Asset Management 11 • ASME: Hybrid Cooling 19 • Control System Update 25
ENERGY-TECH A WoodwardBizMedia Publication
AUGUST 2014
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Dedicated to the Engineering, Operations & Maintenance of Electric Power Plants In Association with the ASME Power Division
Increase burner flexibility
ENERGYT ECH P.O. Box 388 • Dubuque, IA 52004-0388 800.977.0474 • Fax: 563.588.3848 Email: sales@WoodwardBizMedia.com www.energy-tech.com Energy-Tech (ISSN# 2330-0191) is published monthly in print and digital format except in January and July, when it is published in digital format only by WoodwardBizMedia, a division of Woodward Communications, Inc. WoodwardBizMedia assumes no responsibility for inaccuracies, errors or advertising content. Entire contents © 2014 WoodwardBizMedia. All rights reserved; reproduction in whole or in part without permission is prohibited.
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By Jim Sutton, Alstom
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Editorial Board (editorial@WoodwardBizMedia.com) Kris Brandt – Rockwell Automation Bill Moore – Director, Technical Service, National Electric Coil Ram Madugula – Executive Vice President, Power Engineers Collaborative, LLC Kuda Mutama – Engineering Manager, TS Power Plant
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Creative/Production Manager Hobie Wood – hwood@WoodwardBizMedia.com Graphic Artist Valerie Vorwald – vvorwald@WoodwardBizMedia.com Address Correction Postmaster: Send address correction to: Energy-Tech, P.O. Box 388, Dubuque, IA 52004-0388 Subscription Information Energy-Tech is mailed free to all qualified requesters. To subscribe, go to www.energy-tech.com or contact Linda Flannery at circulation@WoodwardBizMedia.com Media Information For media kits, contact Energy-Tech at 800.977.0474, www.energy-tech.com or sales@WoodwardBizMedia.com. Editorial Submission Send press releases to: Editorial Dept., Energy-Tech, P.O. Box 388, Dubuque, IA 52004-0388 Ph 563.588.3857 • Fax 563.588.3848 email: editorial@WoodwardBizMedia.com. Advertising Submission Send advertising submissions to: Energy-Tech, 801 Bluff Street, Dubuque, Iowa 52001 E-mail: ETart@WoodwardBizMedia.com.
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Regulations Compliance
Plant operating procedures to reduce error and improve safety By Neva Espinoza, Electric Power Research Institute
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Mr. Megawatt
Figuring out a high heater problem By Frank Todd, True North Consulting
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Editorial views expressed within do not necessarily reflect those of Energy-Tech magazine or WoodwardBizMedia. Advertising Sales Executives Tim Koehler – tkoehler@WoodwardBizMedia.com Joan Gross – jgross@WoodwardBizMedia.com
Power generating asset management By Komandur Sunder Raj, Energy-Tech contributor
Printed in the U.S.A. Group Publisher Karen Ruden – kruden@WoodwardBizMedia.com General Manager Randy Rodgers – randy.rodgers@woodwardbizmedia.com Managing Editor Andrea Hauser – ahauser@WoodwardBizMedia.com
Increasing operational flexibility of burners in tangentially fired boilers
Turbine Tech
Control system modernization increases reliability and improves owner’s maintainability for Michigan municipality By Kevin Giroux, Turbine Technology Services
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Economic design of hybrid wet-dry cooling systems By R.W. Card, CB&I
iNdUstrY NotEs
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Editor’s Note and Calendar Advertisers’ Index Energy Showcase
oN tHE WEB We’ve added to Energy-Tech’s white paper library with a new contribution from Floscan Instrument Co. Inc. Download its new paper, NOX Reporting Made Simple, at www.energy-tech.contentshelf.com. Cover photo contributed by Alstom.
August 2014
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Editor’s Note
Power sharing Make knowledge transfer a priority Teaching is challenging. Anyone who has tried to teach another individual a skill or information will attest to that point. Throw in time constraints, the amount of information to share and personality quirks, and the challenge can seem impossible. That’s why the people who are talented enough to make teaching seem easy are usually already in the classroom. But as the saying goes, knowledge is power, and as the power industry continues to wrap its arms around long-time employees getting ready to retire and new employees ready to put their college theories into real life practice, knowledge transfer should be a priority for every plant. That’s why the 2014 ASME Power Conference created the student paper track this year, so that tomorrow’s engineers could begin to make the professional connections that are vital to knowledge transfer for the future. It’s why two of the article’s in this month’s issue highlight the importance of creating practices and procedures for plant safety and asset management that might otherwise be overlooked or taken for granted by long-time employees. Creating a list of safety procedures might seem obvious, or an excuse for busy work, but for a new engineer trying to learn the ropes, it can be a vital reference as they learn how to navigate the plant. Learn EPRI’s guidelines for creating plant procedures on page 14, “Plant operating procedures to reduce error and improve safety.” If you enjoy it, share it with your colleagues. The same goes for asset management – long-time employees probably know the machines inside and out, and can tell their maintenance status with a simple inspection, but for the new engineer or member of the maintenance crew, detailed asset management records can help them learn the ins and out of the plant much more quickly – and safely – than trial and error. Read more about it on page 11, “Power generating asset management.” And keep reading Energy-Tech! Our contributors share their experience and expertise in every issue. If your new staff isn’t receiving Energy-Tech, tell them to get signed up. It’s monthly professional development – for free. Subscription information is at www.energy-tech.com. And as always, thanks for reading.
Andrea Hauser
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CALENDAR Aug. 6-8 & 13-15, 2014 Energy-Tech University: Steam and Gas Turbine Troubleshooting Presented by Steve Reid, P.E., TG Advisers Inc. www.energy-tech.com Aug. 19-21, 2014 Power Plant Pollutant Control “MEGA” Symposium Baltimore, Md. www.megasymposium.org/wps/ Aug. 19-22, 2014 Balancing of Rotating Machinery Houston, Texas www.vi-institute.org Aug. 26-28, 2014 Facilitating Remote and Online Meetings Online training presented by WoodwardBizMedia www.remotemeetings.eventbrite.com Sept. 9-11, 2014 2014 Dry Scrubber Users Association Conference Minneapolis, Minn. www.dryscrubberusers.org Sept. 9-11, 2014 Feedwater Heater Operation and Maintenance Seminar Atlantic City, N.J. www.powerfect.com Sept. 16-19, 2014 Machinery Vibration Analysis Salem, Mass. www.vi-institute.org Sept. 22-25, 2014 Pump & Turbomachinery Symposia Houston, Texas www.pumpturbo.tamu.edu Nov. 3-4, 2014 CCGT 2014: O&M and Lifecycle Management for CCGT Power Plants Houston, Texas www.tacook.com/ccgt-usa
Submit your events by emailing editorial@woodwardbizmedia.com.
August 2014
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FEATURES
Increasing operational flexibility of burners in tangentially fired boilers By Jim Sutton, Alstom
Successful operation of a coal-fired power plant increasingly requires more flexibility. Longer times between major outages, more frequent start-ups and shutdowns, and for many plants, more time at minimum load. This article explores recent advances in burner and ignitor technology for tangentially fired boilers that allow operators increased flexibility in scheduling longer durations between outages and greater reliability in start-up.
The issue Intense cost competition among various energy sources (primarily coal, natural gas and wind) has changed the operation of coal-fired boilers. Where previously coalfired boilers ran in a base-load configuration, they now might be forced to spend more time at low load or standby conditions. All of this must be accomplished during operation within established NOX, CO and SOX gaseous emission limits. Additionally, coal-fired boilers major outage intervals have changed from 18 months to 3 years and beyond. Many power plants must bid for the privilege to produce electricity for the next day. Based on the system anticipated load, a clearing price is established and a commitment to produce the power bid is made. If an unexpected outage occurs, and the power plant is unable to produce the contracted power, large monetary losses might be incurred. Finally, if a unit is offline during a period of peak demand, it might miss out on “golden hours� where high demand has pushed prices up. All these relatively new requirements highlight the need to make components Figure 1. A tangentially fired boiler windbox arrangement. in the burner system as reliable as possible, able to safely operate in as wide a load Tangential boiler burner configurations range as possible and allow quick transitions in load. A tangentially fired system is based on the concept of What does this mean for a tangential boiler’s burners a single flame envelope. Both fuel and combustion air are and ignitors, and their controls? injected from the corners of the furnace along a line that is tangential to a small circle, lying in a horizontal plane at the center of the furnace. Intensive mixing occurs where 6
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August 2014
FEATURES these streams meet. A rotational motion, similar to that of a cyclone, is imparted to the flame body, which spreads out and fills the furnace area. A tangentially coal-fired boiler of the 800MW class might have as many as 64 fuel admission locations. These are known as coal compartment assemblies and shown in Figure 1. One side of this assembly connects to the coal piping, while the assembly ends with a coal nozzle tip that is exposed to the furnace. Firing rate (MBTU/hr) is controlled by the number of coal compartment assemblies in service and the fuel flow rate to each assembly. When the boiler is brought up from cold conditions, the first step is to ignite a warm up fuel elevation. In Figure 2 a warm up oil gun can be seen in service. The warm up oil gun is placed between two elevations of coal nozzles. The warm up fuel can either be natural gas or fuel oil. Ignition energy for the warm up elevation is provided by either a high energy electric arc or a pilot ignitor flame. Improvements are now available in these components and will be discussed shortly. When proper outlet temperature is reached, a permissive is cleared to begin injecting pulverized coal into the furnace. In an Alstom-designed Burner Management System (BMS), 3 out of 4 of the ignitors of the elevation being started must be proven to be supplying the proper ignition energy prior to feeding the elevation with pulverized coal. Once fuel is being injected and sufficient air and ignition energy is present, combustion begins. A specially designed flame scanner “proves” the existence of stable flame. This is critical, since furnace explosions might be caused by continuing to inject fuel into a boiler that does not have stable combustion. An elevation is proven stable and ignited when 2 out of the 4 flame scanners near that elevation vote to prove flame. Additional elevations of coal fuel can now be brought into service using the same procedure. Generally, tangential boilers use 2-3 elevations of coal admission assemblies to achieve a stable low-load condition. In the case of an 800 MW boiler described, minimum load on coal would generally be around 250 MW. The burner’s ability to keep a stable attached flame and the ability of the flame scanners to reliably prove flame is generally the limiting factor in low-load operation. In Europe, where stabilizing fuel such as oil and gas is at premium price, devices such as Alstom RSS3 system have allowed lower loads by more sophisticated methods of detecting flame instability. Typically, above 30 percent load, Alstom’s burner management system allows additional flexibility in bringing adjacent elevations of coal in and out of service under certain operating conditions. The individual coal compartment assemblies have a typical lifetime of 3-5 years, depending on wear rates from abrasive coal and heat damage to the tip from flame front location. Wear in both the stationary nozzle and on the
Figure 2. An oil-fired warm-up gun in service.
Figure 3. A T-PRO™ coal compartment assembly.
nozzle tip is rarely uniform, since the coal and air feeding the coal compartment assembly tend to form “ropes” of high concentrations of coal, which wear holes in specific locations rather than create a uniform loss of material. These ropes are formed as the coal and air two-phase mixture winds its way through the various elbows in the coal piping system. Replacement of a coal compartment assembly requires partial disassembly of the windbox and coal pipe, with
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FEATURES Table 1 – Coal Compartment Assembly Lifetime Limiting Component
Traditional approach
State-of-the-art
Nozzle Tip
304 or RA253 fabrications from plate Lifetime 3-5 years
Fabricated or cast HN SS tips with heavy weld overlay Lifetime 5 years + Flame attachment features for low load operation
Stationary Nozzle
Vacuum ceramic lined for wear protection Lifetime limited by tile adhesion
Weld overlay with anti-roping fuel head Lifetime 10 years + Field repairable
Coal Head
Ductile iron
Ductile iron with CFD designed anti-roping vanes
Flame Scanner
Analog visible light flame scanner
Full digital, full light spectrum for coal, gas and oil flame detection Integrated flame temperature measurement Boiler stability/flame monitoring
Oil Gun Ignition
Retractable high energy spark ignition at 4 joules
Retractable high energy spark ignition at 12 joules
Natural Gas Igniters
Pipe and side igniters with eddyplate technology
Bluff body technology supporting igniters over 30 MBTU
removal from the rear. Failure to maintain the integrity of the coal compartment assemblies leads to fuel leaking into the windbox and potentially creating windbox fires, which will cause major damage and downtime. An additional limitation on coal compartment assembly lifetime is the high heat experienced at the nozzle tip. The nozzle tip is constructed of stainless steel (usually grade 304 or RA-253) which allows operation in measured temperatures up to 2,100°F. Flame front location is set by a combination of the windbox fuel air damper position, primary air/coal velocity and mass flow, coal reactivity and overall furnace heat release per area. If designed correctly, the flames will be close to the nozzle tip, but not directly impinging on the metal surfaces. Scenarios that limit flexibility are typically: • Problems with coal compartments, mechanical integrity limit run time • Cold starts take longer than desired due to problems with warm up guns or ignitors • Increasing load takes longer than desired due to difficulty in get-
Figure 4. T-PRO™ fuel heads ready for shipment.
Figures 5A and 5B: Wear rates of elbow and coal nozzle with (left) and without (right) CFD designed turning vanes.
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Figure 6. Coal nozzle and tip after two years of service with abrasive fuel.
August 2014
FEATURES ting 3 out of 4 ignitors proven of each elevation • Low load operation is limited by difficulty proving flame Often, plants will call out additional electricians and I&C personnel during startups and load changes in expectation of problems with equipment.
Upgrades available Table 1 summarizes the issues, traditional approaches and the latest approaches for maximizing operational flexibility of burner and ignitor systems for tangentially fired boilers.
Figure 7. Hardfacing applied to coal nozzle tip.
Coal compartment assembly Alstom’s longest life coal compartment assembly, designed for 6-year service life, consists of three components, shown assembled in Figure 3. It is designed to address the three major issues seen in operation. These are: 1) Overall mechanical erosion caused by coal ropes; 2) Failure of the coal nozzle tip from overheating and stresses produced from high differential temperatures inside the coal nozzle tip; and 3) Integrity of the bonding of ceramics to prevent mechanical wear (used in some units). The overall design is based on computer modeling of the coal air stream flowing into the assembly and finite element modelling of stresses in the nozzle tip. The coal head is shown in Figure 4. It is designed with turning vanes to break up coal ropes and uniformly directs coal down the stationary coal nozzle, substantially reducing erosion. The vanes in the coal head are made of nitride bonded silicon carbide, an extremely wear resistant material. Should the vanes have to be replaced, the coal head cover can be easily removed, allowing access for replacement. Figure 5 shows the erosion rates for a standard coal compartment assembly and erosion rates for a coal compart-
ment assembly equipped with the computer designed rope breaker and turning vane. With the improvement in flow field, weld overlay technology can now be used in the stationary nozzle. This allows long life, simplified installation and the ability to
August 2014 ENERGY-TECH.com
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FEATURES Flame scanner New options in flame scanning allow multiple fuels to be detected and burners to be operated at the lowest possible safe coal firing rate. Flame scanners incorporate the speed and precision of Digital Signal Processing (DSP), as well as full flame detection in multiple light bands. Use of infrared, visible and ultra-violet detectors allow the flame scanner to register gas, oil and coal flames. The Perfecta Flame Scanner features a unique detector Figure 8. Alstom Perfecta Flame Scanner measures light from IR to UV with integrated flame temperature measurement. application that can compute local flame temperature. Burner flame temperature is a significant indicator of the quality of the combustion process, as well as an indicator of NOX produced and local air/fuel stoichiometry. Flame temperature is important information used by the plant operators to improve overall boiler performance. A photograph of the Perfecta Flame scanner is shown in Figure 8. Figure 9 shows the level of information available and how the scanner reacts to a change in fuel type. In the upper corner of this figure a flame spectrum is shown along with the calculated temperature. Testing has shown ability to measure temperature with resolution and repeatability of 50°F-100°F. Figure 9. Flame scanner recognizes fuel change and measures flame temperature.
field repair any minor wear issues. The weld overlay is much more rugged than ceramic tiles in unusual operating circumstances such as mill excursions, small fires and the like. A photograph of a coal compartment equipped with the coal head and weld overlayed stationary nozzle and tip is shown in Figure 6. Finally, the stainless steel coal nozzle tips have been upgraded with two new technology items. Fabricated tips are now designed with stress relieving features that allow the inner and outer shells to expand at different rates. Nozzle tips are now available as castings, and both the fabricated and cast tips can be overlaid with two passes of erosion resistant weld overlay. This is shown in Figure 7.
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Conclusion Flexible operation requires reliability from the burners, ignitors and controls. The major technology direction is longer service life, higher reliability and improved designs to allow lower load operation. An additional trend is use of natural gas for ignitors and warm up. Improvements from many vendors are now available for nozzle tip, stationary nozzles, coal heads, ignitors and flame scanners. ~ Jim Sutton is director of Growth Initiatives in Alstom’s Boiler Service Organization. He has more than 30 years of experience in power generation and is a member of ASME and a licensed professional engineer in the state of Connecticut. He has been awarded six patents and presented papers on topics of interest to power plant operators. Areas of special interest include boiler reliability, efficiency and advanced controls. You may contact him by e-mailing editorial@woodwardbizmedia.com.
August 2014
FEATURES
Power generating asset management By Komandur Sunder Raj, Energy-Tech contributor
This article provides an overview of current standards and initiatives that are involved in developing and implementing an optimum power generating asset management (PGAM) program. The article highlights the need for a holistic approach to optimizing the performance of asset management on a continuous basis by integrating various disparate functions.
Introduction Power generating facilities are capital-intensive and represent sizeable investments for power plant owners (PPOs). With the power industry undergoing transformative changes relating to people, processes and technology, PPOs are increasingly coming under pressure to optimize the value of their power generating assets. This entails designing and implementing a prudent PGAM program to minimize the total cost of ownership and maximize return on investment. Consolidation in power plant ownership has resulted in PPOs maintaining large fleets. Consequently, an optimum PGAM program has to address issues pertaining to the capacity, availability, reliability and efficiency (CARE) of not only individual plants, but also entire fleets. Factors that need to be considered include performance, condition and health, operation and maintenance practices, equipment reliability and environmental compliance. On a fundamental level, since power generating assets comprise of both physical (tangible) and non-physical (intangible) assets, it is impossible to design and implement an optimum PGAM program without addressing people, process and technology.While technological advances and tools are enabling automation, and thus facilitating improved and cost-effective means of monitoring performance and condition of equipment and processes, these still require a knowledgeable and well-trained workforce.The workforce has to be trained in power plant equipment, systems and processes and their interaction.They need to be trained in use of technological tools that are being utilized to monitor performance and condition of equipment, in conducting diagnostics and taking prompt preventive/corrective action. Since power generating assets are very complex and require considerable knowledge, expertise and experience for their management, many PPOs are struggling with their asset management strategy as they look to standardizing, developing and implementing policies across the enterprise and fleets. Standards for optimum asset management 1. Public Available Specification (PAS) 55 The British Standards Institution, in collaboration with the Institute of Asset Management, issued in 2004 the first internationally recognized specification PAS 55 Parts 1 and 2 for asset management. This was subsequently updated in 2008. Part 1 covered optimum management of physical infrastructure assets, while Part 2 provided guidelines for the application of Part 1.
Figure 1. PAS 55 Factors for optimum management of physical assets
Part 1 describes asset management as the systematic and coordinated activities and practices through which an organization optimally and sustainably manages its assets and asset systems, their associated performance, risks and expenditures during their life cycles for the purpose of achieving its organizational strategic plan. Part 1 describes the requirements for best practices in management of physical assets and asset systems during their life cycles. Since management of physical assets is inextricably linked to the management of other asset types, these include human assets, information and knowledge, and financial resources, as shown in Figure 1. Figure 2 shows the PAS asset management structure comprising of: Plan, Do, Check and Act, and associated activities. PAS 55 has been adopted widely as a tool for integrating and improving business practices, enhancing performance and assuring greater consistency and transparency.
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FEATURES Power generating assets can benefit from an integrated approach, since the value of whole life cycle for various phases, from conceptualizing to decommissioning of assets, has been amply demonstrated for capital-intensive industries and environments, as shown in Figure 3.
Figure 2. PAS 55 Asset management structure for plan, do, check & act
2. International Organization Standards (ISO) 55000 In 2014, a new standard for asset management, ISO 55000, was introduced that incorporated updated information from PAS 55. ISO 55000 represents a holistic approach to asset management and defines asset management as “coordinated activity of an organization to realize value from assets.” It consists of three documents: 1. ISO 55000 – Overview, principles and terminology 2. ISO 55001 – Management systems – Requirements 3. ISO 55002 – Management systems – Guidelines for the application of ISO 55001 Elements that were combined in PAS 55 Part 1 were split into ISO 55000 and ISO 55001, with the former containing introduction, key terms and definitions and the latter incorpo-
Join Energy-Tech’s Sept. 30 webinar on predictive maintenance technology and techniques with Komandur Sunder Raj at www.energy-tech.com rating the requirements specification. ISO 55002 corresponds directly to PAS 55 Part 2, providing guidance on the interpretation and application of the ISO 55001 requirements. The benefits of implementing ISO 55000 can be substantial for PPOs with a fleet of power generating assets since they can utilize a standardized and consistent approach for sharing resources, knowledge, experience and technology. The holistic view espoused in ISO 55000 enables PPOs to achieve excellence at both the organizational and plant levels. Figure 3. Power generating asset life cycle
Integrating asset performance management Doing more efficiently with less entails optimum use of people, process and technology. Technological tools and software now permit an integrated approach that addresses equipment, plant and fleet performance considering asset health, operational efficiency, energy usage, emissions and maintenance. Using advanced analytics and business intelligence tools, the tools permit a better understanding of asset health, cost and operational value for an entire fleet. In addition, by integrating asset management, predictive analytics and key performance indicators (KPIs), the tools facilitate informed timely decisions for unit-based generation load dispatch, maintenance and operations. An example of how the various systems may be integrated for optimum PGAM is shown in Figure 4.
Figure 4. Integrated approach for optimum PGAM
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Current initiatives in PGAM The Electric Power & Research Institute (EPRI) has been at the forefront in several initiatives relating to PGAM. August 2014
FEATURES Some examples include: • Performance/Condition Management • Identify new technologies and processes to improve operational flexibility of power plants. • Asset health management to assess and compare the health status of numerous dissimilar assets across a system, unit, plant or fleet. This includes operational trends, material conditions, performance and efficiency, maintenance strategies and actions, and many other elements that contribute to an asset’s overall health. The program provides the structure and processes to integrate data and information from a variety of sources, uniformly assess these data and information, and – ultimately – produce an objective comparison of the health of multiple assets. • Improve life and performance of major power plant components, including boilers, turbines and auxiliary systems. • Maximize the value and life of assets through collaborative and fleet management approaches. • Design and test sensors for realtime monitoring to improve availability, reliability and performance of turbine blades, emissions controls and monitors and other compo90° Prism & nents. Close-Focus • Emissions Management tips available! • Develop technologies to optimize power plant water use, wastewater treatment for pollution controls, water reclamation and reuse. • Evaluate advanced emissions monitors and controls and improve combustion performance.
services for improving and maximizing the performance, capacity, availability and reliability of power generating assets. He has worked with GP Strategies Corp., New York Power Authority, Raytheon Engineers & Constructors, Burns & Roe, and Stone & Webster Engineering Corp. Sunder Raj has authored, presented and published more than 40 papers and articles and is a life member of the American Society of Mechanical Engineers (ASME). He has a bachelor’s degree in Mechanical Engineering from Osmania University, Hyderabad, India, and a master’s degree in Engineering Management from Northeastern University, Boston, Mass. You may contact him by emailing editorial@woodwardbizmedia.com.
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Summary & Conclusions Various challenges have created the need for PPOs to increasingly harness technological advances and tools to optimize PGAM. Given the disparate tools that are being used to track the performance of power generating assets, the future course of action to optimize power generating asset value might very well be an integrated and standardized approach that leverages the functions of different tools. ~ Komandur Sunder Raj is founder and owner of Power & Energy Systems Services. He has more than 45 years of experience providing training, consulting engineering and software applications
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RegULATIONs Compliance
Plant operating procedures to reduce error and improve safety By Neva Espinoza, Electric Power Research Institute
In the face of a challenging economic and regulatory environment, some power generation companies have found ways to improve the safe, reliable operation of their plants without increasing cost.To facilitate this kind of beneficial change, these companies are creating and implementing well-written operating procedures. Fostering a culture of strong power system fundamentals, unit-specific systems knowledge and effective use of procedures has allowed many stations to improve performance in both normal and emergency situations. The Electric Power Research Institute has conducted research to compile best practices on writing and using effective power plant operating procedures.This research has helped identify the characteristics of effective procedures, procedure contents and level-of-detail, and the inclusion of human performance tools to reduce human error and improve safety.
Operating procedures Standard operating procedures are used in most businesses and industries to assist in the safe and efficient operation of those companies. Operating procedures detail the regularly recurring work processes that are to be conducted or followed within an organization.They document the way that activities should be performed to facilitate consistent conformity to technical requirements and support the continued safe and regulatory compliant operations of a facility. Effectively managing a program of procedures is essential to maintain the highest level of plant configuration and status control, minimize human performance errors, respond quickly and confidently to off-normal events, provide a consistent method of accomplishing a task and ensure that industry best practices are used. In today’s power industry, operating procedures also fulfill a critical function in dealing with staff turnover, capturing the knowledge of experienced staff before they leave and passing it on to newer employees. “Written procedures are the best knowledge transfer tool for new hires,” said Dwayne Coffey, operations program manager at Luminant, who has been writing procedures for 25 years. “It’s a whole lot more efficient and reliable to give new employees a procedure to read and discuss versus verbal instructions that will have to rely on their memory.You also help to ensure consistent results. If you write it down, and do it the same way every time, then obviously the results should be the same.” Operating procedures are intended to be specific to the organization or facility whose activities are described and to assist that organization in ensuring consistent and proper operation of plant equipment. 14
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When procedures are required Not all plant activities require the detailed aspects of a procedure. However, many tasks do need rigorous consistency of performance. In these cases, the expectations can be articulated via a program that establishes the mechanism (procedure) for company standardization, industry alignment and personal accountability. A prime example of the need for good procedures and their usefulness is implementing and demonstrating compliance with North American Electric Reliability Corp. (NERC) standards. To ensure grid reliability, NERC established standards that apply to generating facilities and the organizations that operate them. To achieve compliance with these standards, plants need to have a mechanism (such as high-quality procedures) that describe both the programmatic aspects of compliance, as well as detailed instructions that ensure that the appropriate actions are taken in the correct manner to maintain compliance. Reasons for “proceduralizing” tasks include the following: • Personnel have the necessary information to enable them to do their jobs and make decisions within defined parameters. • Personnel understand the limits of the task without having to use trial-and-error methodology. • Concise procedures eliminate the need for supervisors to micromanage every task. • Procedures that contain precautions and safety considerations help improve employee safety. • Procedures that include best practices and use of human performance tools help to reduce errors and drive human performance improvement, resulting in improved organizational results. • Procedures help to identify vulnerable components and add to the protection of plant systems and equipment. Qualities of good procedures The quality of a procedure directly affects how well that task is performed.The probability of human error increases significantly when procedures are poorly written. What makes a good procedure? Procedures must be accurate — with the content organized sequentially, for a specific recurring task, having a measurable outcome. Other important components of a quality procedure include: • Consistency and clarity • Stated level-of-use • Detailed step-by-step communication of the task at hand • Use of standardized formatting and document layout • Inclusion of key safety, health, environmental and operational information necessary to properly perform a job • Aligned with plant nomenclature and labels August 2014
RegULATIONs Compliance “Good procedures,” Coffey said, “are written in checklist form. Each step has only one action item and one task to do in that step.The process doesn’t overload users, but makes it easy for procedures to be successfully performed.The procedure uses a consistent format and numbering. It emphasizes action verbs and avoids vague terms such as ‘periodically’ or ‘normal,’ which mean different things to different people.” Most poorly written procedures, according to Coffey, contain one or more of more than 25 “traps” that go undiagnosed. One common trap involves the inclusion of “field decisions,” where the procedure lacks specific instructions and instead forces users to make a decision on their own, out in the plant or in the field, without a supervisor.Without clear guidance, field decisions require users to choose from multiple options, determine if certain sections of the procedure apply, or determine if certain conditions exist. Such field decisions have an error rate 11x higher than a clear, unambiguous, well-written step. Additionally, procedures should utilize Warnings, Cautions and Notes as special messages to the user, inserted before the step to which it applies.These messages should be placed in a text box or highlighted to differentiate them from procedural text and from each other.They should be short, concise sentences that contain information important for the user to know. Figure 1 is an example of a “Caution” statement.
Level-of-detail Procedures differ in the level-of-detail, which varies according to: • Experience level of the procedure user: As the experience level of the procedure user increases, the level-of-detail in the document can decrease. However, procedures should be written mindful of the influx of newly hired individuals who might have less experience. Procedures should be written for the novice or less experienced staff member who will perform the task, not the expert, ensuring all key steps and information needed to complete a task successfully are available. • Complexity of the task: The more intricate the task, the more detailed the document must be. • Frequency of the task: Many tasks are performed infrequently; therefore, the level-of-detail must increase. • Need for consistency of the task: The greater the need for consistency of the task, the more detailed the document must be. Level-of-use Every procedure should have level-of-use displayed prominently on each page, usually in the document’s header.This clarification
Figure 1. An example of a “Caution” statement.
sets clear expectations to plant operations personnel when each procedure should be used. Industry standards for designating levels-of-use are: • Continuous use. Continuous use documents are written instructions giving step-by-step directions in the performance of a task, expected to be used in-hand by the user. The type of activity that requires a continuous use procedure is one for which the consequences of an improper action are immediate and not reversible. Errors could seriously harm personnel and equipment. Compliance to the document is mandatory. Good examples of continuous use procedures are unit startup or shutdown evolutions, which take a large amount of coordination over several hours. • Reference use. Reference use procedures are recommended for activities for which the consequences of an improper action are not immediate and are not irreversible, and for which the task has a low degree of difficulty. Sections of this document are reviewed and briefed prior to performance. In many cases, these documents might be found at the job site, but are not necessarily in the hand of the operator
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RegULATIONs Compliance being followed step-by-step. Some examples of reference use procedures are swapping lube oil filters or backflushing heat exchangers. • Information use. The designation of information use for a document indicates that a task might be performed from memory, but does not relieve the user of reviewing the document and performing the work in accordance with the instructions. This designation is commonly used for activities that are frequently performed, do not involve complex steps, do not involve direct contact with critical plant equipment and cannot have an impact on safety, the environment or plant reliability if performed incorrectly, and when the activity is within the skill, training and qualification of the worker performing the task. In many cases, these procedures will not be found at the jobsite at all. Some examples of information use procedures include operator rounds, maintaining system temperatures and pressures, and pumping sumps. • Multiple use. A document is designated as multiple use if it contains sections that are classified as reference use and also sections that are classified as continuous use. An example would be an information use procedure that contains a required checklist that is a permanent document.
Improving safety with operating procedures and human performance tools Humans make mistakes — compounded by the failings of equipment, flawed processes and programs, and uninformed decisions.Well-written procedures, however, can help reduce errors and improve safety. To reduce these errors while following procedures, it is critical for facilities to implement strong procedure use and adherence guidelines. A key part of ensuring procedure adherence is the implementation of Figure 2. An example of placekeeping markup placekeeping techniques. Placekeeping is the act of marking steps in a procedure as they are completed or marking the steps that are not applicable. Although placekeeping is not appropriate for all procedures, and is normally based on the level of use designated, placekeeping allows a performer to ensure the correct actions are performed in the proper sequence, prevent missing or skipping steps, and minimize the potential for human error. To properly placekeep, an operator will perform three key actions: 1. Circle the step number prior to starting, indicating the step is in progress. 2. Make a slash through the circle once the step is complete, indicating the step has been completed. 3. Make a step N/A (not applicable) if it is not relevant to the task at hand.
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“Operating procedures can specifically call out safety practices,” Coffey said. “For example, when you’re racking in a 480-volt breaker, the job has arc flash requirements.That means workers have to don special personnel protective equipment (PPE).The procedure includes that step in the instructions. So the workers don the equipment before they get to the step where they close the breaker.They don’t have to remember to get the PPE; it’s there in the procedure.” In addition, common “human performance tools” can be embedded in operating procedures to help identify and mitigate hidden conditions and situations that could cause injury to people and damage to the plant. Human performance tools include the following: • Self-checking (STAR). Self-checking, or STAR, is an effective technique used during tasks or activities that are sometimes performed with little conscious thought. STAR stands for Stop-Think-Act-Review. STAR is an effective tool to help focus operators’ attention on an activity before it is performed. When operators’ attention is focused, they take a moment to think about the intended action and results prior to performance. • Peer checking. Peer checking is an error-prevention technique involving an agreement between two operators (performer and checker) prior to the performance of a specific task. • Independent verification. Independent verification has two or more individuals who are working independently of each other checking the results after the initial work has been completed. Much like the self-checking and peer checking, independent verification confirms that the right work was done on the right component at the right time. But unlike the previously mentioned checks, independent verification occurs after performance of the work, not during or after the job is complete. • Pre-job brief. A pre-job brief is a meeting of the workers assigned to the task and the pertinent supervisors. The brief details the work to be covered. These instructions include each person’s role and experience performing the task, which critical steps are involved that may need rehearsing, which resources are to be used, precautions that need to be taken (job safety analysis), any contingencies that need to be planned and all relevant operating experience. Incorporating both guidance and requirements to accomplish these and other human performance tools within procedures helps reinforce a culture of effective human performance activities. ~ Neva Espinoza is manager of the Operations Management and Technology Program at EPRI, which focuses on processes and related technologies that improve plant operations, support increased plant reliability and flexibility, and reduce operating costs. Previously she worked with Knolls Atomic Power Laboratory, Exelon and NRG in Engineering and Plant Operations. You may contact her by emailing editorial@woodwardbizmedia.com.
August 2014
MR. MEGAWATT
Figuring out a high heater problem By Frank Todd, True North Consulting
This story is about a utility engineer trying to decrease her plant’s heat rate and keep the environmental “federales” off her back. There I was, at the latest conference trying very hard not to look like a slimy contractor, when up comes a bright young engineer with a very concerned look on her face. Staring down at me from her 6´ height, Ragnhild Ragnvaldsson (not a password, but a Swedish name) introduced herself as Reggi; for which I was very thankful (pronunciation of even easy names has always been my downfall). Reggi was the chief engineer at Inner Karlstad Electric American (IKEAPS) which was located as far south in Minnesota as you can go and still enjoy year round ice fishing. Reggi told me the saga of a visit her plant had from the EPA regarding new rules that meant the plant had to dramatically decrease its heat rate. One of its units was on the block unless plant engineers could come up with a way to chop 6 percent. IKEA unit 6 was a fairly small unit, but had been very reliable and had a good capacity factor. Reggi was tasked with coming up with some ideas on the turbine cycle, so she contacted some vendors and they proposed a variety of widgets that would solve all her problems. Reggi had been around the Melodifestivalen before and knew that one must take the meatball with a little salt. She asked us to take a look and see if we could help her figure out what to do. So I took off my name tag and grabbed Richie Reynolds to head over to IKEA power station. The initial task was to try to figure out where the plant was currently operating with respect to its design conditions, so the first thing we did was come up with some correction curves for the key plant parameters by performing sensitivity studies with a thermodynamic computer model of the plant. From these curves we would be able to calculate the current state of the plant to identify any significant losses. The curves developed are shown in Figures 5-9. From these curves we were able to calculate the effect of various plant parameters being off design. This also could be done for the boilers, but Reggi was just interested in the turbine cycle. The results of this analysis are shown in Figure 1, and provide information on the parameters in the plant that the operators might be able to control to get back some of their losses. Figure 1 shows that the largest effect on heat rate is the throttle temperature and that there are some areas where they are doing better than design (throttle pressure and final feedwater temperature). So there was hay to be made by going after some of the controllable parameters. The condenser pressure was much lower than design, so we had to correct for that when doing this accounting. While Reggi was happy with this, she was not at all satisfied that she could avoid the axe just based on the controllable parameters.
Table 1 – Accounted Deviations – Heat Rate (+Loss/-Gain) Units
Current
Design
Delta
Btu/kw-hr
Throttle Temperature
°F
960
1000
-40
45
Throttle Pressure
psia
1485
1465
20
-11
Hot Reheat Temperature
°F
994
1000
-6
9
Final Feedwater Temperature
°F
459
455
3
-4
Superheat Spray
lbm/hr
9348
0
9348
1
Condensor Back Pressure
in hga
1.49
3.50
-2.01
-389
Accounted Deviations
-349
Unaccounted Heat Rate and Load Deviations
388
Figure 1. IKEA-6 Controllable Losses
Figure 2.
Looking at the unaccounted heat rate losses in Figure 1 told us that there was a possibility of some cycle degradation that, if corrected, could help the situation. Now we started looking into the physical changes that could help. We evaluated the turbines and the feedwater heaters to identify the problems there. Figure 2 shows the turbine efficiency differential from design. There was a very good indication that something was amiss in the turbine. Next,
August 2014 ENERGY-TECH.com
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MR. MEGAWATT
Figure 3.
Figure 4.
Figure 5.
Figure 6.
we took a look at the feedwater heaters, Figure 3 shows the Over a nice bottle of Svedka, we discussed all the results. feedwater heater Terminal Temperature Difference (TTD) for If Reggi could fix the turbine and get a handle on some of each heater. TTD is a good indicator of heater efficiency. This the controllable parameters, she might be able to stave off the showed that heater 3 had some problems. We suggested that environmental inquisition and save some fuel costs to boot. Reggi take a look at the heater level to make sure it was not She was appreciative of the fact that she had the ability to too high. understand where she could improve her heat rate, and also All that figuring had us exhausted, so we where there would not be much benefit. took a break to go out for dinner. Over a Find additional figures at She hoped her bosses would be so happy nice plate of Swedish meatballs, Reggi told with the results that they could also focus us that she was satisfied with the results, but www.energy-tech.com on providing the necessary resources to again, where was the biggest impact? The make other plant improvements. next step was to calculate the effect of each possible change Richie and I finished our drinks, hopped back in the pudto the turbine cycle with respect to heat rate. This would dle jumper and headed home. ~ provide the ammunition to go after the most important items. Mr. Megawatt is Frank Todd, manager of Thermal Performance The next morning, Richie was back at the computer for True North Consulting. True North serves the power industry tearing up the thermodynamic model to configure all the in the areas of testing, training and plant analysis. Todd’s career, projected changes. The result of his industrious keyboard spanning more than 30 years in the power generation industry, manipulations is displayed in Figure 4. Richie calculated the has been centered on optimization, efficiency and overall Thermal Performance of power generation facilities. He can be contacted at effect of bringing the turbine and feedwater heaters back to editorial@woodwardbizmedia.com. design conditions. It is clear that the biggest change was in the LP turbine section and that the feedwater heaters did not provide much benefit. 18
ENERGY-TECH.com
August 2014
ASME FEATURE
Economic design of hybrid wet-dry cooling systems By R.W. Card, CB&I
All thermal power plants release waste heat to the environment. The waste heat ranges from about 70 percent of the energy in the fuel for a traditional Rankine-cycle nuclear power plant to about 40 percent for a modern combined-cycle gas turbine plant. The waste heat must be transferred from the working fluid to the environment. For a steam turbine-generator, the working fluid is turbine exhaust steam, and the transfer of waste heat occurs in the condenser. If the temperature of the condensing steam is lower, the efficiency of the power cycle is higher. Most recent power plants use the surface condenser and cooling tower, as shown in Figure 1.[5] The exhaust steam condenses on the outside surface of a bundle of tubes, which are cooled by a continual flow of circulating water inside the tubes. The circulating water (CW) is cooled by evaporation and sensible heat transfer in the cooling tower, known as a “wet tower.” The lowest water temperature achievable is limited by the wet-bulb temperature of the air entering the tower, TWB. This system provides a reasonable exhaust pressure for the turbine, but consumes water by evaporation. (Evaporation provides about 90 percent of the heat transfer duty at design conditions.) Many recent power plants use air-cooled condensers (ACC). The exhaust steam condenses inside an array of finned tubes which are cooled by a continual flow of air outside the tubes. The heat transfer occurs by convection, with no evaporation, so there is no consumption of water; it is “dry.” However, the lowest steam temperature achievable is limited by the dry-bulb temperature of the air entering the tower, TDB. The TDB always equals or exceeds the TWB, so the ACC system generally provides a somewhat higher exhaust pressure for the turbine. This penalizes the cycle efficiency, particularly on hot days with low humidity (high TDB, low TWB). A hybrid cooling system combines wet and dry cooling:[4] “This arrangement allows most of the heat to be rejected to the atmosphere on cooler days, avoiding the use of cooling water, while maintaining the power plant’s thermal efficiency during hot days, with the wet tower taking part of the cooling load.” However, the equipment for dry cooling is much more costly than the equipment for wet cooling. Also, dry cooling requires much more auxiliary power when all fans and CW pumps are included. The main goal is to reduce water consumption by using dry cooling for as great a portion of the duty as possible, while minimizing the penalties to cycle efficiency. The other goal is to properly evaluate the cost of water consumption and the value of net generation. The capital cost of
August 2014 | ASME Power Division Special Section
Figure 1. Conventional “wet” cooling system
a hybrid cooling system cannot be determined until the optimum trade-off of water consumption and power generation is determined.
Background The pressure in the condenser ranges from 1.5˝ Hg A to 5˝ Hg A, for a typical plant with a cooling tower, so the steam temperature is 92°F to 134°F.[1] In a practical condenser, the steam can be condensed at about 5°F above the temperature of the warm water leaving the condenser. This temperature difference is called “Terminal Temperature Difference” or TTD.[2] In practical cooling towers, the water can be cooled to 5°F or 10°F above the wet-bulb temperature of the air entering the tower. This temperature difference is called “approach.”[3] In an ACC, the key parameter is the approach between the steam temperature and the dry-bulb temperature of the air entering the ACC. This is called “Initial Temperature Difference” or ITD. A typical value is about 30°F. The CW lost by evaporation in a wet cooling tower must be replaced by a supply of water, called “makeup.” The makeup is not usually pure, and any contaminants in it do not evaporate but will gradually concentrate in the CW. In order to control the concentration, a portion of the CW is discharged as “blowdown;” this is replaced by additional makeup water. The ratio of the contamination of the CW to that of the makeup water is called “Cycles of Concentration” (COC). Some CW is also lost as droplets entrained in the air stream exiting the tower; this is called “drift.” The evaporation, makeup, blowdown, drift and COC are related by the following equations.[3]
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AsmE FEAtUrE Table 1 – Example Power Plant Gas turbine combined cycle (GTCC) Mode
2x1 Maximum output
Net generation, nominal
645 MW
Net efficiency, nominal
51.3%
Net heat rate, nominal (LHV)
7013 kJ/kwh (6647 Btu/kwh)
Heat-recovery steam generator (HRSG)
Triple pressure
Steam turbine
Single reheat
Throttle pressure, nominal
132 bar ABS (1900 psig)
Table 2 – Cooling Systems CW flow rate in condenser
40778t/h (89.9x 106 lb/hr)
Velocity in condenser tubes
2.6 m/s (8.5 ft/s)
Configuration Cleanliness factor
21.6C (71 F)
CW outlet temperature (THOT )
32.6 C (90.7F)
Head loss in condenser
0.646 bar (9.36 psi)
Head loss in CW piping
0.658 bar (9.54 psi)
Elevation of inlet of cooling tower
551.7°C (1025°F)
CW pressure at inlet to cooling tower
Reheat temperature, nominal
554.4°C (1030°F)
CW cycles of concentration
325.5 MW
Condenser pressure
0.070 bar ABS (1.019 psia, 2.07˝ Hg A)
Air temperature, entering dry-bulb
14.4°C (58°F)
Air temperature, entering wet-bulb
9.0°C (46.4°F, 40%RH)
Air pressure
0.99 bar ABS (14.34 ps)
85%
CW inlet temperature (TCOLD)
Throttle temperature, nominal ST gross generation
2-pass
7.3 m (24´) 1.72 bar abs (24.92 psia) 5
Auxiliary cooling flow rate
1814 t/h (4.0 x 106 lb/hr) 46.6 x 106 kJ/hr (44.2 x 106 Btu/hr)
Auxiliary cooling duty
1855 x 106 kJ/hr (1758.2 x 106 Btu/hr)
Condenser duty Drift rate 0.0005%
0.2t/h (0.45 x 103 lb/hr)
Head loss in ACHE
0.345 bar (5.0 psi)
Nomenclature B COC D E EBONUS M MWGROSS MWAUX
MWNET TDB TWB TCOLD THOT
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m3/s (gpm) Flow rate of blowdown (Dimensionless) CW Cycles of Concentration m3/s (gpm) Flow rate of drift m3/s (gpm) Evaporation, expressed as a flow rate t/h (103 lb/hr) Bonus for evaporation of alternative cooling systems, expressed as a mass flow rate m3/s (gpm) Flow rate of makeup (MW) Gross generation of the ST in the combined-cycle plant (MW) Auxiliary power due to pumps for CW and auxiliary cooling water, and fans for cooling tower, ACHE, ACC and auxiliary cooling tower (MW) Net generation of the ST, pumps and fans in the ST cooling system °C (°F) Dry-bulb temperature of air entering the cooling tower or ACC °C (°F) Wet-bulb temperature of air entering the cooling tower or ACC °C (°F) Temperature of circulating water leaving the cooling tower or entering the surface condenser °C (°F) Temperature of circulating water leaving the condenser or entering the cooling tower
ENERGY-TECH.com
(1)
(2)
Hybrid cooling system This paper considers a hybrid system of the “indirect” or “series” design, as shown in Figure 2.[5] The warm circulating water from a conventional condenser is run first through an air-cooled heat exchanger (ACHE), then through a wet tower. The ACHE is an array of finned tubes, with warm CW pumped through the tubes and cool ambient air blown across the fins. The CW is cooled by convection in the ACHE, then further cooled by evaporation in the wet tower. The indirect system can be easily retrofitted to an existing plant, because the surface condenser and CW piping in the turbine building do not require any modifications. Also, the ACHE of the indirect system can be located some distance from the turbine building, because pressure drop in the CW piping does not have a significant effect on plant performance. The indirect hybrid system is arguably less effective than the “direct” or “parallel” hybrid design that uses the ACC for the dry cooling duty. However, the direct system requires a radically different configuration for the surface condenser, a large steam duct from the turbine exhaust to the ACC, and an ACC that is fairly close to the turbine building. Therefore, the direct hybrid
ASME Power Division Special Section | August 2014
AsmE FEAtUrE ASME Power Division: Heat Exchanger Committee
A Message from the Chair
Figure 3. Penalty on net generation
system is difficult to retrofit to an existing plant.[4] The direct hybrid system also is difficult to incorporate in a new plant if the turbine building is constrained to a standard design.
Combined-cycle power plant The impact of various cooling systems was examined by considering a typical combined-cycle power plant, recently designed and constructed. The plant included a conventional steam surface condenser and wet cooling tower. The heat balance models were prepared with the “Thermoflex” software,[5] and included manufacturer’s performance data for the gas turbines (GT), steam turbine (ST), condenser, cooling tower and other major equipment. The key features are shown in Table 1. For this study, the “maximum output” case was used, with the duct firing assumed in operation in order to maximize ST generation and duty in the ST cooling system. The heat balance models were used to predict the performance of the steam power cycle with the wet cooling tower at various ambient conditions. Then the models were modified to replace the wet tower with dry or hybrid systems, and the performance of the cooling systems was compared on the basis of net generation and water consumption. Design points for hybrid systems Two hybrid systems were considered for this study: one with 30 percent heat rejection in the dry tower at the design point, the other with 70 percent. A system with an ACC (100 percent dry) also was considered. The cooling systems were designed with the same condenser pressure, CW flow rate and ambient conditions as the wet cooling tower. Therefore, the steam turbine and condenser in the example heat balance can be reused with no change. The key features of the condenser and cooling systems are shown in Table 2. A power plant also has auxiliary cooling requirements, such as lube oil coolers and air compressors, which are often served by the CW system and increase the duty in the cooling tower. For the wet tower, the 30 percent hybrid and the 70 percent hybrid, the auxiliary cooling duty was included in the CW
August 2014 | ASME Power Division Special Section
Greetings from the ASME Heat Exchanger Committee! It is my pleasure to introduce our committee, which is a dynamic forum organized to advance the art and science of heat exchanger technology in the power generation industry. Through peer reviewed technical publications, panel discussions, meetings and short courses, the committee organizes the introduction of innovations in relevant technology, case and application studies and industry best practices that are communicated to ASME members, conference attendees and the public domain. During the year, committee members interact with each other to solve operation and maintenance issues on the systems and equipment within this committee’s focus via phone calls and/or email. We invite you to join us at our meetings, just contact me or any member you know or through the Heat Exchanger Committee Membership Coordinator Jim Mitchell at JEMPlastocor@aol.com or call at 724.942.0582. Our committee members are knowledgeable, committed and include an industry cross-section of acknowledged experts in their respective fields. The committee maintains active relationships with other industry organizations, such as HEI, EPRI, ASTM and CTI. This interface ensures a continuous and timely update of information on standards, codes and industry events. We meet twice annually to organize the delivery of valuable conference content. During July of last year, ASME Power 2013 was held in Boston, Mass., and the Heat Exchanger Committee hosted six technical sessions. An excellent example of the material presented at one of our technical sessions in 2013 can be found in this article; “Economic Design of Hybrid Wet-Dry Cooling System,” by R.W.Card of CB&I. I’m sure you will enjoy this timely and relevant article. Thank you and please consider joining us. Check our web site at http://divisions.asme.org/Power/Heat_Exchangers.cfm for more information. Sincerely, Suchat Sonchaiwanich, P.E. ASME Power Division Heat Exchanger Committee Chair Florida Power and Light Company Power Generation Division Engineering Technical Services Principal Engineer Phone: 561 691 2612 E-mail: suchat.sonchaiwanich@fpl.com
ENERGY-TECH.com
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ASME FEATURE Table 3 – Performance at Design Point Wet
30% Dry
70% Dry
Dry ACC
325.5
325.4
325.4
325.4
CW pumps, MW
3.0
3.2
3.2
0
Wet tower fans, MW
2.0
1.8
1.8
0
ACHE Fans, MW
0
2.4
6.3
0
ACC Fans, MW
0
0
0
4.56
Aux clg pumps, MW
0
0
0
0.03
Aux clg fans, MW
0
0
0
0.23
320.4
318.0
314.2
320.6
ST gross generation, MW
St net generation, MW Penalty of net generation, MW Evaporation, t/h (103 lb/hr) Bonus of evap, t/h (10 lb/hr) 3
0.0
2.4
6.2
-0.2
604.3 (1332.3)
423.5 (933.6)
214.0 (471.7)
0
0.0
180.8 (398.7)
390.4 (860.6)
604.3 (1332.3)
(4)
Also, the evaporation (E) for each cooling system was recorded. It is convenient to present the reduced evaporation for the alternative systems as a bonus by comparison to the conventional wet cooling tower.
(5)
Figure 4. Bonus on reduced water consumption
system. For the ACC, a small auxiliary cooling system with an independent ACHE was assumed. The model was run at the design points for all four cooling systems. The ST gross generation was recorded, as were auxiliary power for CW pumps and cooling system fans, and the ST net generation was computed by the equation:
(3)
It is assumed that all other auxiliary power (lighting, water treatment, lube oil system, controls, etc.) is not significantly affected by the choice of cooling system. It is convenient to present the net power for the alternative cooling systems as a penalty by comparison to the conventional wet cooling tower, computed by:
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ENERGY-TECH.com
Some water also is consumed as drift (D). However, the drift rate of 0.0005 percent is typical for modern towers, so the drift is small and is ignored in this paper. The results for the various cooling systems at their design points are shown in Table 3. The 70 percent hybrid consumes less water than the 30 percent hybrid or the wet tower, but also produces less net generation. The dry ACC consumes no water, and the net generation at the design point is comparable to the wet tower. In a typical power plant, the makeup (M) is water withdrawn from a source (such as a river) and the blowdown (B) is returned to the same source. However, in the Western U.S., water rights are priced based on water consumed – withdrawn from the source and not returned. Therefore, evaporation is a suitable basis for comparing the water conservation of various cooling systems. In other areas, where water rights are not priced by consumption, it would be necessary to compute a commodity price for the water used. This should include the cost of energy and chemicals for any required water treatment, and also the annualized cost of the water treatment system.
ASME Power Division Special Section | August 2014
ASME FEATURE Performance at off-design conditions In order to characterize the cooling systems on a year-round basis, the heat balance models were run at four other conditions and the results for hybrid and dry cooling systems were compared to the results for a wet cooling system. It was assumed that all portions of the cooling system (the dry tower, the wet tower and the ACC) would be operated with all their fans in service. This allows the use of the manufacturer’s performance curves, as represented in the heat balance model, to compute the performance of each portion. The penalty on net generation for the systems is shown in Figure 3. The dry ACC suffers a very large penalty on net generation when the TDB is high. The water consumption for the systems is compared to the wet tower in Figure 4. The hybrid systems use much less water than the wet tower (shown as a high bonus), and the dry ACC uses no water at all. When the dry-bulb temperature is higher than the design point, the dry portion of the hybrid systems takes a lesser proportion of the cooling duty. This is shown in Figure 5. The changing ratio of dry duty to wet duty suggests that the operating strategy may vary from season to season.
The proportion of duty might be shifted by operator action. During seasons in which water supply is limited or the price is relatively high, most of the fans in the wet section can be secured. The dry section will handle most of the cooling duty, with the wet section acting to reduce the CW temperature just enough to avoid alarms due to high turbine exhaust pressure. During seasons in which the price of power is relatively high, the fans in the dry section can be secured and the cooling system operated as wet. This increases the consumption of water, but also increases the net generation.
Economic impact The optimum design for the site depends on the relative prices of power and water. For this study, a location in Arizona was assumed (as typical of the Western U.S.), and the prices are: • Power: $40.00 per MWh[6] • Water: $5.1664 per 1,000 gallon[7] The penalty for net generation and the bonus for reduced water consumption were converted into operating costs for the ST cooling system. Baseload operation was assumed (720 hours/month). When the penalty for net generation exceeds the bonus for water savings, both expressed as dollars, then the “cost savings” are negative. The results are shown in Figure 6. When the TDB is moderate, the ACC is most economical. The water conservation, due to dry cooling, makes up for the lower gross generation and higher auxiliary power. However, on particularly warm days, the generation penalties of the ACC system are too great and it would be more economical to consume some water and maximize generation. The ACC alone does not have this capability, but a hybrid system does.
August 2014 | ASME Power Division Special Section
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ASME FEATURE components (CW pump, wet cooling tower, ACHE, ACC and surface condenser). Therefore, the test engineer should use all applicable codes to identify the instrument locations that will produce the data to completely characterize the system.
Figure 5: Proportion of dry cooling
Conclusion A hybrid cooling system can be designed for a combined-cycle power plant, so that the plant net generation is higher than with a dry ACC system, and the plant water consumption is lower than with a surface condenser and wet cooling tower. The design point for the hybrid system depends on the relative cost of water and power. This is an essential input to determining the capital cost, and it will also affect the layout of the system and the size required for piping, pumps, fans and so on. The hybrid cooling system may then be operated in different modes, trading off net generation and water consumption as required by seasonal or monthly conditions. If the price for water consumption can be established, the wet/dry flexibility allows plant operation to be optimized on an economic basis. Acknowledgments The heat balance model used in this study was prepared by Frank Senkel and Nick Zervos, also of CB&I, in the course of other work. Their detailed and complete product made the author’s work much easier. ~
Figure 6: Cost savings vs. wet tower
Performance testing A hybrid cooling system requires special features in the performance test procedure. The system might be designed for a certain proportion of dry cooling, but during the test might operate at a different proportion, as shown in Figure 5. It might not be clear if this is the expected behavior of the system, or is due to a performance shortfall in one component or the other. Therefore, the test procedure should include the measurements and calculations to determine the cooling duty separately in the wet and dry portions of the cooling system. If possible, the performance test for the cooling system should be simultaneous with the performance test for the overall plant or the ST. This will allow the quality of the exhaust steam to be calculated by heat balance[8]. The quality, together with the condenser pressure and condensate flow rate, will allow the overall duty of the cooling system to be calculated with minimum uncertainty. There is no ASME performance test code for hybrid cooling systems. However, there are test codes for each of the
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References 1. ASME, 2006, “Properties of Saturated and Superheated Steam in U.S. Customary and SI Units from the IAPWSIF97 International Standard for Industrial Use.” 2. HEI, “Standards for Steam Surface Condensers,” 10th edition, 2006, §2.16 & 4.1.2 3. Marley Cooling Technologies, “Cooling Tower Fundamentals,” 2nd edition, 1998, pp 14 & 23 4. Zammit, Kent D., “Water Conservation Options for Power Generation Facilities,” Power Magazine, September 2012 5. Thermoflow Inc., “Thermoflex,” version 21.0.1, Revision of November 7, 2012 (graphics were prepared with an earlier version) 6. FERC “OE Energy Market Snapshot,” Western States Version, November 2012 Data Updated December 4,2012, graph for Western Daily Index Day-Ahead On-Peak prices at Mid-Columbia, page 34 of 42, www.ferc.gov/oversight 7. Arizona Water Company “Water Rates – General Service,” White Tank system, Industrial commodity rates for each gallon used over 245,000, effective May 1, 2012 8. ASME PTC 30.1-2007 “Air-Cooled Steam Condensers,” section 4-4.3 Editor’s note: This paper, PWR2013-98111, 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.
ASME Power Division Special Section | August 2014
TURBINE TECH
Control system modernization increases reliability and improves owner’s maintainability for Michigan municipality By Kevin Giroux, Turbine Technology Services
Turbine Technology Services (TTS) successfully retrofitted two OEM control systems operating GE MS6001B Heavy Duty Industrial Gas Turbines for Holland Board of Public Works (HBPW) between the third quarter of 2013 and the second quarter of 2014. The city has a 138kV transmission loop with four gas turbines responsible for a portion of the 226 MWe internal generation capability. Three of the four gas tur- Figure 1. The new turbine control panel. Photos contributed by TTS. bines now operate with TTS-provided control sys• TMS-1000R Turbine Control System tems. These upgrades were necessary to increase system • TMS-1000G Generator Control, Protection and reliability and introduce additional versatility through Excitation System additional features. • TMS-1000 Human Machine Interface The OEM control systems were the original systems (HMI) System supplied with the turbines during the early 1990s – • Time Synchronization System now obsolete and presenting maintenance and reliabil• Inlet Fogging System Integration ity issues, the systems were scheduled for replacement. • Black Start Capability Though the City of Holland owns and operates several power plants, these particular gas turbine generators are Turbine control system critical to the electrical utility grid. They have the abilThe turbine control sysity to operate on either natural gas or distillate fuel, are tem was designed around operated at peak times and in critical demand situations, Rockwell Automation’s and the site where the units are located is unmanned, so ControlLogix® reliability is crucial. Programmable In order to address the customer’s primary concerns Automation Failure to properly of obsolescence, reliability, maintainability and overall system availability, TTS engineered, fabricated, installed ground rotating and commissioned a TMS-1000 Series Turbine and equipment can result in Generator Control System solution. Through the selecexpensive bearing, seal, & tion of platforms (hardware and software), TTS implegear damage. mented a fully integrated solution, consisting of the following major sub-systems: SOHRE TURBOMACHINERY® INC.
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Figure 2. Inside the new turbine control panel.
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Controller (PAC) platform. The ControlLogix® platform offers high-speed, high-performance and high-reliability that is ideal for gas turbine retrofit applications. The TMS-1000R turbine control system was implemented in a redundant configuration, designed with two identical ControlLogix® chassis, each containing a Processor, ControlNet, Ethernet and Redundancy module. The turbine Control and Protection application is automatically cross-loaded from the Primary to the Secondary controller. In addition, while scanning the program, the Primary controller automatically updates the Secondary with any data changes needed to keep it synchronized. In the event of the Primary controller failure, control is automatically switched to the Secondary chassis. Highest priority functions are guaranteed a ‘bumpless transfer’ during control switchover. The TMS-1000R system utilizes both Rockwell Automation’s ControlLogix® and Flex™ I/O modules. The I/O network is implemented with a multi-layer Redundant ControlNet Network. ControlNet uses the proven Common Industrial Protocol (CIP) to combine the functionality of an I/O network and a peer-to-peer network providing high-speed performance and advanced diagnostics for both functions. To increase the system’s tolerance to faults, triplicate field devices were distributed across three I/O nodes – both for discrete and analog devices. The system was configured to operate with two out of three devices reporting healthy. The existing vibration monitoring system was upgraded to a Rockwell Automation XM Condition Monitoring system and is configured per the OEM specifications for unit protection (alarm and trip levels). Within the XM system, TTS also included an independent electronic overspeed detection (EOSD) module to provide an extra layer of unit overspeed protection. The new Frame 6B Control and Protection application was developed using Rockwell Software’s RSLogix5000 programming software package (IEC 11313 compliant). The program is structured into easily navigated subroutines that
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Figure 3. Redundant processors installed.
Figure 4. A generator protection panel.
represent specific Gas Turbine routines. All sequencing, vided by the new automatic synchronizer. The synchroprotective and governor functions have been provided nizer will measure voltage and frequency on the generusing proven TTS algorithms that have been applied ator and the utility system, send proportional correction in numerous control system retrofits. The application pulses to adjust the governor and exciter as necessary, is open and unrestricted to HBPW; meaning that the and automatically close the breaker on synchronization permissive. This process now enables safe, secure, unatcontrol code will be accessible, offer complete system tended synchronization of generation onto the power maintenance (software edits, configuration changes and system. module additions/deletions) The new generaand allow for the ease of inteRead more about Turbine Tech’s tor protection system was gration into other plant-wide designed around Schweitzer systems. capabilities and applications at Engineering Laboratories www.turbinetech.com (SEL) digital protection relays. Generator control, New relays that perform the protection and required generator, transformexcitation system er and overall protective functions were incorporated The new TMS-1000G generator control system incorinto the system design to replace the existing elecporates the original control philosophy through newly tro-mechanical style relays. The new generator protection supplied components – analog display meters, control system addresses specific obsolescence concerns expressed switches, lockout relays, automatic synchronizer, synchby HBPW, and per their requirement is NERC complicheck relay, digital synchro-scope and digital generator ant. Additionally, the protection relays interface to the metering. The major benefit for system reliability is pro-
August 2014 ENERGY-TECH.com
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TURBINE TECH
Figure 5. The Flex I/O Nodes with Redundant ControlNet.
TMS-1000R turbine control system through both hardwired and Modbus connections. The upgraded Excitation system is designed around Basler Electric’s Digital Excitation control platform (DECS), which provides HBPW with increased performance and reliability for its generator’s excitation system.
The new excitation system provides increased control and protection for the generator compared to the previous OEM system, and also adds negative forcing functionality. The DECS-400 automatically controls the level of DC excitation supplied to the generator field and monitors the generator through the existing installed PTs and CTs. The field voltage and current are monitored through the Field Isolation Module. The DECS-400 compares the feedback with the system setpoint to control the firing module and Power Bridge to regulate the level of field excitation. In addition to the DECS400 controller, TTS supplied a new 900 Amp (dc) rated, 6-SCR, SSE-N Rectifier Bridge and new 291kVA Power Potential Transformer (PPT). The old bridge and PPT were removed and the new equipment installed in the same locations within the Generator Accessory Compartment (GAC).
Human machine interface system The TMS-1000 HMI utilizes the most current computer hardware and software, including a native 1080p resolution, for fast communication with a clean crisp look. Built on the latest Wonderware Intouch platform, the HMI offers brilliant graphics and unsurpassed connectivity. It is designed to bring the data that the operator needs in an organized and intuitive manner. The screens have been from arranged to provide the operators with the correct amount of information for each system, while not allowing them to become overfilled or cluttered. One way that TTS achieves this is by extensive use of the “mouse over tooltips” Our technical webinars are free feature. Almost every object that is and feature industry experts tagged to the processor will give you a full description of the tag by “hovering” presenting the most relevant the mouse pointer over it. This includes subject matter as it relates to analog displays, digital displays, bar graphs and even control buttons. electric power generation. Now The TMS-1000 HMI implements archived on www.energy-tech. a standard color code throughout the entire application. All analog boxes and contentshelf.com/shop! bar graphs are designed to change color for either alarm or trip state, in addition to the alarms that come through the standard alarm banners. This makes it easier for the operator to see the
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TURBINE TECH condition of the device at a glance and identify problem areas quickly. Troubleshooting problems can then be facilitated by the use of both real-time and historical trends that are easy to configure and save. Per HBPW’s requirement, TTS also included the SQL-based Wonderware Historian within the HMI package. The Wonderware Historian, together with the Wonderware Historian Client, adds additional valued features. Along with the standard software for real-time and historical trending, the Wonderware Historian also comes with several plug-ins that TTS applied to generate historical and real-time reports in Microsoft Word, Excel and Access. These options not only ease troubleshooting, but also simplify documentation and reporting. The HMI system also included a Rockwell Automation PanelView Plus touch-screen and keypad terminal that is mounted in the Turbine Control Panel door. The Emergency Operator Interface (EOI) is connected directly into the ControlNet I/O network for data transmission during normal and black-start conditions, and the Ethernet network for programming and configuration changes/updates. The EOI is powered from redundant 24Vdc power supplies within the turbine control panel, which will maintain the terminal even in the event of a loss of plant station power. The application has been designed to have a similar look and feel to the main HMI application to provide a common interface for HBPW’s Operations and Maintenance personnel.
system to provide precise ±100ns time synchronization using demodulated IRIG-B. Precise timing proved to be very useful for generator protective relay hardware event recording, as well as the SQL-based Wonderware historian software. A clock display also was added in the control room to provide operators with a conveniently displayed system time.
Inlet fogging integration TTS upgraded the old Allen Bradley SLC500-based inlet fogging control system with two nodes of flex I/O,
Time synchronization system Time synchronization was accomplished by integrating both HBPWspecified Schweitzer Engineering Laboratories (SEL) satellite-synchronized time clock and TTS-specified Rockwell Automation time synchronization module. Typically the Rockwell Automation time synch module is used as a standalone time source for synchronizing multiple Rockwell Automation processors (using PTP- Precision Time Protocol) and HMI computers (using NTP- Network Time Protocol). In this application, the customer requested an SEL clock to be used as the primary time source. The SEL clock was able to be easily integrated into the TTS
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that was integrated into the Balance of Plant controller using redundant ControlNet. The logic was modernized and brought up to date with the latest version of RSLogix5000. Updates to the logic included new features the customer requested, such as disabling the fogging system for maintenance or troubleshooting.
Black start capability Prior to the system upgrades, only one of the two gas turbines were “black start” capable. In the event that the external electric power transmission system was not available, HPBW had the ability to restore its electrical grid by starting the black start unit by relying on the gas turbine’s battery system. The unit would be operated to synchronizing speed (frequency) and voltage and closing the generator circuit breaker onto the “dead” bus. As part of the control system modernization project, TTS maintained this functionality on the original black start unit, and also added this operation mode to the second unit. TTS added an additional Direct Current (Vdc) motor that was installed in a “piggy-back” arrangement with the primary distillate fuel forwarding pump for the second gas turbine. This system modification, in conjunction with the new PPT to provide black-start operation for the primary lube oil cooling fan and lube oil cooling water pump, provide HBPW with additional blackstart capabilities. This added capability further increases HBPW’s value to its customer base by creating a more efficient and dependable power source for the city of Holland. ~ Kevin Giroux is currently the engineering manager for TTS, www.turbinetech.com. He has served a number of technical roles during his 14 years with the company. His body of work has ranged from engineering and design to field services to project management. Giroux received his bachelor’s degree in Mechanical Engineering Technology from Wentworth Institute of Technology in Boston, Mass., in 1998 and his MBA from the University of Central Florida in Orlando, Fla., in 2012. You may contact him by emailing editorial@woodwardbizmedia.com.
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Dedicated to the Engineering, Operations & Maintenance of Electric Power Plants
August 2014
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