Reliable electric supply in the Kingdom of Saudi Arabia depends to a large degree on the proper operation of gas turbines, which dominate the country’s generation infrastructure. At the end of 2018, Saudi Electric Co (SEC), the leading producer of electricity with a nominal 70% market share, had 53,500 MW of capacity installed at its 40 powerplants. Simple-cycle gas turbines comprised about one-third of that total, combined cycles a quarter, and oil- and gas-fired steam turbines most of the remainder.

Worth noting is that Saudi Arabia is the world’s largest producer of desalinated water, relying on 17 facilities to provide that product. Several desal facilities have been sited together with power stations.

Many types of gas turbines are installed in Saudi Arabia for electricity production and mechanical-drive applications. They include the GT11, 501D5, 501D5A, V84.2, M501F, Frame 5, and 6B; most are scattered among the various IPPs and industrial self-generators. By contrast, SEC relies heavily on GE Frame 7s and has more than 150 EAs and FAs in its fleet.

SEC plant personnel often participate in 7F Users Group meetings in the US, but it’s impractical financially for more than a few of the company’s many engineers to attend. A solution was to hold a Combined Cycle Conference (Apr 3, 2019) and a Power Generation Technical Workshop (Dec 11, 2019) in Saudi Arabia.

The first meeting, sponsored by SEC, was hosted by the Ali A Tamimi Co and coordinated by Keck Group International LLC (Fig 1). Tamimi is a respected provider of engineering and onsite O&M services—including turnkey upgrade projects—to SEC and others in the power, petrochemical, and oil and gas industries. KGI, headed by two former GE executives—Richard Keck and Bob Johnston—provides consulting services in support of combined-cycle operations and performance improvements.

The second conference was sponsored by Saudi Aramco, a/k/a Saudi Arabian Oil Co, at its facilities in Dhahran (Fig 2). Saudi Aramco, which owns 7% of SEC, is both the utility’s main fuel supplier and an important customer.

Combined-cycle conference

Adel Al Shuraim, CEO, Tamimi Energy, opened the Combined Cycle Conference. His welcome was followed by that of Khalid Al Tuaimi, EVP, SEC Operations. The morning’s technical presentations followed, beginning with recommendations for improving combined-cycle performance by CoreTech Industrial Corp’s Joel Holt, engineering manager and Bruce Martindale, consulting engineer.

Holt (Fig 3) and Martindale did double duty, following up their opening presentation with a primer on how to reduce plant startup time. Johnston was next with a review of uprates for non-capital parts—with no changes to existing gas-turbine capital parts.

HRSG improvements were addressed by CMI Energy’s technical manager, Raphael Stevens and VP Habib Grini.

Presentations on steam-turbine upgrades and training programs for gas-turbine, steam-turbine, and generators, were developed by MD&A’s Eamonn Rogers and Dave Hagenbuch.

Exhaust-system upgrades and repairs, by Innova Braden Europe’s Ed Chan and Moustafa Al-Shami, closed out the morning program.

The afternoon was reserved for Q&A and open discussion.

The presentations focused on specific issues that each vendor had addressed at combined-cycle plants and showed how that experience could benefit generating facilities in Saudi Arabia. The vendors participating in the conference had agreed to work collaboratively to provide owner/operators of the kingdom’s 15 operating combined cycles complete solutions. Representatives from all those powerplants were among the 100 or so attendees.

Saudi Arabia’s combined-cycle infrastructure includes the following, based on CCJ’s research:

• • Ten 7EA-powered 4 × 1 plants designed for crude oil only. Gas turbines, rated 56 MW each, installed from 2010 to 2012; 130-MW GE steam turbine/generators added to each block between 2014 and 2016 along along with unfired NEM HRSGs.
  • A 7001FA-powered 3 × 1 designed for gas only installed in 2012, equipped with Hyundai HRSGs and a GE D11 steamer.
  • A 7000FA-powered 4 × 1 designed for gas only installed in 2013, equipped with Hyundai HRSGs and a GE D-11 steamer.
  • Two 7F.05-powered 4 × 1 facilities designed for gas with oil backup. Gas turbines, rated 172 MW each, installed in 2014-2015; Alstom HRSGs and 341-MW steam turbine/generators added to each block in 2017.
  • Four 7F.05-powered 3 × 1 facilities designed for gas only are scheduled for 2021 operation. Gas turbines, rated 215 MW each, will be integrated with Alstom HRSGs and 342-MW Alstom steam turbine/generators.

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Holt and Martindale breezed through a review of the principal systems and components in a combined-cycle plant, explaining the functions of each in relatively few words. Then they summarized plant startup (hot, warm, cold) and shutdown procedures, identifying issues sometimes experienced with each step and how to avoid them.

Technical warmup complete, the speakers were ready to tackle one of the meeting’s primary objectives: Encourage attendees to pursue procedural and equipment changes to enable faster starts of their combined cycles without compromising reliability and service life.

The significant penetration of renewables into the power generation market has caused many combined cycles to switch from baseload operation to cycling duty—including the ability to start quickly when non-fuel resources suddenly disappear.

The speakers noted that combined cycles installed in the last five years or so typically were designed and equipped for the new demanding service. But some older plants are not able to accomplish warm starts in less than four hours, which makes profitable dispatch difficult, if not impossible, in today’s competitive power markets. However, new procedures, software, and some equipment upgrades, the group was told, could drive down plant warm restart times to 90 minutes with a generally acceptable investment.

Performance improvement was another topic of major interest given older combined cycles have suffered efficiency reductions over the years. To fully assess areas that should be addressed to improve thermal performance, the speakers recommended doing a current heat balance and comparing it to the original. The main areas requiring improvement will stand out, it was said.

Focused uprates within the capability of existing equipment are a proven path to performance improvement. Keep in mind that most older gas turbines receive upgraded parts when they purchase replacements or spares because OEMs are continually improving the capability of their offerings.

But manufacturers rarely assess the overall capability of the GT when only selling parts. Owner/operators, sometimes assisted by an independent consultant, frequently find a thorough review can guide the selection of parts capable of increasing GT output by as much as 3%, possibly more. This, plus the accompanying increase in exhaust energy boosts overall combined-cycle power and efficiency.

A comprehensive audit of the physical plant, and of the procedures that guide operations, often point to affordable improvements with big returns. The HRSG can be an efficiency hog when wear and tear allows flue-gas bypass of heat-transfer surfaces and catalyst by way of failed baffles and seals, and when gas- and/or water-side deposits retard heat transfer. Steam-turbine upgrades and repair/replacement of key exhaust-system components—ductwork, dampers, etc—can provide significant benefits as well.

Bob Johnston’s “Non-Capital Parts Uprate Program” was an ideal sequel to Holt and Martindale’s presentations, which focused on equipment. Johnston’s “program” focused on applying non-hardware related controls changes to match the capability of hot-gas-path (HGP) parts, thereby increasing gas-turbine output and efficiency. The speaker told the group that all the parts of his “program,” which have been applied successfully to scores of GE engines, also can be used to improve the performance of machines made by other OEMs.

He should know. Johnston, a four-decades GE veteran, retired in 2008 as manager of the company’s Gas Turbine Services Engineering Group, which supplied upgrade/uprate packages for a fleet of more than 7000 frame engines. Industry veterans likely have seen his name on documents in their files.

Johnston began with a review of items that could result from a non-capital-parts uprate study—including the following:

• • Higher firing temperature possible with improved HGP parts.
  • Change in the angle setting for inlet guide vanes (IGV).
  • Increase in power at higher ambient temperatures by changing the isotherm setting.
  • Exhaust-thermocouple corrections.
  • Degradation correction to the control curve.
  • Use of a tilted control curve to improve hot-day performance.

The speaker put up on the screen a valuable table of key data for all Frame 7 models from the introduction of the PG7651A in 1970 to the PG7241FA in 1999. It includes rated output, firing temperature, air flow, heat rate, and exhaust temperature—information needed for comparison purposes in performance studies.

Johnston’s “carrot” was that for any “older” unit, it is likely that sufficient parts have been upgraded through normal supersedure procedures such that they would enable your gas turbine to produce more power. A thorough HGP review can confirm this. He added that most Frame 7 spare parts introduced after your engine was built are directly interchangeable with those in your machine. To illustrate: The later-vintage spare parts for the MS7001B/C/E/EA machines are directly interchangeable with all prior vintages of MS7001 units.

Attendee interest was piqued when Johnston said that degradation correction, along with use of the tilted control curve, had increased the output of some units operating in high-ambient-temperature environments by as much as 1.6%. Only controls changes were required, same hardware. For an MS7001EA this translates to about 1.2 MW of additional power.

The driver for using a tilted control curve is simply that most owner/operators value output on hot days more so than on cold days. Recall that standard GE control curves maintain a constant firing temperature at all ambient temperatures. Tilted control curves overfire on hot days by 16 deg F and under-fire by 25 deg F on cold days. Extensive analysis by the OEM in the mid-1990s was said to confirm that this approach had no net impact on parts life or maintenance intervals. Hundreds of successful applications were reported.

Non-recoverable performance degradation attributed to increased clearances, blade finish, and casing distortion, among other impacts, reduces output. Plus, it also adversely affects the compressor discharge pressure/turbine exhaust temperature relationship, resulting in under-firing of the unit.

The speaker said that extensive performance testing can be done to quantify the degree of under-firing, but that a 5-deg-F reduction in exhaust temperature and a 9-deg-F drop in firing temperature are typical. The simple approach, he said, was to apply an exhaust temperature correction to the control curve and regain the power lost (about 0.8% for a mid-1990s vintage 7EA).

HRSG improvements. The CMI presentation included case histories on HRSG modifications to match a gas-turbine upgrade, dry-ice blasting for tube cleaning, and retubing—topics typically covered in depth at meetings such as the  HRSG Forum with Bob Anderson the European HRSG Forum, and the Australasian Boiler/HRSG Users Group (ABHUG).

HRSG mods to match a GT upgrade described work done at the UK’s King’s Lynn power station (COD 1997) in 2017-2018. The ambitious project included replacing the gas turbine, refurbishment of the HP and LP sections of the steam turbine, and its generator, and addition of a street to the air-cooled condenser.

Goal was to make the plant more flexible (300 or more starts annually), enabling its profitable operation in an increasingly competitive market. This required maximum use of existing infrastructure, improved output and efficiency, high reliability and availability, etc.

CMI’s effort focused on recovering heat from flue gas at higher temperature than could be handled by the 1990s HRSG. Redesign/replacement of the HP superheater and reheater was required. The presentation essentially was a collection of photographs “narrated” by the speakers to explain how the old pressure parts were removed and the new pressure parts installed—a confidence builder for those who may have thought such a retrofit project might not have been possible.

Case studies for energy savings—including tube cleaning and retubing of damaged heat-transfer surface—closed out the CMI segment of the program. Most of the material presented can be found in CCJ’s archives. Access by typing your request into the search function box at www.ccj-online.com.

MD&A’s program included a presentation on D11 HP/IP replacement, which might also have been of interest to many users in the US given the large number of D11 steamers in this country. Dave Hagenbuch focused on D11 issues reported by owner/operators and the features and benefits of MD&A’s solution—and that of parent company Mitsubishi Hitachi Power Systems.

Dished diaphragm repair options, “hot swap” and spare sub-assembly offerings for stop valves and control/intercept valves, and packing rings and seals also were covered in the steam-turbine segment of the agenda.

Training wrapped up the MD&A effort. Seminars offered on steam-turbine fundamentals, alignment, advanced repairs, and performance evaluation and improvement were described in addition to workshops on gas-turbine fundamentals and the Mark VI control system.

Innova Braden Europe presented its air-inlet and exhaust-system retrofit solutions for 7EA and 7FA gas turbines as the morning drew to a close. The speakers began with exhaust systems, covering typical problem areas in older-style plenums—such as hot flanges and outer skin, overheated turbine and load compartments, liner damage, etc. Solutions discussed were well illustrated to facilitate the transfer of knowledge. Much of this material has been covered in CCJ over the years and is readily available with a couple of mouse clicks. Just access www.ccj-online.com and use the keyword search box on the home page.

Bypass diverter dampers were the next topic. Once again, photos illustrated the problems encountered and the solutions available. Cracks on the diverter-damper frame, blade cover, and toggle arms all were discussed, as was damage at the seal-air frame of the diverter-damper blade and wear and tear at the connection to the diverter-damper blade hinge. This material does not get much air time at user-group meetings in the US because regulations here typically do not support the use of diverter dampers.

Diagnostic tools, such as acoustic cameras and drones, and project case histories from major plants worldwide completed the presentation.

Technical workshop

The Power Generation Technical Workshop hosted more than a hundred participants from Saudi Aramco’s engineering office and facilities. The agenda was similar—some presentations basically the same—to that of the earlier Combined Cycle Conference. Holt presented again on combined-cycle efficiency improvements and faster starts, Johnston on uprates of non-capital parts, and Stevens and Grini on HRSG improvements. MD&A covered its training offerings again and replaced some of the SEC steamer presentations with ones on gas-turbine rotor life extension and HGP repairs.

Several topics were in addition to those addressed at the SEC meetings, the prepared presentations running until mid afternoon when a panel was convened to address topics of interest not covered earlier in the day. Presentations added included these:

• • Upgrades for air-cooled condensers, Frederic Anthone, manager of aftermarket support, SPG.
  • GT inlet chilling systems, Tom Tillman, principal engineer, Turbine Air Systems Inc and Bob Johnston.
  • Fuel additives for NOx emissions reduction, Mutasim Al Khayri, technical development manager, Clariant Al Tamimi and Bob Johnston.
  • Regenerative-cycle conversions for all types and models of gas turbines, Ty Moore, VP operations, PalCon.

MD&A’s Hesham Awwad opened his company’s session with a presentation on GT rotor lifetime assessment (RLA). He noted that MD&A does not refer to this activity as an “end of life” evaluation, urging attendees not to “pull the plug” too quickly because an RLA can help owner/operators decide on the best options for ageing assets. He stressed that MD&A’s goal is to help users achieve their planned operating strategies for remaining life through validation, repair/coatings, and/or replacement of limiting components.

Awwad explained his company’s inspection process flow path, inspection scope and equipment, and testing and analytical tools used to develop a rotor-health assessment for planning refurbishment activities, or replacement through MD&A’s rotor exchange program. 7FA compressor upgrades, DLN2.6 combustion parts/repairs, and 7EA/7FA compressor and turbine replacement disks were included in this portion of the program.

Greg Alexander then moved to the podium to discuss new-parts manufacturing and component repairs. Repairs are performed on 6B, 6FA, 7EA, 7FA, 9E, 9FA, V94.3, and V84.3 buckets, nozzles, shroud blocks, and fuel nozzles. Company offers new HGP parts for 7EA, 7FA.03, and V94.3 machines, the group was told.

Inspection and repair of 7FA.03 and 9FA combustion and turbine parts is a focus of MD&A’s aftermarket business with a goal of reducing scrap.

SPG’s Anthone began with the requisite company history and product portfolios for both wet and dry cooling systems, moving quickly through that boiler plate to focus on the inspections, technical advice, maintenance services, and spare parts available to improve performance as operating conditions change. To learn more about air-cooled condensers, access www.acc-usersgroup.org where you will find presentations on a wide range of chemistry and O&M topics archived from the time the ACC Users Group was founded 12 years ago.

It’s no secret, turbine inlet cooling increases the power gas turbines can produce on hot days. Tillman’s presentation focused on water-cooled chiller systems with heat rejection via an evaporative cooling tower and these refrigerant options: R-1233zd (HFO) and R-134a. For plants located on the coast, seawater heat exchangers can replace the standard cooling towers. Typical filter-house modification kits were covered as well.

Users wanting background information on alternative inlet cooling technologies should visit www.turbineinletcooling.org and CCJ’s editorial archives at www.ccj-online.com.

Fuel additives for emissions control is an important topic for a Saudi audience given the large number of gas turbines burning crude oil. In these units, the speakers said, additive is injected upstream of the liquid-fuel stop valve. Focus of the presentation was experience with FuelSpec R114-05 (0.05% Mg/0.4% Fe by weight) in reducing carbon soot emissions.

Smoke and particulate measurements taken by an independent Saudi-based certified test lab, and performance data captured and analyzed by Saudi Aramco and US-based Efficient Fuel Solutions, revealed a reduction in smoke and particulate emissions of 30% when using R114-05, compared to operation on untreated crude oil. The additive injection rate was 1 liter per 130-million Btu. Test was conducted over two days.

Film-forming substances (FFS), intended primarily for the protection of metal surfaces, are not new. The earliest patent (known to the editors) for one such substance, octadecylamine (ODA), was issued in 1954, with first powerplant applications in the former Soviet Union and East Germany. Earlier still, FFS were used to protect shipments of military equipment during WWII.

What is more recent is focused research and trial into applications for combined-cycle plants. Hoped-for benefits include corrosion protection in heat-recovery steam generators (HRSGs), condensers, and the phase transition zone (PTZ) of steam turbines. Other benefits could be better pH control, and less chance of both single- and two-phase flow-accelerated corrosion (FAC).

But also new is an increasing risk of system and equipment damage caused by misapplication, misinformation, and failure to accurately prepare and monitor—in other words, jumping in too quickly.

Although the expected results sound great, potential damage—the industry is learning—can be great as well.

Is the use of FFS worth considering? Absolutely, especially given more cycling, low-load operation, and periods offline. Is this worth implementing, within an already complex water-chemistry program? It could be, depending on the system and equipment, and if you’re both knowledgeable and careful.

Neutralizing, filming amines. About three years ago, the CCJ-Online Team posted the following session review notes for the Combined Cycle Users Group, perhaps the only organization that covers water chemistry for the entire combined-cycle plant:

“The jury is still out on the use of amines,” but “addition of an amine with a low volatility at the pressure of concern may provide benefit: It will hang along the tube wall to protect against loss of oxygen and ammonia from that space. Absent amine, oxygen and ammonia can migrate into the bulk water, leaving the tube-wall area unprotected. Amine volatilizes later, but after protecting the tube wall.  

 “Bear in mind that amine blends are known to increase cation conductivity and possibly mask more corrosive anions. Their use is influenced by the severity of two-phase FAC and turbine corrosion. Monitoring of iron transport is highly recommended before introducing amine blends.”

Then CCJ ONsite published a detailed primer on this fast-approaching frontier, by EPRI’s Steve Shulder and Mike Caravaggio, entitled “Protect equipment against corrosion with neutralizing amines, filming products.” This detailed review covered the latest EPRI research into amines and filming products, monitoring of these substances in action, corrosion control in the steam-turbine PTZ, the need for new tools to quantify corrosion improvement, and a glance at ongoing research.

Since that time, the subject has been included, in some form, at all user-group meetings for combined-cycle systems and components—including turbines, HRSGs, and air-cooled condensers. Something has been happening.

A case study was noted in the inaugural (2017) HRSG Forum with Bob Anderson concluding with the importance (for all aspects of plant water chemistry) of “understanding the damage mechanisms and chemistry control options, performance monitoring, and the critical importance of acting on the measured results.” Measurement, it has been determined, is a difficult part of the overall equation.

IAPWS. The spearheading organization for both FFS research and implementation is the International Association for the Properties of Water and Steam. A key participant is Dr Barry Dooley, senior associate, Structural Integrity Associates Inc, and the executive secretary of IAPWS.

CCJ has been following Dooley (and others) on this for quite some time.

Amines, products, substances. The First International Conference on Film-Forming Amines and Products was held in Lucerne, Switzerland, in 2017. Before the second conference in 2018, organizers had issued a formal and much-needed change in nomenclature.

The term film-forming substances was introduced by IAPWS last year. Feedback from the first two conferences had indicated confusion about the various terminologies used within this relatively new field of chemistry, or what Dooley calls “a narrow topic in cycle chemistry control of powerplants.”

In response, IAPWS introduced the more general term film-forming substances. Two subsets describe these materials in terms of either being amine-based [film-forming amine (FFA) or film-forming amine product (FFAP)], or non-amine-based [film- forming products (FFP)]. FFS could now be the nomenclature for all of these substances worldwide.

FFS2019.

The Third International Conference on Film-Forming Substances, chaired by Dooley, provided a highly interactive forum for the presentation of new information and technology related to FFS, research results, case studies of powerplant and industrial applications, and open discussion among users, equipment and chemical suppliers, researchers, and industry consultants.

At the first meeting in 2017, IAPWS issued Technical Guidance Document (TGD 8-16), “Application of film-forming amines in fossil, combined cycle, and biomass power plants.” At FFS2019, there was global appreciation for and recognition of this unique document. Dooley announced that later this year, a new TGD will be issued on FFS for industrial plants, along with a White Paper on the application for nuclear plants.

It’s important to note that experience in nuclear plants, primarily for layup and storage, continues to be good with ODA the substance of choice.

Nuclear plants have been a bright spot in discussion. There generally has been low impact on the chemistry control with complete observation of hydrophobic films in the feedwater and condensate systems. However, film formation in dry-steam areas remains a question.

But experience in fossil and combined-cycle plants continues to be variable in terms of corrosion-product transport and film formation in steam circuits. Suggestions are being made, repeatedly, to improve the verification process using tube samples and corrosion-product monitoring during startups.

At FFS2019, international updates were presented on recent experiences from powerplants of all types and from industrial plants. Bulleted items below provide some specifics. Participants indicated that problems experienced at fossil and combined-cycle plants after application of FFS most often relate to increased deposition on heat-transfer surfaces which result in under-deposit corrosion

• • Updates were provided on ongoing research activities from different international organizations dealing with decomposition of FFA, thermolysis and distribution of FFA, measuring/quantifying the concentration of FFS in the water, adsorption kinetics of film formation, and the effects of FAC.
  • Many FFS mixtures contain undisclosed (proprietary) components including those commonly referred to as polycarboxylate dispersants. At high pressures these can break down and cause tube failures. Failures can also be caused by any free hydroxides that end up as sodium hydroxide during thermal breakdown. There was no understanding among participants on why a polyacrylate addition was being included in proprietary products.
  • Another discussion thread was the open issues related to inspections following application of FFS to a plant, and the methods of determining hydrophobic films on surfaces, especially steam surfaces, and whether their presence can be related directly to corrosion protection.
  • Little new work was presented on understanding the mechanism of the interaction of FFS with surface oxides and on how an FFS film might change the growth mechanism and morphology, and result in reduced levels of corrosion-product transfer. This relates to the interaction of the FFS film with existing oxide/deposit surfaces in condensate/feedwater and in boiler/evaporator water. Much discussion took place on the oxides which form in steam circuits, and on the chromia oxides which form in the phase transition zone of the steam turbine.
  • One of the continuing conclusions from FFS2019 was the need to first optimize the current chemistry of a plant with verification, or through baseline monitoring, before application of any FFS. See “Section 8 guidance” section below.
  • There were extensive discussions regarding gaps in knowledge and needs for further research work. Dooley noted that IAPWS will define, via one of the organization’s Certified Research Need documents, the work needed on the interactions occurring under all plant conditions and temperature ranges.

To sum up, there is still much to learn and a lot of fundamental work that must be done to understand the mechanisms at play with FFS—including film-formation kinetics, equilibrium and stability, film structure (for example, thickness or number of layers), how the adsorption is affected by other amines, and the correspondence to the reduction in corrosion rate through understanding of the interactions with oxides and deposits.

Cases in point. At the second annual HRSG Forum with Bob Anderson in 2018, EPRI’s Shulder concentrated on FFS application for both corrosion resistance and layup protection. He stated that amine/filming technology is increasingly considered for the following base benefits:

• • Non-optimized corrosion product transport with recommended feedwater treatment program.
    • • Cyclical operation with a number of startups.
      • Excessive ammonia may result in vapors within plant and short polisher runs.
  • Two-phase FAC damage.
    • • Neutralizing amines may provide better dissociation and distribution than ammonia.
      • Higher localized at-temperature pH.
  • Better layup protection during outages of variable duration.
    • • Film-forming products place a hydrophobic barrier between metal surface and liquid.
      • Limit on capital expenditures or labor (dehumidified air).

One highlight of FFS2019 was a presentation entitled “Cycle chemistry issues due to the incorrect application of a film-forming substance,” by David Addison, principal, Thermal Chemistry Ltd, Hamilton, New Zealand.

The case presented was a 600-MW (4 × 150 MW) coal-fired station in Australasia, commissioned in 2010. The plant features a reverse-osmosis/mixed-bed demineralizing plant and is seawater-cooled (no condensate polisher, copper condenser). The feedwater system is all-ferrous.

Although a coal-fired facility, the FFS issues presented are common considerations in both conventional and combined-cycle plants.

The site was commissioned on AVT(R) with phosphate treatment in the boilers, but converted to a film-forming product in 2011. Chemistry guidelines at the plant were described as “limited.”

FFS details (contents) were listed as follows:

• • Oleyl propylenediamine (OLDA).
  • Cyclohexylamine.
  • 2-aminoethanol.
  • Polycarboxylate dispersants (details not known).

Treatment, co-dosed with ammonia, was manually applied and tested with a target concentration (as product) of 12 ppm.

A local agent supplied the product and used “consumption of product” as the basis for testing. Publicly available information from the vendor states the product was formulated “for steam and water systems with softened feedwater” (obviously not the case for this plant), and for plants without a steam turbine, also clearly not the case for this coal-fired facility.

Site steam/water analysis. At the time of the plant review by Addison, no online analyzers were functional and the majority of the sample points themselves were not functional. The entire analysis system had been out of service for eight years, and very little manual sampling and testing was being performed. According to the owner/operator, the site had been told by the FFS vendor that, thanks to the FFS program, there was little need for any online sampling and analysis.

Condenser tube leaks were occurring, undetected.

Major plant issues. Significant boiler waterwall and superheater tube failures were happening causing unplanned forced outage. FAC was causing failures in the feedwater system (with high iron levels). The following observations were made:

• • There were multiple feedwater pipework/heater failures consistent with FAC attack.
  • Multiple HP heaters had been removed from service because of excessive and repeated leaking.
  • Significant amounts of iron oxides were observable in functioning manual sample points (economizer inlet and boiler).

Overdosing of the FFS (above 130 ppm) was at times causing blockages and so-called gunk balls.

No condition-assessment tube samples were taken at the plant during the time under review, and there was no tube failure reduction program in place. Tube analysis by the FFS product vendor was characterized only as “rudimentary.”

The steam turbine was experiencing deposits, pitting, and cracking. Deposits were present on all blades (HP/IP/LP) and no carryover testing was being performed. The first and only turbine-deposit analysis was undertaken by Addison in 2019 during an overhaul and repair outage.

Deposits were consistent with continuous carryover and spray-water contamination while operating with condenser tube leaks:

• • Silica, sodium, and chloride dominated deposits with high sodium and chloride amounts relative to the IP.
  • Silica, sodium, and chloride dominated deposits.
  • Silica dominated deposits.

None of the saturated- or superheated-steam sample points were functional.

Section 8 guidance. A key point made by Dooley at the Air-Cooled Condenser Users Group annual meeting in 2018 was the importance of correct application of IAPWS TGD 8-16, specifically Section 8. It provides clear guidance for applying film-forming substances to generating plants as a supplement to, or as a replacement for, the current chemistry regime—clearly something not apparent to the owner/operator of the plant discussed above.

Addison said that the following key activities had not taken place before conversion from AVT(R)/phosphate treatment to a film-forming product:

1. Tube samples had not been taken and analyzed to understand the oxide condition of the unit. Chemical cleaning might have been needed.

2. A detailed internal inspection of the plant had not been undertaken.

3. A full baseline set of functioning chemical analyzers did not exist.

4. There was no full baseline set of data for corrosion-product transport.

5. There should have been a full composition breakdown of the FFS product so thermal degradation products could be assessed.

TGD non-compliance. Addison’s presentation at FFS2019 pointed out that FFS products, “if applied correctly and in the right circumstances, can actually work really well for offline protection.” He continued, “Baseload is often a challenge to justify the cost versus the potential benefits, but if a combined cycle is off and on then it should at least be carefully considered to determine if a technical and economic use case is present.”

Addison also is involved in development of international cycle-chemistry guidelines for industry, both IAPWS and EPRI. He is the vice chair of the IAPWS Power Cycle Chemistry Group and chairs the New Zealand Association for the Properties of Water and Steam.

The Australasian plant experience above was a classic example of failure to follow IAPWS TGDs for an FFS program or any other aspect of cycle chemistry, and of being entirely reliant on substandard technical advice from a chemical vendor.

The current FFS program at the plant in Australasia has been stopped, pending resolution of other issues. Boiler-tube-failure and turbine-deposit analyses are now underway to determine the precise root causes. A complete steam/water sampling system upgrade has begun, key elements of a boiler-tube failure reduction program are in place, and both cycle chemistry and IAPWS TGD familiarization training have been implemented.

Ongoing discussions. Other related presentations at FFS2019 included long-term preservation (two years) of a coal-fired plant in Germany (good hydrophobicity and no corrosion), and successful use of FFS as a corrosion inhibitor at a combined-cycle power station in the UK.

Also noted was a major challenge with layup and storage of combined cycles, namely the impact on air-cooled condensers. The topics of FFS and cycle chemistry are included in meetings of the Air-Cooled Condenser Users Group.

FFS2020 remains in the planning stages for early next year, with a probable location in France. Details will be announced in CCJ and on the IAPWS website.

The topic also will be included in the upcoming HRSG Forum with Bob Anderson, July 22-24, at the Hilton Orlando.

Film-forming applications for selected component and surface protection are an ongoing target of active research and trial. Experiences, both good and bad, are finally getting the attention they deserve. Most deserving is the clear message to apply due diligence and tread carefully!

Learn from the experts on powerplant chemistry

David Addison, principal, Thermal Chemistry Ltd, a frequent contributor to CCJ on cycle chemistry, called to recommend attendance at the 2019 PowerPlant Chemistry Forum, Sept 26-27, in Washington DC. Addison, who works globally out of his New Zealand office, chairs his country’s committee to the International Association for the Properties of Water and Steam, which develops cycle-chemistry guidelines for industry. He also serves as the vice chair for the IAPWS Power Cycle Chemistry Group.

The fall meeting, which will focus on the latest developments in cycle chemistry of interest to asset and plant managers, operations personnel, plant engineers and chemists, services providers, and others, addresses the needs of combined-cycle, conventional fossil, and nuclear plants.

Preliminary agenda topics include the following:

• • Cycling operation and its chemistry challenges.
  • Startup and layup strategies for chemistry control.
  • Chemical control and monitoring.
  • Sampling systems and instrumentation.
  • Lifecycle chemistry optimization and management.

The steering committee is organizing a program that consists of both invited and contributed technical papers and provides adequate discussion time. Committee members, in addition to Addison, are:

• • Chair Michael Rziha, PPChem AG (Switzerland).
  • Steve Shulder, EPRI.
  • Doug Hubbard, AEP.
  • Chad McKnight, Southern Company.
  • Erin Westberg, FPL/NextEra.
  • Mike Rupinen, LG&E and KU.
  • Randy Turner, Swan Analytical USA.

Follow program developments on the PowerPlant Chemistry website.

The Air-Cooled Condenser Users Group (ACCUG) annual meeting was held outside the US for the first time, in Queretaro, Mexico, Oct 21-24, 2019.

Sessions began with a review of information on flow-accelerated corrosion (FAC) and cycle chemistry prepared by Barry Dooley, Structural Integrity, and presented by EPRI’s Andy Howell, chairman of the group. In-depth discussion covered typical ACC damage and consequences, plus steam-turbine deposits. Timely issues of film-forming substance (FFS) research and application also were addressed.

ACCUG annual meetings began in 2009. The collaborative environment fostered by this focused organization helps chemists, engineers, and O&M personnel expand professionally and return to their plants with best practices for reducing operating expenses and improving system performance.

The following reviews highlights of selected presentations. To learn more, visit the group’s website.

Complexities of filming substances. EPRI’s Brad Burns highlighted cycle-chemistry experience at an ACC-equipped 2 × 1 baseload combined cycle in Mexico. Burns is senior technical leader for EPRI’s Program 64, Boiler and turbine steam and cycle chemistry.

The subject plant was commissioned in 2010 “with minimal sampling and analysis, and no clear pH target.” After several years of operation, iron in condensate and feedwater exceeded 50 ppb, an unacceptably high value. Outage inspection showed a Dooley Howell Corrosion Index (DHACI) of 4C, indicating the significant corrosion damage shown in Fig 1. Details are presented in the user group’s report ACC.01, “Guidelines for Internal Inspection of Air-Cooled Condensers.”

In 2014, improvements were made in the plant’s sampling and analysis panels and a pH target of 9.8 was set using ammonia. After a year of unsatisfactory results at pH 9.8 (iron remained high), the owner/operator attempted to feed a blended filming amine to a target residual but was unable to verify results. The target pH was changed to 9.4.

Treatment was changed in January 2017 from ammonia-only to a 2:1 ammonia/ETA blend, increasing the pH target to 9.6. The blend was eventually changed to 4:1, achieving a pH of 9.2 to 9.3.

As measured in the 2017 outage, the DHACI remained at 4C.

This presentation showed the complexities of filming chemical utilization, noting thermal decomposition of neutralizing amines and difficulties in achieving an optimum feed rate.

Lessons learned included the following:

1. Either increase liquid-phase pH with ETA feed upstream of the ACC (not at the condensate pump discharge), or maintain at least pH 9.8-10 consistently with ammonia at the CPD.

2. Apply standalone LP drum and IP drum pH control with trisodium phosphate (TSP).

3. If using a filming amine or filming product (film-forming substance, FFS), choose one with minimal blended constituents so that target residual can be achieve without dramatic increases in cation conductivity caused by the breakdown of chemicals in the blend.

Saavi Energia. Oscar Hernandez, O&M manager for Saavi Energia, and a member of the user group’s steering committee, discussed fleet-wide system chemistry programs for the Mexico City-based private power producer. Saavi operates several combined cycles—including three with ACCs (El Bajio, San Luis de la Paz, and Chihuahua).

Corporate chemistry guidelines are based on the recommendations of both EPRI and the International Association for the Properties of Water and Steam (IAPWS). One principal objective, Hernandez explained, is an ideal pH level which “must be controlled properly within the recommended range.” He noted two plants with pH targets of 9.4 and 9.6, both showing acceptable iron levels.

Accurate benchmarking, monitoring, and treatment are critical, he explained. The presentation offered details and background on treatment options, monitoring, and diagnostics. Hernandez also described Saavi’s experience with ACC decay tests and finned-tube cleaning methods.

The speaker strongly recommended challenging the cost/benefit claims of contractor-proposed chemical programs (cost versus unit capacity factor).

Emmauel Luévano, a manager at Saavi’s Chihuahua III plant, subsequently reviewed the company’s ACC best practices—including fan start/stop sequencing, fan performance monitoring, vibration analysis, infrared imaging for steam flow distribution, mechanical inspection, etc.

Modifications at Rio Bravo. Hector Moctezuma, Falcon Group, presented on the windscreen project at Central Valle Hermoso, a 500-MW facility added in 2005 as part of the 1490-MW Rio Bravo Energy Park.

Design plant output had been “unattainable during the summer months because of high backpressure. The significant reduction in power output was attributed to ACC under-performance in hot and windy conditions.”

Moctezuma added that “even though the condenser was sized, specified, and supplied correctly, there had been degradation from severe fouling and tube damage. Performance was affected more by higher temperatures and winds.”

The owner/operator considered options and selected a wet/dry parallel condensing system (Fig 2). This was based on considerations that included:

1. ACC enlargement was a very expensive option with marginal benefit, and

2. Additional water sources were available in the vicinity for the limited need.

In this system, “exhaust steam is simultaneously condensed in both a wet evaporative and existing dry cooling system.” The goal was to “remove the steam-turbine backpressure limitation during all periods with ambient temperatures higher than 86F—about 1000 hours per year.”

Advantages of the parallel system included:

• • Combines the performance of a wet evaporative system with the water savings of an ACC.
  • Optimizes water use to minimize condensing system costs.
  • Sized to meet cooling-water availability.

However, the performance-reducing impacts of local winds remained. Winds were causing an ACC pressure increase of 0.44 to 0.88 in. Hg by reducing fan speed, resulting in a steam-turbine power decrease of 3 to 4 MW. This occurred with wind speeds above 9 mph (1800 hr/yr) and became very significant at speeds between 16 and 19 mph (300 hr/yr).

Windscreens were selected to reduce both wind speed and crosswind effects. All available options of type and location were considered. A combination of cruciform and suspended screens was optimal for the atmospheric conditions at the plant. ACC structural reinforcement was needed to comply with Mexican regulations. Screens were installed in May 2018.

Under worst conditions (ambient 86F and winds 19 mph), backpressure and power output improved by 0.59 in. Hg and 1.68 MW.

ACC bundle replacement. Derek Silbaugh, an engineer with Black Hills Energy, reviewed plans to undertake replacement of the tube bundles in an ageing ACC. The multiple issues involved in determining a cost-effective approach for improved performance and long-term reliability are complex but relevant to others in similar situations.

Optimizing windscreens. Cosimo Bianchini, Ergon Research (Italy), offered a comprehensive update on windscreen design and application, entitled “Deficiency reduction after installation of optimized windscreen configuration.”

His presentation included motivations and objectives for windscreens at two 800-MW combined cycles, each with an ACC having nine streets and four cells per street. Screens were installed in 2014 on one ACC to allow greater capacity during hot windy days.

Suspended screens were supplied on the first unit, with performance measured one year before and one year after. Comparisons based on similar ambient temperature, relative humidity, with speed and direction, and backpressure showed an output improvement of 15 to 20 MW with the screens in place. Screens were most effective for wind speeds of 20 mph and below.

Both units were later subjected to CFD modeling for possible improvements, testing a wide range of screen configurations—both ground-based and suspended (Fig 3).

Bianchini’s presentation provided extensive modeling details including variations in screen type and placement. Adding to the complexity, the two ACCs (windscreen options and configurations) could be studied and upgraded independently.

One interesting takeaway was visual representation of the seemingly abundant options.

Bianchini offered the following conclusions:

• • Optimization of windscreen layout by CFD identifies candidates with much higher performance than the one currently installed. Some options were eliminated because of installation complexity and higher structural loads.
  • The selected layout showed capability of recovering 58% of the losses of the downstream ACC capacity compared to the upstream unit.
  • A simplified economic analysis showed an acceptable payback period.

Induced draft. Thomas Louagie, SPG Dry Cooling, discussed the emergent topic of induced-draft ACC designs, along with a history of development from traditional A-frame mechanical draft units. SPG offers a W-style heat exchanger arrangement for all sizes of plant output.

Features include SRC© finned tubes (aluminum-clad steel tubes with brazed aluminum fins); fan deck with perpendicular-shaft gearbox, motor, fan, and fan bell on top of the heat exchanger; short fan bridge supported in the middle by the central top manifold; and an accessible fan deck for maintenance.

Two negative effects of wind on traditional ACC performance are recirculation of hot air exiting the ACC, and reduced fan air flow attributed to disturbances at the air inlet. “With the W-style ACC,” explained Louagie, “recirculation is reduced due to higher exit air velocity, and the fan inlet is protected from crosswinds by the tube bundles, acting like screens.”

“Flow-accelerated corrosion can also be reduced,” he explained, “due to lower steam velocities and less steam pressure drop.”

Details presented also showed improved backpressure and higher steam turbine production at low ambient temperatures (below 50F).

What might be of particular interest to owner/operators is that the ACCUG’s 2020 meeting, Sept 28-Oct 1, at the Danbury (Conn) Crown Plaza will include a tour of CPV’s Towantic Energy Center, which features and induced-draft ACC (Fig 4).

Direct-drive fans. ABB’s Marty Mates explained the installation and experience with permanent magnet (PM) direct-drive fan motors, first introduced to the wet cooling-tower market in 2008. ACC trial installations began in 2015 (Fig 5).

Mates discussed background development, including feedback from previous ACCUG meetings, beginning in 2012. A prototype project concept installed at Basin Electric Power Co-op’s Dry Fork Station) was reviewed at the 2014 conference. Previous group discussions included reliability, size/weight, gearbox issues, and general maintenance concerns.

Environmental issues (including noise) and parasitic load (efficiency) were also discussed for the new design.

Dry Fork’s prototypes were installed in 2015 and 2016, both rated at 250 hp at 104 rpm. Mates also reviewed the installation challenges and solutions for a recent installation in Jordan.

Wet-to-hybrid conversion. George Budik, global product manager for ENEXIO Dry Cooling, explained that water demands continue to rise, offering an example for plants with evaporative/wet cooling systems. “Each 1 MWh of electricity produced in a fossil power plant requires 600 to 660 gal of makeup water to replace wet cooling-tower losses by evaporation, blowdown, and drift,” he explained. There is, therefore, a trend toward at least considering “conversion to all-dry or hybrid cooling technologies.”

Budik then explained various options, including what he called “the optimum solution,” cautioning that each design is site- and system-specific.

Thermal storage. Ronan Grimes, University of Limerick (Ireland), offered a low-temperature thermal storage concept designed to address the following issues with A-frame ACCs:

• • The minimum temperature to which turbine outlet steam can be theoretically cooled is ambient air temperature; practically, it is somewhat higher.
  • Hot climates impose a thermodynamic efficiency penalty.
  • Air in-leakage (efficiency loss) is common.

One approach is low-temperature thermal storage (LTTS, Fig 6) in which a water-cooled condenser (WCC) is combined with a thermal energy storage (TES) tank and air-cooled heat exchanger (ACHEx). The goal is to “exploit the natural ambient temperature variations to condense steam at sub-ambient temperatures.”

In charge mode (during low ambient temperatures), water is pumped from the tank to the ACHEx, cooled, and returned to the tank for storage. In bypass mode (moderate ambient temperature), water from the water-cooled condenser is cooled in the ACHEx then returned to the WCC. In discharge mode (high ambient temperatures), chilled water is pumped from the tank to the water-cooled condenser where it condenses steam at sub-ambient air temperatures.

Feasibility studies and modeling for this concept are ongoing. One noted case study operated at eight hours of charge, eight of bypass, and eight of charge. Modeling results were explained.

Remote performance management. Sean Cusick, SPG Dry Cooling, followed with ACC360 remote performance management, which provides virtual insight into the performance and health of any air-cooled condenser. Main components are:

• • Performance analytics that evaluate past, present, and future performance.
  • Condition-based monitoring, including vibrational monitors, to predict potential failures.
  • Integration of data with weather forecasts.

Cleaning is a must. Consultant Huub Hubretsge addressed the group on various traditional methods of ACC cleaning: high pressure wash, blasting with dry ice, etc. He also explained specific methods of calculating steam-turbine performance loss caused by ACC fouling.

Hubretsge pointed out that these losses go beyond less air available for cooling and reduced heat-transfer coefficients. “If the backpressure at the turbine exhaust increases, the enthalpy of the exhaust steam increases as well (less water in the steam). The higher the enthalpy of steam at the turbine exhaust, the less enthalpy is used for power generation.”

He offered a rule of thumb: “A general rule says that the total power generation will drop 0.7% for every 0.3-in.-Hg pressure increase at the turbine exhaust.”

Sample cleaning/fouling loss calculations were made available to all attendees in Excel spreadsheet format.

For a thorough review of cleaning needs and options, download at no cost Report ACC.02, “Guidelines for Finned Tube Cleaning in Air-Cooled Condensers” at acc-usersgroup.org/reports.

ACC performance enhancement. Andy Howell reviewed the common sources of dry cooling inefficiency (direct-condensing ACCs): steam-to-air heat-transfer efficiency, dependence on ambient temperature, and power requirements for large fans. He then reviewed further inefficiency issues:

• • Air-side debris accumulation.
  • Air in-leakage.
  • Wind effects.
  • Hot air recirculation.
  • Gaps and air bypass.
  • Tube fin damage.

All are common discussions at the ACCUG meetings.

Howell also reviewed more specialized topics from past conferences: wet cooling support, air misting (fogging), deluge cooling, and system expansion (adding streets).

He noted that “a variety of performance improvements are available and should be evaluated for cost effectiveness.” In particular, Howell mentioned fan uprates, including some common uprate results for a specific scenario:

1. Auxiliaries consumption increased by about 1.2 MW because of a larger fan-drive system.

2. Complete elimination of back pressure limitation, with a significant and sustained improvement of a least 3.5 in. Hg.

3. Increase in power output because of a reduction in condenser pressure and the possibility of increasing condenser load and steam flow through the turbine.

4. Heat-rate improvement attributed to lower condenser pressure and lower back pressure on the steam turbine (which he called “free power”).

The first meeting of the Australasian Boiler and HRSG Users Group (ABHUG), held last fall (2019) in Brisbane, Australia, followed 11 annual meetings of AHUG (Australasian HRSG Users Group). The added B is for boilers. Content now includes conventional fossil-plant technologies and issues closely related to those involving heat-recovery steam generators in combined-cycle and cogeneration systems.

ABHUG is an interactive forum for the discussion of new information and technologies related to HRSGs and boilers—including case studies of plant issues and solutions. The event is supported by the International Association for the Properties of Water and Steam (IAPWS) and its national committees in Australia and New Zealand.

The 2019 agenda featured 21 presentations plus a comprehensive workshop on welding, which included segments on ligament cracking in superheater headers, cold repair of Grade 91 materials, and modifications to HRSG ducting.

Updates also were provided for system chemistry, instrumentation and FAC, and thermal transient issues for attemperators, condensate return and superheater/reheater drain management, and bypass operation.

One shared HRSG/boiler issue is layup and offline protection, increasingly common to all operating systems that make way for the growth of renewables. Improper shutdown and layup procedures are now a standard topic at these industry events.

What follows is an insight into some of the shared challenges.

Pitting corrosion at Tarong. The 1400-MW Tarong Power Station in Queensland was commissioned in the 1980s with four subcritical coal-fired boilers, each rated at 350 MW. The primary reheater is located in the back pass, composed of two sections with horizontal tube elements—126 total elements across each boiler’s width. Design steam conditions at the headers  are 935F at 765 psig (610 psig operating).

In 2012, owner/operator Stanwell Corp announced plans to shut down two units for two years because of reduced demand and low wholesale electricity prices. When the cost of natural gas rose in 2014, Stanwell returned the units to service.

Following a Unit 3 major outage in 2018, four reheater tubes across different elements experienced primary failures. Two months later, another two tubes across different elements experienced similar failures (Fig 1).

An EPRI roadmap was used to identify, evaluate, and solve the boiler-tube failure issue—EPRI Technical Report 3002010388, “Boiler and heat recovery steam generator tube failures: theory and practice.”

Stanwell adopted the process described in the EPRI document to determine the following:

1. Primary failure location.

2. Primary failure mechanism.

3. Primary failure root cause.

4. Factors contributing to the primary failure mechanism.

Both visual and tube-removal analyses revealed the key factors and mechanism:

• • Corrosion only in the bottom half of the tube.
  • Partial or complete through-wall pitting corrosion on welds and randomly on tube parent material.
  • Pit sites open or filled with reddish or reddish-brown corrosion products.

In this case, all pit sites were located in the center sections of horizontal tubes (Fig 2). There was no external erosion, apart from steam erosion, attributed to the primary failures. Stanwell’s conclusion: Pitting corrosion attributed to inadequate layup was the primary failure mechanism.

Investigations included metallography, water sources and system chemistry, shutdown procedures, reheat spray operations, and pressure excursions.

Stanwell’s G Wang stated the primary failure root cause as “condensate formed during shutdown. The accumulation of condensate at the bottom of the tubes with oxygen being subsequently introduced during the shutdown provides a stagnant oxygenated-water environment for pitting initiation and development.”

Wang also reviewed relevant contributing factors:

• • History of shutdowns, durations, and long-term preservation practices.
  • Chemical excursions (condenser leaks, for example).
  • Corrosion at welds caused by weld/tube galvanic attack.
  • Sagging at center of horizontal tube elements.
  • Pressure excursions.
  • Lack of protection during washdown after tube failure events.

Stanwell’s long-term strategy includes repair/replace option reviews, enhanced inspection methods, and a direct action for shutdown of “drying the tubes before condensate formation and maintaining RH below 35%.”

Wang then listed specific future inspection methods:

Welds. Cobra PAUT/ToFD (ultrasonic phased array and time-of-flight diffraction) ultrasonic.

Tube parent material. EMAT and FMC/TFM (electromagnetic-acoustic transducer and full-matrix capture/total focusing method).

During discussions, Structural Integrity’s Barry Dooley stressed the benefits of “sharing issues across combined-cycle and conventional fossil plants. Corrosion can be initiated during inadequate layup. This and other presentations illustrate just how severe pitting damage can be for both combined cycle and conventional units.”

Kogan Creek Power Station (CS Energy Australia) is a 750-MW supercritical coal-fired unit in Queensland, commissioned in 2007. In 2018, a tube leak occurred in the horizontal reheater section of the boiler, causing significant secondary damage and an 11-day forced outage. Fifteen tubes were replaced (Fig 3). The primary failure was a pinhole leak that developed near the middle of the horizontal run, at the bottom of the tube. The failure mechanism was identified as pitting corrosion.

Galvanic corrosion caused by moisture and oxygen led to rapid pitting. CS Energy’s Luke Smith explained that “the base of the pit, low in oxygen compared to the wet metal surface, became anodic. This occurred during shutdown when steam was allowed to condense (not during operation). In this particular case, a low level of sulfate also was present.”

In 2019, the entire reheater was replaced (three banks of 196 elements), extending an outage from 56 to 77 days.

The long-term prevention objective is to replace dry steam with dry air (dry storage). Smith explained that “once the reheater has had about five changes of volume, the HP bypass is opened to allow air to flow to the superheaters. The flow of dry air will be maintained for the duration of the outage if possible. We aim for an RH below 30%.”

This was followed by participant discussion on use of dehumidified air (DHA) for systems including reheaters and steam turbines. Dooley again offered input: “Unfortunately,” he said, “the application of DHA is usually added after the damage has occurred, instead of proactively beforehand.”

AGL program. Stewart Mann, responsible for asset integrity at AGL Energy Ltd, discussed the corporate-wide approach to boiler-tube failures at both gas- and coal-fired steam turbine units.

The AGL tube-failure reduction program records each failure mechanism and root cause, the specifics of each repair, and all planned actions.

The approach discussion raised many logical but often bypassed steps needed for a complete analysis program. First, the AGL program is based on the model in EPRI Report 1013098, “Integrated boiler tube failure reduction/cycle chemistry improvement program (2006).” Second, it is produced as a fleet-wide AGL standard. Third, it is now integrated with AGL’s cycle-chemistry standard.”

The goal is to apply risk-based systems to minimize repeat failures, reduce failures from new mechanisms, and decrease the number of failures at new locations for known mechanisms. As Mann stated, “Unless we have recently changed how we are operating, credible inspection and analysis should enable us to confirm whether a potential mechanism is an issue at our plants.”

Data gathering includes failure mode and mechanism, root cause, extent of damage to the tube with the primary failure, tubing in the vicinity of the primary failure (secondary damage), and the surface areas along the leaking tube.

“AGL is careful to preserve removed tubes for metallurgical examination, and to always consider possible removal of additional samples,” added Mann. Also, every repair has strict QA provisions for:

• • Welder certification.
  • Inspector certification.
  • Welding procedures.
  • Welding materials.
  • Selection of tube materials.

“All of this,” he continued, “requires good collaboration among trading, operations, and engineering.”

Each ALG site now has a dedicated boiler-tube failure-reduction program team that includes:

• • Site boiler engineer (lead).
  • In-service inspector.
  • Principal engineers from the company’s technical services group.
  • Operations input.
  • Maintenance input.
  • Complete failure and inspection history reviews.
  • Development of inspection strategy and action plans.

“All reports are finalized, distributed, and accessible to everyone,” he said.

Mann offered an interesting concluding challenge: “Play devil’s advocate, and be prepared to question any prevailing norms.”

A common tube-failure approach. Pitting issues from improper shutdown protection can affect both the HRSG and the steam turbine, as discussed in the recently released report “Trends in HRSG Reliability: A 10-Year Review,” by Barry Dooley and Bob Anderson of Florida-based Competitive Power Resources.

In that report, the authors discuss the importance of root-cause analysis and HRSG tube-failure (HTF) programs. They caution that a tube failure often is assumed to be a bad weld, but warn that if tube removal and analysis are not performed the problems will likely continue.

This review continues: “In many cases the actual root cause may be due to a cycle chemistry deficiency, design feature, or operating practice that has repeatedly inflicted corrosion, corrosion fatigue, or thermal-mechanical fatigue damage in the failed tube and its neighbors.”

It is indeed complex. “The only way to ensure that the corrective actions are taken and will prevent a tube failure from recurring is to remove the initial failure site, have the actual failure mechanism identified via a metallurgical laboratory analysis, then determine the root cause of the failure.”

The tube failure discussions at ABHUG were examples of effective root-cause analysis.

Also common: chromium risk. Chromium is a common alloy element in stainless steels and high-chromium-containing materials in steam turbines, steam turbines, boilers, and HRSGs. It is a transition element (metal) with multiple oxidation states.

Chromium III is essential for human health; Chromium VI (hexavalent chromium) is extremely toxic. Chromium VI is also easily managed with standard industrial hygiene and personal protection strategies applied, combined with neutralization where needed.

Risks associated with welding of high chromium materials are well understood in the industry, as are possible hazards during some chemical cleaning procedures.

Recently, however, hexavalent chromium has been identified on gas-turbine hot-gas-path components (Fig 4), steam-turbine hot external components (bolts), and on the external surfaces of hot HRSG/boiler piping.

For gas and steam turbines, there’s a link to calcium-containing anti-seize pastes often used on hot components.

The yellowish appearance can be misinterpreted as sulfur deposits from the fuel. “Bright yellow HRSG gas-side deposits should be considered a major warning sign, and treated with significant caution,” cautioned David Addison, principal, Thermal Chemistry Ltd (New Zealand).

Although understood and manageable, this alert involved one particular slide labeled “unconfirmed risk areas”:

Upper and lower crawl spaces with:

• • High-chromium pipework.
  • High-chromium liner places.
  • Oxygen atmospheres.
  • High temperatures.
  • Insulation containing calcium oxide.
  • Potential for rain water ingress that allows for calcium leaching.

For HRSGs:

• • Superheater/evaporator upper and lower crawl spaces.
  • GT exhaust ductwork—mainly on the insulation side of plates.