OEM’s team identifies challenges facing 7EA users, provides guidance, offers solutions

To say that developing and organizing content of interest and value to owner/operators of a gas-turbine fleet as large and diverse as the 7B-EA is challenging would be trite. It is a Herculean task. Be mindful that the 1168 engines in this fleet (the OEM’s number in fall 2017) serve in simple-cycle, combined-cycle, and cogeneration systems, operate on multiple fuels, may be anywhere from less than one to nearly 50 years old, generate from about 52 to 90 MW depending on the model and year of manufacture, and are fighting to remain relevant and profitable in a variety of electricity markets in a rapidly evolving industry.

Consider too that customers are demanding more from their services partners, and while the 2017 program focused on the core engine, it included total plant considerations (Fleet360* in GE’s lexicon) involving the steam turbine, generators, HRSGs, environmental control, digital solutions, and balance of plant. Additionally, cybersecurity and regulatory initiatives.

Tall order.

GE brought its A-team of subject matter experts—at least 20 by the editors’ count—to St. Augustine to present, answer user questions, and conduct roundtable discussions during breakout sessions. It’s impossible to do justice to the OEM’s contribution in a summary here of only 1500 words. The highlights, in the eyes of the editors, are presented below. If you want to dig deeper, the first place to look is in the presentations section of the 7EA Users Group website; be prepared to sign up if you’re not already registered. For more information, reach out to your plant’s customer service rep.

Perhaps the two most significant announcements made during GE Day, which began after morning coffee Tuesday and ran until OEM’s “Open House” (dinner and exhibition) at 5 pm, concerned GE’s revamped field-service operation and a change in the rotor maintenance-factor calculation.

Field services. Regarding the first point, the OEM essentially severed its field-service employees from GE employment in August 2017 and allowed most of them to interview for positions in its wholly owned subsidiary, FieldCore, which aggregated the field-service resources from GE Power Services and Granite Services International Inc—at least that’s the way the editors understand the organizational changes. Note that Atlantic Plant Maintenance, a wholly owned affiliate business of GE Power Services that provides craft labor in the US and Canada, was not rolled into FieldCore.

The users were told during the GE-sponsored evening reception that they should continue to contact their regular GE rep to arrange for field-service support. Billing will continue to be directly through GE to the customer. The FieldCore regional GM addressing the group said his organization would continue to provide quality field-service support to/for GE while driving down costs.

There was significant chatter among users during coffee breaks regarding the shift to FieldCore. As you might expect, most of the discussions were negative: Change is difficult for most people to accept without at least some grumbling. Attend the upcoming meeting of the 7EA Users Group in California, October 7-11, to learn more about the transition of field services to FieldCore and how its processes are changing to better suit the customer.

Forced cooling. Shortly before the 2017 meeting, GE published Revision N to its “Heavy-Duty Gas Turbine Operation and Maintenance Considerations (GER 3620),” introduced nearly three decades ago. It generally is recognized as the company’s “bible,” providing frame owner/operators guidance on O&M tradeoffs for the company’s engines.

It’s important for users to obtain a copy of this document and to keep up with future revisions—you never know what surprises it may have. In Revision N, the change creating the most concern among owner/operators is believed to be the one related to the impact of forced cooling on the rotor maintenance factor.

It states that should an operator force-cool a unit after operation, there will be a 4× impact on the maintenance factor for that start. An OEM representative said this applies to E-class units and defined forced cooling as cranking a gas turbine (after a start/run) for an extended period of time at more than 60 rpm. “Extended” was not defined in terms of hours.

Also said was that the maintenance-factor calculation for forced cooling had to be “back calculated” in determining “factored starts” for rotor maintenance actions.

Owner/operators of legacy E and EA models with cranking turning gears (versus ratchet-type turning gears) and cranking speeds above 60 rpm to avoid bucket-rock damage should take a deep breath: A significant addition to the number of factored starts will occur.

Until now it has been “routine” for many plants to force-cool their gas turbines to reduce the time required for maintenance outages and offline compressor washing. This new calculation suggests operators might want to rethink their cooldown procedures. Also, staff at affected plants should review operating logs to determine how the new calculation impacts their rotor-inspection schedule. Presentations at various user-group meetings indicate a two- to three-year planning phase may be required and it’s possible you’re now late getting started. 

More bad news: The unit trip factor is now 2×.

NERC requirements. “Responding to NERC MOD and PRC Standards” was another presentation containing information you might not want to be reminded of, but necessary. It covered the required testing and model validation required to comply with standards that would be July 2018 enforceable. Obviously, that date has already passed. So if some of what follows comes as a surprise to you, it’s a good idea to learn quickly and bring your plant up to current requirements.

The first part of the presentation focused on testing that should be conducted to understand the capability of your equipment and to get the most from it. This is an important step to assure full compliance with NERC standards. The speaker reminded that manufacturer “design” may have a wide range of “normal” and retuning of controller settings or retrofit of late-model digital controllers may result in significant deviation from “book ratings.”

Additional benefits of testing include the following:

    • Recognition of deviations, enabling a refinement in tuning.

    • Better coordination with protection systems.

    • More effective training of staff because of testing at the bounds of control—that is, non-normal operating modes.

NERC model validation standards reviewed were these:

    • MOD-025-2, “Verification of Generator/Plant Real and Reactive Capability.” Requirements include verification of the maximum continuous real power output and lagging and leading reactive power outputs; calculation of transformer losses; analysis of test results and manufacturer’s stated limits; submission of data reporting forms; documentation of auxiliary load consumption.

    • MOD-026-1, “Verification of Dynamic Models and Data for Generator Excitation Control and Plant Volt-VAr Control Functions.” Requirements include submission of an excitation control system description, and of an approved model for the generator, exciter, power system stabilizer, and plant volt/VAr controls. Plus, verification that the model simulation matches the response from a disturbance.

    • MOD-027-1, “Verification of Dynamic Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions.” Requirements include submission of a description of the governor and load control system, and of an approved model for the governor and plant active power controls. Plus, verification that the model simulation matches the response from either a significant disturbance or an online speed governor step test.

So much for the details. To learn more about applicability and timing of the model validation standards, access the presentation on the 7EA Users Group website. Keep in mind that the generation owner is responsible for model validity; also that one size does not fit all: applicability differs in the East, WECC, and Ercot, as does the timing of compliance.

Typical tests were profiled by the presenter and test-equipment requirements were defined, followed by analysis and reporting requirements. If you feel overwhelmed after reviewing all the things you’re responsible for beyond safety, top availability, high starting reliability, low heat rate, etc, you can turn to GE Energy Consulting for help. The short promotional section of the presentation mentioned this group has tested more than 1500 units and has experience with all major OEM equipment.

Technical Information Letters. A review of the latest TILs is always of value. It’s easy to miss communications on these important missives during busy periods. The four TILs highlighted at the 2017 meeting were these:

    • TIL 2046 describes DLN1 purge-valve operating issues (potential gas backflow into the wrapper) and actions to mitigate them.

    • TIL 2028 provides control settings for Reuter Stokes flame sensors. Be aware that false flame detection is possible if the threshold is set too low, resulting in unburned fuel delivery.

    • TIL 2025 addresses dry GE Reuter Stokes Model FTD325 flame-scanner false indication on shutdown.

    • TIL 2044 addresses dry GE Reuter Stokes Model FTD325 flame-scanner false indication while offline.

A session on typical B- and E-class rotors revealed the following findings:

    • R-17 compressor vane migration has been attributed to staking variability. A new standardized method of staking has been implemented. It notches the R17 vane near the center of the wheel and wheel material is moved into the notch on the vane.

    • TIL 1049 regarding history and recommended checks for wear on turbine-wheel dovetails was discussed. Repair personnel were reminded to check platform gaps, and if they are “out of band” then perform a “pin check.”

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