Human error traps 10 • Creep Concerns 15 • ASME: Impact of Plant Cycling 18
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AUGUST 2016
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Energy-Tech (ISSN# 2330-0191) is published quarterly in print and digital format by WoodwardBizMedia, a division of Woodward Communications, Inc. WoodwardBizMedia assumes no responsibility for inaccuracies, errors or advertising content. Entire contents © 2016 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 Editor Kathy Regan – editorial@WoodwardBizMedia.com Editorial Board (editorial@WoodwardBizMedia.com) Bill Moore – Director, Technical Service, National Electric Coil Ram Madugula – Executive Vice President, Power Engineers Collaborative, LLC Kuda Mutama – Engineering Manager, TS Power Plant Tina Toburen – T2ES Inc.
FEATURES
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Flow distribution device design using computational tools By: Anand Gopa Kumar, Analyst, HRST, Inc.
COLUMNS
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Human error traps in technology: Strategies for reducing human error By Dwayne Coffey, Electric Power Research Institute
15
Turbine Tech
24
Machine Doctor
Creep Concerns: Identifying high risk areas for creep and evaluating expended life The dangers of running a compressor in manual By Patrick J. Smith
ASME FEATURE
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Maintenance Matters
Impact of plant cycling on availability By Nikhil Kumar Intertek AIM Sunnyvale, Calif., Maria Ouellette Portland General Electric Company Portland, Ore., Kurt Miller Portland General Electric Company Portland, Ore., Michael C. Liu Intertek AIM Sunnyvale, Calif.
INDUSTRY NOTES
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EDITOR’S NOTE
Another successful ASME Power Conference is in the books. I was disappointed that I was not able to attend this year's ASME Power & Energy Conference, but overwhelming grateful to be able to spend the time witnessing my youngest son’s wedding. I’m happy to report that I only cried through half the wedding and for only a few minutes at the reception while my son serenaded his new bride. Spending time with family and friends who traveled from all over the U.S. to be with us was priceless. Spending time with colleagues at a conference is also priceless. It’s hard to quantify the benefits from networking, attending keynotes and special sessions, and reviewing product offerings at the vendor exhibits. Those of you that attended the 2016 ASME Power & Energy Conference know what I’m talking about and are undoubtedly charged up to get back to business and apply what you learned.
CALENDAR August 1-3, 2016 Generator Auxiliary Systems Symposium Schenectady, N.Y. www.Energy-Tech.com/Gen-Sym August 30 - September 1, 2016 Steam & Gas Turbine-Generator Troubleshooting, Outage Management and Methods Las Vegas, N.V. www.tgadvisers.com September 12, 2016 Turbomachinery & International Pump Users Symposium Houston, Texas pumpturbo.tamu.edu Dec. 13-15, 2016 Power-Gen International Orlando, Fla. www.power-gen.com Submit your events by emailing editorial@woodwardbizmedia.com.
If you didn’t get a chance to attend the conference, Energy-Tech offers an abundance of white papers and Energy-Tech University webinars on a variety of topics featuring industry experts that you can download conveniently from your computer to help recharge your focus. Those same industry experts have written a number of great articles again that we feature here in this issue. We hope you are enjoying our new editorial format and are receiving the weekly email newsletters that will keep you informed between our print issues, which are mailed in February, May, August and November.
Incoming Committee Chair Mike Smiarowski addresses the group
As you read through this issue of Energy-Tech, take a minute to send me an email at editorial@woodwardbizmedia.com with your thoughts on the articles and topics that you’d like to see us cover in the next year. I’ll be starting the editorial calendar for 2017 soon and would love to have your input. And, with next year in mind – the dates have already been set for the 2017 ASME Power & Energy Conference in Charlotte, N.C. Call for papers deadline is October 19, 2016.You’ll want to reserve the time now on your calendar as this conference, coupled with the TurboExpo and ICOPE, will be one that you won’t want to miss!
There are plenty of networking opportunities at the conference
Thanks for reading.
Kathy Regan 4 ENERGY-TECH.com
August 2016
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FEATURES
Flow distribution device design using computational tools By Anand Gopa Kumar, Analyst, HRST, Inc.
Computational methods such as Finite Element Analysis (FEA) and Computational Fluid Dynamics (CFD) are being applied today extensively for design and testing with high levels of result accuracy. An increased share in renewable energy has seen a change in the operating mode of most combined cycle power plants from base loaded to a load following profile.Such changes, which push the HRSG’s limits, were not necessarily foreseen by HRSG designers in the past.Using computational engineering methods to design components for modification or retrofit have been more cost-effective. The following article details an instance where a perforated plate (or flow distribution grid) designed using CFD and FEA methods helped create an option that prevented the customer from choosing a more expensive solution. HRST was recently tasked with helping a customer who had to decommission a few of their superheater tubes upstream of the duct burners. This was because the HP Steam outlet temperature was higher than designed.Continued operation of the decommissioned tubes resulted in them being warped as there is no steam flowing through them.Tube rows in a panel can also function as a means 6 ENERGY-TECH.com
Weld quality checks on installed perforated plate
to straighten the flow and changing the number of rows would change the pressure drop in the gas flow and have an impact on the evenness of the flow entering the duct burner.This could influence the burner’s flame stability and in turn fail to meet emission standards. The first step of the simulation process is to build a 3D computer model of the inside casing of an HRSG built on a one to one scale using a CAD software. This internal volume is then converted into discreet points called grid generation where the calculations to determine the flow simulation will be performed. The Turbine Exhaust Gas (TEG) flow going through the model and the heat transfer from the tube panels were simulated using a CFD solver program. Once a baseline “as-built” model of the flow simulation is established and validated, the evenness of the flow upstream of the duct burner can be determined.The porosity distribution of the perforated plate can be changed at different locations to meet the burner manufacturer specified flow distribution upstream of the duct burner. The pressure exerted by the turbine exhaust gas on the perforated plate was determined from the August 2016
FEATURES
Figure 1. Simulation of flow patterns inside an HRSG
CFD simulation. This data can be further be used to determine the structural stability of the perforated plate through FEA modeling. A 3D model of the perforated plate, which includes its structural elements such as stiffeners and supports is created and a grid is generated for the FEA solver. The gas pressure on the perforated plate is used on the structural model and the stresses acting on it are determined.Additionally, effects of thermal expansion, low cycle/high cycle fatigue, and ratcheting of the plate due to the turbulent gas flow is also determined.
This is particularly helpful in determining the fatigue life of the perforated plate and steps taken to mitigate failure due to such phenomenon. Fatigue related damage is more prevalent in recent times due to the cycling operation of combined cycle power plants.FEA techniques have been proven to be a reliable means to determine the fatigue life; especially when additional components such as thermal stress comes into play. Based on these analysis findings, the design team at HRST was able to produce engineering drawings for the final layout of the perforated plate.Another major aspect of the detailed design is to meet the standards that are required by code.Once a final design has been established, the components were sent to a third party manufacturer who is experienced in fabrication of HRSG components.Quality checks on the manufacturing process are performed with HRST’s oversight and the final product is delivered to the client.
Figure 2. Structural analysis of flow distribution grid showing an exaggerated deformation (times 100) while in operation August 2016
ENERGY-TECH.com
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FEATURES The installation of the final product in the HRSG was also performed under HRST’s supervision. An HRST Technical Advisor (TA) was present to monitor quality checks on the installation and to ensure all the construction is on par with industry standards. Currently multiple HRSGs at this facility has been modified from their as-built configuration to the HRST solution. Redesigning the HRSGs configuration has led to the client saving millions of dollars in piping and heat transfer surface modifications.Adding a perforated plate to the HRSGs have ensured the abandoned superheater panel can be
decommissioned without any interference to the duct burner performance. Using computational tools such as FEA and CFD for designing components with similar retrofit and modifications can be performed with a greater degree of reliability and lower cost.With increasing demand on combined cycle power plants to augment renewable sources of energy; HRSGs endure an increasing number of start-ups and load cycling annually. Older HRSGs in particular are performing outside their design parameters as they were originally intended to operate at constant load.These factors have led to an increase in fatigue related failures, and retrofitting critical components using such computational design tools are becoming more and more common. Flow distribution control is often a challenging issue in HRSGs as the control devices are often subjected to harsh operating conditions.This is primarily due to the high temperatures at which such components operate and the constant vibrations induced by turbulent gas flow over them. This leads to frequent repairs and a shorter service life due to fatigue of the component. Similar methods of design, using computational tools, can also be very helpful in the design of other flow distribution devices such as turning vanes, dragon gates and others. â–
General overview of installed perforated plate
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Anand Gopa Kumar is an Analyst at HRST Inc. His analysis work includes Computational Fluid Dynamics (CFD) simulations of the HRSG gas flow, Finite Element Analysis (FEA) on HRSG components, flow accelerated corrosion studies and HRSG performance reviews. He has received Masters Degrees from Iowa State University in Aerospace Engineering and Systems Engineering. He also has more than six years of research experience related to Aerodynamics and has authored multiple papers in this area. Anand Gopa Kumar currently lives in the Twin Cities area and works out of the HRST Headquarters in Eden Prairie, Minn.
August 2016
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MAINTENANCE MATTERS
Human error traps in technology: Strategies for reducing human error By Dwayne Coffey, Electric Power Research Institute
In an era of increased regulation and global competition, improvements in efficiency and reliability have become more critical than ever in the power industry. However, while improvements to processes and machinery can be designed and built, and while broken equipment can be repaired, it is a much more complex task to improve the performance of those who work in power facilities and to reduce human error. Further complicating the picture, in some cases, the very technology that is introduced to enhance plant efficiency can contribute to human errors. In recent years, the Electric Power Research Institute (EPRI) has supported research to identify the factors that underlie human performance. This research has yielded a deeper understanding of human performance and, most importantly, has led to strategies that are effective in improving performance and reducing errors.
Human errors Reducing human error is recognized in the power generation industry as a key factor in reducing safety-related events as well as improving asset availability. Achieving a sustainable culture change that leads to human error reduction in plant operations and maintenance remains a significant challenge to the industry. It should be clear, too, that human performance applies to every member of the organization and every task performed. The improvement of human performance is, therefore, fundamentally important to the success of any organizational improvement effort. Increasingly, some human errors are caused by the introduction and application of new technology. For example, while walking through a facility, plant personnel may make entries on an iPad, mobile rounds device, or mobile monitoring
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August 2016
MAINTENANCE MATTERS
Flow chart 1
device (such as a thermography camera or handheld sensor.) Through inattention, these workers may run into equipment, stumble over steps or walk in front of moving equipment. Similarly, computer screens in digital control systems (DCSs) may cause operators to miss critical information or alarms through poor color or graphic usage or digital-versusanalog appearance. Incorrectly configured alarms may cause an alarm rate above the industry standard of six alarms per hour, or 150 alarms per day. Anxious to benefit from new technologies, facilities may install the technologies without fully understanding the human performance impact to personnel caused by these rapidly evolving technologies. Many configuration management processes have not adequately addressed the personnel training or the operating and maintenance practices required to be successful with the new technology.
Improving human performance Given the importance of this issue, over the past few years, many EPRI members have requested a simple guide that offers how-to information regarding the enhancement of human performance. In response, EPRI has developed an approach and some tools that can be used to improve human performance. The approach has been developed over several years and has involved the experience of more than 10,000 workers. Unlike traditional top-down, management-imposed approaches to improving human performance, the approach described here begins with the premise that organizational change can best be achieved from the bottom-up.
August 2016
The approach is based on achieving performance that is event free, not error free. This emphasis is to differentiate between significant consequential conditions (events) and those of less, if any, consequence (errors.) This is an important distinction because human beings are fallible—meaning that on any given day, anyone can make a mistake. The intent of this approach is to employ strategies and tactics to drive human error to the lowest possible levels of frequency and severity. By doing this properly, while effectively managing defenses, events can be prevented. A second element of this approach is “one life at a time.” This concept reveals an underlying foundational philosophy— the way to change the world is one person at a time. When it comes to organizational culture, the same holds true— organizational culture is changed one person at a time. This approach is 180 degrees out from the traditional top-down management approach.
Origins of human errors: Land mines and human error traps The foundation of the approach described here is based on four fundamental precepts: 1. Things are the way they are because they got that way. Thus a reason exists for why everything is the way it is. If specific things are not as good as they might be, the power exists to choose to do something different. 2. 84 to 94% of all human error can be directly attributed to process, programmatic or organizational issues. These issues, or simply “the way things are done around here,” set people up to make mistakes. Technically, they are referred to as “latent ENERGY-TECH.com
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MAINTENANCE MATTERS
Chart 2
organizational weaknesses.” Another appropriate term for them is land mines—or elements of the work environment just waiting to be stepped on. When a human error does occur, it is important to remember that these land mines exist. Such instances should be considered opportunities to learn, with follow-up actions taken to remove the setups, rather than succumbing to the initial urge to simply hold someone accountable. 3. People come to work wanting to do a good job. When the complexities of a generating station or a transmission grid are considered, along with all of the human interactions that must take place for the associated systems and integrations to function properly, it is amazing that things work as well as they do. People do come to work wanting to do a good job, which is why societies, organizations and work teams are able to function. If you think about it, most organizations function well. Considering this, why then is so much energy spent focusing on the negatives? This approach places a high level of emphasis on catching people doing things right rather than looking for the negatives. This is because of a behavioral truth: What gets recognized gets repeated. 4. The people who do the work are the one who have the answers. The people closest to the land mines are the ones who know how to dig them out and get rid of them. In addition to land mines, some conditions of the work environment also make it more likely for people to make mistakes. These conditions are referred to as human error traps. The 10 most common human error traps are as follows: • Time pressure • Distraction/interruption • Multiple tasks
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• • • • • • •
Overconfidence Vague or interpretive guidance First working day back Poor communications End of shift or extended shift First time or infrequent task Mental stress
Error elimination tools A number of tools have proved over the past decade to be most effective toward minimizing the potential for workers to make mistakes. These tools are not textbook theory. They are a set of simple behavioral techniques, which have been fully field-proven through the tremendous success in human error reduction achieved within both the nuclear generation and aviation industries over the past two decades. The seven fundamental error elimination tools include the following: 1. Questioning attitude Questioning attitude involves being attentive to all conditions. To have a questioning attitude means to review a situation to see if things are in the right place or as they should be. Questioning attitude encourages employees to challenge preconceptions and assumptions, and to consider actions and assumptions from differing perspectives. This tool is an essential element of identifying and correcting problems before they occur. It is especially important when time pressure exists to get the job done.
August 2016
MAINTENANCE MATTERS 2. Effective communications When communicating on the job, whether giving direction or providing information, employees need to be precise and to ensure that accurate information passes from one individual to another. Using formal communications under such conditions greatly reduces the potential for mistakes.
Formal communications include the following three basic elements: three-part communications, use of the phonetic alphabet and use of phonetic numerals. Threepart communications, which is commonly used for giving and receiving instructions, involves one worker giving an instruction. A second worker repeats the instruction and the first worker acknowledges that the second worker correctly stated the instruction. The phonetic alphabet assigns code words to the alphabet; the NATO phonetic alphabet is the most widely used version in the fossil power industry. A is alpha, B is bravo, etc. This tool is used when a single letter is the only difference in the identities of two pieces of equipment. Phonetic numerals are used when verbally communicating numbers that sound the same. For example, “16” is spoken as “one-six.”
3. Task preview Task preview is a structured means by which to consider the elements and constraints of a task from a human performance perspective prior to beginning the task. It is often used to help prepare to conduct a pre-job brief. It involves consideration of risks involved in performing the task and offers workers an opportunity to consider the whole job and the impact of plant/system conditions, the surroundings and other work in progress.
In a task preview, workers may review procedures, charts and work packages to identify the scope of work, task sequences and critical steps. Workers may ask, “What’s the worst that could happen?” and may consider controls, contingencies and past experience. A task preview allows workers to mentally and physically prepare to perform the task correctly and to minimize the potential for making mistakes.
4. Job site review A job site review is an evaluation of a work area or work site by the individuals who will be performing work immediately before work is commenced. It is conducted to assess system/equipment condition, to identify key components and critical indicators, to evaluate any workplace hazards, and to familiarize workers with locations and nomenclature relative to procedures/work packages.
This tool has been called by other names within the power industry, including, “Take-two” and “Two-minute drill.” The intent is to have full situational awareness of
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MAINTENANCE MATTERS
Video clips of tasks are useful for training
the job and surrounding location prior to commencing/ recommencing work.
result in significant consequences. The tool is symbolized by the acronym STAR, which stands for Stop, Think, Act and Review. Self-checking provides for conscious and deliberate thought prior to performing an action, when taking the action, and for ensuring that the desired response was achieved once the action has been completed. Self-checking is the final barrier between the individual performing the task and a mistake occurring.
5. Procedure use Procedure use involves adherence to the governing documents of an organization, activity or task. Such documents can include formal procedures, policies, work packages/instructions, job sheets, job hazard analyses and drawings.
7. Stop when unsure Stop when unsure is a defined behavior that is executed whenever a worker finds himself or herself in a state of confusion or uncertainty during task performance. The tool provides a brief stoppage of work during which all involved get answers and resolve concerns. It is designed to halt actions and acquire resolution prior to proceeding.
If levels of use have been designated (for example, continuous use, reference use, information use, etc.), organization guidance for the proper use of each level must be adhered to. Procedure use ensures that the right actions are performed in the proper sequence and helps to minimize the potential for making mistakes. 6. Self-checking This is a simple human performance tool for helping workers to focus on a task. It is used in performance of any activity where mistakes could
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Stop when unsure may be used when uncertainty or doubt exists during task performance, when unexpected results occur or unfamiliar situations arise, or when something expected does not happen. ■ Dwayne Coffey is principal program manager in EPRI’s Operations Management and Technology Program. E-mail editorial@ woodwardbizmedia.com to reach Dwayne.
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August 2016
TURBINE TECH
Creep Concerns: Identifying high risk areas for creep and evaluating expended life By Rachel Sweigart, consulting engineer for TG Advisers, Inc.
For materials in elevated-temperature environments, creep is an inevitable damage mechanism. Whena material is exposed to high temperature and stress, slow continuous deformation can occur which iscalled creep. It is a timedependent, stress-dependent, and temperature-dependent phenomenon. In the short term, creep can relieve tensile stresses but over time can lead to problematic dimensional shifts and failure. This damage accumulates over time and is irreversible. Creep damage initiallyappears as voids between the grain boundaries in the material which can be seen in Figure 1. Whenthese voids connect and grow they lead to deformation and cracking. In a steam turbine, the HP and IP inlet stages are most at risk for creep. Any stages that see temperatures above 800°F are likely to accumulate creep damage over time. These
high temperature conditions allow the material to become permanently deformed at stresses below the yield strength. Itis of special concern in the control stage. The control stage, or Curtis stage, is the first stage in thehigh pressure (HP) section of a turbine. It is designed to extract a large amount of energy out of thehighest temperature and pressure steam flow so it is significantly more solid than the following stages. Because of the high temperatures it sees and the increased stresses due to its greater mass, thecontrol stage is very susceptible to creep. Figure 2 shows a Curtis stage that has deformed and failed due to creep. Additionally, if the unit has a reheat system in place, the initial intermediate pressure (IP) stages are at risk for creep. IP blades are significantly larger than HP blades so they have higher levels of stress but, after the steam is reheated, the
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TURBINE TECH fit issues when replacing blades. If the blades are based on the original design and the rotor has expanded due to creep, the lugs can be misaligned geometrically and the blade fit may be loose. It is recommended to root form fit test the rotor before mass producing new blades. To adjust for an expanded rotor, it may be necessary to include an additional blade or modify the blade root geometry to ensure they are in full contact with the load carrying areas of the rotor dovetail.
Figure 1.
temperatures they see are comparable to the HP turbine inlet steam temperatures. When replacing early rows of the HP and the IP, it is important to evaluate creep. As shown in Figure 2, creep can cause catastrophic failures of a blade stage liberating a blade row. Over time, the rotor outer diameter will expand due to creep and thermal relaxation of the material. This can lead to
Design creep life analysis is generally based on the assumption that the unit is operating at full load for 30 years. This assumption allows for the most conservative evaluation. In practice, often this is not the case. Units can be run at low capacity factors or partial loads for much of their lifetimes. If the unit operates at reduced loads, the steam path will see temperatures and pressures below the design conditions which can increase the rotor’s creep life. If the unit has a 20% capacity factor, then the full year operation assumption overestimates creep damage by 80%. However, if a unit is running at temperatures that exceed design conditions, it can severely reduce the creep life. Operational temperatures as little as 5 or 10 degrees over 1000°F can exponentially increase the rate of creep damage. Control over the main steam and reheat steam temperatures is critical in reducing risk of accelerated creep. For a more accurate evaluation of the sustained creep damage in a unit, the actual operating hours and steam temperatures need to be accounted for with a detailed stress analysis. The implementation of operational data historians, such as PI, has made this type of analysis much more feasible because the necessary data is archived with a high level of accuracy.
Figure 1.
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TURBINE TECH To evaluate the stresses experienced during operation, a finite element analysis (FEA) model can be developed of the rotor dovetail. It’s important to consider where the highest stresses would be seen when choosing which section to model. In a circumferential entry design, the closing group experiences the highest stresses. For example, on a GE design the closing bucket is typically pinned to the adjacent blades and therefore, it carries an increased load and is the most likely location to experience creep damage. Once the operational stress has been evaluated, the Larson-Miller method can be utilized to predict remaining life. The Larson-Miller equation proposes that the relationship between the creep rupture stress and the LarsonMiller parameter is approximately linear. As shown in the equation below, the Larson-Miller parameter is calculated using the absolute temperature, the log of time, and a constant C, usually between 10 and 40 depending on the material. LMP = T (log t + C) The Larson-Miller Parameter relationship allows for predicting the time to failure based on a given stress level. Additionally, it can be used to evaluate the maximum allowable stress at a given operational temperature. Figure 3 is a plot showing the relationships between creep rupture stress and the Larson Miller Parameter. For each material,
testing is conducted to develop the LMP vs. stress curves. It is important to note that there is significant scatter inherent in the data. There are three curves shown indicating the minimum, average and maximum ranges of the data. For conservatism, remaining life can be evaluated assuming minimum values. If a more accurate assessment is necessary, a sample can be removed from the rotor and tested to evaluate the actual material properties. Using the actual operational data (in terms of hours, load and steam temperatures) and the Larson Miller Parameter, the expended creep life of the material can be calculated. TG Advisers has had technical experience with rotors that have failed from creep after over 450,000 service hours and rotors that have had creep failures with less than 300,000 service hours. For an accurate account of the remaining creep life the unit’s historical duty cycle and operating conditions must be evaluated. ■Rachel Sweigart joined TG Advisers in 2014 as a consulting engineer. She has provided life assessment, torsional and fracture mechanic analytical modeling and troubleshooting services for main turbine generators located throughout the country. Sweigart is a mechanical engineering graduate from Lafayette College. Email editorial@ woodwardbizmedia.com to contact Rachel.
Figure 3.
August 2016 ENERGY-TECH.com
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ASME FEATURE
Impact of plant cycling on availability By Nikhil Kumar Intertek AIM Sunnyvale, Calif., Maria Ouellette Portland General Electric Company Portland, Ore., Kurt Miller Portland General Electric Company Portland, Ore., Michael C. Liu Intertek AIM Sunnyvale, Calif.
Abstract Evidence is mounting that power plant cycling is causing significant additional wear and tear on the units. However, the effects of this additional wear and tear on future maintenance costs, production cost, and equivalent forced outage rate (EFOR) are not accurately quantified at the present time. For example, units that were originally designed for base load operation are now being cycled by many utilities. Typically, such units experience long-term decreases in availability and significantly increased maintenance and capital equipment expenditures because several materials degradation phenomena (creep, fatigue, creep-fatigue interaction, etc.) are accelerated by increased cycling. The authors will present results of several hundred studies, which highlight the impacts of plant cycling events on short and long term plant availability. The paper will also show the impact of plant cycling design, annual capital and operating expenses which can have a direct impact on plant availability.
Introduction to plant cycling Existing thermal generation plants are being forced to cycle more with the addition of intermittent wind generation and low variable cost base-load generation. Cycling damage manifests itself in terms of known past and future maintenance and capital replacements, as well as forced outages and deratings. There are a number of damage mechanisms that adversely impact plant equipment including fatigue, creep fatigue interaction, corrosion fatigue, chemistry Table 1 – Reliability statistics comparison between baseloadand cycling fossil steam units Comparison (% difference) between baseloaded and cycling fossil steam units. [Source: NERC GADS] Mean
Median
Gross Actual Generation
67%
54%
Planned Outage Hours & Ext.
118%
123%
# of POH Occurrences 114% 105%
114%
105%
Maintenance Outage Hours & Ext.
153%
151%
# of MOH Occurrences
140%
145%
Total Unavailable Hours
115%
121%
Actual Units Starts
154%
119%
Attempted Unit Starts
156%
123%
Note: Percent difference between cycling unit statistics and baseload unit statistics.
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transients and deposition, and mechanical wear. Increased cycling leads to higher maintenance costs and increased downtime, increased forced outage rates, higher heat rates (i.e., lower efficiency), and shortened life expectancies. The “true� cost of cycling power plants can be vastly higher than that assumed and used by most system operators to determine optimal dispatch schedules [1]. The Western Wind and Solar Integration Phase II Study determined that operational costs increased by 2% to 5% on average for fossil fueled plants when high penetrations of variable renewables are added to the electric grid [2]. This increase in costs was determined by performing simulations of the Western Interconnection for various combinations of wind and solar generation capacities (total of 33% of renewable energy) [2]. Cycling refers to the operation of electric generating units at varying load levels, including on/off and low load variations, in response to changes in system load requirements. Every time a power plant is turned off and on, the boiler, steam lines, turbine, and auxiliary components go through unavoidably large thermal and pressure stresses, which cause damage. This damage is made worse by the phenomenon we call creep-fatigue interaction. Creep and fatigue are terms commonly used in engineering mechanics. Creep is time-dependent change in the size or shape of a material due to constant stress (or force) on that material. In fossil power plants, creep is caused by continuous stress that results from constant high temperature and pressure in a pipe or tube occurring during steady-state baseload operation. Fatigue is a phenomenon leading to fracture (failure) when a material is under repeated, fluctuating stresses. In a fossil power plant, such fluctuating stresses result from large transients in both pressures and temperatures. These transients typically occur during cyclic operation. Because baseload fossil units are designed to operate in the creep range, they experience increased outages when they are additionally subjected to cycling-related fatigue. The term creep-fatigue interaction suggests that the two phenomena (creep and fatigue) are not necessarily independent, but act in a synergistic manner to cause premature failure. In fact, materials behave in a complex manner when both types of stresses occur. Creep-fatigue interaction is one of the most important phenomena contributing to component failures and can have a detrimental effect on the performance of metal parts or ASME Power Division Special Section | August 2016
ASME FEATURE components operating at elevated temperatures. It has been found that creep strains (i.e., mechanical deformation as a result of stress) can reduce fatigue life and that fatigue strains can reduce creep life. The effects of cycling on power plant components can be dramatic and surprising. One often neglected effect is the increase in operator errors that occur due to the increased personnel involvement that is necessary for cycling activities. Specific component effects can also be identified. Table 2 lists many power plant component problems attributable to cycling.
Impact of cycling on reliability When a utility begins to cycle its fossil plants, it typically observes a significant increase in equivalent forced outage rate (EFOR) due to the increased component failure rate. Intertek AIM's studies suggest that increased failures lag behind the switch to cycling operation by one to seven years. When the failure rate increases, capital and maintenance spending then must increase to keep the unit operable. The expenditures may lead to much higher, noncompetitive capital, maintenance and fuel costs for the units that are cycling. The higher capital, maintenance and fuel costs for these cycling units, in conjunction with the reduced generation, yield a higher average generation cost. The impact of cycling on plant reliability has been documented in terms of increased forced outage rate per cycling transient [3]. The lower bound results discussed in that study are the bare minimum impacts of cycling on plant reliability. As explained in the study, the best estimate or upper bounds of the impacts can be significantly more. Wholesale market deregulation, increased renewable generation and environmental pressures have impacted how plants are operated; but plant cycling is not a new phenomenon. While units have always been cycled, the intensity of cycling has varied from one unit to another depending on economics. Occasionally, existing coal units, which are usually not subject to extensive flexible generation, have been heavily cycled as discussed in a case study [4]. However, a key statistic in the case study is the significantly higher cycling related forced outage rate. Forced outages and equivalent derations are typically more frequent and of longer duration in cycling units than in baseload units. The recovery costs for additional forced outages should include some of the outages due to operator error. Such errors have included boiler explosions, boiler implosions, generator out-of-phase synchronization, generator motoring, water-induction damage, miscellaneous operator valving errors, miscellaneous errors involving humans, and automatic equipment and control system failures. Increased cycling obviously results in increased opportunities for error. Often forced outages, result in the cost of having to increase utilization of less economical
August 2016 | ASME Power Division Special Section
ASME Power Division: Reliability, Availability & Maintainability Committee
A message from the chair With the latest standard from the Reliability, Availability, and Maintainability (RAM) Standards Committee out the door (RAM-2 “RAM Program Development Process for Existing Power Plants”) and on schedule to be published later this year, the development of the next stages of RAM was the topic of discussion for the RAM Technical and Standards Committees at the POWER Conference in Charlotte, N.C. this past June. There have already been some ideas to continue the current path and develop RAM-3 to address the “RAM Program Development for New Plants” – however the feedback from the industry has always been the driving factor of what the committee should do next. The feedback received has helped to develop the following proposed ideas: 1. Develop RAM-3 to address RAM Program Development for New Power Plants. 2. Not focus on developing RAM-3 right now, but instead update RAM-1 (the RAM overview document from 2013) based upon feedback received. 3. Work on combining RAM-1 (Overview), RAM-2 (Existing Plants), and RAM-3 (New Plants) into a single consolidated RAM standard. The intent being to provide a comprehensive standard with uniform consistency. All of these and more were discussed by the RAM Standards Committee during the recent ASME conference. We are always looking for constructive feedback. If you have any suggestions, comments, or concerns, please do not hesitate to contact me or the committee directly. Thank you, Brian Wodka RAM Committee Chair Brian.Wodka@RMF.com
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ASME FEATURE Table 2 – Effects of Cycling on Plant Components [5] Turbine Chemistry
Electrical
• Fatigue Cracking of: • Boiler tubes in furnace corners • Tube to buckstay/tension bar • Tube to windbox attachment • Tube to header • Tube to burner • Membrane to tube • Economizer inlet header • Header ligament
• Cracking Due to Water Induction Into Turbine
• Increased Controls Wear and Tear
• Boiler Seals Degradation
• Blade Nozzle Block, Solid Particle • Grooving of Condenser/ Erosion Feedwater Heater Tubes at • Rotor Stress Increase Support Plates
Boiler
• Tube Rubbing • Boiler Hot Spots
• Corrosion Fatigue • Oxygen Pitting
• Increased Thermal Fatigue Due • Corrosion Transport to Boiler and to Steam Temperature Mismatch Condenser • Steam Chest Fatigue Cracking • Air, Carbon Dioxide, Oxygen • Steam Chest Distortion Inleakage • Bolting Fatigue Distortion/ • NH3-Oxygen Attack on Admiralty Cracking Brass
• Seals/Packing Wear/Destruction
• Increased Hysteresis Effects that Lead to Excessive Pressure, Temperature, and Flow • Controls not Responsible • Motor Control Fatigue • Motor Insulation Failure Due toMoisture Accumulation • Motor Mechanical Fatigue Due toIncreased Starts/Stops • Wiring Fatigue
• Drum Humping/Bowing
• Blade Attachment Fatigue
• Increased Need for Chemical Cleaning
• Downcomer to Furnace Subcooling
• Disk Bore and Blade Fatigue/ Cracking
• Phosphate Hideout Leading to Acid and Caustic Attack
• Increased Hydrogen Leakage in Generator
• Expansion Joint Failures
• Silica and Copper Deposits
• Silica, Iron, and Copper Deposits
• Fatigue of Generator Leads
• Lube Oil/Control Oil Contamination
• Out of Service Corrosion
• Generator Retaining Ring Failures
• Superheater/Reheater Tube Leg Flexibility Failures • Superheater/Reheater Dissimilar Metal Weld Failures • Startup-Related Tube Failures in Waterwall, Superheater, and Reheater Tubing
• Shell/Case Cracking • Wilson Line Movement • Bearing Damage
• Insulation Fatigue Degradation
• Generator End Turn Fatigue andArching • Bus Corrosion When Cool (i.e.,Low Amps) • Breaker and Transformer Fatigue
• Burner Refractory Failure Leading to Flame Impingement and Short-Term Tube Overheating
generation units (or purchase power) due to lower availability of the cycled units. Typically, utilities make cycling decisions based on factors such as unit size, age, equipment type, fuel costs, system requirements, production costs, etc. Power plant cycling costs have a large variation and depend on several factors such as, design, vintage, age, and operating and maintenance history. When the system requirements cause power plants to cycle, a key decisions faced by plant operators is to determine how to mitigate the effects of cycling. Some effects of cycling on the performance of a power plant include changes in: • Number and intensity (range as well ramp rate) of cycles • Startup and shutdown cycles • Load follow cycles – mild as well as significant • Equipment failure rates 20 ENERGY-TECH.com
• Maintenance requirements • Heat rates and startup fuel usage • Temperature and pressure (stress) transients • Chemistry requirements In a recent study, the authors performed a power plant cycling study in which they analyzed several years of operational and reliability data of two combined cycle units. The study utilized Intertek AIM’s well established methodology to determine the cost of cycling of power plants, but was expanded to evaluate the impacts of cycling on plant reliability. Figure 1 shows the impact of plant cycling measured in terms of equivalent hot starts (EHS). An EHS is Intertek AIM’s standard unit of cycling damage. An EHS represents the damage accumulation rates for a hot, warm, cold start or load change in relation to an idealized gentle load transient. Figure 1 shows two combined cycle ASME Power Division Special Section | August 2016
ASME FEATURE Utility Operation Area Plant Operation
Table 3 – Plant Cycling Risk Mitigation [6] Risk Reduction Measure • Modify startup, shut-down, turndown and ramping protocols to lower component fatigue stresses; For example, determine whether force cooling boiler is for economical reasons or simply to accommodate maintenance staff. • Closely monitor and inspect. Modify inspection plans around cyclic operation. • Train operators on best practices. Use operator alarms to reduce thermal stresses. • Follow appropriate cycle chemistry limits. Install condensate polishing system for rapid water chemistry • Use nitrogen blanketing of condensate storage tank, boiler, turbine
Plant Maintenance
• Establish a formal Reliability, Availability, and Maintainability (RAM) program. [7] • Do predictive maintenance accounting for cycling damage, to minimize cycling related forced outages. • Install thermocouples on strategic locations (example drains) to monitor condensate accumulation. • Risk rank equipment vulnerable to cycling
System Dispatch
• Include both short term and long term cost of cycling in system dispatch. On a new plant, short term maintenance costs might be small, but it is important to develop and plan a long term maintenance plan to mitigate future intermittent cost shocks. • Determine whether saving fuel cost in the short run, while jeopardizing the integrity of the asset in the future is a worthwhile risk?
Contracts
• Include cycling costs in the negotiation and accounting of energy and capacity transactions. • Determine the impact of the transaction on total system cycling costs.
System Planning
• Benchmark operating profile with peer group of units. • Account for cycling costs on existing units when evaluating new resources.
New Construction
• Design and procure designs better suited to cycling. Initial capital investment in an auxiliary boiler or larger condensate storage tanks should be considered. • Use prior experience and industry best practices to build flexible assets.
units at different points in their life cycle, with different rates of cycling as well as forced outage hours. Clearly, the differences observed in the figure reflect the differences in plant design, vintage as well as operating profile. However, the obvious trend observed is the increase in plant forced outage hours associated with cycling and the increase in plant cycling. The study did not include any forced outage unrelated to cycling, for example a transmission related outage or duration was not included. Additionally, the figure also shows the historical replacement power cost associated with each outage. While, there is a difference between traditional utilities and market-based operation, in either scenario the operator has to determine the cost of lost revenue, as well as meet the obligation to procure “replacement” capacity. The secondary axis on figure 1 presents typical cost of replacement power. Figure 2 shows a risk chart from a small sample of coal units that implicitly show a relation between cycling and forced outage rates. To help reduce the clutter in the chart, some key units have been highlighted to illustrate the impact of cycling on forced outage rates for different design units. Note that there are several outliers in the figure August 2016 | ASME Power Division Special Section
that represent High Impact Low Probability (HILP) events which are high consequence events resulting in large forced outages. Often these events are directly related to cyclic operation while other times they may be design flaws in the equipment. The figure shows a stark difference in the forced outage rates of a unit designed for cycling, which operates with significantly more cycles per year than a set of baseload units. Most units fall somewhere in between the two trend lines shown in the chart, however, in all cases there is an upward trend of increasing forced outage rates with increased cycling. Some cycling impacts (and costs) are incurred immediately, such as those due to heat rate increases caused by a low and variable loading. However, wear out costs associated with equipment failures are almost always delayed at least by months and more probably by several years. For most units, we define these wear out impacts as being associated with maintenance and capital equipment spending, along with the cost to replace power from forced outages due to equipment failure and degradation. The impact of cycling on forced outages has been documented in a number of studies [2], [3]. However, there is a time lag between ENERGY-TECH.com
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ASME FEATURE
failures and cycles, but eventually this trend is observed. The time to failure after a significant change to cycling operation can be 5 to 7 years in a new plant, however, in an older plant failures can occur within 9 months to 2 years. As discussed above, there is a clear correlation between plant cycling trends and the subsequent wear and tear and forced outage rates. To corroborate the trends with statistics, the authors analyzed the North American Electric Reliability Corporation's (NERC's) Generating Availability Data System (GADS) database. In one query of the database, the authors filtered and compared baseload steam units (6200 unit years) with fossil steam units that cycled (1700 unit years). Table 1 shows a summary of the results found in the query, which shows a fairly large 18% difference in the Planned Outage Hours (POH) for the cycling units compared to baseload units. The Maintenance Outage Hours (MOH) for the sample of cycling units is roughly 40% higher than baseload units. While, a detailed evaluation of the reliability statistics and the actual events should be performed, it is clear that plants that cycle frequently have lower reliability.
Conclusions To prepare and mitigate the risks of cycling, operators can either implement operational improvements or retrofit their plants. Implementing operational changes can provide significant improvements in cyclic operation of both fossil steam and combined cycle power plants. This is a low hanging fruit, compared to large or even modest capital
22 ENERGY-TECH.com
improvement projects. However, as illustrated in the case study performed by NREL, units with cycling design can indeed operate with significantly more flexibility [4]. Table 3 provides a high level list of mitigation strategies for plant cycling. Clearly, there is a direct correlation between plant cycling and the impact on operating costs and plant reliability. While a unit’s reliability during its early life has little indication of cycling damage and costs, long term costs and life consumption that leads to failures reach a point of very rapid increases in failure rates due to cyclic operation. Further research is required in evaluating the inherent “tradeoff ” relation between higher capital and maintenance expenditure and corresponding lower EFOR.■
Ackowledgements The authors acknowledge the support of Mr. Dwight Agan and Mr. Douglas Hilleman (Intertek AIM) and Ms. Maria Pope, Mr. Stephen Quennoz, Mr., Brian Clark, Mrs. Janet Kahl, Mr. David Rodgers, Mr. Scott Miller, Mr. Mark Tursa, Mr. Mike Dwyer, Mr. Wayne Law, and Mr. Gary Weidinger (Portland General Electric). References 1. Lefton, S.A., Besuner, P.M., and Grimsrud, G.P., “Managing Utility Power Plant Assets to EconomicallyOptimize Power Plant Cycling Costs, Life
ASME Power Division Special Section | August 2016
ASME FEATURE
and Reliability,” Proceedings of EPRI Fossil Plant Cycling Conference,September 14-16, 1994. 2. D. Lew et al, "The Western Wind and Solar Integration Study Phase 2," NREL Technical Report TP-550055588, September 2013 3. Kumar, N., Besuner, P., Lefton, S., Agan, D., & Hilleman, D. (2012). Power plant cycling costs. NREL/SR-550055433. 4. Cochran, A., Lew, D., & Kumar, N. (2013). Flexible coal: Evolution from baseload to peaking plant, NREL Report No. BR-6A20-60575. Golden, Colo.: National Renewable Energy Laboratory 5. Lefton, S.A. et al, "Using Fossil Power Plants in Cycling Mode: Real Costs and Management Responses”,Managing Fossil Generating Assets in the Emerging Competitive Marketplace, EPRI Conference, October 1996 6. Kumar N., "Improving the Flexibility of Coal-Fired Power Plants”, Power Engineering 2014 7. "Reliability, Availability, and Maintainability of Equipment and Systems in Power Plants”, RAM-1 2013,ASME Editor’s note: This paper, POWER2015-49359, 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.
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August 2016 | ASME Power Division Special Section
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MACHINE DOCTOR
The dangers of running a compressor in manual By Patrick J. Smith
There are times when it is necessary or even desirable to run a compressor with the control valves in manual. In this scenario the compressor operating conditions are controlled by setting these valve positions. This sounds reasonable and during steady state operation and even certain transient events, it is a practical way to operate the machine. When an adjustment is necessary, the control valve changes may seem straight forward, but sometimes the system responds differently than expected and the compressor can be driven to undesirable operating conditions. This is the danger of operating a compressor with the control valves in manual. The purpose of this article is to describe an incident where a compressor failed during a transient operating event when the compressor was operated with the control valves in manual and the system didn’t respond as expected.
Introduction This case study pertains to an integrally geared centrifugal compressor driven by a 2500 HP, 3585 RPM induction motor. The gearbox consists of a bullgear and three rotors. Each rotor consists of a pinion with a single overhung open impeller
mounted at one end. The compressor stage 1 and 2 rotors are mounted on the gear case horizontal split line, while the stage 3 rotor is installed in a split line in the upper gear case cover. The gas seals at each stage consist of a single dry gas seal (DGS). The gearbox configuration is shown in Figure 1. The gearbox utilizes tilting pad journal bearings for all three pinions with a single non-contacting proximity type shaft vibration probe adjacent to each impeller side bearing. The pinion rotors are fitted with thrust bearings. The normally active thrust bearings are a tapered land type and the normally inactive thrust bearings are a tilting pad type. The gearbox also utilizes axial position probes at the end of each pinion to monitor the thrust bearing condition. The bullgear journal bearings are a cylindrical sleeve type and the bullgear thrust bearings are a flat land type. The compressor protection system includes high pinion vibration alarms and trips, and pinion axial position alarms and trips. This compressor is used in a closed loop, mixed refrigerant (MR) system, which provides refrigeration for an industrial gas plant. A simplified P&ID is shown in Figure 2. In this cycle the MR is compressed in the compressor, condensed in the main heat exchanger, expanded across an expansion valve, and evaporated in another section of the main heat exchanger. As shown in the P&ID there are also some small vent valves. These are used to control the composition of the MR and vent gas if the system pressures become excessive.
History The compressor is in continuous service in an industrial gas plant. After about three years of operation there was a 2nd stage thrust bearing failure that occurred during a re-start after a power outage. The compressor control valves were operated in manual and the operator was having difficulty controlling the process. The damage was attributed to operation at a heavy stonewall condition. Some additional protections were added to warn the operators if the compressor was operated in this condition in the future. The compressor ran well for the next five years until there was an upset condition in the industrial gas plant which resulted in a loss of the heat load. The MR system was kept in operation to avoid a shutdown and restart. However, the loss of the heat load caused changes in the MR system operating conditions. Initially there was a significant drop in the system pressures and temperatures as more MR was condensed in the heat exchanger due to the loss of the heat load. With the Figure 1. Compressor Configuration
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MACHINE DOCTOR
Figure 2. P&ID
control valves being operated in manual, the expansion valve was further opened. This brought back the compressor suction pressure and system temperatures, but the discharge pressure was still lower than design. This resulted in the compressor operating near the stonewall condition, which was a concern based on the previous failure. The expansion valve was then pinched back while the compressor recycle valve was slowly opened in an attempt to increase the compressor ratio while maintaining reasonable system pressures and temperatures. But, these changes caused the compressor suction pressure to slowly rise and stabilize at a higher pressure than design, while the
Figure 3. Pressure Trends
discharge pressure and system temperatures slowly dropped. Once the recycle valve was completely open the compressor suction pressure and machine power increased very rapidly. In a little over a minute the suction pressure went from 115% of design to 160% of design. The suction valve was then closed, but this didn’t lower the suction pressure or machine power and the machine was shutdown. After the shutdown, the suction pressure momentarily spiked to over 300% of design before the system settled out at about 150% of design suction pressure. Trends of suction and discharge pressure for the last 10 minutes of operation are shown in Figure 3. After the machine was shut down, there were significant changes in the stage 1 and 2 rotor axial positions, which indicated possible thrust bearing damage. See Figure 4. The compressor was disassembled and there was significant damage to several thrust bearings. A brief assessment of the as found machine condition is described below. • Rotor 1 (Compressor stage 1) • No gear tooth, active thrust bearing or dry gas seal damage •Light axial impeller rub at OD • Some varnish on radial bearing pads • Heavy inactive thrust bearing damage • Rotor 2 (Compressor stage 2) • No impeller, gear tooth, radial bearing, or active thrust bearing damage • Rub on DGS hard faces, but seal faces intact • Heavy inactive thrust bearing damage • Rotor 3 (Compressor stage 3) • No gear tooth, radial bearing, active thrust bearing, inactive thrust bearing or dry gas seal damage • Light axial impeller rub at OD • Bullgear • No gear tooth, radial bearing or inactive thrust bearing damage • Heavy active thrust bearing damage Figure 5 shows a picture of the damaged 1st stage inactive thrust bearing.
Root cause Analysis (RCA) The following causes were investigated as part of the failure analysis: • Mechanical design • Progressive wear/damage • Surge • Lack of lubrication • Thrust overload before shutdown • Thrust overload after shutdown Figure 4. Axial Position Trends
Mechanical design The gear and bearing loads at the design conditions were reviewed and were well within industry experience. Thus, it was concluded that excessive mechanical loads at design
August 2016 ENERGY-TECH.com
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MACHINE DOCTOR
Figure 5. Pinion 2 Inactive Thrust Bearing Damage
Figure 6. Compressor Performance During Event
conditions was not an issue. During the repair no changes were made to the compressor mechanical design.
Surge The operating data prior to the failure showed no evidence of operation in surge. The machine vibration levels and rotor axial position trends were stable. And although the operating conditions were changing, there were no rapid oscillations in pressures or power that would have been an indication of surge. Thus, it was concluded that surge prior to the shutdown did not contribute to the failure.
Progressive wear/damage Long term operating trends showed no signs of progressive mechanical damage or wear. There were no detectable changes in long term vibration trends, rotor axial position trends or thermodynamic performance. This included a review of the shutdown trends. When the machine is shutdown, the rotors shift to the normally inactive thrust bearing position. Previous shutdown trends were reviewed and did not show any change in axial position after these shutdowns. This indicated that there was no progressive inactive thrust bearing damage.
Lack of lubrication Immediately after the compressor was shutdown, the oil pressure momentarily dipped from 27 psig to 14 psig, before increasing back to 27 psig. The lubrication system includes
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MACHINE DOCTOR within the design limits. And, as shown in Figure 4, the shift in axial position on all the rotors coincided with machine shutdown. So, it seems unlikely that the 1st and 2nd stage inactive thrust bearing damage occurred before the shutdown.
Figure 7. Pressure Forces Acting on Impeller
a main oil pump (MOP) driven off the bullgear shaft, and an electric motor driven auxiliary oil pump (AOP). On a compressor shutdown, the AOP is started because the capacity of the MOP will fall off as the compressor decelerates. The low oil pressure shutdown set point is 15 psig. A dip in oil pressure may be due to a delay in the start of the AOP and/ or an indication of rapid deceleration of the compressor. This momentary drop of oil supply could have contributed to the bearing damage. Thrust overload before shutdown After the initial drop in suction pressure, the suction pressure rose during the entire event. Using shop test data a thermodynamic performance model was created to evaluate the overall operating conditions and interstage conditions leading up to the failure. As shown in Figure 6, the compressor was driven into a stonewall condition as the suction pressure rose. The interstage performance at different conditions had to be extrapolated from the shop test stage curves. At the operating points shown on the performance curves, the calculated interstage conditions were used to estimate the thrust forces. Thrust forces are a combination of the differential pressure forces acting on both sides of the impeller and the gear reaction forces. Figure 7 shows a simplified model of the pressure forces acting on the impeller. The pressure forces drive the rotors towards the impeller end at normal operating conditions. For rotors 1 and 2, the gear reaction forces are opposite in direction to the impeller pressure forces. However, at the design point, the gear reaction forces are less than 50% of the pressure forces acting on the impeller and so the net force is towards the impeller. Note that for rotor 3 the pressure force and gear reaction force are in the same direction at normal operating conditions. At the higher suction pressure conditions, there is a modest increase in the calculated net rotor 1 axial thrust while the corresponding calculated axial thrust for rotors 2 and 3 drops. The rotor 1 thrust force is still well
During normal operation the bullgear is thrusted towards the non-drive end (NDE). The bullgear thrust forces are purely a function of the net gear reaction forces from all three rotors. At the higher load conditions prior to the shutdown, the calculated bull gear active thrust bearing load was very close to the design limit. Marginal lube oil flow, some minor misalignment, and other factors combined with the high loading at the time of the shutdown may have led to the active thrust bearing damage. Thrust overload after shutdown As the pressures in the compressor settle out, the pressure forces acting on the impellers will drive the rotors in the normally inactive direction, away from the impeller. As shown in figure 7, the face area on the front side of the impeller is larger than the back side due to the area taken up by the shaft. So, at settle out, the thrust force created by the pressure forces acting on the impeller is equal to the pressure times the cross sectional area of the shaft behind the impeller. At higher pressures, the impeller pressure forces in the inactive direction are higher and could be much higher than the forces at design operating conditions in the active direction. The gear reaction
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MACHINE DOCTOR forces will also change direction after the shutdown because the rotors will drive the bullgear until the train stops rotating. However, the gear reaction forces will drop very quickly with speed. When the compressor was shutdown, the suction pressure was already much higher than design and the resulting settle out pressure would be much higher than if the machine was shutdown at the normal pressure conditions. There is not a lot piping volume between the suction valve and the compressor inlet. Shutting the suction valve prior to shutting down the
compressor could have caused a higher settle out pressure than had the valve been kept open and could also have contributed to a higher spike in suction pressure. The large spike in suction pressure immediately after the shutdown could also have caused a large reverse flow through the compressor as the machine coasted down in speed, creating even higher pressure forces. Although there is no data available to calculate the actual forces as the machine is coasting down, it seems plausible that the high suction pressure condition at the time of the shutdown and/or a large reverse flow through the compressor could have caused high thrust load conditions. The other thing to consider is that bearing load capacity is a function of speed. At slower speeds, the bearing load capacity is lower. And the speed will drop off quickly as the machine is coasting down after a shutdown. The other possibility is that a high reverse flow through the compressor could cause the machine to stop quickly and then rotate in the reverse direction. There is no data to substantiate this, but the rotor 1 inactive thrust bearing damage seemed to be consistent with reverse rotation based on the pattern of the Babbitt smearing. Although this isn’t conclusive, it suggests the possibility. This is significant because the pinion thrust bearings are a unidirectional design. Allowable bearing load in the reverse direction of rotation is substantially less and is even lower at lower speeds. Reverse rotation could also cause or contribute to active (NDE) bullgear thrust bearing damage. When the machine is shutdown, the gear thrust forces reverse; the compressor drives the motor on coast down. In this case the bullgear is thrusted towards the drive end (DE). However, if the compressor stops and reverses rotation, the thrust forces would again change direction and the bullgear would thrust towards the NDE. It is possible that there could be enough load at low speeds to cause thrust bearing damage while rotating in the reverse direction, especially if there was any possibility of marginal oil supply. Flat land thrust bearings are not very forgiving.
RCA Conclusion There are a lot of assumptions that went into the RCA and there is a fair amount of uncertainty as to the exact cause. However, it seems likely that the high suction pressure 28 ENERGY-TECH.com
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MACHINE DOCTOR condition and spike in suction pressure caused or contributed to the failure.
recycle valve changes. This led to unstable operation and the overload conditions that led to the failure. As a result additional safeguards are needed to prevent accidental overloading of the compressor, especially during transient operating conditions.â–
This compressor is in a closed loop refrigeration system which involves condensing and evaporation. This is very different from a machine in an open loop, once through system Patrick J Smith is lead machinery engineer at Air Products & hemicals in Allentown, Pa., where he provides technical machinery support to and how the compressor operating conditions are affected the company’s operating air separation, hydrogen processing and by process and control valve changes are not as intuitive. The cogeneration plants. You may contact him by emailing editorial@ events leading up the high suction pressure condition prior woodwardbizmedia.com. 1511-SCHENCK_1-2i.pdf 1 10/13/15 10:33 AM to the shutdown occurred because the system didn’t respond as expected to the control valve changes. And, the rapid increase in suction pressure just prior to the shutdown was another surprise. As a result the corrective actions need to address these issues.
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Corrective action The compressor control system consists of a number of interlocks, alarms and trips to ensure safe, reliable operation of the machine. The following changes were made to the control system to address the issues discussed in the RCA: 1. Addition of a high suction pressure trip. 2. Addition of an interlock to prevent opening of the suction valve if the pressure difference across the valve is too high. This will prevent accidental supercharging of the compressor suction. 3. Addition of a small bypass valve around the suction valve to allow for a controlled equalization of pressure across the suction valve before opening the suction valve. 4. Addition of a discharge dump valve that quickly opens on a machine shutdown and prevents high backflow through the compressor and a significant spike in suction pressure. 5. Lowering of high motor amp set point to prevent overloading of the compressor. 6. Ensuring there is no delay in starting the AOP on a compressor shutdown. C
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Conclusions During steady state operation, the system was operated reliably with the expansion valve in manual. However, the loss of heat load in the system resulted in unexpected changes in the compressor operating conditions and the system did not respond as expected to expansion valve and compressor August 2016
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