Shepard: Identifying design issues mitigates icing problems in the inlet filter house

By Team-CCJ | February 18, 2022 | 0 Comments

Shepard Energy Centre

Owned by Enmax and Capital Power
Operated by NAES Corp

860-MW, gas-fired, 2 × 1 combined cycle powered by M501G1 gas turbines and located in Calgary, Alta, Canada

Plant manager: Terence Dumonceau

Challenge. To protect against ice formation on inlet guide vanes (IGVs) and Row 1 compressor blades during cold-weather operation, the plant was designed with inlet glycol heating and a compressor bleed air system (Fig 1).

Early in the plant’s operation, staff observed that during low ambient temperatures and high humidity conditions, ice would form on the leading edge of the finned glycol heating coils. The gas-turbine control system limited the compressor bleed air system to operation at part load, thereby preventing the system from assisting with icing issues at base load. Even at part load, the nozzle distribution and resulting flow pattern were only able to prevent ice from forming in localized areas downstream of each nozzle.

To prevent the ice from choking air flow to the gas turbine (Fig 2), the plant operations team scraped the face of the glycol heating coils. This had to be done continuously until the ambient conditions changed. Such events were experienced on a weekly basis over the course of the winter, with a typical event lasting between two and eight hours. In severe conditions, scraping was unable to mitigate the ice formation and the gas turbines would be derated.

Over the first three winters of operation, 6.3 GWh were lost because of derates, with an estimated 56 GWh of cumulative derates avoided by the scraping efforts of O&M personnel. Plus, to mitigate icing, the heating coils often were operated at full capacity which increased the gas-turbine inlet temperature by up to 22 deg F above ambient and significantly reduced gas-turbine output. And as these events were related to cold weather, they would coincide with high power prices, which magnified the impact to the plant.

Solution. To further understand the issue and begin working toward a resolution, the plant commissioned a study to assess design documentation, review historical operating data, conduct a site survey, collect field data, and perform CFD modeling (Fig 3). It found the root cause of the glycol coil icing to be the materials of construction. The original coils were made of stainless steel having a poor thermal conductivity. CFD modeling showed that the temperature of the leading edges of the fins were expected to increase by only about 4 deg F above that of the ambient air. Issue identified, multiple options were proposed for permanent resolution.

Option 1: Swap the glycol flow direction from counterflow to parallel flow.

Calculations proved this method to be ineffective. Limited by the thermal conductivity of the stainless steel, even providing hot glycol to the front face of the heating coil was predicted to only result in a 7 deg F increase above ambient.

Option 2: Install an infrared heating system upstream of the glycol heating coils.

Although technically feasible, the high implementation cost and significant electrical load requirement of 600 kW per unit was difficult to justify.

Option 3: Revise control logic to enable use of compressor bleed air at base load.

Control logic changes were evaluated with the gas-turbine OEM. However, use of the bleed air system at base load was not desirable as the primary resolution because of its negative impact on output and heat rate. To properly mitigate the icing issue, the nozzle arrangement and resulting flow pattern would have to be addressed as well.

Option 4: Replace the existing heating coils with ones of copper/aluminum construction.

Despite the coils not being designed for replacement, a cost/benefit analysis supported this as the preferred option.

Implementation. A specification was developed for the replacement heating coils which included copper tubes and aluminum fins with a protective coating. The replacement coils were then procured though a public bid process.

In parallel, the plant team prepared for the complex task of swapping the heating coils through development of a detailed installation plan. This plan was executed during a scheduled gas-turbine outage, which included engineered scaffolding, mobile crane, jack-and-roll system, and over 2000 man-hours. All 12 coils (six left-hand and six right-hand) were safely replaced on schedule within a six-day window.

Results. The performance of the new coils has been validated during multiple icing events (Fig 4). The project has a forecasted payback period of less than five years. With the observed success, the plant is currently proceeding with plans to complete the heating coil replacement on its second gas turbine.

Project participants: Mike Sterling and Shane Bucar, with support from AAF and Camfil.

Middletown: Plant cold-weather operations

By Team-CCJ | February 18, 2022 | 0 Comments

Middletown Energy Center

Owned by NTE LLC 
Operated by NAES Corp 

475-MW, gas-fired, 1 × 1 M501GAC-powered combined cycle located in Middletown, Ohio

Plant manager: Dino Padilha

 

Challenge. Middletown Energy Center faced no operational challenges during its first six months in the PJM market, achieving high reliability during that period. However, it faced freeze-protection issues during the first winter and tripped several times—adversely impacting plant performance. It was imperative that the plant identify and correct the problems to assure reliable and safe operation in future winters.

Looking into the issues that affected the plant during its first winter, staff identified the following four causes:

    • Improper installation of insulation.
    • Failing heat tracing.
    • Improper heat tracing for the application.
    • Inadequate monitoring to allow proactive action.

Once a problem occurred and the plant tripped, it was difficult for O&M personnel to identify all issues that had to be addressed quickly. Separating the problems and analyzing the issues, the plant identified the following main areas to focus on:

    • Several heat-traced lines lost protection because the type of tracing used failed at high temperature. Thermostats were required to sense line temperature and turn off the tracing to avoid overheating. When the thermostats failed, the heat tracing turned off and the lines were left unprotected, leading entire lines to freeze.
    • The instruments themselves had no temperature monitoring inside their boxes, so if the local heater failed, the transmitter would freeze, potentially leading to a plant trip.
    • Several issues with the insulation itself rendered the installed heat tracing inadequate for some lines.
    • After a problem occurred, there was no indication for the troubleshooting team to focus efforts to correct them.
    • Boiler-feedwater-pump lube-oil heater was not able to maintain specified oil temperatures during cold days leading oil pressure to increase because of high viscosity, sometimes causing the pump—and possibly the plant—to trip.

Solution. Separating the issues in these areas, plant personnel started to define action plans to improve operations and prevent the problems from recurring. Heat-trace protection was the primary focus of staff efforts. Whenever a thermostat failed, an entire line would become unprotected leading to severe impacts on plant operations.

Plan was to replace the existing temperature-sensitive self-regulating (SR) cables with heat-tolerant mineral-insulated (MI) cables that did not require thermostat protection. Thus, heat tracing could be turned on and off based on ambient temperature. The new MI cables covered the tap-root connections of the instruments, assuring these areas also would be protected against freezing.

This was an extensive project with 55 lines (over 7000 ft) requiring upgrade of heat tracing, plus insulation. An additional benefit of the upgrade: Insulation of areas ignored by the original design.

After addressing the issues associated with heat tracing, thermostats, and insulation, staff provided operators the tools both to monitor the health of the heat-trace system while the unit is in service and to alert on possible problems by implementing capabilities incorporated into the plant’s Ovation asset management system (AMS). Note that the Ovation DCS operates in conjunction with Mitsubishi’s NetMation gas-turbine controls and Toshiba’s TosMap steam-turbine controls.

Standard information from a transmitter in the field is passed to the DCS system using 4-20-mA signals. Using the Hart communications protocol connected locally at each transmitter, the AMS signal can talk to all transmitters at specific intervals to gather more information—that is, instead of the transmitter just sending pressure, for example, it also tells you how healthy the transmitter is and much additional useful information.

This information is used primarily for obtaining temperatures within an instrument enclosure to warn of impending freeze conditions, possibly saving the plant from a hard trip. In addition to the newly created alarms, the plant also developed a DCS screen with alarm lights on a plant layout to advise operators where a given problem is located.

Despite the flexibility provided by the Ovation AMS, it does not cover the critical instruments connected to NetMation and TosMap that could potentially cause the plant to trip. To address this concern, the plant took the following actions:

    • Installed alarm lamps on each transmitter box not covered by AMS. Each box was equipped with an ambient thermostat that will turn on the lamp to alert the auxiliary operator making rounds whenever the temperature inside the box drops below 40F.
    • Revamped cold-weather rounds to include the checking of the transmitter boxes noted above, and scheduling rounds based on ambient temperature. The colder it gets, the more frequent the rounds.

The other area addressed was boiler-feedwater-pump lube-oil temperature control. The lube-oil tank was insulated with a custom-fit blanket to maintain desired oil temperature year-round. The plant also replaced the oil-heater assembly with one of a higher rating and designed to better distribute the heat throughout the tank and to prevent oil degradation.

Results. Although ambient temperatures at the plant site did not get as low as they did last winter, the thermometer dipped below 10F several times. However, no instruments froze as they had last winter. Plant availability increased significantly, achieving 100% in December, January, and February this winter, versus 94.3%. 78.5%, and 80.7% for the same months last year (excluding non-weather-related events).

AMS will be used to gather more operating information going forward. Plus, it will help maintain records of calibrations and will support the ability to conduct valve calibrations from the control room. Troubleshooting advice installed in the system will help solve problems quickly. It also will facilitate prioritizing work based on the criticality of the asset and the urgency of the alert. Finally, the AMS also will gather information to alert on issues before they become a problem.

Project participants: Ben Sumrall, Dan Truax, Dino Padilha.

Switch source of condenser vacuum-pump cooling water

Challenge. Middletown Energy Center’s (MEC) liquid-ring vacuum pumps were experiencing cavitation and a significant decrease in capacity because of high liquid temperature. There was also a constant need for filter cleaning given the high level of suspended solids in the pump’s cooling water.

Staff responded by changing the cooling-water supply to the vacuum-pump skids—from circulating water to service (city) water. This modification did not increase water usage because the service water used on the vacuum skid was sent to the cooling tower as makeup.

Solution. To help alleviate the effects of pump cavitation and performance loss, and to minimize the need for personnel intervention, MEC piped service (city) water to the plate-and-frame heat exchangers on the vacuum skids. Using city water to cool the operating liquid stopped the cavitation and gained back some of the performance lost (photo). Circ-water temperature in summer is in the 90s; service (city) water is in the high 60s. Note that the circ-water line is still in place and can be used if needed.

Results. The plant estimates that an average of four man-hours per week is saved by using city water instead of circ water for pump cooling.

Project participants: Scott Ashley, Dan Truax, Dino Padilha

New Harquahala: Taking confined-space identification to a higher level

By Team-CCJ | February 18, 2022 | 0 Comments

New Harquahala Generating Co

Owned by Talen Energy 
Operated by NAES Corp 

1080-MW, gas-fired, three-unit, 1 × 1 combined cycle located in Tonopah, Ariz

Plant manager: Jeff Brady

Challenge. The confined spaces at New Harquahala Generating Station were identified and numbered a few years ago. It appeared that during the initial project, the numbering and identification were likely rushed, and the numbering system was labeled haphazardly from unit to unit. While there was the same number of entrances on the units, the numbers did not match up from one unit to the next.

Employees had to pay special attention to which unit’s information was pulled to identify the space and the hazards associated with it. Employees tried to fix this over the years, but there was still much to be done. Three key issues were found in connection with the confined spaces.

First, it was brought to the safety committee’s attention that employees believed some of the confined spaces had been misidentified and some completely missed. Also, numbering of the confined spaces did not match from unit to unit. The safety committee wanted the job done correctly and in a manner that would last a significant amount of time before needing much work again.

Second, the labels on the confined-space signs, along with a few missing signs, would fade and tear before they were even up for a year or two because of weather damage. The safety committee recognized that the current confined space signs, as they were, could not hold up to the elements of extreme heat conditions and the direct sunlight they were receiving. Something had to be done.

Third, the current computer program was not easy to change and/or add confined spaces to it. A list was compiled in Excel that identified the current confined spaces and the confined spaces that staff believed had been misidentified (multiple access points and/or levels) or missed entirely. The safety committee also wanted a new numbering system put in place for the confined spaces that included the missed spaces. They could then align the confined space IDs on the units so they matched.

Solution. It became evident that this project would be better served by seeking a contractor to fill the responsibility for completing it. The facility needed to be re-examined by someone to identify if any confined spaces were missed, if any should be divided into multiple confined spaces, and then the numbering system checked to make sure each unit matched the others. After the difficulty shown in completing the task in house, it was determined to bring in Michael Roberts with MRSafety LLC.

The task was developed in the following five phases:

Phase One was to finalize the outcomes and seek a common numbering system for everything in the plant.

Phase Two was a thorough and careful examination of the facility and each confined space already identified and then to identify any space missed. The locations were documented and numbers assigned to each confined space. Stainless-steel signs were specified for areas with high heat or sun exposure; hard plastic for areas better protected from the elements (Figs 1 and 2). The signs include a printed label with Quick Response (QR) codes.

Phase Three was to affix the signs around the facility and to provide a data sheet that could be entered into Tag Links. This would include a comprehensive notebook (electronic and paper copy) of all the confined spaces at the facility.

Phase Four was for Harquahala staff to pull all the existing photos of the confined spaces and available information into a usable product.

Phase Five was to provide new drawings identifying all confined spaces on unit and site drawings.

Results. Revamp of the confined-spaces portfolio created a better system, one much easier to identify the confined space and the associated hazards. The identification numbering system was redone so that each unit’s identical confined spaces now match from unit to unit.

Signs were printed on the metal backing to ensure they would withstand the Arizona sun and heat through more than a year or two, making it easy for all to identify the confined space. Signs include the appropriate QR code, helping employees and entrants be better prepared for the hazards they might encounter upon entering the confined space.

The QR code was a major reason for using MRSafety’s services. Instead of remembering which confined space is being used, then searching through the records to find the necessary information, and then printing that information, now, the information is provided quickly and efficiently using the QR Reader app.

Tag Links also was upgraded to TK Pro and each of the confined spaces was linked. Even better, the same message that appears on the QR Reader text has been linked to the confined space in TK Pro. When pulling up the confined space, the person in the control room now has access to the exact same information as the person in the field.

Project participants: Jeff Brady, Kim Steffen, Michael Roberts (MRSafety).

Athens Best Practices: Reduce startup NOx, emergency lighting, stack dampers

By Team-CCJ | February 18, 2022 | 0 Comments

Correcting ammonia permissive reduces emissions on startup

Challenge. Several years ago, Athens Generating received a new air permit that placed strict limits on stack emissions during startups. The plant faced significant challenges maintaining the prescribed NOx limits for cold and warm starts. Control logic at the plant dictated that the control valve for the SCR not inject ammonia until the heat-recovery steam generator (HRSG) temperature reaches 550F.

During cold and warm starts, the gas turbine (GT) typically held at around 20% load for several hours to warm up the HRSG and steam turbine (ST). The HRSG typically sat at temperatures of between 530F and 540F for hours during these starts, thereby preventing ammonia injection and keeping emissions elevated during startup.

Solution. Plant personnel reached out to the HRSG OEM and an independent contractor for input. Engineers determined the 550F permissive was based on firing the units on fuel oil. At this time, the plant only burns natural gas. Based on this information, the OEM determined the plant could safely lower the ammonia-injection permissive from 550F to 480F. The plant control logic was changed to reflect this.

Results. The lower ammonia permissive has been implemented on all three units and has been very successful in reducing NOx emissions during startup. Table presents data for a dozen cold starts on Units 1 and 2—both before and after the reduced ammonia permissive was implemented.

For the selected cold starts shown in the table, NOx emissions with the GT hovering at 20% load averaged 58.6 ppm before the change, 38.2 ppm after. This is nearly a 35% reduction in total NOx emissions when the GT is held at 20% load.

Project participants: Chris Mitchell, Todd Wolford, Bob Robinson, Hank Tripp

Emergency lighting switched from battery power to dc bus

Challenge. Emergency lighting was fed from an integral 110-V battery source. When the standard lighting loses power, emergency lighting from the 110-V battery turns on. During routine inspections of the emergency lighting system it was discovered that 10-15 light fixtures of the 80 installed were not powered. Years of heat and vibration in the turbine hall had reduced emergency-lighting battery power.

Solution. Existing fixtures were typical emergency-exit lighting with incandescent lamps. Most of these were replaced with high-efficiency LED lights. The units selected were not available with an integral battery backup. An existing system was deemed to have sufficient spare capacity to move the emergency-lighting load to the dc bus.

New inverters were manufactured and installed at the facility to pull power from the existing bus and route it to the newly installed emergency lighting fixtures. Plant staff worked with a contractor to design and implement the new system (Fig 1).

Results. The new lighting system was successfully installed in the turbine hall for all three units. The scope of the project has expanded to include the air-cooled-condenser area serving all three units as well as the water treatment plant and the river-water pump house. This is in progress on Units 2 and 3 and nearly complete on Unit 1. Because the inverters (Fig 2) power the new emergency lighting, they are always on, increasing visibility around the facility. Each inverter is designed to have at minimum 90 minutes of endurance.

Project participants: Kyle Kubler, Todd Wolford, Hank Tripp.

Stack damper improvements

Challenge. The plant’s stack damper is a fail-close design. The plant experienced several failures during gas-turbine operation, which resulted in forced outages and damage to the HRSG expansion joint. Issues related to the stack damper have caused four forced outages for the plant, with at least one being definitively linked to the stack damper closing during operation.

Solution. Plant staff researched several options. This included modification of the stack damper, replacing the stack damper, and removing the stack damper. Modifications and or replacement of the stack damper would have cost several hundred thousand dollars per unit.

The solution was to pin open the stack damper during operation. This was accomplished by adding fastening hardware to the actuating arm and linkage. When the stack damper must remain open during GT operation, the stack damper is opened and an operator inserts a pin into the slot added (Fig 3).

Logic was added to the control system so the control-room operator (CRO) can select a button to let him/her know that a pin is holding the stack damper open. Upon confirmation from the operator that the pin is in, the CRO selects the button to show “pin in.” To close the stack damper, an operator must first remove the pin from the stack damper and the CRO will uncheck the “pin in” button in the control system.

Results. This simple and inexpensive solution has been implemented on all three units at the plant. To date, there have been no further issues of the stack damper closing during GT operation. The DCS screen as the CRO sees it is in Fig 4.

Project participants: Rob O’Connell, Chris Mitchell, Bob Robinson, Todd Wolford, Hank Tripp

Defects in high-temperature plant components

By Team-CCJ | February 18, 2022 | 0 Comments

Dr Ahmed Shibli, managing director, European Technology Development Ltd (ETD), recently contacted Consulting Editor Steve Stultz to invite CCJ’s participation in the upcoming High-Temperature Defect Assessment (HIDA) conference, April 20-22. The virtual meeting will assess the behavior of high-temperature plant components containing defects and operating under steady and/or cyclic load conditions. This is considered by many experts to be an area of urgent need and interest to the global power-generation community.

Presentations and discussions will incorporate the thinking of experts from the UK, Belgium, Germany, Sweden, Switzerland, Poland, Italy, US, South Africa, Australia, and Japan, among others.

The program is divided into the following three segments:

    • Inspection, damage, and cracking under creep, fatigue, and oxidation conditions.
    • Defects/cracks and life assessment.
    • Martensitic steels—cracking, life assessment, and modeling.

Register today at www.edt-consulting.com.

Shibli and the UK-based consultancy he leads has had a long-term collaboration with CCJ on technologies of importance to powerplant owner/operators. To review some of ETD’s work, access www.etd-consulting.com and/or conduct a simple keyword search at www.ccj-online.com.

The first HIDA conference, a European Commission and industry-support research initiative, was held in Paris in 1998, back when all industry meetings were in-person events.

Steam-turbine diaphragm repair strategies

By Team-CCJ | February 18, 2022 | 0 Comments

Diaphragms are a hot topic at most conferences where owner/operators gather to discuss issues with their steam turbines, such as the Steam Turbine and Combined Cycle User Groups operating under the Power Users Group umbrella. To get the most from these meetings, it’s important to know the basics of steam-turbine design, the differences among machines offered by the leading manufacturers, and typical challenges faced by O&M personnel.

The intent of this article, written by Moe Fournier and Bryan Grant of Advanced Turbine Support LLC, is to provide users a backgrounder on the different types of steam-turbine diaphragms and their associated repair challenges. Recall that the purpose of the stationary blades in a diaphragm—a/k/a nozzles—is to redirect steam from the exit of one rotating stage of blades into the entrance of the next rotating stage. The design intent of the nozzle is to optimize both the angle of steam flow and its velocity into the downstream stage of rotating blades to maximize energy conversion.

Diaphragms are a two-piece assembly consisting of upper and lower halves that are installed in the upper and lower halves of the steam-turbine casing, respectively (Fig 1).

Recall that impulse turbines (Fig 2) typically have far fewer stages than an equivalent reaction turbine. Thus, the energy transfer across each stage of an impulse turbine is much greater than it is in a reaction turbine.

Almost all of the stage-to-stage pressure drop in an impulse turbine occurs across the stationary blades, virtually none across the rotating blades. This means stresses on an impulse blade holder (diaphragm) are significantly higher than they are for a reaction blade holder—dictating that impulse stationary-blade holders be axially larger and more robust than reaction ones. Most are of welded construction to tie all parts together rigidly.

Because they are stationary components, diaphragms often do not receive the same level of attention as rotating blades/buckets. However, improper maintenance and/or repair of diaphragms can have a negative impact on steam-turbine thermodynamic performance. Plus, the mechanical failure of a diaphragm can cause significant turbine damage. Damaged diaphragms also can act as a stimulus on downstream buckets leading to their premature failure and consequential damage to the turbine.

Diaphragm designs

Spacer-band construction (Fig 3), the most common style of impulse diaphragm for many years, remains the industry’s most prevalent design. It is characterized by individual nozzles without sidewalls, typically made of stainless steel, that are inserted into profiled holes in thin stainless-steel spacer bands that form the inner and outer flow paths for the steam.

The spacer band and nozzle subassembly are structurally welded to the inner and outer rings, normally in four places (inner and outer ring, inlet and exit sides) to form the diaphragm. The weld process typically used is MIG or submerged arc; stick and electron beam welding are less common.

Integral sidewall construction (GE singlet, Alstom platform, etc) generally is found in impulse turbines installed since the late 1990s (Fig 4). It consists of individual nozzles with integral sidewalls, typically of stainless steel. The nozzles are structurally welded to the rings, normally in four places (inner and outer ring, inlet and exit sides). Weld process used usually is MIG or submerged arc; stuck and electron beam welding are less common.

Fillet fabrication construction (Fig 5) is very common on the last few stages of LP steam turbines. It consists of individual nozzles, usually of stainless steel, welded directly to the inner and outer rings using full-perimeter fillet welds. A TIG weld, using an Inconel or stainless filler wire, is typical. The nozzles can be solid or hollow and may incorporate moisture-removal features.

Mechanical assemblies are less common but are being offered by some OEMs because they are said to eliminate distortion from welding. In theory, they allow you to replace individual components in the diaphragm. Fig 6 shows two patented concepts.

Failure modes

Steam-path distortion and/or blade/nozzle mechanical damage (including foreign-object damage, solid-particle erosion, cracking, and moisture erosion) are the most common failure modes for diaphragms.

Nozzle mechanical damage and blade flow-path distortion can contribute to three significant failure modes for the steam turbine. They are:

    • Distortion at the nozzle opening adversely affects turbine thermodynamic performance and efficiency because it suboptimizes flow from the nozzle to the downstream rotating bucket.
    • For long blades, changes in nozzle exit openings are conducive to variations in the impulse on the downstream bucket and can lead to bucket resonance/vibration and premature failure of the rotating blades.
    • Nozzle damage can lead to stress risers and mechanical failure of the nozzles themselves, which, in turn, can cause severe or catastrophic downstream damage to rotating buckets.

Structural weld failure. When the structural welds that tie the nozzles to the inner and outer rings fail, the diaphragm is likely to collapse and move into the downstream rotating buckets. This can cause significant damage to steam-path internals, up to and including catastrophic failure of the turbine. Failures often can be attributed to inadequate weld tie-in, improper weld application, and undercut erosion (Fig 7).

Nozzle failures. Although not a common cause of failure, a temperature difference between the diaphragm’s upper- and lower-half components can create forces strong enough to crack and liberate nozzle partitions. Condensate introduction typically is the cause of a thermal mismatch (Fig 8).

Dishing (creep). Diaphragms designed and manufactured with less-than-desirable materials or inadequate structural-weld depths, can, over time, and at elevated temperatures, distort (creep) in the direction of stress. Eventually, this causes the diaphragm to rub against the downstream rotating bucket stage, often resulting in significant damage to steam-path internals, and possibly catastrophic turbine failure.

Seal degradation. Diaphragms typically incorporate seals to prevent performance-robbing steam leakage around bucket tips and along the rotor shaft. When seals are damaged—especially seal tips—their effectiveness at keeping steam in the as-designed pathway is greatly diminished and efficiency suffers. Worse still, if the seals rub against mating components, they can cause surface cracking on the bucket covers and/or rotor shaft. Such cracks can propagate and lead to bucket or shaft failures.

Most diaphragm designs incorporate replaceable seal strips, which should be inspected, straightened and sharpened, and/or replaced at major-inspection intervals. Proper planning is required to ensure the correct spares are on hand to support component replacement.

Repair challenges, risks

Steam-path sections of all diaphragm types. The goals for repairing nozzles and sidewalls of a diaphragm are the following:

    • Remove stress risers in the steam path that could lead to mechanical failure of the diaphragm.
    • Restore the flow path (nozzle opening) to reduce opening-to-opening variations that can cause undue stresses on downstream buckets and premature failure.
    • Ensure diaphragm steam flow into downstream buckets is optimized for thermodynamic performance.

The repair challenges are to understand and apply the correct repair techniques and to preserve flow-path integrity with respect to the three goals above. When the repair involves welding, selection of weld process, weld materials, and proper application of post-weld heat treatment (PWHT) is critical to a successful and lasting repair.

Structural repairs to welded diaphragms. Repairs involving the structural weld require a finite determination of the construction type and the axial depth of the OEM’s structural weld, as well as a basic understanding of the stress fields in the diaphragm.

Additionally, for structural repairs to rings and/or sidewalls, welding must account for the very thin nature of the space band (or hollow ring) and its tendency to distort. Keeping the sidewall in the correct radial location is critical to unit performance; minimizing distortion of the steam path is critical to unit performance and the diaphragm’s fit into the turbine.

Weld repairs also require knowledge of the material types for each component. Material verification testing is recommended before any welding is performed. PWHT must be evaluated based on material types and weld repairs.

Repair of mechanically assembled diaphragms. For blade and steam-path repairs, the challenges noted above apply. For structural repairs to any diaphragm components (rings, etc), knowledge of the component material is necessary. Material verification testing is recommended before any welding is performed. PWHT must be evaluated based on material types and weld repairs. One more concern: Make sure the proposed repair does not negatively impact the mechanical joining feature at the ring-to-nozzle interface.

Best practice: Review proposed repairs on a case-by-case basis with a full understanding of the mechanical stress transfer mechanism of the diaphragm assembly.

Seal repair/replacement. While some refurbishment of seals is possible, replacement typically is the best solution. Depending on the type of seals, challenges can range from procurement cycles to installation techniques; knowledge of the seal design is critical.

CCUG 2020: Team GE focuses on performance improvement, operational flexibility, upgrades

By Team-CCJ | February 18, 2022 | 0 Comments

The first thing to note about the GE presentations is that you’re probably going to want to listen to the recordings, if you’re approved to access them at the OEM’s MyDashboard website.

A blizzard of information swept through the virtual room, along with a virtual army of presenters and technical support folks at the ready. The overarching message was that if you’re seeking to adapt your plant to changing market or operating circumstances, GE can help.

To set the stage, Tom Freeman, chief customer consultant, and Blair Van Dyne, South Region sales director, reviewed basic market forces—mainly the continued surge of renewable energy into the market and decline of coal. Van Dyne said, “US wind developers will add 23 GW of new capacity this year. The previous record was 13.2 GW in 2012. Solar PV accounted for 3.5% of US total energy generation in July. About 31 GW of US coal has retired since 2018. Coal generation dropped 30% in the first half of 2020.”

John Sholes, value solutions leader, discussed myriad ways to “make your plant better,” breaking down the options into short-, mid-, and long-term frames of concern.

A common short-term issue is getting sufficient turndown without exceeding attemperator limits. Options include software changes to lower exhaust temperatures, upgrading the HRSG attemperator to increase spray-water flow, and adding a ring-style second-stage attemperator, which could require up to a one-week outage. GE now offers a standalone “smart attemperator” box that biases the attemperator to current operating data by “buffering” the current instrumentation.

Sholes then discussed a variety of upgrades to “nudge ahead,” including a dry low NOx (DLN) 2.6+ combustor upgrade, advanced gas path (AGP) technology, and extended-turndown valves. Such “technology infusions” on the gas-turbine side can boost capacity by up to 20% but will require balance-of-plant (BOP) upgrades, possibly even a transmission-line upgrade and generator nameplate capacity uprate.

The mods can be phased in over time for plants seeking significant performance-shift goals. Generators have lots of design margin, Sholes added, although cooling capacity is critical.

Responses to audience questions addressed the following:

    • Changes required to condensate recirculation systems.
    • Wet compression on hot days.
    • Retrofitting safety valves versus replacing them.
    • When to involve the HRSG OEM.
    • Excitation-system and voltage-control limitations.
    • Steam-bypass considerations in event of a steam-turbine trip.

John Korsedal, product manager, GE Digital Worker Solutions, talked on flexible mobile and remote operations to achieve mission goals. Digital solutions are available to assist leaner, less-experienced workforces with expertise accessed remotely, inside or external to the owner/operator organization.

Korsedal dwelled on GE Remote Operations, a “packaged software and appliance solution” with much of its recent functionality derived from Covid-19 responses. Goals of the package are to enhance worker location flexibility, promote reliable remote operations, extend monitoring and contingency operations, and achieve multi-plant control flexibility. The package includes a “purpose-built” mobile HMI with view-only access as the default mode and a “pop-out for control management.”

Communications capabilities available with GE’s Remote Operations includes voice, video, text, content-sharing, hands-free broadcast, and group messaging through WIFI or cellular access.

In addition to Remote Operations, GE’s Asset Performance Management Portfolio will shortly introduce a next-generation Rounds product which will be called Rounds Pro. This will be available for large and small BYOD (bring your own device) screens with a new, intuitive, interface to complement work processes.

The presentation includes remote operations use cases.

To close the CCUG portion, Freeman returned to the virtual stage for “Adapting Plant Maintenance with Operational Changes in an Aging Portfolio.” Broad topics included:

    • Conducting a pressure-wave (HRSG cleaning technique) value study by monitoring differential pressure across the HRSG. Freeman noted that typically 0.25 MW (0.35 MW on 7FA) is gained for every 1.0 in. H2O recovered in HRSG differential pressure. An easy check in your historian.
    • Generator reliability and uprates. Freeman cautioned that you don’t want to be forced into a rewind at the wrong time as this requires a lengthy outage. Generally, rotors need a rewind after 15 to 20 years, stators between 25 and 30 years.
    • Impacts on the steam turbine/generator from greater cycling, such as the following: inlet-valve throttling and solid-particle erosion; low-cycle fatigue on HP/IP shells, last-stage blades (LSB), and valve casings; and moisture-induced erosion of LSBs and the turbine casing.
    • Subsystems, including valves, fire protection/hazardous gas, lube oil, and inlet/exhaust plenums.

Combined Cycle O&M: CCUG2020, Week One Recap

By Team-CCJ | February 18, 2022 | 0 Comments

The annual conference of the Combined Cycle Users Group is being conducted online for the first time this year. The four-week event, exclusive to owner/operators, began November 10 with a program focused on user experiences and vendor presentations. The latter were limited to 30 minutes each and conducted in two half-hour sessions. Each vendor was assigned a “breakout room” and users were connected to their presentations of choice. While attendees could not participate in more than two vendor presentations during the live Week One program, ALL presentations—both user and vendor—are available now on the Power Users website.

Highlights of the Week One user presentations, developed by the editors, are below.

Week Two (November 17-19) was GE Week, characterized by meaningful technical presentations, Q&A, and open discussion on topics of interest to the user community. Those presentations can be accessed through the OEM’s MyDashboard website.

Week Three’s CCUG program begins on Tuesday, December 1, at 9 a.m. Eastern with the first three hours allocated for private meetings with vendors; schedule these online just as you would a doctor’s appointment. Presentations by users are next, from noon to 2 p.m. followed by these two hour-long live vendor presentations with Q&A:

    • HRST, 2 p.m., “Drum-Weld Critical-Crack-Size Pre-Outage Assessment and Application Experience.”
    • Environex Inc, 3 p.m., “Is Your SCR/CO System Ready for Turndown? How Increased NO2/NOx Ratios Require Additional SCR Performance,”

A virtual vendor fair, complete with video chat rooms, runs from 4 p.m. until the end of the day’s program at 5.

CCUG2020 concludes with the Week Four program on December 8. Program format is the same as that for December 1. The featured vendor presentations on the last day of the conference are these:

    • Orr Protection, 2 p.m., “Improving the Life Safety of CO2 Fire Extinguishing Systems.”
    • Hydro Inc, 3 p.m. “Achieving Reliable Pump Operation for Non-Baseload Operation,” and “Innovations in Vertical-Pump Vibration Monitoring.”

CCUG2020, Week One user presentations

“Natural Gas Systems: Lessons Learned and Recommendations From Design to O&M,” can be thought of as a tutorial for ensuring safety and performance of gas supply and delivery in combined-cycle facilities, one which also addresses compliance with applicable specs—including ASME B31.1, NFPA 56, and NFPA 85.

Coverage includes LEL (lower explosive limit) detection and monitoring in general, mechanical- integrity inspections, buffer capacity, nitrogen purging, above- versus below-ground piping, change management and integration with the CMMS (computerized maintenance management system), and perhaps most importantly, analyzing all “near-miss” events, performing drills, and making sure your emergency plans are “dusted off.” A great “near-miss” real-world example illustrated is 500-psig fuel gas being trapped between two butterfly valves after shutdown and before some maintenance activities were about to commence in the area.

“Understanding Oil Analysis” likewise covered the tutorial aspects of contamination, fluid condition, and machine wear. Within each of these broad areas, the presenter reviewed the efficacy and cost of specific test procedures, and aspects of testing that can cause problems. For example, the temperature at which a demulsibility (ability to separate oil from water) test is performed can affect the results, something that is especially important for steam-turbine systems. Presenter recommended that someone at the site “needs to have formal third-party or in-house training” in all aspects of oil analysis.

HRSG pressure-wave cleaning. This writer’s jaw dropped to the floor faster than the material removed from an HRSG during a pressure-wave cleaning when he heard that 25 to 30 tons of rust and scale were removed, the pile at the HRSG floor was 14 in. deep, and the HRSG differential pressure dropped from 21 in. H2O to 8-10 in. Some important points for a successful cleaning: Allow only permitted blasting crews to access HRSG during the procedure, notify your neighbors, cover the backside of the SCR with a tarp, cover manway access doors, and clear CEM lines to make sure they don’t get plugged up.

Cold layup and restart. Powerplants want to be run. But when the market dictates otherwise for long periods of time, the plant has to go into cold layup. When the market further dictates that half of the plant capacity is sold into the market before the balance, well, the complications grow. The litany of issues which had to be addressed for a California plant under these circumstances are reviewed in “Plant Extended Layup and Restart Guidelines.” This presentation is a veritable study guide for the next plant that has to do this.

One of the most important lessons learned is that the turbine lube-oil preservative recommended by one vendor and applied was a poor choice and caused significant issues. Another is that calcium products from the vapor-phase corrosion inhibitor used for metal surfaces can get into the lube-oil system. Removing it is similar to removing varnish from lube oil. A third is that zero liquid discharge and air-cooled condensers can contribute to significant issues managing rinse and flush water. This plant also reported experience with GE’s proprietary pressure-wave cleaning method for HRSGs as part of the restart.

CCUG 2020: Focus on Covid best practices, safety, HRSGs, emissions control

By Team-CCJ | February 18, 2022 | 0 Comments

The annual conference of the Combined Cycle Users Group (CCUG) was conducted online for the first time in 2020. The presentations summarized below took place during Week 3 of the conference and are available to owner/operators on the Power Users website. Access Week 1 (User presentations) and Week 2 (GE Day) recaps here. More to follow…

Subjects covered during the CCUG’s Week Three session ran the gamut from what you can bring into (or catch at) the plant to what your facility discharges out the plant—and much in-between. ALL presentations—both user and vendor—are available on the Power Users website for on-demand viewing.

Pandemic viruses. Probably nothing was top of mind like Covid-19 and so the day began with the presentation, “Covid Best Practices.” First slides reviewed the Covid personal practices we’ve been seeing and hearing about for eight months in the news.

Then the presenter drilled down to in-plant practices, specifically changes to outage execution. Some of the basic steps include the following:

    • Daily site employee and worker temperature monitoring for fever.
    • Segregating day and night shift staffs and decreasing shifts by one hour to avoid overlap.
    • Phone- or digital-based shift turnover.
    • Increased social distancing during the shift by holding morning toolbox and shift turnover meetings outside (weather permitting) or in rented trailer, separating crews into teams with different break schedules, and adding a separate trailer for work crews.
    • Increased personal hygiene and addition of wash stations around the site.
    • Wipe down of tools at the end of each shift for the next crew.
    • Additional personnel protection equipment (PPE) in areas where 6-ft distance could not be maintained (confined spaces, for example).
    • All vehicles limited to one worker per trip.
    • Frequent cleaning of all high-traffic surface areas like refrigerators, microwaves, coffee pots, door handles, etc.

The presenter underscored the need to be aware of heat-related stress from wearing masks for long periods in hot environments (such as above 90F), and a need for a solution to crowding at emergency muster points.

The Q&A session got interesting. Illustrating a non-obvious tradeoff of one safety issue for another, one plant rep noted that they had to back off on safety audits and suspend fire drills to minimize person-to-person contact. One user expressed frustration that they couldn’t get the right tech-support folks into plants because of local, state, and national restrictions. In an extreme case, this caused scheduled hot-gas-path (HGP) maintenance to be deferred.

Another facility modified smoking areas and port-a-potty units to keep groups isolated. At least two plants added portable heated-water hand-washing facilities, one said to include a tankless water heater, to encourage longer hand-washing.

Unfortunately, no one had any good way to track workers offsite, behavior that could nullify whatever good practices were occurring onsite. Craft-labor supervisors, the presenter said, were responsible for ensuring that crew members only traveled from hotel to site. Lunches were served onsite to avoid unnecessary offsite travel.

Safety. The next presentation, titled “You Have to Be Present to Win,” addressed safety issues, with Covid-19 being the most recent challenge added to the safety basket. It’s worth getting the slides for the photos of a GT major outage during a pandemic. Some of the specific steps taken at this plant:

    • Substituted a safety-orientation video and a downloadable Excel spreadsheet for the in-person site orientation session.
    • Replaced break trailers with tents, provided by a local contractor, equipped with lights, heat, tables, chairs, floor, etc.
    • Added two remote hot-water hand-washing stations.
    • Held daily contractor meetings in an open, ventilated shop area.

Speaker opened with the personal experience of an injury during a family outing to illustrate “what we do at home affects our work,” and then recounted the experience of a serious accident at the plant as a reminder that “we work in a dangerous environment.”

That set the stage for a discussion of six enemies of safety: complacency, stepping through the motions without thinking about what you’re doing; poor housekeeping, taking the time to clean up and avoid shortcuts; fatigue/lack of focus, especially during long outages and when workers are offsite; deadlines, distinguishing between real and implied; lack of training, “feeling” what’s happening with the equipment in addition to “knowing”; and trusting without verifying, such as taking the time to know what is going on in a LOTO area.

Reporting “near-misses” is key, the speaker stressed, and with follow-up training on the precursors to them.

Two slides list a baker’s dozen of “items to consider.” While most are the usual reminders when plant safety is addressed, a few of the most salient are these:

    • Require workers to state what they are doing instead of just doing it when signing off on work permits.
    • Consider taking the most conservative option when making an on-the-spot decision about safety.
    • Encourage an open mind when personnel suggest solutions and “hear” employees’ safety concerns rather than just listening to them.

One listener encouraged attendees to adopt OSHA’s Voluntary Protection Program (VPP) process to strengthen their safety programs. VPP plants invite OSHA representatives into the plant to guide them in how to do things more safely. Presentations at previous CCUG conferences have addressed the OSHA VPP process. Access them on the Power Users website.

Another attendee conceded that training new employees during a pandemic presents opportunities for improvement. One concrete idea is to upload a virtual orientation to YouTube with a QR code for workers who didn’t see a video before they arrive at the site.

Inspections. Remotely inspecting high-risk areas is another facet of safety. The next speaker presented experience with remote camera inspections of LM6000 and 7EA peaking-unit compartments. This is a specific solution based on a GoPro camera and a digital monitoring device.

Craft labor in this utility’s peaking-turbines department sought a system that would be safe, avoid unnecessary tagouts for things like oil leaks, and not violate the gas-turbine OEM’s requirements—such as the prohibition of entering a turbine package during operation. The solution selected features off-the-shelf components costing at most $1500, rather than expensive stationary cameras. The camera sits in a mag base with remote mounts, while the monitor stands outside the GT housing.

This was also a case where putting the minds of your younger workers to bear on the problem pays dividends, the speaker noted.

The apparatus has already proved its value in detecting water leakage in a GT package following a shutdown and confirming its source (NOx injection water line), detecting smoke emitted from the turbine compartment and confirming its source (vent fan), as well as for conducting condition assessments of inlet-house fogging nozzles and evaporative cooler media, and for monitoring an oil-consumption sight gage.

Generally, any piece of equipment inside a housing can be monitored and recorded externally during operation for an extended period.

Questions included whether the components are explosion-rated and “intrinsically safe” and what the high-temperature limit is (answer, 400F for direct contact, but does not actually contact hot surfaces). One commenter noted that such cameras have also been used in place of borescopes for “troubleshooting insight.”

Market competition. As if it wasn’t yet clear, the presentation titled “Renewables Are Coming” made unassailable the coming competition to gas-fired plants from solar and wind. And if you don’t like that, you can no longer blame it solely on government mandates.

Eight states now require 100% renewable energy by 2045 and five others have 100% renewable “goals.” Large high-profile corporations like Facebook, Google, Microsoft, and other digital-economy leaders, the speaker noted, plan to either build or buy 72 GW of renewable energy by 2030 for their electricity-hungry server farms and other needs.

That’s the demand side. On the supply side, the presenter noted that solar photovoltaic (PV) systems have dropped in cost from $3.50/watt to 50 cents over the last 12 years, and their active-power control capabilities have greatly improved. Grid-scale battery systems, which assist in load management, also have dropped in price by 70% between 2015 and today.

“Lots of states already show solar and wind to be the least-cost capacity options,” observed the presenter, “and only a handful of states show gas-fired generation as the least cost option in 2030.”

There are unintended consequences, however. For example, smoke from the California wildfires this past year decreased solar generation from existing facilities by around 30%. Guess which plants would be making up that loss on a moment’s notice? Yup, gas plants.

Another consequence of the strange year called 2020: Utility system loads shifted dramatically, because of COVID, from commercial facilities to residential units. Zooming takes electrons.

Most of the bulleted items on four slides about how to adapt GT units to this coming onslaught are probably more than obvious to most users and have all been topics of one or more presentations during prior CCUG conferences, including the future potential for hydrogen produced by renewable sources as a GT fuel.

HRSG drum wall cracks. Anand Gopa Kumar, analysis manager, HRST Inc, coached the audience through a relatively new onsite crack-size assessment technique, conducted along with ALS Industrial Services, that has now been demonstrated “on a few HRSGs.” The technique, which follows API 579 and ASME-FFS-1 standards, combines transient thermal simulation (based on finite-element analysis) crack growth under drum operating conditions with standard NDE crack inspection methods—including magnetic-particle and ultrasonic testing.

The deliverable, if you will, is a failure assessment diagram (FAD) of the areas under investigation which reveals critical crack size (Fig 1) as a basis for decisions about remaining life, additional run time, etc. In other words, measure the crack dimensions (length and depth) and project their growth (assuming other variables are fixed) over the next operating cycle.

“All high-pressure drums should be periodically inspected but the thicker HP drums are most at risk,” Kumar said, with the area of greatest risk being the surfaces exposed to the 0-400-psig pressure range where the fastest temperature rises are experienced. “Thick cold drums plus fast pressure ramp equals stresses at the large nozzles,” Kumar noted. The shell-to-head area is also susceptible to cracking.

A typical F-class HRSG HP drum needs around eight different FADs, one for each of the major weld locations. The technique is best performed before an outage, so that relatively quick decisions can be made on repair during the outage versus continued monitoring.

The technique is applied to ID wall cracks, since removing insulation from the OD side usually is impractical or not possible. However, Kumar said, some cracks at OD weld areas can be detected from the inside. The analyst also has to consider adjacent cracks and the potential for crack interaction. “Sometimes cracks close together should be considered a single larger crack,” he said.

Many of Kumar’s slides were devoted to pre-outage, start of outage, and in-testing work.

Pre-outage work includes organizing the information—such as design drawings, operating profile data, historical repair procedures, photos, and any other previous inspection results or condition reports. Drum weld areas need to be properly exposed, cleaned, and prepped for NDT, and drum internals removed. Less obvious: Install snug-fitting foam plugs in nozzles to protect them from foreign objects and install lanyards on all tools if open holes exist.

At the start of the outage, inspect surface prep before the NDT crew arrives, label each weld location with paint stick per the drum weld location map (Fig 2), and protect nozzles from falling objects.

During testing, the technician performs mag-particle tests first, then the phased-array ultrasonic tests to accurately document the start of cracks, while being aware of multiple crack interactions. Length and depth of cracks must both be determined to decide whether more run time without repair is prudent. Decisions whether to leave as is or grind out shallow cracks must be made as well. Minimum wall thicknesses should also be calculated ahead of the outage, using ASME methods.

In response to questions, Kumar stated that fatigue-life calculations are not part of this exercise—these components typically do not operate in the creep temperature range—and it is uncommon to see cracks slow down or stop rather than continue to grow. Performing this technique before a unit enters cycling service can be especially valuable.

Catalyst and turndown. Moving through the combined-cycle system to the NOx and CO emissions catalysts, Andy Toback, Environex, asked in his presentation title, “Is Your SCR/CO System Ready for Turndown?” If your SCR was designed for baseload operation, the answer is probably not.

Chemical constituents change at temperatures typical of low-load operation. NO2 from the gas turbine gets elevated and CO from the GT exhaust can “grow exponentially at low loads,” because the operating-temperature range has shifted. Toback then turned to two case studies to illustrate his points.

The plant in the first case was experiencing ammonia flows higher than design, sometimes twice as much, even at low loads, and low NH3 vaporizer temperatures at high NH3 flows. The NO2 fraction of NOx was measured consistently higher than 50%, and as high as 70%, during startup. Normally, it should be around 20% NO2/NOx.

Nevertheless, both CO and NOx catalysts were performing well. However, the CO catalyst was also oxidizing NO to NO2, so the SCR catalyst had to work harder neutralizing the elevated NO2 levels, acting as if it was near the end of life, asking (through the control logic) for additional NH3 spray.

“The catalyst was behaving perfectly for the baseload conditions it was designed for,” Toback reported, “but to operate at lower loads and meet permit limits, it would require 20% additional volume and 0.6 in. H20 additional pressure drop.”

Toback called the second case study a “turndown field exercise.” The test crew measured steady state catalyst operating temperatures and CO and NOx concentrations in the GT exhaust down to 8% load. The goal was to determine what turndown levels the plant could run at with available catalyst configurations. It turned out that 35% was the load limit with the present catalyst. Both turbine-exit NOx and CO levels (Fig 3) rose precipitously below this point.

“This plant could get to a 28% load limit if they replaced the present CO catalyst with a dual-purpose formulation,” Toback concluded. While this approach could prove worthwhile for some plants facing extended operation at extreme turndown levels, this plant opted to stick with what it had. In addition to the larger catalyst volume, there is a pressure-drop penalty.

One questioner asked what the catalyst concerns would be running the plant at higher-than-design loads. Answer was that the anticipated life of the catalyst would have to be modified based on the operating data post-uprate.

Another asked if catalyst degradation is gradual or “falls off a cliff.” Answer was that NH3 consumption tends to increase exponentially and catalyst deactivates quickly near end of life. Short answer, probably. Catalyst needs to be tested periodically, and “married up to operating data,” to keep from approaching the cliff, especially after the OEM’s warranty period, to establish a baseline. “Early catalysts were over-designed,” Toback noted, “while later CC/GT facilities have catalyst supplied more competitively on volume.

In the Environex virtual breakout room, discussion continued on topics such as these:

    • How often to clean NH3 heaters. One plant cleans with acid every three years, while another plots wattage to vaporizer exit temperature to predict when the next cleaning should be.
    • Options for running at lower capacity factors when your NH3 flow is capped. Check for plugged nozzles in the ammonia spray array, and try to tune the unit by measuring NOx and ammonia slip at each point in a traverse (assuming you can reach the sampling ports or add a sampling port grid), and selectively increase the ammonia flow in trouble spots.
    • Plants having issues with operation below 40F and above 85F can consider seasonal tuning

New tools for locating pitting, wall loss, corrosion, cracking in HRSG headers, tubes, welds

By Team-CCJ | February 18, 2022 | 0 Comments

TesTex Inc specializes in electromagnetic non-destructive testing and has developed innovative methods and equipment for combined-cycle HRSG healthcare. Founded in 1987, the company, both multi-industry and global, maintains a focus on heat-recovery steam generators in the challenging combined-cycle world. Its primary mission is fast, accurate, and cost-effective NDT services using pioneering state-of-the-art equipment and expertise.

CCJ connected with TesTex at the HRSG Forum with Bob Anderson. Showcased at the 2019 meeting were proprietary Remote Field Electromagnetic Technique (RFET) equipment for detecting internal tube pitting and wall loss, and a proprietary Low Frequency Electromagnetic Technique (LFET) system to examine finned tubes from the gas side.

The goal of both is to locate and identify pitting, wall loss, caustic and phosphate gouging, corrosion attack including FAC, cracking, erosion, and manufacturing defects. Also on display was the Balanced Field Electromagnetic Technique (BFET), and a curious new contraption called “The Claw.”

TesTex personnel collaborate with both EPRI and ASME to keep a sharp and expanding focus on HRSG challenges and common areas of concern.

Variety and invention. Consulting Editor Steven C Stultz, who wrote this article, began his professional career in the offshore oil and gas industry, intrigued by what that industry was doing deep in the Gulf of Mexico, and elsewhere. It seems TesTex has some similar roots, using robotic multi-channel sensor arrays (LFET) and automated ultrasonic technology from its Houston office on the massive rigs and platforms with extensive arrays of heat exchangers and piping. Industries do learn from each other.

So when an Alaska pipeline had a containment incident resulting from internal pitting corrosion (a potential shock to the environmentally sensitive North Slope) the US Dept of Transportation put out an urgent call for creative fast-screening NDT. They needed a quick alternative to their primarily manual UT techniques.

TesTex LFET, along with company technicians and NDT engineers, became a critical part of this large-scale, critical and urgent remote-area inspection.

Closer to home, and to the power industry, TesTex developed and applied an ultra-high-speed eddy-current inspection system to a large condenser system, to keep it operating until the next scheduled outage. The condenser contained 18,000 tubes, 40 ft long, and the inspection was wrapped up within five days. Damaged tubes could then be plugged, enabling the owner/operator to get back online.

Balanced field for HRSGs. The TesTex BFET also has an interesting history, plus a recent development labeled “Mini-Claw.”

“The technology was developed to enhance the signal responses produced from small defects, such as cracks, and specifically for tube-to-header weld issues in HRSGs,” says Shawn Gowatski, manager of the company’s Solution Providers Group.

He tells us how it works: Briefly, electromagnetic coils are wound and placed in a balanced state, with the coils in both the x and y geometries at zero potential to each other. “With the excitation coil in the x geometry and the sensor coil in the y, a different signal is produced over defected areas,” says Gowatski.

“The alternating current produced by the excitation coil is uniform and undisturbed if no defects are present. If there are defects, the current is interrupted and the current is forced to travel around them in distorted fashion. This produces an indication that signals a defect, and this can be both detected and then quantified by applying proper calibration standards” (Fig 1).

BFET can test different types of metal by adjusting the test frequencies, which range from 100 to 30,000 Hz, and can test at speeds up to 1 ft/sec.

TesTex’s initial use of BFET centered on two types of probes, Hawkeye and Hawkeye DP (deep penetrating). The Hawkeye probe can penetrate up to 0.250 in. into the surface, the Hawkeye DP up to 0.375 in. The probes, traditionally hand-held (Fig 2), are in wide and varied use today. Probe surfaces can be machined to match required geometries (for example, a specific radius for tube and pipe welds), and multiple probes can be rigged for large areas.

TesTex has used this technology to inspect deaerators, piping, tube stubs, drums, distillation columns, dryers, heat exchanger shells, and other pressure vessels. All data are viewed in real time and recorded.

360-deg BFET.  A major issue for both ageing and newer HRSGs is tube-to-header cracking and potential failure (Fig 3), experienced largely through leaks at the tube-side toe of the weld. But this occurs in a very congested, tightly spaced environment. Traditional inspection methods, such as magnetic particle (MT) and others, can only reach the exposed 180 deg—at best.

“It can be used anywhere an owner/operator suspects cracking within 0.25 in. of a surface,” notes Gowatski. “High-pressure superheaters and reheaters are particularly vulnerable due to ongoing unit cycling.”

TesTex developed the BFET, and in collaboration with EPRI, various tools for its application on HRSGs. One of these is the Claw (Fig 4).

With the Claw, BFET probes and cameras are placed on the welds using a C-clamp housing that attaches to the tube. Once attached, the assembly moves circumferentially around the weld examining for cracking, lack of fusion, porosity, and other defects. This technology detects surface cracks, as well as subsurface cracking within 0.250 in. of the surface.

A feature of the technology is that no surface preparation is required, and the inspection covers the entire 360 degrees of the weld. For most competing technologies, surface preparation can be difficult and time-consuming. Plus, radiography requires personnel evacuation from the area.

Says Gowatski, “Quality readings can be acquired through coatings such as paint, epoxy, and rubber. Uniform scale and rust do not present problems either. However, coal ash deposits, rough, uneven, or repaired welds, and pitted surfaces can present challenges. But they do not preclude successful use of BFET,” he explains.

The BFET probes ride along the contour of the tube-to-header weld and cameras monitor and record the entire process. But the significant achievement is investigation of the entire circumference. Even when a second technology is used for verification, this is normally limited to the 180-deg exposed area, limited by accessibility.

Another feature is the ability to eliminate liftoff (and/or probe wobble) and noise from the signal. As Gowatski explains, “There are two components of the BFET signal that we view, Asin and Acos. To have a clean signal without noise, the angle that we view is rotated and changed to put most of the noise on the Acos signal. By doing this, any cracks or small inclusions are shown prominently in the Asin signal.”

Claw technology is being used to detect fatigue cracking and other issues in headers with diameters from 4 to 14 in., and in tubes of 1.5, 1.75, 2.0, and 2.25 in. diameter.

Both the Claw and the new Mini-Claw (Fig 5) can check header welds on tubes with bends above or below the header. The latter is designed specifically for 1.5-in.-diam tubes and with extremely tight clearances between adjacent tubes—down to 1.25 in. (Fig 6). It has now been used successfully on multiple HRSGs.

Detect and record. With both the Claw and Mini-Claw, the balanced-field electromagnetic technique waveform is displayed in five different windows (Fig 7). The bottom right window shows the raw data, the bottom left the data processed. The two lines in the bottom two windows show the results from each sensor. The top line is from Sensor 1, the bottom line from Sensor 2.

The middle left window is a simulated C-scan, the top left window a zoomed-in view of the data from the second sensor. The top right window shows a capture using the on-board camera.

Turnaround. TesTex has become known for its innovation and quick turnaround without interfering with operations, based on an informal survey of users. The company’s 200-plus person global network, headquartered in Pittsburgh, works primarily from US offices in Philadelphia, Houston, New Orleans, Atlanta, Bakersfield, and South Bend, as well as from locations in Canada, Trinidad, the United Kingdom, France, and India.

Scroll to Top