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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.

How to quickly inspect for cracking at tube-to-header welds in HRSG

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

Finding and fixing HRSG tube leaks before they can grow to the point of requiring an unplanned outage to correct them is a priority of many maintenance managers during annual inspections. Tube-to-header welds are particularly susceptible to cracking and leakage given today’s fast-start/fast-ramp operating practices.

There are several tools inspection personnel traditionally have used to inspect these welds for cracks—including visual, dye-penetrant, magnetic particle, and x-ray. One or more of them may require special certifications, surface preparation prior to use, and/or more working room than is available.

A relatively new tool for inspecting tube-to-header welds, “The Claw,” developed by TesTex Inc, Pittsburgh, uses the Balanced Field Electromagnetic Technique (BFET) to detect cracking on the surface, and below it to depths of 0.250 in. (Figs 1 and 2). It was on display for viewing by owner/operators of heat-recovery steam generators at the 2019 meeting of the HRSG Forum with Bob Anderson.

Over the last couple of years, TesTex technicians have gained a great deal of experience with The Claw and are now able to examine up to about 200 tube-to-header welds in one shift. Fig 1 shows the BFET’s two sensors spaced 180-deg apart and companion cameras traversing the full circumference of the weld. Important: No surface preparation is needed to perform the BFET inspection in HRSGs (Figs 3 and 4).

Lessons learned from an HRSG over-pressure event

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

Powerplant work can be a humbling experience. It seems that once you begin feeling overly comfortable about how well your facility is running, something unexpected occurs and snaps you back to reality. You can blame the “bad luck” on the gremlins, but more likely the cause was human error.

Consider the following experience at a 1 × 1 combined cycle assembled in 2001 from a W501F gas turbine, a 114-MW steam turbine from a retired 1958-vintage coal-fired plant, and a triple-pressure Nooter/Eriksen HRSG designed for operation at a main-steam pressure of 1750 psig:

A maintenance technician working in a control/breaker cabinet accidentally tripped two breakers. He responded immediately, returning them to the “on” position. However, re-energization caused the flow-proportioning/temperature control valve TCV 12 (Figs 1 and 2) to fully close.

With turbine exhaust gas still flowing through the HRSG, water trapped in Economizer 2 by the closed valve flashed to steam. Pressure increased to the 5000 psig or so engineers believed it took to burst the joint between one of the 6-in. riser pipes and the SA 106B 8-in. manifold shown in Figs 3 and 4. The good news: No one was hurt.

This accident happened because there was no way to safely relieve a pressure excursion in the feedwater system between the HP feedwater inlet to the two-stage economizer and the steam drum. This was not a design oversight. Rather, a mechanical stop installed in TCV 12 to prevent it from full closure had been removed, unbeknownst to anyone on the current staff.

This generating unit had been sold by its utility owner to an independent power producer about six years prior to the incident and there had been personnel changes. As many have learned, some of the historical information important to O&M operations does not transfer well—or not at all.

There are alternatives to the mechanical stop to protect against the inadvertent full closure of control valves in this type of service: Relief valves could be installed in the feedwater lines to the economizer (ahead of HP economizers 1 and 2 in this case) or an unrestricted bypass could be routed around the control valves. All of these methods are acceptable to the ASME Boiler and Pressure Vessel Code.

HRST Inc, Eden Prairie, Minn, was dispatched to the site immediately after the over-pressure event. Results of the company’s inspection—including no flow-accelerated corrosion indications, no bulging or cracking of piping or tubes elsewhere in either section of the economizer—were discussed with plant staff and incorporated into the RCA (root-cause analysis) investigation conducted by NAES, the plant operator. Advanced NDE techniques and hydrostatic testing were used to evaluate system health.

Finite-element analysis revealed high bending stresses at the joint where the failure occurred. Fatigue stress caused by many expansion/contraction cycles over time may have been a factor in the failure.

During the investigation and repair stages of the project, the valve-close event was replicated multiple times with the same result: Power failure resulted in the same valve closing. There was no explanation as to why a power-loss event signals TCV 12 to close. At least some of the members of the accident investigation team hypothesized that the Siemens TXP control system might be somehow involved. Most O&M personnel consider that system obsolete and not user friendly. Few in the industry are said to have the knowhow to troubleshoot TXP successfully.

An unvalved, ¾-in. bypass line was routed around TCV 12 to protect the system going forward. TCV 11 had an intact mechanical stop and did not require a bypass.

Damage was local to the failure location. However, the repairs required were extensive, spanning 2½ months and totaling about 10,000 man-hours. In addition to the obvious pipe replacement activity, significant quantities of cabling and cable trays, insulation and cladding, and heat tracing were replaced. Plus, building repairs were necessary. As many as eight contractors and 30 craft personnel were onsite at one time.

Recommendations to others based on lessons learned:

    • Check your economizers for valves that can block feedwater flow to the steam drum.
    • Review original P&IDs and compare them to the system as it exists today. If valve changes have been made over the years that could bottle-up the economizer, correct any deficiencies in timely fashion.
    • If your system does not have a relief valve between the boiler-feed pump and the last valve before the steam drum, investigate why there is none. If there is a relief valve, is it being tested and serviced at the proper intervals?
    • If your system is protected from over-pressure by a mechanical stop, turn off the air to the control valve to be sure it doesn’t go to 100% closed.

Roundtable discussions help Frame 6 users solve current problems

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

Frame6-LogoPerhaps no one understands your job-related challenges better than colleagues with the same engine. That’s what makes the Frame 6 Users Group’s compressor, turbine, combustion, and I&C roundtables particularly valuable. These sessions allow you to describe issues of concern to fellow users and let them suggest possible solutions based on their experiences. Think of it as free consulting provided by the industry’s top O&M experts.

While no safety roundtable is scheduled for the 2021 conference, be aware that there are several safety threads posted to the organization’s online forum, hosted on the Power Users website—including experience with optical flame detectors, how to deal with ill-fitting compartment doors and hardware replacements to correct, functional tests to confirm proper operation of water-mist fire-suppression systems during unit commissioning, opening of compartment doors with the CO2 system activated, etc.

Another way to come up to speed on the safety aspects of Frame 6 O&M is to become familiar with the OEM’s safety-related Technical Information Letters (TILs) and Product Service Safety Bulletins (PSSBs). These are identified in the sidebar. If you don’t have copies of the pertinent documents, request them from your plant’s GE representative. And since you can’t remember everything, consider having one or more safety professionals assigned to your plant during outages.

Safety TILs and Product Service Safety Bulletins affecting 6B gas turbines

TIL 2101, Modification of manual lever hoist for safe rotor removal.
2044, Dry flame sensor false flame indication while turbine is offline.
2028, Control settings for GE Reuter Stokes flame sensors.
2025, GE Reuter Stokes FTD325 dry flame sensors, false flame indication.
1986, Braid-lined flexible metal-hose failures.
1918, 6B Riverhawk load-coupling hardware and tooling safety concern.
1838, Environmentally induced catalytic-bead gas-leak sensor degradation.
1793, Arsenic and heavy-metal material handling guidelines.
1713, 6B, 6FA, 6FA+E, and 9E false-start drain system recommendations.
1709, 6B load-coupling recommendations.
1707, Outer-crossfire-tube packing-ring upgrade.
1700, Potential gas-leak hazard during offline water washes.
1633, Load-coupling pressure during disassembly.
1628, E- and B-class gas-turbine shell inspection.
1612, Temperature degradation of turbine-compartment light fixtures.
1585-R1, Proper use and care of flexible metal hoses.
1577, Precautions for air-inlet filter-house ladder hatches.
1576-R1, Gas-turbine rotor inspections.
1574, 6B standard combustion fuel-nozzle body cracking.
1573, Fire-protection-system wiring verification.
1566-R2, Hazardous-gas detection system recommendations.
1565, Safety precautions to follow while working on VGVs.
1557, Temperature-regulation valves containing methylene chloride.
1556, Security measures against logic forcing.
1554, Signage requirements for enclosures protected by CO2 fire protection.
1537-1, High gas flow at startup—Lratiohy logic sequence.
1522-R1, Fire-protection-system upgrades for select gas turbines.
1520-1, High hydrogen purge recommendations.
1429-R1, Accessory and fuel-gas-module compression-fitting oil leaks.
1368-2, Recommended fire-prevention measures for air-inlet filter houses.
1275-1R2, Excessive fuel flow at startup.
1159-2, Precautions for working in or near the turbine compartment or fuel
handling system of an operating gas turbine.

PSSBs

2018-1003, Online collector-maintenance awareness.
2018-0709-R2, Observation of hexavalent chromium on parts during outage.
2016-1220, GT upgrade—Impact on HRSG.
2016-1209, Gas-turbine water-cooled flame sensor false flame indication.
2016-1117, Lifting and rigging devices.
2016-1104, Gas-turbine operational safety GEK update.

Some of the GE material pertinent to Frame 6 owner/operators goes beyond the basic engine. Example: PSSB20161220, “GT Upgrade Impact on HRSG,” presents the experience of an owner that learned an engine upgrade had been implemented without sufficient evaluation of the safety impacts on the boiler. Specifically, the new steaming capacity was greater than the nameplate rating and the relieving capacity of the existing safety valve.

This is a serious concern. But don’t expect to get a meaningful HRSG discussion going at a meeting focused on gas turbines. For that, you should participate in the HRSG Forum with Bob Anderson. Join the discussion at the first HRSG Forum in 2021, on May 3, by registering for the two-hour virtual event at no cost.

Finally, remember that there’s a fast amount of safety-related information readily available to owner/operators on the CCJ website, where you can find best practices submitted by colleagues over the years.

Below are a few of the discussion topics pursued, and thoughts shared, at recent meetings of the Frame 6 Users Group. Some you may have missed and are of current value, others might trigger some ideas to discuss at the upcoming roundtable sessions May 4 and May 18 from 10 a.m. Eastern to about noon. Access the complete agenda and registration form (no cost to users) on the Power Users website.

Proper electrical and I&C wiring inside the compartment important to unit reliability. When troubleshooting failing or failed sensors, technicians sometimes find that the temperature limit of their wiring is less than the compartment temperature. Poor-quality conduit should be avoided, too. One contributor to this discussion said that at his plant sensors are wired to relays to identify failed sensors.

Avoid water washing your compressor before an outage to minimize the possibility of corrosion. However, do water wash after an outage.

Clear the bellmouth drain after a compressor wash. You don’t want a couple of feet of water accumulating at the compressor inlet where it can be sucked into the unit on restart.

Relocate compressor bleed valves from inside the package to the outside for better reliability.

Check exhaust thermocouples during startup for possible problems ahead. If you a T/C lagging the others by about 100 deg F, and eventually catching up, consider replacement at your next opportunity.

Failure to restart after a unit trip. Check for sulfur buildup in stop/speed ratio valves.

Trip on low lube-oil pressure. A root-cause analysis revealed that regulator valves had not been serviced in more than three decades. Diaphragms became brittle and failed. Recommendation: Add diaphragms to your PM checklist if not already there.

Fire protection is a perennial topic. A user noted that the CO2 system at his plant discharged before the alarm activated. Having reliable alarms and external lighting to warn of a release is critical to personnel safety. One got the impression from the discussion that controls for fire-suppression systems—water mist and CO2—may not be as reliable as they should be. It can be difficult to find qualified vendors to maintain these safety systems, according to a few participants. One said he double-checks third-party certifications and any work done on the system.

Attendees were urged to check package integrity for leaks because if leakage persists—at louvers, for example—you can’t maintain the inert atmosphere while the unit cools. Louver mechanisms on legacy units were identified as a problem area and characterized by one user as being “rinky-dink.”

Difficulty in synchronizing a black-start unit revealed the following to investigators: The Mark VI auto-synch feature was not turned off and the breaker closed with electricians in the generator auxiliary cabinet—a safety no-no. The outcome from this incident was a modified startup procedure that requires operators to confirm excitation at 50% speed on black-start units. Electricians also must check the GAC to confirm there are no faults prior to startup. Finally, a warning sign was hung on the cabinet door and operators are required to issue stop-work notifications to electricians during engine starts.

Unit trip on high oil temperature without alarm notification. Recorded data did not indicate any change in oil temperature. The alarm for high oil pressure was found faulty. The gremlin was a loose wire. Termination strip was repaired and the unit returned to service the same day. User sharing the experience said termination strips can take just so much abuse and suggested that the person you assign to work on them should be someone you trust with a screwdriver.

Locate safety boxes at strategic locations around the plant to retain PPE-use requirements for specific tasks and equipment. Also, consider locating specific tooling at use locations. One example given was the placement of toolboxes on top of the HRSGs to reduce the need for technicians to travel back and forth to a central location, saving time and reducing the risk of injury.

Plant equipment meeting expectations? Check the performance dashboard

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

BASF-Geismar’s operations staff was challenged to develop a tool that provides a simple and intuitive display of the performance of the Utilities Dept’s systems and equipment. Critical to the development of a user-friendly performance dashboard are the following:

    • Identify the proper key performance indicators (KPI) to monitor.
    • Model equipment/system performance accurately to provide appropriate target values under varying operating conditions.

The KPIs selected for monitoring included gas-turbine output and heat rate, boiler efficiency, steam venting, steam letdown through PRVs, specific power consumption for compressed air, and purchased steam.

Some KPI target values were a constant value—such as zero for steam venting and 70,000 lb/hr as the target for purchased steam. However, many KPI targets vary with operating conditions.  For instance, the expected efficiency of a boiler is not a constant value but varies based on boiler load, changes in fuel composition, etc. Similarly, gas-turbine output varies considerably with ambient-air temperature.

Equipment and system performance models were developed for a wide range of operating conditions. At BASF-Geismar Utilities, most of the modeling was based on real-life operating data collected when the equipment was known to be operating well. Thus, the operational targets are proven performance metrics and not necessarily based on new equipment design data, which in some cases may not be appropriate.

Because of the varying targets for different operating conditions, performance indices were developed for many of the KPIs. A performance index is a calculation to gauge how well a piece of equipment, or process, is meeting its defined expectation—or more simply, its target performance. A performance index of 1.0 indicates the equipment/process is exactly meeting its goal; a higher score, exceeding expectations; a lower score, not meeting expectations.

For processes measured by a value that increases with improved performance, the performance index is the actual performance divided by the target performance. To illustrate, if at a given condition boiler efficiency is expected to be 82.0% but the actual performance is 82.4%, that performance index would be 82.4÷82.0 = 1.005.  The result is greater than 1.0, indicating satisfactory performance.

For processes measured by a value that decreases with improved performance, the performance index is the target value divided by the actual performance. An example is gas-turbine heat rate, a measurement of fuel consumption divided by the unit output. If the expected heat rate of a gas turbine is 12.0 million Btu/MW and the measured (actual) performance is 12.25 million Btu/MW, the performance index would be 12.0÷12.25 = 0.9796. The result, being less than 1.0, indicates poor performance.

The performance index is not useful for comparing the performance of two unlike pieces of equipment. For instance, if equipment A, which normally produces 80 units per day instead produces 85 units is compared to equipment B which normally produces 100 units per day but instead produces 95 units, the performance index score for equipment A would be higher yet equipment B still produced more units. But if one does not look at the performance index value, one might think equipment B is doing well because it is out-producing equipment A while in fact it is underperforming its expectations.

The dashboard created (figure) shows KPI data together with a green, yellow, or red indicator light—to provide an instant indication of performance. An Excel spreadsheet was used to download the necessary process data from AspenTech Explorer and perform the necessary calculations.

The performance data displayed shows average values for periods of one, four, 12, and 24 hours along with the current performance. Providing data in this format allows performance trending.

Note that the small button with the “T” is a quick link that opens a trend graph for that particular parameter. Another quick link at the bottom of the dashboard opens a troubleshooting file which can be used as a guide to correct poor performance.

To create some competitive spirit among operators and shifts, there’s a “score” in the top right-hand corner showing the number of green lights compared to the maximum possible number of green lights. Current performance data are not included in this score as it changes on a minute-to-minute basis.

For the dashboard shown, the first three rows of performance data are KPIs monitored using performance indices with target values that vary with operating conditions; the bottom row of data are KPIs that have fixed target values.

From this display you can see boiler No. 4’s efficiency performance was unsatisfactory but improved. Similarly, steam was vented hours ago but the vent is now closed. Condensate return rates dropped and are still marginally low and should be investigated/addressed.

Data displayed in this manner does not tell, for instance, which boiler is operating most efficiently, but rather indicates how the actual boiler efficiency compares to the expected performance.

Boiler efficiency controller improves performance through process automation

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

Boiler combustion controls are designed to optimize the air flow to the fuel flow rate such that sufficient air (oxygen) is available for complete combustion and the amount of performance-robbing excess air is minimized. Recall that insufficient air results in the formation of excess carbon monoxide, a regulated parameter, as well as a loss in efficiency because of incomplete combustion.

Part of the air-flow controls programming at BASF-Geismar allowed for operator adjustment of the stack O2 set-point value—an O2 bias value. An operator could enter a negative bias in an attempt to lower stack O2, thereby increasing boiler efficiency. But if the O2 value were reduced too much, insufficient air would be available for combustion, thereby producing an excessive amount of CO. By contrast, if the O2 bias value was set too high, an excessive amount of air would be used, leading to inefficient combustion.

Powerplant board operators have many duties and do not have the time to babysit the O2/air controllers to fine-tune the O2 bias value and to make adjustments each time boiler load or fuel composition changes. To avoid nuisance CO alarms, operators typically would set the O2 bias to a high value, contributing to inefficient operation.

Initial solutions revolved around trying to give operators target efficiencies to hit, thus letting them know at about what point the CO would “break-through.” This was only moderately effective because the target efficiency varied with boiler load and fuel composition, and occasionally CO break-through would occur before the target efficiency could be reached—for one or more of several minor reasons.

Plant personnel ended up modeling boiler efficiency over a wide range of operating conditions and fuel compositions and created characterization tables that could calculate an accurate efficiency target for the given operating conditions. This model was used to generate a set point for an efficiency controller, which when in automatic, would compare the actual boiler efficiency to the efficiency target (set point) and adjust the O2 bias automatically.

The efficiency controller automatically lowers the O2 bias value until (1) the target efficiency is reached, (2) the CO level starts rising (at which time the efficiency set point is adjusted lower, thereby increasing the O2 bias value), or (3) the minimum O2 bias value limit is reached. In essence, the new efficiency controller automatically adjusts the O2 bias value to achieve the target boiler efficiency, and the CO controller is configured to adjust the efficiency set point on the efficiency controller should CO emissions rise too high.

Control schemes, before and after the staff effort, are illustrated in the diagram.

Results: The efficiency controller and CO override controller have worked very well. Operators no longer have to adjust the O2 bias value as it now is generated automatically. The boilers operate at the targeted values and any CO excursions are handled automatically without operator intervention.

Sharing of best practices a top priority of the Frame 6 Users Group

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

BASF Geismar – BASF Chemical Co
160-MW, gas-fired, 2 x 1 combined cycle cogeneration facility location in Geismar, La.
Plant Manager: Jerry Lebold

The sharing of best practices among owner/operators contributes to safer working conditions and to increases in unit availability and reliability fleet-wide. The Frame 6 users have been proactive in this regard, contributing their experiences during the annual meetings as well as in the group’s online forum, now hosted on the Power Users website.

J C Rawls, a technology engineer in BASF-Geismar’s utilities department and a member of the Frame 6 User Group’s steering committee, has been particularly helpful in explaining the details of his work on boiler and powerplant performance improvement to colleagues at the annual meetings and with the industry at large through CCJ’s Best Practices Program.

Three entries submitted by Rawls recently have been recognized with Best Practices Awards and may be of value to you. One discusses a home-grown boiler efficiency controller that improves performance through process automation, another describes a performance dashboard that tells at a glance if a particular system or piece of equipment is meeting operational expectations.

Finally, in “How to configure controls for economic steam dispatch,” Rawls discusses a proven controls scheme for the efficient production of steam from six boilers (unfired HRSG, duct-fired HRSG, and four conventional boilers) for two-dozen chemical manufacturing units typically requiring from 630,000 to 860,000 lb/hr of superheated steam at 615 psig.

What to do before relocating a gas turbine

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

Turbine Tip No. 9 by Dave Lucier, owner/GM, PAL Turbine Services, applies to General Electric package power plants (PPP), including the following: Model Series 5001P, 6001B, and 7001 B-EA.

Suppose your company has purchased a pre-owned PPP and must move it to a new location. Such resales have become more popular recently as the original purpose of this equipment (peaking and emergency power) has ended for many electric utilities. These plants can be relocated successfully, but it is important to engage a knowledgeable crew supervised by an experienced senior field engineer as technical director. This is no job for amateurs if you want to retain your asset’s value.

Preparation work should reverse the OEM’s original “as-installed” procedure from perhaps 40 or 50 years ago. Nobody working at your plant likely remembers that installation process. Plus, there may not be any GE installation records, field-engineer reports, or information available on how to move this unit to a new foundation.

Bear in mind that to safely uproot and move a GE frame gas turbine, specific procedures must be followed. Among them are those described below:

    • Remove the side panels adjacent to the turbine shell (Fig 1), taking note of the two shell supports, bolting, and dowels. Each support foot has four vertical bolts and one dowel (Fig 2).

    • Loosen the bolts for the two support legs shown in Figs 3 and 4 and install mechanical jacks temporarily at each of the two vertical-joint locations. Next, jack up the shell about 15 mils so a shipping pin can be installed in the lower centerline gib key. Shell lifted, tap loose the shims under the support feet, which may be rusted in place. Note that the turbine must “ride” on a shipping pin in case it is “humped” during transport. This can happen when the machine is lifted by crane or transported by truck or train. Damage could occur to the compressor blades and bearings if the unit is not prepared properly.
    • Bolts for the exhaust seal should be loosened, otherwise they may “snap” when the shell is jacked up. The bolts may be rusted, so be prepared to replace them after tapping the holes (Fig 5).

    • Notice the loosened fasteners and elevated dowel pin between the bolts at the left in Fig 6. The dowel remains in place, shims tapped loose, and support legs are not supporting any turbine weight. Fig 7 shows the pin installed to support the turbine shell during shipping to prevent “humping” of the shell. Red tag is to remind personnel that the dowel should be removed after jacking at the new location. Then the legs can be bolted down to support the shell.
    • The horizontal gib key bolts in Fig 8 can remain in place on each side as long as a 25-mil feeler gage can be slipped in to assure the shell (not shown) is not “pinched.” This will maintain the horizontal centerline and shell position. Once they are installed, the mechanical jacks supporting the casing can be removed.
    • Front flex-plate bolting need not be disturbed.
    • The rotor must be pushed axially against the active thrust bearing (located internally on the opposite end at the No. 1 turbine bearing) to keep the rotor secure during shipment. The axial internal clearance between thrust bearings is about 16 to 19 mils. Use a dial indicator (not shown) to “thrust” the rotor backwards against the active thrust bearing (Fig 9).
    • There’s no need to disturb the front compressor flex support when preparing for the move (Fig 10).

 

 

Replace your ageing CO2 fire protection system

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

Turbine Tip No. 10 by Dave Lucier, owner/GM, PAL Turbine Services, applies to General Electric package power plants (PPP), including the following: Model Series 5001, 6001, and 7001.

GE PPPs originally had Cardox CO2 fire protection (Fig 1) with individual bottles of suppressant connected in two systems—initial burst and sustained delivery—to three compartments: accessory base, combustion, and load gear and exhaust area. Frame 5 and 6 engines with reduction gears had two overhead “trap doors” that closed when the discharge occurred, to mitigate CO2 flow into the air-cooled generator from the load-gear compartment, thereby protecting the generator from contamination.

Each of the three compartments was equipped with color-coded temperature sensors indicating the ambient temperature allowed (Fig 2). If the temperature exceeded the setting in the tip sensor, the bottled suppressant would be discharged to extinguish the fire.

Location, location. Most GE gas turbines had fire protection systems installed inside their control cabs, taking valuable space away from plant operators. Owners typically didn’t like having the bottles so close to personnel, often moving them to an adjacent building (new or existing), thereby opening up space for a desk and chair. Fig 3 illustrates a system and batteries that were moved outside the control cab.

Enclosures for PPPs are supposed to be sealed to contain any fire that might occur. The goal is to entrap the fire and smother it with suppressant, extinguishing it as soon as possible. Thus, door and panel seals must be maintained in good condition (Fig 4). Insurance companies may require plant operators to “prove” the integrity of the sealing system.

Many insurance companies now are requesting that owners consider replacing antiquated fire protection systems. But before doing this, be aware of the following onsite considerations with the existing enclosures and fire sensing systems:

    • Test the existing system for leaks—that is, deliberately discharge suppressant into the compartments to locate leaks, holes, rusted panels, etc. It is very likely that the door and panel seals have rotted, and the panels no longer fit properly to envelop and contain the compartment.
    • Refer to the schematic piping diagrams for the tip ratings of compartment temperature sensors. Typical settings are as follows:
        • Accessory compartment, 45FA-1 and 45FA-2 (200F nominal).
        • Turbine combustion compartment, 45FT-1 and 45FT-2 (600F nominal).
        • Load gear (exhaust plenum) compartment, 45FT-3 and 45FT-4 (500F nominal).

Caution: The CO2 fire protection system is passive. It remains in standby mode until a fire occurs in one of the compartments.

Personnel should “pin” the system whenever personnel are working in the area to prevent accidental discharge. If you think this can’t happen consider the following experience: During cranking checks on MS5001L fuel-regulator controls, a flexible coolant line feeding the diesel cranking engine burst, igniting the ethylene glycol. A flame ball roared through the accessory compartment and the CO2 system discharged to extinguish the fire. The technician was not injured seriously—thankfully—and no lost-time accident was recorded.

 

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