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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Safety a high-profile discussion topic at Frame 6B meetings

The main technical program at Frame 6 meetings begins at 8 a.m. Tuesday morning (June 11 in 2019), following Monday’s engine familiarization workshop and welcome reception and dinner. Roundtable discussions led by members of the steering committee and one of the two invited vendor presentations fill the first-day program until the vendor fair and reception at 5 p.m. The second vendor presentation and remaining discussion topics are on the Thursday morning program; adjournment is at noon, then lunch. Wednesday is GE Day.

Safety is the first discussion topic. That roundtable is led by Co-chair Jeff Gillis, whose position as gas-turbine technology lead for ExxonMobil’s frame gas-turbine fleet worldwide gives him a global perspective on this subject of importance to all attendees. OSHA is not global and America does not have all the answers.

Gillis’ first slide at the 2018 meeting was designed to stimulate thinking aided by morning coffee. He put up a list of possible topics in three categories to get the discussion rolling, including:

  • General

    • Life-saving rules.

    • Compartment entry.

  • Safety systems

    • Hazardous-gas detection.

    • Fire suppression.

  • Maintenance

    • Fall protection and PPE (Personal Protective Equipment).

    • Scaffolding and access.

    • Safety professionals and other personnel.

    • Inlet filter house fire prevention and escape.

    • Rescue considerations.

    • Fuel-nozzle failures resulting in a casing breach.

One of the users in attendance thought “life-saving rules” at the top of the list was a good place to start, suggesting immediate removal from the site of anyone working without a LOTO (Lock Out/Tag Out) permit, engaging in horseplay, walking under a suspended load, not observing rules pertaining to electrical isolation, as well as other infractions. Others agreed.

Compartment entry when the unit is operating always generates discussion among users; opinions differ. On the one hand it’s much easier to find leaks and troubleshoot when the unit is in service; on the other, there are hazards in doing this.

European gas turbines trip if the compartment door is opened while the unit is operating, the group was told. GE claims opening compartment doors violates the ventilation scheme. Some units trip on low ventilation air flow because air escapes from the door rather than exiting via the ventilation ductwork.

While the consensus view is that a compartment entry protocol is site-specific, the discussion revealed many users are trying to minimize, if not eliminate, access with the GT in service. Ideas offered: Install hazardous-gas detectors in the compartment to warn of fuel-gas leaks. Retrofit armored windows in package doors and floodlights inside the compartment to allow visual checks from outside. Provide access to important operating data outside the package.

Another idea offered is to check for leaks when the unit is on crank. One user went beyond this, saying you can introduce enough air into the system to leak-check with the unit offline.

Trip reduction worked its way into the discussion because 6Bs are installed at many industrial plants to provide steam, and loss of an engine might upset a process that must run continuously. It was said that the OEM now has a package to alarm rather than trip for some operating conditions. This enables operators to assess the situation and decide what to do. The number of trips related to a single event also has been reduced.

Attendees were warned about the hazards of standing directly in front of a door being opened. Also noted was the need to properly close the compartment door after exiting; there’s not much protection from CO2 if the door is ajar.

The possible dangers associated with tying-off when working on top of the turbine was another topic. Fall protection lines can get tangled and cause injuries—possibly ones more severe than an actual fall. Railings have been installed in some cases. A few users reported having tie-off exemptions during outages for work on top of the turbine.

Having a safety professional assigned during outages was suggested. Use of bump caps in place of hard hats was recommended for work inside the generator stator.

The possibility of a fire at the turbine inlet is a real concern to many because it can consume the filter house in a matter of minutes trapping anyone inside if there’s no way to exit safely on both sides. Safety tip: Ban the use of halogen lights in the filter house, near evap media, etc. One user mentioned an incident involving the use of halogen lighting when an oil sump was being cleaned out. A lamp came into contact with oil-soaked rags, creating a large amount of smoke in a confined space.

There’s a vast amount of safety-related information readily available to owner/operators wanting to improve their procedures to best-in-class. You might want to begin your research on the CCJ website in the search bar above where you can find best practices submitted by colleagues over the years.

For the Frame 6 specifically, Gillis prepared a slide of 6B user-forum safety threads, several slides describing more than 30 Technical Information Letters focusing on 6B safety concerns issued by the OEM (TIL 1700, for example, “Potential Gas Leak Hazard During Offline Water Washes”), and content summaries of four GE Product Service Safety Bulletins issued by GE.

Some material pertinent to 6B owner/operators goes beyond the basic engine. One example, PSSB 20161220, “GT Upgrade Impact on HRSG,” presents the experience of an owner that learned a GT upgrade had been implemented without sufficient evaluation of the safety impacts on the boiler. Specifically, the new steaming capacity was greater than the nameplate rating and the relieving capacity of the existing safety valve.

This is a serious concern, but don’t expect to get an in-depth HRSG discussion going at a meeting focused on gas turbines. For that you need to attend the annual HRSG Forum with Bob Anderson. Next conference: July 22-25 in Orlando.

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How manual controls help in troubleshooting legacy GE gas turbines

Turbine Tip No. 2, from the Dave Lucier’s PAL Turbine Services O&M solutions library, applies to General Electric Frame 5 models K-LA and M-P, and early 6Bs, 7Bs, and 7Cs, equipped with Y&F fuel regulator and Speedtronic™ Mark I, II, and IV controls.

Overfiring a gas turbine during startup can be a serious condition, particularly when the engine is cold. As a GE gas turbine fires and warms up, fuel flow is controlled by the average exhaust temperature—called Txa. During the subsequent acceleration period, the starting means (diesel engine or electric motor), assists in bringing the turbine rotor up to rated operating speed. 

On legacy units, as the coupled rotor passes through a mid-range zone, compressor air flow and pressure may be insufficient to maintain Txa under 950F, as recommended by the OEM. If your control system is incapable of limiting fuel flow to prevent the exhaust temperature from exceeding 950F, be advised that GE provided for manual control of its early gas turbines (years from 1960 to 1980).

In the decade of the 1960s, GE gas turbines used the Young & Franklin fuel regulator for engine control. In the early 1970s, Speedtronic became the electronic control and protection system of choice. In this 20-year span, the OEM provided methods for “overriding” the automatic controls with a manual feature on its gas turbines.    

In Fig 1, an operator is shown “thumbing” General Electric Manufacturing Co’s (GEMAC) 70TC programmer to control exhaust temperature during acceleration of a Frame 5L gas turbine. This action limits Txa temporarily, by manually controlling fuel flow to the combustors. Once the temperature has “crested,” at about 2200 to 2400 rpm, the operator can release his thumb, allowing the timer to run up to its 100% stop.

Several MS5001K-LA gas turbines installed in the mid-to-late 1960s have had their legacy temperature control and protection systems replaced/upgraded with a programmable logic controller (PLC), like the PAL GEMAC in Fig 2.

Recall that the technology of the day in the post Northeast Blackout era (November 1965) was early integrated circuitry. The operator-friendly PLC can perform many of the electronic functions from 50 years ago easier and faster. Example: Manual override with the PAL GEMAC is provided with the F2 function key (arrow in Fig 2)—much simpler to use than the thumbwheel feature it replaced.

Beginning in the 1970s, Speedtronic Mark I controls had a manual resistor on the speed control circuit board called SSZA (Fig 3). It is the upper resistor knob in the photo—named MAN VCE for manual, variable control electronic, or minimum fuel command. Turning the knob to the right (clockwise) decreases the fuel control voltage, thus fuel flow. An alarm will sound. Fig 4 shows the later version of Speedtronic, the Mark II. Its MAN VCE is located on the SSKC card. The audible sound can be silenced, but the annunciator flag remains until the knob is returned to normal.

Case study. A user recently had a problem starting his MS5001N, equipped with Speedtronic Mark I controls. When the turbine reached approximately 1900 rpm the unit tripped because the average exhaust temperature exceeded its allowed operating limit of 1000F.  Subsequent trips made the problem particularly difficult to diagnose. The diagnostics team believed the turbine had to continue operating, so the system could be observed and analyzed.

Plant personnel were unaware of the manual control option and the reasons why GE had installed it. The site engineer was advised to turn the MAN VCE knob clockwise during acceleration (at 1700-1800 rpm). Yes, the alarm sounded. VCE was limited temporarily, so troubleshooting could begin. In this case, it was desirable to run at a safe speed at an exhaust temperature less than 900F. I&C sleuths determined that a 240F comparator “oven” was defective and had to be replaced.

Even modern GE gas turbine control systems (circa 1980-1985), like the Speedtronic Mark IV (Fig 5), provided for manual control during turbine startup—should it be needed. Refer to FSR MAN in the MIN GATE function. During startup and acceleration, manual control is possible with this function, though on later-model gas turbines its use is less likely. The MIN GATE looks at all inputs and selects the one that “calls for” the lowest fuel flow. In this case, MAN VCE can be that one.

On a new Frame 5 gas turbine, the average exhaust temperature was expected to “crest” at about 810F approximately 3 minutes and 20 sections into the start cycle (red arrows in Fig 6), when the turbine was at about 80% speed (nominally 4000 rpm).

Bear in mind that if the temperature drifted too high, the turbine might trip on over-temperature. The operator could limit VCE manually (read 10 Vdc on the right vertical axis) to prevent a trip until the air flow and compressor discharge pressure increased to cool the exhaust. Perhaps a MAN VCE setting of 9.5 Vdc might work better in this case. Later, the ACCE VCE limit could be recalibrated lower to this same limit.

In conclusion, many legacy GE gas turbines have ways to temporarily control fuel flow (manually) to the combustors. During startup, it may be necessary to manually limit fuel flow until rotor speed passes through a critical zone (1800 to 2300 rpm). GE provided the controls to assist the operations team in troubleshooting.

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HRSG experience, issues typically global in nature

So you switch hemispheres in both directions, west to east then north to south, and you discover that the pesky HRSG operational issues and concerns you are familiar with are much the same everywhere.

The 2018 Australasian Boiler and HRSG Users Group (ABHUG) Conference and Workshops, held last November, confirmed this view. The organization’s 11th annual conference in Brisbane, Queensland, chaired by Barry Dooley of Structural Integrity Associates Inc, provided an interactive forum for new information and technology specific to HRSG challenges in combined-cycle plants. There were in-depth case studies on plant issues and possible solutions, and pointed discussions among equipment users, suppliers, and international industry experts.

The more universal interactions focused on:

    • Cycle chemistry, instrumentation, and flow-accelerated corrosion.

    • HRSG thermal transients.

    • Oxide growth and exfoliation.

    • Attemperators, condensate return, superheater (SH)/reheater (RH) drain management.

    • Steam-turbine bypass operations.

    • Experience and research into the evolving field of film-forming substances.

    • Awareness and detection of air in-leakage.

    • Activities of the International Association for the Properties of Water and Steam—in particular the organization’s Technical Guidance Documents (TGD) of great value to powerplant owners and operators, which can be downloaded online at no cost. 

Highlights of the meeting are summarized below.

Steam-drum cracking. Presentations included several case histories of HRSG steam-drum cracking, occurring primarily at drum-to-downcomer and circumferential welds. Inspection methods included visual, phased array, magnetic particle, ultrasonic, replication, and hardness.

Poor control of rolling and heat treatment of the original materials were highlighted as culprits, followed by weldability concerns. A summary point on weldability: Parent-material properties are dependent on manufacturing parameters for high-strength low-alloy (HSLA) steels, and welding introduces heat that disrupts the parent-material microstructures. Proper microstructures cannot be regenerated by post-weld heat treatment. Repairs, when required, can be problematic.

The common root cause was summarized as reheat cracking propagated by corrosion fatigue. The use of HSLA steels (for reduced wall thickness and increased allowable stress) contributes to this problem because of a unit’s higher operating stresses and material susceptibility to reheat cracking.

Fitness-for-service issues were reviewed that consider stresses caused by pressure, the simple weight of water and steam, and thermal effects of startup and shut down.

Reheater tube failures were examined for a 760-MW 2 × 1 combined cycle commissioned in 2002. The subject three-pressure, three-module HRSG does not have duct burners.

This presentation of a unique reheater-tube failure mechanism may be the precursor of many future mid-life failures in other HRSGs. The tube adjacent to the gap between modules, and entering the lower outlet header horizontally, had clearly overheated as shown by the large internal oxide growth and exfoliation data base (Figs 1 and 2).

Metallurgical reports showed multiple circumferential and transgranular cracks at the ID of the tube, beyond the heat-affected zone, progressing toward the outside.

Discussions and details led to observations of progressively more rapid localized oxide growth and exfoliation (OGE). Various hypotheses and further analysis steps were reviewed. The key takeaway was the following proposed sequence of events:

1. Normal steam-side oxide growth during years of operation.

2. As oxide thickens and insulates the tube internal surface from the steam, tube metal temperature increases, as does the oxide growth rate.

3. Tubes adjacent to the mid-module and sidewall gap operate hotter, and grow oxides faster than other tubes.

4. Eventually the oxide buildup reaches a critical thickness and it exfoliates.

5. In the case described, exfoliated oxide plugged, or partially plugged, the horizontal section of tube resulting in severe overheating.

6. Severe overheating and thermal-transient-driven strain at the failure site further accelerated localized OGE, thinning the tube wall and resulting in failure.

Learn more about this failure and OGE from Dooley at the upcoming HRSG Forum with Bob Anderson, July 22-25, 2019, in the Hilton Orlando. 

Inspection after four years. A comprehensive presentation was given on pressure-vessel inspections at a combined-cycle plant after four years of operation, covering all major systems and their components.

The unit’s cycle chemistry includes all-ferrous feedwater metallurgy, AVT (O), solid alkalizing agent added to the HP and LP evaporators, no condensate polisher, and low iron level in the feedwater. Inspection methods, including commissioning and beyond, were described.

First in-service inspections (2015) showed loss of wall thickness in the HP economizer headers (one unit) and cracking in HP and LP drums (second unit), two-phase FAC in the condenser, and liquid impingement erosion of L-0 turbine blade row and shroud.

Water-chemistry management was reviewed, revealing a lack of trained personnel, lack of water-chemistry documentation, insufficient sampling and testing, and insufficient instrumentation to meet the recommendations of IAPWS published in its TGD 2-09. Improvements began, and by 2018, water-chemistry management was considered “close to normal.”

With chemistry management improved, the plant will concentrate on more active in-service inspections, and a proactive risk-based analysis approach.

HP drum replacement. The conference organizers called this “A great example of successful significant HRSG plant engineering projects—specifically, a total HP steam-drum replacement in a triple-pressure unit with key learnings outlined and shared.”

The HP drum at Tallawarra in Australia was replaced in 2018, after cracks were discovered in 2013 (just four years after commissioning). Deep cracks were discovered in various parts of the drum (risers and downcomers).

The cracks aligned with the fusion line between the weld and the drum and were determined to be blunt and oxide-filled, most likely the result of original welding defects—for example, a lack of sidewall fusion in the weldment to parent material.

The repair option was considered, but would mean a long outage (112 days). Even then, there was risk of not fully resolving the issues. This option was declined. Tallawarra was determined safe to operate (with adjustments) in the short term, and drum replacement planning began.

The challenges. An intensive two-year program was set that included factory visits and documentation reviews, stringent weld procedure and welder qualification checks, material certificates, reviews of heat treatment and hydrostatic test procedures, and clearly defined hold points.

Site preparation included risk-assessment workshops (including health and safety) and mitigation strategies based on workshop outcomes. Material handling challenges included a ground-to-height distance of 100 ft, anchor points with drone location reviews, and physical separation of multiple working levels (three above the drum floor, one below). Height restrictions from a nearby airport called for adjustments to the lift plan.

A key takeaway from this presentation was lessons learned. Engaging contractors in the work-assessment workshops was given high marks, as were real-time opportunities for safety strategies and improvements.

The drum was replaced within the scheduled period of 58 days.

An attendee with relevant experience told the editors afterwards that the drum-replacement plan presented certainly was one a similarly affected user might consider—provided his or her site could accommodate the cranes necessary to remove and replace the drum.

However, he said, he was not aware of a crack in a properly constructed drum-nozzle weld that has required replacement. While there are a lot of in-service cracks being found, the participant continued, he believes all have been successfully managed and/or repaired without removing/replacing the nozzle—thus far, anyway.

Editor’s note: ABHUG is supported by the International Association for the Properties of Water and Steam (IAPWS) and held in association with the European HRSG Forum, the HRSG Forum with Bob Anderson, and the journal PowerPlant Chemistry.

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Key takeaways from the ABHUG workshop on steam-turbine bypass systems

A workshop on optimization of steam-turbine bypass systems at the 2018 meeting of the Australasian Boiler and HRSG Users Group, led by Bob Anderson, Competitive Power Resources Corp, covered the arrangement, purpose, and methods for operating and maintaining this equipment.

Vibrant discussion followed presentations by Anderson, Justin Goodwin of Emerson/Fisher, Ory Selzer of IMI CCI, and Sanjay Sherikar of Nihon Koso Co Ltd.

Anderson set the stage with his opening remarks. In a conventional plant, he reminded, the operator can:

    • Limit furnace exit-gas temperature to protect SH and RH tubes.

    • Limit the drum-pressure ramp rate to avoid humping and through-wall thermal stress.

    • Limit the temperature of steam admitted to a cold turbine.

But in a combined-cycle system, the operator generally cannot limit gas-turbine startup exhaust temperature and, therefore, has limited control over exhaust temperature, the HP-drum-pressure ramp rate, and steam temperature.

HPSH and RH tubes need cooling steam, he continued: The steam turbine needs precise steam temperatures and pressures during startup. Therefore, the bypass system’s primary job during startup is:

    • Control HP-drum-pressure ramp rate.

    • Provide cooling steam to HPSH and RH.

    • Control RH pressure.

    • Provide HP and IP pressure matching.

    • Permit smooth blending of a lag unit into the main-steam and hot reheat (HRH) systems.

During shutdown, the primary job becomes:

    • Permit smooth removal of lead unit from the main-steam and HRH systems.

    • Permit control of HP pressure for bottling-up the unit.

    • Permit steam cooling of HPSH during shutdown.

    • Control HP-drum-pressure ramp rate if depressurizing during forced cooling.

A review of the major bypass-station components followed:

    • Pressure control valve. It provides backpressure control for HP, RH, and LP steam and is exposed to severe duty in the HP and HRH systems.

    • Desuperheater. It controls steam temperature downstream of the bypass. Principal components include a spray-water control valve and block valves.

Some of the important points made during the workshop:

    • Failure to coordinate HP and HRH bypass PCV positions can lead to large RH pressure transients, and severe attemperator overspray.

    • Pressure control valve erosion is caused by water, wet steam, or debris passing through the valve. Seat/plug damage results in leaking steam (overheating downstream carbon-steel piping).

    • The desuperheater must not be operated with the PCV closed. (The valve must be open to its minimum position for desuperheater operation.)

Although many OEMs are using more-erosion-resistant designs and materials, presenters representing leading valve manufacturers stressed that “no PCV design can tolerate wet steam.” Newer materials and designs will only slow the wet-steam erosion process. Severe damage can result within one year in cycling units. Mechanisms of damage by wet steam were explained in detail, with visual examples and specific case studies (both existing and new units).

Operation of bypasses with no heat input to the HRSG were covered—including temperature transients in high-energy piping (HEP) and increased production of condensate in the superheater and reheater.

Interesting case studies were presented on a few F-Class units that experienced repeated leaking after only a few runs (and rapid erosion following modification).

Discussions followed on:

    • When to open bypass.

    • Depressurizing the HP system with the bypass during hot layup.

    • Risks of water hammer.

Cyclic stress examples, resolutions, and maintenance recommendations were presented, concentrating on possible causes. Instrumentation and thermocouples also were reviewed.

Corrective-action discussions included modifying the HP bypass desuperheater spray-valve logic with a master block valve/martyr control valve arrangement, as well as various inspection and maintenance programs.

Dig into the design and O&M details of steam-turbine bypass systems closer to home at the upcoming HRSG Forum with Bob Anderson, July 22-25, 2019, in the Hilton Orlando. The open discussion periods at this meeting afford users the opportunity to get answers to their specific questions and return to their plants with solutions in-hand.

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