September 2014

Analyzing boiler tube failure

ENERGY-TECHDedicated to the Engineering, Operations & Maintenance of Electric Power Plants

In Association with the ASME Power Division

SEPTEMBER 2014

www.energy-tech.comA WoodwardBizMedia Publication

Avoid Voltage Collapse 12 • Creep Damage 15 • ASME: Correction Curves 18

toll free1.877.774.8778

24hr emergency service229.221.4690

Cogeneration

Boiler Replacement Parts

waste to watts

biomass

September 2014 ENERGY-TECH.com 3

FEAtUrEs

6 You need a boiler tube analysis – Now what? By Wendy Weiss and Terry Totemeier, Ph.D., Structural Integrity Associates Inc.

12 Avoiding critical voltage collapse in a changing environmentBy Tony Oruga, P.E., Eaton’s Cooper Power Systems Division

CoLUMNs

15 Maintenance MattersEvaluating creep damage in Grade 91 steelsBy Kent Coleman, Electric Power Research Institute

25 Machine DoctorCompressor vibration due to bearing and seal problemsBy Patrick J. Smith

AsME FEAtUrE

18 Quantifying correction curve uncertainty through empirical methodsBy Christopher R. Bañares, Thomas P. Schmitt, Evan E. Daigle and Thomas P. Winterberger, General Electric Power & Water

iNdUstrY NotEs

4 Editor’s Note and Calendar

30 Advertisers’ Index

31 Energy Showcase

oN tHE WEB

Don’t miss Energy-Tech’s Sept. 16 webinar with Gaumer Process, Electric Process Heating and Demand Fuel Switching, and our Sept. 30 webinar, Power Generating Asset Management, with Komandur Sunder Raj. The live presentations begin at 1 p.m. CST (6 p.m. GMT) and attendees will be eligible to receive 1 PDH credit. Visit www.energy-tech.com for more information.

Cover photo contributed by Structural Integrity Associates.A division of Woodward Communications, Inc.

ENERGY-TECH

P.O. Box 388 • Dubuque, IA 52004-0388800.977.0474 • Fax: 563.588.3848Email: [email protected]

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 PublisherKaren Ruden – [email protected] ManagerRandy Rodgers – [email protected] EditorAndrea Hauser – [email protected]

Editorial Board ([email protected])Kris Brandt – Rockwell AutomationBill Moore – Director, Technical Service, National Electric CoilRam Madugula – Executive Vice President, Power Engineers Collaborative, LLCKuda Mutama – Engineering Manager, TS Power Plant

Editorial views expressed within do not necessarily reflect those of Energy-Tech magazine or WoodwardBizMedia.

Advertising Sales ExecutivesTim Koehler – [email protected] Gross – [email protected]

Creative/Production ManagerHobie Wood – [email protected] ArtistValerie Vorwald – [email protected]

Address CorrectionPostmaster: Send address correction to: Energy-Tech, P.O. Box 388, Dubuque, IA 52004-0388Subscription InformationEnergy-Tech is mailed free to all qualified requesters. To subscribe, go to www.energy-tech.com or contact Linda Flannery at [email protected] InformationFor media kits, contact Energy-Tech at 800.977.0474, www.energy-tech.com or [email protected] SubmissionSend press releases to: Editorial Dept., Energy-Tech, P.O. Box 388, Dubuque, IA 52004-0388 Ph 563.588.3857 • Fax 563.588.3848 email: [email protected] SubmissionSend advertising submissions to: Energy-Tech, 801 Bluff Street, Dubuque, Iowa 52001E-mail: [email protected].

4 ENERGY-TECH.com September 2014

Outage season prepGet details done before the big shutdown

Editor’s NotE CALENdAr

For the huge scale of a utility power plant, it is consistently amazing how just one small problem can shut down its power production in a moment.

We recently completed Energy-Tech University’s online webinar sessions, Steam and Gas Turbine Fundamentals and Advanced Turbine Fundamentals, with Steve Reid from TG Advisers. As I moderated the presentations and listened to Steve explain the photos in the power point slide, attention to detail

was a reoccurring theme. We’ve continued that theme in this issue, although it wasn’t real-

ly on purpose. But as many of our readers head into outage season at their plants, it seemed like a good time to talk about non-de-structive testing advances, boiler tube inspections and preventing bearing and seal problems.

So be sure to read, Evaluating creep damage in Grade 91 steels, by Kent Coleman with the Electric Power Research Institute on page 15. Then turn to page 6 for, You need boiler tube analysis – Now what?, by Wendy Weiss and Terry Totemeier from Structural Integrity Associates Inc. Finally, don’t miss, Compressor vibration due to bearing and seal problems, on page 25. It’s by Patrick J. Smith, who has written as the magazine’s Machine Doctor for sev-eral years.

If you aren’t a fan of Pat’s, you probably should be. Visit www.energy-tech.com is you want to read more of his work.

And if you’re interested in the Energy-Tech University turbine course that just concluded, it’s available for sale on Energy-Tech’s ContentShelf site. Visit www.energy-tech.com to learn more about it.

Finally, I hope you can join us for two webinars in September. The first is on Sept. 16 with Gaumer Process, Electric Process Heating and Demand Fuel Switching. The second is on Sept. 30, Power Generating Asset Management, with Komandur Sunder Raj. The presentations will begin at 1 p.m. CST (6 p.m. GMT) and reg-istration is free. Also, attendees to the live presentations will receive a PDH credit for each of them, so sign up today by visiting www.energy-tech.com.

I hope outage season goes smoothly for everyone and, in the meantime, thanks for reading.

Andrea Hauser

Sept. 9-11, 20142014 Dry Scrubber Users AssociationMinneapolis, Minn.www.dryscrubberusers.org

Sept. 9-11, 2014Feedwater Heater Operation and

Maintenance SeminarAtlantic City, NJwww.powerfect.com

Sept. 16, 2014Webinar: Electric Process Heating and

Demand Fuel SwitchingPresented by Gaumer Processwww.energy-tech.com

Sept. 16-19, 2014Machinery Vibration AnalysisSalem, Mass.www.vi-institute.org

Sept. 30, 2014Webinar: Power Generating Asset

ManagementPresented by Energy-Tech & Komandur Sunder Rajwww.energy-tech.com

Oct. 26-28, 2014Power Plant Management & Generation

SummitAtlanta, Ga.www.ppmgsummit.com/mp_et

Nov. 3-4, 2014CCGT 2014: O&M and Lifecycle

Management for CCGT Power PlantsHouston, Texaswww.tacook.com/ccgt-usa

Nov. 11-14, 2014Advanced Vibration ControlSyria, Va.www.vi-institute.org

Submit your events by emailing [email protected].

Rotork Controls, Inc.675 Mile Crossing Blvd.Rochester, NY 14624

phone: 585 247 2304email: [email protected]

www.rotork.com

Redefining Flow ControlRedefining Flow Control

Enhance plant-wide per formance withRotork ac tuator and damper-drive solutionsEnhance per formance withRotork solutions

plant-wideac tuator and damper-drive

Rotork provides high-performance, cost-effective valve actuator and damper drive solutions throughout your entire power plant. Solutions that can help you maximize plant performance, minimize maintenance problems, and help you meet stringent safety and environmental regulations.

Hundreds of different valve actuators and damper drives are required throughout a typical power plant facility. Rotork can meet all of your needs by offering motor-operated, fluid power, electro-hydraulic, and manual gear operators. Actuators and drives suited for harsh, rugged operating conditions, inside and out, servicing every size and style of valve from small process control valves to super-large isolation valves as well as rotary, linear, or quarter-turn combustion-air and flue-gas dampers. Furthermore, the advanced technological capabilities of Rotork smart actuators can help you easily upgrade connectivity and provide a smart window to your process that includes important predictive maintenance data to help you improve productivity and efficiency as well as cut maintenance costs.

Whether you are building a new plant or are currently operating a fossil-fuel, nuclear, or green-energy facility, we can help. Rotork actuators and drives are currently servicing hundreds of power plants around the world. Our more-than 50-years experience and provenexpertise can help you, too. Contact us today.

Type K pneumaticrotary damper drive

IQ3 electric actuatorwith smart window technology

SM6000 S2 heavy-dutyelectric damper drive

Redefining Flow Control


FEAtUrEs

You need a boiler tube analysis – Now what?

By Wendy Weiss and Terry Totemeier, Ph.D., Structural Integrity Associates Inc.

For more than 30 years, boiler tube failures have been the leading cause of lost boiler availability and forced outages. Determining the mode of damage responsible for a failure is important to ensure that the proper corrective actions are taken and similar failures do not occur again. There are more than 30 different damage/failure mechanisms that can affect boiler tubes, some of which superficially appear similar, but can have very different underlying characteristics. An exam-ple is a so-called “fish mouth” failure that might be a con-sequence of several different damage mechanisms. Therefore, understanding the damage mechanism that caused a failure is essential to provide insight into the underlying root cause so that appropriate corrective actions can be implemented.

These corrective actions can range from adjustments to oper-ation – such as burner systems, cycle chemistry, steam tem-peratures and steam pressures – through pre-emptive non-destructive examination to identify other “at risk” tubes, to defining an appropriate repair strategy – such as pad welding, application of overlay or complete tube replacement.

Failures are not the only reason a tube sample might be removed for analysis. As part of a proactive approach to life management of boiler tubing, it is prudent to periodical-ly sample “typical” tubes for insights into tube condition (remaining life) that can only be gained through a destruc-tive, metallurgical evaluation of the tube. For example, a high pressure (HP) evaporator tube could be removed from a heat-recovery steam generator (HRSG) for evaluation of the internal deposits to help assess the water treatment pro-gram. Superheater and reheater tubes are often removed from boilers for condition assessment to determine the remaining life of those components. A key part of such proactive tube sampling is knowing where to extract representative samples, which requires a thorough understanding of the overall boil-er condition and operations. But that would be a whole arti-cle in itself, so here we will assume that an engineering-based program is in place for tube sampling, or that samples have been extracted in response to tube failures.

Collecting a tube sampleIf you have a tube failure, selecting the appropriate sample

for analysis is usually straightforward, but in some cases (such as those where a tube failure has resulted in so-called “sec-ondary damage” to other tubes), it might not be so obvious where the failure originated. For these situations, taking mul-tiple samples is advised. Also, removing adjacent samples that might have similar damage that has not resulted in a failure can be beneficial to the root cause determination. Sometimes failures can be violent and dislodge deposits or cause damage that impairs evaluation of the failed area.

For proactive condition assessment, samples should gener-ally be taken from the hottest location within a component (or of a particular material within a component). For exam-ple, in a superheater or reheater, samples from the “ferritic” (e.g. Grade T22) side of a transition to stainless steel usually represent the “hottest” condition for that “ferritic” material. In the case of a dissimilar metal weld, this also provides an opportunity to sample that DMW to assess its condition. If samples are being extracted from an evaporator for internal

Figure 1. Failed superheater tube (long-term overheating)

Figure 2. Failed waterwall tube (short-term overheating)


deposit evaluation, then the “hottest” location generally corresponds to that with the peak heat flux.

When removing tube sections, there are some best practices to follow. First, mark the tube before it is cut out. Indicate the tube identification, such as horizontal/ver-tical, top/bottom, direction of flow, gas or furnace facing (hot) side. If the damaged area is hard to visually locate, such as a pin hole leak, mark it as well. Also, be sure to keep track of the tube number, assembly number and elevation (and keep a record of how this is identified – e.g. left to right or front to back). By marking the tube before it is cut out, there is less of chance of tube identifications getting mixed up or the hot and cold sides being mislabeled. If overheating is suspected, or if a steam-side tube from the hottest part of the component has been sampled, including a section of the same heat of material from the coldest end of the circuit can be very beneficial, if available. A cold end sample allows for assessment of the microstructure in the condition that is most similar to the orig-inal, and provides reference dimensions (e.g. original wall thickness) with minimal effects of service (wastage or swelling).

When cutting samples from tubes in a boiler:

• Providing at least 12˝ of tube length for an analysis is generally adequate; if there is a failure or an area of interest, it should be in about the middle of the sample. If a failed tube is being removed for analysis, more material could be required depend-ing on the extent of the damage.

• Prevent contamination, including from cutting debris and cutting fluids (it is best not to use cutting fluids when removing the tube). It is important to ensure that both the OD and ID surfaces are protected from contamination in case depos-its on those surfaces prove to be important in identifying the damage mechanism. Obviously, if the inter-nal deposits are being analyzed, they need to be contaminant-free.

• Be careful not to dislodge deposits when handling tube. For the same reason that you don’t want to con-taminant the deposits, you also want to make sure they stay as intact as possible.

• Ensure cutting techniques do not alter the tube damage or microstruc-ture. Torch cutting can heat the tube metal to the point where the tube microstructure is altered, which is detrimental to an analysis for which assessment of the microstructure is a necessary step (e.g., overheating fail-

FEAtUrEs

VIDEO BORESCOPES

90° Prism & Close-Focustips available!

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 articulation range, and improved the feel. It’s still small, 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

The NEW Hawkeye® Video Borescope!

Quickly inspect cooling tubesinside heat exchangers, turbineblades, and much more!

Bright, High-Res right, High-Res Bright, High-Res BVideo & PhotosVideo & PhotosLarge Range-of-FocusLarge Range-of-FocusQuality ConstructionQuality Construction4-Way Articulation4-Way Articulation4 & 6 mm Diameters4 & 6 mm DiametersStarting at only $8,995Starting at only $8,995

gradientlens.com/V2 800.536.0790

Figure 3. Tube failures can cause a lot of secondary damage.


ures or condition assessments). Torch cutting also melts the area that is being cut, so it is very important to ensure that the failure, or area of interest, is not affect-ed. Torch cuts, if made, need to be at least 6˝ from the area of interest. Torch cuts also can leave splatter behind that can alter deposit loading (deposit weight density) measurements and deposit compositional analyses, so splatter should be prevented or minimized to the extent possible.

• Abrasive saws can leave behind some heat damage, so make sure cuts are several inches from the affected area.

Once the tube section is out of the boiler or HRSG and properly marked and identified, it needs to be prepared for shipping. Proper shipping practices include taping the tube ends to prevent internal contamination, protecting areas of interest from impact damage, making sure markings on the tube will not get rubbed and shipping in a wood crate (this

might seem obvious, but samples have been lost from card-board boxes during shipping!).

Selecting, labeling, removing and shipping the tube sam-ple is just the first step in a good tube evaluation. Equally important is providing thorough background information. The starting point is good information about the tube, including the material’s specification and dimensions. Other helpful information includes:

• Drawing to show location of tube• Design and operating parameters (overall boiler and

tube)• Operating hours• Total starts• Cycle chemistry• Last chemical clean• Maintenance records• Past tube failure, history/failure analysis reports• Other unit history, information, problems

Metallurgical evaluationNow that a tube sample has been provided for evaluation

with good background information, the metallurgical anal-ysis can proceed. While the procedure can be tailored based on particular conditions, in general, the following steps are required for a thorough evaluation.

• Visual examination and photo-documentation The tube condition is photographed prior to destructive analysis to record any distinctive features. This visual examina-tion also is used to determine “cut planes” for the sam-ple, which will be analyzed in subsequent steps.

• NDE (if appropriate) Before the tube is sectioned, the tube might be examined by various non-destructive techniques (e.g., phased array ultrasonics) to both help identify areas for sectioning or assess the effectiveness of an NDE technique to locate similar damage in other tubes.

• Chemical analysis A chemical analysis is performed to determine if the tube metal is within specification, and if any particular additional unspecified or trace elements

FEAtUrEs

Figure 5. OD wastage on an economizer tube.

Figure 4. A well labeled tube sample.


might be present that could affect the serviceability of the metal.

• Dimensional measurements Tube diameter and wall thickness are mea-sured around the circumference of the tube, possibly at several locations along the sample, to characterize wall loss and swelling.

• Hardness evaluation and/or Mechanical property testing Hardness tests can easily be performed on metallurgical sections and provide an indication of the tensile strength of the metal or metallurgical con-dition. Other mechanical property testing, such as obtaining elevat-ed temperature properties (creep strength), can be performed as part of more detailed investigations, such as remaining life evaluations.

• Metallography Tube cross sections (or portions of the cross section) are mounted in a plastic resin and carefully polished to a mirror fin-ish. The sample may be examined in this condition (e.g. to identify holes or cavities) or may be etched with chemicals to reveal the micro-

FEAtUrEs

PARTS | SERVICES | REPAIRS

Restoration of

Gas TurbineBearings

A Division of MD&A

Renewal Parts Maintenance 4485 Glenbrook Rd. | Willoughby, OH 44094

ph. 440-946-0082 | www.RenewalParts.com

Figure 6. Dye penetrant indications.


structure (grain size and morphology), which provides additional insight into the condition of the metal and is helpful to identify both damage and the effects of service exposure (such as changes in the microstructure due to high temperature exposure). Such examinations may be performed using optical microscopes; a scan-ning electron microscope (SEM) may be used to obtain higher resolution images to resolve fine-scale precipi-tates in the metal. The SEM also can be used to provide

local chemical analysis using energy dispersive spec-trometry (EDS), including elemental maps, which can be particularly valuable in diagnosis of some damage mechanisms, especially those involving corrosion.

• Fractography If the sample includes a fracture (broken) surface, then this is examined to determine its charac-teristics. The morphology of the fracture surface pro-vides insight into the mode of failure (transgranular/intergranular) and also might indicate the presence of precipitates, cavities or foreign species that have exac-erbated the failure. Fracture surfaces are commonly examined with a stereomicroscope, which provides a large depth of field, or with a scanning electron micro-scope.

• Characterization of internal and/or external oxide/deposits Often, internal or external deposits (oxidation or cor-rosion products) play a significant role in the damage mechanism, either by directly causing wall loss or internal attack of the metal, or by acting as a secondary contributor to a failure (e.g. internal oxide scale “insu-lating” a steam touched tube and causing an increase in the tube metal temperature). As a result, the thick-ness and morphology, and in some cases the chemical composition or crystallographic structure, is mapped to assess the role that these corrosion products play in the failure or overall condition of a tube. In some cases, such as for evaporator tubes, the quantity of deposits (a so-called “deposit loading”) will be measured to deter-mine the need for chemical cleaning.

The results of these various analyses and measurements are used to draw a conclusion about the underlying condition of the tube material and the damage mechanism that resulted in failure (or degradation) of the tube. Because of the similari-ties between a number of damage mechanisms, this requires not only a good metallurgical knowledge, but an understand-ing of where the tube is located within the boiler, and what operating conditions are possible for that tube (which is why the circumstantial information about the tube sample and its location in the boiler is so critical). To aid in diagnosis of the damage mechanism, stress and temperature calculations also might be performed to determine if it was reasonable to have expected tube failure in the period of service experienced, or if some excursion or other detrimental condition also might have contributed to failure. In the case of tube condi-tion assessments, such calculations are performed to identify the likely remaining life, and this is compared and contrasted against the metallurgical condition of the sample.

From damage mechanism to root causeThis systematic approach definitively identifies the damage

mechanism (what caused the tube to fail) but further work is often needed to identify the root cause of that damage mechanism (why the damage mechanism occurred) and define corrective actions. This latter step of root cause identi-fication often requires a broader engineering evaluation that

FEAtUrEs

Figure 7. Creep in T22 tube to header HAZ.

Figure 8. Creep in Grade 91 base metal.

Figure 9. Creep in stainless steel reheater tube.


FEAtUrEs

encompasses the metallurgical work, other engineering eval-uations and an understanding of the boiler operation. Only once that root cause is identified can an appropriate set of corrective actions be defined. Often, it is tempting to jump from identification of the damage mechanism to corrective actions, but omitting the step of root cause identification often can lead to misdiagnosis of the underlying reason for failures, and to ineffective corrective actions. Hence involving a team with a broad multidisciplinary understanding of met-allurgy, engineering/operating and nondestructive testing is crucial to effective life management of boiler tubing. ~

Wendy Weiss is the FPS Materials Science Center manager. She has a bachelor’s degree from the New Mexico Institute of Mining and Technology and a master’s degree from the University of Texas at Austin. Her primary responsibilities are performing failure analyses and condition assessments of components from fossil power plants at Structural Integrity Associates’ metallurgical laboratory. You may contact her by emailing [email protected]. Terry Totemeier, Ph.D., is in Fossil Plant Services at Structural Integrity Associates Inc. He has a Ph.D. (Metallurgy), from the University of Cambridge (UK), and a bachelor’s degree (Materials Science and Engineering), from the Massachusetts Institute of Technology. He also has more than 20 years of experience performing research, development and failure analysis of materials used in power generation equipment, both fossil and nuclear, with a primary focus on the physical metallurgy, mechanical behavior and oxidation/corrosion resistance of Fe-base and Ni-base alloys for high-temperature service. You may contact him by emailing [email protected].

1224 North Utica | Tulsa, OK 74110T: 918-587-6649 | E: [email protected]

W: www.topog-e.com

The Topog-E Gasket Company produces gaskets

to fit every boiler in production today. Topog-E® Series

180 molded rubber gaskets are special for many reasons. Over forty years as the industry standard have

given us feedback as to why!

• Steam pressure vessels

• Hot water heaters• Demineralizers• Steam humidifiers• Water purifiers• Refrigeration units• Liquid treatment

vessels

• Compressed air tanks

• Filtering units• Dryer cans in

paper mills• Water towers• Water softeners• Deaerators• Make-up tanks

Applications:

Figure 10. Beach marks indicating a fatigue crack from a tight bend in a superheater tube.


FEAtUrEs

Avoiding critical voltage collapse in a changing environment

By Tony Oruga, P.E., Eaton’s Cooper Power Systems Division

For years, capacitor banks have solved power quali-ty challenges in transmission and distribution networks, including voltage collapses and phase shifts associated with alternating current (AC) power supply systems. What can power suppliers do to correct the same anomalies caused by an emergency outage or a temporary increase in reactive power load?

A mobile capacitor bank is engineered to deliver the reactive power compensation and voltage support needed in temporary situations that often represent a challenge to both utilities and their customers.

Consider this: Reactive power is needed to maintain the voltage required to deliver active power through the

transmission and distribution grid. Electric utility suppliers often accomplish this by strategically placing capacitors on the network to maintain the grid’s ability to push active power through the transmission and distribution system. This results in a robust, reliable and quality power source for customers. Utilities can apply the same methodology to emergency or temporary situations by deploying mobile capacitor banks.

Challenges facing the power gridOne of the major concerns associated with utility

power grids is the aging nature of the infrastructure and its tendency to take on a variety of power quality issues.

Electric equipment such as generators, transformers, regulators and the distribu-tion and transmission lines are constantly subject to faults, overloading, envi-ronmental conditions and vandalism. Additionally, it is not uncommon for the grid to experience unexpected outages that can often lead to voltage collapse or capac-ity issues cascading to other parts of the system.

When the grid appears to demonstrate these types of issues, the challenge is to stabilize the grid quickly in order to get customers back online. If executed success-fully, the overall impact to the customer is minimal, with decreased utility down-time and diminished impact on overloaded equipment needed to sustain the grid. This can even lead to a reduction in customer com-plaints.


Capacitor bank applications For decades, capacitor banks have been commonly used

in power systems to address these issues by supporting the system voltage, increasing power flow capability, releasing system capacity, improving losses and reducing utility bill-ing. Capacitors are designed to offer a long-term benefit to the customer and can last up to 30 years if properly main-tained. In many instances, the savings during the life of the product pays for the initial investment several times over, depending on the application and its power supply needs.

Capacitor bank designs vary widely in arrangement, from externally or internally fused to fuseless configurations. Capacitor banks also can be connected to the power sys-tem in a variety of different configura-tions depending on the application, such as single or double grounded-wye, single or double ungrounded-wye and delta. The flexibility of these options allows the use of capacitors to be tailored to meet each customer’s unique application requirements.

Capacitor banks are engineered-to-or-der. Though some banks are similar in design, there are countless other designs manufactured that are exclusive to the customer. Expertise in the proper applica-tion of capacitor products is crucial, and if misapplied can lead to capacitor failure, resonance issues, leading power factor, overvoltages and/or create other system issues.

Rising demand for fast, reactive solutions

As the economy grows, the demand for energy also increases. This drives the need for immediate power solutions for applications and environments that

encounter difficulties within their aging power systems. These utilities are consistently challenged with emergency outages, unique maintenance situations, the need for peak loading support, voltage collapse or the need for reactive power support. They also might need a way to delay costly capital investments.

The mobile capacitor bank can represent a viable solu-tion in many of these scenarios. It offers the same features and benefits of a regular capacitor bank, but with the added flexibility to be quickly deployed and placed anywhere on the system to support an immediate need.

FEAtUrEs

Fuel Gas Conditioningfor all Gas Turbines

713.460.5200www.gaumer.com

Fuel Gas Problems?Gaumer has industry leading knowledge in

fuel gas conditioning including electric heater,

fi lter/coalescer and control panel design.

Gaumer engineers will work with your

unique operating conditions to provide

a complete, successful solution.

Call today for:

• Fuel Gas Conditioning

• Fuel Gas Heaters

• Fuel Gas Filters

Celebrating 50+ Years


Latest solutions in reactive powerMobile capacitor banks can be customized to meet each

customer’s unique requirements, from a simple capacitor bank to a self-contained substation up to 230 kV with the required controls and protection. Since these banks are able to be transported easily, they are typically constructed to include all the necessary working components typically seen with a substation class capacitor bank, but can be grouped together on one or more trailers in order to meet federal and state transportation requirements. With transportation requirements in mind, switches and breakers containing SF6 gas are subject to Department of Transportation (DOT) and Environmental Protection Agency (EPA) regulations. These situations require reclaiming of the SF6 gas before trans-porting the switches and breakers and can be accomplished by using a special SF6 gas handling pump, which can be installed on the vehicle’s trailer.

Mobile capacitor banks often come complete with protection and control schemes, capacitor switching and interrupting devices, control sensing and protec-tive fencing. Some of the additional accompanying equipment can include light-ning arresters, current-lim-iting reactors, polymer insulators, safety fencing, grounding mats and storage enclosures.

With more than 70 years of experience designing and manufacturing power capac-itors, Eaton’s Cooper Power Systems offer a compre-hensive portfolio of power distribution products, includ-ing mobile capacitor banks. Additionally, Eaton’s Cooper Power Systems support cus-tomers globally by answering technical questions, per-forming system studies and performing onsite commis-sioning and product main-tenance for capacitor banks. This includes the supply of complex engineered-to-or-der products, such as capac-itors, open-rack capacitor banks, metal-enclosed capac-

itor banks, pole-mounted capacitor racks, capacitor switches and mobile capacitor banks.

When applied and working properly, traditional capac-itor banks can greatly increase the overall efficiency of the power system for various unique applications. Having the flexibility of a mobile capacitor bank provides utilities with the security of effectively stabilizing the grid by reacting quickly to unexpected contingencies. ~

Tony Oruga is a senior product application engineer with Eaton’s Cooper Power Systems capacitor business. He creates capacitor-related design solutions to meet customer specifications and necessities globally. Oruga has a bachelor’s degree in Electrical Engineering and is a registered professional engineer with 11 years of power systems experience. You may contact him by emailing [email protected].

FEAtUrEs


MAiNtENANCE MAttErs

Evaluating creep damage in Grade 91 steels

By Kent Coleman, Electric Power Research Institute

EPRI is routinely asked to perform third-party review of failure analysis reports for power plant component fail-ures. These reviews are often requested for components manufactured from new materials, including creep strength enhanced ferritic (CSEF) steels.

Several recent reviews have includ-ed evaluations by others in the industry using a life prediction technique known as the “EPRI-Neubauer correlation.” This technique, which was developed in the 1980s by EPRI in conjunction with Bernard Neubauer, utilizes surface repli-cation and relates damage development to remaining life in low-alloy steels.

The EPRI-Neubauer correlation is appropriate for some low-alloy steels such as Grades 11 and 22. However, recent research indicates that it is not suitable for evaluation of CSEF steels such as Grade 91. EPRI is developing new tools and techniques to identify creep damage and predict remaining life of these steels.

Creep damage in Grades 11 and 22 steelLow-alloy steels, commonly referred to by their American

Society for Testing and Materials (ASTM) classifications, Grades 11 and 22, develop creep damage in a well-established order, starting with isolated creep voids, aligned creep voids, micro cracking and finally macro cracking. A diagram commonly used to illustrate this progression is shown in Figure 1.

The EPRI-Neubauer correlation has been applied to met-allurgical samples removed from high-temperature components in power plants, including piping and headers, as a method to determine remaining life. Additionally, the method has been applied in-situ on the surface of components by the technique of replication.

To apply this method in the field, a small area of the com-ponent is first polished to a very fine finish. The polished area is then etched to reveal the microstructure. Then an acetate film is softened and applied to the polished area. The acetate fills the profile of the etched surface and makes a “replica” of the microstructure, much like a 3-D picture. The replica can then be taken to a laboratory microscope, and the microstructure can be evaluated. This technique is often applied to welds in

high-temperature components to determine the suitability for continued service. It also is very useful to determine the mate-rial’s structure.

Grades 11 and 22 have a microstructure with distinct grain boundaries that easily lend themselves to the EPRI-Neubauer correlation, and many developments have been made in the industry to apply this model to low-alloy steels. However, even with these steels, users need to know when the technique should be applied.

One of the difficulties with the EPRI-Neubauer correlation is that it reveals the damage level, and resultant remaining life, only on the component’s surface. Several types of welds, includ-ing longitudinal seam welds, develop damage sub-surface. The damage on the surface might not be representative of the dam-age throughout the component. This same phenomenon also has been observed in circumferential welds in very old systems. Evidence suggests that failures earlier in life might be domi-nated by bending stress, which might be highest on the surface of the pipe. However, on welds with lower bending stress, the highest level of damage might develop subsurface. More infor-mation can be found in the EPRI report Circumferential Seam Weld Cracking: An Interim Report (1014295), published in 2007.

Figure 1. Development of creep damage in Grade 11 and 22 steels.


Creep damage in Grade 91 steelMore recently, instances have occurred in the industry of the

EPRI-Neubauer correlation being applied to alloys for which it was not developed, including CSEF alloys.

Grade 91 steel is one member of the family of CSEF steels. This steel was developed during the 1980s and is increasingly considered the material of choice for boiler, piping and head-er applications in power plants. This steel is being routinely installed in high-energy components in both fossil-fuel-fired

and combined-cycle power generating units throughout the world. Experience from long-term laboratory testing and in-service behavior suggests that the performance of compo-nents manufactured from CSEF steels is likely to depend on creep damage in welds.

Grade 91 and other CSEF alloys have a martensitic lath structure that does not lend itself to the EPRI-Neubauer cor-relation. Of particular concern is the fact that relatively high densities of relatively small creep voids have been shown to develop below the component surface. These voids are, there-fore, not easy to detect. Because many voids can be present through much of the component wall thickness, the processes of crack formation and growth can be relatively rapid. Thus, the window when traditional methods of nondestructive examina-tion (NDE) can identify macroscopic defects is relatively small. This time limit means that inspectors need to determine the size of defect using established methods of inspection, to refine existing methods, and if necessary, to consider new approaches to improve the reliability and sensitivity of detection.

Additionally, damage in CSEF alloys is almost always greater subsurface than on the surface of components. Because of the differences from low-alloy steels in microstructure and damage development, and the prevalence of subsurface damage, EPRI does not recommend applying the EPRI-Neubauer correlation to this class of materials.

To provide a method to predict remaining life in this class of components, EPRI developed a program that includes pre-diction of remaining life, using highly sensitive NDE, an EPRI-developed calculator for material life, and specialized monitor-ing techniques. The following section describes current research in the first of these areas — NDE tools.

Current research: NDE toolsA current three-year EPRI project is evaluating the poten-

tial of available NDE tools to determine the damage level in CSEF alloys and to identify the need for future development of new tools. Project sponsors and participants include utilities, NDE vendors and engineering consultants. The project is uti-lizing current state-of-the-art technologies and working with universities to develop new NDE techniques.

To facilitate this evaluation, EPRI prepared large plates using typical submerged arc welding (SAW) and shielded metal arc welding (SMAW) welding techniques. From these plates, the participants prepared very large creep coupons, measuring up to 48˝ x 1.5˝ x 2˝.

The coupons were instrumented with acoustic emission (AE) equipment from various vendors and tested to failure while measuring the strain accumulation throughout the test (Figure 2). The continuous strain monitoring allows for better correlation of remaining life to damage during the test.

Further coupons were tested, but were interrupted at certain life consumption intervals. The interrupted coupons were then tested with various state-of-the-art NDE processes, including digital radiography, phased array and electromagnetic techniques. Many different transducers and frequencies were

Figure 2. Creep testing of samples instrumented with acoustic emission wave guides.

?Like us on Facebook for exclusive content,

conversations and events!

Like Energy-Tech?

Facebook © 2014

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

MAiNtENANCE MAttErs


evaluated to identify the best techniques for detecting damage, which led to many of the project participants modifying their field inspection techniques.

Replication was performed on the top and sides of the coupons. Although the replicas did not show any damage on the top surface (what would be the outside surface of a pipe), the replicas did show damage on the sides of the coupons. (However, a lesser amount of damage was found than in the center of the samples during the destructive laboratory analy-sis.) Results can be found in the EPRI report, Review of Weld Repair Options for Grade 91, Part 2: Damage Development and Distribution (3002000087), published in 2013.

Following NDE, the samples were sectioned and prepared for laboratory analysis. Due to the extremely large creep sam-ples, the project team had the opportunity to remove multiple metallurgical samples from each coupon. Guided by the NDE results, the team prepared the coupons to demonstrate damage of interest. This process enabled the project participants to cor-relate their NDE signals to damage level.

Current research: Fitness for serviceAnother area of interest is determining if new CSEF mate-

rial is fit for service. CSEF material might be degraded through processes utilized during fabrication, specifically heat treatment and cold forming. EPRI is partnering with a U.K. university in a parallel effort to see if electromagnetic methods might be able to detect microstructural changes in CSEF materials. In phase I of the project, coupons of Grade 91 material were first prepared by heat-treating specimens at various times and temperatures selected to produce different levels of microstructural degrada-tion. The coupons were then submitted to the university to sort them into a ranked damage order.

The results were very promising, and the project is con-tinuing with phase II, where more controlled specimens were created, including new tubing that was heat-treated to various damage levels. Normal temper levels and samples that have exceeded the transformation temperature were prepared to expand the research to see if grain structure and precipitate structure information might be determined.

Much information has already been developed about the relationship between NDE results, damage development, and remaining life with these alloys. The project is currently in the second of three years and will be completed next year. Look for a final report detailing the results and recommendations in the second half of 2014. ~

Kent Coleman manages EPRI’s Boiler Life and Availability Improvement Program. He has been a member of EPRI’s Generation staff for 15 years after a 17-year utility background and has an extensive background in the materials, life assessment and welding areas, and holds several patents in the areas of boiler materials, welding and repair. He also is a member of several ASME Code committees including SCI, Power Boilers. You may contact him by emailing [email protected].

MAiNtENANCE MAttErs

( 8 7 7 - 4 S I - P O W E R )8 7 7 - 4 7 4 - 7 6 9 3

Scan the QR Code for more information

www.structint.com/energy-tech

We Connect the DotsOver the past 30 years, Structural Integrity has built a team of over

200 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.

FROMENGINEERINGANALYSIS TO ADVANCED NDE,LOOK TOSTRUCTURAL INTEGRITY

18 ENERGY-TECH.com ASME Power Division Special Section | September 2014

Quantifying correction curve uncertainty through

empirical methodsBy Christopher R. Bañares, Thomas P. Schmitt, Evan E. Daigle and Thomas P. Winterberger,

General Electric Power & Water

AsME FEAtUrE

IntroductionThe accuracy of a thermal performance

test is typically estimated by performing an uncertainty analysis calculation in accor-dance with ASME PTC 19.1, or another code equivalent to it. The test uncertainty is a measure of the test quality and, in many circumstances, the test setup must be designed so that the uncertainty remains lower than test code limits and/or com-mercial tolerances.

Traditional uncertainty calculations have only included an estimate of the measurement uncertainties and the prop-agation of those uncertainties to the test result. However, in addition to addressing measurement uncertainties, ASME PTC 19.1 makes reference to other potential errors of method, such as “the assumptions or constants contained in the calcula-tion routines” and “using an empirically derived correlation.”

Performance correction curves are uti-lized to correct performance to a specified set of reference

conditions so that the corrected result is independent of boundary conditions that persist during the per-

formance test. Many of the ASME performance test codes (PTC-22 Sections 3-3.1 and 5-5,

PTC-46 Sections 3.4.2.4 and 5.4, ASME PTC19.1 Section 5-3.5, ASME PTC6.2

Section 3-5.3., and ISO2314 Section 7.1) recognize the potential for

errors in the corrected result due to correction method-

ology, and guide the user to make efforts to test

in conditions that

are as close to the specified reference conditions as possible. Further, the codes state that there is an acceptable error due to correction methodology of approximately 0.2-0.3 percent.

However the codes do not provide specific guidance on how to estimate the incremental uncertainty levels associated with the correction methodology, and/or how to account for them either in the overall test uncertainty or in the corrected results. This is important, since experience shows that there is potential for errors in corrections to exceed 0.3 percent. This can happen in cases where insufficient data exist to validate the thermodynamic models used to develop the correction curves at extreme off-rated conditions, or as a result of the normal unit-to-unit variation and its associated impact on estimating the response of the equipment to changes in the boundary conditions.

For the case where empirical validation via a large data set is either not possible or impractical, then when developing the pretest uncertainty analysis, it might be technically valid for the manufacturer to include a line item in the analysis that represents an estimate for correction curve uncertainty

Figure 1. Correction error due to performance variation.

AreShaftCurrentsDestroyingYour 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 01057-1099PH: 413.267.0590 • 800.207.2195 • FX: [email protected] • www.sohreturbo.com

September 2014 | ASME Power Division Special Section ENERGY-TECH.com 19

based on past experience and the extent to which the test condition might deviate from the rated condition.

Case study 1 – Gas turbine unit-to-unit variationField test data for new and clean gas turbines (n = 57) of

the same hardware configuration were used to calculate key performance metrics for the major components of the units, such as compressor efficiency and nozzle flow characteristics. Multiplicative factors were derived to adjust the unit nom-inal thermodynamic model to match the observed compo-nent performance for each unit, factoring out the effects of boundary conditions like ambient tem-perature and inlet pressure loss. This results in a set of factors whose distribution approximates the unit-to-unit variation in component performance for the fleet relative to the model, independent of test boundary conditions. Statistical analysis of the variation in these factors resulted in a model of typical fleet component variations. This model of fleet variation was combined with a model of variation of ambient conditions to create a “fleet” of models (n=500) with identical controls settings, each with unique thermodynamic models, test conditions and predicted per-formance mimicking that of the fleet.

A multiplicative correction factor was calculated for each of the model runs by taking the ratio of the predicted perfor-mance at the test conditions and the pre-dicted performance at a common reference condition using the nominal (un-modified) model, in much the same way that conven-tional corrections are generated and applied. Model predictions were used to eliminate error sources inherent in the usage of curves, such as curve-fitting error and inter-dependencies between corrections. For each case, the correction factor was then applied to the “observed” model performance, so as to calculate corrected performance at the reference condition in a manner consistent with that used in performance testing.

Each model in the “fleet” was then run a second time, at the reference conditions, to determine what the true performance of that unit would have been at the refer-ence conditions. The result at the reference condition was then compared against the same model’s performance at the test condition, with the correction factor applied. The difference between these two results therefore represents the difference between the true performance of the unit

at the reference condition, and the performance calculated by correcting off-design test data back to the reference con-dition without accounting for the unit-specific component behavior. By using the correction process described previ-ously, error sources due to the use of correction curves were eliminated, with the only remaining effect being the differ-ence between typical unit-to-unit variations in component performance and the model predictions used to generate the correction factor.

AsME FEAtUrE

SY Series Steel Scotch Yoke ActuatorsOutstanding corrosion protection in

a workhorse design

These scotch yoke actuators provide a

solution for applications where steel

actuators are required, due to corrosion

protection requirements that aluminum

actuators do not adequately handle .

Available in both Double Acting and Spring

Return, the quarter-turn actuators cover a

broad range of torques from 800 - 12,000

in.-lbs. torque. The actuator shown is

featured on the A-T Controls Power Seal

HPBV, but is also applicable for ball and plug

valves and dampers.

When your application calls for rugged and

reliable valve actuation, rely on the TRIAC SY

Series.

In stock from A-T Controls.

SY Series Steel Scotch Yoke ActuatorsOutstanding corrosion protection in

9955 International BoulevardCincinnati, Ohio 45246(513) 247-5465FAX (513) 247-5462e-mail: [email protected]


AsME FEAtUrE

Figure 1 illustrates the variation between the theoretical unit performance at reference condi-tions and that calculated using the model-based correction factor.

The highlighted section in the center of the graph represents the typical code limit uncertainty band for a PTC-22 test, for reference (approxi-mately +/- 0.5 percent). For cases where the dif-ference between the as-tested ambient tempera-ture and the reference ambient temperature are small, the correction approaches unity and, as one would expect, the error it introduces becomes negligible. However, as the test condition begins to vary from the reference condition, the influ-ence of unit-to-unit variations becomes more pronounced. For variations greater than 30°F from the reference condition, the influence of this effect eclipses that of the combined measurement uncertainty, significantly reducing the accuracy of the test result. In other words, the error illustrat-ed in Figure 1 represents solely the incremental error (i.e. uncertainty) contribution from natural unit-to-unit thermodynamic variations in the equipment components, and does not include the traditional errors associated with measurement uncertainty.

The extent to which the uncertainty intervals need to expand in proportion to the extent to which the test conditions deviate from the ref-erence conditions is analogous to the manner in which most instrument manufacturers define the nominal uncertainty (or accuracy) of an instru-ment to be applicable within a specified range of conditions (such as temperature or humidity), and give a formula the user can use to estimate the incremental additional uncertainty when usage conditions exceed the nominal range. Similarly, in the case of a power plant thermal performance test, the uncertainty (or accuracy) accounting needs to take into consideration the incremental additional uncertainty attributable to testing at off-reference conditions, inclusive of correction curve interdependencies and unit-to-unit compo-nent variations.

To statistically quantify this effect, the same process was used to correct the “fleet” of 500 units to a reference condition of 59°F from vary-ing ambient temperatures in 10°F increments. The resulting variation in corrected performance from each as-tested ambient temperature was analyzed, and a symmetrical 95 percent tolerance interval was calculated as an estimate of the uncertainty contribution from the correction. Figure 2 illus-

Figure 4. Example of correction error from off-frequency test conditions.

Figure 3. Incremental test uncertainty due to correction error.

Figure 2. Estimated correction uncertainty as a function of variation in ambient temperature.


trates the estimated effect of variation in as-tested ambient temperature on correction uncertainty.

By combining this uncertainty estimate with that we obtain from propagation of measurement uncertainty, a combined test uncertainty may be calculated. Figure 3 illustrates the post-test uncertainty for a typical PTC-22 test, 0.4 percent, and the combined uncertainty when the correction uncertainty esti-mate is incorporated.

The shaded area indicates the increase in test uncertainty as a result of the correction curve error. As prior industry experience suggests, the incremental uncertainty is very small within a certain range of test conditions, but increases dramatically as the test con-dition deviates more significantly from the reference condition.

Readers should note that this analysis does not address uncertainty inherent in measuring the component performance factors as described at the beginning of this case study. As a result, this analysis represents an approximation of the mag-nitude of these effects. It is the authors’ assertion that the conclusion of this case study highlights the existence of this error source, its basic characteristics, and a sta-tistically-based method of estimating the incremental uncertainty.

Case study #2 – Gas turbine: Extreme off-rated conditions

There can be times when an addi-tional systematic error is introduced into the corrected test results when the actual turbine response to one or more correc-tion variables deviates considerably from the expected response. And similar to the random errors discussed previously, these systematic errors can grow in magnitude in proportion to the extent of off-rated conditions found.

Recent GE test experience in Pakistan on several heavy duty gas turbines resulted in a data set that was used to empirically adjust the frequency correction curves. The official tests were run at high ambient and low frequency conditions, and the correct-ed results were noted to be higher than expected. A database of archived GT per-formance behavior was then downloaded from the plant historian so that a statistically significant amount of data could be studied across the frequency range. This data was then processed twice, once through the full set of test corrections, including the frequency correction curve (the blue data),

and a second time without the frequency correction (the red data). See Figure 4. As shown in Figure 4, the corrected per-formance at significant under-frequency test conditions tend-ed to be overstated (the blue data is after using the expected off-frequency correction). The frequency correction was then empirically adjusted with consensus of all parties involved, and the statistical data set was used as validation of the empirical adjustments. This case study exemplified the occasional need of empirically adjusting the test correction curves, when warrant-ed by the data, to avoid an unnecessary avoidable incremental systematic error from correction curves.

AsME FEAtUrE


Case study #3 – Gas turbine: Correction errors in an isolated range

Another scenario that can occur is the introduction of a systematic error in the corrected result only in a particular range of a correction variable. In these cases, the turbine’s

operating behavior for a given boundary con-dition might be characterized fairly well by the thermodynamic model in one range of conditions and deviate in other parts of the range. Since the thermodynamic models are used to create the correction curves, errors would be confined only to a particular range of the correction curves.

This scenario was experienced during testing of a newer model heavy duty gas turbine. It was observed during preliminary testing of the turbine that the corrected output appeared to be overstated when test runs were made at conditions below the reference value of one of the boundary parameters. This prompted further analysis using the historical archived data system of a unit of similar configura-tion to gather a statistically significant data set with a larger range of the correction variable of inter-est. Correction curves were applied to the data to obtain corrected output performance and plotted against the range of the variable of interest. The results can be seen in Figure 5. These data showed

that the actual turbine performance was significantly better than expected in the low range of this correction variable.

If no error in correction curves existed, the error over the range of the variable would be centered on zero. This can be seen in the range of correction variable above the reference value (approximately 0-2 percent). However, in the correc-tion variable range below the reference, the performance of the turbine appeared to deviate from expected, resulting in significant positive errors in the corrected result when using the theoretical pre-test correction curves. Similar to the pre-vious case studies, this error increased in proportion to devia-tion from the reference condition.

Case study #4 – Steam turbine: Extreme off-rated conditions

ASME PTC 6 and PTC 6.2 stress the importance of testing as close to specified conditions as possible to mini-mize the magnitude of corrections and error introduced by the correction methodology. Table 3-1 of PTC 6 and Table 3-1.3.5 of PTC 6.2 list the allowable deviations between test and rated conditions.

One variable with a large sensitivity to output and a greater potential for deviation is exhaust pressure. While PTC 6 and 6.2 list different requirements on exhaust pressure, the allowable deviations range from 0.1˝ to 0.5˝ of mercury absolute.

Figure 6 shows an exhaust pressure correction curve for a large steam unit. The solid line is the response predicted by the steam turbine manufacturer’s heat balance modeling pro-gram, while the dashed line is based on plant data measured during an operating period with controlled conditions. While the two curves show good agreement in close proximity to rated conditions, the curves differ significantly at the outer boundaries, illustrating the need to adhere to code require-

AsME FEAtUrE

What’s the word on the wire?

Follow Energy-Tech and keep up with the

industry chatter!

© 2014 Twitter

@ETmag

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

Figure 5. Example of correction error isolated to a specific range of the correction variable.


AsME FEAtUrE

ments. While these differences could be due to a number of reasons, including plant operation and turbine design, the best course of action is to avoid these regions when testing.

Historically, uncertainty estimates have not been increased to account for greater deviations in exhaust pressure. For these situations, consideration should be given to modifying plant operation to change exhaust pressure, waiting until sea-sonal conditions are more favorable, or verifying the exhaust pressure correction curve through additional testing. When none of these means are practical, PTC 6.2 indicates that testing might be conducted while accounting for the addi-tional uncertainty in the uncertainty analysis.

ConclusionAs noted in each major industry test code, efforts should

be made by all parties to conduct the performance test at conditions as close as possible to the reference conditions. In practice, owing to natural effects and commercial require-ments it is not always possible, nor is it always practical, to conduct the test at conditions that would yield the lowest achievable uncertainty. It is the responsibility of the testing organization to estimate the test uncertainty as accurately as possible, taking into account all known contributing factors. As discussed herein, the test uncertainty should take into account not only the contributions from measurement errors and their propagation to the corrected results, but also any additional uncertainty contributions that might result from the correction curves or calculation methodology. As shown in this paper, these additional incremental uncertainty contri-butions from correction curves or calculation methodology can be significant and quantifiable.

Statistical means can be employed to estimate the uncer-tainty stemming from the combination of unit-to-unit variations and deviations from the reference conditions. As shown herein, these can easily contribute an additional 0.2 percent to 0.3 percent incremental test uncertainty. As noted previously, additional analyses are warranted to refine these estimates to consider measurement uncertainty effects on the unit-to-unit variations, to ensure contributions are not over-stated when applied to the overall test uncertainty.

Furthermore, additional test uncertainty can result from limitations in correction curves when considering interac-tion with control system limits. These errors can be reduced by use of model-based performance corrections (ASME POWER2014-32184), though industry acceptance and pro-liferation of this methodology has been historically limited. When a statistically significant data set exists (which is now more common with modern plant historians and industrial Internet capabilities) the equipment supplier can empirically adjust correction curves (or the thermodynamic model) to mitigate the impact of off-reference test conditions, which could otherwise contribute >1 percent incremental test uncertainty.

While a traditional test uncertainty estimate for a PTC-22 code test that only considers measurement uncertainty might

ENERGY-TECHUNIVERSITY

September WebinarsSign up today for these upcoming

FREE exclusive webinars from Energy-Tech!

Electric Process Heating & Demand Fuel SwitchingTuesday, Sept. 16 • 1 pm CDT

Presented by Gaurav Dhingra – VP Engineered Systems, Craig Tiras – VP Technology

Sign up at www.energy-tech.com

Power Generating Asset ManagementTuesday, Sept. 30 • 1 pm CDT

Presented by Komandur Sunder RajPower generating assets represent sizeable investments for power plant owners. With the power industry grappling with transformative changes relating to people, processes and technology, power generating asset management (PGAM) is becoming vitally important, even critical in some cases. This article/webinar reviews technological advances that may be used in developing and implementing an optimum PGAM program and discusses technological tools to effectively gather and use key data and performance indicators to assess health and optimize the performance of power generating assets on a continuous basis. Sign up at www.energy-tech.com/article.cfm?id=75886


yield an uncertainty estimate on the order of +/- 0.5 per-cent, the actual error of the test result might be well above +/- 1.0 percent due to errors in the corrections. Proactively recognizing and considering these error sources can improve test accuracy, thereby reducing the risk of understating or overstating the true equipment performance. As such, it is to

the benefit of all test parties to take these incremental uncertainties into consider-ation when defining the test procedure (including correction methodology) and in selecting test conditions as close as possible to the reference conditions. ~

References1. ASME PTC 22–2005 Gas Turbines2. ASME PTC 46–1996 Performance Test

Code on Overall Plant Performance3. ASME PTC 19.1-2005 Test

Uncertainty4. ASME PTC 6.2–2011 Steam Turbines

in Combined Cycles5. ISO 2314 2009 Gas Turbines –

Acceptance Tests

Christopher Bañares is a senior technical manager for GE Power & Water with 18

years of experience in gas turbine design and performance testing and analysis. He has a bachelor’s degree and master’s degree in Mechanical Engineering from Rensselaer Polytechnic Institute. He is responsible for managing the Gas Turbine Performance Test group. You may contact him by emailing [email protected]. Evan Daigle is a lead methods engineer for GE Power & Water with

8 years of experience in gas turbine testing. In his role he is responsible for development of new testing and analysis methods. He has a master’s degree from the University of Michigan. You may contact him by emailing [email protected]. Thomas P Schmitt is a senior technical manager for GE Power & Water with 29 years of experience in jet engines, gas turbines and combined-cycle power plants. He holds a bachelor’s degree from Michigan State University. He is responsible for power plant performance testing, analysis and methods. You may contact him by emailing [email protected]. Thomas P Winterberger is a senior technical manager for GE Power & Water with 25 years of experience in steam turbine design, analysis and testing. He has a bachelor’s degree from Clarkson University and an MSME from Union College. He is responsible for managing the Steam Turbine Performance Test group. You may contact him by emailing [email protected].

AsME FEAtUrE

Figure 6. Steam output sensitivity to exhaust pressure.

exclusivewebinars

Energy-Techfrom

Our technical webinars are free

and feature industry experts

presenting the most relevant

subject matter as it relates to

electric power generation. Now

archived on www.energy-tech.

contentshelf.com/shop!

Energy-TechEnergy-TechArchived webinarsGas Turbine Inlet Cooling

Feedwater Heater Level Control

Makeup Water

Performance & Reliability

Condenser Retrofi ts

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


MACHiNE doCtor

The causes of turboma-chinery damage are not always obvious. This article presents a case study of a compressor that had a history of minor bearing tempera-ture issues that preceded several bearing failures. The true causes of the bearing damage were not immediate-ly obvious and it turned out to be a problem with toler-ances of certain parts and an undetected seal failure. An assessment of the machinery protection system also will be discussed.

IntroductionThis case study pertains

to a 5-stage integrally geared centrifugal compressor driv-en by a 1,500 rpm, 12,000 hp synchronous motor. The compressor is directly connected to the motor through a flex-ible disc pack type coupling. This machine compresses dry air from approximately 4.8 barg to 63 barg. The gearbox consists of a bullgear and three pinions. The stage 1/2 and stage 3/4 rotors consist of pinions with overhung impellers mounted at both ends. These rotors are mounted at the horizontal split line. The stage 5 rotor is located in the top of the gearbox cover and consists of a pinion with a single overhung impeller mounted at one end. The stage 1/2 rotor operates at a speed of 16,922 rpm, stage 2/3 at 22,562 rpm, and stage 5 at 25,786 rpm.

The gearbox utilizes tilting pad journal bearings for all three pinions. “X” and “Y” non-contacting proximity type shaft vibration probes are adjacent to each bearing, between the bearing and the oil seal. The pinions are fitted with thrust collars, which transmit pinion axial thrust to the bullgear. The bullgear rotor is fitted with a sleeve type journal bearing on the drive end and a combined sleeve type journal bearing and tapered land thrust bearings on the non-drive end. The bearings are all instrumented with temperature probes. The compressor control system includes vibration alarm and shutdown protec-tion, as well as alarm only bearing temperature monitoring.

The pinion air seals are a carbon ring type. Each seal assem-bly consists of multiple self-adjusting one piece carbon rings, which have a close clearance to the shaft to minimize process

gas leakage. The gearbox arrangements for stages 1-4 is shown in Figure 1; stage 5 is omitted for clarity.

HistoryThis compressor was commissioned in March 2007. On

the very first start, the 4th stage bearing temperature quickly climbed to 149°C before the compressor was shut down. The bearing was inspected and there was no visible damage. The compressor had been started with an oil supply temperature of 33°C vs. a design temperature of 45°C. Although the oil was cooler than design, it was above the recommended mini-mum permissible temperature. When the oil temperature was increased to the design operating temperature, the 4th stage bearing temperature quickly climbed to about 130°C after start-up, but eventually dropped and settled out at about 120°C. Although the 3rd stage bearing temperature did not rapidly increase in temperature or overshoot immediately after start-up, the steady state temperature during normal operation also set-tled out around 120°C.

Based on discussions with the compressor manufacturer and the author’s experiences with a similar compressor, the oil supply temperature was raised to 55°C to help increase oil flow to the 3rd and 4th stage bearings. When this was done, the 3rd stage steady stage temperature dropped to 113°C and the 4th stage dropped to 102°C. Although the 3rd stage temperature

Compressor vibration due to bearing and seal problems

By Patrick J. Smith

Figure 1. Compressor configuration


MACHiNE doCtor

was above the recommended alarm temperature of 110°C, it was decided that this was acceptable for short term operation.

The bearing temperatures on the other stages were accept-able. The vibration levels on all stages also were acceptable. Despite the higher bearing temperatures, both 3rd stage “x” and “y” vibrations were around 0.8 mils peak to peak (p-p) and both 4th stage “x” and “y” vibrations were around 0.4 mils p-p. The compressor manufacturer’s high vibration alarm set point for these stages was 1.1 mils p-p and the trip set point was 1.5 mils p-p.

The bearing application, design and assembly records were reviewed with the compressor manufacturer. The bearings were

a 5-pad, tilting pad type with non-aligning, cylindrical, center pivot pads. The pads were made from steel with a Babbitt coating.

The 3rd and 4th stage bearings are the same, except that the bearings were orien-tated differently. Some basic bearing information is shown in Table 1.

Although the bearing journal speed and bearing unit load are within typical bearing manufacturer limits, these are at the upper end of the author’s experience for a typical steel backed tilting pad bearing. The author’s experience would suggest that the bearing application is a slightly more aggressive application and the bearings could be less tolerant to certain condi-tions, which could adversely affect performance. For example, bearing clearance slightly tighter than design is an example of a condition that could adversely affect bearing performance by causing higher bearing tem-peratures.

The compressor manufac-turer evaluated various bear-ing modifications to reduce the bearing temperature and proposed the following changes:• Machine a chamfer on the trailing edge of all the pads. This essentially changes the bearing to an offset pivot

type, which increases oil film thickness and should result in lower bearing temperatures.

• Increase the diameter of the oil nozzles to increase the oil flow into the bearing.

Machine the pinion journal diameter in the bearing area to increase the bearing clearance. In general, higher bearing clear-ances result in lower bearing temperatures, but also can cause slightly higher rotor vibrations. The compressor manufacturer preferred to modify the journal rather than modifying the bearing to increase bearing clearance.

Figures 2a and 2b. September 2013 bearing damage


MACHiNE doCtor

It was decided to pursue the first two recommendations, but not the bearing journal modifications because of the addition-al time to remove, modify and re-install the rotor. It also was decided that only the 3rd stage bearing would be modified. The 4th stage bearing would not be mod-ified because it was already operating at an acceptable temperature. The compressor was operated in continuous service until a planned shutdown in July 2009 provided the opportunity to install the modified 3rd stage bearing. Despite operating at elevated temperatures above the recommended com-pressor manufacturer’s alarm point, the 3rd stage bearing temperature and vibration had been stable since commissioning. When the bearing was removed there was no visible damage.

After restarting the compressor, the 3rd stage bearing temperature was reduced to around 68°C. The “x” and “y” vibrations increased slightly to around 0.9 and 1.0 mils p-p. The 4th stage steady state bearing tem-perature remained about 100°C and the 4th stage “x” and “y” vibration levels were still both 0.4 mils p-p.

In February 2013 the 4th stage “x” and “y” vibrations increased to about 0.7 and 0.5 mils p-p and the bearing temperature increased to about 110°C following a com-pressor shutdown and restart. The “x” and “y” vibrations slowly trended up to about 1.0 and 0.9 mils p-p and the bearing tem-perature slowly increased over a matter of months to about 116°C. A sudden spike in 4th stage vibration caused a compressor trip in September 2013. There were no chang-es in the 3rd stage bearing temperature or 3rd stage vibrations. A process upset, which caused significant changes in compressor flow and discharge pressure preceded the September 2013 trip. It was thought that this upset might have caused an operating instability, which then caused the sudden increase in vibration. However, since there had been an upward trend in vibrations and bearing temperature, it was decided to inspect the 4th stage bearing.

When the bearing was removed, there was some bearing Babbitt damage found on

the 4th stage bearing pads. See Figure 2. No other damage was found and the pads were replaced with spares. The measured diametral bearing clearance also was checked and found to be slightly lower than design; 0.150 mm vs. a design of 0.179 to

Celebrating 50 years in North America

Table 1 – Basic Bearing Information

Stage Pinion Speed, RPM Journal Dia., mm Brg Axial Length, mm Journal Speed, m/sec Bearing Unit Load, barg

3/4 22562 80 71 94.5 23.7


MACHiNE doCtor

0.211 mm. Based on field measurements, it appeared that the shaft journal was slightly larger than design and this was the cause of the tight bearing clearance.

The compressor was restarted and the 4th stage “x” and “y” vibrations stabilized at about 0.6 and 0.5 mils p-p. But the vibrations slowly trended up to 0.9 and 0.8 mils p-p before the compressor tripped again on high 4th stage vibration a month later in October 2013. The bearing temperature after the repair was 100°C and had increased to about 113°C when the compressor tripped in October. Again, bearing pad Babbitt dam-age was found. See Figure 3.

Spare bearing pads were modified by adding the chamfer to the trailing edge, as was previously done to the 3rd stage bearing in 2009. The 4th stage bearing nozzles also were drilled out, as was also done to the 3rd stage bearing in 2009. The bear-ing clearance was measured again and was once more found to be lower than design. Modifications to increase bearing clearance were not pursued due to time constraints. Although tight bearing clearance might have contributed to the higher bearing tempera-tures, it was felt that something else was probably causing the poor bearing performance and progressive damage.

Although there was no change in the compressor thermodynamic performance since commissioning nor were there any signs of excessive seal leakage, it was decided to inspect the 4th stage impeller and seals for any sign of wear or damage. Upon disassem-bly, there was no visible impeller wear or damage, but the 4th stage carbon ring air seals were found damaged. It appeared that the several rings were broken and were hung up in the seal carrier. These seal rings are supposed to have some float so that they can tol-erate minor contact with the shaft without causing a continuous rub. With some of the seal rings stuck in position, there could have been a continuous seal rub, which then led to higher rotor vibration and subsequent bearing damage. The seal rings were replaced and the modified bearing was installed. The compressor was restarted and the 4th stage bearing temperature settled out at 92°C and the “x” and “y” vibrations settled out at 0.5 and 0.5 mils p-p. There has been no change in this performance since the repair.

Figures 3a and 3b. October 2013 bearing damage

- 24 / 7 -EMERGENCY SERVICE

IMMEDIATE DELIVERY

CALL:800-704-200210HP TO 250,000#/hr

250,000#/hr Nebraska 750 psig 750OTTF150,000#/hr Nebraska 1025 psig 900OTTF150,000#/hr Nebraska 750 psig 750OTTF150,000#/hr Nebraska 350 psig115,000#/hr Nebraska 350 psig80,000#/hr Nebraska 750 psig75,000#/hr Nebraska 350 psig60,000#/hr Nebraska 350 psig40,000#/hr Nebraska 350 psig20,000#/hr Erie City 200 psig10-1000HP Firetube 15-600 psig

ALL PRESSURE AND TEMPERATURE COMBINATIONSSUPERHEATED AND SATURATED

RENTAL FLEET OF MOBILETRAILER-MOUNTED BOILERS

75,000#/hr Optimus 750 psig 750OTTF75,000#/hr Nebraska 350 psig60,000#/hr Nebraska 350 psig50,000#/hr Nebraska 500 psig40,000#/hr Nebraska 350 psig30,000#/hr Nebraska 350 psig75-300HP Firetube 15-600 psig

ALL BOILERS ARE COMBINATION GAS/OILENGINEERING • START-UP • FULL LINE OF BOILER

AUXILIARY SUPPORT EQUIPMENT.Electric Generators: 50KW-30,000KW

WEB SITE: www.wabashpower.com847-541-5600 • FAX: 847-541-1279

E-mail: [email protected]

wabash444 Carpenter Avenue, Wheeling, IL 60090

POWEREQUIPMENT CO.

BOILERSSELL•RENT•LEASE

••••••••••••••••••••••••••••••••••

••

••••••••••••••••••••••••••••••••••

••


However, some future minor bearing changes are still planned so that the oil supply temperature can be reduced to the design temperature of 45°C without causing any increase in vibration levels.

Bearing performance analysisDetailed bearing analyses performed following the two

failures predicted bearing temperatures at the tighter bearing clearances. Predicted bearing performance was better at design bearing clearance. The bearing pad and bearing orifice modi-fications were successful in lowering the bearing temperature even at the tighter bearing clearance. However, restoring the design bearing clearance and other modifications are currently being pursued with support from the compressor manufacturer.

Machinery protection system discussionLooking closely at the September 2013 shutdown trends,

the 4th stage “x” vibration gradually increased to about 1.0 mils during several months and then rapidly increased to 1.6 mils p-p in less than a minute, which caused the compressor trip. The “y” vibration also slowly increased to about 0.9 mils during the same time period, and then rapidly increased in vibration to 1.4 mils p-p in less than 30 seconds at the time of the trip. There was no corresponding spike in bearing tempera-ture at the time of the trip. Looking at the Oct. 23, 2012, shut-down, the “x” vibration slowly increased from 0.6 mils p-p to about 0.9 over a month and then rapidly increased to 1.6 mils p-p in less than 30 seconds, which again caused a compressor trip. Similarly, the “y vibration slowly increased from 0.5 mils p-p to 0.8 mils during the month time period and then rapidly increased to 1.4 mils p-p in less than 30 seconds at the time of the trip. And again there was no corresponding spike in bearing temperature at the time of the trip.

Having compressor vibration monitoring and protection does not prevent a problem such as internal damage, wear or fouling from occurring. It does provide information of a pro-gressive problem that allows operators to take action before

there is a significant damage or a sudden failure. It also can minimize collateral damage in the event of a sudden failure. Although there were signs of some progressive wear/damage, as seen by gradual increases in vibration and temperature with both failures described in this article, the vibration levels never operated in a sustained period in alarm prior to the high vibra-tion trips. The large vibration increase occurred very quickly and the vibration protection system was effective in minimizing collateral damage.

Not all process centrifugal compressors are fitted with “x” and “y” vibration probes adjacent to each compressor bearing. For example, some machines might have only a single vibration probe adjacent to each bearing. Even with machines fitted with “x” and “y” probes adjacent to each bearing; some compressor protection systems are configured such that a high vibration trip on either vibration signal is needed to trip a compressor, while others are configured such that both vibration signals have to reach the trip point before the compressor trips. So, one might ask why this is the case and what is really needed to pro-tect a compressor.

Bearing dynamic characteristics such as damping and stiff-ness can be non-symmetrical, which can cause a rotor response to be more sensitive in one direction than another. In other words, it is possible that a problem might mainly affect the rotor vibration in one plane and have a modest or no affect in

MACHiNE doCtor

Table 2 – Compressor Arrangement

Vibration

Stage Before Field Balancing After Field Balancing

MAC Stage 1 0.60 0.62

MAC Stage 2 0.64 0.50

BAC Stage 1 0.49 0.57

BAC Stage 2 0.99 0.74


another plane. This is a reason for having vibration measured in two planes and having high vibration trip logic that shuts down a machine when either the “x” or “y” vibration signal exceeds the trip set point. This sounds like a reasonable approach, but it can lead to more nuisance trips due to instrument issues than a machine fitted with a single vibration probe, due to the number of extra instruments. Even with a machine fitted with dual probes adjacent to each bearing, having the control system configured such that the vibration signal from either probe can cause a trip can cause more nuisance trips than a control system configured such that both vibration signals have to reach the trip point before the machine trips.

However, having dual probes also can add flexibility. If a problem develops with one probe, having a second probe still provides some protection and monitoring capability, but this also adds cost. The problem described in this article caused a similar vibration response in both planes during both trip events. This is consistent with other incidents the writer has reviewed with similar machinery. It doesn’t mean that this is always the case, but compressor operators need to evaluate the impact of additional instrumentation vs. the benefit of addition-al diagnostic information.

ConclusionsAlthough tight bearing clearance probably contributed to

the higher bearing temperatures on both stages 3 and 4, it is likely that the seal ring damage was the catalyst that led to the bearing failures on stage 4. Although the high bearing tempera-tures were mitigated by modifications to the pads even with the tight bearing clearances, restoring the bearing clearances and further modifications could make the bearing more tolerant to less than ideal conditions.

Operators and compressor manufacturers need to collabo-rate on the machinery protection system that meets both the compressor manufacture requirements and the end user needs. This includes both the needed hardware and the control system configuration. It might be different for the same machine in different applications, depending on the cost and consequences of a machine trip, relative to the cost of the machine and any safety implications if the machinery shutdown protection is not sufficient to prevent a loss of containment of parts and/or pro-cess gas. ~

Patrick J. Smith is lead machinery engineer at Air Products & Chemicals in Allentown, Pa., where he provides technical machinery support to the company’s operating air separation, hydrogen processing and cogeneration plants. You may contact him by e-mailing [email protected].

sEPtEMBEr 2014AdVErtisErs’ iNdEX

A-T Controls Inc. www.a-tcontrols.com 19

CU Services www.cuservices.net 31

Cutsforth, Inc. www.cutsforth.com 32

EagleBurgmann www.eagleburgmann-ej.com 31

ECOM America Ltd. www.ecomusa.com 21

FloScan Instrument Co. Inc. www.floscan.com 31

Gaumer Process www.gaumer.com 13

Gradient Lens Corp. www.gradientlens.com 7

Hexeco www.hexeco.com 31

Hurst Boiler www.hurstboiler.com 2

Indeck Power Equipment Co. www.indeck.com 31

Miller-Stephenson Chemical www.miller-stephenson.com 31

MTI Instruments www.mtiinstruments.com 29

Renewal Parts Maintenance www.renewalparts.com 9

Rotork Controls Inc. www.rotork.com 5

Schenck Balancing & Diagnostic www.schenck-usa.com 27

Sohre Turbomachinery Inc. www.sohreturbo.com 18

Structural Integrity Associates, Inc. www.structinc.com 17

Topog-E Gasket Co. www.topog-e.com 11

Wabash Power Equipment www.wabashpower.com 28

MACHiNE doCtor

Coming in October 2014

Look for the next issue of Energy-Tech

magazine and read about:

• Outage season• Pumps• Regulations compliance:

Ash handling• Turbines: Steam• ASME: Performance

Energ

y-tech

show

case

31

miller-stephenson chemical company, inc.California - Illinois - Connecticut - Canada

800-992-2424 203 743.4447 [email protected]

miller-stephenson.com

ms

Aero-Duster®

Contact CleanersSolvent CleanersSpecialty Cleaners

Freeze SprayConformal CoatingsContact LubricantsKrytox® Lubricants

Miller-Stephenson Offers aWide Range of Chemicals

for the Power Industry!

TM

ms

ContactRe-Nu®

& Lube

MS-738

ms

Contact Re-Nu®

MS-730

ms

Vertrel XF Cleaning

Agent

MS-780

ms

Precision Cleaning Solvent

MS-580

ms

Plastic, Glass& Metal Cleaner

MS-260

ms

Acrylic Conformal

Coating

MS-465N

Low Global Warming Formulations Available

BOILERS RENT SALE LEASE

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

24/7 Emergency Service

P 847-541-8300 • F 847-541-9984 [email protected]

www.indeck.com





www.indeck.com





www.indeck.com





www.indeck.com





www.indeck.com





www.indeck.com





www.indeck.com





www.indeck.com





www.indeck.com

The Energy AnalystMechanical Engineering

Software

CU Services LLCPh: 847-439-2303

[email protected]

Boiler Effi ciency• Steam Turbines• Cooling Towers• HRSG • Condensers • Cogeneration• Heat Exchangers • Fanno Flow • Pipe Networks • Gravity Drain Flow • Steam Heaters • Steam Properties • Space Heating • Piping Pressure • Loss

Gas Turbines• Gas Expanders• Chimneys• Insulation• Gas Compressors• Duct Design• Restriction Orifi ce• Fans• Flash Tanks• Pumps• Psychrometrics• Desuperheaters• Deaerators•

CUTS_Brush_Problem_Ad_ENTECH_1-13_FIN.indd 1 12/31/12 11:39 AM

September 2014

Documents

Transcript of September 2014