Onsite – Page 54 – Combined Cycle Journal

How to inspect your aqueous-ammonia storage tank

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

An owner/operator presenting on aqueous-ammonia (NH3) storage tank inspections at the CCUG2020 Week Four session said that according to the governing standard, API510, a “fitness for service” assessment should be conducted every 10 years (or half the remaining life calculated during the last inspection) for pressure tanks. The method results in a calculated remaining life, and typically the work is performed by a specialist contractor squad including an API specialist, NDE technicians (usually two), a confined-space entry team, standby rescue team, environmental contractor, scaffolders, and the ammonia supplier.

Plant management should assign a point person to the project who coordinates with the contractors, prepares the tank documentation, gathers previous inspection reports, etc.

Since tank wash-down water must be disposed of as hazardous waste, an accurate estimate of residual NH3 is necessary ahead of the work. You can expect between about 2000 and 3000 gallons of RCRA-type waste which will have to be disposed of or stored onsite in a tanker. Plant should allow a full day for tank cleaning.

Once cleaned, the actual tank inspection is “pretty straightforward.” The NDE inspectors divide the tank surface into a grid and record thicknesses from ultrasonic transmitter (UT) readings at each location. Allow a second day for the inspection work. Plant staff should take the opportunity to service pressure relief valves, vacuum breakers, and other components, and to leak-check the manway ports (easier for vertical tanks). Make sure to have on hand sufficient calibrated air monitors and extra ammonia sensors.

In response to questions, the presenter said that (1) they had not considered neutralizing aqueous NH3 prior to opening the tank, (2) the dump valve should be inspected and/or replaced at each inspection, and (3) the tanks are carbon steel, piping is stainless, and that iron can mix with the NH3.

Test program identifies ways to improve cooling-tower fan reliability

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

EPRI Technical Executive Sam Korellis opened the CCUG2020 Week Four agenda with a review of EPRI’s cooling-tower (CT) fan-motor-drive and gearbox field evaluation program and its implications for CTs serving more than 800 units at about 300 powerplants.

Many CTs are equipped with multiple fans which start and stop depending on load and ambient temperature. With many plants cycling more and more, these fans cycle on and off more as well. Since each draws auxiliary power, excess fans in operation penalize heat rate.

Korellis noted that the criterion to start or stop a fan is simple: If it allows an increase in net power. Starting a fan improves CT thermal performance and unit efficiency but draws additional power. Stopping a fan has the opposite effect.

Starting and stopping fans frequently leads to gearbox failures. Gearboxes suffer failures at a 10% to 20% annual rate industry-wide, said Korellis, and they are costly. A new one runs about $30,000, plus about $5k in labor. They also require replacement power while out of service. Failures can damage fan blades and other components, and can contribute to oil contamination of the tower water.

Objective of the drive optimization project was to evaluate the start/speed regime under unit cycling. Operating wet-bulb temperatures ranged from 35F to 85F and steam-turbine load from 200 to 900 MW during the test program.

Three starting/speed regimes were tested: one-speed (on/off), a soft start (two-speed), and a variable frequency drive (VFD) capability. Under a variety of operating conditions (load, cold-water temperature, ambient temperature, fan speeds, number of fans in operation, etc), the VFD option offered the greatest net benefit in optimizing performance, and was similar in cost to the two-speed option, even if the latter is of a simpler design.

For the gearbox evaluation, the project team purchased several new right-angle gearboxes, and installed and operated them in one CT, with additional monitoring capability, where they would be subject to identical operating conditions. Objective was an attempt to determine causes of frequent failures, effect of repeated start/stop cycles on gearbox reliability, and the relative reliabilities of gearboxes paired with the three start/speed regimes.

During the evaluation, four gearbox failures were experienced in one year. Elevated lube-oil failures also were noted. There were signs of low oil level, moisture contamination of oil, and high oil-pressure levels which caused vaporization and loss of oil. Oil temperatures greater than 200F were observed in the winter, and as high as 300F in the summer.

Near-term modifications suggested by the results include the following:

      • Upgrade to synthetic oil or higher-grade mineral oil.
      • Check oil level and condition during warm operating months.
      • Develop oil sampling and analysis to detect early degradation.
      • Impose quality threshold levels for oil rejection and replacement.
      • Continuously monitor gearbox temperature.
      • Deploy real-time vibration monitoring sensors.
      • Reduce dead air space around gearbox to promote better cooling.

Longer term and more involved/costly solutions include an automated lube-oil refill system and lube-oil sampling; addition of an external lube-oil filter and cooling system; or convert to a direct-drive system and eliminate the gearbox.

One attendee asked how to feed this knowledge into a design spec and Korellis said to add fins and/or a diverter to improve gearbox cooling, and add instrumentation to monitor temperature inside the gearbox. Another asked whether there was any difference in the performance of the soft-start versus VFD and the answer was “no.” A third asked about the oil sampling and the suggestion was to sample and analyze weekly, but cautioned that sampling apparatus could contaminate the CT water if the sampling tube leaks. Best to locate the sampling apparatus outside of the CT internals, he added.

Improving the life safety of CO2 fire extinguishing systems

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

The main messages from the presentation on fire suppression systems during Week Four of the CCUG2020 meeting, by ORR Protection’s Chuck Hatfield, are that NFPA Code requirements include the life (human) safety and reliability of suppression equipment, whether low- or high-pressure type; and that the industry is “moving away from CO2-based suppression to water-mist systems.”

One reason for the shift is that life safety risk is higher with CO2. Another is the psychological effects—there has been a higher level of deaths in confined spaces protected by CO2 in recent years. A third is that water presents an effectively “unlimited” supply of suppressant compared to CO2.

The presenter distinguished among three types of areas with respect to fire: those requiring lock out/tag out for entry; normally occupied areas, those not governed by LOTO; and normally unoccupied areas, those which cannot be occupied by a person. NFPA has new requirements for equipment to enhance life safety in normally occupied areas. Visit www.nfpa.org for details. An odorizer is an option and is very expensive, according to the presenter. Lockout valves must be monitored.

NFPA 750 and FM 5560 apply to water-mist systems. Fundamentally, all convert water mist into steam which acts like an inert gas, and promote three extinguishing mechanisms—inerting, cooling, and fuel wetting. System varieties include self-contained cylinder units, or diesel engine, gas engine, or electric power drives.

Attributes include the following: They incorporate smoke scrubbing devices, consume a relatively small amount of water, one pump/system can serve multiple generating units (for example, three gas-turbine units), and can be equipped with plug-and-play releasing panels.

The presenter responded to questions on the following topics:

      • Sources of water: Fire-water main loop if potable water, cooling water, or demineralizer water (provided the tank is large enough).
      • Spent water collection. Generally not required; some fire-prone skids like lube oil have a containment wall around them.
      • Testing spray heads for atomization: Test on system commissioning, then blow air to make sure nozzles are free-flowing. NFPA requires blowout with air annually, annual water bottle inspection, and backup-battery tests every six months.

Proper chemistry key to mitigating damage attributed to flexible operations

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

Steve Shulder, EPRI’s subject matter expert on water and steam chemistry addressed chemistry-related damage from flexible operations during Week Four of the CCUG2020 program. Thorough to a fault, most of Shulder’s slides are laden with bullet points, likely summarizing chapters of EPRI reports on the subject. It’s almost impossible to condense the 45-slide deck into useful highlights, so users should both review it and watch the recording on the Power Users website. The presentation is packed with good material for whoever is responsible for plant chemistry.

Two areas worth reviewing here, however, are (1) maintaining sampling and online analyzer systems and (2) plant layup and storage. Keeping the former in top working order is critical because, during operation, “you can’t control what you can’t see,” stressed Shulder.

Of course, online analyzer systems are also impacted by cycling operations and improper layup. Debris in the water/steam circuits can plug sample lines. Sample lines should be equipped with blowdown lines; lines and analyzers should have de-ionized water flowing through them so they don’t dry out. Other checklist items are shown in Table 1.

The table on best available techniques for layup and protection (Table 2) is a convenient guide organized by plant subsystems and components. Of note as well is a recently developed dehumidified-air system (figure), proven at several combined-cycle plants in the south, which protects the turbine steam path from moisture condensation when offline for long periods. “Deposits cannot lead to pitting without moisture,” Shulder reminded the audience.

Innovations in vertical-pump vibration monitoring

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

Hydro Solutions’ first presenter during Week Four at CCUG2020, Ares Panagoulias (“Innovations in vertical-pump vibration monitoring”), reviewed a relatively new, but proven, capability to monitor vibration of submerged vertical pumps using a single-axis piezoelectric accelerometer directly wired to a wireless transmitter with its own power source (Fig 1). Data go to a “cloud-based” app.

Included is a case study of a problem pump with a history of unexpected failures. Two different sensors were mounted 90 deg apart at the motor/pump interface with guard brackets to keep them in place. Specialists were able to “see” a significant vibration trend moving upward over a period of two weeks (Fig 2). Vibration is, of course, a direct indication of wear and fatigue. All three main components—sensor, data transmitter, and data collector gateway—require batteries which are said to last up to 36 months depending on data-collection frequency.

Ares’ co-presenter, Michael Mancini (“Achieving reliable pump operation for non-baseload operation”)(“Innovations in vertical-pump vibration monitoring”), essentially delivered a primer on pump design and operation, specifically the relationship of best efficiency point (BEP) to changing unit load output. Needless to say, or at least good to be reminded, the farther your pump operates from its design BEP, the more performance problems it will experience. Geometry of pump internals (like the impeller) are fixed, and therefore cannot accommodate significant changes from design flow parameters.

Some problems may stem from original design, said Mancini, especially older pumps which didn’t have the advantage of computer-aided design, or were specified by inexperienced personnel in applications engineering.

The presentation includes spectacular video clips from lab plexiglass test stands showing how non-optimum flow conditions create waves, stall areas, back vortexes, and thick swirls. At 40% to 50% flow points, backflow grows dramatically, and significant reliability impacts occur at 20% below BEP, the presenter stressed.

This slide deck (access on the Power Users website) is a must for young engineers on your staff, or older engineers who have forgotten all this stuff. Not only does it provide dramatic illustration of pump issues at less than design parameters, it also includes practical solutions to common issues. The presenter has over 45 years of experience in design, operation, troubleshooting, and repair of pumps worldwide.

If you are hesitating, consider this analogy: A pump operating at its BEP is like a professional diver entering the water with almost no wake; a pump operating away from its BEP is like doing a belly-flop. Not only are significant waves created, but it hurts like hell.

Mitsubishi Power atop the leader board in gas-turbine sales, energy storage

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

Mitsubishi Power (MP) finished 2020 with the highest market share for large frame gas turbines in the Americas, according to McCoy Power Reports, a power-industry market data service. The company’s sales totaled 3288 MW, 54% of total orders in the region. More than half MP’s 2020 orders include a hydrogen performance guarantee or have a joint development agreement for hydrogen in progress.

The company says among its orders are the industry’s first combined-cycle gas turbines that will operate on 30% green hydrogen by their commercial operating dates. They will emit at least 11% less CO2, in pounds per megawatt-hour, than engines not so equipped.

Mitsubishi Power also claimed the No. 1 market-share position in the Americas last year with orders for 151,000-MWh of energy-storage capacity of all durations. The all-duration category covers utility-scale and behind-the-meter technologies—including battery, pumped hydro, and green hydrogen storage. The company provides both long-duration green hydrogen storage systems and short-duration battery energy-storage systems to meet the decarbonization needs of power-generation and grid customers.

An example of the former is the 840-MW Intermountain Power Project in Delta, Utah, which will have two JAC gas-turbine power islands guaranteed to burn a mixture of 70% natural gas and 30% green hydrogen when commercial service begins in 2025. The companion Advanced Clean Energy Storage Project in Delta will use renewable power and electrolysis to produce green hydrogen that will be retained in a salt cavern. It will store enough renewable fuel to produce 150,000 MWh.

Short-duration lithium-ion-based energy storage provides multiple services in power markets—including dispatchable peak capacity, firming of intermittent renewable resources, ancillary services, energy price arbitrage, and T&D congestion solutions. Mitsubishi Power received orders for 920 MWh of short-duration capacity in 2020—all scheduled for commercial service this year.

Recent gas-turbine project developments include the following:

    • Entergy Texas Inc’s 993-MW Montgomery County Power Station, powered by two Mitsubishi Power 501GAC engines, began commercial operation Jan 1, 2021, bringing the number of G-series units in service worldwide to 94.
    • El Paso Electric orders a 228-MW Smart M501GAC enhanced-response gas turbine, allowing the company to triple its renewable-energy portfolio and reduce carbon emissions. The SmartER machine complements renewable-energy resources by starting up and shutting down rapidly to accommodate intermittent generation.
    • Capital Power orders two M501JAC gas turbines to repower its Genesee Units 1 and 2 in Alberta, Canada, from coal to natural gas. The upgraded facility will produce 1360 MW (net), with carbon-emissions intensity decreasing by approximately 60%. Power producer’s goal for Genesee is to be off coal in 2023.
    • Alabama Power selects a Mitsubishi JAC power island for a 720-MW combined cycle being installed at its Barry Power Plant.
    • Mitsubishi Power ships the first JAC gas turbine manufactured in the US to the 1200-MW Jackson Generation project in Elwood, Ill. Commercial operation is scheduled in 2022. The plant is designed with two 1 × 1 power trains to provide efficient, flexible generation to complement power production from renewables resources, in addition to reducing the state’s dependence on coal. By the end of 2020, more than 80 J-series gas turbines had been ordered for service in nine countries.

Turbine Tip 13: How to test your emergency lube-oil pumps

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

O&M Clinic for Legacy GE Gas Turbine Users

Turbine Tip No. 13 by Dave Lucier, owner/GM, PAL Turbine Services, applies to General Electric package power plants (PPP), including Model Series 5001P, 6001, and 7001. 

GE gas turbines are equipped with dc emergency lube-oil pumps (GE designate 88QE). This device is controlled at the motor control center (MCC) with a three-step starter circuit. In many GE configurations, the 88QE is coupled to the ac lube-oil pump (88QC) in a piggyback configuration (Fig 1). The dc motor (green arrow) is atop the ac (red arrow) motor. Below, a centrifugal pump (not shown) has its suction inside the 1800-gal (nominal) lube-oil tank.

Note that while this design was typical in legacy units, some owner/operators preferred two separate motors and pumps, because the interconnecting coupling had been known to fail on occasion.

The dc motor starter is shown in Fig 2. Panel, nametag, sequence lights, and test switch are visible.

The system is designed to allow testing the 88QE motor starting sequence, which should be done regularly, whenever the gas turbine is operated at rated speed. It also can be tested when the generator is synchronized to the grid and under load.

For example, with a GE Frame 5 at 5100 rpm, a reliability test of the dc motor and pump can be conducted by two plant operators as outlined in the sidebar. One plant operator would be stationed inside the control cab observing the annunciator, MCC, and 88QE starter; the other outside, in the accessory compartment adjacent to the pressure-gage panel (Fig 3). They should have compatible communications devices.

Note that 88QE is expected to start during the turbine shutdown sequence. This is done automatically to assure when the rotor coasts down to a very low speed it is not done dry. The gear-driven lube-oil pump inside the accessory gearbox delivers sufficient oil to do these two important jobs:

    • Lubricate all the turbine, generator, and gear bearings as they coast down to a stop.
    • Cool down the bearing babbitt material to prevent damage by wiping.
      • When the turbine goes on ratchet (or turning gear), oil flow and pressure are required.
      • 88QC may now be operating continuously with power. If not, the dc motor would be running. See the MCC to determine which motor is running.
      • If the ratchet is on a three-minute stroking cycle (assuming ac power is not available), the dc motor and pump will turn on only when the ratchet is stroking.

Testing of the emergency lube-oil pump is a necessary action for gas-turbine plant operators (test success or failure should be noted in the logbook). It should be done monthly for baseload gas turbines, during the summer and winter runs for emergency and peaking-power units.

Plant operators likely failed to conduct this simple test on an MS5001P recently. The consequence of a “Failure to Start” of the dc oil pump was the wiping of bearings, causing rubs and blade damage in the 17-stage compressor. Testing of 88QE could have prevented this catastrophic outcome.

Test procedure for the dc lube-oil pump (88QE)

Two operators are required to perform this test, both equipped with compatible communications devices. Operator 1 is in the accessory compartment facing the test valve and gage panel (Fig 3). Operator 2 is inside the control room facing the motor control center (Fig 2). The turbine is running at full-speed no load (5100 rpm); the generator can be synched to the grid and operating under load, or not.

    • Step 1: Operator 1 slowly opens the hand bleed valve to drain oil under pressure past the adjacent inline orifice. Oil pressure appears to drop, although this action fools the system. The operator observes the dc oil pump turning and producing a pressure of about 25 psig.
    • Step 2: Operator 2 confirms that the dc motor has started, not the ac motor. An alarm on the annunciator panel flashes, indicating that the dc pump is running.
    • Step 3: Operator 1 puts his hand on the dc motor to see if it gets warm and is operating. He then closes the bleed valve, observing that the dc pump stops.
    • Step 4: Operator 2 resets the alarm and clears the annunciator drop.

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.

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