When a combined-cycle plant is operat-ing at steady-state, 100% load, it’s anelegant thing to behold. Well, maybenot to the artist or the fashion design-

er, but it is to the engineer who can appreciate itsunmatched thermal efficiency, small footprint, lowwater usage, and single-digit air emissions. Unfor-tunately, during transient and low-load conditions,the marriage of the gas-tur-bine cycle with the steam-tur-bine cycle begins to look a bitawkward.

During these conditions—the ones of greatest concernare startup, shutdown, and asteam-turbine trip—the gasturbine (GT) is producing somuch exhaust heat at suchrapid rates of temperaturechange that, if it were imposeduncontrolled onto the steamside, thermal ramp-rate limitswould be violated in thick-walled components of theheat-recovery steam generator(HRSG) and/or the steam tur-bine (ST). Such transients arebeing encountered more fre-quently today than in the pastbecause of the need to cyclecombined-cycle units designedfor base-load service. In addi-tion, the transients are moresevere in magnitude because the latest combined-cycle plants typically:

■ Feature large GTs with high exhaust flowsand temperatures.

■ Operate at high steam temperatures andpressures.

■ Incorporate reheat steam, which significantlyincreases control complexity during plant startup.

■ Include two or three GT/HRSG blocks supply-ing a single ST, which complicates both startupand shutdown procedures.

■ Demand more aggressive startup, shutdown,and load-response times.

One solution to the imbalance between GTexhaust heat and the steam system’s thermal tran-sient limits is to install a bypass damper and abypass stack upstream of the HRSG, enabling theGT exhaust gas to be vented directly to atmos-phere. This permits simple-cycle operation, but can

still allow serious thermaltransients in the HRSGbecause it is difficult to pre-cisely modulate the bulkybypass damper and complywith National Fire ProtectionAssociation pre-start purgerequirements when transi-tioning from simple- to com-bined-cycle operation. Thissolution also is capital- andmaintenance-intensive, so itis installed in very fewp l a n t s .

Another solution is toallow the HRSG to generatesteam, but to vent it directlyto atmosphere until thesteam-side metal is properlywarmed up. However, theroutine use of so-called “skyvents” during every plantstartup incurs costly losses ofdemineralized water, not tomention problems with envi-

ronmental regulators and plant neighbors whoobject to the imposing noise and plume.

Cascading bypass systemThe most common method to manage the thermalimbalance during times when the steam turbinecannot use all the steam produced is the “cascad-ing” bypass system (Fig 1). In this scheme, thehigh-pressure (HP) superheated steam generated

COMBINED CYCLE JOURNAL, Fourth Quarter 2003 1

1. Steam-turbine bypass system isbeing installed at a 250-MW, 1-by-1combined-cycle plant. HP (A) and IP (C)valve bodies await receipt of actuatorsand valve gear. B is spray watermanifold for HP desuperheater.Desuperheated steam is routed tosparger in steam-turbine exhaust duct

SPECIAL REPORT

S t e a m Tu r b i n e Bypass SystemsA robust condenser dump system is critical to a combined-cycle plant’s ability torespond to transients. Inattention to detail at the design stage can lead to serious andcostly O&M problems

By Robert W Anderson, Progress Energy Inc, and Henk van Ballegooyen, Gryphon International Engineering Services Inc

during startup is diverted around the HP section ofthe turbine, through a pressure-control valve (PCV)and an attemperator, and into the cold reheat line.The primary job of the PCV is to control HP d r u mpressure, thereby limiting thermal stresses on theH P drum—one of the most vulnerable componentsof the HRSG because of its thick walls.

The attemperated steam then mixes withsteam from the intermediate-pressure (IP)drum and is directed through the reheater.

After passing through the reheater, the steam isdiverted around the IP and low-pressure (LP)steam turbines as it travels through a second pres-sure-control/attemperating station (hence thename “cascading”) located off the hot reheat line,before it is directed through a dump tube (or“sparger”) into the condenser. This second PCV’sprimary job is to control reheat steam pressure,thereby limiting IP drum level swings. The secondpressure-control/attemperating station often isreferred to as the “hot reheat bypass” or the “LPbypass” (Fig 2).

As the ST satisfies its warm-up requirements,the control valves in both the HP bypass and thehot reheat bypass progressively close and the STpicks up steam load.

Note that a similar solution applied at somecombined-cycle units is referred to as “parallelbypass.” In this design, the steam generated atstartup in the HP and IP drums is attemperatedand sent directly to the condenser, without flowingthrough the reheater. Another feature of the paral-lel bypass system is that the spray water for theattemperation process comes only from the con-densate pumps. By contrast, spray water in thecascading bypass system is taken from the dis-

charge of both the condensate pumps and the feed-water pumps, hence there is a small reduction inthe efficiency loss with the parallel design.

But in the parallel design, the reheater remains“dry” during startup and receives no cooling fromsteam flow. This forces HRSG designers to signifi-cantly enhance reheater tube metallurgy, andmakes the cascading bypass system the less expen-sive option.

Other advantages of the cascading bypasssystem include the following:

■ Steam flow through the reheater limits theheat input of the HP evaporator (which limits theH P drum transient) during both plant start-upand ST trip.

■ When properly designed and tuned, the cas-cading bypass system’s transient characteristicsclosely resemble the ST characteristics, whichensures the smallest discontinuities during tripand switch-over situations.

■ The steam produced is used to warm up thereheater headers and main steam lines, instead ofbeing dumped immediately after it has left the HPsystem.

A risk introduced by the cascading bypass sys-tem is its potential to cause “windage” overheatingof the HP turbine during startup and shutdown ifPCVs fail to precisely control HP and reheat pres-sure. Windage occurs when the pressure ratiothrough a turbine decreases to a point wheresteam begins to recirculate internally. This recircu-lation causes a very rapid increase in temperaturethat can easily exceed the material limits of the STblading. In certain conditions, windage can occurwithout any indication of trouble to the operator.

The worst case is a warm start during low-flowconditions. (A hot start allows faster ramp rates,

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SPECIAL REPORT

2. In a cascading bypass system, the HPsuperheated steam generated during startup isdiverted around the HP section of the turbine,through a pressure-control valve and an attempera-tor, and into the cold reheat line. After mixing with IPsteam and passing through the reheater, the dumpsteam is diverted around the IP and LP turbinesthrough a second pressure-control/attemperatingstation, before it is directed through a dump tubeinto the condenser

3. A risk introduced by the cascading bypass sys-tem is its potential to cause “windage” overheatingof the high-pressure steam turbine during startupand shutdown if the pressure-control valves fail toprecisely control HP and reheat pressure. Toaddress the problem, designs for some of the com-bined-cycle powerplants recently installed alsoinclude a “startup bypass,” which connects the HPturbine vent directly to the condenser, upstream of acheck valve in the cold reheat line

thus higher steam flows, which protect against theoverheating effect.)

To address this windage problem, some cascad-ing bypass systems also include a “startupbypass,” which connects the HP turbine ventdirectly to the condenser, upstream of a checkvalve in the cold reheat line (Fig 3).

Another risk with cascading-bypass systems isthe potential to motor the ST if the cold reheatcheck valves do not seat properly following an STtrip.

Tough on valves. Cascading bypass systemshandle an immense amount of energy at ele-vated temperatures, pressures, and velocities.

They also experience harsh temperature and flowchanges as PCVs and attemperation valves opensuddenly in response to plant transients. The resultis severe service for the valvesand steam-conditioning equip-ment, which has led to a host ofoperations and maintenance(O&M) problems in the field.

At HRSG User’s Group meet-ings, for example, many plantmanagers report poor reliabilityof their desuperheater sprayvalves. A common problem is thatthese valves have been over- s i z e dor utilize a “linear” trim, leadingto erosion, leak-through, and poorcontrol response. Re-trimmingwith a properly sized “constantpercentage” trim can address thisproblem. At a minimum, an effec-tive preventive-maintenance pro-gram for a cycling HRSG willinclude annual overhaul of thesespray valves, and inspection ofthe block valves, spray nozzles,and thermal liners, if installed.

Members of the HRSG User’s Group also reportgreat difficulty attaining stable, precise, reliablecontrol from their steam-bypass control valves.T h a t ’s a particularly critical problem for cyclingplants because the bypass system is expected toperform during every plant startup and shutdown.In addition to poor process control, the controlvalves in turbine-bypass systems often experiencethe following:

■ Premature trim and body failure caused by alack of control of fluid velocity along the flow path,and internal vibration.

■ Sluggish operation and sticking because ofdifferential expansion between trim and body.

■ Poor shutoff capability. Tight shutoff capabili-ty in the HP-bypass control valve must be pre-served to minimize HP pressure decay duringovernight and weekend shutdowns, and to avoidefficiency losses during normal operation. Ti g h tshutoff capability also is essential in the hotreheat bypass control valve to prevent high-tem-perature steam from leaking through, unattem-perated, into the condenser.

D o n ’t feel like the Lone Ranger if these prob-lems sound familiar. Many owner/operators whowere left with low-bid, poor-performing bypassPCVs by their architect/engineer have been com-pelled to replace these valves with higher qualityequipment. Some have even done so within theoriginal valve warranty period.

Valves need warming, too. Many control-valve problems can be attributed to thermalshock, because the valves are designed with-

out any provision for warming. Think about it: Thebypass control valves are there to warm up HRSGand ST metal, because we understand the damagethat can occur if we shock the HP drum, HP super-heater outlet header, or the turbine’s steam chest,casing, or rotor—the most vulnerable, thick-walledcomponents. Yet we often make no allowance for

the thermal shock that occursto the bypass control valvesthemselves.

During normal operationwith the ST loaded, the HPbypass system’s valve bodiescool to saturation tempera-ture—approximately 600F. Cer-t a i n l y, some amount of bypass-system warming occurs becauseof heat conduction. But in manyplant designs the HP b y p a s svalve is at the end of a longpipe run, perhaps 12 ft or more,arranged with the valve abovethe HP steam pipe and withbottom entry of the pipe. Thisarrangement precludes conduc-tion alone from providing ade-quate valve-body warming.

During both normal shut-downs and trips of the ST, the600F bypass valve bodies are

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SPECIAL REPORT

5. At some plants, the maximumvolumetric flows of dump steamoccur early in a cold start, duringthe soaking period, when the GT isat minimum load. But because thearchitect/engineers based theirdesign on the condition of full GTload/full HRSG pressure, the dumpsystems end up being undersized

4. Control-valve reliability and service life can begreatly enhanced by installing a warmingconnection that, during normal combined-cycleoperation, limits the difference between steam tem-perature entering the respective bypass station andthe valve-metal temperature

suddenly subjected to high flows of steam at1 0 5 0 F, a temperature differential of around 450deg F. By comparison, the allowable temperaturedifferentials set by HRSG and ST manufacturersbetween steam and metal temperatures rangefrom 145 to 200 deg F.

S i m i l a r l y, when the plant is off-line, the bypassvalve bodies cool, all the way down to ambient tem-perature during a long shutdown. On the subse-quent startup, when the bypass valves open, thecold valve bodies experience a high flow rate of hots t e a m .

Control-valve reliability and service life can begreatly enhanced by installing a warming connec-tion that, during normal combined-cycle operation,limits the difference between steam temperatureentering the respective bypass station and thevalve-metal temperature (Fig 4). We recommend adifferential of 160 deg F before the control valvesare allowed to swing wide open.

Bypass valve warming during normal opera-tion can be effectively accomplished without lossof system efficiency or great capital cost. A s m a l l -bore pipe connected at one end to the bypassvalve just upstream of the seat and the other endconnected to the valve’s respective main or hotreheat pipe near the ST will supply sufficientsteam flow to keep the valves warm, while stilldelivering the warming steam to where it wasgoing in the first place. The additional warmingconnections still require the installation of start-up and shutdown drain lines to be installed inthe bypass piping.

Other design improvements. Valves arenot the only design weakness found in thecondenser dump systems at many com-

bined-cycle plants. To be sure, the design chal-lenges are formidable, and somewhat unique tothis plant type. Condenser dump systems havebeen operating successfully in North America formany years at nuclear plants, particularly at boil-ing-water reactor plants, where routine venting ofpotentially radioactive steam is not permitted. Buta nuclear plant’s use of saturated steam avoidsmany of the design challenges found in the super-heated, reheat steam systems of a combined-cycleplant. Similarly, many large fossil-fueled NorthAmerican steam plants have experienced years ofsuccessful condenser-dump operation. But theirbypass systems typically are sized for less thanthe full-load condition—a usual value is 30%dump capacity—so the demands on their equip-ment are less severe.

There has been substantial experience withhigh-capacity dump systems at steam plants out-side of North America. In Europe, South A f r i c a ,and Japan, for instance, the majority of steamplants installed over the past 50 years featuredBenson-type once-through boilers which required100%-capacity dump systems. Several usefullessons can be taken from that experience andapplied to today’s challenges at North A m e r i c a ncombined-cycle plants.

Design, O&M lessons to learnDump undersized for ST trip. Many NorthAmerican condenser dump systems are under-sized, which forces operators to supplement theircapacity by opening the sky vents and therebywaste valuable demineralized water. Use of skyvents also makes pressure control less precise.

When designing condenser dump systems, engi-neers typically consider the case where the STtrips from full load. Some assume, logically at firstglance, that the mass flow will be 100% of the flowthrough the fully loaded ST. But when the STtrips, the HP bypass valve opens and attemperat-ing spray is injected to desuperheat the steamfrom approximately 1050F to 600F. This attemper-ating spray adds mass flow to the fluid stream,perhaps as much as 20% more than the flowthrough the fully loaded ST.

The fluid stream then flows through thereheater and the second, hot reheat attemperationstation, which further reduces steam temperatureto approximately 350F. The hot reheat bypassspray flow adds yet more mass to the fluid stream,approximately another 20%.

In sum, the total mass flow that the condenser-dump system must be sized to handle for the caseof an ST trip is not 100% of the turbine’s full-loadsteam flow, but as much as 140%. In addition tosuitably sizing the piping, valves, steam inlets tothe condenser, and condenser-tube nest, this 140%mass-flow condition requires adequately sized con-densate pumps that can remove the larger volumeof water from the condenser.

Dump undersized for cold start, LP c o n-d i t i o n s . Another common cause of under-sizing condenser dump systems lies in the

analysis of startup transients. When evaluatingstartup scenarios, designers often assume that thehighest steam flow will occur during the latterpart of a startup, when the GT is at full load andthe HRSG is at 100% rated pressure. But a char-acteristic of GTs is that they produce a high per-centage of their full-load exhaust energy duringboth ramp-up and operating at low load—perhapsup to 70%. This means that the HRSG is capableof achieving near rated steam production, often atlower-than-design steam pressures.

During a cold start, the GT is quickly brought toand held at minimum load for heat soaking of theHRSG (Fig 5). During this soak period, steam tem-perature and pressure are low, therefore its specificvolume is very high (the steam is less dense). A tseveral plants analyzed, the maximum volumetricflows occur at these conditions—early in a coldstart when the GT is at minimum load. But becausethe designers of these plants sized the condenserdump system for the condition of full GT load/fullHRSG pressure, the operators must open the skyvents to supplement their undersized dump system.Realize that the operators must open these vents

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SPECIAL REPORT

during e v e r y cold start, so the cumulative waste ofdemineralized water during a cycling plant’s 20-yrservice life is going to be enormous.

If the sky vents are not opened, then pressureramp-rate limits in the HP drum will be violated.So the Hobson’s Choice is to waste demineralizedwater, or shorten HP drum life.

Location, location. . .saturation. A n o t h e rdesign lesson that can be learned from over-seas experience concerns the location of the

bypass station, and the quality of steam that isdumped into the condenser.

The common practice overseas is to locate thehot reheat (HRH) bypass station close to—typical-ly just a few feet away from—the condenser neck.The North American practice, by contrast, hasbeen to locate the HRH bypass station closer tothe boiler (that is, more remote from the con-denser) to minimize the use of expensive P91 pip-ing. But the resulting longer piping runs of HRHdischarge piping, which could be several hundredfeet in length, necessitate either the use of largerdiameter piping or higher steam pressures at theHRH bypass to yield the correct steam pressureentering the condenser.

Closely related to the location issue, is the issueof steam quality as it is dumped into the con-denser. The industry standard in other parts of theworld is to dump saturated steam of approximately90% quality. This is to emulate the fluid that isnormally discharged into the condenser from theST exhaust. Makes sense.

In North America, however, recommended guide-lines published by the Heat Exchange Institute(HEI) and the Electric Power Research Institute(EPRI) require that steam dumped into the con-denser from a turbine bypass system must be s u p e r -h e a t e d . HEI, whose members include condensermanufacturers, is concerned about erosion that mayoccur from “wet” steam. In our experience, this con-cern is overblown, and is the cause of considerablemechanical damage and process-control problems atNorth American combined-cycle plants.

The specification of superheated steam leads toseveral problems. For starters, superheated steamhas a lower heat-transfer coefficient, so the con-d e n s e r, which was sized for 100% ST load, oftenends up with too little surface area in its cooling

tubes to handle the condenser-dump flow. Theresult, during condenser-dump operation, is a lossof condenser vacuum. In a 2-by-1 combined-cycleplant, if one power block is operating at load andthe other is dumping steam through the bypass sys-tem, there is a significant risk of tripping the ST onhigh condenser pressure (inadequate vacuum).

Another potential problem with the NorthAmerican practice is that superheated steam has ahigher specific volume, and therefore a greatervelocity than 90% quality steam, for the samemass flow rate. The tube-support spacing in con-densers is generally designed to handle the lowervelocities of 90% quality steam exiting from anoperating ST, hence the supports often are unableto prevent the condenser tubes from hammeringagainst each other when they encounter high-velocity steam from the dump system. In a mar-ginal case, damaging steam velocities may onlyoccur during cold-weather operation, when lowercondenser pressures further increase the steamvelocity into the tube nests.

When the condenser at a North American com-bined-cycle plant suffered tube failures shortly aftercommissioning, a root-cause analysis showed thattubes hammering against each other, particularlythe first four tubes closest to the dump-tube inlet,was the cause. Extra supporting elements had to beretrofit to this unit to dampen the tube movementcaused by the condenser dump system (Fig 6).

It appears that many North American designersare not even adhering to the HEI and EPRI guide-lines when it comes to the steam enthalpies thatthey are allowing to enter the condenser. HEI 5.4.2states: “Limit the enthalpy of entering steam to nomore than 1200-1225 Btu/lb except in the case ofhigh-flow steam dumps where the enthalpy shallbe limited to 1190 Btu/lb. Acceptance of flows withenthalpy higher than 1225 Btu/lb may be consid-ered depending upon specific conditions of service.”

The EPRI guidelines define “high flow” asgreater than 20,000 lb/hr. A typical F-class 2-by-1power block is configured with two dump systems of717,000 lb/hr each, one per HRSG, dumping into asingle condenser. During startups and shutdowns,dump-steam flow rates from each HRSG typicallyrange from 250,000 to 500,000 lb/hr, or more.

Cl e a r l y, these flow rates far exceed EPRI’s20,000-lb/hr threshold, thus the HEI limit of1190 Btu/lb for “high-flow” systems must

a p p l y. However many designers are allowingenthalpies of 1250 Btu/lb. They rationalize this byciting the HEI exception, which “may be consideredupon specific conditions of service.” But themechanical damage and process-control problemsbeing experienced in North American plantsstrongly suggest that this exception does not applyto F-class combined-cycle condenser dump systems.

At a minimum, then, owner/operators need toensure that their designers are adhering to the1190-Btu/lb enthalpy limit set by HEI and EPRI.To further enhance condenser-dump design, wepropose that the requirement for superheated

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6. NorthAmerican guide-lines, in contrastto European prac-tice, require thatsteam dumpinginto a condenser must be superheated. But thetube-support spacing in condensers generally isdesigned to handle the lower velocities of 90%quality steam exiting from an operating turbine.Tube damage, shown here on shiny area, wascaused by tubes hammering against each otherduring turbine-bypass operation

steam published in the HEI and EPRI guidelinesbe re-evaluated, and that the use of saturatedsteam, commonly practiced in other parts of theworld, be considered. Of course, effectively man-aging the effects of high-velocity water impinge-ment within the condenser remains important, butwe think this is a less troublesome problem thanmanaging highly superheated steam.

HEI published its latest edition (the ninth) of“Standards for Steam Surface Condensers” in1995, plus an addendum that included new mater-ial on turbine bypass in December 2002. The relat-ed EPRI publication is “Recommended Guidelinesfor the Admission ofHigh-Energy Fluidsto Steam SurfaceCondensers,” whichwas last updated in1982.

HRH attem-peration con-t r o l . The con-

trol scheme for thedesuperheating sprayvalve is another com-mon design weaknessat combined-cycleplants. Most controlschemes use a simplefeedback loop w i t hsteam temperature asthe single variable.This temperature-con-trol method worksfine for the HP b y p a s sstation, but not forthe HRH bypass sta-tion, where the steamis close to the saturation point. The results ofclosed-loop temperature control during transientsin HRH bypass stations are excessive hunting ofthe desuperheat-spray valve, and frequent controlexcursions. If the excursion is large enough, it cancause the condenser dump system to trip on high-temperature limit, and force the sky vents to open;or excessive spray to be emitted, leading to pipeerosion and condenser damage.

A more precise, reliable method of attempera-tion control for HRH bypass transient conditionsis a f e e d - f o r w a r d scheme that measures pressureand temperature upstream of the PCV, and pres-sure downstream of the PCV. From these parame-ters and an understanding of the sparge tube’spressure/flow characteristic, we calculate dump-system inlet enthalpy and dump-steam flow rate,which enables the precise determination ofrequired attemperation spray. This enthalpy-con-trol method, extensively applied in European,South African, and Japanese designs, has beenretrofit to some North American plants duringroutine outages, and has eliminated the huntingproblems that previously plagued these facilities.

Sometimes a combination of control schemes can

be used, with the temperature-control scheme han-dling steady-state conditions, while transients arehandled by the enthalpy-control which more rapid-ly positions both the PCV and attemperation valveto yield the correct enthalpy in the bypass. After ashort time delay, the valves are released back tosteady-state, closed-loop temperature control.

Sparge tube design. Several cases have sur-faced where condenser tube damage wascaused by the design of the sparge tube that

distributes dump steam into the condenser. Con-denser designers typically assume that dump

steam will be evenlydistributed acrossthe entire area ofthe tube nests.Unless the spargetube is carefullydesigned and locat-ed, this will noto c c u r, resulting inhigher localizedsteam velocitiesthan anticipated. Itis best if spargetubes extend the fullwidth of the con-denser and are ori-ented perpendicularto the direction ofthe condenser tubes,so that the dump-steam jets from thesparger are parallelto the condensertubes.

One style ofsparge tube that can

be particularly troublesome is represented in Fig7. This tube has relatively large holes arrangedbetween the 11:00 and 1:00 o’clock positions, witha “hood” positioned above these holes to deflect thesteam to each side of the tube. Depending uponhole size, hole location, and hood height, this styleof tube can produce very powerful, potentiallysupersonic jets of steam that impinge on localizedareas of condenser tubes, support structures, andside walls—causing localized heating, excessivevibration, and other mechanical damage.

Noise problems. Excessive noise is a finaldesign weakness that we’ll discuss in thisarticle. Excessive noise can be generated in

the vicinity of the condenser because the con-denser casing is typically constructed of thermallyuninsulated, thin materials compared to that ofthe turbine-bypass valves and piping. For themajority of the applications, the noise is addressedusing noise attenuating trim in the turbine bypassvalve and a downstream dump tube (or sparger)inserted into the condenser.

The increasing use of air-cooled condensers fur-ther aggravates the noise problems. In an air-

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SPECIAL REPORT

7. Condenser designers typically assume that dumpsteam will be evenly distributed across the entire area ofthe tube nests. But unless the sparge tube is care f u l l ydesigned and located, this will not occur. The result ishigher localized steam velocities that cause localized heat-ing, excessive vibration, and other mechanical damage

cooled condenser arrangement, the steam isdumped into a main steam duct that then distrib-utes the steam to finned tube banks located overthe forced-draft fans. This steam duct is a verylarge, thin-walled (typically 0.5-in.-thick wall)piece of pipe that runs along the outside of thecondenser support structure. The noise generatedin such thin-walled ducts can be enough to cause aplant to exceed noise-permit limits.

To eliminate or reduce the noise, several factorsmust be considered. First, is the noise generatedby the control valve itself? Noise is generated herebecause the majority of the system pressure dropoccurs inside the control valve. The next noise for-mation mechanism that must be accounted for isthe sparger. A smaller pressure drop occurs at thispoint, but the noise must be tightly controlled asthe flow dumps into the condenser duct. Finally, asmultiple turbine bypass valves are used in themajority of condenser-dump designs, the noisefrom each separate valve and sparger combinationmust be considered.

For one application with a direct air-cooled con-denser and multiple turbine bypass valves wherenoise from the condenser ducting and air- c o o l e dcondenser was of particular concern, we designeda solution that included four stages of multi-portpressure-reduction plates, with two stages ofattemperation, and lead-lined acoustic insulationon the bypass valves and piping.

Andrew Johnson and James McLeish of GryphonInternational Engineering Services Inc, and MikePearson of J Michael Pearson & Associates con-tributed significantly to this report.

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Robert W Anderson is Manager of Com-bined Cycle Services—CT Operation forP ro g ress Energy Inc, Raleigh, NC. He is amechanical engineer who has managed,operated, and maintained a variety of equip-ment, systems, and powerplants for over 30years—including steam, nuclear, and gas-turbine facilities. Bob also serves as chair-man of the HRSG User’s Group, an educa-

tional organization that fosters collaboration among users,OEMs, and service providers for the advancement of HRSGdesign, operation, and maintenance.

Henk van Ballegooyen is President ofGryphon International Engineering ServicesInc (GIE), a multi-disciplinary consultingengineering firm based in St. Catharines,Ont, Canada. Services provided by GIEinclude conceptual and detail design ofsteam and power generating plants. Thiswork often includes detailed re v e r s e - e n g i-neering and testing of existing HRSG super-

heaters, drums and economizers; steam turbine/generator;condenser and cooling water systems; HP and LP bypassdump systems; steam vent systems; HP and LP piping sys-tems; fuel gas system; and water treatment systems to iden-tify and assess modifications required to allow a given plantto commence cycling duty. Prior to founding GIE in 1990,Henk had extensive powerplant experience in Euro p e ,including the design of plants for South Africa.