HRSG hot topics: risk-based inspection, corrosion under insulation, water chemistry

The Australasian HRSG Users Group (AHUG) celebrates 11 years of service to the industry at the organization’s 2018 meeting at the Brisbane Conference and Exhibition Center, November 11-13. Review the agenda here. Of all the HRSG groups outside the US, AHUG has the second longest history, behind only IMechE in the UK.

The shared purpose of these organizations: Provide interactive forums where owners, operators, manufacturers, service providers, consultants, and others with an interest in HRSG systems and equipment meet to learn from colleagues while sharing their knowledge and experience. All meetings feature a combination of carefully selected technical presentations and discussions facilitated by experts.

The HRSG Forum’s Bob Anderson, actively participates in these meetings, collecting the information disseminated to develop a program specific to the needs of owner/operators in North America with a world view of boiler design, inspection, and O&M technologies.

Selected topics from the 2017 AHUG meeting below, pertinent to challenges faced by users in this hemisphere, illustrate the global nature of HRSG technology. 

Risk-based inspection promotes safety, cost-effective maintenance

The Cockburn Power Station in Western Australia is a 240-MW site with a 160-MW gas turbine, 80-MW steam turbine, and dual-pressure HRSG; it was commissioned in late 2003.

Cockburn averages 150 starts per year in two-shift operation. A recently implemented risk-based inspection (RBI) program allows the plant to better incorporate both targeted maintenance and safety into its operations. (RBI has become a familiar theme in all regional meetings.)

Inspections in Australasia commonly find corrosion under insulation, signs of corrosion fatigue in the HP drum, and corrosion within the closed cooling systems.

Desuperheater instability was discovered in the past year at Cockburn, using methods discussed in detail at the 2016 AHUG meeting.

The 2017 presentation introduced many added topics (seals and at casing penetrations, expansion joints, etc) the plant has faced because of challenging and changing operational trends:

    • More time in layup (little use in summer).

    • Winter peaking operation.

    • More days between starts.

    • Constant standby.

Why RBI? The main risks to the HRSG at Cockburn are from fatigue and corrosion. As Keith Newman of Synergy explained, “If you understand where your risks lie, you can spend your money on the things that matter.”

Problems were appearing with: 

    • Feedwater piping—HP pipe, LP pipe, and HP drain pipe

    • HP drum—cracking on attachment welds and on internal surfaces of both downcomers.

    • Galvanic corrosion in the condenser (seawater cooled).

    • Desuperheater overspray.

This status presentation triggered active discussions and thoughts on solutions. Desuperheater liner replacement is being considered, but repair is a near-term option if the crack does not enter the pressure parts. Penetration seals and corrosion of carbon-steel rings were discussed, along with repair/replacement issues. Fabric penetration-seal retrofits and isolation valves were covered also and would be explained in later presentations.

The RBI concept was openly examined, including the ability to incorporate major events into the RBI calculation. Cockburn currently uses Microsoft Excel. Maintenance planning is with SAP, guided by the RBI analysis. 

Is corrosion lurking below your insulation?

Corrosion under insulation (CUI) was a topic in several case studies. CUI is atmospheric corrosion—a/k/a rusting of carbon and low-alloy steels. For stainless steels this leads to stress corrosion cracking above 140F. The main problem remains this: there is not yet a method of inspecting with the insulation in place. And this is not unique to the power industry. It is a significant concern within the global refining industry as well.

Five case studies were reviewed by Charles Thomas of Quest Integrity.

With insulation removed, inspection of carbon steel can be visual. Inspection of stainless is both visual and with dye penetrant. At highest risk are the small-bore lines, most with thin walls, and dead legs that cool down away from the main vessel. But a plant cannot remove all insulation, and therefore, “Inspection techniques to identify CUI (without removing the insulation) are the current holy grail of the inspection industry.”

Case studies were presented on LP drum-level transmission pipe, HP vent line, pipe bend low points where water pools, and the discovery of stress corrosion cracking under support plates.

The underlying message: look carefully.

Lengthy discussions followed on inspection techniques and methodologies including guided wave, radiography, eddy current and thermal imaging. The general agreement was the need for a risk-based approach: “Manage by targeted inspection of at-risk areas.” 

An interesting thought was generated during the discussions: If insulation is not required, don’t replace it. Perhaps consider also installing rain covers on the pipe bridge for plants with horizontal, exposed runs.

The AHUG case studies are, perhaps, a perfect segue to a presentation by the respected Ian Perrin of Structural Integrity Associates Inc at the upcoming HRSG Forum with Bob Anderson (Hilton Orlando, July 22-24, 2019) on real-time health tracking of HRSGs and piping (including attemperators).

Perrin says determining the health of components that suffer progressive degradation and damage typically has been achieved using NDE, which can be costly; plus, success depends on being in the right place at the right time. He will discuss technology that now exists to track the health (or ageing) of key components—such as headers and piping components—caused by creep, fatigue, and in the case of attemperators, water impingement.

Since leaking and overspray of attemperators are common industry issues, Perrin will show how online monitoring can identify when these events occur—thereby enabling corrective action and timely evaluation of possible damage. 

Lessons learned in layup and recommissioning of combined cycles

For the past three years, participants have reviewed the status and details of Stanwell Corp’s 375-MW Swanbank E Power Station in Queensland. The plant was withdrawn from service on Dec 1, 2014, and placed in dry storage after operating with an average 97.5% reliability.

Site labor was reduced to a caretaker team, and comprehensive cold storage and preservation of all systems was implemented.

Major storage risks, typically, are corrosion of water/steam components and corrosion under insulation. Acid dew point corrosion on the HRSG gas side was a concern, as were gas and steam turbine corrosion. Stanwell’s full storage with dehumidified air has ensured few issues other than rainwater ingress (some corrosion under insulation).

Safety valves were found to have a few problems with debris. Some were overhauled because of casing cracks, primarily attributed to missing insulation.

The unit was returned to service shortly before the 2017 conference. Operations will be reported at the 2018 meeting in Brisbane, November 13-15.

Layup and recommissioning of fuel-fired assets are hot topics in the US given shutdowns of six to nine months annually at some plants in the western desert where PV generation is robust. The upcoming HRSG Forum with Bob Anderson (Hilton Orlando, July 22-24, 2019) will feature a presentation by Andrew Gundershaug of Calpine Corp who will speak to lessons learned on recommissioning of two F-class 2 × 1 combined cycles. 

Those pesky millennials

One presenter at the HRSG Forum with Bob Anderson in Houston this year called a large group of HRSGs millennials, meaning those built in the late 1990s and early 2000s. In Sydney, the presenter keyed into those units in the 2000 to 2005 range, stating that even they are getting close to half way through their original design lives. The common message is the need to do thorough and accurate life assessments of all components and systems, and to understand the overheating mechanisms in ageing units.

Non-pressure parts can be a major concern:

    • Liner plates in inlet ducts (at risk at 1200F).

    • Liner materials in firing ducts (oxidation and thinning at 1500F).

    • Tube ties—chrome steel and Type-304 stainless steel plate.

    • Gas baffles.

    • Type-304 duct-burner materials.

Many units are experiencing the need for new inlet-duct liner systems because of fatigue cracks in Type-409 stainless steel liner plates and bolting systems. Fatigue strength is temperature-dependent and above 1020F it decreases sharply for Type 409.

Duct burners themselves must be carefully monitored.

Superheater and reheater tube ties are traditionally Type-304 plate materials located downstream of the duct burners. These are subject to fatigue cracking, increasing the risk of failures—including tube vibration and fin damage. In the case example, normal thickness of 7/16 in. had been reduced to less than 1/8 in. Standard causes are poor turbine exhaust distribution and poor burner fuel distribution, or both. Monitoring can be done using firing-duct view ports. Flames should never make contact with the tubes, and glowing red components indicate excessive temperatures (1500F).

Loose or missing tube-bank baffles also were discussed. Baffle reinforcement systems are available and were described by Lester Stanley, HRST Inc. He said, “If the baffle system keeps failing you need to redesign it, but it’s very important to keep it in the system.” This led to an interesting exchange on missing or damaged baffles producing the following Rule of Thumb: “Operating without the baffles should never be an option, because of downstream heat damage.”

The presentation then switched to pressure parts and covered:

    • Tubes.

    • Headers.

    • Link pipes (between tubes and headers).

    • Steam outlet piping.

Examples concentrated on overheating as the cause of damage. Overheating would become a common theme in the meeting, and in the workshop on the final day.

During discussions, proper oxide analysis was also discussed, and would also be addressed in the workshop.

Stanley’s presentation offered several takeaways, including:

  1. 1. Perform careful visual inspections to find early clues on overheat risk locations, then monitor these areas. One critical activity should be to both maintain and use the burner view ports. One failure noted was attributed to site personnel “getting lazy.”

  2. 2. Analyze performance (both low load and full load) and compare predicted versus actual performance.

  3. 3. Use performance assessment results to analyze remaining life (then manage the remaining life carefully). 

The basic rules of proper cycle chemistry are always worth repeating

Barry Dooley, Structural Integrity Associates Inc, commonly addresses these meetings on the importance of HRSG cycle chemistry control and flow-accelerated corrosion detection. He did so in Sydney. Key items are repeated here, for ongoing emphasis.

    • Instances of under-deposit corrosion (hydrogen damage) are increasing globally, especially in HP evaporators.

    • FAC is an ongoing issue, in the same locations and situations spanning the past 15 years.

Owner/operators need to concentrate on the known repeat cycle chemistry situations:

    • High corrosion product levels.

    • HP evaporator deposits.

    • Failure to chemically clean when needed.

    • Lack of instrumentation by international standards.

    • Lack of carryover control.

    • Inadequate shutdown protection.

    • Air in-leakage.

    • Contaminant ingress.

    • Failure to challenge the plant’s status quo (policies, procedures, and action/inaction decisions).

As another Rule of Thumb, David Addison principal, Thermal Chemistry Ltd (New Zealand) stressed that “A fully optimized chemistry program should mean almost no loose iron anywhere in the cycle.”

A major source of loose iron comes from exfoliation of steam-side oxides in superheaters and reheaters. In the extreme it can cause problems from erosion of steam-turbine components to plugging and overheating of tubes and plugging of headers. Dooley says that as HRSGs age, the probability of these problems occurring increases.

He recently conducted an extensive study of exfoliation and at the upcoming HRSG Forum with Bob Anderson (Hilton Orlando, July 22-24, 2019) Dooley will give a comprehensive explanation of how the oxides form, how they differ in the various materials used in superheaters and reheaters, the consequences of thick oxide formation, and how to assess oxide thickness. Certainly something for every HRSG owner/operator should know about and understand. 

Update on issues caused by thermal transients

Bob Anderson then presented a brief update on thermal-transient issues. Nearly 30 key items were tracked over a 10-year period for 51 plants including gas turbines from five OEMs, steam turbines from nine OEMs, and HRSGs from 18 OEMs. The trends were interesting.

One focused question: For tube failures, is there an active root cause program in place? Positive response but luke warm, going from 0 plants previously to only 10% of them today.

For superheater/reheater drain issues, responses were better. Drain pipe sizes being large enough improved from 0 to 56%, drain pipes sloping continuously downward improved from 0 to 31%, and blowdown vessels being below SH/RH elevation improved from 11% to 49%.

For attemperators, avoiding overspray actually declined from 75% to 71%. Ensure leaking spray water will drain before entering tubes improved from 32% to 54%.  Routine hardware inspection program use improved from 11% to 22%.

Instances of exceeding a prudent HP-drum ramp rate during startup improved by decreasing from 33% to 28%.

Here was an interesting question: In a perfect world, how do you manage the thermal stresses of rapid shutdown and startups because of increased cycling (use of renewables)? One answer: Control the shutdown to bring the SH steam temperature closer to saturation. This means slowing the GT shutdown. An interesting caution: But be careful; you may run into emissions limits.

Specific to the drain issues, effective draining during startup as confirmed by use of DCS data for superheaters improved from 22% to 44%, but for reheaters declined from 75% to 71%. Having drains open during GT purge improved from 33% to 57%.

Use of a reliable condensate detection system improved from 0 to (only) 8%. 

Ultrasonic condensate detection in superheaters and reheaters

The goal here 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 tube metal failures, stretching and bowing of tubes, and a host of related issues.

The industry has extensive experience using ultrasonic meters to measure flow. One application to detect condensate uses this same method, although calibrated differently to distinguish condensate from steam.    

The example used in Sydney was derived from an EPRI R&D project, managed by Competitive Power Resources using Flexim ultrasonic flow metering equipment.

The system is being used by Nooter/Eriksen on two new HRSGs, incorporating properly set slope and pipe size on all systems, and ultrasonic liquid detection sensors to control the drain valves.

Once condensate is detected, drain piping and valves must be able to remove the condensate while preventing release of live steam. This is a severe service system with large pressure drops and flashing liquid.

The master/martyr valve system was discussed: the master valve is opened first and closed last. The purpose is to maintain reliable shutoff tightness of the master valve by using a sacrificial martyr valve, which is required to throttle.

An early implementer of this system has had 16 systems in service for two years using their original ball-type drain valves. While adequately draining the superheater, ball valves open and close repeatedly during startup and will not have acceptable durability. This plant is currently working to replace the ball valves with modulating valves using the EPRI control algorithm.

Full details on valves, pipe sizes, and headers were presented. Options for drain pots and valve types were also given. Operational challenges were reviewed and discussed. 

Middle East case study highlights cycle-chemistry challenges

Thermal Chemistry’s David Addison presented cycle-chemistry challenges with a new-build combined-cycle project in the Middle East. The Persian Gulf location means very hot and humid summer conditions. The subject plant was commissioned in 2014 at 2000 MW with F-Class gas turbines firing 100% gas or distillate. Bypass stacks were included for open-cycle operation.

HRSGs are triple-pressure with feedforward LP evaporators. Site has five gas turbines (two 2 × 1 and one 1 × 1 combined cycles). Seawater cooling is used (titanium-tubed condenser) with no condensate polishing, and pulse chlorination on cooling water. The plant is designed for flexible operation (part of year baseload, then part load and partial plant operation).

P11 and T11 are used in critical FAC locations.

Commissioning water chemistry was as follows:

    • Feedwater/LP evaporator—AVT(R), ammonia/amine and carbohydrazide.

    • IP/HP evaporator—phosphate treatment with vendor sodium phosphate blends.

    • All chemical dosing—manual control. No automation.

    • Feedwater pH target—8.8 to 9.2.

    • Evaporator pH target—9.1 to 9.6.

    • Chemical vendor prescribed program.

Addison carefully reviewed the steam and water sampling and analysis systems, based on non-OEM-approved system integration. Critical issues include:

    • Sample-line sizes too large.

    • Non-OEM flow cells.

    • Sequencers not working correctly—loss of sample flows.

    • CACE analyzer resin columns installed incorrectly (upwards flow) plus threaded connections (no quick connects).

    • Tight spacing—limited maintenance access and no room for additional analyzers.

    • Lack of air-conditioned space—impact on analyzer performance and maintenance.

    • Non-compliant with IAPWS minimum analyzer levels for a plant of this type.

The plant meets only 80% of the IAPWS minimum instrumentation levels. If the O/S analyzers are taken into account, this drops to 60%.

There is no automation for the dosing systems (manual once per day testing). The plant is constantly over/under dosing and chemists are not dedicated to the area.

The chemistry laboratory onsite is set up primarily for fuel and environmental water analysis and is physically separated from operations and engineering. Experience is low, and documentation levels are poor and, at least in part, technically incorrect.

Layup and storage procedures are poor. HRSGs are left wet without nitrogen capping, partially drained down, for weeks at a time. Steam turbines are left with no protection. DHA equipment at site has never been commissioned. Outside of key summer (high demand) months, the plant is in flexible operating mode. Multiple GTs/HRSGs are out of service, recallable on short notice.

Commissioning was poorly managed with major delays. Commissioning documentation and procedures were poor.

HRSG makeup rates are extremely high. The water treatment plant has operated in overload to ensure makeup demand is met (42% over design). Startups and flexible operation increase the water demand even more.

FAC is a problem. Even with P11 in the LP evaporator, FAC was detected (also in IP evaporator and HP economizers). FAC was attributed to the plant’s initial AVT(R) program with reducing agent, low feedwater and LP evaporator pH, and low IP evaporator pH.

Condenser tube-leak risk is high (no leak detection analyzers) and condenser spill return is directly back to the site demin tank—a major risk of contaminating all units if one leaks.

Improvement activities include the following:

  1. 1. High makeup demand. Focus on identification and fixing/replacing leaking HRSG valves, and improve treatment plant maintenance practices.

  2. 2. Low feedwater/evaporator pH. Undertaking correct dosing; running pumps/chemicals at correct levels.

  3. 3. FAC in HRSGs. Halt reducing-agent dosing, increase feedwater pH to 9.8 with ammonia, increase HRSG evaporators (IP/HP) pH with tri-sodium phosphate (TSP); implement condensate polishing program.

  4. 4. Analyzers O/S. OEM training of technicians, increase priority on defects and repairs, correct setup issues, and begin additional analyzer project (sodium in condensate, etc).

  5. 5. Condenser. Future change to spill/return setup (to raw water tank), and increase in risk awareness

  6. 6. Chemistry management. Rewrite chemistry manual and procedures to align with IAPWS Technical Guidance Documents, phosphate dosing with TSP only, improve chemistry management, ongoing development of chemists.

  7. 7. Layup and storage. Develop procedures; push to commission DHA equipment. 

Film-forming substances

Day Two ended with an update on film-forming substances—specifically GE application experience in HRSGs—by Justin West. Various updates have been covered recently by CCJ.  This presentation highlighted developments by summarizing significant differences between modern FFAs and older filming-amine technology:

    • Higher volatility over wide steam-cycle pressure/temperature range versus ODA.

    • Strongly absorbed and highly persistent surface film.

    • Lower tendency to form unwanted deposits and combinations with corrosion products versus ODA.

    • Equally hydrophobic and difficult to formulate aqueous product solutions.

In the examples given, chemical cost reduction was achieved by utilizing a new pH target, neutralizing amine technology, and improved pH control. A vacuum-pump-drain pH reduction was achieved by using organic amine technology. The pH went from above 10.5 to 9.2-9.3 by replacing ammonia and eliminating the need to divert from the wastewater sump.

In the case described, lower corrosion/iron transport in both cycling and continuous operation was achieved.

The bottom line continues to be this: A great amount of research has been completed and progress made, but there remains a lot more to be done. 

Materials issues workshop 

The third day of the meeting featured a workshop on materials issues in HRSGs. Topics included a review of P91 damage mechanisms, premature failure of a P91 superheater tube, and creep-fatigue life predictions of P91. Much of this material will be covered at the upcoming HRSG Forum with Bob Anderson (Hilton Orlando, July 22-24, 2019) by Jeff Henry of Appied Thermal Coatings.

Henry is one of the leading experts on the evolving issues with creep-strength-enhanced ferritic steels. He will cover ASME Boiler & Pressure Vessel Code activities associated with CSEF steels, including details on ASME’s reduction of the allowable stress for P91 and creation of a new class of P91. The editors rate this presentation as “must attend.”

Some presentations were specific to the region, based on Code AS/NZS3788. Others were more global.

Metallurgical perspectives on overheating compared ferritic steels (deformation and creep) with the more expensive inclusion of alloying elements, reviewing potential benefits. Strengthening was covered in detail, including oxidation and creep life.

Overheating discussions led to life assessments and a variety of proven inspection techniques including ultrasonic, EPRI algorithms, accuracy, and results. Cautions were given leading to a discussion of an “integrity operating window.” The bottom line on asset integrity management:

  1. 1. Ensure safe operating limits are understood, and

  2. 2. Have plans in place to react to overheating.

This was followed by an in-depth discussion on oxide growth and exfoliation in HRSG superheaters and reheaters with Dooley at the front of the room. He included steam-turbine deposits related to HRSG component materials, and various “oxide morphologies.”

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