Onsite – Page 55 – Combined Cycle Journal

Turbine Tip 11: Compartment heaters not for creature comfort

By Team-CCJ | February 5, 2022 | 0 Comments

O&M Clinic for Legacy GE Gas Turbine Users

Turbine Tip No. 11 by Dave Lucier, owner/GM, PAL Turbine Services, applies to General Electric package power plants (PPP), including the following: Model Series 5001, 6001, and 7001.

GE installed heaters in the accessory and turbine compartments (combustion-chamber area) to maintain their space temperatures at levels that promoted good combustion on initial firing.

One experience to share: A client with two MS5001N gas turbines for emergency and peak-power generation called a couple of years ago to say both units were having difficulty starting and firing in the dead of winter (February, minus 18F—to be exact). Once onsite I opened the accessory compartment on one unit and found wires hanging from a space heater (Fig 1). I was told that the heaters in the combustion compartment had failed because of the too-hot environment so all heaters were disconnected, staff believing they were “unnecessary.”

Space heaters are not there for operator comfort, I reminded plant personnel: They are installed to assure that the on-base fuel and fuel-system components are kept relatively warm. Lines from the LP fuel filter, fuel stop valve, fuel pump, HP filter, and flow-divider elements (Fig 2) must be warm to function as designers intended. Especially important is to keep warm the 10 small-diameter fuel lines running from the flow divider under the compressor inlet plenum to the combustors.

Why this is necessary: The first firing attempt involves approximately three gallons of fuel—oil already on the accessory base. If this first attempt fails, oil must come from the fuel forwarding skid, which is off-base and often in open air or an unheated enclosure. Most fuel systems have heat tracing for the buried fuel line to the gas-turbine base, but not all do.

Proper compartment sealing also is important, to retain heat produced by the space heaters. Doors and seals also should be kept in good condition to maintain effective fire protection.

To sum up: Space heaters in the accessory and turbine compartments must be kept operational, particularly in northern US and Canadian locations. This way, when the ambient temperature drops below freezing, you can be confident that the fuel already on-base will be prepared to ignite on the first firing attempt.

Maximizing the lifetime of gas-turbine hot parts

By Team-CCJ | February 5, 2022 | 0 Comments

If you’re having difficulty with your F-class gas turbine OEM when it comes to repair of hot-gas-path (HGP) components, MD&A wants you to know they not only have the experience you are seeking, but also enhancements, which will extend service life, plus better transparency and customer oversight throughout the repair process.

In the “Extending Service Lives of Gas Turbine Components” segment of MD&A’s Spring 2021 Webinar Series (February 23), Director of Engineering Jose Quinones, PE, reviewed the company’s capabilities, experience, and customer-care process, most pointedly through eight examples, including nozzles, blades, and shrouds for  F-class GT stages 1-3 nozzles.

Key takeaway: Don’t sell “scrapped” HGP parts until you let MD&A look at them. Watch to the end of the webinar (users only) and you’ll see why.

MD&A’s sweet spot with these types of repairs is “single-crystal components where users have difficulty getting service.” All steps of the repair process are done in-house except a hot isostatic press and an internal aluminide coat, if necessary.

Several “gates” are established during the repair sequence for process and quality reviews with the customer. As just one example of an enhancement, MD&A adds silicon, hafnium, and other elements to the thermal barrier coating which reduces surface degradation and crack propagation (Fig 1).

Perhaps the most captivating part of the webinar was when Quinones discussed how MD&A repairs components deemed “unrepairable” by others, such as, in one example, second-stage nozzles with creep deflection, cracks, oxidation, and clearance reductions. In this case, the cooling holes were exposed because of thinning (Fig 2).

Quinones explained that there may not have been repair techniques available when some parts were sent to the graveyard. In an astonishing case, MD&A took components worth $7600 as scrap, repaired them for $1.3-million, and saved the customer many millions more.

As noted during the Q&A, best to loop your insurance company into the conversation regarding such repairs, especially when MD&A’s assessment is different from the OEM recommendations.

The road to 100% reliability in liquid-fuel starts, transfers on dual-fuel gas turbines

By Team-CCJ | February 5, 2022 | 0 Comments

The spate of lawsuits filed in the aftermath of the 2021 winter storm that left millions in Texas without power for days and sent natural-gas prices soaring to their highest levels in years—up nearly 17,000% in some cases, according to a Wall Street Journal report—testify to the value of having dual-fuel gas turbines as part of the generation mix.

The well-recognized ability of gas turbines to generate power at high efficiency and with minimal emissions is only one important attribute of these flexible machines. In emergencies, they can start within minutes and when equipped for black-start service can be a major factor in grid restoration as they first did immediately after the Great Northeast Blackout of 1965.

The most-recent Texas experience suggests a re-examination of the financial logic associated with buying gas-only engines may be in order.

In many instances, gas-only is an appropriate choice: Capital cost is lower than for a dual-fuel machine; no backup liquid-fuel system is required; environmental and safety requirements are reduced; overhauls are less time-consuming and costly; training of plant personnel is simplified. In some cases, the presumed advantages of gas-only operation convinced owners to remove liquid-fuel hardware from their engines and abandon in place or remove their oil-storage and fuel-transfer infrastructure.

However, business conditions in the electric-power industry are always in a state of flux. Today, with renewables in regulatory favor, it can be difficult to extract a profit from fuel-fired assets in some areas of the country if they are not equipped to start and run reliably on oil when gas is not available.

Reliable operation demands attention to detail in fuel-system design and equipment selection, which are impacted by such variables as the time allowed for startup on oil or for transfer from gas to oil, the financial penalty of a failure to start on oil, reliability/availability requirements of the off-taker, etc. But be confident that there are commercially available dual-fuel solutions to meet your needs. Success depends in large part on your ability to achieve the following:

    • Assure reliable hot-gas-path (HGP) hardware is installed in your engine.
    • Design a fuel system capable of providing the level of reliability on liquid-fuel starts and transfers needed to meet contractual requirements.
    • Maintain backup liquid fuel in top condition.

HGP hardware. This probably is the easiest box to check. All turbine OEMs, as well as many third-party service providers, can evaluate the ability of your HGP components to perform reliably in dual-fuel operation. Lifetimes of airfoils and other critical parts are less when oil is burned instead of gas, but the number of oil-fired hours experienced by the typical dual-fuel engine will have minimal to no impact on parts life.

An informal survey by the editors indicates that more than a few dual-fuel engines have not operated on distillate oil for periods as long as years—other than to periodically test the ability of their turbines to run on liquid fuel.

Fuel system challenges. Oil temperature is, perhaps, the variable of greatest importance in the design of standby fuel systems. Reason is that distillate remaining in check valves and piping after firing on oil oxidizes at about 250F—or less. The resulting coke coats check-valve internal surfaces (and fuel lines as well) and restricts the movement of valve parts. Once this occurs, a check valve may not open and close properly until it is overhauled.

The most common trip during fuel transfer is believed to be on high exhaust-spread temperature—caused almost exclusively by check valves hung-up on coked fuel.

Engine compartments with GE frame turbines typically reach temperatures in the 250F to 300F range, according to a few users contacted by the editors. This puts uncooled fuel-system components at an elevated risk of coking.

Given that liquid fuel lines are secured in close proximity to the turbine casing, sections of which can hit 500F, you can have oil baking at a temperature well above the coking point in some locations.

There are steps engineers can take at the design stage to mitigate the risk of coking in standard fuel-system components. For example, install a recirculating liquid system, move fuel lines away from the casing to reduce their exposure to very high temperatures, gravity-drain oil lines after use, etc. Regarding the last, one thing to remember is that oil does not drain completely and coke builds up in thin layers over time.

However, this buildup isn’t the biggest problem. When layers of coke break loose, the cause may be an event which impacts multiple fuel lines simultaneously. Examples include liquid-fuel check-valve chatter and rapid expansion or contraction of fuel lines, both of which can dislodge material instantly. Rectifying the problem may require removal of fuel nozzles to address high exhaust-temperature spreads and related trips.

Depending on contractual requirements, another possible downside to the draining of fuel lines is that the system has to be primed and purged of air prior to burning oil again or a false start is likely to occur. Priming, of course, takes time, which you may not have.

Another point to remember: If your fuel valves and lines get plugged, the coke must be removed or the affected components replaced. Fig 1 shows how much coke was removed from one standard liquid-fuel check valve during an overhaul. Fig 2 illustrates the considerable effort required to cut through and flush coke from fuel lines of a 7EA DLN-1 unit using the hydrolazing technique. It took about a week’s effort to return the machine to service.

The gold standard for liquid-fuel systems in dual-fuel plants is water cooling, to prevent coke formation in fuel lines and valves while the engine operates on natural gas and oil is maintained up to the combustor, assuring a seamless transfer to distillate when required.

Liquid-fuel quality must be maintained at the highest level to prevent water and other contaminants from entering the fuel system. Recent experience reported by users on the effectiveness of storage-tank side-stream filtration systems, based on technology used to restore turbine hydraulic and lubricating oils to top condition, illustrate the importance of avoiding the “fill and forget” attitude that prevails at some plants.

The ability of these systems to remove water entrained in stored fuel is beneficial to the health of cast-iron flow dividers still metering fuel to combustors at some plants.

Water-cooled liquid-fuel system

Schuyler McElrath, the industry’s most vocal proponent of water-cooled liquid fuel systems, assures owner/operators that JASC’s® Gen3 system is capable of approaching 100% reliability during oil starts, and on transfers from gas to oil.

On a recent call with the editors, he ran through the company’s nearly two decades of product improvements and the reasons for his enthusiasm. McElrath pointed to five consecutive years of service and 60 consecutive transfers for JASC’s water-cooled liquid-fuel check valves before an unsuccessful attempt (Fig 3) and seven years of experience with water-cooled three-way purge valves without loss of system reliability.

The water-cooled three-way purge valve replaces the uncooled version of the valve, which could plug with coke formed by “cooking” of the liquid fuel when gas was burned. Perhaps the most significant Gen3 improvement on these valves was the elimination of heat-related O-ring failures on liquid-fuel and purge-air connections through the use of copper crush gaskets (Fig 5) in place of Viton.

While Viton is designed for high-temperature applications, after long-term exposure to heat they lose elasticity, take a set, and crack. The typical result is leakage at joints because of metal expansion and contraction during operation.

JASC’s experience is that copper crush gaskets will survive high-temperature exposure indefinitely with no change to sealing integrity, making them more compatible with today’s extended maintenance intervals. Plus, these gaskets can be made, broken apart, and remade multiple times before requiring replacement.

So-called positional tees (Fig 6) are another Gen3 improvement associated with the three-way purge valve. They eliminate tees using Viton O-rings for the purge-air and liquid-fuel connections at the fuel nozzle, opting for copper crush gaskets instead. Positional tees get their name from the fact that they can be rotated and locked down at any point on their 360-deg circumference. The benefit: Three HGP cycles or 12 years of leak-free operation in both peaking and baseload applications.

Heat-sink clamps (Fig 7), located just upstream of the three-way purge valve in Fig 4, keeps the liquid fuel system primed from the stop valve to the fuel controls and ready for immediate dispatch. The clamps protect stagnant diesel fuel against viscosity changes which foul fuel control seats and can transition distillate oil to solid coke during extended periods of operation on natural gas.

Water-injection check-valve Gen3 improvements focus on metal-to-metal sealing, thereby eliminating the degradation of elastomeric materials formally used and preventing leakage while on standby during operation on natural gas. Eliminating water-system evacuation on standby avoids exhaust-temperature spreads/trips when water injection is reactivated for emissions control.

The smart fluid monitor shown in the system diagrams was redesigned for the Gen3 system to accomplish the following:

    • Measure water supply and return flow discrepancies down to 0.1 gpm.
    • Programmable shutoff range of 0.1 to 1 gpm.
    • Ability to monitor up to four turbines remotely.
    • Standalone control or output can be integrated into the turbine control system.
    • Monitor and control cooling-water flow and temperature. A critical function of the smart fluid monitor is to protect the liquid-fuel system against low temperatures associated with paraffin dropout. Recall that wax can impede fluid flow and cause a failure to start.

Liquid-fuel quality

Contaminants introduced into your liquid fuel during transportation can require a substantial cleanup effort if foreign material remains in the oil for a prolonged storage period. Reason: Some contaminants will catalyze the fuel degradation process, compounding the problem.

Having a filter ahead of the storage tank capable of trapping large quantities of water (particularly saltwater, the largest single source of sodium contamination so detrimental to HGP parts) and sediment before they enter the tank is important. Also critical to fuel quality is periodic—read weekly—bleeding of water from the bottom of the tank. This is especially true in warm, humid regions of the country. Remember that oil tanks are vented and they breathe.

Plants monitoring the condition of their backup fuel sometimes are surprised by the poor quality of oil at the bottom of their tanks—say the last 5 ft or so. This generally is not problematic given the floating suction systems typically in use today—that is, until you have to burn the dregs. It doesn’t take much sludge-type material to cause a failure to start or to trip a high-performance gas turbine. The financial penalties could be significant.

CC Jensen Inc’s Technical Manager Axel Wegner, expert in the cleanup of turbine lube and hydraulic oils, has been promoting at user-group meetings for several years the idea of using similar technology to maintain backup-oil quality with a slipstream treatment system on the storage tank. Results from the first two installations (one 1-million-gal tank, one 4-million-gal tank) at gas-turbine peaking and combined-cycle sites, just in, are encouraging (Fig 8).

Wegner told CCJ ONsite that, based on current experience, an appropriate cleanup system for a standby oil tank might turn over the inventory once a month to maintain the fuel quality desired. For a plant burning only diesel (no gas) the system probably should be designed to process oil at 110% of the consumption rate, he added.

One user told the editors that he received only two responses to his RFQ for a diesel-fuel cleanup system, purchasing one each from CC Jensen and Hy-Pro Filtration.

Desert Basin reports experience, success with first 501F FlameTOP7 upgrade

By Team-CCJ | February 5, 2022 | 0 Comments

The numbers are eye-opening: 20-MW gain in simple-cycle output, 3.8% heat-rate improvement in simple cycle, a stable GT turndown to 38%, and less than 9-ppm NOx across the load range. That’s what PSM and Salt River Project’s (SRP) Desert Basin Generating Station reported at the 2021 501F Users Conference after upgrading a 2001 vintage Siemens 501FD2-powered combined cycle with PSM’s FlameTOP7 technology, a first-of-a-kind for PSM on a 501F engine (figure).

Desert Basin has been a 501F fleet leader for two decades. This pioneering installation is no exception. But as Desert Basin’s Moh Saleh and Jess Bills report, you can’t avoid a few challenges along the way.

Design aspects of PSM’s technology progression with GTOP6, GTOP7, FlameSheet™, and AutoTune have been explicated several times in the pages of CCJ (most recently, the last print issue, No. 65, 2021). FlameTOP7 essentially integrates the gas-turbine optimization aspects of GTOP7 with the output and efficiency improvements from the FlameSheet combustion system, with AutoTune thrown in for good measure. GTOP and FlameSheet are hardware upgrades, while AutoTune embodies advanced controls.

Here, the focus is on Desert Basin’s install and initial operating experience, based on material presented with PSM at the conference, and a follow-up call with Bills and Saleh.

Changing needs, ageing units. SRP needs more flexibility and output from its GT fleet with the retirement of large coal-fired units in the state and growing customer load. It was also a natural point in the Desert Basin units’ lifecycle to consider a major upgrade. Unit 1 had 12k EOH (equivalent operating hours) hardware in it, Unit 2 has 25k hardware. The plant wanted to use up the parts in inventory, so the remaining parts were installed in Unit 1. Generally, “the parts were on their last legs,” noted Bills.

After evaluating advanced technology options and settling on FlameTOP7, the plant initiated a 10-month planning cycle, which of course was disrupted by Covid-19, and opted for a PSM total scope outage. It included scaffolding and installation requirements; and re-insulation (ARNOLD insulation) work for the walls, floor, and ceiling of the exhaust transition ducts.

Scope outside of PSM included internal repairs of exhaust transition ducts, HRSG repairs, relay upgrades, generator breaker replacement, new inlet air filters, upgrading of the exciter cooling system, and HRSG impacts evaluation. Additional fretting of the rotor, initially observed seven years earlier, was discovered during the project. PSM worked with Sulzer to address it; this work did extend the outage.

Planning included three site walkdowns, three joint PSM/SRP meetings ahead of the outage, review of logistics of PSM tooling and personnel onsite, and preparing for possible Covid-19 quarantine.

Bills and Saleh credit part of the project success to the decision to hire a third-party contractor for additional project oversight, “extra eyes on the work,” as they put it in the presentation. Seth Conway, Somerset Engineering, had extensive experience doing contract work with PSM and with FlameSheet installations on 7FA machines.

Covid confounds. Once the pandemic settled in, the teams had to resort to virtual inspections of FlameSheet cans in the PSM shop and assembled parts ready for shipment, in addition to virtual training sessions. Plus, no one was able to walk down other sites which had installed GTOP or FlameSheet. Each contractor had its own workspace onsite to avoid cross-transmission.

All office space had to be arranged for social-distancing. Because these are inside units, organizing work and tooling was especially important. Thankfully, no one became Covid positive while onsite.

Bills and Saleh laud tight and highly transparent communications during the entire Covid-impacted project. By the time of commissioning the new equipment, meetings were being held daily. They also credit early attention to logic and controls modifications (which had to be performed virtually) as a key factor in project success. “We were serial Number One,” said Moh, “and we didn’t want any impacts from something we might miss in the controls.”

Safety minute: Crossed crane signals

Seasoned plant folks live by such mottos as “expect the unexpected” and “only the paranoid survive.” Still, no mind or collective hive can be all-knowing. Here’s an important safety minute that came from this project: Don’t assume that the crane remote control is operating the crane you think it is.

Desert Basin has two bridge cranes: a 60-ton unit over the gas turbine, and a 70-ton unit over the steam turbine. Each has a 10-ton auxiliary hook. Hand-held radio controllers are used to move both. Rarely are both cranes used at the same time.

The plant wanted to add load cells so staff would know the weight of equipment being lifted, and an accompanying LED readout option to the joy-stick-equipped belly box for the 70-ton crane used by the operators. One was already installed on the 60-ton crane’s controller.

The appropriate chip was pulled from the box and sent to the manufacturer so it could be re-programmed. After it was returned and re-installed, the SRP crane group tested it. All good. However, the 60-ton unit was not operating during the test.

When the 70-ton crane was next pressed into service, the 60-ton crane started moving! The operator quickly got off the joy stick, and supervisors declared a safety stand-down to figure out what happened. A root-cause analysis was initiated. “You try to do something to make life better [like add an LED readout] and something hiccups,” Bills lamented. Thankfully, no one was injured. The local crane rep reviewed the chip programming and discovered that the signals were crossed at the factory.

Now the plant runs both cranes during tests to make sure there are no interactions between them.

Taming NOx emissions. The conversion from the original DLN (dry low NOx) hardware to FlameSheet was “seamless,” noted PSM and SRP, “the OEM’s fuel manifold was adapted to the new combustor.” However, when the units were first fired up with the new technology, the plant experienced some failed starts and incomplete ignitions. “GTs are very sensitive to fuel and air flows,” Saleh reminded.

The more stubborn problem, though, was that NOx emissions were initially much higher than expected at loads between 70% and 100%, higher than was demonstrated in PSM’s lab. The original permit limit was 25 ppm, but the new guarantee point is 9 ppm.

PSM specialists Brian Micklos, senior manager of product management, and Brian Kalb, lead tech for combustion mechanical design, described “runback events triggered by elevated flashback,” or in simpler terms, “the flame wasn’t where it should have been.” One liner experienced physical damage. The runback logic was revamped to prevent these problems, but the problem was that the combustor was running off of its design point.

PSM did some additional modeling and found unexpected air and fuel flows. Specialists added high-temperature thermocouples inside one combustor can, found some anomalies, and tweaked the FlameSheet liner with some expert welding. That helped, but a second “liner tune” was necessary. It involved “reworking the meter plate and flow sleeve” and additional welding modifications. The hardware tweaks were confirmed with CFD and air-flow testing.

Once the fuel/air ratios across the multiple fuel circuits were rebalanced, the units were able to achieve sub-9 ppm across the load range; reliability also greatly improved, as the combustion dynamics were much more stable after tuning. CO emissions were tuned to 7 ppm at 70 MW, and 10.5 ppm at 65 MW.

Saleh and Bills added that replacing the problematic combustion dynamics monitoring system (CDMS), a fleet-wide issue with these machines, contributed to the improved reliability. “The original electric sensors would fail monthly, lead to runbacks, and other problems,” they said. They were also difficult to access, because of the ¼-in. stainless-steel tubing attached over the combustor can. The new ones are mounted on the combustor “top hat,” not directly on the combustor.

“We were limping along with the old ones for so long because they were costly and difficult to retrofit,” Saleh noted. In any case, the old sensors were not compatible with AutoTune.

Lesson learned—permit details. Commissioning new technology takes time and patience, but as importantly accrues operating hours. Emissions compliance permits are usually very meticulous when it comes to startups and total emissions over a time period.

Desert Basin by no means is the first to drop this into the lessons-learned box, but it’s an important one. “You need to ensure that the owner/operator and the technology vendor are fully aligned on permitting,” stressed Saleh, “and that you know the details of the permit inside and out.” Bottom line: Make sure you manage expectations on how many additional starts, stops, and operating hours could be necessary to fully commission the new technology.

Can the HRSG take it? Impact on the HRSG was another challenge and lesson learned. “If there was one thing we could have done better, we would have worked out the full impact of the GT upgrade on the HRSG,” Bills said. The first contractor they hired to assess the impact gave them modeling, but “what we needed was a practical approach.” So a second contractor was engaged to more fully understand design aspects.

This part of the project is still being investigated. While the GT can now operate at 38% turndown, the plant is limiting it to 45% pending a better understanding of HRSG stresses. In the meantime, they are running field trials to see how the HRSG reacts at lower GT loads.

Balance-of-plant impacts. Another important area of BOP impact was the generator. The generator itself had ample design margin, but ancillaries needed attention. “We were fortunate that Desert Basin typically runs low VARs, so we don’t stress the excitation system,” said Bills. However, plant staff observed that the exciter was running hot the previous summer and, with the GT upgrade, was now bumping up against its temperature limit.

“Our exciter bridges are obsolete, but we devised a home-grown cooling system for them,” Saleh beamed. He credits one of the plant machinists with a penchant for race cars and a crack electrician for the creative solution.

Beyond the generator, Bills and Saleh add, be sure to review transmission capabilities, previous studies, and the owner/operator’s transmission agreements.

LM Engine Common Acronyms

By Team-CCJ | February 4, 2022 | 0 Comments

Keep this list of acronyms nearby during WTUI’s 2021 virtual conference. You’ll find that most speakers talk in “shorthand,” using acronyms freely. If you’re not up to snuff on your aero lingo you can get lost in a hurry and possibly miss key points. The “cheat sheet” that follows can help you remain focused.

AGB—Accessory gearbox (also called the transfer gearbox)

AVR—Automatic voltage regulator

CCM—Condition maintenance manual

CCR—Customized customer repair

CDP—Compressor discharge port

CFF—Compressor front frame

COD—Commercial operating date

CPLM—Critical-parts life management

CRF—Compressor rear frame

CWC—Customer web center (GE)

DEL—Deleted part

DLE—Dry, low emissions combustor

DOD—Domestic object damage

EM—Engine manual

FFA—Front frame assembly

FOD—Foreign object damage

FPI—Fluorescent penetrant inspection

FSNL—Full speed, no load

GG—Gas generator (consists of the compressor and hot sections only)

GT—Gas turbine (consists of the gas generator pieces with the power turbine attached)

GTA—Gas-turbine assembly

HCF—High-cycle fatigue

HGP—Hot gas path

HPC—High-pressure compressor

HPCR—High-pressure compressor rotor

HPCS—High-pressure compressor stator

HPT—High-pressure turbine

HPTN—High-pressure turbine nozzle

HPTR—High-pressure turbine rotor

IGB—Inlet gearbox

IGV—Inlet guide vane

IPT—Intermediate-pressure turbine (LMS100)

IRM—Industrial repair manual

LM—Land and marine

LCF—Low-cycle fatigue

LO—Lube oil

LPC—Low-pressure compressor (not on LM2500; just LM5000 and LM6000)

LPCR—Low-pressure compressor rotor

LPCS—Low-pressure compressor stator

LPT—Low-pressure turbine

LPTR—Low-pressure turbine rotor

LPTS—Low-pressure turbine stator

MCD—Magnetic chip detector

MOH—Major overhaul

NGV—Nozzle guide vane

OEM—Original equipment manufacturer

PN—Part number

PT—Power turbine (turns a generator, pump, compressor, propeller, etc)

PtAl—Platinum aluminide

RCA—Root cause analysis

RDS—Radial drive shaft

RFQ—Request for quote

RPL—Replaced part

SAC—Single annular combustor

SB—Service bulletin

SL—Service letter

SUP—Superseded part

STIG—Steam-injected gas turbine

TA—Technical advisor

TAT—Turnaround time

TAN—Total acid number (lube oil)

TBC—Thermal barrier coating

TGB—Transfer gearbox (also called the accessory gearbox)

TMF—Turbine mid frame and thermal mechanical fatigue

TRF—Turbine rear frame

VBV—Variable bleed valve (not on LM2500; just LM5000 and LM6000)

VBVD—Variable bypass valve doors

VIGV—Variable inlet guide vanes

VSV—Variable stator vane

VSVA—Variable stator-vane actuator

What color is your hydrogen?

By Team-CCJ | February 4, 2022 | 0 Comments

You can add another color to the burgeoning spectrum that is hydrogen as an energy stream: turquoise. According to Brad Bradshaw, speaking on the Hydrogen Energy Center’s (HEC) Apr 23, 2021 webinar (on-demand below), “Decarbonizing the Gas Grid with Hydrogen,” turquoise H2 is methane subjected to pyrolysis to split it into hydrogen and solid carbon. Carbon dust is easier to deal with (and has valuable industrial uses) than CO2, says Bradshaw, president of both HEC and Velerity, a Massachusetts-based research and consulting firm.

HEC describes itself as a “professional association focused on accelerating hydrogen as an enabling solution for renewable energy.”

To review:

    • Green H2 is produced using renewable electricity to split water in an electrolyzer.
    • Blue H2 is produced from steam methane reforming with carbon capture and storage.
    • Gray H2 is produced from steam methane reforming without CCS.

While you’re at it, you can also add another squishy term to the industry’s lexicon: renewable gas. This is natural gas that is processed to reduce the amount of carbon that will ultimately be discharged when it is burned or otherwise used. Processing can be as straightforward as blending H2 in pipeline gas or as involved as gas pyrolysis.

Renewable gas echoes an earlier industry attempt to align a fossil fuel with environmental correctness: clean coal.

The introduction of the HEC’s Renewable Gas Consortium (RGC) is a direct counter to pressures the natural-gas industry faces—listed by Bradshaw as bans on new gas hookups at the local distribution company (LDC) level, pipeline permit reversals, and “calls to electrify everything.” However, the call to electrify everything is not realistic, says Bradshaw, such as winter heating loads in the northern parts of the country and many industrial process heat applications—including district heating and cooling.

LDCs face a threat similar to that of electricity distribution utilities: As more gas customers leave the grid, the remaining customers have to pay more to maintain the infrastructure. Major cities in California, Massachusetts, Washington, and Colorado—including Berkeley, San Jose, Mountain View, Brookline, Denver, and Seattle—have banned new gas customer hookups. Others are seeking to displace gas with electricity.

While solar power purchase agreements have reached 1 cent/kWh, solar and wind curtailments are rising, notes, Bradshaw, because of the mismatch between renewable energy daily and seasonal availability and electricity demand curves (figure). If you can use this excess electricity to moderate natural gas’ carbon footprint, then the phrase “renewable gas” isn’t quite as squishy.

One example is adding H2 to biogas which “sweetens” the methane content by up to 70% by converting CO2 to methane. There’s a net benefit here for biogas that would have been released to the atmosphere because methane’s climate impact is, using the average of the range of figures reported, around 20-fold greater than CO2.

One “turquoise H2” company, C-Zero, Santa Barbara, Calif, employs an innovative thermocatalysis pyrolysis process to convert natural gas to carbon and H2. It is described on the company’s website as a “drop-in” system between the gas distribution infrastructure and gas customers. Bill Gates’ clean energy investor group and Mitsubishi Heavy Industries are both investors in the company and technology. However, the notion that a pyrolysis process can be simply “dropped in” on the gas delivery system makes the phrase renewable gas look like it belongs in Webster’s.

MHI also is invested in Monolith Materials, Lincoln, Neb, with a plasma-based pyrolysis technology.

The National Renewable Energy Laboratory (NREL) is leading a coalition of six national labs in an R&D program to “address the technology barriers to blending” H2 in natural gas pipelines. Southern Company Gas, part of Southern Company, is a major private sector participant.

The blending of hydrogen and methane in pipelines has implications for gas-turbine operators concerned with operating at top efficiency. Likely, an online calorimeter capable of providing virtually instantaneous data on the energy content of the mixed gas will prove valuable for combustion control purposes.

According to Bradshaw, renewable gas and H2 can meet 60% of the non-power gas demand in the Northeast and the RGC is “driving $10-billion investment in renewable gas, hydrogen, and biomethane in the Northeastern US.”

Expectations around H2 should be tempered with the understanding that most of the current activity is positioning for the billions in expected government and venture capital investment. Enthusiasts will undoubtedly declare “this time is different,” but the vast majority of technologies from the clean coal RD&D program—including integrated gasification combined cycle, pressurized fluidized combustion, slagging combustors, and back-end multi-pollutant removal processes—never reached commercial adoption beyond one or two full-scale demonstration units. In the meantime, solar, wind, and gas-fired gas turbines and combined cycles displaced coal-fired systems based on lifecycle economics.

H2 has an added challenge: It is an energy carrier not an energy source, just like electricity. Ultimately, economic viability depends on whether the value of carbon, with respect to its threat to climate and social disruption, is priced high enough to counter the cost of extracting the hydrogen.

How to straighten a bowed steam-turbine rotor

By Team-CCJ | February 4, 2022 | 0 Comments

When you’re sick, or something seems “off,” what do you do? Many people search the web, often arriving at a WebMD, Mayo, or equivalent site, for some initial information. If symptoms persist, you go to your primary-care physician. The doc may tell you to see a specialist or even a surgeon.

Thankfully, when your steam turbine seems “off,” and you suspect the rotor, you can get “integrated care” from the 500 folks at MD&A, including 200 seasonal traveling turbine experts. Who says doctors don’t make house calls?

Think of the “Bowed Rotor to Straight Rotor” presentation by Rob Kilroy in MD&A’s Spring 2021 Webinar Series, summarized here, as WebMD. If the turbine rotor needs an official diagnosis, MD&A will send inspection specialists to your site. If the diagnosis suggests repairs, the company will handle those as well.

If you are recording a gradual increase in rotor vibration over a long period, it may be time to listen up. The rotor may be bowed, caused by persistent asymmetrical heating or cooling of the shaft. Pre-1960s turbines rarely experienced bowing. Today’s longer, more slender rotors with a reduced number of bearing pedestals and more aggressive operating parameters are more susceptible.

The MD&A crew is seeing around a dozen bowed rotors each year. That may not seem like a lot, but given the damage a bowed rotor can do, it’s best not to find out the hard way.

In the webinar, Kilroy explains rotor bowing is defined by the total indicated reading (TIR). If the TIR is less than 0.03 in., the bowing is minor, if between 0.04 and 0.015 in., it’s moderate, and above 0.016 in., consider it severe. Severely bowed rotors typically cannot be balanced, and will require an engineered straightening solution.

The turbine/generator repairs engineer delineates three categories of straightening options, once the detailed in-casing and disassembly inspections are completed: Machining/throwing of journals, stress relief/heat lathe, and thermal straightening (photo). The last two typically do not require resizing of the bearings.

Best of all, Kilroy reviews seven case studies, the first three on the cusp of severe with max TIRs of 0.015. In general, the “surgeries” MD&A performed return the rotors to a TIR of between 0.001 and 0.005. In one case, a rotor with “all kinds of problems” and a 0.007-in. TIR at the turbine end and 0.053 at the generator end, MD&A’s solution reduced the TIRs to 0.001 in. at both ends.

Rotors from a variety of manufacturers are featured in the case studies. Frequently, the rotor was subjected to multiple straightening options and ancillary machining and component replacements. You’ll understand the innovative thinking that’s required once you watch the video (users only).

What GE told STUG2020 attendees about its steam turbines

By Team-CCJ | February 4, 2022 | 0 Comments

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.

EPRI reports offer a short course on delamination of hardfacing and how to avoid it

By Team-CCJ | February 4, 2022 | 0 Comments

EPRI led a research effort from 2013 to 2015 to identify contributing factors to the large number of hardfacing failures—a/k/a delamination or disbonding events—experienced industry-wide. The project purposely engaged stakeholders in the valve supply chain with both users and valve manufacturers sponsoring the effort. Content summaries of the three technical update documents issued in 2015 as a consequence of this effort are below. They are available at no charge to select EPRI members and for a fee to others. To purchase, contact the EPRI Order Center at 650-855-2121 or orders@epri.com.

Investigated failures occurred primarily in valve components (disc, seat, and/or stem) fabricated from CrMo Grade 91 or 400-series stainless where a cobalt-based hardfacing material (Stellite) was directly clad on the base metal. Failures were observed in components where the stated operating temperature was a nominal 975F or higher.

EPRI continues to investigate and update its guidance on the subject. The latest iteration of this ongoing research effort is being led by Dan Purdy (dpurdy@epri.com), a senior technical leader in the organization’s Materials and Repair Program. Purdy now is in the early stages of integrating the first report in the three-part series into a more encompassing large-bore valve-body specification.

“Guidelines and Specifications for High-Reliability Fossil Power Plants: Recommendations for the Application of Hardfacing Alloys for Elevated-Temperature Service,” EPRI product 3002004990, 30 pages.

Cobalt-based hardfacing alloys are used to protect sealing surfaces in high-temperature valve components primarily because of their resistance to wear. Inspection of ex-service valve components has revealed early cracking and disbonding of the hardfacing from the substrate material. Analysis identified the formation of undesirable hard, brittle intermetallic phases in an intermixed zone typically between the substrate and the hardfacing layer.

Although the degree of this first weld pass dilution can affect the extent and kinetics of embrittlement, it is desirable to remove the possibility of the undesirable phase formation entirely through the application of nickel-based-alloy butter layers that do not show the tendency of phase transformation at any level of dilution with the substrate or cobalt-based hardfacing

Report’s objective is to provide scientifically based guidance in the engineering, quality control, and inspection of welded joints between ferritic valve components and cobalt-based hardfacing to avoid delamination in service.

“Experiences in Valve Hardfacing Disbonding,” EPRI product 3002004991, 96 pages.

Evaluations of service history and failed ex-service components have led to an understanding that metallurgical changes within the microstructure during welding and high-temperature service exposure contribute to disbonding. Cracking has been shown to prefer bands of unexpectedly hard layers in the weld deposit, and there is evidence of the formation of the brittle intermetallic Sigma phase in those regions. The solution appears to be not one of process—that is, dilution—control, but rather identification of the alloy combinations that remove the possibility deleterious phases will form.

The report discusses the history of hardfacing disbonding as it applies to the power-generation sector of the industry. Included in the timeline are the advances in the state-of-the-art in fabrication, the potential consequences of those changes in processing, a variety of notable failures, and a thorough look at the thermally driven stresses in valve components. Metallurgical analyses of failed components covering a range of material combinations and applications are presented. Many material combinations have been used to varying degrees of success; the report describes the causes of the issues.


“Proposed Solutions for Hardfacing Disbonding in High-Temperature Valves,” EPRI product 3002004992, 66 pages.

This third report elaborates on an exhaustive thermodynamics methodology to predict the formation of deleterious intermetallic phases over a range of alloy combinations, and the degrees of mixing among them. The thermodynamic predictions uncovered a wide range of problematic material combinations, as well as several key parameters that lead to metallurgically stable combinations—regardless of the degree of mixing among the constituents. Stitching together these safe combinations creates a layered hardfacing welding procedure that removes the possibility of harmful phases affecting the matrix and leading to disbonding.

These alternative weld solutions were validated through laboratory trials and extended ageing to demonstrate their long-term stability. Laboratory welds that recreated the problematic combinations were observed to begin their transformation, while alloy combinations that were expected to be free of that risk did not harden.

Stellite delamination is preventable, but owner/operators must ‘enforce’ the solution

By Team-CCJ | February 4, 2022 | 0 Comments

Liberation of cobalt-based hardfacing (oft-used Stellite™ being one of these materials) from large Grade 91 valves installed in combined-cycle main and hot-reheat (HRH) steam systems, and in steam turbines, was a hot topic in the industry about a decade ago. With the need for an evidence-based solution, the Electric Power Research Institute (EPRI) assembled a committee consisting of owner/operators and stakeholders in the valve manufacturing supply chain to collaborate on the development of guidelines to mitigate the issue.

Three reports on that effort were released by EPRI in 2015 (see companion article) and the solution identified has prevented disbonding of the hardfacing where employed—at least CCJ ONsite has not identified any cases where the solution has not met expectations. Although there are only five or six years of field experience to validate the successful approach at this time, that’s a big improvement for some plants where delamination had occurred in as little as 12,000 hours of operation.

With a solution available, why is CCJ ONsite covering this topic again? The answer in brief: Not everyone who should know about this relatively recent development is aware of it. Proof of the knowledge gap came by way of a phone call from Aaron Florek of Millennium Power Services, a major player in the valve repair business, who told the editors that his firm recently had repaired valves suffering disbonding at three plants in a three-month period.

Needing confirmation that the old news (delamination) is new again, the editors contacted two technical experts with deep experience on the subject—Kim Bezzant of Utah-based Wasatch Welding Engineering Services and John Siefert, manager of EPRI’s Materials and Repair Program—as well as current users, and power-industry veteran Joe Miller, now industry director for power at ValvTechnologies Inc, which offers an alternative to Stellite hardfacing on the disks, seats, and stems of new steam valves.

All agreed that Stellite disbonding continues to haunt the industry—in large measure because owner/operators generally haven’t been diligent in upgrading their specifications both for new valves and valve repairs to reflect recent experience. It is not sufficient to simply specify that valves be manufactured, or repaired, to meet the requirements of the ASME Boiler and Pressure Vessel Code (for valves within the Code boundary) and ANSI/ASME B31.1 (for valves included with boiler external piping). Recall that these documents prescribe minimum requirements and were developed to ensure that the equipment they address is safe.

They certainly do not protect against the financial fallout from a delamination event that forces your plant offline or prolongs a scheduled outage. With all the changes to grid contractual agreements over the last few years, it is worth reviewing the exposure your plant could have to a valve failure and how much it’s prudent to spend on original equipment and repairs to insure against one.

Remember, too, it’s not enough to simply upgrade valve specifications, you have to monitor the manufacturing and repair practices of the selected solutions providers to ensure they are doing what you have carefully specified in the contract. This can be challenging where offshore vendors are involved. Boiler manufacturers and EPC firms tend to buy foreign, in particular from Korea and India, to reduce their costs and they may be reluctant to monitor contract performance in-person. Such details must be agreed to and understood before work begins.

Many boiler and turbine valves have performed admirably over the years with cobalt-based hardfacing, as well as with other hardfacing materials. But the change to Grade 91 valve bodies and the demanding operating conditions for heat-recovery steam generators (HRSGs) in combined-cycle service have pushed to the limit the technology traditionally used to bond cobalt-based hardfacing to C12A or F91 valve trim. Today’s high steam temperatures required a different methodology for attaching the two materials.

In simple terms, here’s what EPRI’s materials experts learned: Addition of a “buttering” layer of nickel-based alloy—such as Inconel™—separated Stellite and F91 material and prevented formation of an undesirable metallurgical condition in the weld zone between the two metals which is conducive to disbonding.

Plant experience. Florek told CCJ many plants in the country are addressing Stellite delamination issues and there are many more not yet aware of the problem they probably have. The three plants located in the Northeast that Millennium Power provided outage services for in the three-month period (2020) mentioned above illustrate findings typically identified at other facilities. Here are some of the details from those projects:

The first plant, a 2 × 1 H-class combined cycle began operating in 2017. Delamination was observed on six valves associated with the boilers and steam system at that facility—HP HRSG isolation, HP header isolation (a/k/a blending valve), and HRH (hot reheat) header isolation (for isolating one boiler from the other when necessary). The first type was in the European boiler manufacturer’s scope of supply and sourced from Korea, the mixing valves in the EPC firm’s scope came from another manufacturer.

The 14-in., F91 HP boiler valves were specified for service at 2420 psig/1065F. The type of Stellite hardfacing was not specified. What is known is that no buttering layer was used and that the Plasma Transferred Arc Welding (PTAW) process likely was employed for Stellite attachment. The HP isolation and blending valves are of the parallel-slide gate type and suffered Stellite liberation from both the seat rings and discs.

Note that these valves were manufactured before the EPRI guidelines (sidebar) were published. The EPRI findings identified disbonding concerns beginning at steam temperatures of about 975F, possibly even lower, with shorter expected life as the operating temperature increased.

When restarting the plant after the 2020 spring outage, an HP bypass valve on one of the HRSGs stuck open at 80% of full travel. This particular valve had just been retrofitted with a new magnetite strainer modification and reassembled. Inspection revealed hardened material in the valve, begging the question: Where’s this coming from?

Repair of two valves on the boiler (the stuck-open valve and one additional HP valve), plus inspection and removal of debris from the steam system, were priorities. Some of the liberated material had traveled downstream to the steam turbine. It had piled up against the unit’s protective steam strainers and was removed later, in fall 2020. During both outages, a borescope equipped with a magnet was run up through the steam lines to collect any remaining loose debris.

A specialty engineering firm was engaged to analyze the scrap and make recommendations. There were no unexpected findings. That company also confirmed the importance of a buttering layer. Bezzant recommends a buffer layer of ERNiCr-3 (Inconel Filler Metal 82), or an equivalent PTAW powder, to prevent carbon migration into the Stellite.

The affected valves were disassembled and discs and seat rings cut out. Millennium provided new seat rings and hardfacing for the discs consistent with EPRI recommendations and the company’s experience.

Plant personnel continue to analyze the delamination issue and how to prevent it, with assistance from one of the valve manufacturers. One of the questions they are trying to answer: Is there a temperature at which hardfacing of the type currently used and applied becomes impractical? Another: Is the ramp rate or steam temperature the cause of disbonding?

Steps already taken by the plant include modification of its cold-start procedure (more time) and greater emphasis on the use of sparging steam from an auxiliary boiler to keep the unit warm when offline.

Regular inspections of valves are important to assess their true condition. The plant manager suggested that absent leak-by, your valves likely are fine. But it’s probably a good idea to still select one or two valves at random for a thorough NDE inspection during each hot-gas-path outage. Why only one or two valves? Every time you open a healthy valve you run the risk of compromising its integrity.

If your inspection indicates leak-by, immediate action to correct is recommended.

Millennium Power refurbished four HP valves (isolation and blending) on the affected boilers to return the combined cycle to full power as quickly as possible. Work on the valves was completed in-situ a day ahead of the eight-day schedule. Plant’s plan is to address damage to other valves suffering delamination, as necessary, during future scheduled outages.

In preparation for the fall 2020 outage, Millennium got the repair effort on the two HRH blending valves moving before the outage began by making new seat rings in its shop, Florek touting the company’s ability to reverse engineer and typically make any manufacturer’s valve parts in less time than it would take the vendor of record to supply them.

The first step in the repair process was to remove damaged parts and prep the valves for new parts and hardfacing—something Florek says the company has done at least a couple of dozen times to date. Follow key steps in the montage of photos incorporated into Fig 1. He added that sometimes just the hardfacing is damaged, not the basic part. In such cases it’s sometimes possible to remove the coating and reapply Stellite with the requisite butter layer.

Millennium Power’s field service personnel moved in short order from this project to another in the region where two 24-in. parallel-slide gate valves were refurbished within two weeks. Old seats were removed, new seats manufactured with Stellite overlay and Inconel butter layer, and the valves rebuilt, including new actuators. Original seat welds were found broken; one of the seats was severely deformed (Fig 2).

At the third plant in the Northeast that Millennium serviced within the three-month period noted above, a 24-in. wedge gate valve in the HRH system was scheduled for a stem replacement to mitigate packing wear. A new stem was manufactured in the company’s shop and shipped to the site for installation.

When technicians disassembled the valve, Stellite disbonding was found on the wedge and both seats. The owner approved corrective action the next day and Millennium’s field machining crew arrived onsite four days later to remove both seats while concurrently refurbishing the existing wedge in accordance with EPRI recommendations. Seats were replaced, wedge refurbished, and valve reassembled all within 16 days of project start.

Steam turbine. A case study of damage suffered by a 262-MW D11 steam turbine because of Stellite delamination associated with HRSG steam valves was presented at the 2019 meeting of the Steam Turbine Users Group. The clue that something was amiss: Following a routine valve test, operators recognized that throttle pressure had to be increased by 70 to 80 psig above “normal” to maintain desired output—symptoms consistent with possible steam-path fouling or damage.

After weeks of data monitoring and analysis involving personnel from the owner/operator and OEM, a two-week outage was taken. Delamination of Stellite from the seats of HRSG steam valves was confirmed by investigators and a borescope inspection of the turbine HP inlet revealed significant damage to the first-stage nozzle block and buckets.

Three run-versus-repair options were considered for the steamer: repair now (reliability outage); run at reduced load with no cycling permitted, and repair when new buckets arrive; and run until the major maintenance outage planned for some months ahead.

The OEM’s recommendation was to run the turbine until the planned major and order new buckets and diaphragms for the first four stages of the 262-MW unit; plus, monitor the machine for noticeable changes in operation that would indicate additional damage. Also recommended was that the owner implement a program to inspect and replace similar Stellite-hardfaced valve parts exhibiting delamination.

Be aware that Stellite also has disbonded from the seats of steam-turbine valves; guidelines for their inspection are presented in GE’s TIL-1629R1, “Combined Stop and Control Valve Seat Stellite Liberation,” Dec 31, 2010. Thus, the information provided in this document predates the extensive work done by EPRI, and summarized in the companion article, by five years.

Inspection. Industry experience suggests inspection of large steam valves for delamination and other possible issues during the next hot-gas-path (HGP) or major inspection—especially if this has not been done previously. Wasatch Welding Engineering Services’ Bezzant explains that visual inspection will confirm Stellite liberation, dye penetrant testing will reveal cracking not visible with the naked eye, and a straight-beam ultrasonic examination is necessary to identify disbonding that may be occurring but not found by visual or dye-penetrant examination.

But before opening your valves, he suggests you have a game plan for repair or replacement in case you find damage. Failure to plan ahead could significantly add to your outage schedule.

Here are your options if damage is found, according to Bezzant:

    • Replace the existing valve with a new one.
    • Cut the valve out of the line and send it to the manufacturer or a qualified third-party shop for repair.
    • Repair the valve inline.

Owner/operators who have already faced repair/replace decisions suggest that you factor the following facts into your decision:

    • The lead time for new valves may extend beyond a year.
    • Shops capable of doing quality valve work and welding generally have a backlog.
    • Quality repairs are difficult to make inline because of preheat and access requirements.
    • Field-service organizations with the requisite in-situ valve repair experience are extremely busy.
    • There is no industry standard for applying hardfacing, although EPRI’s recommendations for this are supported by those contacted by CCJ ONsite. Manufacturers and repair firms may have other procedures but they should be qualified metallurgically before work begins on your valves. Plus, owner/operators are advised to carefully monitor repair work to the qualified written procedure.

The editors contacted California-based Bay Valve at the suggestion of a user to get an idea of what’s involved in conducting a valve inspection. In two words: A lot. Bay said the company’s standard procedure is to have highly experienced personnel perform visual and dye-penetrant inspections and if cracking or other problem is identified it is referred to plant management, which might decide to expand the scope of the examination.

Preparation for inspecting a 12- to 14-in. HP or 20- to 24-in. HRH valve can take upwards of two days, one of the field supervisors told CCJ ONsite. Actual time depends on the size of the valve, manufacturer, plant constraints, etc. He walked the editors through the rigging and safety measures required to remove a 1-ton handwheel as evidence of some of the difficulties sometimes encountered. Budget another five days to complete the inspection and return the valve to operational condition.

Stellite-free valves. Hardfacing options other than Stellite are used in the industry. They too may have technical challenges and owner/operators should investigate their service histories thoroughly before deciding on what hardfacing material to specify.

ValvTechnologies’ Miller, contacted at the suggestion of an owner/operator with several Stellite-free valves at its plants that have been problem-free for several years save one stem packing leak, discussed the highlights of his company’s IsoTech® design for high-pressure applications.

ValvTechnologies’ parallel-slide gate valves for demanding combined-cycle service rely on the manufacturer’s proprietary RiTech® 31 (80% chromium carbide and 20% nickel/chrome by weight) coating, which is much harder than Stellite 6 (68.5 Rockwell C versus 30 for Alloy 6 at 1000F, a difference that increases with temperature). The coating is applied to critical parts—discs, seats, and guides—in HVOF (high-velocity oxygen fuel) spray booths using a compressive spray technique to achieve high bond strength.

The hard coating on the web guide ensures the discs are kept parallel through the entire valve stroke. As the valve is cycled under differential pressure, the hard surfaces reportedly burnish and polish each other, avoiding the scratching and galling cited by some users not using RiTech 31.

Miller said the company’s new IsoTech hybrid design has a cast A217 C12A short pattern body with welded-on forged end rings (pup pieces) which can be either A 182 F91 or F92 to match the piping-system material. The length of the end rings also can be customized to meet either ASME B16.10 end-to-end dimensions, or be provided longer to allow removal of heat-affected-zone material on valve replacement projects. Expected time for customization to your specific requirements is four weeks or less.

The new valve, characterized by a very low pressure drop, according to Miller, accommodates 12, 14, and 16 in. requirements with the same cast body.

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