MECHANICAL
Control abrasive wear in scrubber piping
Minnkota Power Cooperative (Grand Forks, N.D.) provides electric energy to 11 associated distribution cooperatives in eastern North Dakota and northwestern Minnesota. Minnkota operates two coal-fired units at the Milton R. Young Station near Center, N.D., with a combined rating of 705 MW; Unit 1 began operation in 1970 and is rated at 250 MW, and Unit 2 entered service in 1977 and produces 455 MW.
Young Station ranks as one of the lowest-cost coal-fired power plants in the U.S. The station receives lignite coal from a nearby mine, which is operated and owned by BNI Coal. The lignite coal passes through three crushers before it is sent through the coal transport lines using high-velocity, 750F air, which removes most of the moisture. The coal is then sent to the cyclone-fired boilers, where it is mixed with heated air for combustion. The plant consumes about 4.3 million tons of coal annually.
Flyash causes wear and corrosion in piping
Unit 2 began to have problems with abrasion in the pipes when transporting flyash to the plant’s scrubber (Figure 5). “We have a very abrasive situation,” said Dennis Ziniel, mechanical maintenance supervisor for Minnkota Power. “The flyash is very abrasive and very corrosive.”
5. Flyash problems. Minnkota Power Cooperative’s 455-MW Young Station Unit 2 experienced excessive pipe abrasion and corrosion caused by transporting flyash to the plant’s scrubber. Courtesy: Abresist Corp.
The flyash is a product of burning the lignite coal. Lignite coal produces two types of ash--bottom ash and flyash--when it is burned. Bottom ash is a heavy ash that is removed as a molten slag that flows out the bottom of the boiler. Flyash goes through the boiler and is sent to the scrubber to help scrub sulfur dioxide from boiler exhaust gases.
The Young Station has two scrubber towers that are about 40 feet in diameter and 160 feet tall. Inside the towers are nozzle heads that spray the flue gas as it passes through with a liquid mixture that contains a combination of limestone and flyash. The spray scrubs the sulfur dioxide out of the gas by combining it with the calcium in the limestone and flyash. This slurry is then pumped to settling ponds. The water is drawn off the top of the settling pond and recirculated and reused in the scrubber system.
Young’s staff tried fiberglass and stainless steel pipes to reduce the wear from the flyash, but other problems soon arose with those pipes. “Lined fiberglass stands up fairly well for a limited time in some applications,” Ziniel explained. “We’ve got some fiberglass here that’s been in service about 10 years, but we’re starting to see some real issues with it.”
“We also have other applications where we’ve gone with grade 316 stainless steel because it is so abrasive and so corrosive,” Ziniel continued. “But stainless steel is very, very expensive.”
Young Unit 2 needed a solution to the pipes’ wear problems, so Minnkota Power took a look at Abresist Corp.’s cost-efficient lined piped solution. In 1988, Young Station purchased approximately 400 feet of 2-, 3- and 4-inch Abresist lined piping at half the cost of stainless steel piping priced at $200 to $300 per foot, including about 35 elbows and tees, for transporting the flyash to its scrubber. Abresist lined pipe consists of flanged steel shells lined with thick cylinders of cast basalt, an extremely hard volcanic rock that is very good at resisting sliding abrasion. Since installing the Abresist lined pipes, the pipes have not needed to be repaired or relined (Figure 6).
6. Almost legal. Abresist piping was installed at Young Station Unit 2 on the flyash transport piping 20 years ago, after plant managers rejected fiberglass and stainless steel pipe alternatives. The pipes have not required any repairs or relining since installation. Courtesy: Abresist Corp.
Lined pipes vs. fiberglass and stainless steel
“As a maintenance supervisor, I have a lot of problem areas I have to worry about,” Ziniel said. “But one of the areas I don’t have to worry about is the Abresist lined pipe, because I know it’s there and it’s working and I know I’m not going to have an issue with it.”
Though fiberglass pipes are less expensive than Abresist basalt-lined pipes, fiberglass pipes require more maintenance and repair. If the joints on fiberglass pipes are not lined up perfectly, turbulence is created and the fiberglass pipe begins to erode more quickly. “We have several spots like that where we are continually repairing it because they were not perfectly matched up when they were put together,” Ziniel noted.
Stainless steel may hold up against the flyash, but it presents other problems for the plant in addition to its higher cost. Young Station sometimes has build-up in its stainless steel pipes. When the temperature outside drops, a chemical reaction with the slurry occurs, and the slurry adheres to the inside of the pipe. A cleaning contractor then must use high-pressure washers to get rid of the build-up. “That is a very lengthy process. And very costly, too,” Ziniel admitted. “How badly the pipes are built up determines how long the contractors are here. We’ve had cleaning contractors out here for up to two weeks at $600 an hour. But, with the Abresist basalt-lined pipes we haven’t had any build-up, so Abresist lined pipes kind of give you the best of both worlds.” And since build-up is no longer a problem, the plant can save thousands of dollars that were previously spent on cleaning contractors.
--Contributed by Abresist Corp. (www.abresist.com).
I&C
Sensors and final control elements
Most information technology (IT) specialists agree that advances in basic sensor and final-control-element technology thermocouples, pressure gauges, pH meters, flow meters, valves, dampers, and pumps lag far behind the electronics and computer devices they are connected to. What they don’t necessarily agree on are the most important parameters for improvement: accuracy, repeatability, ease of service, or other metrics. This situation brings up the following analogy: Even the most well-trained and organized team will falter if the scout or code-breaker provides erroneous information.
Any plant that has upgraded its control system probably has a story like this one: At one station, the sophisticated multivariable control strategy could only operate about 40% of the time because aging sensors routinely failed, final control elements lacked linear and repeatable movements, dampers wouldn’t respond to remote control, and mechanical linkages would not provide repeatable response to the controls. The fact is that most field devices do not provide the accuracy required of today’s control systems. The situation is most acute when a distributed control system (DCS) or automation package is retrofitted to an existing plant.
Another problem: Instrumentation advances in piecemeal fashion. Predicting how many state-of-the-art instruments assembled from multiple sources would function together is virtually impossible.
Smash technology barriers
Not only are the basic devices in need of improvement, but fundamental pieces of information are missing, and direct measurement of other data would do wonders for process control. For example, even a brand new plant built today probably would not include a continuous on-line analyzer for coal; nor would it have a means to measure coal flow to individual burners. Both of these are critical pieces of information in today’s competitive, environmentally sensitive world. Some plants in Japan and Finland are correlating burner flame images to NOx levels and other combustion-quality parameters.
In corrosive environments, maintenance management would benefit enormously from strategically located continuous on-line corrosion monitors. Reliability and performance would also improve. Direct monitoring of corrosion in, say, the air heater would help operators optimize outlet flue-gas temperatures at low loads. Today’s gas turbine owners would undoubtedly appreciate an accurate, affordable means of monitoring hot-gas-path coating and/or base-metal degradation; owners of large steam turbines would appreciate a means of monitoring blade vibrations, solid particle erosion of high-pressure-stage turbine blades, or corrosion of last-stage low-pressure-module blades.
Based on a few examples, it is clear that the payoff from advanced sensors could be enormous. Acoustic leak-detection devices, now essentially standard equipment on boilers, allow plant owners to predict not only when boiler tubes will fail, but they also help pinpoint where the failed tube is. Planning time for repair is easier when repair is coordinated with planned outages or downtime, and the outage is shortened considerably when the faulty tube is located quickly. The economic advantage of reduced outage time is substantial in a competitive environment--and it may become critical. Imagine that instead of buying power to make up the difference from a plant in outage, your customers contract with someone else to supply power.
Here are two more examples:
- Slag monitors, also popular equipment at today’s plants, allow operators to program sootblowing schedules more intelligently than in the past.
- Compressor fouling in gas turbines is measured indirectly through gas turbine performance degradation, which allows on-line washes to be conducted at optimized intervals.
Each of these instruments would be easily paid for in short order through increased plant efficiency.
Striking a balance between what is done with continuous on-line measurement integrated into the IT system and what is done off-line is important. Computing power and the use of statistical and numerical analysis can often provide insight into mechanical and process trends with little hard data. The burgeoning field of hand-held and portable sensors also provides an option. Taking and analyzing a given parameter weekly or monthly, and crunching the data off-line, may be a better solution than wasting valuable data-acquisition and on-line processing time.
No silicon valves
The final control element--usually a valve, a damper, or pump/motor--is also expected to carry its control functions with it. But unlike sensors, no matter what transpires in microelectronics and systems analysis, the actuator must remain a strong, powerful, and rapidly responding piece of mechanical equipment, whether driven by air, oil, or electronics.
Nevertheless, the introduction of microprocessors and microelectronics directly at the valve or damper actuator and the digitization of signals have significantly changed actuator control, both for modulating and on/off units. In essence, the computer is onboard. This allows two-way communication and valve dynamics analysis. Calibration and verification can be done remotely, and wire-pair numbers, limit switches, and position transmitters are reduced.
A smart final control element has a microprocessor perform a servo-control algorithm for the valve or positioner that seeks to optimize the final control function; characterize the smart final control device at the valve; provide diagnostics for the electronic/pressure converter, electronics module, and communications system; communicate with the DCS; and store valve-specific maintenance information.
Integrating a digital valve with the DCS expands the operator’s view from the input/output cards in the DCS to the digital valve controller. The operator sees valuable information rather than just a process variable or implied valve position. Now the valve position can be measured and transmitted, along with the pressure driving the actuator and diagnostic information on health of the controller, actuator, and valve.
Digital opportunities
Such diagnostics on a valve will, for example, let a plant concentrate on critical maintenance, repair, or overhaul during a scheduled outage. Calculated information covers bench set, spring rate, and seat load. Graphical information on the valve signature, hysteresis, input vs. output signal, and step response helps eliminate need to connect extra equipment for local diagnostics or take the valve to the shop for detailed diagnostics. In short, smart control elements lead to automation of the maintenance functions and blend intelligently with your maintenance management system.
Assessing the integration of information with equipment would not be complete without addressing variable-speed drive (VSD) technology. Although pumps and motors are not considered final control elements the way dampers and valves are, they are modulated to optimize process control and thus take signals from the information system. Motors, for example, drive induced- and forced-draft fans, large valves, and boiler feed pumps. Motors are thought of as constant-speed machines. Yet in fan and pump drives, higher overall efficiency and greater operating flexibility result from variable-speed operation of the motor than from throttling flow.
Modern electronics has made possible widespread use of variable-frequency power supplies. Because machine speed depends directly on applied frequency, voltage must be lowered along with the frequency to vary speed. Logic circuits and variable silicon-controlled rectifier firing angles in the power supplies readily accomplish this. Three types of variable-frequency electronic drives are the voltage-source inverter, current-source inverter, and pulse-width-modulated device. In all three, a solid-state rectifier section converts AC power to DC. An inverter then transforms the DC to an AC adjustable voltage and frequency.
Many functions that were once centralized for VSD can now be executed locally. Powerful microprocessors and fieldbuses help in this regard. Drives of the future will likely include standard modular hardware platforms and allow the unit to be customized through software to match site requirements.
--From the editors of POWER
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