The presentation at the 7F Users Group’s 2020 Digital Conference through Week 3 (two weeks to go) that has generated the most questions and discussion among attendees concerned a leak in a plate-and-frame lube-oil cooler.
Go figure!
How could a mundane leak generate this much interest at a high-tech meeting? Read on: There are some lessons learned you may benefit from.
The background: One 7FA at a 2 × 1 combined-cycle cogeneration facility was out of service for an outage. Lube oil to the unit was shut off, but cooling water was still running through the plate-and-frame heat exchanger. This had been standard practice for the last 18 years. During that time plant personnel had performed the periodic heat-exchanger cleaning required without incident.
The problem: Water pushed through the exchanger’s gaskets after the lube-oil system was secured. Water then ran through the exchanger discharge and all associated systems, and contaminated the 6400-gal oil reservoir. By the time the leak was found and the water shut off the reservoir level had risen by more than 3 in., causing oil to flow from the explosion doors. A quick calculation revealed that about 400 gal of water had been added to the oil reservoir, creating a milky mixture in the tank.
Staff considered that after its last cleaning the heat exchanger might not have been tightened to the applicable “crush” specifications for that model and the number of plates it has. The exchanger was disassembled and the gaskets inspected. No damage to gaskets or plates was in evidence, so the lube-oil cooler was cleaned and reassembled. Alfa Laval, the manufacturer, was asked to provide a formula to guide reassembly and assure the proper crush. The total inside spread between the end caps of this unit with 106 plates was calculated at 18.56 in.
Given that proper crush is so important to leak prevention, consider verifying the specs for your exchangers. And when using outside labor for cleaning, share this information with that team; it’s not just a matter of “tightening” a few bolts/nuts after cleaning a plate-and-frame exchanger, as some might think.
Another thought was that the leak began when the lube-oil system was shut down because the oil cooled. The logic: When the oil was hot, expansion prevented leakage of water into the oil side of the unit.
In either case, the takeaway is obvious: Avoid leakage by shutting down the water system before taking the lube-oil system out of service. This lesson learned has been incorporated into plant procedures.
However, a couple of attendees listening to the presentation reported having the reverse occur, with lube oil leaking out when water was “isolated in the compartment.” The fix here was gasket replacement and right-torqueing. This exchange among users, and others like it during the 7F event, was proof that a virtual conference done correctly can be as effective as a conventional meeting for sharing experiences—possibly even better.
Another attendee suggested all gaskets be replaced every couple of years or so because they lose their resiliency. Yet another mentioned baking the gaskets to cure them after cleaning. There was no follow-on discussion related to this suggestion, however.
The presenter said a vacuum truck was brought onsite to remove the oil/water solution in the lube-oil sump. The dregs then were mopped up by hand, the lube-oil filters replaced, and the tank refilled. Entire process took three days. The plant didn’t pursue centrifuging/vacuum dehydration to save the oil because the cogen facility was necessary to support process operations.
A similar situation was reported by another attendee who said the issue at his facility was brittle gaskets in the heat exchanger that failed once the oil pressure was off the unit and cooling water was still in service. It was a mess, he said, with oil spilling out the explosion doors as the speaker had reported earlier.
This tank also was drained and mopped clean before new oil was added. Oil could not be salvaged, the user said. Two days were spent trying to save it before deciding on disposal. Next step was to replace gaskets on all of the plant’s plate-and-frame heat exchangers serving the 7Fs and D11 steamer. All those assets were commissioned around 2000.
The takeaway from this session suggests that if you have Alfa Laval lube-oil coolers installed during the bubble years and have not replaced their gaskets it might be time to consider doing so. A user suggested buying a spare set of plates with gaskets (glued on or clipped on) then swapping them out with the plates in service. Job should take about four hours based on his experience.
Someone else added that when you send plates to Alfa Laval for refurbishment a Zyglo inspection also is performed. It detected a pin hole in one of this user’s plates that allowed oil to enter the cooling-water system.
The 7F Steering Committee invigorated last Wednesday’s (Day 7, July 1) program by leading off with a discussion session on rotors rather than a user presentation on the subject, as had been the norm for the other days of the event. The format was simple: A committee member and special user guest greased the skids, so to speak, on the subject of rotor maintenance, and attendees provided a seemingly endless string of questions and experiences. In fact, the discussion leaders had to hit the session trip button so the next speaker, Doosan Turbomachinery Services’ VP Engineering Glenn Turner, could make his presentation.
The two discussion leaders combined have fleet-level maintenance responsibility for more than five dozen 7FAs. They began with a brief introduction of the OEM guidance documents of greatest importance to anyone involved in the rotor-maintenance process—read end-of-life (EOL) inspections and life-extension work. They are GER-3620, “Heavy-Duty Gas Turbine Operating and Maintenance Considerations” and Technical Information Letter 1576-R1, “Gas Turbine Rotor Inspections.”
TIL 1576-R1 refers you to GER-3620 for overall guidance on all centerline maintenance. The latter is now at Rev N (November 2017) which is important for you to have. Don’t have a copy? A simple Google search can provide access. Or, a copy of the presentation may also be helpful and can be accessed on the secure, user-only website of powerusrs.org.
Rotor life limits for the 7FA are 144,000 factored hours or 5000 factored starts, depending on whether your machine is starts- or hours-based. The pages in Rev N of interest to this discussion are 30 to 35, with Fig 45 being particularly important. Reason is that the impact of forced-cooling on rotor inspection calculations is now a consideration, replacing the “trip from load factor” in earlier versions of the GR-3620 document.
Attendees were polled on how they operate their units. More than half (52%) said their machines were hours-based, 16% starts-based. For users with multiple units, 27% said they had a mix of hours- and starts-based machines. Interestingly, only 5% of the attendees said their units had switched from starts-based to hours-based, or vice versa.
Calculation of factored starts can be challenging. There was considerable discussion of what to include in your determination. One of the session leaders illustrated how he calculated the rotor maintenance factor for one unit, which was 1.4 multiplied by actual starts.
The other discussion leader said this was fine, provided the entire rotor has been together for its entire life. If not, track the operating histories of individual components—such as the compressor and turbine if they have been decoupled. This approach likely benefits the owner. GE, it was said, considers the rotor one component.
Other points also were made to illustrate the complexity of factored-hours/starts calculations (particularly the latter). Attendees were urged to do make their calculations as accurate as possible to avoid leaving “life” in the rotor before removing it for an EOL inspection. How would you factor the following into your calculations?
-
- Control system changes.
- Staff changes.
- Ownership changes.
- Upgrades—such as going from 24k hours to 32k on a Dot 04 upgrade.
An idea for extending rotor lifetime surfaced: Shift your high-hours machine to a starts-based unit. No guidance was offered, however.
It might appear that calculation of the maintenance factor might be a task assigned to the DCS. But that’s not true. A poll showed only 14% of the attendees used the DCS to calculate maintenance factor; 37% said “No” outright. Another 16% said they weren’t sure; double that number track maintenance factor outside of the DCS.
Safety drives rotor EOL inspections. The experts say gas-turbine casings are not designed to withstand a rotor wheel burst, so if that were to happen personnel could be hurt, possibly killed. Rotor disassembly and inspection can mitigate this risk by identifying wheels that should be replaced. The failure of other components, it is said, would cost money and time but likely would not be life-threatening. Cyclic operation is of particular concern because it induces thermal transients and mechanical stresses on the rotor.
Attendees were asked if they were planning on 7F rotor maintenance in the next five years. “Yes,” based on GER-3620 guidance, was checked by 57% of the users participating; “No,” 29%. The remaining 14% said they had to learn more before deciding.
A few takeaways from the conversation included the following:
-
- Experience from units hitting the 5000-starts limit: Turbine sections typically are in “pretty rough condition.”
- The aft end of the compressor gets most wear and tear on cycling units. Think about replacing the 17th and 16th stage wheels at EOL, perhaps even one or more earlier rows. Suggestion was to have a qualified company help you determine if this is a good idea.
- Expect to replace the first-stage turbine wheel on most starts-based units.
- Poll: Have you performed a rotor lifetime assessment? “Yes,” 22%; “No,” 78%.
- One of the nation’s largest utilities reportedly has not yet hit EOL on an hours-based unit.
- Poll: What are you planning for? Exchange rotor, 29%; lifetime extension, 32%; new rotor, 12%; undecided/do not know, 27%.
Roointon Erach Pavri had recently retired from GE Energy when he was recognized for “extraordinary contributions” to the electric power industry with the Frame 6 Users Group’s 2007 John F D Peterson Award (photo). Pavri had achieved “hero status” with this organization for his technical leadership in resolving complex gas-turbine application issues.
He graduated from the University of Cincinnati with a doctorate degree in aerospace engineering in 1972 and worked in numerous engineering roles in Schenectady and Atlanta for more than three decades, authoring many technical publications. Pavri had two patents to his credit. The gifted engineer probably was best known in the industry for his work in reducing emissions from GE frame engines. The OEM recognized Pavri’s achievements with its coveted Edison Engineering Award in 2004.
John Downing, Turbine Controls & Excitation Group (TC&E), celebrated the company’s 10th anniversary with a presentation last Wednesday at the 7F Users Group’s 2020 Digital Conference. He reminded the 300 or so owner/operators in attendance that many gas turbines are starting and stopping far more frequently than originally designed for. At the same time, independent system operators (ISOs) are imposing stiff fines for failure to meet startup and performance obligations.
Most plants have adapted to these more aggressive operating tempos and performance challenges, but one component that may be getting overlooked is the starting subsystem, especially for older machines equipped with a load commutated inverter (LCI).
Downing says that the Innovation Series™ and LS2100 LCIs, introduced in the late 1990s and early 2000s, consist of three subsystems, or functions: control section, silicon-controlled-rectifier (SCR) bridge section, and cooling section. For units not originally designed for lots of starts, it was common to have one LCI for multiple GTs, often in a one-to-two ratio.
For nearly 25 years, the LCI has provided reliable service. However, with an expected life of 20 years, many have failed, and a substantial number are at, or past, end of life. Failures usually are experienced in the controls and/or the cooling system.
Last production of the Innovation Series and LS2100 LCI controls supplied with GE machines was in 2013. Today, replacement parts are difficult to locate; acquisition times of four to six weeks are common. Also, qualified service and field engineering personnel are becoming harder to find as they retire out of the workforce.
Options to address this risk include the following:
-
- Complete replacement of the LCI.
- Locate, purchase, and inventory critical spare parts, especially those relating to the control and cooling sections, and identify the engineers and technicians qualified to make the replacements when the time comes.
- Install a “digital front end” (DFE) control section replacement. In this case, the controls are replaced with a modern alternative that extends LCI life by 20 years.
TC&E partners with TMEIC, one of the world’s largest manufacturers of LCIs and drives, to provide a turnkey DFE solution that Downing says is far less expensive than the other two options.
Guts of the partnership’s offering are as follows: The obsolete programmable logic controller (PLC), standard VME (Versa Module Europa) rack, power supplies, and input/output (I/O) boards are replaced with new processor-based control circuit cards and a new PLC. The new digital controls fit in the existing panels and reuse most of the existing fiber optic cables and connectors.
The upgrade includes a local color touch-screen control panel and HMI interface.
In the control center, the associated software suite expands the programming, control, optimization, troubleshooting, and data logging of onsite operations, engineering, and maintenance personnel. The new LCI DFE utilizes appropriate communications protocol to talk directly to the GE Mark VI and Mark VIe control systems.
The typical upgrade project can be accomplished in about five days; a turbine shutdown is not necessarily required, although, of course, the LCI will be unavailable for that period.
Presentations on turbine lubricants and/or their maintenance are oft-discussed subjects at user-group meetings. Plus, you can expect to see a half-dozen or more companies in the exhibit hall offering fluids and varnish-removal systems—all competing for your business. Having so much information from disparate sources can make it difficult for a user to decide on the optimal lubrication and treatment options for his or her plant.
How about starting anew? Listen to EPT’s Matthew G Hobbs (video below) who recommends that you treat your turbine fluid as an asset, not a consumable. You’ll probably make better decisions if you do. Hobbs “knows his stuff” and has the sheepskin and experience to support his research and findings. Plus, he speaks clearly and is an excellent “explainer” of things you probably should know. The presentation is only an hour.
Hobbs encourages you to understand and use the tools at your disposal to eliminate unpredictable oil-related failures, which can cause astronomical unbudgeted expenses. His best-practices recommendations include these:
-
- Select high-quality lubricants from reputable manufactures/suppliers.
- Exercise caution with aftermarket additives.
- Demand reliable oil-analysis data.
- Use a conditioning system to remove varnish-precursors as they form.
- Clean your oil so it can clean your system.
Hobbs shows by way of a case study how to keep your lubricant costs affordable and predictable. Recall that most owner/operators generally decide on fluid replacement when the acid number increases by two- or three-fold and additives decrease by 75%. In round numbers, this means that a nominal 10% annual rate of additive consumption equates roughly to a 10-year lifetime for your oil—assuming conditions remain the same over time. A polling question during the presentation indicated about half of the respondents were getting 10 years or less from their lubricants.
The details of a 10-year case study conducted by EPT for a plant using its ICB™ ion-exchange technology since COD to maintain the fluid in top condition, revealed an additive level at the end of a decade of service of 91%; the acid number has never increased. The oil is expected to serve for another 10 years—at least.
The paradigm shift, Hobbs says, is that by annually adding 5% top up with the existing brand of new oil, in conjunction with ICB conditioning, provides a step change in how the oil ages.
If your staff is not experienced in initiating an emergency purge of hydrogen from the generator, personnel at Hermiston Generating Plant, a 474-MW, 7FA-powered 2 × 1 combined-cycle cogeneration facility have a solution to consider.
Hermiston developed an emergency hydrogen purge procedure during plant commissioning nearly 25 years ago. It required entering the collector compartment and opening the lower compartment where the purge valves are located. But this could be problematic in the event of fire and/or release of CO2 into the compartment.
The goal was to make an emergency purge safer for the individual performing this task. Several options were considered. Here’s what was done: Use the logic already in the Mark V Control Sequence Program and add logic to allow the control room to remotely initiate and purge hydrogen with no one near the generator. The relatively simple upgrade was facilitated by replacing the original hydrogen control cabinet with one from EOne.
Drawings of the successful mod are provided in the presentation. After the logic updates were completed, an emergency hydrogen purge was performed on each unit from the control room. Success! Today, the system is tested annually or when hydrogen is removed from the machine during extended maintenance shutdowns.
Mike Dolan, Hytorc’s chief engineer for fasteners, had only a dozen slides and told the 7F audience at the outset that he probably would finish up in 45 minutes. Not! He barely got done the hour maximum for his session. And it was all “good stuff,” including lessons learned and best practices of particular value to O&M technicians—an ideal presentation for a lunch-and-learn at the plant.
Proper tooling for bolting, he stresses, can make maintenance safer, faster, and more efficient than it is with the tools you might now be using. While acknowledging that most bolting work can be done with simple hand wrenches, Dolan continues, large fasteners require power tools to load and unload them. Gas turbines can be a particular challenge: They have large bolts, and long-term operation at high temperatures and loads exacerbates bolting challenges. He calls gas turbines “galling incubators.”
Dolan discusses torque control offered by powered wrenches and their safety attributes, and reviews hydraulic, bolt-heating, and mechanical tensioning. Galling gets deserved attention as does the company’s tension nut system which eliminates that condition.
Access this recorded presentation today; you won’t be disappointed.
The nondescript title of this presentation, repeated as the headline above, does no justice to its compelling content. A simple “Aaron Frost” would have told you much more. Yes, Frost was back in front of the 7F group sharing his encyclopedic knowledge of metallurgy, repair experiences on selected hot-section components, and views on the promise of additive manufacturing for new parts and for the rehabilitation of old.
Frost was the second of APG’s (Allied Power Group) three participants in the company’s hour-long session, speaking for three-quarters of that time. If you missed the presentation and have responsibility for the repair of hot parts for 7F engines, or simply want to add to your knowledge, access the video on the Power Users website; you’ll be glad you did.
Jeremy Clifton, VP sales and marketing, introduces APG and its recent acquisitions to attendees. Marty Magby, VP business development, follows Frost with an outline of how the company implements engine and plant overhauls to meet customer expectations.
Frost begins with a review of APG’s experience in repairing more than 100 sets of first-stage shroud blocks for the 7FA.03, illustrating some of the enhancements the company has made to extend parts lifetime and improve performance. One example he gave is to add full NiCrAlY side-face coatings on shroud blocks to prevent the oxidation uncoated tiles often experienced after only one service interval. Such oxidation was known to create gaps between adjacent tiles and provide a pathway for seals to go downstream and do damage.
Another enhancement is forward outer block shroud hook recovery which involves machining off the crack-prone original Type 310 stainless steel material and restoring the hook with Hastelloy S weld material followed by finish machining.
Final steps in the restoration of shroud blocks included dimensional checks, finish grinding, and application of a bond coat and a high-density thermal barrier coating on the tile face.
In concluding this portion of his presentation, Frost provides details on the repair of first-stage shroud blocks for the 7FA.04, illustrating how the company’s experience described above for the 7FA.03 qualified it to make Dot 04 repairs as well.
Frost links the shroud-block repair and additive manufacturing (AM) segments of his presentation, announcing that APG had successfully developed and printed a 3D 7FA.03 first-stage shroud tile. He is bullish on the future of AM for making critical gas-turbine parts but believes it will be years before it can be applied to mainstream production. An example he gave was that a single 3D tile for a 7FA.03 today takes about a day to make. Also, that commercial AM production equipment is incapable of making large parts—transition pieces, for example.
The big near-term advantage of 3D printing, Frost continues, is that single parts—such as shroud-block tiles—can be made and replaced, avoiding the need to purchase an entire row. Another advantage is that it’s possible to “print” the damaged section of a given part—second-stage nozzle, for example—and weld it into the original. Plus, the portion being replaced can be made with an improved combination of material, design, and coating changes such that the repair is better than a traditional weld or braze repair.
The final segment of Frost’s presentation discusses what he believes are design improvements to the OEM’s third-stage bucket which can extend the lifetime of these parts. He says that AGP has repaired 30 sets of third-stage buckets without a post-repair issue. Attendees were referred to GE Technical Information Letters 2006-R1 (for the 7FA.03) and 2045 (for the 7FA.04) issued relative to third-stage bucket failure potential.
One of AGP’s improvements is replacing the double-rail on original third-stage buckets with a single rail to reduce weight. Experience has shown this change can extend bucket lifetime from one HGP cycle to two. Also important to extending bucket life is AGP’s tight temperature control during heat treatment and a special fixture that allows vertical orientation of the buckets in the oven to maintain bucket integrity.
A major inspection in March 2020 on one of the gas turbines for a 2 × 1 7FA.03-powered combined-cycle power block at Gila River Power Station revealed severe rubs in the compressor and turbine sections upon unit disassembly. The machine, which did not run at all for 18 months beginning in 2017, operated baseload after returning to service. It had accumulated 53,000 operating hours (1760 starts) since commissioning in the early 2000s. Since the unit’s prior outage, a 2014 HGP, the gas turbine had run a nominal 20,000 hours (300+ starts).
Severe rubs were in evidence on one side of the turbine’s first-stage shroud blocks and on the compressor stator airfoils in Rows 13, 14, and 15 on that same side. Plant personnel found rotor clearances tight on the right in almost all rows of the turbine and compressor.
Schaffer Precision Alignment was contracted to check unit alignment (laser) and found the exhaust frame had shifted 0.071 in. to the right. Advanced Turbine Support, onsite to perform a borescope inspection, was asked to inspect the exhaust struts for any obvious signs of damage. Visual indications were found on two struts with confirmation by eddy current on one. A through-wall crack also was confirmed.
The search for a replacement exhaust frame ensued. The owner opted to purchase one in an as-is/where-is condition to minimize schedule impact. The replacement frame was removed from an unfired unit and shipped to the site. Upon arrival, it was inspected with the following observations:
-
- Large gouge in the stainless-steel liner.
- Support legs had a water jacket around them.
- Bearing housing was a three-piece design.
Plant personnel believed that the gouge probably occurred when the weld was ground out during removal of the exhaust frame. The gouge was filled in with weld material and the frame installed at Gila River. Other actions taken were these:
-
- Weld repairs were made on the exhaust manifold.
- New oil seals were installed on the old bearing housing.
- The existing support legs were reused to avoid having to deal with the water jacket on the new legs. All units in the fleet were believed by staff to be working well without the water jacket.
- Stainless-steel exhaust seals were replaced with Inconel 718.
Schaffer Precision returned to check alignment with the replacement exhaust frame. It was located slightly to the left and high. The condition of bearing No. 2 and its position were checked and the experts agreed that it could be reinstalled and satisfactory alignment could be achieved by adjusting the bearing’s position. That’s what was done.
End notes:
-
- The unit was restored to service after a 45-day outage, nine days less than originally scheduled.
- The old exhaust frame is awaiting root-cause-analysis investigation to determine why the struts cracked.
- Balance was not an issue after the work was finished.
- Damaged airfoils in the compressor were simply swapped out because replacements were available and the job could be completed quickly with new stator blades.
The nearly 300 users attending the Week 4 sessions benefited from six presentations that they considered of high value, judging from the onslaught of questions that carried over into the virtual vendor fair staffed by each of the participating vendors.
Quick access to summaries of user and vendor presentations made last Tuesday and Wednesday is simple: Just click titles of interest in the lineup below.
To dig deeper, PowerPoints or video recordings of the presentations, are available on the Power Users website to registered owner/operators. Registration is easy if you don’t already have a “library card.”
