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The HRSG User’s Group is one of several indepen-dent organizations serving owner/operators in the gas-

turbine-based generation sector of the electric power industry. How-ever, it is the only one dedicated to systems and equipment down-stream of the GT in cogeneration and combined-cycle plants—from the transition piece through the heat-rejection system and stack.

The group’s Steam Plant Workshop, held annually in the fall, focuses on the design, opera-tion, and maintenance of heat-recovery steam generators, duct burners, steam systems (piping and valves), steam turbine/gen-erators, condensers, cooling tow-ers, water treatment systems (for makeup, boilers, cooling systems, and plant wastewater), emis-sions control systems, and all the auxiliaries in between. It’s a tall order, but Communications Director Rob Swanekamp fits it all in a meaningful program delivered by industry experts and orchestrated by Chairman Bob Anderson.

Last December’s two-day program had two major objectives: address critical mid-life maintenance issues (nominally 10 to 15 years after COD)

faced by owner/operators of cogen and combined-cycle plants, and review developments in the evolution of steam-plant design.

Bremco Inc’s Bill Kitterman and Don Revane kicked-off the mainte-

nance issues portion of the program with an eye-opening presentation on how to replace headers, or com-plete modules, suffering the effects of age, corrosion, service conditions not specified, etc.

They were followed by Sam Moots of Colorado Energy Management, who had experience to share on chemical cleaning of HRSGs; Bob Pabst of valve consultancy Movaco

Inc, on maintenance of severe-service control valves; Bill Moore of Nation-al Electric Coil on generators; and Larry Flashberg of Saguaro Power on cooling-tower overhauls.

Presenters for the design portion of the program were the following:n Andy Allen, Progress Energy Inc,

“Writing Your Next HRSG Speci-fication.”

n Mark Yarbrough, Arizona Public Service Co, “Treated Effluent and Zero Liquid Discharge.”n Peter Rop, NEM bv, “Scal-ing-up the Once-Through Steam Generator.”n David Allore, Hartford Steam Boiler Inspection & Insurance Co, “European Pressure Equip-ment Directive 97/23/EC, HRSG Compliance via ASME.”n John Van Name, The Wash-ington Group, “NFPA 85 Boiler and Combustion Systems Haz-ards Code.”n Ron Munson, M&M Engi-

neering, “The Use of Advanced Ferritic Alloys in Steam Genera-tion.”

Module, header replacement highlight steam-plant workshop program

1. Dew-point corrosion dictated removal of this feedwater-heater sec-tion from its HRSG

The idea that headers or complete modules (harps) might have to be replaced because of damage caused by flow-accelerated corrosion (FAC), general wear and tear, or other rea-son caught many workshop attendees by surprise. They never thought such a complex undertaking might be nec-essary during the design lifetime of their boilers.

But by the time Bremco Inc VPs Kitterman and Revane finished their presentation, few—if any—in the room appeared very concerned. Rea-son: The boiler erection and over-haul specialists from Claremont, NH, demonstrated to the group that they had developed the art for completing this type of work on time and within budget during a gas-turbine (GT)

major outage. Followup calls by the editors to two customers confirmed company’s capabilities and formed the basis for the two case histories at the end of this section.

Kitterman began with an over-view of the firm and its work experi-ence, ASME and National Board code “stamps” held by the company, etc (visit www.bremco.com for details). He then reviewed the following four reasons for header and harp replace-ments since the early 1990s:n Stress corrosion cracking of Type

304 stainless steel feedwater pan-els which generally suggested their replacement with Grade 2205—a duplex (ferritic/austenitic) mate-rial (Fig 1).

n Age/service-related deteriora-

Module, header replacement

KittermanRevane

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tion that required the retubing or replacement of standard generat-ing banks.

n Cycling of HRSGs designed with dual-pressure panels caused dif-ferential-expansion problems that were solved by modifying header design.

n Most recently, FAC has dictated the replacement of headers and other parts of low-pressure (LP) evaporators in large triple-pres-sure boilers. Revane cautioned that panel

retubing and replacement projects require careful planning on the part of all participants. Major consider-ations for retubing include the fol-lowing:n Project buy-in by all parties.n Material lead times.n How to remove old tubes and

stubs.n Header accessibility for tube roll-

ing/welding.n Development of rolling and weld-

ing procedures and QA/QC for confirming quality of work.

n Method of installing new tubes: whole (toaster slot) or cut (welded).

n Cost. Considerations for panel replace-

ment include several of the items listed immediately above, plus crane availability and site access, site con-

ditions, laydown area, out-of-scope work identified after the HRSG is opened up, etc (Figs 2-4).

Split-header modSeveral 2 × 1 combined cycles enter-ing service in the mid 1990s were equipped with heat-recovery steam generators that had a single header serving both the HP and LP tube bundles. A division plate in the head-er separated the two sections. The idea behind the split header was more cost-effective component fabri-cation and field erection.

This arrangement generally was satisfactory for the base-load service expected, but not for cycling duty. Experts generally agree that during startup, rapid heating of the HP sec-tion quickly expands that portion of the panel and stresses the LP tubes, which are at a much lower temperature. Metal fatigue and cracking typically occur after many start/stop cycles.

A corrective measure used suc-cessfully by Bremco: Cut the LP tubes about a foot above the header, saw off the stubs welded to the head-er, and use a portable machine tool to remove the LP portion of the header (Fig 5). Note that the cut is made on the LP side in close proximity to the internal division plate (Fig 6).

The company manufactures replace-ment LP headers in its shop. It cuts and drills Code pipe to make the head-er sections (Fig 7) and then installs and welds the tube stub ends and end caps shown in Fig 8 to complete the job (Fig 9). Finished field installation is in Figs 10 and 11. Note that the new standalone LP headers are equipped with their own drains.

Header replacementSevere metal wastage caused by FAC (Sidebar) is the primary reason HRSG owner/operators are forced to replace carbon-steel upper headers—and pos-sibly other components as well—in their LP evaporators (Fig 12). Such projects usually specify chrome-bear-ing steel for the replacement parts. Industry experience indicates that even the relatively small amount of chrome in P11 (1¼%) helps to reduce the rate of FAC attack. P22, which con-tains 2¼% chrome, is considered more beneficial, but it has a higher price.

When your consultant recom-mends a materials upgrade be sure the contractor selected for the job has adequate time to survey the HRSG and do the necessary plan-ning. Where field welds are P11 or P22 to carbon steel, for example, welding and QA/QC processes will not be the same as they would for car-

2. Use of a lifting frame minimizes the possibility of damage during the handling of replacement panels (above)

3. Crane availability is a significant consideration in the scheduling of harp-replacement work (right)

4. Setting panels in place demands a safety-minded, skilled crew equipped with reliable communications devices to coordi-nate work with the crane operator

5, 6. First step in converting from a single split header to individual HP and LP headers is to machine off the LP portion (left) in close proximity to the internal division plate, which remains on the HP side (right)

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bon steel to carbon steel. Plus they may take longer to accomplish and require different personnel.

One of the questions raised at the meeting was why not replace the entire harp rather than fit-up and

weld the stubs provided on the new header to the old tubes? The simple answer: Retrofit is significantly less expensive, for these reasons:n The remainder of the LP panel

generally is in excellent condition

7-9. Bremco cuts and drills Code piping to make the LP headers (left), then installs and welds stubs and end caps shown center. Finished job is at right

10-11. Independent HP and LP headers eliminate the metal fatigue and cracking associated with split headers because of uneven thermal expansion

12. Flow-accelerated corrosion was the cause of metal loss in this LP header

Just say ‘no’ to reducing agents

It seems that you can’t review often enough the importance of water

chemistry in maintaining the health of heat-recovery steam generators (HRSGs). Some readers might right-fully react to the following passage by saying “not this again.” However, those charged with HRSG responsi-bilities for the first time often do not have a deep understanding of water-treatment principles and what hap-pens when you don’t adopt a fanati-cism about keeping key parameters within prescribed limits.

The presentation by Bremco Inc’s Bill Kitterman and Don Revane at the HRSG User’s Group’s steam plant workshop last December reflected the need to once again review industry experience with regard to minimizing the potential for flow-accelerated corrosion (FAC) through proper materials selection and tight control of water chemistry.

One of the best reference works on the subject is the HRSG Users Handbook (visit www.hrsgusers.org for details), so the editors reached for

their copy and extracted what follows from the chapter on steam-cycle chemistry by Stephen J Shulder, a respected power-industry water consultant with extensive hands-on operating experience.

Volatile chemicals are used almost exclusively for feedwater treat-

ment in combined-cycle/cogen plants because steam attempera-tion spray typically is taken from the feedwater or further downstream. It is highly undesirable to inject dis-solved solids directly into the steam.

Feedwater treatment typically consists of a chemical additive to maintain an alkaline pH and in rare instances a reducing agent to assist in controlling oxygen. It is important to specify all-ferrous metallurgy in the HRSG design phase of the proj-ect. With all-ferrous systems, use of a reducing agent is strongly dis-couraged because such chemicals have been identified as the culprits in single-phase FAC failures in LP evaporators.

The clear trend in the power industry is to eliminate—or at least minimize—the use of reduc-ing agents, relying on condenser deaeration alone to control dissolved oxygen, and to maintain a slightly oxidizing environment to minimize corrosion-product transport to HRSG evaporator sections.

Note that when components containing copper are present in the condensate/feedwater system, a feed of reducing agent is neces-sary to control copper corrosion. For these plants, the pH must be reduced from the optimal levels to minimize iron transport in order to mitigate corrosion of copper-bearing materials. Ammonia and hydrazine are the most common volatile chemi-cals used in these plants, providing for pH control and the necessary reducing environment.

Ammonia—actually ammonium hydroxide—continues to be the amine-of-choice for pH control in feedwater, although its high volatility in steam is a major drawback.

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and little if anything would be gained by its replacement.

n Complete panel replacement requires considerable laydown room onsite and the need for large cranes which are costly, often difficult to schedule, and generally tough to maneuver to where needed.

n Replacement headers can be made in a qualified local shop to accom-modate schedule requirements with relative ease.

n New headers can be installed dur-ing a GT major outage without extending the schedule.How Bremco does it. First step in

a typical header-replacement project is to open the casing to permit access to the affected components. Next, the risers are cut. Third step is to support the lower headers on timbers so that the supports from which the harp is suspended can be removed.

Then the tubes forming the harp are cut with a Metabo angle grinder several inches below the header and the header is removed. Note that a torch is not used because its heat could change material properties, produce slag, etc.

The new header with stubs attached then is lowered into position and fit-up. Next, a QC inspector verifies the fit-up; then the stub-to-tube welds are made and inspected. After a dye-penetrant test verifies weld quality, compressed air is used to assure leak-tightness of the harp before installa-tion of the next panel begins.

Owner/operators share header-replacement experiences

Users learn valuable lessons from their colleagues, which is why HRSG User’s Group meetings are so well attended. Personnel from two gen-erating facilities had hoped to share their experiences with flow-accel-erated corrosion (FAC) attack in LP evaporator sections at the 2007 Fall Workshop in New Orleans, but plant O&M considerations dictated otherwise. So the editors of the COM-BINED CYCLE Journal spoke with them by phone and compiled the fol-lowing report.

Case history No. 1Plant personnel observed moisture and whisps of steam emanating from an elbow in one of the 72 riser links that connect the upper headers in the LP evaporator section to the LP steam drum. This occurred after several years of demanding opera-tion (see “plant snapshot,” box right).

Location of the distress was where the vertical risers turn to connect to the drum and where two-phase flow and temperature conditions associ-ated with FAC exist.

A comprehensive examination of pressure parts was initiated as soon as resources could be mobilized. It encompassed ultrasonic testing of various headers (top and bottom), header nozzle penetrations, elbows, tees, and riser links. Inspectors found some areas where material thickness had decreased by more than 60 mils since COD. Significant material loss also was found where the risers pen-etrated the upper headers (nozzles) in the first four rows of the LP evapo-rator section.

In addition, the wall thicknesses of tubes located under the middle nozzle connections in the first four rows of headers were reduced near where those tubes entered the upper headers. This finding led plant per-sonnel to question the “experts” who say FAC will not occur in a straight run of pipe and to consider that other phenomena may have been involved.

Temporary repairs were made both to buy the time necessary for engineers evaluate options for correc-tive action and to coordinate boiler work with a planned gas-turbine (GT) major inspection. Specifically, elbows with significant wear were cut out and replaced. This initiative included testing the susceptibility of alternative materials to FAC attack. Several elbows were replaced in-kind with carbon steel, others with P11, and still others with P22 material.

The few tubes under the middle nozzle connections that showed signs of wear were replaced with “Dutch-men” of various lengths. Where the header nozzle connections had indi-cated wear in the first few rows of the LP section, a weld overlay was used to build up wall thickness until replace-ment headers could be installed.

One of the first areas investigated by engineers charged with develop-ing a “solution” was water treatment, which often is a root cause of FAC

(access “FAC and cavitation: Identifi-cation, assessment, monitoring, pre-vention” at www.combinedcyclejour-nal.com/archives.html, click Spring 2004 issue, click title on issue cover). Plant personnel said several experts investigated cycle chemistry and that changes were incorporated to remain within general industry guidelines.

The attention of plant personnel focused on what they believed to be extraordinarily high fluid velocities in tubes located under the center risers (where the Dutchmen were installed) during system transients; also, on the design of the riser cir-cuits connecting the upper headers to the steam drum.

Decision time. Research com-plete, engineers decided to replace all 30 upper headers in the LP evapo-rator section of each boiler and to upgrade the headers to P22. This material also was specified for the risers connecting the headers to the drum in the first four or five rows.

Plant snapshot 1Nominal 500-MW, 2 × 1 F-class combined cycle with a conven-tional triple-pressure drum-type HRSGYear of commercial operation: 2000

Total operating hours to date: approximately 50,000. Plant cycles frequently and ramps continuously between 320 and 500 MW—typical-ly at a ramp rate of 25 MW/min.

LP evaporator is arranged in 10 rows x three modules (A, B, C) wide and supported from the top. The LP harps, as originally supplied, had an upper header of 3-in.-diam Sched-ule 80 carbon-steel pipe and a sin-gle row of 36 1½-in.-diam Schedule 40 carbon steel tubes.

The first four rows in each LP module (in the direction of gas flow) each have three 3-in.-diam nozzles to connect the upper headers to the steam drum; remaining six rows have two risers each.

13. Expansion joints are required where risers penetrate the casing

14. Risers were prefabricated (bent) by a third-party supplier

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P11 was used for risers in the remain-ing rows because enough P22 was not available to do the entire job.

Bids from several contractors were accepted for the project and Bremco was awarded the job. Plant person-nel said they believed that Bremco had the necessary experience to sat-isfactorily complete such a project; the company knew first-hand what had to be done and how long it would take. Calls to references confirmed the company’s capabilities.

Location of the upper headers between the furnace casing and the outer skin of the HRSG increased the complexity of the project and dictated replacement of all casing expansion joints (Fig 13). Despite these and other challenges, the job was completed on budget in approximately 30 days—within the timeline for the GT major.

The new headers were fabricated by a local contractor with tube stub ends welded in place. The new riser links were bent offsite and installed between the headers and the steam drum (Figs 14-16). Headers were replaced from the hot side to the cold side. After each was installed, the quality-control team checked the work: visual review to verify proper fit-up, dye-penetrant tests to verify weld quality, and a compressed-air test on each harp assembly to ensure leak-tightness. Only after QC was satisfied could the next header be installed (Fig 17). A final hydro test was performed on the LP section.

Overall project dimensions are impressive. More than 2500 field welds were successfully completed in approximately one month by a team of approximately 60 fitters and Code-certified welders working two 12-hr shifts daily.

Finally, extensive follow-up ultra-sonic testing to monitor wear rate is planned. Engineers at this plant sug-gest that their colleagues not assume chrome-bearing P11 and P22 pipe are a panacea. Even the 2¼-chrome pipe suffered some metal loss, although it was less than that for the other two

options investigated. Are there other phenomena involved?

Case history No. 2Managers interviewed by the editors at the second plant told a story simi-lar to that described above. However, there were some interesting “twists.” The “plant snapshot” in the box below provides “boiler plate” that will facili-tate understanding what follows.

The all-volatile treatment (ammo-nia) required to control pH and oxy-gen in the once-through HP section must be closely monitored to avoid conditions conducive to metal wast-age in the IP and LP sections. In the

first year or so of operation, chemis-try upsets were difficult to prevent because of the typical startup issues that precipitated an abnormal num-ber of trips and off-normal operating conditions.

Since that time, pH has been main-tained at the highest level possible for the specified ammonia treatment; oxygen has been below 10 ppb con-sistently. The concentration of iron in boiler water is determined daily using a spectrophotometer; samples are taken from different locations in the HRSG. “Excess iron” has never been detected. During shutdowns that permit personnel access to the LP drum, the relatively small amount of iron that collects there is removed, weighed, and recorded.

This facility has been diligent in the gathering of operational data. For example, after about the first year of operation it began conduct-ing annual FAC surveys using ultra-sonic instruments to detect wastage. These surveys identified significant metal loss in random locations of the HRSG having carbon-steel LP components. The unit with P11 com-ponents showed some wear, but noth-ing of immediate concern.

One location with a propensity for FAC attack was where the Schedule 80 carbon-steel risers were saddle-welded to the harps’ upper head-ers. To illustrate: One particular spot showed 221 mils of material in 2005, 118 in 2006, and 95 in 2005. The inspection technique used is not exacting and variations in measure-ment are to be expected. However, several common sources of error were eliminated by using the same quali-fied technician to do the measure-ments each year, the same locations for taking measurements, and the same instrument.

This plant’s experience indicates that the “best practice” for locating and quantifying FAC is to begin with an engineering survey to identify those locations in the fluid-system circuitry most susceptible to FAC (based on temperature, velocity, etc).

Plant snapshot 2Nominal 550-MW, 2 × 1 F-class combined cycleYear of commercial operation: 2004

Plant cycles daily. Capacity fac-tor since COD is approximately 65%.

The HP section of the HRSG is of once-through design; IP and LP sections are of the conventional drum type. The unit has one boiler-feed pump.

LP evaporator is arranged three modules wide. A series of interme-diate headers is located between the steam drum and the upper headers on individual harps. Ris-ers from six harps connect to one “intermediate” header; the latter, in turn, supplies the LP drum.

The LP section of one HRSG was manufactured from carbon steel; the other from P11. Reason: Mishandling of LP components dur-ing construction resulted in damage that dictated their replacement for the second unit. Fabrication of the replacement harps was done by an alternative vendor and the opportu-nity to upgrade materials was taken given emerging industry experience on the benefit of chrome for mitigat-ing FAC.

15. Risers in Fig 14 connect upper LP evaporator headers shown here to the steam drum in Fig 16

16. LP drum nozzles are the final connection point for the risers

17. Quality of field welds is verified by rigorous QC procedures

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Next step is to survey these locations annually to monitor material loss. Obvious from the foregoing is that the macro data collected from iron analyses is ineffective for identifying even extreme metal loss associated with local attack.

Based on the data presented above, plant engineers decided in 2006 that the upper headers for about half

the harps had to be replaced and the rehab project was scheduled for the following year when a GT major would be done. Bremco was selected to make the upgraded P11 replace-ment headers in its shop and to do the field work, which was similar to that for first case history. Once again the project was completed on time and within budget. ccj

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Chemical cleaning of heat-recovery steam generators doesn’t get much attention at industry meetings. In fact, it’s probably the rare plant employee who has given the topic more than a passing thought. But if it comes to happen that an HRSG “best practice” is chemical cleaning after 10 to 15 years of operation as it typically is for large coal-fired boilers—and there’s no reason at this time to suggest that it will be—then it could become a mat-ter of concern for many plants in the near future. The gas-turbine “bubble” that began around 2000 is approach-ing its tenth anniversary.

Sam Moots, production manager, Colorado Energy Management Inc, and a member of the Frame 6 Users Group steering committee, discussed the planning necessary to assure that your HRSG will be cleaned properly if, in fact, cleaning is required. He said that the motivation for chemi-cally cleaning two HRSGs at his plant was tube leaks caused by underde-posit corrosion. Cleaning of the first unit was based on coal-fired boiler experience because the company had none for HRSGs.

Moots suggested that users begin planning for a chemical cleaning anywhere from six months to a year before the work is done—the longer the better. It takes time both to iden-tify the proper contractor for your specific requirements and for the contractor to select chemicals and develop procedures.

One of the first steps in the pro-cess is to take samples from sections of the boiler that will be cleaned. Typ-ically, a tube sample about two and a half feet long would be removed for testing and analysis. Then that sec-tion must be replaced and the boiler hydrostatically tested. Important to blow down hard after tube work is complete; consider reinstalling your start-up steam strainer to protect the boiler stop valve.

What chemists learned about the first sample removed from Moots’ boilers was that the scale was pri-marily composed of iron oxides (near-ly 28%) and copper (nearly 34%, from condenser Admiralty tubes). Also that the density of the deposit was 170 grams/ft2 and its solubility was 97%. Important, too, was the obser-vation that the scale was deposited in layers of iron and copper—it was not a homogeneous deposit. Thus, mul-tiple stages of chemical treatment would be required to dissolve it.

Further sampling revealed that the density of the deposit in this

tube was not representative of that in other sections of the boiler, where it was about 40 grams. However, the layered nature of the scale was con-sistent throughout the unit. The sec-tion where the heavily scaled tubes were found was replaced; other sec-tions were cleaned.

Safety first. Consider as a top priority a safety meeting prior to the start of chemical cleaning with all contractor and plant personnel par-ticipating. Items that should be cov-ered include the following:n Plant safety requirements.n Material safety data sheets.n Ventilation.n Eye-wash stations and safety

showers.n Outline plans on how to deal with

leakage of chemicals.n Waste disposal.

One way to minimize the potential for leakage and having to deal with an unnecessary disposal problem is to hydro the boiler a week or so before cleaning begins to locate and fix leaks, including leaking valves.

Work closely with your contrac-tor to ensure that supply and return lines, and drains, are sealed off or blinded to isolate the HRSG and pre-vent any leakage into the plant. Also, be sure to identify the party respon-sible—it may be you—for providing appropriate inlet and outlet connec-tions for chemical cleaning and for draining the unit.

Moots suggests that if you have the luxury of time, consider resam-pling for cleanliness before the clean-ing system is dismantled.

For Colorado Energy Management chemical cleaning was worthwhile: tube-leak incidents were reduced dramatically after cleaning. ccj

The other presentations at the Steam Plant Workshop will be pro-filed in the next issue.

Plan thoroughly before cleaning your HRSG