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Fire Protection for Gas Turbines

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June 1997 Revised September 1998 Page 1 of 48 FIRE PROTECTION FOR GAS TURBINE INSTALLATIONS Table of Contents Page 1.0 SCOPE ................................................................................................................................................... 3 2.0 RECOMMENDATIONS FOR LOSS PREVENTION .............................................................................. 3 2.1 Protection Against External Fires .................................................................................................... 3 2.1.1 Completely Enclosed Installations ........................................................................................ 3 2.1.2 Unenclosed Installations ....................................................................................................... 8 2.1.3 Partly Enclosed Installations ............................................................................................... 12 2.1.4 Additional Recommendations .............................................................................................. 13 2.1.5 Protection of the Generator ................................................................................................. 13 2.2 Inspection and Testing ................................................................................................................... 13 2.2.1 Total Flooding Carbon Dioxide Systems ............................................................................. 13 2.2.2 Total Flooding Clean Agent Systems .................................................................................. 14 2.2.3 Fine Water Spray (FWS) Systems ...................................................................................... 14 2.2.4 Excess Flow Check Valves ................................................................................................. 15 2.3 Prevention of Internal Fires and Explosions ................................................................................. 15 2.3.1 Protective Systems and Devices ........................................................................................ 15 3.0 GUIDELINES FOR INSTALLATION TO PREVENT FIRES ................................................................ 15 4.0 SUBSTANTIATION FOR RECOMMENDATIONS ................................................................................ 15 4.1 External Fires in Gas Turbine Installations ................................................................................... 15 4.1.1 Summary of Experience with External Fires ....................................................................... 15 4.1.2 Need for Protection of Generator Compartments ............................................................... 21 4.1.3 Water as an Extinguishing Agent in Gas Turbine Installations ........................................... 22 4.2 Internal Fires and Explosions in Gas Turbines ............................................................................. 25 4.2.1 Summary of Experience with Internal Fires and Explosions .............................................. 25 4.2.2 Case Histories of Internal Fires and Explosions ................................................................. 26 5.0 APPENDIX A ........................................................................................................................................ 31 5.1 Excess Flow Check Valves ........................................................................................................... 31 5.2 Excess Flow Shutoff Valves .......................................................................................................... 33 5.3 Pressure Type Emergency Shutoff Valves .................................................................................... 33 5.4 Arrangement of Excess Flow Check Valves in a Gas Turbine Lubrication System ..................... 33 5.5 System Design for Excess Flow Check Valves ............................................................................ 34 5.6 Reliability of Excess Flow Check Valves. ...................................................................................... 37 6.0 APPENDIX B ........................................................................................................................................ 37 6.1 Fine Water Spray (FWS) Systems ................................................................................................ 37 6.2 Description of Fine Water Spray Systems .................................................................................... 37 6.3 Requirements of a Fine Water Spray (FWS) System ................................................................... 38 6.4 Hazard of Direct Impingement of Water Spray on a Hot Casing ................................................. 38 7.0 APPENDIX C ........................................................................................................................................ 41 7.1 Reignition in Gas Turbines after Flameout .................................................................................... 41 7.1.1 Autoignition Delay Time ...................................................................................................... 41 7.1.2 Cutoff of Fuel after Flameout .............................................................................................. 41 8.0 APPENDIX D ........................................................................................................................................ 43 8.1 Less Flammable Lubricants and Hydraulic Fluids ........................................................................ 43 9.0 APPENDIX E ........................................................................................................................................ 44 9.1 Clean Extinguishing Agents ........................................................................................................... 44 9.1.1 Inert Gas Clean Agents ....................................................................................................... 44 9.1.2 Halocarbon Clean Agents ................................................................................................... 45 Factory Mutual Property Loss Prevention Data Sheets 7-79 ©1997 Factory Mutual Engineering Corp. All rights reserved. No part of this document may be reproduced, stored in a retrieval system, or transmitted, in whole or in part, in any form or by any means, electronic, mechanical, photocopying, recording, or otherwise, without written permission of Factory Mutual Engineering Corp.
Transcript
Page 1: Fire Protection for Gas Turbines

June 1997Revised September 1998

Page 1 of 48

FIRE PROTECTION FOR GAS TURBINE INSTALLATIONS

Table of ContentsPage

1.0 SCOPE ................................................................................................................................................... 32.0 RECOMMENDATIONS FOR LOSS PREVENTION .............................................................................. 3

2.1 Protection Against External Fires .................................................................................................... 32.1.1 Completely Enclosed Installations ........................................................................................ 32.1.2 Unenclosed Installations ....................................................................................................... 82.1.3 Partly Enclosed Installations ............................................................................................... 122.1.4 Additional Recommendations .............................................................................................. 132.1.5 Protection of the Generator ................................................................................................. 13

2.2 Inspection and Testing ................................................................................................................... 132.2.1 Total Flooding Carbon Dioxide Systems ............................................................................. 132.2.2 Total Flooding Clean Agent Systems .................................................................................. 142.2.3 Fine Water Spray (FWS) Systems ...................................................................................... 142.2.4 Excess Flow Check Valves ................................................................................................. 15

2.3 Prevention of Internal Fires and Explosions ................................................................................. 152.3.1 Protective Systems and Devices ........................................................................................ 15

3.0 GUIDELINES FOR INSTALLATION TO PREVENT FIRES ................................................................ 154.0 SUBSTANTIATION FOR RECOMMENDATIONS ................................................................................ 15

4.1 External Fires in Gas Turbine Installations ................................................................................... 154.1.1 Summary of Experience with External Fires ....................................................................... 154.1.2 Need for Protection of Generator Compartments ............................................................... 214.1.3 Water as an Extinguishing Agent in Gas Turbine Installations ........................................... 22

4.2 Internal Fires and Explosions in Gas Turbines ............................................................................. 254.2.1 Summary of Experience with Internal Fires and Explosions .............................................. 254.2.2 Case Histories of Internal Fires and Explosions ................................................................. 26

5.0 APPENDIX A ........................................................................................................................................ 315.1 Excess Flow Check Valves ........................................................................................................... 315.2 Excess Flow Shutoff Valves .......................................................................................................... 335.3 Pressure Type Emergency Shutoff Valves .................................................................................... 335.4 Arrangement of Excess Flow Check Valves in a Gas Turbine Lubrication System ..................... 335.5 System Design for Excess Flow Check Valves ............................................................................ 345.6 Reliability of Excess Flow Check Valves. ...................................................................................... 37

6.0 APPENDIX B ........................................................................................................................................ 376.1 Fine Water Spray (FWS) Systems ................................................................................................ 376.2 Description of Fine Water Spray Systems .................................................................................... 376.3 Requirements of a Fine Water Spray (FWS) System ................................................................... 386.4 Hazard of Direct Impingement of Water Spray on a Hot Casing ................................................. 38

7.0 APPENDIX C ........................................................................................................................................ 417.1 Reignition in Gas Turbines after Flameout .................................................................................... 41

7.1.1 Autoignition Delay Time ...................................................................................................... 417.1.2 Cutoff of Fuel after Flameout .............................................................................................. 41

8.0 APPENDIX D ........................................................................................................................................ 438.1 Less Flammable Lubricants and Hydraulic Fluids ........................................................................ 43

9.0 APPENDIX E ........................................................................................................................................ 449.1 Clean Extinguishing Agents ........................................................................................................... 44

9.1.1 Inert Gas Clean Agents ....................................................................................................... 449.1.2 Halocarbon Clean Agents ................................................................................................... 45

Factory MutualProperty Loss Prevention Data Sheets 7-79

©1997 Factory Mutual Engineering Corp. All rights reserved. No part of this document may be reproduced, stored in a retrieval system,or transmitted, in whole or in part, in any form or by any means, electronic, mechanical, photocopying, recording, or otherwise, without writtenpermission of Factory Mutual Engineering Corp.

Page 2: Fire Protection for Gas Turbines

10.0 GLOSSARY ........................................................................................................................................ 4610.1 Glossary of Terms ........................................................................................................................ 46

11.0 REFERENCES .................................................................................................................................... 4711.1 Specific References ..................................................................................................................... 4711.2 Related Data Sheets .................................................................................................................... 47

List of FiguresFig. 1. Gas turbine test facility fire. ............................................................................................................. 18Fig. 2. View into load tunnel showing separated lube oil lines. .................................................................. 19Fig. 3. External damage to test facility. ...................................................................................................... 20Fig. 4. Damage to interior of building in northwest corner. ........................................................................ 21Fig. 5. Oil spray in AEC spray fire test, just prior to ignition. ..................................................................... 23Fig. 6. Apparatus used in spray fire tests at the Technical Research Centre of Finland,

showing the arrangement of the oil spray. ...................................................................................... 24Fig. 7. Damage to turbine rotor blades as a result of an internal fire. ....................................................... 27Fig. 8. Damage to turbine stationary nozzle vanes as a result of an internal fire. .................................... 28Fig. 9. Gaseous fuel valves. ....................................................................................................................... 29Fig. 10. Combustor damage due to pool fire in combustor casing. (a) Arrangement of combustor

baskets, looking rearward. (b) Burned combustor baskets. .......................................................... 30Fig. 11. An excess flow check valve in a fuel, hydraulic or lube oil line. (MGM) ...................................... 32Fig. 12. Magnetic excess flow check valve. (CTE Chem-Tec) ................................................................... 32Fig. 13. Excess flow shutoff valve. (Maxitrol) ............................................................................................. 34Fig. 14. Pressure type emergency shutoff valve. (Maxitrol) ....................................................................... 35Fig. 15. Arrangement of excess flow check valves in a gas turbine lubrication system. .......................... 36Fig. 16. Layout of fire detectors, piping, and nozzles in an FWS system. ................................................ 38Fig. 17. Arrangement of water reservoir and air cylinder for FWS system. (Securiplex) .......................... 39Fig. 18. Typical nozzle for a Fine Water Spray (FWS) system. ................................................................. 40Fig. 19. Variation of hot-casing deflection with impinging droplet size. ..................................................... 40Fig. 20. Effects of temperature and pressure on minimum autoignition delay time of No. 2 fuel oil. ....... 42Fig. 21. Flame detector and amplifier. (Honeywell) .................................................................................... 43

List of TablesTable 1. Fire Protection for Gas Turbine Installations ................................................................................... 4Table 2. Summary of External Fire Losses in Gas Turbine Installations (Numbers of Losses) ................. 16Table 3. Gross Property Damage Costs of External Fire Losses in Gas Turbine Installations .................. 16Table 4. Numbers of Fires Involving Lube or Fuel Oil, and Gaseous Fuel by Type of Protection ............. 16Table 5. Gross Property Damage Costs of Fires Involving Lube or Fuel Oil, and Gaseous Fuel by

Type of Protection ......................................................................................................................... 16Table 6. Summary of External Fire Losses in Gas Turbine Installations by Number of Losses (FM) ........ 17Table 7. Gross Property Damage Costs of External Fire Losses in Gas Turbine Installations (FM) ......... 17Table 8. Numbers of Fires Involving Lube or Fuel Oil, and Gaseous Fuel, by Type of Protection (FM) ... 17Table 9. Gross Property Damage Costs of Fires Involving Lube or Fuel Oil, and Gaseous Fuel,

by Type of Protection (FM) ............................................................................................................ 17Table 10. Internal Fires and Explosions ..................................................................................................... 26Table 11. Internal Fires and Explosions (FM) .............................................................................................. 26Table 12. Makeup of Atmospheres Produced by Inerting Agents in Extinguishment Concentrations ........ 44Table 13. Halocarbon Clean Extinguishing Agents12 ................................................................................... 45

7-79 Fire Protection for Gas Turbine InstallationsPage 2 Factory Mutual Property Loss Prevention Data Sheets

©1997 Factory Mutual Engineering Corp. All rights reserved.

Page 3: Fire Protection for Gas Turbines

1.0 SCOPE

This data sheet addresses fire protection for:

• gas turbine installations and (alternating-current) a. c. generators.

• external fires involving lubricating, control oil, and liquid or gaseous fuel.

• internal fires and explosions in gas turbines (see also Data Sheet 13-17).

A glossary of certain specialized terms is provided in Section 10.0.

2.0 RECOMMENDATIONS FOR LOSS PREVENTION

2.1 Protection Against External Fires

This section divides installations into three types:

1. Completely enclosed installations, including skid-mounted package installations.

2. Installations in a large building without individual enclosures other than a ‘‘lagging’’ around the combus-tor and turbine section for personnel protection.

3. Partially-enclosed installations having lube oil, fuel and hydraulic skids external to the package.

Table 1 summarizes the protection recommendations for the first two of the above categories; protectionfor the third is a suitable combination of these. The subsequent sections describe the recommendations inmore detail and introduce additional specific recommendations.

2.1.1 Completely Enclosed Installations

The areas to be protected are the:

• gas turbine compartment

• load tunnel

• accessory compartment.

See Section 2.1.5 for a discussion of protection for the generator compartment.

Completely enclosed installations often have integral control, switchgear and motor control rooms. Theseshould be protected as described in Data Sheet 5-32, Electronic Data Processing Systems.

Completely enclosed package installations may be protected by one of the following systems:

• Complete system of excess flow check valves.

• Gaseous total flooding system.

• Fine water spray (FWS) system.

• FM-Approved less flammable lubricants and hydraulic fluids (see Section 8.0).

The following sections present complete and sufficient sets of recommendations for these systems. Gen-eral recommendations common to all installations are in Section 2.14.

2.1.1.1 Excess Flow Check Valve Systems

1. Install an FM-Approved excess flow check valve in the pressure line just downstream of the main lubeoil pump. The minimum closing flow should be 10% greater than the maximum flow the pump can deliver tothe lubrication system at the installed setting of the pressure regulator. Install the valve between the pumpand the isolation check valve for the auxiliary and emergency pump systems, so that the systems can startin case the excess flow valve accidentally closes.

If the main lube oil pump is a constant displacement type, an excess flow check valve will not function regard-less of the drop in line pressure after a break or major leak. In such a case, an FM-Approved low-pressure shutoff valve should be used instead. This valve should be set to close at a value lower than theline pressure that could result from a major leak (such as from a fracture of bearing branch line) down-stream of the pressure regulator.

Fire Protection for Gas Turbine Installations 7-79Factory Mutual Property Loss Prevention Data Sheets Page 3

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Page 4: Fire Protection for Gas Turbines

Section 5.0 (Appendix A) describes excess flow check valves and low pressure shutoff valves, and dis-cusses the issues involved in their selection and sizing.

Table 1. Fire Protection for Gas Turbine Installations

Completely EnclosedInstallations

UnenclosedInstallations

Area Protection Gas turbine compartment. Excess flow check valvesthroughout lubrication, fuel,and hydraulic systems,

ORTotal flooding gaseous system,

ORApproved fine water spraysystem,

ORLess flammable lube oils andhydraulic fluids, plus excessflow check valves in fuelsystem.

Excess flow check valvesthroughout lubrication, fuel,and hydraulic systems.

ORLess flammable lube oils andhydraulic fluids, plus excessflow check valves in fuelsystem.

Load tunnel betweenexhaust duct andgenerator compartment.

If the lube oil and hydraulic sys-tems cannot be protected byexcess flow check valves, theturbine building should beprotected as follows:1. Fireproofing on mainstructural members in turbinebuilding,

OR2. Fixed water spray nozzlesto protect the main structuralmembers.

Accessory compartment.

Local Protection Under gas turbine. No recommendations beyondarea protection specifiedabove.

Attended locations:Portable CO2 foam or drychemical extinguishers.Unattended locations:Fixed CO2 foam or dry chemicalextinguishing system.

Bearings. No recommendations beyondarea protection specifiedabove.

Lube system, if separate fromturbine enclosure or building.

No recommendations beyondarea protection specifiedabove.

Excess flow check valve,OR

Pressure-type emergency shut-off valve at main lube pumpdischarge, and in each branchline of main lube oil header.Excess flow check valves atlube oil filters and at coolers.

Fuel systems. When using less flammablefluids, use excess flow checkvalves in fuel system.

Excess flow check valveOR

Pressure-type emergency shut-off valve downstream of fuelpump.

Fuel systems (pigtails atcombustors).

When using less flammablefluids, use excess flow checkvalves in fuel system.

Excess flow check valve ineach pigtail.

Hydraulic systems. No recommendations beyondarea protection specifiedabove.

Excess flow check valvesdownstream of pumps, and inbranch lines.

7-79 Fire Protection for Gas Turbine InstallationsPage 4 Factory Mutual Property Loss Prevention Data Sheets

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Page 5: Fire Protection for Gas Turbines

2. In addition to the above, install FM-Approved excess flow check valves throughout the lubrication sys-tem as described in Section 5.0 (Appendix A).

Install thermocouples in the pads of each sliding friction thrust and journal bearing, set to alarm or trip theunit as follows:

Alarm: 210-220°F(98-104°C)

Trip: 240-250°F(115-121°C)

This recommendation exists in Data Sheet 13-17, Gas Turbines, for thrust bearings only. The recom-mended thermocouples are designed to trip the turbine as rapidly as possible in case an excess flow valvecloses for any reason. This minimizes bearing damage.

3. Install FM-Approved excess flow check valves in the main gaseous and liquid fuel lines leading to thefuel manifolds on the gas turbine. The valves should be installed in the fuel pump discharge, and sized sothat the minimum closing flow is 10% greater than the maximum flow the pump can deliver in the fuel pip-ing system with the fuel pressure regulator wide open.

If a liquid fuel pump is a constant displacement type, an FM-Approved low pressure shutoff valve shouldbe used instead of an excess flow check valve.

4. Install an FM-Approved excess flow check valve in each pigtail from the fuel manifold to a fuel nozzleat the connection to the manifold. The minimum closing flow should be 10% greater than the maximum flowin the pigtail at maximum pump discharge pressure. Supply sufficient gas turbine compartment cooling tomaintain the temperature of the valve below the approval rating.

Do not use excess flow check valves in combustor pigtails unless a blade path spread monitoring system,as described in Data Sheet 13-17, Gas Turbines, is installed in the gas turbine exhaust to alarm at an inter-mediate value of spread, and to trip the unit at a dangerous level. Such a system monitors the variabilityof gas temperature around the exhaust flowpath continuously, and produces an alarm and trip at specified val-ues of the spread. The accidental closure of a pigtail excess flow valve, which will shut off the fuel to its com-bustor fuel nozzle and increase the spread, can be detected in this manner.

5. Install an FM-Approved excess flow check valve at the hydraulic pump discharge, and in any branch linejust downstream of the junction, in each hydraulic system (starting, variable compressor stators, variable tur-bine nozzles, compressor bleed). The valves should have minimum closing flows 10% higher than the maxi-mum flow in the line at maximum pump discharge pressure. Lines subjected to surges of pressure should beprovided with accumulators to control rates of flow change

6. If the driven generator is hydrogen cooled, use excess flow check valves to protect the hydrogen seal-oil system.

7. Install FM-Approved fire detectors in the roof of the gas turbine enclosure in accordance with Data Sheet5-48, Automatic Fire Detectors, to detect a fire from a small leak in the lubricating, hydraulic or fuel system,that would not be sufficient to actuate the corresponding excess flow check valve. These detectors shouldannunciate an alarm in the control room, and should trip the gas turbine off line, shutting off the fuel sys-tem instantly. The lubrication system should be shut off either instantly or after a specified delay deter-mined from a fire risk evaluation.

If heat detectors are used, they should be the temperature compensated, rate-of-rise type. The tempera-ture rating of the detector should be based upon the maximum operating temperature expected within thecompartment. A common rating in the gas turbine, accessory, and generator compartments is 375°F (190°C).However, load compartments operate hot, and a temperature rating of up to 600°F (316°C) may be required.

The purpose of this recommendation is to respond to spray fires from leaks that are too small to actuatethe excess flow check valves because of the necessary tolerances on closing flow. A fire risk evaluation maydetermine the lubrication system, in the event of a lube oil fire, should be shut off as rapidly as possible.This involves the risk of damage to bearings while the unit is coasting down and going on turning gear. Con-versely, the fire-risk evaluation might determine that a delay of up to ten minutes, before shutting off the lubri-cation system, is permissible.1

Fire Protection for Gas Turbine Installations 7-79Factory Mutual Property Loss Prevention Data Sheets Page 5

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Page 6: Fire Protection for Gas Turbines

• Bearing damage is minimized, since lubrication is shut off after the rotor has decelerated.

• A spray fire originating at the opening in the lubricating or hydraulic system may enlarge the opening rapidly,and the appropriate excess flow check valve will then respond and shut off oil flow with minimum dam-age to the bearings.

• The operator has time to distinguish between a fuel fire (which would be extinguished as soon as the fuelis shut off) and a lube- or hydraulic-oil fire, and, in the case of a fuel fire, maintain lubrication to the bearings.

8. Provide curbs for the gas turbine installation (including fuel and lube oil skids) to contain any slow leaks,or leaks that are not sufficient to actuate the excess flow valves. Provide drains to remove the spilled lubeoil or liquid fuel to a safe disposal location or a catch basin, and slope the floor around the installation towardthe drains. (See Data Sheet 7-83, Drainage Systems for Flammable Liquids, for drainage details).

The quantity of flammable liquid to be handled by the drainage system is one-half the capacity of the lubeoil reservoir.

9. If a space exists beneath the gas turbine in which lube oil or liquid fuel can accumulate, installFM-Approved fire detectors on both sides of the turbine to respond to a spill or pool fire. If the turbine has insu-lating blankets over its hot section, install approved fire detectors above the turbine to respond to a fire inthe blankets should they become soaked by leaking lube oil, liquid fuel, or hydraulic fluid, and then ignited bycontact with the hot turbine casing.

10. In an attended location, store portable dry chemical and/or foam extinguishers adjacent to the gas tur-bine housing for extinguishing spill and soaked blanket fires.

11. In an unattended location, install a fixed dry chemical or foam extinguishing system to protect the areaunder the turbine, as well as blanketed areas where a soaked blanket fire could occur. This system shouldbe activated by the fire detectors of Recommendation 9.

2.1.1.2 Gaseous Total Flooding Systems

A completely enclosed installation may be protected by an FM-Approved gaseous total flooding system.

FM-Approved systems are:

• Clean agent systems (inerting and halocarbon)

• CO2 systems

• Halon systems (only where currently in place)

1. Install an FM-Approved clean agent fire extinguishing system in accordance with the FM Approval Stan-dards, the manufacturer’s instructions, and NFPA 2001, Clean Agent Fire Extinguishing Systems2. Suffi-cient agent should be provided to produce an extinguishing concentration in one minute. An extendeddischarge should then add agent gradually to compensate for any leakage from the compartment and main-tain an inerting concentration for as long as necessary to prevent reignition of a fire. A minimum time of 20minutes, or the time determined by the gas turbine manufacturer, whichever is greater, should be used forthe gas turbine and load tunnel. For the other compartments, the minimum time should be 10 minutes.

After installing the total flooding clean agent system, perform a concentration (fan) test to assure the enclo-sure maintains the specified inerting concentration for the established hold time.

2. Install a carbon dioxide extinguishing system in accordance with Data Sheet 4-11N, Carbon Dioxide Extin-guishing Systems. Sufficient carbon dioxide should be provided to produce a gaseous concentration of 34%by volume in one minute. An extended discharge should then add carbon dioxide gradually to compen-sate for any leakage from the compartment and maintain a concentration of 30% for as long as necessaryto prevent reignition of a fire. A minimum time of 20 minutes, or the time determined by the gas turbine manu-facturer, whichever is greater, should be used for the gas turbine and load tunnel. For the other compart-ments, the minimum time should be 10 minutes.

After installing the total flooding carbon dioxide system, perform a concentration (fan) test to assure the enclo-sure maintains the desired concentration of 30% for the established hold time.

3. If a Halon 1301 or Halon 1211 extinguishing system is installed, the installations should be in accor-dance with NFPA 12A Halon 1301 Extinguishing Systems3 or NFPA 12B Halon 1211 Extinguishing Systems4.

7-79 Fire Protection for Gas Turbine InstallationsPage 6 Factory Mutual Property Loss Prevention Data Sheets

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Page 7: Fire Protection for Gas Turbines

4. The fire extinguishing system should be actuated automatically by FM-Approved fire detectors, installedin the roof of the enclosure in accordance with Data Sheet 5-48, Automatic Fire Detectors.

If heat detectors are used, they should be temperature compensated, rate-of-rise detectors. The tempera-ture rating of the detector should be based upon the maximum operating temperature expected within thecompartment. A common rating in the gas turbine, accessory, and generator compartments is 375°F (190°C).However, load compartments operate hot, and a temperature rating of up to 600°F (316°C) may be required.The heat detectors should actuate a relay that will activate the fire protection system and trip the gas turbine.

5. If a space exists beneath the gas turbine in which lube oil or liquid fuel can accumulate, install addi-tional fire detectors on both sides of the turbine to respond to a pool fire.

6. Provide the gas turbine installation (including fuel and lube oil skids) with curbs to contain any leaks oflube oil, hydraulic fluid or liquid fuel. Either drains should be provided to remove the spilled liquid to a safe dis-posal location or a catch basin and the floor around the installation should slope toward the drains. (SeeData Sheet 7-83, Drainage Systems for Flammable Liquids, for drainage details).

The total quantity of fluid to be handled by the drainage system is one-half the capacity of the lube oil reservoir.

7. Provide remote or accessible means to actuate the fire extinguishing system manually.

8. The actuation relay should activate interlocks that will shut off the compartment ventilation system andclose the ventilation dampers. If doors to a compartment can be held open by some device, they also shouldhave automatic-release mechanisms that will allow them to be closed by activating of the interlocks.

9. Provide automatic closers for the doors to the various compartments. The doors should never be blockedopen while the turbine is in operation or on turning gear.

2.1.1.3 Fine Water Spray Systems

1. An FM-Approved fine water spray (FWS) system may be used in lieu of a gaseous total flooding sys-tem. The system must be approved for the size of enclosure involved, and it must have the capacity to main-tain fire extinguishment for the periods described in Recommendation 2. The fine water spray system mustbe installed in accordance with the manufacturer’s authorized installation procedures.

2. The fine water spray system should have the capacity to provide 20 minutes of protection for gas turbineenclosures, and 10 minutes of protection for auxiliary rooms containing oil pumps, oil tanks, oil filters and cool-ers, fuel pumps and filters, hydraulic gear, and similar equipment. This requirement may be met by cyclingspray discharge for a specified number of seconds on, followed by a specified number of seconds off.

3. The fire extinguishing system should be actuated automatically by FM-Approved fire detectors, installedin the roof of the enclosure in accordance with Data Sheet 5-48, Automatic Fire Detectors.

If heat detectors are used, they should be temperature compensated, rate-of-rise detectors. The tempera-ture rating of the detector should be based upon the maximum operating temperature expected within thecompartment. A common rating in the gas turbine, accessory, and generator compartments is 375°F (190°C).However, load compartments operate hot, and a temperature rating of up to 600°F (316°C) may be required.The heat detectors should actuate a relay that will activate the fire protection system and trip the gas turbine.

4. If a space exists beneath the gas turbine in which lube oil or liquid fuel can accumulate, install addi-tional fire detectors on both sides of the turbine to respond to a pool fire.

5. Provide curbs for the gas turbine installation (including fuel and lube oil skids) to contain any slow leaks.Provide drains to remove the spilled lube oil or liquid fuel to a safe disposal location or a catch basin. Slopethe floor around the installation toward the drains. Size the drain system to remove the total fluid flow in theevent of system actuation. (See Data Sheet 7-83, Drainage Systems for Flammable Liquids, for drainagedetails).

The flow to be handled by the drainage system is the maximum discharge rate from the FWS tank, plus25 gpm (1.58 l/s) flow of flammable fluid. The latter value is selected as the most likely maximum flow ratein a gas turbine installation.

The total quantity of fluid to be handled by the drainage system is the capacity of the FWS tank, plus one-half the capacity of the lube oil reservoir.

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6. Provide remote or accessible means to actuate the fire extinguishing system manually.

7. The actuation relay should activate interlocks that will shut off the compartment ventilation system andclose the ventilation dampers. If doors to a compartment can be held open by some device, they also shouldhave automatic-release mechanisms that will allow them to be closed by activating of the interlocks.

8. Provide automatic closers for the doors to the various compartments. The doors should never be blockedopen while the turbine is in operation or on turning gear.

2.1.1.4 Less Flammable Lubricants and Hydraulic Fluids

If less flammable, FM-Approved lubricants and hydraulic fluids are used, the requirements for fire preven-tion and protection of lubrication and hydraulic systems may be waived. The criterion for approval of these flu-ids is described in Appendix D. Fire protection is still recommended for fuel systems as follows:

1. Install FM-Approved excess flow check valves in the main gaseous and liquid fuel lines leading to thefuel manifolds on the gas turbine. The valves should be installed in the fuel pump discharge and be sizedso that the minimum closing flow is 10% greater than the maximum flow the pump can deliver in the fuel pip-ing system with the fuel pressure regulator wide open.

If a liquid fuel pump is a constant displacement type, an FM-Approved, low pressure shutoff valve shouldbe used instead of an excess flow check valve.

2. Install an FM-Approved excess flow check valve in each pigtail from the fuel manifold to a fuel nozzleat the connection to the manifold. The minimum closing flow should be 10% greater than the maximum flowin the pigtail at maximum pump discharge pressure. Supply sufficient gas turbine compartment cooling tomaintain the temperature of the valve below the approval rating.

Do not use excess flow check valves in combustor pigtails unless a blade path spread monitoring system,as described in Data Sheet 13-17, Gas Turbines, is installed in the gas turbine exhaust to alarm at an inter-mediate value of spread, and to trip the unit at a dangerous level. Such a system monitors the variabilityof gas temperature around the exhaust flowpath continuously, and produces an alarm and trip at specified val-ues of the spread. The accidental closure of a pigtail excess flow valve, which will shut off the fuel to its com-bustor fuel nozzle and increase the spread, can be detected in this manner.

3. Provide curbs for the gas turbine installation (including fuel and lube oil skids) to contain any slow leaks,or leaks that are not sufficient to actuate the excess flow valves. Provide drains to remove the spilled lubeoil or liquid fuel to a safe disposal location or a catch basin, and slope the floor around the installation towardthe drains. (See Data Sheet 7-83, Drainage Systems for Flammable Liquids, for drainage details).

The quantity of flammable liquid to be handled by the drainage system is one-half the capacity of the lubeoil reservoir.

4. If a space exists beneath the gas turbine in which lube oil or liquid fuel can accumulate, installFM-Approved fire detectors on either side of the turbine to respond to a spill or pool fire. If the turbine has insu-lating blankets over its hot section, install approved fire detectors above the turbine to respond to a fire inthe blankets should they become soaked by leaking liquid fuel, and then ignited by contact with the hot tur-bine casing.

5. In an attended location, store portable dry chemical and/or foam extinguishers adjacent to the gas tur-bine housing for extinguishing spill and soaked blanket fires.

6. In an unattended location, install a fixed dry chemical or foam extinguishing system to protect the areaunder the turbine, as well as blanketed areas where a soaked blanket fire could occur. This system shouldbe activated by the fire detectors of Recommendation 4 above.

2.1.2 Unenclosed Installations

Unenclosed installations may be protected by one of the following systems:

• Complete system of excess flow check valves

• FM-Approved fire-resistant lubricants

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• A structural steel protection system for the turbine hall, if a system of excess flow check valves is notfeasible.

The following sections present complete and sufficient sets of recommendations for these systems. Gen-eral recommendations common to all installations are in Section 2.1.4.

2.1.2.1 Excess Flow Check Valve Systems

1. Install an FM-Approved excess flow check valve in the pressure line just downstream of the main lubeoil pump. The minimum closing flow should be 10% greater than the maximum flow the pump can deliver tothe lubrication system at the design setting of the pressure regulator. Install the valve between the pumpand the isolation check valve for the auxiliary and emergency pump systems so that the systems can startin case the excess flow valve closes accidentally.

If the main lube oil pump is a constant displacement type, an excess flow check valve will not function regard-less of the drop in line pressure after a break or major leak. In such a case, an FM-Approved low-pressure shutoff valve should be used instead. This valve should be set to close at a value lower than theline pressure that could result from a major leak (such as from a fracture of bearing branch line) down-stream of the pressure regulator.

Section 5.0 (Appendix A) describes excess flow check valves and low-pressure shutoff valves, and dis-cusses the issues involved in their selection and sizing.

2. In addition to the above, install FM-Approved excess flow check valves throughout the lubrication sys-tem as described in Section 5.0 (Appendix A).

Install thermocouples in the pads of each sliding friction thrust and journal bearing, set to alarm or trip theunit as follows:

Alarm: 210-220°F(98-104°C)

Trip: 240-250°F(115-121°C)

This recommendation exists in Data Sheet 13-17, Gas Turbines, for thrust bearings only. The recom-mended thermocouples are designed to trip the turbine as rapidly as possible in case an excess flow valvecloses for any reason. This minimizes bearing damage.

3. Install FM-Approved excess flow check valves in the main gaseous and liquid fuel lines leading to thefuel manifolds on the gas turbine. The valves should be installed in the fuel pump discharge, and sized sothat the minimum closing flow is 10% greater than the maximum flow the pump can deliver in the fuel pip-ing system with the fuel pressure regulator wide open.

If a liquid fuel pump is a constant displacement type, an FM-Approved low pressure shutoff valve shouldbe used instead of an excess flow check valve.

4. Install an FM-Approved excess flow check valve in each pigtail from the fuel manifold to a fuel nozzleat the connection to the manifold. The minimum closing flow should be 10% greater than the maximum flowin the pigtail at maximum pump discharge pressure. Supply sufficient ventilation to maintain the tempera-ture of the valve below the approval rating.

Do not use excess flow check valves in combustor pigtails unless a blade path spread monitoring system,as described in Data Sheet 13-17, Gas Turbines, is installed in the gas turbine exhaust to alarm at an inter-mediate value of spread, and to trip the unit at a dangerous level. Such a system monitors the variabilityof gas temperature around the exhaust flowpath continuously, and produces an alarm and trip at specified val-ues of the spread. It is necessary to monitor blade path spread to detect accidental closure of a pigtail valve,which will shut off fuel to its combustor fuel nozzle.

5. Install an FM-Approved excess flow check valve the hydraulic pump discharge, and in any branch linejust downstream of the junction, in each hydraulic system (starting, variable compressor stators, variable tur-bine nozzles, compressor bleed). The valve should have a minimum closing flow 10% higher than the maxi-mum flow in the line at maximum pump discharge pressure. Lines subjected to surges of pressure shouldbe provided with accumulators to control rates of flow change.

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6. If the driven generator is hydrogen cooled, use excess flow check valves to protect the hydrogen seal-oil system.

7. Install FM-Approved fire detectors around the gas turbine in accordance with Data Sheet 5-48, AutomaticFire Detectors, to detect a fire arising from a small leak in the lubricating, hydraulic or fuel system, that wouldnot be sufficient to actuate the corresponding excess flow check valve. These detectors should annunci-ate an alarm in the control room, and should trip the gas turbine off line, shutting off the fuel system instantly.The lubrication system should be shut off either instantly or after a specified delay determined from a firerisk evaluation.

If heat detectors are used, they should be the temperature compensated, rate-of-rise type. The tempera-ture rating of the detector should be based upon the maximum operating temperature expected around a gasturbine.

The purpose of this recommendation is to respond to spray fires from leaks that are too small to actuatethe excess flow check valves because of the necessary tolerances on closing flow. A fire risk evaluation maydetermine that a lube oil fire should be shut off as rapidly as possible, accepting the risk of damage to thebearings while the unit is coasting down and going on turning gear, or that a delay of up to ten minutes is per-missible. The fire rating of an uninsulated column, or other structural member that might be targeted by thefire, is ten minutes1. The advantages of such a delay in the event of a small leak and fire are:

• Bearing damage is minimized, since lubrication is shut off after the rotor has decelerated.

• A spray fire originating at the opening in the lubricating or hydraulic system may enlarge the opening rap-idly, and the appropriate excess flow check valve will then respond and shut off oil flow with minimum dam-age to the bearings.

• The operator has time to distinguish between a fuel fire (which would be extinguished as soon as the fuelis shut off) and a lube- or hydraulic-oil fire, and, in the case of a fuel fire, maintain lubrication to the bearings.

8. If a space exists beneath the gas turbine in which lube oil or liquid fuel can accumulate, installFM-Approved fire detectors of Recommendation 7 in positions to respond to a spill or pool fire. If the tur-bine has insulating blankets over its hot section, install the fire detectors in positions to respond to a fire inthe blankets in case they become soaked by leaking lube oil, liquid fuel, or hydraulic fluid, and then ignitedby contact with the hot turbine casing.

9. In an attended location, store portable dry chemical and/or foam extinguishers adjacent to the gas-turbine housing for use in extinguishing spill and soaked blanket fires.

10. In an unattended location, install a fixed dry chemical or foam extinguishing system should be installedto protect the area under the turbine, as well as blanketed areas where a soaked blanket fire could occur.This system should be activated by the fire detectors of Recommendations 7 and 8.

11. If the building in which the gas turbine is installed is sprinklered, provide shielding or lagging over thegas turbine, to avoid damage in the event of accidental sprinkler discharge. “Lagging” is a term used for vari-ous types of protective barriers installed on and around the hot sections of gas turbines. Barriers can varyfrom blanketing to wooden enclosures designed to keep personnel away from the casing.

2.1.2.2 Less Flammable Lubricants and Hydraulic Fluids

If less flammable, FM-Approved lubricants and hydraulic fluids are used, the requirements for fire preven-tion and protection of lubrication and hydraulic systems may be waived. The criterion for approval of these flu-ids is described in Appendix D. Fire protection is still recommended for fuel systems as follows:

1. Install FM-Approved excess flow check valves in the main gaseous and liquid fuel lines leading to thefuel manifolds on the gas turbine. The valves should be installed in the fuel pump discharge, and sized sothat the minimum closing flow is 10% greater than the maximum flow the pump can deliver in the fuel pip-ing system with the fuel pressure regulator wide open.

If a liquid-fuel pump is a constant-displacement type, an FM-Approved low pressure shutoff valve shouldbe used instead of an excess flow check valve.

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2. Install an FM-Approved excess flow check valve in each pigtail from the fuel manifold to a fuel nozzleat the connection to the manifold. The minimum closing flow should be 10% greater than the maximum flowin the pigtail at maximum pump discharge pressure. Supply sufficient gas turbine compartment cooling tomaintain the temperature of the valve below the approval rating.

Do not use excess flow check valves in combustor pigtails unless a blade path spread monitoring system,as described in Data Sheet 13-17, Gas Turbines, is installed in the gas turbine exhaust to alarm at an inter-mediate value of spread, and to trip the unit at a dangerous level. Such a system monitors the variabilityof gas temperature around the exhaust flowpath continuously, and produces an alarm and trip at specified val-ues of the spread. The accidental closure of a pigtail excess flow valve, which will shut off the fuel to its com-bustor fuel nozzle and increase the spread, can be detected in this manner.

3. Provide curbs for the gas turbine installation (including fuel and lube oil skids) to contain any slow leaks,or leaks that are not sufficient to actuate the excess flow valves. Provide drains to remove the spilled lubeoil or liquid fuel to a safe disposal location or a catch basin, and slope the floor around the installation towardthe drains. (See Data Sheet 7-83, Drainage Systems for Flammable Liquids, for drainage details).

The quantity of flammable liquid to be handled by the drainage system is one-half the capacity of the lubeoil reservoir.

4. If a space exists beneath the gas turbine in which lube oil or liquid fuel can accumulate, installFM-Approved fire detectors on either side of the turbine to respond to a spill or pool fire. If the turbine has insu-lating blankets over its hot section, install approved fire detectors above the turbine to respond to a fire inthe blankets should they become soaked by leaking liquid fuel, and then ignited by contact with the hot tur-bine casing.

5. In an attended location, store portable dry chemical and/or foam extinguishers adjacent to the gas tur-bine housing for extinguishing spill and soaked blanket fires.

6. In an unattended location, install a fixed dry chemical or foam extinguishing system to protect the areaunder the turbine, as well as blanketed areas where a soaked blanket fire could occur. This system shouldbe activated by the fire detectors of Recommendation 4.

2.1.2.3 Fire Protection of Structural Steel

If a system of excess flow check valves is not feasible, protect the building in which the gas turbine is installedwith sprinklers and water spray directly. This recommendation applies to the main structural columns, theroof girders and trusses, and the crane rails. The flow of flammable liquid is assumed to be 25 gpm(1.57 l/s).

The required densities are:

1. Main structural columns:

• 2-hour rated fireproofing on all main structural columns,

OR

• fixed water spray systems with nozzles directed at the flanges and webs of the columns to apply a den-sity of 0.45 gpm/sq ft (18 mm/min) over the wetted area. This protection should extend over the full lengthof the columns.

This recommendation is predicated on a target distance of 16.5 ft (5 m) from the possible source of a sprayof flammable liquid to the nearest column. If the target distance is 33 ft (10 m) or above, the density require-ment may be reduced to 0.20 gpm/sq ft (8 mm/min).

Locate water spray nozzles at 10 ft (3 m) intervals on opposite sides of H-columns. Use the above spacingalso for box- or pipe-columns. Sidewall sprinklers directed at the columns at 15 ft (4.5 m) intervals, and pro-viding the recommended coverage, may be used in lieu of water spray nozzles.

2. Principal roof members:

• 2-hour rated fireproofing on all main structural roof members,

OR

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• sprinklers or water spray nozzles arranged to provide a spray density of 0.15 gpm/sq ft (6 mm/min) ofexposed surface on the lower flange of a truss or girder.

This recommendation is predicated on a target distance of 33 ft (10 m) from the possible source of a sprayof flammable liquid to the bottom of the roof truss.

3. Crane girders:

• 2-hour rated fireproofing on bottom and sides of crane girders,

OR

• sprinklers or water spray nozzles arranged to provide a spray density on the lower flanges of the rails of0.2 gpm/sq ft (8 mm/min) of exposed surface.

This recommendation is predicated on a target distance of 30 ft (9 m) from the possible source of a sprayof flammable liquid to the bottom of the crane girder.

The purpose of Recommendations 1, 2 and 3 is to protect the main structural members in a building froma fuel, hydraulic, or lube oil spray fire. It is known that discharge of water on such jet fires does very little tomitigate their intensity; therefore, the main structural building members should be cooled directly to pre-vent their collapse (See Data Sheet 7-93N Aircraft Hangars, for a similar protection scheme).

4. If the turbine building has an overhead crane, and if a fire-risk evaluation indicates it should be pro-tected in the event of a spray fire, install ventilators in the roof in accordance with NFPA 204M, Guide forSmoke and Heat Venting.

The purpose of this recommendation is to enable a fire brigade to enter the building to direct hoses on thecrane to keep it cool until a spray fire can be extinguished by cutting off the source of fuel. Vent sizing shouldbe sufficient to limit the smoke layer to a level above the crane.

5. Locate connections for 11⁄2 in. (38 mm) hose at strategic points around the gas turbine installation. Con-sider adequate coverage of the unit combined with accessibility to firefighting personnel.

6. Provide curbs for the gas turbine installation (including fuel and lube oil skids) to contain any slow leaks.Provide drains to remove the spilled lube oil or liquid fuel to a safe disposal location or a catch basin, andslope the floor around the installation toward the drains. (See Data Sheet 7-83, Drainage Systems for Flam-mable Liquids, for drainage details).

The quantity of flammable liquid to be handled by the drainage system is one-half the capacity of the lubeoil reservoir.

7. If a space exists beneath the gas turbine in which lube oil or liquid fuel can accumulate, installFM-Approved fire detectors on either side of the turbine to respond to a spill or pool fire. If the turbine has insu-lating blankets over its hot section, install approved fire detectors above the turbine to respond to a fire inthe blankets in case they become soaked by leaking liquid fuel, and then ignited by contact with the hot tur-bine casing.

8. In an attended location, store portable dry chemical and/or foam extinguishers adjacent to the gas tur-bine housing for extinguishing spill and soaked blanket fires.

9. In an unattended location, install a fixed dry chemical or foam extinguishing system to protect the areaunder the turbine, as well as blanketed areas where a soaked blanket fire could occur. This system shouldbe activated by the fire detectors of Recommendation 7.

10. Separate adjacent unenclosed gas turbines in buildings protected as described in this section by a 2-hourrated, fire-resistant barrier.

2.1.3 Partly Enclosed Installations

These installations enclose the major components, but the oil reservoir, pumps, filters and coolers, thegaseous and liquid fuel systems, and possibly a hydraulic starting system, are installed outside the enclo-sures. The recommendations of Section 2.1.1 apply to the gas turbine and other compartments. Recommen-dations of Section 2.1.2 apply, as applicable, to the unenclosed skids.

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2.1.4 Additional Recommendations

1. Provide a system to shut off fuel, hydraulic or lube oil from the control room or other remote location inthe event of a fire that is not otherwise under control. Route instrumentation and control cables, as far as pos-sible, through areas where they would not be affected by a fire.

2. Provide instrumentation in lubricating oil lines with metal guards to prevent accidental breakage ofinstrumentation.

3. Use safety glass or similar impact-resistant material for windows in sight glasses.

4. Wherever practicable, fabricate lubricating oil lines of pipe-guard (concentric pipes) construction (alsoknown as safety piping) with the pressure line running inside the drain line.

5. If the driven equipment is a hydrogen cooled a.c. generator, locate hydrogen cylinders outside the build-ing or gas turbine enclosure, or in special rooms, as defined in Data Sheet 7-91, Hydrogen. The hydrogensystem should be maintained as described in Data Sheet 7-91.

The provisions of Data Sheet 7-91 rely on the fire-resistivity of the walls of the turbine building or enclo-sure. In the case of spray fires, the structure and walls should have twice the resistance rating obtained forthe standard fire (ASTM E119).

6. Provide lines from the hydrogen cylinders to the hydrogen control system with FM-Approved, excess flowcheck valves near the cylinders.

7. Provide access doors or hatches in inlet air filter enclosures, and have manual firefighting equipmentavailable.

8. In an installation classified as a Hazardous Location (Class I, Div. 1 or 2, or equivalent), make the elec-trical installation explosionproof or intrinsically safe in accordance with the National Electrical Code (NEC),Article 500, for Hazardous Locations5, or other equivalent code.

2.1.5 Protection of the Generator

Factory Mutual loss experience does not warrant a recommendation for protection against flammable liquidfires originating at the electric generator in gas turbine installations. However, if excess flow check valvesare used in lubrication systems, they should be used throughout the system.

2.2 Inspection and Testing

2.2.1 Total Flooding Carbon Dioxide Systems

1. If a carbon dioxide cylinder is discharged, perform a hydrostatic test (if more than five years have elapsedsince the last hydrostatic test) before refilling the cylinder. Re-mark the cylinder.

2. Discharge carbon dioxide cylinders and subject them to a hydrostatic test at least every 12 years, or asrequired by local jurisdictional regulations requiring more frequent testing than 12 years.

3. Inspect and test the total flooding carbon dioxide system in accordance with the following schedule:

Weekly:

Check the liquid level gage on storage tanks.

Monthly:

• Check valve-packing glands, safety relief valves, and screwed connections for leakage.

• Inspect and adjust automatic closers on manually-operated doors as necessary.

Biannually:

• Weigh carbon dioxide cylinders and replace any cylinder having a weight loss of 10% or greater.

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• Test the operation of the carbon dioxide tank pressure switch and alarm by reducing and raising the pres-sure. To reduce the pressure, close the valve in the line from the vapor space and remove the test plug.To increase the pressure, connect a high pressure cylinder to the test opening. After the test, carefullyreplace the plug and reopen the vapor line valve.

Annually:

• Calibrate liquid level and pressure gages.

• Test the entire protection system for operation. Disconnect the control leads from the carbon dioxide cyl-inders, and actuate the system by placing a heat source under the heat detectors in the compartment.Observe the functioning of all relays and latches .

Every Five Years:

Replace the frangible disks on the carbon dioxide cylinders.

2.2.2 Total Flooding Clean Agent Systems

Inspect and test the total flooding clean agent system according to the following schedule:

1. If a clean agent container is discharged, perform a hydrostatic test (if it has been more than five yearssince the last hydrostatic test) before refilling the container. Remark the container.

2. Inspect and test the total flooding clean agent system according to the following schedule:

Weekly:

Check the liquid level gage on the storage container.

Monthly:

• Inspect and adjust the automatic closers on manually-operated doors as necessary

• Check valve packing glands, safety relief valves, and screwed connections for leakage.

Biannually:

• Test the operation of the clean agent container pressure switch and alarm by reducing and raising thepressure.

Annually:

Calibrate the liquid level and pressure gages

Test the entire protection system for operation. Disconnecting the control leads from the clean agent con-tainer, and actuate the system by placing a heat source under the heat detectors in the compartment. Observethe functioning of all relays and latches.

2.2.3 Fine Water Spray (FWS) Systems

Inspect and test the fine water spray system according to the following schedule:

Weekly:

Check the water level gauge and the air pressure gauge on the water reservoir.

Monthly:

• Inspect automatic closers on manually-operated doors as necessary

• Check the safety valve and inspect connections for leakage.

Biannually:

Check the liquid level and pressure gages on the water reservoir.

Annually:

• Calibrate liquid level and pressure gages

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• Test the entire fine water spray system for operation.

2.2.4 Excess Flow Check Valves

Inspect, clean and bench-test excess flow check valves every three years.

2.3 Prevention of Internal Fires and Explosions

2.3.1 Protective Systems and Devices

1. Provide flame detectors in combustors to actuate a fuel shutoff valve in the event of flameout duringoperation. The time from flameout to complete fuel cutoff should not exceed 750 ms.

2. Provide redundant fuel shutoff valves in gaseous and liquid fuel systems, with automatic venting in gas-eous systems, and a drain in liquid fuel systems.

3. Install automatic drains in the combustor casings of gas turbines using liquid fuel.

4. At least annually during regular combustion section inspections, inspect the fuel system as described inSection 4.2.2.5 of this data sheet. (See also Data Sheet 13-17, Gas Turbines, Sections 2.1.3 and 3.1.3).

3.0 GUIDELINES FOR INSTALLATION TO PREVENT FIRES

Most fires in gas turbine installations are spray fires involving flammable liquids. Most start when a pipe car-rying the liquid fractures or loosens. The following installation measures for lubrication and fuel lines maybe used to minimize the likelihood of such occurrences:

• Flexible metallic hose is preferred for fuel, hydraulic and lube oil lines and lines at the interface with the com-bustion turbine.

• Provide freedom in rigid metal piping to deflect with the engine, in any direction, at the interface with the tur-bine. This recommendation also applies to hydraulic lines connected to accessory gearboxes or actua-tors mounted directly in the turbine.

• Support rigid piping connected directly to the turbine so that the natural frequency of the piping will not coin-cide with the rotational speed of the combustion turbine.

• Use welded pipe joints where practical. Use a torque wrench to assemble threaded couplings and flangebolts in fuel and oil piping. Torque the couplings and bolts per the manufacturer’s requirements. Providepositive locking devices to prevent couplings from unscrewing.

• Provide metal guards for instrumentation in lubricating oil lines at the combustion-turbine interface to pre-vent accidental breakage of instrumentation. Sight glasses should be of safety glass or similar impact-resistant material.

4.0 SUBSTANTIATION FOR RECOMMENDATIONS

4.1 External Fires in Gas Turbine Installations

This section summarizes loss experience involving external fires in gas turbine installations and analyzesthe experience in terms of type of fire and the effectiveness of the extinguishment method. A case history ofa typical fire in a sprinklered building is analyzed in some detail.

4.1.1 Summary of Experience with External Fires

4.1.1.1 Industry Experience

Tables 2 through 5 summarize 80 external fire losses in gas turbine installations. The sources of the compi-lation in the tables are Factory Mutual loss experience, a compilation of fire experience by the National FireProtection Association, and a compilation of fire experience by the Edison Electric Institute6.

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Table 2. Summary of External Fire Losses in Gas Turbine Installations (Numbers of Losses)

Location of Fire

Major Fire Types Major Fire Fuels

AllFires

SprayFires

PoolFires

SoakedBlanket

Lube OilFire

Fuel Oil orGaseousFuel Fire

Accessory compartment 10 6 1 – 5 2Turbine compartment 42 12 7 12 14 20Exhaust area 14 7 3 2 9 3Load tunnel 1 1 – – 1 –Turning gear enclosure 1 1 – – 1 –Fuel system 1 – 1 – – 1Generator area 6 – 1 – 2 –Unknown 5 – 1 – 2 1Total 80 27 14 14 34 27

Table 3. Gross Property Damage Costs of External Fire Losses in Gas Turbine Installations

Damage Costs All Fires Spray Fires Pool FiresSoakedBlanket

Other andUnknown

Gross Property Damage in U. S. $1000’s(1996 Dollars)

$25,815 $17,070 $2,030 $164 $6,550

Average Gross Property Damage in U. S.$1000’s (1996 Dollars)

$323 $632 $156 $12 $252

Although there were a relatively large number of soaked blanket fires, spray and pool fires involving lubeoil, fuel oil and gaseous fuel constitute the highest risk category in gas turbine installations. Accordingly, Tables4 and 5 summarize the loss experience with these fire types. These tables show the numbers of these firesby type of protection used in the installations, and the total costs of such losses. The tables also show thenumbers of fires in which the protection did not function properly, and the associated costs of these losses.

Table 4. Numbers of Fires Involving Lube or Fuel Oil, and Gaseous Fuel by Type of Protection

Type of Fire

Numbers of FiresUnsuccessful Extinguishments in ( )

FixedProtection

(Halon, CO2)

Sprinklersor

Deluge Foam System

Other Fixed Protection(Dry Chemicals, Foam,

Etc)

No FixedProtection

or UnknownSpray Fire 20 (9) 2 (2) – 5Pool Fire 10 (5) – 2 (0) 2

Table 5. Gross Property Damage Costs of Fires Involving Lube or Fuel Oil, and Gaseous Fuel by Type of Protection

Type of Fire

Gross Property Damage in Fires Loss Costs in 1000s (96 U.S. $s)Fixed

Protection(Halon, CO2)

Sprinklersor

Deluge Foam System

Other Fixed Protection(Dry Chemicals, Foam,

Etc.)No FixedProtection

Spray Fire $6,688 $3,510 – $2,958Pool Fire $594 – – $651

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In 47% of the fires having automatic, total flooding Halon or CO2 systems (14 cases) extinguishment wasunsuccessful. The unsuccessful extinguishments broke down by cause as follows:

Housing did not seal 5Malfunction of actuation system 4Fire not in protected area 2System overwhelmed by size of fire 1Fire not detected 1Unknown 1

4.1.1.2 Factory Mutual Experience

Tables 6 through 9 summarize the FM’s loss experience in external fires.

Table 6. Summary of External Fire Losses in Gas Turbine Installations by Number of Losses (FM)

Location of Fire

Major Fire Types Major Fire Fuels

AllFires

SprayFires

PoolFires

SoakedBlanket

Lubeor

Hydraulic OilFire

Fuel Oilor

GaseousFuel Fire

Accessory compartment 5 5 – – 3 2Turbine compartment 3 1 – – 1 1Exhaust area 4 4 – – 2 1Load tunnel 1 1 – – 1 –Total 13 11 – – 8 4

Table 7. Gross Property Damage Costs of External Fire Losses in Gas Turbine Installations (FM)

Damage CostsAll

FiresSprayFires

PoolFires

SoakedBlanket

Other andUnknown

Gross Property Damage in U. S. $1000’s(1996 Dollars)

$11,153 $9,616 – – $1,537

Average Gross Property Damage in U. S.$1000’s (1996 Dollars)

$858 $874 – – $769

Table 8. Numbers of Fires Involving Lube or Fuel Oil, and Gaseous Fuel, by Type of Protection (FM)

Type of Fire

Numbers of Fires - Unsuccessful Extinguishments in ( )Fixed

Protection(Halon, CO2)

Sprinklersor

Deluge Foam System

Other Fixed Protection(Dry Chemicals, Foam,

Etc.)No FixedProtection

Spray Fire 5 (2) 2 (2) – 4Pool Fire – – – 4

Table 9. Gross Property Damage Costs of Fires Involving Lube orFuel Oil, and Gaseous Fuel, by Type of Protection (FM)

Type of Fire

Gross Property Damage in Fires Loss Costs in 1000s (96 U.S. $s)Fixed

Protection(Halon, CO2)

Sprinklersor

Deluge Foam System

Other Fixed Protection(Dry Chemicals, Foam,

Etc.)No FixedProtection

Spray Fire $1,350 $3,018 – $2,930Pool Fire – – – –

4.1.1.3 Case History of an External Fire in a Gas Turbine Installation

A prototype industrial gas turbine was undergoing test in the manufacturer’s test facility. This was a 75 x87 x 57 ft high (23 x 27 x 17 m) building. The walls were insulated metal panels on a steel frame, and theroof was insulated steel deck on steel beams supported by steel trusses. The building was sprinklered

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throughout by a center-fed system designed to provide a coverage of 0.21 gpm/ft2 (8.4 mm/min) over themost remote 2,400 sq ft (223 m2). Figure 1 shows the layout of the building and the progress of the fire.

The gas turbine was a two-shaft machine with a power turbine cantilevered forward over two bearings housedin the load tunnel — the cavity inside the exhaust duct, through which the drive shaft passed. The drive shaftwas coupled to a dynamometer.

The turbine installation was on the west side of the building, with a substantial clearance from the west wall.The exhaust duct exited through the north wall to an outside stack. An oil reservoir at the inlet end of thegas turbine, near the south wall, provided oil for lubrication and hydraulic control. A pump driven by the gasturbine shaft delivered 120 gpm (7.5 l/s) through pipes of up to 4 in. (10 cm) diameter to the three bearingsumps, including the sump in the load tunnel for bearings 3 and 4. Pressure in the lines was regulated to 15psi (103 kPa). During startup and shutdown a motor-driven auxiliary pump in the reservoir delivered oil ata rate of 25 gpm (1.5 l/s). An emergency pump driven by a battery-powered d.c. motor backed up the aux-iliary pump. The drain oil from the bearing sumps was piped out of the building to a cooler, and then returnedinside to the reservoir.

The incident occurred when part of the rim of the power turbine disk fractured, releasing some of the blades.A blade jammed between the remaining blades and the casing, decelerating the rotor very rapidly, and impart-ing a high transverse load to the bearings. This caused the cantilevered bearing housing to deflect verti-cally and/or horizontally, and the flange bolts sheared at both pressure and return lube oil lines, separatingthe lines from the housing (Figure 2). Oil sprayed out of the 3 in. (7.5 cm) pressure line and was ignited;the flame impinged on and ran up the west wall of the building.

The operator immediately tripped the gas turbine and it decelerated quickly to a stop. The fire continued, how-ever, as the auxiliary lube oil pump continued to pump oil through the separated line, and when power toit was cut off, the emergency pump took over. Burning oil sprayed and flowed through an open door in thewest wall into a sewer.

The public fire department arrived within five minutes and proceeded to fight the fire from outside. All seventy-two sprinklers discharged with no apparent effect on the conflagration, although three sprinklers were partlyobstructed by heating ducts halfway up the west wall of the building. The fire continued until an employee

Fig. 1. Gas turbine test facility fire.

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Fig. 2. View into load tunnel showing separated lube oil lines.

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went into the building and shut off the emergency lube pump, cutting off the fuel supply.

Damage to the building was extensive. A 100 x 65 ft (30.5 x 20 m) section of the west wall had to be replaced(Figure 3) as well as some of the roof structure. Figure 4 shows some of the internal damage to the building.

The above case history has a number of instructive aspects and typifies the problems of protection of gas tur-bines. The incident started with an internal failure in the turbine; the reaction of the machine severed theoil lines to the bearing in the load tunnel. Unpredictably the oil sprayed out laterally and ignited. There wasno obvious source of ignition, because the only hot object in the area (the exhaust duct) was completely insu-lated. The torch-like spray fire jumped across to the wall of the building, doing very little damage to the gasturbine itself. The flame ran up the wall, damaging it even though the sprinklers were in full operation. Thesprinkler discharge had no effect on the fire itself, although it could have limited the damage to the buildingby providing a curtain of water. The spray fire was extinguished only by cutting off the source of fuel.

Fig. 3. External damage to test facility.

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4.1.2 Need for Protection of Generator Compartments

Only six of the 80 fires comprising the loss history of Table 2 occurred in the generator compartment, andthree of these were electrical fires in the bus duct or collector area. The risk of an oil-fed fire in the genera-tor is slight when compared with the risk of such a fire in the gas turbine compartment. For this reason, gen-erator compartments generally are not protected by total flooding systems. There are three reasons for thereduced risk:

1. Lack of fire hazard: Table 2 shows that fuel oil or gas is a common source of fuel for fires in gas turbine com-partments. The absence of fuel lines in generator compartments lowers the overall risk.

2. Less chance of jolting of bearings: Mechanical failures that jolt the bearings of machines are more com-mon in gas turbines than in generators. The case history is a good example, particularly of the violent mecha-nism of blade jamming. Such jolts at the bearings fracture lube lines, leading to the oil sprays and subsequentfires.

3. Lack of hot surfaces: The chance of ignition of the oil spray after a lube-line fracture in the generator com-partment is less because of the absence of hot surfaces.

Because of the experience summarized in Table 2, in which such fires appear to be a minor hazard, no rec-ommendation is being made for fire protection of the generator compartment, other than those recommen-dations pertinent to storage of hydrogen (Section 2.1.4).

Fig. 4. Damage to interior of building in northwest corner.

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4.1.3 Water as an Extinguishing Agent in Gas Turbine Installations

It is clear from the case history described in Section 4.1.1.3, as well as from laboratory experiments, thatsprinkler or deluge systems can have little effect on controlling high intensity oil-spray fires. They may limitthe fire damage somewhat, by providing a cooling curtain of water over the walls of the building. Neverthe-less, substantial damage can still occur, as the case history shows.

4.1.3.1 Atomic Energy Commission (AEC) Tests

Factory Mutual Research Corporation (FMRC) conducted a series of tests for the United States Atomic EnergyCommission to determine if automatic sprinklers could protect the AEC’s facilities against spill fires involv-ing lubricating oil. One of the tests addressed the problem of lubricating oil spraying from a ruptured pipe.

Test Procedure:

A structural frame consisting of a steel column and a series of crossbeams was constructed, and an oil spraynozzle was mounted vertically 12 ft (3.7 m) above the floor, and 2 ft (0.6 m) from the vertical column on oneof the crossbeams, as illustrated in Figure 5. Lubricating oil was pumped to the nozzle at a flow rate of10.8 gpm (0.68 l/s) and ignited; the figure shows the oil spray just prior to ignition. Thermocouples weremounted throughout the steel structure and at the roof level, 33 ft (10 m) above the floor. Sprinkler headswere mounted at the roof level at 10 ft (3.05 m) spacing, and were discharged about 1 minute after ignitionof the spray.

In the spray fire test, the sprinkler discharge density was increased to 0.36 gpm/ft2 (14.4 mm/min), but ther-mocouples on an exposed steel column continued to register 1400-1800°F (760-983°C) over a period of8 minutes, until the oil spray was shut off. At the same time, a thermocouple at roof level, at a point 14 ft(4.3 m) laterally from the ignition point, registered a temperature of 860°F (460°C), with an average tempera-ture of 720°F (383°C) over a period of 2 minutes. The roof temperature would have been substantially higherdirectly over the spray flame.

The test was repeated. The sprinkler discharge density was increased to 0.46 gpm/ft2 (18.5 mm/min) withno substantial change in the results.

Conclusion:

Where oil may be discharged in the form of a spray at an elevation above floor level, whether or not thereis initially any substantial oil spill on the floor, a fire under these conditions may bring about failure of exposedsteel in the immediate vicinity of the fire. The discharge from automatic sprinklers at any practical densitymay not extinguish the spray fire. There is no other economically practicable automatic fire protection meansavailable which will extinguish such a spray fire at any one of a large number of possible locations distrib-uted over a wide area, even if it were considered necessary to extinguish.

4.1.3.2 Tests at the Technical Research Centre of Finland

In 1979 a series of tests involving lubricating-oil fires was conducted at the Technical Research Centre ofFinland7. Figure 6 shows the apparatus used. In these tests a burning oil spray was discharged against an8 ft (2.5 m) high wall of steel plates, from which it sprayed and flowed into a collection pool measuring9.8 ft by 13.1 ft (3 m by 4 m). The length of the oil jet was 13.1 ft (4 m). In some of the tests the pool waspartly surrounded by walls of steel plate. In some other tests the walls were partly removed.

This series of tests provided no assurance that oil jet fires can be extinguished by sprinklers or water spray,or that the temperatures of the building structure can be kept to safe values. There was substantial defor-mation of sprinkler piping, and very high temperatures were recorded.

Test Procedures7

Three high-velocity nozzles were used for investigating the possibilities to control a burning oil spray by direct-ing the water spray at a limiting part of the oil jet. For application of water sprays from above, three sepa-rately controlled loops of sprinkler piping were mounted so that the distribution plates of pendent sprinklersinstalled on the pipe were situated at an elevation of 9.8 ft (3 m) above the oil collecting pool. In varioustests, 0.6 in (15 mm) and 0.8 in (20 mm) spray sprinklers, medium-velocity nozzles, and high-velocity nozzleswere installed on the loops.

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Temperatures were registered by thermal elements in 11 different locations above and around the oil fire andthe intensity of heat radiation from the fire was registered in one location 30 ft (9 m) from the center of thepool.

Fig. 5. Oil spray in AEC spray fire test, just prior to ignition.

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Conclusion:

In general, sprinklers or water spray cannot extinguish a jet fire, but complete automatic extinguishment isnot always necessary; getting the ambient temperature and the intensity and size of the fire under control maybe sufficient.

The question arises, however, as to whether the temperatures were actually kept under satisfactory controlduring the tests.

Three tests are of particular interest.

Test 6:

In this test, with a sprinkler discharge density of 0.5 gpm/ft2 (20 mm/min), the temperature 10 ft (3 m) abovethe spray near its target reached 2,470°F (1,300°C) after 40 seconds. At this location, the temperature wasabove 1,300°F (700°C) for up to 50 seconds. Another sensor directly above the spray reached 1,830°F(1,000°C) after 50 seconds.

The radiation intensity at a point 29.5 ft (9 m) from the jet centerline was 23-108 kW/ft2 (7-10 kW/m2) for40 sec with the discharge rate at the above 0.5 gpm/ft2 (20 mm/min). At a distance of 16.5 ft (5 m), the tem-perature of a structural column would have to be 1,100°F (600°C) to radiate this flux. This temperature wouldprobably be excessive for structural steel.

The conclusion is that sprinkler discharge, even at 20 mm/min (0.5 gpm/ft2), would be insufficient to pro-tect a building.

Fig. 6. Apparatus used in spray fire tests at the Technical Research Centre of Finland,showing the arrangement of the oil spray.

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Test 12:

This test was conducted with the back wall in place and the jet was completely covered with water sprayfrom four high-velocity sprayers. The density was 0.7 gpm/ft2 (28 mm/min). The fire was extinguished in 12seconds, although the temperature 10 ft (3 m) above the jet reached 1,940°F (1,060°C).

In this test, the oil jet did not burn, but hit the back wall and dropped into the pool, where it was ignited. Itbecame, in effect, a pool fire, and was readily extinguished, although with a water spray density much higherthan normally employed.

Test 17:

This test was conducted without the backwall in place to contain the jet. There was no flame in the area cov-ered by the sprayers, but, even though the coverage density was increased to 1.0 gpm/ft2 (40 mm/min),the fire burned beyond the area of coverage with undiminished intensity.

4.1.3.3 Hazard of Accidental Discharge of Water on Hot Gas Turbine Casings.

An accidental water discharge on the hot casing of a gas turbine while it is operating may cause damage.A major loss occurred when a series of accidental deluge system trips wetted a heavy-duty gas turbine cas-ing. The casing was operating at 550-600°F (288-316°C). The deluge nozzles were directed at top of the tur-bine casing. No immediate damage was noted, but the performance of the turbine deteriorated with eachsuccessive accidental trip. The unit was shut down and the turbine section was opened for inspection. Theblades on both turbine stages were rubbed severely at their tips; the blades in the first stage were wornapproximately 0.060 in. (1500 microns), while the blades of the second stage were worn a little less (0.050in. or 1300 microns). The casing had distorted elastically as a result of the circumferentially-varying cool-ing effect of the deluge system discharge, and the blades had rubbed to the extent noted. There was no per-manent material damage to the casing, and its dimensions were all within blueprint limits after it returnedto its original shape when the temperature gradients were removed.

Factory Mutual analyzed the temperatures, stresses, and deflections of hot gas turbine casings subjectedto sprinkler discharges of various densities and distributions. The casing involved in the loss referred to abovewas used as a model for the study.

Following is a summary of the results:

Sprinkler Discharge Densitygpm/ft2

(mm/min)

Maximum Deflectionin.

(cm)Analysis 0.2 (8) 0.18 (0.457)Measured 0.2 (8) 0.12 (0.307)

The analysis may be conservative, but the permissible deflection would have to be merely 0.030 in (0.076cm) to avoid rubbing at the condition of minimum assembly clearance and tightest tolerance. It is con-cluded that sprinkler discharge on a hot gas turbine casing produces a hazard of severe internal rubbing.

4.2 Internal Fires and Explosions in Gas Turbines

4.2.1 Summary of Experience with Internal Fires and Explosions

Table 10 represents combined statistics from FM, Edison Electric Institute, and the NFPA.

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Table 10. Internal Fires and Explosions

Loss CausesNumber of Losses Gross Property Damage Costs

(U.S. $1000s in 1996 dollars)Casing Drain Malfunction 5 $3,356Combustor Flameout 10 $8,743Ignition Failure 1 $972Leaking Fuel Valves and Fuel Switchover 8 $3,336Flashback, Foreign Liquid, Faulty Regulator, Etc. 9 $7,751Unknown 6 $6,882

39 $31,040

Table 11 represents FM statistics.

Table 11. Internal Fires and Explosions (FM)

Loss CausesNumber of Losses Gross Property Damage Costs

(U.S. $ 1,000s in 1996 dollars)Casing Drain Malfunction 3 $1,708Combustor Flameout 10 $8,743Ignition Failure 1 $972Leaking Fuel Valves and Fuel Switchover 5 $3,091Flashback, Foreign Liquid, Faulty Regulator, Etc. 8 $7,751Unknown 3 $779

30 $23,044

4.2.2 Case Histories of Internal Fires and Explosions

The following case histories illustrate the major categories of internal fires and explosions. Each case historydiscusses the approach to avoiding that particular hazard.

4.2.2.1 Internal Fire Due to a Leaking Fuel Valve

A single-shaft gas turbine driving a standby generator in a public utility had been started up and warmedprior to loading. Before it was loaded, the dispatcher canceled the request, and it was shut down. Before theshutdown sequence was completed, attempts were made to restart the engine, but it would not respond.When the gas turbine was opened up and examined, the turbine section was found completely burned out.Rotating and stationary components of the turbine section were severely damaged (Figures 7 and 8).

The leading edges of first stage nozzles exhibited light damage, possibly unrelated to the fire. But the trail-ing edges were extensively burned. A torch-like flame severed almost all of the second and third stagenozzles: the second stage at midspan, and the third stage at the outer flow path. Apparently the flame fronthad been positioned halfway through the first stage nozzle row.

Nothing in the control logic could explain the development of the internal fire; it should have been impos-sible to inject fuel into the engine during the restart attempt before the igniter was activated. However, thefuel flow was governed by a throttle valve, an overspeed trip valve, and the fuel isolation valve, all down-stream of the fuel pump. The overspeed trip valve was normally open. The function of the isolation valvewas to shut off the liquid fuel during normal shutdown, and while the turbine was operating on the alter-nate fuel. This valve was air-tested after the loss, and it leaked. It was concluded that liquid fuel was forcedthrough this leaking valve by the motor-driven fuel pump upon startup, and the pressure was sufficient toatomize the fuel as it flowed through the fuel nozzles into the hot combustion chambers. The fuel ignited andburned in a controlled manner in the turbine section.

Newer gas turbines often employ a double valve system for the gaseous fuel. Figure 9 is a schematic of adouble valve arrangement with a solenoid-operated vent valve to bleed off any fuel trapped between the pri-mary and secondary valves. This vent valve is closed during operation and is opened when the primary fuelvalve closes on shutdown. In the system shown, the secondary valve is closed by differential pressure asthe vent valve opens. In other systems the primary and secondary valves are closed by the control system.

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Liquid fuel systems often do not have a double valve arrangement. In one installation, the control valve servesas a shutoff valve. In this case the main fuel pump is turbine driven, and ceases to produce fuel pressurewhen the turbine decelerates. This may be a sufficient protection against an internal fire after shutdown or justbefore startup.

The system of this case history has a solenoid-operated shutoff valve downstream of the control valve, andthe main fuel pump is motor driven. If the shutoff or isolation valve is leaking, an internal fire hazard existsif the turbine is started hot or if the pump continues to operate after shutdown.

The case history shows clearly that it is important to provide double fuel valves in liquid fuel systems withmotor-driven fuel pumps. The combustor drain is not sufficient protection against a leaking valve throughwhich fuel can be sprayed under maximum fuel pump pressure.

4.2.2.2 Internal Explosion Due to Slow Response of the Fuel Valve to Flameout.

A gas turbine with a vertical combustor discharging through a U-duct into the turbine had been started on liq-uid fuel and synchronized. Steam was being injected through ports around the combustor fuel nozzle foremissions control. About twenty minutes after the initial injection of steam, a violent explosion took place inthe combustor. At the same time, a number of alarms sounded, including a flameout.

The internal damage in the gas turbine was extensive. The combustor itself was not extensively damaged,but the 3⁄8 in (10 mm) thick internal liner of the U-tube was torn, with sections completely broken away. Thefirst two rows of turbine blades were completely sheared off at the roots, and stationary nozzle vanes were bro-ken and damaged. Downstream blades were badly fragmented from impact. Flange bolts on the engine cas-ing were broken and the flanges bent and separated.

Fig. 7. Damage to turbine rotor blades as a result of an internal fire.

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Apparently the introduction of steam around the fuel nozzle resulted in a flameout. Flame detectors had beeninstalled to sense flameout and to cut off the fuel supply. However, a time delay of 3.5 seconds was builtinto the shutoff sequence to give the fuel control time to react to underspeed conditions and avoid spuri-ous trips. After the flameout, fuel continued to flow into the hot combustor, and was reignited after the auto-ignition delay time, resulting in an explosion, probably at the discharge from the combustor, and in the U-tube.The autoignition delay time is a function of temperature and pressure in the combustor. In this loss it wasclearly less than the 3.5 second delay built into the shutoff sequence.

Internal fires and explosions resulting from flameout during normal operation can be prevented by rapidcutoff of fuel to the combustor after the flameout. The principles of fuel reignition within the gas turbine,as well as the technique of rapid response of the fuel valves to a flameout, are discussed in Section 7.0(Appendix C).

4.2.2.3 Internal Fire Due to a Faulty Casing Drain.

A third hazard of internal fire arises when liquid fuel collects in the bottom of the combustor casing after a shut-down and is not drained off, possibly because of drain malfunction. This pool of liquid fuel is ignited by thehot gases developed in a combustor during a subsequent startup.

A large industrial gas turbine generator fueled by No. 2 fuel oil had been started and was being loaded whenit tripped out on overspeed. It was idle for two hours while the control system was checked out. The over-speed trip resulted from a control malfunction, and the turbine was restarted. Within a few minutes, the gasturbine tripped on high exhaust temperature, and the exhaust stack began to emit dense black smoke. TheEGT reached 1,200°F (650°C), far in excess of the normal level of 700°F (370°C). An operator opened adoor in the exhaust duct and saw a glow from within the turbine.

When the turbine was cooled down and dismantled, three of the sixteen combustor baskets were found exten-sively damaged. Large areas were missing. These edges curled inward and were covered with scale. Solidi-fied globules of metal were adhering to the surface, indicating metal had melted. Another combustor basketwas slightly damaged, but the remaining twelve were still serviceable. The first two rows of rotating turbine

Fig. 8. Damage to turbine stationary nozzle vanes as a result of an internal fire.

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blading were extensively damaged, presumably by impact with the fragments broken out of the combus-tion baskets.

The three damaged combustor baskets were at the bottom of the casing (Figure 10) where unburned liq-uid fuel tends to accumulate when a gas turbine is shut down. An automatic drain in the bottom of the cas-ing should drain off this fuel oil after shutdown, so that an uncontrolled fire will not occur when next the gasturbine is started and the entering fuel is ignited. After the incident, this drain was found jammed shut andwould not open under the spring load.

The cause of the damage, therefore, was an uncontrolled burning of fuel oil that had drained into the com-bustor casing after the engine had tripped on the spurious overspeed signal; the oil had accumulated in thecasing because of the jammed drain. The damage was limited to Combustors 9, 10 and 11, because the burn-ing gases were drawn into the bleed opening by the air being bled from the combustor casing. The flamewas thus drawn away from adjacent combustors (such as Nos. 7 and 8) leaving them undamaged. The dilu-tion of these gases by the bleed air prevented additional heat damage in the bleed system.

The above case history shows that combustor cases should have automatic drains to remove any accumu-lation of liquid fuel in the casing after shutdown. These valves may be pneumatically operated, held closedby compressor discharge air while the engine is operating, and opening under spring force upon loss ofpneumatic pressure after shutdown. A means (possibly pneumatic) of periodically testing these valves toassure free operation should be available.

Fig. 9. Gaseous fuel valves.

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Fig. 10. Combustor damage due to pool fire in combustor casing.(a) Arrangement of combustor baskets, looking rearward. (b) Burned combustor baskets.

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4.2.2.4 Internal Fire Occurring during Switchover from One Type of Fuel to Another.

Fires and explosions sometimes occur during switchover from liquid to gaseous fuel, or vice versa. One causemay be inadequate control of flow reduction of fuel No. 1, and of flow increase of fuel No. 2. Fuel No. 1 maynot have been purged adequately, and an uncontrolled combustion may occur. Uncontrolled combustioncan also occur if the admission valve for Fuel No. 1 is leaking, and the fuel continues to flow after theswitchover is complete.

During the first startup after an inspection, a gas turbine generator having a dual fuel system was broughtup to part load on liquid fuel. After a short time a changeover to butane gas was made. Within a few min-utes, the fuel pressure dropped and an explosion occurred. Both turbine stages were badly damaged byimpact with fragments originating in the combustor and passing downstream.

An investigation showed that a loose cap on one of the dual-fuel nozzles permitted liquid fuel to leak intothe combustor. The excess fuel ignited somewhere in the combustor and the explosion occurred.

4.2.2.5 Maintenance and Inspection of Gas Turbine Fuel Systems

Three case histories in this section involved component malfunctions that could have been detected by main-tenance or inspection. This is true of the leaking valve in the first incident, of the jammed combustor drainin the third, and of the cap on the dual-fuel nozzle in the fourth.

Combustion section inspections should include inspecting fuel nozzles, igniters and flame detectors. Thelast, in particular, are subject to moisture and dirt contamination that could destroy their ability to sense pres-ence or absence of flame. Particular attention must be paid to sealing the quartz lenses. Gas valves, fueloil valves and dual fuel check valves should also be inspected and leak tested during combustion sectioninspections, and fuel manifold and combustion casing drain valves should be tested for free and preciseoperation.

The turbine in the first case history, a standby unit, was used for few operating hours per year. It is reason-able to recommend inspection of the critical fuel system components in standby units annually (Section2.3.1). Malfunction of the components does not depend only on hours of operation; idle time may have justas much effect.

5.0 APPENDIX A

This section describes the valves used to shut off flow in lube, hydraulic, and fuel oil lines after a down-stream break. It also illustrates where these valves should be installed in lubrication systems and dis-cusses some significant system design and installation issues.

5.1 Excess Flow Check Valves

The head of an excess flow check valve is normally held open by a spring preloaded in compression, butit closes when the increased flow through the line produces sufficient pressure drop to overcome the open-ing spring force. Figure 11 shows one type of valve installed in a line which may have fuel, oil or gas flow-ing in it. Fluid flow is through a ring of valve ports and then through the space between the valve head andthe seat. There is normally a nominal pressure drop across the valve.

If the line breaks downstream of the valve, the flow will increase, increasing the pressure drop across thevalve. At the minimum closing flow, the load on the head will overcome the preload and the resistance of thespring, and the valve will close. It will remain closed until the load is reduced, e.g., by reduction of upstagepressure.

The minimum closing flow can be selected to allow for overpressures or surges in the line during normaloperation. The minimum closing flow is a function of the installed orientation of a valve, being slightly higherin a vertical (outlet up) than in a horizontal orientation. Excess flow check valves are available up to 10 in.(25 cm) in diameter.

Figure 12 shows a magnetic excess flow valve available in sizes down to 1⁄4 in (6.4 mm) with flow to 4 gpm(7.5 l/min). The valve plunger has a small permanent magnet embedded in it. It is held open by a similar mag-net, fixed in the body of the valve. When the flow through the valve increases sufficiently, the Bernoulli effect

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reduces the pressure in the valve outlet; lowered pressure increases the axial force on the plunger, the mag-netic attraction is overcome, and the valve snaps shut.

Fig. 11. An excess flow check valve in a fuel, hydraulic or lube oil line. (MGM)

Fig. 12. Magnetic excess flow check valve. (CTE Chem-Tec)

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The operating temperatures of excess flow check valves are usually specified below 200°F (93°C). How-ever, if a valve contains no non-metallic component, this temperature limit can be raised substantially. Somevalves are fabricated entirely of stainless steel, permitting operation up to 800°F (425°C) or higher. The tem-peratures around the lubrication and hydraulic lines would normally be in about of 100°F (38°C) because per-sonnel have access to these areas, and adequate cooling or ventilation is needed.

The load tunnel of an enclosed installation (the space between the exhaust duct and the generator compart-ment), is frequently too hot for human entrance (possibly as high as 300°F [150°C]). The fuel manifold andpigtails are close to the engine casing, although not at the hottest station. These are more difficult to coolby means of the ventilation system; the temperature could reach 250°F (120°C) in this area.

5.2 Excess Flow Shutoff Valves

An excess flow shutoff valve performs the same function as an excess flow check valve, closing when flowincreases following a break in the line. Flow is sensed by pressure drop across an orifice, and the valveis actuated by differential pressure across a diaphragm. This type of valve is more complex than the excessflow check valves of Figures 11 and 12, since it relies on three springs, two pressure sensors, and adiaphragm.

Figure 13 is a cross-section of an excess flow shutoff valve. These valves are available in sizes from11⁄2 in (38 mm) to 8 in (203 mm) line diameter, and for working pressures up to 300 psi (2,070 kPa).

The valve illustrated in Figure 13 has an orifice downstream of the seat. The flow across this orifice is sensedby two pressure sensors on either side of the orifice. The sensed upstream and downstream pressures aretransmitted to the lower and upper sides (respectively) of the diaphragm shown; at a preset pressure dif-ferential (controlled by the adjusting stem and control spring) the diaphragm deflects upward, disengagingthe latch lever, and allowing the valve to snap shut under the force of the disk arm spring.

5.3 Pressure Type Emergency Shutoff Valves

The valves discussed in Sections 5.1 and 5.2 rely on excess flow to trigger operation. They are effectiveonly in systems where flow can increase from a downstream break. Frequently lubrication and fuel sys-tems in gas turbine installations employ constant displacement pumps. The flow can never increase abovethe capacity of the pump at a given speed. In such systems, pressure type emergency shutoff valves maybe used to respond to a downstream break.

Figure 14 is a cross-section of a pressure type emergency shutoff valve. The sensing tube detects a dropin downstream pressure arising from a line break or separation, and transmits it to the upper face of a dia-phragm. The spring diaphragm deflects upward against the force of the control spring, and pivots the latchlever, releasing the valve disk. The disk then swings against the valve seat, shutting off flow. The activationpressure is controlled by the preload in the control spring.

5.4 Arrangement of Excess Flow Check Valves in a Gas Turbine Lubrication System

Figure 15 shows where excess flow check valves should be installed in gas turbine lubrication circuits forbasic protection of the system. Basically, they would be installed at the entrance to each branch line in thepressure system. If a line separates, say, at a bearing, that line will be closed off automatically. Oil will con-tinue to flow normally to the remaining bearings and other equipment while the machinery trips off line anddecelerates to turning gear operation. This provides maximum protection to the bearings and journals, andprevents a spray fire. The bearing supplied by the broken line will be wiped, of course, but it would be lost inany case.

Thermocouples should be installed in the bearing liners of turbine installations using excess flow check valves.The thermocouples should be set to trip the unit automatically at 240-250°F (115-121°C). Then, if a linebreaks, or if an excess flow check valve closes accidentally, and a bearing becomes starved of oil, the unitwill be tripped, and bearing damage will be minimized.

Some oil spray fires involve leakage from the oil coolers or the filters. Figure 15 illustrates a method of shut-ting off the flow in the event of such accidents. Coolers and filters are installed in duplicate. A 3-way trans-fer valve directs oil flow to of the units, as desired. One unit is always inactive, and can be maintained or

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cleaned as necessary . The other is on line. Figure 15 assumes a motorized transfer valve that can be actu-ated by the pressure switch in the main pressure oil header, downstream of the cooler. If, as has hap-pened, a cooler tube becomes loose during cleaning, or the cover of a filter is inadvertently loosened, a largeleak will occur in that branch. The excess flow check valve installed in that branch will close, and the low-ered delivery pressure downstream will be sensed by the pressure switch. The unit will trip, and the auxil-iary oil pump will be energized. At the same time, the transfer valve will be actuated to switch flow over tothe inactive cooler (or filter, if applicable), and lubrication will continue during the trip sequence. The inter-ruption of lubrication will be minimal.

There are other locations for excess flow check valves in such a system, notably in lines to thermometersand pressure gages, which have been involved in very serious fires. A line should be protected if a studyshows that a leak of 2 gpm (7.5 l/min) or higher can occur if the line breaks. Such a leak can produce a4 MW fire at 100% combustion efficiency.

5.5 System Design for Excess Flow Check Valves

Manufacturers of excess flow check valves caution users that these valves are not ‘‘drop-in devices.’’ Theymust be carefully engineered for each installation. A lubrication system must be treated as a whole, recog-nizing pump characteristics, pressure regulator characteristics, pressure line sizes and restrictions, toler-ances and bearing orifice sizes. The redistribution of flow in the various branch lines resulting from likely

Fig. 13. Excess flow shutoff valve. (Maxitrol)

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alterations of conditions in the system, such as changes in internal pipe surface roughness and wear of ori-fices, must be determined. The maximum possible normal operating flow in each branch line must be deter-mined so that the valves can be set to flows just slightly higher than the maximum, and will not close underany normal operating condition.

When setting valve closing flow, the phenomenon of ‘‘chatter’’ must be considered. Chatter is a rapid clos-ing and opening of the valve. It occurs when the flow through the open valve approaches the closing flow, atwhich time the valve closes and stays closed. The difference between the maximum flow rating — at whichpoint the flow is steady and uninterrupted — and the closing flow, is the chatter range. The chatter rangemust be added to the maximum possible normal flow when establishing the required valve closing flow.

In general, manufacturers recommend setting the minimum valve closing flow about 10% above the maxi-mum operating flow to account for chatter. This tolerance can be reduced if the actual chatter range for a givenvalve is known.

Fig. 14. Pressure type emergency shutoff valve. (Maxitrol)

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Viscosity of the oil also affects the closing flow of a valve to some extent. The range of possible tempera-tures of the oil and the corresponding range of viscosities must be taken into account in design of the system.

Following are the basic design requirements for an excess flow check valve in a lubrication system:

• The minimum closing flow must be at least 10% higher than the maximum possible normal flow in theline.

• The valve must remain closed under minimum auxiliary pump pressure.

The lowest reasonable tolerance on closing flow should be used. This requirement ensures valve actuationfor partial line breaks or small leaks that could produce a serious fire. Relatively few significant fires resultfrom partial line breaks or small spray leaks from flanges or seals. Fires resulting from such leaks would beexpected to widen the leak rapidly.

Nevertheless, close tolerances on closing flows, compared to normal industry practice, should be used forgreatest effectiveness of excess flow check valves. The preset activation flow of a valve could reasonablyhave a tolerance of (± 5%). Then the preset flow could be set 5% above the desired actuation flow to pro-duce a tolerance on that value of (-0% to +10%). When this valve tolerance is added to the chatter allow-ance, the closing range would vary from +10% to +20% above the maximum operating flow in the line.

Fig. 15. Arrangement of excess flow check valves in a gas turbine lubrication system.

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5.6 Reliability of Excess Flow Check Valves.

In 1995 FMRC completed a study of excess flow check valve reliability8. The study focussed on two areas:

1. The valves will prevent fire in case the protected line breaks

2. The valves will not close accidentally during normal operation.

The study assumed a complete gas turbine lubrication system was equipped with valves. The effects of fail-ures in the lube system on the operation of the valves, as well as of design defects and improper installa-tion, were taken into account. The study allowed a 3-year period for overhaul, bench testing and refurbishmentof the valves, as recommended in this data sheet.

The conclusions of the study were:

1. The estimated probability of a VFO (valve fails open) incident in 3 years was 1 in 2000 installations, fora failure rate of 0.02/million hours. This rate is categorized as Highly Reliable by Atomic Energy of Canada,Ltd9.

2. The estimated probability of a VFC (valve fails closed) incident in 3 years was 1 in 250 installations. Thefailure rate is 0.15/million hours. A rate of 0.1/million hours is categorized as Highly Reliable.

The most significant contributor to a VFC in the study was the failure of the diaphragm in the pressure regu-lator. The probability of failure of the weld attaching the diaphragm to the plunger, allowing an increase in out-let pressure, was estimated to be 0.0026 in the specified 3-year period between inspections. This probabilitywas arrived at very conservatively using a Department of Defense database on frequency of failure of weldedjoints in nonelectronic parts. The database included no instance of the failure of such a welded joint, so thepopulation of welded components and the total hours of use were combined to arrive at a maximum valueof probability of failure; that is, it was assumed that the first instance of failure was imminent.

6.0 APPENDIX B

6.1 Fine Water Spray (FWS) Systems

It is well established that conventional sprinkler and water spray systems will control and extinguish hydro-carbon pool fires. However, hydrocarbon spray fires constitute the greatest hazard in gas turbine installa-tions, and conventional sprinkler protection systems are ineffective against such fires. The limitations of water-based, protective systems has led to the development of systems using fine water sprays and mists (FWSsystems). These systems extinguish spray fires in two ways:

1. Oxygen displacement: a blanket of steam is produced over or around the fire, displacing the air, and reduc-ing the oxygen available for combustion

2. Flame cooling: the fine droplets are entrained within the spray, thereby cooling the burning mixture offuel and air to a level at which combustion is not sustainable

The fine sprays or mists are produced in various ways. Water is ejected through a nozzle, sometimes with air-assist, at pressures varying from 10 to 300 bar. Average droplet sizes vary from 0.002 in. (50 microns) to0.016 in. (400 microns).

6.2 Description of Fine Water Spray Systems

Fine Water Spray (FWS) extinguishing systems protect gas turbines housed in well-sealed enclosures whosedoors and openings are kept closed while the gas turbine is operating. These enclosures have forced draftventilation systems that can be shut off when the FWS system is actuated, with simultaneous automatic clos-ing of the ventilation openings, and of the enclosure doors.

The FWS fire suppression system consists of fire detectors (heat or ultraviolet), a control panel, a water res-ervoir and air cylinder, water and air piping, and banks of nozzles. Figure 16 shows how the piping is arrangedin a gas turbine enclosure. Heat detectors installed in the ceiling have fire ratings determined by the nor-mal operating temperature in the enclosure. Water spray nozzles are installed in two banks on each side of

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the gas turbine. One is installed in the ceiling of the enclosure. The other runs along the wall at a distanceof about 3 ft (0.9 m) above the floor. The latter is directed at fires under the turbine that may be shieldedfrom the overhead nozzles.

Figure 17 illustrates a typical arrangement of water reservoir and air cylinder. The solenoid valve on the air cyl-inder is actuated by the fire detection system. Air then pressurizes the water tank and provides the motiveforce to deliver water through the piping to the gas turbine enclosure. Additional air passes through the pip-ing to the enclosure, as illustrated in Figure 16.

Figure 18 illustrates a typical spray nozzle. Air discharges through the central orifice, while water dis-charges through the outer ring of orifices. In other designs, the reverse is the case.

6.3 Requirements of a Fine Water Spray (FWS) System

An FWS system must extinguish a hydrocarbon spray fire before the target of the spray fire (e.g., the gas tur-bine, a major auxiliary system, or the building or enclosure) has been damaged significantly by direct flameimpingement or radiated heat. The system must accomplish this even if the spray fire is shielded from thedirect trajectory of the water spray. The water spray or mist must not damage the gas turbine by cooling thehot casing.

6.4 Hazard of Direct Impingement of Water Spray on a Hot Casing

Gas turbines can be damaged significantly if water spray impinges directly on the hot casings during opera-tion. Section 4.1.3.3 describes a gas turbine loss in which the turbine blades were severely rubbed fromrepeated, accidental discharges of a deluge system on the turbine casing. Other similar events have occurred.

Fig. 16. Layout of fire detectors, piping, and nozzles in an FWS system.

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Sprinkler discharges have also occurred without damage to the gas turbine, as in the loss described in Sec-tion 4.1.1.3, in which the sprinklers discharged on the operating gas turbine casings, in response to a fire,with no evidence of casing damage. However, in that case, the turbine had been operating at substantiallyreduced power for five minutes at the time of the incident. The internal clearances are significantly increasedat such lowered power settings. At maximum power, the operating radial clearance in an industrial gas tur-bine can be as low as one-thousandth of the diameter. This would permit contact between the casing andthe blades at an easily achieved level of radial case deflection due to unsymmetrical cooling.

Figure 19 shows the results of a study of the radial deflections due to water spray discharge on the hot gasturbine casing described in Section 4.1.3.3. The loss report indicates that the water discharged on the topof the casing, presumably over an angle of 90°. The clearance data were measured when the gas turbine wasassembled, and again after the loss.

The radial-deflection and clearance data are presented as fractions of the casing radius. The range of clear-ance ratios at operating conditions is typical for all gas turbines, since manufacturers try to minimize thisratio in the interest of optimum performance.

Figure 19 shows three things:

1. The range of operating clearance ratios (∆R/R) over the turbine section of the gas turbine involved inthe loss based upon the tolerance band of assembly clearances;

Fig. 17. Arrangement of water reservoir and air cylinder for FWS system. (Securiplex)

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2. The range of casing deflection ratios (∆R/R) due to deluge system spray impingement in the loss. The oper-ating clearance ratios (maximum and minimum) were subtracted from the blade-to-casing clearances mea-sured after the loss, to determine the range of blade rubbing; this range was then added to the operatingclearances to determine the maximum and minimum casing deflections around the circumference.

Fig. 18. Typical nozzle for a Fine Water Spray (FWS) system.

Fig. 19. Variation of hot-casing deflection with impinging droplet size.

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3. Calculated radial deflection ratios (∆R/R) at two typical values of spray density (0.15 gpm/ft2 [6 mm/min]and 0.2 gpm/ft2 [8 mm/min]), and at two values of average spray droplet size (500 and 1000 microns).

The data are given in terms of radial deflection per unit casing radius (∆R/R), for the casing radius/thickness ratio involved in the loss. These data can be considered valid for all industrial gas turbines hav-ing corresponding radius-to-thickness ratios. Radial deflection ratios are approximately proportional to radius-to-thickness ratio. Figure 19 shows that conventional spray systems employing conventional droplet sizescan damage gas turbines if they are discharged directly on the hot turbine casing, and the calculations showthat a density of 0.15 gpm/ft2 (6 mm/min), with droplet sizes above 300 microns, could produce the radialdeflections observed in the referenced loss.

However, the downward trend of deflection ratio with droplet size indicates that fine water spray systemswith droplet sizes in the 50-100 micron range could possibly be safe, and this has provided encourage-ment to Factory Mutual to support the development of such systems for extinguishment of hydrocarbon sprayfires in gas turbine enclosures. At the same time, such development must assure that FWS systems sat-isfy a criterion that limits the maximum heat transfer from the spray to the turbine casing to prevent exces-sive case distortion.

7.0 APPENDIX C

7.1 Reignition in Gas Turbines after Flameout

If a flameout occurs in a gas turbine, the flow of fuel must be shut off very quickly. If fuel continues to flowfor a period greater than the autoignition delay time of the particular fuel in use, it will reignite in an uncon-trolled manner.

7.1.1 Autoignition Delay Time

The autoignition delay time depends on the operating temperature and pressure. Figure 20 shows a set ofautoignition curves for No. 2 fuel oil10.

In a typical industrial gas turbine with a pressure ratio of 10:1, the temperature of the combustor baskets, tran-sition ducts, and turbine flowpath surfaces (exclusive of the blading, which will operate hotter) will exceed1,000°F (550°C). If flameout occurs, these surfaces will cool off and the pressure will drop. Figure 20 showsthat, if the temperature and pressure drop to the values of 740°F (395°C) and eight atmospheres, reignitionwill occur in 750 ms unless the fuel is shut off. It is not known how the pressure and temperature vary aftera flameout. Clearly, however, the highest available technology should be used to cut off the fuel as rapidly aspossible.

The location of reignition is a function of the autoignition delay time. This, in turn, depends on the tempera-ture and pressure in the combustor, on the velocity of airflow through the combustor, and on the length ofthe combustor. The length divided by the velocity is the residence time, i.e., the time a droplet of fuel takesto flow through the combustor. If the residence time is greater than the autoignition delay time, the ignitiontakes place in the combustor; if not, the ignition is downstream. In the former case, an explosion may occur,because the flow through the turbine nozzles is choked in normal operation; they provide a restriction, there-fore, to the passage of shock waves, and turn the combustor section into a partially closed chamber. In thecase history described in Section 4.2.2.2, the combustor and transition U-tube were unusually long, and igni-tion took place within them.

If the autoignition delay time is greater than the residence time, ignition will take place somewhere in the tur-bine section or the exhaust. The burning fuel-air mixture is not confined, and a fire with a well-defined flamefront at some axial position is the usual outcome. Blades and vanes upstream of the flame front are notburned, although they may be damaged by radiative heat.

7.1.2 Cutoff of Fuel after Flameout

The cutoff of fuel involves three steps:

1. Sensing flameout

2. Detecting flameout signal by the control system, and transmitting signal to the fuel shutoff valve

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3. Closing fuel shutoff valve.

Flameout is sensed by flame detectors mounted on the combustor casing and aimed through an openingin the combustor liner at the flame. Figure 21 shows an ultraviolet flame detector suitable for this applica-tion. This detector can sense the absence of flame in 200 ms. Two such devices are usually installed at thetop two combustor cans, or at the top of single can or an annular combustor. The sensors are driven throughan amplifier by d.c. voltage. When the sensor is excited by a source of ultraviolet radiation it transmits pulsesof current at a frequency corresponding to the intensity of the radiation source. These pulses are inte-grated in the amplifier which provides an output signal of zero voltage for flame and plus voltage for no flame.

Each of the two flame detectors produces a signal at one of the two output terminals of the amplifier. Thesesignals are transmitted to a programmable controller that scans the inputs and makes an appropriate deci-sion. If both inputs provide a zero signal (indicating that both detectors are showing flame) no action is taken.But if only one input is plus, an alarm is actuated; if both inputs are plus (indicating flameout at both detec-tors) the fuel valve instantaneously closes. This voting arrangement avoids spurious trips that could occurif one sensor is affected by something extraneous, if its quartz lens is clouded by smoke, or if it becomes inop-erative. The input logic is typically scanned eight times a second. This means that it could take 125 ms todetect a flameout.

The third phase of fuel cutoff closes the fuel stop valve. This valve may be up to 4 in. (10 cm) diameter for liq-uid fuels and up to 8 in. (20 cm) for gaseous fuels. In older gas turbines it is a two-position oil-relay type.It is normally closed (NC), and hydraulic pressure opens it on startup and holds it open during operation. Whenemergency shutdown is required, a relay-operated solenoid valve dumps the hydraulic fluid to drain, andthe stop valve closes under spring load. A 3 in. (7.5 cm) valve closes in 300 ms. The complete sequence fromflameout to fuel cutoff takes 625 ms, plus possibly 50 ms to transmit the signals.

Fig. 20. Effects of temperature and pressure on minimum autoignition delay time of No. 2 fuel oil.

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In current installations, the fuel stop valve is usually a solenoid valve. It should be normally closed, that is, itopens when the solenoid is energized and closes under spring load when de-energized.

It is possible to design a 3 in. (7.5 cm) semidirect lift internal pilot valve to close in 100 ms with liquid fuel.It is estimated that an 8 in. (20 cm) internal pilot valve should close in 200 to 250 ms with gaseous fuel.

It is, therefore, possible to detect flameout, evaluate the decision logic, and cut off the fuel flow to the com-bustor in less than 750 ms, even in the largest gas turbines. In smaller machines, it may be possible toachieve this in 500 ms. According to Figure 20, an autoignition delay time of 750 ms corresponds to a fuel tem-perature of 740°F (394°C) at 8 atmospheres, while a delay time of 500 ms corresponds to a temperatureof 760°F (405°C). Such a difference in what might be called an allowed temperature is not significant; the goalof having the fuel shutoff in 750 ms after flameout (as specified in Section 2.3.1) is attainable and shouldbe adopted.

8.0 APPENDIX D

8.1 Less Flammable Lubricants and Hydraulic Fluids

The use of fire resistant lubricants in gas turbines and other turbomachinery has been promoted for manyyears but the lubricants have not become widely used for a number of practical and economic reasons, forinstance:

1. Cost of the lubricants

2. Cost of converting lubrication and hydraulic systems to use less flammable fluids

3. Converting lubricating and hydraulic systems for use with phosphate esters involves replacing all elas-tomers with synthetic materials

4. Toxicity, requiring special handling

5. Emulsification with water, requiring special treatment

6. Ecotoxicity, requiring special recovery methods

Fig. 21. Flame detector and amplifier. (Honeywell)

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Some synthetic fluids have been developed to overcome some or all of the above concerns. However, theprincipal issue is their flammability. They do have higher flash points and autoignition temperatures thanmineral-based fluids which possibly eliminates the pool-fire hazard; however, concerns exist about their flam-mability in spray form. It is known that sprays of these fluids can ignite, but they may not sustain combustion.

Factory Mutual developed a test method and approval protocol to classify these fluids as to spray flamma-bility. Less flammable lubricants and hydraulic fluids are classified by Spray Flammability Parameter (SFP)11,given by

SFP = Chemical Heat - Release RateDe

. (Critical Heat Flux for Ignition)

The term De is the equivalent diameter of the nozzle used in the tests.

The acceptability criterion is SFP below 20 x 104, using the nomenclature of the test method; this value wasadopted as the dividing line between the ability and inability of fluid to sustain ignition in a high pressurespray. In view of the significance of spray fires in gas turbine installations, only lubricants and hydraulic flu-ids that are FM-Certified (i.e., meet the SFP criterion) should be used in gas turbine systems without addi-tional fire protection. Fire protection for a fuel oil system is still necessary.

For comparison, the SFP of mineral oil is 60 x 104.

9.0 APPENDIX E

9.1 Clean Extinguishing Agents

With the phaseout of Halons 1301 and 1211, much research has been devoted to developing alternativeagents for extinguishment of Class B fires, that would have a suitably low ozone depletion potential (ODP).Carbon dioxide is such an agent, but it can be highly toxic for humans in the concentration needed for extin-guishment, and many gas turbine users are reluctant to use it. NFPA 20012 has identified a number of suchclean agents, three of which are currently FM-Approved. The approved agents are Inergen — an inert gas;and FM-200 and FE-13 — both halocarbons.

9.1.1 Inert Gas Clean Agents

Table 12 summarizes the makeup of the gases in an enclosure after release of inerting agents in the requiredconcentrations. NFPA 2001 recommends a safety factor of 20% for extinguishment, and a factor of 10%for continued inerting during the period of extended discharge.

Table 12. Makeup of Atmospheres Produced by Inerting Agents in Extinguishment Concentrations

Carbon DioxideCO2

Inergen52 N2, 40 Ar, 8 CO2

Extinguishing Concentration Initial concentration 28.57 41.83Oxygen 15 12.21Ambient CO2 28.6 3.36

Design extinguishing concentration(20 safety factor)

Initial concentration 34 47.84Oxygen 13.86 10.95Ambient CO2 34 3.84

Extended discharge (inerting) concentration(20 safety factor)

Initial concentration 31.43 46.10Oxygen 14.35 11.6Ambient CO2 31.4 3.6

The Environmental Protection Agency has the following requirements to assure human safety12 :

• Upper limit on CO2 concentration: 5%;

• Lower limit on oxygen concentration: 10%.

The following levels of hazard are due to oxygen12:

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• Oxygen concentration below which symptoms develop: 15%;

• Tolerable oxygen concentration range for a short period: 12-14%

• Concentration below which marked symptoms develop: 10%.

Carbon dioxide installations have a time delay between detection of a fire and discharge of gas. A pre-discharge alarm warns any occupants of the gas turbine enclosure and allows time to evacuate. This is nec-essary because of the large concentration of CO2 that would develop. Inergen would not produce such alarge concentration, but the resulting oxygen level could produce some symptoms. NFPA 2001 recom-mends that installations having the oxygen concentrations shown in Table 13 for Inergen12 also have a timedelay, pre-discharge alarm, and provisions to permit rapid evacuation of an enclosure.

Inergen is stored as a gas at 150 atmospheres, in contrast to CO2, which is stored as a liquid at 60 atmo-spheres in high pressure systems. Large quantities of Inergen agent are required for extinguishment of fires.Fire protection systems using Inergen, therefore, are expected to be bulky and expensive.

Another concern with Inergen is noise of discharge when such a large quantity of agent must be dis-charged rapidly.

9.1.2 Halocarbon Clean Agents

Halocarbons function by chemical reaction with the free radicals in the flame; this results in flame inhibi-tion. However, the chlorides and fluorides, particularly HF (hydrogen fluoride), produced are highly toxic. Thequantity produced will be 5 to 10 times that produced by the decomposition of Halon. Table 13 gives somesignificant data on the two approved halocarbons, with corresponding data for Halon 1301 for compari-son. The environmental factors ODP and GWP are relative to a fluorocarbon compound CFC-11.

FM-200 and FE-13 have no ozone depletion potential. FE-13 has a high global warming potential, and the life-time of the decomposition products after extinguishment is 280 years. These factors may militate againstits use. FM-200 seems to be much more benign than even Halon 1301, but the low GWP may be offset bythe fact that the rate of production of toxic compounds may be as high as 10 times greater. FM-200 has ahigh boiling point relative to Halon 1301 and FE-13; this is a practical disadvantage.

Table 13. Halocarbon Clean Extinguishing Agents12

Halon 1301 FM-200 FE-13Chemical Name Bromotrifluoro-

methaneHeptafluoro-

propaneTrifluoro-methane

Boiling Point -72°F(-57.5°C)

2.5°F(-16°C)

-115.7°F(-82°C)

PerformanceFactors

Extinguishing concentration 3.5 5.8 12Extinguishing concentration with 20 safety factor 5

(Minimumfrom NFPA

12A)

7 14.4

Inerting concentration with 10 safety factor 5(Minimumfrom NFPA

12A)

8.8 20.4

EnvironmentalFactors

ODP — Ozone Depletion Potential (Relative to CFC-11) 16 0 0GWP — Global Warming Potential (Relative to CFC-11) 0.8 0.45 13ALT — Atmospheric Lifetime (Years) 110 41 280

Toxicity Factors LOAEL — Lowest Observed Adverse Effect Level () 10.1 10.5 >30NOAEL — No Observed Adverse Effect Level () 7.5 9 30

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10.0 GLOSSARY

10.1 Glossary of Terms

This section explains some unfamiliar terms and concepts used throughout the data sheet. Generally themeaning of these terms may be derived from the context in which they are used. They are defined here forconvenience.

Acceptance: Confirmation by FM that equipment, materials or systems installed at a given location are suit-able for their intended use. Accepted equipment, materials or systems may be FM-Approved, listed byanother testing agency, or unlisted. Usually such equipment, materials or systems are acceptable to theauthority having jurisdiction (the organization, office, or individual responsible for the installation).

Approval: Listing by FM in its Approval Guide. FM-Approved equipment has been examined and inspectedby FMRC technicians and engineers, and has been found to satisfy FM Approval Standards and recog-nized national and international requirements.

Clean extinguishing agent: Nonconducting volatile or gaseous fire extinguishing agent that does not leavea residue upon evaporation.

Enclosed installation: A gas turbine installation in which all major components and systems (except thedriven machine) are housed in a single enclosure (q.v.) for protection from the weather. Sometimes referredto as a package installation, because it is arranged on a structural skid for transportation as a unit.

Enclosure: A housing (usually metal) around a gas turbine and its installed auxiliaries, that can be sealedoff to prevent the escape of a total flooding extinguishing agent in the event of a fire.

Excess flow check valve: A valve in a lube oil, hydraulic fluid or liquid fuel line, held open by a spring, thatcloses automatically when flow-induced pressures produce a load on the valve head in excess of the springpreload. The flow at which this occurs is the closing flow. Excess flow check valves are also known as veloc-ity fuses and flow limiting valves.

Excess flow shutoff valve: A valve in a lube oil, hydraulic fluid or liquid fuel line, held open by a latch, thatcloses automatically when the differential pressure across an orifice in the line downstream of the valve seatdeflects a diaphragm sufficiently to trip the latch. The flow at which this occurs is the closing flow.

Fine water spray (FWS) system: A fire extinguishing system in which multiple spray nozzles discharge direc-tional fine water sprays under high pressure, or by air atomization, into a fire having a high heat releaserate. The system produces significantly smaller water droplets than those generated by automatic sprin-klers, and extinguish large, hot fires (including spray fires) faster and more effectively, because the smallerdroplets vaporize and extract heat more rapidly from the flames. Gas turbines protected by FWS systemsmust be in enclosed installations (q.v.).

Flameout: General loss of flame in a gas turbine combustor, possibly because of restriction in the fuel linesto the combustor section or a control malfunction that reduces fuel flow below the lower limit of combustion.

Gaseous, total flooding system: A fire extinguishing system that relies on filling an enclosure with a vola-tile or gaseous extinguishing agent, and maintaining the extinguishing concentration within the enclosure untilthe fire is extinguished and conditions will not permit reignition.

Gas turbine installation: The arrangement of a gas turbine and its driven machine (usually an electric gen-erator or compressor) in a facility. The installation is usually understood to include a lubrication system forthe machinery bearings, a hydraulic system for certain control and protective functions, liquid fuel and gas-eous fuel conditioning and delivery systems, a fire protection system, switchgear and a control room. Theair intake and filter, including silencer and air cooling system, and the exhaust duct and silencer, are part ofthe installation.

Halocarbon clean agent: An extinguishing agent constituted of organic compounds containing fluorine, chlo-rine, bromine or iodine.

Inert gas clean agent: An extinguishing agent constituted of the inert gases argon, nitrogen, helium or neon.A blended agent may also include carbon dioxide.

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Lagging: The term ‘‘lagging’’ refers to a covering or enclosure of some kind designed to shield the hot sec-tion of a gas turbine from external factors, such as other equipment, water discharge, or simply the environ-ment, and to keep personnel from accidental contact with the hot section while the turbine is operating.Lagging may consist of metal-covered, insulating blankets around the casing, or a metal or wooden enclo-sure surrounding the turbine section. Another term used is ‘‘shielding.’’

Less flammable fluid: A lubricant or hydraulic fluid that is unable to stabilize a spray flame, and is classi-fied as Group 1 according to the FM Specification Test Standard for Flammability of Hydraulic Fluids Class6930. Mineral oil is classified as Group 3 according to this standard.

Partly enclosed installation: An installation in which one or more gas turbine auxiliary system(s) (lubrica-tion, hydraulic, fuel, etc.) are outside the gas turbine enclosure. The auxiliary system(s) may have a sepa-rate enclosure(s), or be unenclosed.

Pressure-type emergency shutoff valve: A valve in a lube oil, hydraulic fluid or liquid fuel line, held openby a latch, that closes automatically when the pressure downstream of the valve seat is reduced suffi-ciently, as a result of a downstream leak or break, to cause a diaphragm to deflect and trip the latch.

Skid: A structural steel base on which a gas turbine and/or its auxiliary components are mounted. It maybe enclosed or unenclosed.

Unenclosed installation: A gas turbine installation, usually in a large building and possibly part of a mul-tiple installation, without individual weatherproof enclosures for any of its auxiliaries or components.

11.0 REFERENCES

11.1 Specific References

1. Structural Integrity during Fire, NFPA Fire Protection Handbook, 14th Edition, 1976, Chapter 7, Table 6-7V

2. NFPA 2001 Clean Agent Fire Extinguishing Systems

3. NFPA 12A Halon 1301 Extinguishing Systems

4. NFPA 12B Halon 1211 Extinguishing Systems

5. NFPA 70 National Electrical Code

6. Peaking Unit Fire Prevention and Protection, Edison Electric Institute, 1981

7. Sprinkler and Waterspray Tests on Turbine Oil Fires, Mr. Nils-Erik Gustafsson, Industrieforsakring, Nr. 4,Helsingfors, Finland, 1980

8. Reliability of Excess Flow Check Valves in Turbine Lubrication Systems, Robert E. Dundas,PWR-Vol. 30, Joint Power Generation Conference, Volume 2, ASME 1996, pp. 219-230

9. Machinery Reliability Assessment, Bloch, Heinz P. and Geitner, Fred K., Van Nostrand Reinhold, 1990

10. Spadaccini, L.J., Autoignition Characteristics of Hydrocarbon Fuels at Elevated Temperatures andPressures, Journal of Engineering for Power, Trans. ASME, January, 1977, pp. 83-87

11. FM Specification Test Standard for Flammability of Hydraulic Fluids Class 6930.

12. Review of Total Flooding Gaseous Agents as Halon 1301 Substitutes, Joseph Z. Su, Andrew K. Kim,Jack R. Mawhinney, Journal of Fire Protection Engineering, 8 (2), 1996, pp. 45-64.

11.2 Related Data Sheets

Data Sheet 4-8N Halon 1301 Extinguishing Systems

Data Sheet 4-11N Carbon Dioxide Extinguishing Systems

Data Sheet 5-32 Electronic Data Processing Systems

Data Sheet 5-48 Automatic Fire Detectors

Data Sheet 7-83 Drainage Systems for Flammable Fluids

Fire Protection for Gas Turbine Installations 7-79Factory Mutual Property Loss Prevention Data Sheets Page 47

©1997 Factory Mutual Engineering Corp. All rights reserved.

Page 48: Fire Protection for Gas Turbines

Data Sheet 7-91 Hydrogen

Data Sheet 7-93N Aircraft Hangars

Data Sheet 13-17 Gas Turbines

FM Engr. Comm. April 1997

7-79 Fire Protection for Gas Turbine InstallationsPage 48 Factory Mutual Property Loss Prevention Data Sheets

©1997 Factory Mutual Engineering Corp. All rights reserved.


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