The gas turbine/generator, steam turbine/generator, and HRSG get the lion’s share of attention at most user-group meetings, but one hallmark of the Combined Cycle Users Group is a focus on the connecting fluid handling equipment—pumps, valves, piping, ducting, and filters—covered in the presentations summarized below.

New challenges for filters. Headlines on the weather of course impact plant operations. Smoke and ash are plaguing facilities in the Northwest, severe weather challenges combined-cycle plants everywhere. A highly experienced plant manager, and member of the CCUG’s steering committee, led a roundtable discussion on how all this impacts filters.

Wildfire smoke particles are “really, really small” (comparable to bacterium and coronavirus particles and two orders of magnitude smaller than a grain of salt) and can pass through pre-filters and “quickly overwhelm” the filter media protecting the gas turbine. Plus, peaking units with tempering air run the risk of putting smoke particles directly into the SCR and fouling catalyst.

Planned maintenance for air inlet filters is a no-brainer, but there are materials shortages and delivery issues these days. The speaker reminded the audience that filters must be stored properly, with attention to maximum temperature for seals; auxiliary equipment like puffers should be included in PM programs.

Consider as well upgrading your pre-filters to a Minimum Efficiency Reporting Value (MERV) of 11 – 12 to trap some smoke particles and protect the final filter. One attendee recommended adding a transmitter to the DCS to monitor filter performance.

In severe cold, driving snow impacts filters, and causes ice buildup and freezing, regardless of protective hood size and configuration. Freezing of fog particles or cooling-water drift can impair filter performance in short order. It’s important to think through blockage scenarios before they occur and plan for heating panels or changes to the dispatch plan and reduced-load operation.

Boiler-feed-pump reliability. Segmental ring designs are lower first cost than barrel pumps but are less robust, said Robby Byron, Hydro Inc. They exhibit significantly less mass and therefore lower stiffness and damping, and are more susceptible to external factors (pipe strain, soft foot, tie rod’s torque value, and sequence) and hydraulic instability when operating off the best-efficiency point. Byron then detailed a case study of how a segmental ring pump exhibiting repeated catastrophic failures (that is, shaft breakage) was analyzed for root causes, then modified with engineered solutions.

One impressive result, among others: Reducing the last-stage casing gap from 0.007 to 0.008 in. to 0.001 to 0.002 in. improved pressure-carrying capacity from 2500 to 4000 psig.

Pump testing as PM tactic. A second presentation by Hydro Inc, this delivered by Ares Panagoulias, argued for certified performance testing and vibration/condition monitoring for pumps as part of a preventive-maintenance (PM) strategy, especially for plants at which “original design may not be how the plant operates today.” Difference in performance at low flow or maximum flow conditions are considerable, he said, plus impellers may have been modified, or other factors are likely affecting performance and reliability.

Hydro Inc tests the full train, motor and pump, while simulating real-world conditions. In fact, Panagoulias stated that his company was the first to be certified by the Hydraulic Institute for a full range of pump designs, and helped create the audit and inspection standards.

Panagoulias showed several slides on how pump testing relates to reliability and performance and can help assess impact of process demands on pump condition. He offered a case study of a “between bearings” pump suffering repeated failures. The proposed engineering solution was verified through performance and vibration testing, which also was used to set a baseline in a controlled environment for trending and subsequently understanding system influences.

Steam isolation valves. If you’ve ever said, or heard someone say, “flapper-type valves do not have to ‘blue’ 100%,” Jason Wheeler and Dean Casey, Mechanical Dynamics & Analysis (MD&A), beg to differ. More likely, the valves just haven’t ever been properly repaired so users accept a new normal.

Generally, check/non-return/flapper-type valves, or valves which allow flow in only one direction, are difficult to service because they operate with two centerlines which must be maintained during servicing and require special tooling that many repair shops do not keep on-hand. In addition, these valves show lots of indications from cycling service.

MD&A’s experience with these valves is additionally captured in these bullet points:

• • Because these valves are difficult to overhaul, normally just the disc and flapper-arm assemblies are removed and sent to the shop for inspection.
  • Some valve shafts are prone to bending.
  • The integral valve seats can distort through years of cycling.
  • Most companies are “thrilled” to get 80% blue contact at the seat during reassembly.

Wheeler and Casey then proceeded through an inspection and repair case study for a Westinghouse reheat flapper type valve, which can be of an articulated or rigid disc design, with photos illustrating each step in the process onsite and in the shop.

Valve maintenance program. To eliminate a costly reactive maintenance posture, a 3 × 1 501G-powered combined cycle partnered with Millennium Power Services, to track valve performance and health and prioritize maintenance. The service provider follows all industry valve repair standards, keeps the plant informed at all times, transmits photos of damage, and issues reports within 30 days of an outage.

Among the program features discussed by the plant’s O&M manager is Millennium’s TrimKit program (Fig 1), which reduces costs and labor by having all new parts for specific valves arrive in one “suitcase.” This allows all parties to keep better control over inventory.

In response to an audience question, the speaker said the scope includes all severe-service valves, “really everything repaired during each outage,” except for the steam turbine valves, which are serviced by the turbine OEM. However, TrimKits are not necessarily available for every valve, he added.

Covered steam piping. Madeleine Fink, HRST Inc, reviewed ASME standard B31.1, “Covered Piping Systems,” which includes specific creep-regime requirements. She focused much of her talk on scope of the standard, “overlooked Code requirements,” common problem areas, and case studies.

Frequently overlooked requirements include written O&M procedures covering topics mandated by the Code, review of dynamic events since the last condition assessment, and record-keeping—including procedures, drawings, findings, material history, failure analysis, etc. Support documentation and maintenance are not limited to spring supports, Fink cautions, but include all supports.

The listed common problem areas for combined cycles are:

• • Areas undergoing thermal stresses, especially during transient operations—such as bypass valves and attemperator piping.
  • Areas of highest stress and temperature at risk of creep damage—including under-supported areas, over-constrained areas, piping susceptible to thermal cycles, and thermal stresses at dissimilar-metal welds or piping-thickness changes.
  • Attemperator spools, large valve bodies (stop valves, for example), branch welds, undrainable low points, and transition from HRSG OEM scope to piping scope

You’ll want to review Fink’s four richly detailed case studies, covering an HRSG interstage attemperator serving a G-class, 2001-vintage gas turbine; a spray-water line to a bypass valve for an HRSG at a 2010-vintage LM6000-powered cycling plant; h-p interstage piping at a 2004-vintage G-class unit exhibiting vibration issues; and creep damage at a P91-P22 dissimilar metal weld on a HRSG.

Underground pipe inspection. “After eight years with no visual inspection,” said the plant engineer for a combined-cycle plant, “we found oscillating vibration on one of our cooling-water (CW) pumps and decided to pull it for inspection.” It turned out that the cast-iron impeller had severe erosion, the root cause being the wrong material being selected in the first place. It was replaced with a stainless-steel impeller, and rebalanced with stiffeners added to the upright pump support. No visible damage has been exhibited after five years of service.

The plant took the opportunity to conduct an inspection of the CW piping. The slides included in the presentation are a veritable tutorial with critical bulleted checklists on these topics:

• • Planning for safety and timing (including restricting exhaust-emitting equipment from accessing the area).
  • Tools and aids (don’t forget your rock, or geologist’s hammer and an extra radio).
  • What to look for during the inspection (including valve internals).
  • Notes of caution, such as not allowing heavy loads to cross where the piping is buried.

Duct liner plates. As Ryan Sachetti, CEO of Industrial Air Flow Dynamics Inc, reminded the audience, a liner plate is any internal duct/piping steel that “touches” the gas path directly, usually the insulation and protection systems. Hot spots identified from external thermography are “the first-line indication of heat getting in behind the liner system.” Inside when offline and cool, look for broken hardware, fallen washers, spongy or soft sections when you push against the material, large gaps between plates, and exposed insulation. Analyze for root cause before you select a repair or upgrade option, the latter necessary if gas-turbine performance has been enhanced.

As if the photos of failures and subsequent repaired and upgraded areas weren’t enough, the presentation also includes a not-to-be missed video of a “complete liner failure.” The repair/upgrade photos tell the story of liners ready for years of future service, at least one (Fig 2) in which you can visualize astronauts comfortably floating inside a la “2001: A Space Odyssey.”

During the QA/QC Roundtable at the Combined Cycle Users Group’s 2021 virtual conference, led by steering-committee members Jonathan Miller, maintenance manager at Cleco’s Arcadia Power Station, and Ben Stanley, plant manager of DGC Operations’ CPV Valley Energy Center, the facilitators conducted two polls.

When asked if their facility had a formal plan for welding contractor QA/QC, 13.4% of the audience said “yes,” 14.2% said “no”; the others did not answer. When asked if they used a third-party QA/QC service to monitor contractors, 16.4% said “yes,” 11.9% said “no,” and 71.6% did not answer. However, since there were about 140 attendees at that point, more than one quarter did respond, so the sample size isn’t trivial.

Quotes from the audience suggest those who answered in the negative to both questions may wish to get their leadership to reconsider the value of having a formal QA/QC plan:

• • “We’ve found valves welded in backwards!”
  • “Our sites have often had 100% dropouts of ‘certified’ welders who show up but can’t pass a performance test.”
  • “We’ve had a contractor cut out equipment even before the appropriate measurements have been made.”
  •  “The foreman of a contractor crew, on whom we depend for the QA/QC, got Covid, and workers were not following procedures without the foreman’s supervision.”
  • We’ve had major problems with failed welds on 12-in. P91 HRSG steam headers.”

The accompanying slides, available to registered users on the Power Users website [link] implied that these aren’t isolated incidents; many plants are suffering from poor weld quality, repeat work at failed weld locations, and general rework. Roundtable leaders suggested having a formal QA/QC oversight process, or making your existing one more robust, with these elements: pre-planning, implementation, and completion/verification (Sidebar).

The details involve mostly common sense—and include the following: verify proper materials are being used and include drawings and manufacturers’ data report on pressure vessels (U1A form) during preplan; verify contractor welding procedure specifications (WPS), work breakdown structures (WBS), and procedure qualification records (PQR) during implementation phase; and review NDE and post-weld heat-treatment reports to verify completed work.

The important thing is to formalize, checklist, and document that the proper steps have been taken and confirmed with written or digital records.

Valuable contributions from audience members included these:

• • Use a PMI (positive material identification) machine to verify alloys.
  • Have stores verify that materials arriving onsite match the materials data sheets before accepting.
  • Check transmitters from overseas for cybersecurity issues.
  • Require that plans be developed in collaboration between contractors and site personnel to ensure that scope of work is aligned.
  • Consider either hiring a third-party QA/QC contractor or certifying one of the site staff for this function, increasing their compensation if necessary.

A representative from one of the largest combined-cycle owner/operators noted that his company pre-tests all welders coming onsite even though they have certifications. The weld performance tests include a plate test, a bend test, a monster or super coupon test, and a coupon-9Cr wire test. Regarding the last, the rep said that welders might be qualified on carbon steel but not higher-alloy materials. He said, “9Cr material flows much faster and easier.

Safety time out: Review this

Checklist before proceeding

Safety is a perennial favorite topic at the Combined Cycle Users Group (CCUG) for obvious reasons and at least one non-obvious one: With declining staff at sites, each person is responsible for more, and more varied, tasks. Chances for human error grow. While the safety issues addressed here are very site-specific, the take-away should more be a gentle reminder about anything similar at your plant.

Chemical handling. Marih Salvat, Operations Manager, Tenaska Virginia Generating Station (and member of the CCUG Steering Committee), said they “overhauled chemical handling and safety” to avoid wearing full PPE (personnel protection equipment) when not necessary. Because low and high risk chemicals were often handled near each other, policy was to default to the most restrictive PPE for containment areas. Now, the plant separates high risk areas from nearby low risk areas using plexiglass curtains and safety shields (figure).

Access, lighting, fall risks. Robert Mash, Plant Manager, GE Power Services for River Road Generating station (also a steering committee member), opened with a tale of an intruder (non-malicious apparently) who breached the perimeter fence and entered the unsecured transformer yard fencing, which prompted several upgrades for access and control, including electronic card reader access (tied into the existing access control system), and tamper-resistant emergency exit crash bars to manway gate doors on the east and west side of the yard.

Previously, the transformer yard, where the generator breaker and step-up transformers, generator excitation and LCI systems, and other critical plant equipment were located, was thought secure because it was inside the perimeter fence. The yard is accessed at least four times a day for routine equipment checks.

In response to an audience question, Mash said there was nothing wrong with the fencing, but they did add security cameras as well.

Then Mash identified with photos several potential fall hazards and remedies around the HRSG, including insufficient handrail/guardrails in areas where critical work is performed. This was followed by a review of lighting system additions in areas like the gas yard, behind the cooling tower, and turbine transition to HRSG. All existing lights were replaced with LEDs in 2017; the assessment of additional lighting needs followed.

Readers are urged to link to the actual presentations to view the before and after lighting and railing photos, only one of which is shown here (figure).

During the Q&A period, attendees and presenters discussed upgrading intercom systems. One plant rep said they were currently reviewing the existing system. Another mentioned that some folks have a hard time hearing the lightning alerts. A third reported that all people on their site were required to have radios, with “extenders” installed to cover the entire plant. At the “all-hands” monthly meetings, personnel are re-familiarized with the sounds and what they signify at still another facility.

Finally, a user mentioned “lone worker” or “man down” devices for low-staff sites – these are clips workers wear and can indicate whether a worker is “not active,” i.e., snoozing or non-responsive, with a signal transmitted to the 9-1-1 system. This was tested at their plant and “works well.”

www.ccj-online.com/issue-55/11nmc-best-practices-orlando-cogen

Amine skid is separated from phosphates handling area so PPE appropriate to each area can be used

GE Day during the Combined Cycle Users Group (CCUG) 2021 virtual conference began with a glimpse into the next 20-30 years of combined-cycle facility operations and ended with a tutorial in using historical data to trend the last 20 years of a plant’s operation. In-between were deep dives into BOP plant impacts from gas turbine (GT) technology upgrades and aggressive operating tempos, followed by solutions for those impacts on HRSGs, generators, and steam turbines.

The overarching message was that GE has the depth and breadth of expertise to, essentially, be your partner and keep you on-mission, in-market, and thriving, regardless of what challenges your plant faces in the coming years.

Think of it this way. If your primary-care physician designed your body and manufactured its components, you’d probably have a high level of trust that he/she could maintain it. As the OEM for the GT/generator, HRSG, and steam turbine (ST)/generator at many combined-cycle facilities worldwide, GE wants you to know that they have the fleet performance data, specialists who can analyze your plant-specific operating data, diagnostic capabilities, manufacturing capacity for replacement components, repair procedures, and technology upgrades to keep your plant surviving and thriving into the future.

Jeff Chann, business intelligence leader, talked about the realities of “obsessive carbon management” in the political and cultural realms and the inevitability of converting some of today’s GTs to burn different levels of hydrogen. He gave a candid review of the pros and cons of hydrogen and the need for carbon capture and storage if the hydrogen is produced through steam reforming rather than electrolysis powered by surplus renewable electricity and “really clean water.”

Example: The largest installed hydrogen storage facility in the US would be emptied in eight hours by an H- or J-class GT. Takeaway: The accompanying hydrogen production, storage, and delivery infrastructure need to be built out.

Chann rallied the audience by noting “existing plants will have to stick around longer to help” with the transition to a low-/no-carbon electricity future and that “we’re the ones with the technical expertise to enable hydrogen.” Queen’s “We are the Champions” could have been playing in the background.

Evaluating plant impacts. John Sholes, principal engineer, divided plant impacts into short-term (this year), mid-term (next major outage), and long-term (game-changer GT technology infusion). Examples:

• • Long-term—full AGP upgrade for hot-day peaks and cold-day performance, along with identifying and addressing BOP (cooling tower, GSU/transformer, attemperator valves) limitations (Fig 1).
  • Short-term—modifying controls and upgrading the attemperator to achieve 80% turndown (60% is considered typical for low-load operating plants today).
  • Mid-term—upgrading the combustor with advanced gas path (AGP) technology and extended-turndown valves for the attemperator.

Matt Matthews, project engineering manager, delivered a case study of a winter-peak plant upgrade, timely given the catastrophic Ercot grid-wide winter outage this past February. Objective for this Ercot-based plant customer was a risk assessment targeting cold-plant operation. Matthews described the uprate as involving relatively small changes, such as boosting generator output by increasing hydrogen coolant pressure and higher horsepower motors for the boiler feedwater pumps. The plant will begin operations with the upgrades in the first quarter of 2022.

Harp replacements. Vasileios Kalos, platform leader, HRSG Services, cautioned the audience that off-spec operating conditions like sustained low-load operation and aggressive cycling accelerate life consumption of HRSG pressure parts. PPs operating under such conditions require more inspections and more repairs. Users considering replacing pressure parts need to think in terms of 12-month lead times and planning for “intensive field resources,” such as large cranes, and even temporary preservation of PPs onsite for up to 12 months.

Kalos supported his presentation with four case studies:

• • Working with a user to create a “value story” for an HP evaporator replacement.
  • Replacing HP evaporator and economizer harps damaged by a hydrotest. (Lesson learned: You can’t perform a 10-yr hydrotest on an older unit as if it were brand new.)
  • Replacing HP superheater and reheater harps during a GT upgrade to extend HRSG life.  Extensive cracking was discovered after 20 years of operation and daily start/stops.
  • Replacing HP and IP economizer and evaporator harps damaged by corrosion because of improper preservation of pressure parts. User anticipated tube leaks and frequent forced outages as a result.

Generator lifecycle. Ian Hughes, principal engineer, Fleet Management, reviewed recommended maintenance and rewinds to avoid generator forced outages. To drive his main points home, Hughes noted that a planned stator rewind typically takes 28 days. Double that for an unplanned one.

Unplanned rewinds (Fig 2) are increasing, having doubled since 2011, he said, because of, you guessed it, larger load swings, more load swings, greater number of starts/stops, and time units are on turning gear. Generally, GE is not able to pinpoint the root cause of these rewind outages; years in service is the best predictor of need for a rewind.

Hughes dwelled on core step-iron damage at the turbine end for 7FH2 units shipped between 2001 and 2003, the subject of TIL-2260, including some outlier finds of missing teeth. These units represent 6% of the fleet. This type of damage is generally found on the GT generators, not the ST unit. He further noted that there are eight different design versions of the 7FH2 generator, and some of the components are not interchangeable.

Perhaps the most important part of Hughes’ talk was that the 1999-2002 GT supply bubble has led to a “rewind bubble” currently. By 2024, rewinding needs will exceed industry capacity, Hughes warned. GE has some exchange rotor fields for swap-outs but not many. He advised users to have stator and rotor bars “on-hand” as GE cannot, from a business perspective, carry too much inventory. “We have to shave the peak of this bubble,” he cautioned.

GE recommends flux-probe and PDA tests prior to an outage to detect potential damage and at least a one-year planning cycle for rotor/stator rewinds. GE also offers several M&D packages for generators which range from twice yearly inspections to 24/7/365 remote monitoring.

Cycling impacts on steam turbines. Matt Foreman, platform leader, Combined-Cycle Steam Turbine Services, carried on by reviewing the many ways cycling operations impact the steam turbine lifecycle (Fig 3). Major takeaway: Most ST components are “made to order,” only the last-stage blades have commonality, few components are stocked, and you should figure on an 18-month planning cycle prior to an outage. Regular inspection and maintenance are key to avoiding outage-inducing surprises.

Caught early, minor cracks, such as found in highly stressed components like main steam control valves, can be addressed through “grind and blend” repair techniques. As for a current common issue, diaphragm dishing,“ GE has been dealing with dishing for a long time in the D11 fleet,” Foreman said. However, he mentioned a relatively new impact—axial shell creep moving diaphragms downstream.

An important aspect of Foreman’s slides came at the end, when he showed several graphs (Fig 4) of long-term operating data (from the inception of commercial ops), and how data analysis also can identify minor issues before they become big ones. “Each unit has a unique operating history, and data mining can reveal trends important to a predictive maintenance strategy,” Foreman said.

A quick search of the CCJ’s editorial archives [link] shows how much arc-flash safety is on the minds of owner/operators, especially in the best practices category. Whether you have a formal arc-flash safety program or not at your facility, there’s still much to be gained by listening to Aaron Neuvert’s presentation on this important topic at the Combined Cycle Users Group’s 2021 virtual conference, available on the Power Users website. [link]

His company has incorporated the relevant OSHA, National Fire Protection Association (NFPA), IEEE, and state standards to create its own program which “summarizes and simplifies [these standards] for practical application.” The presenter’s commentary substantially expands on the content of the slides.

Arc flashes are low-frequency, high-impact events but their occurrence is increasing industry-wide. About 2.5% of arc-flash incidents result in the death of a worker; 95% are caused by human error, so training and strictly adhering to, and updating, best practices are critical. Clear and proper labeling is vital, as is the use of the proper personnel protective equipment (PPE), both areas of the standards which have been updated recently.

A few main points:

• • An open-air arc in a switchyard or a powerline may be more dramatic, but arch flashes in a contained space (arc in a box) are much more dangerous because the energy has only one path—towards the opening.
  • Stay away from ground cables and ask the question, “Can a ground cable withstand the faults the manufacturer claims it can?”
  • New best practices are coming into play, based on recalculation of so-called minimum approach distances (MAD).
  • When modeling for boundary protection, test for equipment voltage, rather than rely on rated design data from the supplier.
  • The arc-flash boundary becomes effective only when hazardous tasks (table) are being performed on or around the equipment.
  • Always wear flame-resistant clothing when working around equipment prone to arc flash.

An audience member asked for thoughts on arc flash for dc equipment. The speaker responded that they are only starting to test dc systems; not enough is known about them yet, but he expects updates to industry practices within the next five years.

Long term, Neuvert projected, the solution is to become a “remote-racking” organization and use robotic devices which “take the employee out of the hazardous area.”

[TABLE]

Tasks for which the arc-flash boundary becomes engaged

• • Any activity that increases the chance of a fault condition.
  • Anytime the MAD is breached by a body part or uninsulated tool.
  • Working on energized electrical conductors and circuit parts.
  • Performing voltage testing.
  • Racking potential transformer (PT) trays.
  • Installing or removing protective grounds.
  • Racking breakers into or out of energized compartments while within the arc-flash boundary.
  • Installing or removing temporary barriers that are in direct contact with exposed live parts.
  • Installing or removing bolted covers near exposed energized parts.
  • Installing or removing buckets from energized motor control centers that are not equipped with integrated arc-flash safety features.

• • Manually operating breakers, switches, or disconnects.
  • Opening hinged covers on cabinets or panels that contain exposed energized parts.
  • Installing or removing fuses.
  • Working on control circuits with exposed energized electrical conductors and circuit parts greater than 120 V.

• • Opening voltage transformer or control power-transformer compartments.

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.

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, [link to www.powerusers.org] 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.

As severe weather events grow make sure your ACC keeps up

Whether you call it “weather” or “climate,” severe weather events are increasing in both number and severity, which means hot and cold days may be more intense and more frequent, regions surrounding your plant may be ravaged by fires and smoke, and ice and snow events may be more prolonged. Remember, your air-cooled condenser (ACC) is inhaling whatever is in the air and, like your lungs, bad stuff is being deposited on its heat-transfer surfaces.

All these are excellent reasons to spend an hour viewing the webinar conducted in late September by Conco Services LLC on ACC cleaning and leak detection. Fouled tubes can rob a plant of performance, especially on hot days; a 20% loss of air flow across the tubes leads to a 33% increase in turbine backpressure on a vacuum steam system, reminded Gary Fischer, national sales manager and presenter.

Thoroughly cleaning tubes with an automated water wash system (amply detailed in the presentation) can add 15 to 18 MW of output for the example given. One plant in the UK pegged its weekly savings at over $18,000.

Regarding leaks, Fischer told his audience that higher levels of tube leakage are observed at sites prone to freezing conditions, especially when the winds come from the same direction most of the winter. Ercot’s catastrophic grid meltdown in February, focusing the industry’s attention on winterization, should be motivation enough to make sure your ACC is ready for winter. Consider helium-based tube leak detection done by pros to be part of that preparation.

Fischer’s presentation is available in the recorded webinars section of CCJ’s website. For prep, you may want to quickly review the summary of last year’s Conco presentation on the same subjects in CCJ No. 65 (2021) p 66.

[CAPTION]

1. Automated online cleaning system is set up on a typical air-cooled condenser

The Combined Cycle Users Group (CCUG) opened Day One of its 2021 virtual conference with a roundtable discussion on confined-space safety. Arguably, it’s a topic perhaps even more essential to onsite staff as other responsibilities shift to offsite personnel, contractors, and OEM reps.

The discussion was facilitated by Steve Hilger, plant manager at Dogwood Energy (operated by NAES); Jonathan Miller, maintenance manager at Cleco’s Acadia Power Station; and Aaron Kitzmiller, plant engineer at Luminant’s Fayette Power Plant. All three serve on the CCUG steering committee.

Surprisingly, there is no accepted way to classify “confined space.” The OSHA definition, for compliance purposes, has three criteria: space is large enough and configured so that a worker can enter bodily, has limited or restricted means for entry or exit, and is not designed for continuous employee occupancy. The gray areas here were underscored by the fact that the representatives of these three facilities “saw things differently.”

One of the panelist’s noted that many process plants classify all enclosed spaces as confined. In other words, they do not distinguish between a permit-required or non-permit-required confined space.

Much of the discussion focused on three options for rescue teams: third party offsite, trained onsite, and local fire department. There are pros and cons with each. Examples: the local fire department is experienced with rescue events but may not be able to respond in a timely manner, typically within 15 minutes; an onsite team may be most familiar with the facility but the additional responsibilities may be a burden on shrinking staffs; and a third-party team may have its own equipment but not able to respond on short notice.

The panelists created a list of “possible best practices”:

• • Sign in and out for all (permit and non-permit) confined space work—described as a nuisance but necessary.
  • At least one continuous air monitor per team in a confined space.
  • Create and review the rescue plan before entry.
  • Document the time-weighted average personal air sampling pump readings when welding, to understand potential for contaminants.
  • Use “Rite in the Rain” or equivalent all-weather paper to print permit materials and avoid the problems associated with using off-the-shelf paper when it gets wet.
  • Invite local fire department personnel to the site to get familiar with the spaces.
  • Use tubes (familiar in real estate) with labels and rare earth magnets to house confined space permits.
  • Step through “what ifs” before starting the project.
  • Test communication devices.

A few best practices which might be added based on the Q&A accompanying this session are the following:

• • Make sure contractors understand the distinction between permit- and non-permit-required confined spaces, and defer to the more rigorous one.
  • Perform audits on confined spaces early in the outage.
  • Know where everyone is working to avoid issues with falling objects.

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Site map helps track confined-space status

Dogwood Energy has proactively shared its safety best practices with colleagues for years via CCJ’s editorial pages. One, not discussed in detail during the confined-space roundtable but worth revisiting here, is described below. It protects against entry into a confined space after LOTO clearance. The example given was an HRSG door left open following an outage.

Dogwood has over 150 confined spaces to keep track of, challenging the responsible individuals. Michael Davis, a control room operator (CRO) and a member of the plant’s safety committee, advocated for a visual way to account for confined-space status in the control room. After reviewing different ways to keep an eye on the confined spaces, he noticed that most of the solutions relied on technology that increased costs as well as the workload of the CRO. Davis focused his task on finding a low-risk, low-cost, low-technology, high-results outcome.

His idea was to create a site map showing the major equipment and some of the underground systems on a white magnetic board that included all the plant confined spaces. This map would be in the control room above the LOTO cabinet (photo).

Davis worked with NAES drafting to develop a simplified site plan for the Missouri plant. In addition to the major equipment and underground information, the 45 × 45-in. map also includes the following:

• • Safety showers in green.
  • Tornado shelters.
  • Water storage tanks and capacities.
  • Manholes with system identification and numbers.
  • Electrical manways.
  • Hazardous chemical locations.

For work requiring entry into a confined space, the CRO moves the magnetic label for the associated confined space from the label storage board (right of the window in the photo) to the left-hand side of the site map and then places a red magnetic dot at the location of the confined space on the map.

This provides Dogwood personnel a visual of the approximate location of open confined spaces at any given time. After a confined space has been closed and returned to its normal state, the label and dot are removed and returned to the storage board. Keeping the process simple enables its success.

The map also provides a visual representation of the plant to facilitate discussions among plant personnel and contractors and to show evacuation routes and muster points, and all door swings.

The confined-space map, in use for well over a year, is a safety and awareness win for both employees and contractors.

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Confined-space map is mounted above LOTO cabinet and alongside the label storage board

An international user writes via the forum, We have a horizontal dual-pressure HRSG (Alstom India) with bypass stack and diverter damper. A recent inspection of the HP section found that some tubes and face plates were “sagging” (photos). Those tubes are misaligned because of this. The same observation was made during the previous inspection, with no further deviation observed. 

Kindly review the pictures and advise if there is any standard or comparison document to benchmark the acceptable level of sagging/deflection in HRSG superheater tubes. Thanks for the help in advance, HB.

HB: The bowing (you called it sagging) of tubes such as this is caused by water passing through and quenching (shrinking) these tubes while other tubes remain dry and hot. The water typically arrives from the attemperator, but can also come from undrained pipework or headers (manifolds in the case of the Alstom HRSG). There is no standard that I am aware of regarding the acceptable degree of bowing.

When bowing is severe, it creates large gaps between tubes, allowing bypass of exhaust gas, or permits adjacent tubes to contact each other. In such cases, the bowing generally is considered in need of correction. However, the degree of bowing in your photo does not look severe.

It is also typical not to be concerned about future problems being caused by bowing if it is moderate and not getting worse over time (as in your case). However, consider that the water causing the bowing may accelerate thermal fatigue damage in welds between interconnection piping and headers/manifolds. This can be a particular problem in the Alstom design.

The more important issue is where did the water come from and during what operating condition. A common source of the water is leaking attemperator spray when the tubes are hot with little or no steam flow (such as during startup and following shutdown).

Another source/event is overspray of the attemperator during startup, shutdown, and/or during low-load operation. If the steam temperature downstream of the attemperator drops below 50 deg F above saturation, overspray is occurring. The closer the steam temperature downstream of the attemperator is to the saturation temperature, the more damage that occurs in the tubes, headers, manifolds, and interconnecting piping.

Another source of water is the owner failing to ensure that superheater and reheater pipework, manifolds, and headers are completely drained of condensate and leaking spray water prior to initiation of steam flow during each startup.

Repeated water-quenching events may not result in increasing degrees of tube bowing if later thermal transients are not more severe than the initial transient that first caused the tube to bow. However, each repeated thermal transient does cause additional thermal fatigue damage in pipework to manifold/header welds and will eventually result in cracks. Thus, it is very important to identify why and when the thermal transients occur and apply corrective actions promptly.

I routinely identify thermal transients and their causes, then suggest the necessary corrective actions for owners of HRSGs around the world. To dig deeper, find several papers and articles on the subject on my website at www.CompetitivePowerResources.US.

Calling it “safer, faster, and deeper” than dry-ice blasting, Jeff Bause, CEO, Groome Industrial Service Group, introduced participants in the 2021 virtual conference of the Combined Cycle Users Group to KinetiClean HRSG tube cleaning, a patented kinetic shockwave technique widely used in other industries but new to combined cycles. It was developed by Explosive Professionals Inc. (ExPro), a detonation-based cleaning services firm with decades of industry experience.

Only a few weeks after his July 27 CCUG presentation, Bause announced on September 7 that Groome had acquired ExPro, uniting the latter’s patented processes and Groome’s 50-plus-year history in providing premium powerplant services—many identified with the hot-gas path in gas-turbine-powered simple- and combined-cycle plants. ExPro executives Brad McGinnis (President/CEO) and Rod Hall (Executive VP) have transitioned to the Groome team, bringing the skills and expertise honed at the 26-yr-old company to increase the number of critical service options available to owner/operators.

One of the stated competitive advantages of KinetiClean over alternative tube-cleaning techniques is that some of the work involved—such as the placement of detonation (a/k/a det) cord—can be performed while other outage work proceeds in parallel.  Additionally, limited to no scaffolding is required for this process.

KinetiClean is a three-step process. First, the shock waves created by the det cord curtain dislodges deposits from the HRSG’s finned tubes, then compressed air removes any loosened deposits that remain, and finally, the floor of the HRSG is vacuumed clean.

The process begins with the installation of det cord, described as a flexible textile jacket encasing PETN which is an extremely stable powder plastic explosive. Simply, a curtain of det cord, spaced 12 to 18 in. apart between tube bundles, extends the length of the finned tubes to be cleaned (photo montage). Det-cord acing is based on the nature and volume of foulant as determined by ExPro. The det cord curtain is only armed when the blasting caps are introduced.

When the cord detonates along its length at a velocity of about 23,000 ft/sec (optimal for hard deposits), the ensuing shock waves remove debris from tube surfaces and fins. Importantly, no detonation material or tools touch any HRSG internal surfaces.

Next, patented air vestibule machines remove loosened debris that settled on fins below with high volume/high pressure air. The machine is digitally programmable to ensure full tube-bundle coverage. Once all debris has been removed from the fins, vac trucks are utilized to collect the material from the HRSG floor.  The primary focus of this turnkey operation is to mitigate the chance of any opacity issues upon startup.  A typical job takes six to eight 12-hr shifts to complete, meaning the cleaning of an F-class HRSG is a three- or four-day project.

Knowing that the mention of explosives was likely to send palpitations to the collective heart of the audience, Bause included as one of his first slides a record of the industry’s safety and training record—specifically, no reportable incidences, lost time, or fatalities over the last three years, each representing close to 30,000 hours of work. A crew of seven typically does the work, including one licensed blaster.

Bause gave several case studies to wrap up, each exhibiting four to six tons of material removed and a 4- to 5-in.-H2O differential-pressure improvement. During one site’s work, damper repair work was conducted in parallel. Other slides quantify the general benefits of tube cleaning, although few combined-cycle personnel need any convincing on that front.

During the Q&A, attendees learned that 30 minutes following detonation, workers can enter the HRSG; noise levels are not expected to impact neighbors; that the technique is effective at removing ammonium bisulfate deposits; and the technique is not recommended for catalyst cleaning, although the patented air vestibule machine could be adapted for non-scaffold cleaning of the SCR catalyst at some point in the future.