HRSG Welding

8/13/2019 HRSG Welding

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32 COMBINED CYCLEJOURNAL, Second Quarter 2006

HRSG USERS GROUP

Over the past 13 years,the annual conferenceand exhibition of the

HRSG Users Group(HRSG UG) developed

a reputation for great venues, excep-tional food, andmost important-lya solid technical program thatprovided participants the practicalinformation needed to reduce out-age time and O&M costs, increaseplant efficiency and availability, andlower emissions. The 2006 event,held last March at the BroadmoorHotel in Colorado Springs, certainlyenhanced that reputation, exceedingexpectations both in creature com-forts and in program and exhibitioncontent.

Delegates were treated to the orga-nizations most impressive venue

and culinary service yet: The Broad-moor is one of only three resorts inthe country to have earned the AAA

Five-Diamond rating every yearsince the awards were establishedin 1976. This years informationexchange comprised two jam-packeddays of insightful presentations byindustry experts, plus the tradi-tional user-driven discussions. Thelatter were skillfully moderated byChairman Bob Anderson, princi-pal, Competitive Power ResourcesCorp, Palmetto, Fla ([email protected]), and summa-rized in a special report for attend-ees by Rob Swanekamp, executivedirector of the HRSG Users Group([email protected]).

A relaxed, but productive, exhibi-tion enhanced collaboration among

users, manufacturers, architect/engineers, consulting engineers, andservice providers in attendance (see

montage above).Another bonus. All attendees

received a copy of the HRSG UsersHandbook,a new 500-page referencework that contains a wealth of prac-tical knowledge on the procurement,design, operation, and maintenanceof heat-recovery steam generators.The editors of the COMBINEDCYCLE Journal consider this hand-book a must-read for the combined-cycle/cogen community (to orderonline, access www.hrsgusers.org).

From the users vantage point inthe Broadmoor Hall, it was clearthat the groups Steering Commit-teeAnderson, Swanekamp, YogeshPatel of Tampa Electric Co, and Paul

HRSG USERS GROUP

New tools for tube repair,

analysis of risks posed bysafety/relief valve clinic


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COMBINED CYCLEJOURNAL, Second Quarter 2006 33

HRSG USERS GROUP

Fernandez of GE Contractual Ser-vicesworked hard to produce anenjoyable event, while compiling a

program that delivered high-calibertechnical information on HRSGs andtheir associated steam systems.

Constant format,fresh infoThrough the years, the meetingsformat has remained relativelyconstant: A series of Open ForumDiscussionsself-help clinics, if youwilldominate the agenda, withonly a handful of prepared presenta-tions sprinkled in to cover particu-larly challenging issues.

While this years presentationswere interesting and on-point asusual, the things that really separate

welding best practices,prolonged low-load operation,highlight annual meeting

1. Steam-plant issues raised by owner/operators at the 2006 HRSG Users Groupconference included methods to monitor HRSG performance, the pros and consof all-volatile water-chemistry treatment, and the challenges associated with con-trolling superheater and reheater outlet temperatures while at low loads


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this event from the rest of the confer-ence pack are the number of attend-eesupwards of 350and the type

of people actively contributing to thediscussion topicsmostly end users(plant managers, O&M supervisors,operators, maintenance techs, chem-ists, and so on), with a significantand vocal contingent of plant-support

authorities (HRSG OEM engineers,water-chemistry specialists, plantservice contractors, engineering con-

sultants, etc). This technically skilledassembly, unleashed to raise whatev-er steam-plant issues they currentlyface, ensures that the discussions arefresh and timely year after year.

Note that the delegate assembly

was particularly robust this year,thanks in part to the active par-ticipation of the dog that wags the

tail of this industry: Several leadersfrom GE Energys team that speci-fies and delivers complete combined-cycle plants participated in the 2006event. Their technical contributions,and the customer feedback theyreceived, were of significant value tothe industry.

The formal presentations deliv-ered at this years conference aresummarized in the large sidebarsincluded with this report. What fol-lows are some highlights of the OpenForum Discussions, the centerpieceof the HRSG UGs annual conference

(Fig 1).

Heat transfer opens themeetingThe conference opened with a ques-tion from a refinery operator concern-ing the tools and methods available topredict HRSG thermal performance,given gas-turbine (GT) and duct-burner theoretical heat input data.This design-related discussion thenevolved toward practical methodsthat operators can apply to monitorHRSG performance, given the lim-ited instrumentation installed at thetypical plant. For instance, operatorscan trend the pinch, approach, and

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2. Many HRSG users experience tube fouling caused by ammonium salts. Butone user at the conference was experiencing this fouling only on the side tubesof his HRSG. Possible causes and cures for this localized deposition were dis-cussed by the 350 attendees


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stack temperatures, one consulting engineer explainedto the crowd. Discussion of this topic might have goneon longer if one of the attendees hadnt noted thatChapter 5.2 of the HRSG Users Handbookdubbedthe Blue Book by that individualcovered this topicin great detail.

Next came a good example of a user bringing a vexingquestion to the meeting and getting a definitive answer

on the spot. A steam specialist from a southeastern util-ity displayed a photo of salt deposits that had formed inthe cold end of one of his HRSGs, and asked of the audi-ence why these deposits seem to be forming only alongthe sides of the unit, rather than uniformly across theHRSG (Fig 2).

After studying the photo for a minute, one experi-enced consultant suggested that the pattern was typi-cal of cross-flow tube coils where cold inlet water startsat the side of the coil, and moves across the tube bankprogressively picking up heat. The end result is sometubes being warmer than others. The salt depositionselectively builds up on the colder tubes, the consultantexplained.

The user thought he had his answer, until an engi-

neer from that HRSGs OEM interjected that this par-ticular design did not use any cross-flow coils. The OEMengineer proposed that, instead, these deposits mightbe forming during shutdown when a slipstream of cold-er air along the sidewalls is created because of naturaldraft. Often the corrosion and deposition phenomenaare worse when a unit is not operating, than whenonline and up to temperature, he explained.

The proverbial light bulb went off in the usershead, as he realized that other evidence he hadobserved supported the OEMs suggestion. The userhad found a very similar, localized pattern of ammo-nium salts collected around the HRSGs manway doorgasketsgaskets that were known to be experiencing

air in-leakage.Unfortunately, not all questions during the OpenForum Discussions can be as definitively answered asthis one, even by the large group of experts and opera-tors gathered in the room. For example, a user from theMidwest with experience in fossil-fired boilers askedhow many years of service the typical HRSG can beexpected to deliver before it requires chemical cleaning.The response: It depends.

As other attendees explained, there are many vari-ables affecting this intervalvarious design factors, theoperators execution of the water chemistry program,and base-load versus cyclic operation, to name a few.The answer also is not definitive because of the lack ofdata within the industry on tube-deposit formation.

The fleet of high-pressure HRSGs in power-genera-tion service, compared to the fleet of fossil boilers, isstill quite young, and little, if any, empirical data ontube deposition have been collected and analyzed. Asa result, discussion of this question centered aroundwhen, where, and how to take evaporator tube sam-ples to analyze the rate of deposit formation in yourHRSG.

While a definitive answer for the HRSG communityawaits such data, a consensus seemed to emerge amongthe veterans in attendance that a well-designed andwell-run HRSG can be expected to go without chemi-cal cleaning for 10 to 15 years. Of course, it only takesa few hours of operation outside accepted water chem-istry limits to create a situation that could necessitateimmediate chemical cleaning, Chairman Andersonpointed out.

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HRSG USERS GROUP

Ever since riveted pressure ves-sels went the way of the horsen buggy, welding has been an

essential and common activity in theconstruction and maintenance of boil-ers and piping systems. Most userssee it going on during plant outagesand some may even get involvedin its planning and execution. Mostalso can list some of the well-knownproblems associ-ated with weld-ingsuch as thefrustrating lengthof time required(often on the crit-ical path) for fitup, welding, andpost-weld heattreating (PWHT)of large p ipe;rework of reject-ed welds; andfinding sufficient numbers of skilledwelders when needed (Fig A).

While these are significant issuesworthy of the maintenance managersattention, there are many other less

obvious considerations associatedwith planning and executing a weld-ing job that can mean the differencebetween an on-budget, on-sched-ule project and the proverbial trainwreck. At the 2006 HRSG UsersGroup meeting, William F Newell, Jr,PE, IWE, a vice president of Euro-weld Ltd, Mooresville, NC ([email protected]) shared with the audienceseveral of these less obviousbut

still importantwelding pitfalls, cov-ering both technical troubles andfinancial flops.

Measure twice, cutonceNewell opened by emphasizing theimportance of planning your out-age well in advance. Key planningsteps include collecting the appli-cable specifications and drawings,identifying predictable trouble spotsbased on previous problems andfleet history, deciding how to workwith dissimilar metal joints, obtainingsufficient materials inventory, and soon. He pointed out that these funda-mental planning activitiesthoughperhaps a bit tedious and unexcit-ingcan prove highly valuable to asuccessful outage.

Following the review of outage-planning fundamentals, Newell dis-cussed some of the planning tasksthat are specific to welding projects.These include becoming familiar withcodes, NDE techniques, and accep-

tance criteria; selecting the optimumweld processes and consumables foreach job; procuring the right materi-als; creating and implementing quali-fied procedures, engaging qualifiedand productive welders, andlastbut not leastsatisfying the autho-rized inspector and/or regulatorybodies so all repairs are acceptablefor a plant restart.

In Newells experience, observing

ASME Boiler & Pressure Vessel Code(Code), specification, and jurisdic-tion criteriacoupled with hiring theright personnelcan lead directly toenhanced equipment reliability andhigher plant availability.

But someone at the top mustappreciate and understand the job,he said. Thats not always easygiven the complexity of welding withadvanced alloys. Older materialswere very forgiving, compared withthe alloys in todays combined-cycleplant, Newell pointed out. And justas welding has gotten more compli-cated, fewer and fewer people aretaking the time to truly understandthe discipline.

Material shortages

Another very timely aspect of hispresentation dealt with todays chal-lenge of procuring sufficient materi-als for welding projects. Such itemsas welding rods, wires, fluxes, andspecial-alloy piping are in short sup-ply. To a large extent, Newell said,

these shortages are attributed to thesignificant amount of industrial con-struction going on today. That mayseem surprising to power generationprofessionals in North America andEurope, because new constructionin this industry and in these locales isquite sluggish. But there is so muchwork going on in other parts of theworld, particularly in China, Newellsaid, that it is literally sucking up the

Welding techniques for asuccessful plant outage

Newell

B. Successful welding jobs begin with proper prepara-tion and fit-upA. Welding projectsare a part of virtually all combined-cycle/cogen plant outages. Keeping them on-scheduleand within budget can be a serious challenge


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HRSG USERS GROUP

raw materials we need for our powerprojects.

Compounding that problem is thefact that most of the weld metal forchrome-moly pipingused exten-sively in combined-cycle/cogenplantsis being made overseas

these days. This adds perhaps fourto six weeks to the delivery timeforshipment across the oceanandoften keeps much of that piping in itscountry of origin. Why should steelproducers ship it to far-flung reachesof the world, when they can sell it athandsome profit to a nearby con-struction project?

Its a similar situation even for thebase metals, Newell said.Reportedly there is only oneUS vendor that can makeseamless pipe, and that sup-plier is very busy. We putin an inquiry for strip clad-ding in 250-ton increments,and we were laughed at,Newell reported. They said,Dont bother us. Were mak-ing money selling the cheapstuff. We dont want to makeanything sophisticated. Andthis was a premier melter!

Newell cautioned HRSGusers that this situationcould become very criticalif they have an emergencyneed for a particular fitting

or special piping. Trying toget that special fitting, orforging, or valve you need[in an emergency] could bevery problematic, he said.Moral of the story, as Aesops antunderstood but his grasshopper didnot: Better lay in some stores whileyou can!

Cost and schedule

Estimating and controlling costs andschedule challenge plant managersduring most welding projects. Thats

because there are many variablesthat can enter into the equation.Newell offered a few rules of thumbthat hes found handy:n Regardless of the job, assume pre-

heat and PWHT will be required,and budget your money and timeaccordingly.

n Regardless of the job,skilled craftand welders are necessary. Dontthink you can save money by hir-ing on the cheap.

n Regardless of the job, certifiedmaterial test reports for weld metalshould be required because theyllreduce your project headaches.

n Regardless of the job, demand

good fit-up and youll save time inthe long run (Fig B).

n For every welding dollar spent,figure labor and overhead will cost86 cents, equipment (manual) sixcents, and filler metal and shield-ing gasses eight cents.

To minimize time, Newell sug-gested that users:n Coordinate weld-groove geom-

etries with welding process selec-tion.

n Use gas tungsten arc welding(GTAW, TIG, heliarc) when pos-sible. Although considered slow, itis faster in the long run than otherprocesses on small-bore or stan-

dard-wall piping.n Implement processes to be used

based on who shows up. Inother words, coordinate the selec-tion of welding processes with theavailable skilled labor pool.

n Pre-select or pre-qualify yourheat-treatment contractor.Plan how the heat treatment on

each job will be conducted. Is it best

to preheat and weld, then to performPWHT on a number of joints? Willyou heat-treat single versus multiplecomponents? Should you cluster theheat treating activities in one area,or heat-treat individual componentsin remote locations? Maybe its bestto use a combinationperform indi-vidual preheat, then batch PWHT (FigC).

Also plan the heat sources to beused: flame (not on the latest alloys),electrical resistance, electrical induc-tion, or portable furnaces (gas orelectric). Today it is not uncommonfor the alloys and configurations todictate the methods available.

To increase productivity withoutsacrificing quality, Newell said youshould cull the welders in the weldtest shoprather than on the job.High reject rate in the test shopalways equals lower reject rate onthe job, and vice versa. Newell rec-

ommended requalifying each welderon important projects rather thanaccepting CommonArc or UA certifi-cations unless you have prior positiveexperience with these group qualifi-cation efforts.

As evidence, he discussed a casestudy where all of the above stepswere considered during the planningstage. The project competed ahead

of schedule with a rejectrate of less than 1%. Ofcourse, there were otherdetails during execution ofthe work that also had agreat impact on this suc-cess. For example, thebest planned welding jobwont be successful if youdont keep the arc on andhot, he said.

No welding processpermits deposition of weldmetal 100% of the time.Some things that requireinterruption of weldinginclude changing elec-trodes, the welder repo-sitioning, chipping slag,

grinding, preheat/PWHT,joint preparation and per-sonal time.

Selection of the weldingprocess also can have an

impact on welding productivity. Forexample, typical operating factors forsome common welding processeswhen used in the shop are 30% formanual GTAW and shielded metal arcwelding (SMAW or stick), 40% forsemi-automatic gas metal arc welding(GMAW, MIG) and flux cored arc weld-ing (FCAW), and 50% for fully auto-matic submerged arc welding (SAW).

Al l of the above va lues are atleast 10 percentage points lower forfield application. This 10 percentagepoint reduction correlates with onlysix additional minutes each hourwhen weld metal is not being depos-ited, but it can drive a 21% to 50%increase (dependent upon electrodesize and process) in the cost perpound to deposit the weld metal.

One of the things you can do toincrease welder productivity is toselect welding processes and con-sumables that appeal to the opera-tor. This means those that producea smooth arc, good control of thepuddle and bead, reduce weld clean-

C. Post-weld heat treatment is needed for many weldingprojects, and is essential if youre dealing with P91/T91material


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ing and grinding by producing slagthat is easy to remove, produce no

spatter and produce good beadshape. Its also important, Newellsaid, to take steps that reduce thewelders personal time requirements(distance to water cooler and restroom) and eliminate non-weldingtasks and diversions.

As for keeping the arc hot, Newellexplained that reducing the current10% below optimum when usingthe FCAW process will result in adecrease in weld metal deposi-tion rate of 13% and an increase ofdeposition cost of 15%.

Anothe r fact or th at ca n have

a significant effect on the cost ofthe welding project and its sched-ule is the choice of welding wirewhen using the FCAW process. Forexample, a low-alloy wire with anefficiency of 60% may cost $10/lb,while a wire with an efficiency of90% may cost $14/lb. Therefore, toget one pound of metal depositedrequires 1.7 lb of the less expensivewire, but only 1.1 lb of the premiummaterial. If thats not already badenough, most of the lost metal endsup as spatter that requires grinding.

You can see where this is going.If you do the math, the cheap wireactually costs $17/lb of deposited

metal while the more expensive wirecan be deposited for $15.40/lb.

Which one would you choose?

Using Code as king

One of Newells concluding mes-sages dealt with the Code, andthe propensity of todays usersto rely on it as some sort of infal-lible construction handbook. Manypurchasers of combined-cycle andcogeneration plants are under theimpression that their specificationswill be sufficient as long as theyrequire compliance with the Code.But the sole purpose of the Code,

Newell reminded the audience, isto ensure safetyto prevent cata-strophic failures and the resultantloss of life, injury, and property. Itsa set of minimum requirementsonly the bare-bones minimum. Ifyou think you need more, then itsup to you to do more.

The comment, triggered by aquestion from a user in the audience,prompted Newell to regale the crowdwith a short anecdote based on hismany years of experience in weldingand on Code committees. We weresitting in an ASME Strength of Weld-ments Subgroup meeting, Newellrecalled, and three Fellows present

reasoned that the problem with theCode and the allowables and every-

thing else is that no rule-of-thumbis provided as a guide and youngdesigners sitting in front of their com-puter screens today actually believewhat theyre seeing.

In the past, Newell continued,designers would determine whatthe Code required, and would thenadd a margin of safety. If I need aninch, Ill use an inch and a quarter.If I need an inch and a half, Ill usean inch and three quarters. If I needfive inches, Ill use seven. But thosedesignersand their conservativedesign philosophyare no longer in

charge.Newell also pointed out that the

advanced materials being used inHRSGsand in the next genera-tion of fossil boilersare simply notas forgiving as the older, traditionalsteels. Plus were running thesecomponents at higher stress levels.

Net result, Newell said, is thatusers do need to be more diligentin their specification, than to simplysay comply with ASME Code.Meanwhile, Newell, along with manyother materials and design experts,are working within ASME commit-tees to set more prescriptive stan-dards when appropriate.

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At early HRSG UG conferences,

leakage around drum-door gasketsand their catastrophic failure wererevealed to be relatively commonproblems in the industry. Hence, thereasons causing the leaks and themethods to avoid them usually gar-nered considerable discussion. At the2006 event, drum-door leakage wasraised yet again as a serious issue,suggesting that even after more thana decade of US experience, this prob-lem remains. As usual, some excel-lent tips were bantered about, butthis years discussion of drum-doorgaskets didnt consume a lengthytime period because this is anothertopic now covered in detail in theHRSG Users Handbook

Water chemistry, asalwaysDiscussions surrounding waterchemistry are always popular atHRSG UG meetings, and the 2006event was no exception. This yearthe topic that seemed to garner themost interest is the desire, if not anoutright trend, for operators to movetoward all-volatile treatment (AVT)and away from their conventionalphosphate treatment programs (Fig3). Discussion on this topic was solively, that an excerpt is presentedbelow. It was extracted directly fromthe meeting notes with permission ofthe HRSG Users Group.

User: One of our consultants has

recommended going to AVT. Werehaving issues with phosphate hide-out; result is that every time we startup, pH drops down in the 8-range forprobably the first one or two hoursthat were operating. If people arenot switching to an AVT program,Id be curious as to why theyre not.What are the concerns?

Chemical vendor: To answer thefirst question, about experience inchanging to AVT-O: It is happeningright now in many plants. Theyve

had, generally, a good degree ofsuccess. But there are a number ofqualifiers that you have to meet atthe plant level, and at the chemistrylevel, in order to make that changesuccessfully. Issues associated withdissolved oxygen in the hotwell; withair in-leakage; with what happenswhen youre cycling, etc, all can beaddressed mechanically and chemi-cally.

When people have done that,theyve had good results, in terms ofiron transport, and generally theyrevery satisfied with the switch to

AVT-O, and also with the change tono phosphate in the drums. So itsbeen effective, and from my point ofview its an industry trend that wellsee more of. To make the transition itrequires taking care of the mechani-cal, as well as the chemical, things.

Chairman Anderson: I want toask a couple of follow-up questions.When you say AVT-O, are you talk-ing about true all-volatile treatment,or are you just talking about very lowphosphate levels to avoid the hide-out. And if youre talking all-volatiletreatment, are you using a conden-sate polisher?

Chemical vendor:The terminol-ogy can be a bit confusing. Of course,

3. Water-chemistry authoritieslike Rich McKee (left) and Jim Witherow,of Nalco Co, Naperville, Ill, and Scientech LLC, Clearwater, Fla, respective-lyresponded to users questions about moving away from their conventionalphosphate treatment programs and toward all-volatile treatment

Continued from page 35


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we always use all-volatile treatment

in the condensate/feedwater system,so even if you use phosphate in theboiler, you are on an AVT programin the condensate/feedwater. The

AVT-O specifically refers to no useof passivatorsso no hydrazine, nocarbohydrazide, no other chemical

passivator for an all-steel system.

And that has been a very successfulchange, whether youre still usingphosphate in the drums or not.

Now, going completely to a non-phosphate treatment in the drum issomething we also see people doing,without condensate polishing, as

long as they have tight condensers.

Many plants recently commissionedthat dont have condenser tube leakshave gone to all-volatile treatmentwith no polishersuccessfully.

Some go to a backup of phosphatein case they do have a condensate cat-ion conductivity issue. Others have

Workshop to explore water chemistry, outage practices

The HRSG Users Group, an organization that welcomesas members all combined-cycle/cogen professionals,recently announced dates for its next two events. Fur-

thest away is the 15thAnnual Conference & Expo, whichwill be held Mar 26-28, 2007, in Kansas City, Mo. Prelimi-nary details are available at www.hrsgusers.org.

This fall, the organization will conduct another of itspopular Steam Plant Workshopsthis one co-locatedwith Power-Gen International, in Orlando, November 28-30. Workshops, conducted periodically, are intended tosupplementnot replacethe annual conference. Thelatter encourages free-ranging discussion on a broadarray of issues facing users; the workshops are in-depthseminars that focus on one or two topics.

First day of the fall 2006 workshop will address thelatest advances in boiler water/feedwater chemistry. Pre-sentations include:n Understanding AVT-O (oxidation) and AVT-R (reduc-

tion).n Pros and cons of feeding amines in HRSGs.

n New guidelines on phosphate treatment programs.n Caustic treatment: An overlooked program option.n Online particle counters for boiler water control.

Day Two will focus on best practices for outage main-tenance, with presentations on:n HRSG cold-end corrosion: Causes and cures.n User experience with gas-side tube cleaning.n SCR life cycle: Minimizing fouling, degradation test-

ing, and refurbishing/replacing.n Planning and executing an FAC survey.n User experience with FAC monitoring.

The HRSG Users Group is one of the fewperhapsthe onlyuser organization serving the combined-cyclecommunity that is approved by a state board of profes-sional engineers as a Certified Education Provider. SteamPlant Workshop attendees will receive two continuingeducation units. For more details on this, and all otherHRSG Users Group activities, visit www.hrsgusers.org oremail or call Executive Director Rob Swanekamp ([email protected], 406-582-8655).


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gone to a caustic treatment, instead

of phosphate, in the drumsin factI was in some plants last week thatdid thisand thats been successfulas well. So there are many variationsgoing on, but I do see a trend in theindustry.

Independent consultant: I dis-agree completely. There is a largetrend, and its a continuing trend overthe last decade, of getting cleaner andcleaner in the evaporator sectionsuntil you cant get any cleaner becausesomething stops youwhether thatsair in-leakage or condenser contami-nation from the circulating water. If

youre on a cooling tower and chlo-rides and sulfates start butting upagainst your controls, then you haveto start putting some sort of bufferingchemistry in there. In the entire loop,both high and intermediate pressure(HP, IP), AVT is becoming a veryviable process.

Im concerned about the recom-mendation to summarily removingoxygen scavenger from non-ferroussystems. Just like some others here,I came back from a conference allhot-to-trot about knocking out thescavenger/reducing agent, in a unitwith a copper condenser, and itate our lunch in a heartbeat. EPRIsays thats not supposed to happen.

EPRI says you can have 90/10 cop-

per/nickel-tubed condensers and stillget away with it. But for us, that wasnot the case.

So I would be interested in speak-ing with people who are makingthese AVT-O swaps, getting rid ofthe reducing agent. Gosh, were car-rying 9.4, 9.5, 9.6 pH levels, whichis 10 times the ammonia we usedto have when we were on an AVT-Rprogram with a copper condenser.Im curious if anybody is havingany success doing that, because itreally addresses the question: Whywould you not go to AVT-O? Thats

two parts of ammonia and 25 or 50ppb of dissolved oxygen, and thatsdeadly.

Chemical vendor: I think thedevil is in the details. Reading theEPRI guidelines carefully, they saythat if there is a copper condenserthen lets move the pH up very slow-ly. The new pH range for copper, formixed-metal systems, is 9.0 to 9.3.They suggest that if youre adopt-ing AVT-O, try going to 9.4 to 9.6,but monitor the copper levels in thecondensate both before and after thechange, and see what your systemwill tolerate. Copper pickup from thecondenser is also going to be tied tothe air or oxygen level, so its not nec-

essarily a blind mans step to a high

pH. Its a careful evaluation of whatyour system can tolerate.Chemical vendor: I agree with

my colleague on that. I think thatthe EPRI representatives commentin other sessions about completelyeliminating the reducing agent wasdirectly related to the fact that mostof these HRSG systems are all-steel.They do not have any copper alloysin them. So AVT-O is obviously agood option to consider.

I want to make a comment onthe one fellows statement that hesthinking of switching because of

phosphate hideout problems. That isa big driver for this switch. But dontforget that you also have in yourarsenal the ability to go to caustictreatment, or to what I call the low-level alkaline-phosphate programwhere you carry the two to four partsof phosphate, but you carry some freehydroxide alkalinity.

You try not to run equilibrium-phosphate chemistry, because oneof the big drivers of hideout in theseHRSGs is the dependence on ductburners; it can be the high energyinput from them that affects the solu-bility of the phosphate if youre run-ning at too high a level. We also knowfrom this forum that one of the major

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HRSG USERS GROUP

The most common location forleaks to occur in HRSGs is attube-to-header welds. Some-

times, the leak will be in the front orrear tube row ofa module, alonga lower header,and quite acces-sible for repair.More often, how-ever, the leak islocated in a tuberow in the inte-rior of a module,and is thereforeextremely diffi-cult to access. To reach the leaker,many undamaged tubes must beremoved and replaceda processoften described as cutting yourway in and welding your way out.Not only is this time-consuming andexpensive, but it often leads to futurefailures of the tubes that had to bedisturbed for access.

Another repair method sometimesused on inaccessible tube-to-headerwelds is to cut a window in the back

side of the header, on each end ofthe failed tube, and then weld a pluginto the tube openinga process ofabandoning the tube in place. MostHRSG coils can handle a few aban-doned tubes without serious thermalperformance impact, but there is alimit to how many times this methodcan be applied.

Tube-to-header leaks

In his presentation at the 2006 HRSGUsers Group meeting, David Gandy,senior project manager for materi-

als and repair, EPRI, Palo Alto, Calif

([email protected]), describednew, specialized tooling that canimprove on these traditional meth-ods. The new tooling allows removaland replacement of the leaking weldusing field machining tools and aremote welding device. The new toolsgain access to the damaged area via

a precisely machined window cut into

the back side of the header.The proprietary process and spe-

cialized tooling was developed forEPRI by Encompass Machines Inc,Rock Hill, SC. Like tube plugging,discussed above, this techniqueavoids the need to cut and replacemany otherwise good tubes. It offersthe added advantages that it leavesthe repaired tube in-servicehenceno reduction in HRSG thermal per-formanceand it requires only awindow weld in the header adjacentto the leaknot in the headers onboth ends.

Acc ordin g to Ga nd y, th e ne wequipment provides precise controlof tube and tooling alignment viaa precision base-plate strapped tothe header, and mandrels to provideclose tolerance weld fit-up and highquality full-penetration welds. Theresult, Gandy reported, is considereda permanent repair.

Heres the process: The headerwindow and the internal headerweld prep are precisely and rapidlycut using specially shaped carbon

electrodes, and electrical dischargemachining (EDM) technology (Fig A).Next, a precisely measured lengthof the original tubing (containingthe crack) along with the originaltube-to-header weld is removedby remote machining through theheader window. A custom-machinedreplacement oversize tapered stubis then pressed into the header, andremotely welded on each end, to thetube and header respectively (Fig B).All tube and stub welding is automat-ed, and performed from the inside.Finally, the header window is manu-

ally welded back into place, and any

New technologies to facilitateHRSG tube repair

EDMassembly

Base plate

A. One new tube-repair methodintended for leaks at tube-to-headerjointsgains access to the damagedarea via a precisely machined windowcut into the back side of the header.Applicable to header diameters rang-ing from 3 to 12 in., the techniqueshould reduce the need to plug leakingtubes or disturb nearby good tubes

Gandy

failure mechanisms in HRSGs hasbeen over-feed of phosphate, becauseof hideout, that causes acid-phos-phate attack. This is a critical issueto consider if you want to move into

AVT-O. If you have an all-steel sys-tem, theres no problem. If you have asystem with a copper-alloy condenser,then you must consider the earliercomments by my colleague.

Chairman Anderson: Are thereany users here who are using AVTin their evaporators? If so, can youshare with us why you are, and howthat program is working out for you?

User:Yes, weve switched to AVTand only using ammonia. One ofthe big reasons we could make theswitch is because were air-cooled.We dont have a cooling tower, so weavoid the issues that come with it.Its been three years since we madethe switch. We find it easier andmore cost-effective to control pH.We no longer use any other chemi-cals regularly; however, occasionallywell use caustic for additional pHsupport on the drumsif we startgetting high on the condensate. Cop-per transport is not an issue for us.

And we have been seeing steadilydecreasing iron.

Were now six years old, and origi-nally we had a lot of iron transportwhen the air-cooled condenser wasbreaking in. I dont know how much ofour decrease in iron can be attributedto the switch to AVT, and how much isattributed to the air-cooled condenserfinally getting passivated. Regardingdissolved oxygen in the feedwater:Were real close to 10. Weve got thedeaerator working quite well.

Ive heard a lot of people talkingabout demin makeup. Sometimes


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HRSG USERS GROUP

necessary post-weld heat treatmentis performed.

The supplier provides tooling andtrained technicians as a contractservice for EPRI members and non-members alike.

Leaks along the tubelengthWhen water chemistry is not man-aged well, under-deposit corrosioncan cause tube leaks along a tubeslengthrather than at the more com-mon tube-to-header weld. If locatedsome distance from a header, theleaks cannot be repaired using thetooling described above, Gandypointed out. In these cases, tra-ditional tube plugging or cuttingin/welding out probably are the onlyoptions.

But Gandy described to the groupanother recent innovation that mightbe useful for some of these leaksalong the tube length. Like the tech-nology described in the first half ofhis presentation, this technique alsowas developed for EPRI, this time byCarolina Energy Solutions, Rock Hill,SC. It requires removing a preciselymeasured length of original tubing viaconventional non-flame cutting meth-ods. The tube ends are then preppedand a prefabricated replacement sec-tion is installed.

Why is that innovative? Becausethe welding is performed remotelyfrom theinsideof the tube, typically inonly one pass per end. This is accom-plished using new remote weldingtooling through a precisely machinedoval window in the replacement tubeswall. Once the tube ends are weldedand inspected (both inside and out),a precision-machined section of tubematerial is manually welded into thewindow opening.

This is considered a permanentrepair, Gandy reported, since thecarefully controlled geometry of the

window produces no large stress

concentrationsas are often foundin field-fabricated window welds.According to the supplier, use of thistechnique is faster than conventionalexternal tube welding, and it provideswelds of superior quality. It has theminor disadvantage, Gandy conced-ed, that tube sections of appropriatedimensions and materials must beprefabricated with the oval windowand window closure plug.

Although the technique was devel-oped for use in fossil boilers, Gandy

expects it to find use in HRSGs

where access for conventional weld-ing to the back and sides of tubingis limited by the close spacing ofadjacent tubes. It also may be putto good use in quickly and reliablyremoving tube samples for determi-nation of when to chemically clean anHRSG. Premachined tube sections,the remote welding equipment, orturnkey field service using this tech-nique is available from AggressiveEquipment, Lawrenceville, Ga. EPRImembership is not required to pur-

chase or contract its use.

Window

Window

Tube

C. Leaks along the tubelengthmight benefit fromanother new repair tech-nique, which removes aprecisely measured, oval-shaped length of originaltubing via conventionalnon-flame cutting methods(left). The tube ends are thenprepped for welding and aprefabricated replacementsection is installedall per-formed remotely and fromthe inside diameterof thetube (right)

B. A precisely measured lengthof theoriginal tubing (containing the crack)along with the original tube-to-headerweld is removed by remote machiningthrough the header window (left), afterwhich a replacement oversized stub ispressed into the header, and remotelywelded on each end

we have some tube leaks and thecondensate dissolved oxygen will behigh. Weve got a pretty tight HRSG,I think right now were down to the20s or so. Ammonia level at conden-sate discharge: I dont have any idearight now. Chemistry savings: Obvi-ously weve had some, because thechemicals are a lot cheaper. And itseasier for the operators to test thechemistry. I dont know if weve hadmore tube leaks, or fewer, directlyrelated to the AVT switch. Regardingthe oxide layer: Its kind of red in thedrums, and its black in the air-cooled

condenser and LP turbine exhaust.Chairman Anderson: Thanks.

Its very helpful to hear directly fromusers with their experience on this,particularly since youre out there atthe leading edge of the technology.

Those interested in learningmore about transitioning away fromphosphate treatment to other chem-istry programs, as well as what thelatest guidelines are for phosphateprograms, should consider attend-ing the HRSG UGs upcoming SteamPlant Workshop, where a full daywill be dedicated to presentations

and discussion of water chemistry(see sidebar, p 40).

Confounding controlsquestionsControl systems was the third of 10Open Forum Discussions in ColoradoSprings. Several users reported dif-ficulty in controlling superheaterand reheater outlet temperatureswhile at low loadsparticularly withHRSGs operating behind a 7FA gasturbine (GE Energy, Atlanta).



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HRSG USERS GROUP

Many of todays combined-cycle plants are compelledby market demands to shut

down and restart frequentlywheth-er the plant was designed to do soor not. These repeated start/stopcycles, as readers of the COMBINEDCYCLE Journal and attendees ofHRSG Users Group conferenceshave come to understand, imposessubstantial wear-and-tear on heat-recovery steam generators.

But market demands also areforcing many plants to spend longperiods operating at low loads. Atthe 2006 conference, Scott Wam-beke, systems engineer for HRSTInc, Eden Prairie, Minn, ([email protected]) discussed the lesswell-known risks of this low-loadoperating mode. For purposes of hispresentation, Wambeke defined low-load as being below 80% of baseload, although some gas turbines(GTs) permit operation as low as30% of the nameplate rating. Thereis a long list of potential steam-plant problems caused by low-load

operations, not all of which are

intuitive. While Wambekefocused on the first fourof these, he listed themany potential low-loadproblems as:n Economizer and pre-

heater fatigue.n Desuperheater over-

spray.n Failure of non-pressure

partssuch as perfo-rated plates, turningvanes, liners, and baffles.

n Operation below the design base-ment pressure (also called floorpressure).

n Insufficient catalyst temperatures.n Elevated cold reheat tempera-

tures.n Control valve throttling.n Economizer steaming.n Off-design duct firing.n Vibration.n Water chemistry.

Economizer and preheaterfatigue can occur during low-loadoperation if feedwater flow instabilityexists. Flow instability causes some

tubes to fluctuate in temperaturerelative to their neighboring tubes.The resulting differential thermalexpansion between these tubeswhich in many horizontal HRSGs arerestrained between rigid top and bot-tom headersproduces the stressnecessary for fatigue (Fig A).

All types of economizer/preheaterpanels (multiple row, single row, andreturn bend) are susceptible to thiscondition. Wambekes case in point:A feedwater preheater that was suf-fering repeated tube leaks at spe-cific tube-to-header welds. A study

performed by HRST indicated thatlow water velocities were occurringwhen the unit was operating at lowload, resulting in flow instability (FigB), hence differential thermal expan-sion. The solution? HRST workedwith the client to modify the internalheader flow baffles in such a wayas to increase flow in the affectedtubes.

Desuperheater overspray occurswhen more cooling water is sprayedinto the steam flow than can becompletely vaporized. When theresulting steam/water mixture entersthe superheater panel, the heavierwater droplets take a straight path

into those tubes directly oppositethe panels inlet nozzle, while drysteam makes the turn and entersthe other tubes. The tubes receivingthe wet steam are quenched sig-nificantly and therefore experiencesignificant tensile stresses, com-

pared to the other tubes. The tensilestresses can be so significantthat these tubes often arefound elongated and warpedout of position during visualinspections of HRSG inter-nals. In severe cases, thetubes can be cracked and/orpulled away from the header.

What does low-load opera-tion have to do with desu-perheater overspray? As GTload is decreased, Wambeke

explained, steam flow through thesuperheaters and reheaters alsodecreases. Depending on the exhaustprofile from the GT, this may shiftheat absorption in the HRSG to favorthe superheaters and reheaters. Atthe same time, reduced steam veloc-ities around the desuperheater mayresult in a less-than-optimal mixingenvironment for the steam and water.

Making matters worse, some GTsnotably the 7FA (GE Energy, Atlan-ta)actually produce higher exhaust-gas temperatures at low load than atbase load. The result is that very highdesuperheater spray-water flow is

needed (to prevent exceeding designsteam temperatures) at a time whenspray-nozzle performance is prob-ably degraded.

How can you tell if your HRSG isexperiencing desuperheater over-spray? Wambeke pointed out thatone obvious indication is super-heater or reheater tube failures nearthe header inlet nozzles. Warpedtubes can be another indication,but thorough investigation may benecessary to eliminate other pos-sible sources of tube warping. If thesteam temperature downstream of

your desuperheater has less than 35deg F residual superheat, you prob-ably have high risk of an overspraycondition. Likewise, if the desuper-heater is installed near upstream ordownstream pipe bends, you prob-ably have poorly mixed and poorlyvaporized spray and overspray-likesymptoms (Fig C).

What to do? Depending on thesituation, here are a few possibleoptions that Wambeke presented:n Modify steam piping around the

desuperheater.n Install a different style desuper-

heater less prone to performanceloss during low steam flow periods.

Risks to HRSGs inlow-load operation

Gas flow

Gas flow

A. Tubes are restrained betweenrigid top and bottom headers, in ahorizontal HRSG. Differential thermalexpansion can then produce thestress necessary for fatigue

Wambeke


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HRSG USERS GROUP

n Modify superheaters to reduceheat pickup.

n Install a steam bypass around thesuperheater.

n Investigate if higher superheateroutlet steam temperature is per-missible without causing otherproblems to piping, steam turbine,etc.

n Reduce GT exhaust temperature.

Look at non-pressureparts, tooPressure parts are not the only com-ponents that can take a beating

during low-load operation, as Wam-bekes presentation made clear.Reduction in exhaust-gas flow andchanges in exhaust-gas tempera-ture patterns occur, when movingfrom base- to low-load operation.This can cause non-pressure partsin the exhaust-gas streamsuchas perforated plates, turning vanes,liner systems, and tube supportstooverheat or experience unanticipatedvibrations (Fig D). It also can degradeduct-burner and catalyst perfor-mance.

Sometimes simple fixes such asstiffening components and adding

supports can solve these problems.In other cases, it may be necessaryto replace components with improveddesigns or better materials. Problemswith ductburner and catalyst per-formance may require physical orCFD (computational fluid dynamics)modeling of gas-flow profiles beforeeffective modifications can be made.

How low can you go?

Many of todays combined-cycleplants operate in sliding pressuremode. This means that as GT loadis reduced, the steam turbines inlet

Feedwater outlet Feedwater inlet

Stagnant orreverse-flow circuits

Steam outlet

Steam fromdesuperheater

Upper header

Lower header

Quenched and stretched tubesbuckle as they equalize temperatureswith neighboring tubes

Tubes below inlet nozzles arequenched and experience alarge tensile load

Thermocouple reads at or nearsaturation temperature

Superheater tubesat uniform hightemperature

B. Operating at low load can cause flow instability in econ-omizers and preheaters, which leads to differential thermal

expansion and potential fatigue damage in HRSG tubes

C. Desuperheater overspray is another potential problem induced by low-load operation. As the load is decreased,steam flow through the superheaters and reheaters also decreases, causing superheater panels to over-perform andreducing the turbulence needed for optimum desuperheater spray-nozzle performance (top right)

Ductburner

Feedwaterinlet

SCR

Superheater HP evaporatorHP economizer

LP evaporator

Gas temperature to SCRtracks saturation temperaturein tubes and steam drum.At 1200 psig, saturationtemperature is 569F;at 800 psig, 520F. SCRcontrols may stop ammoniaflow when gastemperature is between500F and 550F

Gas turbineexhaust gas

Deaerator

D. Non-pressure partsalso can be damaged bylow-load operation. These perforated plates becamewarped from overheating, caused by changes inexhaust-gas flows and temperatures

E. Operating below the basementor floorpressurecan cause several problems, among them improper function-ing of the SCR catalyst


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HRSG USERS GROUP

valves are left wide open (for maxi-mum thermal efficiency), result-ing in lower HRSG steam pres-sures. As steam pressure falls, waterand steam densities decrease andtheir velocities increase. Eventually,as Wambeke explained, a point is

reached where further increase insteam/water velocities will cause car-ryover of water into the superheateror water-side erosion of evaporatortubes and risers.

Realize too that when evaporatorpressure drops, so does evaporatortemperatureas the Mollier Diagramillustrates for saturated steam condi-tions. Because the evaporator tem-perature sets the exhaust-gas tem-perature entering the catalyst, and

because the catalyst has a minimumoperating temperature, there is aminimum evaporator pressure belowwhich the catalyst will not functionproperly (Fig E).

When the first of these lower pres-sure limits is reached, the boiler issaid to be at its basement or floorpressure. Unfortunately, significantoperating time at low load often wasnot anticipated by the OEM, Wam-beke said, and many HRSGs were

designed with relatively high floor-pressure limits.

Some possible solutions if toohigh a floor pressure limits your abil-ity to operate at low load? Increas-

The issue stems from thermody-namic fundamentals. While at highloads, steam pressure and mass floware high, and GT exhaust tempera-ture is conducive to desired steamconditions. At low loads, steam pres-

sure is lower (at least for units oper-ating on sliding-pressure control) asis steam mass flow. However, GTexhaust temperature actually is muchhigher. This apparent paradox is adesign characteristic of advanced gasturbinesparticularly evident on the7FAthat is required to maintainflame stability in the combustor.

Unfortunately, many users reportthat at low loads they are not ableto cool the steam sufficiently usingtheir interstage attemperators with-out creating an overspray condi-

tion where some spray water fails tovaporize. Overspray conditions cre-ate very severe thermal stresses andfatigue damage in piping, headers,and tubing.

A lengthy discussion ensued aboutturndown ratios, valve trim, soft-

ware options, ASME Boiler& Pressure Vessel Coderequirements, etc. It wasclear that this controls prob-lem is serious, and wide-spread. One user summedup the situation quite well:

I have to say that, in mycompany, weve becomereluctant experts on thistopic. Weve had steam linescrack and fail because ofthermal quenching.

When you run in a regulated, dis-patched-to-the-grid environment,energy control centers love the flexi-bility of a combined cycles ramp rate.So we have some units that load-fol-low pretty dramatically, and spenda lot of time running at low loadsbecause theyre serving the grid and

the spinning reserve needs. [Withthese units,] weve had problems onthe reheater side, and its thermal-quench-driven from having the highspray flows. Were working on tryingto design this out when we build anew plant.

An experienced OEMengineer astutely pointedout, This is really not acontrol problem. This is anintegration problem, of thegas turbine, the HRSG, andthe control elements. Its

very complicated. Thereare many different pos-sible solutions, and thereare many different possibleproblems.

Collaborative efforts.As men-tioned above, several members ofthe team responsible for designingcombined-cycle plants offered by GEparticipated in the meeting. Clearly,these engineers came to work. Oneexample: During the discussions oncontrols, a prominent GE designerraised the following question. Faster

starting of HRSGs is the big issuewe see for new plants. Specifically,easing or eliminating the limita-tion on GT loading. Uncouple theGT and steam cycles with respect tostartup. Low-load GT holds increasethe startup emissions, which are nowcontrolled in some areassuch assouthern California. And of coursewe need to do this five times a weekthroughout the year and still achievea minimum 30-year life. We wouldlike to think out of the box to findways to address this issue.

Talk about a spark ignition!

This question set off a benchmarkexchange of ideas between users andsome of the real decision-makers atGE. If in future plants you see GEimplementing some of the followingideas, you will know the brain trustpresent at the Broadmoor and thehealthy exchange of technical infor-mation had something to do with it:n Use of terminal attemperation to

thermally uncouple the steam tur-bine startup from the GT loadingrate.

n Use auxiliary boiler to pull vacu-um before GT startup.

n Use auxiliary boiler to warm theHRSG via steam sparging beforeGT startup.

Lant


4. Chairman Bob Anderson (right) and Bob Gunnerson of Xcel Energy dis-cuss the O&M challenges of advanced combined-cycle plants. Most of the

conference agenda is comprised of Open Forum Discussions, in which userspresent technical problems they currently face at their facilities; other attend-ees are asked to share their experiences and debate solutions


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HRSG USERS GROUP

n Use electric heating pads to warmthe HP drum before GT startup.

n Full automation of total plantstartup.

n Careful integration of all plantequipment and systems.

n Better access for pressure-partinspection and maintenance.

n Keep the difference in size betweentubes and headers as small as pos-sible.

nAllow sufficient time in the projectschedule for the HRSG designer todo a proper job.

n Specify a once-through, Benson-type boiler rather than a drum-type unit.

Taking it home

During the two days of Open Forum

Discussions, many more in-depthand valuable deliberations trans-pired, covering the seven remainingcategories: piping systems; duct-work, dampers, and stacks; valves;supplementary firing; environmentalsystems; and balance of plant (BOP).Many questions were asked, andmany solutions identified. Still otherquestions were raised that requireeither more time than a conferenceallows, or more study and analysisby both the user and the suppliercommunities.

One thing seemed clear: The hun-

dreds of users and suppliers who cometogether each year at the HRSG UGconference to share their knowledge,experience, problems, and solutionswill continue to drive the industry for-ward. As Chairman Anderson (Fig 4)reminded the crowd at the events con-clusion, This format works becauseof the people that attend and openlycontribute to the discussions. No mat-ter what your level of experience, wehope you leave each conference withmore than you brought.

Pre-conf seminar debutThis year the HRSG UG added some-thing new to its annual conference: a

one-day technical seminar held theday prior to the events official start.Damage Mechanisms in Combined-Cycle Plants was attended by 80power professionals and conductedby European Technology Develop-ment (ETD). The Surrey, UK-based

firm is an engineering advisory, con-sulting, and R&D company special-izing in plant life extension, main-tenance, materials, and engineeringissues in all types of power generat-ing and process plants.

In addition to conducting the pre-conference seminar in Colorado, ETDhas organized numerous workshops,training courses, and conferencesin Europe and Asia. The seminarwas led by Tony Lant, ETDs plantservices manager, who covered suchdamage mechanisms as:n

Creep.n Fatigue.n Thermal fatigue.nAcid dewpoint corrosion (Fig 5).n Flow-accelerated corrosion.n Stress corrosion cracking.n Corrosion fatigue.

Lant also discussed drivers inHRSG design, thermodynamic con-siderations in design, HRSG tubingand panels, welding in HRSG fabri-cation, and issues for cycling opera-tion. Following are a few excerptsfrom the seminar:

1. Ever wonder why HRSGs

are so much larger than fossil-firedboilers of similar capacity? Semi-nar attendees now know. As Lantexplained:

Temperature differencesbetweenfurnace and flue gas, and betweenwater and steamare much lowerin HRSGs. This makes heat-transferrates in HRSGs low, relative to con-ventional boilers.

Low temperature differences inHRSGsbetween the exhaust gasand the steam/water mixturesrequire the use of finned tubes, andlots of them. Not all HRSGs use allof the features for maximum heat-transfer efficiency. Tradeoffs areoften necessary. For example, tight

tube pitch with a staggered arrange-ment may not be appropriate for thecold end of HRSGs that burn oil orare equipped with an SCR.

Gas-turbine exhaust contains 100to 200% excess air. This is because ofthe need to air-cool hot parts in thecombustion system and hot gas path,to avoid overheating of GT compo-nents. This high excess-air contentof the exhaust gas results in stacklosses that are two to three timeshigher than in a conventional boiler.In addition, flue-gas flow through an

ing the catalyst temperature withoutincreasing the evaporator pressure isdifficult. Throttling the steam-turbineinlet valves can raise HRSG evapo-rator pressures at the cost of someST efficiency. Consider checkingwith the HRSG OEM or a qualified

consultant for evaluation of yourunits evaporator circulation andpossible modifications to mitigatethe problem.

Wambeke also pointed out that

operating in sliding-pressure modeand at low load can exacerbateflow-accelerated corrosion (FAC),because FAC tends to increase attemperatures around 300F. If this per-tains to your plant, you should have aprogram in place to monitor the high-

est risk areas. (Note that all HRSGusers should have an FAC monitoringprogram covering their entire steamplant, even if they never operate atlow load.)

Another component that takes abeating at low operating pressure isthe feedwater control valves whenused with fixed-speed boiler feed-water pumps. In this situation, thecontrol valves experience enormouspressure drop across their control

surfaces for extended periods oftime. Wambeke suggested that asecond low-flow feedwater controlvalve may need to be installed, tomitigate this problem.


CCGT

Fossil

6. Substantially higher stack lossesare one of the many characteristicsthat distinguish HRSGs from conven-tional fossil boilers. Such differencesresult in unique operating and main-tenance challenges, which both users

and suppliers are working to address

5. Dewpoint corrosion, clearly evi-dent on these finned tubes, is one ofthe HRSG damage mechanisms thatwere explored in detail during a pre-conference seminar conducted byEuropean Technology DevelopmentLtd


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HRSG USERS GROUP

Like all high-pressure boilers,HRSGs are required by theASME Boi ler & Pressure Ves-

sel Code (Code) to employ a varietyof safety valves (covered in SectionI) and relief valves (Section VIII) toprevent overpressure operation andeliminate the risk of explosion. Infact, because of their multiple pres-sure levels and greater complexity,HRSGs typically will have many moresafety/relief valves than conventionalfossil boilers.

Note: While the terms often arethought of as interchangeable, asafety valve is a pressure-reliefdevice characterized by rapid and fullopening (or pop action) at its set-point. By contrast, a relief valve isa device that opens in proportion tothe increase in pressure that exceedsits setpoint.

Both types of valves have a longtrack record of reliable performanceand often are considered simpledevices. But they still require care-ful attention to installation details, aswell as recurring maintenance and

testing, if safe, reliable performanceis to be attained (Fig A). In his pre-sentation to the 2006 HRSG Users

Group conference, Robert Pabst, avalve design/maintenance consul-tant for Movaco Inc, Bradenton, Fla([email protected]), provided auseful summary of those details andreminded users of the ongoing valvework they need to accomplish in theirmaintenance programs.

Start with drains, vents

Pabst began with a review of thevent and drain subsystems soimportant to pressure-relief valveoperation. For example,rainwater and condensa-tion routinely collect inthe valve body, dischargeelbow, drip pan, vent pip-ing/stack, and silencer. Ifthe small-bore, carbon-steel drain piping thatremoves this water is notinstalled correctly or isallowed to plug with rustand debris, you can counton expensive, and possibly danger-ous, system damage (Fig B).

Water left standing in vent pipingor silencers also will, if the valve lifts,immediately flash to steam. This, in

turn, can cause backpressure fluctu-ations conducive to shortened blow-down cycles, irregular valve behavior,water hammer, and internal damageto the valve, piping, and silencers.Pabst said, Incidents of shrapnelbeing ejected from the silencers arenot uncommon. Even if the valve isnever forced to lift, standing waterin the valve body is certain to causecorrosion damage to valve internals,altering the valves operationif notentirely preventing it.

Another potential problem arisesif the drains from the pres-sure-relief system are rout-ed to locations that restrictflow or otherwise cause thedrains to pressurizesuch asimproper tie-ins to other pip-ing systems. Improper tie-insto pressurized systems haveprevented safety valves fromlifting at their setpoint, Pabstreported, resulting in cata-strophic plant damage.

Heres another all-too-commoninstallation mistake that Pabst has

seen: Many safety valves have asmall-bore vent connection on thebody cap. This vent is supposed tobe piped to a safe location whereescaping steam during valve opera-tion will not cause injury to person-nel, but where it also will not restrictvent flow or otherwise create back-pressure. Pabst has sometimesseen this vent incorrectly piped intothe valves drain system. When thisoccurs, undesirable backpressureand improper valve operation is sureto follow.

Pabst recommended that plant

personnel include drain-line inspec-tions as part of each of their regu-latory-mandated valve tests andrepair tasks. Check to ensure thatno alternative source of pressure canbe introduced into the drain system,and that vent cap ports are vented toatmosphere using very short runs ofpipejust enough, he said, for per-sonnel protection as the short burstof steam vents during a lift.

The manufacturers manual is anexcellent reference for both drain-lineinstallation and inspection. Wheredrain pipe is hard-plumbed intothe valve, Pabst urged users toinstall a pipe union at the first avail-

Safety/relief valves:Installation, maintenance, testing

A. Maintenance and testing of safety/relief valves should be essential ele-

ments of any combined-cycle or cogeneration plants O&M program. Thesepressure-relief devices protect the vital investment of the facility

Pabst


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HRSG USERS GROUP

able opportunity, to facilitate futureinspections.

Valve installation

Pabst also had a lot to say aboutthe selection and installation of thevalves themselves. For example,when pilot-operated safety valves areused in high-temperature applica-tions, a heat exchanger on the pilotsensing line should be incorporatedto protect vital o-rings and sealsinside the valve. Such heat exchang-ers, Pabst reported, often are omitted

from the initial design of combined-cycle/cogen plants.

When backpressures are knownto exist that could shorten the blow-down, Pabst advised that a bellows-type safety valve should be used (FigC). A typical application in a com-bined-cycle plant is on the cold reheatsteam system, if the valves dischargeinto a single or combined silencer.

He also said that if any of yourpressure-relief valves require fre-quent, repetitive maintenance, thenyour existing valve probably is notsuitable for the given application. A

user in the audience brought up justsuch an example. Only a month afterinitial commissioning, both of his hotreheat safety valves started leak-ing. One was chattering noticeably,before the spring and stem broke.

Pabst suspected that these valves

were incorrectly specified becausetheyre operating too close to their setpressure. Go back and look at yoursystem pressures at the time the chat-tering happened, he responded, andsee if your safety valve setpoint is with-in 20% of that margin. If it is, you needto think about going to a different typeof valve, or raising the setpoint. Youcan do that within the Code, but youhave to check with the boiler manufac-turer and go through some hoops.

A final installation tip that Pabstcovered deals with initial qualitycontrol. This year the National Boardof Boiler & Pressure Vessel Inspec-tors, Columbus, Ohio, will publishsome new rules concerning QC, hereported. At issue is that some Sec-tion I safety valves are designed withcapacities greater than that of themanufacturers boiler capabilities forflow testing and cannot be tested forcapacity blowdown. Set pressuresare checked at the manufacturer.

Manufacturers normally cannotship a new valve without flow testingand still comply with the Code, butthe National Board has given suppli-

ers allowance for this constraint. Atypical allowance is a sign-off checksheet from the manufacturer notifyingthe end user that capacity blowdowncannot be tested and that an alterna-tive means of setting the blowdownwill be done. Pabst made HRSGusers aware that if they want to testfor full blowdown, they must do soafterinstallation at the plant site.

Valve maintenance,testingDeveloping and executing a safety/

relief valve maintenance programcompliant with all codes and regula-tions is important for all powerplants.Pabst offered the following sugges-tions for such a program:

Determine the code that applies toeach of your valves. A V stamp onthe ASME nameplate indicates Sec-tion I applies. A UV stamp on theplate indicates Section VIII applies.

Define maintenance intervals foreach valve based on the most restric-tive requirements among the NationalBoard, local jurisdictions, and yourinsurance carrier.

Typically, an annual pressure settest is required for all Section I safety

B. A reliable pressure-relief system also requires adequate draining of waterthat collects from each safety/relief valves vent stack and drip pan. Drain lines,typically constructed of carbon steel, can corrode internally and clog

C. Pilot-operated safety valves (left) used in high-temperature applicationsshould incorporate a heat exchanger on the pilot sensing line to protect vital O-rings and seals inside the valve. Bellows-type safety valves should be selectedwhen backpressures are known to exist that could shorten the blowdown


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HRSG USERS GROUP

valves. This should be done just priorto your annual outage, Pabst said,so that if any valve that fails to reseatduring the test can be repaired dur-ing the upcoming outage.

Typically, pressure set testing forSection VIII relief valves is required

on a three-year interval. This requiresthat some valves be removed fromthe system and tested at a qualifiedtest and repair facility. Smaller reliefvalves should simply be replaced,Pabst noted, because the cost oftesting them might exceed theirreplacement cost.

Typically, Section I safety valvesmust undergo teardown and internalinspection every six years. This mustbe performed by a technician froma VR stamp-holding repair facility.During such teardown and inspec-tion, certain components must havecritical dimensions checked andrecorded, and any found to be out-of-tolerance must be either replacedor machined. Which componentsrequire this scrutiny is determinedby the manufacturer for each modelof safety valve. After completinginspection and reassembly, the safe-ty valve also must be set-pressuretested either at the qualified shop oron the owners equipment.

If set pressure testing is performedusing plant steam pressure, plant loadmust be held steady between 80 and

90% of the full-load rating. Sometimesthis is difficult to accomplish on inter-mediate- and low-pressure (IP andLP) systems in multi-pressure HRSGs.

Therefore, Pabst suggestedthat electronic valve test-ing equipmentsuch asthat supplied by AVK Indus-tries Inc, Jacksonvillebeused for on-boiler valve set-point testing. A certified test

report is required for eachvalve. A warning from Pabst:When performing on-boilersetpoint testing, an accuratereading of the steam pres-sure at the valve is required. NormalDCS pressure read outs, even whenrecently calibrated, may not givesufficiently accurate pressure at thesafety valves location. Best practiceinvolves installing a pressure tap nearthe safety valve for temporary use dur-ing testing.

New designs on thehorizonA s a n e x c e l l e n t s up p le m e n tto Pabsts presentation, JorgenGertz, now marketing manager forNorth American Power Products atValvtechno logies Inc ([email protected]), presented information on veryrecent developments that couldchange the type of safety valvesallowed for use on Section I boilers.

The basic design of the directspring-operated safety valve, Gertzpointed out, has been around almost

as long as boilers themselves. Cur-rently, Section I of the Code permitsonly this type of safety valve. Whilethis has been the case for many years

and has worked well for con-ventional boilers, the widerrange of operating pressuresof todays more complexHRSGs can tax the simpleaction of the direct spring-operated safety valve.

Section VIII of the Code,wh ich addresses r e l i e fvalves, allows the use ofpilot-operated valves anddirect spring-operated with

power actuator safety relief valves,in addition to the traditional directspring-operated valve.

Gertz and other valve profession-als are working within the ASME tomodify the Code to allow the useof alternative safety valve designson Section I applications. This hasalready been accomplished to someextent, Gertz reported, via Code Case2446 which permits the use of pilot-operated safety relief valves on Sec-tion I economizers. Benefits of thischange, according to Gertz, include:n Improved seat tightness.n System can operate closer to set

pressure.n Stable operation in multi-phase

flow.n Ability to modulate.n Can handle higher backpressure.n In-situ setpoint verification with-

out lifting main valve.Gertz anticipates that the next

change will be expansion of thescope of Code Case 2446 to per-mit the use of pilot-operated safetyvalves forallSection I boilers.

HRSG is about 10 times greater thanfor a conventional plantall addingup to increased stack losses (Fig 6).

2. Ever wonder why longitudi-nal pipe welds in steam piping andheaders are of greater concern thancircumferential welds? Seminarattendees now also know this. Lant

explained:Design stress equals hoop stress

equals twice the axial stress. Hoopstress is the stress trying to expandthe pipe because of the internal pres-sure.

Only axial stress operates over acircumferential weld, hence it experi-ences approximately half the stressthat the longitudinal seam weld sees.

Exposure to higher stress while athigh temperature causes creep dam-age to occur faster, particularly inthe weaker heat-affected zone (HAZ)of a weldment.

Therefore, premature creep failurein seam welds is more likely than ingirth welds, all other things being

equal. Of course, all other things arenot always equal. Large unplannedstresses can be placed on girth weldsbecause malfunctions in piping sup-port systems. Thats why pipe hang-ers and supports need to be checkedoften, and problems fixed promptly.

3. Ever wonder what causesmost HRSG tube failures? Lant

explained:n One of various internal corrosion

mechanisms in water-wetted sec-tions.

n Or one of various mechanismsassociated with thermally inducedstresses at tube-to-header attach-ments. These include corrosionfatigue in preheaters, economizers,and evaporators. In superheatersand reheaters, they include ther-mal fatigue, creep fatigue, andductile overload.ETDs advice for flexible operation

and high HRSG durability:n Select appropriate design features

and details for the HRSG thateliminate or minimize its suscepti-

bility to tube and header tempera-ture anomalies.

nAdopt combined-cycle unit operat-ing procedures for startups andshutdowns that develop transientthermal gradients and stresses incritical HRSG components com-patible with the desired designcyclic life.

Support group forHRSG usersThe 14th annual conference wassupported by representatives of 74suppliers of combined-cycle equip-ment and/or services who partici-pated in more than just the eventstrade show. In contrast to manyuser events, which restrict suppli-ers to the expo hall only, all HRSGUG conference sessions are open toall industry participantsincludingmanufacturers, EPC contractors,water-treatment suppliers, engineer-ing consultants, insurance carriers,and so on. CCJ

Gertz



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Others have tried to imitate it,but this wide-ranging,up-to-date, and affordable handbook could havebeen assembledonly by the HRSG User's Group.We tapped our 14 years of educational events and1400-plus members to create the book's 40chapters on steam-plant design, operatioand maintenance. Contributing authorsinclude HRSG users, OEM engineers,service contractors, steam-equipment

designers, chemistry specialists, andlicensed engineering consultants.

The Industry's New"Blue Book"

Available exclusively through the HRSGUser's Group! This 2006, 2nd Edition ofHRSG Users Handbookcomprises nearlythree times more content than the 1st

Edition, with far greater depth andclarity. Individual copies cost $345,with discounts offered on ordersof five and up. For more details, aswell as on-line ordering, visit

www.HRSGusers.org or call RobSwanekamp at 1-406-582-8655.

"There is no better single source ofinformation on the topic of HRSGs!Typically a book of this nature is full oftheory, with a few practical experiencesinterjected as examples. However, the

HRSG Users Handbook is a compendiumof experience-based knowledge,supported by theory. It has become anessential tool in our control room, and isa great reference during outage planningdiscussions at our site."Terry Toland, Facility ManagerGE Contractual Services - River Road Generating Plant

"We found the HRSG Users Handbook tobe very useful for our plant engineers.The book covers all aspects of O&M

issues, and provides excellent guidance tothe operating engineers. It's compact,easy to read, and easy to understand."Lenin Vadlamudi, Planning EngineerTransAlta Energy Corp

"This book is written with practicalapplication in mind. The topics are definitiveto daily operations and maintenance issues.There was sufficient interest fromoperators, maintenance, and managementpersonnel, after reviewing the book, that

we purchased multiple copies for each ofour sites."Charles Dameron, Resource ManagerDuke Energy - Combined Cycle Non-Regulated Fleet

"HRSG Users Handbook should berequired reading for all who manage oroperate a GT-based combined-cycle orcogeneration plant. It's a foundation uponwhich all users can build more reliableand efficient generating facilities."Bob Schwieger, Editor and Publisher

Combined Cycle Journal

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