April 2014 by Energy-Tech Magazine

Novel Apps in PM 11 • ASME: Natural Gas CC 20 • Turbine Blades 28

ENERGY-TECH A WoodwardBizMedia Publication

APRIL 2014

www.energy-tech.com

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

Level control for feedwater heaters

FROM ENGINEERING ANALYSIS TO ADVANCED NDE, LOOK TO STRUCTURAL INTEGRITY

We Connect the Dots Over the past 30 years, Structural Integrity has built a team of over 260 industry experts providing comprehensive solutions to the energy industry. We connect the dots from problem to resolution, from regulations to compliance, from nondestructive examination, to engineered solutions, even custom equipment. You can look to us for our: • Knowledge of power plants, codes, and how things work. • Extensive experience and leadership. • High quality, hard work, and responsiveness.

Call us today and we’ll connect the dots for you.

Scan the QR Code for more information

877-474-7693 (877-4SI-POWER) www.structint.com/energy-tech

ENERGYT ECH P.O. Box 388 • Dubuque, IA 52004-0388 800.977.0474 • Fax: 563.588.3848 Email: sales@WoodwardBizMedia.com www.energy-tech.com Energy-Tech (ISSN# 2330-0191) is published monthly in print and digital format except in January and July, when it is published in digital format only by WoodwardBizMedia, a division of Woodward Communications, Inc. WoodwardBizMedia assumes no responsibility for inaccuracies, errors or advertising content. Entire contents © 2014 WoodwardBizMedia. All rights reserved; reproduction in whole or in part without permission is prohibited. Printed in the U.S.A. Group Publisher Karen Ruden – kruden@WoodwardBizMedia.com General Manager Randy Rodgers – randy.rodgers@woodwardbizmedia.com Managing Editor Andrea Hauser – ahauser@WoodwardBizMedia.com Editorial Board (editorial@WoodwardBizMedia.com) Kris Brandt – Rockwell Automation Bill Moore – Director, Technical Service, National Electric Coil Ram Madugula – Executive Vice President, Power Engineers Collaborative, LLC Kuda Mutama – Engineering Manager, TS Power Plant

FEAtUrEs

By Mike Catapano and Eric Svensson, Powerfect Inc.

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.

A division of Woodward Communications, Inc.

Developing novel applications of predictive maintenance techniques By Gary Noce, Electric Power Research Institute

CoLUMNs

Regulations Compliance

Coal storage hazards and solutions By Julianne Couch

Mr. Megawatt

Vendor correction connection By Frank Todd, True North Consulting

Turbine Tech

Don’t lose your tune with turbine blade damage By Stephen R. Reid, PE, TG Advisers Inc.

Editorial views expressed within do not necessarily reflect those of Energy-Tech magazine or WoodwardBizMedia. Advertising Sales Executives Tim Koehler – tkoehler@WoodwardBizMedia.com Juli Hoppensteadt – jhopp@WoodwardBizMedia.com Joan Gross – jgross@WoodwardBizMedia.com

The importance of proper level control of feedwater heaters

AsME FEAtUrE

A dynamic process model of a natural gas combined cycle – model development with startup and shutdown simulations By Eric Liese and Stephen E. Zitney, National Energy Technology Laboratory

iNdUstrY NotEs

4 30 31

Editor’s Note and Calendar Advertisers’ Index Energy Showcase

oN tHE WEB Register for Energy-Tech’s free April webinar, Proper level control for feedwater heaters, with Mike Catapano and Eric Svensson from Powerfect Inc. Read their article on page 6, then join us for the webinar. Registration is free, visit www.energy-tech.com for more information. See you there! Cover photo contributed by Powerfect Inc.

April 2014

ENERGY-TECH.com

Editor’s Note

Desk education Energy-Tech University offers classes wherever you are Energy-Tech magazine just finished its first live training event, Energy-Tech University, in Chicago at the end of March. The courses went well and both attendees and instructors left satisfied that they knew more than when they arrived. The Energy-Tech staff learned a lot too, and we’re looking forward to implementing those lessons throughout the coming year, with Energy-Tech University online. We know our readers already count on Energy-Tech for relevant, hands-on information about the engineering and maintenance issues they work to solve every day. We also know that many of our readers have registered for one of our technical webinars and come back for more. We plan to provide exactly that, with more expert articles, webinars and online training sessions in the coming year. Some of these will be free and some will have a fee, but all of them will be chock-full of useful information you can apply in your day-to-day work. The next one you should mark on your calendar is Energy-Tech’s technical webinar, Proper level control for feedwater heaters, on April 24. It will be presented by Mike Catapano and Eric Svensson, who wrote the article on page 6 on the same topic. In the webinar they will be expanding on points raised in the article and providing a more in-depth analysis. The webinar also will include a live Q&A session for attendees. It’s free and only an hour long, be sure to sign up. You can find the registration link at www.energy-tech.com. Then keep an eye out for emails about our summer schedule. We have several webinars planned – and the ASME conference – so it’s going to be busy. And, as always, if you have topics you’d like us to address, please email them to me at ahauser@woodwardbizmedia.com. Thanks for reading!

CALENDAR April 1-3, 2014 Electric Power Conference & Exhibition New Orleans, La. www.electricpowerexpo.com April 6, 2014 International Conference of Doble Clients Boston, Mass. www.doble.com April 22-25, 2014 Advanced Vibration Analysis Syria, Va. www.vi-institute.org April 24, 2014 Energy-Tech University webinar: Proper level control for feedwater heaters www.energy-tech.com May 19-22, 2014 Introduction to Machinery Vibrations Knoxville, Tenn. www.vi-institute.org June 11-13, 2014 2014 Vibration Institute Training Conference San Antonio, Texas www.vi-institute.org June 11-13, 2014 3rd Natural Gas Vehicles USA Conference & Exhibition Houston, Texas www.ngvevent.com July 21-25, 2014 Rotor Dynamics and Modeling Syria, Va. www.vi-institute.org July 28-31, 2014 ASME 2014 Power Conference Baltimore, Md. www.asmeconferences.org/power2014

Andrea Hauser

Aug. 19-22, 2014 Balancing of Rotating Machinery Houston, Texas www.vi-institute.org

Submit your events by emailing editorial@woodwardbizmedia.com.

ENERGY-TECH.com

April 2014

DHCP = $AFETY

for your GE Hydrogen-Cooled Generator ™

WHEN HYDROGEN PURITY DROPS, windage losses increase, operating costs increase – and then your plants lose revenue and profitability. Gas purity is also a critical life safety issue, making monitoring for potentially explosive levels essential. E/One’s Dual Hydrogen Control Panel (DHCP) was designed specifically for monitoring and controlling hydrogen purity in GE generators that utilize scavenging seal oil systems. The DHCP contains two independent analyzers that monitor hydrogen purity from both the turbine-end seal drain enlargement and the collector-end seal drain enlargement. Designed to be used in a hazardous location, the DHCP has the ability to automatically increase the amount of hydrogen gas bled from the generator. It’s also an easy drop-in replacement for your old hydrogen control cabinet. Featuring digital displays, warnings and alarms the DHCP works with all GE and non-GE control systems. DHCP = $AFETY, it’s just a little equation, but it delivers huge benefits. Visit www.eone.com/solutions today to find out more about increasing your plant’s safety and profitability.

Environment One Corporation www.eone.com/solutions A Precision Castparts Company

GE is a registered trademark of General Electric Company

FEATURES

The importance of proper level control of feedwater heaters By Mike Catapano and Eric Svensson, Powerfect Inc.

One of the most common causes of tube failures in a feedwater heater (FWH) is the improper control of the internal liquid level, which also can cause operational and maintenance costs that might lead to premature replacement.These problems are not new, they have been experienced by many utility plants throughout the industry during the past 50 years. However in many cases, the resulting damaging phenomenon has seldom been totally understood, and the loss of corporate knowledge and failure of some utilities to identify and rectify level control problems continues to bring this issue to the forefront of root causes of FWH operational failures. In general, the performance of the Drain Cooler (DC) Zone is tied to the operational parameter of Drain Cooler Approach (DCA). DCA is defined as the temperature difference between the drains leaving the heater and the feedwater entering the heater. Most FWHs are designed with a DCA of approximately Figure 1. Areas of two-phase flow can be seen near DC zone baffels. Photos 10°F.While DCA is a good indication of whether the DC Zone contributed by Powerfect Inc. is operating properly, it is not the only parameter that should be considered. DCA is a measurement of temperatures only.The around the tubes and change direction many times due to the pressure of the drains also must be known in order to determine baffling arrangement, and also due to changes in elevation and the degree of subcooling and whether there is a potential for elbows in the downstream piping. If the liquid drains are not flashing, either within the DC itself or the downstream piping subcooled enough, any one of these pressure drops could result in before the level control valve. Flashing and two-phase flow in flashing and two-phase flow.Two-phase flow is known to cause either of these areas can cause significant damage to the heater. problems to piping, tubing, the cage and the shell, especially in the It is important to remember that the drain cooler is designed case of carbon steel components. to be a water-to-water exchanger. It must remain that way to This flashing phenomenon is typically more problematic in LP function properly. Any admission of heaters than in HP heaters, although vapor into the zone typically results both are susceptible.To understand this, Sign up for Energy-Tech’s April in problems.This might be a result of one need only to consult the steam a low liquid level in which steam is tables and look at the specific volume feedwater heater webinar at admitted directly from the condensing of saturated liquid vs. saturated vapor. www.energy-tech.com zone into the DC zone, the result of Let’s consider a HP heater operating at flashing within the DC zone itself, approximately 250 psia and a LP heator can be the result of leakage into the zone via the endplate er operating at approximately 10 psia. From the steam tables, we or shroud cracks. In most cases, the OEM designs the DC zone observe the following: such that the linear velocity of the liquid within the DC zone It can be seen that in the case of the HP heater, when the liqremains a reasonable 2´-4´ per second.When velocity increases, uid flashes within the drain cooler, it wants to occupy a volume the pressure drop increases exponentially (approximately a square that is approximately 100x the volume that the liquid previously function).When flashing occurs, the localized velocity can be occupied. As mentioned above, this drastically increases the localmuch greater than designed and tube vibration and/or tube OD ized velocity (and can result in further pressure drop and more erosion might occur, as well as damage to the carbon steel cage flashing). In the case of the LP heater, the same amount of flashing components. liquid now wants to occupy more than 2,000x the volume, which Flashing, by definition, is the change in state of liquid to vapor. can lead to significant failure mechanisms. While in most cases this change of state results from the addition One thing that also must be considered is the effect on the of heat (as in the boiler), in a FWH the most common cause of drain cooler when operating with other feedwater heaters out flashing is a result of a reduction in pressure (or pressure drop). of service (i.e. single string or downstream heater out of service). Pressure drop might be a result of the geometry of the Drain This can result in a significant overload condition in which the Cooler Entrance window, the fact that the drains must travel DC Zone must now pass a significant amount of drains, and 6

ENERGY-TECH.com

April 2014

FEATURES Table 1 Pressure (psia)

Sat. Temp (°F)

Specific Volume Liquid (ft3/lb)

Specific Volume Vapor (ft3/lb)

Ratio Sat Vap./ Sat Liq.

250

401

0.0187

1.843

98.5

193

0.0166

38.42

2314

Table 1

most likely above the normal design point. If these abnormal modes of operation were not considered by the FWH designer, than the high liquid velocity and therefore high pressure drop within the DC zone also Figure 2. Tube damage due to flashing within a could result in failures. drain cooler zone. Feedwater heaters are provided in a number of different arrangements, each one with its own unique level control problems. Each case is addressed below:

Horizontal feedwater heaters Horizontal feedwater heaters may be provided with a “short” full pass DC zone or a “long” partial pass DC Zone. In most modern horizontal FWHs, the short DC is provided. As mentioned, the DC zone must remain a water-to-water exchanger; therefore the boundary of the DC zone is well defined by a thick DC endplate, and a DC shroud which generally consists of a flat top plate and a bottom semi-circle enclosure.The entrance to this zone is via a cutout window (Figure 3) or snorkel (Figure 4), which is below the bottom row of tubes. The snorkel must remain submerged in the liquid in order to prevent steam from the condensing zone from entering the zone (even throughout transient conditions). Additionally, the liquid velocity through the DC entrance must remain low in order to ensure that the resulting pressure drop does not result in flashing. The optimum level in which to operate can be determined by performing a “knee of the curve test,” as described in Paragraph A2.2 of the HEI for closed feedwater heaters, which is derived from a paper by Fred Linley, “A review of Salient Conditions Affecting Closed Feedwater Heater Availability and Performance,” recommended reading for all engineers with FWH responsibility. By plotting DCA vs. FWH level, the point at which flashing occurs can be determined.This point is represented by the marked increase in DCA during a small change in liquid level and generally equates to the entrance to the DC zone. The normal liquid level (NLL) should then be set approximately 2˝ above this point.This typically results in approximately the bottom three rows of tubes being submerged during normal operation.The submerged tube surface has the benefit of providing some subcooling to the drains prior to entering the DC Zone, and ensur-

A REVOLUTION IN BRUSH CHANGING FOR TURBINE-GENERATOR RELIABILITY The NEW Cartridge-Style Plug-In Brush Holder It is now possible to easily and safely change brushes on live equipment! The solution the industry has long awaited is now available from the leader in brush holder technology, Fulmer Company. ■ Brushes changed on-line, without service interruption, using a simple changing fixture ■ Direct replacement for many OEM styles with no rigging modification required ■ Longer brush box to provide better brush support and allow the use of a 4” brush, increasing brush life and reducing the frequency of changes ■ Rugged, lightweight and ergonomically built ■ Removable insulated handle with flash guard

BRUSH CHANGING MADE EASY

THE FULMER WAY.

Fulmer Company A Wabtec Company 3004 Venture Court Westmoreland Industrial Park III Export, Pennsylvania 15632 Phone 724-325-7140 www.fulmercompany.com

April 2014 ENERGY-TECH.com

FEATURES

Figure 3. DC entrance window

Figure 5. Failures at the DC entrance window due to low liquid level.

Figure 6. Failures at DC snorkel pipe due to flashing/high pressure drop at entrance.

ing that that liquid does not immediately flash into vapor when it experiences the initial pressure drop as it traverses through the DC entrance window. With time, the liquid level might be required to be changed. This is especially true if there are a significant number of plugged tubes. If there are plugged tubes in the bottom rows that are submerged in the normal liquid level, the ability to “pre-cool” the drains prior to entering the DC zone might be lost and flashing might once again occur. In this case, the “knee of the curve test” should be performed again and the NLL adjusted higher. 8

ENERGY-TECH.com

Figure 4. DC snorkel pipe

For heaters with a “long” partial pass drain cooler, level control is a little more straightforward, although the same principles described for the “short” drain cooler can be applied. As before, it is imperative that the drain cooler remain a water-to-water exchanger.This generally means keeping the liquid level in the heater above the flat DC top plate at a minimum. In these heaters, there is no DC endplate and the shroud simply ends prior to the start of the U-bends.This has two distinct advantages. First, there is essentially no pressure drop as the liquid enters the zone, and second, there is some pre-cooling of the drains prior to entering the DC Zone due to the U-bend surface that is submerged near the entrance. Both of these minimize the potential for flashing. Of course, the normal liquid level is maintained higher than that of a short drain cooler, which lessens the margin to a high liquid level condition and could result in a flooded venting system, or in a worst case scenario, turbine water induction.

Vertical feedwater heaters Vertical FWHs might be designed with the channel down or the channel up. Each of these designs is unique when it comes to level control.While maintaining a constant level in a horizontal FWH is relatively easy, it is typically harder to maintain a constant level in a vertical FWH and, as a result, the design of the heater must take into account the potential for level swings.The ability to maintain a constant level is a function of the capacitance of the heater. Capacitance can be defined as the available free volume per inch of level. In a horizontal feedwater heater, the capacitance is quite large, since it takes a significant amount of liquid to change the water level by 1˝. Capacitance in a vertical feedwater heater is much more limited, especially in the case of a Vertical Channel Down 3-zone heater, where the entire outlet pass is not available for liquid level due to the presence of the Desuperheat Zone (DSH). A small capacitance combined with an improperly sized control valve can result in significant level swings.This can lead to significant problems to the heater. If the level swings too low, the DC zone will be exposed to the steam, and if the level is not restored quickly, the DC zone will lose its effectiveness and flashing in the downstream piping might occur. Conversely, if the level gets too high, in the case of a 3-zone heater, the liquid will spill into the exit of the DSH zone, where steam is traveling at velocities on the order of 100´-150´ per second.When the water April 2014

FEATURES becomes entrained in this steam, it has the effect of a “shot-gun” blast on the tubes and internal components, as shown in Figures 7 and 8. In most cases for vertical channel down heaters, the level is established at about 5˝ above the top of the DC zone. Additionally, for 3-zone heaters, the top of the DSH zone should be at least 36˝ above the top of the DC Zone in order to allow for the worst case level swings that can be expected. Similar to the horizontal heaters, the worst case overload condition must be analyzed. Higher drainage flow due to heaters out of service typically results in more drastic level swings, especially if the control valve is not very responsive (or overly responsive). In some cases 5˝ above the DC zone might not be enough, in which case the level should be set higher based on operational test and observations. Vertical Channel Up heaters obviously have the level controlled at the bottom of the heater near the U-bend region. For single-zone heaters, this is no problem at all since the drain’s outlet nozzle is simply placed at the bottom of the heater. As long as the liquid is subcooled enough to safely transit to the lower pressure heater or condenser without flashing, then problems do not occur. However, for Vertical Channel Up heaters with a drain cooler, maintaining level is similar to drinking from a straw. In these heaters a “long” partial pass drain cooler as described above is employed.The start of the DC zone 90° Prism & must be continually submerged in the liquid Close-Focus level in order to maintain the suction and tips available! flow through the DC Zone. Not only is there a pressure drop due to the baffling arrangements within the zone, but there is a change in elevation from the bottom of the heater to the top of the heater, and the potential for flashing is exceptionally high.

control valve should be approximately 12˝ from the DC entrance. In cases where this is not possible due to the physical arrangement (i.e. condenser neck heaters) then the NLL should be optimized based on the “knee of the curve test” described above. Simply setting the level based on the vendor’s recommended level on the calibration plate might not be adequate since the level at the DC entrance might be significantly different than at the location at which the level is being measured. It is preferred to have separate level taps (about 12˝ apart) for normal control, local indication and emergency/alarm control as opposed to having all the columns manifolded together. In the

The NEW Hawkeye

Best practices Utilities tend to have the most success when the effect of liquid level on FWH performance is known and level control problems are recognized quickly by operators. In addition to displaying FWH inlet and outlet temperatures on control room monitoring screens, DCA and heater level also should be displayed, monitored and recorded in historical data systems such as PI. The location and number of liquid level taps also plays a significant role.The liquid level within the heater is not flat, there is a gradient within the heater and it changes with load, therefore, the liquid level taps should be placed close to the entrance of the DC zone, where the level is most important. Generally, the column that is used for the

Video Borescope!

Bright, High-Res Bright, Video & Photos Large Range-of-Focus Quality Construction 4-Way Articulation 4 & 6 mm Diameters Starting at only $8,995

VIDEO BORESCOPES

Ideal for cooling tube inspection! We’ve improved the image quality in the new Hawkeye® V2 with a higher resolution, more light sensitive camera, delivering bright, crisp, clear images! The new 5” LCD Monitor provides comfortable viewing, and intuitive, easy-to-use controls, allow photo and video capture at the touch of a button! We’ve increased the 4-way Quickly inspect cooling tubes inside heat exchangers, turbine articulation range, and improved the feel. It’s still small, blades, and much more! lightweight, portable, delivers great image quality, and is priced starting at only $8995. Available in 4 and 6 mm diameters. Optional 90° Prism and Close-Focus adapter tips available. Made in USA

gradientlens.com 800.536.0790

Visit us at: Booth 4949 Las Vegas, NV May 5 - 8, 2014

April 2014 ENERGY-TECH.com

FEATURES Level control valves (both normal and emergency) should be located as close as possible to the lower pressure source. Flashing of the drains will occur at the control valve and the amount of piping that will then experience the resulting two phase flow should be minimized. As mentioned above, the condition of the drains Figure 7. Erosion of tubes and side bars in a vertical FWH. Figure 8. Flow accelerated corrosion of vertical FWH shell due to exiting the heater (temmoisture entrained in the steam. perature and pressure) latter case, a problem with the one line (such as clogging due to should be monitored to FME) will affect all indications, meaning you will lose the intendensure that there is enough sub-cooling to prevent the drains ed redundancy. from flashing before reaching the control valve. Emergency drain lines that provide alternate dumps should be through a separate nozzle in the condensing zone, as opposed to Summary simply branching off the normal drains line.This has the benefit Inadequate liquid level control can lead to tube failures and of being able to bypass the DC zone and, in the case of an overDC zone damage. It is important to optimize the normal liquid load condition, relieve the DC of the high velocity condition and level set point to avoid flashing or vapor ingestion within the DC additional pressure drop that might be experienced. However, zone.The DC zone is designed to be a water-to-water exchanger. since these drains will be at saturated conditions, there is additional When the conditions that allow it to remain as such are violated, concern for pressure drop. Slower velocity limits are important to problems can quickly develop. ~ ensure non-flashing situations.

Non-Intrusive Flow Measurements in the HRSG Industry t Highly accurate and reliable flow measurement up to 750 °F t No process stops for installation t Virtually maintenance free t Decreased downtimes and forced outages

The Ideal Solution for: t Phase detection – steam or water in the HRSG during startup t Controlling drain valves during heavy cycling t Measurement of auxiliary liquidsystems – water treatment, cooling tower flows, natural gas www.flexim.com · salesus@flexim.com

FLEXIM AMERICAS Corporation · Toll free: 1 888 852 74 73 10

ENERGY-TECH.com

Michael C. Catapano has more than 35 years of experience in the operation, design, procurement and maintenance of feedwater heaters, condensers and other shell and tube heat exchangers, including 7 years with PSE&G and 28 years as president of Powerfect Inc. His current work at Powerfect is primarily devoted to consulting, troubleshooting problems and assisting utilities with feedwater heater replacement and operating and maintenance activities. Catapano is an ASME fellow and has assisted ASME and EPRI in numerous feedwater heater projects, seminars and publications. He also holds three patents pertaining to feedwater heater testing and repair. Catapano has a bachelor’s degree in Mechanical Engineering from Newark College of Engineering. You may contact him by emailing editorial@woodwardbizmedia.com. Eric Svensson graduated from the Georgia Institute of Technology in 1993 with a bachelor’s degree in Chemical Engineering. He joined the Naval Nuclear Propulsion program shortly after graduation, where he received training in Nuclear Power Theory and Operations. In 2000, he received a master’s degree in Operations Management from University of Arkansas. His current role as vice president of Engineering at Powerfect is devoted to consulting, troubleshooting problems, as well as operations and maintenance activities. Since joining Powerfect, he has been involved in writing the specifications and conducting quality control checks for more than 20 replacement feedwater heaters. He also is a member of the ASME Heat Exchanger Committee and has co-authored several technical papers. You may contact him by emailing editorial@woodwardbizmedia.com. April 2014

FEATURES

Developing novel applications of predictive maintenance techniques By Gary Noce, Electric Power Research Institute

As U.S. fossil plants age and components reach end of life, equipment condition monitoring and associated data analysis are increasingly critical to maintain reliability and avoid failures. One of the key tools for equipment monitoring involves predictive maintenance (PdM). PdM, which has been part of the landscape of the fossil generation industry for many years, involves acquiring data on plant equipment, assessing the data to derive information, and then using that information to make decisions regarding corrective actions and appropriate timelines for performing maintenance. (Figure 1) The Electric Power Research Institute (EPRI) recently conductFigure 1. Predictive maintenance: From data to information to action. ed two case studies to investigate the potential for novel applications of one • Aging of fossil generating plants, due in part to the lack traditional PdM technology — infrared thermography of new fossil plant construction during the last 15 (IRT) — to illustrate ways to expand the use of existing years. This trend has created an environment in which PdM technologies and to maximize the value of condition more monitoring is required as individual components monitoring practices. at existing plants reach their end of life. The advent of new applications in PdM can be beneUtilities have responded to these industry forces by ficial to organizations, because the technology potentially improving maintenance and work management practices requires less time for data collection, allows more data to be and by taking a more proactive stance toward asset mancollected from a single device, and uses smaller instruments. agement, equipment reliability and material condition

Evolution of predictive maintenance During the past 20 years, significant changes have occurred in the power generation industry, including: • Utility deregulation, which has created competition and driven the industry to achieve significant increases in power plant generation capabilities and higher levels of equipment reliability, while reducing O&M and capital budgets. • Corporate acquisitions and mergers, resulting in the formation of larger power generation fleets, which have influenced changes in both site and corporate equipment reliability responsibilities. • Significant reductions in utility personnel at each power generation facility, making it difficult to sustain the resources needed to focus on nonreactive maintenance activities such as condition-based maintenance. • Economic pressure to reduce intrusive, time-based preventive maintenance (PM) tasks in favor of cost-effective condition-monitoring activities.

improvement. An important enabler and strategic element of this proactive equipment reliability approach has been the implementation and/or expansion of PdM and condition-based maintenance (CBM) programs. CBM programs have resulted in the detection of equipment anomalies at early stages of degradation and have allowed for maintenance actions

Are Shaft Currents Destroying Your Machinery?

Failure to properly ground rotating equipment can result in expensive bearing, seal, & gear damage. SOHRE TURBOMACHINERY® INC.

128 Main Street, P.O. Box 1099 Monson Massachusetts, USA 01057-1099 April 2014 ENERGY-TECH.com 11 PH: 413.267.0590 • 800.207.2195 • FX: 413.267.0592 tsohre@sohreturbo.com • www.sohreturbo.com

FEATURES

Figure 2. Visual image of a hot gas duct.

prior to equipment failure, thereby reducing costs and equipment/plant downtime. Through the years, some utility companies have expanded the application of CBM beyond the typical major rotating equipment to many other components, such as valves, heat exchangers, transformers and high-pressure piping. Early PdM programs used condition-monitoring techniques such as vibration analysis, IRT, and lube oil analysis to collect data used to support maintenance decision making. The subsequent evolution of PdM data collection devices during the past 20 years has had a significant impact on the utility industry. Devices used in the early days of PdM data collection were often large, bulky and time-consuming to deploy, and in many cases they failed to provide sufficient data to enable a clear determination on a component. Examples of older technologies include single-channel vibration analyzers and shortwave IR cameras. With time, these technologies have matured and programs have evolved, incorporating new approaches such as on-line and off-line motor testing and ultrasonics. Examples of the evolution of PdM technologies include the following: • Vibration/Balancing. Equipment used to collect vibration/balancing data has seen vast improvements through the years. Not only is it possible to collect more data from a single device to support condition assessment of a component, but currently available vibration/balancing data collectors have a wider range of capabilities and more automated functions than some of the older models. In addition to being able to perform conventional functions for components such as motors, fans and blowers, the new generation of data collection devices also can detect the root cause of mechanical failures — for example, bearing problems, misalignment, unbalance and looseness. • Ultrasonics. Ultrasonic testing has taken major strides through the years and has become an indispensable 12

ENERGY-TECH.com

Figure 3. Thermal image of the hot gas duct.

technique for a number of power-industry inspection situations. One of its primary uses in PdM is for detection of electrical and mechanical anomalies in places where an IRT camera cannot be used. For example, in most power stations, high-voltage breakers would ideally be imaged with an IRT camera, but because of safety issues, the breaker compartments cannot be opened. If no IRT windows are available to enable the use of an IRT camera, then ultrasonic testing is the next best thing. Scanning around the compartment door with an ultrasonic device can detect arcing inside, and if an anomaly is found, the breaker can be scheduled for maintenance. Besides being useful in electrical and mechanical inspections, ultrasonic testing can be used to detect leaks in valves and piping and to inspect steam traps. It also can be used to prevent over-lubrication in motors. Many vendors supply ultrasonic equipment to the energy industry. Equipment that is available for PdM applications can analyze conditions, pinpoint locations with a laser pointer, and store collected data. Ultrasonics also can be used in applications for remote monitoring. • Infrared Thermography (IRT). IRT is a nonintrusive, diagnostic technology. An IRT program involves conducting periodic inspection surveys of a database of critical equipment used in the production and delivery of electric power. The critical equipment in the database will usually exhibit an abnormal thermal pattern at some point in time before functional or operational failure occurs. An inspection made with an IRT camera can detect these abnormal thermal patterns. Abnormal thermal patterns that are observed on a piece of equipment are referred to as thermal anomalies. An IRT camera uses infrared sensors to make simultaneous temperature measurements of multiple points on the surface of a piece of equipment (a tarApril 2014

FEATURES get), without making physical contact with the target. The measurements of the target surface are taken from a distance. IRT is not an X-ray technique. It will not make measurements through an object. IRT inspections must be done while the equipment is under normal operating load and after a period of run-time sufficient to allow a component to reach normal operating temperatures. IRT data are displayed in the form of a picture. The pictures are commonly referred to as thermograms or thermal images. Thermal images can be analyzed in real time or stored electronically and analyzed later. The images are analyzed to determine whether the thermal pattern is normal or abnormal. (Figures 2 and 3) IRT equipment, like vibration measuring equipment, has seen major improvements in recent years. Whereas early IRT equipment tended to be unwieldy and required inconvenient warm-up times, new products are compact and easy to use, with features such as hands-free focus, point-and-shoot capabilities, built-in laser pointers and flashlights, and sophisticated electronics that enable high image resolution and processing ability. Some units can be used in conjunction with a smart phone or tablet device. Along with the development of the technology, a competitive marketplace has made it more practical for organizations to supply IRT equipment to a larger number of personnel for use in the field, including maintenance and operations staff performing routine inspections of equipment. In power plant applications, IRT is used on many different types of equipment and components, including motors, pumps, motor control center (MCC) cabinets, breakers, bus ducts, transformers, substation equipment and boilers. A few example applications illustrate the wide range of uses of IRT in the power industry: • Determination of heat loss from HVAC systems • Inspection of flames in a boiler • Detection of gases such as SF6 and carbon monoxide

• Post-maintenance testing to confirm elimination of IR anomalies

Expanding PdM applications One way to expand the applications of PdM data collection technologies is simply to extend the PdM program itself to cover equipment, whether new or existing, that was not originally covered by the program. In most power stations, the PdM group collects and interprets data on critical equipment such as pumps, fans, motors, breakers, MCCs and transformers. Plants can consider whether there is other

April 2014 ENERGY-TECH.com

FEATURES plant equipment and/or technology that should be included in the PdM program. As new plant equipment is acquired, plants need to evaluate it for possible inclusion in the PdM program, and any implications of added equipment on the program need to be considered. Another way to expand usage of PdM technologies is to find different applications for existing PdM equipment. These new applications can be especially advantageous when personnel changes occur in PdM groups — for example, in cases of staff retirements and/or new hires. The new applications can ease transitions for PdM personnel who might not have intensive training and experience to support condition evaluations on components.

circuit. The temperature profiles were reviewed for heat-up rates and temperatures. It was immediately evident that the test board heat-up rates were significantly elevated and that the +24V regulator module was heating abnormally, in both heat-up profile and temperature levels. Visual images were also reviewed, and an abundance of heat damage was identified. • Grease in Bearings. In the second case study, IRT was used to evaluate thermal behavior of grease to obtain information that could lead to better sampling techniques, which might, in turn, support the expanded use of grease monitoring as a diagnostic tool for PdM.

As part of a comprehensive predictive or condition-based maintenance program, lubricant analysis is an effective complement to other diagnostic technologies such as vibration Two case studies analysis, IRT, ultrasonic detection and motor circuit evaluEPRI conducted two case studies to investigate the ation. Oil sampling and analysis is a well-established diagexpanded application of IRT. nostic tool for industrial machinery, providing insight into • Printed Circuit Boards. In the first case study, IRT was the condition of the bearings, gears and other lubricated used to evaluate heat-up profiles and overall thermal mechanical components, and into contaminants that have profile of printed circuit boards in a root-cause invesentered the system, as well as the condition of the oil itself. tigation. The focus was the failure of a +24V power Grease sampling and analysis, on the other hand, has supply. Multiple points of reference were chosen on a not seen widespread use as a diagnostic tool. Although test board and a control board to relate the temperagrease lubrication of rolling element bearings is one of the tures of the two boards at peak temperatures within most common lubrication scenarios in industry, the exact the +24V circuit, +24V regulator module, and -15V behavior of greases while equipment is in operation is not well understood. The primary barrier to routine use of grease analysis has been the challenges related to understanding and obtaining representative samples. This case study was conducted to show thermal patterns of circulating grease in a common electrical motor application and utilize these thermal patterns, as well as knowledge of the flow behavior of non-newtonian fluids. The goal was to aid Our interactive in the establishment of a strategy for utidigital issue is lizing grease sampling tools to access samples of grease that will be representative of available the first of the grease condition and the health of the every month! Visit monitored component. ~

Keep up-to-date with the

ENERGY-TECH

digital edition

Energy-Tech.com to get an exclusive “first look” at our new issue, every month!

ENERGY-TECH.com

Gary Noce is a project manager in EPRI’s Generation Applications in the Generation Sector. His responsibilities include EPRI’s PlantView Software, the Infrared Thermography User Group, and the Plant Reliability Interest Group. He previously worked for EPRI Solutions as a project manager for PlantView Software and the Plant Reliability Optimization process. Prior to that, he worked for CSI Services and M&D, LLC. You may contact him by emailing editorial@woodwardbizmedia.com.

April 2014

REGULATIONS COMPLIANCE

Coal storage hazards and solutions By Julianne Couch, Energy-Tech contributor

Coal storage at power generation facilities might not be on most people’s minds, but the U.S. Environmental Protection Agency has created regulations for it, and companies have responded with solutions to the problems coal storage can create. The history of coal storage oversight by the EPA began in 1987, when a section was added to the Clean Water Act to address stormwater discharge under the National Pollutant Discharge Elimination System (NPDES) program. Section 402(p) required the development of a permitting program for stormwater discharges from industrial activity. In 1990, the EPA issued the Phase I stormwater rules, which identified specific categories of industrial activity requiring NPDES permit coverage, including discharges from steam Photos contributed by Mole-Master electric plants and coal mining facilities. Pollutants might be present in stormwater as a result of material handling and transport operations, waste disposal and airborne particles deposited into water, according to the EPA. “In addition, sources of pollutants other than stormwater, such as illicit connections, spills and other improperly dumped materials, might increase the pollutant loadings discharged into receiving waters,” the agency said. Most steam electric plants and coal mining facilities have permit coverage for their stormwater discharges under a general NPDES permit, the EPA said. Facilities must ensure that discharged stormwater does not violate water quality standards. Likewise, stormwater discharges specifically from coal storage piles at steam electric plants are subject to an “effluent limitation guideline.” Coal pile runoff is regulated under “best practicable technology” and under “new source performance standards” parts of Section 402 (p). Both of these regulations limit total suspended solids to 50 milligrams per liter. “Coverage is required for stormwater discharges from all industrial activities occurring at steam electric power generating facilities and at coal mining facilities, which includes areas of coal storage,” according to the agency. Whether stormwater runoff from coal piles occurs from heavy rainfall or from allout flooding, it is covered by NPDES permitting program. The program takes into account that sometimes extreme weather events cause a facility to be temporarily unable to comply with NPDES permit terms. In addition to regulations for stormwater runoff, the EPA also has regulations for cleaning the storage systems and ensuring that wash water used in cleaning be drained to a proper collection system, and not the stormwater drainage system. “The permit does not authorize discharges of vehicle and equipment wash water to waters of the U.S., including waters from tank cleaning operations,” the agency said. Whether power plant facilities are storing the coal in silos, tanks or a dome, the EPA requires the implementation of good housekeeping practices to “minimize discharges of pollutants associated with coal handling areas at steam electric plants.”

• • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • •

• • • SELL • RENT• LEASE • - 24 / 7 • EMERGENCY SERVICE • • • • • • IMMEDIATE DELIVERY • CALL: 800-704-2002 •• 10HP TO 250,000#/hr • • • • • • • • RENTAL FLEET OF MOBILE • TRAILER-MOUNTED BOILERS • • • • • ALL BOILERS ARE COMBINATION GAS/OIL ENGINEERING • START-UP • FULL LINE OF BOILER • AUXILIARY SUPPORT EQUIPMENT. • Electric Generators: 50KW-30,000KW • WEB SITE: www.wabashpower.com • 847-541-5600 • FAX: 847-541-1279 • E-mail: info@wabashpower.com • wabash • •

BOILERS

250,000#/hr Nebraska 750 psig 750OTTF 150,000#/hr Nebraska 1025 psig 900OTTF 150,000#/hr Nebraska 750 psig 750OTTF 150,000#/hr Nebraska 350 psig 115,000#/hr Nebraska 350 psig 80,000#/hr Nebraska 750 psig 75,000#/hr Nebraska 350 psig 60,000#/hr Nebraska 350 psig 40,000#/hr Nebraska 350 psig 20,000#/hr Erie City 200 psig 10-1000HP Firetube 15-600 psig ALL PRESSURE AND TEMPERATURE COMBINATIONS SUPERHEATED AND SATURATED

75,000#/hr 75,000#/hr 60,000#/hr 50,000#/hr 40,000#/hr 30,000#/hr 75-300HP

Optimus Nebraska Nebraska Nebraska Nebraska Nebraska Firetube

750 psig 350 psig 350 psig 500 psig 350 psig 350 psig 15-600 psig

750OTTF

POWER EQUIPMENT CO.

444 Carpenter Avenue, Wheeling, IL 60090

April 2014 ENERGY-TECH.com

REGULATIONS COMPLIANCE

Just like keeping one’s home free of debris and in good working order maintains its condition, good housekeeping practices at power plants are practical, cost-effective ways to prevent potential pollution sources from coming into contact with stormwater. In one of the EPA’s Industrial Stormwater Fact Sheet Series titles, “Steam Electric Power Generating Facilities, Including Coal,” it noted numerous general practices, and several related directly to coal storage. The agency lists coal pile management practices such as “confining storage to areas outside of drainage pathways and away from surface waters; diverting stormwater around storage areas with vegetated swales, and/or berms; and practicing good housekeeping measures such as frequent removal of dust and debris.” They indicate that “mobile sweepers, scrapers or scoops” can be used to clean, and collecting, containing and recycling should be done using properly designed basins. For example, “control measures such as berms, silt fences or waddles should be used to control sediment from leaving the coal storage area.” Last but not least, employees should be well-trained in these in good housekeeping methods. The goal of these practices is to eliminate or minimize the presence of pollutants in stormwater discharges. Housekeeping is one of several best management practices (BMPs) geared toward discharge prevention. The agency notes that if prevention practices are not enough, it might be necessary to implement costlier treatment BMPs. These include “engineered structures intended to treat stormwater runoff and/or mitigate the effects of increased stormwater runoff peak rate, volume

ENERGY-TECH.com

and velocity. Treatment BMPs are generally more expensive to install and maintain and include oil-water separators, wet ponds and proprietary filter devices,” according to the agency. How do power generation plant managers keep track of the various steps they need to take to avoid pollution, of which these are just a small part? Mole-Master Services Corp., based in Marietta, Ohio, is one company that, in part, helps power generation facilities meet these EPA regulations. For more than 25 years, it has provided silo cleaning and inspection services to numerous industries, including aluminum and steel processing, biofuels, cement, coal, glass, power generation, mining, plastics/chemical and many more. “Coal isn’t like water, which flows easily. Coal has to be taken places,” explained Dave Laing, general manager at MoleMaster, and there are several steps to get stored coal from a concrete silo at a power plant into the system. “Coal comes from the mine supplier, then goes to the prep plant, then to the plant,” he said. “It is stored temporarily in a concrete silo, and then when the time comes, it goes into day bins or bunkers in the power plant. From there, coal enters into the boilers that operate the power generation system. The resulting ash enters a cyclone to cool, which is stored in silos, pits or ponds.” The key to this system is that the coal has to flow through smoothly. Anything that stops or blocks this process puts the plant into slow or shut down mode. “The cost of an unplanned shutdown to plants is high,” Laing said. “They’ve promised the power, by contract, and have to deliver it, whether they are functioning properly or not.” There are certain aspects of this process that power plants can’t control, he said. “There are variables in the nature of the coal they receive, and then there are other variables based on how it is shipped, be it by rail or truck. When coal goes into silos, that keeps it dry, but silos build up and can also freeze.” That’s where Mole-Master comes in. “Depending on how a coal silo is engineered, there might be one to 7 discharges in a coal silo. It is not uncommon for operators to use one feeder more than the others, which is contrary to the design of the silo. They are actually designed to discharge equally and maintain equal pressure inside the silo. When coal feeds through asymmetrically, that changes the pressures in the silo and creates feed problems inside the structure.” That feed problem will affect how the silo performs and can even cause harm. “Uneven pressure from uneven flow will damage a silo,” Laing said. The life expectancy of a silo is related to how it is designed by an engineering group for specific applications and types of coal. For example, Laing explained, in the eastern United States, there has been a shift from local coal to Powder River Basin coal from Wyoming, which has different characteristics. That change can cause flow issues.

April 2014

REGULATIONS COMPLIANCE “There’s a learning curve for power plants to figure out involved with things like fire and explosion, which are at the how to modify their systems for loading, conveying and top of list with coal. It is important to be safe with things that storage,” he said. “Also important is the age factor. Concrete have risk to life and facilities.” ~ doesn’t last forever. In storage at a power generation plant, coal can get compacted to the point it is harder than it would have Julianne Couch is the author of, “Traveling the Power Line: From the been when in the mine. Mole-Master has tools and expertise Mojave Desert to the Bay of Fundy.” She has a master’s degree in to dislodge material without putting undue stress on the silo.” English from Emporia (Kansas) State University, and has spent much Through the years, Laing has seen changes in the upkeep of her career as an independent journalist. She has taught English at the University of Wyoming since 1998, although she presently lives in of coal silos at power facilities. Bellevue, Iowa, and teaches courses for UW online. You may contact “Coal mines and prep plant silos used to be inspected on her by emailing editorial@woodwardbizmedia.com. a regular basis to look for cracks in the concrete,” he said. “In recent years the coal industry has gone backwards in revenues so now they do it only occasionally. That can lead to catastrophic failure.” Preventative maintenance is crucial, Laing said. “The coal industry has been dealt a lot of blows,” he said. “Twenty years ago the industry was strong and powerful, but it has not maintained that level because of politSafety Silo Silo & Bin ical and environmental issues. In the old First Cleaning Inspection days, power plants rarely cared about what it cost, they just wanted it to be fixed.” Now preventative things that aren’t crucial at the moment slip away, Laing said. Mole-Master sometimes works with plants on inspections and also can assist with issues regarding how the coal flows from storage through the plant. Another consideration with coal is the “flammability and explosive problem,” Laing said, Because safety has Because for more than Because Mole•Master adding that the explosive nature of coal always been Job One a quarter of a century, helps you prevent dust impacts the degree of difficulty of the at Mole•Master. Mole•Master has been problems before they work. Mole-Master might assist when the the #1 choice for silo become problems. • Professionally trained plant is preparing for a planned shutdown, and bin clean-out. We We have decades of or when the plant is ready to resume oper• Certified technicians get your facility up and experience inspecting ation after that planned shutdown. They in OSHA/MSHA running in record time. silos and identifying also get emergency calls when some part of Safety Standards a silo has become completely blocked. potential issues. Whether it is power generation or any of the other industries they work with, Laing said it is crucial to know how to manage storage and material inventories. “It is important to not ignore build-up problems within systems,” he said. Many of the problems his company is called to resolve are not a result of people Learn more about Why MOLE•MASTER should be your choice making mistakes, Laing said, it just comes for Silo & Bin Cleaning and Inspection. with the territory. 1.800.322.6653 • www.molemaster.com Nevertheless, “people need to maintain the safe way of doing whatever they do,” he said. “If there’s a problem, a lot of people have smart guys who know when to call us, but also know all the risks and hazards

Why

740.374.6726 • Fax: 740.374.5908 • Email: info@molemaster.com

April 2014 ENERGY-TECH.com

MR. MEGAWATT

Vendor correction connection By Frank Todd, True North Consulting

Being a practitioner of data, I’m always intrigued by how much certainty people have if they can follow a statement up with the phrase “studies show.” With just that phrase, many will hang their hat on a graph or statement based on someone else’s study or evaluation. This is also the case with the “vendor” at a power plant. Often, if a vendor says it, there are no questions asked. There is some logic to this, since the vendor is the one who made the thing in question and should know the most about it. Funny thing though, all the vendors I have dealt with are human and we humans are known to be wrong on occasion. Just ask my wife. Looking out my window, wishing I could see the San Juan Mountains instead of more large snowflakes, I was distracted by an email notification – *bing! Of course, this is one of the most beautiful sounds in the world, so I immediately clicked and read. My peaceful moment morphed to dread. It was a message from Jersey Jungle Power Station (JJPS). Last time we visited and helped them with a turbine evaluation, Brian and I barely got away with all our digits. This email was from the Don himself, Mr. Gangone, who was now the VP of the syndicate. “Dear Mr. Megawatt, Please present yourself and your associates at our offices tomorrow morning. I have an offer for you that … ” As I tried to keep my composure, I saw a black Humvee drive up the side of the bluff and out stepped two impressively large men. “Mr. Gangone sends you his respects and would like yuz to come along wit us,” one said. “We have your associate inside da ca, please get in.” Not my typical commute to work, but how could I refuse? So I climbed in and greeted a pale looking Brian the BTU Buster. We were driven down the bluff and to the airport, where a puddle jumper was waiting to carry us to the Jersey Jungle Municipal airport. During the flight, we were given the details of the problem. JJPS had recently installed a new turbine generator in Unit 2, and while the testing indicated that everything was fine, Vito thought there were some problems. Vito was the engineer we worked with on our last job with JJPS and he was now the plant manager for Unit 2, which was their first Nuclear Unit. When we realized that, Brian and I breathed a very significant sigh of relief. We had bailed out Vito on our last visit, and Vito is not one to forget a favor. Once we arrived, Brian and I got to work reviewing the test data. Based on the data and the corrections provided by

ENERGY-TECH.com

Fig. 1.

the vendor, everything looked fine. The plant had increased the thermal power at the same time that they replaced the high pressure and the low pressure turbine. The guarantee value was 115 MWe and the vendor calculation indicated an increase of 118 MWe. Vito was no dope, so I thought we should bring in our testing wizard, Kerry W. Kilowatt (KW) to look things over. Vito was a little dubious, but I told him that Kerry really knew how to “go to the mattresses” with a vendor, so Vito agreed. Kerry arrived and immediately starting building a model of the heat balance so we could verify the correction curves provided by the vendor. He evaluated all the corrections and calculated the corrected generation for both the pretest and the post test data. We soon understood that Vito was right to question the results. We asked Kerry to put on a three piece suit and went to meet with Mr. Gangone and the vendor. What Kerry discovered was that the LP exhaust pressure correction curve that the vendor provided for the post test did not match the curve that we developed based on the exhaust loss curve also provided by the vendor. In addition, the vendor curve has some obvious anomalies at the lower pressures. If their curve was correct, then there was a loss of physics accident (LOPA) going on in the exhaust hood. Since the exhaust loss curve is an input to coming up with the back pressure correction curve, we figured it was the correct curve of the two. Figure 1 shows the two condenser pressure correction to load curves. There were two questionable areas in the curve, one at the low pressure (the left side of the curve) and one at the high pressure (the right side of the curve). Unfortunately the post test was performed at a much higher condenser pressure than the pretest, so the correction had a much larger effect. The pretest was around 1.4 INHGA and the post

April 2014

MR. MEGAWATT Table 1 – JJPS Unit 2 Pre and Post Test Analysis Pre Test

Post Test

TNC

Vendor

Test Date

01/01/13

07/05/13

Start Time

10:15AM

8:30AM

TNC

Vendor

Units

End Time

12:15PM

10:30AM

Measure Gross Generator Load

940642.3

940642.5

1008384.1

1008384.0

Corrected Gross Generator Load (generator corrections)

940024.7

940024.5

1007930.9

1007931.0

801.0

400.0

500.0

600.0

Top Heater Terminal Temperature Difference Correction

1.0002

1.0004

0.9986

0.9987

---

Extraction Line Pressure Drop Correction

1.0008

1.0012

1.0008

---

System Water Storage Changes Correction

0.9998

1.0000

---

Condensate Subcooling Correction

0.9997

0.9998

0.9999

---

Reactor Thermal Power Correction

0.9994

0.9993

0.9985

---

Secondary Leakage Correction

HP Turbine Inlet Steam Pressure Correction

1.0013

1.0001

---

HP Turbine Inlet Steam Quality Correction

1.0000

1.0005

1.0000

---

MSR Pressure Drop Correction

1.0026

1.0021

1.0032

1.0027

---

LP Turbine Exhaust Pressure Correction

0.9918

0.9919

0.9525

0.9500

---

Reheater Terminal Temperature Difference (2nd Stage) Correction

1.0003

1.0002

1.0001

1.0002

---

Total Group 1 and 2 Correction Final Corrected Load

0.9958

0.9961

0.9540

0.9508

---

944782.6

944099.8

1057000.2

1060684.0

112217.6

116584.2

Increase in generation Table 1 – JJPS Unit 2 Pre and Post Test Analysis

test was around 2.7 INHGA. Figure 2 shows a comparison between our corrections and the vendor corrections. We matched fairly well on the pretest, but were significantly off on the post test. This was largely due to the turbine exhaust back pressure correction. We walked into the conference room with the smell of spaghetti sauce and, with more than a little trepidation, I remembered the last time we were here. In came Mr. Gangone with his two “associates” and a couple of very frightened looking fellows from the turbine vendor. Mr. Gangone thanked everyone for being there to clear up the slight misunderstanding. Since the liquidated damages were in the six digits, Mr. Gangone’s use of the term “slight” was interesting. Kerry walked in wearing a 3-piece-suit, complete with a pocket watch he had borrowed from me. Just one look at the expressions in the room told me I had made the right choice. Initially, the vendor had indicated that they had met the 115 MWe guarantee with some margin, but our calculations showed that they had not met the guarantee. Kerry explained the situation in sufficient detail and that there was no doubt about the cause of the discrepancy. I’m not sure if it was Mr. Gangone’s associates cracking their knuckles or that the vendor’s representatives were honest,

but either way the jig was up. We sent our calculations to the vendor before the meeting showing a 112 MWe improvement, including our correction curve and that they had performed a CFD analysis of the back end of the turbine, verifying that our curve was correct. Kerry suggested that this whole problem could have been avoided if the test had been performed during a period of lower condenser pressure similar to the pretest. The end result was that large sums of money were passed in the opposite direction then what was initially expected. Thanks to Kerry, once again we had dodged the cement overshoes, Brian could now convert his Miata to a Ferrari and Kerry could do some serious upgrades to his condo. I was just happy to get back to my office, wind my clock, and plan a trip to see my twin granddaughters without any email distractions. ~ Mr. Megawatt is Frank Todd, manager of Thermal Performance for True North Consulting. True North serves the power industry in the areas of testing, training and plant analysis. Todd’s career, spanning more than 30 years in the power generation industry, has been centered on optimization, efficiency and overall Thermal Performance of power generation facilities. He can be contacted at editorial@woodwardbizmedia.com.

April 2014 ENERGY-TECH.com

ASME FEATURE

A dynamic process model of a natural gas combined cycle – model development with startup and shutdown simulations By Eric Liese and Stephen E. Zitney, National Energy Technology Laboratory

The National Energy Technology Laboratory (NETL) Computational Science and Engineering Division (CSED) recently deployed a high-fidelity, full-scope, real-time dynamic simulator for a generic IGCC power plant with CO2 capture for use in engineering research. The simulator is based on the DYNSIM® dynamic simulation software and InTouch® human-machine interface (HMI) software, provided by Invensys Operations Management (IOM). More recently, NETL Figure 1. HMI for combined-cycle section of the IGCC dynamic simulator deployed at the NETL AVESTAR Center. and IOM have established describes the model and some early results, after a discusa cooperative research and sion of motivation for the work and some literature pertidevelopment agreement (CRADA) to specify, develop, nent to the topic. test and deploy a generic Natural Gas Combined Cycle (NGCC) operator training simulator (OTS), which will Literature and motivation be used by NETL for R&D related to NGCC Cycling. The NGCC dynamic simulator will be used for operaCSED has completed the steady-state design (heat and mass tor training and research. Given continued low natural gas balances) for a generic 560 MW net NGCC power plant prices and more stringent pollutant emissions regulations with two 180 MW gas turbines (GT) and a 210 MW steam on coal-fired plants, it is anticipated that the role of NGCC turbine (ST). Designed using the GT-Pro software package power plants in the U.S. energy portfolio will increase. This, from Thermoflow, the 2-on-1 NGCC power plant has 56 coupled with the increased capacity of renewable generapercent LHV net electric efficiency. tors, especially wind, will result in NGCC plants that will Using the combined cycle section of the IGCC dynamexperience even more stress due to cycling. Thus, the need ic simulator shown in Figure 1 as a starting point, CSED for more operator training and smarter control will be has implemented the DYNSIM® design changes, matching important. The effect of more frequent cycling, and espethe new NGCC steady-state results from GT-Pro. While cially two-shifting, on equipment failures in power plants is work remains to finalize the NGCC OTS (InTouch® HMI becoming more significant[1]. Not to be forgotten, emissions graphics modifications, emissions characterization, etc.), the characteristics also are negatively affected, as pointed out by dynamic model is currently capable of simulating operating Bivens[2] and Katzenstein et al[3]. scenarios ranging from startup to shutdown. Testing of the dynamic NGCC model has been initiated, and this paper

ENERGY-TECH.com

ASME Power Division Special Section | April 2014

AsME FEAtUrE ASME Power Division: Combined-Cycle Committee

A Message from the Chair

Figure 2. Simple schematic of combined cycle equipment in the NGCC plant.

Technology providers are attempting to address these issues. Alstom discusses the use of combined cycles as an “ideal solution to balance grid fluctuations”[4]. In particular, Alstom highlights low-load point operation, a fast hot start capability, improved HRSG design concepts, and steam turbine stress control. GE literature also discusses steam turbine stress control and other operations for decreasing startup time, such as a purge credit, which removes the need for purge of the HRSG during startup[5, 6]. Siemens suggests some design and procedure changes to improve hot startup times by 50 percent compared to its reference plant[7]. Henkel et al.[8] discuss limitations to fast start-up times due to waiting for water chemistry and stress limitations of thick-walled components in the steam turbine and HRSG. Proposed solutions include: steam attemperators in the final stage of the HRSG; stress monitoring of thick-walled components in the steam turbine and HRSG; different startup modes; optimization of main steam warm-up lines; condensate polishing systems and flexible purity requirements. Shortened startup also is discussed using: early ST roll-off using “cold” steam, with startup in 40 minutes after overnight shutdown; “hot-start on the fly”, steam is not dumped or GT is held going right to maximum GT loading rate and the ST is loaded as pressure increases; modified steam line and turbine warm-up procedures that shorten cold and warm/hot startup. Also, modified steam turbine sliding pressure operation for frequency control participation is suggested. Presumably, dynamic simulation is being used by manufacturers as a means to investigate and address some of the aforementioned issues. Sometimes the dynamic model also is used as the control solution, such as in model predictive control (MPC) as shown by D’Amato[5]. In the public literature, there is the work by Alobaid et al.[9, 10] showing the benefits of using dynamic simulation for improving startup procedures. Making a decision on the best solution to a problem will likely require detailed analyses of the plant dynamics, along with the individual component behavior, followed by an economic comparison between the various options. While the dynamic NGCC model under development by NETL will be used as a training simulator,

April 2014 | ASME Power Division Special Section

The Combined-Cycle Committee is a dynamic community addressing the technological aspects of combined-cycle power plants. It functions as a technical committee of the Power Division to promote the technological science, development, design, construction, operation and maintenance of combined-cycle power plants, as well as their major components. With tightening environmental regulations resulting in closure of coal plants, the integration of renewable energy, and the vast new supplies of natural gas from shale formations, resulting in record low natural gas prices, simple- and combined-cycle power plants will continue to fill an increasing portion of the current installed and planned North America generation technology profile. The committee meets twice annually to organize the delivery of valuable conference content. The committee sponsors the Simple- and Combined-Cycle track at the ASME Power conference each year, which includes technical sessions, panel session and workshop/tutorials. The topics of the sessions will cover operational and maintenance, gas turbine designs and upgrades, integration with renewable energy, and cycling operation issues. This year’s conference will be held in Baltimore, Md., July 28-31, 2014. I invite you to attend this year’s conference, and encourage you to participate in committee meetings and other activities. For more information, visit www.asmeconferences.org/power2014/. This month’s ASME Feature is an excellent example of a relevant paper presented during one of our technical sessions at 2013 ASME Power Conference in Boston, Mass. I hope you enjoy the article. Best regards, Benjamin Deng Chair - ASME Power Division Combined Cycle Committee Hatch 2800 Speakman Drive Sheridan Science & Technology Park Mississauga, ON, Canada L5K 2R7 bdeng@hatch.ca

ENERGY-TECH.com

ASME FEATURE which are slightly different then the GT Pro results due to model setup. Table 1 – Comparison of NGCC and IGCC Main Parameters Analysis Some differences to note between the NGCC and IGCC are as follows. GT NGCC CC IN IGCC The NGCC exhaust flow is lower Power (MW) 183.8 230.4 compared to the IGCC, even though Compressor air flow rate (lb/sec) 976 912 the compressor air flow rate is slightExhaust flow rate (pps) 1014 1125 ly higher. This is because the IGCC has a significant amount of dilution Firing temp (°F) 2508 2425 nitrogen from the air separation EGT (°F) 1168 1107 unit that is added to the combusHRSG EGT (°F) 190 (185) 264 tor for NOX control. Also, the GT ST NGCC CC IN IGCC firing temperature is higher for the NGCC. For the IGCC, the GT temHP perature was considered a bit more Power (MW) 46.1 58.7 limited due to the higher water Inlet Pressure (psia) 1768 1733 vapor content concerns affecting the turbine inlet blades. The HRSG Temp (°F) 1046 993 exhaust gas temperature (EGT) is Flow rate to turbine (pps) 245 363 (320 from RSC drums) lower for the NGCC; the IGCC Flow rate from drum (pps) 250 88 case being too limited compared to IP common practice (the limit being related to condensation within the Power (MW) 67.1 95.4 last economizer section). Inlet Pressure (psia) 331 413 The HRSG has three presTemp (°F) 1047 998 sure-levels, namely high-pressure Flow rate to turbine (pps) 289 369 (HP), intermediate-pressure (IP) and low-pressure (LP), and a natural Flow rate from drum (pps) 40.2 22 recirculation steam drum design; LP operating and design conditions are Power (MW) 99.24 115.4 given in Table 2. The order, hotInlet Pressure (psia) 54.7 51.8 to-cold, of the HRSG Superheater (SH), Reheater (RH), Evaporator Temp (°F) 586 456 (EV) and Economizer (EC) heat Flow rate to turbine (lb/sec) 329 432 exchangers are shown in Table 3. Flow rate from drum (lb/sec) 39.4 62.9 The NGCC dynamic simulator will retain most of the auxiliary Table 1 – Comparison of NGCC and IGCC main parameters systems that the combined cycle required for the IGCC simulator, there also are plans to use it as a test bed for implementasuch as lube oil, steam seal, etc. Also, the operating procetion of advanced process control methods, optimal sensor dures will be similar; however, more development is needed placement, or for providing input data for fluid flow and for load following, single turbine shutdown and hot/warm structural analysis of equipment components, along with restarting. Because the entire scope of the simulator’s opererosion/corrosion modeling and failure/life analysis. Also, ational procedures and capabilities is large, the results will the NGCC dynamic simulator might be used to investigate not show the step-by-step procedure, but will focus on a other issues, such as pollution minimization. particular operation and section of the HRSG.

Model description The steady-state conditions for the model were determined using the commercial software package GT Pro by Thermoflow. It was decided to simulate a 2-on-1 (2 GTs and one ST) combined cycle since the IGCC model is a 2-on-1. Also, a GT with a similar airflow rate to the IGCC was used. Table 1 shows a comparison of the NGCC and IGCC main parameters. The table shows the steady-state results for the dynamic NGCC model (in DYNSIM),

ENERGY-TECH.com

Results Figure 2 shows a simple schematic of the combined cycle equipment in the NGCC plant that will be discussed here. Simulation results of particular interest include the HRSG final high-pressure SH steam and gas temperatures (in, out), and the outlet secondary steam temperature, as well as the steam and gas turbine power and mass flow rate.

ASME Power Division Special Section | April 2014

ASME FEATURE

Component Upgrade

Functional Testing to Verify DROOP & Deadband

409

Complete Overhaul

gh by ,O H4

MHC Operating Governor

4• om 80 0ts.c r a P 4 4 6-4 776 • www.Renewal

Figure 3 shows the shutdown history of a single gas turbine from full-load conditions (182 MW). The load (blue dotted line) is decreased at a rate of 10 MW/min, and then held at 18.5 MW for 6 minutes to allow cool down of the combustor and turbine components. The other GT load also changes during this maneuver; however, it does not affect any results presented in the following discussion. As turbine load is reduced, the variable inlet guide vanes (VIGV) close to reduce GT airflow (dashed pink line), maintaining constant temperature to the HRSG inlet, as seen by the constant final SH gas inlet temperature (purple). This VIGV movement is standard in combined cycle operations and is done to maximize system efficiency. Depending on the type of GT, the turndown capability is 20-50 Figure 3. Shutdown of one Gas Turbine (GT) percent of the flow. and closing of various steam valves to the steam headers. After the VIGV closes to its minimum The plots in Figure 3 and the discussion above only highposition, the final SH gas inlet temperature (purple line) light a few aspects of the shutdown for demonstration. begins to drop, and thus the final SH steam outlet temperaFigure 4 shows a startup of the GT after a hot-hold ture (green line) also drops. Most interesting in this plot is period of 8 hours. The startup scenario begins by spinning the “bump-up” in the final SH steam outlet temperature the GT up to light-off speed with a Load Commutating (red) at around 1,000 seconds. The steam is desuperheated about 25°F at design, and about 50°F at the minimum IGV limit. This ~50°F temperature rise occurs while the other temperatures and flows are decreasing, and this is attributed to the attemperator shutdown. Note that the secondary SH outlet temperature (orange) and final SH inlet temperature (red) are the same after the desuperheater is no longer in use (the desuperheater is in between them). It is interesting to note that poorly controlled attemperator sprays are a recognized cause for thermal cycle damage. After the GT trip at around 1,600 seconds, it can be seen that the final SH steam inlet temperature (red) is higher than the secondary SH steam outlet temperature (orange). These temperatures are not the same due to the thermal capacitance of the desuperheater. After the turbine spins down, it is put on turning gear and the stack damper is closed to put the combined cycle in u a hot-hold state. There are a number of llo i the other procedures, both automatic and •W d manual, during the shutdown that are not Ren ew Roa shown or discussed, such as the bypassing al P rook

ar ts Maintenan • 4485 Glenb ce

April 2014 | ASME Power Division Special Section

ENERGY-TECH.com

ASME FEATURE

Figure 4. Startup of one GT after hot-hold (other GT and ST already running)

Table 2 â&#x20AC;&#x201C; Three-pressure HRSG Conditions HRSG Drums HP Operating Pressure (psia)

1890

Diameter (inches I.D.)

Length (ft)

Thickness (in) Normal Water Level (NWL) (inches above centerline)

5.125 4

Storage Time NWL to dry (min)

3.5

Evaporator recirculation ratio

14:1

Operating Pressure (psia)

384

Diameter (inches I.D.)

Length (ft) Thickness (in) Normal Water Level (NWL) (inches above centerline)

40 1.125 0

Storage Time NWL to dry (min)

13.7

Evaporator recirculation ratio

35:1

LP Operating Pressure (psia)

Diameter (inches I.D.)

Length (ft)

Thickness (in)

0.525

Normal Water Level (NWL) (inches below centerline)

16.8

Storage Time NWL to dry (min) (includes BFW flow)

2.22

Evaporator recirculation ratio

75:1

Inverter (LCI) after opening the stack damper. In this case, it is assumed that no purge of the HRSG is necessary. After synching the generator, load is automatically set to 20 MW and then load (blue dotted line) is raised from 20 MW to 185 MW at ~10 MW/min. Temperature matching takes place around 35,000 seconds; temperature matching limits the maximum steam temperature (the green line) to the steam turbine inlet via opening the VIGV. In our operating procedures, we usually hold load while VIGV temperature matching is engaged, and then turn off temperature matching before ramping to full load, but in the case shown there is no hold. Once full load is reached, the VIGV position is full open and the desuperheater comes on, as indicated by the final SH steam inlet temperature (red line). For the GT startup presented, the most apparent region of significant temperature gradient occurs during the ramping between 20 MW and 80 MW (blue shaded region). As indicated by the GT flow rate (dashed pink line), the VIGV position does not change, and remains near its minimum position. The position does not start to increase until the temperature matching is turned on.

Conclusions Development of a dynamic simulator for a 2-on-1 natural gas combined cycle was briefly described. This simulator, while being generic, will have many of the important features necessary for training operator personnel. It also is planned to be used as a tool for developing and analyzing potential improvements to operating procedures and control; especially issues related to increased cycling. While the NGCC dynamic simulator is composed primarily of 0-D models, the temporal data can be used as inputs into more detailed models of critical components. A shutdown and hot-startup scenario were presented and focused on temperature trends for the final SH in the HRSG, where expectedly high temperature changes are occurring. As an example lesson, it is possible that the VIGVs could be modulated to lessen the thermal

Table 2 â&#x20AC;&#x201C; Three-pressure HRSG Conditions

ENERGY-TECH.com

ASME Power Division Special Section | April 2014

ASME FEATURE impact on the final SH, superseding its efficiency-based modulation during the shutdown or startup maneuver. Also, the desuperheater control could be modified in anticipation of events that have known negative impacts.

Table 3 – HRSG Heat Exchange Order

Disclaimer This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof. ~ References 1. Lefton, S. A., Besuner, P. M., Grimsrud, G. P., Agan, D. D., and Grover, J. L., 2009, “Analysis of Cycling Impacts on Combined Cycle Heat Recovery Steam Generators and Evaluating Future Costs of Countermeasures to Reduce Impacts”, ASME Power Division Special Section, pp. 25-29. 2. Bivens, R. J., 2002, “Startup and Shutdown NOx Emissions from Combined Cycle Combustion Turbine Units”, EPRI CEM User Group Meeting, Chicago, Illinois.

Visit us at our upcoming shows! Electric Power | April 1-3 | Booth #249 Morial Convention Center | New Orleans LA

Gas Flowpath Final HP-SH

HP-ST

Final RH

IP-ST

Secondary HP-SH

HP-SH

Primary RH Primary HP-SH HP-EV

Final RH Secondary HP-SH Primary HP-SH

Secondary IP-SH

Primary RH

Secondary HP-EC

HP-EV

LP-SH

LP-ST

Primary IP-SH

Secondary IP-SH

Primary HP-EC

Secondary HP-EC

IP-EV Secondary IP-EC and Primary HP-EC

Primary IP-SH IP-EV and Secondary HP-EC

LP-EV

LP-SH

Primary LP-EC

LP-EV

Table 3 – HRSG Heat Exchange Order

Refcomm | April 28-02 | Booth #52 Moody Gardens Convention Center | Galveston TX

LED FAA Obstruction Lighting Reduced Maintenance Cost Highly reliable Class 1 Division 2 products for hazardous locations April 2014 | ASME Power Division Special Section

Steam/Water Feeds

315-699-4400 www.unimar.com ENERGY-TECH.com

ASME FEATURE 3. Katzenstein, W., and Apt, J., 2008, “Incorporating Wind into Natural Gas Turbine Baseload Power System Increases NOX and CO2 Emissions from Gas Turbines”, Carnegie Mellon University – Future Energy Systems: Efficiency, Security, Control. 4. Ruchti, C., Olia, H., Franitza, K., and Ersahm, A., 2011, “Combined Cycle Power Plants as Ideal Solution to Balance Grid Fluctuations, Fast Start-up Capabilities”, Kraftwerkstechnisches Kolloquium, Dresden, Germany. 5. D’Amato, F., Kirchhof, D., Baker, D., Holzhauer, D., and Macvaugh, R., 2006, “Model Predictive Control for Combined Cycle Startups”, GE Global Research Technical Report, 2006GRC652. 6. DeLeonardo, G., Scholz, M., and Jones, C., 2011, “FlexEfficiency 50 Combined Cycle Power Plant”, GE Energy, GEA19089. 7. Emberger, H., Schmid, E., and Gobrecht, E., 2005, “Fast Cycling Capability for New Plants and Upgrade Opportunities”, Siemens Power Generation, Germany. 8. Henkel, N., Schmid, E., and Gobrecht, E., 2008, “Operational Flexibility Enhancements of Combined Cycle Power Plants”, Power Gen Asia, Kuala Lumpur, Malaysia. 9. Alobaid, F., Postler, R., Strohle, J., Epple, B., and HyunGee, K., 2008, “Modeling and Investigation Start-up

April 2014 | ASME Power Division Special Section

Procedures of a Combined Cycle Power Plant”, Applied Energy, (85) pp. 1173-1189. 10. Alobaid, F., Strohle, J., Epple, B., and Hyun-Gee, K., 2009, “Dynamic Simulation of a Supercritical Oncethrough Heat Recover Steam Generator During Load Changes and Start-up Procedures”, (86), pp. 1274-1282. Editor’s note: This paper, PWR2013-98179, 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. Eric Liese is a research engineer currently doing dynamic process simulation in the Computational Science and Engineering division at the U.S. Department of Energy’s (DOE) National Energy Technology Lab (NETL). He has been working for more than 20 years in various areas of experimental and computational research for fossil fuel energy technologies, like fuel cells and gas turbines. Liese has experience using dynamic modeling tools such as Matlab Simulink, Aspen, Aspen Custom Modeler, and Dynsim. He received his bachelor’s degree in Aeronautical Engineering from Purdue University and master’s degree in Mechanical Engineering from West Virginia University. You may contact him by emailing editorial@woodwardbizmedia.com. Stephen E. Zitney, PhD, leads dynamics and control R&D efforts at the U.S. Department of Energy’s (DOE) National Energy Technology Laboratory (NETL). Before joining DOE/NETL in 2004, Zitney held senior consulting and R&D management positions at Fluent, a leading provider of computational fluid dynamics software, Aspen Technology, a major supplier of process simulation software, and Cray Research, a leading provider of supercomputing tools to the process industries. He received M.S./Ph.D. degrees in Chemical Engineering from the University of Illinois at Urbana-Champaign and a bachelor’s degree in Chemical Engineering and Engineering & Public Policy from Carnegie Mellon University. You may contact him by emailing editorial@woodwardbizmedia.com.

ENERGY-TECH.com

Mark your calendar now for the BEST technical conference in power generation

July 28-31, 2014 Baltimore, Maryland

Hyatt Regency Baltimore on the Inner Harbor Engage in operating, maintenance, and equipment issues with experts inside the

ASME 2014 Technical Tracks: Track 1

Fuels & Combustion, Material Handling, Emissions

Track 2

Steam Generators

Track 3

Heat Exchangers & Cooling Systems

Track 4

Turbines, Generators & Auxiliaries

Track 5

Plant Operations & Maintenance

For more information, go to

Track 6

www.asmeconferences. org/Power2014

Reliability, Availability & Maintainability (RAM)

Track 7

Plant Systems, Structures, Components & Materials Issues

Track 8

Simple & Combined Cycles

Track 9

Advanced Energy Systems Renewables (Wind, Solar & Geothermal)

Track 10

Energy-Water Nexus

Track 11

Thermal Hydraulics & CFD

Track 12

Nuclear Plant Design, Licensing & Construction

Track 13

Performance Testing & Performance Test Codes

Track 14

Student Paper Competition Track

power plant and find out the latest methods and cutting-edge technology to improve your power plantâ&#x20AC;&#x2122;s operation.

Media Sponsor

TURBINE TECH

Don’t lose your tune with turbine blade damage By Stephen R. Reid, PE, TG Advisers Inc.

Blade erosion damage The later stages of low pressure (LP) turbine blades operate in a low quality steam environment. Design moisture levels can range from 1 or 2 percent all the way up to 15 percent. Units that suffer from reheat or main steam temperature droop at low loads can significantly increase moisture levels and subsequent rates of erosion. There has been a trend in merchant plants to reduce minimum load to the furthest degree possible to mitigate operating losses during periods of low demand and energy pricing. Figures 1a and 1b provide two examples of typi- Figure 1a. Blade water droplet erosion damage Figure 1b. Blade water droplet erosion damage cal erosion damage experienced on the last stages of a fossil LP design. As noted, there is signifLP blades see these icant cut-back and loss of blade material from erosion. For upsets in steam flows these examples, the leading edge of the last stage included as non-uniform steam a soldered stellite shield to mitigate erosion. Other designs pressures, velocities, include induction-hardened leading edges to accomplish and/or flow angles at the same design task. multiples of running When making repair decisions, it is important to note speed. If resonance later stage LP blades are tuned to avoid resonances at mulexists between the tiples of running speed. These blades experience vibratory natural frequency of a steam excitation from: blade or blade group • Partial admission (HP blades only) and fundamental • Inexact matching of stationary blade geometry at the multiples of running Figure 1c. Blade water droplet erosion damage horizontal joint speed, high-cycle • Leakage in stationary blade shrouds at the horizontal fatigue failures can joint occur. The resulting vibratory response of the blade to this • Thermal distortion of stationary components harmonic excitation will dictate whether one or more of that cause ellipticity the blade natural frequencies must be tuned away from har• Non-uniform spacing of stationary monics of running speed. For blade modes that cannot be blades tuned, it is necessary to keep the resulting vibratory stress• Extractions and moisture removal es below the endurance limit of the respective materials. slots Figure 2 provides an example “Campbell Diagram” which illustrates the number of modes that are typically tuned for a last stage nuclear blade. It is crucial to recognize the loss of blade material, from erosion or other causes, which can significantly alter a blade or group’s vibratory response away from design; and, perhaps reduce or eliminate margins from multiples of running Failure to properly speed. It is rarely a reasonable course of action to “do nothground rotating ing” and leave severe erosion untouched. equipment can result in Figure 3 shows a silver solder and stellite repair “in expensive bearing, seal, & progress” which was completed by a major U.S. utility. The repair restored the original blade geometry. gear damage.

Are Shaft Currents Destroying Your Machinery?

SOHRE TURBOMACHINERY® INC. 128 Main Street, P.O. Box 1099 Monson Massachusetts, USA 01057-1099 28 ENERGY-TECH.com PH: 413.267.0590 • 800.207.2195 • FX: 413.267.0592 tsohre@sohreturbo.com • www.sohreturbo.com

April 2014

TURBINE TECH

Figure 2. Blade campbell diagram

Figure 3a. Stellite repairs

Figure 3b. Stellite repairs

natural frequency is resonant with one of these multiples of Lashing wire and lug cracking running speed, rapid high-cycle fatigue failure can occur. Low Pressure Blade Lacing wire (GE design) and lashing Low pressure blades that have significant service time can lug (Westinghouse/Siemens) cracking are common findings suffer from water droplet erosion damage and also cracked during major outage inspections of LP turbine blading (see lashing lugs. This damage can significantly alter a blade or Figure 4). In some cases, the GE design lacing wire extends blade group’s natural frequency, which in some cases, result through multiple blades to form groups. The connection is in a resonance condition. To avoid this condition, careful typically brazed to the blade. In other cases, the GE type inspection and repair of lashing/lacing wire cracking must design is a loosely fitted wire that is intended to float in be completed. In addition, water droplet erosion damage the blade hole and provide additional mechanical dampwill gradually remove blade material and cause blade natural ing of the blade group. The Westinghouse/Siemens vintage blade design usually has a lashing lug that is Inconel welded to adjacent blades to form a pre-determined grouping of blade multiples. Lashing wires and lugs are areas where it is common to find cracking. If Gaumer has industry leading knowledge in not addressed, cracked lashing wires can fuel gas conditioning including electric heater, produce unique and off-design blade frequencies that can lead to a resonance filter/coalescer and control panel design. failure. This should be an area where Gaumer engineers will work with your careful NDE is completed during an outunique operating conditions to provide age. In some cases, removal of the brazed a complete, successful solution. material is required to detect hidden blade cracking at this high-stressed locaCall today for: tion. Fortunately, most cracking can be • Fuel Gas Conditioning detected and repaired in place. Additional • Fuel Gas Heaters shot peening operations have been added • Fuel Gas Filters to the lashing lug repairs to provide enhanced high-cycle fatigue resistance.

Fuel Gas Problems?

Conclusion The later stages of low pressure turbine blading are typically tuned to avoid resonance with fundamental steam excitation frequencies (typically up to the 8 harmonic of running speed). At these frequencies, LP blades see upsets in steam flows as non-uniform steam pressures, velocities, and/or flow angles. If a blade’s

Celebrating 50+ Years

Fuel Gas Conditioning for all Gas Turbines 713.460.5200

www.gaumer.com

April 2014 ENERGY-TECH.com

TURBINE TECH frequencies to shift higher in their frequency band. If there is insufficient margin, blade resonance can occur. Options to restore/repair blade water droplet erosion damage that is described herein should be explored at each major outage if Cutsforth, Inc. www.cutsforth.com 32 significant blade erosion is found. ~

April 2014 Advertisers’ Index

EagleBurgmann

www.eagleburgmann-ej.com 31

Environment One Corp. www.eone.com 31 Stephen R. Reid, P.E., is president of TG Advisers Inc. and has more Flexim www.flexim.com/us 10

than 29 years of turbine and rotating machinery experience. Reid and his team provide turbine troubleshooting, health assessments and expert witness services to major energy companies in the Frederick Cowan & Co. www.fcowan.com 26 U.S. and have provided condition assessment evaluations on more Fulmer Co. www.fulmercompany.com 7 than 100 turbine generators in the U.S. Reid also is a short course instructor for EPRI, ASME, Electric Power and POWERGEN, has Gaumer Process www.gaumer.com 29 numerous patent disclosures and awards, and published more than Gradient Lens Corp. www.gradientlens.com 9 20 technical papers and articles. Reid was the recipient of the 1993 ASME George Westinghouse Silver Medal Award for his contributions Hexeco www.hexeco.com 31 to the power industry and is past chairman of the ASME Power Generation Operations Committee. He is a registered professional Indeck Power Equipment Co. www.indeck.com 31 engineer in the state of Delaware. You may contact him by emailing Miller-Stephenson Chemical www.miller-stephenson.com 31 editorial@woodwardbizmedia.com.

FloScan Instrument Co. Inc.

www.floscan.com

Mole•Master Services www.molemaster.com 17 Renewal Parts Maintenance Rolled Alloys

www.renewalparts.com

www.rolledalloys.com

Sohre Turbomachinery Inc. www.sohreturbo.com 11,28 Structural Integrity Associates, Inc. www.structinc.com 2 Unimar - Light & Control Solutions Wabash Power Equipment

www.unimar.com

www.wabashpower.com

exclusivewebinar

from

Energy-Tech

Archived webinars Makeup Water Performance & Reliability Condenser Retrofits Hydrogen Safety Turbine Outage Optimization Equipment Reliability Programs Turbine Testing with Cycle Isolation Steam Generation Chemistry Power Generating Assets Steam Turbine Failure Feedwater Heater Troubleshooting Maximizing Condenser Tube Life

ENERGY-TECH.com

Proper level control for feedwater heaters With Mike Catapano and Eric Svensson, Powerfect Inc. April 24 • 1 pm CST Sign up at www.energy-tech.com Free and worth 1 PDH

April 2014

Energy-tech showcase

BOILERS BOILERS BOILERS BOILERS BOILERS BOILERS BB

Coming in May 2014

Contact Re-Nu® & Lube

RENT RENT RENT SALE SALE SALE LEASE LEASE LEASE m

Look for the next issue of Energy-Tech magazine and read about:

RENT RENT RENT SALE SALE SALE LEASE LEASE LEASE

Contact Re-Nu®

MS-738

Vertrel XF Cleaning Agent

MS-730

Precision Cleaning Solvent

MS-780

Plastic, Glass & Metal Cleaner

• Outage Season m s Rental Rental and and and Stock Stock Stock Boilers Boilers Boilers m • Instrumentation/ • • •Rental s • • •Generators Generators Generators Controls • • •Chillers Chillers Chillers • Compressors • • •Deaerators Deaerators Deaerators • • • Boiler Boiler Parts Parts Parts • Balancing/Vibration/ Boiler Miller-Stephenson Offers a Wide Range of Chemicals • • • Boiler Boiler Boiler Services Services Services Alignment for the Power Industry! Combustion Combustion Controls Controls Controls • ASME: Advanced •• •• ••Combustion Aero-Duster Freeze Spray Solid Solid Solid Fuel Fuel Fuel Applications Applications Applications Contact Cleaners Energy Systems/IGCC Conformal Coatings Acrylic Conformal Coating

MS-580

MS-260

MS-465N

Solvent Cleaners Specialty Cleaners

ENERGYT ECH

RE R

•• •• •• •• •• •• •• ••

•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

•• •• •• •• •• •• •• ••

• • • • • • • •

Contact Lubricants Krytox® Lubricants

Low Global Warming Formulations Available

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

miller-stephenson chemical company, inc.

P P847-541-8300 847-541-8300 P 847-541-8300 ••F- • FIllinois 847-541-9984 847-541-9984 F 847-541-9984 California - Connecticut - Canada 800-992-2424 203 743.4447 info@indeck-power.com info@indeck-power.com info@indeck-power.com supportET@mschem.com www.indeck.com www.indeck.com www.indeck.com miller-stephenson.com

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 P84

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