STUG 2015 OEM presentations: General Electric

Helping achieve your desired outcomes, Jamesetta Strickland

General Electric packed a great deal of information into the nearly six hours the STUG steering committee allowed the company for its steam-turbine presentations. Sounds overwhelming, but the GE team divided the subject matter for each session into “bite-size” packages of technical information with hard starts and stops. This way anyone who needed a time-out would not come back into the room and be lost for half an hour or more. There was almost sure to be a new topic within 10 minutes or so.

The opening presentation was short and general enough so you didn’t miss anything important while getting settled. Several slides outlined the important material to come—upgrades (enhanced steam path, HP/IP section replacement, OpFlex™ steam turbine agility, shell warming system), repair network, repair solutions, field force automation, etc. Access presentation.

Steam turbine maintenance, Bill Girzone, Steve Walcott, Nick Giannakopoulos

The thumbnails of GE Technical Information Letters (TILs) compiled by the trio of experts is of high value to (1) new plant employees trying to come up to speed on turbine issues they may have heard about, (2) those responsible for planning outages, and (3) experienced hands, as a refresher. The lineup of TILs discussed is below; you can access the thumbnails on the Power Users website. If that information is insufficient for your needs, contact the plant’s GE service representative for the complete document.

TIL 1943: LP rotor pin and cross-key staking. Applies to assembled rotors shipped during the 2005-2014 period. Issue: Inadequate staking of LP finger dovetail pins and cross-keys have shown potential for axial migration of pins/keys during operation which could lead to reduced overspeed capability.

TIL 1927-R1: Drain-line overheating. Addresses solutions to overheating events that have occurred in after-seat drain lines installed in some turbiness with 9-in. main stop control valves (MSCVs). R1 of this TIL provides three new/modified recommendations of importance to users.

Lifting-beam modification TILs. Safety concerns impacting certain lifting-beam configurations are addressed in a series of advisories. A change in assumptions and calculations for some lifting beams in use resulted in lower safety factors than originally calculated. An existing TIL was revised and three new ones, plus a Product Service Safety Bulletin (PSSB), were issued to assure the safety factors desired. The documents of interest are the following:

      • TIL 1926 R1, Lifting-beam mods for axial-flow machines with combined casing lifts.

      • TIL 1956, Lifting-beam inspection for medium and large steam turbines.

      • TIL 1957, Lifting-beam modification requirements for medium and large steam turbines.

      • TIL 1959, Lifting-beam advisory for medium and large steam turbines.

PSSB, Lifting-beam precautions for axial and down-flow medium and large steam turbines with combined casing lifts.

TIL 1940: N1 steam-seal packing axial clearances. HP steam-seal packing (typically R3 and R4) in some units has suffered axial rub damage during shutdown or warm/hot-restart. Bear in mind that severe rubbing is conducive to bearing vibration. Recommendation: Follow temperature-matching guidelines presented in GEK 110856.

TIL 1739, Main-stop-valve stem erosion. MSV stem erosion can lead to binding, failure, or interference with valve operation. Condition is attributed to impingement of iron-oxide particles on the MSV stem during valve throttling; exfoliation of HRSG tubing is the source of the particulates. Guidelines are presented for stem inspection, erosion mitigation, and stem replacement if necessary.

TIL 1629-R1, Combined stop and control valve seat liberation. Failure of the Stellite seat inlay in some main control valves has resulted in steam-path damage and, potentially, the loss of turbine speed control. Water induction/steam quenching and poor bonding between the Stellite and base seat material are the causes cited.

TIL 1531-R1, Disc cracks on 7-, 9-, and 11-in. main control valves. Cause is attributed to alternating stresses during specific valve throttling conditions. Recommendations regarding testing, replacement, etc, are presented.

TIL 1950, Valve operability, testing, and health. Important that turbine valves operate properly to prevent an overspeed event. Periodic testing and maintenance are recommended. However, it may not be possible to test valves on some units; many of those are in combined-cycle plants. Guidance is provided by the TIL. Access presentation.

Vibration, Tim Maker

Virtually everyone on the deck plates is aware that high vibration can trip their steam turbine, something no one wants to happen. Vibration has many causes and relatively few plant personnel have a strong background in its analysis to determine why it measures x in./sec today when it was fine yesterday. There’s a gremlin at work in the minds of many. How many times have you experienced, or heard colleagues complain of, increases in vibration levels following an outage—even, perhaps, after a low- or high-speed balance?

Maker’s presentation focuses on sub-synchronous vibration attributed to oil-wedge instability (whip/whirl) offering typical causes and corrective actions, and including a case history. The speaker’s goal obviously was awareness and appreciation of vibration, not to teach the subject (there were only eight slides). Attendees at a general meeting like STUG tend to disengage from the speaker when the person at the front of the room believes he or she is presenting a “course.”

Perhaps the most valuable part of the presentation, in addition to the practical review of oil-wedge instability, were the follow-on references suggested:

      • GEK 100468 for journals 10 in. and smaller.

      • GEK 100469 for journals larger than 10 in.

      • GEK 111107 for rotors operating at 1500 or 1800 rpm. Access presentation.

Steam turbine lifing, David Welch

The life remaining in principal equipment—such as steam and gas turbines and generators—is a major concern of generation executives. How many years will my turbine last if we continue to operate the way we are today? What are our contractual obligations going forward? Can we meet them by changing operating procedures rather than investing in costly upgrades? If not, what upgrades do we perform and what will they buy us in terms of life extension? Questions such as these can adversely affect soundness of sleep.

Welch’s presentation hit the highlights regarding lifetimes you can expect from principal components. It is compact, like the previous presentation by Maker, with only a dozen slides. But it is well organized and easy to navigate, enabling you to begin a checklist of things to do going forward to maximize the return on your assets.

The first section on stationary structures covers HP/IP shell casing lifing and distortion, HP/IP diaphragms, D11 N2 packing head repair verses replace, and MSCV casings. The second section focuses on rotating components, HP/IP blades and rotors, and last-stage-blade finger dovetail cracking. Field observations are presented and recommendations offered. Access presentation.

Fossil retrofit solutions, Randy Tadros

D11 HP/IP advanced steam-path retrofit

Siemens and Mitsubishi presented their retrofit/replacement solutions for the D11 on Wednesday (see above). Thursday was GE’s time to review with attendees upgrades for its equipment. Once again, information was divided into digestible packages, enabling attendees to focus on what alternatives to consider at their plants. If any of the solutions described below are new to you, access the GE presentations on the Power Users website as a starting point.

Dense Pack™ retrofit, an HP or HP/IP solution, offered since 2000 and installed in more than 80 units, is said to resist degradation based on fleet-wide inspection results. It incorporates advanced aerodynamic buckets and nozzles, advanced sealing technologies and optimized clearances, and a rugged mechanical design. Benefits: Improves the efficiency of mature steam turbines, boosts profitability, and extends asset life.

HEAT™ steam-path retrofit replaces existing HP/IP sections on 60-Hz D11s, delivering up to a 2% increase in output via technology advancements using the same bottoming cycle. The “drop-in” turbine requires no modifications to the existing foundation. An example presented, involving a HEAT retrofit on a 255-MW unit (1800 psig/1000F/1000F/3 in. HgA) delivered a 5% increase in output, improved HP-section efficiency of close to nine percentage points, and improved IP-section efficiency by more than three percentage points.

LP upgrades discussed included section replacement with one delivering higher output, lower heat rate, reduced exhaust losses (longer last-stage blades).

The second presentation focused on the characteristics of the advanced steam path described in the first presentation, as applied to the D11. Details are presented on improved designs for rotors, diaphragms, nozzles, buckets, bucket tip seals, shaft seals, etc. Access presentation.

Heating blanket, David Welch

OpFlex AGILITY™ combined-cycle startup enhancement, N Piccirillo

Most of the D11 solutions offered by competitors presenting on Wednesday, and those described by Tadros immediately above, involved major commitments in terms of schedule and cost. Welch’s second presentation, together with Piccirillo’s offered practical and affordable solutions for users wanting to start their steam turbines faster, and ramp up and down faster, all without adverse metallurgical and mechanical impacts. Benefits can be many, including less fuel burned, emissions reduction, increased revenue from participation in the ancillary services market.

Welch described heating blankets for faster starting/ramping, reducing the rate of cooling during shutdown/cooldown periods, and controlling top to bottom temperatures during shutdowns to minimize shell deflection. Piccirillo explained to attendees how OpFlex AGILITY can be used to reduce the time for starts by optimizing the process and starting automatically (just a push of the “start” button). Best of both worlds: Combine blankets and OpFlex. A 2 × 1 plant manager in the Northeast recently told the editors he had both and was able to eliminate all cold and warm starts. Hot starts enabled the facility to start reliably in less than 40 minutes on a consistent basis. Access presentation.

D11 major best practices, Merv Joseph and Ben Kazirskis

The speakers focused on best practices for reducing the time required for a D11 major inspection—typically 45 to 50 days. They offered a checklist for better organization, and preplanning for non-standard scope, which reduced the MI outage to 29 days at one Latin American plant. Access presentation.

Repair technology, John Sassatelli and Donald Blais

In doubt as to what GE brings to the table regarding repair technology in the shop and onsite, and the outage support it can provide? Access this presentation. It was the longest in the GE program in terms of number of slides (plenty of photos on how specific jobs are done), covering the specifics of rotor-bow correction, typical rotor weld repairs, steam-path repairs, diaphragm cleaning and inspection, stress relief of welded bucket tenons in the field, stud hole restoration, coupling alignment, seal repair, etc. Special tooling was part of the presentation—including N2 packing head separation tool, shell key puller/snout pipe puller, and turning-gear drive as a backup for when the installed TG is out of service. Access presentation.

ST performance: Degradation mechanisms and quantifying losses, Brian Marriner

Good presentation for an in-plant lunch and learn. Buy a couple of pizzas and set up a projector in the break room. First part of the presentation covers the common causes of steam-turbine performance degradation—leakage, friction, and aerodynamic losses—and where to look for them. There are especially good photos showing how steam leaks by nozzles and buckets, across joints and seal faces, through excessive butt-gap clearances, etc.

Other slides will help your team differentiate among airfoil profile changes caused by small-particle impingement, foreign-object damage, deposits, erosion, corrosion pitting, and poor repairs. Such surface discontinuities contribute to performance-robbing friction and aerodynamic losses. An informed, motivated staff can provide specific information critical to maintenance planning, and for achieving performance excellence, that is difficult or impossible to get from PI data or the corporate M&D center.

A series of five slides provides perspective on the impact of bucket and nozzle surface roughness on efficiency loss in the HP and IP turbines, and on the loss of nozzle efficiency as airfoil trailing-edge thickness is reduced.

The third section on estimating the impact of performance losses was only a few slides long. The highlight is an equation for estimating output loss caused by stage efficiency loss. The actual kilowatt loss for a given stage, the speaker said, depends on the combined impact of the stage efficiency losses, the energy produced in that stage, and the location of the stage within the steam path.

The final section discussed recoverable versus unrecoverable losses. The former are losses recovered as a result of repairs/cleaning—such as replacement of worn/rubbed packing and or spill strips; the latter, losses remaining after repairs/cleaning are performed—such as inner casing distortion. Access presentation.

Generator maintenance, Carlo Yon and Sherwyn Applewhaite

Topics covered included were connection-ring tie systems, oil intrusion into hydrogen scavenging and purity systems, rotor removal during major inspections, ripple-spring wear into stator bars, and generator wedge tightness inspections.

GE has employed three connection-ring tie systems over the years. From 1970 to 2004, dry ties were used on model 7FH2 and 324 generators. From 2005 to 2012 it was consolidated dry ties for 7FH2, 324, and 330H generators. Use of this alternative was initiated as an improved bonding system by concentrating resin at the tie. In 2010, the wet-tie era began. Wet ties are used today on all 7FH2, 324, 330H, and 390H/450H generators. Tie system should be maintained in accordance with intervals prescribed in GEK103566 Rev J.

The practical section on hydrogen seal-oil ingress and system experience discusses issues such as seal-oil coking and contamination and recommendations for resolving issues.

The speaker stressed there is no fixed set of rules for rotor removal. Each unit and case is unique. The basis for a rotor removal is involves consideration of rotor history and thorough visual inspection of stator and field. A slide likely of particular interest to most users presents the top five reasons for removing the field—such as operating with high vibration that worsens with load—and the top five reasons for leaving it in—including robotic inspection is capable of capturing all inspection points.

Bar abrasion caused by the relative motion between a stator bar and a side ripple spring likely would be in evidence as greasing on the slot end of 390H generators.

The importance of wedge tightness was covered in the last segment of the generator session. Stator wedges hold down stator bars in the slot to keep them secure and control vibration and greasing. Bear in mind that if vibration is not checked insulation wear could lead to a short to ground. The speaker referred attendees to GEK 103566, which recommends wedge inspections during majors. Access presentation.

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