HRSG Forum 2019: Exclusive conference report

Technical presentations by subject matter experts on topics of importance to owner/operators of combined-cycle and cogeneration plants powered by gas turbines are the foundation of the HRSG Forum with Bob Anderson. 

Consulting Editor Steve Stultz has abstracted the presentations below from the group’s fourth annual meeting. O&M personnel likely will find at least one or two of use in helping to improve plant performance and in correcting deficiencies. Users wanting to dig deeper can request copies of specific presentations directly from Chairman Bob Anderson. 

Duke Energy’s experience in preparing its HRSGs for cycling

“Controlling condensation is a major HRSG team focus,” explained Eugene Eagle, Duke Energy. “Our long-term goal is asset protection and reliability.” The company’s lead HRSG engineer addressed participants on Duke’s extensive experience with HRSGs in North and South Carolina, explaining how it is preparing HRSGs for cycling.

All Duke HRSGs are triple pressure with reheat, equipped for duct firing, and originally designed for baseload and load-following. Most are within 2 × 1 F-class 500- to 800-MW combined-cycle configurations.

His emphasis was damage prevention: “We manage equipment. It does not manage us.” In other words, the hardware is there. You just need to use and care for it properly. This focus aligned with a principal theme of every HRSG Forum: long-term system reliability.

Eagle also offered detailed market backgrounder on the increasing need for cycling. Renewable energy continues to enjoy first-dispatch status, he said. Eagle’s analysis highlighted solar power, now targeting 2500 MW at Duke Energy alone. A solar-project status report for the continental US showed 35 GW in operation and another 75 GW under construction.

His summary: “On/off cycling, low loads in spring and fall, and flexible operations will become more common” as we are forced to defer to renewables. That means Duke must learn how to operate their combined cycles in cyclic mode while dramatically reducing thermal/mechanical fatigue damage to their components and systems.

A summary chart on expected unit life brought clarity, comparing damage levels for the most common cyclic events (Fig 1). “Units designed for baseload service will need to be modified,” he stated, “especially for condensate removal. Proper attemperator operation is also critical.”

Condensation can cause thermal-transient fatigue damage, as mentioned several times during the Forum and in detail in “Trends in HRSG reliability, a 10-year review,” published recently in CCJ ONsite.

Eagle’s focus areas addressed common Forum participant concerns:

    • Superheater and reheater drains.

    • Attemperators.

    • Startup and shutdown procedures.

    • Heat conservation after shutdown.

    • Proper chemistry practice.

He noted that the HRSG team at Duke makes extensive use of EPRI reports and research, including both #1015464 (startup and shutdown) and #1018003 (thermal transients).

The challenges. Maintaining hot startup conditions with HP drum pressure over 500 psig is difficult for many reasons—including auxiliary steam needs, drain operations, pre-start purge requirements, and leaking valves. “About six hours,” he said, “is the limit” for a hot restart.

Efforts are underway at several Duke sites to install thermocouples on select high-pressure superheater (HPSH) and reheater (RH) tubes to help evaluate drain system performance, calculate potential tube damage from condensate, and provide input for component life-assessment reviews.

He then displayed severe attemperator damage (Fig 2) and offered some experience-based recommendations:

1. Avoid reducing HPSH/RH attemperator setpoints below 1050F. “It is better to overshoot on steam temperatures than to overspray to saturation.”

2. Never place the HPSH/RH attemperator temperature control valve (TCV) into manual control or reduce temperature setpoints. This will cause overspray conditions and significant pressure-part damage.

3. Upgrade attemperator block valves to metal-seated ball valves (bi-directional seats).

4. Use a TCV martyr/block valve master arrangement.

Best practices. During startups and shutdowns, two parameters should be independently controlled: HP drum saturation temperature (HP drum pressure) and HP/hot-reheat (HRH) steam ramp rates.

For startups:

1. Procedures should be divided into hot, warm, and cold using different ramp rates and recommendations for each.

2. Use heat soaks at periods of high stress to minimize thermal fatigue damage.

3. Maintain HP steam and drum ramp rates within limits.

4. Immediately after synchronizing the GT generator, select both the megawatt output and the GT exhaust gas temperature (EGT) to the minimum values to reduce heat input to the HRSG during subsequent HRSG heat-soak stages.

For hot shutdown:

1. If GE 7FA or 9FA, always use exhaust temperature matching (ETM) for every startup and shutdown.

2. If GE 7FA or 9FA, rapid ramp through the hot zone at the low-load isotherm.

3. Steam-cool the HP superheaters within about 50 deg F of saturation.

4. After transfer to bypass valves, build HP drum pressure back to 1600-1800 psig with bypass valves. This will ensure that HP drum pressure will be above 500 psig (hot-start criterion) following a 6-hr shutdown.

5. For Siemens units, Duke is still working through reducing EGT for minimum loads.

6. Complete a final stabilization of approximately 5 min at GT minimum load before cease fire.

This led to Duke’s plans for retaining heat in the system during shutdown. The company’s program includes the following actions and recommendations:

    • Stack dampers are being added to some units.

    • For units with installed bypass dampers, close the dampers immediately after the GT has ceased firing to keep cool air off HRSG tubes during coastdown at low load (about 5 MW).

    • For units with installed stack dampers, close the dampers and isolate all steam, feed, vents, drains, blowdowns, etc, to retain heat and pressure.

    • Avoid topping off drums during layup; top off only just before restart.

Eagle concluded with some broad-spectrum recommendations going forward:

    • Review life assessment data.

    • Continue to monitor cycling evolutions and make improvements to both operational practices and control logics.

    • Install HPSH and RH tube-skin thermocouples; gather data to help refine drain operations and look for thermal damage mechanisms.

    • Continue with cycling improvement projects, namely:

        • Drain system upgrades.

        • Stack dampers.

        • Stack insulation.

        • GT purge credits (with low condensate generation).

Participant questions and discussions covered potential benefits of additional automation (less operator input to attemperator spray), proper insulation and thermal seals, stack damper and stack insulation benefits, the possibility of electric-blanket heating for drums, attemperator inspection intervals, header and tube repair techniques (and preferences), and the benefits of complete root-cause analysis (RCA) for damage.

What ASME’s new rules for Grade 91 mean to operators

ASME recently reduced the allowable stress values for Grade 91 (Gr 91) steel, a topic anticipated and discussed at length in the previous HRSG Forums. “It was not a decision taken lightly,” explained Jeff Henry of Applied Thermal Coatings—Combustion Engineering Solutions (ATC-CES), Chattanooga, Tenn. Henry currently chairs ASME’s Working Group on Creep Strength-Enhanced Ferritic (CSEF) Steels (Fig 3).

When reviewing the table, keep the following points in mind:

    • The distinction made between tube wall thicknesses in the 2017 Code no longer is viewed as meaningful.

    • Type 2 Grade 91 material has tighter restrictions on certain residual elements—such as copper, arsenic, tin, etc—than Type 1 material. The “cleaner” Type 2 offers better rupture ductility.

    • Data presented in Roman type are governed by tensile or yield strength; that in italics by creep strength.

The primary industry and Forum participant concern: “What does this mean for owner/operators?” There is confusion at the plant level in the US regarding the impact on future operation of plants with Gr91 pressure parts, and there is concern about the higher cost of Gr91 Type 2.

In China, explained Henry, there is “both anger and confusion” over ASME’s action. In Europe, there is “a more muted response” because similar actions have already been taken there.

CSEF steels are metallurgically complex alloys that achieve improved elevated temperature strength through controlled chemical composition and heat treatment. However, the quasi-stabilized structure produced in the CSEF steel during successful processing slowly breaks down under the influence of stress at elevated temperatures.

At last year’s meeting, Henry focused on Gr91’s history and development, and the original allowable stress rating process that lacked long-term testing and used only a limited number of heats. This year he explained in detail the critical and complex stages of adopting any new code material, using Grade 93 and Grade 23 (and others) as examples.

“In determining allowable stresses,” he explained, “the ASME Boiler & Pressure Vessel Code (Code) process reviews tensile, creep, and stress-rupture property data obtained over the temperature range of usage, and applies specific criteria listed in Section III, Part D, of the Code. If alloy properties, and particularly the allowable stress values, are attractive to designers,” he continued, “the alloy will be specified for use in new construction and for replacements.”

During the process of adopting a new Code material, Henry explained, the original producer generates technical requirements for the alloy to be included in a material specification, adopted by a Standards-making organization like ASTM. This provides requirements including chemical composition, heat treatment, and mechanical properties that any producer can use to make the alloy (as restricted by any patents).

“But,” he cautioned, “other producers can offer their versions of the alloy if any patent restrictions can be skirted. The final product will not necessarily be in accordance with the original producer’s best practice, and new producers often focus on meeting minimum requirements of the material specification.” This could include the most cost-effective heat treatment cycle or production process (continuous cast versus ingot).  

And one wake-up call: “To date, failures in Gr91 components seldom have occurred in base metal. Most failures have occurred at welds, where weld-related changes in structure govern life of the pressure part” not factored into the stress values. Also, current inspection techniques may not provide early warning of concerns.

So what does this mean for HRSGs?

1. For the existing fleet, the reduction does not mean the equipment is suddenly at risk.

2. If material problems exist or emerge, they are likely attributed to poor design, poor control of operating conditions, or poor quality control during either manufacture or installation (or both).

3. Assessments should be carried out to determine the significance of the Code reduction (if any) for individual components.

4. The main concern becomes margin, not necessarily material risk.

Henry then walked participants through typical staged assessment of plant conditions.Most concerning was a discussion on “implications for operators.”

“For new HRSGs and piping systems,” he predicted, “designers will look to stronger CSEF grades, particularly Grade 92 or Grade 93 (not necessarily a good outcome).” However, there is limited operating experience with Grade 92, questions remain over the poor damage tolerance of Grade 92, and there is less experience with Grade 93, even in Japan.

“Coupled with increasingly demanding operating conditions in response to expanding deployment of renewables,” he continued, “operators will likely face very difficult challenges in the coming years at a time when the resources available to successfully handle those challenges are more limited than at any time in the industry’s history.”

He repeated that we now have the loss of OEM metallurgy expertise, which is a “game changer,” along with elimination of support engineering functions within the utilities and operators. For the OEMs, he explained, this added expense was (in the past) in their own best interest as they “stood behind their designs and products.”

Unfortunately, he added, there are some smaller engineering firms that, although good, might not know how to address complex material interactions. “They might not know what they don’t know.”

Even more troubling was one participant’s prediction: “New builds are projected by some to be run by drones, not people.”

The reduced allowable stress values were released in July 2019 and are required by year end.

In Editor Stultz’s view, Jeff Henry’s presentations and discussions are timely, thought provoking, profound, and acutely informative. The HRSG Forum with Bob Anderson has become a prime venue for important updates to this critical issue. Henry is expected to return to the Forum in 2020 with additional updates and critical information.  

Oxide growth and exfoliation

Barry Dooley, Structural Integrity Associates Inc, covered the important fundamentals of flow-accelerated corrosion (FAC), optimum cycle chemistry, repeat cycle chemistry situations, and the potential for film-forming substances. He then focused on oxide growth mechanisms in power generation cycles, specifically oxide growth and exfoliation (OGE).

“The morphologies of OGE are well understood for both ferritic and austenitic alloys,” he explained, considering superheated steam with temperatures up to more than 1100F.

OGE has become, he said, a major problem worldwide. “Steam growth oxides are semiconductors and grow by counter flux ionic diffusion processes of Fe2+ moving outwards and O2- (oxide ion) moving inwards,” he explained. Growth and exfoliation of oxides in steam do not depend on oxygen levels, but on the partial pressure of oxygen and other factors.

Anderson and Dooley then presented data and experience discussed recently at the European HRSG Forum about reheater tube failures apparently influenced by internal oxide growth and exfoliation. The referenced plant is an 800-MW 2 × 1 IPP near Bilbao, Spain, that began commercial operation in 2003.

This installation includes horizontal triple-pressure HRSGs behind 9FA+e gas turbines upgraded to DLN2.6 in 2015.

Since 2011, the plant has been moving toward more frequent starts and fewer operating hours per cycle. Currently, unit operations rotate with one unit down for a week.

Thermal mechanical fatigue was causing recurring leaks in the No. 2 reheater. Typical tube leaks caused by thermal fatigue are shown in Fig 4.

In the case presented, however, a reheater tube failure occurred on the tube side of the tube-to-header weld (Figs 5 and 6). The possible cause investigated was oxide growth and exfoliation.

RCA sampling showed an ID surface gouge where oxide was spalling off. See the circumferential crack in Fig 7.

No baffles exist between modules in this HRSG and tubes next to the gaps had operated at higher temperatures than those in the middle of the module. Partial tube blockage with exfoliated oxide was the apparent cause.

As Anderson explained, even a 3- to 4-deg-F temperature increase can accelerate oxide growth significantly. If the tube at the gap is running hotter than its neighbors, this could mean thicker internal oxide which would further increase tube metal temperature. Any resultant tube flexing could cause the spalling.

This analysis continues, and thermocouples are being added to tubes at the gaps at the side wall, at the module ends, and well away from the gaps.

Questions regarding this ongoing investigation included ability to determine remaining life of a reheater using oxide scale as an indicator. Another posed question: How do you know whether the issue is temperature rather than geometry? The answer: This particular case is showing a natural progression of a T22 tube impacted by increased temperature.

Assessment of pressure-wave cleaning technology for HRSGs

HRSG tube cleaning experience is typically included in the Forum, and the past few years have predicted increased consideration of pressure-wave tube cleaning technology. In 2019, this was the focus of a presentation by EPRI’s Stan Rosinski.

He addressed the primary concern of owner/operators—potential tube and structural damage.

Pressure-wave cleaning technology, using methane and O2, was first applied to HRSGs in Ireland in 2015 based on improved cleaning effectiveness, reduced outage time, and reduced labor. The principal provider is Switzerland’s Bang & Clean Technology AG. GE currently holds the US license.

To evaluate potential tube damage, EPRI conducted tests at the Colorado School of Mines Explosive Research Laboratory, and results were reviewed at the Forum. Experiments measured blast parameters of both single- and double-bag configurations to understand the performance and effectiveness of the process (including shock-wave physics on finned tubes). High-speed photography captured the processes.

Metallographic analysis showed no internal or external tube cracking, and no fin damage. Tubes are now at EPRI for further analysis.

The final technical report is under review. Anticipated long-term applications also include evaluation of damage to catalysts and air heaters.

Expansion joints and penetration seals

Jake Waterhouse, Dekomte, explained that most expansion-joint problems are with the casings, not with the seals. And he asked some key questions:

    • Are the number of cycles specified when purchasing expansion joints?

    • Are irregular stresses and movements being properly evaluated?

    • What changes have been made since installation (patches, improvements, redesigns)?

He stressed that a key to reliability is technical assessment of current conditions and expected operations. He cautioned that “many HRSG OEMs can get it wrong in the original delivered design.”

Both visual and thermographic inspections become critical, creating condition reports that clearly state:

    • Evaluation of fixing system and gas tightness.

    • Review of adjacent elements for corrosion, cracking, or distortion.

    • Internal review of expansion joints, including the flow plates and lining systems.

As combined-cycle plants face greater challenges, owner/operators must be aware of any duct fatigue during thermal transients, irregular stresses caused by movements, and any acid or water dew-point condensation.

The discussion then focused on penetration seals, and the differences between common OEM supply and retrofit options. Metal bellows seem to be favored by OEMs, Waterhouse suggested, but are often not flexible enough for long-term plant operations. Metal in-kind retrofits often must be delivered in split halves, or pipes must be cut and welded. Fabric retrofits, however, offer greater flexibility in the most compact design, and are favorable for high-movement areas.

Various applications were discussed, with examples, covering metal bellows, sidewall installations for hot and cold reheat, metal-to-fabric retrofits, labyrinth/gland seal-to-fabric retrofits, and limited access roof seals.

Availability and application of online pumpable (liquified) insulation also was discussed.

Questions and discussions included the pros and cons of insulation inside metal bellows.

Impact of water ingress into insulation

Anthony Cosenze offered Aspen Aerogels’ inaugural presentation at the Forum, focusing on how water reacts within HRSG insulation systems potentially leading to corrosion under insulation (CUI).

“Aspen Aerogels has been protecting insulated pipes and materials in the petrochemical industry for more than a decade,” he stated. Cosenze explained water’s behavior within insulation as a “BTU conveyor belt,” a process of wicking, evaporation, capillary action transport (vapor), and re-condensation (Fig 8).

He followed with a case study from a US combined cycle involving a pinhole leak and ingress through a penetration seal with mineral-wool insulation. He likened the result to “a wet sock.” The insulation was removed, revealing significant OD corrosion (Fig 9). Next, Cosenze showed a photo of a pipe insulated with Aerogel after 10 years of operation (Fig 10).

HRSG examples discussed included penetration seals, HRH line bottom seals, and floor seal/boiler casing insulation integration systems.

A strong feature is reduced thickness and weight. Cosenze explained that a 2.8 in. thickness of aerogel/Pyrogel® offers the same insulating capability as 7 in. of calcium silicate or mineral wool, and is more hydrophobic (organic silicone base). Aerogel is lighter in weight (insulated pipe weight) with less wind loading, and is reusable.

Real-time health tracking of HRSGs and piping

Structural Integrity’s (SI) Ian Perrin discussed real-time health and damage tracking of HRSGs and high-energy piping, with a focus on attemperators.

He began with the fundamentals of typical damage and cause:

    • Creep: Temperature and pressure.

    • Oxidation/corrosion: Temperature, environment.

    • Fatigue: Thermal and pressure transients.

    • FAC: Temperature and chemistry.

He concentrated on real-time monitoring as a complement to offline inspections, material sampling, failure analysis, and fitness for service. His message: Online health tracking is dynamic rather than a static snapshot, and can take instrumentation well beyond the typical control function.

Virtual monitoring offers calculations based on available operating data (both current and historical), and real-time visualization of damage consumption. Results should be dynamic, based on actual history, and without assumptions regarding operating profiles.

The end goal is integrated asset health tracking directing inspection, repair, and possible component replacement scheduling.

SI offers an analytics engine that takes plant data in real time and develops lifetime consumption calculations, then displays the information within the company’s Plant Track system. The result is real-time, continuous damage tracking based on actual operation.

Such a system, he explained, can be retrofitted on older units. Plus, data from past operations can be collected to improve current life calculations.

Example applications displayed creep-damage development in high-energy piping systems, creep-fatigue and oxidation damage trending in HP and RH headers, and fatigue damage in selected attemperators.

Perrin’s specific case study was a reheat interstage attemperator where the damage mechanism was determined accurately, but would have been missed by a normal DCS with standard instrumentation.

Acoustic leak detection technologies for critical valves

Nick Grigas, Mistras Group, discussed critical valve leak-detection technologies, concentrating on acoustics and EPRI Program #1005285, “Attemperator Monitoring.” Plant 1 of the program is the Thomas A Smith Energy Facility in Dalton, Ga, a 1250-MW 2 × 1 combined cycle owned and operated by Oglethorpe Power Corp.

“Acoustic trends have demonstrated the ability to record significant changes in ultrasonic noise as the HPSH and/or RH attemperator valves open and close with spray demand,” Grigas explained. “This gives rise to the potential to use acoustics as an alarm for under plug/seat leakage.

Other recorded events have shown cycling of the HPSH block valve with zero spray demand, and what appears to be the RH spray control valve position chasing spray-flow demand. These events could lead to better understanding behavior of the attemperators’ control logic and development of potential corrections.”

He explained a variety of portable and online leak detection systems for continuous monitoring of attemperators.

Impact of GT upgrades on your HRSGs

HRSG topics and concerns focus largely on the transition to cyclic operations. System effects from gas-turbine upgrades can be equally challenging.

Uniper SE’s Dan Blood explained that traditional combined-cycle plants “are being displaced in the dispatch order by new market entrants (primarily renewables).” Note that Uniper was formed when E.ON separated the fossil-fuel generating facilities from its asset portfolio.

The relatively new company, based in the UK and Germany, has experience and credibility with more than 37 GW of total generation in more than 40 countries, including 25 years in HRSG/combined-cycle plants. Their profile promotes the following: “Our highly flexible and adjustable powerplants ensure a sufficient and reliable power supply.”

Blood stressed that the change from hours-based to starts-based operations can increase the owner/operator focus on startup costs. Gas turbine upgrades can improve a unit’s market value by improving speed of response (fast starts, fast ramps, fast shutdowns), by increasing maximum load and cycle efficiency, and by reducing emissions at low or minimum load. Upgrades are designed for enhanced ability to offer “grid services,” thereby keeping plants competitive.

“A key question to consider,” Blood stressed, “is the GT upgrade’s impact on the water/steam cycle and the ability of systems to cope with the new process conditions.”

He added a caution: “GT suppliers may not offer a comprehensive assessment or may make assumptions which are not truly valid.”

Blood offered a clear and structured approach to full-system impact assessment to mitigate such risks:

    • Planning:

1. Define new modes of operation (for example, new GT exhaust conditions).

2. Review impacts (plant modeling).

3. Conduct an initial review of risks (hazards and operability).

4. Quantify risks (engineering impact assessments).

5. Integrate risk reduction plans (modify designs or operating procedures).


    • Testing:

6. Undertake plant trials.

7. Assess plant trials (are the impacts as predicted?).


    • Implementation:

8. Apply, optimize, and standardize.

9. Re-assess.

10. Adapt/enhance maintenance and inspection regimes (for example, pressure-part integrity strategy).

Uniper offers a thermal-plant modeling program that evaluates key parameters, including saturation and superheat margin.

Blood described a case study, conducted jointly by Uniper and GE starting in 2011. This GE9FA/9FB variable-load-path (VLP) upgrade led to a full commercial product offering by GE.

Note that VLP is a GT control feature that uses inlet-guide-vane (IGV) control to keep exhaust temperature low during startup; allows independent control of GT load and exhaust temperature within an “operating space”; and significantly decouples GT output from HRSG/steam turbine thermal constraints.

Details shown included HRSG heat-balance comparisons, requirements for an “exhaust flow boundary” for plant integrity and safety, potential IP drum safety valve impact, and balance-of-plant risks and mitigations.

Questions from participants included application for low-load units at night, assistance in avoiding overspray during startup, and potential IP moisture carryover risk.

Anderson labeled the discussion “significant” as the industry upgrades turbines and “expects certain benefits or capital expense payback.”

Calpine Sutter restart experience

Andrew Gundershaug, Calpine Corp, discussed the history and restart of the 2 × 1 Sutter Energy Center in Yuba City, Calif. He covered the reasons for cold layup, the restart process, specific challenges, and lessons learned.  

Sutter was commissioned in 2001 and became “a gem in the Calpine fleet” using two 501F machines. It then became a stranded asset in 2015, and owners decided to stop operations.  

When the plant came offline, it transitioned to cold layup. Staff level was reduced to a small team (from 30 to four) tasked with plant oversight and continued operation of two LM6000 plants in the same area.  

Markets turned more favorable for operations in late 2017. Calpine made the call to restart the plant effective April 1, 2018.  

“The biggest concern was lack of staff and the short timeline,” stated Gundershaug. “A project engineer and HRSG expert were brought promptly to the site.”  

Major restart projects began January 15 and included DCS checks and enhancements, GT hot-gas-path inspection, steam-turbine minor inspection, HRSG inspection and cleaning, covered piping system survey, electrical system testing, valve inspection, and HRSG/GT1 expansion-joint replacement, among others.  

Lessons learned have included the benefit of bringing back former employees who understood operational issues, failure of using shutdown time to make needed (and known) repairs, unanticipated water requirements to rinse and flush the plant, the ability to troubleshoot and optimize an aging DCS system, problems with elastomer parts, calcium complications from lube-oil preservatives, attempts to use an old replacement-parts inventory, benefits of a third-party safety team to monitor and advise, and an onsite purchasing team becoming “overwhelmed with the amount of purchasing required.”

Sutter began operations on schedule and has been operating with an equivalent forced outage rate of 0.27%.

Automatic drain control on the cusp of commercialization

Updates have been presented at each Forum on the development of an automatic drain control system that began in 2011. The EPRI project, managed by Competitive Power Resources and supported by FLEXIM, is expected to go commercial soon.

In stressing the importance of this topic, Anderson highlighted his recently completed, 10-year survey of 54 different units for thermal-transient mechanisms and damage, centering on 31 key issues. His summary: “Attemperators cause the most problems, followed by drains.”

During a pressurized startup purge cycle, a large amount of condensate is produced. There is a need to quickly establish cooling-steam flow to SH and RH tubes, but only after the SH and RH are drained of condensate. Draining condensate as it forms during the purge speeds up the draining process. Because it’s important to drain condensate only, and not release an excessive amount of steam, there is a need to detect water versus steam. Thermocouples cannot make this determination prior to firing of the gas turbine.

The goal is to detect and remove condensate from superheaters and reheaters to prevent damage to coils and other equipment in the steam path. This reduces damage from thermal fatigue failures, stretching and bowing of tubes, and a host of related issues.

Once condensate is detected, drain piping and valves must be able to remove it while preventing release of live steam. This is a severe service system with large pressure drops and flashing liquid. One solution is a high-flow drain pot arrangement, but there is not sufficient area for this below many existing HRSGs.

Anderson described the FLEXIM high-temperature waveguide system (WaveInjector® and transducers) and its application on various pipe sizes, including thermally insulated installations. He also reviewed various drain-control valve types, listing the modulating control valve as preferred.

An initial permanent installation has four liquid detection systems (two on the HPSH, two on the RH) on each of four HRSGs. One HRSG has a modulating control valve with EPRI-developed control logic to prevent flashing. The other three have ball valves with simple logic. Cold start of the first has been successful, and hot-start testing will follow.

Systems are being installed on two new Nooter/Eriksen HRSGs and results will be discussed in detail at the next Forum.


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Synergy between fired boilers, HRSGs increases value proposition of AHUG, now ABHUG

The experiences shared at the Australasian HRSG Users Group (AHUG) annual meeting have been chronicled for the last decade by CCJ ONsite and in the print edition of the Combined Cycle Journal. Beginning here, and going forward, you’ll also benefit from the lessons learned/best practices of fired-boiler owner/operators facing technical and operational issues closely related to those in HRSGs.

The first annual meeting of the Australasian Boiler & HRSG Users Group (ABHUG), chaired by Barry Dooley of Structural Integrity Associates Inc, attracted 75 participants from Australia, Japan, New Zealand, Thailand, UK, and US to the Brisbane Convention & Exhibition Centre, Oct 30-Nov 1, 2019. About half of the participants were users. The agenda included 21 technical presentations and a welding workshop that brought together multiple experts to present on the latest standards, welding of service-exposed materials, ligament cracking in superheater headers, cold repair of Grade 91 material, etc. 

The steering committee voted to expand the attendee base because many of the failure/damage mechanisms occurring in HRSGs are similar to those found in conventional boilers, and that other equipment in combined-cycle plants have many of the same issues as those in fossil stations. Dooley told the editors that ABHUG will continue to concentrate on HRSG aspects but will add the technical areas common to fossil and HRSG plants—such as tube failures, steam turbines, high-energy piping, valves, etc.

The chairman characterized the inaugural ABHUG meeting as a highly interactive forum for the presentation of new information and technology related to HRSGs and boilers, case studies of plant issues and solutions, and open discussions among users, equipment suppliers, and industry consultants.

ABHUG is supported by the International Association for the Properties of Water and Steam together with the local national committees of IAPWS in Australia and New Zealand. It is held in association with the European HRSG Forum (EHF) and the US-based HRSG Forum with Bob Anderson. Two gold sponsors—Bang&Clean Technologies AG and HRL Technology Group—and seven exhibitors—ALS, Duff & Macintosh and Sentry, Flowtech Controls, Quest Integrity, Mettler Toledo, Optimum Control, and Swan Analytical—provided financial support (see end notes).


    • International updates on cycle chemistry, instrumentation, and flow-accelerated corrosion (FAC), plus a review of the recent IAPWS Technical Guidance Documents (TGD) in those areas—including the following:

        • Applications of Film-Forming Substances (TGD11-19).

        • Air In-leakage in Steam-Water Cycles (TGD9-18).

        • Chemistry Management in Generator Cooling Water during Operation and Shutdown (TGD10-19).

    • International updates on HRSG thermal transients associated with attemperators, condensate return and superheater/reheater drain management, and bypass operation. 

    • Two fossil-plant presentations on pitting were of practical value to operators of HRSGs. This mechanism is unique to reheaters and discussion focused on how it occurs when layup procedures are not in keeping with best industry practices. While the topic has been discussed at AHUG meetings over the years, these presentations illustrated how severe the damage can be.

Both presentations were followed by discussions on the use of dehumidified air (DHA) for reheaters and steam turbines. Typically, however, DHA capability is added after the damage has occurred, not as a proactive solution beforehand.

    • A practical presentation on hexavalent chromium contamination of high-chrome materials in gas turbines, HRSGs, steam turbines (casing bolts), and steam piping was made by David Addison of Thermal Chemistry Ltd. He covered how and where hex chrome forms, the health risks it poses, PPE requirements, best work practices, proper disposal, etc. An article based on Addison’s work will be published in the first quarter of 2020.

    • A new inspection tool on developing a digital twin of pressure vessels and other plant components using state-of-the-art imaging and image-capture technology was described. Chairman Dooley said an interesting application of the technology might be its use in the upper ducts of an air-cooled condenser (ACC) to view, without entry into the upper ducts (streets), the tube entries and any associated FAC. He should know: Dooley is a member of the ACC Users Group steering committee and respected for his knowledge of ACC damage mechanisms.

    • Operators representing four generating stations equipped with HRSGs shared their experiences in the form of “a year in the life” of their respective plants. This format was well-received by attendees.

    • The question/answer periods included impromptu discussion of the oxidation limits for steels used in superheaters and reheaters. Dooley announced that a new index on oxide growth and exfoliation (OGE) is in preparation. It will discuss the formation of steam-side oxide, how the characteristics of oxide exfoliation vary from one material to another, and the various types of damage caused by different exfoliated oxides. OGE piqued the interest of attendees at the 2019 meeting of the HRSG Forum with Bob Anderson as noted in the meeting report for that event.

    • Experiences with pressure-wave cleaning of fireside/gas-side surfaces in fossil boilers/HRSGs were shared at the same forum perhaps for the first time. Pressure-wave cleaning of HRSGs was a “hot” topic at the 2019 meeting of the HRSG Forum with Bob Anderson as mentioned in the meeting report for that event. 

End notes: Sponsor, exhibitor briefs

The sponsors and exhibitors active in ABHUG may be unfamiliar to readers in the Western Hemisphere. What follows are summaries of their activities:

ALS is one of Australia’s leading providers of asset reliability and integrity services geared to help power producers maximize production, extend asset life, and assure top operational performance.

Bang&Clean Technologies AG specializes in cleaning boilers and HRSGs by way of pressure waves created by closed and controlled gas explosions. The Swiss company’s patented system reportedly has been used in more than 20,000 cleanings since 2001.

Duff & Macintosh has specialized in the area of sample conditioning for the last 50 years. It is the exclusive agent in Australia Pacific for Sentry Equipment Corp.

Flotech Controls provides valve solutions, specializing in severe-service isolation and control applications.

HRL Technology Group focuses on laboratory testing, asset integrity, materials engineering, power and combustion performance engineering, and process and energy efficiency engineering.

Quest Integrity is active in the development and delivery of asset integrity and reliability management services.

Mettler Toledo Process Analytics specializes in inline analytical process solutions. Its Thornton unit provides state-of-the-art technology in conductivity, sodium, silica, chloride/sulfate, pH, ORP, ozone, dissolved oxygen, and TOC measurement.

Optimum Control Co represents a range of valve and actuator manufacturers and has a facility in Sydney to repair those components.

Swan Analytical Instruments offers a range of analyzers for pure, ultra-pure, and cooling-water applications—including pH, conductivity ORP, dissolved oxygen, silica, sodium, phosphate, chlorine, chlorine dioxide, bromine, iodine, ozone, and turbidity.

2020 meeting

ABHUG returns to the Brisbane Convention & Exhibition Center next year, in early December. Follow the organization’s website for announcements.

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Industry Notes: 2019 comes to an exciting close

NAES in the news

Orange Grove Energy earns VPP Star status

Over the last decade, CCJ’s best practices program has seen a dramatic uptick in entries pertaining to safety, a few for achieving VPP Star status. If you’re not familiar with the acronym VPP, Voluntary Protection Programs is an OSHA initiative that encourages private industry and federal agencies to prevent workplace injuries and illnesses through hazard prevention and control, worksite analysis, training, and cooperation between management and staff.

The certification process is arduous and can take a couple of years in some cases. Success depends to a great degree on the commitment of the personnel involved. It’s no mission for the faint of heart.

John Hutson, plant manager of Orange Grove Energy (OGE), a two-unit LM6000 peaking facility in Pala, Calif, shared some highlights of his plant’s journey to certification with the editors on a recent call. The flag-raising ceremony, well-attended by owner J-Power USA and operator NAES Corp executives (Fig 1) and plant personnel (Fig 2), took place a few weeks following the 2019 NAES Plant Managers Conference, September 17-19 (see following article).

Hutson recalled that he and Compliance Manager Ramiro Garcia attended a NAES Safe Conference in 2017 where CEO Bob Frishman asked all plants to consider pursuing VPP certification. It was clearly a benchmark for all NAES plants to strive toward in their safety culture. A few months later, J-Power USA CEO Mark Condon asked that all of his company’s plants be certified VPP Star.

Hutson and staff accepted the challenge with a desire to improve an already successful safety program while having OGE officially recognized as the elite organization all personnel believed it was.

Garcia served as the plant’s interface with Cal-OSHA, Palomar Energy (the VPP mentor facility), and the consultants engaged for the effort. Tony Moretto led his team of OMTs—including Al DeLuna, Erik Cherry, Gregg Stephens, and Paul Braemer—on making the O&M improvements that became evident as OGE worked through the process. Corporate support was provided by David Jackson, VP safety; Boggy Barnett, senior manager of safety; and Chris Trevino, project manager of safety.

OGE addressed and closed more than 300 safety issues and actions identified by plant staff, certified safety professionals, and Cal-OSHA inspectors—this at a plant with an enviable safety record in a company that promoted safety continually. The plant applied for Cal-OSHA VPP Star certification in August 2018; official certification came in August 2019.

Sixteen plants recognized for their best practices

One of the highlights of the mid-September NAES Plant Managers Conference, which focused on safety and operational excellence, was a session dedicated to best practices. Presentations were made by the plant managers from the four facilities earning Best of the Best recognition from CCJ: Dogwood Energy Facility, Edgewood Energy, Elwood Energy, and the Quail Run Energy Center. Another dozen generating plants powered by gas turbines received Best Practices Awards (Sidebar 1).

1. NAES plants recognized with 2019 Best Practices Awards

AMP Fremont Energy Center       Lawrence Generating Station
CCC Tuxpan II and V                  MEAG Wansley Unit 9
Channel Islands Power Cogen     Orange Grove Energy Center
Energia del Valle de Mexico I      Pinelawn Power LLC
Ferndale Generating Station       Shoreham Energy LLC
Green Country Energy               Worthington Generating Station

The NAES Plant Managers Conference is not your typical user meeting; it goes beyond technology into the staffing and training challenges facing plant managers, shares leadership and consensus-building know-how, and digs into HR and environmental initiatives that require a plant manager’s attention.

Technical presentations are of a more general nature than one typically finds at frame-specific user meetings. Titles of the vendor presentations in Sidebar 2 illustrate this point. Presentations by plant personnel are much the same, geared for an audience with diverse information needs. The presentations by plant managers in the best practices session, which showcased NAES’s experience with 7F, 501F, LM6000, and 7EA engines, offered ideas that could be adopted at most gas-turbine plants. Below are thumbnails of the Best of the Best Practices with accompanying links for greater detail.

Dogwood Energy Facility. To improve operational performance and enhance personnel safety, plant staff designed and implemented procedures and modifications to verify proper seating of gaskets for steam-drum doors and to eliminate the need for hot torqueing.

Edgewood Energy. Plant staff took an unconventional route to outage success by selecting multiple service providers to perform maintenance and field services which drastically reduced the cost of LM6000 repairs traditionally provided by one company.

Elwood Energy. Changes in the plant’s operating profile prompted management to develop and implement a comprehensive, long-term employee training and retention program to develop the next generation of multi-skill powerplant O&M technicians and supervisors.

Quail Run Energy Center. Excessive vibration in one of the site’s generator rotors caused by thermal sensitivity led plant staff and a vendor partner to conduct comprehensive inspection, testing, and repairs that resulted in a successful return to service within proper design parameters.

2. Exhibitor presenters and their topics

  • Bruel & Kjaer Vibro, Gas turbine balancing and vibration analysis.
  • S T Cotter Turbine Services Inc, The runway alternative for generator rotor removal.
  • The EI Group Inc, NFPA 70E electrical arc flash.
  • Emerson, New technologies for the global power industry.
  • Nalco Water, Minimizing iron transport.
  • Orr Protection Systems Inc, Improving the life safety of CO2 fire extinguishing systems.
  • Power Emissions Group, Catalyst 101.
  • Power Plant Services, PPS reverse engineering.
  • Power Substation Services, Hot oil reclamation on transformers.
  • SDMyers LLC, Best monitor or best fit? Selecting between single- and multiple-gas remote monitoring.
  • Sherwin Williams Co, Corrosion prevention.


As plants strive to reduce operating costs, respond to changing grid demands, and maximize revenue, digital upgrades from controls all the way to artificial intelligence will fuel their progress. Mitsubishi Hitachi Power Systems is responding to these challenges with its MHPS-TOMONI® plant solutions aimed at steadily progressing towards a smart powerplant capable of autonomous operation.

“Creating the Smart Power Plant of the Future” offers generation-asset owner/operators a roadmap to the digital future and a look at the digital solutions that will be implemented in what the company calls the “world’s first smart power plant” under construction at MHPS’ Takasago Machinery Works.

The smart powerplant is aware of neighboring plants, grid congestion, power markets, and weather forecasts and able to provide real-time insights and recommendations based on analytics to optimally support the grid and maximize revenue from energy and ancillary services markets.

J-series Americas recap. After installing the first J-series turbine in 2017, MHPS installed 11 more machines in 2018. Four 501JAC orders booked in 1Q/19 were split between Mexico and the US. In early July, J-Power USA ordered two 1 × 1 501JAC power trains for the nominal 1300-MW Jackson Generation Project in Elwood, Ill. A noteworthy feature of this plant will be its ability to operate at less than 25% of full load while remaining in emissions compliance. In October, Suncor Energy ordered two 501JAC engines and two HRSGs for a future cogeneration facility at the company’s Oil Sands Base Plant near Fort McMurray. Finally, PowerSouth ordered a 640-MW combined cycle, powered by a 501JAC engine, for its Lowman Energy Center in Leroy, Ala, to replace ageing coal-fired units.


Siemens delivered the world’s first HL-class gas turbine, its SGT6-9000HL, to Duke Energy’s Lincoln Combustion Turbine Station near Denver, NC. The 402-MW engine was lifted to its foundation in November 2019 and is scheduled to begin a four-year testing program early in 2020. It will operate in simple-cycle mode under real powerplant conditions. Efficiency is 43%, ramp rate 85 MW/min, inspection intervals are 33k equivalent base hours and 1250 equivalent starts.

Recent orders. RUE Vitebskenergo (Belarus) orders five SGT-800 gas turbine/generators and auxiliaries for the state-owned utility’s new 150-MW Lukomiskaya and 100-MW Novopolotskaya peaking plants.

    • Vietnam’s Hiep Phuoc Power Co will upgrade its Heip Phuoc steam plant in Ho Chi Minh City to combined cycle with the addition of three SGT5-4000F gas turbines and related equipment, increasing output by about 780 MW to 1200 MW.

    • South Korean IPP Yeoju Energy Services selects an HL-class 2 × 1 power island from Siemens to power its new 1004-MW plant in Gyeonggi Province, scheduled for commissioning in mid-2022. This is the OEM’s first HL-class plant for the Asian market.

    • Pakistan’s K-Electric orders a 900-MW combined cycle powered by two SGT5-4000F gas turbines for its Bin Qasim Power Complex in Karachi. Project completion is expected by early 2022.

    • PJSC Kazanorgsintez, one of Russia’s largest chemical companies orders a 250-MW 1 × 1 combined-cycle plant that will operate on a syngas byproduct of ethylene production. The SGT5-2000E-powered plant will be built in Tatarstan.

    • Specialty chemicals producer Evonik Industries orders a two-unit combined-cycle cogeneration plant for the Marl Chemical Park in North Rhine-Westphalia, Germany. The two 90-MW units will replace the last coal-fired units at the site.

    • Astoria Generating Co contracts for the turnkey construction of two nominal 300-MW SeaFloat power barges each equipped with eight SGT-A65 (Industrial Trent 60) gas turbines. They will replace four existing power barges located at Gowanas Generating Station, offshore Brooklyn, NY, commissioned nearly 50 years ago.

      Compagnie Electrique de Bretagne, an affiliate of Total SA, contracts for the turnkey construction of a 446-MW combined cycle powered by an SGT5-4000F gas turbine. Location: Landivisiau, France. COD is expected in the second half of 2021.

    • PowerSouth repowers the McWilliams powerplant in Covington County, Ala, with an SGT6-2000E gas turbine section replacing the existing V84.2. Results: Power increase from 102 to 114 MW, simple-cycle efficiency increase from 31% to 35%, emissions decrease from 13-16 ppm NOx to 10 ppm.


Generator Users Group, part of the PowerUsers family, elects Dave Fischli of Duke Energy chairman for 2020 and Jeff Phelps of Southern Company vice-chair.

Emerson completes the purchase of Intelligent Platforms from GE, enabling Emerson to expand its capabilities in machine control and discrete applications. IP’s portfolio of cloud-connected controllers and devices for smart plants will complement Emerson’s Plantweb™ digital ecosystem. 

In related news, the city of Fremont (Neb) Dept of Utilities selects Emerson to replace existing controls with automation technology designed for widely distributed assets—including power generation and delivery and water/wastewater collection, treatment, and distribution.

The company also selects Dragos Inc to collaborate on cybersecurity protection for the power and water industries.

Cassa Depositi e Prestiti (CDP) appoints Ing Giuseppe Marino CEO of Ansaldo Energia, a subsidiary company through CDP Equity. Marino was Hitachi Group’s COO.

Conval, a global leader in high-performance severe-service valves for HRSGs and other demanding applications, announced the following personnel changes over the last several weeks: Mike Hendrick, VP global marketing and sales, well respected by powerplant owners and operators, has retired. President Don Curtin has appointed Don Bowers Jr, who had been sales director since spring 2017, to replace Hedrick. Rod Alford is the company’s new Midwest regional manager.

Izzy Kerszenbaum and Geoff Klempner, known to generator owner/operators worldwide, announce their five-day technical training program, “Design, Operation, and Maintenance of Large Turbo-Generators.” Jan 13-17, 2020, in Irvine, Calif. Course is based on information from their textbook, “Handbook of Large Turbo-Generator Operation and Maintenance,” third edition.

Rodger Anderson, perhaps best known in the industry for his compressor-vane pinning repairs, has retired from DRS. Core Tech Turbine Services has been licensed to provide ongoing support for this product line, including new pinning projects. The company’s engineering manager, Joel Holt, a former 7F user, was involved in one of the first pinning projects in 2003.

Sal DellaVilla, CEO of Strategic Power Systems Inc, is appointed managing director of the Gas Turbine Association, effective Jan 1, 2020. He will replace William H Day, who served in that position since the group’s inception in 1995. Day will continue to serve as a strategic consultant for the GTA going forward. For more insight, please read the commentary on p 3.

Paul Tucker, president of Houston-based TBS Manufacturing/FIRST Consulting & Inspection Services, called to say his company now manufactures accessory couplings for GE Frame 3, 5, 6, and 7 engines, as well as for some Westinghouse and Siemens gas turbines. Product includes the shaft as well as the external shaft hub with an external spline as well as the coupling hub itself, which has an internal spline. Companion service offering includes repairs to shafts/couplings fit for further use.

Tucker, one of the industry’s pre-eminent turbine mechanics, also spoke to the availability of custom 7F and 7EA inner and outer crossfire tubes using a new manufacturing process that is said to offer longer life than the traditional rolled-plate/seam-welded design. TBS’s crossfire tubes are made from solid bar stock (L-605) to avoid the typical out-of-round condition near the end of life.

Jeff Bause, a familiar face and frequent participant/presenter on HRSG cleaning at gas-turbine user group conferences, is appointed COO of Groome Industrial Service Group

MTU Aero Engines celebrates 50 years of service to the industry. Engineers from Daimler-Benz and MAN Turbomotoren GmbH joined forces in 1969 to collaborate on engine technology. The company’s journey through a half century of innovation, and a look at the propulsion technologies of tomorrow, are chronicled in articles, videos, photo galleries, and interactive specials at

Hytorc’s Lithium Series II electric torque tool, said to be the next revolution in bolting technology, features a lightweight 36-V battery with built in TorcSense™ technology driven by an all-new brushless motor. Tool is compatible with conventional sockets and the company’s washers and nuts. Models go to 5000 ft-lb.

Liburdi’s advanced repairs for critical turbine components—including buckets, nozzles shroud blocks, combustion liners, transition pieces, and fuel nozzles—extend the lifetimes of these parts, thereby reducing O&M costs and deferring—possibly avoiding—the purchase of new components.

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HRSG Forum expands to include daylong water workshop

The HRSG Forum with Bob Anderson contributes significantly to industry knowledge on the design, operation, and maintenance of heat-recovery steam generators with its lineup of technical presentations by subject matter experts, plus hands-on discussions among owner/operators, component and service providers, and concerned OEMs. In sum, this premier event encourages the exchange of experience and specifics that keep the industry as dynamic as its markets.

For the 2019 conference and exhibition, held in Orlando last July, Chairman Anderson expanded the meeting’s traditional content and technical depth by adding to the program a one-day water workshop and another daylong session in cooperation with the Electric Power Research Institute (EPRI) on HRSG and balance-of-plant technology—the fourth annual event becoming HRSG Week, arranged as follows:

Monday, July 22




The Makeup Water Workshop featured discussions on advancements in the treatment of makeup water, the impact of changing raw-water sources, treatment system operation, equipment troubleshooting and layup, and much more.

The agenda included the following presentation/discussion topics, among others:

    • Design of water-treatment systems for combined-cycle plants.

    • Best practices on makeup water and pretreatment monitoring.

    • Dealing with complex makeup water challenges.

    • Optimizing water use at a combined-cycle plant operating on reclaimed water.

    • Best practices for reverse-osmosis systems.

    • Using digital tools to optimize the operation of integrated mobile water systems.

    • Layup practices for makeup treatment equipment.

    • Challenges in makeup water production faced by owner/operators.

    • Considerations in the treatment of municipal wastewater for powerplant use.

Tuesday/Wednesday, July 23-24




Thursday, July 25




All delegates to the HRSG Forum were invited to participate in EPRI’s HRSG and BOP Technology Transfer Day, led by experts from EPRI Program 88, Combined Cycle HRSG and Balance of Plant. Cross-reference discussions were conducted with EPRI professional from the following related areas:

Program 64, Boiler and Turbine Steam and Cycle Chemistry.

Program 65, Steam Turbine-Generators and Auxiliary Systems.

Program 79, Combined Cycle Turbomachinery.

Program 87, Materials and Repair.

HRSG Week 2020

The new meeting format, given high marks by attendees, will be followed again in 2020 when HRSG Week is at the Rosen Shingle Creek in Orlando, Fla, July 20-23. The Water Workshop on July 20 will focus on film-forming substances, a topic of major interest to owner/operators not running their plants baseload.

The HRSG Forum with Bob Anderson will be conducted July 21 and 22, with Thursday the 23rd reserved for EPRI’s HRSG and BOP Technology Transfer Day.

Agendas for all three program elements—Water Workshop, HRSG Forum, and EPRI Day—are in development. Details will be announced on the HRSG Forum’s website when they become available during the spring.

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Adapt advanced process control for tighter regulation of SH, RH temperatures

Many combined-cycle units originally designed for baseload operation are now required to cycle frequently, with still more starts and more rapid ramping over a wider range when in automatic generation control (AGC) mode. As a result, a significant number of heat recovery steam generator (HRSG) failures experienced worldwide have been at least partly attributed to inadequate steam attemperator control.

To avoid HRSG damage caused by poor control of steam temperature, some combined cycles operate at reduced steam temperatures and pay a penalty in reduced thermal performance. Inadequate temperature control also can result in excessive spray flow reactions, risking damage from saturated steam and large variations in steam temperature at the attemperator outlet.

The two major objectives in the control of steam temperature are minimizing both the extent and periods of high temperature, and avoiding spraying to saturation temperature. The former reduces component life because of thermal creep; the latter often is associated with cracking in downstream piping and in uneven tube heating and cracking.

To improve thermal performance and reduce damage industrywide, a need exists to demonstrate better process control of combined-cycle attemperation, says Steve Seachman, principal technical leader in the Instrumentation, Controls, and Automation Program for the Generation Sector at the Electric Power Research Institute (EPRI).

The temperature control design typically installed in HRSG systems is very similar to that used in baseload drum boilers, and it has been the standard control structure for several decades. Improvements to distributed control system (DCS) technology have allowed enhancements—such as the calculation of steam properties, inclusion of nonlinear parameter adaption, and improved filtering and dynamic feedforwards.

Nonetheless, the operating strategies demanded of many combined-cycle units—including very fast startups and V-style load ramp profiles—have brought steam temperature control to the fore as an operational limiting factor.

By introducing an advanced steam temperature control strategy, HRSG operators might avoid periods of high temperature through the anticipatory action of sprays that can operate over a smaller flow range and have complementary influences to the main-steam temperature and pressure setpoints to reduce heat uptake disturbances. Benefits might include reduced temperature deviations, improved stability, and reduced actuator activity—all of which provide support for more flexible operation.

Testing of advanced strategies for steam temperature control. A study by EPRI surveyed advanced control system strategies for combined-cycle units. The project then selected two approaches for testing through simulation, subsequently testing one on a 2 × 1 combined cycle. The study and its findings are described in the EPRI report “Steam Temperature Control for Combined-Cycle Units: Survey and Testing of Advanced Strategies (3002106316).”

The following five performance criteria were considered:

    • Temperature deviations during ramps and disturbances—measured as peak deviation from setpoint. This is an indication of creep-life cost and the ability of the control to respond quickly to large disturbances—such as fast start, load ramping, frequency response, and duct-burner operation.

    • Time in temperature ranges above and below design. Temperatures above design produce a creep-life cost; temperatures below design produce a thermal-efficiency cost.

    • Stability is determined as time to settle following a load ramp or setpoint change. Settling time is commonly defined as the time to fall and stay within defined steady-state deviation limits.

    • Operation at or near saturation. The controls should successfully steer the attemperator outlet temperature away from saturation by holding to a set margin above saturation, without causing instability or large excursions.

    • Actuator activity. Excessive activity of motorized actuators can cause overheating and early wearing of bearings and gearboxes. Pneumatic actuators can also suffer premature wear and loss of accuracy with high levels of activity. In both cases, valve glands can wear and leak if operated more than the design duty.

The typical design of steam temperature control on HRSGs is a cascade configuration, whereby a primary (outer loop) PID (proportional, integral, derivative) controller regulates the superheater (SH) outlet temperature by generating a setpoint for the attemperator outlet temperature. The attemperator outlet temperature then is controlled by a fast secondary (inner loop) PI (proportional plus integral) controller that modulates the spray-water valve opening to attenuate any upstream disturbances (such as duct-burner operation) and to track the setpoint generated by the primary controller.

The computational capability of modern DCS processors has enabled the introduction of advanced algorithms to improve the control of complex, high-order, and interactive processes. A feature of all these algorithms is a model of the process and associated influences (either implicit, as an approximate inversion, or explicit) that direct the controller’s corrective actions with greater accuracy than a conventional PID controller, provided an appropriate set of process and influencing models has been determined.

The potential advantages of advanced HRSG steam-temperature control lie with the ability to reduce temperature deviations during startups and load ramping and other disturbances and to reduce overspray events by beginning to act earlier.

These four controller options were considered for the study:

    • Smith Predictor. A well-proven, dead-time compensation design that would use a standard block in the DCS to augment the PID controller.

    • Modified Smith Predictor a/k/a Advanced PID (A-PID). Similar in design to the Smith Predictor but with a plant model that also reduces the time of the response presented to the PID controller. The model compensation block is built up from existing DCS blocks. It has been applied successfully on several coal-fired plants.

    • Model Predictive Control (MPC) is well-proven in process-industry applications and already applied on some thermal plants. The controller has a concise response-model definition capable of capturing high-order response dynamics, with inherent capabilities to include limits and cost metrics in the control design. MPC control of combined-cycle plants and HRSGs has been the subject of modeling and research, but little exists in the way of published test methods and results from practical plant applications.

    • State Feedback with Disturbance Observer, which is offered as a module by some DCS vendors. It has been demonstrated on SH temperature controls for drum and supercritical units. It could be built up from standard DCS blocks, but no published procedures exist for setup and tuning.

A-PID, MPC. The project team selected two controller designs for the study: A-PID and MPC.

The former was chosen because of its successful application on coal-fired boilers and because it required no advanced control modules (provided the DCS has a delay function block). A-PID is an extension of the well-known Smith Predictor, a model-based controller that effectively eliminates process response dead time, enabling controllers to be tuned with higher gain.

This is achieved by estimating the expected response to a controller output change, but with the dead time removed. The resulting signal is added to the process feedback so the controller “sees” a response to its output actions very quickly and responds appropriately. Then, after the dead time has elapsed, and the actual process begins to respond, the Smith model’s output is progressively removed with the same time constant as the process. This mechanism gives a smooth crossover from model to actual process input.

The MPC was selected for its potential to model and reject two independent disturbances, because it is capable of modeling “inverse” SH outlet temperature dynamics seen during load ramps. Plus, MPC modules were available for testing at the host site’s DCS, provided as part of an advanced control suite.

MPC has been growing as a powerful control concept, with many applications over the last three decades. The most prevalent application has been in chemical, refinery, and other process industries, but its capability to deal with interactive processes and its inherent ability to compensate for dead time and high-order processes lead naturally to powerplant control applications—such as steam temperature, sream pressure, and drum level control.

Simulation tests. Both the A-PID and MPC designs initially were tested with a PC-based plant/controller simulation (with Simulink™ modeling environment) to ensure the control structures functioned as expected and potential implementation issues were identified. The advantage of PC-based simulations is having unrestricted access to the models and enabling scenario testing faster than in real time. Success of this phase to test the controllers depends on the level of process model static and dynamic accuracy and controller emulation fidelity.

Subsequently, the two designs were configured on virtual DCS controllers and tested at the host site’s replica operator training simulator. Goals of the onsite simulator tests were the following:

    • Compare the control performance of the options.

    • Check practical aspects of the implementation (signal tracking, override functions, bumpless controller switching, etc).

    • Establish procedures and methods for process model identification and controller tuning.

Following extensive testing, the MPC design was selected for deployment at the plant. The design was installed and commissioned on one HRSG reheater temperature control loop. This arrangement enabled a comparison between the performance of the MPC (A-HRSG controls) and the original PID (B-HRSG controls).

A control switching facility also enabled a comparison to be made between a retuned PID control and the new MPC design on the same HRSG. Wide-range load-ramp tuning and benchmark tests were performed, providing data for a quantitative performance comparison.


Following MPC tuning, A-HRSG reheater MPC performance was demonstrated as significantly superior to the existing PID control still operating on the B-HRSG. It was also shown to be more stable and faster responding than the retuned and optimized PID control of the A-HRSG.

    • The A-PID controller was relatively easy to tune with the system identification tuning calculation tools. The design gave a fast, stable control capability. Some tracking issues related to cascade control windup and resetting contributed to the inclusion of a saturation protection limiter were particular to the DCS and not necessarily an impairment to the design concept.

The A-PID design, based on a modified Smith Predictor, is best suited in applications with large dead time and high-order process responses, as noted earlier—such as those found on large drum boilers with a single-stage desuperheater. Investigators found that the final stages of the HRSG superheater and reheater have lower-order responses; however, they are more prone to disturbances because of their relatively lightweight tubing and rapid variations in gas temperatures during startups and load ramps.

For the SH controls, the split-range valve design performed well, but in its present form, the A-PID did not achieve significantly improved disturbance rejection on the simulator. The reheater (RH) temperature control with the A-PID was superior to the standard PID for both stability and disturbance rejection. This is because the response model of the RH was of higher order, and so some of the features of the delay and order-reduction functions came into play.

    • The MPC facility’s capability to input two independent disturbance variables inputs was used to advantage on the reheater to reject the disturbance caused by load changes on both the A and B gas turbines (GTs). The SH outlet and disturbance response models vary significantly over the GT load range. Because the MPC is not adaptive, two MPCs were used with a fuzzy blending (weighted average) function to slide between controllers, which were sufficient to cover the entire load range.

For the MPC design to provide significantly superior performance during load ramps, the structure must include an output feedforward signal predicting the expected attemperator outlet temperature. The MPC design, as implemented for the tests, provided significant improvement to temperature disturbance deviations, time to settle, periods away from setpoint, and overall stability. The final design for the reheater MPC functional outline is shown in the figure.


    • Improved temperature control. When the MPC controller is applied in a regulator configuration with attemperator outlet setpoint feedforward, and full use is made of the disturbance inputs, the MPC provides a stable and very responsive control design.

    • Opportunity to improve steam-cycle efficiency. The MPC provides a significantly narrower band of temperature deviations over time. Such an outcome allows operators to raise steam temperature setpoints without decreasing creep life, thereby reducing unit heat rate and fuel consumption.

    • Reduced actuator activity. The MPC can be adjusted to reduce reversals in the attemperator outlet temperature direction without compromising temperature control performance. Thus, actuator activity can be reduced, together with valve and actuator wear. For motorized modulating actuators, this capability would reduce bearing and gearbox wear as well as the risk of motor overheating.

    • Supporting unit flexibility. Implementing MPC may provide an effective strategy against damage risk to both high-temperature HRSG components and field actuators. Therefore, it could play a significant role in supporting flexible operations, particularly if the need for more frequent ramping and startups increases as more unregulated generation enters the energy mix.

    • Reduced saturation events. MPC provides the opportunity to increase temperature setpoints, thereby reducing the number of saturation events in steam piping and tubing and prolonging the service lives of these components.

In sum, the study demonstrated the application of advanced steam-temperature control strategies on a combined-cycle plant, and provided quantitative assessments by benchmarking performance against the classical cascade control structure previously applied at the host site.


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