July 2015

Return On Training 10 • Upgrade Damper Drives 13 • ASME: Automatic Fault Location 16

ENERGY-TECH A WoodwardBizMedia Publication

JULY 2015

www.energy-tech.com

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

Rotor Field Balancing

POWER-SEAL PM/PH SERIES

High Performance Butterfly Valves...

at their best when things HEAT up!

• Thru-Shaft design • Live loaded packing • Temperatures to 900ºF (1100º with Inconel Seat) • 150#/300# ANSI/ASME in stock 2”-36”, with 48” available

9955 International Boulevard Cincinnati, Ohio 45246 (513) 247-5465 FAX (513) 247-5462 sales@atcontrols.com www.a-tcontrols.com

ENERGYT ECH P.O. Box 388 • Dubuque, IA 52004-0388 800.977.0474 • Fax: 563.588.3848 Email: sales@WoodwardBizMedia.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 © 2015 WoodwardBizMedia.

All rights reserved; reproduction in whole or in part without permission is prohibited.

FEATURES

6

By Steve Kilmartin, E/One Corp.

10

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.

COLUMNS

13

Maintenance Matters

Upgrading power plants’ gas-fired boiler damper drives

By Dean Stedman, Rotork Dallas Inc.

24

Machine Doctor

Field balancing an integrally geared turbocompressor rotor

By Patrick J. Smith, Energy-Tech contributor

ASME FEATURE

16

Advertising Sales Executives Tim Koehler – tkoehler@WoodwardBizMedia.com Joan Gross – jgross@WoodwardBizMedia.com

Automatic fault location on distribution networks using synchronized voltage phasor measurement units

By Jonathan Lee, California Institute of Energy and the Environment Department of Electrical Engineering and Computer Science, University of California, Berkeley

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.

Return-On-Training-Investment (ROTI)

By Harold Parker, HPC Technical Services

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

A quick tour of critical auxiliary equipment for large steam turbine generators

INDUSTRY NOTES

4 27 28

Editor’s Note and Calendar Advertisers’ Index Energy-Tech Showcase

ON THE WEB Summer School continues with Energy-Tech magazine! Our next course is July 8-9, Belt Drives – Installation, Maintenance & Troubleshooting. There is still time to register at www.energy-tech.com/summerschool.

A division of Woodward Communications, Inc.

July 2015

ENERGY-TECH.com

3

EDITOR’S NOTE

Back to the ’80s New analysis of Clean Power Plan shows 1980-level emissions As a child of the 1980s, I have fond memories of watching Marty McFly and his DeLorean time machine drive through the continuum in the Back to the Future trilogy, setting things right. As each new installment came out, my dad would rent the videocassette tape and we’d make a Saturday night movie event of it in the living room, popcorn included.

As an adult in 2015, flying cars still aren’t a reality for my children, like much of the “innovative technology” highlighted in the movie. Even Doc Brown couldn’t have predicted the iPad. Instead we have the Internet, and all its possibilities, benefits and distractions, incorporated into a lot of old tech – an upgrade without any true innovation.

In my April note, I discussed the Clean Power Plan and the potential benefits to state economies that incorporate lower emissions standards and renewable energy generation. New model analysis by the U.S. Energy Information Administration shows that utilities choosing a compliance strategy based on cost could see emissions lowered to levels last seen in the 1980s, according to a May 26 article in the Houston Chronicle’s Fuel Fix blog.

Since I began working on Energy-Tech eight years ago, I’ve talked a lot about the changes the power generation industry would be adapting to in the coming years. Now those years are here, and with growing momentum from the international community – including religious leaders like Pope Francis – and the American public, those changes aren’t going to be sidelined easily.

Utilities that adapt to the changing power mix and regulations first will weather the changes the best and be able to find continued profitability in the long-term. As Americans who take pride in our innovative spirit, this is a challenge that should be embraced. An Apollo Program for our time.

I don’t expect my grandchildren to be riding around in flying cars, but I hope they live in an era when energy efficiency is a given, energy generation is diverse and emissions are so low that they cease to be a concern. American engineers have the knowledge and creativity to make this a reality – I look forward to seeing how they take us back to the future.

As always, thanks for reading.

Andrea Hauser

4 ENERGY-TECH.com

CALENDAR July 8-9, 2015 Energy-Tech University Summer School Webinar 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 Webinar 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 Webinar Course www.energy-tech.com/turbines Sept. 21-25, 2015 Machinery Vibration Analysis (MVA) Salem, Mass. www.vi-institute.org Sept. 22-24, 2015 Advanced Turbine Troubleshooting & Failure Prevention Webinar Course www.energy-tech.com/turbines Oct. 12-16, 2015 Balancing of Rotating Machinery (BRM) Knoxville, Tenn. www.vi-institute.org Oct. 20-21, 2015 Risk-Based Inspection for High Energy Piping Webinar Course www.energy-tech.com/piping Nov. 18-20, 2015 Gas and Steam Turbine Reliability Chicago, Ill. www.energy-tech.com/chicago2015

Submit your events by emailing editorial@woodwardbizmedia.com.

July 2015

FEATURES

A quick tour of critical auxiliary equipment for large steam turbine-generators

By Steve Kilmartin, E/One Corp.

Safety, risk mitigation and increased efficiency are requisite priorities for every power plant in this day and age. And as the nation’s generator fleet continues to age, extending the life and efficiency of a generating asset requires a broad perspective, including not only the machine itself, but the auxiliary systems and predictive maintenance systems that support it. So, let’s take a look at the critical auxiliary equipment and condition monitoring that is key to ensuring a turbo-generator’s maximum performance with minimum downtime.

Why hydrogen?

Central stations have produced and supplied electrical power to customer bases since the early 1800s. As power demand increased, so did the physical size of air-cooled generators that produced more megawatts and required more iron. In the early 1930s, it became apparent that a better method of cooling these large turbo-generators was needed and the first hydrogen-cooled generator was introduced.

Hydrogen replaced air as a cooling agent principally because it has the lowest density of any stable gas and has superior cooling properties. Properly used, hydrogen is 14x more efficient than air in removing heat and greatly reduces windage friction losses. The thermal conductivity of hydrogen is nearly 7x that of air, resulting in superior heat transfer through forced convention (Table 1).

Using hydrogen as a cooling medium delivers additional benefits. Because the generator case is a sealed pressure vessel, the internal components are less likely to become vulnerable to outside contaminants. Pressurized hydrogen also suppresses partial discharge and increases the amount of voltage required to cause a component breakdown.

Despite hydrogen’s many benefits as a cooling medium, caution must be exercised. For example, a mixture of hydrogen in air with a range of 5 percent to 75 percent becomes very explosive. Generator efficiency decreases in tandem with declines in hydrogen purity. Hydrogen purity should be maintained at more than 97 percent to ensure safe and efficient operation of the generator.

Hydrogen supply & control Safe operation and maintenance of hydrogen-cooled generators requires three different gases. During maintenance, the generator is purged of its hydrogen and filled with an inert gas (usually CO2). Then the generator is filled with air and 6 ENERGY-TECH.com

maintenance can be performed. This process must be monitored closely to ensure that no hydrogen ever mixes with the air.

The air — obtained from the power plant’s instrument air supply system — must be clean and dry. Plants often install an air dryer between their instrument air supply and the generator to ensure a clean, dry air supply.

Carbon dioxide (CO2) has been the traditional inert gas used to prevent the mixture of hydrogen and air. However, some power plants and generator OEMs now utilize nitrogen or argon. When utilizing CO2 as the intermediate gas, heed caution to minimize the chances of freezing and thermal shock to the generators. A CO2 vaporizer often is incorporated by utilities to prevent CO2 from freezing. Importantly, an operator should maintain a sufficient amount of CO2 on site in case emergency purging of each generator is required.

A gas manifold system is used to control the flow of gases from the bulk supplies to the generator case (Figure 1). Most gas manifolds incorporate a mechanical system that prevents hydrogen and air from being introduced to the generator at the same time.

Bearing lube oil and seal oil systems Electric power production is simple: Convert mechanical energy into electrical energy. The mechanical energy created by the turbine spins the rotating magnetic field or rotor. In order for the rotor to spin with minimal resistance, it must be supported on both ends with pressurized oil bearings, which vary in design based on mechanical considerations such as size, weight and speed.

Proper operation of the bearing lube oil system requires correct oil flow, pressure and temperature. The generator OEM should be consulted for detailed monitoring requirements. Additionally, the following parameters should be monitored: flow; inlet and outlet pressure; inlet and outlet oil temperature; inlet and outlet water temperature; filter differential pressure; and oil reservoir level.

A generator’s efficiency is directly related to hydrogen purity and case pressure. During normal operation of the generator, pure, dry hydrogen is employed. The hydrogen supply should be 99.997 percent pure with a dew point of less than -10oC regardless of its supply method: bottles, bulk tank or on-site hydrogen generator. In order to maintain both hydrogen purity and case pressure, the generator frame

July 2015

FEATURES

Figure 1. A gas manifold system is used to control the flow of gases from the bulk supplies to the generator case. Most gas manifolds incorporate a mechanical system that prevents hydrogen and air from being introduced to the generator at the same time.

is designed to serve as a Table 1 – Hydrogen vs. Air Comparison pressure vessel and a seal must be formed around the rotating field. The function Cooling Medium Molecular Weight Specific Heat Capacity Density of the hydrogen seals is to Air 28.95 1.00 1.00 minimize hydrogen leaking from the case and air enterHydrogen 2.02 14.30 0.07 ing into it. A film of presHydrogen at 30 psig 14.30 0.21 sured oil is applied to create Hydrogen at 45 psig 14.30 0.26 a seal around the gyrating Water 4.18 1000.00 rotor and the generator case, thus minimizing hydrogen usage. Proper operation oil filter differential pressure; seal oil reservoir level and seal and upkeep of the seals guarantees efficiency and safety. A oil vacuum tank pressure. potentially dangerous situation can occur if the hydrogen is allowed to drop below 74 percent, the explosive range.

Stator winding cooling water system The seal oil system consists of two seal glands, one on Larger hydrogen-cooled generators often incorporate the turbine end and one on the exciter end and a seal oil water as an additional cooling agent for stator windings. Most supply system (seal oil skid), typically located under the of the components that comprise a stator winding cooling generator. Proper operation requires adequate flow, pressures water system are primarily stainless steel or copper and are and temperatures. The following are typical seal oil system mounted on a single skid located under the generator’s belly. parameters that are monitored and are similar to the bearStator winding cooling water system designs vary depending lube oil system; seal oil flow; seal oil pump inlet and ing on the generator’s size and manufacturer. Some fabricaoutlet pressure; seal oil coolers inlet and outlet oil temperators build what is called a high-oxygen system (meaning the ture; seal oil coolers inlet and outlet water temperature; seal water has a high concentration of oxygen) while others will

July 2015 ENERGY-TECH.com

7

FEATURES incorporate a low-oxygen system with minimal levels of the dissolved oxygen content in the cooling water.

As with the bearing lube oil and seal oil systems, temperatures, pressures and flows require monitoring. Among them: Stator cooling water inlet and outlet temperatures, stator cooling water inlet and outlet pressure, stator cooling water filter differential pressure, stator cooling water flow. Besides the normal pressures, temperatures and flows, the water chemistry also should be monitored for conductivity, oxygen content, copper/iron content and pH value.

Figure 2

Figure 3

Excitation system Current flowing through the field coils or generator rotor windings establishes the magnetic field of large generators. Without a field current, there is no magnetic, and without a magnetic no electricity is produced. The process of creating this magnetic field by means of electric current is called excitation.

The excitation system is designed to control the supply of voltage and therefore the amount of current being generated through the rotor windings, which allows control of the generator output voltage. The excitation system is critical in generator control because it governs the reactive power and power factor controls between the energy-producing generator and the system grid.

Excitation systems are built in two basic designs: rotating and static. Even within these two designs, there are many different subsets. However, the primary function of each is to furnish DC power to the generator field, thus creating the magnetic field.

Since excitation voltage is a vital component in controlling the generator terminal voltage, an important design characteristic is the excitation system’s ability to produce high levels of excitation voltage — very quickly — following any changes in terminal voltage.

The excitation system is a critical part of power production that requires routine maintenance. Several essential parameters must be monitored: AC power into the excitation system, DC power out of the excitation system, exciter cooling air inlet and outlet temperature, collector and brush housing inlet and outlet temperature, and differential pressure across the filter used in the collector and brush housing.

These parameters are just examples. Consulting the OEM for a more comprehensive monitoring program is imperative.

Monitoring systems Several factors are taking place in the power industry that are making it necessary to perform more monitoring: increasing pressure to extend outages; increased cycling of generators; and the loss of power plant expertise as a result of the aging workforce and cutbacks in manpower. In the past,

Figure 4

8 ENERGY-TECH.com

July 2015

FEATURES it was not uncommon to have an outage every 18 months.

Now, however, it is not unusual to have an outage every five to 10 years. Whereas in previous eras most large generators were base load units, the current trend toward cycling these sizable units increases mechanical and electrical stress.

Operators can make critical decisions only if they are intimate with a generator’s inner-workings while it is online.

Operators must know: • The temperatures of water in and out of the hydrogen coolers, gas temperatures in and out of the hydrogen coolers, the stator windings temperatures and bearings temperatures – all valuable pieces of information • The purity and dew point of the hydrogen and how much is being consumed is essential knowledge • The vibration levels of the rotor, stator and end windings • If there are any shorted turns in the rotor windings, if there is any liquid in the generator case or if there is any overheating

authored numerous papers, including work as principal investigator for the “EPRI-Turbine-Generator Auxiliary Systems, Volume 3: Generator Hydrogen System Maintenance Guide.” Kilmartin began his career with E/One in 1988 as an instrumentation specialist. Prior to that, he worked in the instrument shop at GE, and also as an applications engineer at Mechanical Technology Incorporated in New York. His career has taken him in and around large machines, and around the world for more than 30 years. You may contact him by emailing editorial@woodwardbizmedia.com.

These embody just a few examples of conditions inside a generator that can be monitored with state-of-the-art instrumentation, and with skillful deployment can minimize downtime and maintenance costs. Figure 5 indicates a modern state-ofthe-art monitoring package.

Conclusion Obsolete and outdated auxiliary equipment often is ignored during generator inspections, upgrades and rewinds.

Auxiliary equipment is critical to ensure efficient, reliable and safe operation of the generator. Unreliable auxiliary equipment could potentially lead to a problem that ends in catastrophic generator failure.

Extending the period between outages means that auxiliary equipment is even more important for the safety and the efficiency of the generator.

With proper care and tending enabled via predictive monitoring and critical auxiliary systems, a turbo-generator can and will provide reliable and extended power production, even in protracted scheduled outage cycles. ~ Steve Kilmartin is the director of products and markets for E/One’s Utility Systems business.

Considered a leading expert in the field of generator monitoring and maintenance, he has

July 2015 ENERGY-TECH.com

9

FEATURES

Return-On-Training-Investment (ROTI)

By Harold Parker, HPC Technical Services

I had an interesting thought the other day about many of the costly incidents I have witnessed in my career. In more than 40 years, I’ve seen many damaging – and some catastrophic – incidents at the power plants where I have worked. Once it was an entire centerline of a 500 MW steam turbine generator destroyed. Another time it was a water induction incident that nearly destroyed the plant. Then there was the generator stator dropped from the 3rd floor down to the ground below. Another was a destructive overspeed (can you imagine your 3,600 rpm unit running at 5,400 rpm)? Multiple incidents where the turbine coasted down from rated speed without oil (didn’t take long to coast down). Multiple incidents where there was a hydrogen explosion. The list goes on.

What is the one thing in common with all of the above? The answer is part of my interesting thought – because every one of these incidents was avoidable!

At plant “A”, where they experienced one of the coast downs without oil, I was actually under contract to deliver a turbine-generator maintenance course at that site in September of that year. They called me up in mid-August and said they had good news and bad news. The bad news was they were going to cancel the upcoming maintenance class since they had decided that with the loss of oil coastdown repair, they would just start the planned outage now. The good news was they need operations training now.

Please note that when I say there was an operator error, I am not pointing a finger at an operator. I’m arguing there is an inadequate understanding of the operation of that system and/or inadequate understanding of the relationship of multiple systems.

With regard to the operator, I’d also add the operator is always involved since he/she is the last line of defense, even if they had only 9.8 nano-seconds to respond.

When I’ve been on site doing training, I’m often asked, “Why am I here? Why has this training session been scheduled?” A notable percentage of the time the answer was that this plant, or one of the sister plants within the company, had experienced an incident and management felt plan personnel needed further training to make sure this problem would not repeat itself. This is what I’d loosely describe as training that is “reactive.”

At some other plants, the answer to this question was they felt it was time to review these materials to ensure proper operating procedures were being followed and personnel were prepared for events that “could occur.” This is what I’d loosely describe as training that is “proactive.”

Think about this difference. When it comes to training the plant personnel, are you “reactive” or “proactive?”

On the “reactive” side of this analysis, you could look back at the plant “A” incident described previously and think about the cost. First, they had to make an emergency purchase of replacement power in the middle of August. Then they had the additional cost of repair. I’d argue that if personnel had been properly trained, this event would never have occurred and the costs, inconvenience and embarrassment would have been avoided.

On the “proactive” side of this analysis let’s look at plant “B.” This 500 MW unit keeps running along and nothing has happened (at least nothing that got a lot of attention). Why did nothing happen? Maybe it was because equipment was being properly maintained, or because operations followed thought out procedures, or because personnel responded to alarm situations in a way that resolved the problem before it became serious. We will never know how much money, inconvenience and embarrassment were saved. We’ll never know, because nothing ever happened. This fact makes it very difficult to put a $$ sign on the “Return-on-Training-Investment” (R-O-T-I).

Figure 1. Educational ladder

10 ENERGY-TECH.com

July 2015

FEATURES Another consideration is this: Training is not a check mark add understanding of the logic and its relevance to the on your employment records. Just because someone attended a equipment operation. class on a given subject 10 years ago does not mean that person 3. Compare the course learning objectives with these idenis adequately capable to operate or maintain the equipment today. tified needs.

I recall a systems engineer at a nuclear plant who had attended a 4. If using a stand-up instructor, make sure they are adecourse I delivered on turbine controls about 20 years ago. At the quately ‘expert’ on the topic, are a good presenter and time, this systems engineer was new to the job assignment. The are flexible. The word “adequate” is used to describe the engineer asked some very good questions, but they were all very expert as you the instructor should be “expert” relative to basic. the audience. He/she obviously doesn’t need to be a sciTwo or three years passed and, one day that engineer called entist or “the” design engineer. and asked if we could do the course again for their technicians.

We did, and that systems engineer attended a second time. This time, some very good ® questions were asked, that were clearly much more than the basics. A few more years passed and we were asked to come back and teach the course again. Some of the older technicians and the system engineer attended again. This time the questions from the more experienced engineers were significant.

The time elapse clearly demonstrated that in technical training we take a few steps with each training opportunity as we climb the ladder from being “new to the job” to being “expert.”

I’d argue that there was a meaningful 90° Prism & R-O-T-I along each step of the educational Close-Focus ladder. As a side note, this course was on a tips available!

• Sharp, Clear Photos & Video subject I first learned more than 40 years ago, • Large 5-inch LCD Monitor and during the class with the experienced systems engineer, I learned a few things as • Easy-to-Use Controls well. So think about Figure 1, where we’ve • Annotation Feature shown someone climbing the educational ladder. Given a particular topic, where are • Rugged Tungsten Sheathing you on that ladder?

• Quality Construction On the subject of maximizing your R-O• Precise 4-Way Articulation T-I in a proactive manner I’d suggest the following: • Starting at only $8,995 VIDEO BORESCOPES 1. Fully understand the background and education of the intended audience.

In stock, ready for overnight delivery!

2. Fully understand what they need Hawkeye® V2 Video Borescopes are fully portable, to know to do their job (while also finely constructed, and deliver clear, bright high being reasonably prepared for what resolution photos and video! The 5” LCD monitor could go wrong). As an example, allows comfortable viewing, and intuitive, easy-to-use plant personnel should know (a) the controls provide photo and video capture at the touch Quickly inspect cooling tubes purpose of the system, (b) normal inside heat exchangers, turbine of a button! V2’s have a wide, 4-way articulation and emergency operating modes, (c) blades, and much more! range, and are small, lightweight, and priced starting enough about the system to underat only $8995. V2’s are available in both 4 and 6 mm standably apply O&M procedures, (d) diameters. Optional 90° Prism and appreciate items that could go wrong, Close-Focus adapter tips.

Visit us at: and (e) emergency actions that might TRY Made in USA need to be taken. Maintenance perBEFORE sonnel would need to add disassembly, YOU BUY! reassembly and routine repair proceBooth # 415 dures. I&C personnel would need to Columbus, OH August 18 - 20, 2015 gradientlens.com/V2 800.536.0790

Hawkeye

Videoscopes

Fast, Reliable, Affordable, Visual Inspection!

July 2015 ENERGY-TECH.com

11

FEATURES

Figure 2.

5. Course materials should be easy-to-read and understandable (again this is a relative statement as definitions of easy-to-read will definitely vary with the complexity of the subject). Drawings should be simplified, but related to the original P&IDs, logic circuits or cross-sections that actually exist. An example of the use of a simple diagram to demonstrate a point of discussion is shown in Figure 2, a steam turbine driving a generator. The drawing is often used as a lead in to a discussion of basic generator theory.

6. The instructor should ask relevant “check-your-understanding” (CYU) questions within the presentation. This is a test of the students’ learning AND of the instructor’s presentation. The student and the instructor need to be communicating, and CYU is a check of that communication.

7. Arrange thought-out “on-the-job learning activities” (OJLA) that will allow the learner to apply the information learned. For example, schedule a walkdown of the equipment. Ideally the instructor would be present, but often this is not easily done since there can be so many restrictions. So make a list of OJLA and accomplish this list of items in a convenient manner.

8. Upon completion of the material there is a final examination. Where there may be employee/employer agreements that make the delivery of a final examination, both parties should understand that there are mutual gains in this process and they should work out a functional plan on how to proceed.

9. Now, after completion of the exam, we should recognize that any good training program is a project in the works.

We should evaluate the effectiveness of this program and revise as needed. ~ Harold Parker started work in 1969 as a field engineer for GE in Detroit, Mich. He later became a GE start-up engineer, responsible for commissioning new turbine-generators and resolving operational problems as they occurred. In the mid-1970s he became a training specialist and then a training manager, responsible for training new and experienced engineers. Today, he is part owner of HPC Technical Services, www.hpcnet.com, and continues to implement ADDIE training programs in the power generation industry. You may contact him by e-mailing editorial@woodwardbizmedia.com.

Have you visited our new website?

We’ve got a new look!

Featuring an updated interface with improved search features, faster access to topics and updated news and features, events calendar and much, much more!

ENERGY-TECH.com 12 ENERGY-TECH.com

July 2015

MAINTENANCE MATTERS

Upgrading power plants’ gas-fired boiler damper drives

By Dean Stedman, Rotork Dallas Inc.

For today’s North American power plants, modernizing a utility boiler presents tough challenges, as well as major opportunities.

One problem associated with old boilers is outdated and inefficient equipment. No matter how good a maintenance staff is, keeping an aging boiler operational presents a host of daily challenges. In many power utility plants, it’s a common problem that as existing boilers age, the experienced manpower required to operate and maintain the equipment decreases. Add to this the increasing environmental pressure to reduce emissions, and it’s clear that upgrading the power plant’s utility boiler often surfaces as a top management priority.

At first, the challenge of modernizing the instrumentation of an old utility boiler can seem overwhelming, especially when the boiler might have been commissioned in the 1960s.

Historically in the U.S., the desired management approach for power utility base load preference has been the domain of large, coal-fired boilers.

The recent abundance of inexpensive natural gas, however, means the emphasis has shifted to modernizing gas-fired boilers. With stricter emissions restrictions exerted by the EPA and local regulators, implementing a cost-effective approach to upgrading gas-fired utility boilers makes more sense than ever before.

Focus on damper drives One major opportunity to consider when exploring the feasibility of upgrading boiler performance is to focus on the advantages associated with retrofitting the boiler’s damper-drive equipment. Recent advances in damper drive technology offer a reliable and cost-effective way to make an immediate – and significant – improvement in operational efficiency and emission reduction.

By pinpointing and upgrading key damper drive applications, power plants can often achieve significant improvements in efficiency and reliability. In short, by replacing old damper-drive technology with modern, fast-acting and precise equipment, a power plant can achieve important increases in the BTU/fuel, as well as MW/fuel ratios.

Furthermore, new damper-drive equipment can help reduce emissions, improve boiler draft control, and lower fuel consumption. In fact, the latest generation of rotary-vane damper drive equipment provides many features for extremely fast, safe operation. The drives are easily networked for automated operation and can be set to fail CW, CCW or last position. Most important, retrofitting old damper-drive technology with new equipment can be surprisingly cost-effective and easy to install.

Figure 1. The old, existing equipment included aging damper drives and indicator switches that were problematic.

Upgraded damper drives to meet regulations for industrial boilers Upgraded dampers can assist industrial boiler owners to comply with the EPA’s new boiler MACT rules. The U.S Environmental Protection Agency has published the “National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters; Final Rule Jan. 31, 2012” in the Federal Register. This regulation affects about 1,700 existing major source facilities, with an estimated 14,316 boilers and process heaters.

July 2015 ENERGY-TECH.com

13

MAINTENANCE MATTERS

Figure 2. Two new-generation, direct-mount damper drives were installed as a test to evaluate performance.

Figure 3. As part of the retrofit project, offset mounting designs were required for some structural areas around the boiler.

Retrofitting existing dampers with new damper-drive retrofits can provide a better, cleaner burn and help power utilities meet demanding regulations. Furthermore, the Boiler Maximum Achievable Control Technology (Boiler MACT) Rule require some boiler owners to carry out tune-up procedures either annually or bi-annually. Two major components of the tune-up procedure – where modern damper drives directly influence boiler performance – are the accurate control of the air-to-fuel ratio and in optimizing CO and NOX emissions.

14 ENERGY-TECH.com

Real life example of a damper-drive retrofit Many power plants in the U.S. and around the world have recognized that upgrading key damper drives in their facilities is a wise business decision.

Below is an example of how one U.S. power utility plant implemented this strategy.

In this particular situation, the tangentially fired (“T-Fired”) power boiler hosts 12 Auxiliary Air dampers and 12 Fuel Air dampers, but the drives were failing in their performance and were simply worn out beyond their service life. (Figure 1) Acting in consultation with a major damper-drive manufacturer, plant management decided to install two new, direct-mount, rotary-vane register drives in the spring of 2014 as a test fit.

These two pneumatic drives featured a limit switch module for damper position and permissive start-up reading back in the control room. Each drive also included a 24V DC dual-coil solenoid compatible with the plant’s existing DCS command system. (Figure 2) The test drives performed admirably through the summer of 2014. Because of the major improvements that could be realized, plant management quickly approved the funds to retrofit the remaining 22 drives in the fall of 2014.

The benefits of the new drives were immediate. One such benefit was that the new drive equipment saved plant operators from making trips up and down the boiler. In the past they were usually dispatched out to the boiler to work on air connections, changing supply lines to the drives, and dealing mechanically with any sticking drives.

In addition to the upgraded drives, the retrofit included installation of a windbox bearing upgrade at each damper location. Quite often, the windbox bearing is the source of the problems found with dampers that have binding issues or are frozen in place. Often this looks like an actuation or instrumentation problem from the control room. Those symptoms contribute to a false reading in the DCS. So, some of the register dampers believed to have a damper-drive problem were in fact frozen in place. Addressing both the windbox damper bearings and the damper drives at the same time is very beneficial to aging boilers.

Part of the solution for instrument changes on the boiler relate to environmental constraints both today and those that might arise in the future. The latest generation of damper drives was an ideal choice. These new drives are compatible with the current DCS system, so the utility did not need to make any control room hardware or software changes. The register dampers are currently solenoid operated (24 V DC), but are also convertible for positioner upgrade in case future environmental regulations force the utility to further reduce NOx output. The latest generation of damper-drive design offers that flexibility.

Another important aspect of the retrofit project was that the plant’s utility staff personnel were able to complete the windbox bearing and drive upgrades without a contractor, using only their own people. The damper-drive manufacturer supplied detailed drawings with full installation and operation manuals, along with a day or two of on-site assistance for the installation team. (Figure 3)

July 2015

MAINTENANCE MATTERS

This provided a significant savings to the utility by eliminating outside contractor expenses.

Overall, the installation went very well. By installing the two test drives in early spring, the utility was able to create a game plan for the main installation that followed.

They installed the remaining 22 drives in about a week. That included removal the old drives, torching out the weathered shaft glands that were part of the Figure 4. Drop-In-Place retrofit original windbox trim, and then solutions are available that precisely welding in the windbox bearing fit new damper drives in the existing applications with no field upgrades into place. Once the modifications. bearing upgrades were set, the new damper drives also were bolted firmly in place.

The plant technical service team set the limit switches, installed air headers and flex lines to each new drive. All limit switches and solenoids were then field-wired and marshalled into corner-mounted electrical enclosures with flex conduit and wiring.

A Drop-In-Place solution A Drop-In-Place damper-drive retrofit solution is available that precisely fits the new equipment into the existing application with no field modifications. (Figure 4)

Such a retrofit program provides end-users with a high-performance drive that can be installed without any field engineering or fabrication, using basic hand tools in a short time.

Existing connecting rods and linkages are reused without modification.

With a Drop-In-Place direct-mount or pedestal-mount retrofit drive: • The new drive will match the existing drive footprint or mounting surface • The drive shaft and drive lever are in the exact same place relative to the floor mount or direct mount bolt holes • The drive lever will be dimensionally identical to the existing lever and will rotate through the same arc • No costly field design or fabrication is required Key features of a pneumatic Drop-In-Place damper drive include: • 100 percent duty cycle, with a continuous modulating service rating of 3,600 starts per hour without overheating • High speed/high-torque, up to 20,800 lbf-ft. with stroke speed as low as 3 seconds full scale • Easily serviced with open-frame design • Excellent in harsh, high-temperature environments • Virtually zero air bleed in resting state – reduces air consumption

Summary Today’s latest generation of rotary-vane damper-drives offer power plants an economical and convenient way to upgrade key areas of an existing boiler to improve efficiency, reduce maintenance and achieve compliance with emission regulations. By working closely with an experienced damper-drive manufacturer right from the beginning, the entire project and installation of the proper equipment can be done quickly and inexpensively. ~ Dean Stedman is the current product manager for Type K Damper Drives, a division of Rotork Controls. His experience includes more than 30 years in damper manufacturing and controls automation. You may contact him by emailing editorial@woodwardbizmedia.com.

Benefits of pneumatic drop-in-place retrofits

Installation of new damper drives can be quick, easy and provide many important benefits, such as: • High speed continuous modulation of ID/FD fan and • Precise damper and burner positioning; inlet guide vanes; • Simple commissioning and diagnostics; • Improved modulation and control of secondary air • Low running costs, virtually maintenance-free; dampers; • Wide range of control system interfaces, including • Improved automation and burner management; pneumatic, analog and bus network communica• Quick response to plant demand; tion. Digital communication compatibility is available • Improved reliability in high temperature environments, for open Fieldbus protocols, including Profibus, up to +300° F. (+149° C); Foundation Fieldbus, HART and Modbus.

July 2015 ENERGY-TECH.com

15

ASME FEATURE

Automatic fault location on distribution networks using synchronized voltage phasor measurement units

By Jonathan Lee, California Institute of Energy and the Environment Department of Electrical Engineering and Computer Science, University of California, Berkeley

System reliability and resilience are major goals of the modernization and creation of a smart grid. In the United States, power outages are estimated to cause $79 billion in annual economic losses, and the cost of each outage increases with duration[1]. Automated fault location systems have the potential to reduce outage time and costs to customers by allowing fast and efficient deployment of repair crews.

Furthermore, 90 percent of outages originate in distribution systems[2], highlighting the need for fault location algorithms tailored to generally opaque distribution feeders.

The problem illustrated by these statistics is this: the costs of outages demand investments to reduce outage time, but the problems occur on the distribution system, where the cost of undergrounding or heavily instrumenting every feeder also becomes very high[2]. An effective fault location system should be accurate enough to direct maintenance crews directly to the point of the fault, and be cost effective so that significant investments are not required to enable the system.

Power system faults can be classified as either series or shunt faults. A series fault (also known as an open circuit fault) is a fault for which the impedances of each of the three phases are not equal, usually caused by the interruption of one or two phases[3]. A shunt fault (also known as a short circuit fault) is defined as a fault that is characterized by the flow of current between two or more phases or between phase(s) and earth at the frequency of the associated power system[3]. Shunt faults are generally more severe than series faults and can cause fires or damage to equipment from high short circuit currents[4]. From 1992-2011, weather alone caused 78 percent of customer outages in the United States[6].

Not only are overhead distribution circuits highly susceptible to shunt faults, but the circuits in rural areas that are exposed to the elements are more likely to be long, sparsely loaded and in difficult to access areas. This makes an important class of faults difficult to locate by visual inspection.

Existing fault location methodologies Existing methods of fault location vary in complexity and in feasibility. The traditional brute force method consists of obtaining an initial estimate of the location of a fault from

16 ENERGY-TECH.com

mapping customer outages, performing switching operations and then sending repair crews to visually inspect long sections of line[7]. While reliable and easily performed, this method is antiquated and prolongs outage time.

Another class of fault location systems, often referred to as traveling wave methods, relies on a high sampling rate and synchronized measurements to calculate the location of the fault[8]. This type of approach involves using signal processing techniques (particularly wavelet transforms) to identify the time at which the disturbance from a fault is observed.

Because the time for the signal to propagate from the disturbance to the measurement equipment is a function of the distance from the fault, the difference in observed disturbance times at different synchronized measurement devices can be used to locate the fault[9]. Another wave based approach is presented in Ref. 10 that is specifically tailored for tree structured distribution systems with distributed generation and makes use of the difference in arrival times of reflected waves, rather than synchronized measurements. These techniques have been shown to be highly accurate and robust to variations in system conditions (including loading and distributed generation) since they are not dependent on any assumptions about the system besides the topology and line parameters.

A third class of fault location systems for distribution networks, which are broadly known as impedance based methods, involve calculations using line impedances and observed changes in voltage and current at the substation[5]. These methods vary in subtle ways, but the general approach is to use pre-fault and during-fault voltage and current measurements to estimate the fault loop impedance, which depends on the location of the fault. A comprehensive review of some of the more cited impedance based approaches is given in Ref. 11 and a comparison of the performance of the leading algorithms is presented in Ref. 12.

Proposed solution This paper presents an automated fault location algorithm for location of distribution shunt faults using synchronized voltage phasor measurement units (PMUs). PMUs have experienced rapid growth in transmission systems to almost

ASME Power Division Special Section | July 2015

ASME FEATURE

Figure 1. Feeder diagram with aggregated loads

100 percent coverage, largely because of the range of applications they support[15][16], but in particular for observing angle stability and general operating state. A project conducted in partnership by the California Institute for Energy and the Environment, the University of California, Berkeley, Lawrence Berkeley National Labratory, and Power Standards Lab Inc. is developing a low cost, high precision phasor measurement unit specifically designed for distribution systems[17]. The GPS synchronized device has a frequency of 512 samples per cycle (31 kHz on a 60 Hz system) and is capable of measuring subcycle phase angle difference between devices. It utilizes the Simple Measurement and Actuation Profile (sMAP) technology for concentration of data, creating a foundation for application based software such as fault location[18]. It is expected that similar to transmission systems, PMU technology will present a compelling business case for the grid of the future by enabling many different applications through system awareness. A fault location approach based on PMU data differs from the specialized fault indicator networks and wave sensors described above by leveraging a technology with other applications and a readily available data stream; i.e. the cost of instrumentation need not be justified by fast fault location alone.

The proposed algorithm uses pre- and during-fault voltage magnitude and phase at the substation and remote PMUs, as well as current measurements at the substation and an imprecise system model in order to pinpoint a fault in less than a minute. The addition of PMU data to substation current measurements improves upon traditional impedance methods by measuring the behavior of the system on both sides of the fault, making the estimate more robust to the distance of the fault from the substation, variations in system conditions, and uncertainties in system models. In addition to the incorporation of remote measurements, a novel method of load aggregation is used that improves accuracy for higher impedance faults. The potential for using remote measurements of voltage sag data has been explored in Refs. 19 and 20, but these methods do not explore the potential benefit from phase angle difference. A method that uses PMU data is discussed in[21], but the paper focuses primarily on the related topic of PMU placement, rather than the response of the algorithm to variations in system conditions and uncertainty in system state.

July 2015 | ASME Power Division Special Section

Formulation of algorithm using PMU measurements Scope of algorithm The algorithm presented is designed for shunt faults occurring on sections of the feeder that are instrumented by a PMU on either end, such that the fault occurs between the two PMUs. In practice, this would mean faults that occur on the primary distribution system because each small lateral and customer connection would not be instrumented. Fast location of these faults is especially important because, unlike faults that can be isolated on laterals, these faults will affect the most downstream customers. Faults that occur on laterals that are not instrumented can be located to the branch point using the proposed algorithm in order to identify the faulted lateral; and then any of the established single end impedance

Applications: • Steam pressure vessels • Hot water heaters • Demineralizers • Steam humidifiers • Water purifiers • Refrigeration units • Liquid treatment vessels

• Compressed air tanks • Filtering units • Dryer cans in paper mills • Water towers • Water softeners • Deaerators • Make-up tanks

The Topog-E Gasket Company produces gaskets to fit every boiler in production today.

Topog-E® Series 180 molded rubber gaskets are special for many reasons.

Over forty years as the industry standard have given us feedback as to why!

1224 North Utica | Tulsa, OK 74110 T: 918-587-6649 | E: info@topog-e.com W: www.topog-e.com

ENERGY-TECH.com

17

ASME FEATURE multiple PMUs is described in the next section. The fault is assumed to be on the line connecting nodes k and k+1. Prefault conditions are estimated. Then, during-fault load is estimated and a least squares algorithm is used to estimate fault distance d as a fraction of the line length. If the optimal value of d is one (implying that the fault is at or beyond the end of the line segment), then the next line section is considered.

There are PMUs on each phase at the substation (node S) and at the end of the feeder (node R). The substation current is also measured for each phase. All loads and laterals between nodes S and k are modeled as a single unknown load, as are all loads and laterals between nodes k+1and R, as shown by the dashed rectangles in Figure 1. Note that before the fault, If = 0.

Figure 2. Multiple fault locations depending on remote PMU

measurement methods can be used to estimate the location of the fault on the lateral.

High level characterization The proposed fault location algorithm is described by the following process: 1. Identify the type of fault and which phases are affected.

2. Select the PMU at the substation and one of the remote PMUs. 3. Starting at the substation, iterate over each line segment connecting the two PMUs. Assume a fault on that line segment and calculate the fault distance. If the calculated distance is greater than the line length, continue to the next line segment. If not, the fault is located according to these two PMUs. 4. Repeat steps 2 and 3 for each remote PMU. 5. Resolve the multiple location estimates from each PMU to a single estimate of the fault location.

Identification of fault type Distribution shunt faults on three phase lines can be of various types. It is necessary to know the faulted phase(s) in order to accurately locate the fault. Ref. 22 describes a method to classify faults based on the rotation of the negative sequence voltage during a voltage sag. This method is employed at the substation to determine which phases to inspect for the fault.

Estimation of pre-fault conditions In this lumped load model with PMU measurements, the voltages and currents at nodes k and k+1are observable before the fault if the location of the equivalent loads are known, as expressed by the parameters α1 and α2. Z1 and Z2 are the known line impedance parameters between the source and node k and between node k+1and the remote PMU. Zf is the impedance of the assumed faulted line segment, and αi can be estimated using power flow simulations for the normal operation of the feeder. The advantage of this model is that it is robust to conincident load variations.

This model is built off of the assumption that loads are not directly measured or known, and that as load varies, its spatial distribution remains roughly constant (this might not apply to all feeders, but is especially applicable to feeders with similar customers). Leading fault location algorithms proposed in Refs. 11 and 12 rely on the stronger assumptions of either knowing each load or placing all load at the end of the feeder, which can be relaxed because of synchronized remote end voltage measurements.

The voltage at the equivalent loads and at the nodes on either end of the assumed faulted section are given by Ohm’s law and KCL in Eqs. 1-5. These relationships hold both before and after the fault, though the PMU voltages and substation current will change as a result of the fault. Voltages and currents are considered to be 3×1 vectors representing phase quantities. Impedances are 3×3 matrices and αi is a 3×3 diagonal matrix representing the location of the equivalent load on each phase.

Equation 1

Calculation of fault distance The following procedure is used to calculate the location of the fault using pre- and during-fault substation measurements and a remote PMU at the end of one of the radial feeder paths. The consolidation of measurements from

18 ENERGY-TECH.com

Equation 2

ASME Power Division Special Section | July 2015

ASME FEATURE Equation 3

Equation 4

Equation 5

Before the fault, no current is lost on the line connecting nodes k and k+1, which allows us to write Eqs. 6 and 7 from KCL and Ohm’s law. The linear system of Eqs. 1-7 can be uniquely solved for the 7 unknown variables[VL1,VL2,Vk,Vk +1,Ik,IL1,IL2] to determine the pre-fault state.

Equation 6

Figure 3. Fault positions on IEEE 123 bus test feeder

After the fault Eqs. 6 and 7 no longer hold, and Eqs. 10-12 are introduced. Note that in the previous section, prefault measurements were used, but now during-fault substation and PMU measurements are used.

Equation 7

Estimation of during-fault load currents Following the fault, Eqs. 1-5 still hold, assuming that Îąi does not change (i.e., load currents may change after the fault, but their spatial distribution remains constant). At this point we must introduce a static load model to estimate the during-fault load currents. We use the ZIP model described in Ref. 14. This allows for the calculation of the duringfault load current where the parameters Z% +I% +P% = 1 describe the proportion of the load that is constant impedance, current and power, respectively. It is important to note that this approach does not assume knowledge of each individual load, but allows for a general adjustment of the aggregated load. The during-fault voltage VLi is given by Eqs. 1 and 2. The loads are assumed to be constant power factor as described in Eq. 9.

Equation 8

Equation 9

Eqs. 8 and 9 yield an estimate of the during-fault total load current IL0 i from during-fault measurements and the prefault estimates of loads from the previous section.

Calculation of fault distance

July 2015 | ASME Power Division Special Section

Equation 10

Equation 11

Equation 12

We also include the estimates of during-fault load currents through Eqs. 13 and 14.

Equation 13

Equation 14

Forgetting about fault distance d for a moment, there are nine unknowns[VL1,VL2,Vk,Vf ,Vk+1,IL1,Ik,If ,IL2]. The system of equations given by Eqs. 1-5 and 10-14 gives 10 linearly independent complex equations with respect to those nine complex unknowns (for a three phase line it becomes 30 equations and 27 unknowns). If the fault is identified to be single phase or two phase, an additional equation (or two equations) is included that set the fault current on the healthy phases to zero. For a given d, this overdetermined system of equations can be solved by a least squares method,

ENERGY-TECH.com

19

ASME FEATURE

Figure4. Algorithm error with respect to distance

or weighted least squares if some measurements or assumptions are known to be more accurate than others. Because the system is overdetermined, there can exist some least squares error ξ≼ 0. The problem of locating the fault can then be formulated as in Eq. 15, where ξ(d) is the error from the least squares solution as a function of fault distance.

Equation 15

To solve Eq. 15, a simple search with a fixed step size can be used. The step size can be set to be the desired fault location accuracy (on the order of 1 m). The bounds on d and the relatively large acceptable error allow for a brute force search to be computationally tractable. If the optimal value of d is 1, then the fault is on the next line segment, and the preceding calculations are repeated for each line segment until the optimal d is less than 1.

Resolution of multiple estimates The procedure described in the previous section yields an estimate according to a single remote end PMU. Consider the representation of a radial distribution feeder with a tree structure and multiple PMUs, as in Figure 2. The PMUs are located at the end of lines, and the arrows show the respective estimates of the fault. As shown, different remote PMUs will give different fault locations. This is because a fault occuring on the line connecting one PMU to the substation might appear as on a lateral for a different PMU, and the result from this PMU will report the fault as occuring at or near the junction point for the lateral. In Figure 2, PMUs 1-3 will estimate the fault near one junction, PMU 5 will provide another more accurate estimate near another junction (that is farther from the substation), and PMU 4 will

20 ENERGY-TECH.com

provide the most accurate estimate as the fault occurs on the direct path to it from the substation. In this case, there are essentially three estimates, and the task is to choose the one closest to the fault. In some cases, the fault might occur on the direct path to k PMUs, and in this case not a single estimate, but an average of these k estimates should be taken.

The following recursive algorithm can be used to obtain a single estimate of the fault location. It relies on reasonable accuracy of the preceding calculations, and on the observation that incorrect estimates will be near a branch point that is closer to the substation than the actual fault location; implying that the best estimate (or cluster of estimates) will be the one farthest from the substation.

The first step is to identify the point at which the feeder branches to different PMUs, or equivalently the last common node on the path from the substation to each remote PMU. If all of the fault location estimates are closer to the substation than that branch, then we can assume the fault occurs upstream of that branch, and the average of all of the estimates are taken. This is the first stopping criterion. If not, the remote PMUs are paritioned into groups based on which branch they are in. If we conceptualize the radial feeder as a tree, and each PMU is a leaf of the tree, then we are splitting the tree into subtrees at the first branch point (for simplicity assume there are two branches - a binary tree - recognizing that the approach can easily be extended if there are more than two subtrees at a branch point). Next, the mean fault location (distance from the substation) according to each of the two groups of PMUs is calculated. If both averages are within 50-m of each other, then there is no way to determine which is more correct, so the fault is assumed to be at the branch point. This is the second stopping criterion.

However, if there is a significant distance, the group that estimates the fault farther away is chosen, and the same approach is applied recursively to that group until either of the two stopping criteria are met or there is only one PMU in the group.

For the case in Figure 2, the branch point is shown by the dotted circle. The arrows show the location of the estimate according to each PMU. PMUs 1 and 2 will be on one branch, and PMUs 3 and 4 will be on another. PMUs 1 and 2 will give estimates close to the branch point, but PMUs 3 and 4 will give estimates farther away, so the estimates from PMUs 1 and 2 are discarded. The next branch point is shown by the dashed lines, but because the estimates from PMUs 3 and 4 are close to each other, the branch point is taken to be the fault location. Had the estimate from PMU 4 been further away, then it would be taken to be the fault location.

Discussion This paper proposes a novel fault location algorithm that leverages a synchronized voltage measurement stream in order to increase visibility of the feeder during the fault. The

ASME Power Division Special Section | July 2015

ASME FEATURE use of these accurate PMUs and the proposed algorithm has several advantages for fault location. When compared with other sensor based platforms, it drastically reduces the number of sensors needed to locate faults. When compared with traditional impedance based methods, it increases accuracy, especially at remote ends of the feeder and for higher impedance faults, which are traditionally the downfall of substation based impedance approaches. Travelling wave methods remain superior in accuracy and robustness because they are not affected by system loads (though uncertainties in line parameters can introduce error), but they require specialized equipment that does not serve any other purpose. The real power of the PMU based approach is that it leverages a data stream that is not specific to fault location. In the transmission system, PMUs have become ubiquitous because of their many applications to system diagnostics and control, and fault location is just one of many applications. This paper demonstrates that a PMU based approach has the potential to automatically and remotely locate faults on the order of meters or tens of meters, which is generally sufficient for dispatching maintenance crews or executing switching operations in the event of a fault.

The algorithm yields acceptable results for preliminary testing; however, there are multiple factors that need to be explored in simulation and physical environments. These areas of further research can broadly be classified as sources of error in the modeling of either loads, faults and measurement equipment. On the load side, one of the most important is the spatial distribution of the loads. Though the algorithm is robust to variations in the total load level, it is unclear what the effect of non-coincident load variation is. In addition, the response of loads under fault currents needs to be better modeled than the traditional ZIP model specified in the IEEE 123 bus system. In addition to load response during faults, the response of solid state voltage regulators needs to be modeled and accounted for in the fault location process.

It is important to note that for the purposes of the preliminary testing of the algorithm presented in this paper, only ideal resistive faults are modeled. Arc faults and other non-ideal faults, especially faults with time varying impedances, have the potential to introduce additional error. In addition, the simulation conducted for this paper assumes ideal measurements. While the voltage angle measurements from the PMUs have an accuracy of 0.01 degrees, there is a potential for fault conditions to saturate current transformers and limit the effectiveness of the method. The simulation in this paper shows that the method is robust to variations in fault impedance in the range of typical shunt faults[13]. In order to properly assess the limitations of the method, this variation in impedance needs to be combined with non-ideal fault modeling and error models in measurement equipment to determine under which conditions the algorithm yields unacceptable error. As faults create a system state that is out-

July 2015 | ASME Power Division Special Section

side of the bounds of normal operation and well developed models, there is no substitute for testing of a fault location algorithm on an operating feeder or physical test feeder.

However, this research demonstrates that the use of high precision synchronized voltage measurement devices provides additional knowledge of the system state both before and during the fault that can be used for a more robust and accurate fault location algorithm than traditional impedance based methods.

Acknowledgements This research was funded by the U.S. Department of Energy, ARPA-E Award #DE-AR0000340. Special thanks to Prof. Alexandra von Meier and Dr. Reza Arghandeh of the California Institute for Energy and Environment (CIEE) and Dr. Emma Stewart of the Lawrence Berkeley National Laboratory (LBNL) for their advice and support. ~ References 1. K. H. LaCommare and J. H. Eto, “Cost of Power Interruptions to Electricity Consumers in the United States,” Energy, vol. 31, no. 12, pp. 1845–1855, 2006.

2. K. L. Hall, “Out of Sight, Out of Mind: An updated study on the undergrounding of overhead power lines,” Edison Electric Institute, Tech. Rep., 2013.

3. “International Electrotechnical Vocabulary. Chapter 448: Power system protection,” IEC Std. 60050-448, 1995.

4. M. Ohrstrom, “Fast Fault Detection for Power Distribution Systems,” Ph.D. dissertation, Karlstad University, 2003.

5. M. M. Saha, J. Izykowski, and E. Rosolowski,˙ Fault location on power networks. Springer, 2010.

6. E. Mills, “U.S. Disaster Reanalysis Workshop, National Climatic Data Center, Asheville, North Carolina,” in Electric Grid Disruptions and Extreme Weather, May 2012, accessed:2013-10-14.

7. “IEEE Guide for Determining Fault Location on AC Transmission and Distribution Lines,” IEEE Std C37.1142004, pp. 1–36, 2005.

8. P. Gale, P. Crossley, X. Bingyin, G.Yaozhong, B. Cory, and J. Barker, “Fault Location Based on Travelling Waves,” in Developments in Power System Protection, 1993., Fifth International Conference on. IET, 1993, pp. 54–59.

9. F. H. Magnago and A. Abur, “Fault Location Using Wavelets,” Power Delivery, IEEE Transactions on, vol. 13, no. 4, pp. 1475–1480, 1998.

10. Borghetti, M. Bosetti, C. Nucci, M. Paolone, and A. Abur, “Integrated use of time-frequency wavelet decompositions for fault location in distribution networks: theory and experimental validation,” Power Delivery, IEEE Transactions on, vol. 25, no. 4, pp. 3139–3146, 2010.

11. M. M. Saha, R. Das, P. Verho, and D. Novosel, “Review of fault location techniques for distribution systems,” Power

ENERGY-TECH.com

21

ASME FEATURE Systems and Communications Infrastructures for the future, Beijing, 2002.

12. J. Mora-Florez, J. Melendez, and G. Carrillo-Caicedo, “Comparison of impedance based fault location methods for power distribution systems,” Electric Power Systems Research, vol. 78, no. 4, pp. 657–666, 2008.

13. S. Hanninen and M. Lehtonen, “Characteristics of earth faults in electrical distribution networks with high impedance earthing,” Electric Power Systems Research, vol. 44, no. 3, pp. 155–161, 1998.

14. Y. Li, H.-D. Chiang, B.-K. Choi,Y.-T. Chen, D.-H. Huang, and M. G. Lauby, “Representative static load models for transient stability analysis: development and examination,” IET Generation, Transmission & Distribution, vol. 1, no. 3, pp. 422–431, 2007.

15. U.S.D. of Energy, “Summary of the North American Synchrophasor Initiative (NASPI) Activity Area,” June 2012.

16. N. B. Bhatt, “Role of synchrophasor technology in the development of a smarter transmission grid,” in Power and Energy Society General Meeting, 2010 IEEE. IEEE, 2010, pp. 1–4.

17. A. von Meier, D. Culler, A. McEachern, and R. Argandeh, “Micro-synchrophasors for distribution systems,” in IEEE 5th Innovative Smart Grid Technologies Conference, Washington, D.C., February 2014.

?

18. S. Dawson-Haggerty, X. Jiang, G. Tolle, J. Ortiz, and D. Culler, “SMAP: A Simple Measurement and Actuation Profile for Physical Information,” in Proceedings of the 8th ACM Conference on Embedded Networked Sensor Systems.

ACM, 2010, pp. 197–210.

19. S. Lotfifard, M. Kezunovic, and M. J. Mousavi, “Voltage sag data utilization for distribution fault location,” Power Delivery, IEEE Transactions on, vol. 26, no. 2, pp. 1239– 1246, 2011.

20. Z. Galijasevic and A. Abur, “Fault location using voltage measurements,” Power Delivery, IEEE Transactions on, vol.

17, no. 2, pp. 441–445, 2002.

21. R. Pereira, L. Da Silva, and J. Mantovani, “PMUS optimized allocation using a TABU search algorithm for fault location in electric power distribution system,” in Transmission and Distribution Conference and Exposition: Latin America, 2004 IEEE/PES. IEEE, 2004, pp. 143–148.

22. J. Arrillaga, M. H. Bollen, and N. R. Watson, “Power quality following deregulation,” Proceedings of the IEEE, vol. 88, no. 2, pp. 246–261, 2000.

Editor’s note: This paper, POWER2014-32231, 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.

Jonathan Lee is an electrical engineer and social entrepreneur focused on developing small scale power systems tailored to communities who are not served by traditional grids. In 2014, after researching intelligent electric power systems and receiving simultaneous degrees in Electrical Engineering and Computer Science and in Environmental Economics and Policy from UC Berkeley, he co-founded the social benefit corporation New Sun Road to develop community scale solar power systems as a micro-utility. He is currently working with New Sun Road on a series of electrification projects on the islands in Lake Victoria, Uganda. In the future, he hopes to pursue an advanced degree in systems and information theory. You may contact him by emailing editorial@woodwardbizmedia.com.

Like Energy-Tech?

Like us on Facebook for exclusive content, conversations and events!

Facebook © 2015

22 ENERGY-TECH.com

Dedicated to the Engineering, Operations & Maintenance of Electric Power Plants

ASME Power Division Special Section | July 2015

Don’t miss these upcoming training opportunities available exclusively from Energy-Tech!

Sign up today for Early Bird pricing! Group discounts also available!

July 8-9 ETU Summer School Webinar Course: Belt Drives – Installation, Maintenance and Troubleshooting Tom Davis, Maintenance Troubleshooting Learn how to install tension and operate a belt drive and obtain it’s max design life. 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 August 4-6 Microsoft Excel Up to Speed 1 Webinar Course: Shortcuts, Functions and Charts in Excel Take your Excel skills to the next level and beyond. If you’ve ever spent an 8 hour day working in Excel and thought “there has got to be a better way,” then this is the class for you. Register at www.energy-tech.com/excel August 12-13 ETU Summer School Webinar Course: Troubleshooting and Correcting Problems with Rotating Equipment Using Predictive Maintenance Tools Tom Davis, Maintenance Troubleshooting Learn best practices for troubleshooting and predictive maintenance program design. 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 August 18-20 Excel 2 Webinar Course: Analysis and Visual Basic Programming in Excel Learn how to apply Excel tools specifically designed to speed up analysis and auditing tasks. We’ll also look at Excel’s built in support for the Visual Basic programming language. Register at www.energy-tech.com/excel October 20-21 Risk-Based Inspection for High Energy Piping Systems Webinar Course Learn how to create a thorough inspection plan for your plant’s high energy piping systems and save time, money and stress. 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/piping

Sept. 15-17 Steam and Gas Turbine Fundamentals Webinar Course Sept. 22-24 Advanced Turbine Troubleshooting & Failure Prevention Webinar Course 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 November 18-20 Gas and Steam Turbine Reliability – Live Event This intensive, 16-hour course, held live in Chicago, Ill., will teach participants dynamic cost-effective methods of inspection that ensure long-term operational reliability, availability, maintainability and integrity of gas and steam turbine units. Led by Steve R. Reid, P.E., of TG Advisers Inc., time is allotted for course attendees to discuss their own case studies and establish next-step options for failure prevention. Register at www.energy-tech.com/chicago2015

Visit our extensive webinar archive at

www.energy-tech.com/etu

Ask us about webinar sponsorship opportunities today!

www.energy-tech.com • 800.977.0474 • editorial@WoodwardBizMedia.com

MACHINE DOCTOR

Field balancing an integrally geared turbocompressor rotor

By Patrick J. Smith

The first step in analyzing any vibration problem is to assemble and evaluate all the available data leading up to the incident. This includes reviewing mechanical trends (oil supply pressure and temperature, vibration, etc.), process trends (flows, pressures, temperatures, distance to surge, etc.), maintenance records, inspections, oil analysis, engineering data, etc.

In some cases, it is necessary to obtain additional vibration analysis data in order to better understand the possible causes of a high vibration condition and have confidence in the corrective action. As described in the May 2015 Energy Tech article, “Using Transient Data to Troubleshoot an Integrally Geared Turbocompressor Vibration Problem,” transient startup and shutdown data can be extremely useful in evaluating turbomachinery vibration problems. In this case, the additional data was helpful in determining that the most likely cause of the high vibration was residual unbalance and that field balancing would correct the problem. The purpose of this article is to describe the procedure used to field balance the rotor and present the results of the field balance.

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. Each rotor consists of a pinion with open impellers mounted on each end. The low speed rotor comprises the first two stages of the main air compressor (MAC) service.

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 and stationary labyrinth type air and oil seals. There are single

non-contacting proximity type vibration probes mounted in the air seals. The probes are connected to transmitters, which are then connected to the DCS for vibration monitoring and alarm/trip protection. Both pinions are fitted with thrust collars, which are used to transmit pinion axial thrust to the bullgear. The thrust bearings are on the bullgear rotor, as shown in Figure 1.

A vibration problem developed with the MAC 2nd stage.

This problem persisted even after replacing the rotor and pinion bearings. As described in the May 2015 Energy-Tech article, it was concluded that that the most likely cause of the high vibration was high residual unbalance and that this problem could be corrected by field balancing.

Plan Proper planning is key to a successful field balance. This first step is determining the field balance procedure to be used, which will then dictate the required instrumentation, parts/hardware and resources needed to support the work.

Field balancing involves adding a known unbalance and then measuring the vibration response in order to determine the correction weight and its location. Single plane balancing involves adding correction weights in one plane. Two plane balancing involves adding weights in two planes. This is more complex than single plane balancing and is typically needed when unbalance indication at one end of a rotor is affected by an unbalance at the other end of the rotor. In other words, an unbalance indication at one end of the rotor is the result of the actual unbalance at that end, plus the cross effect from the opposite end. This condition is sometimes called a “cross effect” or a “correction plane interference.”

As mentioned above, the LS rotor consists of a pinion with overhung impellers mounted at each end. The impellers are mounted on the pinion using a hydraulic interference taper fit. The rotor assembly also includes a balance washer, a locknut and a cap at each end, as shown in Figure 2. For small balance corrections on one end of the rotor, a single plane balance using the balance washer or a balance

Figure 1. Compressor Configuration

24 ENERGY-TECH.com

July 2015

MACHINE DOCTOR nut is typically sufficient to get a good dynamic balance on this type and size of rotor.

Two traditional methods for field balancing are single plane balancing with phase, and single plane balancing without phase. Balancing with phase requires more instrumentation, but balancing can typically be done faster and with better results than balancing without phase. Since the instrumentation needed for balancing with phase was already installed for the transient data collection and analysis, it was decided to perform a single plane balance with phase. Recall that 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.

Required instrumentation To resolve the 2nd stage vibration problem, balancing would only be performed on the 2nd stage end of the rotor.

The required instrumentation is a single vibration probe and a key phasor probe. However, since a second probe was added for the transient vibration analysis, both “x” and “y” vibration probes would be used for field balancing. The probes were connected to Bentley Nevada 990 transmitters. GE was contracted to perform the field balance and the transmitters were connected to an ADRE 408 via 990 adapters.

Required hardware To perform the field balance, the locknut and cap at the end of the pinion would be temporarily replaced with a threaded balance nut. The balance nut included threaded axial holes near the OD where set screws could be installed for balancing. With the balance nut installed, the cap that would typically cover the locknut had to be removed. A picture of the rotor with the cap installed and a picture of the rotor with the balance nut installed is shown in Figure 3. The rotor end would be balanced with the balance nut. However, once the correction weight and location were determined, an equivalent amount of weight would be removed from the opposite side of the balance washer in order to achieve the same approximate balance correction with the original locknut and cap configuration (no balance nut).

Trial weight The trial weight needs to create enough of a change in the balance that the unbalance response can be calculated in order to determine the balance correction. A recommended safe initial trial weight size can be calculated based on unbalance that is equal to 10 percent of the rotor weight at each bearing support. In this case, the rotor weighs 1,108 lbs. So, each bearing supports 554 lbs and, based on this suitable target trial weight, would produce a force of 55.4 lbs.

The force caused by a rotor’s unbalance mass can be calculated from Newton’s second law. The unbalance mass causes a centripetal force, which can be calculated from the general equation:

Figure 2. Rotor end configuration

Figure 3. Rotor end configuration. Left: configuration with temporary balancing nut.

Right: design configuration

Equation 1

where:

m = unbalance mass

v = tangential velocity

g = gravitational constant In terms of unbalance, this formula becomes:

Equation 2

where:

Funb = radial unbalance force in pounds

RPM = speed of rotor

Runb = unbalance in rotating assembly in ounce-inches

July 2015 ENERGY-TECH.com

25

MACHINE DOCTOR For this case study, the target unbalance force is 55.4 lbs and the rotor speed is 10,472 rpm. So the target unbalance works out to 0.285 ounce-inches. There are (12) 1/4 ˝ threaded holes on the balance nut that are machined on a 0.937˝ diameter circle that are used for balancing. So the trail weights are added a radius from the shaft centerline of 0.4685˝ Based on this, the target trial weight works out to 0.6 ounces (17 grams).

The longest 1/4˝ set screw that could be installed in the balance nut was 7/8˝ A 1/4 ˝ diameter, 7/8˝ long set screw weighed 5.196 grams. Although this is less than the target trial weight, it was decided that this is what would be used for the actual trial weight.

Figure 4. Balance nut with trial weights

Balance procedure and results The overall vibration is a result of vibration at all frequencies. Residual unbalance creates a vibration response that is at 1x frequency (one times running speed). The balance correction calculations would only use the 1x vibration levels and phase.

The balance procedure and results consisted of the following steps: 1. Connected the vibration and key phasor transmitters to the ADRE 408. Note that the “x” and “y” probes are 90 degrees apart. The ADRE was configured so that a phase angle of 0 degrees corresponded to the probe location for each probe separately.

2. Removed the 2nd stage inlet piping and the 2nd stage inlet piece. This inlet piece is sometimes called a contour ring because it closely follows the contour of the open impeller. Once removed, this completely exposes the front side of the impeller.

3. Removed the 2nd stage cap and impeller locknut.

4. Installed the balance nut.

5. Marked the balance nut with reference to the “y” probe.

6. Started compressor and recorded steady state vibration and phase (1st run of field balancing). a. “x” vibration = 2.726 mils p-p; 1X vibration = 1.783 mils p-p at a phase angle of 215 degrees (relative to the “x” probe) b. “y” vibration = 2.539 mils p-p; 1X vibration = 2.037 mils p-p at a phase angle of 285 degrees (relative to the “y” probe) 7. Installed a 5.196 gram trial weight on the balance nut at an angular location of 345 degrees referred to the “y” probe.

8. Started compressor and recorded steady state vibration and phase (2nd run of field balancing). a. “x” vibration = 2.331 mils p-p; 1X vibration = 1.470 mils p-p at a phase angle of 209 degrees b. “y” vibration = 2.374 mils p-p; 1X vibration = 1.674 mils p-p at a phase angle of 276 degrees 9. Shut down compressor.

10. Using a GE balance program and the available balance holes, the correction weight and location were determined. This also could have been determined by hand using polar graph paper and vector analysis (see references 2 and 3). Based on this (3) 7/8˝ long set screws mounted in adjacent holes with a combined weight 15.709 grams were installed at a mean angular location of 315 degrees referred to the “y” probe. See Figure 4.

11. Started compressor and recorded steady state vibration and phase (3rd run of field balancing). a. “x” vibration = 2.030 mils p-p; 1X vibration = 0.855 mils p-p at a phase angle of 210 degrees b. “y” vibration = 1.393 mils p-p; 1X vibration = 0.861 mils p-p at a phase angle of 270 degrees

Figure 4. Balance washer. Clockwise from upper right: drilled hole for field balancing; locating pin; three previous balance holes.

26 ENERGY-TECH.com

July 2015

MACHINE DOCTOR 12. The balance nut was removed and the GE balance program was run based on removing material from the installed balance washer. Based on this, 20 grams of material at an angular location of 135 degrees referred to “y” probe was removed by drilling the balance washer. See Figure 5. The drilled hole was at approximately the same radius for the centerline that the balance weighs were added. Then the original locknut and cap were reinstalled.

13. Started compressor and recorded steady state vibration and phase (4th run of field balancing). a. “x” vibration = 2.069 mils p-p; 1X vibration = 0.864 mils p-p at a phase angle of 208 degrees b. “y” vibration = 1.692 mils p-p; 1X vibration = 0.913 mils p-p at a phase angle of 270 degrees 14. Using GE balance program, determined that some additional material could be removed from the balance washer in order to improve the vibration further.

Another 4 grams of material (24 grams total) was removed.

15. Started compressor and record steady state vibration and phase (5th run of field balancing) a. “x” vibration = 1.233 mils p-p; 1X vibration = 0.560 mils p-p at a phase angle of 233 degrees b. “y” vibration = 1.112 mils p-p; 1X vibration = 0.436 mils p-p at a phase angle of 296 degrees

JULY 2015 ADVERTISERS’ INDEX A-T Controls Inc.

www.a-tcontrols.com

2

Condenser Life Cycle Seminar www.condenserseminar.org

5

CU Services

www.cuservices.net

28

www.eagleburgmann-ej.com

28

ECOM America Ltd.

www.ecomusa.com

9

Gradient Lens Corp.

www.gradientlens.com

11

Hexeco

www.hexeco.com

28

Indeck Power Equipment Co.

www.indeck.com

28

www.miller-stephenson.com

28

www.topog-e.com

17

EagleBurgmann

Miller-Stephenson Chemical Topog-E Gasket Co.

Once the compressor was loaded, the 2nd stage steady state vibration as measured in the DCS lined out at approximately 1.0 mils p-p and has been stable for several months.

Conclusion The field balance was successful in reducing the 2nd stage vibration to an acceptable level. What made this successful was analyzing the data to have confidence the problem was due to an out of balance condition that could be corrected by field balancing. It also required proper planning and having the right procedure, parts and resources in place to support the work. ~ References 1. Smith, Patrick, “Using Transient Data to Troubleshoot an Integrally Geared Turbocompressor Vibration Problem,” Energy-Tech magazine, May 2015 2. Jackson, Charles, “The Practical Vibration Primer,” Reliabilityweb.com, 2013 3. Randall L. Fox, “A Practical Guide To In-Place Balancing,” Proceedings of the Tenth Turbomachinery Symposium, pp 113 – 129.

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.

What’s the word on the wire?

Follow Energy-Tech and keep up with the industry chatter!

@ETmag

Dedicated to the Engineering, Operations & Maintenance of Electric Power Plants © 2015 Twitter

July 2015 ENERGY-TECH.com

27

Energy-Tech Showcase

Energy Tech Ad 1-6pg Krytox 11-4-2014.qxp_Kryt

BOILERS BOILERS BOILERS BOILERS BOILERS BOILERS BOILERS BOILERS BOILERS RENT RENT RENT SALE SALE SALE LEASE LEASE LEASE

Expansion joint solutions and turnkey services for power generation RENT RENT RENT SALE SALE SALE LEASE LEASE LEASE RENT RENT RENT SALE SALE SALE LEASE LEASE LEAS

DuPontTM Krytox® Lubricants

DuPont™ Krytox® oils and greases. These high-performance fluorinated lubricants are ® •Rental Rental Rental and and and Stock Stock Boilers Boilers Boilers derivatives of Stock Teflon and offer the following advantages: Chemically inert. Wide temper•Generators Generators Generators ature range (-103°F to 800°F). Compatible •Chillers Chillers Chillers with plastics, rubber, ceramics, & metals.

•Deaerators Deaerators Deaerators Nonflammable. Insoluable in common solvents.

No silicones or hydrocarbons. Krytox® •Boiler Boiler Boiler Parts Parts Parts may be applied to gearboxes, dampers, •Boiler Boiler Boiler Services Services Services ductwork valves, steam valves, gaskets, seals, compressors, bearings, boilers, •Combustion Combustion Combustion Controls Controls Controls pumps, and Turbine Auxiliary systems.

•• •• •• •• •• •• •• • • •Solid Solid Solid Fuel Fuel Fuel Applications Applications Applications

For more information and sample call 800.992.2424 or 203.743.4447

•• •• •• •• •• •• •• ••

•Rental Rental Rental and and and Stock Stock Stock Boilers Boilers Boilers •Generators Generators Generators •Chillers Chillers Chillers •Deaerators Deaerators Deaerators •Boiler Boiler Boiler Parts Parts Parts •Boiler Boiler Boiler Services Services Services •Combustion Combustion Combustion Controls Controls Controls •Solid Solid Solid Fuel Fuel Fuel Applications Applications Applications

Channel Partner Since 1991

24/7 24/7 24/7 Emergency Emergency Emergency Service Service Service

24/7 24/7 24/7 Emergency Emergency Emergency Service Service Service

P P847-541-8300 847-541-8300 P 847-541-8300 ••F • F847-541-9984 847-541-9984 F 847-541-9984

P P847-541-8300 847-541-8300 P 847-541-8300 ••F • F847-541-9984 847-541-9984 F 847-541-9984

info@indeck-power.com info@indeck-power.com info@indeck-power.com supportET@mschem.com www.miller-stephenson.com www.indeck.com www.indeck.com www.indeck.com

info@indeck-power.com info@indeck-power.com info@indeck-power.com www.indeck.com www.indeck.com www.indeck.com

High Pressure Silencers     

Simple yet effective diffuser silencing Suitable for high pressure, high temperature steam and gas Compact size and weight Non Clogging Minimum supporting requirement

Model D800 Silencer

CU Services LLC

725 Parkview Cir, Elk Grove, IL 60007 Ph 847-439-2303 rcronfel@cuservices.net

www.cuservices.net

28

•• •• •• •• •• •• •• •• • • • • • • •

•Rental Rental Rental and and and Stock Stock Stock Boilers Boilers Boilers •Generators Generators Generators •Chillers Chillers Chillers •Deaerators Deaerators Deaerators •Boiler Boiler Boiler Parts Parts Parts •Boiler Boiler Boiler Services Services Services •Combustion Combustion Combustion Controls Controls Controls •Solid Solid Solid Fuel Fuel Fuel Applications Applications Applications

Crossover Piping & Ducting Exhaust Systems Gas & Steam Turbines ASME Code Heat Exchangers HRSG Boiler Penetration Seals Refurbished Expansion Joints 24/7 24/7 24/7 Emergency Emergency Emergency Service Service Service Complete Turnkey Solutions

P P847-541-8300 847-541-8300 P 847-541-8300 ••F • F847-541-9984 847-541-9984 F 847-541-998

EagleBurgmann KE Inc. Tel: +1 (619) 562 6083 ejsales@us.eagleburgmann.com www.eagleburgmann-ej.com

info@indeck-power.com info@indeck-power.com info@indeck-power.com www.indeck.com www.indeck.com www.indeck.com

Coming in August 2015 Look for the next issue of Energy-Tech magazine and read about:

• Retrofit/Rebuild/ Equipment Upgrade • Burners & Ignition • Instrumentation & Controls • Steam Turbines • ASME: Heat Exchangers

ENERGYT ECH