What GE told STUG2020 attendees about its steam turbines

Matt Foreman, platform leader, Combined-Cycle Steam-Turbine Services, opened the GE Day program at the 2020 virtual meeting of the Steam Turbine Users Group (STUG) with an overview of the topics to be discussed, including: fleet updates, valve and turbine-casing cracking, valve upgrade experience, D11 rotor bow, assessments to improve operability and reduce O&M spend, and performance improvement. Highlights follow. The full presentation recordings can be accessed by approved GE customers on the MyDashboard website.

If steam turbines fall under your responsibilities, be sure to register for the STUG 2021 annual meeting in St. Louis, taking place August 23-27.

TIL, GEK, and fleet updates

Mike Jones, service manager for ST products, and Jamie Anderson, ST system integration leader, stressed the importance of these two Technical Information Letters:

    • TIL-2010 recommends endoscopic inspection and NDE of the radial inlet vane at the next scheduled outage to identify possible deformation and/or cracking, which can be caused by a clearance reduction attributed to scale buildup. A borescope inspection ahead of the outage was suggested.
    • TIL-1886-R1 requires removal and NDE of finger-dovetail L-1 buckets after 30 years of service to inspect for stress corrosion cracking in the dovetail area.

Recent D11 shell and valve casing findings

Dave Welch, consulting principal engineer for ST product service, shared recent HP/IP shell casing findings and experience in mitigating horizontal-joint leakage, plus N2 packing-head experience and valve-casing findings.

He stressed the cleaning, inspection, maintenance, and repair of casing cracks as essential outage activities to prolong the life of HP and IP shells. Photos of casing findings and typical locations of occurrence provide valuable user perspective. TILs 1748 and 1749 suggest machining actions to address casing stress issues, which are impacted by creep and low-cycle fatigue.

Horizontal joint leaks are not a major fleet concern, noted Welch. They are caused, he said, by creep relaxation of joint studs and nuts and by localized casing distortion from thermal- and pressure-induced stresses. Repair options are presented.

N2 packing-head (PH) replacement benefits and experience were summarized for attendees. Users were referred to TILs 1627, 1748, and 1749 regarding shell and N2 PH fit modifications released about 10 years ago. Welch said GE has successfully implemented about 50 modified packings within the D11 fleet. He added that the OEM’s reconfigured N2 packing head has reduced premature failures of the shell and the PH throughout the fleet.

Casing cracking on old-style main stop and control valves (MSCV) has occurred before 15 years of service, Welch continued, recommending blast-cleaning and inspection for indications at every minor outage. Grind and blend, or machine-out, small cracks once they are found to minimize the need for a weld repair later.

The OEM’s Next-Gen ST valve experience

Welch opened his second presentation by explaining that Next-Gen is a name change for the “digital-valve” moniker used previously. Reason: The improved offering goes beyond digital with robust hardware material and geometry improvements. The enhanced hardware can enable minor-outage interval extensions from three to six factored years.

There are two standard product offerings for MSCVs and combined reheat valves (CRVs):

    • Package 1 targets 7.5-, 9.25-, and 11-in. valves with modern actuators and no casing cracks, primarily addressing issues related to the internals—such as stem sticking and solid-particle erosion (SPE). Installations, which can be done during a minor outage, thus far reveal no SPE of valve stems. Return-to-service issues—wiring and erratic behavior—on two valves—were resolved quickly. In both cases, the actuators had not been replaced. Eight units now have Package 1 installed with the first unit accumulating hours since 2017.
    • Package 3 addresses issues related to valve casing cracks and includes a new actuator. Target is 9.25-in. lower-chamber valves and CRV links and lever hydraulics. Valves for the first replacement project in October 2019 were installed in less than a month.

Rotor-bow detection and corrections

John Sassatelli, consulting engineer, repair development, opened his presentation with a survey, to help focus his presentation on user needs. The question: Where is your plant regarding ST rotor bowing? There were four possible answers: (1) I don’t think my rotor is bowing; (2) I think my rotor is bowing and I’m monitoring it; (3) I have taken some action to address rotor bow, and it’s working; and (4) I have taken some action; however, it looks like the bow is returning.

Nearly 60% of the respondents did not think their rotors were bowing.

Sassatelli then outlined his highly informative and practical presentation, one that all users with rotor involvement likely would benefit from (access it at GE’s MyDashboard.com). He covered rotor-bow detection (What is it? What to trend?), causes (Why does it happen? What are the system effects?), and management (Managing the factors contributing to rotor bowing, plus issue remediation and intervention.).

Runouts taken with the unit out of service are critical to understanding what’s causing the bow, the consulting engineer said. He then put up a slide of a D11 rotor with three typical curves developed from runout data—one showing a bow centered at the HP-steam inlet, one with a “kink” at the reheat-steam inlet, and one illustrating a bow distributed along the length of the rotor (parabolic shape).

If you suspect your rotor may have a bow, Sassatelli said you want to know if the bow is temporary or permanent and if the vibration response is trending up or down over the unit’s service history. He suggested reviewing the first-critical-speed response over the time horizon for which data are available. You also want to see if the shutdown critical normalizes the thermal effects of startup.

Three well-illustrated case histories were presented to facilitate understanding the vibration signatures of bows. But wait! Things other than a bow can produce similar signatures (misalignment, oil/steam whirl, mass loss, rotor crack, for example) and you should rule them out before pursuing a bow solution. Suggested reading: GEK 89610.

Sassatelli then asked the group which came first on their units: rubbing or bowing? More than two-thirds of the respondents said “rubbing.” He then offered several charts to help owner/operators answer the question: Does rubbing cause bowing or vice versa? Vibration plots of cold and warm starts show the latter is less likely than the former to produce vibrations of sufficient magnitude to initiate a turbine trip.

Although a warm start does not give the same high vibration numbers as a cold start, Sassatelli continued, it does seem to correlate with accumulated damage. The riskiest timeframe for light rubbing, he said, is a warm start 24 to 48 hours after shutdown.

The impact of insulation condition was factored into the speaker’s comments on rubbing. The increasing temperature deviation between the upper and lower casings over time in the area of the HP and RH steam inlets, he said, generally can be attributed to insulation deterioration. The delta T contributes to casing distortion conducive to rubbing.

The pros and cons of various rotor and system interventions closed out Sassatelli’s presentation. They provide of checklist of options for owner/operators to consider for mitigating bowing concerns.

Analyzing the data from your combined cycle

Principal Engineer Peter J Eisenzopf’s goal was to share methods for turning operating data into information that can be used to make better O&M decisions. He, like the previous speaker, began with a short survey question to help focus his remarks on user needs. The question: Which steam-turbine components/systems drive the most emergent work? The four choices: Turbine valves, rotors, casings, and accessories and balance-of-plant equipment. If “turbine valves” is your answer, you’re among the majority. Two-thirds of the respondents, in round numbers, agreed with you.

Eisenzopf then provided a useful checklist of items the OEM uses to gather information of value so you can better manage your unit and outages. The variables discussed and illustrated in the presentation included the following:

    • Lifetime mission mix. The chart provided for one D11 plots the HP bowl metal temperature at the time of turbine roll for all lifetime starts, allowing plant staff to identify easily changes in mission over the years. Examples: When the plant was in peaking service, when warm starts predominated, etc.
    • Lifetime shutdown hours preceding an ST roll (an alternative to HP bowl temperature to define the type of start). Fleet data indicate the most common starts, in decreasing order, occur at eight, 32, and 56 hours, and in 24-hr increments beyond that. The message: When specifying guarantees for new units, owners should consider asking the OEM for the start times associated with these specific shutdown durations, plus dead cold. Traditionally, start-time guarantees for new units most often have been specified at eight, 48, and 72 hours.
    • Percent cyclic tracking. GE invented the parameter “percent cyclic” because simply tracking the number of starts does not include sufficient information for lifetime evaluations. Eisenzopf said units with similar percent-cyclic missions may also have similarity in the features which require maintenance. Understanding this with GE’s help could be valuable in both outage planning and in designing an operational profile to maximize asset value.
    • Lifetime operating hours are tracked by virtually all plants because of its value in inspection and maintenance planning. But the speaker said tracking factored hours is more valuable because it is condition-based.
    • Transient ST load profiles. Eisenzopf explained GE’s transient-data viewer tool which enables you to chart important turbine operating parameters—such as start time, which can help operators reduce start times and lower startup cost.
    • ST rotor cyclic life per start/shutdown cycle helps in reducing start times. It is particularly valuable for quickly assessing the impact of changes to startup logic/procedures on rotor life consumption.
    • Cooldown upper-to-lower shell metal temperature-difference tracking allows operators to assess the relative quality of their insulation, the OEM having fleet-wide data for comparison. Eisenzopf stressed the importance of insulation quality in minimizing casing distortion. The methodology discussed can be used by plant staff for evaluating the work of contractors in replacing insulation after an outage.
    • Startup transient efficiency tracking. GE invented the “transient efficiency” metric to measure/quantify startup quality. In the example provided by the speaker, plant was able reduce the start time by more than an hour with life consumption equal to or lower than the baseline number.

Several more parameters—such as steam-to-metal temperature matching at ST roll—also are discussed in Eisenzopf’s presentation available at MyDashboard.com. While they all enable better decision-making, their measurement and tracking may require instrumentation and data collection capability not currently available at your plant. Performance improvement, like most everything else, has a cost, but it typically is a relatively small percentage of the financial gain.

One way to launch a performance improvement initiative at your facility might be to review the presentation, determine what variables you are not now tracking and begin doing so, identify other parameters you believe have value in tracking, and determine what equipment and controls changes are necessary to make this happen. Then do it. Your GE rep can help, of course.

Combined-cycle ST performance improvement strategy, tradeoffs

Jim Stagnitti, leader, application and requisition engineering, began by reviewing the reasons owner/operators pursue performance-improvement initiatives—extend maintenance intervals, improve reliability and/or flexibility, for example—and the considerations involved in decision-making—including cost, desired remaining unit life, and operating profile.

He then explained the value of a so-called “opening assessment” to make recommendations for repairs during an upcoming outage, both structural (impacts reliability) and thermal (impacts performance). A closing assessment also is necessary, the group was told, to verify the as-left condition of the unit.

A highlight of the presentation was an overview of what’s involved in upgrading your ST with a new rotor. Simply put, a typical scope is full steam-path replacement—that is, bucketed rotor, diaphragms, packing heads, and seals. This likely would be done to accommodate an increase in steam flow attributed to a gas-turbine uprate, increase in duct-burner capacity, and/or HRSG upgrade. The benefits of this approach include the following:

    • Avoid emergent work and the risk of outage extensions.
    • Restart the maintenance clock with new and clean replacement parts.
    • Improve heat rate

An economic analysis presented supports the value of rotor replacement. The case study showed steam-path replacement value is positive within three years and increasing over time.

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