EPRI: Seasonal readiness 11 • ASME: Wind turbines 17 • Data troubleshooting 26
ENERGY-TECH
MAY 2015
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Atomized Dust Suppression
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By Komandur Sunder Raj, Energy-Tech contributor
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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. Editorial views expressed within do not necessarily reflect those of Energy-Tech magazine or WoodwardBizMedia.
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Maintenance Matters
Coal handler adopts atomized dust suppression By Laura Stiverson, president, Dust Control Technology
26
Machine Doctor
Using transient data to troubleshoot an integrally geared turbocompressor vibration problem By Patrick J. Smith, Energy-Tech contributor
ASME FEATURE
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Seasonal readiness planning for power plants By Ray Champers, Electric Power Research Institute
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Managing power generating assets – Challenges and solutions
Inclusion of a simple dynamic inflow model in the Blade Element Momentum Theory for wind turbine application By Xiaomin Chen and Ramesh Agarwal, Washington University, Saint Louis, Mo.
INDUSTRY NOTES
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Editor’s Note and Calendar Advertisers’ Index Energy-Tech Showcase
ON THE WEB Energy-Tech University Summer School starts June 10-11 and will hold class again in July and August with instructor Tom Davis. Learn more about this educational series at www.energy-tech.com/summerschool. Cover image courtesy of Hendricks River Logistics.
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EDITOR’S NOTE
Summer school with ETU Keeping training short, sweet and effective Summer has almost arrived, and as much as I like to think of it as a calm, peaceful season in the year, the reality is it is often not calm at all. Between baseball schedules, soccer schedules, yard work, weddings and squeezing in some pool time, I often feel like we’re running even more during the summer than the school year. And this doesn’t even count the challenge of trying to keep my kids from forgetting their math facts and how to write in (relatively) complete sentences. Trying to find time to learn or do anything for myself – whether professionally or personally – is often a challenge, and I know I’m not alone in this dilemma. Which is why I’m so excited about Energy-Tech’s upcoming Summer School webinar course. During June, July and August, EnergyTech is going to offer three separate courses, two days each for two hours each day.You can sign up for one, two or all three courses and by the end of the summer you could have 12 PDH credits earned by just turning on your computer and logging into the course. The course dates and topics include: • June 10-11: Bearing Installation, Precision Fitting and Lubrication • July 8-9: Belt Drives – Installation, Precision Fitting and Lubrication • Aug. 12-13: Troubleshooting and Correcting Problems with Rotating Equipment Using Predictive Maintenance All three of these classes will be taught by Tom Davis with Maintenance Troubleshooting. Tom presented an hour-long webinar on pumps for Energy-Tech in October 2014 and we’re excited to have him teaching again. Go to www.energy-tech.com/summerschool for more information on the courses and registration. And while you’re there, check out some of Energy-Tech’s other upcoming technical courses, from Excel fundamentals to a turbine troubleshooting recap with Steve Reid.You can find it all at www.energy-tech.com, or looking at the calendar to the right. We know your schedules are busy. We know you want the best information and expertise to help keep your plants running. EnergyTech magazine has the experts, information and solutions you need. I hope you’re able to join us this summer. In the meantime, thanks for reading
CALENDAR May 7, 2015 Hurst Boiler Integrated CAD Solution webinar www.energy-tech.com/hurstCadsolution May 11-15, 2015 Advanced Vibration Analysis (AVA) Houston, Texas www.vi-institute.org June 10-11, 2015 Energy-Tech University Summer School Online Course: Bearing Installation, Precision Fitting and Lubrication, with Tom Davis www.energy-tech.com/summerschool 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 July 8-9, 2015 Energy-Tech University Summer School Online Course: Belt Drives – Installation, Precision Fitting and Lubrication, with Tom Davis www.energy-tech.com/summerschool Aug. 4-6, 2015 Excel I Webinar Course www.energy-tech.com/excel Aug. 12-13, 2015 Energy-Tech University Summer School Online Course: Troubleshooting and Correcting Problems with Rotating Equipment Using Predictive Maintenance Tools, with Tom Davis www.energy-tech.com/summerschool Aug. 18-20, 2015 Excel II Webinar Course www.energy-tech.com/excel Sept. 15-17, 2015 Steam and Gas Turbine Fundamentals www.energy-tech.com/turbines
Submit your events by emailing editorial@woodwardbizmedia.com.
Andrea Hauser
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MAY 2015
Upcoming webinars and Energy-Tech University Summer School Don’t miss these upcoming training opportunities available exclusively from Energy-Tech! Sign up today for Early Bird pricing! Group discounts also available! June 10-11 ETU Summer School: Bearing Installation, Precision Fitting and Lubrication Tom Davis, Maintenance Troubleshooting
The course will be held from noon to 2 p.m. CT each day and attendees will receive 4 PDH credit hours. Register at www.energy-tech.com/summerschool July 8-9 ETU Summer School: Belt Drives – Installation, Maintenance and Troubleshooting
Aug. 12-13 ETU Summer School: Troubleshooting and Correcting Problems with Rotating Equipment Using Predictive Maintenance Tools Tom Davis, Maintenance Troubleshooting
The course will be held from noon to 2 p.m. CT each day and attendees will receive 4 PDH credit hours. Register at www.energy-tech.com/summerschool Aug. 18-20 Excel II Webinar Course Register at www.energy-tech.com/excel
Tom Davis, Maintenance Troubleshooting
The course will be held from noon to 2 p.m. CT each day and attendees will receive 4 PDH credit hours. Register at www.energy-tech.com/summerschool Aug. 4-6 Excel I Webinar Course Register at www.energy-tech.com/excel
Visit our extensive webinar archive at
www.energy-tech.com/etu
Sept. 15-17 Steam and Gas Turbine Fundamentals – Webinar Series Sept. 22-24 Advanced Turbine Troubleshooting & Failure Prevention These intensive, 6-hour courses describe major failure modes that turbines experience. The fundamentals of steam and gas turbine design are covered in detail. In addition, predictive maintenance technologies and associated performance issues are discussed along with case studies that demonstrate turbine fundamentals. Register at www.energy-tech.com/turbines
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FEATURES
Managing power generating assets – Challenges and solutions By Komandur Sunder Raj, Energy-Tech contributor
Historical perspective in power generation Coal The U.S. has the world’s largest estimated recoverable reserves of coal expected to last 200 years. Coal has served as the predominant source of energy for electric power generation, and coal-fired power plants have been around for more than 60 years. Figure 1 shows the coal-fired generating capacity for different age groups. Plants less than 30 years old account for about 27 percent of the total generating capacity of about 319 GW. Plants in the 31- to 40-year-old group represent 37 percent of the total capacity, and the remain-
Figure 1. Coal-fired generating plant capacity and age groups
ing 36 percent is comprised of plants more than 40 years old. Almost 75 percent of the total capacity is accounted for by plants more than 30 years in age and 35 percent of the capacity is from plants more than 40 years old. Since the average plant life is about 40 years, plants more than 40 years old, especially those with low capacity utilization and low efficiencies, might be potential candidates for retirement. Figure 2 shows the life cycle of power generating assets. By the time the asset is commissioned, 95 percent of the total cost of ownership is already pre-determined. Since the life cycle of coal-fired power generating assets from concept through decommissioning is long, asset management has to be addressed early in the life cycle to prevent management issues during the latter part of the life cycle. Following the creation of the Environmental Protection Agency (EPA) in 1970, the emergence of nuclear energy, the 1973 oil embargo and other factors, the power industry landscape started to experience significant changes. Other energy sources In 1973, coal supplied 46 percent of the electricity while nuclear energy provided less than 5 percent. Oil and natural gas generated 35 percent and hydroelectric power accounted for the remainder. By 1983, as the prices of natural gas, and especially oil, increased more rapidly than coal prices, the share of coal-fired and nuclear-powered generation grew to 55 percent and 13 percent, respectively. During the past three decades, there have been dramatic changes in the power industry. Deregulation, environmental concerns with emissions and greenhouse gases from use of fossil fuels, aging coal-fired power plants, changes in demographics and the workforce, increased domestic production and relative changes in prices of coal, oil and natural gas, increased costs of complying with environmental regulations, continued uncertainties with the regulatory climate and changes in electricity demand, among other advances – were all factors that affected the use of coal in power generation, its share of the generation mix and the ability of power plant owners to effectively manage plant assets. Figure 3 shows the yearly capacity additions for different energy sources and the changes in the generation mix for the period 1969-2010, extracted from a database of capacity additions dating back to 1890. Figure 4 shows the same yearly capacity additions arranged by different age groups for the period 1890-2010. The following may be noted from Figures 3 and 4:
Figure 2. Life cycle of power generating assets
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FEATURES
Figure 3. Yearly capacity additions for different energy sources shown for period 19692010
Figure 4. Capacity addition by energy source for different age groups for period 18902010
Figure 5. Nameplate capacity and No. of units for different energy sources as of 2013
Figure 6. Generation mix from 2006-2016 for different energy sources
• From 1969-1974, there were significant gains in natural gas and nuclear generating capacity. • With more plants coming on-line, nuclear generating capacity increased from 1982-1990. • From 1984-1997, coal-fired capacity additions were generally on the decline, while natural gas capacity additions were increasing. • There were no new additions to nuclear capacity from 1991-2010, except through power uprates. • With new plants coming on-line, coal-fired capacity increased during 2004-2010. • From 1999-2010, natural gas capacity increased. • Since 2005, there has been substantial growth in wind capacity.
Current energy mix The nameplate capacity and number of units for each energy source, as of 2013, are shown in Figure 5. Natural gas with 5,700 units had the highest total capacity of approximately 488 GW, followed by 1,212 units of coal with a total nameplate capacity of about 330 GW. Nuclear ranked third
with 100 units with a total nameplate capacity of about 104 GW. Figure 6 shows the power generated from the different energy sources during the period 2006-2014, with projections through 2016. The differences in generation among the energy sources reflect the varying degrees of capacity utilization. In 2014, coal accounted for about 39 percent of the generation, followed by natural gas at 27 percent and nuclear at about 20 percent. Hydro and renewables combined amounted to about 13 percent.
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FEATURES The coal-fired units that were retired during 20102012 had an average net summer capacity of 97 MW with an average age of 57 years, and average capacity factor of 35 percent, well below the average capacity factor of 63 percent generating units for that period. Table 1 – Number of environmental equipment and impact upon capacity from 2003-2013
The Energy Information Administration (EIA) estimates that about 13 GW of coal-fired generating capacity will be retired this year. By 2020, this is expected to climb to 60 GW. The coal-fired units that are planned to be retired this year have an average summer nameplate capacity of 158 MW, considerably smaller than the average of 261 MW for other coal-fired units.
Challenges Based on the foregoing historical perspective and the current energy situation, the challenges in managing coal-fired power generating assets are highlighted in Figure 7. The following is a brief review of some of the key challenges: Size/Age As noted earlier, about 75 percent of the total coal-fired generating capacity is from plants more than 30 years old and more than 50 percent of coal-fired units are less than 300 MW in size. Capacity Factors As shown in Figure 8, capacity factors for coal-fired units have been declining. From 2008-2014, the average capacity factor decreased from 73 percent to 61 percent. Under-utilization of capacity or subjecting coal-fired units to sustained cyclic or load-following operation that deviate from normal modes of operation adversely affect their efficiency, reliability and availability.
Table 2 – Fuel, O&M costs (mills/kWhr) for nuclear, coal & natural gas from 1997-2012
Efficiency As can be seen from Figure 9, for the period 2001-2013, the average efficiency of coal-fired units remained essentially unchanged at an overall average of 32.9 percent, on a par with the efficiency of nuclear units at about 32.7 percent. The efficiency of natural gas units, on the other hand, has been increasing, averaging about 40 percent for the same period. Environmental Besides dealing with the issues of design, efficiency, size, age, capacity utilization, operation and maintenance, power plant owners have faced considerable environmental challenges that have impacted their ability to effectively manage their coal-fired generating units. They also have been installing environmental control equipment to comply with environmental regulations. Table 1 shows the equipment installed during the period 2003-2013 and the associated impact upon the net summer capacity of the power generating units.
Figure 7. Key challenges for coal-fired power generating asset management
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Figure 8. Capacity factors for different energy sources for period 2008-2014
Figure 9. Average efficiencies of coal, natural gas and nuclear power generating plants 2001-2013
Another challenge is the EPA’s Mercury and Air Toxics Standards (MATS) to meet stricter emissions standards. Some power plant owners have chosen to retire their units since it will be cost-prohibitive to retrofit to comply with the new standards. The EPA also has proposed carbon dioxide (CO2) targets (lbs/MWh) starting in 2020. The baseline year established is 2012 in proposing a target of 6 percent reduction in CO2 emissions and net heat rates (efficiency) for coal-fired power plants. While this is expected to be challenged, it will further exacerbate the already onerous burden placed on power plant owners, and could accelerate the pace of retirement of, especially, older and more inefficient units with low capacity utilization. Operation/Maintenance Costs Operation and maintenance costs associated with use of environmental equipment, as well as operation and maintenance costs associated with overall plant capacity, efficiency, reliability and availability have been significant for many power plant owners.
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Table 3 – Flue gas desulfurization equipment capital, O&M costs for 1997-2012
Table 2 shows the increases in the average installed capital cost, as well as the operating and maintenance cost for flue gas desulfurization (FGD) systems for the period 1997-2012. Table 3 shows the costs of fuel as well as operating and maintenance costs for nuclear, coal and natural gas units. Operation and maintenance costs have been increasing for all three energy sources. Current combined operation and maintenance costs for coal are around 24 percent, with fuel costs accounting for 76 percent of the total. For natural gas, the numbers are 15 percent for combined operation and maintenance and 85 percent for fuel. Lower operation and maintenance costs appear to favor natural gas units, but the degree of capacity utilization is dependent upon relative changes in the fuel costs.
This is the first of a two-part series on the challenges faced by power plant owners in managing power generating assets and the solutions to deal with the challenges. Managing power generating assets involves dealing with a whole host of issues that are not mutually exclusive and not necessarily compatible with one another. A holistic approach is necessary to effectively manage and optimize their value. The focus of this two-part series is on managing coal-fired power generating assets since they are currently the major source of power generation facing the greatest challenges. While several factors that will be explored in the series have seriously impacted the ability of coal-fired power plants to retain their dominance, they are expected to continue to be a very important part of the generation mix for the foreseeable future. This first part examines the historical perspective and background in the use of coal-fired power generating assets, the impact of other energy sources and the key challenges that need to be considered. The second part in the December 2015 issue of Energy-Tech will elaborate on some of the key challenges, and discuss solutions and initiatives, as well as an integrated approach for managing coal-fired power generating assets.
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Knowledge management A significant challenge to managing power generating assets is knowledge management. This deals with management of human resources, overall processes and technology. Changing demographics in the workplace, an aging workforce and attrition have resulted in loss of knowledge and experience. Knowledge management is an organized and concerted effort designed to capture, retain and build upon knowledge necessary for effective asset management. The challenge lies in maintaining a highly-skilled workforce by effectively utilizing knowledge of processes and taking advantage of the latest advances in technology, and the tools that it has to offer.
Summary This article discussed historical developments in the rise to dominance of coal-fired power generation, and the issues and challenges in managing these assets to retain their relevance as a vital part of the generation mix. In December, we will deal with some of the key challenges in depth, discuss solutions and initiatives, as well as an integrated approach to effectively manage coal-fired power generating assets. ~ Komandur Sunder Raj is founder and owner of Power & Energy Systems Services. He has 47 years of engineering and consulting experience in the power and energy industries, specializing in maximizing power generating asset value through workforce training, plant process performance optimization and developing/providing technological tools for performance monitoring/diagnostics. He has worked for GP Strategies Corp., New York Power Authority, Raytheon Engineers & Constructors, Burns & Roe and Stone & Webster Engineering Corp. Sunder Raj has authored, presented and published more than 40 papers and articles and is a life member of the American Society of Mechanical Engineers (ASME). He is a past chairman of the ASME Plant Operations and Maintenance Committee and the current vice chairman of ASME PTC-PM Performance Monitoring Guidelines Sub-Committee. He also is a speaker for the ASME Speakers Bureau. He has a bachelor’s degree in Mechanical Engineering and a master’s degree in Engineering Management. You may contact him by emailing editorial@woodwardbizmedia.com.
MAY 2015
FEATURES
Seasonal readiness planning for power plants By Ray Chambers, Electric Power Research Institute (EPRI)
In recent years, North American weather patterns have brought unexpected extremes, with record-setting summer high temperatures and unprecedented winter cold temperatures and snowfall levels. In 2011, the summer was the second hottest in U.S. history, with Dallas,Texas, enduring 70 days of 100°F plus temperatures. In the winter of 2014, American popular culture was introduced to the concept of the “Polar Vortex,” which brought temperatures much lower than typical for longer durations.This past winter saw days of sustained subzero temperatures across large portions of the Midwest and Northeast, more than 100˝ of snow in Boston, and significant snow and ice storms in Southern states unaccustomed to winter storms such as Georgia, Kentucky and Texas.
Seasonal readiness Weather and climate considerations have a significant impact on power plant operations and maintenance.To ensure that power plants are able to withstand unexpected weather conditions and continue to operate as needed, plant owners and operators need to initiate, well in advance of the season, inspection and maintenance activities that protect system components and prevent equipment damage and failure. An essential part of this planning involves “seasonal readiness,” which is the systematic and defined process, repeated on an annual cycle, to prepare plants for an upcoming season.The process includes preparations, execution, restoration and feedback mechanisms to ensure lessons learned are captured year after year to continue to improve the overall process. Figure 1 shows the overall cycle for seasonal readiness. In recent years, EPRI has conducted a number of research efforts to assist plant owners/operators in planning seasonal readiness activities. Seasonal readiness guideline One key EPRI project involved working with utilities around the country to compile best practices and lessons learned into a new Seasonal Readiness Guideline.The Guideline includes possible tasks to be included in summer and winter seasonal readiness, formulation of a seasonal readiness cycle for an operating fleet, development of the technical content and activities for seasonal readiness, and example tracking sheets and checklists. Winter readiness In the U.S., winter brings the most prevalent disruptive weather condition. Freezing conditions can occur in plant areas, with prolonged low temperatures that penetrate walls, insulation, ground depth, etc. In addition, winds that intensify the freezing process also are a consideration.
Figure 1. Annual Seasonal Readiness Cycle
As this article appears in the May issue of Energy-Tech Magazine, it is the ideal time for winter readiness activities.These activities are principally aimed at prevention of problems caused by temperature fluctuations, such as freezing and condensation formation in systems and spaces where they can create problems. Activities involve inspection and maintenance to ensure that heating provisions for spaces and equipment are functional and in the proper state of readiness. Even where designed and as-built measures are not provided, operating plants are well advised to maintain a number of portable heaters available for use. A meteorological phenomenon that is experienced once or twice per decade is the breakout of a very cold polar air mass to more southerly latitudes than is typical.This phenomenon, which has been called the Polar Express or Polar Vortex, can introduce temperatures much lower than typical for the southern latitudes, with long duration (several days to one week). If this weather pattern is accompanied by high winds, freeze protection measures can be severely compromised. In the winter of 2014, the Polar Vortex in the U.S. demonstrated that:
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FEATURES Freeze protection In addition to the Seasonal Readiness Guideline, EPRI also is developing tools for specific seasonal conditions affecting power plant operations. One new tool being developed provides guidance for component maintenance for freeze protection. This work grew out of the electric utility industry experience in 2014 with the Polar Vortex. When the Polar Vortex occurred in January 2014, it created fast-moving, extremely cold and protracted conditions. Typical preparations for cold weather were insufficient. Grid conditions became critical and all generation types — including coal-fired, gas turbines and nuclear — were affected. EPRI found that a number of mechanisms led to a freeze-up, including cold weather near or below plant design, wind accelerating line freeze-up, duration of conditions penetrating insulation, degraded insulation conditions, failed freeze protection circuits, moisture in the air creating freeze plugs, and hangers, brackets and bracing acting as sources of heat loss. Past practice and workplace culture can contribute to freezing risks. Months or years are required to correct chronic problems. EPRI recommends developing a programmatic approach to freeze protection. Such an approach would keep freeze protection circuits operable all year. PM deferral of freeze protection circuits requires a manager’s approval. Missing or damaged insulation is tracked. Insulation design standards are established to withstand area conditions. Freeze protection cable standards are established to ensure reliability. EPRI’s freeze protection activities include standards, guidelines and a maintenance basis for freeze protection systems. • Temperatures can fall up to 20°F or more below historical values for any given location and date. • The duration of these low temperatures can persist longer than average previous experiences. • The combination of significant wind velocities, coupled with the very low temperatures, can overwhelm properly functioning heat-tracing capabilities. • Even minor damage or compromise to thermal insulation can expose piping, tubing, etc., to freezing during these types of below-average or below-design-basis temperature excursions. Recognition of the possibility of encountering this phenomenon has signaled the need to modify and add to plant winterization procedures, alter plant O&M culture in terms of awareness, and consider retrofits of added protection, such as heated housings for instruments, more complete insulation coverage, etc.
Summer readiness Summer readiness involves preparation for elevated ambient temperatures and the prevalence of high levels of atmospheric 12 ENERGY-TECH.com
moisture (depending on local climate). Elevated summer temperatures have the potential to reduce output, degrade heat rate and create operational challenges for plant staff. High temperatures also result in shortened lives of equipment, degrading lubrication quality, electronic component failures, etc. High humidity, combined with elevated temperatures during the day, can result in condensation forming at night in unwanted places. Although the summer readiness process might have less urgency than winter readiness, the potential benefits are significant, and these measures should be undertaken with the same comprehensive attention to detail as the winter readiness activities. Summer readiness typically consists of cleaning and checking the condition of heat transfer equipment (both air and water cooled) to ensure peak performance during the summer months when temperatures are elevated. Failure to do so can result in decreased generation capability or unexpected alarms and trips due to high lube oil temperatures, etc. Examples of this type of activity include cleaning finned tube heat exchangers of accumulated dust/pollen/bugs to improve heat transfer, cleaning sumps and cooling tower fill of accumulated sludge and bio growth, etc. Temperatures of closed cycle cooling water and other closed fluid cooled by direct heat transfer (lube oil exiting from finned coolers) should be checked to determine if heat transfer is performing adequately.The real test will occur during the peak summer temperatures, but condition and performance during the transition can be an indicator of what lies ahead. Summer also can be a time of limitations on the ability to obtain adequate supplies of makeup water for plant operations.This is especially true in areas experiencing extended or severe periods of drought.
Other seasonal conditions In addition to winter and summer, a number of other seasonal conditions can affect power plant operations, including thunderstorms, hurricanes, tornadoes, flooding, drought, and wind and sand storms.The EPRI Seasonal Readiness Guideline lists some of the issues to be considered for each of these conditions. Best practices and lessons learned Seasonal issues should be well understood by plant operations and maintenance staff. But even a good understanding of normal weather patterns can leave a plant ill prepared when sustained below or above normal conditions plague a facility. Best practices that can be further developed into existing practices include: • Updating Computerized Maintenance Management System (CMMS) to generate seasonal readiness tasks and track their completion. • Utilizing CMMS to give priority status to seasonal deficiencies entered as future jobs. • Treating lagging, heat trace and enclosures as required components for completion of other maintenance tasks (job is not complete until heat trace, insulation, doorways and access points are restored to operational condition). • Verifying building penetrations are properly insulated and sealed from the elements.
MAY 2015
FEATURES • Developing hot and cold operating plans that include actions in the casualty control procedures to reflect impact of the conditions. • Developing contingency plans or actions for weather effects and incorporate into the emergency action planning. • Reviewing material condition of plant equipment, enclosures and barriers to weather as necessary to the operation of the plant. • Updating training requirements for operations and maintenance staff to include seasonal awareness. • Adding work steps to existing job aids to prevent maintenance activities from defeating protective functions (e.g., heat trace de-energized during freezing conditions, insulation removed and left off for extended periods).
People and culture issues Each facility will need to strengthen the understanding of operations and maintenance staff on the effects of their actions on freeze potential in plant systems. Prior to each winter season, staff should conduct a review of winterization practices to refocus daily activities where the potential for freezing conditions are most likely to occur. Management must be proactive in developing the culture at each facility where all elements are considered while preparing systems for weather extremes. Most effective programs are focused on inspection and repairs in the early spring and summer months in preparation for the next winter’s freezing conditions.
Discussions should focus on areas where other plants have had problems when operations and maintenance personnel lost focus on how weather affects plant operation. Areas include leaving doors, windows and wall openings ajar; workers climbing on lagging, damaging jacket and insulation; lagging removed and freeze protection circuits pulled away to access equipment for maintenance and not returned.
Conclusion Effective seasonal readiness can be achieved on a consistent basis by starting with a comprehensive initial assessment that provides the basis and supporting documentation for an annual cycle. Implementation, including sufficient contingency, creates a reliable generation resource to the grid, while minimizing hazards to personnel. Capturing lessons learned ensures that the seasonal readiness program is a “learning program’ that continuously improves. Adding to the programmatic element ensures that it not only continues to improve, but repeatedly supports reliable plant operations. ~ Ray Chambers is the program manager of EPRI’s Generation Maintenance Applications Center (GenMAC). His background includes 23 years with Progress Energy as a manager in various O&M management positions, including Plant general manager of the Robinson Nuclear Station. You may contact him by emailing editorial@woodwardbizmedia.com.
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MAINTENANCE MATTERS
Coal handler adopts atomized dust suppression By Laura Stiverson, president, Dust Control Technology
Located on the Mississippi River – just north of Keokuk, Iowa, and 970 miles from Gillette, Wyo., – Hendricks River Logistics (HRL) is a high-volume coal trans-shipping company servicing the Powder River Basin, exclusively supplying two utilities along the Mississippi River. According to General Manager Shawn Duer, the company’s location is a key to its operations, because historically it’s been efficient and relatively inexpensive to transport coal by barge. Because the PRB coal-burning utility clients of HRL also are located on or very near the river, the barges offload directly to the customer facilities. HRL has fleeting for 80 barges. Trains as long as 123 cars, loaded with sub-bituminous coal, make the 5.5-day round trip to HRL’s site. The train enters a 3-mile spur track off of the main BNSF line. Each car is unloaded using a rotary dumper, a large cylindrical framework with its own track, which braces onto the car with hydraulic clamps, then turns the car and track nearly 160 degrees, emptying the contents into a large hopper. The rotary dumping sequence takes about two to three minutes per car. The coal is then loaded onto conveyor belts leading to the stockpile, generating large volumes of dust when the load is discharged. “We generally do about 1.6 to 1.7 million tons of production per year,” Duer said. “PRB coal is inherently dusty, so we knew from the beginning that we needed some form of dust control to maintain air quality and keep the site free of particulate accumulation.” Duer’s team researched trade magazines for options and spoke to several sources before deciding to try a DustBoss™ Ring (DB-R) from Dust Control Technology (Peoria, IL). The conveyor leading from the stockpile to the barge dock is 1,100´ (335m) long, loading barges at a rate of 1,500 TPH (1,360 MTPH). Coal is directly discharged onto the barge through a 54˝ DB-R (137.2 cm), a circular, stainless steel manifold containing 30 specialized nozzles, which releases 18.9 GPM (71.54 LPM) in the form of millions of atomized droplets. The curtain of mist helps keep the dock, equipment and barges cleaner, with less fugitive dust settling on the water. The intrinsically safe design delivers continuous, effective suppression with no moving parts. The only maintenance required is periodic cleaning of nozzles as they accumulate minerals or other debris over time.
14 ENERGY-TECH.com
MAY 2015
MAINTENANCE MATTERS The DB-R creates an atomized mist of 50-200 micron sized droplets, which travel with the dust, absorbing the airborne particles and pulling them to the ground with little pooling or runoff. Water pressure is adjustable to match the fluctuations in dust volume dispensed from the belt. The size of the mist droplets does not change, regardless of pressure. Unlike sprinklers used by some facilities for dust management, which can distribute 300-500 GPM (1,1361,893 LPM), the lower water volume required for the DB-R means less material saturation and runoff. But the greatest drawback to sprinklers is droplet size: water droplets produced from sprinklers and spray bars are simply far too large to produce any meaningful benefit in controlling airborne dust particles. Atomized mist is a more effective option, which relies on the principle of creating millions of tiny droplets of a specific size and delivering them at relatively high velocity across a wide coverage area, inducing collisions with dust particles and driving them to the ground. The method has proven well suited for managing dust from a broad range of industries and applications, one of the few technologies capable of delivering dust control via airborne capture and surface wetting. “We initially purchased the DB-R for our 48˝ wide barge loading conveyor belt, and it did such an excellent job that we decided to get another one for our other main discharge point,” Duer said. The main discharge belt leads 1,000’ (304m) uphill from the rotary dumper. The belt is 60˝ wide with a material volume of as much as 3,000 TPH (2,721.5 MTPH), feeding into the 14-acre stockpile that is managed by bulldozer. The large 72˝ DB-R (182.9 cm) features 38 misting nozzles mounted on the conveyor 3’ below the discharge point, using about 24 GPM (90.85 LPM) of atomized water. “Visiting the site, we noticed the main discharge point was high enough for air currents to carry dust a long distance,” said Carl Harr, Senior Sales Technician for Dust Control Technology, manufacturer of the DustBoss line of
MAY 2015 ENERGY-TECH.com
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products. “It does twice the volume of the barge loader, but since it’s located on a hill, it creates greater potential for migration, so adding a new DB-R in that location was an excellent choice.” Options on the DB-R include a booster pump that can be added to increase water flow and pressure, as well as a 2-way valve that delivers manual control over the water flow. A variety of nozzle types and sizes are available to match droplet characteristics to specific material properties and operating environments. Units also can be supplied with a filter for use with non-potable water. The DB-R is currently available in nine different sizes, ranging from 17˝ (43.18 cm) to 100˝ (254 cm), and also can be ordered in custom sizes and shapes to suit specialized applications. Effective dust management has been cited by company officials as an important component of the facility’s environmental stewardship and regulatory compliance. By surrounding the discharge flow on all sides, the DustBoss Ring provides simple, focused dust management that’s well suited to continuous duty, such as radial stackers. With the two DB-Rs in place, HRL reports a significant reduction of fugitive dust across the entire work site. “We try to run the most efficient and environmentally responsible operation possible,” Duer said. “The DustBoss has become an essential part of that.” ~
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Laura Stiverson is the president of Dust Control Technology, where she has invested several years toward advancing the design and application of high-efficiency suppression equipment, helping customers in a wide range of industries manage fugitive dust and odor. Her primary responsibilities involve product engineering, business development and customer service. Stiverson holds a degree in biochemistry at the University of Illinois in Urbana. You may contact her by emailing editorial@woodwardbizmedia.com.
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MAY 2015
ASME FEATURE
Inclusion of a simple dynamic inflow model in the Blade Element Momentum Theory for wind turbine application By Xiaomin Chen and Ramesh Agarwal, Washington University, Saint Louis, Mo.
Introduction Because of recent emphasis on carbon free renewable energy, there has been great deal of research directed toward the design of aerodynamically efficient wind turbines. There are mainly two kinds of wind turbines: Horizontal-Axis Wind Turbines (HAWT) and Vertical-Axis Wind Turbines (VAWT). Between them, HAWTs are the most commercially deployed turbines all over the world since they are able to generate more electricity at a given wind speed, especially in large wind farm applications when the wind is intermittent.[1] In a previous paper, Chen and Agarwal [2] evaluated the effect of different airfoil sections on HAWT performance using the quasi-steady Blade Element Momentum (BEMqs) theory. The basic BEM theory assumes instant equilibrium of the wake when wind conditions change. This study focuses on modifying the quasi-steady BEM theory by including a simple dynamic inflow model developed by Henriksen et al. [3] to capture the unsteady behavior of wind turbines on a larger time scale. The new code is designated as BEMinflow. Brief overview of the Blade Element Momentum (BEM) Theory The BEM theory combines the momentum theory and the blade element theory briefly described below.[4] Momentum theory In the momentum theory, we consider the stream tube surrounding the wind turbine which is modeled as an actuator disc, as shown in Figure 1. Assuming steady, uniform, axisymmetric incompressible, inviscid flow with a nonrotating wake, the mass conservation in the stream tube gives the following relation:
Thus, we have: Equation 3
Equation 4
Figure 1. Actuator disk model of a wind turbine.[4]
Equation 1
where Ad is area of the actuator disk. Since the actuator disc induces velocity in the stream tube, an axial induction factor a is defined as:
Equation 2 Figure 2. Rotating annular stream tube.[4] MAY 2015 | ASME Power Division Special Section
ENERGY-TECH.com
17
ASME FEATURE Using equation (7), the torque in equation (8) can be expressed as:
Equation 9
Blade element theory In the blade element theory, the blade is assumed to be divided into n sections which are called the blade elements. It is assumed that there is zero aerodynamic interaction between the blade elements and there is negligible span-wise velocity component on the blade. The forces on the blade element are solely determined by the lift and drag characteristics of 2D airfoils of the blade element; lift and drag components are defined perpendicular and parallel to the relative wind speed direction. The total tangential velocity experienced by the blade element is (1+ a´) Ω r and the axial velocity is (1- a) U∞. The relative wind velocity at the blade is given by:
Equation 10
Figures 3 and 4. Airfoil data extrapolation using the original experimental data. Lift coefficient CL (top) and drag coefficient CD (bottom).
Applying the Bernoulli equation between points 1, 2 and 3, 4 we can derive the following expression for pressure difference across the actuator disk:
Equation 5
Thus, the net force normal to the plane on a ring of width dr in the actuator disk can be calculated as:
Equation 6
Next, we consider the rotating annular stream tube, shown in Figure 2. Defining an angular induction factor a´ as:
The angle between the relative wind velocity and the plane of rotation is given by:
Equation 11
where λr is the local tip speed ratio. The net force normal to the plane of rotation for each blade element and the resulting torque on each blade element can be written as: Equation 12
Equation 13
where dL and dD are the lift and drag forces on the blade elements respectively. They are defined as:
Equation 14 Equation 7
where ω is the angular velocity of the blade wake and Ω is the angular velocity of the blade, for a small elemental ring of width dr the torque can be obtained as:
Equation 15
For a multi-bladed wind turbine with B number of blades, one can write:
Equation 8 Equation 16
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ASME Power Division Special Section | MAY 2015
ASME FEATURE
Equation 17
Defining the local solidity as and replacing W in equations (16) and (17) using equation (10), equations (16) and (17) become:
Equation 18
Equation 19
Tip loss correction and modified BEM theory The original BEM theory does not include 3D characteristics of the flow and viscous losses due to separation and turbulence. Some modifications have been applied to the theory to take into account these losses. The modified BEM theory includes the tip-loss and hub loss with Glauert’s corrections.[5] These losses are calculated by the equations:
Equation 20
Equation 21
The net loss is given by: Equation 22
The Glauert’s empirical relation with a modification for the tip loss factor is given as:
Equation 23
where:
Equation 24
After considering the losses and Glauert’s correction, we obtain four equations – (25) and (26) derived from the momentum theory and (27) and (28) obtained from blade element theory as: Equation 25
MAY 2015 | ASME Power Division Special Section
ASME Power Division: Advanced Energy Systems & Renewables Committee
A Message from the Chair The Advanced Energy Systems and Renewables (ASME-AESR) Committee promotes innovative concepts concerning the design, operation, maintenance and planning of renewable energy technologies. These technologies include wind turbine, solar panels, geothermal, hydropower, energy storage and integration of the smart grid. There also is a special interest in small-scale renewable energy resources in ASME-AESR. One of the committee’s functions is to sponsor the Advanced Energy Systems & Renewable Energy track in the ASME Power Conference each year. The committee promotes authors to prepare technical papers in various topics and present them at the annual ASME Power Conference. Each year the committee receives numerous papers from authors all around the world with academic and industrial backgrounds. These papers are peer reviewed by qualified experts in the related fields. After being reviewed, the track chair conducts the final check on the paper’s technical merit and structure before the authors can present them at the ASME Power Conference. ASME PowerEnergy 2015 combines ASME’s most dynamic annual energy events serving the worldwide energy community: the ASME Power Conference, the 9th International Conference on Energy Sustainability, the 13th Fuel Cell Science, Engineering and Technology Conference, and the inaugural Nuclear Forum. It will be held in San Diego, Calif., from June 28-July 2, 2015. This year, the Advanced Energy Systems and Renewables track reviewed 44 abstracts and accepted 24 papers that will be presented at the ASME Power Conference. The number of papers presented in our track has grown exponentially the past few years. The technical merit of the papers also has evolved. We always appreciate new members on the board. If you’re interested in participating in ASME-AESR activities, feel free to contact me. This month’s ASME feature is an excellent example of the type of material presented during one of the technical sessions at the 2014 ASME Power Conference, held in Baltimore, Md. We hope that you enjoy it. Reza Arghandeh, Ph.D. University of California, Berkeley Berkeley, CA 94704 arghandeh@berkeley.edu
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ASME FEATURE Equation 26
Equation 27
Equation 28
By equating the force relation (25) and (27) and torque relation (26) and (28), the axial induction factor a and the angular induction factor a’ can be calculated. The process of calculating the induction factors is an iterative process described in Chen and Agarwal.[6] The induction factors are then used to calculate the angles of attacks and thrust for each blade element separately; this information is then used for the wind turbine performance analysis. The total power from the rotor is given by:
Equation 29
Simple dynamic inflow model The quasi-steady BEM Theory discussed above describes the steady state values of the induction factors and the pressure coefficient CP and the thrust coefficient CT. We denote the axial induction factor a, and the angular , ‘n’ denotes ‘normal’ meaning that it is an induction factor of the induced velocity normal to the rotor plane. In , ‘t’ denotes ‘tangential’ meaning that it is an induction factor of the induced velocity tangential to the rotor plane. The corresponding induced velocities and are assumed to settle to their stationary values instantly[3], which can be described as follows: Equation 30
Equation 31
where Vrel is the relative wind speed normal to the rotor plane. Now we introduce the simple dynamic inflow model due to Henriksen et al.[3]; in this model the tangential induced velocity is assumed to be quasi-steady given by equation (31). However, the induced axial or normal wind speed is computed by taking into account the variation in denote the averaged induced normal velocity with the temporal dynamics: Equation 32
where the time constant satisfies the equation:
Equation 33
Figure 5. Geometric properties of NREL Phase III wind turbine.
In equation (33), R is turbine radius. Solving equation (33) with the initial condition gives the following solution:
Equation 34
where
Equation 35
Thus, the induced axial (normal) wind speed states can then be obtained as follows:
Figure 6. Geometric properties of Risoe wind turbine.
20 ENERGY-TECH.com
ASME Power Division Special Section | MAY 2015
ASME FEATURE
Figure 7. Comparison of BEMqs calculations with test data for NREL Phase III wind turbine.
Figure 8. Comparison of BEMqs calculations with test data for Risoe wind turbine
ed to cover high angles-of-attack regimes. This study uses Viterna’s method [9] in AirfoilPrep v2.2 developed by NREL as the extrapolation tool to construct the CL and CD data between -180 and +180 degrees of angles of attack. The Reynolds numbers are chosen as some appro-
Equation 36
where
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Equation 37
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The above assumptions and the simple inflow model are valid if the dynamic inflow is not very large. This inflow model is incorporated in BEMqs to develop BEMinflow code, as described in [6].
Airfoil data preparation As described in [6], the iterative procedure for calculation of the induction factors requires the knowledge of aerodynamic characteristics (CL and CD) of the airfoils to determine the thrust coefficient CT. This study employs the airfoil shapes that include S809 [7] and NACA 632xx series [8] airfoils. The experimental data for these airfoils is available in the open literature for a range of angles-of-attack α (usually from -5 to 15 degrees) and Reynolds numbers Re [7, 8] . However, in the actual operation of a wind turbine, the blades experience very high angle-of-attack regimes. The currently available data needs to be expand-
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ASME FEATURE priate fixed numbers. Figures 3 and 4 show examples of airfoil data extrapolation for DU 91-W2-250 airfoil.
Results and discussion Validation of BEMqs analysis tool Before calculating the wind turbine power using the dynamic inflow model, BEMqs code validations are performed to assess its accuracy and efficiency. Three different wind turbines – NREL Phase II and Phase III and Risoe turbines are employed in the validation process. The calculated results are compared with the experimental data in Reference [7] and the BEM results of Ceyhan [10]. For
Table 2 – NREL Phase III Wind Turbine General Characteristics Variable
Value
Number of Blades
3
Turbine Diameter
10.06 m
Rotational Speed
71.3 rpm
Cut-in Wind Speed
6m/s
Control
Stall Control
Rated Power
19.8 kW
Root Extension
0.723m
Blade Set Angle
3 degrees
Twist
44 degrees (max.)
Chord
0.4572@ all span location
Airfoil
S809
Table 2 – NREL Phase III wind turbine general characteristics
Table 3 – Risoe Wind Turbine General Characteristics Variable
Value
Number of Blades
3
Turbine Diameter
19.0 m
Rotational Speed
35.6 and 47.5 rpm
Cut-in Wind Speed
4 m/s
Control
Stall Control
Rated Power
100 kW
Root Extension
2.3 m
Blade Set Angle
1.8 degrees
Twist
15 degrees (max.)
Root Chord
1.09 m
Tip Chord
0.45 m
Airfoil
NACA 63-2xx series
the sake of brevity, here we present the results for NREL Phase III and Risoe turbines. For the NREL Phase III wind turbine, Table 1 and Figure 5 provide the operating conditions and geometrical properties. For Risoe turbine, NACA 63-2xx series airfoils are used. Table 2 and Figure 6 provide the operating conditions and geometrical properties. Figures 7 and 8 show the comparisons of results with the experimental data [7] and the computations of Cehyan [11] for NREL Phase III and Risoe wind turbines respectively. These figures show that the BEMqs analysis tool employed in this study performs quite well in matching the experimental data. Inclusion of simple dynamic inflow model in BEMqs (The code BEMinflow) The code BEMinflow is employed to evaluate the influence of changes in wind speed and rotational speed of the rotor on power generation over a short time interval of interest due to intermittent wind conditions. In this study, we consider almost sudden change in the rotational speed of the rotor, a condition that always occurs during the startup stage of a wind turbine. The effect of this change in rotational operating condition at a fixed wind speed is simulated using both the BEMqs and the BEMinflow codes. The power generated by the NREL Phase III and Risoe wind turbines is computed under this sudden change in rotational speed. The wind speed of 12 m/s is chosen as the mean steady wind speed for the two turbines. We consider the startup stage of the wind turbines from zero rotational speed to desired rotational speed Ω (rad/sec), as given in Tables 1 and 2. In addition to the free-stream wind speed, the input operating condition to the codes is the turbine rotational speed Ω which is provided as a time varying function. The changes in Ω with time during an initial time period of rotation T are shown in Figure 9 for NREL Phase III turbine and in Figure 10 for Risoe wind turbine. Figures 11 and 12 respectively show the power generation from BEMqs and BEMinflow codes for NREL Phase III and Risoe turbines. Figure 9 describes the starting stage of NREL Phase III turbine at a fixed wind speed of 12m/s. The input rotational speed Ω changes from zero to the operating value of 71.3 rpm in a very short time. Figure 10 shows the change in rotational speed Ω for Risoe turbine from zero to the operating value of 47.5 rpm; the wind speed remains the same at 12m/s. Figures 11 and 12 show the change in output power generation of wind turbines due to sudden change in rotational speed. When Ω first reaches its operating value, the BEMqs and BEMinflow codes give slightly different results for power generation during the early stage, where the effect of sudden change in Ω from zero to its operating value is to increase the power generation from the turbine for a very short period before it slowly goes back to its steady state value, predicted by the quasi-steady BEM code BEMqs. This difference in the
Table 3 – Risoe wind turbine general characteristics
22 ENERGY-TECH.com
ASME Power Division Special Section | MAY 2015
ASME FEATURE predictions of BEMqs and BEMinflow is due to the capability in BEMinflow to account for sudden changes in flow conditions. Here we have only considered the effect of sudden change in rotational speed of the turbine. We have not considered the effect of changes in wind speed over certain time period; this aspect will be considered in our future work.
Conclusions The primary focus of this study has been to modify the quasi-steady BEM theory by including a simple dynamic inflow model to capture the influence of unsteady wind conditions on the power generation of wind turbines on sufficiently large time scales of the order of a few hours. The modified code BEMinflow was tested by considering the startup stage of wind turbines when their rotational speed increases from zero to the rated operational value; the free-stream wind speed was taken at a fixed value. The calculations showed that the modified BEMinflow code predicts a higher value for power generation during the early stage compared to the prediction from the quasi-steady BEM code. The results show the need for including a dynamic inflow model in evaluating the performance of a wind turbine because of the intermittent nature of wind velocity. ~ References 1. Energy-XS, “Vertical Axis Wind Turbines v/s Horizontal Axis Wind Turbines,” accessed from http://www.energyexcess.com/node/7 (10 June 2010). 2. Chen, X. and Agarwal, R., “Assessment of the Performance of Various Airfoil Sections on Power Generation from a Wind Turbine Using the Blade Element Momentum Theory,” International Journal of Energy and Environment, Vol. 4, Issue 5, 2013, pp. 835-850. 3. Henriksen, L.C., Hansen, M.H., and Poulsen, N.K., “A Simplified Dynamic Inflow Model and its Effect on the Performance of Free Mean Wind Speed Estimation,” Wind Energy, 2012, doi: 10.1002/we.1548. 4. Ingram, G., “Wind Turbine Blade Analysis Using the Blade Element Momentum Method,” Version 1.1, October 18, 2011. 5. Moriarty, P.J. and Hansen, A.C., “Aerodyne Theory Manual,” Technical Report No. NREL/TP-500-36881, January 2005. 6. Chen, X. and Agarwal, R.K., “Inclusion of a Simple Dynamic Inflow Model in the Blade Element Momentum Theory for Wind Turbine Applications,” ASME Paper Power 2014-32292, Proc. of the ASME 2014 Power Conference, Baltimore, 28-31 July 2014.
Figure 9. Input to BEMqs and BEMinflow codes for NREL Phase III wind turbine.
Figure 10. Input to BEMqs and BEMinflow codes for Risoe wind turbine.
Figure 11. Output from BEMqs and BEMinflow codes for NREL Phase III wind turbine.
Figure 12. Output from BEMqs and BEMinflow codes for Risoe wind turbine.
MAY 2015 | ASME Power Division Special Section
ENERGY-TECH.com
23
ASME FEATURE 7. Schepers, J. G. et al., “Final Report of IEA Annex XVIII: Enhanced Field Rotor Aerodynamics Database,” Technical Report ECN-C-02-016, Energy Research Centre of Netherlands, February 2002. 8. Bertagnolio, F., Sørensen, N.N., Johansen, J., and Fuglsang, P., “Wind Turbine Airfoil Catalogue,” Tech. Report No. Risø-R-1280(EN), Risø National Laboratory, Roskilde, Denmark, 2001. 9. Viterna, L.A. and Janetzke D.C., “Theoretical and Experimental Power from Large Horizontal Axis Wind Turbines,” NASA TM-82944, 1982. 10. Ceyhan, O., Sezer-Uzol, N., and Tuncer, I.H., “Optimization of Horizontal Axis Wind Turbines by Using BEM Theory and Genetic Algorithm,” Proc. of the 5th Ankara International Aerospace Conference, METU, Ankara, Turkey, 17-19 August, 2009.
Acknowledgement The authors are grateful to Professor Ismail Tuncer of Middle East Technical University in Ankara, Turkey, for
providing the BEM code developed by his student O. Ceyhan. Editor’s note: This paper, PWR2014-32292, 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. Dr. Xiaomin Chen received a Ph.D. in Mechanical Engineering from Washington University in St. Louis, Mo., in 2014. He is currently employed at Denso International America Inc. in Detroit as Design Engineer II. His expertise is in Computational Fluid Dynamics and its industrial applications. You may contact him by emailing editorial@woodwardbizmedia.com. Dr. Ramesh Agarwal is the William Palm Professor of Engineering at Washington University in St. Louis, Mo. His research interests are in Computational Fluid Dynamics and its industrial applications. You may contact him by emailing editorial@woodwardbizmedia.com.
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MACHINE DOCTOR
Using transient data to troubleshoot an integrally geared turbocompressor vibration problem By Patrick J. Smith, Energy-Tech contributor
The causes of rotating machinery vibration problems are not always obvious. While the data that is typically monitored might be sufficient to monitor the machinery condition, in many cases it is not sufficient to determine the cause of vibration problems. Transient startup and shutdown data can be very useful in determining the causes and corrective action of high vibration in turbomachinery. The purpose of this article is to present a case study of a chronic problem with high vibration in an integrally geared turbocompressor and how transient startup and shutdown data was useful in evaluating the cause and corrective action.
Introduction This case study pertains to a dual service integrally geared centrifugal compressor driven by a 1,485 RPM, 6,900 KW induction motor. The gearbox consists of a bullgear and two rotors. The low speed (LS) rotor consists of a pinion operating at 10,472 RPM with impellers mounted at each end. The LS rotor comprises the first two stages of the main air compressor (MAC) service. The high speed rotor (HS) consists of a pinion operating at 15,126 RPM, also with a double overhung impeller configuration. The HS rotor comprises the 3rd stage of the MAC service and the single stage booster air compressor (BAC) service. The compressor configuration is shown in Figure 1. The gearbox utilizes tilting pad journal pinion bearings. There are single non-contacting proximity type vibration
probes mounted in the air seals behind the LS and HS impellers. Both pinions are fitted with thrust collars that are used to transmit pinion axial thrust to the bullgear. The thrust bearings are on the bullgear rotor, as shown in Figure 1. The bullgear journal bearings are a cylindrical sleeve type and the thrust bearings are a tapered land type. There are no vibration probes on the bullgear rotor. The air and oil seals are stationary labyrinth types. The main drive coupling is a flexible disc type.
History After the compressor was commissioned, it was put into continuous operation. The MAC 1st and 2nd overall vibration levels were approximately 0.6 mils p-p, which was consistent with the shop test vibration levels. After approximately 3½ years of stable vibration levels, the 2nd stage vibration started trending up. Over 6 months the vibration gradually increased to 1.2 mils. The 1st stage vibration was unchanged. The plant operators observed that the vibration was sensitive to oil temperature. When the oil supply temperature was increased from the normal 43°C to 54°C, the 2nd stage vibration decreased to 0.8 mils. The vibration levels on all other stages were unchanged. The operators also reported that the vibration was sensitive to load. Higher loads caused higher 2nd stage vibration levels. The other stage vibrations were unaffected by load. During the next 5 months the compressor was operated with an elevated oil supply temperature in order to suppress the 2nd stage vibration, but vibration slowly trended up back up to 1.1 mils. A spectrum analysis showed that most of the vibration was at a frequency of one times (1x) running speed. During this time period there was also an issue with frequent oil filter pluggage. Although oil testing did not reveal any abnormalities, the oil was replaced after draining and cleaning the reservoir. Due to the increasing 2nd stage vibration, the compressor was shut down to inspect
Figure 2. Compressor configuration
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MACHINE DOCTOR the 2nd stage impeller and pinion bearing. There was heavy fouling on the 2nd stage impeller, which was cleaned. There also were significant varnish deposits found on the bearing and journal, but no significant wear or damage. See Figure 2. The varnish deposits were cleaned and the bearing was re-installed. It was concluded that high residual unbalance due to the fouling, and tighter bearing clearance due to the varnish deposits were the causes of the vibration increase. However, when the compressor was restarted, the 2nd stage vibration was 1.4 mils higher than before the repair. The 1st stage vibration was unchanged. Due to customer demand, the compressor continued to operate. During the next 6 months, the 2nd stage vibration slowly increased to 1.7 mils and then stabilized. The oil supply temperature remained elevated at about 50째C. The 2nd stage vibration remained stable for approximately 3 years, but then slowly increased to 2.0 mils and was more erratic. The compressor was shut down and again the 2nd stage impeller had some fouling and there were varnish deposits on the bearing and journal. However, there also was some back of pad bearing wear, and this necessitated replacing the bearing. The 2nd stage impeller and bearing journal also were cleaned. When the compressor was restarted however, the 2nd stage vibration level actually increased to 2.4 mils and the 1st stage vibration increased slightly to 0.8 mils. During the next three months the 2nd stage vibration increased to 2.7 mils. There was no change in the 1st stage vibration. The compressor was shut down for a third time and this time the rotor and both pinion bearings were replaced. In preparation for this work, the spare rotor was sent to a local shop for a low speed balance. After the outage, the 1st stage vibration fell to 0.3 mils, but the 2nd stage vibration remained at approximately 2.7 mils. The vibration was reduced to 2.2 mils by increasing the oil supply temperature to 56째C. Again, a spectrum analysis showed that most of the vibration was at 1x running speed. Although high residual unbalance is the most common cause of 1x vibration, there are other causes such as tight bearing clearances, journal and bearing misalignment, a rotor bow, casing distortion, a structural or rotor bearing resonance, etc. And the sensitivity to oil temperature and load suggested that there could be something other than just unbalance. Regardless, lowering the residual unbalance should still reduce
the overall vibration amplitude. So it was decided to perform a transient vibration analysis to better understand the possible causes of the high vibration, followed by a field balance.
Discussion In preparation for the transient analysis, additional vibration probes were installed on the 1st and 2nd stage. These probes were mounted 90 degrees apart from the existing probes, creating an x and y configuration for both stages. In addition, the compressor was already fitted with LS pinion key phasor probe that was wired to a local transmitter box. The use of the x and
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MACHINE DOCTOR
Figures 2a and 2b. There also were significant varnish deposits found on the bearing and journal, but no significant wear or damage
Figure 3
Figure 4
y probes and the key phasor probe allowed the following transient startup and shutdown plots to be generated. • Bode/polar • Cascade/waterfall • Shaft centerline • Orbit (steady state plot) GE was contracted to collect the data. The scope of work included connecting the vibration and key phasor probes to an 28 ENERGY-TECH.com
ADRE 408 with 990 Adaptors and then collecting startup, shutdown and steady state data. To understand the effect of oil temperature changes on vibration, vibration amplitude and phase were recorded while reducing the oil temperature from 57°C to 50°C. As shown in the plot in Figure 3, the vibration amplitude increased by approximately 0.5 mils, but there was no change in phase angle. The phase angle is the angular difference between the location of the reference mark seen by the key phasor probe and the angular location of the maximum shaft displacement (heavy spot) during one shaft rotation. A change in phase angle would indicate that the vibration increase could be due to something other than unbalance and would also make field balancing more difficult, since the angular location of the heavy spot would change with oil temperature. In a similar way, to understand the effect of load changes, vibration amplitude and phase were recorded while reducing the load from the 100 percent normal load to 30 percent normal load. The amplitude decreased from approximately 0.5 mils, and again there was no change in phase angle. After this the compressor was shut down and the transient shutdown data was collected and reviewed. A Bode plot is a measure of shaft amplitude and phase as a function of time. This plot can be useful in identifying rotor MAY 2015
MACHINE DOCTOR natural frequencies by locating the peak in vibration amplitude that corresponds to a phase shift of approximately 180 degrees. In preparation for the field test, the Bode plot from the original shop test was reviewed along with the results from the lateral rotordynamic analysis. The shop test results showed a natural frequency of approximately 7,800 CPM with an amplification factor of about 3.5. This was conFigure 5 sistent with the lateral rotordynamic analysis. The amplification factor is a measure of the severity of a vibration response due to unbalance when operating in the vicinity of a lateral critical speed. It also provides an indication of the amount of damping that is present. An amplification factor less than 5 generally indicates that the system is not sensitive to unbalance when operated in the vicinity of the natural frequency and that the system is well Figure 6 damped. The shutdown Bode plot is shown in Figure 4. The rotor critical speed is not obvious on this plot, but it does indicate that the system is well damped. However, the shutdown Bode plot shows a vibration response the moment the compressor was tripped. This was further evaluated using a waterfall plot. A waterfall plot is a series of spectrum plots taken over a period of time. As shown in Figure 5, there is a sub-synchronous peak at 1,031 CPM and harmonics of this that appear the moment the compressor is tripped. This frequency corresponds to the torsional natural frequency. It is likely that the torsional natural frequency was being excited on coast down. Since there were no issues with the motor, coupling or bullgear and this condition probably existed since the commissioning, it was concluded that this probably was not a problem and was not a cause of the high 2nd stage vibration. A polar plot is the same data as a Bode plot, but in a different format. Sometimes it is easier to evaluate the critical speeds in this format. However, the lateral critical speed was also not obvious on the shutdown polar plot either. See Figure 6. A centerline plot is a designed to show changes in the average position of the shaft. Shaft centerline plots taken over long periods of time can be used to evaluate bearing wear. The startup and shutdown shaft centerline plots also can be used
Figure 7
to evaluate if the rotor moves to the expected position in the bearing and if there are any possible issues with rotor/bearing misalignment. The shutdown centerline plot is shown in Figure 7. There were no concerns identified with this plot.
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MACHINE DOCTOR A shaft orbit is the dimensional path of the shaft centerline in the bearing. These plots can be useful in identifying possible rubs, instabilities, excessive bearing preload, rotor/bearing misalignment, resonances, etc. The orbit that was recorded for this machine prior to shutting down is shown in Figure 8. There were no concerns identified with the orbit. It was concluded that the most likely cause of the high 2nd stage vibration was high residual unbalance. The field balance procedure and results will be discussed in an upcoming EnergyTech article.
Figure 8
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Conclusion The compressor that is the subject of this article had been shutdown three times to correct a vibration problem and each attempt failed. Although there was a reasonable degree of confidence the problem was due to high residual unbalance and could be corrected by field balancing, the data available was limited and wasn’t convincing. Collecting and evaluating additional vibration data immediately prior to field balancing would not only aid in field balancing, but also would provide the data needed to evaluate other causes in case the problem wasn’t due to high residual unbalance. Transient startup and shutdown data can be extremely useful in evaluating turbomachinery vibration problems. In this case, the Bode and polar shutdown and startup plots did not show any severe lateral resonance that could point to a rotor/ bearing problem. There was a possible torsional resonance that was identified on the shutdown waterfall plots, but this wasn’t considered a problem. And the shaft centerline plots and orbits didn’t show any indications of rubs, instabilities, excessive preload, rotor/bearing misalignment or resonances. So, there was a higher degree of confidence that high residual unbalance was the cause of the high vibration and that field balancing would correct the problem. ~ References 1. Jackson, Charles, “The Practical Vibration Primer,” Reliabilityweb.com, 2013 2. Marscher, William D. and McGinley, James J., “Vibration Troubleshooting of an Air Compressor,” Sound and Vibration Magazine, May 2006 3. Wilcox, Ed, “Troubleshooting Turbomachinery Using Startup and Coastdown Vibration Data,” Proceedings of the ThirtyFirst Turbomachinery Symposium, 2002.
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Patrick J. Smith is lead machinery engineer at Air Products & Chemicals in Allentown, Pa., where he provides technical machinery support to the company’s operating air separation, hydrogen processing and cogeneration plants. You may contact him by emailing editorial@woodwardbizmedia.com.
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