Biomass boilers 6 • Modern plant safety 9 • Identify EGT failures 26
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FEBRUARY 2015
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Energy-Tech (ISSN# 2330-0191) is published monthly in print and digital format except in January and July, when it is published in digital format only by WoodwardBizMedia, a division of Woodward Communications, Inc. WoodwardBizMedia assumes no responsibility for inaccuracies, errors or advertising content. Entire contents © 2015 WoodwardBizMedia. All rights reserved; reproduction in whole or in part without permission is prohibited. Printed in the U.S.A. Group Publisher Karen Ruden – kruden@WoodwardBizMedia.com General Manager Randy Rodgers – randy.rodgers@woodwardbizmedia.com Managing Editor Andrea Hauser – ahauser@WoodwardBizMedia.com Editorial Board (editorial@WoodwardBizMedia.com) Bill Moore – Director, Technical Service, National Electric Coil Ram Madugula – Executive Vice President, Power Engineers Collaborative, LLC Kuda Mutama – Engineering Manager, TS Power Plant Tina Toburen – T2ES Inc.
FEAtUrEs
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By Harriet Lublin and Karen Phillips, Hurst Boiler
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FEBRUARY 2015
Modern age plant safety: Are we pulling a car with an old horse? By Hector Perez, PAS Inc.
CoLUmNs
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Regulations Compliance
Capturing mercury emissions By Savannah Cooper, Worldwide Recycling Equipment Sales
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Mr. Megawatt
Show me the proof By Frank Todd, True North Consulting
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Turbine Tech
Identifying the cause of EGT failures By Gregory Bray, Ametek Power Instruments
Editorial views expressed within do not necessarily reflect those of Energy-Tech magazine or WoodwardBizMedia. Advertising Sales Executives Tim Koehler – tkoehler@WoodwardBizMedia.com Joan Gross – jgross@WoodwardBizMedia.com Thea Somers – thea.somers@WoodwardBizMedia.com
Sullivan County biomass project provides economic, environmental benefits
AsmE FEAtUrE
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Leveraging natural gas: Technical considerations for the conversion of existing coal-fired boilers By Jason C. Lee, P.E., Babcock Power Services Inc., and Michael Coyle, Riley Power Inc.
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Editor’s Note
What’s the plan? New Congress, regulations and science show the need How is winter treating you in your part of the world? So far, we Midwesterners are doing pretty well. We’ve had snow – but not too much, and cold – but not for too long, so it feels bearable. My sons are old enough to do all the shoveling now too, so that’s made a big difference in my overall attitude as we head into February. Not having to shovel the driveway means I have more time to indulge my news junkie habit, and 2015 has offered plenty to think about so far. For example, we have a new Congress with a Republican majority, and they’ve said more than once that they want to work in a bipartisan manner. We also have new EPA and environmental rules from the White House on emissions, with everything from methane to mercury being scrutinized. Finally we have news that 2014 was the hottest year ever recorded, from several agencies around the world. What do those three nuggets of news say to you? If you’re thinking, “It’s time for a comprehensive energy plan,” you just read my mind. A lot of people get upset when these topics come up, but that’s such a waste of energy. Getting upset is easy, but it isn’t effective and doesn’t lead to constructive solutions. As I’ve attended energy conferences over the years, a consistent complaint I’ve heard about regulations from the EPA – and the federal government in general – is that they don’t have a long-term game plan. Everything is patched together and no one is sure about the end goal. That’s a legitimate complaint – but is anyone letting our lawmakers know? It’s one thing to complain about it among your colleagues, but another to contact your representative – or for your utility company to contact its lobbyist. We need the energy industry to fully engage in pushing for – and helping craft – a comprehensive energy policy. We need the expertise of people who know what it takes to generate 1 MW of electricity – let alone the billions it takes to keep us in the modern age. So as we barrel into another year, let’s pause and think about the work we’re doing and what we want our own long-term goals to be. And feel free to share your thoughts about these issues with me at ahauser@woodwardbizmedia.com, or on Energy-Tech’s Facebook page. And as always, thanks for reading.
CALENDAR Feb. 16-20, 2015 Introduction to Machinery Vibrations (IMV) Tempe, Ariz. www.vi-institute.org March 23-27, 2015 Basic Machinery Vibrations (BMV) Knoxville, Tenn. www.vi-institute.org April 21-23, 2015 Electric Power Conference & Exhibition Rosemont, IL www.electricpowerexpo.com May 11-15, 2015 Advanced Vibration Analysis (AVA) Houston, Texas www.vi-institute.org June 15-19, 2015 Rotor Dynamics and Modeling (RDM) Syria, Va. www.vi-institute.org June 28-July 2, 2015 ASME Power & Energy 2015 San Diego, Calif. www.asmeconferences.org/powerenergy2015 Sept. 21-25, 2015 Machinery Vibration Analysis (MVA) Salem, Mass. www.vi-institute.org Oct. 12-16, 2015 Balancing of Rotating Machinery (BRM) Knoxville, Tenn. www.vi-institute.org Nov. 30-Dec. 4, 2015 Advanced Vibration Control (AVC) Houston, Texas www.vi-institute.org
Submit your events by emailing editorial@woodwardbizmedia.com.
Andrea Hauser
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FEBRUARY 2015
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Sullivan County biomass project provides economic, environmental benefits By Harriet Lublin and Karen Phillips, Hurst Boiler
Perseverance was the key for Sullivan County’s District Energy biomass project. It was more than worth the wait since the benefits have been immediate. Sullivan County was interested in utilizing biomass for quite some time in order to reduce reliance on fossil fuels and carbon emissions. After much research by Facilities Director John Cressy and his team, the county purchased a Hurst biomass boiler district heating system with a backpressure steam turbine/generator to serve the county’s 166-bed nursing home and 168-bed prison complex, as well as two smaller on-site buildings in Unity, New Hampshire. At a cost of $3.4 million, the Biomass Combined Heat and Power (CHP) District Energy System was constructed at its Unity Complex. The system is almost entirely fueled by Figure 1. An example of the process schematic. locally sourced, renewable wood chips, provided by Cousineau Forest Products in Henniker, N.H., and produces inexpensive heat and electricity for the more than 215,000 sq. ft. of conditioned space. The system has replaced 95 percent of fuel oil purchases and 10 percent of electric purchases in the nursing home. An initiative and a feasibility study for a biomass project was in progress when Cressy arrived five years ago, but he said it did not meet the county’s expectations and the entire project was shelved. Then the Wood Education and Resource Center stepped in and offered to do a new feasibility study. “The study blew our minds,” Cressy said. “The numbers looked almost too good to be true.” In the meantime, he also was busy researching biomass boilers for the project, looking at almost two dozen plants to see what they were using. “I ran into a Hurst competitor at the Figure 2. The project layout. Northeast Biomass Conference 2 years ago and Sullivan County built a new 3,000 sq. ft. building for the was shown some of his equipment. We liked the project, instead of retrofitting another space. The front of the concept and robust nature of the ‘walking floor’ so I specified it plant is a huge hopper where the chips are poured. From there, in our bid package,” he said. “The equipment specified by the they drop onto a conveyor belt and are carried up to the boilwinning bidder turned out to be Hurst equipment.” er. By running a steam line to both facilities, the new biomass 6 ENERGY-TECH.com
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FEATURES system provides space heating, hot water heating, power to steam dryers and to the kitchen of the jail and nursing home. Steam provided to the nursing home is used to drive the 40 kW backpressure turbine/generator, producing electricity. The exhaust steam is used throughout the nursing home. “Ninety percent of our fuel load has replaced fossil fuels,” Cressy said. Sullivan County officials are very pleased so far with the performance and savings from the new biomass system. “It (the system) has been operating since December and has already saved us about $100,000,” said Jeff Barrette, chairman of the Sullivan County Commission, during the equipment dedication in April 2014. “This will significantly lower our energy costs and create a net savings in the first year of operation.” Another county official said the savings as of March 31, 2014, came in at $127,000, and this is only a sliver of the projected long-term savings during the next 25 years, assuming an annual increase in fuel oil costs, which is projected at around $4 million. The county estimates operation of the biomass plant at less than $300,000 a year by 2025, while fossil fuel costs for the complex would climb to nearly $1 million. They also project that the annual fuel savings will pay for the construction bond within 15 years. With the sale of energy credits, the county expects to receive a minimum of $75,000/year of offsetting revenue. Bob Waller and his company, Thermal Systems Inc., coordinated and performed all specification and procurement services for the project. Figure 3. The plaque at the final project site.
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FEATURES
Figure 4. The hybrid system in place.
At a glance
• Project cost: $3.4 million • Project savings: $300,000 annual energy savings plus avoided costs Energy profile (annual): • 120,000 gallons fuel oil, plus 5,000 gallons propane offset • 137,000 kWh electricity produced from renewable energy • 1,900 tons wood chips used • 1,200 tons net CO2 reduction Equipment: • Hurst Biomass Boiler – 5.0MMBtu/hr, 150 psi, Hybrid Design • Hurst Fuel Reclamation System – custom engineered to encompass a nine-tree reciprocating floor, this was a complex challenge requiring specialized construction designed to take into account the entirely unique natural terrain of the site, and the 15´ elevation discrepancy between the material handling and storage areas of the boiler room • Hurst ‘Oximizer’ Deaerator – with a duplex pump set • Hurst Propane Package Boiler – 80 hp, 150 psi
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Waller and TSI oversaw the development of the equipment specifications, the equipment arrangement design and the procurement of the components necessary to meet the requirements of the county initiative. “Even though it’s still a new system, I’m very pleased with the Hurst equipment,” Cressy said. “It’s robust, which is important in New Hampshire, as we put heating systems through a lot up here.” The equipment utilized in the project included a biomass boiler at 5.0MMBtu/hr, 150 psi, with a hybrid design, a fuel reclamation system, which was custom engineered to encompass a nine tree reciprocating floor – a complex challenge requiring specialized construction designed to take into account the entirely unique natural terrain of the site, and the 15´ elevation discrepancy between the material handling and storage areas of the boiler room, an ‘oximizer’ deaerator with a duplex pump set and a propane package boiler at 80 hp, 150 psi. The $3.4 million project was funded in part through several grants totaling $675,000, in addition to a tax-exempt bond through a local bank. Due to recent renewable energy incentives now available to the marketplace, the Sullivan County Unity District CHP Energy Project was able to secure several grants, including $75,000 from the North Country RC&D Grant, $250,000 for the U.S. Forest Service, Forest Products Laboratory, and $300,000 from the New Hampshire Public Utilities Commission – Commercial & Industrial Thermal or Electric Renewable Energy Project. In addition, the project allows all those energy dollars to stay in the local economy. Inspired by the success of this project, Cressy has been working on educational outreach through local schools and technical centers within the county about the benefits of biomass energy. “One of the most important parts of this biomass initiative is building public awareness of the benefits of lessening dependence on fossil and foreign fuels, thus putting more dollars into the local economy,” he said, noting that most of the woodchips used for fuel are found within a five-mile radius of the county complex. ~ Harriett Lublin is a marketing/SEO specialist with Hurst Boiler and Welding Co. Inc., www.hurstboiler.com. She is a graduate of the University of Maryland. You may contact her by emailing editorial@woodwardbizmedia.com. Karen Phillips is a marketing/copywriting specialist with Hurst Boiler and Welding Co. Inc., www.hurstboiler.com. She is a graduate of the University of Tennessee. You may contact her by emailing editorial@woodwardbizmedia.com.
FEBRUARY 2015
FEATURES
Modern age plant safety: Are we pulling a car with an old horse? By Hector Perez, PAS Inc.
Human error ties to all industrial accidents in one shape or form. “Hold on! Pumps fail and cause incidents all the time,” you might say. Yet, why do pumps fail? Often it is due to improper maintenance. Sometimes it might be because of shoddy design. Even with the pump failing to perform, there is still often an opportunity to avoid an incident if a console operator takes timely corrective actions. No matter the situation, it can always be traced back to a human error. Distributed control systems (DCS) were created in large part to decrease human error. We needed them to catch problems more efficiently than humans. And they do. They also have the added benefits of increasing safety and maximizing profitability.Yet, even with DCSs in place today, mishaps still occur. It all goes back to the only problem … no matter how much automation is implemented, humans are still the ones in the driver’s seat. The question is: Are we enabling our operators to drive the DCS “car” to its fullest potential? Or, are we forcing them to pull the car with a horse? Since incidents still happen, very likely it is the latter.
lead to an incident. We must enable our operators to drive the car they have and stop pulling it with a horse. Alarms A large part of the console operator’s job today requires staying on top of alarms in the plant. The modern DCS allows us to place alarms just about anywhere they are needed in order to alert the operator about an abnormal situation. They are so easy and inexpensive to configure that we started adding alarms for all kinds of things — regardless of whether they were appropriate. In the event of an abnormal situation, today’s operator gets thousands of alarms. It’s impossible to keep up with them. Sooner, rather than later, the operator will miss an important alarm and an incident will happen. The DCS alarm management problem can and should be fixed.
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DCS Control loops Running today’s power plant is much like driving a car. The automation takes care of most of the actions required to keep it running. Control systems in power plants changed the game for operators — they made effortless the opening, closing and assessing actions based on real-time readings of plant variables. Even more impressive, today’s control loops function automatically based on a commanded setpoint.Yet for some reason, an estimated 30 percent of controller points in industry remain in manual mode. By configuring a control loop to be on manual, the operator must take cumbersome actions to adjust a specific parameter. This should not be tolerated. We should utilize the software to tune and fix problems so the control loops work automatically. This helps avoid missing an emergent abnormal situation that might
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FEATURES 98.6 98.444 98.51 98.354 98.5 98.464 98.459 98.5 98.112
98.484 98.479 98.19 98.1 98.504 98.23 98.132 98.3 98.524
98.519 98.6 98.4 98.544 98.12 98.4 98.3 98.297 98.292
98.3 98.45 98.317 98.692 98.45 98.55 98.399 98.345 98.55
Figure 1. Digital example
Figure 2. Analog example
HMIs Not only is the amount of annunciated alarms problematic, but also the lack of context with which we present alarms to operators. When DCS graphics were built, the alarm light-boxes that were on the walls of the old control room were transferred to the DCS. The transfer was quite literal. We drew squares on the screen that changed colors to depict an alarm, but our DCSs are capable of so much more. We can convey contextual information, such as embedding a trend or placing navigation buttons to open diagnostic screens that allow us to quickly understand why an alarm turned on. By knowing why, our operators can swiftly remediate escalating situations.
The DCS is even capable of allowing operators to detect abnormal situations before alarms are generated. This can be accomplished via analog indication, as opposed to the traditional depiction that involves raw data (numbers with no context) on a screen. As humans, we understand analog indicators better than raw data because analog provides a frame of reference. A common place where we value analog indication is in our car. If the speed limit is 40 mph, we don’t really care if we are going 39.4 mph or 40.6 mph. All we care about is that we are driving close enough to the speed limit and an analog gauge does the job well. A digital number alone requires mental deciphering that involves an extra fraction of a second to determine if we are close enough to the speed limit. Now this might not seem like a big problem, but a power plant operator is in charge of monitoring about 5,000 live process variables in real time. That extra fraction of a second creates a heavy mental workload and it’s unrealistic to expect an operator to sit in front of the DCS for up to 12 hours a day doing this. What is the best thing an operator can do when provided such poor monitoring tools? The operator will wait for an alarm and then take action. He is reactive. A console operator must be enabled to be proactive in order to keep the plant running in a safe condition. Consider Figure 1 and see if you can find the number that is above 98.6. It was a simple task.Yet, even with this limited amount of data, it took a few seconds to figure out. Without looking at Figure 1, how confident are you there was only one number above 98.6? Let’s take a look at a second example, but this time using analog indication. In Figure 2, find the point that is above 82.5. In Figure 2 your attention was immediately drawn to the portion that “looked different.”You effortlessly found the abnormal situation in the analog example when compared to the digital example presented earlier. There are several items to point out to explain why this analog depiction is effective. Each analog bar has different components: • The light blue band in the middle show the normal (desired) operating range
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FEBRUARY 2015
FEATURES • The triangle pointer shows the current value of the process variable • The grey tips on top and bottom show the proximity of the alarms (Hi/HiHi and Low/LowLow) • The black tips show the proximity of a safety shutdown system As long as the pointer is somewhere in the light blue band, everything is running well. In this example analog depiction, as well as appropriate color usage, were utilized to draw attention to the abnormal.You might also have noticed the bar on the right is outside the normal operating range — it is not in alarm yet, but it is not normal either. This is the type of situation awareness that enables the operators to be proactive and fix problems before they even get an alarm. Modern DCSs have the capabilities of implementing these HMI strategies (and others described in The High Performance HMI Handbook) to create effective operator displays. This does not have to be difficult. Every coal-fired power plant in the world has the following basic flow: The coal is pulverized, sent to a boiler, steam is made, which turns a turbine hooked up to a generator, and voila – electricity is made! Given these similarities, a standardized set of graphics, such as PAS PowerGraphiX, that were designed following best practices should be employed as a starting point for every project. By using these standardized blueprints, we avoid having to “re-invent the wheel” on every HMI project. Otherwise, graphics are mistakenly created based on the personal preference of the creator and not necessarily on best practices. We know these blueprint graphics reduce human error, improve safety and increase profitability. Let’s utilize them and give our operators the tools to drive the DCS car, rather than pull it with a horse.
our operators are stuck pulling a fancy DCS “car” with an old horse. ~ Hector Perez oversees the High Performance HMI business line at PAS. He is a chief designer of high performance graphics intended to facilitate situation awareness in a variety of industries, and he also has a strong background in alarm management. He has facilitated numerous alarm management workshops, conducted alarm rationalization projects, and has a wide range of clients in the petrochemical, power generation, pipeline and mining industries. He has a bachelor’s degree in chemical engineering. You may contact him by emailing editorial@woodwardbizmedia.com.
Conclusion The DCS has the ability to decrease human error while increasing profitability. We have seen profitability increase, but costly incidents caused by human error continue to happen. When you stop to think about all the capabilities of today’s DCS, we really are underutilizing its full potential. It is time to engineer the DCS to present functional and actionable information to the operators. Until we do this,
FEBRUARY 2015 ENERGY-TECH.com
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Regulations Compliance
Capturing mercury emissions By Savannah Cooper, Worldwide Recycling Equipment Sales
For 40 years, a site in New York was used to reclaim mercury from batteries and other materials. Located beside a tributary of the Hudson River, the site slowly contaminated the surrounding area for decades, threatening the health of the more than 100,000 people who lived within just three miles. In 1999, the U.S. Environmental Protection Agency took over the cleanup of the site — one of many Superfund sites across the U.S. contaminated with toxic mercury. Mercury is a naturally occurring element that is found in the environment and exists in several forms, Figure 1 including elemental mercury and mercury compounds. be washed into lakes, rivers and streams. After it is deposited, Classified as a neurotoxin, a chemical that is destructive to the mercury can be converted into methylmercury, a highly toxic nervous system, mercury can impair brain development in form of the element that builds up in the gills of fish. The larginfants and small children and cause severe neurological damage er the fish, the more mercury it absorbs, leading states to release in adults. Mercury also is harmful to wildlife and the environadvisories on the consumption of fish and seafood. ment because it can travel long distances in the air to soil and Human activities and industries add a substantial amount bodies of water, then travel up the food chain, contaminating as of mercury to the atmosphere. Mercury is emitted from some it does so. coal-fired power plants, cement As a naturally occurring elemanufacturing plants, by burning ment, mercury can be found in hazardous wastes, breaking prodThe goal of the Clean Air Mercury numerous places and within many ucts that contain mercury and the materials. Natural sources of merRule is to reduce utility emissions of improper treatment or disposal cury in the atmosphere include mercury from 48 tons per year to 15 of mercury-contaminated wastes. volcanoes and geological deposits. Generating low concentrations of Rocks, water and soils also naturally tons per year, a 70 percent reduction. mercury vapor, coal-burning power contain small amounts of mercury, plants are the largest human-caused and some mineral deposits and source of mercury emissions in thermal springs contain higher concentrations of the element. the U.S., accounting for more than 50 percent of the mercury More commonly though, mercury cycles in the environreleased into the air. ment as a result of human activities, and the environmental In addition, industrial processes that use mercury, waste cycle of mercury presents threats both to human health and the generators and mineral mining operations all contribute to earth. Most mercury in the atmosphere is elemental mercury mercury pollution. Poor management of emissions or leakage vapor, which can circulate in the air for up to a year and thus can result in concentrations of mercury in the soil that are can be widely dispersed and transported thousands of miles well above the regulatory limits. In 2007, the EPA reported from the source of the emissions. Once released, mercury even- that mercury was a “contaminant of concern” at nearly 300 tually settles into bodies of water or into the earth, where it can Superfund sites across the country. As a result, the EPA and
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Regulations Compliance other organizations around the globe have tightened regulations on emissions of hazardous chemicals, such as mercury. Exposure to mercury can have devastating effects on the human nervous system and damage the brain, heart, kidneys, lungs and immune system. To combat the threat of mercury exposure, the EPA has established and tightened regulations on mercury emissions during the past 20 years. The Mercury Export Ban Act of 2008 (MEBA) prohibits the export of elemental mercury from the U.S. This prohibition is designed to limit the availability of elemental mercury in the global market. The European Union established a similar ban on the exportation of mercury and mercury compounds in 2007. The Clean Air Mercury Rule, which the EPA issued in 2005, created “performance standards and established permanent, declining caps on mercury emissions” (U.S. EPA, 2005). This regulation marks the first time that the EPA has regulated mercury emissions from coal-fired power plants. The goal of the Clean Air Mercury Rule is to reduce utility emissions of mercury from 48 tons per year to 15 tons per year, a 70 percent reduction. In May 2011, the EPA proposed the National Emission Standard for Hazardous Air Pollutants (NESHAP). This regulation was created to reduce toxic air pollutant emissions, such as mercury, from coal-fired and oil-fired electricity generating utilities. In the past 15 years, many states also have established regulations limiting mercury emissions from coal-fired power plants. Between 1999-2009, emissions decreased by almost 27 percent. Another contributor to mercury emissions is the cement industry. Cement manufacturing is an energy-intensive process that grinds and heats a mixture of raw materials—such as limestone, clay, sand and iron ore—in a rotary kiln. The product of this process is known as “clinker” and is used to make cement, which is then mixed with aggregate and water to create concrete. A variety of pollutants, including mercury, are released from the burning of fuels and heating of the raw materials used to make cement. The EPA aims to reduce the harmful air pollution from the cement industry through regulations that depend on current technology to limit the emissions of toxic air pollutants such as mercury. The newest mercury regulations from the EPA are designed to limit emissions from cement kilns to 55 lbs per million tons of clinker. The EPA requires that mercury-contaminated waste be treated to remove or stabilize the toxic metal and keep it from leaching into the soil and groundwater. Mercury can be treated and removed from many materials, including soil, sediment, sludge and other industrial wastes. Fortunately, mercury can be cost-effectively removed from soil before it has a chance to negatively impact human health and the environment. Mercury can be removed from contaminated substrates through the use of a process known as thermal desorption. In this process, intense heat is applied to the material to volatize the mercury without damaging the material itself. In a thermal desorption unit, the contaminated soil is heated and the mercury is vaporized. A gas or vacuum system then
transports the vaporized mercury and water to an air-emission treatment system. Worldwide Recycling Equipment Sales, LLC (WWR) in Moberly, Mo., is uniquely positioned to aid those in the industry in the removal of mercury and mercury products from contaminated materials. Through our Vulcan® Systems, WWR has developed technology that is able to remove mercury from substrates on a continuous basis. This custom-designed and manufactured thermal equipment includes vapor recovery for the collection of vaporized mercury and has been demonstrated on both a pilot plant and a commercial basis. WWR is capable of designing systems to remove mercury from any industrial powders, such as activated carbon, fluorescent lamp powder, sludges and soil contaminated with mercury and mercury compounds. Vulcan® Systems custom-designs and manufactures drying, calcining and thermal desorption equipment. Each system is custom-built to suit the client’s specific needs and services include setup, commissioning, training and maintenance support services over the lifetime of the project. ~ Savannah Cooper is the writer/copy/social media specialist at Worldwide Recycling Equipment Sales, LLC, www.getavulcan.com. She has a bachelor’s degree from Lincoln University of Missouri. You may contact her by emailing editorial@woodwardbizmedia.com.
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MR. MEGAWATT
Show me the proof By Frank Todd, True North Consulting
Much of our Christmas season was spent in transit – our grandchildren have a way of calling us to them in even the worst of driving conditions. As Mrs. Megawatt and I wended our way through the majestic mountains in our 4x4 tundra-ready vehicle, I remembered a time when I wasn’t so sure about how my journey would end. The Missouri Xenia Mississippi Area Station (MXMAS) is located at the crossroads of the “Show me State” and the “Land of Lincoln.” Richie Reynolds and I were headed down to try out our new method of figuring out Cycle Isolation losses. MXMAS had received all of the wrong kind of attention in the last year from their owners and the federales because of their plant efficiency. They had tried several different approaches, and we were on their list of those who might be able to help. Of course, we were in the unenviable position of coming on the scene after many empty assurances from our predecessors who had promised they had “just the right widget” that would solve all the plant’s problems. ‘Scrutiny’ does not do justice to the group of steely eyed managers and engineers who were sitting across the table from us, with looks designed to crumble the most arrogant used car salesman with a passing glance. Understanding the nature of our predicament, Richie and I explained our proposal. One area that MXMAS had not looked into yet was cycle isolation. Leakage from high energy valves was a missed opportunity at many power plants, mainly because you cannot see the leakage. Table 1 shows the typical effect on Load and Heat Rate for valve leakage. Figure 1 shows the additional generation costs for various heat rate increases, relative to the nominal size of the plant. The costs are determined by calculating the additional fuel required at the increased heat rate levels. This value, in Btu/hr, is multiplied by the average fuel cost per million Btu ($/MBtu). These graphs assume a 100 percent capacity factor base load operation, but actual plant costs should be determined based on individual plant operating conditions and costs. In order to evaluate the economic impact of cycle isolation, the cost of the overall impact on the plant must first be understood. There are two scenarios where a cycle alignment leak will impact a plant. In the first scenario, the plant is prevented from increasing the energy added to the cycle. This could be due to turbine, boiler, pump or environmental (emissions) limitations. In this situation, the plant will lose revenue in the form of lost generation. The second scenario involves no limit in the plant. In this case, the plant will increase the fuel and the associated costs required to maintain the load, but be able to maintain the revenue.
14 ENERGY-TECH.com
Figure 1. Relationship between heat rate effects and generation costs for a coal steam plant @ 9,000 Btu/kWh heat rate.
Figure 2. Calculation of additional fuel costs due to a 1 MW leak.
Figure 2 shows the cost of a lost megawatt from the effect of additional demand on the plant and lost generation. The operating cost curve is based on the Average Power Plant Operating Expenses for Fossil Steam Plants. The value used for the operating cost curve is 32.30 mills/ kWhr, which also can be expressed as 32.30 $/MWh. The lost revenue curve is based on the median wholesale price of a MWh for a cross section of power markets in the United States. The value used here is 43.5$/MWh, and the figure assumes a leak that costs 1 MW is left unaddressed for a period of time. So now we had their attention, but the real question was how these leaks could be found and – even more difficult – how they could be quantified. Some power stations were reluctant to fix leaks they could see, let alone those they could not see. So if you had a situation like Figure 3, you could convince people that there is a leak, but to quantify the leak is difficult. More concerning is what is shown in Figure 4, or rather what is not shown, leakage to the condenser. Leakage that cannot be seen is very difficult to quantify, especially if you do not have a pressure gauge downstream of the leak. There are a few methods available with various merits, but all of them fall short of a good estimate of the leakage rate. The method we chose to use as FEBRUARY 2015
MR. MEGAWATT a starting point is the most common in the industry, measuring the temperature downstream of the valve. Generally, temperature can let you know that there is a leak, but how can that be turned into a leakage rate and where do you measure the temperature? The methodology we were proposing infers the pressure from the pipe temperature and uses the pressure to calculate the flow. However, where the temperature is taken can either make or break the calculation of flow. Figure 6 is an illustration of the pipe wall temperature and leakage rates. If the measurement is upstream of the valve or very close to the valve outlet, a very small leak will indicate a high temperature. To be useful for determining leakage rate, the measurement should be taken farther downstream. The underlying assumption in using temperature to detect leaking valves is that the leaking fluid will increase the temperature downstream of the valve. The magnitude of this temperature can be used to estimate the amount of leakage present. Figure 6 is a sketch of the inputs to the calculation method. This temperature can be measured either inside the pipe or on the outside surface of the pipe. When using surface temperature, a small hole must be cut in the pipe insulation to facilitate recording the measurement. The assumption in this case is that the surface temperature is equivalent to the temperature inside the pipe. This is a conservative assumption, since the surface temperature would never be higher than the inside temperature, unless the environment around the pipe is very hot. The resulting predicted flow would then be lower (i.e. more conservative) than flow calculated with a higher temperature. Once the temperature of the pipe has been determined, the next step is to infer the pressure inside the pipe. This inference depends on the conditions of the fluid upstream of the valve and the location of the temperature measurement with respect to the valve and the sink. The assumption regarding an increase in temperature downstream of a leaking valve cannot ignore the cooling effect that will occur when steam is expanded.
Table 1 – Effect Of 1% Leakage To The Condenser Origin of 1% Leakage Flow
Effect on Heat Rate
Effect on Load
Throttle
0.83%
0.94%
HP Turbine Exhaust
0.53%
0.69%
Ahead of Intercept Valve
0.69%
0.69%
Cross-over
0.44%
0.44%
Table 1. Typical effect on load and heat rate for valve leakage.
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15
MR. MEGAWATT
Figure 3. A leak you can see.
Figure 4. A leak you cannot see.
There are various calculations available to go from the temperature to the flow; the method Richie and I proposed uses five different calculations. They are all in some way based on choked flow conditions, which is normally the case. These different calculations can be compared and the proper method for the given situation is used. But as we sat around the table, the skeptical glares did not diminish. Sure they understood the potential for losses but how could we be sure that the location we picked for the temperature measurement was the right one? So we explained that we accounted for the pipe geometry by determining the flow resistance (or head loss) in pipes, valves and fittings, which is generally given in terms of the resistance coefficient K. The resistance coefficient can be included in the Bernoulli equation to account for flow resistance between two points, as shown in Equation 1. The two points are the location on the pipe where the temperature is measured and the final destination of the liquid leaking past the valve, in this case the condenser.
Equation 1
Where:
Figure 5
Figure 6
Under normal circumstances, the temperature of a fluid will decrease as it expands. The assumption is based on the temperature in the downstream pipe. The steam from the upstream side will cool as it expands through the valve, but it will still cause a temperature increase on the downstream side of the valve.
16 ENERGY-TECH.com
P1 = V1 = Ď = g = z1 = P2 = V2 = Z2 = K =
Pressure Upstream (psi) Velocity Upstream (ft/s) Density of fluid downstream of valve (lbm/ft3) Acceleration due to gravity (32.2 ft/s2) Elevation Upstream (ft) Pressure Downstream (psi) Velocity Downstream (ft/s) Elevation Downstream (ft) Resistance Coefficient
If the equation is solved for V2, a formula with the form can be found (where a accounts for the other terms in the Bernoulli equation). The separated term accounts for the flow resistance. Because it is proportional to velocity and flow, this term can be applied as a correction factor to the velocity and flow results of the basic flow equations, which do not account for flow resistance. So now we gave them an equation, but they still were not impressed. Unsurprisingly, they wanted us to show them before they would buy into it. MXMAS had a blowdown valve that they knew was leaking and had a flow measurement record on that valve. They wanted us to grab our gear and go out into the plant, to see if we could measure the flow; sort of a blind test. In addition, we had to measure the temperature at various downstream locations. The plant engineer wanted the flow resistance correction we discussed earlier to be validated, as well as the calculation methods, since the blowdown flow is measured. So Richie and I took
FEBRUARY 2015
MR. MEGAWATT
A REVOLUTION IN BRUSH CHANGING FOR TURBINE-GENERATOR RELIABILITY The NEW Cartridge-Style Plug-In Brush Holder
Figure 7
up the challenge, sort of like going around a curve with a 500´ drop off while traversing the San Juan’s – with a little fear and trepidation. We strapped on our safety gear, grabbed my stethoscope and infrared gun and headed out to the plant to measure the temperature at various locations along the pipe. We built the mathematical model – which sounds more impressive – of the geometry in order to calculate the flow. The X-axis of Figure 7 indicates the distance from the condenser for each measurement. As Figure 7 demonstrates, the correction for distance to the condenser produces consistent results, since the temperature increases the farther from the condenser the temperature is measured. The design flow is displayed for reference, indicating that the flow measurement method demonstrated is conservative (i.e. reports lower flows than actual). This conservatism is beneficial because it will not cause any calculation of payback to be overstated. All thermal performance engineers know the inverse correlation between your credibility and overestimating a pay back. While they were still a little skeptical, the plant staff decided that the methodology would be OK, and we felt like we were finally on a nice flat road with the mountains well behind us. I left Richie to complete the rest of the walkdown, knowing that there would be other cycle isolation calculation perils along the way, but those are a story for another time. ~ Mr. Megawatt is Frank Todd, manager of Thermal Performance for True North Consulting. True North serves the power industry in the areas of testing, training and plant analysis. Todd’s career, spanning more than 30 years in the power generation industry, has been centered on optimization, efficiency and overall Thermal Performance of power generation facilities. You may email him at editorial@woodwardbizmedia.com.
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FEBRUARY 2015 ENERGY-TECH.com
17
ASME FEATURE
Leveraging natural gas: Technical considerations for the conversion of existing coal-fired boilers By Jason C. Lee, P.E., Babcock Power Services Inc., and Michael Coyle, Riley Power Inc.
The idea of converting an existing coalfired boiler to natural gas-firing is not new. The MIT Energy Lab published a report reviewing the feasibility and cost of such a conversion in 1986, with the ultimate goal of reducing sulfur oxide emissions [1]. Today these conversions are being revisited as an alternative to capital intensive emissions control equipment for not only sulfur, but nitrogen oxides and even carbon dioxide. High volatility in the price of natural gas has typically kept this option from being pursued, but recent increases in natural gas production and storage have reduced and steadied the price of the fuel. The U.S. Energy Information Administration (EIA) has reported steady annual average Henry Hub spot prices for natural gas under $8/MMBtu through 2040, with prices staying below $5/MMBtu through 2025 [3]. In some markets, rising coal prices and low gas prices are resulting in gas becoming less expensive than coal. These prices – combined with rising capital investment requirements for coal-fired generation to stay Figure 1. Riley STS® Low-NOX Natural Gas Burner compliant with new environmental regulations – make a conversion to natural gas-firly consists of a new natural gas fuel transport system (ie. Gas ing an attractive option. A significant portion of coal-fired metering station, pressure reducing station, piping, etc.), gas generation is projected to be retired as a result of increasing burners, ignitors and flame scanners. New logic designed for gas regulatory costs. SNL Energy reports more than 48 GW of firing will need to replace the existing coal-based logic in the coal-fired generation scheduled for retirement during 2012burner management system (BMS). Some logic will need to 2020. A conversion to natural gas-firing is being considered be modified in the combustion control system (CCS) as well, more frequently as an alternative to retirement for these units. since combustion air requirements and master fuel controls will A reported 6,900 MW of existing capacity, approximately 14 be different when firing natural gas. All system designs will be percent of planned retirements, are planned for conversion to required to meet current codes, which might include NFPA 85, natural gas, according to SNL Energy data [4]. NFPA 497, NFPA 54 and NFPA 70.
Fuel system modifications When considering the conversion of an existing coal-fired boiler to fire natural gas exclusively, plans must be made to remove the existing coal equipment and install the necessary gas-firing equipment. The new equipment required general-
18 ENERGY-TECH.com
Gas burners Natural gas burner suppliers can typically re-use existing coal burner openings with little to no pressure part modifications in order to deliver the required fuel and air into the furnace for 100 percent MCR gas-firing. Gas burners are similar
ASME Power Division Special Section | JANUARY 2015
AsmE FEAtUrE Table 1 – Comparison Of Ignitor Classes Class 1
Class II
Class III
Class III-Sp.
Ignition of Main Burner
Coal, Gas
Coal, Oil, Gas
Gas, Oil
Gas, Oil
Heat Input
>10% burner @ full load
4-10%@ full load
<4%burner@ full load
N/A
Cont. Operation
Yes
Yes (w/2 scanners)
No, light-off only
No
to coal burners in that they supply the required air and fuel mixture at design velocities required for proper fuel combustion within the furnace. Figure 1 is an example of a natural gas low NOX burner design for wall firing. Due to the favorable fuel properties of natural gas and the greater turndown capabilities of a natural gas burner (greater than 10:1 burner turndown in some cases) the gas burners can often be used to warm the unit during a cold start, allowing the use of smaller Class II or Class III ignitors. In some instances, it is possible to retrofit the existing coal burners by replacing the coal components with gas components and re-using the existing air register, while at other times a complete burner replacement is required. Excess air levels required for gas-firing are much less than coal-firing – 8-10 percent compared to 15-20 percent, respectively. This change in airflow requirements generally leads to the need for smaller air register designs and possibly decreased fan duty. For boilers requiring the use of flue gas recirculation (FGR), the total combustion air [combustion air plus FGR] may be nearly the same mass flow as was required for coal-firing. In burner retrofit applications, burner registers might need to be modified to maintain proper air velocities through the burners. Ignitors Gas and coal burners generally have different ignition requirements due to the fuel differences and burner turndown limitations. Table 1 provides a description for the different ignitor types available [6]. Flame scanners When switching to natural gas fuel, the flame scanners used to monitor flames within the furnace will need to be monitored since there are significant differences in characteristics between the coal and gas flames, such as the spectral intensity of radiation. There are three types of flame scanners typically used in boiler applications; ultra-violet (UV), infrared (IR) and flame rods. UV and IR scanners are usually the most utilized in utility boilers, with the latter being more typical for coal-fired applications. Some coal-fired units are equipped with combination UV/IR flame scanners and can be re-used for gas-firing with proper calibration by the scanner OEM.
19 ENERGY-TECH.com
ASME Power Division: Plant Operations and Maintenance Committee
A Message from the Chair The ASME Power Division’s Plant Operations and Maintenance Committee is comprised of a dedicated group of industry professionals that volunteer their skills, knowledge, experience and time in pursuit of identifying and sharing industry “best practices” in the operation and maintenance of power and other energy conversion facilities. The committee includes members from throughout the industry, including owners, O&M service providers, engineer/architects, equipment manufacturers, insurance agencies and specialty consultants. The purpose of the Plant O&M Committee is to provide industry guidance on the selection, performance, operation and maintenance of power generation equipment and systems. This is primarily accomplished by sponsoring technical papers and presentations at the annual ASME Power Conference. The next scheduled conference will be a joint conference held with the International Conference on Energy Sustainability, and the Fuel Cell Science, Engineering & Technology Conference, June 28-July 2, 2015, in San Diego, Calif. Our committee is currently organizing a Plant O&M track for the 2015 ASME Power Conference. This is an exciting time as we discuss key issues impacting the operations and maintenance of power and other energy conversion facilities. Change is occurring in the power industry resulting from a myriad of environmental and reliability issues. These issues directly impact the operation and maintenance of power generation facilities. The aging workforce in our industry also creates challenges regarding effective knowledge transfer and attracting new employees into this industry. The ASME Power Division Plant O&M Committee strives to provide a forum for discussing these issues. If you are interested in joining us, we generally meet once each year at the ASME Power Conference and have periodic conference calls. The committee provides a great forum to network and discuss important industry topics. If you would like more information about the Plant O&M Committee or have interest in joining, please contact myself or visit our group page on ASME.org, Brian J. Langel, PE Manager Production Engineering Omaha Public Power District blangel@oppd.com
ASME Power Division Special Section | JANUARY 2015
AsmE FEAtUrE
Figure 2. FEGT as a function of area heat release
Figure 3. Relative gas energy profiles (PRB Base Coal)
Performance considerations When considering the change from coal-firing to natural gas-firing, one also must consider the changes in unit performance and the effect of such changes on the overall economic profile of the generating unit. The impacts of a switch from coal to gas are wide-ranging depending on the base fuel, unit characteristics and the final performance objectives. Black and Bielunis [7] discussed the effects of converting a coal-fired boiler to natural gas, but their discussion on thermal characteristics of a conversion were more focused on smaller industrial boilers with output less than 500,000 [lbs hr-1] steam flow. Here, the focus is given to the effects that can be expected for larger utility-scale units.
20 ENERGY-TECH.com
Furnace performance A change in fuel will drive changes in the performance characteristics of the radiant furnace. These characteristics are (a) the radiant heat flux profile in the furnace walls, (b) the portion of radiant heat transferred to the upper furnace, both steam and water cooled, (c) the portion of radiant heat transferred directly to the furnace outlet plane, and (d) the resulting furnace exit gas temperature (FEGT). The FEGT can either increase or decrease depending on the base fuel and furnace characteristics. Typically, a furnace is designed to meet several criteria, including fuel burnout, velocity requirements for convection, ash deposition and erosion, and gas temperatures. Typically, a furnace designed to fire natural gas will be much smaller than one designed to fire coal, due to the faster burnout, and there is no ash to consider for erosion or deposition. Additionally, when there is no ash deposition to inhibit heat transfer to the furnace walls and the distribution of fuel/air in the furnace is more even, higher heat release rates are possible. A typical gas furnace can have a design area heat release rate approximately 2.5x greater than a typical coal-fired unit with equal rated output. This large difference in design criteria make it clear that a complete and detailed analysis of the furnace performance is necessary when converting a coal-fired unit to natural gas-firing. Figure 2 shows FEGT as a function of the furnace area heat release rate for various fuels for front wall-fired boilers. It can be seen that if the base fuel is a western sub-bituminous coal, such as that from the Powder River Basin (PRB) with a medium- to high-heat release rate, the FEGT will decrease for gas-firing. With a low slagging base coal the FEGT can be expected to increase when firing gas. The wide range of possible FEGT values for any given heat release rate when firing coal necessitates a caseby-case evaluation of the furnace performance for each unit being considered. A coal flame is much more emissive than a natural gas flame. Radiation from a coal flame is significantly enhanced by the presence of carbon/soot particles, which radiate at nearly black-body emissivity. Thermal radiation from a flame containing soot can be 2-3x that of a flame without soot [8] . Thermal radiation is proportional to the fourth power of the temperature. The adiabatic flame temperature is a function of the heat content of the fuel and the flue gas properties and can be calculated via Equation 1 [9].
Equation 1
ASME Power Division Special Section | JANUARY 2015
ASME FEATURE higher FEGT and suffer a decrease in absorption due to the Generally, a higher heat content fuel with low moisture will lower gas flow. result in higher flame temperatures. For reference, a bituminous Consideration also must be given to the change in bundle coal burned at 20 percent excess air will have an adiabatic flame temperature near 3,300ºF (1,816ºC), while a high moisture, low effectiveness due to the presence of ash deposits on convective heat content PRB coal with the same excess air would have a surfaces. Engineering judgment and experience must be relied flame temperature closer to 2,950ºF (1,621ºC). A representaupon for this assessment. Convective effectiveness can increase tive natural gas flame will have an adiabatic temperature near up to 15 percent depending on the base coal and ash deposi3,200ºF (1,760ºC) at 20 percent excess air and near 3,500ºF tion characteristics. (1,927ºC) at 10 percent excess air. Utility scale boilers will typically experience an overall Analysis of a radiant furnace system is complex, requiring decrease in convective absorption in SH and RH sections, detailed calculations for radiant gas properties, including the decreasing main steam and reheat steam temperatures to the effects of particles such as char, soot and ash, as well as geometric properties such as radiant exchange factors. Further complicating the analysis are the effects of ash deposition on the radiant surfaces. Typically, this can be accounted for by utilizing a calibrated furnace model based on operating data available from the unit. It is challenging to identify how these different furnace Zeeco’s 35-year history of combustion and characteristics will change when the gasenvironmental successes makes us the eous fuel is burned in the furnace. Surface breath of fresh air you need to convert emissivities must be adjusted to account for coal-fired power to natural gas, or add the elimination of ash deposits, which can low or ultra-low NOx gas-fired capability to significantly reduce the absorption to those meet the latest emissions and efficiency surfaces when firing coal. Engineers still rely targets. In a combined cycle facility, ZEECO® heavily on experience when analyzing these low-NOx duct burners also assist in meeting systems. clean-air standards.
A Breath of Fresh Air.
Steam conditions Table 2 summarizes the comparative parameters for two different coals and natural gas. Firing gas at the same heat input results in an approximate 14.5 percent decrease in the total required combustion air. It follows that approximately 16-20 percent less flue gas will exit the furnace while firing gas. Although the gas temperatures entering the convection sections can typically be higher than that for coal-firing, the lower flue gas mass flow rates while firing gaseous fuel will often result in a net decrease in convective absorption. The change in flue gas mass flow will change the outside convective heat transfer coefficient, while an increase or decrease in FEGT will affect the temperature difference. In a unit experiencing an increase in FEGT, the first convective section will often experience an increase in absorption, as shown by Black et. al [7]. Although this first surface would likely see an increase in absorption due to higher available energy, downstream surfaces often see diminished effects of the
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JANUARY 2015 | ASME Power Division Special Section
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ASME FEATURE Capacity There are several factors Table 2 â&#x20AC;&#x201C; Combustion Parameter Comparison With Different Fuels that have the potential to limit the load capability of Bit. Coal PRB Coal Nat. Gas Nat. Gas a converted unit, including HHV Btu/lb 14,100 8,223 23,143 23,143 the ability of the forced-draft Excess Air % 20.00 20.00 20.00 10.00 (FD) fans to supply sufficient Dry Air Req. lb/lb 12.85 7.51 19.68 18.04 combustion air to the boiler, and maximum allowable Dry Air Req. lb/10kBtu 9.12 9.13 8.50 7.79 metal temperatures. If the Dry F.G. Prod. lb/lb 13.36 7.75 18.57 16.93 convective heat transfer is Wet F.G. Prod. lb/lb 13.95 8.56 20.94 19.27 too high in the superheater or reheater such that mateWet F.G. Prod. lb/10kBtu 9.9 10.41 9.05 8.33 rial temperature limits are exceeded, the unit might require a load reduction if Table 3 â&#x20AC;&#x201C; Boiler Efficiency Comparison With Different Fuels pressure part modifications are not desired. Pressure Parameter Bit. Coal % PRB Coal % Nat. Gas % part modification in this Dry Flue Gas Loss 5.97 6.01 4.66 case could involve materiMoisture (Liquid) in Fuel al upgrades, the addition/ 0.24 4.16 0.00 Loss upgrade to spray attemperaWater from H2 Combustion 3.31 4.53 10.63 tion stations, or the complete redesign of SH and/or RH Air Moisture Loss 0.14 0.14 0.12 surface to accommodate Unburned Carbon Loss 0.09 0.09 0.00 gas-firing and optimize boilRadiation Loss 0.17 0.17 0.17 er performance. Unaccounted Loss 0.50 0.50 0.50 Additionally, when firing coal, a portion of the comTotal Loss 10.42 15.60 16.08 bustion air is supplied to Boiler Efficiency 89.58 84.40 83.92 the furnace as transport air for the solid fuel. With the turbine. In order to recover lost convective heat transfer, FGR gaseous fuel, all combustion often is utilized to increase the mass flow of gas from the furair will be supplied through the windbox via the forced-draft nace and through the convection sections. FGR can be accomfan(s). While the total amount of combustion air required plished with several different configurations, such as induced to combust natural gas is less than that required for coal, the flue gas recirculation (IFGR), using the existing FD fan or a amount being supplied by the FD fan(s) can be higher. A connew dedicated FGR fan. IFGR will further increase the duty version to gas could result in greater than 20 percent more air of the FD fan and will limit the temperature of the flue gas being supplied by the FD fans. FD fan capacity should be evalrecirculated, based on the limitations of the existing fan mateuated for capability to supply the required flows for gas-firing. rials. Flue gas is generally taken from the economizer exit and recirculated back to the furnace via the windbox, lower furnace Boiler/plant efficiency or upper furnace. Mixing the flue gas with the combustion air As discussed earlier, natural gas-firing produces lower flue gas in the windbox and through the burners provides an additional flow rates for the same heat input. The lower gas flow results benefit of reduced NOX production. Figure 3 shows a comparin lower dry gas losses. This lower dry gas loss increases boiler ison of the specific energy in the flue gas entering each surface efficiency, but the higher hydrogen content in gas will lead to a of an example unit analyzed for gas conversion. In this example higher moisture loss, negatively impacting the boiler efficiency. FGR was added in order to recover some of the energy to The increase in boiler efficiency due to lower gas losses and achieve original steam condition while firing natural gas. The no unburned carbon loss will typically not be greater than the gas enthalpies shown are normalized using the furnace exit negative impact of higher moisture losses, for net loss of up to enthalpy for the base coal. 5 percent in boiler efficiency. Table 3 shows an example of the Pressure part modifications also can be considered for perdifferences in the major efficiency losses for coal and natural formance optimization, but will require high capital investment. gas in the same unit at rated load. The data in Table 3 shows that for a coal with high moisture, the efficiency reduction for
22 ENERGY-TECH.com
ASME Power Division Special Section | JANUARY 2015
AsmE FEAtUrE gas-firing is small, while that for a unit burning a low moisture bituminous coal will be much higher. A change in the boiler efficiency will impact the overall Unit Net Heat Rate (UNHR). The boiler efficiency is inversely proportional to boiler efficiency according to Eq. 2:
Equation 2
Thus, a 5 percent reduction in boiler efficiency will result in an approximate 5 percent increase in heat rate. The increase in heat rate due to boiler efficiency is typically partially offset with a decrease in station load, resulting from the elimination of fuel handling equipment such as coal pulverizers and PA fans. The values in Table 3 assume like conditions at the regenerative air heater. The air heater performance will be altered when switching from coal- to gas-firing, since the flow rates are changed as well as the ratio of air to flue gas. Regenerative air heater performance is dependent on the specific heat ratio, known as the “X” ratio, as follows:
Figure 4. Correction to heat rate for a reduction in steam temperature.
Equation 3
A 10 percent decrease in the “X” ratio will result in a decrease of boiler efficiency of approximately 0.75 percent [10]. In addition to the boiler efficiency changes, any changes in the steam conditions can affect the UNHR as well by changing the turbine cycle heat rate (TCHR). Figure 4 shows a typical heat rate correction to the TCHR for a given reduction in the steam temperatures [11]. The change in steam temperatures, superheat and reheat, will be dependent on the units’ configuration for steam temperature control, as well as the changes in heat transfer performance. For units with gas proportioning dampers, a larger reduction in RH temperature than SH is typical and any correction to increase steam temperature will typically avoid the use of RH spray attemperation. For units without gas proportioning dampers, the changes in heat transfer characteristics, along with potential corrections to steam temperature (burner tilt or FGR addition) can result in a need for RH spray attemperation. The positive effect on heat rate for increased SH steam temperature should be balanced with the negative effects of RH spray in this case. In general, a 2 percent increase in heat rate will be incurred for every 1 percent increase in RH spray flow. Emissions performance Natural gas-firing offers lower sulfur (SOX), mercury (Hg) and particulate matter (PM) emissions given that there is little to none of the required precursors present in natural gas. This makes a switch to natural gas-firing an attractive option from an environmental compliance perspective. In addition, CO2 emis-
JANUARY 2015 | ASME Power Division Special Section
Figure 5. Relative NOX production by mechanism for different fuels.
Figure 6. NOX reduction by application of FGR
ENERGY-TECH.com
23
ASME FEATURE sions from a natural gas-fired boiler will typically be 50 percent or less than that of a similarly rated coal-fired boiler. In general, gas-firing will produce roughly 1/3 or less of the NOX emissions produced from coal-firing. As shown in Figure 5, roughly 80-90 percent of NOX generated from coal combustion is due to Nitrogen in the fuel, which converts to NOX during the combustion process. Since there is little to no nitrogen in natural gas, almost all of the NOX produced from natural gas combustion is via the thermal NOX mechanism. Typical NOX control technologies employ some form of air or fuel staging. Low NOX burners employ internal air and fuel staging while the addition of over-fire air (OFA) employs external staging of the air in the furnace. Additional measures can be taken to further decrease NOX levels, including the use of FGR as mentioned earlier. A unit converted from coal to natural gas that is equipped with an FGR and OFA system can reduce NOX by more than 75 percent. An example of typical reduction in NOX via the application of gas recirculation is shown in Figure 6.
Conclusions In conclusion, it has been demonstrated that understanding the furnace performance is key in understanding the potential impacts of the fuel switch on the performance of the boiler. Key parameters include base fuel composition and heating content, furnace geometry and firing configuration. While overall performance changes are case-specific, utility boilers will typically experience a decrease in steam temperatures and efficiency. Emissions performance is significantly better on gas-firing due to the lack of fuel-bound nitrogen, sulfur and ash. There are many benefits to gas-firing in lieu of coal-firing with respect to the overall O&M profile of the unit, including the reduction of auxiliary power and additional flexibility in boiler turndown and improved reliability. Dual-fuel capability can be considered for additional flexibility, allowing the operation of the unit on 100 percent coal-firing, 100 percent natural gas-firing or any combination thereof. ~ References 1. J. A. Fay, D. S. Golomb and S. C. Zachariades, “Feasibility and Cost of Converting Oil- and Coal-Fired Utility Boilers to Intermittent Use of Natural Gas,” MIT Energy Laboratory, Cambridge, 1986. 2. G. Dusatko, “Gas Co-firing Assessment for Coal Fired Utility Boilers,” Electric Power Research Institute (EPRI), 2000. 3. U.S. Energy Information Administration, “Annual Energy Outlook,” April 2013.
24 ENERGY-TECH.com
4. SNL Energy, “Unit Operating Status Database,” SNL Energy, Charlottesville, VA, 2014. 5. B. Reinhart, A. Shah, M. Dittus, N. U. and B. Slettenhaugh, “A Case Study on Coal to Natural Gas Fuel Switch,” in POWER-GEN International, Orlando, 2012. 6. National Fire Protection Agency (NFPA), “NFPA 85 Boiler and Combustion Systems Hazards Code,” National Fire Protection Association, Quincy, 2011 Ed. 7. S. Black and D. Bielunis, “Challenges When Converting Coal-Fired Boilers to Natural Gas,” Energy-Tech Mag., pp. 6-13, October 2013. 8. R. Siegel and J. R. Howell, Thermal Radiation Heat Transfer, New York: Taylor & Francis, 2002. 9. The Babcock & Wilcox Company, Steam Its Generation and Use, Barberton: The Babcock & Wilcox Company, 2005. 10. J. G. Singer, Combustion: Fossil Power, 4th Ed., Windsor: Combustion Engineering, Inc., 1991. 11. K. Cotton, Evaluating and Improving Steam Turbine Performance, 2nd Ed., Rexford : Cotton Fact Inc., 1998. 12. North American Electric Reliability Corporation (NERC), “Generating Availability Data System (GADS) Publications,” NERC, 2012. 13. L. Baxter and R. DeSollar, Applications of Advanced Technology to Ash-Related Problems in Boilers, New York: Plenum Press, New York, 1996. 14. B. Courtemanche and C. Penterson, “Dual Fuel Firing The New Future for the Aging U.S. Based Coal-Fired Boilers,” in Proceedings of the 37th International Technical Conference on Clean Coal and Fuel Systems, Clearwater, 2012. Editor’s note: This paper, PWR2014-32272, was printed with permission from ASME and was edited from its original format. To purchase this paper in its original format or find more information, visit the ASME Digital Store at www.asme.org. Jason Lee is supervisor of proposal engineering for the Energy Systems & Services Group at Babcock Power Services, where he is responsible for managing a group of proposal engineers in the development of all technical proposals for boiler systems in the utility and industrial market. Lee is a licensed professional engineer in three states and holds a master’s degree in mechanical engineering from Arizona State University and a bachelor’s in mechanical engineering from Northern Arizona University. You may contact him by emailing editorial@woodwardbizmedia.com. Michael Coyle is currently the manager of product management at Babcock Power’s parts business unit. He graduated from Wentworth Institute of Technology in 2006 with a bachelor’s degree in mechanical engineering technology. You may contact him by emailing editorial@woodwardbizmedia.com.
ASME Power Division Special Section | JANUARY 2015
Call For Presentation-Only Abstracts! Deadline: May 12, 2015
JUNE 28-JULY 2, 2015 SAN DIEGO CONVENTION CENTER | SAN DIEGO, CALIFORNIA | GO.ASME.ORG/POWERENERGY
ENERGY SOLUTIONS FOR A SUSTAINABLE FUTURE In 2015, four of ASME's major conferences come together to create an event of major impact for the Power and Energy sectors: ASME Power & Energy 2015. Fossil and nuclear power generation, solar, wind, fuel cell applications and much more will be discussed in each of the four concurrent conferences within this larger event.
The ASME Power Conference delivers the very latest power engineering solutions in plant operations, maintenance and construction with cuttingedge technology.
The ASME Conference on Energy Sustainability is the world class exchange of innovative technology and R&D efforts that offer a path to renewable solutions.
The ASME Fuel Cell Conference offers the very latest technology research and solutions for fuel cells.
The ASME Nuclear Forum presents the most recent developments in the Nuclear Power industry.
Call For Presentation-Only Abstracts!
Demonstrate your involvement in this critical industry by submitting your presentation-only abstract (for oral or poster presentation) to a track within the events above. In addition, we welcome case studies and real world applications/ best practices. ASME’s Power & Energy event is the can’t miss event in 2015.
Visit go.asme.org/powerenergy for full track listings and submission details. Presentation-only abstracts are due May 12, 2015!
SPONSORSHIP & EXHIBITION OPPORTUNITIES ARE LIMITED, SO ACT NOW! GO.ASME.ORG/POWERENERGY About ASME For more than 100 years, ASME has successfully enhanced performance and safety for the energy and piping industries worldwide through its renowned codes and standards, conformity-assessment programs, training courses, journals, and conferences – including the Offshore Technology Conference (OTC), the International Conference on Ocean, Offshore and Arctic Engineering (OMAE), the International Pipeline Conference (IPC), and Turbo Expo.
The American Society of Mechanical Engineers (ASME)
TurBINE TECH
Identifying the cause of EGT failures By Gregory Bray, Ametek Power Instruments
Most gas turbines utilize Type K or N thermocouples to provide important temperature readings at key locations of the turbine. Thermocouples are well suited to a robust unit that can withstand the thermal cycling and vibration stresses, while providing fast temperature response. Two of the most common applications on larger gas turbines are at the wheelspace and exhaust locations. The temperature data is used by the control system for a Figure 1. Thermocouple bushing wear and fretting variety of purposes, including efficiency, emissions, flameassembly. A replaceout detection and general operating conditions. While this ment only requires the article is structured around the General Electric Frame disconnection of the turbines, many of the failure modes can be applied to other flexible cable assemengines as well. bly from the probe Thermocouples come in a variety of styles, depending and the loosening of a on the age and turbine model that you might have. Some compression fitting for thermocouples have a design in which the semi-rigid metal removal. While these sheath material goes all the way back to the junction box junction box heads have before it transitions to flexible leads. This design has been a reduced ambient temutilized for more than 50 years in gas turbines and is time perature at the junction Figure 2. Thermocouple failure due to proven. This type of design generally has a lower initial pur- head of around 1,000°F, damaged radiation shield seat chase cost, but it also can take up to four hours to install the ability to change out a replacement since any weather covers or the insulation the thermocouple in as little as 5 minutes is a big advanblanket have to be removed to access the thermocouple, tage seen in this design. Unlike the semi-rigid style, a failed as well as the cable clamps that secure it along the probe can be changed while the engine is still hot without engine. The MI cable is fairly stiff, which makes requiring a longer outage for the engine to cool. Some of it difficult to bend and route along the engine. the latest frame engines utilize a quick connector that make Benefits of this design include the low connection even easier, while offering a seal against water initial cost, as well as the ability to withfrom wash down. The connectors on these tend to be rated stand extremely high ambient heat at around 700°F. conditions that might cause flexible Premature failure of thermocouples is a common probleads to fail. lem experienced by many operators. While it has been Another design type is a observed that some operators will jumper out a failed thermocouple probe, it is not a good practice. This leaves the control systhat has a junctem blind to that area of the engine and can lead to greater tion box head on issues. When looking at the failures that are experienced, it that attaches many can be traced back to problems with the installation. Failure to properly to a flexible There are a variety of root causes that can be attributed to ground rotating thermocou- thermocouple failures, including installation procedures and equipment can result in ple cable turbine conditions.
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TurBINE TECH Cold/warm engine installation When installing a replacement exhaust gas thermocouple (EGT) into a warm frame engine, the thermocouple must be allowed to warm up prior to being tightened into it. Many of the EGTs have the metal over sheath material made of Inconel, a nickel alloy. These are being installed into a radiation shield that is typically carbon or stainless steel (SST). The thermodynamic properties of these two materials are different, with the thermal growth coefficient of SST being larger than that of Figure 3. Thermocouple failure from unsecured cable Inconel. This can lead to seating issues with To verify the condition of the seat the thermocouple. in the radiation shield, a borescope If the EGT is being installed in a cold engine, a slight preload should be applied inspection should be performed. If the seat is found to have been worn to the thermocouple head to ensure that away, the radiation shield must be the EGT remains properly seated when replaced. This will likely need to be the engine warms up. performed during an extended outOne way to determine if you are age, as the radiation shield will need experiencing seating issues is to look at to be cut out of the plenum wall and the failed thermocouples upon removal. a new one oriented and welded in Looking at the bushing end of the EGT can tell you a lot about the cause of your place. Another failure point on an EGT premature failures. is the over tightening of the comIn Figure 1, we can see the wear on pression fitting used to secure the the bushing and sheathing. This fretting thermocouple. This is typically an is likely caused by the thermocouple not easy failure to diagnose and correct. If being seated properly into the radiation you are finding that your thermocoushield. When it is not completely seated, ples are breaking at the point of the the thermocouple will vibrate in the ferrule, then the likely culprit is the airstream, causing the thermocouple to over tightening of the Swagelok fitwear prematurely. If this is allowed to ting. While applying pressure on the continue over time with the installation of several thermocouples in this location, head of the thermocouple into the seat, tighten the compression fitting ¼ the seat of the radiation shield also will turn beyond hand tight, but no more begin to wear. As the seat of the radisince tightening by ½ turn or greater ation shield is worn away, the thermowill likely cause the thermocouple to couples will wear even faster and more break at the point of the ferrule. severely, as seen in Figure 2.
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TurBINE TECH
Figure 4. Proper cable strain relief
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Moving up the thermocouple, we also see failures caused by insufficient strain relief on the cable. This is particularly critical in the installation of the connectorized thermocouples, as the cable comes straight off the end of the thermocouple instead of at a 90-degree angle, as on the junction box style. If the cable is loose, the energy will be amplified and cause the thermocouple head to break, as seen in Figure 4. A proper installation will have the cable restrained by cable clamps to prevent the cable from excessive movement during operation. This will dampen the vibration and increase the life of both the thermocouple and mating cable. This can be seen in Figure 5. Even if you have installed your thermocouple correctly, you might still be experiencing failures that could be the result of another issue on your turbine. One of the biggest issues is caused by excessive heat that is likely a result of an exhaust gas leak due to a bad duct seal. While this is more prevalent on older engines, it has been observed on some new engines due to improper installation. If you have a bad leak, it will be easy to determine, since you will likely find the cable connector melted. When there is a small leak migrating under the insulation and exiting the hole by the thermocouple, it becomes more difficult to diagnose the cause. These leaks will often appear as a thermocouple problem, and once you replace the identified thermocouple the problem appears to go away for a while. With time, it might crop up again and again, creating a reliability nightmare. One of the key identifiers can be found by looking at the connector end of the thermocouple. If there is a black residue around one of the pins of the thermocouple, it might be originating from the connector on the cable end. Replacing the thermocouple will scrape this insulation material from the inside of the connector, making the new thermocouple appear to be the solution. However, the black residue is actually the insulation material from the cable connector that is migrating down into the thermocouple due to excessive heat and vibration. If it
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was only a failure caused by a bad thermocouple, the pins should be clean. There are several paths that can be taken to correct this type of failure. If the duct seal can be repaired or replaced at the next major outage, this should be done while also replacing both the affected cable and thermocouple. If the source of the high temperature can either not be identified or fixed due to commercial or operational considerations, a change of the thermocouple type might be warranted. The junction box style of thermocouples have a higher heat rating, and higher temperature aftermarket flexible thermocouple cables are available to further increase the cable operating temperature. For those areas that might be seeing in excess of 1,000°F, the semi-rigid thermocouple cable can be used. While it does not have the advantages of quick connections, it does offer an operating temperature in excess of 2,000°F. The cost of a failed thermocouple is far more than the price of the thermocouple. Loss of production, labor expenses and contract penalties following a turbine trip exceed the cost of the probes. Proper installation is a critical part of ensuring you are able to get the performance expected from your thermocouple. In addition to a good installation, check that the probes you specify are OEM qualified to ensure they have been designed and tested to meet the challenging performance requirements for your engine. ~
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Gregory Bray is a business manager for Ametek Power Instruments with more than 20 years of experience working on instrumentation for the gas turbine and nuclear market. You may contact him by emailing editorial@woodwardbizmedia.com.
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