Single-permissive remote start, automated fuel equalizing
Challenge. Rolling Hills recently updated its run profile from a 30-min start window to five minutes. Like many other plants with a 5-min window, a remote start program was implemented.
The challenge that Rolling Hills faced was to simplify the old startup sequence so an operator could bring units online successfully while working remotely from a secure device, and then drive to the plant.
Before project implementation, the starting procedure required the operator to open the main fuel-gas valve, start the demineralized-water pump, start the fuel-gas heater, and put the unit on turning gear. The first three already were integrated into the control system, but the turning gear was not. It was controlled by a hand switch located in the electrical package for each unit.
Lastly, Rolling Hills faced the challenge of fuel surging and popping relief valves from opening the main fuel-gas valve without first equalizing the plant pressure. This was done via a hand-operated valve, also opened by the operator before each start.
Solution. Logic changes were required to implement a simple remote start/stop routine. The plan: Create a single remote-start page that had only five buttons, one for each of the plant’s five gas turbines. With the main fuel-gas valve, fuel-gas heater, and demin-water pump already integrated into the DCS, focus of the plan was to electrically control the turning gear and the fuel-gas equalizing valve.
The turning-gear hand switch was located inside each units’ electrical package, where the PLC also was housed. A wire was run from an output card directly to the “auto” side of the hand switch, then mapped to the DCS for programming.
The last piece of the puzzle was how to ensure the pressure differential between the plant side and supply side of the fuel-gas system would not be so great as to impede safe operation. Bear in mind that the main fuel-gas valve is an instantaneous open/close valve to protect the plant in case of an emergency. Opening this valve when there is a high pressure differential would open relief valves throughout the plant, causing a high pressure drop.
Thus, the replacement for the hand valve had to be one that could be controlled by a 4-20-mA signal to regulate the equalization pressure. Plant employees installed the valve (Fig 2), ran the power and control wires, and mapped the valve back to the DCS for programming.
Lastly, the logic was created to automatically equalize Rolling Hills’ fuel-gas pressure, open the main fuel-gas valve, start the fuel-gas heater, reset any trips on the unit, place the turbine on turning gear, and then, after a set time, start the unit. Staff mapped the new logic to pictograms and placed it all on a special, designated remote-start page, reducing the start and stop sequences to a single-button permissive per unit (Fig 1).
Result. All employees were trained on the new start procedure. The simplified process helps prevent operators from missing any steps and has allowed them to start units remotely with ease. Success: Every technician has started units remotely and Rolling Hills has not missed a dispatch within the 5-min window.
Logic was reversed to make the unit stop sequence as easy as the start. By simply sending an “off” permissive using the same single remote-start button, the unit virtually runs the logic backwards and shuts down everything automatically—all while remaining smart enough to know when another unit is running and not to stop the fuel and water system. Plus, also placing itself back on turning gear for unit cooldown.
All Rolling Hills OMTs
Covid-19 initiatives protect plant, contractor personnel
Challenge. The questions Covid-19 presented to Rolling Hills and other plants included the following:
- How do we keep our employees safe?
- How do we keep up ongoing maintenance with reduced staffing?
- How do we keep our contractors and employees working safely during scheduled outages?
At plants with a relatively small workforce, like Rolling Hills, outage work had to be broken down methodically into step-by-step procedures to analyze the potential contamination of tools, equipment, and staff. Industry standard procedures were rewritten to adapt to the “new normal.” With only a handful of employees at this simple-cycle facility, the need to limit staff exposure to sickness was particularly important. One of the first things that had to be addressed was the need to get contractors into the plant and ready for work while limiting staff exposure.
Solution. First step was to improve the plant’s safety orientation plan. Contractor orientation and visitor registration procedures were rewritten, paying close attention to detail to limit Covid exposure from outside sources.
Prior to being admitted onsite, contractors were emailed an information packet that included instructions on where to park and report to for a wellness screening conducted by contracted health professionals (Fig 3). Good health verified, contractors were directed to the plant warehouse, which was converted to a breakroom for safety orientation—complete with DVD player, procedures, and required paperwork.
Rolling Hills staff was on hand (at a safe distance) to answer any questions contractor personnel might have had during their self-guided orientation using strategically placed plant radios.
Rolling Hills Generating LLC
Owned by Eastern Generation LLC
Operated by Consolidated Asset Management Services LLC
850-MW, gas-fired, simple-cycle generating facility powered by five 501F engines, located in Wilkesville, Ohio
Plant manager: Corey Lyons
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.
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.
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.
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.
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 (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.
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.
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.
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.