The High-temperature Defect Assessment conference has drawn international participation since its inception in April 1998. HIDA began as a European Commission and industry supported research project aimed at unifying defect-assessment procedures validated on materials of interest to high-temperature processes—primarily power generation.

HIDA continues to meet periodically in response to industry developments and with a strategic focal point. The first two events, in France and Germany, concentrated on the beginning and end of the original four-year European Commission program. HIDA-3, held in Lisbon, Portugal, focused on crack growth and repair of high-temperature welds.

HIDA-4, in the UK, saw an industry need to dive further into probabilistic assessment, and was followed by HIDA-5, again in the UK, to discuss fitness-for-service and risk-based inspection. Moving to Japan in 2013, HIDA-6 concentrated on martensitic steels and creep-fatigue interaction, followed by HIDA-7 (UK) discussing life and crack assessment for industrial components.

Like the first seven events, HIDA-8 was organized and coordinated by European Technology Development Ltd, Leatherhead, UK. Its focus: crack inspection and assessment, repair options, and monitoring of cracks and pre-crack damage. Participants represented Australia, Belgium, Germany, Ireland, Italy, Japan, the Netherlands, Poland, Spain, South Africa, Sweden, Switzerland, the UK, and the US.

Dr Ahmed Shibli, managing director of ETD, opened the virtual meeting, held April 20-22, 2021, by stressing the values and benefits of this ongoing, dynamic collaboration thusly:

“Assessment of the behavior of high-temperature plant components containing defects and operating under steady and/or cyclic load conditions has become an area of urgent need and interest. We have strategically organized HIDA-8 into sessions dedicated to inspection, damage, and cracking under creep, fatigue, and oxidizing conditions; defects/cracks and life assessment; and martensitic steels—cracking, life assessment, and modeling.”

Consulting Editor Steven C Stultz participated in HIDA-8 for CCJ ONsite and provided the following highlights from the more than 30 presentations and online discussions.

Casting weld defects have become a significant industry concern. Ronnie Scheepers, Eskom, South Africa, discussed acceptability assessments of casting weld defects under transient thermal loading. The basis of this presentation was weld repair of castings during both manufacture and operation, emphasizing the need for qualified welding procedures and strict quality control.

In many cases, cracking (on initial assessment) is attributed to in-service creep damage accumulation. However, consideration of specific geometry and operational stress distribution often suggest stress relief or reheat cracking because of an original manufacturing weld repair.

“Weld repair of castings during manufacture,” he stated, “is a well-known and acceptable practice if conducted in accordance with approved standards and procedures. However, cracking of these weld repairs in high-temperature and ageing plants, especially those operating beyond design life, is all too common.

“Structural-integrity assessments of such components must not only consider reduced material toughness caused by temper embrittlement, but also the stress intensities generated during transient thermal events, such as start/stops and quenching incidents,” he continued.

“Most defects are detected during outage inspections of in-service plants,” the speaker explained. “The focus then becomes a management strategy of replace, repair, excavate, or leave as-is.”

The first of two case studies presented by Scheepers discussed the acceptability of weld-repair defects in the outer casing of an HP turbine. This 1980s-vintage unit for a 618-MW site had logged 220,000 hours and 328 starts. Material of manufacture is GS17CrMoV5-11 (1.7706). Operating conditions are 4.3 MPa at 330C to 430C.

Phased-array NDT showed an internal defect about 48 mm deep in a wall of 114-mm thickness. An external vertical defect was about 78 mm deep where wall thickness (WT) was 108 mm; an external horizontal defect about 63 mm deep (108 mm WT). Refer to Fig 1. Remaining ligaments were clear of indications.

Microstructural evaluation showed a mixture of ferrite and mostly bainite, and confirmed cracks in both the weld and in the heat-affected zone. Cracks were oxide-filled with decarburization along crack lengths, and no indications of propagation.

Metallurgical assessments concluded significant temper embrittlement had occurred. This was considered in a finite-element-based structural-integrity assessment that reflected design operating conditions as well as a hypothetical quenching event.

A second case considered an LP-turbine bypass valve, 1980s vintage from a 686-MW unit with 190,000 hours and 155 starts (Fig 2). Operating conditions were 4 MPa/535C during startup and shutdown; the baseload operating temperature, 248C. Material: GS17CrMoV5-11.

A 67-mm-long surface-breaking defect was identified by magnetic-particle test (MT); phased-array ultrasonic testing (PAUT) indicated a depth of 44 mm within 65-mm wall thickness. No other defects were found. A macro crack in the weld repair area was oxide-filled and micro cracks were found with stress-relief voids.

Weld repair had not been reported during manufacture.

In this case, the material temper embrittlement was found to be less severe, but the criticality of pre-warming to reduce transient thermal stress and, by extension, crack stress intensities during trips or shutdowns, was clearly demonstrated.

Remaining life assessments, in both cases, considering creep or fatigue crack growth and allowable defect sizes concluded the defects to be acceptable for operation to the next planned outage.

Predicting creep damage. Rolf Sandström, Materials Science and Engineering, KTH Royal Institute of Technology, Stockholm, Sweden, provided a tutorial on creep damage.

During creep deformation, he explained, several changes in the microstructure occur that tend to reduce the time to rupture. These changes include cavitation, substructure coarsening, particle formation, particle coarsening, and recovery of hardening phases. These are often referred to collectively as creep damage.

“Information on creep damage is used to predict the remaining life of materials and components and to improve the properties of existing materials,” he said. “To make predictions, accurate data about the creep damage is essential. Since extrapolation to longer times is almost always involved, methods must be available to perform this. Considering the number of damage types, it is a challenging task.”

He then clarified: “In recent years, creep models based on physical principles have been developed that do not rely on the use of adjustable parameters. These models are referred to as fundamental.”

Such models, he explained, represent a major advantage, since damage types that have not been possible to measure precisely can be predicted. In this way, a more complete picture of the creep damage can be obtained.

For several materials, rupture is controlled primarily by cavitation—at least when the stresses are not too high. Fundamental methods have been formulated that can predict the observed strain dependence of creep cavitation.

Referring to published works, Sandström noted that a common way to determine the creep damage has been to analyze tertiary creep. Changes in the dislocation structure are the main cause of tertiary creep, so the mechanisms are different in comparison to those controlling the failure. However, the data from tertiary creep still give valuable insight. “Fundamental models for tertiary creep have only recently been developed,” he said.

Sandström demonstrated that by taking all the main damage mechanisms attributed to dislocations, particle formation, and cavitation into account, the rupture life of austenitic stainless steels has been predicted successfully.

Sandström’s presentation was designed to review recent modeling of creep damage using fundamental methods. “In all work on creep,” he stated, “it is important to identify the operating mechanisms. To generalize and extrapolate the results can only be done if the operating mechanisms are known.”

He reviewed several examples where mistakes have been made in applying empirical approaches, such as the following:

• • The stress exponent n is used as an adjustable parameter in many models, even in those that have a partially physical basis.
  • At the same time, the n value traditionally has been used to identify the creep mechanism.
  • This is problematic knowing that, for example, the creep exponent for dislocation creep can take values from 1 to 50.
  • It is documented that a stress exponent of 1 is not enough to identify the mechanism as diffusion creep.

Resolution, Sandström stated, is in the use of basic (fundamental) models where the derivation of the model is based entirely on physical principles and all parameters are well defined and their values are known. There are no adjustable parameters involved.

He reviewed several models fulfilling these requirements, including:

• • Models for dislocation creep covering low-to-high stresses.
  • Models for solid solution and precipitation hardening during creep.
  • Influence of prior cold work on creep life.
  • Models for primary and tertiary creep.
  • Initiation and growth of creep cavities.
  • Development of cell and sub-grain dislocation structures.

“These models have been established for some materials but not yet for a wide range,” he stated.

Sandström then listed and reviewed the basic models for predicting creep damage:

1. Particle formation, transformation and coarsening. Can be handled with commercial thermodynamic software such as Dictra, Prisma, and MatCalc.

2. Coarsening of substructure (important for 9Cr and 12Cr steels).

3. Initiation and growth of creep cavities.

4. Tertiary creep.

He went on to give specific examples.

“These models are predictable,” he stated, “and can be used for generalization and extrapolation.”

Single-crystal materials. Kurt Boschmans, ENGIE-Laborelec, Belgium, addressed evaluation of high-temperature creep degradation in single-crystal gas turbine materials through both conventional creep testing and small punch testing, comparing the methods.

In 2020, ENGIE performed a study to stretch the maintenance intervals of a gas turbine within its fleet by evaluating the condition of post-service turbine blades and vanes. In the framework of this study, the high-temperature creep properties of the materials were thoroughly evaluated.

“Historically,” said Boschmans, “this evaluation has been performed by conventional creep testing on airfoil and root materials, and by comparing the test results to the known properties of the superalloys in question.”

Boschmans then explained traditional comparisons of creep properties using a material-specific LMP (Larson-Miller Parameter) curve.

In the framework of the new and expanded data project, a comparison was made between the results of conventional creep testing (CCT) of sub-size creep samples and results of small punch testing (SPT). The goal was to evaluate whether or not SPT could replace CCT in cases where there is insufficient material available to extract an acceptable creep sample from the available hardware.

“Conventional creep testing,” he explained, “has a minimum size requirement: M5 sample with diameter of 3 mm to allow creep testing in air. Sample extraction thus becomes critical for first-stage blades, as well as for evaluating aeroderivative gas-turbine hardware, putting limits on the method.”

The option of using sub-size samples, he explained, is possible but expensive. SPT requires much less material (a 0.5-mm-thick disc-shaped sample), but at the time of this study:

• • No internal experience was available.
  • Registered exporter (REX) data on single-crystal superalloys (anisotropic material) was limited.
  • There were no known comparisons of both methods on the same turbine blade.

Several studies were reviewed indicating that a relationship (conventional versus small punch) appears valid for highly anisotropic materials such as single-crystal superalloy in certain conditions. A good LMP-curve correlation was reviewed.

“Results confirmed that the material properties at high temperatures are still corresponding to the requirements of new material, suggesting a stretching of the maintenance interval is possible for the specific blade studied.” However, this study is recent and microstructural evaluation of the test sample is ongoing (as of April 2021).

Conclusions:

1. Evaluation of high-temperature mechanical properties of the same turbine blade by means of CCT and SPT verified both the feasibility and accuracy of small punch testing, for which no internal experience was available on single-crystal superalloy materials.

2. Test results illustrate the SPT results show a good correlation with the CCT that was performed in parallel.

3. For superalloy materials where the extraction of creep test samples is not possible, the application of small punch testing can provide an economical alternative to sub-size creep testing.

Operation in creep conditions. Jerzy Trzeszczynzki of Pro Novum, Poland, discussed the conditional operation of boiler components working under creep conditions until replacement, using a large utility boiler as an example.

One of the more serious operational problems is thermal-fatigue damage detected on internal surfaces of pressure elements (steam coolers and superheaters), especially those working under creep conditions. “Such damages are practically irreparable,” he said, “especially during a planned outage. They typically require fabrication of new elements.”

Using the technology of digital twins, fracture mechanics, and remote diagnostics, Pro Novum has developed and implemented a methodology of conditional operation (until the element is replaced or the boiler is shut down) that allows supervision of the damage under the control of an appropriate software. “The system can simultaneously control the possible development of a dozen or so damages and assess the condition of the element online,” he explained.

The elements operating the longest in these test conditions have worked for two years. Ultrasonic testing during operation, and destructive tests after the disassembly of the elements, confirmed the possibility of computational monitoring of crack propagation with an accuracy sufficient for practical operational purposes.

Examples also were described for headers that received endoscopic examinations during a utility boiler renovation in 2018. Crack depth ranged from 2 to 10 mm.

These components work in creep conditions, but periodically are exposed to thermal fatigue and thermal shock because of water-injection and condensate events.

The program goal was to further assess damage through fracture mechanics and achieve a schedule for conditional operation. This would include monitoring of working conditions, and periodic assessment of the technical conditions.

Trzeszczynzki summed it up: “Component replacement time can be determined with acceptable accuracy by monitoring conditions of the initiation of new cracks and the propagation of the existing cracks using the online calculation method and by verifying the calculations with controlled endoscopic and ultrasonic tests.

Using data scatter. “There is a large amount of scatter in the creep properties of welded joints of the steels; however, the scatter is not considered in conventional remaining-life assessments of welded joints of in-service piping.” This was the presentation opening by Masatsugu Yaguchi, Materials Science Research Laboratory, Central Research Institute of Electric Power Industry (Criepi), Japan.

“Thus,” stated Yaguchi, “we have developed a new method of assessing the individual creep properties of welded portions of actual pipes.”

This presentation explained the assessment method and described the actual implementation for Grade 91 steel, as an example.

The premise: “Data scatter (heat-to-heat variations) has not been considered for remaining-life assessment. Test specimens are taken to conduct creep tests and to analyze the data, but there is no data for the actual component.”

In Japan, the common method of remaining-life assessment for materials is the 99% lower-limit curves for data obtained at various temperatures, on a typical stress versus time-to-rupture diagram.

The question remains: “Is the 99% lower limit, or minus-20% strength, really ‘the weakest?’  Also, materials used in creep tests do not cover all specification ranges of Grade 91 steels (Fig 3).”

“Therefore,” stated Yaguchi, “consideration of heat-to-heat variations is important.”

The institute’s program objectives: Propose a life-assessment method considering heat-to-heat variations, develop a database and elemental technologies for Grade 91 welded joints.

In the method described, the creep property of the welded joint is related to that of each base metal because the creep properties of welded joints strongly depend on the creep life properties of the corresponding base metals.

Microstructure analyses and small punch creep tests on samples cut from the base metals at the outer surface of pipes in service were conducted, and the results were compared with a material database to estimate the creep property of each base metal of the target pipe.

The precision of the remaining-life assessment of pipes is significantly improved using the developed method because it can consider variations of the creep properties of their materials, which are not considered in existing life-assessment methods. Then, the method was applied to the welded joints of the pipes in ultra-supercritical power stations during periodic inspections, and remaining lives of the components were estimated (Fig 4).

Research continues at the Central Research Institute of Electric Power Industry, Yokosuka, Japan.

Looking ahead. European Technology Development has been deeply involved in HIDA conferences for more than two decades and will continue to both participate in and organize future conferences. Cooperation and knowledge gained from these events are critical elements of ETD’s ongoing commitment to the global power industry.

Other examples of the consultancy’s involvement include a recently published study titled “Review of 9-12Cr Martensitic Steels for Pressure Vessels, Steam Piping and Tubing,” focusing on Grades 91 and 92.

The guidelines presented in this report are based on the experience of ETD Consulting, the reports and experience of its International P91 Users Group and ETD’s network of consultants, the experience of international industry in general, EPRI guidelines, and latest research findings. It can be a valuable resource to plant owners/operators for material quality control, fabrication/welding, inspection, monitoring and repair, and for understanding the incidents of cracking/failure and how to deal with these.

The guidelines are of greatest value to decision-makers at plant design firms, plant owner/operators, service providers and steel producers. For more information, contact enquiries@etd-consulting.com.

UPCOMING HRSG FORUM EVENTS

Bill Gretta, principal, SCR Solutions LLC, presented two case studies at a recent HRSG Forum virtual session, in which a unique field test method combined with sophisticated CFD analysis suggested modifications for improving distribution of ammonia through the SCR catalyst modules to improve NOx reduction and ammonia slip. Old units, and many new ones, are not equipped with a permanent NH3 sampling grid downstream of the SCR, and it’s costly to add, Gretta said.

He described a method that makes use of a flexible weighted probe with NOx and NH3 sensors which is lowered into the SCR inlet and exhaust gas flow fields from multiple ports on the roof (photo). Then EPA Test Method 320 is applied. Subsequent CFD analysis revealed the reasons for areas of high and low NH3 concentrations after the ammonia injection grid (AIG).

In the first case study, a 2 × 1 501F-powered combined cycle with close to 500-MW output, this approach resulted in removing and rebuilding the AIG, locating it three feet closer to the CO catalyst, and adding mixing baffles and plates to reduce the root mean square (RMS, an indication of the quality of distribution, the deviation from the average of many values) of ammonia-slip variance from 70% to 10%; additional tuning got it down to 6%. Buildup of ammonium bisulfate in zones of high ammonia slip decreased dramatically.

In the second case study, a 2 × 1 501D-powered combined cycle installed more than 25 years ago had to meet a lower emissions profile, so a dual-function catalyst was selected, but failed to meet the new standards. Analysis showed there was plenty of catalyst, so other system issues were at play.

Gretta and his team simulated 501D exhaust, sampled at 50 data points in a 5 × 10 array of SCR inlet and outlet locations with the weighted probe, and then did an inspection and CFD modeling when an RMS value of 19.3 indicated poor distribution. Causes of poor distribution and solutions were similar to those identified in the first case study.

Insights gleaned from the Q&A included the following:

• • In both case studies, AIG heavy support elements (which Gretta said probably would be found only in early SCRs) were getting in the way of flow; the replacement was designed to be self-supporting to eliminate the old support structures.
  • Rust and scale were blocking the AIG ports. The new AIG uses stainless steel instead of carbon-steel pipe and includes cleaning and vacuuming ports in each lance. Hole diameters also were increased and rearranged.

UPCOMING HRSG FORUM EVENTS

 

During the HRSG Forum’s second monthly meeting, June 2, 2021, hosted by Bob Anderson and Barry Dooley, close to 130 owner/operator representatives from 34 countries (out of 219 total attendees), were enlightened on two vexing issues with HRSGs: (1) steam-side oxide growth and exfoliation (OGE) from superheater (SH) and reheater (RH) tubes, and (2) the use of computational fluid dynamics (CFD) and field testing to improve selective catalytic reduction (SCR) unit performance.

Judging from the number and quality of the questions for both presenters, these attendees weren’t just staring at their screens. You don’t want to miss listening to recordings of the presentations all available at HRSGforum.com. They are rich in detail with a methodical sequence of illustrations for truly understanding the problems, impacts, and solutions.

Barry Dooley, a senior associate at Structural Integrity Associates Inc, whose experience dates back decades to some of the early work done at the UK’s CEGB, Ontario Hydro, and EPRI on OGE, explained how SH and RH ferritic steels like T11, T22, T5, T9, T23, and T91 are susceptible to oxide growth on inner surfaces containing greater amounts of hematite versus magnetite, which can lead to exfoliation of particles under the right thermal stresses (Fig 1). The progression of formation for different alloys, from laminations in the oxide layer to cracks to exfoliation, is well depicted in the slides.

The varying alloy compositions—chromium and molybdenum contents specifically—help determine how fast deposits grow, and the risk of exfoliation. The specific environmental factors are saturated or superheated steam, gas-turbine exhaust temperatures from 1100F to 1150F, use of duct burners, and tube temperatures ranging up to 1200F.

The deposits themselves can lead to tubes operating at higher temperatures, resulting in an ever-increasing oxide growth rate. The exfoliated material causes erosion, plugging, and sticking in valves; erosion of downstream HP and IP steam-turbine inlet-valve and steam-path components; or simply collects in a header (Fig 2). Impacts tend to show up after many thousands of operating hours but of course are aggravated by deep unit cycling and starts/stops, once the oxide reaches the critical thickness for exfoliation. Dooley shows one HRSG case in which material began to exfoliate after only 24,000 operating hours.

Unfortunately, OGE cannot be controlled through steam/water chemistry changes. It’s not dependent on O2 concentrations, but instead on O2 partial pressure. The influence of film-forming substances in the chemistry is uncertain. Shot-peened 304H and S304H SH tube alloys will exhibit a Cr-rich layer along the surface which slows the rate of exfoliation. “It’s rare for them to exfoliate,” Dooley said.

Among the insights that emerged from the Q&A session:

• • No relationship has been developed among operating parameters (for example., total operating hours, number of starts, etc) and OGE to predict its onset before impacts occur.
  • Cycle modifications which increase gas-turbine exhaust temperature raise the risk of oxide growth.
  • UT analysis can detect oxide-scale thickness but only lab metallographic analysis can reveal the characteristics of the oxide layer critical to OGE.
  • Early theorists suspected that steam/water O2 levels contributed to hematite formation, but deeper research has proved this false.
  • Small additions to the alloy, like vanadium and tungsten, will alter iron-ion migration patterns.

UPCOMING HRSG FORUM EVENTS

 

If the CCUG 2021 Day One roundtable on cold-weather preparation is any guide, winterization continues to vex plant personnel. Many of the issues can be traced to inadequate design bases and insufficient equipment. However, the root cause appears to be building “outdoor” facilities in locations which clearly require far better protection against protracted frigid conditions. Exhibit One: The tragic consequences in Ercot this past February.

For this virtual roundtable, convened in the early afternoon (Eastern time) of July 13, Steve Hilger, plant manager at Dogwood Energy (operated by NAES Corp) and a member of the Combined Cycle User Group’s steering committee, was joined by Mike Armstrong, engineering manager at Competitive Power Ventures’ Woodbridge Energy Center. Hilger’s plant is located south of Kansas City, Armstrong’s 2016-vintage combined cycle is in New Jersey about 20 miles south of New York City and near the shore. Both were designed as outdoor facilities.

Hilger’s first slide notes that the lowest ambient temperature experienced at Dogwood was -23F while the heat-trace design basis was +2F. Dogwood is two decades old and climate disruption is real, but surely this differential is better explained by designer negligence.

Woodbridge, says Armstrong, was designed to -8F but does not account for wind chill. “Most equipment, even our HRSG drums, lack enclosures, and are open to the wind.” Snow breaks and wedges were never installed on the roofs of outbuildings at Woodbridge. “Once we covered 175 valve handles to prepare for a cold weather event,” he lamented (Sidebar). Woodbridge has also added warming sheds on the top of the HRSG to keep personnel warm, and purchased several 120-Vac instrument space heaters wired to plug into outlets. These are used in transmitter boxes and ductwork with failed heaters.

Dig deeper: Heat tracing demands constant attention

Some of these temporary measures have their risks. Portable gas or propane heaters, for example, used in enclosed space elevate CO exposure to workers and present fire hazards.

The impacts aren’t solely on the equipment either. “Operators find reasons to be absent when it is cold outside,” Armstrong said. Woodbridge purchased steel-toed buck boots for winter work and makes space available in nearby motels to keep employees off the highways. We also remind them to look up for icicles in areas which may have leaks, he said, but also review work orders to identify equipment which may be leaking.

Equipment of special interest are drip-pot drains, attemperators, air filters (which can become plugged with ice), and outside air compressors, the last “a problem” at Woodbridge. “We had our heat-tracing contractor do an audit to compare design conditions to actual,” Armstrong said.

An audience member suggested that plants check for clogged drain lines using NDE. He said it takes his plant about three hours to check all HRSG drains in this way. And actions taken in other seasons, like a contractor removing heat tracing for a valve repair in summer, need to be checked.

Users struggling with winterization might spend quality time with the slides, which could be turned into a poster titled “Winter is coming” and hung in the plant’s lunch or common area. Here are a few bullet points:

• Review the 32F action plan (or prepare one if your plant doesn’t have).
• Review alarm points and operational permissives which may be impacted by cold-weather operation.
• Order bulk chemicals and review chemical properties to determine freeze points.
• Stage electric and propane heaters in problem areas.
• Develop HRSG drain procedures with valve identification in case there is only enough fuel to operate one unit.
• Perform a heat-trace audit in August/September and evaluate heat-trace insulation for deficiencies, keeping in mind that heat tracing cannot protect areas with water-soaked insulation.
• Verify calibration of all transmitters suspected of freezing or of over-heating.

With winter just over the horizon, the roundtable on winterization at the 2021 conference of the Combined Cycle Users Group was perfectly timed. There are still a few weeks, depending on your plant’s location, to implement best practices shared by colleagues from Woodbridge Energy Center, Dogwood Energy, and others.

By virtue of its location and importance to the grid, Woodbridge, a 2 × 1 7FA.05-powered combined cycle located outdoors in the Northeast, has heat-trace experience beyond that of many others in the industry. Engineering Manager Mike Armstrong represented his plant in the roundtable.

What follows are details on Woodbridge’s heat-trace initiatives, some of which were not discussed during the roundtable because of time constraints.

Get off on the right foot. Plant personnel learned during commissioning, and afterwards, that poor installation practices coupled with the lack of documentation made it difficult to troubleshoot the heat-trace system. This required staff to spend roughly 60 man-hours per week identifying and fixing issues with heat-trace circuits not functioning as designed. The poor performance of the heat-trace system jeopardized reliability and operability by allowing critical instruments and equipment to freeze-up.

Woodbridge was constructed by a single EPC contractor with multiple equipment suppliers. Design of the heat-trace system was subcontracted to a reputable supplier while installation was handled by the EPC contractor’s craft electricians, who had little or no experience with heat-trace equipment.

The various scope-of-supply boundaries and types of heat tracing proved problematic. Many field changes were required to complete the installation—changes performed without the knowledge of the designer and poorly documented.

Heat tracing was designed to maintain an equipment temperature of 40F at an ambient of -8F. The heat-trace supplier implemented the use of microprocessor-based temperature control and monitoring panels which required other new equipment—including various temperature sensors, new alarm capability, DCS integration, self-testing circuit cards, and programmable RTD outputs.

The lack of qualified oversite from the heat-trace designer during equipment installation and in preparing documentation of as-built conditions proved challenging for the plant operator once it took possession of the facility.

Dig deeper: Grid meltdown forces cold-weather prep to front burner

The first step in fixing the problem was to bring back the original heat-trace designer to audit the entire system and identify and correct any deficiencies. This required all 612 individual circuits to be reviewed to ensure the correct materials were used along with the correct installation practices. Next, all the documentation was updated to reflect as-built conditions. This information and a thorough review ensured the system was designed and installed as originally intended.

Why would NAES Corp, the largest third-party O&M services provider to combined-cycle facilities, run a three-day conference on NERC-related issues and compliance for its people and select clients and industry stakeholders? For one thing, NAES has 130 plants under its purview and supports over 100 plants outside its portfolio.

Then you might ask: Why does NAES have over 20 subject-matter experts (SMEs) in its NERC Compliance Services Group, which also includes a Compliance Testing arm? The answer: Managing NERC compliance risks for clients is a business in itself, and a key area of growth for the company. It is also considered a competitive distinction by NAES executives.

As one presenter, from a major ISO, put it, “the operations staff does not have the desire, or time, to review or interpret regulatory requirements in real time.” Put another way by another presenter, CIP (critical infrastructure protection) standards are now too complicated for the typical plant employee; many asset managers simply don’t have the experience or the background to manage NERC compliance risks.

A NAES NERC services group leader added, “NERC now has to be taken into account for any project, big or small, that has potential to impact facility output.” Scenarios he gave as examples include engine (GT) tuning, for which he listed six impacts of NERC standards; relay upgrades, which touch at least four NERC standards; and excitation control upgrades, which touch at least seven standards.

While the depth and breadth of the material presented was, well, almost overwhelming, much of it of most interest to combined-cycle owner/operators centered on EOP-011-2, recently adopted by NERC (but still in draft) addressing emergency operations and preparedness generally, and cold-weather readiness in particular.

One presenter suggested that valid bids into ISOs will be required to submit new weather-related data, such as minimum design temperatures, historical operating temperatures, and current cold-weather performance temperatures as determined by engineering analysis. EOP-011-2 includes deadlines and procedures for cold-weather preparation plans, identifying and tasking a responsible coordinator, definition of the “cold-weather period,” assessment of winter readiness, and new monitoring requirements for detecting failures, especially in heat-trace systems.

Update: There is now a Standard Authorization Request (SAR), entitled “Extreme Cold Weather Grid Operations, Preparedness, and Coordination” (Oct 6, 2021), that would add some additional requirements to EOP-011. These would include requiring annual training for generator owners and operators, detailed root-cause analyses for any freeze-related failures, and retrofit of existing generating units to operate in “extreme” weather conditions for their locations.

As one concrete impact, additional operator rounds will be required when ambient temperatures fall below certain limits, such as rounds once per shift when temperature falls below 32F, two rounds per shift when below 20F, and so on. Anything that could initiate an automatic trip should be included on these rounds. Training in cold-weather operations will have to be provided to site staff.

Reflecting, one highly experienced industry engineer advised that temperature is only part of the equation. Wind direction and velocity also are meaningful factors, he said, as are duration and current plant state (running, offline, etc). He recalled working at a facility that could run/start/operate at -20F when there was no wind. But when there was a 20-mph wind from the West it struggled at +20F. After five years of operation, staff was still ill at ease when confronted with uncommon temperature and wind combinations.

One of the presentations provided some instructive real-world cold-weather horror stories, including these:

• A 2 × 1 combined cycle in Nevada, designed with a 15F heat-trace system, experienced 7F ambient. The GT inlet bleed valves started behaving erratically, and operators were cycling through fans to keep the air-cooled condenser operating. When the cold-reheat pressure transmitter froze, it tripped the plant. One week later, the plant was able to restart.
• A 2 × 1 plant in Washington state suffered a cold snap and heavy snow. Natural-gas demand in the area overwhelmed supply lines. Ice and icicles formed. The fuel-gas system alarmed on low pressure. When the third fuel regulation station failed to operate, the unit tripped. Moisture trapped in piping froze.
• At a third facility, $100,000 worth of transmitters had to be replaced after a cold-weather event; water buildup in low points of oil feed pipes froze, and ice built up on the cooling towers because they lacked drift eliminators.

The presenter concluded with the mention of a plant which had to spend $4.5-million to be capable of running during extreme cold weather.

Among the other jewels of knowledge shared at the conference:

• Lessons at the industry level tend to get lost rather than learned. For example, Ercot experienced catastrophic cold-weather events in 1988 and 2011, and then again this past winter.
• Texas has 190 registered “generation owners”; 100 of them are new in the last five years, which means they may not be battle-tested for extreme weather events.
• The 70-member North American Generator Forum (NAGF) focuses on the NERC activity which directly affects the generator segment, and has six working groups, one of which focuses on the emerging cold-weather standard.
• NERC may create a “resilience” standard (in contrast to reliability). NAGF is busy determining the “cost of resilience,” a value to base investment on, since, according to the presenter from the group, organized markets do not support the value of resilience and the costs are born unequally among stakeholders.