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Experience Regarding Conformity With Regu-latory Codes in the Planning of Gas Turbine (GT)Installations With Downstream Heat RecoverySteam Generators (HRSG)

H. Chr. Schröder, H. Engesser, G. Scheffknecht, and H. Stierstorfer

Power Generation and Engineering Services of TÜV SÜD

SPECIAL PRINT VGB KraftwerksTechnik79. volume, issue 4/99, page 36-42

Power Generation and Engineering Servicesof TÜV SÜD

Services of the TÜV SÜDPower generation and plant services

VGB PowerTech 4/99 3

Introduction

This contribution shows problems that arisein the practical application of the pertinentsafety codes, particularly in combined-cyclepower plants, i.e. gas turbine plants withdownstream HRSG (heat recovery steamgenerators). These problems are encounteredin the following areas:

— the venting and purging of the flue gasducts,

— flame monitoring, and

— trails in ignition times.

Several different aspects are to be consideredin deciding to build a combined-cycle powerplant. These include, for example, the reduc-tion of the CO2 emissions, the high efficiencyof the facility, fast start-up times, high flexi-bility of operation, short construction time,low expenditure on investment, and possibil-ities for re-powering existing facilities.

In Germany, the TRD’s (Technical Rules forSteam Boilers) of Series 400 apply, the spe-cific code depending on the fuel beingburned. TRD 411 and 412 apply for the usualfuels burned in gas turbines, heating oil ELand gas respectively. TRD 411 calls for a

purging of the flue gas paths with at least50 % of the combustion air flow at full loadover a period of time long enough to producea three-fold air exchange in the flue gas vol-ume being purged.

The volume flows in the gas turbine com-pressor are dependent not only on speed:They are subject to limits due to the start-uppower of the starting device and to bladingvibrations. For this reason, it is not alwayspossible to satisfy this provision of TRD 411.

Combustion in the gas turbine GT 24/GT 26of ABB takes place in sequence: a first com-bustor with a high-pressure turbine, followedby the second combustor with a low-pressureturbine. For the flame monitoring in the sec-ond combustor of a gas turbine (sequentialcombustion), the inlet temperature is thecritical factor inherently determining thecombustion. For the second combustor then,a temperature monitor can be used instead ofthe optical flame monitor called for in thecodes since, in this range of temperature,there is no ensuring that optical flame moni-tors will recognize the flame with certainty.F i g u r e 1 shows the design of the first andsecond combustors in an ABB gas turbine ofmodern design.

The processes of filling the fuel supply linesand cross-ignition of the burners in moderngas turbines with annular combustors meanthat a greater amount of time is required be-fore the flame is burning safely. It is not pos-sible here to maintain the trail in ignitionperiod required according to the TRD be-tween the opening of the shut-off device (tripequipment) and activation of the opticalflame monitor.

This leads to questions in connection withpurging the flue gas paths, flame monitoring,and trail in ignition times when applying theTRDs.

In the following, we present possible solu-tions for dealing with these topics safely, i.e.for ensuring a high degree of safety in theprocess while still maintaining the high avail-ability demanded of gas turbine plants, andfor fulfilling the safety standards called for inthe codes with the use of plant components

that are normally there, without requiring anadditional fresh air fan.

Purging of Combined-Cycle Plants

Requ i r emen t s i n t he Codes fo r t he Pu rg ing o f F lue Gas Pa th sin Combined -Cyc l e Power P l an t s

The procedures followed for purging theHRSG in combined-cycle power plants withand without a bypass stack can differ.

How much purging is needed results essen-tially from the requirements in the individualTRDs, such as, for example, TRD 411 forfuel oils and TRD 412 for fuel gases.

We are also familiar with two further systemsof rules from the USA and England, namelythe NFPA (National Fire Protection As-sociation) 8506 from the USA, and theguidelines from British Gas (Guidance Noteson the Installation of Industrial Turbines, As-sociated Gas Compressors and Supplemen-tary Firing Burners).

In America, the differences in operation anddesign between heat recovery steam gener-ators and conventional steam generators haveled to separate standards for HRSGs (NFPA8606). The current revision of the NFPAcalls for at least a 5-fold exchange of the gasturbine air at a rate of at least 8 % of themaximum mass through-flow. Alternativepossibilities are also offered for demonstrat-ing the effectiveness of the purging of theHRSG.

Proces s Techno log i ca l Requ i r e -men t s f o r t he Pu rg ing o fCombined -Cyc l e P l an t s

The maximum temperature of the purgingmedium during the purging process is limitedby the theoretical ignition temperature of thefuel being used. The ignition temperature ofordinary natural gas is on an order of ap-proximately 600 °C. Coal gas, as a mixture ofhydrogen and carbon monoxide, likewise hasan ignition temperature of approximately550 °C. Liquid fuels such as light heating oil(HEL) or naphtha are at approximately220 °C.

Experience Regarding Conformity WithRegulatory Codes in the Planning ofGas Turbine (GT) Installations WithDownstream Heat Recovery SteamGenerators (HRSG)By H.Chr. Schröder, H. Engesser, G. Scheffknecht and H. Stierstorfer

Dipl.-Ing. H.Chr. Schröder

TÜV Süddeutschland,Mannheim.

Dipl.-Ing. H. Engesser

ABB Power Generation Ltd.,Baden/Switzerland.

Dr.-Ing. G. Scheffknecht

EVT Energie- und Ver-fahrenstechnik GmbH, Stuttgart.

Dipl.-Ing. H. Stierstorfer

Siemens AG, Bereich Energieerzeu-gung (KWU), Erlangen.

For a relative safety margin from the theoret-ical ignition temperature, the maximum tem-perature for purging should provide a marginof approximately 20 % from the above-men-tioned temperatures, i.e., a margin of ap-proximately 100 °C for gas and ap-proximately 40 °C for oil.

In practice this means that, for gas turbinesfired on natural gas, it is possible to purgewith the exhaust flow, provided that the tem-perature of the flue gases remains far enoughbelow the ignition temperature of the givenfuel after taking into account any temperatureslopes and peak temperatures that might oc-cur. It must be noted, however, that naturalgas often contains among the components inits mix longer-chained hydrocarbons such aspropane, butane, etc., whose ignition tem-peratures are less than 600 °C. In order torule out even those uncertainties with regardto the venting temperature that result in con-nection with temperature peaks and lows, itis recommended not to purge with an exhaustgas temperature of more than 400 °C.

The situation is different when using liquidfuels. Here it is not readily possible to purge

the downstream units with the exhaust flowfrom the gas turbine because the exhaust gastemperature from the gas turbine is higherthan the ignition temperature of the liquidfuel. The possibility of explosions could notbe ruled out if there were any remnants ofunburned liquid fuel present in the HRSG.

In addition, it should be mentioned that thepertinent TRDs neither make any referenceto the air temperature nor do they indicatewhether the purging volumes are in terms ofmass flow or volume flow.

In actual practice, purging the gas turbineitself presents no relevant problem since thegas turbine, regardless of the operating con-dition from which the firing is begun, is auto-matically purged before every firing start.This means that no discussion is needed ofany renewed light-off after a malfunction inoperation or shutdown in operation.

The situation is different in the downstreamcomponents of the plant. The volume flowejected from the gas turbine is still present inthe downstream flue gas system and in theHRSG.

Due to the small volume flows in the gas tur-bine in its lower speed range while the com-pressor is being turned by the generator(turning operation), it is impossible toachieve a purging flow in the HRSG of morethan 50 % relative to the total flue gas flowproduced from the combustion. The purgingflows that can actually be attained underthese operating conditions lie at about 10 to15 % of the maximum compressor air massflow. Section “Verification of SuccessfulPurging” below shows this to be sufficientfor a safe purging.

Imp lemen ta t i on o f Pu rg ing P roces se s i n Combined -Cyc l ePower P l an t s

Necessity of Purging Combined-CyclePower Plants

It can be necessary to purge an HRSG in thefollowing cases:

— prior to commissioning,

— after a failed ignition (e.g., where theflame monitor has not taken over),

— following an interrupted start of the gasturbine after the ignition process,

— after an emergency trip from operationunder load.

The TRDs regulate the first of these cases ap-propriately. The TRD expressly allows dis-pensing with a purging of the flue gas pathsif a fail-safe monitoring of the fuel supplysystem has been provided.

While the next two cases urgently require apurging of the flue gas paths, the emergencytrip from load operation and even the ordi-nary shutdown require closer examination.

During an ordinary shutdown of the gas tur-bine, i.e., a shifting from operation underload to idling and a subsequent shutting offof the fuel supply, the flue gas system is ad-equately purged by the volume flow of ex-haust gas coming from the gas turbine while

4 VGB PowerTech 4/99

Temperature > 1000 °C

Sequential burner

Sequential combustor

Main burner

Main combustor

High pressure turbineLow pressure turbine

Figure 1. Sequential combustion. Cross-section through the hot gas path of the GT 26 gas turbine.

m = 80

25 s

0,0

50 s75 s

100 s125 s

150 s

kgs

gCH4

kg

Figure 2. Quality of the purging process at various points in time asfunction of the gas concentration.

m = 40 m = 160

50 s 12,5 s

0,0

150 s 37,5 s250 s 62,5 s

kgs

kgs

gCH4

kg

Figure 3. Results of the purging from Figure 2, but with the purgingmass flow doubled or halved respectively.

it is running down. In this operating status,any fuel/air mixture that might be present istoo lean for ignition. Another favourable fac-tor is that, in this process of shutting downthe gas turbine, no fuel can get into theHRSG unburned since the fuel trip valves areclosed when the output is low. As a result,the flame still present will extinguish due to alack of fuel.

Even in case where the trip valves closeduring operation under load, it can be as-sumed that the amounts of fuel still present inthe supply lines to the burners will be burnedand the flame will go out due to a lack offuel. In order to preclude any risk that mightremain here, it is recommended that theHRSG be purged using the starting converterwhenever the gas turbine drops out from op-eration under load, as called for in TRD 411and TRD 412 (a shutdown due to an emerg-ency trip is the equivalent of an “unplannedoperation”).

One must check on a case-by-case basiswhether an adequate purging can be achievedusing the volume flow forwarded during therun-down of the gas turbine.

When the unit is restarted, for example,during a hot start of the unit, the temperatureswithin the HRSG can be higher than the ig-nition temperatures of the liquid fuels com-monly used. For that reason, the purging ofthe HRSG and the cooling that results there-from must be carried out, among other rea-sons, in order to drop below the critical ig-nition temperature.

Whenever the gas turbine plants are beingoperated exclusively on natural gas, it is pos-sible, after consultation with all those in-volved (the customer, governmental authori-ties, inspection authorities, and the supplier)to dispense with a separate purging if it canbe verified that the HRSG will be purged ad-equately during the run-up of the gas turbine,and the maximum flue gas temperatures willhave a sufficient safety margin from the per-tinent ignition temperatures.

Further sources of ignition, such as sparkingwithin the gas turbine due to mechanical rub-bing on the hot metal surfaces during thestart-up phase and possible static chargesmust also be included in the considerations ormust be treated appropriately for the ignitiontemperatures of the fuels being used.

Purging of Plants without a Bypass Stackand without Supplementary Firing

In combined-cycle power plants without abypass, the gas turbine must always bestarted up and shut down across the HRSG.The volume flow of flue gas flowing throughthe HRSG during a normal starting process isgenerally not large enough to ensure an ad-equate air exchange of the HRSG volume onthe flue gas side as called for in the pertinentTRDs.

This means that the HRSG must be purgedfor a sufficient length of time prior to startingup the gas turbine with its starting converter.There is no other technical possibility avail-able. Depending on the volume of the HRSG,the gas turbine compressor is turned for sev-eral minutes (5 to 10 minutes) at 20 to 30 %of its nominal speed with the guide vanes inthe start-up position. This ensures themultiple exchange of air called for in theHRSG (approximately 3-fold to 5-fold, de-pending on code requirements).

For a purging at a constant speed that lastsover several minutes, this purging speed musthave a sufficient safety margin from the criti-cal blade vibration speeds of the compressor.

Again depending on the design and manu-facture of the machine, approximately 10 to15 % of the maximum compressor air massflow is attained in this range of speeds.Measurements on existing HRSGs show thata purging mass flow is not great enough inthis sector to cool the boiler components no-ticeably during purging prior to a warm or ahot start. For that reason, no high thermalstresses need be expected to result in thick-walled components from the purging a hotHRSG.

Purging of Plants with a Bypass Stack butwithout Supplementary Firing

Purging Process when Burning Fuel Gases

In plants with a bypass stack that burn gasfuels, the purging process is normally accom-plished with the aid of switch-over equipment.The gas turbine is started up across the bypassstack, whereby the bypass stack is adequatelypurged by the gas turbine as it starts, since thevolume of the diffusor and the bottom sectionof the stack, including the stack pipes, isrelatively small in comparison to the exhaustgas mass flow of the starting gas turbine.

As soon as the exhaust temperature reachesapproximately 350 to 400 °C during the run-up of the gas turbine, the gas turbine load isheld constant and the switch-over equipmentopens fully in the direction of the HRSG,purging the steam generator at the lowestpossible temperature and with the maximumpossible volume flow of the flue gas. Thefurther increase in gas turbine load togetherwith the HRSG then follows.

If operations should require that the gas tur-bine be run in single-cycle operation, the gasturbine must be run down to a part-load withan exhaust gas temperature of approximately350 to 400 °C if the steam section of theHRSG is to be connected up. This action pre-vents explosions in the HRSG zone. In ad-dition, it also results in a start-up that is ea-sier for the machine.

Due to the high flue gas speed and the largeair flow, the time is required for purging is

significantly less (< 1 min.) than that inplants that have no bypass stack and use astarting converter (approximately 5 to 10min.).

But this method of starting cannot be pro-vided on all gas turbines. It is not permis-sible to use this method of purging the HRSGif the minimum flue gas temperature in oper-ation lies in the area above or close to the ig-nition point of the fuel being used. In thatcase the HRSG can only be purged with theaid of the starting converter.

Purging Process when Burning Liquid Fuels

When the gas turbine is fired on liquid fuels,the ignition temperatures of the fuel are gen-erally lower than 350 °C. It is therefore nec-essary to purge the HRSG at a lower air tem-perature, taking proper consideration ofspecial operating statuses (shutdowns due tomalfunctions). In this case, the HRSG mustbe purged – as in the case of a combined-cycle power plant without a bypass stack –with the diverter damper fully open and usinga starting converter.

Purging of Combine-Cycle Plants with Supplementary Firing

In these plants, allowance must also be madefor the possibility that fuel can get directlyinto the HRSG through the supplementaryheater. In addition, consideration must begiven to whether or not these plants areequipped with an additional fresh air fan.

HRSG with Supplementary Firing but With-out an Additional Fresh Air Fan

These combined-cycle power plants must al-ways be purged according to TRD 411 andTRD 412 because their operating conditionsare comparable to those in conventionalsteam generator plants.

Plants burning natural gas can be purged withthe flue gas flow. Plants burning oil arepurged using the starting converter and themethod already described.

In order not to reduce the availability of thecombined-cycle power plant due to therequired purging actions, TRD 411 and TD412 recommend that the HRSG also beequipped in such a way as to preclude on afail-safe basis any uncontrolled intrusion offuel while the HRSG is not in operation andto enable dispensing with purging after anunplanned shut-down of the combustion. Incase of a trip after a malfunction, of course, itis always necessary to purge prior to re-starting the machine.

HRSG with Supplementary Firing and anAdditional Fresh Air Fan

HRSG plants with an additional fresh air fando not present any problem because they canbe purged adequately according to TRD 411and TRD 412 using the fresh air fan regard-

VGB PowerTech 4/99 5

less of whether such plants are or are notequipped with a bypass stack.

Verification of Successful Purging

Numerical Calculations for the Purging Process

Calculations of the flows during the purgingprocess have been carried out for thecombined-cycle power plant built at the Ba-denwerk AG’s Rheinhafen Power Station inKarlsruhe. The HRSG here is of a verticaldesign.

A cold start with a preceding failed attempt atignition was assumed. The concentrations ofgas possible in the waste heat portion of theplant in this case result from the con-frontation of the amounts of gas flowing outduring the trail in ignition time with the airflow forwarded during that time. For pur-poses of simplification, we assumed that themaximum possible gas concentration waspresent throughout the entire waste heat sec-tion, i.e., in the gas turbine exhaust duct, theheat recovery steam generator, and in thestack, at the point of time when the purgingbegan.

The gas concentrations for the various pointsin time as shown in F i g u r e 2 indicate thequality of the purging process. The purgingmass flow rate from the gas turbine is80 kg/s, from which the purging timerequired to produce the 3-fold exchange ofvolume called for turns out to be somewhatmore than 5 minutes. This corresponds to15 % of the gas turbine’s exhaust flow atnominal load.

The calculations showed that the incomingflow of purging air displaces or flushes outthe air/gas mixture out very evenly and withonly an insignificant amount of back-mixing.The only asymmetries that occur are in thearea of the top half of the steam generator,and then later in the stack pipes. These aredue to the geometry of the components. Theydo slightly prolong the amount of timerequired to flush out the mixture of air and

gas completely, but they do not detract fromthe effectiveness of the purging.

It can be seen that the gas concentration atthe outlet from the stack has been reduced byhalf even after a single volume exchange.After purging for approximately 150 s, whichcorresponds to a 1.4-fold volume exchange,the gas concentration in the entire exhaustgas path has dropped to practically zero.

In addition, F i g u r e 3 shows the resultswith the purging mass flow halved anddoubled. The corresponding purging timesare doubled or halved respectively, with onlyan insignificant change in the quality of theresults produced by the purging.

It is striking that the differences that occur inradial concentrations within the stack pipe aresmaller when the purging flow has beenhalved. This difference can be identifiedclearly by comparing the concentrations pres-ent after 150 s of purging at 40 kg/s with thosefrom purging for 37.5 s at 160 kg/s. The leastthat may be concluded from this is that no in-crease in the flow of purging gas or purgingair will bring any improvement in the resultsof purging.

Investigation of the Purging Process in theFlow Model

We built a to-scale plexiglass model of anexisting HRSG plant, filled it with smoke,and performed flow tests using various ratesof purging gas flow. This HRSG was of ahorizontal design. Here we studied the pur-ging of the inlet tract to the steam generatorand of the steam generator itself.

Evaluation of the video recording shows thatthe efficiency of the purging drops off sharp-ly at flows less than 10 % of the total com-bustion air flow, and can be improved onlyinsignificantly at flows greater than 15 %thereof, F igu re 4 .

Flow guide vanes can bring a sustained im-provement in the purging efficiency here.Moreover, an increase in the speed of purg-ing produces very strong eddies and corre-spondingly poor purging in certain zones.

Purging flows of about 10 % were shown tobe sufficient to ensure a safe purging of thesteam generator. This has also been con-firmed by practical experience.

Consideration of the Trails in IgnitionTimes Called for by IndividualRequirements in the Codes

Gene ra l Obse rva t i on

The trail in ignition time has been defined asthe time between the entry of the fuel into thecombustor and the activation of the flamemonitors. This trail in ignition time thus de-termines the maximum amount of fuel thatcan get into the combustor during a failedstart. The limits for the trail in ignition timehave been set in such a way that no explosivemixture can build up within the gas turbine,whereby the air flow velocity within the gasturbine ensures a corresponding dilution.

However, whenever this mixture enters intothe heat recovery steam generator at sig-nificantly lower flow speeds, a questionarises concerning the accumulation of gascomponents and the building up of an ex-plosive mixture within the boiler. In theopinion of the authors, this means that theboiler must be purged after a malfunction inoperation and/or a failed ignition.

The discussion that follows deals primarilywith problems in connection with the gas tur-bine trail in ignition times. The start of thetrail in ignition time is defined as the entry ofthe fuel into the combustor. Because it is im-possible to measure this point in time exactlyusing any process criterion, the maintainingof this waiting period depends on the choiceof a substitute criterion, quite reasonably theopening of the trip valve.

T ra i l i n I gn i t i on T imes fo r GasTurb ine s o f t he Pas t

In older gas turbines with a silo combustorand single burner, the fuel control and trip

6 VGB PowerTech 4/99

1 2 3 4 5 6

15

10

5

Com

bus

tion

air

flow

in %

Purging time in minutes

Figure 4a. Purging efficiency in the plexiglass model of the steamgenerator

0 s

0 s

0 s

20 s

30 s

60 s

30 s

60 s

290 sSimulated

5 %Mass Flow

Simulated10 %

Mass Flow

Simulated15 %

Mass Flow

Startof purging

Eddyat the inlet

Remnants of fluegas in the HRSG

Figure 4b. Purge test results simulated 5 % mass flow.

valves are located relatively close to theburner, F igu re 5 .

As a result, because of its proximity to theburner, the opening of the trip valve appearedto be a reasonable substitute criterion for theentry of the fuel into the combustor. The tripvalve is considered to be a safe shut-off de-vice, and the line to the burner is so short thatthe corresponding ignition conditions forflow and pressure can be attained very quick-ly.

To optimize the ignition process, the controlvalves are first run to the ignition stroke, andthe trip valves are then opened. An ignitionwithin 2-3 seconds is possible, which meansthat the trail in ignition times called for in theTRDs can be satisfied for both oil and gas.

The output of the burner during the ignitionphase is limited by the control system andmonitored by the protection system. This en-sures that, if the control valve should fail, atrip will be initiated before any large amountof an explosive mixture can build-up andthus reach the combustor.

T ra i l i n I gn i t i on T imes fo r GasTurb ine s o f Today

Modern gas turbines with annular com-bustors have a relatively extensive fuel dis-tribution system including long ring-shapedpipes between the trip valves and burners,F igu re 6 .

Here, it takes 2 to 5 seconds to fill the linesbefore the fuel enters into the combustor. Ithas been shown that trail in ignition times of5 s can nonetheless be maintained ap-proximately for gas. Analogous to gas tur-bines of the past, a monitoring of the controlvalve ignition stroke initiates the trip whenthe position is wrong.

During operation on oil, the control valvemust be opened fully for a short time to mini-mize the time needed for filling. In addition,sector valves on the combustor prevent thefuel from entering the combustor pre-maturely.

This results in the following sequence forfilling and ignition:

— opening of the trip valves,

— opening of the control valves until theconnecting pipe ring is full,

— run back to the ignition stroke,

— opening of the sector valves.

A correspondingly involved monitoring ofthe ignition stroke ensures that only a limitedamount of fuel will be admitted if the controlvalve is not in the correct position.

In this way, the trail in ignition time follow-ing the opening of the sector valves can bebrought down to 5 s. The starting point forthe trail in ignition time is determined by theopening of the sector valves instead of thetrip shut-off valve, which corresponds to theactual entry of the fuel into the combustor.

T ra i l i n I gn i t i on T imes fo r P i l o tBurne r s

For pilot burners and the ignition gas flowsfor them, a trail in ignition time of 10 sapplies. This trail in ignition time is notmonitored directly with a flame monitor butindirectly by the process logic.

The pilot device is started earlier than themain flame, in such a way that the end of thetrail in ignition time for the pilot burner co-incides with the end of the trail in ignitiontime for the main flame. This means that thepilot flame is monitored indirectly via themonitoring of the main flame.

Consideration of Possibilities for theFlame Monitoring in Gas Turbines

Called for in the Code

There are various ways in which the firing in-side a unit can be monitored. In detail, theseinclude:

— Flame monitors: the goal is to watch overthe starting of the flame.

— Monitoring of �: the global ratio of fuelto air.

— Monitoring of CO: Indicates how com-plete the combustion is.

— Temperature monitoring.

In the normal case, no problems arise in de-signing flame monitoring units for con-ventional steam generators because these aredealt with accordingly in the pertinent TRDs411 to 415, which cover the associated typesof units specifically.

Essentially, for gas turbine installations, theprovisions of TRD 411 apply for heating oil,and TRD 412 for gas.

TRD 411 and TRD 412 call for monitoringthe breaking off of the flame by installingcorresponding optical flame monitors. In ad-dition, it is also possible to monitor the com-bustion zone whenever the cross-ignitionfrom other burners present and in operationcan be ensured. The advantage here is thatthe number of flame monitoring units can bereduced accordingly.

Some modern gas turbines (such as, forexample, the GT24, GT26 of ABB) employsequential combustion to increase efficiency,see Figure 1. F i g u r e 7 presents this pro-cess in a T/S-Chart which shows that thetemperature of entry into the sequential com-bustor is significantly higher than that in con-ventional combustors. The first combustor ismonitored conventionally in accordance withthe provisions of the above-mentioned TRDs.It thus does not differ from the combustors ofthe past with regard to how it functions.

In the sequential combustor, the temperatureat the inlet is the criterion that inherently en-sures combustion. For that reason, the tem-perature present offers itself as a reasonablecriterion for monitoring. This possibility formonitoring steam generators is supported inthe NFPA 8506, which therefore allows re-placing the flame monitors with a tempera-ture monitor wherever the temperatures areabove 760 °C.

This exception is based on the fact that amixture of gas and air ignites spontaneouslyabove a certain temperature. F i g u r e 8

VGB PowerTech 4/99 7

Tripvalve

Gas

Oil

Tripvalve

Controlvalve

Controlvalve

Figure 5. Arangement of the trip and control valves for the fuel supplysystem on gas turbines with a silo combustor.

Tripvalve

Controlvalve

Main burnerSector valves

Connectingpipe ring

Figure 6. Arrangement of the control, trip and sector valves for thefuel supply line on gas turbines with an annular combustor.

shows this spontaneous ignition temperature,indicating the trail in ignition for the variousfuels as a function of the temperature.

The prerequisite for this spontaneous com-bustion is that there also be adequate concen-trations of oxygen present. The gas turbineprocess ensures this, and combustion in thesequential combustor also takes place with acorresponding amount of excess air. Theflame in the sequential combustor is moni-tored by monitoring the inlet temperature in-to the combustor.

Whenever the inlet temperature drops below900 °C (a sufficient safety margin from the

NFPA provision of above 760 °C), the tripvalves for the fuel supply to this combustorclose automatically. This does not affect thecontinued operation of the first combustorprovided there is no malfunction presentthere that would shut down the firing there aswell via normal safety system operation.

This protection system operates indepen-dently of the control system that primarilydetermines the temperature within the se-quential combustor. This ensures that no fireor explosion will be possible downstreamfrom the gas turbine. If combustible com-ponents do not burn within the combustor inthe above-mentioned range of temperatures,they will certainly not burn or form a flam-

mable mixture at the lower temperaturesdownstream from the gas turbine.

One possible malfunction that might occurmust be considered here: A drop in the gassupply pressure to the sequential combustorcould cause the flame to go out without caus-ing a response of the temperature monitor,and hot gases could flow backward from thecombustor into the gas supply system. Be-cause this is taken into account by monitor-ing the differential pressure in the controlvalve, there is no real problem here.

Summary

In this presentation, we have shown whatproblems can arise with regard to the im-plementation of the applicable regulatorycodes in actual practice with gas turbineswith downstream heat recovery steam gener-ators.

Depending on the code to be applied, dis-cussions arise during the project developmentphase as to their practicable application inconnection with:

— venting and purging the flue gas paths,

— flame monitoring, and

— trail in ignition times.

8 VGB PowerTech 4/99

~ 1000 °C

Sequential burner

Main burner

Compressor

High pressure turbine

LowpressureturbineT

S

Figure 7. Basic principle of the sequentialcombustion process as shown in aT/S chart.

400 600 800 1000

10

1

0,1

Diesel oil

MethaneNatural gas

Del

ay in

igni

tion

in m

s

Mixed temperature in °C

Figure 8. Spontaneous combustion tempera-ture, with associated delay in igni-tion for various fuels.

Table 1. Comparison of requirements to be met for flushing, flame control and safety periods of the various codes.

Code Requirements Results of Need for Recommen-Subject TRD 411/412 NFPA 8506 British Gas G.I. Model test Flow calculat. Clarification dation

Purging of combined- More than 50 % At least a 5-fold 5-fold air ex- An adequate With a purg- TRD is not di- Correlate thecycle power plants of the combus- exchange of air change at a purging effect ing mass flow rectly applicable results of thewith the purging flow tion air flow for at a rate at temperature is attained of about to combined- model test, cal-specified in the TRDs long enough to least 8% of the < 400 °C with a purging 15 %, there is cycle power culations, and theand NFPA 8506 ensure a 3-fold maximum mass mass flow of no longer an plants. Corre- NFPA recom-

air exchange; through-flow. about 10 % air / gas mix- sponding mendation as ano temperature ture present recommenda- provision to beindicated Alternative pos- after a 1.4- tions therefore applied in com-

sibilities for dem- fold air ex- need to be bined-cycleonstrating the change. worked out power plants:effectiveness of This is also 10 % purgingthe purging are true when the mass flow with aalso offered air mass flow 3-fold air ex-

is halved or changedoubled

Flame Monitoring Optical flame Flame monitors Optical flame – – Reconciling the Temperaturemonitors or temperature monitors – requirement monitoring to

monitors – information augment thewith regard to flame monitorquality of igni-tion

Trail in ignition times TRD 411/412 Trail in ignition Trail in ignition – – Define the time e.g., 12 sTable 1 times for: times as short as from the opening This time is the

Main flame 5 s possible of the trip valve sum of an ad-Pilot flame 10 s to take-over by vance time of 8 s

the flame monitor and an additionalas the complete 4 s for take-overtrail in ignition by the flametime monitor

VGB PowerTech 4/99 9

With the gas turbine, it is not possible to sat-isfy the provisions of TRD 411 and TRD 412that call for a 3-fold air exchange at a flowequal to at least 50 % of the total combustionair flow.

The situation is similar with regard to theflame monitoring in the downstream secondcombustor (sequential combustion), wherethe use of optical flame monitoring equip-ment has proven to be problematic. A thirdpoint leading to discussions involves the trailin ignition times prescribed by the TRDswhich cannot be maintained, particularlywith oil-fired gas turbines. Among other rea-sons, this is due to the fact that the fuelsupply systems in these new gas turbineshave relatively long supply lines.

This contribution presents possible solutionsfor these problem areas, showing how a safeoperation is technically possible while stillmaintaining a high degree of availability. In

addition, it discusses fully and in detail alltechnical processes and points under dis-cussion so as to provide a basis for furtherdiscussions that can then be incorporated intothe corresponding regulatory codes.

T a b l e 1 shows the possible solutions sug-gested by the authors, comparing them withthe existing codes TRD, NFPA, and BritishStandards and the results indicated in theSection above.

In other countries, other regulatory codesapply (e.g., NFPA 8506). Experience withthem should by all means be discussed aswell and taken into account where necessaryin the TRD code.

Bibliography

[1] Technische Regeln für Dampfkessel. TRD411 und 412 (Entwurf 09/96).

[2] National Fire Protection Association (NFPA)8506. NFPA 8506 (Stand 1995).

[3] MFUP 8506 (Entwurf 03/97).

[4] Joos, F., Brunner, P., Schulte-Werning, B.,und Syed, S. (ABB Power Generation Ltd.),and Eroglin, A. (ABB Management Ltd.):Devolopment of the sequential cominitionsystem for the ABB GT24/GT26 Gas turbinefamiliy.

[5] British Gas: Guidance notes on the installa-tion industrial turbines, associated gas com-pressors and supplementary firing burners(06/89).

[6] Weber, K.: Inbetriebnahme verfahrenstech-nischer Anlagen. VDI-Verlag (1996).

[7] Fachkunde für den Dampfkraftwerksbetrieb.VGB-Kraftwerkstechnik GmbH (1976).

[8] Bernecker, G.: Planung und Bau verfahren-stechnischer Anlagen. VDI-Verlag (1984).

[9] Nabert, K., und Schön, G.: Sicherheitstech-nische Kennzahlen brennbarer Gase undDämpfe. 2. Auflage, Deutscher Eichverlag,Braunschweig (1991).

Management and Optimization

Project management methods

Clarification of data to be assessed

Risk Potential and Probabilistic Approach

Acceptable assessment of risk categories

Probabilistic approach

In-service Inspection Methods

Reduction of stress by design-induced and operation-inducedmodifications by the example of a feedwater tank

Evolution of Loading and Preventive Measures

Evolution of loading due to aging and fatigue

Extension of operating time by preventive measures

gAte* –Our Approach for Your Integrated Plant Engineering.

A Powerful Service by TÜV SÜD for Your Success.

Of course: If more inspections are ordered at first sightthe costs are higher than in case of the unsophisticatedexaminations of your systems based on regulatoryguides

It is also clear that you will pay for all of the inspectiononly a fraction of the costs that will arise in case of onesingle failure of your systems.

* gAte a wholistic approach in systemsengineering. It is offered by TÜV SÜDIndustrie Service for some years nowand applied succesfully in manyindustrial fields.

The gAte-Approach is implemented considerably earlierthan the traditional inspection based on regulatory guides.This early implementation which will cost you naturally inpart more money, but will pay in the long term!

And this is our goal! The same way as it is yours!

If you want to know more, call us, send us a Fax or an e-mail.

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