The upcoming HRSG Forum 2024 features four days of advanced technical content and a unique balance of presentations, pinpoint education, focused discussions, and active sharing of solutions and new ideas of considerable value to owner/operators.

Each element of this important conference and exhibition is open to all attendees—including users, service and equipment providers, OEMs, and global consultants. Discussions and the robust sharing of ideas are moderated by Bob Anderson, Competitive Power Resources, and Barry Dooley, Structural Integrity Associates (UK). They are guided by a steering committee of industry veterans: Eugene Eagle, Duke Energy; Albert Olszewski, Constellation Energy; Yogesh Patel, TECO Energy; and Scott Wambeke, Xcel Energy.

Sponsors of the 2024 Forum

Diamond. Precision Iceblast Corp.

Platinum Plus. EPRI.

Platinum. Viking Vessel Services/Tuff Tube Transition, Zepco.

Gold. Arnold Group, Dekomte Expansion Joint Technology, GE Vernova, ValvTechnologies.

Silver. SVI Bremco, Questtec Solutions, Thompson Industrial Services, Cust-O-Fab, GasPath Solutions, Vector Systems Inc.

Bronze. Power & Industrial Services Corp, Nooter Eriksen, Groome Industrial Service Group, Millennium Power Services, Environmental Alternatives Inc, Badger Expansion Joints, Mistras, IAFD, Environex Inc.

Register today for the only Power Users conference focused on heat-recovery steam generators, high-energy piping, and cycle chemistry. Visit www.powerusers.org for full details and registration information.

HRSG Forum requires no membership or credentials other than an interest in learning more about HRSGs, maintaining and operating them better, improving their design and performance, and sharing your own expertise and experiences with others.

What you’ll learn in St. Louis

This year’s event in St. Louis begins on June 10 with an SCR/CO emissions control workshop focusing on system design, chemistry, operation and maintenance, and distinctions between catalyst and non-catalyst factors that impact performance.

That afternoon, participants reconvene for a deep-dive workshop on boiler-feed-pump fundamentals, installations, O&M, performance issues, and troubleshooting.

June 11 and 12 are the general sessions packed with presentations by users, service providers and consultants, highlighting specific operating experiences and case histories.

Then on Thursday, the Electric Power Research Institute (EPRI) will lead attendees through the latest research designed to improve combined-cycle operations, focusing on high-temperature components, high-energy piping, plus low-temperature components (a topic raised at last year’s meeting). A key takeaway will be EPRI’s respected and authoritative state-of-the-industry review and close look at today’s ever-changing challenges.

Last year’s highlights

The 2023 event in Atlanta, the organization’s first physical meeting since the Covid interruption, established the current four-day in-person format, encouraging all attendees to participate in the following:

• Cycle Chemistry Workshop—Film-forming substances
• Materials Workshop—Welding and metallurgy
• General Session presentations by Users
• General Session presentations by service providers
• EPRI Technology Transfer Workshop

As stated last year by Bob Anderson, HRSG Forum chairman, “What makes the HRSG Forum format work is the active participation of attendees—users, manufacturers, service providers, and consultants. This arrangement is important to provide timely and accurate answers to questions, and to hear what users have to say about their needs. Exhibitors (47 in 2023) are encouraged to attend the technical sessions.”

Sponsors in 2023 were Viking Vessel Services, Tuff Tube Transition, EPRI, ZEPCO, Arnold Group, Dekomte, GE, Nooter/Eriksen, Precision Iceblast, Questtec Solutions, SVI/Bremco, Thompson Industrial Services, Accurity Industrial Contractors, Advanced Valve Solutions, Badger, Cust-o-Fab, Eagle Burgmann, Groome Industrial, Degauss, Millennium Power Services, Power & Industrial Services, Structural Integrity, TEAM Valve Solutions, and Vogt Power International.

HRSG Forum is associated with the European HRSG Forum and the Australasian Boiler and HRSG Forum, enhancing its international content and relevance.

With the 2024 HRSG Forum fast approaching in June, have a look at the breadth of topics and discussion points covered at last year’s event during the end user presentations, featured here, and all the other components of the conference. The 2023 HRSG Forum event in Atlanta, the organization’s first physical meeting since the Covid interruption, established the current four-day in-person format, encouraging all attendees to participate in the following:

• Cycle Chemistry Workshop—Film-forming substances
• Materials Workshop—Welding and metallurgy
• General Session presentations by Users
• General Session presentations by service providers
• EPRI Technology Transfer Workshop

HP evaporator replacement

Yogesh Patel, Tampa Electric/TECO, and Vignesh Bala, Vogt Power, gave a detailed, experience-based presentation on the replacement of HP evaporators for the two combined cycles at the 1800-MW Bayside Power Station, Unit 1 (3 × 1) and Unit 2 (4 × 1), commercial since 2003 and 2004, respectfully. The units are equipped with GE 7FA gas turbines and Alstom HRSGs.

In December 2016, the station incurred several HP-evaporator tube failures in two of its seven HRSGs. All experienced under-deposit corrosion. Failure analysis indicated significant amounts of deposit weight density (DWD) within the tubes. The first sample showed the loading at 154 g/ft².

In 2018, borescope inspections at Unit 2 showed a concentration of debris within the front headers and within the tube bundles approximately 18 to 20 in. above the bottom header. Tube leak-location experience was then analyzed. Tubes were removed (Fig 1) showing heavy deposit loading and wall-thickness issues.

Replacement decisions were made. Bala discussed planning, detailed design, fabrication, delivery, and construction. TECO selected Grade T11 tubes with carbon-steel fins and elected to fabricate in the US (Boiler Tube Company of America/BTA) for schedule and ease of inspections.

Preliminary construction planning considered both side and top access. Top entry was not effective because of the drums, so TECO selected the individual-lift side-entry option. The power producer also selected in-shop hydro with authorized inspection to ensure the integrity of welds and conduct any repairs before delivery.

“Demolition was one of the most challenging parts of the construction phase,” explained Bala. Harps were severed and removed.

“Coordination within the last 100 ft is critical; new harps must be delivered in the proper sequence!”

Installation included 48 individual harp lifts using one handling frame and one up-righting frame. A monorail system was used to slide the harps into the HRSG (Fig 2).  Welding and NDE followed.

Post-presentation questions and discussions focused on the benefits of removing HP evaporator tube samples and having them analyzed for internal deposit loading, the impacts of poor long-term water chemistry, and the need to monitor for total iron.

HRSG damage monitoring

Duke Energy and Structural Integrity Associates (SI) jointly discussed online monitoring—more specifically a unique HRSG damage monitoring system. Presenters Eugene Eagle (Duke) and Kane Riggenbach (SI) looked at real-time assessment of system performance and component integrity for both HRSGs and high-energy piping.

Their example: Duke’s 920-MW H F Lee Energy Complex, a 3 × 1 combined cycle  (commercial 2012) anticipating future cycling requirements (Fig 3).

The Siemens F-class gas turbine/Vogt triple-pressure HRSG units at Lee have accumulated nearly 70,000 hours and have had damage issues related to RH and HP attemperation. “Many SH/RH drain, operational, CT exhaust, and attemperator control logic changes have been implemented,” explained Eagle. Current operation is baseload, with low-load turndown to 40 MW per gas turbine.

They began with an interesting HRSG overview, adding that each unit has surface-mounted, thermocouples of an advanced design that were installed at commissioning. It showed components typically susceptible to creep, fatigue, creep-fatigue interaction, corrosion fatigue, oxidation, and exfoliation. The focus (16 areas per unit) includes interstage and bypass attemperators, intermediate headers and tubing downstream of attemperators, branch connections, final-stage outlet headers, and drums.

Structural Integrity provided and monitors the PlantTrack™ system installed after 70,000 service hours.

Program goals are early detection when rate of damage is rising, and prioritizing locations and systems with a long-term goal of extending inspection intervals. Data can also be used to assess accuracy of fitness-for-service assumptions and adjust recommendations.

Specific life-management benefits include detection of operational or process changes (failed nozzles, leaking valves, etc) and evaluations of control logic changes (valve opening, spray amounts, etc). Comparison of operating modes (and impacts on component life) are made between units and plants, for low-load operations, operating with and without steam sparging, and for changes in startup times.

Riggenbach explained damage trending saying that “when monitoring, a time series of damage will be created,” then adding that “a historical rate of damage consumption can be extrapolated.” Previous inspections can be used as benchmarks. With this, future projections of damage consumption can be made (Fig 4).

Various examples of data presented on the PlantTrack Dashboard also were provided.

Duke’s plan is to develop trends and translate the data for sister units.

The presentation generated many questions, comments and discussions. Placement of thermocouples (total of 128) was further explained. Other comments focused on thermocouple attachment (EPRI method used), the security hurdles of sending live data away from the site, the possibility of using the data for faster startups, and using the data to estimate remaining life of piping.

Attemperator repairs

Al Olszewski, Constellation Energy, reviewed fleet-wide Attemperator inspections and repairs. This non-plant-specific presentation covered selected issues with various attemperators, including:

•  High-pressure (HP) to cold-reheat bypass. Fig 5 shows internal indications at downstream girth-weld (P91 material). Girth weld was machined out and repaired with spool piece.
•  Intermediate pressure interstage (vertical). Significant quench-cracking of liner was revealed. Inspection is ongoing; a spare now is available onsite.
•  Hot reheat interstage (vertical). The liner liberated after 68k hours and was repaired with liner pins.
•  HP interstage. A P91 nozzle liberated at weld after 35k hours. Thermal-mechanical fatigue was cited as the cause. Opening was rounded to reduce stress.
•  Hot-reheat bypass to condenser. Repeat cracking of upstream and downstream girth welds after 45k hours. Now monitoring for thermal fatigue.

Many similar case histories and repair solutions were discussed after the presentation, stressing the need for frequent and complete testing (including addition of thermocouples). The benefits of proper clearances and use of OEM parts in critical applications also were mentioned.

HRSG tube failures

The Qurayyah Combined Cycle Power Plant in Saudi Arabia comprises multiple blocks, each 3 × 1 with GE 7FA.04 gas turbines and GE D11 steam turbines. The unfired triple-pressure HRSGs are Doosan and CMI vertical-gas-path units.

Ghazi Al-Shammari discussed HRSG tube failures and consequences. He walked through the plant’s background, then focused on the tube failures in one unit that became apparent in 2016 (high water consumption, noise, and steam emitted from the main stack).

All tubes and headers were visually inspected. Tube defects were found at 19 locations near the hot-reheat header. Thermal-fatigue cracking also was apparent close to the tube-to-header welds (Fig 6).

The speaker walked through the various damage mechanisms found and then the root-cause graphic depiction of thermal stresses.

Recommendations made based on plant experience were these:

•  After each HRSG shutdown, ensure all TCVs/bypass MOVs and inlet isolation MOVs are closed.
•  Follow normal startup procedures and physically verify all valve positions, both open and closed.
•  Watch for any abnormal valve behavior—including noise, vibration, or temperature change.
•  All manual drain isolation valves should be open at all times.
•  All drain MOVs should be on auto at all times.
•  Operators should physically monitor drain-valve levels and differential temperatures at all times.

Qurayyah has reduced (1) annual forced outages attributed to tube leaks from five to one, (2) water consumption, and (3) tube metal temperatures.

Discussions and suggestions followed on numerous issues—including the following:

•  Manual bypass around the attemperator block and control valve (should be removed).
•  Spray-valve operation and maintenance.
•  Inability to drain RH and SH tubes (in this design).
•  Proper and improper use of dampers.
•  Tube failure-analysis options—including removal, accuracy of data programs, and root- cause/damage mechanism distinctions.

Valve maintenance program

Bernard Frezza, Athens Generating, operated by NAES, discussed the Valve maintenance program at the 1080-MW plant with three 1 × 1 combined cycles equipped with Siemens 501G gas turbines, Nooter/Eriksen HRSGs, and Siemens HE steam turbines.

Athens did not have a valve monitoring program when commissioned in 2004. Work orders were put in by staff if a valve had visible failure, noise, or leaks. The plant learned over time that this reactive approach led to unplanned maintenance, costly repairs, and outages.

Athens has been working with Millennium Power Services since 2017 to track and prioritize valve maintenance, and bring their program up to industry standards through a proactive approach. One benefit is “improved heat rate through reductions in water and steam losses,” said Frezza.

Millenium keeps records and maintenance interval data, and plans for future inspections based on plant budget and needs. Each valve has an associated report.

Athens uses Millenium’s TrimKit™ program to reduce costs and labor, and to provide all new parts for specific valves. Refurbished parts can be returned to the kits (Fig 7).

Millennium now offers Athens a 10-yr plan, revised as necessary.

Wireless HEP program

CPV’s St. Charles Energy Center in Maryland (Fig 8) has implemented a wireless high-energy-piping (HEP) program, which was described by Jacob Boyd. Background: The 745-MW plant, commissioned seven years ago with two GE Fast-Start 7FA.05 gas turbines, one GE D-11A steam turbine, and two CMI HRSGs, typically cycles from 140 to 170 times annually.

Near the end of 2019, one HRSG suffered a through-wall leak at a girth weld on a hot reheat (HRH) steam-to-condenser bypass line. The failed weld was removed and sent to Structural Integrity (SI), finding that thermal fatigue was the most likely cause.

“Plant personnel worked with SI to install thermocouples around the area to assess the magnitude of thermal transients during load changes and normal operations,” explained Boyd. Significant temperature variations around the pipe circumference (up to 700 deg F) were noted during load-change events. SI data were sent to the OEM who redesigned the HRH bypass attemperator spray-nozzle assembly. Plant staff modified the attemperator logic.

The plant had only been operational for two years, and “plant staff was concerned there may be other unknown high-energy piping issues that could fail prior to regularly scheduled inspection,” said Boyd. “Working with Structural Integrity, a solution was proposed to install a wireless sensor network and thermocouples to remotely read data in near real-time and incorporate the readings into St. Charles’ PlantTrack online database.”

SI performed a risk-ranking prioritization known as Vindex™ (Vulnerability Index) that considers factors such as creep life, Grade 91 risk factors, consequence of failures, etc, and assesses each weld or location of interest according to damage potential. The plant then installed thermocouples at 10 different locations throughout the HEP system, plus nine online pipe-hanger monitors.

Data were used for the spring 2023 outage. Online monitoring of the HRH bypass had shown five high events and 155 medium events. Field results in 2023 then identified multiple ID and OD indications. A spool piece was needed and installed.

Said Boyd, “the system is a highly valuable tool to target inspections and plan outage scopes. We now have improved plant safety and reliability, while reducing O&M costs and the potential for lost generation.”

Chemistry and corrosion, user survey results

Barry Dooley, Structural Integrity (UK), presented the latest international statistics on cycle chemistry and FAC, summarizing results from 270 combined-cycle and fossil plants. He began with the following observation: “It looks like hydrogen damage/under-deposit corrosion is increasing around the world. This is a big issue!” He would soon return to this topic, discussing repeat cycle-chemistry situations (RCCS).

Dooley first reviewed chemistry-influenced tube failure damage and failure mechanisms, corrosion-product transport attributed to inadequate feedwater low-pressure circuit chemistries, and steam turbine deposits/damage/failures.

For the latter, leading current steam-turbine damage mechanisms are:

•  Corrosion fatigue of blades and discs in the phase transition zone (PTZ) of the LP turbine.
•  Stress corrosion cracking of discs in the PTZ.
•  Pitting (initiator of damage).
•  Liquid droplet erosion.
•  Flow-accelerated corrosion.
•  Deposition.

He reviewed the repeat cycle-chemistry situations found in the assessments, then focused on hydrogen damage and internal HP evaporator deposits as an example.

Dooley noted that the International Association for the Properties of Water and Steam (IAPWS) would soon publish a procedure to quantify corrosion-product transport during startup. He called this an “exciting development” and summarized the procedure:

•  Flush feedwater sample point as soon as pressure is available.
•  Measure and register oxide levels in feedwater by proxy methods during startup.
•  Take samples for filtered iron intermittently to establish a correlation to proxy results.
•  Note times for milestones: first fire, bypass, turbine rollup, synchronization, etc.
•  Plot iron levels versus time after first fire and mark milestones.
•  Integrate (iron level, feedwater flow) from first fire to steady state level; iron transported to boiler during startup.

He then turned to both single- and two-phase FAC, which he said are “still occurring worldwide and not being identified properly” as they do not share the same mechanisms.

Looking for single-phase FAC evidence in HRSGs he offered a few interesting notes, including “things to look for”:

•  Level of oxygen at condensate-pump discharge and boiler feed pump.
•  Color of LP and IP drums for “ruggedness of redness.” Red appearance will be “patchy” with grey magnetite showing through when oxidizing power is “low.”
•  Levels of iron (“Rule of 2 and 5”): Less than 2 ppm total iron in condensate/feedwater, less than 5 ppm in evaporators/drums.

His concluding reminder: resources for all areas of water and steam are freely available for review and download at www.iapws.org.

Open discussion

A sampling of questions and discussion topics submitted to the HRSG Forum as part of the registration process included these:

•  What are the best practices for welding carbon-steel tubes to headers (including inspections)?
•  Poll: How many users are taking HP evaporator deposit-density tube samples?
•  Tube sample methods and locations were discussed, initiating discussions on chemical cleaning and under-deposit corrosion.
•  HRSG tube-plugging impact on hydraulic flow characteristics led to discussions on (1) tube temperature changes, and restorability of abandoned tubes, (2) inventory of spare tubes retained onsite, including filler metals; and (3) experiences with tube repair versus plugging. Interesting comment from Bob Anderson during this exchange: If you plug, you don’t know the failure mechanism and root cause to reduce chance of repeat failures.
•  Best practices for boiler feedwater pumps and control valves for controlling HP-drum levels led to discussions on attemperators and valves.
•  Drum-level trips related to instrumentation and controls.
•  Repair experience with attemperator nozzle bore hole cracking.
•  Duct-burner replacement: Determining the need, timing, and material options.

With the 2024 HRSG Forum fast approaching in June, have a look at the breadth of topics and discussion points covered at last year’s event during the solutions provider presentations, featured here, and all the other components of the conference. The 2023 HRSG Forum event in Atlanta, the organization’s first physical meeting since the Covid interruption, established the current four-day in-person format, encouraging all attendees to participate in the following:

• Cycle Chemistry Workshop—Film-forming substances
• Materials Workshop—Welding and metallurgy
• General Session presentations by Users
• General Session presentations by service providers
• EPRI Technology Transfer Workshop

Vent silencer design, inspection

Samir Baydoun and Tucker York, SVI Bremco, presented HRSG vent-silencer safety inspections and design, focusing on the safe and quiet discharge of high-pressure steam. Most silencers are installed at high elevations downstream of steam-drum relief valves, HP/RH safety valves, and startup ventilation. They can also be installed on blowdown tanks and deaerators. Their primary purpose is to meet site-permitted noise limits.

Main vent-silencer components are: diffuser assembly with inlet pipe, silencer shell with or without liner, and silencer inserts (Fig 9).

Presenters covered common failure and safety concerns, usually caused by deterioration of the silencer perforated liner or diffuser basket and loss of acoustical insulation (Fig 10). The result is loss of aerodynamics and acoustical performance, but a major safety issue occurs when parts of the liner separate and eject out of the silencer.

Visual inspection methods are presented in an eight-point summary covering corrosion, missing bolts, cracking, weld damage, and improper draining. Go-Pro cameras can be used to check baffle sheets, frames, and supports. Cameras can also check various welds and diffuser-cap conditions.

Root causes of damage could be inherent in design or in selection of materials, welding processes, corrosion, and water collected at the bottom of the silencer (clogged drains). Thermal fatigue can also occur because of temperature, number of cycles, and other operating conditions—including backpressure. Thus, routine inspection is critical.

Details of an SVI Dynamics vent silencer are provided. It uses an inlet radial diffuser with either a one-, two-, or three-wall arrangement (Fig 11). The floating diffuser replaces common metal bells and enables thermal growth in the axial and transverse directions. The lower plenum section is an expansion chamber for radial dispersion of flow, and promotes uniform flow transition to the absorptive upper stage. The upper stage is designed in either concentric-baffle configuration, tubular array, bar array, or parallel-baffle arrangement. Variations are in thickness, spacing and active length to further dissipate acoustic energy (Fig 12). The diffuser basket is critical to redistribute the energy radially.

The silencer works by acoustically shifting from broadband to middle-to-high-range frequencies.

Discussions included design details and welding to ASME specifications, and the benefits of detailed metallurgical exams of failed materials.

Tube repair innovation

Tuff Tube Transition (TTT) offered Innovative HRSG tube repairs, specifically a sleeve-type connection that eliminates open-root butt welds, does not require back purge, and eliminates the need for NDT/RT. This provides a “faster and more reliable joint alignment,” said Marshall Hicks of Viking Vessel Services/TTT.

As an overview offered by Hicks:

•  The thicker material of the sleeve-type TTT increases the connection stiffness and decreases stresses (virtually eliminates fatigue cracking in tube-to-header joints).
•  The reduction of stresses corresponds to a decrease in the weld connection stresses.
•  The 30% reduction in thermal stresses claimed is said to increase connection life and reduce the number of failures, plus increase service life by 50% to 75%.

The Tuff Tube Transition, developed by Viking, was first used at Calpine Freestone Energy Center in Fairfield, Tex. TTT was applied on sections with P11 header and T11 tubes in an HRSG that had been in service for 20 years (Fig 13). These purgeless sleeves are made of T22 (2.25 Cr-1 Mo).

After two years of service and 102 cycles, PMI Specialists Inc, a metallurgical services firm, was asked to evaluate the condition of the welds. Finite-element-analysis results were discussed.

Table compares TTT and conventional methods of tube repair.

Comparing method of boiler-tube repair
Tuff Tube Transition	Conventional
No butt weld Fillet weld No purging No RT Self-aligning fit-up No bevel required No radiation barrier Reduces downtime Easier weld Reduces contractor costs	Butt weld Open root/complete joint penetration Purging required for alloys such as T91 RT required in most repair cases Open root/root gap fit-up Bevel required for most butt welds Radiation onsite Increases downtime More difficult weld Increases contractor costs

Tuff Tube Transition is US made and warranted, and offers full packages for HP, IP, and LP sections. When asked if TTT applied to both steam-touched and water-touched service, the answer was “both.”

The discussion period dove further into experience. There are currently no reported issues with TTT installed in nine HRSGs. Questions included any resulting flow restrictions, but to date there have been no negative effects. Further results and discussions are anticipated at HRSG Forum 2024.

Detecting spray-water leakage

Denis Funk, Flexim, discussed Ultrasonic detection of spray-water leakage to find leaks and prevent attemperator steam pipe and superheater/reheater tube damage.

This was a case study from 2020, when a major CCGT operator had issues with HP and RH steam tube damage. Several cracks also had been discovered in attemperator spray liners.

The suspected root cause was HP attemperator spray block valve leak-by, with quenching of the liner and tubes during low load. First response was to diagnose leaking by continuously monitoring conditions using existing instrumentation, with these problems:

•  Differential flow meters are limited in turndown and low-flow resolution.
•  Comparison of upstream and downstream thermocouples did not show sufficient accuracy for low-flowing leak-by.
•  Acoustic monitors were not providing flow values, just noise signatures.

The operator then consulted with EPRI and Bob Anderson, Competitive Power Resources.

Testing involved Fluxus 6 series portable equipment with transducers for extended temperature range at three different locations on the HP and RH spray lines. These are non-invasive ultrasonic flow meters (Fig 14).

Measurements were taken during valve opening and when fully closed (for leakage detection). Testing showed that the ultrasonic meter and the calculated flow (heat-balance equations) matched very closely. However, the differential-pressure-based flow meter was not able to capture the flow rate precisely, especially during low loads.

Funk noted that “During low loads, leakage can cause the most damage because the spray is not completely evaporating.”

Two ultrasonic transducers (Fig 15) are mounted with a defined distance onto the pipe. By sending sound signals alternating with and against the flow, a transit time difference can be measured. This corresponds to the flow velocity, and calculation of volume flow and mass flow.

The equipment features no moving parts, no pipe penetrations, high repeatability, and is factory calibrated. Applications include natural gas, boiler feedwater, blowdowns, compressed air, cooling water, hydrogen cooling, and steam.

An interesting question followed: Can this distinguish between water and steam? The answer was “yes,” using diagnostics.

After various utilities reported successful use of this equipment during discussions, Bob Anderson carried support a bit further, saying: “Once you know the fluid, pipe OD, wall thickness, materials, etc. and enter this into the meter, it automatically gives you the transducer spacing and calibrates the system. The meter communicates with the transducer to acquire the specific calibration curves. Fluid temperature is also an important variable, but temperature elements in the transducer automatically provide this as well.”

One strong supporting comment came from Duke’s Eugene Eagle: “We have installed permanent Flexim meters on every Carolina unit’s HP and RH attemperators. We are looking to install them on the rest of the fleet.”

Silent sentinels

Kurt Bedar, NDE/PRD Consulting, offered a Pressure/safety relief valve maintenance program. “Pressure relief valves,” he began, “are one of the most ignored parts of the plant. They are the silent sentinels for safety.”

“Relief valves are often handled and stored like pipe fittings, but need to be treated as delicate instruments,” he said (Fig 16).

Bedar stressed, “Perhaps no one valve plays a more critical role in preventing industrial accidents than the pressure relief valve.” Sometimes referred to as a safety or safety relief valve, it helps mitigate industrial accidents caused by the over-pressurization of boilers and pressure vessels.”

The three main parts of the valve are nozzle, disc, and spring. “Pressurized steam enters through the nozzle and is then threaded to the boiler. The disc is the lid to the nozzle, which opens or closes depending on the pressure coming from the boiler. The spring is the pressure controller,” he explained.

Common problems are a lack of testing and improper original specification. The former leads to reduced relieving capacity, leaking and shimmering, and improper repairs attributed to workmanship or failure to identify and correct problems. Also, said Bedar, “Replacement parts should be OEM only, and technicians must be certified.”

His conclusion: “It is essential that each PRV owner, in cooperation with an approved PRV service provider, establish an effective quality-control system to ensure that valves tested and repaired have been returned to conditions equivalent to the standards for new valves. By combining the use of competent repair personnel with an effective quality control system and conducting repairs in accordance with the provisions of the National Board VR Stamp certification program, a pressure relief valve tested or repaired will perform as expected when needed.”

Aging HRSGs

Mark Stockman, United Dynamics Advanced Technologies Corp (UDC), discussed NDE techniques for an aging HRSG fleet.

Stockman began with some generalized, conservative observations:

1. Retirement age for HRSGs was often assumed (when installed) at 25 years for a baseload unit.
2. Baseload was defined as four cold starts, 52 warm starts (weekend shutdowns) and several eight-hour-shutdown hot starts per year.
3. The big buildout was in the early 2000s. Those units are getting close to end of life.

But some coal plants bult in the 1950s are still operating, exceeding 50 years. So do we need to get more life out of the HRSGs? “If so,” he suggested, “we have to focus on the life extension of installed units. This means thorough condition assessments.”

He offered some building blocks for life assessment and life extension:

•  Review PI data and focus on overstressed components.
•  Know that many problems are not visible from a standard inspection.
•  Dig deeper using NDE techniques to determine where the next failure might occur.

Example: Use PI data to trend HP superheater outlet temperatures downstream of the duct burner, the temperature before attemperation. Look for temperature excursions. This is a target for NDE to determine the extent of damage. It also helps with root-cause analysis.

He offered other examples, then focused on HP, SH, and RH overheating, looking at tube-internal oxide scale and detection by NDE.

He described an oxide-scale theory in which 1 mil of scale equates to a tube OD temperature increase of 2 deg F. (Dooley later commented that this might be 4 deg F.) See Fig 17.For oxide-scale thickness of 0.01 to 0.03 in., this means a temperature increase of from 20 to 60 deg F.

Explaining further: “The primary failure mechanism in steam-carrying SH/RHs at temperatures above 900F is stress rupture. Primary contributors are temperature, stress, and time. Stress and temperature increase with time,” Stockman explained.

He then looked at tube-to-header welds for OD-propagated cracking, using magnetic particle testing on superheaters, reheaters, and HP economizers. Other areas shown were P91 drain and steam-drum nozzles.

Phased array, he said, is used primarily for ID-initiated cracking (tube-to-header welds, etc), for economizers, and drains in particular (Fig 18). He then reviewed ultrasonic thickness testing on elbows, economizers, and balance-of-plant areas.

Turning to drones Stockman looked at pipe supports and other areas not accessible from platforms, scaffolding or grade.

He then turned to metallographic replication to analyze piping components without removing samples. Videoscope inspections were next, looking at evaporator tubes, attemperator downstream piping and drums. Stockman ended with under-insulation corrosion, which he called “too often neglected.”

Editor’s note: During the main-session presentations at HRSG Forum 2023, Duke Energy and Structural Integrity Associates Inc (SI) jointly presented on an online “HRSG damage monitoring system,” which is highlighted in CCJ’s summary report of that conference.

At the same Forum last June, Jacob Boyd presented “Wireless high-energy-piping monitoring program,” recently implemented at his plant, CPV’s St. Charles Energy Center in Maryland.

Both topics were expanded during the two-hour webinar reviewed below, “Real-time damage monitoring of HRSG components,” held Nov 7, 2023. View recording of that event, coordinated by CCJ and HRSG Forum, at the end of this page. What follows are selected highlights of what you will see and hear in this webinar.

Monitoring at Duke Energy

Structural Integrity’s Kane Riggenbach introduces the webinar while Duke’s Eugene Eagle reviews for listeners his company’s damage monitoring system. They offer a real-time assessment of system performance and component integrity for both HRSGs and high-energy piping (HEP). The webinar focuses on Duke’s goals, implementation, significant results, and future plans.

The online monitoring system begins with existing plant monitoring equipment for temperatures, pressures, steam flows, and valve positions. Duke and SI then add specific temperature instrumentation (in this case, 64 thermocouples per unit). All data feed into Structural Integrity’s PlantTrak™ software, relayed to SI through a secure VPN connection. Company analysts then look for indicators and trends that affect creep and fatigue life, and monitor high-temperature alerts and other abnormalities specific to the HRSG components.

The reference plant (Fig 1) has three triple-pressure HRSGs behind Siemens F-class gas turbines that have accumulated 70,000 service hours since 2012. Currently in baseload, the plant is moving into cycling operation, expected to increase wear and tear on the units.

The purpose of the new monitoring system is to look more closely at these high-temperature components susceptible to creep, fatigue, corrosion fatigue, oxidation, and exfoliation:

• Interstage attemperators.
• Bypass superheaters.
• Intermediate headers and tubing downstream of attemperators.
• Branch connections.
• Final-stage outlet headers.
• Drums.

As Riggenbach summarizes, this “allows you to dig deeper into what might appear to be acceptable results.”

The webinar offers data comparisons for operating modes, comparisons between units and sites, the effects of low-load operations, operating with and without steam sparging, and the impacts of startup time changes.

One key benefit discussed is help in targeting inspections, setting inspection times and budgets, and basically, states Riggenbach, “finding the problems before they find you.”

As Eagle explains, “These are big and important units for Duke. They are highly efficient, and if we can get maximum life out of them while ramping them a bit harder, or cycling them more, we can get the most value out of these assets.”

Kane then addresses specifics of instrumentation which he says are “now more specific to component life management than simply process variables.”  He explains that detection (instrumentation) is now looking at both magnitude and frequency of events. Such monitors look at temperature differentials, ramp rates, over-temperatures, and other items. This leads to trending, analysis and diagnostics, and setting priorities.

At this point in the webinar, some questions and answers are monitored by Co-chairs Barry Dooley, Structural Integrity, and Bob Anderson, Competitive Power Resources.

An interesting caution for older HRSGs: Historical operating data could be difficult to obtain and verify. Also, system and component changes over the years might not be well documented.

Other questions discussed include benefits to parts supply and storage, fitness-for-service predictions, and benefits to control-logic changes.

High-energy piping

Jacob Boyd then discusses wireless HEP monitoring at the 2 × 1 St. Charles Energy Center, a program implemented with SI. This plant, commissioned in 2017, has fast-start 7FA.05 gas turbines, a D-11A steam turbine, and CMI HRSGs. The plant cycles 140 to 170 times per year.

In late 2019, the site experienced a through-wall leak at the girth weld of a hot-reheat (HRH) bypass line. Root cause was thermal fatigue. Plant personnel worked with SI to install local thermocouples to better assess thermal transients during operations.

The presentation includes descriptions of data collection nodes and e-mail notifications, highly valued at St. Charles because of limited engineering and walkdown staff.

Cycling concerns led to wireless monitoring of the HEP system, again working with SI (Fig 2). HEP monitoring examples highlight a growing area of concern at many plants.

At this point in the webinar, questions are again coordinated by Dooley and Anderson.

More data

SI’s Wes Bauver, follows with various case-study examples of other damage monitoring systems.

This includes discussion of HRH bypass thermocouple locations (Fig 3), circumferential data with thermocouples at 12:00, 3:00, 6:00 and 9:00 locations, and results of data over time.

Bauver looks at a specific HP-to-CRH bypass event, and data indicating non-uniform attemperator spray and indications of possible bypass-valve leakage.

Next is an interstage attemperator thermocouple arrangement recommended for older units: specific locations relative to spray nozzles, elbows, and liners. Discussions cover lessons learned through comparing spray flows and steam flows on two units over time.

He shows a bypass system with thermowell instrument locations relative to valves, and discusses temperature differentials relative to elbows, bypass valve, and bypass piping. Data plots show differentials recorded during startups from 2016 to 2022, and unit comparisons.

Bauver ends with a look at typical cold starts and graphic evidence of valve hunting (Fig 4).

The fundamental point for all of the above: the more data, the better.

The webinar then offers a recap of the primary benefits of online monitoring:

• Targeted inspection locations and intervals.
• Extended inspection intervals or delayed inspections.
• Expedited fitness-for-service evaluations.
• Optimized component life management.
• Improved confidence in unit reliability.

This ends with a discussion on future use of monitoring technology, including the use of various ultrasonic transducers to monitor metal thickness during operation.

By Vaughn Watson, Vector Systems Inc
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The efficiency and long-term performance of an SCR system is largely dependent on several key design considerations for its various components. When complex NOₓ reductions on heat-recovery steam generators (HRSGs) are required, there are critical aspects of the system that must be addressed to ensure success. While the catalyst often gets all the credit, and all the blame, when performance declines, careful attention to system design can mitigate or prevent many of the top factors contributing to SCR issues.

Catalyst design itself is crucial to the effectiveness of the emissions control system. Catalyst volume, formulation, and pressure drop must consider the totality of operating scenarios the boiler will encounter. This evaluation should include all load levels, including the minimum emissions-compliant load (MECL), that the boiler will operate within.

All ambient conditions also should be considered. This is especially important for boilers firing multiple fuels or blended fuel streams. Your evaluation must include all operating cases from the HRSG OEM, but also interpolation of DCS data trends, if evaluating an existing unit for catalyst performance.

Additional testing to ascertain the NO/NO₂ ratio is important because high NO₂ speciation can be a major issue to SCR efficiency and require specific SCR catalyst formulations to achieve desired NOₓ reductions. Be sure to consider boiler turndown as well because the NOₓ produced typically is higher, and the decrease in exhaust temperature will limit catalyst efficiency.

SCR catalyst should be inspected at every outage to ensure the catalyst face is not blocked by rust or insulation (Fig 1). This can majorly affect SCR catalyst performance by masking the SCR’s active pore sites.

Bypass can greatly affect NOₓ and ammonia slip. The catalyst support structure, as well as the perimeter seals, should be inspected to ensure there is no bypass of exhaust gas and ammonia. Assure catalyst modules are well packed to prevent ammoniated exhaust gas from passing unreacted through gaps around the catalyst bed. On a high-performance SCR, small amounts of bypass can drastically add up to the inability to meet objectives.

Ammonia distribution within the exhaust-gas cross section is a major factor in the catalyst’s ability to properly reduce NOₓ levels. This important part of the system falls on the design of the ammonia injection grid. AIG design must consider the amount of ammonia and diluent required for the reaction, as well as the ability to inject and mix the ammonia with the NOₓ present in the exhaust gas (Fig 2).

Give careful consideration to injection pressures, mass flow, and density change along the length of each AIG lance. Injection-grid design for advanced NOₓ control will carefully vary injection orifice sizing, spacing, and angle of injection necessary to ensure the NH₃:NOₓ distribution is matched to the volume of catalyst (Fig 3).

Inspect the AIG every outage to ensure there is no significant plugging, which could have a huge impact on catalyst performance. Clean the AIG if you find plugging, then determine the root cause. Often, the design of the AIG can be improved to achieve better performance and provide some resilience against frequent plugging issues.

Avoiding many SCR performance issues begins with the ammonia supply. Work with a reputable and accountable chemical supplier to ensure you are getting the reagent purity necessary for your system. Avoid ammonia contamination in transit to the plant by requiring dedicated trucks for each haul.

Also, require certificates and test reports before offloading to help protect the system against such contaminants like chlorides and calcium. These impurities can damage and plug the various components of the ammonia system.

Specifying the correct purity grade of ammonia is critical for aqueous ammonia systems; reagent-grade ammonia is the best option. The key differentiation is the purity of the water content of the solution which may contain soluble minerals that can plug, foul, erode, and damage SCR system components.

Such impurities in the reagent solution can lead to vaporizer fouling, AIG plugging, and potential catalyst performance problems. Keep in mind that it only takes one bad load of ammonia to experience the headaches associated with ammonia impurity.

By ensuring the foregoing factors are considered in the SCR and ammonia-system design, and addressing problems when they are discovered, are essential to an efficient SCR system capable of advanced NOₓ reduction.

By Cesar Moreno, HRST Inc
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Gr 91 material is named after its main components: 9% Cr and 1% Mo-V. It was developed in the late 1970s, with the focus of its use in the nuclear power industry. The material is part of the Creep Strength Enhanced Ferritic (CSEF) steels group, which includes its predecessor, Gr 9. One of the main factors supporting the creep resistance of CSEF materials is their microstructure. This is why it is critical to maintain proper fabrication procedures to obtain the full capabilities of the material.

Shortly after its development, Gr 91 material soared in popularity. It offered many significant benefits—including reduced minimum wall thickness (up to about 40%) for the same creep life as traditional boiler steels. In addition to the reduction in MWT, Gr 91 boasts up to a 12-fold increase in fatigue life. Additionally, it has about an 18% lower coefficient of thermal expansion than Gr 22, making it especially attractive for applications in cycling units that frequently experience transient conditions.

As the industry continued to develop, and new equipment required more demanding operating conditions, the market for Gr 91 grew quickly. This encouraged the mass production of Gr 91 material which often led to producers maintaining only the minimum requirements in the chemical composition and fabrication process.

Some of the cost-saving measures applied in production—such as lean chemical composition, application of minimum guidelines for heat-treatment cycles, and varying production processes (strand casting versus ingot)—lead to measurable variations in the final compositions of different heats. The combination of these variables is detrimental to the final characteristics of the material.

Given the wide use of Gr 91 material in the industry and the vast amount of data collected over several decades of in-service applications, there is now information available to provide more accurate results for design limitations and life expectancy of the material.

Predicting creep life for Gr 91 generally has a high degree of uncertainty and extrapolating from (relatively) short tests is not reliable. The availability of long-term data (over 30,000 hours in operation) allows for more realistic estimates of the material’s life.

In the 2021 revision of the ASME Boiler and Pressure Vessel Code, the allowable stress values (ASVs) for designs using Grade 91 materials were reduced. This decision was based on a combination of factors, but seemingly driven primarily by the significant differences in the material’s capabilities when produced under ideal production conditions versus those produced following the absolute minimum requirements.

The material is now classified in two categories, Type I and Type II, differentiated by their chemical composition. Type II Gr 91 has the stricter requirements of the two, producing a higher-quality material which more closely resembles the composition used during the original development and testing.

The reduction of ASVs has a direct impact in HRSG design considerations. At a typical operating condition with a tube metal temperature (TMT) of 1100F, the new ASVs for Type I and Type II materials see a reduction of 15.5% and 11.6% respectively. This directly results in a higher MWT requirement for the same operating temperature; conversely, it reduces the allowable TMT for existing designs.

In addition, there are many other industry changes that add to the considerations of the Code change. Many plants have implemented GT upgrades which often create more demanding conditions for the HRSG. Operating profile changes, especially more frequent operation at lower loads also have a significant impact on the expected life of systems using Gr 91 material. Other issues such as non-uniform flow distribution in the burner duct area, increased firing temperature, missing baffles that create bypass lanes, and internal oxide growth can exacerbate the problem.

Most HRSG designs employ Gr 91 material near its limits, which creates a situation where a small increase (15 to 20 deg F) in TMT could have a drastic reduction in the expected life of the material (Figs 2 and 3).

HRST has performed analyses of specific cases using the Larson-Miller Parameter (LMP) for creep-life approximation and found up to a 40% reduction in expected operating hours for an 11-deg-F TMT increase. Given the possibility for these types of situations, consider putting steps in place to evaluate the current condition of your Gr 91 systems.

ASME B31.1 provides requirements for monitoring the condition of external high-energy piping (HEP), also commonly referred to as covered piping systems, or CPS. Inside the HRSG, the design limits should be reviewed using the new ASVs to determine if there are any concerns. Following this review, if the values are not ideal, the evaluation can be repeated using the actual operating conditions of the plant.

Once this has been done a condition assessment can be developed. It should include an individual assessment of each system, stress analysis for the concerning areas, and NDE. Finally, if problems are identified during the assessment, they can be used to determine specific locations of high risk. Destructive assessment can be performed for the material to determine its chemical composition and heat-specific strength, which would help guide the appropriate actions to take at that point.