Boiler combustion controls are designed to optimize the air flow to the fuel flow rate such that sufficient air (oxygen) is available for complete combustion and the amount of performance-robbing excess air is minimized. Recall that insufficient air results in the formation of excess carbon monoxide, a regulated parameter, as well as a loss in efficiency because of incomplete combustion.
Part of the air-flow controls programming at BASF-Geismar allowed for operator adjustment of the stack O2 set-point value—an O2 bias value. An operator could enter a negative bias in an attempt to lower stack O2, thereby increasing boiler efficiency. But if the O2 value were reduced too much, insufficient air would be available for combustion, thereby producing an excessive amount of CO. By contrast, if the O2 bias value was set too high, an excessive amount of air would be used, leading to inefficient combustion.
Powerplant board operators have many duties and do not have the time to babysit the O2/air controllers to fine-tune the O2 bias value and to make adjustments each time boiler load or fuel composition changes. To avoid nuisance CO alarms, operators typically would set the O2 bias to a high value, contributing to inefficient operation.
Initial solutions revolved around trying to give operators target efficiencies to hit, thus letting them know at about what point the CO would “break-through.” This was only moderately effective because the target efficiency varied with boiler load and fuel composition, and occasionally CO break-through would occur before the target efficiency could be reached—for one or more of several minor reasons.
Plant personnel ended up modeling boiler efficiency over a wide range of operating conditions and fuel compositions and created characterization tables that could calculate an accurate efficiency target for the given operating conditions. This model was used to generate a set point for an efficiency controller, which when in automatic, would compare the actual boiler efficiency to the efficiency target (set point) and adjust the O2 bias automatically.
The efficiency controller automatically lowers the O2 bias value until (1) the target efficiency is reached, (2) the CO level starts rising (at which time the efficiency set point is adjusted lower, thereby increasing the O2 bias value), or (3) the minimum O2 bias value limit is reached. In essence, the new efficiency controller automatically adjusts the O2 bias value to achieve the target boiler efficiency, and the CO controller is configured to adjust the efficiency set point on the efficiency controller should CO emissions rise too high.
Control schemes, before and after the staff effort, are illustrated in the diagram.
Results: The efficiency controller and CO override controller have worked very well. Operators no longer have to adjust the O2 bias value as it now is generated automatically. The boilers operate at the targeted values and any CO excursions are handled automatically without operator intervention.
BASF Geismar – BASF Chemical Co
160-MW, gas-fired, 2 x 1 combined cycle cogeneration facility location in Geismar, La.
Plant Manager: Jerry Lebold
The sharing of best practices among owner/operators contributes to safer working conditions and to increases in unit availability and reliability fleet-wide. The Frame 6 users have been proactive in this regard, contributing their experiences during the annual meetings as well as in the group’s online forum, now hosted on the Power Users website.
J C Rawls, a technology engineer in BASF-Geismar’s utilities department and a member of the Frame 6 User Group’s steering committee, has been particularly helpful in explaining the details of his work on boiler and powerplant performance improvement to colleagues at the annual meetings and with the industry at large through CCJ’s Best Practices Program.
Three entries submitted by Rawls recently have been recognized with Best Practices Awards and may be of value to you. One discusses a home-grown boiler efficiency controller that improves performance through process automation, another describes a performance dashboard that tells at a glance if a particular system or piece of equipment is meeting operational expectations.
Finally, in “How to configure controls for economic steam dispatch,” Rawls discusses a proven controls scheme for the efficient production of steam from six boilers (unfired HRSG, duct-fired HRSG, and four conventional boilers) for two-dozen chemical manufacturing units typically requiring from 630,000 to 860,000 lb/hr of superheated steam at 615 psig.
Turbine Tip No. 9 by Dave Lucier, owner/GM, PAL Turbine Services, applies to General Electric package power plants (PPP), including the following: Model Series 5001P, 6001B, and 7001 B-EA.
Suppose your company has purchased a pre-owned PPP and must move it to a new location. Such resales have become more popular recently as the original purpose of this equipment (peaking and emergency power) has ended for many electric utilities. These plants can be relocated successfully, but it is important to engage a knowledgeable crew supervised by an experienced senior field engineer as technical director. This is no job for amateurs if you want to retain your asset’s value.
Preparation work should reverse the OEM’s original “as-installed” procedure from perhaps 40 or 50 years ago. Nobody working at your plant likely remembers that installation process. Plus, there may not be any GE installation records, field-engineer reports, or information available on how to move this unit to a new foundation.
Bear in mind that to safely uproot and move a GE frame gas turbine, specific procedures must be followed. Among them are those described below:
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- Remove the side panels adjacent to the turbine shell (Fig 1), taking note of the two shell supports, bolting, and dowels. Each support foot has four vertical bolts and one dowel (Fig 2).
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- Loosen the bolts for the two support legs shown in Figs 3 and 4 and install mechanical jacks temporarily at each of the two vertical-joint locations. Next, jack up the shell about 15 mils so a shipping pin can be installed in the lower centerline gib key. Shell lifted, tap loose the shims under the support feet, which may be rusted in place. Note that the turbine must “ride” on a shipping pin in case it is “humped” during transport. This can happen when the machine is lifted by crane or transported by truck or train. Damage could occur to the compressor blades and bearings if the unit is not prepared properly.
- Bolts for the exhaust seal should be loosened, otherwise they may “snap” when the shell is jacked up. The bolts may be rusted, so be prepared to replace them after tapping the holes (Fig 5).
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- Notice the loosened fasteners and elevated dowel pin between the bolts at the left in Fig 6. The dowel remains in place, shims tapped loose, and support legs are not supporting any turbine weight. Fig 7 shows the pin installed to support the turbine shell during shipping to prevent “humping” of the shell. Red tag is to remind personnel that the dowel should be removed after jacking at the new location. Then the legs can be bolted down to support the shell.
- The horizontal gib key bolts in Fig 8 can remain in place on each side as long as a 25-mil feeler gage can be slipped in to assure the shell (not shown) is not “pinched.” This will maintain the horizontal centerline and shell position. Once they are installed, the mechanical jacks supporting the casing can be removed.
- Front flex-plate bolting need not be disturbed.
- The rotor must be pushed axially against the active thrust bearing (located internally on the opposite end at the No. 1 turbine bearing) to keep the rotor secure during shipment. The axial internal clearance between thrust bearings is about 16 to 19 mils. Use a dial indicator (not shown) to “thrust” the rotor backwards against the active thrust bearing (Fig 9).
- There’s no need to disturb the front compressor flex support when preparing for the move (Fig 10).
Turbine Tip No. 10 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 PPPs originally had Cardox CO2 fire protection (Fig 1) with individual bottles of suppressant connected in two systems—initial burst and sustained delivery—to three compartments: accessory base, combustion, and load gear and exhaust area. Frame 5 and 6 engines with reduction gears had two overhead “trap doors” that closed when the discharge occurred, to mitigate CO2 flow into the air-cooled generator from the load-gear compartment, thereby protecting the generator from contamination.
Each of the three compartments was equipped with color-coded temperature sensors indicating the ambient temperature allowed (Fig 2). If the temperature exceeded the setting in the tip sensor, the bottled suppressant would be discharged to extinguish the fire.
Location, location. Most GE gas turbines had fire protection systems installed inside their control cabs, taking valuable space away from plant operators. Owners typically didn’t like having the bottles so close to personnel, often moving them to an adjacent building (new or existing), thereby opening up space for a desk and chair. Fig 3 illustrates a system and batteries that were moved outside the control cab.
Enclosures for PPPs are supposed to be sealed to contain any fire that might occur. The goal is to entrap the fire and smother it with suppressant, extinguishing it as soon as possible. Thus, door and panel seals must be maintained in good condition (Fig 4). Insurance companies may require plant operators to “prove” the integrity of the sealing system.
Many insurance companies now are requesting that owners consider replacing antiquated fire protection systems. But before doing this, be aware of the following onsite considerations with the existing enclosures and fire sensing systems:
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- Test the existing system for leaks—that is, deliberately discharge suppressant into the compartments to locate leaks, holes, rusted panels, etc. It is very likely that the door and panel seals have rotted, and the panels no longer fit properly to envelop and contain the compartment.
- Refer to the schematic piping diagrams for the tip ratings of compartment temperature sensors. Typical settings are as follows:
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- Accessory compartment, 45FA-1 and 45FA-2 (200F nominal).
- Turbine combustion compartment, 45FT-1 and 45FT-2 (600F nominal).
- Load gear (exhaust plenum) compartment, 45FT-3 and 45FT-4 (500F nominal).
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Caution: The CO2 fire protection system is passive. It remains in standby mode until a fire occurs in one of the compartments.
Personnel should “pin” the system whenever personnel are working in the area to prevent accidental discharge. If you think this can’t happen consider the following experience: During cranking checks on MS5001L fuel-regulator controls, a flexible coolant line feeding the diesel cranking engine burst, igniting the ethylene glycol. A flame ball roared through the accessory compartment and the CO2 system discharged to extinguish the fire. The technician was not injured seriously—thankfully—and no lost-time accident was recorded.
Turbine Tip No. 12 by Dave Lucier, owner/GM, PAL Turbine Services, applies to General Electric package power plant (PPP) models MS5001D, L, and LA.
GE installed compressor bleed valves (a/k/a recirculation valves) on these legacy gas turbines. Axial-flow compressors for the earliest units—those with 15 or 16 stages—had valves to recirculate air from the 10th stage to the fourth, for “unloading” the machine during startup and shutdown to mitigate vibrations caused by the surge phenomenon. Two valves were installed for this purpose in the turbine compartment adjacent to the compressor casings (Fig 1).
Later turbine models, those with 17- and 18-stage compressors, were equipped with valves to bleed air from the 11th stage to the turbine exhaust during startup and shutdown.
The recirculation valve shown in Fig 1 is open during startup and shutdown and later closed by compressor discharge pressure tapped from the 16th stage via the small line on top of the valve (arrow). Depending on spring strength, the valve is fully closed at a PCD of about 30 to 40 psig. Note that the acronym for compressor discharge pressure, PCD, as found in early instruction books, was changed to CDP in the mid-1980s.
These recirculation valves do not have position “indicators.” If either or both valves should remain hung-up in the open position during online operation, performance (turbine power output) would suffer, because air flow to the combustors would be lower. However, no damage to the compressor should be experienced even if not fully closed when the unit is online.
My late former partner, Charlie Pond devised a simple solution to assist operators in knowing whether the valve is open or closed (Fig 2):
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- Remove the valve cover and drill a 9/16-in.-diam hole in the top beside the PCD tubing line.
- Relieve the hole opening to accommodate an O-ring.
- Determine the length of rod to be used as the indicator and mark it for the fully open and closed positions.
- Select an appropriate O-ring to help seal the rod from excessive air leakage.
- Grease the rod and O-ring, making sure the rod moves smoothly as the valve strokes from open to closed.
- Install a pressure gage in the PCD supply line.
Note that it’s best to test the valve travel while the gas turbine is shutdown.
Jeff Bause, Noxco’s CEO, opened the webinar by explaining to turbine users how his company is raising an industry bar with the first LTSA (long-term service agreement) for emissions compliance. He said that by removing the burden and responsibility for protecting and managing complex systems from owner/operators, Noxco delivers performance, predictability, cash flow, and 100% risk mitigation through a turnkey solution.
Bause is well-known to many CCJ readers for his deep knowledge of catalyst system maintenance, gained over the years as CEO of Groome Industrial Service Group. He is a frequent speaker at industry events on SCR and CO catalyst cleaning, repacking, and replacement, plus the cleaning of ammonia vaporizers and injection grids, as well as of HRSG tubes.
Noxco’s turnkey solution, Bause says, increases the operational flexibility and performance of the SCR, CO catalyst, and ammonia injection system (AIG) to deliver sustained peak performance at the lowest lifecycle cost (figure). LTSA benefits include all system maintenance, inspections, tuning, optimization, catalyst testing and cleaning, catalyst replacement with the optimal product for your site and operating conditions, spent catalyst disposal, AIG design optimization and tuning, and performance upgrades. Access the recorded webinar below to get the details.
Jeff Bause, CEO, jbause@gonoxco.com, 201-675-5818
Jorge Cadena, VP-Business Development, jcadena@gonoxco.com, 678-528-3551
Metal temperature is, perhaps, the variable most affecting the service lives of superheaters and reheaters. Long-term overheating of these components can result in failures necessitating multi-million-dollar repairs, based on the experience of Bryan Craig, PE, and his colleagues at HRST Inc. There is an upward trend for overheating failures in the industry, and many HRSGs are approaching the time in their respective lifecycles when this is becoming a significant risk.
Fig 1 shows a typical configuration of a large HRSG with a duct burner. In HRSGs with duct burners, maximum tube metal temperatures in Module 2 occur when duct firing. An increase in the operating metal temperature of 15 to 20 deg F can reduce equipment life by half in some instances.
The overwhelming majority of superheater and reheater overheating failures seen to date by HRST engineers have been downstream of duct burners (Fig 2). Poor exhaust-gas and/or fuel-gas flow distribution at the duct burner can lead to local areas that are fuel-rich, resulting in long flames and local overheating in the downstream tube bundles.
Here are two scenarios:
Uniform fuel-gas flow distribution, non-uniform exhaust-gas flow distribution.
Turbine exhaust gas (TEG) is the “air” source for an HRSG duct burner. If the fuel gas is distributed uniformly throughout the burner elements, but the exhaust gas flow is non-uniform, then the areas with higher-than-average exhaust-gas velocities will have a high air/fuel ratio, and areas with lower-than-average exhaust-gas velocities will have a low air/fuel ratio. A low air/fuel ratio means fuel-rich. Thus, areas with lower-than-average TEG velocities will be fuel-rich and have longer-than-average flames.
Non-uniform fuel-gas distribution, uniform TEG flow distribution.
This is straightforward. If there’s uniform distribution of TEG flow to the duct burner, then the areas that receive higher-than-average fuel flow will be fuel rich, comparatively, and will have longer flames.
In reality, of course, neither the fuel flow nor the TEG flow to a duct burner is perfectly uniform. Still, it helps to think of the two effects separately.
TEG velocity profile. Turbine exhaust enters the HRSG at high velocity, at a low elevation. The momentum of TEG flow entering the HRSG causes its velocity to be higher at the bottom of the duct burner and lower at the top. This can be corrected by installing a flow-distribution device—such as a perforated plate.
If there are multiple rows of HP superheater and reheater tubes upstream of the duct burner, the flow resistance of these also can help to even out the TEG flow profile at the duct-burner plane. Even so, it typically is not perfectly uniform, as Fig 3 shows.
With this TEG flow profile, and assuming fuel flow is distributed equally to each duct-burner element and uniformly across the elements, you can expect a higher-than-average temperature and longer flames downstream of the HRSG at the top of the unit, and a lower-than-average downstream temperature at the bottom of the HRSG—based on the relative air/fuel ratios in the different zones.
Fig 4 presents the velocity profile for another HRSG, on the same scale as that described in Fig 3, but one with no flow distribution grid and a very short inlet duct. The TEG velocity at the bottom of the HRSG is much higher than average and the TEG velocity at the top of the unit is much lower than average. There is only a small zone with a TEG velocity close to the average value across the plane, as Fig 5 indicates.
Fuel flow profile. Now, let’s look at fuel flow. Fuel enters the HRSG at a much lower temperature (40F is typical) than the nominal 1000F TEG temperature at the duct-burner inlet. Thus, the fuel heats up as it flows along the duct-burner element. Heat-transfer calculations made by HRST engineers predict the fuel temperature curve in Fig 6 for a typical duct burner.
Most duct burners inspected by HRST personnel have uniformly distributed, equal-size openings (a/k/a nozzles) in the burner runners. With this design, a higher fuel flow per nozzle is expected at the inlet end of the runner where the fuel is cooler than it is at the far end. The duct-burner fuel-flow profile in Fig 7 is based on the fuel-temperature profile from Fig 6.
With this fuel profile, one would expect the downstream gas temperature to be higher, and flame length longer, on the fuel inlet side of the duct burner; and lower/shorter on the far side.
If you calculate the downstream tube-metal-temperature variation driven only by the effect of left-to-right fuel-flow distribution along the length of the duct-burner elements, the difference from the left side to the right side of the HRSG is nearly 40 deg F, as illustrated in Fig 8. This is substantial considering that a 15- to 20-deg-F difference in tube metal temperature can correlate to a factor of two in creep life!
Combined effects of fuel and exhaust-gas flow distribution. The photos in Fig 9 are from a plant with two identical HRSGs, except that they are mirrored. There are no flow-distribution grids in these units. The downstream tubes in both HRSGs show indications of overheating at the higher elevations, plus a bias toward the fuel-supply side.
It gets worse, in some cases. Duct-burner nozzles sometimes become plugged with debris (Fig 10). In HRST’s experience, nozzle plugging is most prevalent at the far end of the burner elements (opposite the fuel supply).
Plugging can significantly exacerbate fuel-flow maldistribution, causing a far greater left/right temperature imbalance downstream of the burner than the fuel-temperature-driven imbalance described above. HRST engineers have seen instances of very large left/right fuel flow imbalances caused by nozzle plugging. Some of these have resulted in HP superheater tube failures immediately downstream of the duct burner.
Recommendation: Use existing view ports to visually observe the flames for length and shape when the HRSG is operating and the duct burners are at maximum fire. Flames should be independent and horizontal. A rule of thumb: Flame should extend only one-half to two-thirds of the way down the firing duct. If flames come within 3 to 4 ft of tubes, that’s probably too close. Flames should never contact the tubes! If long flames occur, it is likely because of a problem with either exhaust-gas or fuel flow distribution—perhaps both.
A duct-burner camera is an alternative to using view ports to observe flame length during operation (Fig 11). One or more cameras can be installed inside the firing duct and provide a real-time view of the duct-burner flames to the control room operator.
During offline inspections, make note of, and photograph, any color variations in the tube bundle downstream of the duct burner. Gray zones in tubes downstream of the duct burner often correspond to long flames and possible overheating (Fig 12).
To address trim erosion on HP-bypass pressure control valves (PCV), HRSG Forum’s Bob Anderson (see previous article) put together a panel of experts—including Ory Selzer, IMI/CCI; Justin Goodwin, Fisher Valve; Vasileios Kalos, GE Gas Power; and Consultant Joe Schroeder. The erosion occurs when high-pressure steam entrains water droplets (not to be confused with saturated steam) and passes through the valve trim at high velocities “like sandpaper.” The damage can be so severe that some users thought their trim had melted!
Once the trim has eroded, the valve will leak steam and overheat the downstream carbon steel piping.
The bad news is that you can’t buy a valve that avoids this problem. All models are susceptible. Using better trim materials, reducing velocities by increasing the seat diameter by 10 to 15 mm, and/or lengthening the control plug, may buy you some time and keep the valve tighter for a longer period, but that’s about it.
The root cause of the problem lies in details of the HP-bypass piping design and the peculiarities of starting up a multiple-GT/single-steam-turbine combined cycle. The lag cold-start unit (the second GT to start up) on a 2 × 1 design usually is the culprit. Because the HP isolation valve for the common manifold of the main-steam header is closed, something that does not happen for the lead cold-start unit occurs. Reason is that there is no flow path for steam to warm and dry the HP steam pipe between the HPSH outlet and the isolation valve prior to opening the HP-bypass PCV.
Once the PCV begins to leak enough to overheat the downstream piping, the only safe action is to operate with the PCV at its minimum-open position until the valve can be repaired. Opening the desuperheater-water injection valves to cool the piping—with the PCV closed—is, by consensus, “definitely a bad idea,” Get the details by listening to the panel discussion below.
Interest in the subject was revealed through the extensive questions delivered ahead of the meeting. One attendee asked if there is another source for the erosion—such as magnetite. Panelists answered that magnetite would pass through all the valves and this erosion is heavily biased towards the HP-bypass PCV. One panelist noted he’d only seen one valve that had experienced solid-particle erosion rather than water-induced erosion.
Another asked about chromium or tungsten carbide materials for the trim instead of Stellite-6, and the response was they weren’t used in steam applications. “Promising alternative trim materials have not seen many operating hours,” one panelist noted, including a temporary repair technique using Inconel 625 or 718 or superalloys with high titanium or aluminum content as a “buttering layer.”
Anderson suggested that establishing a proper steam flow path to warm the piping from the superheater outlet to the common manifold isolation valve prior to opening the PCF is needed to avoid condensate ingestion. This may require enlarging the drain upstream of the isolation valve. Pre-warming the valve body and steam line with warm-up nipples has shown inconsistent experience. One panelist made the wry comment that “spray valves leak and drain valves plug.” So, to will HP-bypass PCV valve trim erode and leak—at least until further notice.
This year’s annual HRSG Forum with Bob Anderson is taking place online in monthly installments. If the first, held May 3, 2021, is any indication, you won’t want to miss any of the upcoming sessions. Follow CCJ ONsite for announcements of session content, dates, and times, and registration link. Invited participants are powerplant owner/operators and consultants and vendors with an interest in heat-recovery steam generators.
The two issues focused on in this first round were hexavalent chromium and trim erosion of high-pressure (HP) bypass pressure control valves (PCV). Both are vexing issues for combined-cycle facility operators and even incremental additions to users’ knowledge/experience base are worth paying attention to. Hex chrome is covered here; the following article summarizes key points extracted from the valve panel discussion.
To tackle the hex-chrome issue, venerable HRSG expert and consultant, Bob Anderson, and co-chairman expert chemist/metallurgist Barry Dooley of Structural Integrity Associates Inc, enlisted David Addison, principal consultant, Thermal Chemistry Ltd, a world-class authority on powerplant water chemistry. Watch and listen to Addison’s presentation below.
The tell-tale bright yellowish deposits of the highly toxic hexavalent chromium show up on air/gas side equipment downstream of high-energy chromium-containing piping, especially in areas where water ingress occurs. Typical areas reported out to the industry include gas-turbine hot-gas-path components; steam-turbine hot external components, such as bolts; and HRSG hot-pipe external surfaces.
Precautions and protections
Follow these recommended precautions and protections when inspecting areas that have tested positive for hex chrome (or suspected of containing the toxic chemical) and/or when removing the material.
Activity: Inspections in areas where hex chrome residues are present but the residues have not been disturbed.
Exposure: Skin absorption, ingestion.
Controls: Eye protection, disposable nitrile gloves, particle-resistant disposable overalls. Plus, no eating, drinking, smoking, or bathroom breaks should be taken without first washing hands and face.
Activity: Removal or disassembly of items with hex-chrome residues present.
Exposure: Skin absorption, ingestion, inhalation.
Controls: All the controls recommended for inspections (above), in addition to the following: P2 respirator and, where possible, ultrasonic cleaning of parts.
Activity: Grinding, wire brushing, finishing, welding, etc, of surfaces with confirmed hex-chrome residue.
Exposure: Skin absorption, ingestion, inhalation.
Controls: All the controls recommended for inspections and removal/disassembly (above), in addition to the following: goggles, upgraded respiratory protection (to powered air-purifying respiratory protection), mechanical ventilation HEPA filters, and use of controls to limit the aerosolization of hex-chrome residues.
Hex chrome is a known and manageable problem in the welding of chromium alloys. Protocols for dealing with it are well-established. Turbine OEMs have issued technical bulletins on it. While those bulletins have not specified the chemical form, XRD/XRF testing confirms that it manifests as calcium chromate. Sources of calcium include anti-seize pastes (containing calcium oxide, CaO) and some lagging/insulation materials.
If you see bright yellow deposits on your equipment, first, don’t panic. But also don’t think it is sulfur-bearing. That’s not possible, though some have made that mistake.
Second, make sure you don’t disturb a deposit, until you are ready to remove it completely. Left to its own devices, calcium chromate will not vaporize or melt. When you are ready to remove it, follow protocols to avoid both worker exposure and inhaling the dust (sidebar). The good news is that Addison is not aware of any health issues associated with hexavalent chromium from powerplant operations.
Eliminating the calcium source avoids the problem. If possible, select anti-seize pastes and insulating materials with no calcium oxide. Preventing water ingress also goes a long way towards mitigating the problem. Adding a reducing agent will convert the hexavalent form to the benign trivalent form. One OEM recommends spraying an ascorbic acid/surfactant formulation on the deposit, and field experience suggests this works well.
Other areas which exhibit the right conditions for hexavalent chromium—chromium-containing components, oxygen atmospheres, high temperature, presence of calcium, and water ingress—should be suspect, including superheater and evaporator upper and lower crawl spaces, gas-turbine exhaust ductwork (insulation side). Testing is underway to confirm presence in these areas.
Two relatively short white papers available from Mitsubishi Power can bring you up to speed on the state-of-the-art and future of remote operation and support and on digital strategies for improving steam-plant performance. Some of the insights shared on the latter topic also are of value to combined-cycle owner/operators.
“Remote Operation and Support—the New Normal?” tracks the rapidly growing demand for remote technology—including early-warning diagnostics using advanced analytics, plus access to offsite technical expertise for troubleshooting and response. It walks readers through the company’s considerable analytics experience, which began in 1999 with a remote monitoring center at Mitsubishi’s extensive engineering and test facilities in Takasago, Japan.
Since that first step, digital solutions, like the company’s growing Tomoni™ suite of offerings, allow O&M staffs to leverage the massive amounts of data from the thousands of sensors in a plant to provide valuable insights, solve complex problems, and maximize performance.
Advancement through digitalization is a core focus of the white paper, which includes experience gained when a scheduled plant outage was shifted because of the pandemic and condition-based maintenance intervals provided a pathway to success. Another sidebar presents the case history on how a Tomoni digital solution improved efficiency by enabling a process to actively optimize the flow of gas-turbine cooling air.
“How Digital Strategies Improve Steam Power Plant Performance” discusses the new level of flexibility required by traditional fuel-fired generating assets to remain competitive in today’s rapidly changing electricity markets. Fuel flexibility, faster starting and ramping, and reduced minimum load highlight the challenges faced by industry participants.
