GE Day: 6B dissected from inlet to exhaust

The Frame 6B OEM was responsible for the Wednesday technical program and split the day with the morning dedicated to fleet-wide topics suggested by the steering committee and the afternoon divided among three discussion-focused breakout sessions catering to specific user interests.

A “state of the frame” presentation launched the GE Day program with highlights of the 6B’s 40 years of service to the industry. The first engine was commissioned in Montana in 1979 and advancements in the technology have been ongoing since that time, the group was told. To date, the 1150 6Bs installed globally have operated more than 65-million hours on a wide variety of fuels with a reported reliability of about 99%. Eleven 6Bs were installed in 2017-2018.

Perhaps the most significant announcement of the day was the startup of the first US 6B AGP (Advanced Gas Path) unit two days earlier. The highlighted benefits: 14% increase in output, HGP (Hot Gas Path) intervals of 32K FFH (Factored Fired Hours), heat-rate improvement of up to 5%, and an increase in exhaust energy of up to 8%. Eight units in Saudi Arabia were said to have the AGP upgrade

Beyond the advantages of the AGP offering, the speaker mentioned solutions for better performance, lower O&M costs, and life extension—including extended turndown, efficiency enhancements, and a flange-to-flange 6F.01 drop in module. Five 6F.01 modules were said to have been sold, but not shipped, at the time of the meeting. Three of these will be configured as hot-end drives.

TILs (Technical Information Letters) important to 6B owner/operators and issued between the 2017 and 2018 meetings were reviewed. A handy table indicating document number, title, date of issue, and degree of importance is available on the user group’s website.

If you are not familiar with TILs 2041, 2044, 2046, 2051 2003-R1, 2060, 2064, 2066, 2076, or 1566-R2, it’s a good idea to come up to speed quickly. Two of these documents are safety-related and five others require compliance, a couple at the first opportunity and one prior to next time the affected system is operated.

The compressor sections for 6Bs generally have been bullet-proof over the years. Problems experienced include IGV (Inlet Guide Vane) cracking attributed to corrosion pitting and rubs; root liberation at the leading edge of some R1 rotor blades believed caused by erosion and corrosion or, possibly, IGV miscalibration; S1 stator vane leading-edge cracking/clashing; and tip loss from some airfoils in Rows 2 and 3.

Mitigation actions were offered. One example is replacement of carbon-steel vane rings with ones made of stainless steel to prevent the lock-up of vanes from rusting and minimize the potential for clashing. Blade health monitoring via sensor probes on the first three compressor stages is expected to help warn of possible clashing by monitoring changers in blade deflection and frequency.

Documents offering maintenance advice for the air inlet structure to improve compressor availability/reliability included PSIB20170428A, GEK 116269, PSIB20130813A, and GEK101944. Add missing documentation to your plant library. Need help? Ask your GE representative.

GER3620N, issued in October 2017 and accessible online with a simple Google search, provides inspection and maintenance advice for the engine proper.

A briefing on the OEM’s new blade-health monitoring system, which relies on vibration signature (probes are installed on the compressor casing) to warn of an impending issue, was a highlight of the compressor presentation. Get details from your GE rep.

Parts interchangeability. Given the fleet’s 40-year service life and the number of people who have had O&M responsibility for your 6Bs since COD, it’s easy to believe you might not know the vintage of parts installed in the engines or those on a warehouse shelf. What parts fit where and how was the subject of a short presentation, “HGP considerations,” that’s worthwhile reviewing before the next outage—especially one involving parts replacement in a row of mixed airfoils. Visit the Frame 6 Users Group website.

Controls. When the first 6B went into operation, the control system offered by GE was the Mark II. Some machines in service today still are equipped with the Mark IV, offered from 1982 to 1991. Many have Mark Vs, manufactured from 1991 to 2004. During the user-only discussion session on controls the day before the OEM’s presentations, by show of hands, four attendees said their units were equipped with the Mark IV; about half of the group’s engines had Mark V. Another third had the Mark VI, the remainder Mark VIe.

The OEM urged attendees to upgrade their control systems to the Mark VIe. There are several reasons to do this, chief among them: availability of parts, cybersecurity issues (patching is not supported), technical support during outages, ability to allow new performance-enhancement options the owner/operator might find of value.

Two modernization options were discussed, full-panel retrofit and migration. A complete control system replacement was said to take about 25 days and possibly require more floor space than the existing system occupies. Migration translates to nondestructive key-component replacement through plug-and-play. All field wiring remains as is—no determination/re-termination. Depending on scope and technician deployment, the migration option could take from about a week to 14 days. This option is less expensive than a full panel retrofit.

The speaker went on to describe stepwise conversions from the Mark IV, Mark V, and Mark VI to the Mark VIe—a good starting point for someone considering an upgrade.

Generators were the last topic on the OEM’s 6B technology agenda. This was the longest presentation of the day and rightfully so: Most plant personnel are comfortable with mechanical work and I&C, and typically have little experience with high-voltage electrical equipment—generators in particular.

The speaker began with an examination of lifecycle considerations. Cyclic operation (starts/stops) taxes the rotor, he said, while operating hours impact stator maintenance intervals. Historically, the speaker continued, rewind risk increases for rotors between years 15 and 20 and 35 to 40, for stators between 25 and 30 years.

The value of GEK 103566 (ask your GE site rep for a copy) in planning an effective generator maintenance program was stressed. Rev L updates were discussed to bring users up to date. Key talking points included these:

    • Updated rotor life-management recommendations.

    • Addition of recommendations for when to remove the rotor—only for repairs, not inspections. Condition assessments can be made using a combination of online trending, in-site testing, and visual (borescope) inspection.

    • Recommendation for a low-oxygen stator cooling-water system.

    • Benefits of combined stator and rotor test and inspections.

Types of robotic inspections—in-situ air gap, in-situ retaining ring, and wedge tapping—and   their applicability to the various generator models associated with the 6B, were explained along with their idiosyncrasies and the background information required to assist in condition assessment.

A case study describing the need for a generator rewind based on robotic findings was incorporated into the presentation. The robotic inspection for this unit included a partial stator-slot wedge-tightness check, an EL CID test, and visual inspection of field parts, stator core, and field/stator windings. Here were the findings:

    • Slot wedges in good condition.

    • Some FOD impact damage to the core.

    • Minor dusting in the stator.

    • Four broken leaves found on one main lead terminal stud.

    • Several slots found with springs moved and nearly closed vent holes.

Generator monitoring to enable condition-based maintenance—partial discharge, rotor flux, rotor shaft voltage, endwinding vibration, stator temperature, collector health, and static leakage—was a major part of the presentation. Keep in mind that the benefits of early fault detection are considerable. For example, it enables plant personnel to control unit operation to limit deterioration and prevent a forced outage.

Each of the diagnostic tools noted above was reviewed in terms of the sensors used for detection, what was being monitored, and what it was capable of finding—for example, loose stator bars in the case of partial discharge.

To dig deeper into generator monitoring, inspection, and maintenance, access Clyde Maughan’s course, available at no cost, on the CCJ website. Maughan is well respected for his knowledge of generators, the focus of his 35-year GE career and more than three decades of consulting work after retiring from the OEM. The program is divided into the following manageable one-hour segments:

    • Impact of design on reliability.

    • Problems relating to operation.

    • Failure modes and root causes.

    • Monitoring capability and limitations.

    • Basic principles of inspection.

    • Test options and risks.

    • Basic approaches to maintenance.

The three afternoon breakout sessions each featured three presentations, conducted in parallel, as outlined below. These were followed by a reception and special GE product fair.

   Breakout No. 1:

    • Exhaust and wheel-space thermocouple reliability.

    • Rotor end of life.

    • Combustion systems.

   Breakout No. 2:

    • Control system obsolescence, including generator excitation systems.

    • Repair technology.

    • Peakers.

   Breakout No. 3:

    • Instrumentation.

    • FieldCore.

    • Accessories.

Users talk back. Attendees expressed several concerns during the course of GE Day. Here are a few of them:

    • Level of experience of FieldCore personnel.

    • Amount of time it takes to respond to pac cases.

    • Quotes for non-LTSA customers take too long.

    • Repair improvement and lead-time expectation.

    • Division of responsibility between the Power Services and Baker Hughes organizations.

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