This section contains the exhaust hood spray system components consisting of: •

Control Valves Assemblies

•

Operating Documentation

•

Piping and Instrumentation

15. Lubrication This section contains the steam turbine lubrication system components consisting of: •

AC Motor Operated Lube and Hydraulic Pumps

•

DC Motor Operated Pumps

•

AC Motor Operated Vapor Extractors

•

Lube Oil Conditioning System

•

Filters

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

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GEK 116811a

Customer O&M Manual Users Guide

•

Coolers

•

Piping and Instrumentation

16. Hydraulic System This section contains the steam turbine hydraulic system drawings, fluid recommendations O&M Manual for components consisting of: •

AC Motor Operated Hydraulic Pumps Filters

•

Coolers

•

Piping and Instrumentation

17. Monitoring This section contains the vibration monitoring, shaft voltage monitoring, and shell expansion monitoring equipment. 18. Supervisory Instruments This section contains steam turbine vibration monitoring probes and vibration monitoring O&M Manual. 19. Generator This section contains the generator operating recommendations, electrical and mechanical drawings, descriptive GEK’s, and generator expected operating data. 20. Generator Excitation This section contains the excitation control equipment, supporting transformer and compartment information. 21. Generator Control Panel This section contains the equipment included in the generator protection panel, which may include, but is not limited to the following components: •

Various Relays

•

Current Transformers

•

Voltage Transformers

•

Disconnect switches

•

Alarm Panels

22. Accessory Compartments This section contains the equipment required to support operation of the generator, which may include, but are not limited to the following components: •

16

Various transformers © 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

Customer O&M Manual Users Guide

•

GEK 116811a

Excitation compartment

23. Gas Control and Monitoring System This section contains the generator hydrogen cooling system drawings, monitoring equipment and O&M Manual for components consisting of: •

Hydrogen Control Manifolds and Valves

•

Hydrogen Monitoring Panel

•

Piping and Instrumentation

24. Seal Oil System This section contains the steam turbine seal oil system drawings, O&M Manual for components consisting of: •

Hydrogen Seals

•

Regulating Valves

•

Piping and Instrumentation

25. Technical Information Letters The Technical Information Letters Section is the same as defined in section 2.2.15 26. Bills of Material and Drawings The Bills of Material and Drawings Section is the same as defined in section 2.2.16.

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

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GEK 116811a

Customer O&M Manual Users Guide

III. EXAMPLES FOR LOCATING INFORMATION A. Locating Component Tab To locate information on your gas turbine’s main lube oil pump. First look in the volume Table of Contents (found in the front of every volume) you will find that Lubrication System information is in Tab 14 (this tab location for the Lubrication System may vary). Then turn to Tab 14 and look at the Tab Table of Contents to find the instruction Manual for this pump. The Table of Contents functions as a broad general outline of the contents of the Manual set. It is constructed as a generic tool to lead you to a main system. When you have located the system you need, refer to the referenced tab number and volume. Look for your item in the Tab Table of Contents. Items will be listed by name and device symbol. Main Table Of Contents

18

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Customer O&M Manual Users Guide

GEK 116811a

B. Locating Component within Tab

The Tab Table of Contents is a precise, specific list of all documentation included in a particular tab. The Tab Table of Contents for any turbine system, like the Lubrication System in our example above, will always list the system text first, followed by the system schematic. Following this information is an item number arranged list of all major devices (filters, motors, pumps, etc.) and their publication number. These publications can be found directly behind the Tab Table of Contents. If you needed to find information on the lube oil pump, the main Table of Contents would have directed you to the correct number tab. From the Tab Table of Contents you can look down the list of devices, locate the entry entitled “Main AC Lube Oil Pump Assembly,” and see that Buffalo Forge publication “Buff Pumps_3382GE-Heb” covers this pump. This publication can be found in this tab. © 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

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GEK 116811a

Customer O&M Manual Users Guide

C. Using the Bill of Materials and Drawings Tab This section contains bills of materials and drawings. 1. Bills of Material The Bills of Material and Drawings Section (BOM&D) is designed to provide “project specific” information in support of the documents contained in the O&M Manual. It contains the Bills of Material (BOMs) and Assembly Drawings issued for each project as reference information for field maintenance activities. As an example, the BOM&D is used to locate and identify parts needed to plan for and perform equipment maintenance. This Bill of Materials has Part number 10 Highlighted.

20

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Customer O&M Manual Users Guide

GEK 116811a

2. Drawings The Tag number corresponds to a number, which identifies the component on the drawing, in this case the number 10, for part number 10.

D. Access to Online O&M Manuals The O&M Manual may also be accessed on-line at www.gepower.com, under Technical Library select “Technical Manuals”. CD/DVD and/or hardcopy formats are also provided depending on contractual requirements. To access the on-line version you must first obtain a Single Sign On ID (SSO ID). The URL address in item 1 provides the link to request an SSO ID. The URL address in item 2 provides the link to the online Technical Manual application. 1. Use this URL for an SSO ID request: http://www.gepower.com/online_tools/downloads/how_to_register_SSO.pdf http://www.gepower.com/about/suppliers/en/index.htm © 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

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GEK 116811a

Customer O&M Manual Users Guide

2. For direct access, the URL for the on-line Technical Manual application is: http://www.gepower.com/online_tools/tech_manuals.htm. E. Fully Engineered Quote (FEQ) GE Energy Services has provided to the owner/operator, under separate cover, a “Spare Parts Recommendation” including price and delivery cycle data for this project. That listing was provided to allow the equipment owner/operator to select specific spare parts to be provided by GE. The GE Energy Services Spare Parts Recommendation included in the GE O&M Manuals is a coordinated listing, however not including pricing or delivery cycle data. This “coordinated copy” of the original Spare Parts Recommendation from GE Energy Services is titled “Spare Parts Recommendation (Not priced)” and is provided for reference only. It can be used in conjunction with maintenance activities described in the GE O&M Manuals. This Spare Parts Recommendation is based on the AS SHIPPED configuration of the unit(s). Any changes made to the unit(s) after shipment are NOT reflected. For Material Ship Direct (MSD) items listed in the section labeled “MSD Waiting Definition”, the spare parts lists were not available at the time the GE Energy Services Spare Parts Recommendation was prepared. For those items, Users can refer to the appropriate tab in the O&M volume of the comprehensive set of GE O&M Manuals. For additional questions related to Spare Parts contact your local GE Representative. The Fully Engineered Quote (FEQ) is the GE Energy Services Spare Parts Recommendations, for either the gas turbine and generator or the steam turbine and generator. For the steam turbine it is located in the turbine maintenance section, for the gas turbine it is located in the gas turbine section.

22

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Customer O&M Manual Users Guide

GEK 116811a

THIS PAGE INTENTIONALLY LEFT BLANK

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

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Customer O&M Manual Users Guide

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GE Energy General Electric Company www.ge-energy.com

24

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

g

GEK 103591c Revised, May 2012

GE Energy

Technical Communications

These instructions do not purport to cover all details or variations in equipment nor to provide for every possible contingency to be met in connection with installation, operation or maintenance. Should further information be desired or should particular problems arise which are not covered sufficiently for the purchaser's purposes the matter should be referred to General Electric Company. These instructions contain proprietary information of General Electric Company, and are furnished to its customer solely to assist that customer in the installation, testing, operation, and/or maintenance of the equipment described. This document shall not be reproduced in whole or in part nor shall its contents be disclosed to any third party without the written approval of General Electric Company. © 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

GEK 103591c

Technical Communications

The following notices will be found throughout this publication. It is important that the significance of each is thoroughly understood by those using this document. The definitions are as follows: NOTE Highlights an essential element of a procedure to assure correctness. CAUTION Indicates a potentially hazardous situation, which, if not avoided, could result in minor or moderate injury or equipment damage.

WARNING INDICATES A POTENTIALLY HAZARDOUS SITUATION, WHICH, IF NOT AVOIDED, COULD RESULT IN DEATH OR SERIOUS INJURY

***DANGER*** INDICATES AN IMMINENTLY HAZARDOUS SITUATION, WHICH, IF NOT AVOIDED WILL RESULT IN DEATH OR SERIOUS INJURY.

2

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

Technical Communications

GEK 103591c

TABLE OF CONTENTS I. II.

GENERAL ................................................................................................................................................... 4 SELF SERVICE AND CONTROLS CONNECT INSTRUCTIONS ..................................................... 5

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

3

GEK 103591c

Technical Communications

I. GENERAL Technical communications are issued periodically to GE turbine and generator users and service personnel to provide updated information on the operation and maintenance of the GE supplied equipment. These communications include Technical Information Letters (TILs) and are GE’s way of telling their customers about technical improvements, maintenance practices, or safety concerns regarding GE supplied equipment. Many of GE’s customers prefer to have TILs that affect their units directly emailed to them. GE maintains a database of these customers’ email addresses and the appropriate TILs are emailed to the customers when published. TIL distribution will be made by electronic email distribution. Equipment owners will need to register for TIL distribution via Self Service or Controls Connect page at www.ge-energy.com. A direct link to the Controls Connect and Self Service website is provided below.

http://www.ge-energy.com/tools_and_training/tools/controls_connect.jsp Detailed instructions on how to register and utilize this new functionality are included in the pages that follow. GE is committed to providing every customer with the TILs that affect their sites. When a TIL is issued that affects your turbine or generator, that TIL is promptly emailed to the address listed for that unit that is contained in the GE database. Information provided as part of the Technical Communications registration will be used for the process of distributing TILs and will be stored on a secure server in compliance with GE Energy data storage policy.

4

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

Technical Communications

GEK 103591c

II. SELF SERVICE AND CONTROLS CONNECT INSTRUCTIONS Self Service and Controls Connect is accessed through http://www.ge-energy.com/ or directly though the link below:

http://www.ge-energy.com/tools_and_training/tools/controls_connect.jsp

Self Service and Controls Connect requires an SSO login in order to access the application. Once at this page, you will need to login with your SSO or register for an SSO if you do not have one.

Accept the Legal Notices by selecting OK

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

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GEK 103591c

Technical Communications

Self Service landing page Viewing TILs In order to view your unit specific TILs, you will need to associate at least one site to your profile. Select My Profile. TILs are associated to sites and you will need to add sites using the available sites tab. For best results, search by unit serial number. You will only be able to see sites that are associated to your SSO.

NOTE TIL search may also return TILs with “Obsolete” status. These TILs have either been superseded by a revision, or made obsolete by Product Service.

6

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

Technical Communications

GEK 103591c

Once a site is associated to My Profile, it will show up under My Sites. If multiple sites are selected, technical communications from all the sites will return in the knowledge management section of the Self Service tool.

Select Home to return to the Self Service landing page. TILs can be viewed via two methods: Method 1 1.

Enter the TIL number into the search bar and select search

2.

The knowledge base will return the TIL document as well as all knowledge objects referencing that content. Alternately, a topic can be searched with the term TIL in the search bar and related TILs to that topic that will return. Only TILs applicable to the sites in your profile will return. If no sites are associated, no TILs will return.

TIL 1725 – TIL Distribution

3.

By selecting My TILs in the content areas in the center of the page, TILs can be browsed that are applicable to the site(s) in My Profile.

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

7

GEK 103591c

Technical Communications

Method 2 1.

Select the Technical Communications link under the Related Tools menu on the right side of the webpage.

2.

Pick one of the three searches: a.

Searching by TIL number will return a list of TILs that meet that criterion. You can then select a TIL number and see the units which the TIL applies to.

b.

Searching by unit serial number will return the TILs that apply to that unit

c.

Searching by the search criteria will return TILs that meet the searched upon criteria. Registering for TILs

TIL distribution will be made by electronic email distribution. Equipment users will need to register for TIL distribution via Self Service or Controls Connect by selecting the Technical Communications link under the Related Tools menu on the right side of the webpage.

8

1.

Select the Technical Communications link under the Related Tools menu on the right side of the webpage.

2.

Select the TIL Registration link in the header bar

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

Technical Communications

3.

4.

GEK 103591c

Search by the desired method to see the site you wish to register with. You will only be able to see sites associated with your SSO. a.

Searching by Customer and Site Station Name will take you to that site

b.

Searching by Unit Serial # will show a list of email addresses against that serial number

c.

Searching by Email Address will show you all the units associated with that email address.

Update the distribution information by: a.

Selecting Add New User

b.

Adding or removing units and selecting Update

c.

Selecting the check box and selecting Delete i.

You will only be able to delete your individual profile

ii.

Contact a GE representative to update other profile information.

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

9

GEK 103591c

Technical Communications

Knowledge Base The Knowledge Base is a continually evolving resource which contains information from the technical manuals, TILs, FAQs and other GE content. We are continually adding and updating content to the system. The Knowledge Base is intended to provide GE customers and internal personnel with instantaneous access to information about their equipment. You have the option to switch your edition back and forth between Controls Connect and Self-Service micro sites. This feature is available on the home page of the web site only. Self-Service includes all the content within Controls content but also contains content that covers GE Gas Turbines, Steam Turbines and Generators. Controls Connect is a micro site specifically dedicated to delivered a tailored service experience for GE Controls products and services. The content is filtered to be Controls product content relevant allowing the user to see only Controls product content.

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GE Energy General Electric Company www.ge-energy.com

10

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

Rev B

Released 8/8/2013

Page 1 of 4

8

7

NOTES: 1 2 3

H

THE TERM “OTHERS” USED ON THIS DRAWING IS DEFINED AS THE PLANT DESIGNER AND/OR PLANT INSTALLER. DATA CELLS POPULATED WITH THREE DASHES (---) INDICATE THAT THIS FIELD IS NOT APPLICABLE TO THE FLUID TYPE OR CONNECTION. UNITS ARE AS SPECIFIED IN COLUMN HEADING UNLESS OTHERWISE SPECIFIED WITHIN A CELL.

LO19 IS A LUBE MIST VENT MOUNTED ON THE ROOF OF THE A160 MODULE AND REQUIRES NO INTERFACE BY OTHERS. HOWEVER, THIS CONNECTION IS A POTENTIAL SOURCE OF FLAMMABLE ATMOSPHERE. THE EXTENT OF THE HAZARDOUS AREA AND OTHER INFORMATION AND RECOMMENDATIONS TO ASSIST OTHERS IS GIVEN IN MLI 0331. MLI 0417

5

G 6

7

8

F 9

INSTRUMENT AIR MUST BE PROVIDED IN ACCORDANCE WITH INSTRUMENT AIR REQUIREMENTS INCLUDED IN MLI 0438 AND SIZED CONSIDERING THE FOLLOWING CONDITIONS: A) TURBINE START-UP CONDITION: -TRANSIENT: NO FLOW -STEADY STATE: NO FLOW B) TURBINE OPERATION CONDITION (FULL SPEED, NO LOAD): -TRANSIENT: FLOW REQUIRED WHEN MAIN BREAKER IS CLOSED. AIR IS NEEDED FOR ONLY 5 SECONDS. -STEADY STATE: NO FLOW C) TURBINE SHUT DOWN CONDITION: -TRANSIENT: NO FLOW -STEADY STATE: NO FLOW THE DESIGN PRESSURES AND TEMPERATURES ARE THE CONDITIONS UPSTREAM OF THE ISOLATION VALVES. PIPING DOWNSTREAM OF CLOSED ISOLATION VALVES WILL NOT NORMALLY BE SUBJECTED TO THESE CONDITIONS. THESE VALVES MUST ONLY BE OPEN DURING AN OFF-LINE WATER WASH. PIPING AT THESE CONNECTION POINTS MUST BE DESIGNED TO THE DESIGN PRESSURE LISTED IN CASE A VALVE IS LEFT IN THE OPEN POSITION. DESIGN PRESSURE AND TEMPERATURE VALUES DO NOT OCCUR AT THE SAME TIME DURING UNIT OPERATION. DESIGN PRESSURE WILL OCCUR WHEN THE TEMPERATURE IS 647°F [342°C]. DESIGN TEMPERATURE WILL OCCUR WHEN THE PRESSURE IS 186 PSIG [1280 KPAG]. CA52 DESIGN PRESSURE AND TEMPERATURE VALUES DO NOT OCCUR AT THE SAME TIME DURING UNIT OPERATION. DESIGN PRESSURE WILL OCCUR WHEN THE TEMPERATURE IS 463°F [240°C]. DESIGN TEMPERATURE WILL OCCUR WHEN THE PRESSURE IS 66 PSIG [455 KPAG]. CA53 DESIGN PRESSURE AND TEMPERATURE VALUES DO NOT OCCUR AT THE SAME TIME DURING UNIT OPERATION. DESIGN PRESSURE WILL OCCUR WHEN THE TEMPERATURE IS 463°F [240°C]. DESIGN TEMPERATURE WILL OCCUR WHEN THE PRESSURE IS 115 PSIG [793 KPAG]. MLI 0419

10 ALLOWABLE PRESSURE DROP IN THE INTERCONNECT PIPING BY OTHERS IS LESS THAN OR EQUAL TO 10 PSID [68.9 KPAD]. MLI 0420

E

11 GE SUPPLIED EQUIPMENT PRESSURE DROPS: COOLING WATER LOCATION PRESSURE DROP LUBE OIL COOLER (CW6 -CW7) 20 PSID [138 KPAD] GENERATOR (CW12 - CW13) 8 PSID [55.2 KPAD] TURBINE BASE (CW52 - CW53) 20 PSID [138 KPAD] LCI COOLER (CW94 - CW95) 4.7 PSID [32.4 KPAD] 12 GAS TURBINE HEAT REJECTION: COOLING WATER LOCATION TURBINE BASE (CW52 - CW53) LUBE OIL COOLER (CW6 - CW7) LCI COOLER (CW94 - CW95) 13 GENERATOR HEAT LOADS: GENERATOR HEAT REJECTION COOLANT INLET TEMPERATURE 79°F [26°C] 104°F [40°C] 115°F [46°C]

D

HEAT REJECTION BTU/MIN [KW] 500 [8.78] 145000 [2550] 5800 [102]

3

25 AT FG1 START-UP MODE GAS TEMPERATURE MAX: 350°F [177°C] MIN: 50°F [10°C] SUPERHEAT

SIZE

E

DWG. NO.

THIS DOCUMENT SHALL BE REVISED IN ITS ENTIRETY. ALL SHEETS OF THIS DOCUMENT ARE THE SAME REVISION LEVEL AS INDICATED.

MLI 0477

NORMAL OPERATING GAS TEMPERATURE: 295°F [146°C]

2

MLI 4035

STARTUP AND OPERATION IN DIFFUSION MODE - DIFFUSION NOZZLE ONLY. EITHER HEATED OR UNHEATED FUEL MAY BE USED. IF FUEL HEATING BECOMES UNAVAILABLE, THE UNIT OPERATION ABOVE DIFFUSION MODE POTENTIALLY WILL BE LIMITED BY LOAD OUTPUT, COMBUSTOR DYNAMICS, OR EMISSIONS.

-DURING TURBINE OPERATION FUEL GAS PRESSURE TO BE REGULATED BETWEEN 410 PSIG [2830 KPAG] AND 500 PSIG [3450 KPAG]. -STEADY-STATE: SUPPLY PRESSURE AT ANY OPERATING POINT WITHIN THE GAS TURBINE CAPABILITY MUST BE REGULATED WITHIN +/- 1% OF POINT, WITH PEAK-TO-PEAK PERIOD OF NOT LESS THAN 8 SECONDS (0.25% PER SECOND AVERAGE RATE OF CHANGE). -TRANSIENT: DURING TRANSIENTS MAXIMUM SUPPLY PRESSURE EXCURSIONS MUST NOT EXCEED EITHER A 1% PER SECOND RAMP OR 5% STEP. THE 1% PER SECOND RAMP LIMIT IS APPLICABLE OVER THE RANGE OF MINIMUM REQUIRED PRESSURE TO MAXIMUM OPERATION PRESSURE. THE 5% STEP LIMIT IS APPLICABLE OVER THE RANGE OF MINIMUM REQUIRED PRESSURE TO 95% OF MAXIMUM OPERATING PRESSURE AND WITH NO MORE THAN ONE 5% STEP CHANGE IN 5 SECONDS. THESE TRANSIENT LIMITS APPLY DURING BRIEF PERIODS ASSOCIATED WITH PRESSURE CONTROL MODE TRANSFERS SUCH AS BETWEEN GAS FUEL PRESSURE SOURCE CHANGEOVERS, OR RAPID FUEL DEMAND TRANSIENTS SUCH AS GAS TURBINE LOAD REJECTIONS.

(CW12 - CW13, ALL COOLERS) BTU/MIN [KW] 161000 [2830] 139000 [2450] 119000 [2090]

B

1 DATE

APPROVED

A

B

SH1,2 & 3: REVISION LEVEL UPDATE ONLY. SH4: ADDED CONNECTIONS WW121 & WW122 ECR0030642 ECO0114464 P.SANTHIYAGU

H

13-08-07 SEE PLM

G

27 INSTRUMENT AIR TO BE SUPPLIED BY OTHERS, MUST BE IN ACCORDANCE WITH GEK 110727, (MLI 0438). AIR SUPPLY REQUIRED TO BE SUPPLIED PRIOR TO STARTUP OF TURBINE. DESIGN FLOW IS 0.04 PPS [0.02 KG/S] 10 SECONDS TRANSIENT AND 0.01 PPS [0.006 KG/S] STEADY STATE. MINIMUM PRESSURE IS 90 PSIG [620 KPAG]. 28 MINIMUM PRESSURE AT FG21 IS BASED ON DOWNSTREAM FUEL GAS CONDITIONING EQUIPMENT AND ASSUMED INTERCONNECT PIPING PRESSURE LOSSES AT THE MAXIMUM FLOW RATE BETWEEN FG21 AND FG1. ACTUAL PIPING PRESSURE LOSSES BETWEEN FG21 AND FG1 MUST BE DEFINED AND ACCOUNTED FOR BY OTHERS. REFER TO MLI 0482 FOR A LIST OF ADDITIONAL DOWNSTREAM EQUIPMENT.

F

MLI 0426 29 DESIGN FLOW RANGE BASED ON MINIMUM AND MAXIMUM FIELD RANGE EQUIVALENT LENGTHS. INTERCONNECT PIPING MUST BE DESIGNED PER THE INTERCONNECT PIPING DATA TABLE ON MLI 0426 DRAWING. 30 THE FLOW RATE THROUGH MANIFOLD CONNECTIONS NN7 AND NN8 IS BASED ON THE CAPACITY OF THE CO2 TANKER FILLING PUMP. FLOW RATE NORMALLY RANGES FROM 44.1 TO 51.5 PPS [20.0 TO 23.4 KG/S] FOR NN7 AND 0.076 TO 0.089 PPS [0.034 TO 0.040 KG/S] FOR NN8. THE FILLING PRESSURE TYPICALLY RANGES FROM 220 TO 250 PSIG [1520 TO 1720 KPAG] . THE VAPOR CONNECTION NN8 MUST RETURN A VOLUME OF VAPOR EQUIVALENT TO THE VOLUME OF LIQUID PUT INTO THE TANK. 31 THE CO2 STORAGE SYSTEM IS A VENDOR DESIGNED SKID MOUNTED SUPPLY AND DISTRIBUTION SYSTEM WITH A CAPACITY OF 12000 LB [5440 KG]. PIPING DETAILS ARE GENERIC AND CAN VARY BASED ON SUPPLIER DESIGN. SYSTEM DESIGN PRESSURE AND TEMPERATURE IS 325 PSIG[2240 KPAG]. 32 DESIGN CONDITIONS DO NOT OCCUR AT THE SAME TIME. DESIGN TEMPERATURE OCCURS AT 14.7 PSIG [101 KPAG], WHILE DESIGN PRESSURE AND FLOW OCCUR AT 60°F [15.6°C].

E

MLI 0442

14 COOLANT SYSTEM EQUIPMENT IS DESIGNED TO OPERATE WITH THE FOLLOWING COOLANT: 100% WATER WITH ADDITIVES

17 IT IS RECOMMENDED THAT THE PIPING ARRANGMENT DEPICTED BELOW IS USED FOR INTERCONNECTION OF THE GAS TURBINE EQUIPMENT. OTHER PIPING CONFIGURATIONS MAY BE POSSIBLE. OTHERS MUST ADD THROTTLING VALVES AND FLOW MEASURING ORIFICES TO ACHIEVE THE STATED FLOW RATES. COOLING WATER SUPPLY TO CW12 AND CW94 THEN TO CW6 AND CW52 THEN TO COOLING WATER RETURN 18 DURING SYSTEM BALANCING, THE LUBE OIL TEMPERATURE CONTROL VALVE, VA32-1, SHALL BE FORCED TO FULL OPEN. NORMAL CONTROL SHALL BE RETURNED AFTER COMPLETION OF SYSTEM BALANCING. 19 INTERCONNECT PIPING PRESSURE DROP MUST BE LESS THAN OR EQUAL TO 10 PSID [68.9 KPAD). MLI 0422 20 NATURAL GAS LHV: 940.1 BTU/SCFT [35.03 MJ/SCM] , 21162 BTU/LB [49.22 MJ/KG]. 21 OTHERS MUST PROVIDE A PRESSURE RELIEVING DEVICE IN THE FUEL GAS SUPPLY PIPING UPSTREAM OF FG1 IN ACCORDANCE WITH ASME B31.3 AND CONSTANT WITH A DESIGN PRESSURE OF 550 PSIG [3790 KPAG]. 22 FG2, FG3, AND FG439 ARE A POTENTIAL SOURCE OF FLAMMABLE ATMOSPHERE. THE EXTENT OF THE HAZARDOUS AREA, OTHER INFORMATION, AND RECOMMENDATIONS TO ASSIST OTHERS ARE GIVEN IN MLI 0331. 23 PRESSURE DROP FROM FG20 TO FG21 IS 5 PSID [34.5 KPAD] MAXIMUM. 24 REFER TO MLI 0331, HAZARDOUS AREA MAP AND NOTES FOR INFORMATION ON HAZARDOUS AREAS AND RATINGS OF GE SUPPLIED EQUIPMENT. IT IS THE RESPONSIBILITY OF OTHERS TO CARRY OUT ANY NECESSARY FURTHER POWER PLANT HAZARDOUS AREA CLASSIFICATION STUDIES AND TO DESIGN AND INSTALL THE PIPING AND EQUIPMENT IN ACCORDANCE WITH APPLICABLE SAFETY CODES AND STANDARDS. GUIDANCE AND INFORMATION IS GIVEN IN MLI 0331 TO ASSIST OTHERS IN THIS TASK.

34 WATER WASH NORMAL OPERATING CONDITIONS AS FOLLOWS: OFF-LINE: NORMAL PRESSURE = 95 PSIG [655 KPAG] NORMAL TEMPERATURE = 50 TO 180°F [10 TO 82.2°C] FLOW RATE = 58.5 USGPM [221 LPM] ONLINE: NORMAL PRESSURE = 90 PSIG [621 KPAG] NORMAL TEMPERATURE = 50 TO 180°F [10 TO 82.2°C] FLOW RATE 13 = USGPM [49.2 LPM] 35 INSTRUMENT AIR NORMAL FLOW REFERS TO LEAKAGE IN SOLENOIDS (NEGLIGIBLE IN THIS CASE). DESIGN FLOW REFERS TO RE-OCCURRING MAXIMUM TRANSIENT FLOW RATE THROUGH SOLENOIDS (DURATION NOT TO EXCEED 5 SECONDS PER OCCURRENCE). 36 INTERFACE CONNECTION DESIGN REQUIREMENTS APPLY TO WATER WASH SYSTEM OPERATION ONLY. 37 MAXIMUM PRESSURE FOR WW19 AND WW1 ARE BASED ON 150# FLANGE RATINGS. 38 DRAIN FLOWS (TANKS AND/OR FLOOR DRAINS) ARE INTERMITTENT. 39 MAXIMUM ALLOWABLE PRESSURE DROP BETWEEN WW20 AND WW1 IS 10 PSID [68.9 KPAD].

D

MLI 0471 40 PRESSURE DROP IN INTERCONNECT PIPING MUST NOT EXCEED 4 PSID [27.6 KPAD]. 41 DESIGN PRESSURE AND TEMPERATURE VALUES ARE NOT CONCURRENT OPERATING VALUES. DESIGN PRESSURE WILL OCCUR WHEN THE TEMPERATURE IS 647°F [342°C]. DESIGN TEMPERATURE WILL OCCUR WHEN THE PRESSURE IS 186 PSIG [1280 KPAG]. 42 EVAPORATIVE COOLER SUPPLY FLOWS REPRESENT A MAXIMUM TEMPERATURE OF 120°F [48.9°C], 10% RH DAY (90% NOMINAL EFFICIENCY) AND TWO CYCLES OF CONCENTRAION (BLOW DOWN RATE = EVAPORATIVE RATE). PIPING BY OTHERS MUST BE SIZED TO OTHERS MAXIMUM EVAPORATIVE COOLER FLOWS. 43 SUPPLIED LINES BY OTHERS MUST NOT BE REDUCED AND MUST ALLOW UNRESTRICED FLOW FOR THIS GRAVITY DRAIN. THE LOOP (TRAP) SEAL MUST BE DESIGNED FOR A MINIMUM BACK PRESSURE OF 12 INCHES [305 MM] OF WATER (MINIMUM 12 INCH [305 MM] TRAP) 44 IE7 MAXIMUM FLOW BASED ON INSTANT OF EVAPORATIVE COOLER SHUTDOWN WITH MEDIA DRAINING AND MAKEUP WATER VALVE (IE5) LOCKED OPEN AT MAXIMUM SUPPLY PRESSURE. 45 MAXIMUM DEWPOINT = -40°F [-40°C] 46 MAKEUP WATER AND THE RESULTING SUMP MUST BE IN COMPLIANCE WITH THE LATEST REVISION OF GEK 107158 WITH A MINIMUM OF TWO CYCLES OF CONCENTRATION. MAKEUP WATER THAT REQUIRES LESS THAN TWO CYCLES OF CONCENTRATION TO MEET THE REQUIREMENTS OF GEK 107158 IS UNACCEPTABLE.

C

B

MLI 0474 47 INSTRUMENT AIR, SUPPLIED BY OTHERS, MUST BE IN ACCORDANCE WITH PLANT INSTRUMENT AIR SYSTEM REQUIREMENTS INCLUDED IN MLI 0438. AIR SUPPLY REQUIRED TO BE SUPPLIED PRIOR TO STARTUP OF TURBINE. DESIGN FLOW PER CONNECTION IS 0.62 CFH [0.017 M^3/H]; MINIMUM PRESSURE IS 90 PSIG [621 KPAG]. 48 MAINTENANCE OF INSTRUMENT AIR AT STATED FLOW/PRESSURE CRITICAL FOR TURBINE OPERATION; THESE CONNECTIONS PROVIDE MOTIVE AIR FOR TURBINE SAFETY CRITICAL SYSTEM THAT MAY RESULT IN TRIP IF AIR IS NOT PROVIDED.

A

1 IT.

SIGNATURES

DATE

JURADO, ARTURO

12-11-05

UNLESS OTHERWISE SPECIFIED DRAWN

DIMENSIONS ARE IN INCHES

© COPYRIGHT 2012 -2013 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. ALL RIGHTS RESERVED. THE INFORMATION CONTAINED HEREIN IS GE ENERGY GAS TURBINE PROPRIETARY TECHNICAL INFORMATION THAT BELONGS TO THE GENERAL ELECTRIC COMPANY, GE ENERGY (USA), LLC AND/OR THEIR AFFILIATES, WHICH HAS

TOLERANCES ON 2 PL DECIMALS ± 3 PL DECIMALS ± ANGLES ± FRACTIONS ±

CHECKED

SEE PLM

12-11-05

LANPHER, NATHAN

12-11-05

ENGRG

ISSUED

SEE PLM

FIRST MADE FOR: ML-9K1WFA163-1 SIZE

NO DUPLICATION, OR OTHER DISCLOSURE, OR USE WHATSOEVER FOR ANY, OR ALL SUCH INFORMATION EXCEPT AS EXPRESSLY AUTHORIZED IN WRITING BY THE GENERAL SIM TO:

ELECTRIC COMPANY, GE ENERGY (USA), LLC AND/OR ITS AFFILIATES.

6

5

4

3

GENERAL ELECTRIC COMPANY GAS TURBINE

GE Energy

Connection & Line List, Customer Interface

12-11-05

ALL PERSONS, FIRMS, OR CORPORATIONS WHO RECEIVE SUCH INFORMATION SHALL BE DEEMED BY THE ACT OF THEIR RECEIVING THE SAME TO HAVE AGREED TO MAKE

THIRD ANGLE PROJECTION

g

QUALITY

BEEN PROVIDED SOLELY FOR THE EXPRESS REASON OF RESTRICTED PRIVATE USE.

7

SPEC, SCHEMATICS AND DIAGRAMS 372A3671 IDENT NOMENCLATURE LIST OF COMPLEMENTARY DOCUMENTS

GE CLASS II (INTERNAL NON-CRITICAL)

49 INSTRUMENT AIR REQUIREMENTS ARE INCLUDED IN MLI 0438. INSTRUMENT AIR MINIMUM PRESSURE MUST BE 90 PSIG [621 KPAG].

8

REV.

SH1: UPDATED NOTES 20 AND 25. SH2 AND SH3: UPDATED MAXIMUM TEMPERATURE FOR FG1/FG20 AND MIN/MAX TEMPERATURE 12-12-17 SEE PLM FOR FG21/FG425/FG426/FG428 A&B/FG438/ FG439. SH4: REVISION LEVEL UPDATE ONLY - NO CHANGE. ECR0019317 ECO0085113 LIÑAN, CLAUDIA

51 REFER TO MLI 0331, HAZARDOUS AREA MAP AND NOTES FOR INFORMATION ON HAZARDOUS AREAS AND RATINGS OF GE SUPPLIED EQUIPMENT. IT IS THE RESPONSIBILITY OF OTHERS TO CARRY OUT ANY NECESSARY FURTHER POWER PLANT HAZARDOUS AREA CLASSIFICATION STUDIES AND TO DESIGN AND INSTALL THE PIPING AND EQUIPMENT IN ACCORDANCE WITH APPLICABLE SAFETY CODES AND STANDARDS. GUIDANCE AND INFORMATION IS GIVEN IN MLI 0331 TO ASSIST OTHERS IN THIS TASK.

26 PRESSURE REGULATION AND CONTROL AT FG1:

1

REVISIONS DESCRIPTION

REV

50 THIS CONNECTION IS A POTENTIAL SOURCE OF FLAMMABLE ATMOSPHERE. THE EXTENT OF THE HAZARDOUS AREA AND OTHER INFORMATION AND RECOMMENDATIONS TO ASSIST OTHERS ARE GIVEN IN MLI 0331.

MIN SUPERHEAT TEMPERATURE MUST COMPLY WITH THE REQUIREMENTS STATED IN GEI 41040. THE MAXIMUM RATE OF GAS TEMPERATURE CHANGE IS 2 F/SEC [1.1 C/SEC].

SH.

145E4535

MLI 0432

16 CONTINUOUS FLOW REQUIRED DURING GAS TURBINE/ GENERATOR OPERATION TO PREVENT AIR ACCUMULATION.

B

4

33 DESIGN PRESSURE AND TEMPERATURE VALUES ARE NOT CONCURRENT OPERATING VALUES. DESIGN PRESSURE WILL OCCUR WHEN THE TEMPERATURE IS 647°F [342°C]. DESIGN TEMPERATURE WILL OCCUR WHEN THE PRESSURE IS 186 PSIG [1280 KPAG].

15 APPROXIMATE SYSTEM COOLANT CAPACITY EXCLUDING FIELD PIPING SUPPLIED BY OTHERS IS 600 U.S. GALLONS [2270 LITERS]. (REFER TO INTERFACE TABLE ON THIS DOCUMENT FOR ACTUAL MAXIMUMS.)

C

5

NOTES:

MLI 0416 4

6

2

NONE

E

CAGE CODE

DWG NO

4063

145E4535

SCALE

A

SHEET

1 of 4

DISTR TO

DWG Number 145E4535

1 GE Proprietary Information - Class II (Internal) US EAR - NLR

Rev B

Released 8/8/2013

Page 2 of 4

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5

CONNECTION NAME

MLI

SHEET & ZONE

FLUID TYPE

INTERFACE TYPE

CONNECTION DESCRIPTION

NORMAL PRESSURE PSIG [KPAG]

LO1

0416

SH 2 B8

OIL

GEE-OTHERS

OIL TANK FILL / RETURN FROM LUBE OIL CONDITIONER

LO2

0416

SH 2 A1

OIL

GEE-OTHERS

LUBE OIL TANK DRAIN

LO13A

0416

SH 2 D1

OIL / WATER

GEE-OTHERS

4

3

2

SIZE

E

DWG. NO.

145E4535

NORMAL TEMPERATURE °F [°C]

NORMAL FLOW USGPM [LPM]

MINIMUM PRESSURE PSIG [KPAG]

MINIMUM TEMPERATURE °F [°C]

MINIMUM FLOW USGPM [LPM]

MAXIMUM PRESSURE PSIG [KPAG]

MAXIMUM TEMPERATURE °F [°C]

MAXIMUM FLOW USGPM [LPM]

DESIGN PRESSURE PSIG [KPAG]

DESIGN TEMPERATURE °F [°C]

DESIGN FLOW USGPM [LPM]

NOTES

0 [0]

180 [82]

10 [38]

---

---

---

---

---

---

150 [1030]

225 [107]

200 [757]

---

0 [0]

AMBIENT

0 [0]

---

---

---

---

---

---

2 [13.8]

225 [107]

18 [68.1]

---

ACCESSORY COMPARTMENT FLOOR DRAINS

0 [0]

130 [54]

0 [0]

---

---

---

---

---

---

2 [13.8]

225 [107]

3 [11.4]

---

LO13B

0416

SH 2 C1

OIL / WATER

GEE-OTHERS

ACCESSORY COMPARTMENT FLOOR DRAINS

0 [0]

130 [54]

0 [0]

---

---

---

---

---

---

2 [13.8]

225 [107]

3 [11.4]

---

LO13C

0416

SH 2 C1

OIL / WATER

GEE-OTHERS

ACCESSORY COMPARTMENT FLOOR DRAINS

0 [0]

130 [54]

0 [0]

---

---

---

---

---

---

2 [13.8]

225 [107]

3 [11.4]

---

LO13D

0416

SH 2 C1

OIL / WATER

GEE-OTHERS

ACCESSORY COMPARTMENT FLOOR DRAINS

0 [0]

130 [54]

0 [0]

---

---

---

---

---

---

2 [13.8]

225 [107]

3 [11.4]

---

LO13E

0416

SH 2 B1

OIL / WATER

GEE-OTHERS

ACCESSORY COMPARTMENT FLOOR DRAINS

0 [0]

130 [54]

0 [0]

---

---

---

---

---

---

2 [13.8]

225 [107]

3 [11.4]

---

LO13F

0416

SH 2 B1

OIL / WATER

GEE-OTHERS

ACCESSORY COMPARTMENT FLOOR DRAINS

0 [0]

130 [54]

0 [0]

---

---

---

---

---

---

2 [13.8]

225 [107]

3 [11.4]

--SEE NOTE 4

LO19

0416

SH 2 H4

AIR / OIL VAPOR

GEE-OTHERS

VENT FROM LUBE OIL DEMISTER

0 [0]

180 [82]

200 TO 300 SCFM [5.7 TO 8.5 M^3/ MIN]

---

---

---

---

---

---

2 [13.8]

225 [107]

500 SCFM [14 M^3/MIN]

LO21

0416

SH 2 C8

OIL

GEE-OTHERS

LUBE OIL TO LUBE OIL CONDITIONER

0 [0]

180 [82]

10 [38]

---

---

---

---

---

---

2 [13.8]

225 [107]

20 [76]

---

LO125

0416

SH 3 D8

OIL

GEE-OTHERS

GENERATOR SEAL OIL SUPPLY - AT GENERATOR

100 [689]

130 [54]

18 [68.1]

---

---

---

---

---

---

150 [1030]

175 [79]

157 [594]

---

CA5

0417

SH 2 C6

AIR

GEE-OTHERS

AIR SUPPLY FOR SELF-CLEANING FILTERS

223 [1540]

754 [401]

---

---

---

---

---

---

252 [1740]

814 [434]

CA16

0417

SH 2 C5

AIR

GEE-OTHERS

INLET AIR HEATING

223 [1540]

754 [401]

---

---

---

---

---

---

252 [1740]

814 [434]

CA20

0417

SH 2 C5

WATER

GEE-OTHERS

LOW POINT DRAIN, INLET AIR HEATING PIPING

0 [0]

AMBIENT

0 [0]

---

---

---

---

---

---

252 [1740]

814 [434]

5 [19]

CA52A

0417

SH 2 E8

WATER

GEE-OTHERS

COMP ST9 LOW POINT WATER WASH DRAIN

0 [0]

AMBIENT

0 [0]

---

---

---

---

---

---

71 [490]

553 [290]

5 [19]

CA52B

0417

SH 2 D8

WATER

GEE-OTHERS

COMP ST9 LOW POINT WATER WASH DRAIN

0 [0]

AMBIENT

0 [0]

---

---

---

---

---

---

71 [490]

553 [290]

5 [19]

CA53A

0417

SH 2 E7

WATER

GEE-OTHERS

COMP ST13 LOW POINT WATER WASH DRAIN

0 [0]

AMBIENT

0 [0]

---

---

---

---

---

---

131 [903]

724 [385]

5 [19]

CA53B

0417

SH 2 D7

WATER

GEE-OTHERS

COMP ST13 LOW POINT WATER WASH DRAIN

0 [0]

AMBIENT

0 [0]

---

---

---

---

---

---

131 [903]

724 [385]

5 [19]

CA54

0417

SH 2 F5

WATER

GEE-OTHERS

LOW POINT WATER WASH DRAIN

0 [0]

AMBIENT

0 [0]

---

---

---

---

---

---

252 [1740]

814 [434]

5 [19]

CA60A

0417

SH 2 G1

AIR

GEE-OTHERS

90 [621]

AMBIENT

---

---

---

---

---

---

110 [758]

120 [48.9]

CA60B

0417

SH 2 F2

AIR

GEE-OTHERS

90 [621]

AMBIENT

---

---

---

---

---

---

110 [758]

120 [48.9]

CA64

0417

SH 4 G1

AIR

GEE-OTHERS

HEAT RATE CONTROL VALVE ACTUATION AIR

90 [621]

AMBIENT

---

---

---

---

---

---

110 [758]

120 [48.9]

CC3

0417

SH 4 H7

AIR

GEE-OTHERS

INSTRUMENT AIR TO CTM FLOW CONTROL VALVE

90 [621]

AMBIENT

---

---

---

---

---

---

110 [758]

120 [48.9]

COMPRESSOR BLEED EXTRACTION VALVE ACTUATION AIR COMPRESSOR BLEED EXTRACTION VALVE ACTUATION AIR

AP1

0419

SH 1 E7

AIR

GEE-OTHERS

COMPRESSED AIR INLET

223 [1540]

754 [401]

AP2

0419

SH 1 E2

AIR

GEE-OTHERS

COMPRESSED AIR OUTLET

100 [689]

145 [63]

AP3

0419

SH 1 D2

WATER

GEE-OTHERS

COALESCER PRE-FILTER DRAIN

0 [0]

AMBIENT

AP4

0419

SH 1 D2

WATER

GEE-OTHERS

WATER SEPARATOR DRAIN

0 [0]

CW6

0420

SH 2 C7

COOLANT

GEE-OTHERS

COOLING WATER TO LUBE OIL HEAT EXCHANGERS

CW7

0420

SH 2 C6

COOLANT

GEE-OTHERS

COOLING WATER FROM LUBE OIL HEAT EXCHANGERS

CW12A

0420

SH 3 F8

COOLANT

GEE-OTHERS

CW12B

0420

SH 3 F7

COOLANT

CW12C

0420

SH 3 F6

CW12D

0420

CW13A

0.24 PPS [0.11 KG/ S] 0 TO 32.7 PPS [0 TO 14.8 KG/S]

0.0004 PPS [0.0002 KG/S] 0.0004 PPS [0.0002 KG/S] 0.0004 PPS 0.0002 KG/S] 0.0004 PPS 0.0002 KG/S] 0.24 PPS [0.11 KG/ S] 0.20 PPS [0.09 KG/S]

0.24 PPS [0.11 KG/ S] 32.7 PPS [14.8KG/ S]

1

H

G

F

SEE NOTE 5 SEE NOTE 5 SEE NOTE 5 SEE NOTE 5

---

---

---

---

---

252 [1740]

814 [434]

---

---

---

---

---

104 [717]

145 [63]

0 [0]

---

---

---

---

---

---

2 [13.8]

131 [55]

0.5 [1.9]

---

AMBIENT

0 [0]

---

---

---

---

---

---

2 [13.8]

131 [55]

1.0 [3.8]

---

---

---

---

65 [448]

57.2 [14]

1000 [3790]

125 [862]

120 [49.1]

1000 [3790]

150 [1030]

200 [93]

1000 [3790]

---

---

---

---

65 [448]

57.2 [14]

1000 [3790]

125 [862]

138 [58.9]

1000 [3790]

150 [1030]

200 [93]

1000 [3790]

---

COOLING WATER TO GENERATOR COOLERS

---

---

---

65 [448]

57.2 [14]

675 [2560]

125 [862]

114.8 [46]

675 [2560]

150 [1030]

200 [93]

675 [2560]

---

GEE-OTHERS

COOLING WATER TO GENERATOR COOLERS

---

---

---

65 [448]

57.2 [14]

675 [2560]

125 [862]

114.8 [46]

675 [2560]

150 [1030]

200 [93]

675 [2560]

---

COOLANT

GEE-OTHERS

COOLING WATER TO GENERATOR COOLERS

---

---

---

65 [448]

57.2 [14]

675 [2560]

125 [862]

114.8 [46]

675 [2560]

150 [1030]

200 [93]

675 [2560]

---

SH 3 F6

COOLANT

GEE-OTHERS

COOLING WATER TO GENERATOR COOLERS

---

---

---

65 [448]

57.2 [14]

675 [2560]

125 [862]

114.8 [46]

675 [2560]

150 [1030]

200 [93]

675 [2560]

---

0420

SH 3 G8

COOLANT

GEE-OTHERS

COOLING WATER FROM GENERATOR COOLERS

---

---

---

65 [448]

57.2 [14]

675 [2560]

125 [862]

120 [49.0]

675 [2560]

150 [1030]

200 [93]

675 [2560]

---

SEE NOTE 10 ---

CW13B

0420

SH 2 G7

COOLANT

GEE-OTHERS

COOLING WATER FROM GENERATOR COOLERS

---

---

---

65 [448]

57.2 [14]

675 [2560]

125 [862]

120 [49.0]

675 [2560]

150 [1030]

200 [93]

675 [2560]

---

CW13C

0420

SH 2 G6

COOLANT

GEE-OTHERS

COOLING WATER FROM GENERATOR COOLERS

---

---

---

65 [448]

57.2 [14]

675 [2560]

125 [862]

120 [49.0]

675 [2560]

150 [1030]

200 [93]

675 [2560]

---

CW13D

0420

SH 2 G6

COOLANT

GEE-OTHERS

COOLING WATER FROM GENERATOR COOLERS

---

---

---

65 [448]

57.2 [14]

675 [2560]

125 [862]

120 [49.0]

675 [2560]

150 [1030]

200 [93]

675 [2560]

---

CW14A

0420

SH 3 G8

COOLANT

GEE-OTHERS

GENERATOR COOLER VENTS

---

---

---

0 [0]

57.2 [14]

0 [0]

125 [862]

120 [49.0]

5 [19]

150 [1030]

200 [93]

5 [19]

---

CW14B

0420

SH 2 G7

COOLANT

GEE-OTHERS

GENERATOR COOLER VENTS

---

---

---

0 [0]

57.2 [14]

0 [0]

125 [862]

120 [49.0]

5 [19]

150 [1030]

200 [93]

5 [19]

---

CW14C

0420

SH 2 G7

COOLANT

GEE-OTHERS

GENERATOR COOLER VENTS

---

---

---

0 [0]

57.2 [14]

0 [0]

125 [862]

120 [49.0]

5 [19]

150 [1030]

200 [93]

5 [19]

---

CW14D

0420

SH 2 G6

COOLANT

GEE-OTHERS

GENERATOR COOLER VENTS

---

---

---

0 [0]

57.2 [14]

0 [0]

125 [862]

120 [49.0]

5 [19]

150 [1030]

200 [93]

5 [19]

---

CW15A

0420

SH 3 F8

COOLANT

GEE-OTHERS

GENERATOR COOLER DRAINS

---

---

---

0 [0]

57.2 [14]

0 [0]

125 [862]

120 [49.0]

5 [19]

150 [1030]

200 [93]

5 [19]

---

CW15B

0420

SH 3 F7

COOLANT

GEE-OTHERS

GENERATOR COOLER DRAINS

---

---

---

0 [0]

57.2 [14]

0 [0]

125 [862]

120 [49.0]

5 [19]

150 [1030]

200 [93]

5 [19]

---

CW15C

0420

SH 3 F6

COOLANT

GEE-OTHERS

GENERATOR COOLER DRAINS

---

---

---

0 [0]

57.2 [14]

0 [0]

125 [862]

120 [49.0]

5 [19]

150 [1030]

200 [93]

5 [19]

---

CW15D

0420

SH 3 F6

COOLANT

GEE-OTHERS

GENERATOR COOLER DRAINS

---

---

---

0 [0]

57.2 [14]

0 [0]

125 [862]

120 [49.0]

5 [19]

150 [1030]

200 [93]

5 [19]

---

CW16A

0420

SH 3 F8

COOLANT

GEE-OTHERS

GENERATOR COOLER DRAINS

---

---

---

0 [0]

57.2 [14]

0 [0]

125 [862]

120 [49.0]

5 [19]

150 [1030]

200 [93]

5 [19]

---

CW16B

0420

SH 3 F7

COOLANT

GEE-OTHERS

GENERATOR COOLER DRAINS

---

---

---

0 [0]

57.2 [14]

0 [0]

125 [862]

120 [49.0]

5 [19]

150 [1030]

200 [93]

5 [19]

---

CW16C

0420

SH 3 F6

COOLANT

GEE-OTHERS

GENERATOR COOLER DRAINS

---

---

---

0 [0]

57.2 [14]

0 [0]

125 [862]

120 [49.0]

5 [19]

150 [1030]

200 [93]

5 [19]

---

CW16D

0420

SH 3 F6

COOLANT

GEE-OTHERS

GENERATOR COOLER DRAINS

---

---

---

0 [0]

57.2 [14]

0 [0]

125 [862]

120 [49.0]

5 [19]

150 [1030]

200 [93]

5 [19]

---

CW52

0420

SH 2 B8

COOLANT

GEE-OTHERS

COOLING WATER TO TURBINE BASE

---

---

---

65 [448]

57.2 [14]

6 [23]

125 [862]

120 [49.1]

6 [23]

150 [1030]

200 [93]

6 [23]

---

CW53

0420

SH 2 C6

COOLANT

GEE-OTHERS

COOLING WATER FROM TURBINE BASE

---

---

---

65 [448]

57.2 [14]

6 [23]

125 [862]

131 [54.7]

6 [23]

150 [1030]

200 [93]

6 [23]

---

CW94

0420

SH 3 G2

COOLANT

GEE-OTHERS

COOLING WATER TO LCI COOLER

---

---

---

65 [448]

57.2 [14]

50 [189]

125 [862]

115 [46.0]

50 [189]

150 [1030]

200 [93]

50 [189]

---

CW95

0420

SH 3 E2

COOLANT

GEE-OTHERS

COOLING WATER FROM LCI COOLER

---

---

---

65 [448]

57.2 [14]

50 [189]

125 [862]

129 [53.8]

50 [189]

150 [1030]

200 [93]

50 [189]

---

FG1

0422

GAS

GE-OTHERS

FUEL GAS INLET

---

---

---

410 [2830]

SEE NOTE 24

0.5 PPS [0.23 KG/S]

500 [3450]

350 [177]

550 [3790]

390 [199]

FG2

0422

GAS

GE-OTHERS

FUEL GAS STRAINER VENT

---

---

---

0 [0]

AMBIENT

0 [0]

500 [3450]

120 [48.9]

550 [3790]

390 [199]

FG3

0422

GAS/AIR

GE-OTHERS

FUEL GAS VENT

---

---

---

0 [0]

AMBIENT

0 [0]

150 [1030]

814 [434]

150 [1030]

814 [434]

SEE NOTES 25 & 26 SEE NOTES 22 & 24 SEE NOTES 22 & 24

FG20

0422

GAS

GE-OTHERS

FUEL GAS FLOW METER INLET

---

---

---

449 [3100]

AMBIENT

0.5 PPS [0.23 KG/S]

500 [3450]

350 [177]

550 [3790]

390 [199]

31 PPS [14.1 KG/S] 0.7 PPS [0.32 KG/S] 1 PPS [0.45 KG/S] 31 PPS [14.1 KG/S]

SH 2 C8

B

SEE NOTES 6&7 SEE NOTES 6&8 SEE NOTES 6&8 SEE NOTES 6&9 SEE NOTES 6&9 SEE NOTES 6&7

---

31 PPS [14.1 KG/S] 0.7 PPS [0.32 KG/S] 1 PPS [0.45 KG/S] 31 PPS [14.1 KG/S]

REV.

SEE NOTE 7

---

SH 2 C5 SH 3 F8 SH 2 G5 SH 3 F8 SH 2 G5 SH 3 H4

2

SEE NOTE 7

0.01 PPS [0.005 KG/S] 0.01 PPS [0.005 KG/S] 0.01 PPS [0.005 KG/S] 0.01 PPS [0.005 KG/S] 0.24 PPS [0.11 KG/ S] 0.20 PPS [0.09 KG/ S]

SH.

E

D

C

B

A

--GE CLASS II (INTERNAL NON-CRITICAL)

g DRAWN ISSUED

8

7

6

5

4

3

2

GENERAL ELECTRIC COMPANY

GE Energy JURADO, ARTURO SEE PLM

SIZE

E

CAGE CODE

DWG. NO.

145E4535

SCALE

SHEET

2 of 4

DISTR TO

DWG Number 145E4535

1 GE Proprietary Information - Class II (Internal) US EAR - NLR

Rev B

Released 8/8/2013

Page 3 of 4

8

7 CONNECTION NAME

H

MLI

SHEET & ZONE

CONNECTION DESCRIPTION

NORMAL PRESSURE PSIG [KPAG]

NORMAL TEMPERATURE °F [°C]

NORMAL FLOW USGPM [LPM]

MINIMUM PRESSURE PSIG [KPAG]

MINIMUM TEMPERATURE °F [°C]

0422

SH 2 C7

GAS

GE-OTHERS

FUEL GAS FLOW METER OUTLET

---

---

---

444 [3060]

AMBIENT

0422

SH 2 C7

GAS

GE-OTHERS

SAFETY SHUTOFF STOP VALVE INLET

---

---

---

414 [2850]

AMBIENT

FG426

0422

SH 2 C6

GAS

GE-OTHERS

SAFETY SHUTOFF STOP VALVE OUTLET

---

---

---

411 [2830]

AMBIENT

---

---

---

0 [0]

AMBIENT

---

---

---

0 [0]

AMBIENT

SAFETY SHUTOFF STOP UPPER VALVE PACKING LEAK OFF SAFETY SHUTOFF STOP UPPER VALVE PACKING LEAK OFF

3 MINIMUM FLOW USGPM [LPM] 0.5 PPS [0.23 KG/S] 0.5 PPS [0.23 KG/S] 0.5 PPS [0.23 KG/S]

MAXIMUM PRESSURE PSIG [KPAG]

MAXIMUM TEMPERATURE °F [°C]

500 [3450]

350 [177]

500 [3450]

350 [177]

500 [3450]

350 [177]

0 [0]

500 [3450]

350 [177]

0 [0]

500 [3450]

350 [177]

2 MAXIMUM FLOW USGPM [LPM] 31 PPS [14.1 KG/S] 31 PPS [14.1 KG/S] 31 PPS [14.1 KG/S] 0.003 PPS [0.001 KG/S] 0.003 PPS [0.001 KG/S] 57 PPS [25.9 KG/S] 57 PPS [25.9 KG/S]

DESIGN PRESSURE PSIG [KPAG]

SIZE

E

DESIGN TEMPERATURE °F [°C]

550 [3790]

390 [199]

550 [3790]

390 [199]

550 [3790]

390 [199]

550 [3790]

390 [199]

550 [3790]

390 [199]

550 [3790]

390 [199]

550 [3790]

390 [199]

DWG. NO.

145E4535

DESIGN FLOW USGPM [LPM] 31 PPS [14.1 KG/S] 31 PPS [14.1 KG/S] 31 PPS [14.1 KG/S] 0.003 PPS [0.001 KG/S] 0.003 PPS [0.001 KG/S] 57 PPS [25.9 KG/S] 57 PPS [25.9 KG/S] 0.04 PPS [0.02 KG/S] 0.04 PPS [0.02 KG/S] 0.04 PPS [0.02 KG/S]

SH 2 D6

GAS

GE-OTHERS

SH 2 D7

GAS

GE-OTHERS

FG438

0422

SH 2 E6

GAS

GE-OTHERS

SAFETY SHUTOFF VENT VALVE INLET

---

---

---

411 [2830]

AMBIENT

0 [0]

500 [3450]

350 [177]

FG439

0422

SH 2 E6

GAS

GE-OTHERS

SAFETY SHUTOFF VENT VALVE OUTLET

---

---

---

0 [0]

AMBIENT

0 [0]

500 [3450]

350 [177]

FG7

0422

SH 2 G5 SH 3 H2

AIR

GE-OTHERS

INSTRUMENT AIR SUPPLY

105 [724]

AMBIENT

---

---

---

---

---

---

120 [827]

150 [65.6]

FG427

0422

SH 2 D6

AIR

GE-OTHERS

INSTRUMENT AIR GAS SAFETY SHUT OFF STOP VALVE

105 [724]

AMBIENT

---

---

---

---

---

---

120 [827]

150 [65.6]

FG440

0422

SH 2 E6

AIR

GE-OTHERS

INSTRUMENT AIR GAS SAFETY SHUT OFF VENT VALVE

105 [724]

AMBIENT

---

---

---

---

---

---

120 [827]

150 [65.6]

GEE-OTHERS

FILL CONNECTION

220 TO 250 [1520 TO 1720]

0 [-17.8]

45.1 TO 51.5 PPS [20.0 TO 23.4 KG/ S]

---

---

---

---

---

---

220 TO 250 [1520 TO 1720]

0 [-17.8]

45.1 TO 51.5 PPS [20.0 TO 23.4 KG/ S]

SEE NOTES 29 & 30

GEE-OTHERS

VAPOR RETURN CONNECTION

220 TO 250 [1520 TO 1720]

0 [-17.8]

0.076 TO 0.089 PPS [0.034 TO 0.040 KG/S]

---

---

---

---

---

---

220 TO 250 [1520 TO 1720]

0 [-17.8]

0.076 TO 0.089 PPS [0.034 TO 0.040 KG/S]

SEE NOTES 29 & 230

GEE-OTHERS

NO.2 BEARING INITIAL DISCHARGE SUPPLY

325 [2240]

0 [-17.8]

6.1 TO 7.67 PPS [2.8 TO 3.48 KG/S]

---

---

---

---

---

---

450 [3100]

0 [-17.8]

6.1 TO 7.67 PPS [2.8 TO 3.48 KG/S]

SEE NOTE 29

GEE-OTHERS

NO.2 BEARING EXTENDED DISCHARGE SUPPLY

325 [2240]

0 [-17.8]

0.31 TO 0.34 PPS [0.14 TO 0.15 KG/ S]

---

---

---

---

---

---

450 [3100]

0 [-17.8]

0.31 TO 0.34 PPS [0.14 TO 0.15 KG/ S]

SEE NOTE 29

GEE-OTHERS

LUBE OIL COMPARTMENT INITIAL DISCHARGE

325 [2240]

0 [-17.8]

3.7 TO 4.88 PPS [1.7 TO 2.21 KG/S]

---

---

---

---

---

---

450 [3100]

0 [-17.8]

3.7 TO 4.88 PPS [1.7 TO 2.21 KG/S]

SEE NOTE 29

GEE-OTHERS

LUBE OIL COMPARTMENT EXTENDED DISCHARGE

325 [2240]

0 [-17.8]

0.18 TO 0.19 PPS [0.080 TO 0.086 KG/S]

---

---

---

---

---

---

450 [3100]

0 [-17.8]

0.18 TO 0.19 PPS [0.080 TO 0.086 KG/S]

SEE NOTE 29

GEE-OTHERS

COMMON RELIEF VALVE VENT

14.7 [101]

60 [15.6]

24.1 PPS [10.9 KG/S]

---

---

---

---

---

---

14.47 [101]

60 [15.6]

24.1 PPS [10.9 KG/S]

SEE NOTES 29 & 30

GEE-OTHERS

TURBINE DISCHARGE COMPARTMENT INITIAL DISCHARGE SUPPLY

325 [2240]

0 [-17.8]

37.2 TO 43.1 PPS [16.9 TO 19.5 KG/ S]

---

---

---

---

---

---

450 [3100]

0 [-17.8]

37.2 TO 43.1 PPS [16.9 TO 19.5 KG/ S]

SEE NOTE 29

GEE-OTHERS

TURBINE DISCHARGE COMPARTMENT EXTENDED DISCHARGE SUPPLY

325 [2240]

0 [-17.8]

0.94 TO 1.23 PPS [0.43 TO 0.56 KG/ S]

---

---

---

---

---

---

450 [3100]

0 [-17.8]

0.94 TO 1.23 PPS [0.43 TO 0.56 KG/ S]

SEE NOTE 29

GEE-OTHERS

TURBINE COMPARTMENT PNEUMATIC SIREN

325 [2240]

0 [-17.8]

0.083 PPS [0.038 KG/S]

---

---

---

---

---

---

450 [3100]

0 [-17.8]

0.083 PPS [0.038 KG/S]

SEE NOTE 29

GEE-OTHERS

LUBE OIL COMPARTMENT PNEUMATIC SIREN

325 [2240]

0 [-17.8]

0.083 PPS [0.038 KG/S]

---

---

---

---

---

---

450 [3100]

0 [-17.8]

0.083 PPS [0.038 KG/S]

SEE NOTE 29

GEE-OTHERS

TURBINE DISCHARGE COMPARTMENT INITIAL DISCHARGE SUPPLY

325 [2240]

0 [-17.8]

37.2 TO 43.1 PPS [16.9 TO 19.5 KG/ S]

---

---

---

---

---

---

450 [3100]

0 [-17.8]

37.2 TO 43.1 PPS [16.9 TO 19.5 KG/ S]

SEE NOTE 29

GEE-OTHERS

TURBINE DISCHARGE COMPARTMENT EXTENDED DISCHARGE SUPPLY

325 [2240]

0 [-17.8]

0.94 TO 1.23 PPS [0.43 TO 0.56 KG/ S]

---

---

---

---

---

---

450 [3100]

0 [-17.8]

0.94 TO 1.23 PPS [0.43 TO 0.56 KG/ S]

SEE NOTE 29

---

---

---

---

---

---

450 [3100]

0 [-17.8]

6.1 TO 7.67 PPS [2.8 TO 3.48 KG/S]

SEE NOTE 29

0426

SH 2 B2

NN8

0426

SH 2 B2

CO2 GAS

FP25

0426

SH 3 G2

FP26

0426

SH 3 G3

FP31

0426

SH 3 D4

FP32

0426

SH 3 D4

NN44

0426

SH 2 A2

FP60

0426

SH 3 F4

FP61

0426

SH 3 F4

FP91

0426

SH 3 F4

FP93

0426

SH 3 D4

NN1

0426

SH 2 C3

NN2

0426

SH 2 C3

DUAL PHASE FLOW LIQUID CO2 AND CO2 GAS DUAL PHASE FLOW LIQUID CO2 AND CO2 GAS DUAL PHASE FLOW LIQUID CO2 AND CO2 GAS DUAL PHASE FLOW LIQUID CO2 AND CO2 GAS DUAL PHASE FLOW LIQUID CO2 AND CO2 GAS DUAL PHASE FLOW LIQUID CO2 AND CO2 GAS DUAL PHASE FLOW LIQUID CO2 AND CO2 GAS DUAL PHASE FLOW LIQUID CO2 AND CO2 GAS DUAL PHASE FLOW LIQUID CO2 AND CO2 GAS DUAL PHASE FLOW LIQUID CO2 AND CO2 GAS DUAL PHASE FLOW LIQUID CO2 AND CO2 GAS DUAL PHASE FLOW LIQUID CO2 AND CO2 GAS DUAL PHASE FLOW LIQUID CO2 AND CO2 GAS DUAL PHASE FLOW LIQUID CO2 AND CO2 GAS DUAL PHASE FLOW LIQUID CO2 AND CO2 GAS DUAL PHASE FLOW LIQUID CO2 AND CO2 GAS DUAL PHASE FLOW LIQUID CO2 AND CO2 GAS

--SEE NOTES 22 & 24 SEE NOTE 27 SEE NOTE 27 SEE NOTE 27

G

F

NO.2 BEARING INITIAL DISCHARGE SUPPLY

325 [2240]

0 [-17.8]

GEE-OTHERS

NO.2 BEARING EXTENDED DISCHARGE SUPPLY

325 [2240]

0 [-17.8]

0.31 TO 0.34 PPS [0.14 TO 0.15 KG/ S]

---

---

---

---

---

---

450 [3100]

0 [-17.8]

0.31 TO 0.34 PPS [0.14 TO 0.15 KG/ S]

SEE NOTE 29

GEE-OTHERS

LUBE OIL COMPARTMENT INITIAL DISCHARGE

325 [2240]

0 [-17.8]

3.7 TO 4.88 PPS [1.7 TO 2.21 KG/S]

---

---

---

---

---

---

450 [3100]

0 [-17.8]

3.7 TO 4.88 PPS [1.7 TO 2.21 KG/S]

SEE NOTE 29

GEE-OTHERS

LUBE OIL COMPARTMENT EXTENDED DISCHARGE

325 [2240]

0 [-17.8]

0.18 TO 0.19 PPS [0.080 TO 0.086 KG/S]

---

---

---

---

---

---

450 [3100]

0 [-17.8]

0.18 TO 0.19 PPS [0.080 TO 0.086 KG/S]

SEE NOTE 29

GEE-OTHERS

TURBINE COMPARTMENT PNEUMATIC SIREN

325 [2240]

0 [-17.8]

0.083 PPS [0.038 KG/S]

---

---

---

---

---

---

450 [3100]

0 [-17.8]

0.083 PPS [0.038 KG/S]

SEE NOTE 29

GEE-OTHERS

LUBE OIL COMPARTMENT PNEUMATIC SIREN

325 [2240]

0 [-17.8]

0.083 PPS [0.038 KG/S]

---

---

---

---

---

---

450 [3100]

0 [-17.8]

0.083 PPS [0.038 KG/S]

SEE NOTE 29

AIR

GEE-GEE

INLET HEATING CONTROL VALVE INLET

223 [1540]

754 [401]

---

---

---

---

---

---

252 [1740]

814 [434]

SH 1 C3

AIR

GEE-GEE

INLET HEATING CONTROL VALVE OUTLET

223 [1540]

754 [401]

---

---

---

---

---

---

252 [1740]

814 [434]

0432

SH 1 C7

AIR

GEE-GEE

INLET HEATING ISOLATION VALVE INLET

223 [1540]

754 [401]

---

---

---

---

---

---

252 [1740]

814 [434]

0432

SH 1 C6

AIR

GEE-GEE

INLET HEATING ISOLATION VALVE OUTLET

223 [1540]

754 [401]

---

---

---

---

---

---

252 [1740]

814 [434]

INSTRUMENT AIR SUPPLY TO INLET HEAT CONTROL VALVE

---

---

---

---

---

---

110 [758]

120 [48.9]

SH 2 C2

NN4

0426

SH 2 C3

NN5

0426

SH 2 C4

NN6

0426

SH 2 C4

NN31

0426

SH 2 C3

NN33

0426

SH 2 C4

IH1

0432

SH 1 C5

IH2

0432

IH3 IH4 IH7

0432

SH 1 E7

AIR

GEE-OTHERS

HV8

0436

SH 3 D8

AIR

GEE-OTHERS

HV9

0436

SH 3 F6

AIR

GEE-OTHERS

LOAD COMPARTMENT EXHAUST (COMPARTMENT INTERFACE) ACCESSORY MODULE (LUBE OIL REGION) EXHAUST (COMPARTMENT INTERFACE)

0 TO 32.7 PPS [0 TO 14.8 KG/S] 0 TO 32.7 PPS [0 TO 14.8 KG/S] 0 TO 32.7 PPS [0 TO 14.8 KG/S] 0 TO 32.7 PPS [0 TO 14.8 KG/S]

90 [621]

AMBIENT

.0004 PPS [.0002 KG/S]

---

---

---

0 [0]

AMBIENT

---

0 [0]

163 [72.8]

---

223 [1540]

---

---

---

0 [0]

AMBIENT

---

0 [0]

133 [56.1]

---

105 [724]

32.7 PPS [14.8KG/ S] 32.7 PPS [14.8KG/ S] 32.7 PPS [14.8KG/ S] 32.7 PPS [14.8KG/ S] .006 PPS [.003 KG/ S] TRANSIENT

-20 TO 200 [-29 TO 93] -20 TO 160 [-29 TO 71]

H

---

GEE-OTHERS

0426

1

---

6.1 TO 7.67 PPS [2.8 TO 3.48 KG/S]

NN3

B

---

0422

NN7

REV.

---

0422

DUAL PHASE FLOW LIQUID CO2 AND CO2 GAS

3

SEE NOTE 28

FG428B

0.01 PPS [0.005 KG/S] 0.01 PPS [0.005 KG/S] 0.01 PPS [0.005 KG/S]

SH.

NOTES

FG428A

C

B

INTERFACE TYPE

4

FG21

F

D

FLUID TYPE

5

FG425

G

E

6

E

D

C

SEE NOTE 33 SEE NOTE 33 SEE NOTE 33 SEE NOTE 33

B

---

6400 ACFM [181 M^3/MIN] 7400 ACFM [210 M^3/MIN]

-----

IE4

0442

SH 2 C5

WASH WATER

GEE-OTHERS

DRAIN FROM INLET PLENUM

0 [0]

180 [82.2]

15 [57]

---

---

---

---

---

---

5 [34.5]

212 [100]

15 [57]

---

WW1

0442

SH 2 C7

WASH WATER

GEE-OTHERS

WATER WASH TO SPRAY MANIFOLDS

SEE NOTE 34

SEE NOTE 34

SEE NOTE 34

---

---

---

---

---

---

110 [758]

212 [100]

58.5 [221]

SEE NOTES 34, 37 & 39

WW10

0442

SH 2 D3

WASH WATER

GEE-OTHERS

WASH WATER DRAIN FROM TURBINE SHELL AFT

2 [13.8]

212 [100]

5.5 [21]

---

---

---

---

---

---

5 [34.5]

212 [100]

5.5 [21]

---

A

A GE CLASS II (INTERNAL NON-CRITICAL)

g DRAWN ISSUED

8

7

6

5

4

3

2

GENERAL ELECTRIC COMPANY

GE Energy JURADO, ARTURO SEE PLM

SIZE

E

CAGE CODE

DWG. NO.

145E4535

SCALE

SHEET

3 of 4

DISTR TO

DWG Number 145E4535

1 GE Proprietary Information - Class II (Internal) US EAR - NLR

DWG Number 145E4535

Rev B

Released 8/8/2013

Page 4 of 4

8

7 CONNECTION NAME

H

G

MLI

SHEET & ZONE

6

FLUID TYPE

INTERFACE TYPE

CONNECTION DESCRIPTION

5 NORMAL PRESSURE PSIG [KPAG]

E

D

NORMAL FLOW USGPM [LPM]

MINIMUM PRESSURE PSIG [KPAG]

MINIMUM TEMPERATURE °F [°C]

3 MINIMUM FLOW USGPM [LPM]

MAXIMUM PRESSURE PSIG [KPAG]

MAXIMUM TEMPERATURE °F [°C]

2 MAXIMUM FLOW USGPM [LPM]

DESIGN PRESSURE PSIG [KPAG]

SIZE

E

DESIGN TEMPERATURE °F [°C]

DWG. NO.

145E4535

DESIGN FLOW USGPM [LPM] 0.003 PPS [0.001 KG/S] 0.001 PPS [0.0004 KG/S]

0442

SH 2 D7

AIR

GEE-OTHERS

INSTRUMENT AIR SUPPLY TO VA16-1

100 [689]

175 [79]

0 [0]

---

---

---

---

---

---

120 [827]

175 [79]

WW112

0442

SH 2 C6

AIR

GEE-OTHERS

INSTRUMENT AIR SUPPLY TO VA16-3

100 [689]

175 [79]

0 [0]

---

---

---

---

---

---

120 [827]

175 [79]

WW12

0442

SH 2 E7

WASH WATER

GEE-OTHERS

OFF-LINE FEED WATER DRAIN

4 [27.6]

5.5 [21]

---

---

---

---

---

---

5 [34.5]

212 [100]

5.5 [21]

SEE NOTE 38

WW13

0442

SH 2 D6

WASH WATER

GEE-OTHERS

ON-LINE FEED WATER DRAIN

4 [27.6]

5.5 [21]

---

---

---

---

---

---

5 [34.5]

212 [100]

5.5 [21]

SEE NOTE 38

WW15

0442

SH 2 D3

WASH WATER

GEE-OTHERS

WASH WATER DRAIN FROM EXHAUST DIFFUSER FWD

4 [27.6]

212 [100]

5.5 [21]

---

---

---

---

---

---

5 [34.5]

212 [100]

5.5 [21]

---

WW16

0442

SH 2 D3

WASH WATER

GEE-OTHERS

WASH WATER DRAIN FROM EXHAUST DIFFUSER AFT

4 [27.6]

212 [100]

5.5 [21]

---

---

---

---

---

---

5 [34.5]

212 [100]

5.5 [21]

---

WW24

0442

SH 2 D2

WASH WATER

GEE-OTHERS

WASH WATER DRAIN FROM EXHAUST DUCT

2 [13.8]

212 [100]

21.5 [81]

---

---

---

---

---

---

5 [34.5]

212 [100]

21.5 [81]

---

WW30

0442

SH 2 D4

WASH WATER

GEE-OTHERS

WASH WATER DRAIN FROM TURBINE SHELL MANWAY

2 [13.8]

212 [100]

28 [106]

---

---

---

---

---

---

5 [34.5]

212 [100]

28 [106]

---

WW33

0442

SH 2 C5

WASH WATER

GEE-OTHERS

WASH WATER DRAIN FROM COMBUSTION SYSTEM

2 [13.8]

212 [100]

32 [121]

---

---

---

---

---

---

5 [34.5]

212 [100]

32 [121]

---

WW19

0442

SH 1 E6

WATER

GEE-OTHERS

WATER TANK INLET

0 [0]

AMBIENT

0 [0]

---

---

---

---

---

---

120 [827]

122 [50]

100 [379]

SEE NOTE 37

WW20

0442

SH 1 C2

WASH WATER

GEE-OTHERS

WATER MIX OUTLET

SEE NOTE 34

SEE NOTE 34

SEE NOTE 34

---

---

---

---

---

---

110 [758]

212 [100]

58.5 [221]

SEE NOTES 34 & 39

WW21

0442

SH 1 G5

DETERGENT

GEE-OTHERS

DETERGENT TANK INLET

0 [0]

AMBIENT

0 [0]

---

---

---

---

---

---

60 [414]

122 [50]

50 [189]

---

WW22

0442

SH 1 F6

DETERGENT

GEE-OTHERS

DETERGENT TANK DRAIN

0 [0]

65 [18.3]

0 [0]

---

---

---

---

---

---

3 [20.7]

122 [50]

10 [37.9]

SEE NOTE 38

WW23

0442

SH 1 B5

WATER

GEE-OTHERS

WATER TANK DRAIN

0 [0]

50 TO 180 [10 TO 82.2]

0 [0]

---

---

---

---

---

---

3 [20.7]

212 [100]

25 [94.6]

SEE NOTE 38

WW29

0442

SH 1 B6

WATER

GEE-OTHERS

FLOOR DRAIN

0 [0]

65 [18.3]

0 [0]

---

---

---

---

---

---

3 [20.7]

122 [50]

25 [94.6]

SEE NOTE 38

WW121

0442

SH 2 D7

AIR

GEE-OTHERS

INSTRUMENT AIR SUPPLY TO VA16-4

100 [689]

175 [79]

0 [0]

---

---

---

---

---

---

120 [827]

175 [79]

0.003 PPS [0.001 KG/S]

SEE NOTE 35

WW122

0442

SH 2 D8

WASH WATER

GEE-OTHERS

OFF-LINE FEED WATER DRAIN

4 [27.6]

50 TO 180 [10 TO 82.2]

5.5 [21]

---

---

---

---

---

---

5 [34.5]

212 [100]

5.5 [21]

SEE NOTE 38

0.20 PPS [0.09 KG/S] 32.7 PPS [14.8 KG/S] 6.5 PPS [2.95 KG/S]

SEE NOTES 40 & 43 SEE NOTES 40 & 41

50 TO 180 [10 TO 82.2] 50 TO 180 [10 TO 82.2]

IE2

0471

SH 1 C6

AIR

GEE-OTHERS

COMPRESSED AIR INLET

100 [689]

145 [63]

IE20

0471

SH 2 F6

AIR

GEE-OTHERS

AIR INLET FOR INLET HEATING

223 [1540]

754 [401]

IE116

0471

SH 1 B5

DUST / PARTICULATE

GEE-OTHERS

SCREW AUGER DRAIN

0 [0]

AMBIENT

HG17

0474

SH 1 H5

AIR

GEE-OTHERS

AIR SUPPLY FOR COMB GAS ASPIRATOR

105 [724]

HG24

0474

SH 1 G5

AIR

GEE-OTHERS

AIR SUPPLY FOR COMB GAS ASPIRATOR

105 [724]

HG31

0474

SH 1 H2

AIR

GEE-OTHERS

AIR SUPPLY FOR COMB GAS ASPIRATOR

HG38

0474

SH 1 G2

AIR

GEE-OTHERS

AIR SUPPLY FOR COMB GAS ASPIRATOR

HG45

0474

SH 1 C2

AIR

GEE-OTHERS

HG52

0474

SH 1 D2

AIR

HG78

0474

SH 1 D7

HG79

0474

HG80

0474

0.20 PPS [0.09 KG/S] 0 TO 32.7 PPS [0 TO 14.8 KG/S]

---

---

---

---

---

---

104 [717]

145 [63]

---

---

---

---

---

---

252 [1740]

814 [434]

0 [0]

---

---

---

---

---

---

25 [172]

122 [50]

AMBIENT

0.62 [2.35]

---

---

---

---

---

---

120 [827]

150 [66]

0.75 [2.83]

AMBIENT

0.62 [2.35]

---

---

---

---

---

---

120 [827]

150 [66]

0.75 [2.83]

105 [724]

AMBIENT

0.62 [2.35]

---

---

---

---

---

---

120 [827]

150 [66]

0.75 [2.83]

105 [724]

AMBIENT

0.62 [2.35]

---

---

---

---

---

---

120 [827]

150 [66]

0.75 [2.83]

AIR SUPPLY FOR COMB GAS ASPIRATOR

105 [724]

AMBIENT

0.62 [2.35]

---

---

---

---

---

---

120 [827]

150 [66]

0.75 [2.83]

GEE-OTHERS

AIR SUPPLY FOR COMB GAS ASPIRATOR

105 [724]

AMBIENT

0.62 [2.35]

---

---

---

---

---

---

120 [827]

150 [66]

0.75 [2.83]

AIR

GEE-OTHERS

AIR SUPPLY FOR COMB GAS ASPIRATOR

105 [724]

AMBIENT

0.62 [2.35]

---

---

---

---

---

---

120 [827]

150 [66]

0.75 [2.83]

SH 1 C7

AIR

GEE-OTHERS

AIR SUPPLY FOR COMB GAS ASPIRATOR

105 [724]

AMBIENT

0.62 [2.35]

---

---

---

---

---

---

120 [827]

150 [66]

0.75 [2.83]

SH 1 D5

AIR

GEE-OTHERS

AIR SUPPLY FOR COMB GAS ASPIRATOR

105 [724]

AMBIENT

0.62 [2.35]

---

---

---

---

---

---

120 [827]

150 [66]

0.75 [2.83]

---

---

---

---

---

---

52 [359]

814 [434]

---

---

---

---

---

---

52 [359]

814 [434]

PG1

0477

SH 2 H2

AIR / GAS

GEE-OTHERS

GAS PURGE VALVE VENT (D5)

0 [0]

AMBIENT

PG13

0477

SH 2 C2

AIR / GAS

GEE-OTHERS

GAS PURGE VALVE VENT (PM2)

0 [0]

AMBIENT

0.04 PPS [0.02 KG/S] 0.04 PPS [0.02 KG/ S]

FG257

4035

SH 1 D8

GAS

GEE-OTHERS

SAMPLE PROBE INLET (ACTIVE)

---

---

---

35 [241]

-20 [-29]

FG258

4035

SH 1 C8

GAS

GEE-OTHERS

SAMPLE PROBE INLET (SPARE)

---

---

---

35 [241]

-20 [-29]

FG259

4035

SH 1 D5

GAS

GEE-OTHERS

SAMPLE STREAM TO GAS CHROMATOGRAPH (ACTIVE)

---

---

---

20 [138]

90 [32]

FG260

4035

SH 1 C5

GAS

GEE-OTHERS

SAMPLE STREAM TO GAS CHROMATOGRAPH (SPARE)

---

---

---

20 [138]

90 [32]

FG261

4035

SH 1 B5

GAS

GEE-OTHERS

STREAM BYPASS VENT

---

---

---

0 [0]

90 [32]

FG262

4035

SH 1 G4

GAS

GEE-OTHERS

SAMPLE VENT

---

---

---

0 [0]

90 [32]

FG264

4035

SH 1 D6

GAS

GEE-OTHERS

SAMPLE PROBE OUTLET (ACTIVE)

---

---

---

20 [138]

90 [32]

FG265

4035

SH 1 C6

GAS

GEE-OTHERS

SAMPLE PROBE OUTLET (SPARE)

---

---

---

20 [138]

90 [32]

0.51 PPD [0.23 KG/D] 0.51 PPD [0.23 KG/D] 0.51 PPD [0.23 KG/D] 0.51 PPD [0.23 KG/D] 2.30 PPD [1.04 KG/D] 0.13 PPD [0.06 KG/D] 0.51 PPD [0.23 KG/D] 0.51 PPD [0.23 KG/D]

500 [3450]

365 [185]

500 [3450]

365 [185]

25 [172]

365 [185]

25 [172]

365 [185]

200 [1380]

130 [54]

200 [1380]

130 [54]

25 [172]

365 [185]

25 [172]

365 [185]

5.09 PPD [2.31 KG/D] 5.09 PPD [2.31 KG/D] 5.09 PPD [2.31 KG/D] 5.09 PPD [2.31 KG/D] 5.09 PPD [2.31 KG/D] 0.28 PPD [0.13 KG/D] 5.09 PPD [2.31 KG/D] 5.09 PPD [2.31 KG/D]

550 [3790]

390 [190]

550 [3790]

390 [190]

100 [689]

390 [190]

100 [689]

390 [190]

250 [1720]

130 [54]

250 [1720]

130 [54]

100 [689]

390 [190]

100 [689]

390 [190]

1.0 PPS [0.45 KG/S] 1.0 PPS [0.45 KG/ S] 33.9 PPD [15.4 KG/D] 33.9 PPD [15.4 KG/D] 33.9 PPD [15.4 KG/D] 33.9 PPD [15.4 KG/D] 33.9 PPD [15.4 KG/D] 565 PPD [256 KG/D] 33.9 PPD [15.4 KG/D] 33.9 PPD [15.4 KG/D]

SH.

4

REV.

B

1

NOTES

WW111

B1

F

NORMAL TEMPERATURE °F [°C]

4

SEE NOTE 35 SEE NOTE 35

H

G

F

--SEE NOTES 47 & 48 SEE NOTES 47 & 48 SEE NOTES 47 & 48 SEE NOTES 47 & 48 SEE NOTES 47 & 48 SEE NOTES 47 & 48 SEE NOTES 47 & 48 SEE NOTES 47 & 48 SEE NOTES 47 & 48

E

SEE NOTE 50 SEE NOTE 50

-----

D

----SEE NOTE 51 SEE NOTE 51 -----

C

C

B

B

A

A GE CLASS II (INTERNAL NON-CRITICAL)

ISSUED

8

7

6

5

4

3

2

GENERAL ELECTRIC COMPANY

GE Energy JURADO, ARTURO SEE PLM

SIZE

E

CAGE CODE

DWG. NO.

145E4535

SCALE

SHEET

4 of 4

DISTR TO

g DRAWN

1 GE Proprietary Information - Class II (Internal) US EAR - NLR

DWG Number 107T6779

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Released 8/21/2013

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Tab 4

g

GEK 116642 April 2010

GE Energy

Turbine Control Devices

These instructions do not purport to cover all details or variations in equipment nor to provide for every possible contingency to be met in connection with installation, operation or maintenance. Should further information be desired or should particular problems arise which are not covered sufficiently for the purchaser's purposes the matter should be referred to the GE Company. © General Electric Company, 2010. GE Proprietary Information. All Rights Reserved.

Turbine Control Devices

GEK 116642 TABLE OF CONTENTS

I. INTRODUCTION..........................................................................................................................

3

II. OVERVIEW ...................................................................................................................................

3

III. DEVICE NOMENCLATURE ......................................................................................................

4

IV. FUNCTIONAL DESCRIPTION ..................................................................................................

5

V. CALIBRATION AND MAINTENANCE ....................................................................................

9

2

© General Electric Company, 2010. GE Proprietary Information. All Rights Reserved.

Turbine Control Devices

GEK 116642

I. INTRODUCTION The turbine control device schematic (MLI 0415) shows devices that provide feedback on the conditions of the gas turbine. These inputs are sent to controls software and used in the control or monitoring of the gas turbine. The conditions of the gas turbine covered by the devices on the schematic are as follows: •

Presence of Flame in Combustors

•

Inlet Bell-Mouth Temperatures (°F, °C)

•

Exhaust Temperatures (°F, °C)

•

Bearing Temperatures (°F, °C)

•

Wheelspace Temperatures (°F, °C)

•

Vibration at Bearings (in/sec)

•

Turbine Rotational Speed (rpm)

•

Turbine Ignition System

II. OVERVIEW The areas mentioned above are covered by categories of devices. Each device will provide the data needed to analyze the given area of the turbine. This data will then be given to controls to perform any monitoring, diagnostics, alarm, or trip function. Device categories are as follows: •

Combustion Flame Detectors

•

Magnetic Speed Pickups

•

Combustion Ignition Exciter / Spark Plugs

•

Compressor Discharge Thermocouples

•

Turbine Case Temperature Management Thermocouples

•

Exhaust Thermocouples

•

Wheelspace Thermocouples

•

Inner Barrel Thermocouples

•

Inlet Plenum Thermocouples

•

Journal Bearing Thermocouples

•

Thrust Bearing Thermocouples

•

Casing Movement, Seismic Sensor

© General Electric Company, 2010. GE Proprietary Information. All Rights Reserved.

3

Turbine Control Devices

GEK 116642 •

Bearing Displacement, Vibration Probe

III. DEVICE NOMENCLATURE XX designates specific number related to location and/or quantity. Device XX number may change per frame size. See 0415 drawing on the new unit and applicable mod BOMs for project specific devices. 1.

Combustion Flame Detectors: 28FD-XX

2.

Magnetic Speed Pickups 77HT-XX 77NH-XX

3.

Combustion Ignition Exciter / Spark Plugs 30SG-1 (relay) 95SG-XX (exciter) 95SP-XX (sparkplug)

4.

Compressor Discharge Thermocouples CT-DA-XX

5.

Turbine Case Temperature Management Thermocouples TT-TC-XX

6.

Exhaust Thermocouples TT-XD-XX

7.

Wheelspace Thermocouples TT-WS1AO-XX (first stage aft outer) TT-WS2AO-XX (second stage aft outer) TT-WS3AO-XX (third stage aft outer) TT-WS1F1-XX (first stage forward inner) TT-WS2FO-XX (second stage forward outer) TT-WS3FO-XX (third stage forward outer)

4

© General Electric Company, 2010. GE Proprietary Information. All Rights Reserved.

Turbine Control Devices 8.

GEK 116642

Inner Barrel Thermocouples TT-IB-XX

9.

Inlet Plenum Thermocouples CT-IF-XX

10.

Journal Bearing Thermocouples BT-J1-XXA,XXB BT-J2-XXA,XXB BT-J3-XXA,XXB

11.

Thrust Bearing Thermocouples BT-TA1-XXA,XXB (multiple) BT-TI1-XXA,XXB (multiple)

12.

Casing Movement, Seismic Sensor 39V-XX

13.

Bearing Displacement, Vibration Probe 39VS-XX 96VC-XX 77RP-XX

IV. FUNCTIONAL DESCRIPTION Below provides a generic description of the devices and their functionality. 1.

Combustion Flame Detectors •

Purpose: Flame Detectors are used to detect the presence of flame in the combustion cans.

•

Controls Impact: Signal used by Turbine Control Panel (TCP), for turbine control.

•

Additional Information: Typical combustion can location of Flame detectors are: 7E –2,3,7,8; 7F – 11,12,13,14; 9F – 15,16,17,18. In these specific cans only one flame detector is used. In DLN applications on 7E, secondary and primary flame detectors are used resulting in two flame detectors per combustion can.

•

Typically provided by: MLI 1121

© General Electric Company, 2010. GE Proprietary Information. All Rights Reserved.

5

Turbine Control Devices

GEK 116642 2.

3.

4.

5.

6

Magnetic Speed Pickups •

Purpose: Magnetic speed pickups are used to detect the speed of the turbine by monitoring the speed of a multi-toothed wheel.

•

Controls Impact: Speed signal used by TCP, for overspeed and trip functions.

•

Additional Information: Two sets of three sensors are used for triple modular redundancy functionality. One set is used for overspeed and the other for trip.

•

Typically provided by: MLI 0546

Combustion Ignition Exciter / Spark Plugs •

Purpose: Ignition exciter and sparkplugs are used when firing the turbine.

•

Controls Impact: Signal used by TCP, for turbine control.

•

Additional Information: Two sparkplugs placed in the combustion cans are used for firing. This initial spark will provide the flame needed to all cans via cross-fire tubes.

•

Typically provided by: MLI 1213 (ignition exciter and leads) and 1214 (sparkplugs)

Compressor Discharge Thermocouples •

Purpose: Compressor discharge thermocouples are used to monitor temperature at the point when air exits the last stage of the compressor.

•

Controls Impact: Temperature signal used by TCP, for turbine control.

•

Additional Information: Three TC’s are placed at the compressor discharge location on the bottom side of the turbine.

•

Typically provided by: MLI 0637

•

Typically located by: MLI 0219

Turbine Case Temperature Management Thermocouples •

Purpose: Turbine Case Temperature Management Thermocouples are used to monitor temperature in the turbine casing stage one region.

•

Controls Impact: Temperature signal used by TCP, for turbine control.

•

Additional Information: Multiple TC’s are used in a circular array placed around the turbine section.

•

Typically provided by: MLI 0637

•

Typically interface with: MLI 0705 turbine casing

© General Electric Company, 2010. GE Proprietary Information. All Rights Reserved.

Turbine Control Devices 6.

7.

8.

9.

GEK 116642

Exhaust Thermocouples •

Purpose: Exhaust thermocouples are used to monitor temperature in the exhaust area.

•

Controls Impact: Temperature signal used by TCP, for turbine control.

•

Additional Information: Multiple TC’s are used in a circular array around the exhaust diffuser.

•

Typically provided by: MLI 0623

•

Typically interface with: MLI 0706 exhaust diffuser

Wheelspace Thermocouples •

Purpose: Wheelspace thermocouples are used to monitor temperature in the turbine rotor wheelspace.

•

Controls Impact: Temperature signal used by TCP, for turbine control.

•

Additional Information: Overall 12 wheelspace TC’s are used in six locations with each location having redundant TC’s.

•

Typically provided by: MLI 0637

•

Typically interface with: Guide tubes that are located in the turbine casing, nozzles, and inner barrel.

Inner Barrel Thermocouples •

Purpose: Inner Barrel thermocouples are used to monitor temperature in the inner barrel of the exhaust diffuser.

•

Controls Impact: Temperature signal used by TCP, for turbine control.

•

Additional Information: Three TC’s are placed in the inner barrel, with one at the top inside position of the inner barrel and two on either side of the inner barrel.

•

Typically provided by: MLI 0637

•

Typically interface with: MLI 0706.

Inlet Plenum Thermocouples •

Purpose: Inlet plenum thermocouples are used to monitor temperature in the inlet plenum.

•

Controls Impact: Temperature signal used by TCP, for turbine control.

•

Additional Information: The inlet may be arranged in four different ways: up and fwd, right side, left side, bottom inlet turbine plenum. The most common of these is up and fwd. Each configuration has three TC’s for temperature measurement.

© General Electric Company, 2010. GE Proprietary Information. All Rights Reserved.

7

Turbine Control Devices

GEK 116642 • 10.

11.

12.

13.

8

Typically provided by: MLI 0637

Journal Bearing Thermocouples •

Purpose: Journal bearing thermocouples are used to monitor temperature in the journal bearing.

•

Controls Impact: Temperature signal used by TCP, for turbine monitoring.

•

Additional Information: Two TC’s are located in the first, second and third bearings, depending on frame size.

•

Typically provided by: MLI 235A/B/C

Thrust Bearing Thermocouples •

Purpose: Thrust bearing thermocouples are used to monitor temperature in the thrust bearing.

•

Controls Impact: Temperature signal used by TCP, for turbine monitoring.

•

Additional Information: A total of four TC’s, 2 per bearing, are used to measure temperature on the active and inactive thrust on the first bearing.

•

Typically provided by: MLI 235A

Casing Movement, Seismic Sensor •

Purpose: Seismic sensors are used to monitor velocity of vertical movement on the casing of the turbine.

•

Controls Impact: When movement is detected signal is used by TCP, for turbine control.

•

Additional Information: Redundant sensors are place at the top of every bearing, except for the number two bearing on 7E. Excessive vibration detected by these sensors creates a turbine trip.

•

Typically provided by: MLI 218A/B/C

Bearing Displacement, Vibration Probe •

Purpose: Shaft axial & radial position probes and keyphasor are all used in detecting bearing displacement.

•

Controls Impact: When displacement is detected signal is used by TCP, for turbine control.

•

Additional Information: Probes are places on the X and Y axis 90 degrees apart.

•

Typically provided by: MLI 235A/B/C

© General Electric Company, 2010. GE Proprietary Information. All Rights Reserved.

Turbine Control Devices

GEK 116642

The table below provides device ordering MLI and interfaces MLI. See new unit BOM for specific drawings. Devices

Ordering MLI

Typical Interface MLI's

Flame Detectors

1121

1127, 0401

Magnetic Speed Pickups

0546

1159, 0401

Ignition Exciter / Spark Plugs

1213, 1214

1105, 0401

Compressor Discharge Thermocouples

0637

0219, 1118, 0401

Turbine Case Temperature Management Thermocouples

0637

0705, 9019, 1118, 0401

Exhaust Thermocouples

0623

1625, 0706, 1160, 0401

Wheelspace Thermocouples

0637

1402, 0218, 1409, 0706, 1118, 1160, 0401

Inner Barrel Thermocouples

0637

0706, 1160, 0401

Inlet Plenum Thermocouples

0637

1612, 1159, 0401

Journal Bearing Thermocouples

235A, 235B, 235C

0706, 0801, 0805, 1501, 1502, 1503, 1507, 1154, 1159, 1160, 0401

Thrust Bearing Thermocouples

235A, 235B, 235C

0706, 0801, 0805, 1501, 1502, 1503, 1507, 1154, 1159, 1160, 0401

Casing Movement, Seismic Sensor

218A, 218B, 218C

1159, 1160, 0401

Bearing Displacement, Vibration Probe

235A, 235B, 235C

235A, 235B, 235C

V. CALIBRATION AND MAINTENANCE For calibration, maintenance and replacement guidelines consult the manufacturer’s operation and maintenance manual or appropriate GE specifications and arrangement drawings.

© General Electric Company, 2010. GE Proprietary Information. All Rights Reserved.

9

Turbine Control Devices

GEK 116642

g GE Energy General Electric Company www.gepower.com

10

© General Electric Company, 2010. GE Proprietary Information. All Rights Reserved.

Tab 5

Inlet Filter House Arrangement Without Evaporative Cooler

WĂŐĞϭŽĨϲ 

Pulse Self Cleaning Filter Arrangement

Dirt removal maybe with a screw conveyor or extraction fans.

WĂŐĞϮŽĨϲ 

Filter supports, tube sheet and air distribution system pulse diaphragm valves.

WĂŐĞϯŽĨϲ 

TS1000 Coalescer Filters- located in weather hoods

Cleaning

WĂŐĞϰŽĨϲ 

PULSE FILTER CARTRIDGES

WĂŐĞϱŽĨϲ 

WĂŐĞϲŽĨϲ 

DWG Number 145E4540

Rev -

Released 10/25/2012

Page 1 of 2















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MSA in Europe [ www.MSASafety.com ] Northern Europe

Southern Europe

Eastern Europe

Central Europe

Netherlands MSA Nederland Kernweg 20 1627 LH Hoorn Phone +31 [229] 25 03 03 Fax +31 [229] 21 13 40 [email protected]

France MSA GALLET Zone Industrielle Sud 01400 Châtillon sur Chalaronne Phone +33 [474] 55 01 55 Fax +33 [474] 55 47 99 [email protected]

Poland MSA Safety Poland ul. Wschodnia 5A 05-090 Raszyn k/Warszawy Phone +48 [22] 711 50 33 Fax +48 [22] 711 50 19 [email protected]

Germany MSA AUER GmbH Thiemannstrasse 1 12059 Berlin Phone +49 [30] 68 86 0 Fax +49 [30] 68 86 15 17 [email protected]

Belgium MSA Belgium Duwijckstraat 17 2500 Lier Phone +32 [3] 491 91 50 Fax +32 [3] 491 91 51 [email protected]

Italy MSA Italiana Via Po 13/17 20089 Rozzano [MI] Phone +39 [02] 89 217 1 Fax +39 [02] 82 59 228 info-italy@ msa-europe.com

Czech republic MSA Safety Czech s.r.o. Dolnojircanska 270/22b 142 00 Praha 4 - Kamyk Phone +420 [59] 6 232222 Fax +420 [59] 6 232675 [email protected]

Austria MSA AUER Austria Vertriebs GmbH Modecenterstrasse 22 MGC Office 4, Top 601 A-1030 Wien Phone +43 [0] 1 / 796 04 96 Fax +43 [0] 1 / 796 04 96 - 20 [email protected]

Great Britain MSA Britain Lochard House Linnet Way Strathclyde Business Park BELLSHILL ML4 3RA Scotland Phone +44 [16 98] 57 33 57 Fax +44 [16 98] 74 0141 [email protected]

Sweden MSA NORDIC Kopparbergsgatan 29 214 44 Malmö Phone +46 [40] 699 07 70 Fax +46 [40] 699 07 77 [email protected]

MSA SORDIN Rörläggarvägen 8 33153 Värnamo Phone +46 [370] 69 35 50 Fax +46 [370] 69 35 55 [email protected]

Spain MSA Española Narcís Monturiol, 7 Pol. Ind. del Sudoeste 08960 Sant-Just Desvern [Barcelona] Phone +34 [93] 372 51 62 Fax +34 [93] 372 66 57 [email protected]

Hungary MSA Safety Hungaria Francia út 10 1143 Budapest Phone +36 [1] 251 34 88 Fax +36 [1] 251 46 51 [email protected]

Switzerland MSA Schweiz Eichweg 6 8154 Oberglatt Phone +41 [43] 255 89 00 Fax +41 [43] 255 99 90 [email protected]

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g

GEK 110494c Revised, March 2010

GE Energy

Gas Turbine Functional Description

These instructions do not purport to cover all details or variations in equipment nor to provide for every possible contingency to be met in connection with installation, operation or maintenance. Should further information be desired or should particular problems arise which are not covered sufficiently for the purchaser's purposes the matter should be referred to the GE Company. © General Electric Company, 2010. GE Proprietary Information. All Rights Reserved.

GEK 110494c

Gas Turbine Functional Description

The below will be found throughout this publication. It is important that the significance of each is thoroughly understood by those using this document. The definitions are as follows: NOTE Highlights an essential element of a procedure to assure correctness. CAUTION Indicates a potentially hazardous situation, which, if not avoided, could result in minor or moderate injury or equipment damage.

WARNING INDICATES A POTENTIALLY HAZARDOUS SITUATION, WHICH, IF NOT AVOIDED, COULD RESULT IN DEATH OR SERIOUS INJURY

***DANGER*** INDICATES AN IMMINENTLY HAZARDOUS SITUATION, WHICH, IF NOT AVOIDED WILL RESULT IN DEATH OR SERIOUS INJURY.

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Gas Turbine Functional Description

GEK 110494c

TABLE OF CONTENTS I.

INTRODUCTION ...................................................................................................................................... 4 A. General................................................................................................................................................... 4 B. Detail Orientation................................................................................................................................... 4 C. Gas Path Description.............................................................................................................................. 4 II. BASE AND SUPPORTS ............................................................................................................................ 5 A. Turbine Base .......................................................................................................................................... 5 B. Turbine Supports.................................................................................................................................... 5 III. COMPRESSOR SECTION....................................................................................................................... 6 A. General................................................................................................................................................... 6 B. Rotor ...................................................................................................................................................... 6 C. Stator...................................................................................................................................................... 8 IV. DLN-2+ COMBUSTION SYSTEM........................................................................................................ 10 A. General................................................................................................................................................. 10 B. Outer Combustion Chambers and Flow Sleeves.................................................................................. 14 C. Crossfire Tubes .................................................................................................................................... 14 D. Fuel Nozzle End Covers ...................................................................................................................... 14 E. Cap and Liner Assemblies ................................................................................................................... 14 F. Spark Plugs .......................................................................................................................................... 15 G. Ultraviolet Flame Detectors ................................................................................................................. 15 V. TURBINE SECTION............................................................................................................................... 24 A. General................................................................................................................................................. 24 B. Turbine Rotor....................................................................................................................................... 24 C. Turbine Stator ...................................................................................................................................... 28 VI. BEARINGS ............................................................................................................................................... 35 A. General................................................................................................................................................. 35 VII. LOAD COUPLING .................................................................................................................................. 35

LIST OF FIGURES Figure 1. Compressor Rotor Assembly .................................................................................................................. 7 Figure 2. Compressor Inlet Casing and No. 1 Bearing .......................................................................................... 9 Figure 3. Typical MS9001FA DLN-2+ Combustion System Arrangement ........................................................ 11 Figure 4. Typical MS9001FA DLN-2+ Combustion Arrangement ..................................................................... 12 Figure 5. Flow Sleeve Assembly.......................................................................................................................... 13 Figure 6. Optional Dual Fuel DLN-2+ Fuel Nozzle Cross-Section ..................................................................... 16 Figure 7. Optional Dual Fuel Nozzle Arrangement ............................................................................................. 17 Figure 8. Combustion Liner Assembly ................................................................................................................ 18 Figure 9. Cap Assembly ....................................................................................................................................... 19 Figure 10. Cap Assembly-View From Downstream ............................................................................................ 20 Figure 11. Spark Plug Assembly.......................................................................................................................... 21 Figure 12. Flame Detector Assembly................................................................................................................... 22 Figure 13. Water-Cooled Flame Detector ............................................................................................................ 23 Figure 14. Turbine Rotor Assembly..................................................................................................................... 25 Figure 15. MS9001FA First, Second and Third-Stage Turbine Elements ........................................................... 26 Figure 16. Turbine Section-Cutaway View Showing Cooling Air Flows............................................................ 30 Figure 17. MS9001FA First-Stage Bucket Cooling Passages.............................................................................. 31 Figure 18. MS9001FA Stage-2 Bucket Cooling Flow ......................................................................................... 32 Figure 19. MS9001FA First-Stage Nozzle Cooling............................................................................................. 33 © General Electric Company, 2010. GE Proprietary Information. All Rights Reserved.

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GEK 110494c

Gas Turbine Functional Description

I. INTRODUCTION A. General The MS-9001FA is a single-shaft gas turbine designed for operation as a simple-cycle unit or in a combined steam and gas turbine cycle (STAG). The gas turbine assembly contains six major sections or groups: 1. Air inlet 2. Compressor 3. Combustion System 4. Turbine 5. Exhaust 6. Support systems This section briefly describes how the gas turbine operates and the interrelationship of the major components. NOTE Illustrations and photographs of typical and optional equipment/configurations accompany the text showing components that may have been supplied to this site. These optional equipment/configurations are identified as such and may be disregarded if not applicable. The flange-to-flange description of the gas turbine is also covered in some detail. Support systems pertaining to the air inlet and exhaust, lube oil, cooling water, etc. are covered in detail in individual sections. B. Detail Orientation Throughout this manual, reference is made to the forward and aft ends, and to the right and left sides of the gas turbine and its components. By definition, the air inlet of the gas turbine is the forward end, while the exhaust is the aft end. The forward and aft ends of each component are determined in like manner with respect to its orientation within the complete unit. The right and left sides of the turbine or of a particular component are determined by standing forward and looking aft. C. Gas Path Description The gas path is the path by which gases flow through the gas turbine from the air inlet through the compressor, combustion section and turbine, to the turbine exhaust. When the turbine starting system is actuated and the clutch is engaged, ambient air is drawn through the air inlet plenum assembly, filtered and compressed in the multi-stage, axial-flow compressor. For pulsation protection during startup, compressor bleed valves are open and the variable inlet guide vanes are in the closed position. When the high-speed relay actuates, the bleed valves begin operation automatically and the variable inlet guide vane actuator energizes to position the inlet guide vanes for normal turbine operation. Compressed air from the compressor flows into the annular space surrounding the combustion chambers, from which it flows into the spaces between the outer

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Gas Turbine Functional Description

GEK 110494c

combustion casings and the combustion liners, and enters the combustion zone through metering holes in each of the combustion liners. Fuel from an off-base source is provided to flow lines, each terminating at the primary and secondary fuel nozzles in the end cover of the separate combustion chambers. Options: •

On liquid fueled machines, the fuel is controlled prior to being distributed to the nozzles to provide an equal flow into each liquid fuel distributor valve mounted on each end cover and each liquid fuel line on each secondary nozzle assembly.

•

On gas-fueled machines, the fuel nozzles are the metering orifices which provide the proper flow into the combustion zones in the chambers.

The nozzles introduce the fuel into the combustion zone within each chamber where it mixes with the combustion air and is ignited by one or more of the spark plugs. At the instant when fuel is ignited in one combustion chamber flame is propagated, through connecting crossfire tubes, to all other combustion chambers where it is detected by four primary flame detectors, each mounted on a flange provided on the combustion casings. The hot gases from the combustion chambers flow into separate transition pieces attached to the aft end of the combustion chamber liners and flow from there to the three-stage turbine section. Each stage consists of a row of fixed nozzles and a row of turbine buckets. In each nozzle row, the kinetic energy of the jet is increased, with an associated pressure drop, which is absorbed as useful work by the turbine rotor buckets, resulting in shaft rotation used to turn the generator rotor to generate electrical power. After passing through the third-stage buckets, the gases are directed into the exhaust diffuser. The gases then pass into the exhaust plenum and are introduced to atmosphere through the exhaust stack. II. BASE AND SUPPORTS A. Turbine Base The base that supports the gas turbine is a structural steel fabrication of welded steel beams and plate. Its prime function is to provide a support upon which to mount the gas turbine. Lifting trunnions and supports are provided, two on each side of the base in line with the two structural cross members of the base frame. Machined pads on each side on the bottom of the base facilitate its mounting to the site foundation. Two machined pads, atop the base frame are provided for mounting the aft turbine supports. B. Turbine Supports The MS9001FA has rigid leg-type supports at the compressor end and supports with top and bottom pivots at the turbine end. On the inner surface of each support leg a water jacket is provided, through which cooling water is circulated to minimize thermal expansion and to assist in maintaining alignment between the turbine and the load equipment. The support legs maintain the axial and vertical positions of the turbine, while two gib keys coupled with the turbine support legs maintain its lateral position. One gib key is machined on the lower half of the exhaust frame. The other gib key is machined on the lower half of the forward compressor casing. The keys fit into guide blocks which are welded to the cross beams of © General Electric Company, 2010. GE Proprietary Information. All Rights Reserved.

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the turbine base. The keys are held securely in place in the guide blocks with bolts that bear against the keys on each side. This key-and- block arrangement prevents lateral or rotational movement of the turbine while permitting axial and radial movement resulting from thermal expansion. III. COMPRESSOR SECTION A. General The axial-flow compressor section consists of the compressor rotor and the compressor casing. Within the compressor casing are the variable inlet guide vanes, the various stages of rotor and stator blading, and the exit guide vanes. In the compressor, air is confined to the space between the rotor and stator where it is compressed in stages by a series of alternate rotating (rotor) and stationary (stator) airfoil-shaped blades. The rotor blades supply the force needed to compress the air in each stage and the stator blades guide the air so that it enters the following rotor stage at the proper angle. The compressed air exits through the compressor discharge casing to the combustion chambers. Air is extracted from the compressor for turbine cooling and for pulsation control during startup. Option: •

Air may also be extracted from the compressor when the combustion turbine is operating for use in the plant compressed air system.

B. Rotor The compressor portion of the gas turbine rotor is an assembly of wheels, a speed ring, tie bolts, the compressor rotor blades, and a forward stub shaft (see Figure 1). Each wheel has slots broached around its periphery. The rotor blades and spacers are inserted into these slots and held in axial position by staking at each end of the slot. The wheels are assembled to each other with mating rabbets for concentricity control and are held together with tie bolts. Selective positioning of the wheels is made during assembly to reduce balance correction. After assembly, the rotor is dynamically balanced. The forward stubshaft is machined to provide the thrust collar, which carries the forward and aft thrust loads. The stubshaft also provides the journal for the No. 1 bearing, the sealing surface for the No. 1 bearing oil seals and the compressor low-pressure air seal. The stage 17 wheel carries the rotor blades and also provides the sealing surface for the high-pressure air seal and the compressor-to-turbine marriage flange.

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GEK 110494c

Figure 1. Compressor Rotor Assembly

Gas Turbine Functional Description

© General Electric Company, 2010. GE Proprietary Information. All Rights Reserved.

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GEK 110494c

Gas Turbine Functional Description

C. Stator 1. General The casing area of the compressor section is composed of three major sections. These are the: a. Inlet casing b. Compressor casing c. Compressor discharge casing These casings, in conjunction with the turbine casing, form the primary structure of the gas turbine. They support the rotor at the bearing points and constitute the outer wall of the gas-path annulus. All of these casings are split horizontally to facilitate servicing. 2. Inlet Casing The inlet casing (see Figure 2) is located at the forward end of the gas turbine. Its prime function is to uniformly direct air into the compressor. The inlet casing also supports the No. 1 bearing assembly. The No. 1 bearing lower half housing is integrally cast with the inner bellmouth. The upper half bearing housing is a separate casting, flanged and bolted to the lower half. The inner bellmouth is positioned to the outer bellmouth by nine airfoil-shaped radial struts. The struts are cast into the bellmouth walls. They also transfer the structural loads from the adjoining casing to the forward support which is bolted and doweled to this inlet casing. Variable inlet guide vanes are located at the aft end of the inlet casing and are mechanically positioned, by a control ring and pinion gear arrangement connected to a hydraulic actuator drive and linkage arm assembly. The position of these vanes has an effect on the quantity of compressor inlet air flow. 3. Compressor Casing The forward compressor casing contains the stage 0 through stage 4 compressor stator stages. The compressor casing lower half is equipped with two large integrally cast trunnions which are used to lift the gas turbine when it is separated from its base. The aft compressor casing contains stage 5 through stage 12 compressor stator stages. Extraction ports in aft casing permit removal of 13th-stage compressor air. This air is used for cooling functions and is also used for pulsation control during startup and shutdown. 4. Compressor Discharge Casing The compressor discharge casing is the final portion of the compressor section. It is the longest single casting, is situated at midpoint - between the forward and aft supports - and is, in effect, the keystone of the gas turbine structure. The compressor discharge casing contains the final compressor stages, forms both the inner and outer walls of the compressor diffuser, and joins the compressor and turbine casings. The discharge casing also provides support for the combustion outer casings and the inner support of the first-stage turbine nozzle.

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Gas Turbine Functional Description

GEK 110494c

Figure 2. Compressor Inlet Casing and No. 1 Bearing

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The compressor discharge casing consists of two cylinders, one being a continuation of the compressor casing and the other being an inner cylinder that surrounds the compressor rotor. The two cylinders are concentrically positioned by fourteen radial struts. A diffuser is formed by the tapered annulus between the outer cylinder and inner cylinder of the discharge casing. The diffuser converts some of the compressor exit velocity into added static pressure for the combustion air supply. 5. Blading The compressor rotor and stator blades are airfoil shaped and designed to compress air efficiently at high blade tip velocities. The blades are attached to the compressor wheels by dovetail arrangements. The dovetail is very precise in size and position to maintain each blade in the desired position and location on the wheel. The compressor stator blades are airfoil shaped and are mounted by similar dovetails into ring segments in the first five stages. The ring segments are inserted into circumferential grooves in the casing and are held in place with locking keys. The stator blades of the remaining stages have a square base dovetail and are inserted directly into circumferential grooves in the casing. Locking keys hold them in place. IV. DLN-2+ COMBUSTION SYSTEM A. General The combustion system is of the reverse-flow type with the 18 combustion chambers arranged around the periphery of the compressor discharge casing as shown on Figure 3. Combustion chambers are numbered counterclockwise when viewed looking downstream and starting from the top left of the machine. This system also includes the fuel nozzles, a spark plug ignition system, flame detectors, and crossfire tubes. Hot gases, generated from burning fuel in the combustion chambers, flow through the impingement cooled transition pieces to the turbine. High pressure air from the compressor discharge is directed around the transition pieces. Some of the air enters the holes in the impingement sleeve to cool the transition pieces and flows into the flow sleeve. The rest enters the annulus between the flow sleeve and the combustion liner through holes in the downstream end of the flow sleeve. (See Figure 4 and Figure 5). This air enters the combustion zone through the cap assembly for proper fuel combustion. Fuel is supplied to each combustion chamber through five nozzles designed to disperse and mix the fuel with the proper amount of combustion air.

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Gas Turbine Functional Description

GEK 110494c

Figure 3. Typical MS9001FA DLN-2+ Combustion System Arrangement

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Gas Turbine Functional Description

Figure 4. Typical MS9001FA DLN-2+ Combustion Arrangement

GEK 110494c

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Gas Turbine Functional Description

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GEK 110494c

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Figure 5. Flow Sleeve Assembly

GEK 110494c

Gas Turbine Functional Description

Options: Dual fuel-The DLN-2+ combustion system shown in Figure 4 is a single stage, dual mode combustor capable of operation on both gaseous and liquid fuel. On gas, the combustor operates in a diffusion mode at low loads (50% load). While the combustor is capable of operating in the diffusion mode across the load range, diluent injection would be required for NOx abatement. Oil operation on this combustor is in the diffusion mode across the entire load range, with diluent injection used for NOx . Gas Fuel only-On gas, the combustor operates in a diffusion mode at low loads (50% load). While the combustor is capable of operating in the diffusion mode across the load range, diluent injection would be required for NOx abatement. Liquid fuel only- On oil operation, this combustor is in the diffusion mode across the entire load range, with diluent injection used for Nox. B. Outer Combustion Chambers and Flow Sleeves The outer combustion chambers act as the pressure shells for the combustors. They also provide flanges for the fuel nozzle-end cover assemblies, crossfire tube flanges, and, where called for, spark plugs, flame detectors and false start drains. The flow sleeves (Figure 5) form an annular space around the cap and liner assemblies that directs the combustion and cooling air flows into the reaction region. To maintain the impingement sleeve pressure drop, the openings for crossfire tubes, spark plugs, and flame detectors are sealed with sliding grommets. C. Crossfire Tubes All combustion chambers are interconnected by means of crossfire tubes. The outer chambers are connected with an outer crossfire tube and the combustion liner primary zones are connected by the inner crossfire tubes. D. Fuel Nozzle End Covers There are five fuel nozzle assemblies in each combustor. Figure 6 and Figure 7 shows a typical crosssection of a DLN-2+ fuel nozzle. The nozzle shown is for the dual fuel option and shows the passages for diffusion gas, premixed gas, oil, and water. When mounted on the endcover, as shown in Figure 6, the diffusion passages of four of the fuel nozzles are fed from a common manifold, called the diffusion circuit, that is built into the endcover. The premixed passage of the same four nozzles are fed from another internal manifold called the PM4. The premixed passages of the remaining nozzle is supplied by the PM1 fuel circuit; E. Cap and Liner Assemblies The combustion liners (Figure 8) use external ridges and conventional cooling slots for cooling. Interior surfaces of the liner are thermal barrier coated to reduce metal temperatures and thermal gradients. The cap (Figure 9 and Figure 10) has five burner tubes that engage each of the five fuel nozzles. It is cooled by a combination of film cooling and impingement.

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Gas Turbine Functional Description

GEK 110494c

F. Spark Plugs Combustion is initiated by means of the discharge from spark plugs which are bolted to flanges on the combustion cans and centered within the liner and flowsleeve in adjacent combustion chambers. A typical spark plug arrangement is shown in Figure 11. These plugs receive their energy from high energy-capacitor discharge power supplies. At the time of firing, a spark at one or more of these plugs ignites the gases in a chamber; the remaining chambers are ignited by crossfire through the tubes that interconnect the reaction zone of the remaining chambers. G. Ultraviolet Flame Detectors During the starting sequence, it is essential that an indication of the presence or absence of flame be transmitted to the control system. For this reason, a flame monitoring system is used consisting of multiple flame detectors located as shown on Figure 3. The flame detectors (Figure 12 and Figure 13) have water cooled jackets to maintain acceptable temperatures. The ultraviolet flame sensor contains a gas filled detector. The gas within this detector is sensitive to the presence of ultraviolet radiation which is emitted by a hydrocarbon flame. A DC voltage, supplied by the amplifier, is impressed across the detector terminals. If flame is present, the ionization of the gas in the detector allows conduction in the circuit which activates the electronics to give an output indicating flame. Conversely, the absence of flame will generate an output indicating no flame. The signals from the four flame detectors are sent to the control system which uses an internal logic system to determine whether a flame or loss of flame condition exists. For detailed operating and maintenance information covering this equipment, refer to the vendor publications.

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GEK 110494c

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Gas Turbine Functional Description

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Figure 6. Optional Dual Fuel DLN-2+ Fuel Nozzle Cross-Section

Gas Turbine Functional Description

GEK 110494c

Figure 7. Optional Dual Fuel Nozzle Arrangement

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Gas Turbine Functional Description

Figure 8. Combustion Liner Assembly

GEK 110494c

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GEK 110494c

Figure 9. Cap Assembly

Gas Turbine Functional Description

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Gas Turbine Functional Description

Figure 10. Cap Assembly-View From Downstream

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Gas Turbine Functional Description

GEK 110494c

Figure 11. Spark Plug Assembly

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Gas Turbine Functional Description

Figure 12. Flame Detector Assembly

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Gas Turbine Functional Description

GEK 110494c

Figure 13. Water-Cooled Flame Detector

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Gas Turbine Functional Description

V. TURBINE SECTION A. General The three-stage turbine section is the area in which energy in the form of high temperature pressurized gas, produced by the compressor and combustion sections, is converted to mechanical energy. MS9001FA gas turbine hardware includes the turbine rotor, turbine casing, exhaust frame, exhaust diffuser, nozzles, and shrouds. B. Turbine Rotor 1. Structure The turbine rotor assembly, shown in Figure 14, consists of the forward and aft turbine wheel shafts and the first-, second- and third-stage turbine wheel assemblies with spacers and turbine buckets. Concentricity control is achieved with mating rabbets on the turbine wheels, wheel shafts, and spacers. The wheels are held together with through bolts mating up with bolting flanges on the wheel shafts and spacers. Selective positioning of rotor members is performed to minimize balance corrections. 2. Wheel Shafts The turbine rotor distance piece extends from the first-stage turbine wheel to the aft flange of the compressor rotor assembly. The turbine rotor aft shaft includes the No. 2 bearing journal. 3. Wheel Assemblies Spacers between the first and second, and between the second and third-stage turbine wheels determine the axial position of the individual wheels. These spacers carry the diaphragm sealing lands. The 1-2 spacer forward and aft faces include radial slots for cooling air passages. Turbine buckets are assembled in the wheels with fir-tree-shaped dovetails that fit into matching cut-outs in the turbine wheel rims. All three turbine stages have precision investment-cast, longshank buckets. The long-shank bucket design effectively shields the wheel rims and bucket root fastenings from the high temperatures in the hot gas path while providing mechanical damping of bucket vibrations. As a further aid in vibration damping, the stage-two and stage-three buckets have interlocking shrouds at the bucket tips. These shrouds also increase the turbine efficiency by minimizing tip leakage. Radial teeth on the bucket shrouds combine with stepped surfaces on the stator to provide a labyrinth seal against gas leakage past the bucket tips. Figure 15 shows typical first-, second-, and third-stage turbine buckets for the MS9001FA. The increase in the size of the buckets from the first to the third stage is necessitated by the pressure reduction resulting from energy conversion in each stage, requiring an increased annulus area to accommodate the gas flow.

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Gas Turbine Functional Description

© General Electric Company, 2010. GE Proprietary Information. All Rights Reserved.

GEK 110494c

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Figure 14. Turbine Rotor Assembly

GEK 110494c

Gas Turbine Functional Description

Figure 15. MS9001FA First, Second and Third-Stage Turbine Elements

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Gas Turbine Functional Description

GEK 110494c

4. Cooling The turbine rotor is cooled to maintain reasonable operating temperatures and, therefore, assure a longer turbine service life. Cooling is accomplished by means of a positive flow of cool air extracted from the compressor and discharged radially outward through a space between the turbine wheel and the stator, into the main gas stream. This area is called the wheelspace. Figure 16 shows the turbine cooling air flows. 5. First-Stage Wheelspaces The first-stage forward wheelspace is cooled by compressor discharge air. A labyrinth seal is installed at the aft end of the compressor rotor between the rotor and inner barrel of the compressor discharge casing. The leakage through this labyrinth furnishes the air flow through the first-stage forward wheelspace. This cooling air flow discharges into the main gas stream aft of the first-stage nozzle. The first-stage aft wheelspace is cooled by 13th stage extraction air ported through the 2nd stage nozzle. This air returns to the gas path forward of the 2nd stage nozzle. 6. Second-Stage Wheelspaces The second-stage forward wheelspace is cooled by leakage from the first-stage aft wheelspace through the interstage labyrinth. This air returns to the gas path at the entrance of the secondstage buckets. The second-stage aft wheelspace is cooled by 13th stage extraction air ported through the 3rd stage nozzle. Air from this wheelspace returns to the gas path at the third-stage nozzle entrance. 7. Third-Stage Wheelspaces The third-stage forward wheelspace is cooled by leakage from the second-stage aft wheelspace through the interstage labyrinth. This air reenters the gas path at the third-stage bucket entrance. The third-stage aft wheelspace obtains its cooling air from the discharge of the exhaust frame cooling air annulus. This air flows through the third-stage aft wheelspace, and into the gas path at the entrance to the exhaust diffuser. 8. Buckets Air is introduced into each first-stage bucket through a plenum at the base of the bucket dovetail (Figure 16). It flows through serpentine cooling holes extending the length of the bucket and exits at the trailing edge and the bucket tip. The holes are spaced and sized to obtain optimum cooling of the airfoil with minimum compressor extraction air. Figure 17 shows the MS9001FA first-stage bucket design. Unlike the first-stage buckets, the second-stage buckets are cooled by spanwise air passages the length of the airfoil. Air is introduced like the first-stage, with a plenum at the base of the bucket dovetail. Again airfoil cooling is accomplished with minimum penalty to the thermodynamic cycle. See Figure 18.

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The third-stage buckets are not internally air cooled; the tips of these buckets, like the secondstage buckets, are enclosed by a shroud which is a part of the tip seal. These shrouds interlock from bucket to bucket to provide vibration damping. C. Turbine Stator 1. Structure The turbine casing and the exhaust frame constitute the major portion of the MS9001FA gas turbine stator structure. The turbine nozzles, shrouds, and turbine exhaust diffuser are internally supported from these components. 2. Turbine Casing The turbine casing controls the axial and radial positions of the shrouds and nozzles. It determines turbine clearances and the relative positions of the nozzles to the turbine buckets. This positioning is critical to gas turbine performance. Hot gases contained by the turbine casing are a source of heat flow into the casing. To control the casing diameter, it is important to reduce the heat flow into the casing and to limit its temperature. Heat flow limitations incorporate insulation, cooling, and multi-layered structures. 13th stage extraction air is piped into the turbine casing annular spaces around the 2nd and 3rd stage nozzles. From there the air is ported through the nozzle partitions and into the wheel spaces. Structurally, the turbine casing forward flange is bolted to the bulkhead flange at the aft end of the compressor discharge casing. The turbine casing aft flange is bolted to the forward flange of the exhaust frame 3. Nozzles In the turbine section there are three stages of stationary nozzles (Figure 16) which direct the high-velocity flow of the expanded hot combustion gas against the turbine buckets causing the turbine rotor to rotate. Because of the high pressure drop across these nozzles, there are seals at both the inside and the outside diameters to prevent loss of system energy by leakage. Since these nozzles operate in the hot combustion gas flow, they are subjected to thermal stresses in addition to gas pressure loadings. 4. First-Stage Nozzle The first-stage nozzle receives the hot combustion gases from the combustion system via the transition pieces. The transition pieces are sealed to both the outer and inner sidewalls on the entrance side of the nozzle; this minimizes leakage of compressor discharge air into the nozzles. The Model 9001FA gas turbine first-stage nozzle (Figure 19) contains a forward and aft cavity in the vane and is cooled by a combination of film, impingement and convection techniques in both the vane and sidewall regions. The nozzle segments, each with two partitions or airfoils, are contained by a horizontally split retaining ring which is centerline supported to the turbine casing on lugs at the sides and guided by pins at the top and bottom vertical centerlines. This permits radial growth of the retaining ring, resulting from changes in temperature, while the ring remains centered in the casing.

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Gas Turbine Functional Description

GEK 110494c

The aft outer diameter of the retaining ring is loaded against the forward face of the first-stage turbine shroud and acts as the air seal to prevent leakage of compressor discharge air between the nozzle and turbine casing. On the inner sidewall, the nozzle is sealed by a flange cast on the inner diameter of the sidewall that rests against a mating face on the first-stage nozzle support ring. Circumferential rotation of the segment inner sidewall is prevented by an eccentric bushing and a locating dowel that engages a lug on the inner sidewall. The nozzle is prevented from moving forward by the lugs welded to the aft outside diameter of the retaining ring at 45 degrees from vertical and horizontal centerlines. These lugs fit in a groove machined in the turbine shell just forward of the first-stage shroud T hook. By moving the horizontal joint support block and the bottom centerline guide pin and then removing the inner sidewall locating dowels, the lower half of the nozzle can be rolled out with the turbine rotor in place. 5. Second-Stage Nozzle Combustion air exiting from the first stage buckets is again expanded and redirected against the second- stage turbine buckets by the second-stage nozzle. This nozzle is made of cast segments, each with two partitions or airfoils. The male hooks on the entrance and exit sides of the outer sidewall fit into female grooves on the aft side of the first-stage shrouds and on the forward side of the second-stage shrouds to maintain the nozzle concentric with the turbine shell and rotor. This close fitting tongue-and-groove fit between nozzle and shrouds acts as an outside diameter air seal. The nozzle segments are held in a circumferential position by radial pins from the shell into axial slots in the nozzle outer sidewall. The second-stage nozzle is cooled with 13th stage extraction air

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Figure 16. Turbine Section-Cutaway View Showing Cooling Air Flows

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Gas Turbine Functional Description

GEK 110494c

Figure 17. MS9001FA First-Stage Bucket Cooling Passages

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Figure 18. MS9001FA Stage-2 Bucket Cooling Flow

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Gas Turbine Functional Description

GEK 110494c

Figure 19. MS9001FA First-Stage Nozzle Cooling

© General Electric Company, 2010. GE Proprietary Information. All Rights Reserved.

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GEK 110494c

Gas Turbine Functional Description

6. Third-Stage Nozzle The third-stage nozzle receives the hot gas as it leaves the second-stage buckets, increases its velocity by pressure drop, and directs this flow against the third-stage buckets. The nozzle consists of cast segments, each with three partitions or airfoils. It is held at the outer sidewall forward and aft sides in grooves in the turbine shrouds in a manner similar to that used on the second- stage nozzle. The third-stage nozzle is circumferentially positioned by radial pins from the shell. 13th stage extraction air flows through the nozzle partitions for nozzle convection cooling and for augmenting wheelspace cooling air flow. 7. Diaphragm Attached to the inside diameters of both the second and third-stage nozzle segments are the nozzle diaphragms. These diaphragms prevent air leakage past the inner sidewall of the nozzles and the turbine rotor. The high/low, labyrinth seal teeth are machined into the inside diameter of the diaphragm. They mate with opposing sealing lands on the turbine rotor. Minimal radial clearance between stationary parts (diaphragm and nozzles) and the moving rotor are essential for maintaining low interstage leakage; this results in higher turbine efficiency. 8. Shrouds Unlike the compressor blading, the turbine bucket tips do not run directly against an integral machined surface of the casing but against annular curved segments called turbine shrouds. The shrouds’ primary function is to provide a cylindrical surface for minimizing bucket tip clearance leakage. The turbine shrouds’ secondary function is to provide a high thermal resistance between the hot gases and the comparatively cool turbine casing. By accomplishing this function, the turbine casing cooling load is drastically reduced, the turbine casing diameter is controlled, the turbine casing roundness is maintained, and important turbine clearances are assured. The first and second-stage stationary shroud segments are in two pieces; the gas-side inner shroud is separated from the supporting outer shroud to allow for expansion and contraction, and thereby improve low-cycle fatigue life. The first-stage shroud is cooled by impingement, film, and convection. The shroud segments are maintained in the circumferential position by radial pins from the turbine casing. Joints between shroud segments are sealed by interconnecting tongues and grooves. 9. Exhaust Frame The exhaust frame is bolted to the aft flange of the turbine casing. Structurally, the frame consists of an outer cylinder and an inner cylinder interconnected by the radial struts. The No. 2 bearing is supported from the inner cylinder. The exhaust diffuser located at the aft end of the turbine is bolted to the exhaust frame. Gases exhausted from the third turbine stage enter the diffuser where velocity is reduced by diffusion and pressure is recovered. At the exit of the diffuser, the gases are directed into the exhaust plenum.

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© General Electric Company, 2010. GE Proprietary Information. All Rights Reserved.

Gas Turbine Functional Description

GEK 110494c

Exhaust frame radial struts cross the exhaust gas stream. These struts position the inner cylinder and No. 2 bearing in relation to the outer casing of the gas turbine. The struts must be maintained at a constant temperature in order to control the center position of the rotor in relation to the stator. This temperature stabilization is accomplished by protecting the struts from exhaust gases with a metal fairing that forms an air space around each strut and provides a rotated, combined airfoil shape. Off-base blowers provide cooling air flow through the space between the struts and the wrap- per to maintain uniform temperature of the struts. This air is then directed to the third-stage aft wheelspace. Trunnions on the sides of the exhaust frame are used with similar trunnions on the forward compressor casing to lift the gas turbine when it is separated from its base. VI. BEARINGS A. General The MS9001FA gas turbine unit has two four-element, tilting pad journal bearings which support the gas turbine rotor. The unit also includes a thrust bearing to maintain the rotor-to-stator axial position. Thrust is absorbed by a tilting pad thrust bearing with eight shoes on both sides of the thrust bearing runner. These bearings and seals are incorporated in two housings: one at the inlet casing, one in the exhaust frame. These main bearings are pressure-lubricated by oil supplied from the main lubricating oil system. The oil flows through branch lines to an inlet in each bearing housing. 1. Lubrication The main turbine bearings are pressure-lubricated with oil supplied, from the oil reservoir. Oil feed piping, where practical, is run within the lube oil drain lines, or drain channels, as a protective measure. In the event of a supply line leak, oil will not be sprayed on nearby equipment, thus eliminating a potential safety hazard. When the oil enters the housing inlet, it flows into an annulus around the bearing. From the annulus, the oil flows through machined holes or slots to the bearing rotor interface. 2. Lubricant Sealing Oil on the surface of the turbine shaft is prevented from being spun along the shaft by oil seals in each of the bearing housings. These labyrinth seals are assembled at the extremities of the bearing assemblies where oil control is required. A smooth surface is machined on the shaft and the seals are assembled so that only a small clearance exists between the oil seal and the shaft. The oil seals are designed with tandem rows of teeth and an annular space between them. Pressurized sealing air is admitted into this space to prevent lubricating oil vapor from exiting the bearing housing. The air that returns with the oil to the main lubricating oil reservoir is vented to atmosphere after passing through an oil vapor extractor. VII. LOAD COUPLING A rigid, hollow coupling connects the forward compressor rotor shaft to the generator. A bolted flange connection forms the joint at each end of the coupling. © General Electric Company, 2010. GE Proprietary Information. All Rights Reserved.

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GEK 110494c

Gas Turbine Functional Description

g

GE Energy General Electric Company www.gepower.com

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© General Electric Company, 2010. GE Proprietary Information. All Rights Reserved.

GE Power Systems Annular Space or Annulus The ring like space between the combustion liner and the flow shield.

GGAS TURBINE TERMINOLOGY Accessory Compartment A sheet metal house with access doors which may be located on the same base as the turbine or on a separate base. It contains the mechanical accessories needed to support the prime mover operation.

Anti-Icing System Preheating of the inlet air to prevent ice formation in the inlet system. Atomizing Air High pressure air which is used to break up liquid fuel into small droplets to improve the combustion.

Accessory Coupling A fluid or grease filled flexible coupling which drives the accessory gear from (the forward end of) the prime mover.

Aux. Hydraulic Supply Pump The motor driven high pressure pump used to supply servo pressure during start-up or emergency conditions.

Accessory Gear Encompasses a number of gears which drive most of the gas turbine accessories at the proper speeds and which connects the turbine to its starting device. The gear is driven by the starting device, and then by the turbine when the unit reaches self-sufficient speed. Common items driven by this gear are: liquid fuel pump, water pump, main lube pump, main hydraulic pump, main atomizing air compressor.

Aux. Lube Pump Provides lubricating oil during start-up and shutdown, and serve as a standby to the main pump. An AC motor is usually the drive source. Axial Flow A (gas turbine) compressor which moves air axially through a series of rotor and stator compressor blades. The rotating elements impart momentum to the air mass, and the stator elements convert that momentum to pressure in conjunction with the converging walls of the compressor casing.

Accessory Gear Box Refers to the complete accessory gear assembly. Accumulator A hydro-pneumatic device designed to absorb a hydraulic shock and to deliver a regulated force (in the form of pressure and flow) during transient demands on a system.

Base Load The load at the rated temperature control setpoint at which the turbine can be operated to maintain the recommended parts life expectancy.

Acid Removal Filter The machine part that neutralizes acid in the lube oil supply.

Bearing The stationary machine part which contains the journal bearing liner.

Actuator A self-contained device designed to deliver a controlled or regulated force in order to activate some other device. Aft End

Bearing Feed Header The section of the lube oil piping, downstream of the oil filters, which carries lubrication to the individual turbine bearings.

The exhaust end of the gas turbine.

Bearing Seal A general term identifying a means of preventing oil leakage from a bearing.

Aftercooler The atomizing air cooler downstream of the main atomizing air compressor.

Bellmouth The flared bell-shaped cast inlet which provides an even airflow distribution to the compressor through the inlet guide vanes.

Air Separator The device which removes large particulate matter from an air supply via an inertial or centrifugal force.

Black Start The means of starting a turbine without incoming AC power.

Ambient Air Air surrounding the gas turbine housing which enters the turbine to support combustion. GLOSSARY OF TERMINOLOGY

Blade A rotating or stationary airfoil in an axial compressor. 1

C00023GT

GE Power Systems Blow Off Valve A valve which bypasses air from the compressor around the regenerator and the high and low pressure turbines (i.e. two (2) shafts gas turbine) to reduce available energy and prevent overspeed during a sudden loss of load. It is primarily used on two shaft, generator drives.

Combustion Liner The chamber where chemical energy is released and added to the gas flow path. Combustion System A system consisting of fuel nozzles, spark plugs, flame detectors, crossfire tubes, combustion liners, transition pieces and a combustion casing or wrapper.

Brittle The loss of resiliency in the parent metal due to aging, extreme cold or chemical action.

Compression Ratio The ratio of the compressor discharge pressure to the inlet pressure.

Brake Horsepower The horsepower developed at the load coupling.

Compressor The mechanical component which is used to increase the pressure of the working medium within its structure.

Buckets Airfoil elements mounted radially on the rotor wheel to transfer energy from the working medium to the turbine rotor.

Compressor Discharge Casing Contains the last stages of the compressor stator blades and is used to:

Burnishing The process of smoothing a metal surface by means of a mechanical action with no loss of material. This normally occurs on plain bearing surfaces.

— Join the compressor and turbine stators — Support the forward end of the combustion wrapper — Provide an inner support for the first stage turbine nozzles.

Bypass Valve A device which regulates the flow of a fluid in: A) A fuel bypass valve on a liquid fuel system using a positive displacement pump or, B) An air control valve used for compressor pulsation protection.

— May provide support for a bearing Control Compt. (Control CAB) The compartment which contains the gas turbine electrical controls and protection equipment.

Centrifugal Separator A device used to remove dust from the gas turbine cooling and sealing air system. Separation is achieved by a centrifugal action.

Cooling and Sealing Air A system which provides air pressure for cooling and sealing various turbine components.

Chamfer A beveled edge (i.e. by the removal of some of the gear material at an angle from the top land to the bottom land at the ends of the teeth.

Cooling Water Pump Provides cooling water flow for the system. A gear box or electric motor drives the pump.

Check Valve A device which allows fluid flow in only one (1) direction.

Cooling Water Radiator The on or off base water/air or water/water heat exchanger.

CO2 Carbon dioxide, used as a fire extinguishing medium.

Coupling A component which connects a driven component to the drive source. Examples: Accessory Gear Coupling, Load Coupling, Pump Coupling, Starting Motor Coupling, etc.

Combustor or Combustion Chamber The mechanical component of the combustion system in which the combustion takes place (increasing the temperature of the working medium). C00023GT

Coupling Comp. pling. 2

A housing for the load cou-

GLOSSARY OF TERMINOLOGY

GE Power Systems Exhaust Frame The machine part which usually support the aft journal bearing. The air discharged from the exhaust diffuser is directed to the turning vanes. Air-cooled, internal struts maintain position of the bearing.

Cranking The turning of the turbine rotor during start-up or shutdown. Crossfire Tubes The piping which interconnects the combustion chambers on multiple combustion chamber turbines. These tubes also allow flame propagation from the two (2) spark plug ignited combustors to the other chambers.

Exhaust Hood The component which surrounds the aft bearing area and is bolted to the turbine case aft flange. It assists in guiding air flow in to the turning vanes.

Cycle Thermal The ratio of the net work output to the total heat input = [ Work of Turbine - Work of Efficiency Compressor ]/Heat Input.

Exhaust Plenum An enclosed cavity which receives discharged exhaust gases after the gases exit from the load turbine wheel.

Diaphragm The stationary element containing a set of nozzles used to expand the working medium and direct it against the rotating blades.

Exhaust Ports Machine bosses on the compressor casing which extracts air for cooling and sealing.

Diffuser The section designed to increase the area of the flowpath to convert flow velocity to static fluid pressure.

Exhaust Pressure Drop

Exhaust duct losses.

Exhaust Stack The exhaust assembly which can include silencing sections.

Distance Piece A hollow cylindrical shaft used to couple the axial-flow compressor to the first stage turbine wheel.

Exit Guide Vanes Guide vanes at the exhaust end of the load turbine which direct the gas flow to the exhaust.

Eductor A device used for evacuating an enclosed space usually by means of air purge.

Expansion Joints expansion.

Electrostatic A device used for removing oil particles from an air/oilmixture using the charged particle Precipitator method.

Extraction Valves Devices used to assist in preventing compressor surge by allowing air to be extracted during off-design periods from an intermediate compressor stage.

Emergency Stop An immediate de-activation of the fuel system due to an emergency electrical or mechanical device or done manually.

Filters Components normally used to remove solid particulate matter in a given size range from an air/fluid supply and from lube oil.

Emergency Lube Oil Pump The back-up lube oil pump to the main pump. It uses the 125 Vdc battery to power the motor.

Fin Fan (Cooling Fan) A mechanically or electric motor driven air fan used tocool the water running through the radiators.

Evaporator Cooling Liquid (usually water) is added to an air supply, and the resultant evaporation cools the air mass and increases its mass per unit volume.

Firing Temp The temperature of the air mass at the inlet of the first stage turbine nozzle. Flame Detectors Sensors (usually ultraviolet) used to detect flame.

Exhaust Diffuser The component which slows the exhaust gas exit from the last turbine stage to recover energy, and reduce losses. GLOSSARY OF TERMINOLOGY

Devices that allow thermal

Flow Divider A device which distributers fuel flow equally to the fuel nozzles. 3

C00023GT

GE Power Systems A general term used to describe a liquid or Heat Exchanger/Cooler The heat transfer equipment used to extract excessive heat from one working fluid and transmit it to another non-workFuel Forwarding Skid The off-base pumping ing fluid for eventual dissipation to the atmosphere. unit used to transfer, condition and control the flow Heat Rate The ratio of input energy to output enof liquid fuel to the turbine. ergy (i.e. BTU/BHP-HR). Fuel, Gas Either natural gas with a high heat conHeat Recovery System The means of recovertent or manufactured gas. ing heat which would otherwise be lost during the process. Fuel, Light Distillate (Also known as No. 2 fuel.) A volatile distillate fuel having good comHeating Value The heat content of a given fuel bustion properties, clean burning and readily atom(i.e. BTU/lb.). ized. Preheating is usually not necessary. High Pressure Turbine The first stage turbine Fuel Nozzle The device that injects fuel into the (that drives the compressor on 2-shaft gas turbines). combustion chamber. Hot Gas Path A path of flow of the hot gases Fuel Oil Stop Valve A spring-closed, hydrauliconsisting of the combustion chambers, transition cally opened device used as a positive shutoff of pieces, turbine nozzles and buckets, and the exliquid fuel. haust section. GTFluid gas.

Fuel Pump, Main The shaft driven, high pressure, liquid fuel pump.

Hydraulic Ratchet A form of turning gear which turns the rotor slightly at periodic intervals.

Fuel, Residual Low volatility petroleum products remaining at the end of a refinery distillation processes. All residual fuels require heating for pumping, filtering and proper air atomization at the fuel nozzle.

Inductor Alternator A permanent magnet type of AC generator connected to the compressor shaft. Inlet Guide Vane The guide vanes at the inlet to the compressor which direct and control the air flow to the first stage of the axial flow compressor.

Fuel Treatment The process of treating residual fuel to eliminate or inhibit contaminants.

Inlet Plenum An enclosed cavity that directs the inlet air to the gas turbine.

GAC Abbreviation for the Generator Auxiliary Compartment containing high voltage switch gear and excitation.

Inlet Pressure Drop (in inches of water).

Inlet Temperature The inlet air temperature to the gas turbine compressor.

Gib Block A steel block welded to the turbine base which has adjusting bolts for axial and transverse locating of the turbine. Provision is made for a gib key in the gib block.

Journal Bearing The part that supports the weight of the rotating shaft during normal operation. Labyrinth Packing A seal designed with multiple rows of (aluminum alloy) teeth located at the extremities of the bearing assemblies. Sealing air is circulated between the shaft and the seal to prevent oil from passing the seal and spreading along the shaft.

Gib Key The key for the gib block (i.e. described above). It is machined as an integral part of the lower half of the exhaust frame. Heat Consumption The heat consumed at rated output (i.e. BTU/hr.). C00023GT

The inlet duct pressure drop

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GLOSSARY OF TERMINOLOGY

GE Power Systems 5 Overspeed Bolt A spring loaded sliding rod, which is located in the accessory gear box monuted on the shaft connected to the turbine rotor, and mechanically senses a rotor overspeed condition and generates a trip independent of the electrical overspeed protection system.

Lagging The thermal and/or acoustic covering or enclosure. Lifting Trunnion Extensions which are integrally cast as part of the casing and used to hold slings for lifting purposes.

Pad Support pads located on all base mounted assemblies.

Lighting Transformer A device usually associated with backfeeding the generator output of 13.8KV and reducing it to 480/V 3-phase. Load Shaft

Partition The airfoil shaped stator portion of the nozzle assembly.

The low pressure turbine shaft.

Peak Load The load reached at the peak exhaust temperature control setpoint (above the base load setpoint) which produces more power but reduces the life expectancy of the turbine parts.

Load Turbine Nozzle The variable angle nozzle between the high pressure and low pressure turbine wheels on 2-shaft turbines which is to aproportion energy distribution between the turbines. Low Pressure Turbine

Peak Reserve A short term rating (seldom used) for getting maximum power, recognizing that this drastically reduces the life of the hot section turbine parts.

The load turbine.

Lube Oil Header The main lube oil piping which feeds the turbine bearings, gears, coupling, etc.

Platform The portion of a turbine bucket between the airfoil shape and the shank.

LVDT Abbreviation for Linear Variable Differential Transformer.

Plenum An enclosure which contains a volume of air (i.e. inlet) or exhaust gas (i.e. exhaust).

Mist Eliminator A device which removes small oil droplets from the oil tank vent system prior to the discharge of the vapor in to the atmosphere. Model

Power Plant A comprehensive term for the components which are contained in an integrated power system.

Defines the gas turbine frame size.

Pre-cooler The air cooler upstream of the main atomizing air compressor.

Nozzle/Diaphragm Assembly A combination of the nozzle and the air control device between the turbine stages at the inner side wall.

Pre-selected Load An adjustable, pre-designated load point between spinning reserve and base load.

Nozzle Segment A small number of nozzle partitions made as an assembly: multiple assemblies will constitute a complete nozzle assembly.

Pressure Ratio The ratio of the compressor discharge pressure to the inlet pressure.

Off-Base A part which is not mounted on the accessory, turbine or generator base.

Pulsation Protection A mechanical network designed to prevent surge/pulsation during off-speed conditions of the compressor.

On-Base A part which is mounted on th accessory, turbine or generator base.

Pump, Centrifugal A non-positive displacement pump designed to use a rotor impeller in an enclosure as a means of transferring a fluid from one place to another.

Outer Combustion Casing A cover that provides a pressure vessel and an air flow path. GLOSSARY OF TERMINOLOGY

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C00023GT

GE Power Systems Soleplates Individually grouted-in foundation plates used for mounting and supporting the pads of the gas turbine bases.

Pump, Gear A positive displacement pump that consists of a drive gear and driven gear mounted in a housing. The working medium travels from the intake port around the outside of the gear to the outlet port.

Spinning Reserve The minimum load control point based on generator output.

Regenerative Cycle The working cycle which recovers a portion of the exhaust heat to reduce the cycle heat input required to read cycle operating temperatures. The working medium passes through compressor, regenerator, combustor, turbine and regenerator.

Stage The combination of one row of stator blades or nozzles with one row of rotor blades or buckets. Starting Clutch The (overrunning, hydraulically positioned jaw) clutch which connects the torque converter or turning gear output to the accessory gear box and disengages when the turbine reaches self-sustaining speed.

Regenerator A heat exchanger used to transfer heat from the exhaust gas to the working fluid before it enters the combustor.

Starting Device The machine part used to produce adequate torque for the starting system. Some types of starting devices are:

Rotor The rotating part of an assembly which is usually surrounded by a stator or stationary casing. RTD Abbreviation for a Resistance Temperature Detector.

1. Diesel Engine

SFC Specific fuel consumption (i.e. lbs/BHPHR) defined for a given fuel heating value.

3. Steam Turbine

Shaft Horsepower The power developed at the input or output shaft.

5. Turbine Impingement

2. Electric Motor 4. Natural Gas Expansion Turbine 6. Air motor

Shank The portion of a bucket between the platform and the dovetail.

Stator The stationary part of an assembly usually surrounding a rotating component or rotor.

Shroud A segmented part located adjacent to the blade tips which is used to limit the working fluid leakage.

Stub Shaft A hollow cylindrical section integral with the first stage compressor wheel. Thermocouple A pair of dissimilar metals joined in series to form a closed circuit, which will generate a thermo-electric current when heated.

Silencer A section of the inlet or exhaust of a gas turbine designed to reduce the sound level of air passing through it.

Thrust Bearing An active or inactive machine part which absorbs the axial thrust of the rotating shaft.

Simple Cycle A cycle where the working fluid passes directly through the compressor, combustor and turbine (without heating/cooling).

Tie Bolt A large bolt used to assemble the compressor rotor wheels.

Single Shaft Turbine A gas turbine whose rotating components, (compressor and turbine) are arranged on one shaft. C00023GT

Torque Converter A hydraulic device coupled to the turbine starting means which transfers and 6

GLOSSARY OF TERMINOLOGY

GE Power Systems amplifies torque causing turbine compressor shaft rotation during start up.

Valve, Relief A valve that automatically maintains a maximum, predetermined pressure by discharging or bypassing the fluid in a system.

Transition Piece A thin walled duct used to conduct the combustion gases from the circular combustion chambers to the annular turbine nozzle passage.

Valve, Servo A hydraulically powered valve with provisions for direct control (i.e. positioning) in direct relation with a primary control of a comparatively low level of force. Used for proportional control.

Turbine Stage A set of stationary nozzles and one row of moving buckets mounted on a wheel. The working medium expands through the stationary nozzle to a lower pressure causing kinetic energy to be transfered to the moving buckets.

Valve, Solenoid A valve specifically designed to control the flow of fluid by means of the magnetic action of an electric coil on a movable core or plunger, which actuates the valve stem or pilot needle. Used for on-off control.

Turbine Wheels Discs on the gas turbine shaft which are used to mount buckets on the wheel periphery.

Valve, Temp. Regulating A self-acting valve designed for controlling the flow of fluids via a thermostatic element located in the fluid.

Turning Gear The machine part which is used to break the turbine away while starting and rotate the shaft during cooldown and inspection.

Vane An airfoil used to direct the flow of air or gas. Water Removal Filter A device which removes suspended water from the lube oil.

Two-shaft Turbine A turbine arrangement where the high pressure and low pressure turbine stages are only coupled aerodynamically and run at different speeds.

Wheelspace Temperature The temperature of the air in close proximity to the surface of the turbine wheel below the platform surface of the turbine buckets.

Valve, Pressure Regulating A valve designed for continuous automatic control of pressure.

GE Power Systems Training General Electric Company One River Road Schenectady, NY 12345

GLOSSARY OF TERMINOLOGY

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C00023GT

GER-3567H

GE Power Systems

GE Gas Turbine Performance Characteristics Frank J. Brooks GE Power Systems Schenectady, NY

GE Gas Turbine Performance Characteristics Contents Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Thermodynamic Principles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 The Brayton Cycle. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Thermodynamic Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Combined Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Factors Affecting Gas Turbine Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Air Temperature and Site Elevation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Humidity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Inlet and Exhaust Losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Fuels. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Fuel Heating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Diluent Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Air Extraction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Performance Enhancements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Inlet Cooling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Steam and Water Injection for Power Augmentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Peak Rating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Performance Degradation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Verifying Gas Turbine Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 List of Figures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 List of Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

GE Power Systems GER-3567H (10/00) ■

■

i

GE Gas Turbine Performance Characteristics Introduction GE offers both heavy-duty and aircraft-derivative gas turbines for power generation and industrial applications. The heavy-duty product line consists of five different model series: MS3002, MS5000, MS6001, MS7001 and MS9001. The MS5000 is designed in both single- and two-shaft configurations for both generator and mechanical-drive applications. The MS5000 and MS6001 are gear-driven units that can be applied in 50 Hz and 60 Hz markets. GE Generator Drive Product Line Model Fuel ISO Base Rating (kW) PG5371 (PA) PG6581 (B) PG6101 (FA) PG7121 (EA) PG7241 (FA) PG7251 (FB) PG9171 (E) PG9231 (EC) PG9351 (FA)

Gas Dist. Gas Dist. Gas Dist. Gas Dist. Gas Dist. Gas Dist. Gas Dist. Gas Dist. Gas Dist.

26,070. 25,570. 42,100. 41,160. 69,430. 74,090. 84,360. 87,220. 171,700. 183,800. 184,400. 177,700. 122,500. 127,300. 169,200. 179,800. 255,600. 268,000.

Heat Rate (Btu/kWh)

Heat Rate (kJ/kWh)

12,060. 12,180. 10,640. 10,730. 10,040. 10,680. 10,480. 10,950. 9,360. 9,965. 9,245. 9,975. 10,140. 10,620. 9,770. 10,360. 9,250. 9,920.

12,721 12,847 11,223 11,318 10,526 10,527 11,054 11,550 9,873 10,511 9,752 10,522 10,696 11,202 10,305 10,928 9,757 10,464

tions the product line covers a range from approximately 35,800 hp to 345,600 hp (26,000 kW to 255,600 kW). Table 1 provides a complete listing of the available outputs and heat rates of the GE heavy-duty gas turbines. Table 2 lists the ratings of mechanical-drive units, which range from 14,520 hp to 108,990 hp (10,828 kW to 80,685 kW). The complete model number designation for each heavy-duty product line machine is provided in both Tables 1 and 2. An explanation of

Exhaust Flow (lb/hr) x10-3 985. 998. 1158. 1161. 1638. 1704. 2361. 2413. 3543. 3691. 3561. 3703. 3275. 3355. 4131. 4291. 5118. 5337.

Exhaust Flow (kg/hr) x10-3 446 448 525 526 742 772 1070 1093 1605 1672 1613 1677 1484 1520 1871 1944 2318 2418

Exhaust Temp (degrees F)

Exhaust Temp (degrees C)

Pressure Ratio

905. 906. 1010. 1011. 1101. 1079. 998. 993. 1119. 1095. 1154. 1057. 1009. 1003. 1034. 1017. 1127. 1106.

485 486 543 544 594 582 536 537 604 591 623 569 543 539 557 547 608 597

10.6 10.6 12.2 12.1 14.6 15.0 12.7 12.9 15.7 16.2 18.4 18.7 12.6 12.9 14.4 14.8 15.3 15.8 GT22043E

Table 1. GE gas turbine performance characteristics - Generator drive gas turbine ratings All units larger than the Frame 6 are directdrive units. The MS7000 series units that are used for 60 Hz applications have rotational speeds of 3600 rpm. The MS9000 series units used for 50 Hz applications have a rotational speed of 3000 rpm. In generator-drive applica-

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the model number is given in Figure 1. This paper reviews some of the basic thermodynamic principles of gas turbine operation and explains some of the factors that affect its performance.

1

GE Gas Turbine Performance Characteristics Mechanical Drive Gas Turbine Ratings Model

Year

ISO Rating

ISO Rating

Heat

Heat

Mass

Mass

Exhaust

Exhaust

Continuous

Continuous

Rate

Rate

Flow

Flow

Temp

Temp

(kW)

(hp)

(Btu/shp-hr)

(kJ/kWh)

(lb/sec)

(kg/sec)

(degrees F)

(degrees C)

M3142 (J)

1952

11,290

15,140

9,500

13,440

117

53

1,008

542

M3142R (J)

1952

10,830

14,520

7,390

10,450

117

53

698

370

M5261 (RA)

1958

19,690

26,400

9,380

13,270

205

92

988

531

M5322R (B)

1972

23,870

32,000

7,070

10,000

253

114

666

352

M5352 (B)

1972

26,110

35,000

8,830

12,490

273

123

915

491

M5352R (C)

1987

26,550

35,600

6,990

9,890

267

121

693

367

M5382 (C)

1987

28,340

38,000

8,700

12,310

278

126

960

515

M6581 (B)

1978

38,290

51,340

7,820

11,060

295

134

1,013

545

Table 2. GE gas turbine performance characteristics - Mechanical drive gas turbine ratings

GT25385A

MS7000 PG

7

12

1

(EA)

Application

Series

Power

Number of Shafts

Model

M - Mech Drive PG - Pkgd Gen

Frame Approx 1 or 2 3,5,7 Output 6,9 Power in Hundreds, Thousands, or 10 Thousands of Horsepower

R - Regen Blank - SC

GT23054A

Figure 1. Heavy-duty gas turbine model designation

Thermodynamic Principles A schematic diagram for a simple-cycle, singleshaft gas turbine is shown in Figure 2. Air enters the axial flow compressor at point 1 at ambient conditions. Since these conditions vary from day to day and from location to location, it is convenient to consider some standard conditions for comparative purposes. The standard conditions used by the gas turbine industry are 59 F/15 C, 14.7 psia/1.013 bar and 60% relative humidity, which are established by the International Standards Organization (ISO) and frequently referred to as ISO conditions. GE Power Systems GER-3567H (10/00) ■

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Air entering the compressor at point 1 is compressed to some higher pressure. No heat is added; however, compression raises the air temperature so that the air at the discharge of the compressor is at a higher temperature and pressure. Upon leaving the compressor, air enters the combustion system at point 2, where fuel is injected and combustion occurs. The combustion process occurs at essentially constant pressure. Although high local temperatures are reached within the primary combustion zone (approaching stoichiometric conditions), the 2

GE Gas Turbine Performance Characteristics Fuel Combustor

Exhaust

2 4

Compressor 3

Generator

1

Turbine Inlet Air

GT08922A

Figure 2. Simple-cycle, single-shaft gas turbine combustion system is designed to provide mixing, burning, dilution and cooling. Thus, by the time the combustion mixture leaves the combustion system and enters the turbine at point 3, it is at a mixed average temperature. In the turbine section of the gas turbine, the energy of the hot gases is converted into work. This conversion actually takes place in two steps. In the nozzle section of the turbine, the hot gases are expanded and a portion of the thermal energy is converted into kinetic energy. In the subsequent bucket section of the turbine, a portion of the kinetic energy is transferred to the rotating buckets and converted to work. Some of the work developed by the turbine is used to drive the compressor, and the remainder is available for useful work at the output flange of the gas turbine. Typically, more than 50% of the work developed by the turbine sections is used to power the axial flow compressor. As shown in Figure 2, single-shaft gas turbines are configured in one continuous shaft and, therefore, all stages operate at the same speed. These units are typically used for generatordrive applications where significant speed variation is not required. GE Power Systems GER-3567H (10/00) ■

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A schematic diagram for a simple-cycle, twoshaft gas turbine is shown in Figure 3. The lowpressure or power turbine rotor is mechanically separate from the high-pressure turbine and compressor rotor. The low pressure rotor is said to be aerodynamically coupled. This unique feature allows the power turbine to be operated at a range of speeds and makes twoshaft gas turbines ideally suited for variablespeed applications. All of the work developed by the power turbine is available to drive the load equipment since the work developed by the high-pressure turbine supplies all the necessary energy to drive the compressor. On two-shaft machines the starting requirements for the gas turbine load train are reduced because the load equipment is mechanically separate from the high-pressure turbine.

The Brayton Cycle The thermodynamic cycle upon which all gas turbines operate is called the Brayton cycle. Figure 4 shows the classical pressure-volume (PV) and temperature-entropy (TS) diagrams for this cycle. The numbers on this diagram cor3

GE Gas Turbine Performance Characteristics Fuel Combustor

Exhaust

Compressor

HP

LP

Load

Turbine Inlet Air Figure 3. Simple-cycle, two-shaft gas turbine

GT08923C

air at point 1 on a continuous basis in exchange for the hot gases exhausted to the atmosphere at point 4. The actual cycle is an “open” rather than “closed” cycle, as indicated.

respond to the numbers also used in Figure 2. Path 1 to 2 represents the compression occurring in the compressor, path 2 to 3 represents the constant-pressure addition of heat in the combustion systems, and path 3 to 4 represents the expansion occurring in the turbine.

Every Brayton cycle can be characterized by two significant parameters: pressure ratio and firing temperature. The pressure ratio of the cycle is the pressure at point 2 (compressor discharge pressure) divided by the pressure at point 1 (compressor inlet pressure). In an ideal cycle,

The path from 4 back to 1 on the Brayton cycle diagrams indicates a constant-pressure cooling process. In the gas turbine, this cooling is done by the atmosphere, which provides fresh, cool

3

2 P

Fuel

4

2

4

1 3

V 3

1

T

4 2

1 S

GT23055A

Figure 4. Brayton cycle

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4

GE Gas Turbine Performance Characteristics this pressure ratio is also equal to the pressure at point 3 divided by the pressure at point 4. However, in an actual cycle there is some slight pressure loss in the combustion system and, hence, the pressure at point 3 is slightly less than at point 2. The other significant parameter, firing temperature, is thought to be the highest temperature reached in the cycle. GE defines firing temperature as the mass-flow mean total temperature

OPEN LOOP AIR-COOLED NOZZLE

sented as firing temperature by point 3 in Figure 4. Steam-cooled first stage nozzles do not reduce the temperature of the gas directly through mixing because the steam is in a closed loop. As shown in Figure 5, the firing temperature on a turbine with steam-cooled nozzles (GE’s current “H” design) has an increase of 200 degrees without increasing the combustion exit temperature.

ADVANCED CLOSED LOOP STEAM-COOLED NOZZLE

200F More Firing Temp. at Same NOx Production Possible

GT25134

Figure 5. Comparison of air-cooled vs. steam-cooled first stage nozzle at the stage 1 nozzle trailing edge plane. Currently all first stage nozzles are cooled to keep the temperatures within the operating limits of the materials being used. The two types of cooling currently employed by GE are air and steam. Air cooling has been used for more than 30 years and has been extensively developed in aircraft engine technology, as well as the latest family of large power generation machines. Air used for cooling the first stage nozzle enters the hot gas stream after cooling down the nozzle and reduces the total temperature immediately downstream. GE uses this temperature since it is more indicative of the cycle temperature repreGE Power Systems GER-3567H (10/00) ■

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An alternate method of determining firing temperature is defined in ISO document 2314, “Gas Turbines – Acceptance Tests.” The firing temperature here is a reference turbine inlet temperature and is not generally a temperature that exists in a gas turbine cycle; it is calculated from a heat balance on the combustion system, using parameters obtained in a field test. This ISO reference temperature will always be less than the true firing temperature as defined by GE, in many cases by 100 F/38 C or more for machines using air extracted from the compressor for internal cooling, which bypasses the combustor. Figure 6 shows how these various temperatures are defined. 5

GE Gas Turbine Performance Characteristics

Turbine Inlet Temperature - Average Gas Temp in Plane A. (TA) Firing Temperature - Average Gas Temp in Plane B. (TB)

CL

ISO Firing Temperature - Calculated Temp in Plane C. TC = f(Ma , Mf)

GE Uses Firing Temperature TB • Highest Temperature at Which Work Is Extracted GT23056

Figure 6. Definition of firing temperature

Thermodynamic Analysis Classical thermodynamics permit evaluation of the Brayton cycle using such parameters as pressure, temperature, specific heat, efficiency factors and the adiabatic compression exponent. If such an analysis is applied to the Brayton cycle, the results can be displayed as a plot of cycle efficiency vs. specific output of the cycle. Figure 7 shows such a plot of output and

efficiency for different firing temperatures and various pressure ratios. Output per pound of airflow is important since the higher this value, the smaller the gas turbine required for the same output power. Thermal efficiency is important because it directly affects the operating fuel costs. Figure 7 illustrates a number of significant points. In simple-cycle applications (the top curve), pressure ratio increases translate into efficiency gains at a given firing temperature.

GT17983A

Figure 7. Gas turbine thermodynamics GE Power Systems GER-3567H (10/00) ■

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6

GE Gas Turbine Performance Characteristics The pressure ratio resulting in maximum output and maximum efficiency change with firing temperature, and the higher the pressure ratio, the greater the benefits from increased firing temperature. Increases in firing temperature provide power increases at a given pressure ratio, although there is a sacrifice of efficiency due to the increase in cooling air losses required to maintain parts lives. In combined-cycle applications (as shown in the bottom graph in Figure 7 ), pressure ratio increases have a less pronounced effect on efficiency. Note also that as pressure ratio increases, specific power decreases. Increases in firing temperature result in increased thermal efficiency. The significant differences in the slope of the two curves indicate that the optimum cycle parameters are not the same for simple and combined cycles. Simple-cycle efficiency is achieved with high pressure ratios. Combined-cycle efficiency is obtained with more modest pressure ratios and greater firing temperatures. For example, the MS7001FA design parameters are 2420 F/1316 C firing temperature and 15.7:1 pressure ratio;

while simple-cycle efficiency is not maximized, combined-cycle efficiency is at its peak. Combined cycle is the expected application for the MS7001FA.

Combined Cycle A typical simple-cycle gas turbine will convert 30% to 40% of the fuel input into shaft output. All but 1% to 2% of the remainder is in the form of exhaust heat. The combined cycle is generally defined as one or more gas turbines with heat-recovery steam generators in the exhaust, producing steam for a steam turbine generator, heat-to-process, or a combination thereof. Figure 8 shows a combined cycle in its simplest form. High utilization of the fuel input to the gas turbine can be achieved with some of the more complex heat-recovery cycles, involving multiple-pressure boilers, extraction or topping steam turbines, and avoidance of steam flow to a condenser to preserve the latent heat content. Attaining more than 80% utilization of the fuel input by a combination of electrical power generation and process heat is not unusual. Exhaust HRSG ST Turb

Fuel

Gen Gen

Comb

Comp Air

Turb

Gen

Gas Turbine

GT05363C

Figure 8. Combined cycle

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7

GE Gas Turbine Performance Characteristics parameters and component efficiencies as well as air mass flow.

Combined cycles producing only electrical power are in the 50% to 60% thermal efficiency range using the more advanced gas turbines.

Correction for altitude or barometric pressure is more straightforward. The air density reduces as the site elevation increases. While the resulting airflow and output decrease proportionately, the heat rate and other cycle parameters are not affected. A standard altitude correction curve is presented in Figure 10.

Papers dealing with combined-cycle applications in the GE Reference Library include: GER-3574F, “GE Combined-Cycle Product Line and Performance”; GER-3767, “Single-Shaft Combined-Cycle Power Generation Systems”; and GER-3430F, “Cogeneration Application Considerations.”

Humidity

Factors Affecting Gas Turbine Performance

Similarly, humid air, which is less dense than dry air, also affects output and heat rate, as shown in Figure 11. In the past, this effect was thought to be too small to be considered. However, with the increasing size of gas turbines and the utilization of humidity to bias water and steam injection for NOx control, this effect has greater significance.

Air Temperature and Site Elevation Since the gas turbine is an air-breathing engine, its performance is changed by anything that affects the density and/or mass flow of the air intake to the compressor. Ambient weather conditions are the most obvious changes from the reference conditions of 59 F/15 C and 14.7 psia/1.013 bar. Figure 9 shows how ambient temperature affects the output, heat rate, heat consumption, and exhaust flow of a single-shaft MS7001. Each turbine model has its own temperature-effect curve, as it depends on the cycle

It should be noted that this humidity effect is a result of the control system approximation of firing temperature used on GE heavy-duty gas turbines. Single-shaft turbines that use turbine exhaust temperature biased by the compressor pressure ratio to the approximate firing temperature will reduce power as a result of

130

120

110

Heat Rate Percent Design

100

90

Exhaust Flow Heat Cons. Output

80

70

Compressor Inlet Temperature

0

20

40

60 °F

80

100

120

-18

-7

4

16 °C

27

38

49

GT22045D

Figure 9. Effect of ambient temperature

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8

GE Gas Turbine Performance Characteristics

GT18848B

Figure 10. Altitude correction curve

GT22046B

Figure 11. Humidity effect curve increased ambient humidity. This occurs because the density loss to the air from humidity is less than the density loss due to temperature. The control system is set to follow the inlet air temperature function. By contrast, the control system on aeroderivatives uses unbiased gas generator discharge temperature to approximate firing temperature. The gas generator can operate at different speeds from the power turbine, and the power will actually increase as fuel is added to raise the GE Power Systems GER-3567H (10/00) ■

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moist air (due to humidity) to the allowable temperature. This fuel increase will increase the gas generator speed and compensate for the loss in air density.

Inlet and Exhaust Losses Inserting air filtration, silencing, evaporative coolers or chillers into the inlet or heat recovery devices in the exhaust causes pressure losses in the system. The effects of these pressure losses are unique to each design. Figure 12 shows 9

GE Gas Turbine Performance Characteristics 4 Inches (10 mbar) H2O Inlet Drop Produces: 1.42% Power Output Loss 0.45% Heat Rate Increase 1.9 F (1.1 C) Exhaust Temperature Increase 4 Inches (10 mbar) H2O Exhaust Drop Produces: 0.42% Power Output Loss 0.42% Heat Rate Increase 1.9 F (1.1 C) Exhaust Temperature Increase

GT18238C

Figure 12. Pressure drop effects (MS7001EA) the effects on the MS7001EA, which are typical for the E technology family of scaled machines (MS6001B, 7001EA, 9001E).

Fuels Work from a gas turbine can be defined as the product of mass flow, heat energy in the combusted gas (Cp), and temperature differential across the turbine. The mass flow in this equation is the sum of compressor airflow and fuel flow. The heat energy is a function of the elements in the fuel and the products of combustion. Tables 1 and 2 show that natural gas (methane) produces nearly 2% more output than does distillate oil. This is due to the higher specific heat in the combustion products of natural gas, resulting from the higher water vapor content produced by the higher hydrogen/carbon ratio of methane. This effect is noted even though the mass flow (lb/h) of methane is lower than the mass flow of distillate fuel. Here the effects of specific heat were greater than and in opposition to the effects of mass flow. Figure 13 shows the total effect of various fuels on turbine output. This curve uses methane as the base fuel. Although there is no clear relationship between fuel lower heating value (LHV) and output, it is GE Power Systems GER-3567H (10/00) ■

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possible to make some general assumptions. If the fuel consists only of hydrocarbons with no inert gases and no oxygen atoms, output increases as LHV increases. Here the effects of Cp are greater than the effects of mass flow. Also, as the amount of inert gases is increased, the decrease in LHV will provide an increase in output. This is the major impact of IGCC type fuels that have large amounts of inert gas in the fuel. This mass flow addition, which is not compressed by the gas turbine’s compressor, increases the turbine output. Compressor power is essentially unchanged. Several side effects must be considered when burning this kind of lower heating value fuels: ■ Increased turbine mass flow drives up compressor pressure ratio, which eventually encroaches on the compressor surge limit ■ The higher turbine power may exceed fault torque limits. In many cases, a larger generator and other accessory equipment may be needed ■ High fuel volumes increase fuel piping and valve sizes (and costs). Low- or medium-Btu coal gases are frequently supplied at high temperatures, which further increases their volume flow 10

GE Gas Turbine Performance Characteristics 60 100% H2

30

20

10

LHV-Btu/lb (Thousands)

Kcal/kg (Thousands)

50

40

30 100% CH4

20 100% CH4H10

10 75% N2 - 25% CH4 75% CO2 - 25% CH4

100% CO 0

100

105

110

115

120

125

Output - Percent

130 GT25842

Figure 13. Effect of fuel heating value on output ■ Lower-Btu gases are frequently saturated with water prior to delivery to the turbine. This increases the combustion products heat transfer coefficients and raises the metal temperatures in the turbine section which may require lower operating firing temperature to preserve parts lives ■ As the Btu value drops, more air is required to burn the fuel. Machines with high firing temperatures may not be able to burn low Btu gases ■ Most air-blown gasifiers use air supplied from the gas turbine compressor discharge ■ The ability to extract air must be evaluated and factored into the overall heat and material balances As a result of these influences, each turbine model will have some application guidelines on flows, temperatures and shaft output to preserve

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its design life. In most cases of operation with lower heating value fuels, it can be assumed that output and efficiency will be equal to or higher than that obtained on natural gas. In the case of higher heating value fuels, such as refinery gases, output and efficiency may be equal to or lower than that obtained on natural gas.

Fuel Heating Most of the combined cycle turbine installations are designed for maximum efficiency. These plants often utilize integrated fuel gas heaters. Heated fuel results in higher turbine efficiency due to the reduced fuel flow required to raise the total gas temperature to firing temperature. Fuel heating will result in slightly lower gas turbine output because of the incremental volume flow decrease. The source of heat for the fuel typically is the IP feedwater. Since use of this energy in the gas turbine fuel heating system is thermodynamically advantageous, the combined cycle efficiency is improved by approximately 0.6%.

11

GE Gas Turbine Performance Characteristics Diluent Injection Since the early 1970s, GE has used water or steam injection for NOx control to meet applicable state and federal regulations. This is accomplished by admitting water or steam in the cap area or “head-end” of the combustion liner. Each machine and combustor configuration has limits on water or steam injection levels to protect the combustion system and turbine section. Depending on the amount of water or steam injection needed to achieve the desired NOx level, output will increase because of the 130

Generally, up to 5% of the compressor airflow can be extracted from the compressor discharge casing without modification to casings or on-base piping. Pressure and air temperature will depend on the type of machine and site conditions. Air extraction between 6% and 20% may be possible, depending on the machine and combustor configuration, with some modifications to the casings, piping and controls. Such applications need to be reviewed on a case-by-case basis. Air extractions above 20% will require extensive modification to the turbine casing and unit configuration. Figure 15

With 5% Steam Injection

120 110

Output %

100 90

No Steam Injection

3% 1%

80 70

40

60

4

16

80

100

120

27

38

49

ºF ºC

Compressor Inlet Temperature GT18851A

Figure 14. Effect of steam injection on output and heat rate additional mass flow. Figure 14 shows the effect of steam injection on output and heat rate for an MS7001EA. These curves assume that steam is free to the gas turbine cycle, therefore heat rate improves. Since it takes more fuel to raise water to combustor conditions than steam, water injection does not provide an improvement in heat rate.

Air Extraction In some gas turbine applications, it may be desirable to extract air from the compressor.

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GT22048-1C

Figure 15. Effect of air extraction on output and heat rate shows the effect of air extraction on output and heat rate. As a “rule of thumb,” every 1% in air extraction results in a 2% loss in power.

Performance Enhancements Generally, controlling some of the factors that affect gas turbine performance is not possible. The planned site location and the plant configuration (such as simple- or combined-cycle) determine most of these factors. In the event additional output is needed, several possibilities to enhance performance may be considered.

12

GE Gas Turbine Performance Characteristics Inlet Cooling The ambient effect curve (see Figure 9) clearly shows that turbine output and heat rate are improved as compressor inlet temperature decreases. Lowering the compressor inlet temperature can be accomplished by installing an evaporative cooler or inlet chiller in the inlet ducting downstream of the inlet filters. Careful application of these systems is necessary, as condensation or carryover of water can exacerbate compressor fouling and degrade performance. These systems generally are followed by moisture separators or coalescing pads to reduce the possibility of moisture carryover. As Figure 16 shows, the biggest gains from evaporative cooling are realized in hot, low-humidity climates. It should be noted that evaporative cooling is limited to ambient temperatures of 59 F/15 C and above (compressor inlet temperature >45 F/7.2 C) because of the potential for icing the compressor. Information contained in Figure 16 is based on an 85% effective evaporative cooler. Effectiveness is a measure of how close the cooler exit temperature approaches the ambient wet bulb tempera-

Figure 16. Effect of evaporative cooling on output and heat rate ture. For most applications, coolers having an effectiveness of 85% or 90% provide the most economic benefit. Chillers, unlike evaporative coolers, are not limited by the ambient wet bulb temperature. The achievable temperature is limited only by the capacity of the chilling device to produce coolant and the ability of the coils to transfer heat. Cooling initially follows a line of constant 100% RH

Psychrometric Chart (Simplified)

GT22419-1D

40

.020 60% RH

35

.015 30

40% RH

Btu Per Pound of Dry Air

Evaporative Cooling Process

25 .010

Specific Humidity

20% RH

20 Inlet Chilling Process 15

.005 10% RH

Dry Bulb Temperature

°F 40

60

80

100

120

°C 4

16

27

38

49

.000

GT21141D

Figure 17. Inlet chilling process GE Power Systems GER-3567H (10/00) ■

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13

GE Gas Turbine Performance Characteristics specific humidity, as shown in Figure 17. As saturation is approached, water begins to condense from the air, and mist eliminators are used. Further heat transfer cools the condensate and air, and causes more condensation. Because of the relatively high heat of vaporization of water, most of the cooling energy in this regime goes to condensation and little to temperature reduction.

Steam and Water Injection for Power Augmentation Injecting steam or water into the head end of the combustor for NOx abatement increases mass flow and, therefore, output. Generally, the amount of water is limited to the amount required to meet the NOx requirement in order to minimize operating cost and impact on inspection intervals. Steam injection for power augmentation has been an available option on GE gas turbines for over 30 years. When steam is injected for power augmentation, it can be introduced into the compressor discharge casing of the gas turbine as well as the combustor. The effect on output and heat rate is the same as that shown in Figure 14. GE gas turbines are designed to allow up to 5% of the compressor airflow for steam injection to the combustor and compressor discharge. Steam must contain 50 F/28 C superheat and be at pressures comparable to fuel gas pressures. When either steam or water is used for power augmentation, the control system is normally designed to allow only the amount needed for NOx abatement until the machine reaches base (full) load. At that point, additional steam or water can be admitted via the governor control.

Peak Rating The performance values listed in Table 1 are base load ratings. ANSI B133.6 Ratings and

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Performance defines base load as operation at 8,000 hours per year with 800 hours per start. It also defines peak load as operation at 1250 hours per year with five hours per start. In recognition of shorter operating hours, it is possible to increase firing temperature to generate more output. The penalty for this type of operation is shorter inspection intervals. Despite this, running an MS5001, MS6001 or MS7001 at peak may be a cost-effective way to obtain more kilowatts without the need for additional peripheral equipment. Generators used with gas turbines likewise have peak ratings that are obtained by operating at higher power factors or temperature rises. Peak cycle ratings are ratings that are customized to the mission of the turbine considering both starts and hours of operation. Firing temperatures between base and peak can be selected to maximize the power capabilities of the turbine while staying within the starts limit envelope of the turbine hot section repair interval. For instance, the 7EA can operate for 24,000 hours on gas fuel at base load, as defined. The starts limit to hot section repair interval is 800 starts. For peaking cycle of five hours per start, the hot section repair interval would occur at 4,000 hours, which corresponds to operation at peak firing temperatures. Turbine missions between five hours per start and 800 hours per start may allow firing temperatures to increase above base but below peak without sacrificing hours to hot section repair. Water injection for power augmentation may be factored into the peak cycle rating to further maximize output.

Performance Degradation All turbomachinery experiences losses in performance with time. Gas turbine performance degradation can be classified as recoverable or non-recoverable loss. Recoverable loss is usually

14

GE Gas Turbine Performance Characteristics associated with compressor fouling and can be partially rectified by water washing or, more thoroughly, by mechanically cleaning the compressor blades and vanes after opening the unit. Non-recoverable loss is due primarily to increased turbine and compressor clearances and changes in surface finish and airfoil contour. Because this loss is caused by reduction in component efficiencies, it cannot be recovered by operational procedures, external maintenance or compressor cleaning, but only through replacement of affected parts at recommended inspection intervals. Quantifying performance degradation is difficult because consistent, valid field data is hard to obtain. Correlation between various sites is impacted by variables such as mode of operation, contaminants in the air, humidity, fuel and dilutent injection levels for NOx. Another problem is that test instruments and procedures vary widely, often with large tolerances. Typically, performance degradation during the first 24,000 hours of operation (the normally recommended interval for a hot gas path inspection) is 2% to 6% from the performance test measurements when corrected to guaranteed conditions. This assumes degraded parts are not replaced. If replaced, the expected performance degradation is 1% to 1.5%. Recent field experience indicates that frequent off-line water washing is not only effective in reducing recoverable loss, but also reduces the rate of non-recoverable loss. One generalization that can be made from the data is that machines located in dry, hot climates typically degrade less than those in humid climates.

Verifying Gas Turbine Performance Once the gas turbine is installed, a performance test is usually conducted to determine

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power plant performance. Power, fuel, heat consumption and sufficient supporting data should be recorded to enable as-tested performance to be corrected to the condition of the guarantee. Preferably, this test should be done as soon as practical, with the unit in new and clean condition. In general, a machine is considered to be in new and clean condition if it has less than 200 fired hours of operation. Testing procedures and calculation methods are patterned after those described in the ASME Performance Test Code PTC-22-1997, “Gas Turbine Power Plants.” Prior to testing, all station instruments used for primary data collection must be inspected and calibrated. The test should consist of sufficient test points to ensure validity of the test set-up. Each test point should consist of a minimum of four complete sets of readings taken over a 30-minute time period when operating at base load. Per ASME PTC-221997, the methodology of correcting test results to guarantee conditions and measurement uncertainties (approximately 1% on output and heat rate when testing on gas fuel) shall be agreed upon by the parties prior to the test.

Summary This paper reviewed the thermodynamic principles of both one- and two-shaft gas turbines and discussed cycle characteristics of the several models of gas turbines offered by GE. Ratings of the product line were presented, and factors affecting performance were discussed along with methods to enhance gas turbine output. GE heavy-duty gas turbines serving industrial, utility and cogeneration users have a proven history of sustained performance and reliability. GE is committed to providing its customers with the latest in equipment designs and advancements to meet power needs at high thermal efficiency.

15

GE Gas Turbine Performance Characteristics List of Figures Figure 1. Heavy-duty gas turbine model designation Figure 2. Simple-cycle, single-shaft gas turbine Figure 3. Simple-cycle, two-shaft gas turbine Figure 4. Brayton cycle Figure 5. Comparison of air-cooled vs. steam-cooled first stage nozzle Figure 6. Definition of firing temperature Figure 7. Gas turbine thermodynamics Figure 8. Combined cycle Figure 9. Effect of ambient temperature Figure 10. Altitude correction curve Figure 11. Humidity effect curve Figure 12. Pressure drop effects (MS7001EA) Figure 13. Effect of fuel heating value on output Figure 14. Effect of steam injection on output and heat rate Figure 15. Effect of air extraction on output and heat rate Figure 16. Effect of evaporative cooling on output and heat rate Figure 17. Inlet chilling process

List of Tables Table 1. GE gas turbine performance characteristics - Generator drive gas turbine ratings Table 2. GE gas turbine performance characteristics - Mechanical drive gas turbine ratings

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16

g

GEK 117004 January 2012

GE Energy

Detection of Gas Leakage and Hydrogen Purity Formulas

These instructions do not purport to cover all details or variations in equipment nor to provide for every possible contingency to be met in connection with installation, operation or maintenance. Should further information be desired or should particular problems arise which are not covered sufficiently for the purchaser's purposes the matter should be referred to General Electric Company. These instructions contain proprietary information of General Electric Company, and are furnished to its customer solely to assist that customer in the installation, testing, operation, and/or maintenance of the equipment described. This document shall not be reproduced in whole or in part nor shall its contents be disclosed to any third party without the written approval of General Electric Company. © 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

GEK 117004

Detection of Gas Leakage and Hydrogen Purity Formulas

The following notices will be found throughout this publication. It is important that the significance of each is thoroughly understood by those using this document. The definitions are as follows: NOTE Highlights an essential element of a procedure to assure correctness. CAUTION Indicates a potentially hazardous situation, which, if not avoided, could result in minor or moderate injury or equipment damage.

WARNING INDICATES A POTENTIALLY HAZARDOUS SITUATION, WHICH, IF NOT AVOIDED, COULD RESULT IN DEATH OR SERIOUS INJURY

***DANGER*** INDICATES AN IMMINENTLY HAZARDOUS SITUATION, WHICH, IF NOT AVOIDED WILL RESULT IN DEATH OR SERIOUS INJURY.

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Detection of Gas Leakage and Hydrogen Purity Formulas

GEK 117004

TABLE OF CONTENTS INTRODUCTION ...................................................................................................................................... 4 PURPOSE ................................................................................................................................................... 4 METHODS OF LEAK DETECTION...................................................................................................... 4 A. Soapy Water ............................................................................................................................................ 4 B. Flammable Gas Detectors........................................................................................................................ 4 C. Ultrasonic Leak Detector......................................................................................................................... 4 D. Multiple Gas Detectors............................................................................................................................ 5 E. Odorants .................................................................................................................................................. 5 F. Halogen Leak Detectors .......................................................................................................................... 5 IV. TESTING .................................................................................................................................................... 6 A. Initial Conditions ..................................................................................................................................... 6 B. Initial Testing with Air ............................................................................................................................ 6 C. Final Testing with Hydrogen................................................................................................................... 6 D. Hydrogen Sampling of Generator Bearing Bracket................................................................................. 6 V. PROCEDURE FOR LOCATING LEAKS .............................................................................................. 7 VI. POSSIBLE SOURCES OF GAS LEAKAGE .......................................................................................... 7 A. Stator Casing ........................................................................................................................................... 7 B. Seal Oil Drain System ............................................................................................................................. 7 C. Gas Piping ............................................................................................................................................... 7 D. Hydrogen Control Cabinet....................................................................................................................... 7 E. Liquid-Cooled Winding Equipment ........................................................................................................ 8 F. Miscellaneous Gas Equipment ................................................................................................................ 8 G. Field (Rotor) Terminal Packing............................................................................................................... 8 H. Valve in Purging Vent Line..................................................................................................................... 8 I. Scavenging Flowmeters........................................................................................................................... 8 J. Bearing Enclosure in Outer End Shields ............................................................................................... 10 VII. EVALUATION OF LEAKS.................................................................................................................... 11 A. Leak Size ............................................................................................................................................... 11 B. Gas Consumption .................................................................................................................................. 11 C. Pressure Decay Test............................................................................................................................... 12 D. Increasing the Hydrogen Purity ............................................................................................................. 15 E. Hydrogen Purity when Emergency Seal Oil System is in Operation (for Vacuum-Treated Seal Oil Systems Only) ....................................................................................................................................... 16 F. Evaluating Leak Rate Using Bubble Test.............................................................................................. 17 G. Evaluating Leak Rate at Bearing Drain Enlargement Vent................................................................... 18 I. II. III.

LIST OF FIGURES Figure 1. Hydrogen Leakage Detection Flow Chart .............................................................................................. 9 Figure 2. Quantity of Hydrogen Required to Increase Gas Purity from Equation (10) ....................................... 16 Figure 3. Decrease in Machine Purity with Time; Seals Supplied with Untreated Oil........................................ 17

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GEK 117004

Detection of Gas Leakage and Hydrogen Purity Formulas

I. INTRODUCTION The generator casing and all the gas piping must be given an air leakage test to determine that only a minimum amount of leakage will occur before hydrogen is introduced. Also, it is sometimes necessary to test the generator for gas leakage after it has been placed in hydrogen operation. The following describes various methods which have been successfully used in detecting leaks in the gas system of hydrogencooled generators and gives information pertinent to conducting leakage tests. These instructions also contain formulas for calculating the amount of gas leakage from the generator and for determining how much hydrogen must be added to the generator to obtain a desired increase in hydrogen purity. The formulas for gas leakage are used when the generator is being tested for leaks before being placed in operation. II. PURPOSE Although the generator casing and the several component parts of the seal–oil and gas systems are pressure tested for gas leaks at the factory, there are many joints in the equipment which must be made up during assembly in the field; hence, leakage tests on the assembled generator and the connected equipment must be made.

WARNING IF HYDROGEN LEAKAGE QUANTITY DETECTED FOR ANY UNIT EXCEEDS 200 CUBIC FEET PER DAY, THE UNIT SHOULD BE REMOVED FROM SERVICE AND INSPECTED. III. METHODS OF LEAK DETECTION A. Soapy Water A mixture of liquid soap, glycerin and water, applied with a brush to the joints of the gas system, with the latter under pressure, will indicate leaks by bubbling of the liquid. A suitable commercial preparation is “Leak-Tec” (formula 372-E), manufactured by American Gas & Chemicals Co. B. Flammable Gas Detectors This type of instrument may be used for leak detection when the generator contains hydrogen. This type of detector is designed to read in percent of the lower explosive limit (LEL) of a hydrogen-air mixture (4% hydrogen in 100% air). The “Explosimeter” manufactured by Mine Safety Appliances Co., Pittsburgh, Pennsylvania, has been used successfully in the detection of hydrogen leaks. C. Ultrasonic Leak Detector This type of detector utilizes the ultrasonic energy generated by molecular collisions as gas escapes from or enters a small orifice. The probe of the detector is directional, which allows it to be used in a manner similar to a flashlight to search for leaks. When the probe is pointed toward a leak, sound from the headphones or speaker will increase. As the probe is moved closer to the leak, the sound will increase further in intensity.

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Detection of Gas Leakage and Hydrogen Purity Formulas

GEK 117004

D. Multiple Gas Detectors This type of leak detector is sensitive to a wide range of different gases in air. It detects inert gases (such as helium), flammable gases (hydrogen), corrosive gases (ammonia, chlorine), halogens (Freon) and also carbon dioxide. Its versatility is due to the use of temperature-compensated, solidstate detectors which sense the thermal conductivity characteristic of gases. The “Qualicheck Series” leak detectors manufactured by Uson Corporation, Houston, Texas, are good examples of this device. E. Odorants If the aforementioned methods of leak detection should be unsuccessful or not available, an odorant may be introduced into the gas system. This will usually indicate the general area of the leak, after which the leak may be traced to its source by one of the foregoing methods. Ether and Captan are two odorants which have been successfully employed –the latter being obtainable from the Natural Gas Odorizing Company, Houston, Texas. F. Halogen Leak Detectors CAUTION Do not use halogen-type leak detectors in a combustible or explosive atmosphere. The halogen leak detectors are portable, usually with a hand-held probe. The detectors are designed for detecting leaks in a pressurized system where halogen compound gases (such as Freon 12) are used as a tracer gas to check for leaks (refer to section on use of Freon 12). General Electric “Type H” or the General Electric “Ferret-type” halogen leak detectors (formerly manufactured by the Yokogawa Corporation of America, Shenandoah, Georgia) has been used successfully in the detection of air leaks with a Freon tracer. If the leakage test with a Halogen Leak Detector is made with the generator at standstill, no special precautions need be observed. At ordinary temperatures Freon 12 is inert and can cause no damage to the generator parts. With an air in the casing while the generator is in operation, corona may be present at the ends of the armature winding which could decompose the Freon 12 present into hydrogen chloride gas. This gas, in combination with any water vapor present, will form hydrochloric acid vapor that could damage the iron parts of the generator. To avoid damage, the following rules relative to the use of Freon 12 have been formulated. If Freon 12 is introduced with the generator at standstill, purge out the Freon 12 before placing the generator in operation. If the leakage test is made with air, prior to operation in hydrogen, this condition will be automatically fulfilled since the air and Freon 12 would be purged with carbon dioxide before admitting hydrogen. At first, it is best to admit only about one half-pound (0.23 kg) of Freon per 500 cubic feet (14 m3) of generator volume. If the leaks are small and difficult to find, the amount of Freon used may be increased to 1 lb. (0.45 kg) per 500 cubic feet (14 m3) of volume. The amount of Freon used should be consistent with the sensitivity of the leak detector being utilized.

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GEK 117004

Detection of Gas Leakage and Hydrogen Purity Formulas

IV. TESTING A. Initial Conditions A leakage test should first be made with air pressure and with the generator at a standstill. The shaft sealing system must, therefore, be in operation. The air used for the leakage test should be reasonably dry. B. Initial Testing with Air The pressure decay test can be done in air or hydrogen, while the unit is operating on turning gear or at standstill. For initial testing air is preferred due to safety and availability. It is important that the measurements of pressure and temperature be made as accurately as possible. Relatively small errors in measurements have a very significant effect on the calculated consumption. Readings should be taken periodically during the test period; for example, every 4 hours during a 24-hour test. This will generate several consumption rates which can be averaged. This procedure will help eliminate errors due to measurement tolerances. 1. Raise the air pressure in the casing to 15 to 30 psig (1.03 to 207 kPa). Maintain the pressure while all joints of the generator, the storage tank, the connecting gas piping, as well as the seal drain piping are tested. 2. Coat joints with a solution of liquid soap, glycerin, and water, as discussed in Section III.A. Any leakage will cause bubbling of this solution. 3. As soon as all apparent leaks have been stopped, close off the air line and record the pressure. 4. After the machine has been allowed to stand for several hours, calculate the amount of leakage from the change in air pressure, using equation (2) in Section VII.C. The drop in air pressure at constant temperature during a twenty–four hour period, starting from an initial pressure of about 15 psig (103 kPa), should not exceed 0.5 psi (3.4 kPa). This would correspond to a hydrogen leakage of approximately 21 cubic feet (0.59 m3) per day, assuming a casing volume of 1,000 cubic feet (28 m3). C. Final Testing with Hydrogen 1. After the casing has been filled with hydrogen, repeat the leakage test with a portable instrument reading percent of hydrogen in air, as discussed in Section III.B. 2. Raise the hydrogen pressure to about 20% (140 kPa) and test the hydrogen accessories and their connecting piping for leakage. 3. After the machine has been allowed to stand for several hours, calculate the amount of leakage from the change in H2 pressure, using equation (2) in Section VII.C. D. Hydrogen Sampling of Generator Bearing Bracket Gas sampling ports are provided in bearing brackets or bearing cap of hydrogen–cooled generators to permit sampling of the atmosphere of the inner cavity of the bracket. At initial operation of the generator in hydrogen, check air samples from the bearing bracket using a sensitive gas analyzer calibrated for hydrogen as discussed in Section III.B. The presence of a significant percentage of hydrogen in the atmosphere of the bracket may indicate a mechanical joint or gasket leakage, or improper venting of the bearing drain enlargement.

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Detection of Gas Leakage and Hydrogen Purity Formulas

GEK 117004

V. PROCEDURE FOR LOCATING LEAKS In searching for leakage, the flow chart in Figure 1 can be useful as a “process of elimination” method of determining the area of the source of leakage. It has also been found useful to make leakage tests with different sections of the gas system piping isolated from the generator through the closing of valves, and the gas supply shut off; meanwhile taking readings of gas pressure, gas temperature and barometric pressure at regular intervals. A curve of absolute gas pressure with time is plotted, the slope of which, at constant gas temperature, is proportional to the leakage rate. If on closing the valves isolating a given section of the system, the curve shows a significant decrease in slope, a leak in the section isolated is indicated. Such a test should be made, preferably, with the generator at standstill. However, by exercising proper care that the normal operation of the generator is not impaired, the test may be made with the generator in operation. In the latter case, operation at a practically constant load is desirable; otherwise the slope of the pressure time versus curve will not indicate the true leakage rate. With a given section of the gas system isolated from the generator, the remaining sections should be explored for leaks. When the section or sections in which the major leaks occur are found from analysis of the pressure-time curve, the search for the actual location of the leaks may be concentrated on these sections. A very small hole or crack is usually very difficult to locate. A great deal of diligence must be used in searching for these defects as they can leak a significant amount of gas. For example, one 0.005 in. (0.13 mm) hole can emit 175 cubic feet (5.0 m3) of hydrogen per day from a machine pressurized at 75 psig (517 kPa). VI. POSSIBLE SOURCES OF GAS LEAKAGE The various sections into which the gas system of a hydrogen-cooled generator may be considered as being divided for a leakage investigation are described in the following paragraphs. A. Stator Casing Leakage sources include: flanged joints between end shields and casing; between casing sections (domes, with some type of construction); between end shield sections (leakage from the joints may frequently be detected at bolt heads, hence these must be checked); gasketed cooler joints; packing glands for temperature detector leads; Gas Turbine-Generator well; welded joints between gas piping casing; access opening covers; high voltage bushings; and weld joints in the casing itself. B. Seal Oil Drain System Possible leakage sources include welds and valves in the seal oil drain piping, hydrogen detraining tank assembly, seal oil float trap assembly, and liquid detector assembly. Leakage past the float trap valve may be detected at the bearing drain enlargement (or BDE) vent. C. Gas Piping The gas piping lines should be checked for leaks at piping connections to the generator’s casing, at weld joints, at flanged joints and at shut-off valves. All vent lines for purging and relief valves must be checked. Discharge should be checked for leakage through the relief or shut-off valve. D. Hydrogen Control Cabinet The leakage sources in the hydrogen control cabinet include compression-type tube fittings, brazed joints, valves, gas analyzer components, pressure gauges, pressure switches, flowmeter, differential pressure gauge and pressure transmitter. The entire cabinet may be isolated from the rest of gas control system for the purpose of leak testing. © 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

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GEK 117004

Detection of Gas Leakage and Hydrogen Purity Formulas

E. Liquid-Cooled Winding Equipment Should a leak develop in the liquid cooled windings, hydrogen would enter the liquid cooling system because the gas pressure is normally higher than the water pressure. If a leak is present, hydrogen will be detected at the stator cooling system vent line. NOTE There is a normal permeation of gas through the flexible hoses of the liquid cooling system that may result in a loss of 2 to 3 cubic feet (0.057 to 0.085 m3) per day. If a significantly large quantity of hydrogen is detected at the YTV vent, a General Electric Company representative should be contacted for aid in pinpointing and correcting this type of leak. F. Miscellaneous Gas Equipment The piping, valves, welds, flanges and the components of the hydrogen manifold, CO2 manifold, gas dryer, liquid detectors, core monitor, pyrolysate collector and the purchaser’s bulk gas supply system are all possible sources of leakage. G. Field (Rotor) Terminal Packing Leakage in this section may be detected at the collector rings with a leak detecting instrument or an odorant as described in Section III. H. Valve in Purging Vent Line A test plug is provided in vent line to check for leakage through this valve, using a detecting instrument or an odorant as described in Section III. I. Scavenging Flowmeters For units with the scavenging system, loss of hydrogen through these instruments may be calculated from the equation; cubic feet of pure hydrogen lost per day = 0.051 KRZ, where K = flowmeter purity correction factor, R = flowmeter reading (sccm), and Z = per unit purity of scavenged hydrogen.

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Detection of Gas Leakage and Hydrogen Purity Formulas

GEK 117004

Figure 1. Hydrogen Leakage Detection Flow Chart © 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

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GEK 117004

Detection of Gas Leakage and Hydrogen Purity Formulas

J. Bearing Enclosure in Outer End Shields (See typical collector end sectional view of end shield in GEK95110 or GEK95211. Leakage into this area may occur by one of the following: a. the shaft seals due to insufficient seal oil pressure b. an improper joint between the seal housing and the end shield c. the seal housing d. the welded pocket in the lower half of the end shield that is part of the hydrogen side seal oil drain to the hydrogen detraining tank e. improper end shield horizontal joint Leakage into this area may be detected most conveniently when hydrogen is in the generator, with the use of a flammable gas detector, as described in Section III.B. Leakage may first be detected at the vent from the auxiliary detraining tank. A slight negative pressure will exist in the bearing enclosure, which is created by the flow of oil through the drain lines acting as an air pump. Due to the negative pressure it may be necessary to use an aspirator with the flammable gas detector. There may be a 0.04 to 0.08% concentration of hydrogen in air mixture detected at the vent even without any abnormal leakage. Hydrogen that has become dissolved in the oil is released to the atmosphere in the auxiliary detraining tank. (The vent line from the loop seal may tie directly into this vent line as well.) If a high concentration of hydrogen in air is detected at the Bearing Drain Enlargement vent, there may be a problem with the float trap valve, seal oil flow is excessive making it difficult for the seal oil drain enlargement to function properly, or gas is leaking into the bearing enclosure. A test plug is provided in each bearing cap to permit detection of leakage into the bearing enclosure. Blow air through the test opening to remove any oil before using the leak detector. Apply the gas detector at the test openings in the bearing caps to determine which end of the generator gives the highest percentage of hydrogen. A slight trace of hydrogen will sometimes be detected at both ends, due to a minute leak in the joint. However, for a large leak, a reading of possibly 60 to 70% of the lower explosive limit of 4% hydrogen in air could be observed. To check for leakage through the shaft seals to the bearing enclosure, increase the differential seal oil pressure in 2 psi (14 kPa) increments. Correction of the leak would be indicated by obtaining a reduction in the reading of the gas detector at the test openings in the bearing caps, or a decrease in the calculated leakage rate. If an increase in seal oil pressure causes no reduction in the readings of the gas detector, leakage at the joint between the seal housing and the end shield, the seal housing, the welded pocket connected with the seal drain, or the horizontal end shield joint is indicated. If the leak should be in the joint between the seal housing and the end shield, and the seal housing, or the horizontal end shield joint (all within the bearing enclosure), the concentration of the hydrogen in the gas mixture in the vent line will be relatively low (compared to the LEL).

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Detection of Gas Leakage and Hydrogen Purity Formulas

GEK 117004

If the leak should be in the welded pocket connected with seal drain, at the bottom of the end shield, or at a point below the oil level in the bearing drain compartment, a high concentration of hydrogen in the vent from the bearing drain enlargement would be measured, possibly between 30 and 40% hydrogen in air, as a result of the large amount of hydrogen that would be entrained in the bearing oil from such a leak. To measure a hydrogen concentration of this magnitude with a flammable gas detector requires the use of a dilution valve. To locate the source of leakage in the bearing enclosure with the generator shut down and the bearing cap removed; a flammable gas detector may be used. If the leak can be covered with soapy water, its size may be approximately determined from Section VII.A. In the case of a leak in the welded pocket or the joint between the seal housing and lower half of the end shield, which may not readily be located with detecting instruments, it is frequently possible, with either hydrogen or air under pressure in the generator, to locate the leak by closing the bearing drain opening with a wooden plug and filling the lower half of the end shield with oil up to the underside of the shaft. The appearance of large bubbles will indicate the presence of a leak, and the size of the leak may be calculated approximately from the size and rate of formation of the bubbles, using Section VII.A. VII. EVALUATION OF LEAKS A. Leak Size The approximate size of a leak may frequently be estimated by noting the size and rate of formation of the bubbles in soapy water or in oil. If the leak is at a flanged pipe joint, wrap friction tape around the joint and pierce the tape at one point, then apply soapy water to the opening. It is sometimes useful to build a partial enclosure around the leak, using putty or a similar material. Then fill the enclosure with water or oil and note the size and rate of formation of the bubbles. If it is possible to completely enclose the leak, pass the leakage through the flowmeter in the portable gas analyzer; or a displacement meter may be improvised by inverting a glass container in a pail of water, a tube from the enclosure being inserted in the mouth of the container and the time required to displace the water from it measured. If one of the hydrogen flowmeters is used with air, the scale reading must be multiplied by 0.263; or if a flowmeter (such as the one in the portable gas analyzer) calibrated in air is used with hydrogen, the scale reading must be divided by 0.263. Multiply cubic centimeters per minute by 0.051 to obtain cubic feet per day. B. Gas Consumption Gas is depleted from the generator by both leakage from pressure-containing parts, e.g., frame and end shield joints, weld joints and piping, and by entrainment into the seal oil. Total gas consumption (Total) when the unit is in operation or on turning gear is

Ltotal = L frame + Loil + Lscav

(1)

where: Lframe = gas leakage from generator frame Loil = gas entrainment in seal oil Lscav = total rate of scavenging from hydrogen control panel

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GEK 117004

Detection of Gas Leakage and Hydrogen Purity Formulas

C. Pressure Decay Test Total gas consumption is a combination of leakage and scavenged gas, and can be determined by means of a pressure decay test.

Ltotal = 863

P + B2 ⎤ V ⎡ P1 + B1 − 2 ⎥ ⎢ H ⎣ 460 + T1 460 + T2 ⎦

(2a)

where: Ltotal is calculated in ft3/day for the average pressure and temperature at STP during the test period. Standard temperature and pressure (STP) volumes are the equivalent volume of gas at “room temperature” (68°F or 20°C) and atmospheric pressure (14.7 psia or 101.3 kPa) H = duration of test, (hr) V = gas volume of the generator system, (ft3) B1 and B2 = initial and final barometric pressures for the test, typically 14.7 psia P1 and P2 = initial and final generator test pressures, measured with respect to atmospheric pressure, (psig) T1 and T2 = initial and final gas temperatures for the test, (ºF) 4. And, in metric units,

Ltotal = 69.5

V P1 + B1 P + B2 [ − 2 ] H 273 + T1 273 + T2

(2b)

where: Ltotal is calculated in ft3/day for the average pressure and temperature at STP during the test period. Standard temperature and pressure (STP) volumes are the equivalent volume of gas at “room temperature” (68°F or 20°C) and atmospheric pressure (14.7 psia or 101.3 kPa) H = duration of test, (hr) V = gas volume of the generator system, (m3) B1 and B2 = initial and final barometric pressures for the test, typically 101.3 kPa P1 and P2 = initial and final generator test pressures, measured with respect to atmospheric pressure, (kPa) (gauge) T1 and T2 = initial and final gas temperatures for the test, (ºC) Equivalent hydrogen leakage can be determined from the air pressure decay results. Hydrogen will leak through joints or holes at a much higher rate than air but will be lost through entrainment in the

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Detection of Gas Leakage and Hydrogen Purity Formulas

GEK 117004

seal oil only slightly faster. It is, therefore, necessary to separate the two components of total air consumption, e.g., air leaked and air entrained. The volume solubility of air in oil (A) is approximately 11% at room temperature. This value is relatively independent of pressure at pressures less than 5 atmospheres. Thus, the loss of air from the generator casing (Loa) by entrainment into the seal oil for equilibrium conditions, is determined from the following equation:

⎛ B+ P⎞ ⎛ B+ P⎞ Loa = 385⎜ ⎟ AQS fa = 21.2⎜ ⎟Q ⎝ B ⎠ ⎝ B ⎠

(3a)

where: Loa = air entrained in seal oil, (ft3/day) B = baraometric pressure, typically 14.7 psia P = Gas pressure in generator, (psig) Q = seal oil flow to gas side seals, (gpm) Sfa = saturation factor for air = 0.5 (this factor has been determined empirically; it takes into account the amount of air actually entrained in the seal oil), and, in metric units,

⎛ B+ P⎞ ⎛ B+ P⎞ Loa = 86.4⎜ ⎟ AQS fa = 4.75⎜ ⎟Q Loa = 86 .4 ( B + P ) AQS fa = 4.75 ( B + P )Q (3b) B B ⎝ B ⎠ ⎝ B ⎠ where: Loa = air entrained in seal oil, (m3/day) B = baraometric pressure, typically 101.3 kPa P = Gas pressure in generator, (kPa) (gauge) Q = seal oil flow to gas side seals, (L/s) 5. The amount of hydrogen that would be entrained if the test were run in hydrogen, considering that the volume solubility (H) is approximately 6% at atmospheric pressure, as given by:

⎛ B+ P⎞ ⎛ B+ P⎞ Loh = 385⎜ ⎟ HQS fh = 23.1⎜ ⎟Q ⎝ B ⎠ ⎝ B ⎠

(4a)

6. where: Loh = hydrogen entrained in seal oil, (ft3/day) Sfh = saturation factor for hydrogen= 1.0, and in metric units, © 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

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GEK 117004

Detection of Gas Leakage and Hydrogen Purity Formulas

Loh = 86 .4 (

B+P ) AQS B

fa = 4 .75

(

⎛ B+ P⎞ ⎛ B+ P⎞ B+P ⎟HQS fh = 5.18⎜ ⎟Q (4b) )Q Loa = 86.4⎜ B ⎝ B ⎠ ⎝ B ⎠

where: Loh = air entrained in seal oil, (m3/day). As a result,

Loh ≅1.1Loa

(5)

Subtracting the entrained air from the total air consumption leaves that portion which has leaked through the frame and associated piping.

Lea = Lta − Loa

(6)

where: Lta = total air consumption Lea = air which has leaked through the frame and piping A 98% mixture of hydrogen and air will leak 3.38 times faster than air because of the difference in molecular make-up. therefore:

Leh = 3.38Lea

(7)

where: Leh = hydrogen which has leaked through the frame and piping Total equivalent hydrogen consumption is the sum of entrained and leaked gas from equations (5) and (7):

Lth = Loh + Leh

(8)

where: Lth = total hydrogen consumption Pressure decay tests performed with the unit on turning gear or at standstill will yield values of consumption less than can be expected during normal operation. This is because the seal oil flows are greater when the unit is at speed. Gas lost through entrainment will increase in proportion to gas side seal oil flow. Equations (2) or (8) give total gas consumption at the test pressure. To determine gas consumption at other than the test pressure the following correction can be applied to the leakage portion:

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Detection of Gas Leakage and Hydrogen Purity Formulas

L e = L'e

Pd Pt

B + Pd B + Pt

GEK 117004

(9)

where: Le = leakage at desired pressure L’e = leakage at test pressure Pd = desired pressure, (psig) or (kPa {gauge}) Pt = average test pressure, (psig) or (kPa {gauge}) B = atmospheric pressure, typically 14.7 psia or 101.3 kPa Pressure correction for the entrained portion of consumption is made by substituting the desired pressure in equation (3) or (4). D. Increasing the Hydrogen Purity During operation of a hydrogen-cooled generator it is sometimes necessary to increase the purity of the hydrogen in the generator. This is done by admitting fresh hydrogen and discharging an equal amount of gas to atmosphere. Assuming perfect diffusion of the entering hydrogen with the gas in the generator, the amount of fresh hydrogen of purity S0 required to increase the hydrogen purity from S1 to S2 is

⎡ S − S1 ⎤ ⎛B+P⎞ Q h = 2.3V ⎜ ⎟ log 10 ⎢ o ⎥ (10) ⎝ B ⎠ ⎣ So − S2 ⎦ where: Qh = amount of fresh hydrogen of purity S0 added at atmospheric pressure, (ft3) or (m3) V = gas volume of the generator, (ft3) or (m3) P = pressure in generator, (psig) or (kPa {gauge}) B = atmospheric pressure, typically 14.7 psia or 101.3 kPa S0 = hydrogen supply purity, (%) S1 = initial generator purity, (%) S2 = final generator purity, (%) NOTE Qh and V must be chosen so that they are in the same consistent set of units, e.g., either (ft3) or (m3).

Qs = KQh

(11)

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GEK 117004

Detection of Gas Leakage and Hydrogen Purity Formulas

where: Qs = amount of fresh hydrogen added while unit is a standstill, (ft3) or (m3) K = volumetric flow correction factor (found on Figure 2) In Figure 2. , values of Qh/V(B/B+P) have been calculated from equation (10) for different values of desired final purity with the machine in operation and assuming that S0 = 99.6%. From these curves it is possible to determine the amount of fresh hydrogen (in standard volumetric units) required to produce a desired increase in generator hydrogen purity.

Figure 2. Quantity of Hydrogen Required to Increase Gas Purity from Equation (10)

E. Hydrogen Purity when Emergency Seal Oil System is in Operation (for Vacuum-Treated Seal Oil Systems Only) During operation of the emergency seal oil system, the shaft seals are supplied with oil that has not been vacuum-treated. Air from the oil will be released into the generator casing. This will gradually reduce the hydrogen purity. The generator must be scavenged periodically with fresh hydrogen in order to keep the hydrogen purity at a satisfactory value. Scavenging will be necessary any time the vacuum pump is not operating properly. Figure 3 shows the estimated drop in hydrogen purity for a typical generator when the seals are supplied with untreated oil. This graph shows that the hydrogen purity will decrease at the rate of about 2% in 8 hours.

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Detection of Gas Leakage and Hydrogen Purity Formulas

GEK 117004

Figure 3. Decrease in Machine Purity with Time; Seals Supplied with Untreated Oil To overcome this drop in purity, the casing must be scavenged at regular intervals. This is done by admitting fresh hydrogen to the generator and discharging gas from the generator to the atmosphere. The rate of which hydrogen must be added to the generator may be determined from the estimated rate of air entering the generator with the sealing oil similar to the calculation for a unit operating with a scavenging system. F. Evaluating Leak Rate Using Bubble Test 1. The volume of a bubble created during a leak test, may be calculated using equations (12).

1 v = π d3 6

(12a)

where: v = volume of bubble formed, (in3) d = diameter of bubble formed, (in), and

v=

1 π d3 6000

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

(12b)

17

GEK 117004

Detection of Gas Leakage and Hydrogen Purity Formulas

where: v = volume of bubble formed, (ml) d = diameter of bubble formed, (mm) 2. In estimating the size of a leak from the volume, note the time of formation of a large soap bubble and use equations (13).

Lb = 50

kv

(13a)

t

where: Lb = equivalent hydrogen leakage from that source, (ft3/day) v = volume of bubble, (in3) t = time for bubble to form, (s) K = 1 with hydrogen in generator, 3.38 with air in generator and, in metric units,

Lb = 86.4

kv

(13b)

t

where: Lb = equivalent hydrogen leakage from that source, (liter/day) v = volume of bubble, (ml) t = time for bubble to form, (s) K = 1 with hydrogen in generator, 3.38 with air in generator G. Evaluating Leak Rate at Bearing Drain Enlargement Vent In evaluating a large leak of hydrogen from a generator, we can see from the leak detection flow chart and in the section on sources of gas leakage that it may be advantageous to check for leakage of hydrogen with a flammable gas detector at the vent from the auxiliary detraining tank. Detection of hydrogen from the vent will mean a bearing enclosure or float trap leak. It will be advantageous to determine the approximate amount of hydrogen flowing out the vent to determine if these areas are the main source of the large leakage.

18

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

Detection of Gas Leakage and Hydrogen Purity Formulas

GEK 117004

To determine the total approximate flowrate out the vent a velocity meter (anemometer) should be used; however, the “bag” method can be utilized. Take a bag (plastic) of known volume and place it over the vent and note the time it takes to fill up. Assume a 10 ft3 (283 l) bag was used and it took 26 seconds to fill. This results in a flowrate of approximately 33,333 ft3 (944 m3) per day out of the vent. If three percent of that flowrate is hydrogen, this would equal approximately 1,000 ft3 (28 m3) per day. Most of the expected hydrogen consumption of 500 ft3 (14 m3) per day will go out the vent under normal conditions; therefore, the additional 500 ft3 (14 m3) per day measured leakage may be the result of a float trap problem or leak into the bearing enclosure area. NOTE If concentrations of greater than the lower explosive limit are detected, a portable gas analyzer should be used to determine the concentration of hydrogen in air.

© 2012 General Electric Company. All Rights Reserved. This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

19

GEK 117004

Detection of Gas Leakage and Hydrogen Purity Formulas

g

GE Energy General Electric Company www.gepower.com

20

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6,=(

':*12

$

6+

$

7+,5'$1*/(352-(&7,21



5(9

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‹

&23 60 %). TNHAR is reduced near full speed to help transition to Full Speed No Load (FSNL) without overshoot.

signal TAKR1

value 1

units %

type REAL

definition TURB ACCEL REF AT OPERATING SPEED

04.00.20 STARTING DEVICE BOGGED DOWN

This function monitors the speed of the turbine shaft during startup. If the turbine speed has decreased by more than the allowable setting (LK60BOG1), a time delayed trip of the starting device and turbine is initiated. This trip is not enabled during periods of coastdown from full crank speed for purge before firing.

signal LK60BOG1 LK60BOG2

value 5 1000

units % MSEC

type REAL UDINT

definition START DEVICE BOGDOWN SETPOINT START DEVICE BOGDOWN TIME DELAY

04.00.30 BEARING LIFT PUMP WITH TURNING GEAR-STARTING AND SHUTDOWN LOGIC

When the turbine is given a start command, the lift oil supply isolation valve (L20QB1) is opened. Once bearing lift oil pressure has been established, for K63QBLZ All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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seconds, the turning gear will engage and keep the turbine on slow roll. The turbine speed contact (L14HT) is used for stopping the turning gear on acceleration and restarting on deceleration. The turbine speed contact (L14HA) is used for deenergizing the lift oil isolation valve on acceleration and energizing on deceleration. Once the static starter accelerates the unit above the speed setpoint L14HT (TNK14HT1), the turning gear run command (L4TG) will drop out. The lift oil system will continue to provide lift to the bearings until accelerating speed (L14HA), at which time the lift oil isolation valve will close. When the turbine decelerates past accelerating speed TNK14HA2, the lift oil solenoid valve will energize and provide lift oil. On coastdown, once the unit decelerates below speed setpoint (TNK14HT2), the turning gear will re-engage as long as sufficient lift oil pressure is present. The hydraulic pumps, lift oil, and turning gear will then remain operating throughout the remainder of the cooldown period (L62CD). A fault detection signal (L86QBFLT) will also allow the turning gear to start if the unit is coasting down and the lift oil is not functioning. This run signal to the hydraulic pumps latches in with signal L1Z, which means that even if the turbine is tripped, the hydraulic pumps will continue to run throughout the cooldown period.

04.04.00 STATIC STARTER

The Static Starter uses a Load Commutated Inverter (LCI) to drive the generator as a motor to accelerate the turbine through the starting sequence. The Speedtronic sends various speed references representing each stage of startup to the LCI, along with 2 contacts to permit the LCI to run and to make torque. The LCI also makes excitation control commands to the Exciter (EX2100) in order to effectively control the generator motoring properties. A turning gear is used to break the rotor away from a dead stop, and slowly roll the rotor for cooldown.

04.05.00 FIRED SHUTDOWN

The FSRSD algorithm controls the gas turbine fuel during a fired shutdown by initiating FSR ramp down at appropriate events until FSRMIN is intercepted.

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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signal FSKSD[0] FSKSD[1] FSKSD[2] FSKSD[3] FSKSD[4] FSKSD[5]

value 0.101 5 1 0.101 1 0.101

Page 524 of 577

524 units %/SEC %/SEC %/SEC %/SEC %/SEC %/SEC

REV

A

type REAL REAL REAL REAL REAL REAL

definition SHUTDOWN FSR RAMP RATE ARRAY SHUTDOWN FSR RAMP RATE ARRAY SHUTDOWN FSR RAMP RATE ARRAY SHUTDOWN FSR RAMP RATE ARRAY SHUTDOWN FSR RAMP RATE ARRAY SHUTDOWN FSR RAMP RATE ARRAY

04.05.01 SHUTDOWN FUEL STROKE REFERENCE

When the generator breaker opens, the shutdown FSR (FSRSD) ramps from the existing FSR to FSRMIN at set rate FSKSD3 (FSRSD latches onto FSRMIN and decreases with corrected speed); when the speed drops below a defined threshold (K60RB) FSRSD ramps to a blowout at one flame detector. The sequencing logic remembers which flame detectors are functional at breaker open. When any of the functional flame detectors loses flame, FSRSD then ramps down at fast rate (FSKSD5) until fuel is shutoff with flameout. Timers limit the duration of the ramp to blowout. One timer trips after a fixed time from ramp down. A second timer limits fuel after any functional flame detector drops out.

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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FSRSD

FSKSD3

FSR %

BREAKER OPEN INTERCEPT

FSR

FSRMIN

INTERCEPT FSRMIN

FSKSD4

FSKMINN2

L60RB FSKSD5 ONE CAN OUT FLAME OUT TIME

signal K60RB

value 20

units %

type REAL

definition ABOVE RAMP TO BLOWOUT SPEED

04.05.02 MINIMUM FSR

Minimum FSR is the least amount of fuel that will continue to maintain flame in the combustor. It is required to ensure that other forms of FSR control cannot call for a fuel level that will cause the flame to blow out. Minimum FSR is calculated by performing a linear interpolation as a function of corrected speed (TNHCOR). During startup on gas fuel, FSRMIN is generated from a four point linear interpolator using constants FSKMINU[0], FSKMINU[1], FSKMINU[2], AND FSKMINU[3] and corresponding speed constants FSKMINN[0], FSKMINN[1], FSKMINN[2] AND FSKMINN[3]. During shutdown, FSRMIN is generated from a four position linear interpolator using

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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the following constants for gas : Gas

FSKMIND1[0] FSKMIND2[0] FSKMIND3[0] FSKMIND4[0]

and corresponding speed constants FSKMINN[0], FSKMINN[1], FSKMINN[2], FSKMINN[4]. If FSKMIND4X is set too low the unit may blow out during load rejection or synchronizing. If FSKMIND4X is set too high the unit will continue to increase its speed after 100% speed is reached, as speed control is unable to reduce FSR below the level defined by FSKMIND4X.

FSRMIN(%)

During shutdown, FSRMIN settings at open and closed IGV corrected speed allow correction for airflow as IGVs close. Two other points are set at lower speeds to allow for airflow to decrease in a quadratic manner. Values for shutdown should be set to provide a continuously decreasing combustion reference temperature, not too close to blowout.

FSKMIND4 SHUTDOWN FSKMIND3 FSKMIND2 FSKMIND1

FSKMINN[0]

FSKMINN[1]

FSKMINN[2] FSKMINN[3]

100 %

THNCOR, % SPEED

04.05.03 SHUTDOWN SEQUENCE TIME LIMIT TRIP

Once a Shutdown command is given and the generator breaker opens, the unit will be tripped if it is still running after timer K94XZ times out. The unit will also be tripped, if the speed falls below K60RB for K2RBT seconds before the flame in the All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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machine goes out.

signal K94XZ

value 8

units MIN

type REAL

definition FIRED SHUTDOWN TIME DELAY

04.06.01 COOLDOWN SEQUENCE

Cooldown Sequence for a unit at rest "Cooldown On" is selected from the Speedtronic panel. Initially with the tubine shaft at rest, the turning gear is used to breakaway the rotor and maintains a slowroll speed of 6 RPMs for cooldown. The cooldown will continue indefinitely until "Cooldown Off" is selected. Cooldown Sequence for a unit coasting down When the turbine shaft slows down to L14HT, the L62CD sequence starts timing. The cooldown slowroll is maintained by the turning gear at least until L62CD times out. Then the cooldown must be manually terminated by selecting "Cooldown Off."

signal K62CD

value 1440

units MIN

type REAL

definition COOLDOWN TIME

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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05.00.00 SECTION 5 - FUEL CONTROL

05.00.01 FUEL STROKE REFERENCE

The FSR algorithm compares all of the calculated fuel stroke references (except FSRMIN) and selects the minimum value as the controlling FSR. The value of FSR is limited to anything less than or equal to the value of load_lim. If FSR is running at or below FSRMIN, the control generates a TRUE logic output at L30FMIN. The lowest (and therefore dominant) FSR value input to FSRMIN is reflected in an enumerated state output, as well as a set of logical outputs. Unused FSR inputs should be set to maximum values so they will not affect control of the turbine.

05.00.03 MANUAL FUEL STROKE REFERENCE

FSR manual control is an open loop fuel control used to suppress the fuel stroke reference in the FSR minimum select gate algorithm. The FSR setpoint is preset at 128% out of the way. The FSRMAN below 128% alarms indicating that the FSRMAN is not at the maximum value. The setpoint may be adjusted with the following three methods: raise and lower commands, analog setpoint, or the preset button which sets FSRMAN equal to FSR.

05.00.035 FSR RATE OF CHANGE LIMITS

The rate of change of FSR algorithm logic, identifies when an excessive FSR rate of change has been detected. Logic signals change state if the increasing or decreasing rates have exceeded the alarm settings for three scans. The change must have exceeded a magnitude for the duration of three successive scans. The detected rate of FSR/sec is set by LK60FSR1/2/3/4/5/6.

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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signal LK60FSR1 LK60FSR2 LK60FSR3 LK60FSR4 LK60FSR5 LK60FSR6

value 20 20 30 10 20 30

A

SH

Page 529 of 577

529 units %/SEC %/SEC %/SEC %/SEC %/SEC %/SEC

REV

A

type REAL REAL REAL REAL REAL REAL

definition FSR RATE OF DECREASE SETPOINT 1 FSR RATE OF DECREASE SETPOINT 2 FSR RATE OF DECREASE SETPOINT 3 FSR RATE OF INCREASE SETPOINT 1 FSR RATE OF INCREASE SETPOINT 2 FSR RATE OF INCREASE SETPOINT 3

05.02.09 GAS RATIO VALVE INTERVOLUME PRESSURE REF

The pressure ahead of the GCV is controlled by the speed ratio valve (SRV) at a ratio of TNH plus a preset. P2 pressure = FPKGNG * TNH + FPKGNO When the fuel gas supply is shut off, the ratio valve acts as a stop valve, and is given a negative anti-dribble reference to force it closed.

signal FPKGNG FPKGNO

value 4.186 -23.6

units PSI/% %

type REAL REAL

definition FUEL GAS PRESSURE RATIO CONTROL GAIN FUEL GAS PRESSURE RATIO CONTROL OFFSET

05.02.10 GAS SPEED RATIO VALVE - CHECKOUT

1. LVDT Adjustment: a. With the hydraulic pressure at zero, check that the SRV is in the closed position. b. Connect an AC voltmeter across the LVDT (96SR-1) blue and yellow output leads in the junction box near the LVDT. c. Loosen the locknut on the corresponding LVDT and position the core to obtain a LVDT feedback RMS voltage (0.7 +- 0.005 VRMS) for the closed position. Tighten the locknut.

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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d. Repeat steps b and c for 96SR-2. 2. Regulator Setup: a. Determine the regulator used from the I/O Calibration List (Section 00). b In TOOLBOX ST, select "HARDWARE" Tab. Locate the REGULATOR section and install the card values listed in the I/O Calibration list for the SRV valve. Verify screen and exit. Download settings. Install the card values listed in the I/O Calibration List for devices 90SR-1, 96SR1 and 96SR-2. 3. Servo Polarity Check NOTE: This test is done under control of , and individually ( on Simplex units). If the SRV servo is controllable in all tests, correct polarity of the servovalve is confirmed. a. Establish Hydraulic Pressure to operate the Speed Ratio Valve. b. Establish trip oil pressure (OLT-1) by forcing the following logics: L20TV1X = 1 L4_XTP = 0 L20FG1X = 1 c. In TOOLBOX, select "HARDWARE" Tab. Locate the REGULATOR section and double click on regulator for SRV to calibrate valve. Select MANUAL VERIFICATION to permit the use of the analog forcing signal servo adjust reference. d. Disconnect the servovalve wires from and (on TMR) so that only is connected. Raise and lower the forcing reference and observe the resulting motion of the SRV servoactuator. If the motion is snap-action rather than smooth control,reverse the polarity of the connections in the box (notify Controls Engineering through customer service if a change is made). e. Repeat step d for and then for (if applicable). f. Put the SRV in the full open position. With all three servo coils disconnected verify that the SRV goes to the full closed position. 4. SRV Position Calibration: 0% stroke = 0.7 VRMS feedback 100% stroke: 90 Degrees a. The SRV actuator is calibrated by opening TOOLBOX ST and selecting "HARDWARE" Tab. All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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Locate the REGULATOR section and double click on regulator for SRV to calibrate actuator. b. Select ON for CALIBRATION MODE, and calibrate by selecting the min and max end positions and fixing these points respectively. SAVE calibration, and download settings. 5. Servo Valve Null Current Check a. With the hydraulic supply on, access the CALIBRATION window and select MANUAL VERIFICATION. b. Using MANUAL VERIFICATION, put the SRV in a mid travel position. c. Determine the null bias voltage by measuring the voltage across each servo coil at the I/O card. Refer to the I/O Report for terminal locations. d. Calculate the individual servo currents by dividing the servo voltage by the servo coil resistance (1000 ohms for gas turbine servos). The null servo current should be -0.267+-0.13 mA per controller. Notify Controls Engineering through customer service if the sum of the currents is not within specifications. Note that a Normally Closed valve should be opened with negative current because we want the valve to fail null bias closed. Example: (null bias voltage) ----------------------- = null bias current (servo coil resistance) : -0.267 VDC ---------- = -0.267 mA 1000 ohms : -0.266 VDC ---------- = -0.266 mA (if applicable) 1000 ohms : -0.267 VDC ---------- = -0.267 mA (if applicable) 1000 ohms --------sum of currents = -0.8 mA sum of currents I/O Configuration Bias % = ----------------------------------- * 100 (no. of servo coils)(rated current) 0.8 ma 2.67 % = ------- * 100 (3)(10) e. After calculating the current bias, put the new value in the I/O Configurator All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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(note that the current bias percentage should be input as a positive number). Verify screen and exit. It is important that this value is used because an error between the SRV reference and the SRV position could result if the bias is off. f. Download new I/O settings. 6. Final Verification Check NOTE: Set up to accurately measure the SRV stroke (typically a dial indicator) a. With the hydraulic supply on, access the CALIBRATION window and select MANUAL VERIFICATION. b. Stroke the valve to intermediate positions (typically 25, 50 and 75% stroke) and check the valve stroke versus the percent position displayed on the Mark VIe. Refer to drawing: Stop/Ratio Valve Assembly (MLI 0507) for the "B" stroke value. c. The LVDT's for the SRV are now calibrated. Select VERIFICATION "OFF" and exit the calibration window. REMOVE ALL forced logic points. d. Turn off aux. hydraulic pump. e. Measure the gap between the spring retainer plate and the spring travel retainer dimension "C" and verify that it is within specifications. f. If required, download final I/O settings.

05.02.14 GAS FUEL CONTROL FAULTS

Continuous monitoring of the control valve position feedback signal then comparing this signal to the reference allows the control system to monitor the error in the actual valve position. If this error becomes greater than the allowed deviation, an alarm will annunciate. If this error continues over an additional time period, the unit will trip. Failure to control valve position properly will cause inaccurate load control and inaccurate flow split control. Inaccurate flow split control can cause combustor to operate in regions of high dynamics, high temperatures, and high emissions.

05.02.17 GAS FUEL SEQUENCING PROTECTION

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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Gas Fuel Protection sequencing provides monitoring and diagnostics, perform leakage diagnostics across the Stop/Speed Ratio valve and Control Valves by performing a number of tests during startup and warm-up, to prevent the gas turbine from excessive or low fuel at light-off, to prevent wind-up of the machine. The purpose of the Gas Leak Test is to check the integrity of the Fuel Gas System Valves at every startup and shutdown. There are two tests performed: the Gas Stop/Speed Ratio Valve Test and the Interstage Leakage Test, performed on startup just after the machine moves off cranking speed and again at shutdown after flameout. These tests monitor the leakage rates across the valves by stroking the valves and monitoring the pressure in the P2 cavity. The test first performs the Fuel Gas Stop/Speed Ratio Valve leakage test by closing the fuel gas vent valve (20VG-1) and monitoring the pressure across the valve. If the interstage pressure rises above K86GLTA psi, the machine will not be allowed to fire via a pre-ignition trip. The second test performs the Interstage Leakage Test of the Gas Control Valves and Vent Valve. Pressure is introduced into the cavity and monitored. If the pressure drops below line pressure minus K86GLTB psi, the machine will not be allowed to fire via a pre-ignition trip. If either test fails the unit should not be fired until the problem has been resolved. The valve in question should be identified and inspected for any dirt or particulate build up, any visible seal damage, or re-calibrated to ensure proper functionality. The Pre-Ignition P2 Pressure High protection sequencing makes sure that the P2 cavity is clear of any interstage valve pressure when 20VG-1 is open, just prior to light-off. If the interstage valve pressure FPG2 exceeds KFPG2IH psi increasing pressure, the machine will not be allowed to fire. After firing and before warm-up complete, the P2 pressure is monitored to ensure that it is within a predetermined pressure window. If the P2 pressure is outside the window, (L86FPG2HT and L86FPG2LT) the gas turbine will trip. The Stop/Speed Ratio Valve Not Tracking compares the actual position of the valve to the desired position during the warm-up of the machine. If the Stop/Speed Ratio Valve is not following the reference value (L3GRVT), the gas turbine will trip. If the expected P2 pressure drops below the required setpoint for fuel splits when the generator breaker is closed, the unit will perform a runback (L3FG_P2X) to prevent wind-up of the fuel gas system to prevent an overspeed condition in the event full pressure is restored.

signal FPKGNG FPKGNO

value 4.186 -23.6

units PSI/% %

type REAL REAL

definition FUEL GAS PRESSURE RATIO CONTROL GAIN FUEL GAS PRESSURE RATIO CONTROL OFFSET

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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signal FPKGSD FPRGK_BIAS K20FGZ K3FG_P2X K86FPG2IH KFPG2IH KFPG2IHDB LK3GFIVP LK3GFLTD LK3GRVFB LK3GRVO LK3GRVSC LK60FSGH

Page 534 of 577

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value 23.604651 16 10 15 2.5 5 6 1 -5 2 -6.67 5 24.597 20

REV

A

units

type

definition

PSIG

REAL

GAS FUEL SPEED RATIO VALVE COMMAND SHUTDOWN REF

PSIG SEC SEC SEC PSIG PSI PSI SEC % % % %

REAL REAL REAL REAL REAL REAL REAL REAL REAL REAL REAL REAL

P2 PRESSURE BUDGET CONSTANT TIME DELAY FOR L20FGZ ABOVE ESTIMATED P3 MARGIN TD CONSTANT PRE-IGNITON P2 PRESSURE HIGH INHIBIT TD GAS FUEL P2 PRESSURE PRE-IGNITION LIMIT GAS FUEL P2 PRESSURE PRE-IGNITION LIMIT DEADBAND GAS VALVE INTERVALVE PRESSURE TROUBLE SETPOINT GAS VALVE TROUBLE TIME DELAY STOP/RATIO VALVE POSITION FEEDBACK TROUBLE SETPOIN STOP/RATIO VALVE OPEN TROUBLE SETPOINT STOP/RATIO VALVE SERVO CURRENT TROUBLE SETPOINT STARTUP FUEL STROKE REFERENCE HIGH ALRM SETPOINT

05.02.18 SLIDING P2 PRESSUE CONTROL DESCRITPION

P2 Reference Generation The fuel pressure reference upstream of the GCV is the median value of three control curves: FPRGCRIT, FPRGSUP, and the minimum of FPRGN and FPRGTAMB. FPRGCRIT is the minimum P2 pressure required in order to maintain choked GCVs. It is composed of two CPD-based curves and passes a value of 0 psi when the breaker is open. FPRGSUP is the supply pressure (FG1) minus a pressure drop across the SRV. FPRGN is the speedbased pressure reference, calculated as follows: FPRGN = FPKGNG * TNH + FPKGNO FPRGTAMB is an ambient temperature bias from FPRGN, derived from base load at each ambient temperature extreme. A plot of these pressure reference components is shown below:

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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System Protection System protection from low gas supply pressures prevents the gas turbine from operating in regions of possible high dynamics, SRV wind-up, and uncontrollability of GCVs. As FPG2 nears the FPRGCRIT line, a Raise Inhibit will prevent the unit from operating at higher loads without the required supply pressure. If FPG2 drops some deadband below FPRGCRIT for a certain amount of time, a trip will occur. The unit will be allowed to unload along FPRGCRIT in Premix Mode as supply pressure decreases. If the unit has unloaded to the point of transferring to Piloted Premix, the unit will trip. A higher gas supply pressure is needed to complete the transfer. The unit will not be allowed to operate in Extended Piloted Premix mode. If a G1 Purge Valve Error occurs in Premix, the result is a runback to the Piloted Premix to Premix transfer point. As the SRV nears the full open position, the unit will perform a fast runback until the valve is in safe operating range. This is also true for the GCVs at the normal All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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unload rate. MWI Correction FQKCG_MWI was modified to become FQKCGP2_MWI. A P2 correction factor is in place to account for differences in current pressure reference versus the legacy pressure reference.

05.02.210 TOTAL FUEL GAS FLOW - CHECKOUT

1.

Verify that the orifice plate located in the gas metering tube is installed with the sharp edge upstream and the beveled edge downstream.

2.

During initial installation, verify the following meter tube dimensions: Orifice Size: Meter tube ID: Beta Ratio:

Per Shipping Material 8.0 inches Per Shipping Material

*If certificate of conformance for the meter tube and the orifice plate did not ship with the material contact the Control Engineer identified in section 01.07.00. Note that the Beta Ratio is the orifice size divided by the meter tube ID, and this ratio should be between 0.5 - 0.7 for accurate flow measurement. 3.

Determine the location of the MA inputs for the following transmitters from the I/O Calibration List (Section 00): 96FM-1

4.

In ToolboxST, install the PAIC/PCAA card values listed in the I/O Calibration List for the milliamp input definitions. Verify and exit.

5.

If the I/O Configuration values have changed, download new settings.

6.

Final Verification Ensure that the device is mounted with the flange mounting face in a horizontally

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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level position per the 0302 drawing. Calibrate the gas flow transmitter by placing nominal pressure (per section 05.02.15) across both device ports via the test injection port. Verify that the device output is 4mA. Simulate the RTD input to read nominal temperature (per section 05.02.15), place nominal pressure on the upstream device port, and nominal pressure minus 5 PSI on the down-stream port. The device output should be 20mA. Display the signal names on the and verify the Mark VIe values are the same as the input values. If the site has a Rosemount Hand Held HART Communicator Model 275, it may be used as well to calibrate the device. See the instruction which shipped with the device for details on how to do this function.

05.10.001 DLN2+ COMBUSTION REFERENCE COMPARATORS

This software contains three combustion reference temperature comparators which trigger the transfers. The first comparator is used in conjunction with L14HS in order to transfer from diffusion to sub piloted premix. The other comparators trigger transfers from sub piloted premix to piloted premix, and from piloted premix to premix, respectively. Each of these temperature comparators employs a deadband and time delay to drop out. In addition each comparator has an anti-cycle timer, which prevents the comparator from picking up again after it drops out until the anti-cycle timer expires. The purpose of the anti-cycle timer is to prevent rapid cycling between combustion modes in the event of an oscillating combustion reference temperature.

05.10.011 DLN2+ FSR COMPENSATION FOR PURGE INTRODUCTION

Initiation of transfers involving purging of an active manifold can result in a load swing as the fuel is being displaced into the combustor by the incoming purge air. The magnitude of this transient depends on the purge valve characteristics, the initial stored mass of fuel in the piping, and fuel nozzle flow characteristics. Compensation for this effect, by ramping the gas control valve FSR to a lower value, until the transfer has been completed will reduce the load swing. The ramp rates,

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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maximum reduction of FSR, and the time delay constants may require adjustment in the field. If this compensation did not take place to prevent or at least minimize the load spike, machines employing constant settable drop would follow the over firing transient with an under firing transient. During the load spike, droop control would ramp down FSRN to compensate for the extra fuel being exhausted from the manifold which is to being purge, however the effect of extra fuel from the manifold being purged decays very rapidly at which point the firing temperature undershoots as FSR is lower than when the event began.

05.10.021 DLN2+ FLOW SPLITS TO VALVE STROKE REFERENCE

For G1 and G2, the appropriate flow reference for each mode is selected and passed to FXSGn, which is then either passed through a rate control or rate bypass loop to generate the flow reference as a percentage of total fuel FXSGnC. The rate bypass loop is used when the valve needs to be stepped to the reference rather than moved there under ramp control. For example, if the unit is running in piloted premix and there is a breaker open event, all the fuel needs to be sent to the G1 valve immediately, both FXSG1 and FXSG1C will be stepped to 100%. On the other hand, when transferring from sub piloted premix to piloted premix, FXSG1 will step from FXSG1_LC (G1 sub piloted reference) to FXSG1_HC (G1 piloted reference). FXSG1C will ramp between these values so diffusion fuel will ramp off in a smooth linear fashion while premix fuel is ramped on via G2 and G3. Each of the gas valves operates with a critical pressure drop, which makes the mass flow through each gas valve independent of downstream pressure (gas manifold pressure). Provided that the pressure drop remains critical, mass flow is then a function of upstream pressure (P2), gas temperature, and valve stroke. For constant gas temperature and inlet pressure (P2), the flow is only a function of valve stroke. The stop-speed-ratio-valve is controlled to maintain a constant P2 pressure, which is the inlet pressure to each of the three gas control valves. To balance fuel-flowsplit between differently sized gas control valves, a CG-reference needs to be used to determine the appropriate valve stroke. After generating the flow reference to each gas valve (FQRGnX), the flow reference is converted to a CG reference FQRGnCG. Note: CG is called the gas sizing coefficient, which relates critical flow across the valve to inlet (P2) pressure. The CG-reference is then converted to a valve-stroke-reference using the valve scaling block, which simply performs a linear interpolation between the valves of the CG and stroke to generate signal FSRGn. The servo-output-block saturates the closed valve by calling for a position of -25% when L3Gn does not enable the valve.

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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05.10.031 DLN2+ MODE CONTROL

This design standard defines each of the combustion modes (a unique combination of fuel nozzles being on). In addition, this standard contains the code that drives all of the gas manifold prefills. The DLN2+ has 5 unique combustion modes as shown in the table below. COMBUSTION MODE DIFFUSION SUB PILOTED PREMIX PILOTED PREMIX PREMIX PM1 LOAD REJECTION

FUEL SYSTEMS ON G1 G1,G2 G1,G2,G3 G2,G3 G2

DIFFUSION MODE (L83FXP) In this mode all the gas fuel is directed to the five diffusion tips in each of the combustors. At this time the premix passages PM1 and PM4 are purged with CPD air. Diffusion is the normal mode of operation from ignition to L14HS and unloading from L14HS to flameout. SUB PILOTED PREMIX (L83FXL) In this mode the fuel is split between the two gas control valves. The G2 PM1 split ramps up in the higher end of this mode to optimize combustion dynamics. Attention must be made not to exceed the defined split-level at the high end of this mode due to hardware concerns. Sub piloted premix is the combustion mode between L14HS and FXKTH loading and FXKTH-FXKTHDB to L14HS. Sub piloted premix mode is the steady state FSNL mode PILOTED PREMIX (L83FXH) In this mode the fuel is split between the three gas control valves. To give an even premix split between G2 and G3, the split would be 20/80. It is normal to run the premix burners slightly off even-split to optimize combustion dynamics at the expense of emissions. Piloted premix is the combustion mode between combustion reference temperature FXKTH and FXKTM-loading, and FXKTM-FXKTMDB to FXKTH-FXKTHDB unloading. PREMIX (L83FXM) In premix all the fuel is directed to G2 and G3, which feed PM1 and PM4 respectively. To give an even premix split between G2 and G3, the split would be 20/80. It is normal to run the premix burners slightly off even split to optimize combustion dynamics at the expense of emissions. Note on Fuel Temperature Sub Piloted Premix and Piloted Premix mode can run on both heated and unheated fuel All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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up to 1900 CRT. For Piloted Premix mode above 1900 CRT and all of Premix mode, fuel temperature must be maintained within the wobbie range specified for the unit. More information on wobbie can be found in the controls design standard BK2R_MWI. Note if SPPM is disabled: Anytime the machine is operated in diffusion above 1500 CRT with a fuel temperature above 125o F for a period of 45 seconds, the following alarm will be generated: "Fuel temp high reduce temp or load into PPM to prevent unload" Note: using the normal loading rate it takes 33 seconds to load from 1500 to 1600 CRT. If the machine is operated in diffusion mode above 1500 CRT and the fuel temperature is above 125o F for 3 minutes, a governor lower will unload to 1450 CRT. Once the machine is unloaded, the timer will reset. In addition to the unload, any auto loading mechanisms such as preselected load will be cleared to prevent Auto loading back above 1500 after the lower command drops out. In other words, operator action will be required in order to load the machine. The following alarm signal will also be generated: "Fuel temperature high for diffusion governor lower" Anytime the gas fuel temperature exceeds 380o F, it will be alarmed. If the fuel temperature exceeds 395o F, it will be alarmed and an automatic shutdown commanded will be issued.

05.10.041 DLN2+ SPLIT SCHEDULE & CLAMPS

Each of the fuel schedules contains an array of combustion reference temperatures and flow splits. When the actual combustion reference temperature is between two of the combustion reference temperatures, a linear interpretation is performed to determine the appropriated flow split. After the flow split is generated from the linear interpolator, it is passed through a median select block that places upper and lower boundaries on the level that the flow split may be set to. This software contains a total of four split schedules, which are as follows: 1. Sub Piloted Premix All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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a. b.

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G1 fuel is scheduled as a percentage of total gas fuel flow. G2 fuel is not scheduled as it gets the remainder fuel left after G1.

2. Piloted premix a. G1 fuel is scheduled as a percentage of total gas fuel flow. b. G2 fuel is scheduled as a percentage of total gas fuel flow less diffusion fuel. c. G3 fuel is not scheduled as it gets the remainder fuel left after G1 and G2 get the fuel defined by their respective schedules. 3. Premix a. G2 fuel is scheduled as a percentage of total gas fuel flow. b. G3 fuel is not scheduled as it gets the remainder fuel left after G2. 4. Premix Split Bias a. This bias subtracts fuel from the PM1 passage and through remainder fuel, adds it to the PM4 passage during premix transfer transients. The default constant for the bias is zero but may be adjusted up to 4% if the transfer is unstable. For the transfer into premix, the bias is introduced with the start of the D5 purge sweep and ends after the D5 purge control valve reaches its maximum transient position. For the transfer into piloted premix, the bias is initiated with L3FXHS and terminated with L3FXHC (piloted premix transfer start and complete). The bias is intended to be field tunable in the event that premix transfers are not robust, but a bias of 4% or more should not be implemented without consulting Combustion Engineering in Schenectady.

05.10.09 DLN2+ GAS PURGE

Each of the gas manifolds is purged anytime it is not transporting gas fuel. indicates when each of the purge systems is on: Operational mode DIFFUSION SUB PILOTED PREMIX PILOTED PREMIX PREMIX PREMIX INNER LOAD REJ

D5 OFF OFF OFF ON ON

PM1 ON OFF OFF OFF OFF

Table 1

PM4 ON ON OFF OFF OFF

Table 1

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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GAS FUEL PURGE TIMING The turning on of premix purges is staggered to minimize load transients. The PM4 purge is time-delayed 15 seconds after the PM4 (G3) gas valve is confirmed closed. PM1 purge comes on immediately when the PM1 (G2) gas valve is confirmed closed. D5 purge comes on five seconds after the G1 gas valve is confirmed closed. GAS FUEL PURGE FAULT DETECTION AND PROTECTION The gas fuel purge system uses a truth table to detect the condition of the purge system, which has five digital feedbacks, indicating the status of the system. Four of the feedbacks are limit switches, giving positive indication of both open and closed position of the gas side and airside purge valves. The fifth input is from triple redundant pressure switches, monitoring the inter-purge valve cavity pressure. With five inputs, there are 2^5 (32) possible system configurations. Only one configuration is correct - indicating that all five inputs are confirming that the system is in the commanded state. There are then thirty-one other configurations in which the system is in some kind of fault condition. Within these thirty-one cases, there are various levels of fault severity. A level of severity is defined as any fault state in which the actions taken are the same. In order to preserve the integrity of the following purge fault matrix, the D5 purge control valve has four limit switches that combine to form the "valve open" and "valve closed" signals; the first limit switch is to confirm that the valve is closed. The second and third switches are placed to protect against combustor dynamics (high and low side). The fourth switch is set just below the position of the sweep purge level. It is also used to confirm that the valve is at this minimum position for liquid operation. During transients and different modes of operation, one of these limit switches will make up the "valve open" signal. There is also a 4-20 mA position feedback signal from the valve I/P controller. This is used for position reference and to ensure that the valve does not improperly get stuck in any one position. NOTE: BURST mode must be enabled on the valve I/P controller using the HART controller in order to get a correct feedback signal OPEN FAULT MATRIX (Note: there is a separate closed fault matrix.) Considering the open fault matrix below, it may be seen that there are three fault categories or levels of severity: 0,1, and 2: Fault level 0 (fault index 22) is normal, as both open switches are indicating open, both closed switches are indicating not closed, and the inter-cavity pressure is high. This is the correct configuration when the purge system is commanded on. Fault level 1 occurs when all but one of the limit switches is indicating the correct position. Fault level 2 is any case that is not case 0 or 1.

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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05.10.101 DLN2+ VALVE FAULT LOGIC

This software monitors the gas valves and their corresponding servo valves to insure they are being controlled as intended. When a fault is detected an alarm is generated and in cases where the fault is severe the machine is tripped.

05.10.111 DLN2+ TIMERS & COUNTERS

It is required that timers and counters record the fired hours in each mode. The modes are DIFFUSION, SUB PILOTED PREMIX, PILOTED PREMIX, and PREMIX for gas fuel. A summation of this information will be available to the turbine operator in the form of a unique display at the operator interface.

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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06.01.00 MODULATED INLET GUIDE VANE CONTROL

The variable inlet guide vanes (IGV) are modulated to maintain high exhaust temperature during part load for waste heat recovery. They are also modulated at startup and shutdown as function of corrected speed. During start-up, the inlet guide vanes will open to a minimum angle and subsequently modulate to the full open position as gas turbine loads and the exhaust temperature reach the IGV control reference. In this mode, exhaust temperature is maximized for part-load operation which is desirable for heat recovery (combined-cycle mode). When IGV temperature control is turned "off", IGV control of exhaust temperature is rescheduled to modulate at a constant exhaust temperature, approximately 300oF below the base isothermal exhaust temperature reference. Holding the IGVs closed at less than quarter load helps to avoid combustor pulsations. They go full open as temperature exceeds the reference (simple-cycle mode).

06.02.00 PART SPEED INLET GUIDE VANE CONTROL

During the startup, acceleration of the gas turbine compressor to operating speed is necessary to open the inlet guide vanes as a function of temperature corrected speed (TNHCOR), to prevent stall at low speeds typically in the front stages of the compressor. The Speedtronic controls utilize an algorithm to open the inlet guide vanes from a minimum startup position to a minimum operating condition. This algorithm increases inlet guide vane angle along a linear path as a function of corrected speed. The equation for corrected speed is listed below. TNH is the turbine compressor rotor (high pressure shaft) speed, CTIM is the compressor inlet temperature (oF), and CQKTC_RT is the temperature correction basis. CQKTC_RT can be a value of either 540oR (80oF) for NEMA conditions or 519oR (59oF) for ISO conditions. The temperature correction factor (CNCF) is defined also defined below. The equation to calculate part speed IGV angle is as follows: Part speed IGV angle = CSKGVPS2 * (CSKGVPS1 - TNHCOR) TNHCOR = TNH*SQRT(CQKTC_RT/(CTIM+460)) CNCF = SQRT((CQKTC_RT)/(CTIM+460))

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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signal CSKGVPS1 CSKGVPS2

value 81.06 6.42

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type REAL REAL

definition VIGV PART SPEED HP CORR SPEED OFFSET VIGV PART SPEED HP CORR SPEED GAIN

06.11.06 COMPRESSOR PRESSURE RATIO MEASUREMENT

The gas turbine compressor pressure ratio (Xc) is calculated by taking the ratio of the compressor discharge absolute pressure and the compressor inlet bellmouth absolute pressure. The compressor discharge absolute pressure is formulated by adding absolute ambient pressure to the measured compressor discharge gauge pressure. The compressor inlet bellmouth absolute pressure is found by subtracting the inlet filter and duct pressure drop from the absolute ambient pressure. The Speedtronic control panel implements the compressor pressure ratio calculation using signals derived from pressure transducers mounted on the gas turbine. The compressor pressure ratio signal (CPR) is calculated by the equation listed below. CPR = [CPD + (AFPAP * CPKRAP)]/[CPKRAP * (AFPAP - (AFPCS/CPKRPC))] Since compressor pressure ratio is a critical input for compressor protection and exhaust temperature control routines, the measurements of compressor discharge pressure and ambient pressure are performed with triple redundant transducers for high reliability. The inlet pressure drop measurement is not measured with triple redundant sensors because a failure of this measurement will typically result in less than a 2% error in the pressure ratio calculation. It is sufficient to clamp the inlet pressure drop signal between expected minimum and maximum limits. The limits on ambient pressure should be set to the maximum expected barometric pressures for the site. In particular, the lower barometric pressure limit (CPKRAMN) may need to be adjusted for sites that are at high elevations. The scaling for 96AP transducers should be consistent with the CPKRAMN and CPKRAMX limit settings. The 96CS-1 transducer is typically scaled to a maximum value of 11.1 inH2O because the maximum inlet filter and ducting system pressure drop should be well within this range when properly designed and implemented. Compressor Pressure Ratio Measurement Checkout The compressor pressure ratio CPR is a critical control parameter for exhaust temperature control and compressor protection. The calibration and accuracy of the atmospheric pressure transducers (96AP-1/2/3), the compressor discharge transducers All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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(96CD-1/1B/1C), and the inlet pressure drop transducer (96CS-1) should be verified during unit commissioning and at each major maintenance outage. I/O Configurator Setup 1. In ToolboxST select CA001 in Hardware and go to the PAIC section with the CPD definitions. Set the I/O Configurator values to the values listed in the I/O Calibration List (Section 00) for the compressor discharge transmitter(s) 96CD1, 96CD-1B and 96CD-1C (if applicable). Verify and exit. 2. Next, in ToolboxST select CA001 in Hardware and go to the PAIC/PCAA section with the AFPAP definitions. Set the I/O Configurator values to the values listed in the I/O Calibration List (Section 00) for the ambient pressure transmitter(s) 96AP-1A, 96AP-1B and 96AP-1C (if applicable). Verify and exit. 3. Next, in ToolboxST select CA001 in Hardware and go to the PAIC/PCAA section with the AFPCS definitions. Set the I/O Configurator values to the values listed in the I/O Calibration List (Section 00) for the inlet pressure drop transmitter 96CS-1 (if applicable). Verify and exit. 4. If any of the values in the I/O Configurator have changed, Download settings by selecting "Distributed I/O" and go to Device tab to select "DOWNLOAD" to download the new settings. Compressor Discharge Transmitter Check 1. Using a nitrogen pressure source and calibrated test gauge calibrate the compressor discharge transmitter(s) 96CD-1, 96CD-1B and 96CD-1C (if applicable), to the specification located in the Device Summary (MLI 0414). 2. In ToolboxST, search for the CPD signal. 3. Put pressure on the Compressor Discharge Transmitters, one at a time, and check that the Mark VIe indication is the same as the pressure input. Check at 0%, 25%, 50%, 75%, and 100%. Due to the critical function of these transmitters, they should be calibrated accurately. Verify that: 96CD-1 goes to via the pin "cpd1a" 96CD-1B goes to via the pin "cpd1b" 96CD-1C goes to the via the pin "cpd1c" 4. After testing, restore the transmitters and valving to the normal operating condition.

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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Barometric Pressure Transmitter Check 1. Using a pressure source and calibrated test gauge calibrate the barometric transmitter(s) 96AP-1A, 96AP-1B and 96AP-1C (if applicable) to the specification located in the Device Summary (MLI 0414). 2. In ToolboxST, search for the AFPAP signal. 3. Put pressure on the Barometric Pressure Transmitters, one at a time, and check that the Mark VIe indication is the same as the pressure input. Check at 0%, 25%, 50%, 75%, and 100%. Due to the critical function of these transmitters, they should be calibrated accurately. Verify that: 96AP-1A goes to via the pin "afpap1a" 96AP-1B goes to via the pin "afpap1b" 96AP-1C goes to via the the pin "afpap1c" 4. After testing, restore the transmitters and valving to the normal operating condition. Inlet Pressure Drop Transmitter Check 1. Using a pressure source and calibrated test gauge, calibrate the inlet pressure drop transmitter 96CS-1 to the specification located in the Device Summary (MLI 0414). 2. In ToolboxST, search for the AFPCS signal. 3. Put pressure on the Inlet Pressure Drop Transmitter, and check that the Mark VIe indication is the same as the pressure input. Check at 0%, 25%, 50%, 75%, and 100%. Due to the critical function of these transmitters, they should be calibrated accurately. Verify that: 96CS-1 goes to via the pin "afpcs" 4. After testing, restore the transmitters and valving to the normal operating condition.

06.11.094 MINIMUM IGV FOR OVERSPEED

To minimize overspeed during a breaker opening the minimum IGV setpoint will modulate All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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as a function of speed. Holding the IGVs open during this transient will reduce the speed overshoot due to two factors. The increased airflow at higher IGV angles will produce higher compressor loads. The higher IGV angles will result in higher compressor discharge pressures which will reduce the pressure drop across the gas fuel nozzles and therefore reduce the fuel flow inrush after the breaker opens.

06.11.12 IGV REGULATOR CONFIGURATION

Model Type: Combustion System Configuration Closed Ring Stop Closed Actuator Stop Closed Electronic Stop Minimum Operating Angle w/ IBH Minimum Operating Angle w/o IBH Opened Electronic Stop Opened Actuator Stop Opened Ring Stop

MS9001FA+e Uncambered DLN 2+ 24.5 26.5 28.5 47.5 N/A 89.5 91.5 93.5

* - Uprated/performance recovery to 90 DGA

06.11.121 IGV REGULATOR - CHECKOUT

LVDT Adjustment 1. With the hydraulic pressure at zero, check that the IGVs are in the closed position. 2. Connect an AC voltmeter across the LVDT (96TV-1) blue and yellow output leads in the junction box near the LVDT. 3. Loosen the locknut on the corresponding LVDT and position the core to obtain a LVDT feedback RMS voltage (0.7 +- 0.005 VRMS) for the closed position. Tighten the locknut.

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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4. Repeat steps 2 and 3 for 96TV-2. Regulator Setup 1. Determine the regulator used from the I/O Calibration List (Section 00). 2. Set the servo regulator hardware jumpers to the values listed in Section 01, Servo Regulator Hardware Jumper Settings. 3. In ToolboxST, select CA001 and go to the PCAA/PAIC. Under that go to the REGULATORS section and install the card values listed in the I/O Calibration list for the IGV regulator. Verify screen and exit. Download settings by selecting "Distributed I/O" and go to Device tab to select "DOWNLOAD" to download the new settings. Servo Polarity Check **WARNING: Before measuring IGV angles, verify the turning gear/ratchet system has been disabled to prevent the turbine rotor from moving. Do not rely on Logic Forcing for protection of personnel. Isolate power to the turning gear/ratchet by removing hardware jumpers or wires to the hydraulic ratchet solenoid (20HR-1) or by turning off the turning gear motor breaker (if applicable). Refer to the Diagram, Schem PP-Strt Mns (MLI 0421), for the specific arrangement of the unit. See the I/O Calibration List and the Application Manual for locations of hardware jumpers. NOTE: This test is done under control of , and individually ( on Simplex units). If the IGV Servo is controllable in all three tests, correct polarity of the servo valve coils is confirmed. 1. Establish Hydraulic Pressure to operate the IGV servo actuator. 2. Establish trip oil pressure (OLT-1) by forcing the following points: L20TV1X = 1 L4_XTP = 0 SAFETY WARNING: moving.

Make sure that maintenance personnel are clear of the IGVs when

3. In ToolboxST, select CA001 and go to the PCAA/PSVO. Under that go to the REGULATORS section and double click on regulator for IGVs to calibrate actuator. Select MANUAL VERIFICATION to permit the use of the analog forcing signal servo adjust reference. 4. Disconnect the servo valve wires from and (on TMR) so that only is All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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connected. Raise and lower the forcing reference and observe the resulting motion of the IGV servo actuator. If the motion is snap-action rather than smooth control, reverse the polarity of the connections in the box (notify Controls Engineering through customer service if a change is made). 5. Repeat step 4 for and then for (if applicable). 6. Raise the IGVs to the full open position. With all the servo coils disconnected, verify the IGVs go to the closed position. 7. Set reference to zero and exit the calibration window. 8. Reconnect all wires to give the proper polarity. 9. Shut off the hydraulic supply Position Calibration: The IGV actuator is calibrated by opening ToolboxST, select CA001 and go to the PCAA/PSVO. Under that go to the REGULATORS section and double click on regulator for IGVs to calibrate actuator. Force the calibrate permissive logic to enable actuator calibration (L3ADJn = 1). Select ON for CALIBRATION MODE, and calibrate by selecting the min and max end positions and fixing these points respectively. SAVE calibration, and Download settings by selecting "Distributed I/O" and go to Device tab and select "DOWNLOAD". Servo Valve Null Current Check 1. With the hydraulic supply on, access the CALIBRATION window and select MANUAL VERIFICATION. 2. Using MANUAL VERIFICATION put IGVs in a mid-travel position. 3. Determine the null bias voltage by measuring the voltage across each servo coil at the regulator cards. Place the positive lead on SVOnn and the negative lead on SVORnn. Refer to the I/O Report for terminal locations. 4. Calculate the individual servo currents by dividing the servo voltage by the servo coil resistance (1000 ohms for gas turbine servos). The null servo current should be -0.267(+-0.13 mA) per controller. Notify Controls Engineering through customer service if the sum of the currents is not within specifications. An adjustment to the mechanical null bias, located on the side of the servo, may be necessary. Note that a Normally Closed valve should be opened with negative current because we want the valve to fail null bias All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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closed. Example: (null bias voltage) ----------------------- = null bias current (servo coil resistance) :

-0.267 VDC ---------- = -0.267 mA 1000 ohms

:

-0.266 VDC ---------- = -0.266 mA (if applicable) 1000 ohms

:

-0.267 VDC ---------- = -0.267 mA (if applicable) 1000 ohms

sum of currents = -0.8 mA sum of currents I/O Configuration Bias % = ----------------------------------- * 100 (no. of servo coils)(rated current) 0.8 mA -------- * 100 = 2.67 % (3)(10 mA) NOTE: see Section 01, Servo Regulator Hardware Jumper Settings for rated current. 5. After calculating the current bias, put the new value in the I/O Configurator (note that the current bias percentage should be input as a positive number). Verify screen and exit. It is important that this value is used because an error between the IGV reference and the IGV position could result if the bias is off. 6. Download new I/O settings by clicking on "Mark VIe I/O" with right mouse button and selecting "DOWNLOAD." Download new I/O settings by selecting "Distributed I/O" and go to Device tab to select "DOWNLOAD" Final Verification Check 1. With the hydraulic supply on, access the CALIBRATION window and select MANUAL VERIFICATION.

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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2. Put the IGVs at the 42o position. Measure the IGV angle with a protractor and verify it is the same as the Mark VIe display. 1. NOTE: Accuracy of the IGV calibration is important to the unit performance. The IGVs should be within .5o the Mark VIe display. 2. Put the IGVs at the 57o position. Measure the IGV angle with a protractor and verify it is the same as the Mark VIe display. 3. Put the IGVs at the 88o position. Measure the IGV angle with a protractor and verify it is the same as the Mark VIe display. 4. Select VERIFICATION "OFF" and exit the calibration window. Un-force logic points and restore turning gear/ratchet wires or hardware jumpers to normal. 5. If required, download final I/O settings by selecting "Distributed I/O" and go to Device tab to select "DOWNLOAD" CAUTION: When installing hardware jumpers on solenoid circuits check that the logic to the solenoid is a "0" to prevent arcing.

06.11.13 IGV NOT FOLLOWING REFERENCE

Protection against operation with IGVs in the compressor surge region is an IGV trip and turbine trip when the IGV feedback (CSGV) exceeds the part speed reference (CSRGVPS) by a set margin.

06.11.15 INLET GUIDE VANE FAULT DETECTION

The actual LVDT position of the IGVs (CSGV) and the IGV servo driver output (CAGV) are compared to preset limits to annunciate IGV fault conditions. On Mark VIe, positive current closes the IGVs.

06.14.00 COMPRESSOR INLET BLEED HEAT CONTROL

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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The compressor bleed valves are open at part speed and closed at operating speed to avoid compressor stall conditions. They close above 14HS with complete sequence (L3) or with closed breakers (L52GX). Actuation is by compressor discharge pressure through 20CB. Possible malfunction of 20CB, necessitates tripping the turbine startup if the compressor bleed valve trouble alarm indicates the bleed valves are closed below 14HS operating speed.

06.14.01 DLN INLET BLEED HEAT CONTROL

Dry Low NOx (DLN) combustion systems operate in a mode called Premix Mode, where fuel and air are mixed prior to burning. On GE DLN I gas turbine systems, Premix Mode is designed to occur at a fairly constant firing temperature with modulated compressor airflow during unit operation on exhaust temperature control. With normal minimum inlet guide vane (IGV) angles and exhaust temperature control, Premix Mode operation occurs after approximately 70% load. By lowering the allowable minimum IGV angle, exhaust temperature control operation and Premix Mode can be extended to lower loads, down to approximately 40-50% load. Lowering the minimum IGV angle to extend Premix Mode to lower loads has consequences with respect to the gas turbine compressor design margins. Also, the reduced IGV angles cause a higher pressure drop and a resultant temperature depression of the air flow. This effect could lead to ice formation on the first stage stator blades under certain ambient conditions. To address compressor design concerns when Premix Mode is extended by lowering IGV minimum angles, up to 5% compressor discharge air is extracted from the compressor and recirculated to a mixing manifold located in the inlet air stream. Bleeding the compressor and recirculating the compressor discharge air to the inlet airstream increases the compressor design margins and prevents conditions necessary for the formation of ice on the first stage stator blades. The amount of inlet bleed heat in terms of percent compressor airflow (CSRBH) is scheduled as a function of IGV angle. DLN inlet bleed heat flow is regulated by modulating the VA20-1 control valve with a proportional plus integral control which utilizes a calculated percent inlet bleed heat compressor extraction signal (CQBHP) as the feedback parameter. The percent compressor extraction flow (CQBHP) is derived by dividing a calculated inlet bleed heat mass flow signal (CQBH) by an estimated gas turbine total airflow signal (WEHX). The DLN Premix Mode Turndown inlet bleed heat command (CSRDLN) is maximum selected with other inlet bleed heat references (if applicable) to formulate the VA20-1 control valve command reference (CSRIH). All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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DLN Inlet Bleed Heat Schedule

% Compressor Discharge Extraction

6 5 4 3 2 1 0 42

45

48

51

54

57

60

63

66

69

72

Inlet Guide Vane Angle (DGA)

06.14.02 COMPRESSOR OPERATING LIMIT PROTECTION

GE gas turbine compressors are designed to operate below a compressor pressure ratio limit (CPRLIM) that is a function of IGV and temperature corrected rotor speed (TNHCOR). Combinations of factors such as extreme cold ambient temperatures, low IGV angles, high firing temperature, low BTU gas fuel composition, and high combustor diluent injection can cause the compressor pressure ratio to approach design limits. Software has been developed to control the amount of compressor bleed to limit the pressure ratio. Inlet bleed heat for compressor operating limit protection features a compressor operating limit map built into the Speedtronic software as a protective control reference. The compressor pressure ratio (CPR) is calculated from inlet and discharge pressure transducers measurements and used as a feedback signal for closed loop control. The amount of inlet bleed heat is regulated by proportional plus integral control action using the protective reference and the pressure ratio measurement feedback. A maximum of 5% compressor discharge flow is extracted to limit the pressure ratio. A secondary method of compressor operating limit protection features IGV temperature control suppression. Again, using closed loop proportional plus integral control action, the IGV temperature control curve is suppressed, causing the IGVs to open. This opening of the IGVs will increase the compressor operating limit. All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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The gas turbine fuel control (FSRCPR) is used as a back up to compressor bleed for limiting the compressor pressure ratio. This backup fuel control may be encountered during fast load transients or in the event of an inlet bleed heat system fault. Compressor Pressure Ratio, CPR Max Allow Error CPRLIM, FSR Backup FSR Deadband F

IBH Control Ref

E

Min BH Enable

CPRERR negative CPRERR positive

B A

C

Min BH Deadband

D CPR (Typical Unit Loading)

A B C D E F

CPKERRMX CPKERRO CSKRPREN CSKRPRDB CPKFSRDB CPKFSRO

Corrected Speed, TNHCOR

06.14.04 INLET BLEED HEAT CONTROL FAULT DETECTION

The inlet bleed heat system design contains fault detection instrumentation and software that is aimed at identifying possible errors in the operation of the system. The general failure modes that are tracked with the inlet bleed heat system fault detection scheme are: Control Valve (VA20-1) Manual Isolation (VM15-1) (Valve Positioning Errors) Pressure Transducer (96BH-1/2) (Measurement Error) The IBH system is failed open when the compressor needs to be protected due to sensor

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failures. This occurs when all knowledge of compressor inlet temperature (CTIM) has been lost; all physical CTIM measurements are unavailable and the corresponding sensor model is invalid or not present. It also occurs when ambient pressure (AFPAP) cannot be accurately measured. The output signal initiating this protective action is L3BHSENS_F. The IBH DLN turndown schedule is disabled when there is no way to determine the IBH flow (CQBH), which is used as feedback for the control loop. This occurs when the downstream IBH pressure transmitter (CPBH2) is failed and the CQBH model is not valid. The output signal initiating this protective action is L3BHTSENS_F.

06.14.05 INLET BLEED HEAT CONTROL VALVE

The standard VA20-1 valve selected to control the inlet bleed heat flow is a Fisher globe style valve with a machined cage trim (per GE specification/ordering drawing 356A4778). The 356A4328 functional specification, documents the design requirements for the VA20-1 control valve. The VA20-1 valves specified have an approximately linear flow characteristic versus stroke. This valve experiences a high pressure drop and is a potential source of excessive ambient noise, pipe vibration, and inlet bleed heat flow dynamic pressure fluctuations. The valve currently used for VA20-1 on new unit production (per 356A4778) features a multi-stage cage designed to minimize dynamic pressure disturbances and to limit noise generation. Expected valve noise should be below 85.0 dBA with the application of acoustic insulation on the valve (per GE specification 355A7453). A multi-stage control valve also reduces the risk of shock waves residing in the inlet bleed heat downstream piping or inlet distribution manifold. A 4-20 mA pneumatic actuator (65EP-3) is utilized to control the VA20-1 valve position. A VA20-1 position feedback signal, generated from a 4-20 mA transducer, is used by the control valve position fault detection software. The actuator also may include a mechanical position limit stop used to set 100% position command to the proper stroke in terms of inches of travel. The VA20-1 mechanical travel stop setting is defined to the valve supplier in the specification to be set at the factory. The VA20-1 control valve also features a trip solenoid valve (20TH-1) used to exhaust air from the actuator and move the VA20-1 control valve to its fail safe position. The 20TH-1 trip solenoid valve is controlled by software that is designed to detect positioning faults and irregular VA20-1 operation. This trip solenoid is typically a 125 VDC type, requiring power to operate the VA20-1 control valve. For MS6001FA, MS7001FA, and MS9001FA applications the VA20-1 valve is designed to be All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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a normally open control valve. On loss of pneumatic air supply, loss of the 4-20 mA command signal, or on loss of the 20TH-1 dc voltage signal the VA20-1 control valve on these applications is defaulted to the open position by a fail-safe spring contained in the actuator design. This fail safe open mode was chosen for FA gas turbine applications because the inlet bleed heat system is used for compressor operating limit protection and bleeding the compressor. Actuation air is required to close the VA20-1 valve for FA units during gas turbine startup sequencing.

06.14.07 INLET BLEED HEAT MASS FLOW CALCULATION

Mass flow through the inlet bleed heat system is estimated using the ANSI/ISA standard control valve flow equation programmed in the Speedtronic software and applied to the VA20-1 Inlet Bleed Heat Control Valve. The 96BH-1/2 pressure transducers measure the VA20-1 control valve inlet pressure and pressure drop. The compressor discharge temperature signal (CTD) is used as the inlet bleed heat air flow temperature. These parameters are used along with the valve Cv vs. stroke characteristic from the manufacturer, to calculate mass flow.

06.14.08 INLET BLEED HEAT CONTROL VALVE COMMAND OUTPUT

The inlet bleed heat software selects as the VA20-1 control valve position command output (CSRIHOUT): the maximum of the Anti-Icing, the DLN Premix Turndown, and the Compressor Operating Limit independent inlet bleed heat command references. Also, the VA20-1 command output software allows manual control of the valve in a calibration mode and gives the valve a hard shut down below gas turbine operating speed.

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07.00.00 SECTION 7 - AUXILIARIES CONTROL

07.12.00 HRSG HIGH STEAM TEMPERATURE PROTECTION

High Steam Temperature Runback Load Control High temperature initiates a runback until the Gas Turbine Exhaust Temperature is less than a target value (TTKGT_RB). This will produce a runback from back rate from base load to no load of approximately 40 sec. The runback is provided by the GT Mark VIe controller upon receiving a maintained high temperature signal as sensed at the HRSG controller. The load control for the affected unit should be disabled during runback. IGV Control The minimum IGV Angle is set to 54 degrees to provide a lower exhaust gas temperature at a higher load than the normal 42 degrees or 48 degrees IGV Angles. Unload at 54 degrees is an accepted DLN2 combustion path. This is accomplished by turning off Inlet Bleed Heat Premix Mode Turndown, only when the actual IGV angle is above 54 degrees at the time of runback. The unit will unload with the IGV temperature control "ON", which means is will unload along the Combined Cycle path. This may cause the exhaust temperature to increase as unloading begins, hold steady along the isotherm, and then decrease once the IGVs reach their minimum. High-High Steam Temperature Trip Units without Diverter Dampers The High-High Temperature Trip provides protection on the event that the GT load runback is not successful in lowering the steam temperature. When a high-high temperature trip signal is generated by the HRSG controller, the Steam Turbine control valves are shut and the GT is reset to the FSNL position by setting the GT speed/load setpoint to 100.3%. This action provides the lowest GT exhaust gas

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temperature while keeping the Gas Turbine on-line. If this corrective action is successful, as sensed by the GT fuel valve stroke below 30% and the exhaust temperature below the alarm level (TTKGT_RB), the GT is taken off-line by opening the generator breaker. This precludes any fluctuations in load due to grid frequency variations. If either of those conditions is not met after ten seconds, then the GT shall be tripped. Unit with Diverter Dampers The High-High Temperature Trip provides a trip of the diverter damper which removes the GT exhaust gas from the HRSG while maintaining the GT in simple cycle operation. This allows the GT to provide power output while the HRSG Unit is protected. At this point, the Temperature Control Curve in the GT Mark VIe must be switched to the Simple Cycle values. If confirmation, in the DCS, that the diverter damper is closed is not received after a time delay, the GT shall be tripped to ensure the exhaust heat is removed. If the DCS is monitoring the damper position, the customer signal (L4CT) can be used to provide the trip. signal TTKGT_RB

value 1050

units °F

type REAL

definition EXHAUST GAS TEMPERATURE RUNBACK SETPOINT

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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08.00.00 SECTION 8 - UNIT PROTECTION

08.00.01 MASTER PROTECTIVE SEQUENCE

A test of the trip oil dump valves, confirming that the trip oil pressure drops as fast as expected, is performed automatically every shutdown or trip. A "Hydraulic protective trouble" alarm on shut down or trip indicates a defective trip oil system which should be resolved before restarting the turbine. Hydraulic trip oil pressure should decay below 63HG or 63HL setting within K4Y time (normally 1 sec). It is important not to alter this setting as the emergency shutdown system design of the unit may be compromised.

08.01.02 COMBUSTOR FLAME DETECTION

The flame detectors used on GE gas turbines output a 4-20 mA signal that is directly proportional to the detected flame intensity. The 4-20 mA signal is processed directly by the Mark VIe control system, which corresponds to percent intensity. A strong flame indication signal from the flame detectors should have an intensity of 50-75% or higher, and a frequency of 500 Hz or higher.

08.02.01 VIBRATION PROTECTION

The vibration protection scheme employed in Mark VIe is configured by constant settings depending upon the vibration sensor I/O assignments. There are twelve possible vibration sensor input channels (BB1 thru BB12). The standard MS9001FA vibration sensor assignments are: MS9001FA Vibration Transducer Assignments: ----------------------------------------BB1 - 39V-1A BB2 - 39V-1B BB3 - none All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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BB4 - 39V-2A BB5 - 39V-2B BB6 - none BB7 - 39V-4A BB8 - 39V-4B BB9 - 39V-5A BB10 - none BB11 - none BB12 - none The vibration sensors are organized into groups according to location. The grouping of sensor channels is defined by mask constants JK39U_g where the group number "g" varies from 1 to 4 and represents: 1 2 3 4

-

Gas Turbine Vibration Sensors Load Gear Vibration Sensors Generator or Driven Load Vibration Sensors Miscellaneous Vibration Sensors

The vibration trip logic treats each of the four groups above separately and independently. Utilization and Redundancy Masks The utilization mask constants JK39U_g are hexadecimal values that are used to indicate which vibration sensor channel is used for each of the four groups. The redundancy mask constants JK39R_g are hexadecimal values that are used to indicate which vibration channels are paired or adjacent sensors for each of the four groups. The value for these mask constants can be determined by mapping out the bits of the hexadecimal values against the twelve vibration sensor channels: (GAS TURBINE SENSOR GROUP) JK39U_1=D801, JK39R_1=D800 (HEX NUMBERS) BIT F E D C B A 9 8 7 6 5 4 3 2 1 O BBn: 1 2 3 4 5 6 7 8 9 10 11 12 -------------------------------------------------------------------39V-1A 1B 2A 2B -------------------------------------------------------------------U: 1 1 0 1 | 1 0 0 0 | 0 0 0 0 | 0 0 0 1 R: 1 1 0 1 | 1 0 0 0 | 0 0 0 0 | 0 0 0 0 --------------------^---------------^---------------^--------------(LOAD GEAR SENSOR GROUP) JK39U_2=0000, JK39R_2= 0000 39V-------------------------------------------------------------------U: 0 0 0 0 | 0 0 0 0 | 0 0 0 0 | 0 0 0 0 All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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R: 0 0 0 0 | 0 0 0 0 | 0 0 0 0 | 0 0 0 0 --------------------^---------------^---------------^--------------(DRIVEN LOAD SENSOR GROUP) JK39U_3=0381, JK39R_3=0300 39V4A 4B 5A -------------------------------------------------------------------U: 0 0 0 0 | 0 0 1 1 | 1 0 0 0 | 0 0 0 1 R: 0 0 0 0 | 0 0 1 1 | 0 0 0 0 | 0 0 0 0 --------------------^---------------^---------------^--------------(MISCELLANEOUS SENSOR GROUP) JK39U_4=0000, JK39R_4=0000 39V-------------------------------------------------------------------U: 0 0 0 0 | 0 0 0 0 | 0 0 0 0 | 0 0 0 0 R: 0 0 0 0 | 0 0 0 0 | 0 0 0 0 | 0 0 0 0 --------------------^---------------^---------------^--------------Redundant Sensors Processing The least significant bit of the utilization mask constant JK39U_g sets the group to be processed as non-redundant or redundant sensors. A "0" least significant bit for JK39U_g will indicate that the group is to be processed as non-redundant sensors and any sensor that indicates a vibration trip will cause the unit to trip. A "1" least significant bit for JK39U_g will indicate that the group is to be processed as redundant sensors such that a single transducer failure in a manner to indicate high vibration will not trip the unit. A unit high vibration trip will require an active sensor at trip level and another active sensor in the group to be above alarm level. The redundant sensor option is the standard configuration. If a majority of the sensors in a redundant group are disabled, a unit trip will occur on a high vibration trip indication from only one active sensor. Adjacent Sensors The least significant bit of the redundancy mask JK39R_g sets the group to be processed as adjacent sensors. A "1" least significant bit for JK39R_g will allow the turbine to be tripped when a sensor indicates a trip vibration level and an adjacent sensor is either disabled or at alarm level. This is an option that is not standardly used. Adjacent Sensor Differential Alarm The redundancy mask JK39R_g defines paired or adjacent sensor signals to be compared and alarmed if the differential exceeds a certain value. This alarm gives the All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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operator an indication of faulty vibration sensors. The adjacent sensor differential comparison is only performed on active sensors and is ignored for operator disabled sensors. Faulty Sensor Disabling Each sensor channel that is defined as being utilized by the JK39U_g mask is monitored for open circuit sensor faults. If a vibration sensor channel is determined to be faulty an alarm is annunciated to the operator. The operator can also manually disable a faulty vibration sensor channel so that an additional transducer fault will not trip the unit. If a vibration sensor reading has been ascertained JK39_n, where "n" is the BBn channel number from 1 0.0 to disable that channel. A disabled vibration displayed but the alarm and trip level indications trouble alarm will be inhibited for that sensor.

to be faulty, control constant to 12, can be set to a value of sensor channel output can be as well as the vibration detector

Startup Permissive and Shutdown Logic If all sensors in a group are disabled or identified as faulted, the turbine is automatically given a normal shutdown command. If a majority of sensors in a group are disabled or identified as faulted, the turbine is inhibited from starting.

08.02.011 VIBRATION PROTECTION - CHECKOUT

Vibration Sensor Cable Shield Test Check each vibration sensor cable shield, using an ohmmeter, to determine that it is continuous from the transducer to the control panel and connected to common only at the control panel end. Vibration Sensor Open Circuit Fault Test 1. In ToolboxST, search for the vibration transducer fault logic (L39VF). Determine which of the 12 vibration inputs are being used from the I/O Calibration List. 2. Cut the safety wire and disconnect the vibration sensor cable from the All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

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vibration transducer. Verify that L39VF_n becomes logic "1" and the "VIBRATION TRANSDUCER FAULT" alarm comes in. Reconnect the sensor and reset the alarms. 3. Repeat for all transducers 4. Safety wire the vibration sensors and cables after testing.

08.03.011 FIRE PROTECTION - CHECKOUT PROCEDURES

Prior to installation of nozzles, the entire piping system should be pressurized with compressed air and maintained with no leakage allowed for at least 10 minutes (This will also serve to clear the piping of any debris as previously described). Due to varying site conditions, differing locations of the off-base supply of CO2 to the turbine and potential leaks in the lagging and piping, a CO2 concentration test is required to ensure the integrity of the fire protection system design. A simple "Puff Test" is not satisfactory to ensure the system functions properly. In order to perform the concentration test, a qualified technician must be present to make sure the test is run correctly. This test involves running a full C02 concentration test consisting of both the initial and extended discharges for each zone of protection. The initial discharge runs for 1 minute (or less) following the release of CO2, while the extended discharge runs simultaneously, but continues for at least 30 minutes or more (depending upon the discharge times required). The vendor should be contacted in order to locate and schedule a technician to come to the particular site and oversee the concentration test. The initial discharge is designed for a minimum concentration of 34% within 60 seconds. The extended discharge is designed to maintain a minimum concentration of 30% for 30 minutes or more (depending on the required discharge times). Upon successful completion of the CO2 concentration test, GE Gas Turbine Engineering should be consulted and the results of the concentration test should be sent to the appropriate design engineer for documentation purposes.

08.04.00 HAZARDOUS GAS PROTECTION SYSTEM

The purpose of the Hazardous Gas Protection System is to signal (and take action if necessary) if the presence of a combustible gas mixture in the gas turbine and associated accessories reach a high level. The detector settings are based on the

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Lower Explosive Limit (LEL) of the combustible gas. There are two detector settings, a high and high-high % LEL setting for each compartment, which correspond to a gas pocket volume with a 50% LEL concentration exceeds 0.1% of the net enclosure volume and a gas pocket volume with a 100% LEL concentration exceeds 0.1% of the net enclosure volume. The settings take into account the amount of air through the compartment, airflow distribution through the compartment, detector location, and probability of leak. These settings are specific to that compartment and factory settings should not be adjusted in the field. Hazardous gas detectors are wired back to a gas monitor, separate from the control panel. The Gas Monitor then sends signals back to the control panel, either digital contact inputs or 4-20 mA signals based on the action required from the detector. Single detectors, usually located within the compartment, detect high and high-high LEL settings for alarm purposes only. The single detectors are wired back to the gas monitor and then ganged together by rack. If any one of the detectors signals high or high-high (L45HnL_ALM, L45HnH_ALM), the gas monitor should be consulted for which detector has signaled high LEL levels and the problem should be investigated. Some compartments have three detectors in the extract ducts of the ventilation system to measure high and high-high LEL settings. The Gas Monitor sends these analog LEL settings back to the control panel where voting is done. If any one of the three detectors measures high gas concentration, an alarm will be generated. If any two out of three detectors measures high-high gas concentration, a gas turbine trip will be initiated and the problem should be investigated. If any detector should fail in the compartments or extract ducts, the gas monitor performs internal diagnostics and will send an alarm, one for each rack, back to the control panel. If any alarm is generated, the problem should be investigated. The extract duct detectors, which are fed back to the control panel via 4-20 mA signals, also have a diagnostic check at the control panel to ensure that the 4-20 mA signals is within range. If any of these alarms are generated, the problem should be investigated.

All rights reserved. The information contained herein is GE Energy GAS Proprietary © COPYRIGHT 2014 GE ENERGY (USA), LLC AND/OR ITS AFFILIATES. Technical Information that belongs to the General Electric Company, GE Energy (USA), LLC and/or their affiliates, which has been provided solely for the express reason of restricted private use. All persons, firms, or corporations who receive such information shall be deemed by the act of their receiving the same to have agreed to make no duplication, or other disclosure, or use whatsoever for any, or all such information except as expressly authorized in writing by the General Electric Company,GE Energy (USA), LLC and/or its affiliates.

GE CLASS II (INTERNAL NON CRITICAL)

GE Energy DRAWN

212322980

DRAWN DATE

2014-03-25

GENERAL ELECTRIC COMPANY

SIZE

A

CAGE CODE

DWG NO

100A1046 SHEET

565 of 577

GE Proprietary Information - Class II (Internal) US EAR - NLR

DWG Number 100A1046

SIZE

A

DWG NO

Rev A

Released 5/22/2014

100A1046

Page 566 of 577

SH

566

REV

A

09.00.00 SECTION 9 - DRIVEN LOAD INTERFACE

09.01.00 AUTO SYNCHRONIZATION

When auto synch is selected, SC43SYNC goes to a 2 and L83AUTSYN picks up. During breaker synch, big block L60SYNC1 controls fuel flow. The speed load setpoint (TNR) is raised or lowered by L60TNMR/L. Auto voltage matching is accomplished by L60SYNR/L. The synchronizing 25 relay is energized when the protective module(