October 2014 by Energy-Tech Magazine

Bloch: Pump Life Stats 5 • Electric Process Heaters 8 • Biocoal Tests 12

ENERGY-TECH

OCTOBER 2014

A WoodwardBizMedia Publication

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Dedicated to the Engineering, Operations & Maintenance of Electric Power Plants In Association with the ASME Power Division

Handle ash waste without water

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ENERGYT ECH P.O. Box 388 • Dubuque, IA 52004-0388 800.977.0474 • Fax: 563.588.3848 Email: sales@WoodwardBizMedia.com www.energy-tech.com 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 © 2014 WoodwardBizMedia. All rights reserved; reproduction in whole or in part without permission is prohibited.

FEAtUrEs

By Heinz P. Bloch, P.E.

Editorial Board (editorial@WoodwardBizMedia.com) Kris Brandt – Rockwell Automation Bill Moore – Director, Technical Service, National Electric Coil Ram Madugula – Executive Vice President, Power Engineers Collaborative, LLC Kuda Mutama – Engineering Manager, TS Power Plant

CoLUMNs

Creative/Production Manager Hobie Wood – hwood@WoodwardBizMedia.com Graphic Artist Valerie Vorwald – vvorwald@WoodwardBizMedia.com Address Correction Postmaster: Send address correction to: Energy-Tech, P.O. Box 388, Dubuque, IA 52004-0388 Subscription Information Energy-Tech is mailed free to all qualified requesters. To subscribe, go to www.energy-tech.com or contact Linda Flannery at circulation@WoodwardBizMedia.com Media Information For media kits, contact Energy-Tech at 800.977.0474, www.energy-tech.com or sales@WoodwardBizMedia.com. Editorial Submission Send press releases to: Editorial Dept., Energy-Tech, P.O. Box 388, Dubuque, IA 52004-0388 Ph 563.588.3857 • Fax 563.588.3848 email: editorial@WoodwardBizMedia.com. Advertising Submission Send advertising submissions to: Energy-Tech, 801 Bluff Street, Dubuque, Iowa 52001 E-mail: ETart@WoodwardBizMedia.com.

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Regulations Compliance

Taking the water out of ash handling By Jim Sutton and Mike Tanca, Alstom Power

Mr. Megawatt

Data reconciliation By Frank Todd

Turbine Tech

Important considerations in establishing combustion turbine blade and vane refurbishment intervals By Stephen R. Reid, P.E., TG Advisers Inc.

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

Technical growth of electric process heaters By Craig Tiras, P.E., and Gaurav Dhingra, Gaumer Process

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

Process pump life assessed from published statistics

AsME FEAtUrE

Torrefied-biomass for the 600MW Boardman Power Plant By Ezra Bar-Ziv, Michigan Technological University, Roman Saveliev, EB Clean Energy, Ltd., Jaisen Mody, Portland General Electric Co., Miron Perelman, Michigan Technological University

iNdUstrY NotEs

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oN tHE WEB Learn from the comfort of your laptop! Energy-Tech has a growing library of webinars, white papers and case studies you can download for free. Visit www.energy-tech.contentshelf.com. Cover photo contributed by Alstom’s Boiler Service Organization.

OCTOBER 2014

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Editor’s Note

Windy City redux Energy-Tech University holds a pre-holiday session This past March, Energy-Tech magazine moved into new territory, putting on a three-day training seminar in Chicago. There were a variety of topics available for attendees, but the most popular by far were the courses about turbine maintenance, with Steve Reid from TG Advisors. In an effort to reach even more people, Reid also taught two online courses for Energy-Tech University this past August, which also had great turnout and feedback from attendees. It’s seldom you can have too much of a good thing – especially when it comes to good technical training - so we’re hosting another opportunity to see Reid in-person, as he teaches Gas and Steam Turbine Reliability – Failure Prevention and Life Extension, with Energy-Tech University. The seminar will be held Dec. 3-5 at the Hilton Suites on Chicago’s Magnificent Mile, about a block from the Water Tower Place – and all the holiday shopping that entails. Registration cost is $1,800 and includes breakfast and lunch, with dinner on your own.You can find more details at energy-tech.com/etu. If you weren’t able to join us in March, I hope you can make it to this session. It is definitely worth the time, effort and investment in your professional training. But if you can’t, we plan to try to make up the difference with technical webinars and online training opportunities throughout the rest of this year and into 2015. From our articles in the magazine to our website to our social media pages – our goal is to help you stay up-to-date on the latest ideas and solutions in the industry. We know you’re busy, that the demands of the power industry are dynamic and sometimes unpredictable. But information is power, so our goal is to give you the information you need conveniently – whether in in print, online or in person. I hope you’re able to join us for a training session or technical webinar in the coming months. And as we continue to plan for 2015, let me know which topics you would like to see more of next year. I always enjoy hearing from our readers – email me at ahauser@woodwardbizmedia.com. And in the meantime, thanks for reading.

Andrea Hauser

ENERGY-TECH.com

CALENDAR Oct. 14, 2014 E/One webinar: Large Turbo-Generators Hydrogen Auxiliary Systems 101, with Steve Kilmartin, E/One Energy Systems www.energy-tech.com Oct. 26-28, 2014 Power Plant Management & Generation Summit Atlanta, Ga. www.ppmgsummit.com/mp_et Oct. 30, 2014 Energy-Tech webinar: Best Maintenance Practices to Rebuild an ANSI End Suction Pump, with Tom Davis www.energy-tech.com Nov. 3-4, 2014 CCGT 2014: O&M and Lifecycle Management for CCGT Power Plants Houston, Texas www.tacook.com/ccgt-usa Nov. 11-14, 2014 Advanced Vibration Control Syria, Va. www.vi-institute.org Dec. 3-5, 2014 Turbine-Generator Troubleshooting and Failure Prevention, with Energy-Tech University Chicago, Ill. www.energy-tech.com/ETU Dec. 9-11, 2014 Power-Gen International Orlando, Fla. www.power-gen.com

Submit your events by emailing editorial@woodwardbizmedia.com.

OCTOBER 2014

FEATURES

Process pump life assessed from published statistics By Heinz P. Bloch, P.E.

Throughout the world’s many industry segments centrifugal process pumps are, without a doubt, the preferred fluid movers. Hundreds of millions of centrifugal pumps make up the bulk of these well-understood machines. Millions are built to comply with particular industry standards, such as ISO (International Standards Organization), ANSI (American National Standards) and API (American Petroleum Industry). It has been estimated that pump drivers consume more energy than all the lighting and illumination devices in service worldwide. But the run-time before repair of the many different styles and sizes of pumps can vary greatly, and all kinds of variables will enter the picture. Moreover, what is thought of as a reasonable run length for observer “A” might be considered unacceptable by observer “B.”

Examining pump repair records and MTBF While aiming for exact numbers is rarely a fruitful pursuit, we nevertheless find good guidance in books. Also, we can reach back into decades of applicable experience and record-keeping for probable repair frequencies in certain industry segments. In general, these records include failure listings that can be readily translated into mean-time-between-failure or “MTBF.” (Ref. 1) Statistics serve many purposes and their relevance is sometimes disputed by parties that score below average on such tabulations. To ward off disputes or arguments about the validity of statistics, many of the best practices used by plants in the time period leading up to the early 2000s simply took all their installed pumps, divided this number by the number of repair incidents, and multiplied it by the time period being observed. For a well-managed and reasonably reliability-focused U.S. refinery with 1,200 installed pumps and 156 repair incidents in one year, the MTBF would be (1,200/156) = 7.7 years. The refinery would count as a repair incident the replacement of parts – any parts – regardless of cost. In this case, a drain plug worth $4.70 or an impeller costing $15,000 would show up the same way on the MTBF statistics. Only the replacement of lube oil would not be counted as a repair. The best-practices plant’s total repair cost for pumps would include all direct labor, materials, indirect labor and overhead, administration cost, the cost of labor to procure parts, and even the prorated cost of pump-related fire incidents. There are references to the stated average cost of pump repairs: $10,287 in 1984 and $11,000 in 2005. We believe this indicates, in relative terms, a repair cost reduction, because a dollar in 2005 bought considerably less than a dollar in 1984. It can be reasoned that predictive maintenance and similar monitoring having led to a trend toward reduced failure severity. Chances are that

Figure 1. Target performance values for mechanical seals (Refs. 2 and 3)

Table 1 – Process Pump Mean-Times-Between-Failures ANSI pumps, average, USA:

2.5 years

ANSI/ISO pumps average, Scandinavian P&P plants:

3.5 years

API pumps, average, USA:

5.5 years

API pumps, average, Western Europe:

6.1 years

API pumps, repair-focused refinery, developing country:

1.6 years

API pumps, Caribbean region,

3.9 years

API pumps, best-of-class, U.S. Refinery, California:

9.2 years

All pumps, best-of-class petrochemical plant, USA (Texas):

10.1 years

All pumps, major petrochemical company, USA (Texas):

7.5 years

repairing a somewhat typical, 25-30 kW, average-service APIcompliant refinery pump in 2014 will cost in the vicinity of $14,000. Again, this would include the overhead percentages found in Ref. 1. Using the same bare-bones measurement strategy and from published data and observations made in the course of performing maintenance effectiveness studies and reliability audits in the late 1990s and early 2000s, the mean-times-between-failures of Table 1 have been estimated.

Other studies of pump statistics In early 2005, Gordon Buck (then John Crane Company’s Chief Engineer for Field Operations in Baton Rouge, La.) examined the repair records of a number of refineries and chemical plants. He obtained meaningful reliability data for centrifugal process pumps; he included in his survey a total of 15 operating plants having nearly 15,000 pumps. The smallest of these plants had about 100 pumps; several plants had more

OCTOBER 2014 ENERGY-TECH.com

FEATURES traditionally been “throw away” items because chemical attack limited pump life. Things have improved in recent years, but the limited space available in DIN and ASME (American Society of Mechanical Engineers) stuffing boxes does limit the type of seal that can be fitted in the more compact and simple pump versions. Lifetimes in chemical installations are generally believed to be around 50-60 percent of the refinery values.

Target pump and component lifetimes Based on the lifetime levels being achieved in practice in 2000, and combined with the known “best practice” as outlined in available reference texts, the target component lifetimes of Table 3 are recommended and should be considered readily achievable. It should again be emphasized that many plants are achieving these levels. Nevertheless, to reach these pump lives, the pump components themselves must be operating at the highest levels. An unsuitable seal with a lifetime of one month or less will have a catastrophic effect on pump MTBF, as would a badly-performing coupling or bearing.

Figure 2. Lip seal (top) and advanced rotating labyrinth seal (bottom). Source: AESSEAL, Rotherham, UK and Rockford, TN

Table 2 – Suggested Refinery Seal Target MTBFS Target for seal MTBF in oil refineries Excellent

>90 months

Very good

70/90 months

Average

70 months

Fair

62/70 months

Poor

<62 months

than 2,000 pumps and all plants were located in the United States. Also, all plants had some sort of pump reliability program in progress. Some of these programs could be considered as “new;” others as “renewed” and still others as “established.” Many of these plants, but not all, had an alliance contract with the John Crane Company. In some cases, the alliance contract included having a John Crane technician or engineer on-site to coordinate various aspects of the program (Ref. 3). Not all plants are refineries, however, and different results can be expected elsewhere. In chemical plants, pumps have 6

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Other pump and mechanical seal statistics of interest Some statistics are of interest to many people. Certain statistics are relevant to particular readers while others might not be. Some statistics are misleading and some are highly accurate. Here are a few that you might want to ponder. For the year 2004, the U.S. Census Bureau reported 8,535,920 centrifugal pumps shipped, with a value of $1,572,298,000. That’s quite a number of pumps, but with the average value per pump at only $184 we are obviously not dealing with process pumps in this situation. So, we really don’t know what to do with this data. In other words, we’ll have to look elsewhere to find out about refinery pump life and component failure data. Figure 1 shows combined MTBF values based on more than 12,000 seals in 36 refineries. It includes upper and lower quartile numbers that are useful for suggesting target performance values (Table 3). Mechanical seal life in best practices refineries deserve to be singled out. At least one major refinery on record has obtained a yearly seal MTBF in excess of 10 years (Ref. 2, pp. 475). Bearing protector seals Literature dealing with pump reliability improvement has often made the case for bearing housing protection seals or “bearing isolators.” Unlike wear-prone lip seals, rotating labyrinth and magnetically activated face seals are essential for reliability-focused plants. Advanced bearing protector seals often provide full payback within weeks. Suppose you used some of these devices (Figure 2) in your process pumps and larger electric motors? With a well-established manufacturer of rotating labyrinth bearing isolators having sold “only” a total of perhaps 2.5 million (traditional) rotating labyrinth style bearing protector seals in perhaps two decades, imagine how many hundreds of OCTOBER 2014

FEATURES millions of motors and pumps out there are still begging for cost-justified bearing housing protection! Along the same lines of thought, examining available process pump statistics must be deemed valuable. Making a comparison allows pump owners to see where they fit in and to aim toward having fewer failures or outages than the “average” process pump user. ~

References: 1. Bloch, Heinz P.; “Pump Wisdom: Problem Solving for Operators and Specialists,“ ISBN 978-1-118-04123-9; John Wiley & Sons, Hoboken, NJ 2. Bloch, Heinz P. and Budris, Allan R.; “Pump User’s Handbook: Life Extension,” (2013) 3. Fourth Edition, ISBN 0-88173-720-8; Fairmont Publishing Company, Lilburn, GA 4. Wallace, Neil, and David, M.T.J.; “Pump reliability improvements through effective seals and coupling management”, presented at 15th International 5. Pump Users Symposium, Texas A&M University, Houston, Texas, 1998 Heinz P. Bloch is a consulting engineer residing in Westminster, Colo. He has held machinery-oriented staff and line positions with Exxon affiliates in the U.S., Italy, Spain, England, The Netherlands and Japan in a career spanning several decades prior to retirement as

Table 3 – Realistic Target Pump and Component Lifetimes Seals

Refineries

Chemical and Other Plants

Excellent

90 months

55 months

Average

70 months

45 months

Membrane type

120 months

Gear type

>60 months

Coupling All plants Bearings All plants

Continuous operation

60 months

Spared operation

120 months

Based on series system calculation

48 months

Pumps

(Note that “target” is less than “best actually achieved.”)

Exxon Chemical’s Regional Machinery Specialist for the U.S. Bloch is the author of 18 comprehensive texts and more than 500 other publications on machinery reliability improvement. He advises process plants worldwide on equipment uptime extension and maintenance cost reduction opportunities. He is an ASME Life Fellow and maintains registration as a professional engineer in Texas and New Jersey. You may contact him by e-mailing editorial@woodwardbizmedia.com.

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FEATURES

Technical growth of electric process heaters By Craig Tiras, P.E., and Gaurav Dhingra, Gaumer Process

Electric Process Heaters (EPHs) have been growing in number and size for more than 50 years. This relatively new technology has taken another major leap from 480 volts to 4,160 volts. EPHs have the advantages of a small footprint, 100 percent efficiency, no emissions, low maintenance and longevity. Sizes have steadily increased from the large 100KW sizes in the 1980s to the large 10MW today. As the need for larger power heaters grows, a higher voltage is necessary to reduce the control panel size and the interconnection wire size. Gaumer Process has successfully developed and implemented the world’s first 4,160 volt EPH. This article describes the applications, features and technical development of electric process heating.

History of electric process heaters The first industrial EPH in the 1960s was a joint venture between GE and UOP for a refinery Platforming process. A high outlet temperature was needed at the top of a distillation tower. Compared to other equipment such as pumps, heat exchangers and fired heaters, EPHs are very new to industry. Fifteen years ago, a 100KW heater was considered large. Today, a 1.0MW is not uncommon and 10MW EPHs are being requested. Since 1960, the heater bundle fell into a section of code for “proprietary equipment” and was designed between the supplier and customer only. Only around the year 2000 did ASME recognize EPHs. However, it only addressed the mechanical design. NEC has addressed EPHs in boilers only, with section 424-73 describing the over temperature protection of an electrically heated boiler. During the 1990s, dry, low NOX gas turbines were introduced and needed higher quality fuel gas. EPHs were specified in fuel gas conditioning systems around the world for both on and offshore. Industrial grade applications exist in the oil & gas, pipeline,

Are Shaft Currents Destroying Your Machinery?

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Figure 1

Figure 2

refinery, chemical plant, process and power industries. These industries are subject to a variety of regulations, such as API, ANSI, ASME and TEMA. Since the electric process heater is so new, an industry standard has yet to evolve. Also, since electric process heaters Figure 3 have a mechanical, electrical and process design, it doesn’t fit easily into an existing group of equipment. An EPH design requires expert electrical, mechanical and process engineering. Changing one aspect of the electrical design will affect the mechanical process, and

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FEATURES changing another aspect of the mechanical design will affect the process and the electrical. Most engineering houses split their departments along the lines of electrical, mechanical and process. Gaumer’s R&D, mechanical, electrical and process engineers work together to avoid those problems. Gaumer Process helped develop electric process heater technology during the last 50 years, acquiring several patents for its electric process heaters, systems and controls. Hundreds, if not thousands, of minute details can be specified while designing an EPH. These details range from selecting the accurate watt density, proper immersion length, type of labels put on the wires inside of the control panel, wall thickness of the heater element, even up to the type of root pass weld put on the heater vessel, based on the specific design. Gaumer Process reviews every application in detail, run process simulation and performs thermal and mechanical analysis to provide a solution that will exceed customer requirements.

Advantages of electric process heaters EPHs are relatively small and very safe to operate. EPHs are a clean source of heat. Electric heaters are emission-free at the point of use. They are more efficient in converting process fluid to vapor compared to conventional fossil fuel-fired equipment, and there’s no stack loss, wasted heat, unburned fuel or excess air escaping up the flue stack. EPHs are common in power plants, refineries, chemical plants and offshore production platforms. The footprint and weight of an electric process heater is smaller than a direct or indirect gas-fired heater. There are no open flames or leaking fluids with EPHs. There are no moving parts with EPHs. EPHs can achieve higher temperatures than heat exchangers and indirect-fired heaters. EPHs using full SCR control have 0-100 percent turndown. Looking at the bundle temperature of an EPH as flow changes shows that the watt density changes will keep the bundle temperature lower than the design case.

Table 1

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FEATURES

Figure 4

Figure 5

EPHs also use radiant heat transfer to assist with high temperature gas heating applications. • Qfcep – heat transferred to process by forced convection off elements • Qrep – heat transferred to process by radiation • Qrev – heat transferred to heater vessel by radiation • Qfcvp – heat transferred to process by forced convection off heater vessel

Electric process heaters vs. shell and tube exchangers An EPH is different from a heat exchanger in that the elements will continue to get hotter unless the process cools down the elements or the over temperature thermocouple stops power input. A heat exchanger will only get as hot as the process fluid on hot side. A properly designed EPH will stay cool during start-up, normal operation and shutdown. EPHs boast nearly 100 percent thermal efficiency, have a smaller footprint, offer huge weight savings, low maintenance and are quick to start-up/shut-down.

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Inside electric process heaters Compressed magnesium oxide (MgO) contains the voltage on the NiChrome wire while easily transferring heat to the sheath of the heater element. MgO also contains the voltage on the NiChrome wire and does not allow current to pass to the heater element sheath. However, MgO is hygroscopic. H2O is attracted to the surface of the MgO matrix. Faulty seals are the No. 1 reason for EPH failure. Before a new EPH is complete, the MgO must be baked dry and the ends of the heater elements must be sealed. Otherwise, moisture will almost immediately wet the MgO and lower the dielectric strength. Different grades of MgO exist and all Gaumer EPHs are made from grade ‘A’ MgO. Recent advances in electric process heating consist of better seals. Methods consist of temporary, short-lived coatings, welded seals, nitrogen purge and, in Gaumer EPHs, the Infi-SealTM, a process that converts the end of the heater element from hygroscopic to hydrophobic. Elements are tested for moisture content by a Megger test and a Hi-Pot test. How the Infi-Seal works The diagram below shows a tubular electric heater element. For electric process heaters, these elements are u-bent, pressed at the bend and annealed. Inside of the tubular element is a NiChrome wire similar to the heating wire in a light bulb. The NiChrome wire is surrounded by compressed Magnesium Oxide. To control where the heating starts, cold pins are used to transfer the electricity to the NiChrome wire. Compressed MgO also surrounds the cold pins. Infi-Seal increases the life of the heater, eliminates startup problems due to moisture in the heating elements,

OCTOBER 2014

FEATURES prevents shutdown due to ground fault trips and reduces the chance of electric shock. Historically, the biggest problem for electric heaters has been moisture, so the Infi-Seal process addresses that problem by coating the MgO in the cold section with a hydrophobic seal, rendering the heater non-susceptible to moisture problems. This technology transforms the hygroscopic MgO into a hydrophobic barrier. Bare Infi-Seal elements soaked in water have shown to return to an infinite state with time. This is the exact opposite of untreated heater elements. Instead of elements soaking up the water from a humid environment, these elements pushed the water out of the treated MgO.

Figure 6

Learn more about electric process heaters by downloading Gaumer Process’ free webinar at www.energy-tech.contentshelf.com Gaumer’s 4kV Electric Process Heaters Until recently, the large current requirements of electric resistance heaters – which usually operate at normal building distribution voltage (480V) – meant that they were not commercially practical for very large loads. However, because many large process industries and almost all power plants have higher voltages available, the possibility existed for operating larger MW process heating equipment at higher voltages. The introduction of the world’s first 4kV heater has made that possibility a reality. Now readily available to industrial and commercial customers, the 4kV fills the gap in the industry for a 1-20 MW range medium voltage electric heater with resistance elements up to 4,160V. Anticipated future of 4kV electric process heaters Electricity production in the U.S. is growing, as shown Figure 7, and the demand for EPHs is growing faster. Until now, EPHs were limited to the 480-600 volt range. The currently available 4,160 volt EPH creates additional applications and improves existing EPH solutions. The size of EPHs also grows each year to cater to the growing power demand. In 1992, a 100KW EPH was considered a very large heater. In 2013, a 1MW EPH is not an uncommon application. ~ Craig Tiras, P.E., is vice president of Technology at Gaumer Process. You may contact him by emailing editorial@woodwardbizmedia.com. Gaurav Dhingra is vice president of Engineered Systems at Gaumer Process. You may contact him by emailing editorial@woodwardbizmedia.com.

Figure 7

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REGULATIONS COMPLIANCE

Taking the water out of ash handling By Jim Sutton and Mike Tanca, Alstom

The combustion of coal produces unburned residues. These include bottom ash that exits the bottom of the boiler, flyash that exits the economizer and particulate removal systems, and flue gas scrubbing residues. Most flyash and gas scrubbing residues are handled as dry residues, while bottom ash has historically been handled as a wet product that is sluiced to an ash pond. Power plants are increasingly replacing this water sluicing method and switching to more reliable dry bottom ash systems in order to meet expected Environmental Protection Agency (EPA) guidelines, and reduce the cost of maintenance and operation. Alstom has installed more than 100 dry bottom ash systems in the United States and around the world. This equipment is extremely useful to achieve the following goals: • Eliminate ash pond or tank farm • Extend time between outages • Allow more reliable removal of fuels with slagging tendencies • Reduce maintenance costs • Minimize water usage and facilitate re-use of boiler’s ash in cement and road construction • Create a safer working environment

The issue Over the years, the EPA has been studying various aspects of boiler ash disposal. Included in the studies are evaluations of whether boiler ash should be considered a hazardous material and whether there should be additional structural and lining requirements for ash ponds. The studies are a result of several ash spills where ash pond materials were released into waterways in both private and public properties, as well as concerns about the leaching of hazardous materials from ash ponds into the environment. The legislative issues are described in more detail in the sidebar.

Historically in the United States, ash removal and transportation was handled with wet sluicing systems. Ultimate disposal was handled in a variety of ways, including on-site in settling ponds, trucked to landfills, or used in cement and road construction. Equipment associated with removing ash by the usual sluicing method is prone to significant maintenance costs because both bottom ash and flyash are very abrasive. This is generally due to the ash containing quartz, which is significantly harder than steel. Making the wear situation worse is that when ash is removed as part of a water sluicing system, the velocities must be high to ensure ash does not fall out of the stream, causing pluggage. Since the rate of erosion is driven by velocity to the third power, and the difference in materials’ hardness, it is easy to see why some ash components can wear out in three months or less. Ash sluice system piping, which can extend for thousands of feet, often requires rotation and can be a real mess if pluggage occurs. Both compliance with expected environmental regulation issues, and long-term cost reduction can be achieved with the adoption of a dry ash system. Payback, based on reduced maintenance costs, lower energy usage and reduced water usage, are generally in the two- to three-year range, depending on site specific costs.

Typical bottom ash removal system Bottom ash removal systems are a very important and integral part of any coal-fired power plant. Most utility boilers in North America were originally designed with a water-impounded, refractory lined ash hopper at the bottom of the combustion chamber. This water-filled hopper configuration serves several purposes: the water buffers the impact

Figure 1. Submerged scraper conveyor, general arrangement

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OCTOBER 2014

REGULATIONS COMPLIANCE of the ash falling from the boiler, the water quenches the hot material and the hopper provides storage until the removal process is initiated. It is common for ash to cling to the boiler tubes during the combustion process, forming clinkers, which eventually fall into the ash hopper. The relatively cold water in the hopper usually causes the larger clinkers to fracture into smaller pieces due to thermal shock. A separate water-filled trough around the upper, exterior perimeter of the hopper is included to provide a water seal via suspended plates from the boiler bottom. This type of removal system is typically referred to as an ash sluicing system. The final disposal method of the ash varies from plant to plant, but usually includes a dewatering bin for truck unloading, or sluicing directly to a nearby storage pond. In addition to the hopper itself, a typical bottom ash sluicing system includes discharge gates, gate housings, refractory cooling system, clinker grinders, high pressure and high horsepower pumps, abrasion resistant pipe and valves, and a control system to automate the process.

Figure 2. Ash being transported up the dewatering ramp.

Dry ash system now available In the mid- to late-seventies, a different type of bottom ash removal system was introduced in the U.S. These systems were technically not ‘new systems,’ because they had been in use for many years in Europe. Although this new equipment was referred to by several different names – Drag Chain Conveyor (DCC), Submerged Scraper Conveyor (SSC), Submerged Drag Chain Conveyor (SDCC), Submerged Mechanical Drag Chain (SMDC) – it was basically a mechanical method of removing the bottom ash from underneath the boiler. This article will refer to the equipment as a submerged scraper conveyor or SSC. An SSC consists of a boiler transition chute, a submerged collection trough, a dewatering ramp and a dry return trough. Two parallel chain loops run the entire length of the conveyor, with perpendicular flight bars connected to the chain. This is shown in Figure 1. The flight bars push the ash through the submerged trough section and up the dewatering ramp. The dewatered ash (containing 15-30 percent moisture) is then deposited into a crusher (optional) or sizing grid, and onto the discharge device. Figure 2 shows ash being slowly dragged up the dewatering ramp. After dumping the ash at the top of the dewatering ramp, the flights and chain return in a reverse direction through the dry lower trough section. Chain spray nozzles are located along the return section to help remove adhering ash particles.

OCTOBER 2014 ENERGY-TECH.com

REGULATIONS COMPLIANCE A transition chute is attached to the boiler, and extends down into the upper water filled trough, creating the boiler seal very similar to the traditional seal plate/seal trough arrangement. Since this was proven technology in Europe, it began to draw attention in the U.S. However, the reliability

of this type of system was of some concern. Many installations in the European countries had two SSCs mounted under each boiler, side by side, supported on wheels and rails. One SSC was under the boiler in operation, with the other unit on standby, available to be moved into place via the wheels and rails. If, for any reason, the operating unit Table 1 – Maximizing Operational Flexibility of Burner and Ignitor Systems had a problem, the second For Tangentially Fired Boilers unit was readily available. In order to keep the unit Parameter Traditional U.S. Sluicing approach Submerged Scraper Conveyor online, a clamshell door • Stainless steel transition chute • Refractory lined ash hopper with arrangement was installed • Heavy duty drag conveyor water seal on some units to close off weldment • Clinker grinder Major Components the bottom of the boil• 40 HP hydraulic drive • Ash gate • High pressure sluicing system pump er while the transfer was and abrasion resistant piping made. Since the dual SSC arrangement was relatively Wet product, must have water removed Typically product is suitable via dewatering bin or by utilizing gravity/ for loading into trucks for expensive, the emphasis on Product Produced settling in an ash pond transportation to cement/asphalt reliability of the equipment plant or landfill became very important • Clinker Grinder rebuild • Grease idlers to the U.S. utilities. After Typical Maintenance Activities and • Repair refractory in hopper • Replace flights (online) thorough investigation and Frequences • Replace/rotate ash piping • Replace drag chain (6-10 design concepts were scruyears) tinized, the first units were 24,000 ft/min (in jet pump) Less than 3´/min (typical Maximum Ash Velocity installed in the U.S. during conveyor speed) the late 1970s. Experience Energy Required 400-1,000 HP 50 has shown that the equipWater Required Average consumption at 1,000 gpm 100-200 GPM ment is highly reliable and there is no need for redunLimited to door size on discharge hopper Up to 8´ in length Maximum Clinker Handled dant SSCs. Figure 3 shows a (usually 3´) modern SSC inspected, tested and ready for shipment from Indonesia to the U.S., and Figure 4 shows an SSC installed underneath an 800 MW boiler in the U.S. As previously mentioned, reliable operation is well proven at more than 100 sites, but some customers still want to retain the rollout feature. This is not to swap in a redundant SSC, but to enable rapid access to the boiler during outages. With the SSC rolled out on wheels, as shown in Figure 4, scaffolding and large equipment can be easily brought into the furnace cavity.

Figure 3. Shop assembly of SSC for a retrofit project.

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OCTOBER 2014

REGULATIONS COMPLIANCE The trough size is based on the boiler discharge dimensions and ash production rates. The trough sizing also is related to conveying capacity, flight speed, flight height and drive unit selection and horsepower. Generally, Alstom recommends that the trough be large enough to enable the system to store eight hours of ash production. The drive unit, which can be electric or hydraulic, single, two-speed or variable speed, is sized to â&#x20AC;&#x153;pull outâ&#x20AC;? the ash under these heavily loaded conditions. The most common selection is hydraulic. The dewatering ramp length and upward angle (normally 30 degrees) is designed and selected for the desired moisture content of the ash, the generation rate of the ash and the available space and clearances.

or the other. Economics, maintenance, physical restrictions, auxiliary power, etc., are all factors in the decision.

Conclusion SSCs are highly reliable equipment installed at hundreds of U.S. and global power plants. They can be incorporated under most boilers, or set up as a remote system on units with insufficient room under the boiler. SSCs eliminate the need for ash ponds and tank farms, extend time between outages, allow more reliable removal of fuels with slagging tendencies, reduce maintenance costs, minimize water usage

Summary of advantages Table 1 summarizes the issues, traditional approaches and the latest approaches for maximizing operational flexibility of burner and ignitor systems for tangentially fired boilers. Remote SSCs The system mentioned previously in this paper is based on an SSC located below the boiler bottom outlet, beneath the boiler. This type of SSC is used when there is sufficient room below the boiler hopper to remove the old system and install the dry system. In many cases, a retrofit is not practical due to the lack of room for the new system where the old system once stood. Structural steel, cable trays, pipe rack, walls, etc., have been located around the boiler floor area, making a direct conversion to an under boiler SSC not economically feasible. Remote SSCs have been developed to locate the SSC in an external area, away from the boiler. The existing bottom ash sluicing system is used to transport the ash to the remote SSC, instead of the existing ash pond. This type of system is advantageous when there is no room beneath the boiler and when there are two or more small boilers requiring retrofit, economically. A layout for a remote SSC system is shown in Figure 4. This technology is relatively newer and there are a handful of sites in operation. Both the under-boiler SSC and remote SSC have their own advantages, and there is no clear winner. Each retrofit situation has its own sets of conditions that will drive the selection toward one application

OCTOBER 2014 ENERGY-TECH.com

REGULATIONS COMPLIANCE

Figure 4. SSC installed under 800 MWE boiler.

A short history on regulation of Coal Combustion Residues (CCR)

CCR includes fly ash, bottom and flue gas scrubbing residues. • October 12, 1976: The Resource Conservation and Recovery Act (RCRA) was enacted and Subtitle C required all wastes to be classified as hazardous or not. • December 18, 1978: EPA declares coal combustion residues as a “special waste” with standards to be developed. • October 12, 1980: Congress passes the Solid Waste Disposal Act Amendments, including the Bevill amendment that specifically classifies CCR as a “special waste” to be regulated as non-hazardous and low risk to human health. • December 22, 2008: TVA ash impoundment structurally fails, causing damage to waterways and structures. • June 21, 2010: EPA proposes a regulation to manage CCR as hazardous, non-hazardous or non-hazardous with special considerations. Public comment sought. EPA receives an estimate 1.5 million comments. • December 19, 2014: EPA, under court order, finally releases final rules governing disposal of CCR by this date.

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and facilitate re-use of boiler ash in cement and road construction. Finally, dry ash systems allow a safer and cleaner working environment. ~ Jim Sutton is director of Growth Initiatives in Alstom’s Boiler Service Organization. He has more than 30 years of experience in power generation and is a member of ASME and a licensed professional engineer in the state of Connecticut. He has been awarded six patents and presented papers on topics of interest to power plant operators. Areas of special interest include boiler reliability, efficiency and advanced controls. You may contact him by emailing editorial@woodwardbizmedia.com. Mike Tanca is the Product Manager for Engineered Solutions, which includes wet-to-dry bottom ash conversions, in Alstom’s Boiler Service Organization. He has more than 40 years in power generation and is a licensed professional engineer in the state of Connecticut. He has been awarded 17 patents and has written numerous technical papers. You may contact him by emailing editorial@woodwardbizmedia.com.

OCTOBER 2014

MR. MEGAWATT

Data reconciliation By Frank Todd, True North Consulting

One of the nice things about living on a bluff is that I have a wide perspective of various nuances of nature and man’s influence on it – from the long flat mesa, vast and unmalleable, to the orderly fields of corn orchestrated for efficient harvesting.This vantage point provides a grasp of the whole picture at a glance. All the data before me is compiled in my brain and gives me the feeling of awesome wonder. Mrs. Megawatt would call it a puzzle picture. Based on the title of this article, you might think I’ve drifted into some philosophical or psychological rabbit trail, maybe a “Dear Abby” for engineers.Well, let’s say it’s a “Dear Abby” for a power plant; a discussion of how to reconcile all that data we engineers love to analyze. With the advent of more diverse sources of electricity, the way we manage resources is changing. Many plants that used to be base loaded will now adjust load on a regular basis.The challenge for a utility is to determine which resource will be the best to apply and which will be the worst. There are several considerations that could be evaluated, but this discussion will focus on incremental heat rate; or the heat rate of a power station for an off-load condition.Traditionally, this is determined by state point tests at various load conditions. Unfortunately, for a fossil plant this entails a large amount of uncertainty. Some of the most significant uncertainties are from the measure of the amount of energy being added to the boiler (coal flow and heating value) or the feedwater flow (sometimes condensate flow) to the boiler. If I have a fleet of 10 coal-fired power stations and the 50 percent load heat rate varies by 400 BTU/kwh due to instrument error, making an informed decision becomes difficult.The result is that the real costs are not known. Here is how one power station solved the problem. Normally I am happy to just sit in my office and calculate turbine efficiency until the cows come home.When a call comes in to disturb my reverie, I am often somewhat cantankerous; Mrs. Megawatt can attest to that fact. However when the call comes from the land of Oktoberfest, thoughts of grain and hops can have a soothing effect. So it was that I grabbed Brian the Btu Buster (BTB2) and we jumped the pond to Deutschland. BTB2 only agreed to this if we could rent a Porsche 918 Spyder – top speed 214 mph – and he got to drive. So we did. We made the 200-mile trip in about 1.2 hours and arrived at the Gauss Jordan Memorial Power Station (GJMPS) located in the little Bavarian town of Lignitenstein.The performance engineers at GJMPS were being pressed by their national leaders to improve their dispatch heat rates or face the prospect of being replaced by 15,000 windmills; even if they did have to stretch above the trees.They wanted some help to stave off the big white monstrosities. For this project we were going to take a back seat to our friends from the area, Dr. Magnetic Long and his sidekick, Andy the Master of Matrix Jordan, ML and AJ.

Before I get into the actual application of the process, I need to wax statistical. As the name reconciliation implies, with respect to a power Figure 1 plant (or any other physical process), when we look at the data it never completely obeys the laws of physics. If we are using measurements, we are always somewhat off from the Figure 2 actual physical conditions. A good example is when we weigh ourselves.What do you do when you jump on the scale and read your weight? Often you look for another scale, because the one you’re using cannot be correct. Either that or it must be your 15 lb. pair of pants, so you make a correction to the measured value. As it was with my children, the big question is who is right? The answer is nobody is right, just some are more right than others.The ultimate goal of the Data Reconciliation process is to figure out what is the most right value of each measurement in the process. Fasten your seatbelts … Given a section of pipe that branches into two parallel flow headers, the measurements will never add up perfectly (see Figure 1). Similarly, if we measure the parameters around a feedwater heater and calculate the power (Q) on the tube side and shell side, they will never be exactly the same.This difference sets up a conflict (or contradiction) between the measurements. If you believe the tube side conditions more than the shell side conditions, then Failure to properly

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MR. MEGAWATT

Figure 3

Figure 4

you can correct the shell side parameters based on the tube side parameters. In making these corrections to the shell side parameters, you also will have a difference between the measured value and the corrected value. If you have a higher confidence in the shell side parameters, then you can calculate corrected values for the tube side.These relationships provide the ability to create a functional redundancy (Figure 1). In addition to the functional redundancy, we can improve the overall uncertainty of the process by providing for hardware redundancy (Figure 2). Corrected values can be supplied based on hardware redundancy.The temperatures T1 minus T2 can provide a correction for T1 with respect to T2 and so on. In Figure 1, the measured values of ṁ2 and ṁ3 will never add up exactly to the measured value of ṁ1. Inevitably, there will be contradictory measured values.Therefore, in order for the calculation to be balanced, corrections must be applied to all the variables.With the data reconciliation process, a correction calculation is performed that takes into account all of the covariance analysis and produces a correction factor and an estimated value for each variable.The resulting variables calculated from these estimated values and their covariance matrix have the lowest possible measurement uncertainties. Corrections (v) are made to the measured values x to obtain the reconciled values x –: x – = x +v 18

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The corrections v are determined to fulfill the quadratic form: ∈0 = vT · Sx-1 · v becomes a minimum. Sx-1 = inverse empirical covariance matrix of random variables x and ∈0 = square form of errors.The empirical covariance matrix Sx is the estimated value for the uncertainty of the measured variables X.This is the general form of the Gaussian correction principle. Say that 50 times and you have it. If you take these principles and apply them to the entire power cycle, you can have a method to determine the best possible value for each measured and calculated value, along with the uncertainty of the individual parameters and the overall or global uncertainty. Using the statistical criteria for confidence intervals, a determination of the quality of the overall calculation can be determined.The process requires an exact fulfillment of the mass, energy and material balance for all the components and for the entire power cycle (no loss of physics allowed). More information and detailed calculation examples can be found in the German code VDI-2048. If you’re still with me, let me continue on with the story. So the problem was for GJMPS to figure out which units should be dispatched at off load conditions. Figure 3 provides the original dispatch curves.The plant engineers performed all the typical measurements on the boiler and turbine cycle to calculate overall unit heatrate. After operating on this basis there was a concern that they did not have enough reliable information on which to base their dispatch order. Often the boiler efficiency can be off a significant amount, just based on the coal flow measuremnts. BTB2 looked at all the calculations and instruments; it was clear that there were significant uncertainties involved.We could understand the concern about the dispatch order. Dr. Long suggested that they evaluate the plant data using the Data Reconciliation methodology. It was agreed; ML and AJ were on the job. After a few weeks of some serious modeling and verifying, a set of curves was developed to show the reconciled heatrate charts shown in Figure 4. As can be seen in Figure 4, the heatrate order varies with load. It was clear that not only was the original order incorrect, but it would change based on the load. With this information, GJMPS was able show a significant improvement in its dispatch orders and save fuel costs by adjusting its dispatch order over the load range.The plant engineers were able to avert the machinations of the wind generators. Driving up the bluff from the airport, I realized that I had been gone for almost three weeks at a location that was not altogeter unpleasant. Mrs. Megawatt would not be pleased, some reconcilation was going to have to take place. ~ Special thanks to Dr. Magnus Langenstein and Andy Jansky of BTB-Jansky for their support in writing this article. 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. He can be emailed at editorial@woodwardbizmedia.com.

OCTOBER 2014

ASME FEATURE

Torrefied-biomass for the 600MW Boardman Power plant By Ezra Bar-Ziv, Michigan Technological University, Roman Saveliev, EB Clean Energy, Ltd., Jaisen Mody, Portland General Electric Co., Miron Perelman, Michigan Technological University

Abstract PGE, in collaboration with EBC and MTU, is carrying out a test program to fire 100 percent biocoal (torrefied-biomass) in the Boardman 600MW boiler. The program has three important aspects: (1) biomass feedstock suitability to coal power boilers, (2) production of biocoal and (3) biocoal combustion. The selection of suitable biomass feedstock from which biocoal will be produced is essential because of potential problems with slagging. The study tested the following feedstock: Arundo Donax (AD), wheat, corn, woody hybrid poplar, woody pine and their barks. It was found that bark and corn comprised significant amounts of soil (varying from 10-25 percent) with low fusion temperatures. We developed a sifting method that removed the soil entirely. All sifted feedstock showed mineral content that is respective to the land where it grew. Samples were characterized for ultimate and proximate analysis, ash content and analysis and fusion temperatures. AD, wheat and corn showed high content of potassium and low fusion temperatures, and therefore may not be used at 100 percent firing unless some of the minerals are removed. Woody and bark biomass showed high fusion temperatures (>2,500째F), which makes them suitable for the 100 percent firing test. We produced biocoal from all the feedstock previously mentioned. Briquettes were produced from the biocoal and those were tested according to standard coal procedures. The 100 percent pulverized biocoal was fired in a 50kW test facility and yielded temperature and gas concentration profiles similar to those of coal. NOX emission from all biocoal from any biomass type was found to be significantly lower than that from coal burning. SOX emission was negligible. Fouling was quite low for all biocoal tested.

mass (biocoal)(4, 1, 5, 6, 9)which is considered a renewable energy if grown sustainably. PGE will conduct a test burn with 10,000 tons biocoal in April 2015 in the 600 MW Boardman boiler, which may lead to complete replacement of coal with biocoal by 2020 (more than a million tons of biocoal). This program is made in collaboration with EBC and MTU. There are three aspects of this program: (1) the biomass feedstock suitability to coal-fired boilers, (2) production of biocoal and (3) test burn. Biomass feedstock: Each ton of biocoal requires 2-3 tons of raw biomass, hence 10,000 tons of biocoal will require 20,000-30,000 tons of feedstock. The selection of suitable biomass is crucial because of potential slagging in the boiler. We tested seven different types of feedstock and found that some comprised significant amounts of soil/ dust (varying from 10-25 percent) with low fusion temperatures and therefore must be avoided from the boiler.

1. Introduction and background Driven by environmental regulations, European and U.S. companies developed torrefaction to produce torrefied-bio-

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ASME Power Division Special Section | OCTOBER 2014

ASME FEATURE Table 1 – Ultimate And Elemental Analysis Of Biomass After Removing Soil Fines. Results Are Based On Dry Basis. Property

Corn

Wheat

Wood pine

Bark pine

Wood poplar

Bark poplar

Total moisture

10.11

10.07

9.68

16.97

11.68

17.53

14.73

Volatile matter, w%

73.66

76.7

71.9

80.21

81.13

81.4

83.46

Fixed carbon, w%

17.41

15.02

17.4

17.87

16.21

16.39

11.62

Sulfur, w%

0.241

0.056

0.11

0.011

0.021

0.017

0.010

Gross Calorific value, BTU/lb

7,884

7,736

7,509

8,796

8,717

8,644

8,534

Carbon, w%

44.81

44.37

43.5

50.25

49.73

49.26

48.98

Hydrogen, w%

5.62

5.53

5.45

6.01

5.95

5.85

Nitrogen, w%

1.33

0.85

0.78

0.2

0.27

0.3

Oxygen, w%

39.06

40.92

39.5

41.61

41.43

42.3

39.93

Chlorine, mg/kg

16,573

5,188

19,0

188

103

Ash content before sifting

9.70

19.8

12.4

4.20

26.6

2.40

27.2

Ash content after sifting, %

8.94

8.29

10.7

1.92

2.66

2.21

4.5

Table 2 – Ash Analysis Of Biomass After Removing Soil Fines Item

Corn

Wheat

Bark Pine

Woody Poplar

Bark Poplar

Ash content

8.94

8.29

10.7

1.92

2.66

2.21

4.5

SiO2

25.4

31.2

40.5

61.9

48.7

58.5

54.7

Al2O3

0.15

0.34

0.4

5.6

3.27

0.16

0.18

TiO2

0.03

0.07

0.06

0.91

0.84

0.08

0.14

Fe2O3

0.41

0.64

0.76

7.31

5.25

0.69

0.6

CaO

4.43

3.13

2.51

5.2

15.5

3.31

11.4

MgO

3.72

1.48

1.51

0.69

1.83

1.41

2.07

K2O

48.6

43.2

44.3

7.47

12.4

21.0

19.2

Na2O

1.3

4.21

1.51

1.59

1.57

0.4

0.63

SO3

5.94

0.59

1.81

0.58

0.91

0.78

1.23

P2O5

5.88

10.72

1.89

2.57

4.75

8.73

4.92

SrO

0.02

0.06

0.02

0.03

BaO

0.02

0.03

0.04

0.06

0.04

0.02

0.03

MnO

0.05

0.02

1.59

0.26

0.1

0.12

Undetermined

4.05

4.4

4.68

4.48

4.7

4.81

4.79

Total

100

We developed a separation technology of the soil from the biomass and were able to obtain biomass feedstock only with the plant minerals. Biocoal: Torrefaction is a mild thermal treatment of biomass under inert environment(3,8), carried out at ~300°C. It produces a fuel that is similar to coal(10). For our 10,000 ton test burn we designed and constructed a 4 ton/hour torrefaction facility.

Wood Pine

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Biocoal combustion: The various biocoal types were tested in a combustion chamber in order to determine their NOX, SOX, CO, PAH and particulates emissions, and to compare them to those of PRB coal. Fouling of biocoal types also was tested, but only the woody biomass was tested for slagging.

ASME Power Division Special Section | OCTOBER 2014

AsME FEAtUrE ASME Power Division: Fuels & Combustion Technologies Committee

A Message from the Chair

Figures 1a and 1b. Heat content and volatile matter vs. mass loss in woody biomass torrefaction.

2. Methods 2.1 Preparation: Shredding, soil removal and drying Our torrefaction technology uses ~6mm biomass particles, which requires coarse shredding and fine shredding. For the coarse shredding we used a chipper, and for fine shredding we used hammermills with more than 200 blades rotating at 1,800-3,600 rpm. We noted the feedstock contained soil/dust fines that had to be removed because of potential slagging. The output from the fine shredding had three fractions: fines under 45 micron (soil and dust); 0.5-2mm and >5mm that are only biomass. Using a vibro-screen-shaker with a bottom screen of <0.5mm enabled the separation of the soil and dust from the biomass, retaining only the mineral from the plants. We used a rotary drum for drying, with the hot air co-flowing with the feedstock and a bag house collecting the fines for environmental compliance. 2.2 Biocoal production We are producing biocoal in three facilities: (1) in Israel at a rate of 2 ton/hour of biocoal, (2) in MTU at a rate of 1 ton/hour and (3) in Boardman at a rate of 4 ton/hour. In the first two facilities, we carried out the R&D of process parameters and material handling, the Boardman facility is for production. The Boardman plant comprises the following system: (1) two-stage shredding of the biomass, coarse and fine, to reach the right size required for tor-

OCTOBER 2014 | ASME Power Division Special Section

The FACT committee is dedicated to the understanding of fuels and combustion systems in modern utility and industrial power plants, including fuel handling, preparation, processing and by-product emissions controls. At the ASME Power 2014 Conference in Baltimore, FACT sponsored nine sessions, all with excellent attendance. Attendee response to the FACT track papers was overwhelmingly positive. I chaired the track with Dr. Ashwani Gupta, who is the co-chair of the FACT committee this coming year. I invite everyone with an interest in fuels, combustion, environmental and material handling technologies to join the committee. It is important to note that being a member of ASME is not a prerequisite to joining the FACT committee. Attending one of our conference-based meetings also is not required. The Power Division has supplied a conference call dial-in number to anyone who would like to participate remotely in our meetings. If you are interested in joining the committee, please send me an email and I’ll make sure you receive periodic updates on our activities and meetings. The FACT committee is a great place to share your industry knowledge, network with your peers and make your voice heard. Typical participants include electric utility/IPP engineers, A&Es, manufacturers, industrial power/steam generators and sales/marketing representatives. The FACT committee also welcomes your active participation in the upcoming ASME Power Conference next June in San Diego, as well as your participation in Committee meetings and other activities. Please visit www.asme.org/power15 for more information. The committee is comprised of nearly 2,000 individuals from power producers, academia, manufacturing and the A&E communities. We encourage your participation in our various subcommittees that include: • Combustion Systems • Handling, Transportation & Storage • Fuel Properties and Characteristics • Processing and Alternate Fuels, including Biomass • Committee for Academic and Industrial Research If you are interested in joining, please contact me. Respectfully, Christopher F. Blazek Chair, Fuels and Combustion Technologies Committee Benetech Inc., 2245 Sequoia Drive, Aurora, IL 60506 630-844-1300, ext. 214 blazekc@benetechusa.com

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ASME FEATURE

Figure 2. SEM photograph of torrefied biomass at X500 magnification (left) and elemental analyses of an area indicated in the photograph as #1.

Figure 3. SEM photographs of Cerrejon D coal (left), woody biocoal (middle) at magnification of X500, and size distribution of the two samples (right).

Figure 4. SEM photograph of torrefied biomass at X2400 magnification (left) and elemental analyses of three area indicated in the photograph as #1, #2, #3.

refaction, (2) drying of the biomass to bone-dry state, (3) fast heating of the biomass feedstock to the desired torrefaction temperature, (4) torrefaction according to needs (fixed carbon, volatile matter, heat content), (5) grinding and (6) briquetting. 2.3 Biocoal combustion We have used for this study a well-developed firing methodology that was tested and used for many coals(11, 7). Pulverized coal is burned in a 50kW entrained-flow 2-D test facility and the gases CO2, O2, CO, NOX, SOX, PAH, LOI, gas temperature and heat flux were measured. Fouling

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and slagging also were measured, as well as emissivities. In the experiments, we fired a 400-600 kg pulverized sample.

3. Results and discussion 3.1 As-received biomass PGE has been growing Arundo Donax (AD) and sorghum for the torrefaction project. We also explored other sources such as wheat straw, corn stover and various barks. The as-received and sifted feedstock was analyzed for ultimate and elemental analysis and the results are given in Table 1. While the moisture content is tolerable, the ash content is quite high, which is a major hindrance for

ASME Power Division Special Section | OCTOBER 2014

ASME FEATURE

Figure 5. Briquettes from woody biocoal.

firing in the Boardman boiler because it can create slag and excess fouling. Note the high content of sulfur and chlorine in AD, corn and wheat. Woody biomass feedstock display very little chlorides and almost no sulfur. 3.2 Sifted biomass: Fouling and slagging After sifting ash content was reduced, some with significant reduction of >10 percent for corn and >24 percent for the barks. Ash analysis was carried out of the sifted biomass feedstock and results are summarized in Table 2. We also analyzed the slagging index with results presented in Table 3. Table 2 shows very high slagging indices (therefore very high slagging propensity) for AD, corn and wheat. To validate the high slagging propensity shown in Table 3, we measured the fusion temperatures at reducing and oxidizing atmospheres of the fly ash of all biomass feedstock. Table 4 summarizes these results, indicating that indeed AD, corn and wheat have very low fusion temperatures, whereas the highest is Greenwood (bark or woody). As far as fouling is concerned, we have used common correlations to determine ash type and ash index, and results are presented in Table 5. Fouling propensity for ash of all biomass feedstock seems to be low to medium; i.e., no indication of major fouling.

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3.3 Biocoal production Properties: We carried out torrefaction of all sifted feedstock types mentioned above (~20 min at 300째C with ~ 30 mass loss). Ash content increased by about 30 percent from the value of the sifted values, with moisture content of ~2.5 percent. We measured heat content

OCTOBER 2014 | ASME Power Division Special Section

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ASME FEATURE Table 3 – Slagging Indices And Propensities For The Biomass After Removing The Soil Fines Item

Corn

Wheat

Woody Pine

Bark Pine

Wood Poplar

Bark Poplar

(Ca+Mg)/Fe

19.88

7.20

5.29

0.81

3.29

6.84

22.37

Slagging Index (Ca+Mg)<Fe

0.51

Propensity

Low

Slagging Index (Ca+Mg)>Fe

1,828

1,716

1,732

2,390

2,700

0.14

Slagging Propensity

Very High Slagging

Low Slagging

Medium Slagging

Low Slagging

Table 4 – Fusion Temperatures Of The Biomass After Removing Soil Fines Reducing Atmosphere Item

Corn

Wheat

Woody Pine

Bark Pine

Woody Poplar

Bark Poplar

Initial Def. Temp.

1720

1590

1540

2180

2260

2700

Softening Temp.

1730

1600

2210

2290

2700

Hemispherical Temp.

1740

1610

1660

2250

2310

2700

Fluid Temp.

1750

1980

1990

2300

2340

2700

Oxiding Atmosphere Item

Corn

Wheat

Woody Pine

Bark Pine

Woody Poplar

Bark Poplar

Initial Def. Temp.

1790

1670

1630

2260

2340

2700

Softening Temp.

1820

1710

2310

2380

2700

Hemispherical Temp.

1860

1740

1820

2380

2430

2700

Fluid Temp.

1910

2095

2160

2470

2490

2700

Table 5 – Fouling Indices And Propensities For The Biomass After Removing Soil Fines Item

Corn

Wheat

Woody Pine

Bark Pine

Woody Poplar

Bark Poplar

Ash Type

Lignite

CaO+MgO+Fe2O3

13.12

15.52

5.21

4.74

7.23

9.91

6.78

Fouling Propensity

Low To Med

and volatile matter vs. mass loss for woody biomass torrefaction, shown in Figure 1. These two properties depend only on mass loss. This is a very important finding because we can select the properties of the biocoal according to the need. For example, loss of 40 percent mass will yield biocoal at 4,600 kcal/kg. Grindability: Grinding is an essential part of a coal power plant. The result of grinding is a direct consequence of the morphology of the material. Lab grinding was carried out with a high shear mixer and the ener24

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gy required to grind the material was determined. For comparison, PRB was pulverized in the same apparatus. Measurements were carried out by placing a sample of the biocoal/coal sample (the former as briquettes while the latter as received) in the grinder for a specific time, then measuring the size distribution and energy required per unit mass. Similar size distributions were obtained for both coal and biocoal (from any type of feedstock) and the energy per unit mass was ~20kWh/ton, similar to the

ASME Power Division Special Section | OCTOBER 2014

ASME FEATURE values determined by Bergman et al., 2004(2), and to those mass types previously mentioned. Figure 5 displays single for PRB coal. briquettes (left), a bucket full of briquettes (middle) and Morphology and minerals: Figure 2 is an SEM phobriquettes also are shown at the outlet of the briquette tograph of biocoal at X500 magnification (left) before machine. The briquettes showed good water resistance and grinding. As seen, the biocoal retains the same fibrous durability. Because there is no standard measurement for structure as the original biomass. The figure also shows these two properties, the results are only qualitative. elemental analyses of an area indicated in the photograph as #1 (right). Many scans were carried out and the 3.4 Biocoal combustion results, carbon and oxygen, are typical for all biocoal samThe fixed carbon content of biocoal samples was in the ples (all samples contain gold because it is added for the range 72.8-74.5 percent, hydrogen in the range 3.5-4.8 SEM measurements). Figure 3 shows SEM photographs percent, about 3.5 percent nitrogen and negligible sulfur of Cerrejon D coal (left) and biocoal (middle) after grinding to size distribution common for power plants. A clear difference between the morphology of the two samples is observed: biocoal shows distinct elongated particles that originated from the fibrous nature of the biomass, while the coal particles are a random distribution of sizes that are typical to coal after grinding. Figure 3 also shows that biocoal and the coal have similar size distribution characteristics that are suitable for pulverized coal firing. Minerals in the biocoal play a major role in the behavior of biocoal in a coal boiler. Not only the mineral content is important for the dynamics of ash, but also the way it is distributed in the fuel particles after grinding. Detached mineral particles from the fuel particles yield entirely different fouling and slagging behavior than if the minerals were trapped within the fuel particles. In coal we observed both behaviors, detached and trapped minerals. Figure 4 shows an SEM photograph of torrefied biomass at X2400 magnification (left) and elemental analyses of three areas indicated in the photograph as #1, #2 and #3. Area #1 shows a uniform material, and its elemental analysis shows only carbon and oxygen â&#x20AC;&#x201C; two elements in the biomass structure. Areas #2 and #3 show particles with different morphology than that of Area #1. Area #2 shows Na, Al, Si, K and Ca, while Area #3 shows Mg, Al., Si and Ca. All of these elements are part of the minerals in the biomass plant. The important and interesting part is that these mineral particles are detached from the carbon-oxygen particles and Renewal Parts Maintenance are not trapped within them. 4485 Glenbrook Rd. | Willoughby, OH 44094 Compaction: Many experiments were A Division of MD&A ph. 440-946-0082 | www.RenewalParts.com conducted on briquetting of all bio-

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ASME FEATURE (0.03 percent); calorific value was around 4,800-6,810 kcal/kg. In the experiments, the excess oxygen was around 3 percent. Figure 6 shows results of combustion experiments at 100 percent biocoal and coal. The profiles show the expected very close behavior for gas temperature, CO2 and O2. However NOX had significantly lower emissions than those for coal, which is attributed to the higher volatile matter in the biocoal. These results indicate that there

are no expected issues in the behavior of firing and burning of the biocoal in any boiler, however the ash behavior is still to be revealed.

4. Summary and conclusions Biomass feedstock: We have carried out a comprehensive study with various biomass feedstock in order to test their suitability to prepare torrefied biomass for the 600MW Boardman coal boiler. Our conclusions are: (1) Bark has significantly higher soil content than the respective woody biomass, probably because bark collects soil by wind blowing and other processes. (2) Soil fines were effectively separated by screening using a proper combination of mesh size screens and screening technology. (3) After soil fine separation it was found that poplar biomass, both woody and bark, has very low slagging propensity. (4) After soil fine separation it was found that pine biomass, both woody and bark, has medium slagging propensity. (5) AD, wheat and corn have very high slagging propensity. (6) All biomass feedstock do not seem to indicate any problems with fouling that cannot be resolved with adequate operation of the water cannon system. (7) It is recommended that the 10,000-ton test burn will be conducted as follows: i) Poplar biomass, either woody or bark, whatever is cheaper, will be mostly used for torrefaction to produce biocoal for the firing test for the Boardman boiler. ii) Pine biomass, either woody or bark, can be used for firing tests at 100 percent in the Boardman boiler without any indication of slagging. iii) The rest of biomass feedstock is recommended to be torrefied and be co-fired at moderate blends with coal in order to minimize slagging in the boiler. (8) For the long-term we think that the high slagging propensity biomass can be treated to enable routine operation of 100 percent firing of its biocoal. We offer two approaches for these types of biomass feedstock, (1) pretreatment to remove certain critical elements of the minerals and (2) adding an additive that increases fusion temperatures. Based on literature information, we trust that separation of these undesirable elements can be accomplished at a reasonable cost per unit ton of coal. Furthermore, based on preliminary work, we believe that additives also are a viable solution. Biocoal production: We produced and tested samples from the seven biomass feedstocks: AD, wheat waste, corn waste, woody hybrid poplar, woody pine and their barks. We also produced briquettes as an end-product for a coal power plant. We showed that we can control the properties of the biocoal to match those of coal in terms of fixed carbon, volatile matter and heat content. An important observation is that the minerals with the biomass are separated from the carbon structure after torrefaction and grinding, and hence provide conditions for removal of these minerals. Grinding testing revealed similar characteristics to those of coal.

Figure 6. Experimental results for burning 100 percent biocoal and coal in a 50kW test furnace.

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ASME Power Division Special Section | OCTOBER 2014

ASME FEATURE Biocoal combustion: Pulverized biocoal samples were burned at 100 percent in a 50kW test facility that operates at temperatures and residence times similar to those prevailing in coal-fired boilers. PRB and other coals also were tested. The combustion results showed similar behavior to those of coals burned under similar conditions.

Acknowledgment This project is sponsored in part by US-Israel Bi-National Research and Development (BIRD) Foundation under agreement # 1329. ~ References 1. Arias B, Pevida C, Fermoso J, Plaza MG, Rubiera F, Pis JJ Influence of torrefaction on the grindability and reactivity of woody biomass. Fuel Process Technology 2008; 89:169-75. doi:10.1016/j.fuproc.2007.09.002. 2. Bergman, P., Boersma, A., Kiel, J., Prins, M., Ptasinski, K., Janssen, F., 2004, “Torrefaction for entrainedflow gasification of biomass”, in: W.P.M. Van Swaaij, T. Fjällström, P. Helm, A. Grassi (Eds.), Second World Biomass Conference, Rome Italy, 10–14 May 2004. 3. Bourgeois, J., Doal, J., 1984, “Torrefied wood from temperate and tropical species, advantages and prospects,” in: H. Egneus, A. Ellengard (Eds.), Bioenergy 84, Vol III Biomass Conversion, Elsevier Applied Science Publishers, pp. 153–159. 4. Bridgeman TG, Jones JM, Shield I, Williams PT Torrefaction of reed canary grass, wheat straw and willow to enhance solid fuel qualities and combustion properties. Fuel 2008; 87:844-56. doi:10.1016/j. fuel.2007.05.041. 5. Couhert C, Salvador S, Commandré J. “Impact of torrefaction on syngas production from wood.” Fuel 2009; 88:2286-90. doi:10.1016/j.fuel.2009.05.003. 6. Duncan A, Pollard A, Fellouah H Torrefied, spherical biomass pellets through the use of experimental design. Appl Energy. doi:10.1016/j.apenergy.2012.03.035. 7. Korytnyi E, Saveliev R, Perelman M, Chudnovsky B, Bar-Ziv E. “Computational fluid dynamic simulations of coal fired utility boilers: An engineering tool.” Fuel 88 (2009) 9–18. 8. Lipinsky, E., Arcate, J, Reed, T., 2002, “Torrefied wood, an enhanced wood fuel,” Fuel Chemistry Division Preprints, 47, pp. 408–410. 9. Medic D, Darr M, Shah A, Potter B, Zimmerman J. “Effects of torrefaction process parameters on biomass feedstock upgrading.” Fuel 2012; 91:147-54. doi:10.1016/j.fuel.2011.07.019.

OCTOBER 2014 | ASME Power Division Special Section

10. Prins, M., Ptasinski, K., Janssen, F., 2006a, “More efficient biomass gasification via torrefaction,” Energy, 31(15), pp. 3458–3470. 11. Spitz, N., Saveliev, R., Korytnyi, E., Perelman M., Bar-Ziv, E., Chudnovsky, B. “Prediction of Performance and Pollutant Emission from Pulverized Coal Utility Boilers,” Chapter 3 in Electric Power: Generation, Transmission and Efficiency, Nova Science Publishers Inc., 2007. Editor: C. M. Lefebvre, pp. 121-170, Inc. ISBN: 978-1-60021-979-5. Editor’s note: This paper, a compilation of PWR201432031, PWR2014-32036 and PWR2014-32037, 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. Jaisen Mody, ME, PE, is general manager for Power Generation at Portland General Electric Company. You may contact him by emailing editorial@woodwardbizmedia.com. Roman Saveliev, Ph.D., ME, is manager at E.B. Clean Energy. You may contact him by emailing editorial@ woodwardbizmedia.com. Miron Perelman, EE, is senior research engineer, at Michigan Technological University. You may contact him by emailing editorial@ woodwardbizmedia.com. Ezra Bar-Ziv, Ph.D., is a professor of Physics and Chemistry at Michigan Technological University. You may contact him by emailing editorial@ woodwardbizmedia.com.

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TURBINE TECH

Important considerations in establishing combustion turbine blade and vane refurbishment intervals By Stephen R. Reid, P.E., TG Advisers Inc.

Combustion turbine blade maintenance and refurbishment intervals must take into account many design and operation specific factors. Combustion Turbine Hot Section blades and vanes are subject to a number of damage and failure mechanisms, as noted here.

Most common failure mechanisms • Creep - steady stress at elevated temperatures (base load concern) • High Cycle Fatigue – blade vibration • Thermal Mechanical Fatigue – combination of thermal and mechanical fatigue loading (low-cycle fatigue) • Foreign/Domestic Object Damage • Oxidation – elevated temperature exposure • Hot Corrosion – temperature and fuel environment related • Microstructural – aging, embrittlement Establishing an effective inspection interval based on a combination of the damage mechanisms noted above can be challenging. There can be a fine line between premature scrapping of parts and forced outages due to non-conservative design and operating assumptions. As operating experience is accumulated, damage signatures can help establish the types of mechanism that are present on a specific row under specific operating regimes. These, in turn, can help establish refinements in maintenance intervals for blade refurbishment. Some examples of common damage mechanism are noted throughout this article. Figure 1 illustrates stationary vane and

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Figure 1. An example of oxidation damage.

Figure 2. An example of vane trailing edge thermal-mechanical fatigue cracking.

surface oxidation damage from high temperature exposure. Upgrades in vane coating technology could be one consideration for extended maintenance intervals on these parts. The root cause for the cracking illustrated in Figure 2 was determined to be thermal mechanical fatigue. Upgrades in materials might be a consideration for extending TMF life, since these vanes are replaced with new parts. In other cases, unexpected vibration might be present in a unit and cause catastrophic failure of a rotating blade before it reaches its normal refurbishment schedule. An example of a combustion turbine blade root high cycle fatigue failure is shown in Figure 3. These types of failures are rare and typically are associated with generic/

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TURBINE TECH fleet design issues and/or an operational excursion that ultimately results in vibratory stresses that exceed the material’s endurance limit. The root cause of the failure in Figure 3 was determined to be an unstalled flutter condition that occurred at high mass flows on freestanding blades with detrimental blade-to-blade frequency relationships. This issue was eventually addressed by the OEM with a new design blade, with blade to first mode natural frequency separation.

Maintenance and refurbishment interval calculations A number of industrial sized combustion turbine OEMs have developed an equivalent operating hours (EOH) Figure 3. A combustion turbine blade root high cycle fatigue failure. formula to provide guidance for estabdesign unit at two locations that operate in cycling mode lishing intervals for blade path refurin one location and is base loaded in the other. After some bishment. In the most simplistic form, the EOH formulas operating time, the cycling mode blades might have signifinclude the following factors: icant creep life remaining. It would therefore be possible • Tracking of normal operating hours for a blade from the cycling unit to perform reliably in • Equating the number of starts to an hour equivalent the base loaded unit for some economically significant with a time multiplier • Equating the number of full load trips with a time multiplier • Peak load operating hour multiplier EOH formulas that are OEM specific can produce significant variations in refurbishment intervals depending on operating strategies. An example calculation using an EOH formula could produce an EOH of approximately 22,000 hours for a unit that has been operating at baseload for three years. Using the same EOH formula for a cycling unit, an EOH of ~ 38,000 hours was calculated. The example illustrates how the damage mechanisms of a base-loaded application are normally very different from a unit that has start/stop cycles. However, it should be noted that in many cases, cycling and operating hour damage do not occur in the same component locations, and are not additive as the EOH formula suggests. This is why some OEMs have adopted intervals based on total cycles or total operating hours, whichever comes first. In fact, to take this example one step further, a power producer might have the same

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additional time interval. Leveraging a pool of similar blades with different duty cycle exposure might provide an opportunity to reduce the pool of end of life blades. The elapsed EOH life determination would not provide that opportunity.

Going forward Blade and vane replacement costs can make up a large percentage of a plant’s operating and maintenance budget for major CT overhauls. Performing a thorough evaluation of the failure mechanisms that result in blade and vane replacement, and an assessment of the accuracy of the maintenance interval recommendation provided by the OEM might provide an opportunity to refurbish rather than replace. Issues with hot corrosion and oxidation might be reduced by use of coatings with better resistance to these mechanisms. Thermal barrier coatings might be a way to reduce parent material creep damage. Blades that have limited cycling life might operate reliably in base-loaded applications. Taking a proactive approach to manage part life and refinement of the predictive refurbishment interval process can ultimately reduce the cost of the number of parts requiring replacement. Destructive evaluation of parts at or near the end of their life can be very revealing. Vane/ blade metallurgical sectioning for accelerated creep life analysis, determination of tensile properties and coating effectiveness can yield significant knowledge that will help refine intervals and opportunities for extended part operating life. ~ Stephen R. Reid, P.E., is president of TG Advisers Inc. and has more than 29 years of turbine and rotating machinery experience. Reid and his team provide turbine troubleshooting, health assessments and expert witness services to major energy companies in the U.S. and have provided condition assessment evaluations on more than 100 turbine generators in the U.S. Reid also is a short course instructor for EPRI, ASME, Electric Power and POWERGEN, has numerous patent disclosures and awards, and published more than 20 technical papers and articles. Reid was the recipient of the 1993 ASME George Westinghouse Silver Medal Award for his contributions to the power industry and is past chairman of the ASME Power Generation Operations Committee. He is a registered professional engineer in the state of Delaware. You may contact him by emailing editorial@woodwardbizmedia.com.

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