August 2015 by Energy-Tech Magazine

EPRI: Duct burners 5 • Environmental analyzers 13 • On-site hydrogen 28

ENERGY-TECH A WoodwardBizMedia Publication

AUGUST 2015

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

ASME: Feedwater heater alterations

Upcoming webinars and Energy-Tech University Summer School Don’t miss these upcoming training opportunities available exclusively from Energy-Tech! Sign up today for Early Bird pricing! Group discounts also available! Aug. 12-13 ETU Summer School: Troubleshooting & Correcting Problems with Rotating Equipment Using Predictive Maintenance Tools — Webinar Course Tom Davis, Maintenance Troubleshooting

The course will be held from noon to 2 p.m. CT each day and attendees will receive 4 PDH credit hours. Register at www.energy-tech.com/summerschool Aug. 18-20 Excel II Webinar Course Register at www.energy-tech.com/excel Sept. 15-17 Steam and Gas Turbine Fundamentals — Webinar Course Series Sept. 22-24 Advanced Turbine Troubleshooting & Failure Prevention These intensive, 6-hour courses describe major failure modes that turbines experience. The fundamentals of steam and gas turbine design are covered in detail. In addition, predictive maintenance technologies and associated performance issues are discussed, as well as case studies that demonstrate turbine fundamentals. Register at www.energy-tech.com/turbines

Oct. 20-21 ETU: Risk-Based Inspection for High Energy Piping — Webinar Course John Arnold, Niantic Bay Engineering, LLC

The course will be held from noon to 2 p.m. CT each day and attendees will receive 4 PDH credit hours. Register at www.energy-tech.com/piping Nov. 18-20 Gas and Steam Turbine Reliability — LIVE EVENT, Chicago, Ill. Join Stephen R. Reid and Tom Reid for a live 16-hour course over three days discussing gas and steam turbine reliability. The course will be held in Wood Dale, Ill., near the Chicago O’Hare International Airport. Register at www.energy-tech.com/chicago2015

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FEATURES

By Bill Carson, Electric Power Research Institute

Editorial Board (editorial@WoodwardBizMedia.com) Bill Moore – Director, Technical Service, National Electric Coil Ram Madugula – Executive Vice President, Power Engineers Collaborative, LLC Kuda Mutama – Engineering Manager, TS Power Plant Tina Toburen – T2ES Inc. Editorial views expressed within do not necessarily reflect those of Energy-Tech magazine or WoodwardBizMedia. Advertising Sales Executives Tim Koehler – tkoehler@WoodwardBizMedia.com Joan Gross – jgross@WoodwardBizMedia.com

COLUMNS

Regulations Compliance

Getting the most from environmental analyzers By Danielle Adams, AliCat

Mr. Megawatt

A place to start By Frank Todd, True North Consulting

Turbine Tech

On-site hydrogen gas for generator cooling By John Speranza, Proton OnSite

ASME FEATURE

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The compact future of fuel gas performance heating By Rob Broad and Dereje Shiferaw, Heatric Ltd.

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Duct burner operation beyond original design

High pressure feedwater heater cup forging alteration By Thomas R. Muldoon, American Exchanger Services Inc., Bob Cashner and Sara Vestfals, American Electric Power

INDUSTRY NOTES

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

ON THE WEB Energy-Tech University’s last summer school session is coming up on Aug. 12-13. Join Tom Davis as he discusses Troubleshooting & Correcting Problems with Rotating Equipment Using Predictive Maintenance Tools. Visit www.energy-tech.com/summerschool to learn more and register. Cover image courtesy of American Exchanger Services Inc.

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August 2015

ENERGY-TECH.com

EDITOR’S NOTE

Learning live and in person Energy-Tech University sets a new Chicago date As I’m sure many of our readers have noticed in the past year, Energy-Tech increased its webinar courses in 2015 and plans to set a similar schedule in 2016. We know about the knowledge transfer concerns in the power generation industry, as one generation retires and the next generation tries to catch up on decades of engrained knowledge. Since one of Energy-Tech’s primary goals is to give our readers the best information on engineering and maintenance techniques and solutions, with the help of our expert contributors, adding a live training component to technical articles is a natural next step – and we’ve been getting a good response to it. But as popular as our online training is becoming, some people just prefer to be in the same room as their instructor, which is why we will be holding our third session of Energy-Tech University in Wood Dale, Ill., November 18-20. It will be held at the Courtyard by Marriott, near Chicago O’Hare International Airport, and will include several meals and a networking reception. Stephen R. Reid, P.E., and his son, Thomas Reid, will present, Gas and Steam Turbine Reliability, which includes turbine failure statistics, design, chemistry and corrosion, among other turbine-related topics. This course has received great reviews from everyone who has attended and builds off of many of the topics Steve discusses in his regular contributions to Energy-Tech’s Turbine Tech columns. Visit www.energy-tech.com/chicago2015 for more information. I hope you can join us. And if you can’t join us in Chicago, please continue to pay attention to our monthly calendar and email notifications about upcoming webinar options. We have a wide variety of topics coming up and are excited about the presenters – we think you will be too. As always, if you have any ideas or suggestions for topics you would like to see addressed, please let me know. In the meantime, thanks for reading.

Andrea Hauser

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CALENDAR Aug. 4-6, 2015 Excel I Webinar Course www.energy-tech.com/excel Aug. 12-13, 2015 Energy-Tech University Summer School Online Course: Troubleshooting and Correcting Problems with Rotating Equipment Using Predictive Maintenance Tools, with Tom Davis www.energy-tech.com/summerschool Aug. 18-20, 2015 Excel II Webinar Course www.energy-tech.com/excel Sept. 15-17, 2015 Steam and Gas Turbine Fundamentals www.energy-tech.com/turbines Sept. 21-25, 2015 Machinery Vibration Analysis (MVA) Salem, Mass. www.vi-institute.org Sept. 22-24, 2015 Advanced Turbine Troubleshooting & Failure Prevention www.energy-tech.com/turbines Oct. 12-16, 2015 Balancing of Rotating Machinery (BRM) Knoxville, Tenn. www.vi-institute.org Oct. 20-21, 2015 Risk-Based Inspection for High Energy Piping webinar www.energy-tech.com/piping Nov. 18-20, 2015 Gas and Steam Turbine Reliability Chicago, Ill. www.energy-tech.com/chicago2015 Nov. 30-Dec. 4, 2015 Advanced Vibration Control (AVC) Houston, Texas www.vi-institute.org

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August 2015

FEATURES

Duct burner operation beyond original design By Bill Carson, Electric Power Research Institute

Duct burners are added to heat recovery steam generators (HRSGs) to increase the steam production above that possible with just the heat from the gas turbine (GT) exhaust. A large duct burner can more than double the HRSG’s high-pressure (HP) unfired steam production. After a duct burner, the design exhaust gas temperature can be fired as high as 1,600°F–1,700°F (871°C–927°C) in a conventionally designed HRSG. Duct burner operation increases overall unit heat rate, but is a relatively inexpensive method of increasing unit capacity with current gas market prices. HRSGs installed in plants that are intended for only electric power generation might not have been designed for duct burner operation below full GT load. Recently, however, due to changes in the electric market, and in spite of warnings, some power generation plants are firing duct burners during startup, operating the duct burner at GT loads well below full output, and/or are more aggressively increasing duct burner firing rate. In HRSGs not designed to operate in this manner, these practices can lead to significant damage to critical HRSG components. To address this issue, the Electric Power Research Institute (EPRI) sponsored research to identify and, where possible, quantify the impact of duct burner operation beyond the original design limitations of the HRSG for combined-cycle applications. The research project explored factors that might affect duct burner performance, including operating changes, operating specifications, design factors and plant controls. Research also identified typical duct burner problems. The findings of this research will help plant operators become more aware of the risks of off-design operation of duct burners and better understand the best options for duct burner operation in their plants. The research and its results are described in an EPRI report, Understanding the Impact of Duct Burner Operation Outside of Original HRSG Design Limitations.

Increasing demand for faster startups Changes in the electric market are placing an increasing premium on flexible unit operation. This means that the emerging power market favors plants that can start up and achieve full electric output in a shorter time period than previously required. It also favors plants that can more rapidly increase and decrease electric output when on-line. The addition of renewable power generation sources such as wind turbines, solar photovoltaic, and solar/thermal plants to the electric grid is a primary driver of the need for greater flexibility in non-renewable power plants. The ability to control the timing of starting and stopping, the electric power output quantity, and the rate of change in output of renewable generation is limited and very dependent on changes in the weather. Because storage and recovery of alternating current electric energy are very limited in North America, and because government regulation gives priority on the grid to renewable generation sources, non-renewable power plants must respond in real time to load changes imposed by renewable sources. As more renewable generation sources are added to the grid, non-renewable plants face the increased challenge of adequately responding to often unpredictable load changes. Together, these market factors are causing some plants to operate duct burners beyond their design limitations, and creating a need to better understand the technology and the consequences of operational changes. Duct burner technology The most common style of gas-fired duct burner is a runner- or grid-type duct burner, as shown in Figure 1. This burner assembly would be inserted through an opening in the HRSG casing. A runner-style gas burner can

Figure 1. Runner-type duct burner. Source: EPRI August 2015 ENERGY-TECH.com

FEATURES

Figure 2. Can-type duct burner.

distribute heat across the length of the burner, spanning the full width of the HRSG duct. Some duct burners are configured as a can or register style, as shown in Figure 2. Can-style burners are typically used with an oil fuel, but also can be used to fire gas. Canstyle burners offer a localized spot injection of heat, making it more difficult to distribute the heat uniformly across the width of the HRSG. Each burner runner consists of a pipe spanning the firing duct that supports the other burner runner components. The pipe is also a conduit for fuel gas distribution to the burner orifices. The orifices are the fuel gas discharge point from the burner pipe. Orifices are evenly spaced along the runner pipe, but are stopped short of casing wall liners to prevent flame impingement. Burner fuel is mixed with some turbine exhaust gas (TEG) as fuel exits the orifice, and this creates the anchored base of the flame. Flame holders protect the flame from being quenched and from blowout by shielding a large part of the base of the flame from the TEG. The shape of the flame holders also creates turbulence and provides additional TEG to mix within the flame as the flame develops. This mixing helps meter the fuel and oxygen to complete the fuel combustion and reduce flame length. Flames that are cooled too quickly or that have incomplete combustion can result in high carbon monoxide (CO) and unburned hydrocarbon (UHC) emissions. Flames that run too hot can result in high nitrogen oxide emissions. The flame holder design meters the TEG into the flame in the proper proportion.

Locations of duct burners The most common configuration for duct burners in large HRSGs is to locate the duct burner in the exhaust gas flow downstream (with respect to exhaust flow) of the final superheater/reheater sections and upstream of primary superheater/reheater sections. (Figure 3) This arrangement provides more heat to the evaporator and early stages of the superheater to maximize steam production with little effect on the final steam outlet temperature, even at different fir-

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ing rates. This location also tends to minimize the need for attemperation associated with duct burner operation. The heating surface upstream of the burner also helps improve the exhaust gas flow distribution to the burner. A burner also can be placed just after the GT (in the HRSG inlet duct) and upstream of any coil section, although this arrangement is less common. During unfired conditions with a burner in the inlet duct, the superheater steam outlet temperature will be lower. Achieving the proper exhaust flow distribution to the burner in the inlet duct can be difficult, often requiring an extensive flow correction device(s) upstream of the burner. Some details of the HRSG and duct burner design might need to be modified if the duct burner is going to be operated below GT full load. If the owner anticipates duct burner operation below GT full load, then the combinations of GT load and duct burner firing rate to be considered must be developed and included in the HRSG specification. Some duct burners have been designed to fire with the GT operating at full speed but producing no load.

Operating changes and specifications that affect duct burner performance EPRI research noted operating changes of significance for the performance of duct burners. For example, GT modifications or upgrades have to be carefully analyzed to assess the impact on an existing HRSG. Modifications to a GT compressor also will increase mass flow through the turbine, which in turn increases the exhaust pressure drop through the HRSG. Additional turbine mass flow from a compressor upgrade could minimize or eliminate the need for duct firing. Duct firing should be evaluated for compressor upgrades to ensure that a maximum value of steam production is not exceeded such that operating drum pressure increases to where safety valves could lift. Burner heat release might need to be limited under these conditions. As regards specifications, the operating conditions for the design of the HRSG and duct burner are defined in the HRSG purchase specification heat balances. These heat balances define the duct burner operating envelope. If burners are required to operate with the GT at part load, then partload cases also need to be defined. Design and control factors A number of design factors affect duct burner performance. One factor is firing duct length. Adequate duct length should exist after the duct burner to prevent flames from impinging on downstream components and to allow for adequate mixing of TEG and burner fuel. The duct section between the burner and downstream coil bounded by the casing walls is called the “firing duct.” Firing duct lengths are usually 12’–18’ (3.7–5.5 m) between the burner and coil face. Other design factors include number of runners, sequential firing of runners, GT load, GT exhaust profile, GT

August 2015

FEATURES exhaust flow distribution and modeling, and GT exhaust velocity and pressure drop across the burner. Among the controls, the National Fire Prevention Association’s NFPA 85, “Boiler and Combustion System Hazard Code” is the main standard for fire/ explosion protection of HRSGs and duct burners. The code defines required safeguards, including parameters that must be monitored and general alarms, interlocks Figure 3. Split superheater duct burner configuration. and parameter values that must result in a downstream of the burner. TEG flow profile at the master fuel valve trip for a duct burner system. Other conburner should be as uniform as possible. trols include automatic plant load following, duct burner • Fuel gas flow maldistribution. The fuel gas flowing turndown and operation with runners out of service. through the burner runner pipe will heat up as it flows through the runner pipe because TEG flow over the runner heats the runner pipe. The static pressure Typical duct burner problems inside the runner pipe also varies along the pipe. Among the duct burner problems that can arise, accordTemperature and pressure of the fuel gas changes the ing to EPRI research, are the following: fuel gas density, thus the flow through the various • Condensation and corrosion in fuel lines. A duct burner orifices. The fuel gas flow and thus the heat burner should have automatic isolation of individual release will vary along the runner length unless adjustburner runners. This provides flexibility in operation ments are made (by the manufacturer) to the orifice if instrumentation or hardware fails on individual sizing to correct for this effect. Monitoring temperarunners by providing the ability to isolate the runtures across the downstream coil will provide an indiner. Isolation of burner runners prevents GT exhaust cation of the uniformity of heat release. If necessary, water vapor from diffusing into external burner piping and condensing when a burner is not in operation. Condensation can cause corrosion and rust in fuel gas lines that can clog burner orifices. Condensate also can accumulate in the external piping and be blown into burner runners when the burner is placed into service. This can cause damage to the burner runners inside the HRSG. Figure 4 shows severe distortion of a burner runner caused by condensate. • Exhaust flow distribution. TEG flow distribution is important, because it affects local fired temperatures downstream of the burner and flame length. TEG flow should remain within a 15 percent rms distribution at the burner plane. Even with this criterion, locally long flames can occur in lower exhaust flow areas. The flow profile should be determined at the HRSG design stage by CFD or by flow model testing. A burner could be designed in which each runner matches the local exhaust flow profile, but this is undesirable because it would result in temperature maldistribution

August 2015 ENERGY-TECH.com

FEATURES

Figure 4. Burner runner distortions from condensate.

the orifices along the runner can be field-modified to correct the fuel gas distribution and minimize coil temperature variation. • Flame impingement. Flame impingement can occur on firing duct liners so that liners are damaged and insulation is exposed. Flames also can damage the burner runner. In most cases, these types of flame impingement are attributed to improper TEG flow distribution in which the exhaust flow is skewed across the runner or recirculates back onto the runner. Long flames can result in flame impingement on downstream coils. Overheating of a coil can occur downstream from can-style burners where heat input is more focused at the can locations. The steam temperature would vary across the outlet of this coil, and varying average tube temperatures would occur in the tube row across the duct. Tubes operating at different temperatures within the same tube row will create tube stresses that are detrimental. Using a bare tube row immediately downstream of the burner provides

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some additional protection against local tube overheating. • Flame impingement and long flames are manifestations that are observable through appropriately designed and installed site ports. Operators should regularly inspect burner flames for any abnormalities. EPRI research also identified other duct burner problems, including firing-zone liner warping, flame length, coking, burner runner failure, flow-distribution device failure, overly rapid duct burner firing rate changes, duct burner starting reliability, rerating a coil for higher temperatures, retrofitting a duct burner to an existing HRSG, modifying a duct burner after GT modifications and burner runner support. ~ Bill Carson manages EPRI’s Combined Cycle HRSG and Balance of Plant Program. He joined EPRI in 2008, after working in various capacities at Dynegy for 18 years. Carson has more than 30 years’ experience managing the construction and ensuring the safe and reliable operation of plants in the power industry. You may contact him by emailing editorial@woodwardbizmedia.com.

August 2015

FEATURES

The compact future of fuel gas performance heating By Rob Broad and Dereje Shiferaw, Heatric Ltd.

The power generation industry is constantly seeking higher efficiency and lower carbon emissions. Because fuel costs are a major part of total power plant operating costs, even very small increases in overall cycle efficiency can add up to valuable gains for utilities – if the extra costs can be made to make economic sense. Fuel gas performance heating to improve fuel consumption is one popular and relatively simple way to raise generator efficiency. System heat (in the form of boiler feed water from the economizer) is used to pre-heat the Figure 1. A PCHE is 85 percent smaller and lighter than a shell and tube unit of comparable duty. Source: Heatric Ltd. fuel gas so that less energy ent-metal strength but with flow channels running through it. is required to bring it up to (Figure 2) The allowable stresses for a PCHE far exceed those combustion temperature. The closer the fuel gas temperature of other designs. (Figure 3) can be brought to the auto ignition point, the greater the effiFor any given heat transfer application, the precise path ciency gains. This, in turn, depends on the calorific value of the taken by the flow channels (along with numerous other facheat source and, crucially, the efficiency of the heat exchangers. tors, such as wall thickness and channel depth) can be easily Shell and tube exchangers remain popular in power genoptimized, and the complete unit configured for co-, cross- or eration because they are well-understood. But in fuel gas counter-current flow to match thermal duty (NTU) with heating their inherent design limitations make it hard for them available pressure drop. It is the high surface densities (i.e., the to maximize cycle efficiency gains without excessive capital heat transfer surface area-per-unit volume of heat exchanger) costs undermining the economic case. Compact, high integrity, of the diffusion-bonded, etched-plate design, combined with ‘printed circuit’ heat exchangers (PCHEs), on the other hand, these bespoke heat transfer geometries that make a PCHE so are ideally suited to high pressure, counter-flow applications like compact. fuel gas heating, offering effectiveness levels as high as 99 percent that can unlock those lost efficiency gains.

What is a PCHE? The term ‘compact’ is often confused with ‘small.’ In fact, individual printed circuit heat exchangers can exceed 26’ in length and weigh 100 tons or more. More accurately, compact is a relative term that refers to the larger duties achieved for a given size; typically a PCHE is 85 percent smaller and lighter than a shell and tube unit of comparable duty. (Figure 1) Instead of pipes running through shells, a PCHE’s heat transfer core consists of flow channels chemically-etched into flat metal plates. The etched plates are stacked in alternating layers – usually one for the process fluid and one for utility – and diffusion-bonded to create a near-solid block, retaining par-

‘Printed circuit’ vs. shell and tube Gas turbine power plants are frequently used for peak power shaving operations, where they must respond rapidly to sudden increases in electricity demand by reliably reaching peak power very quickly. Any fuel gas heating system must match this performance in every dimension if it is not to become the plant’s Achilles’ heel. But conventional heat exchangers are prone to vibration-induced tube failure and slow thermal response, weaknesses with serious consequences for costs. To achieve the highest practicable efficiency gains, fuel gas temperature must be raised from ambient to above 570°F. It would take six shells in series (typically operating at around 76 percent effectiveness) to come close to matching the deep

August 2015 ENERGY-TECH.com

FEATURES

Figure 2. The diffusion-bonded core of a PCHE.

Figure 3. Allowable stresses for compact, diffusion bonded heat exchangers.

temperature cross possible using PCHEs, and each of them would need to be expensively engineered to cope reliably with the high pressures involved. It is because heat exchanger costs become prohibitive after a certain point that it has become common practice in fuel heating to instead use two U-bend shell and tube exchangers in series (equivalent to four single shells), sometimes also split to cope with thermal stresses. But this is only a partial solution that leaves approximately half of the optimal duty unperformed, and so a good part of the gains unrealized.

Diffusion-bonded units, on the other hand, are known for their fast temperature response times and minimum maintenance, making them particularly suitable for demanding peakhour operations. In fuel preheating using single (mostly intermediate) pressure feedwater, a compact exchanger’s strengths in counter-flow arrangements allow for a deep temperature cross heat release curve (i.e., closer temperature approach), while its native robustness means it can easily handle the combination of high pressure feedwater and tight temperature approaches. The effectiveness of a PCHE can reach as high as 99 percent, making much higher heat recovery possible. The flexibility of the PCHE design and manufacturing processes also makes it a relatively simple matter to bring several streams together in a single unit. In the particular case of fuel gas heating, that means multi-stage heating (using more than one heat source and feed pressure) can be comfortably achieved in a single unit (Figure 4), saving space and piping, minimizing pressure drop, and creating a system that is easy to modularize as a skid or package. Using two pressure levels in this way also creates the flexibility needed during part-load operations when IP feedwater alone might not be sufficient to maintain a steady fuel gas temperature at the required value.

Modeling efficiency improvements and exchanger effectiveness In the following case study, using compact diffusion bonded exchangers in a combined-cycle gas turbine (CCGT) plant with three pressure levels, we see how these operational advantages can add up to plant efficiency improvements. In a multi-stream, multi-pressure level feedwater system, intermediate pressure (IP) feed water (800 psig, 460°F) is used in the first section to increase fuel gas temperature into the 350°F-450°F range. This delivers a first efficiency improvement of between 0.5 percent and 0.7 percent, which equates to everything that is typically possible using conventional heat exchangers. Then a second stage, high pressure (HP) feedwater (3,600 psig, 670°F) can be used to raise gas temperature to 610°F. This adds an additional half a percentage point to cycle efficiency gains, bringing the total to 1.2 percent. Figure 4. Multi-stream counter flow compact exchanger combining different pressure level feed water systems.

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August 2015

FEATURES

Figure 5. UA and Q vs. heat exchanger effectiveness for the IP feed water/fuel gas section. Shell and tube VA = 100 kW/K; PCHE VA = 400 kW/K.

Figure 6. An additional 1,650 kW is available using PCHEs.

the cost of achieving it) accelerates sharply as exchanger effecCrucially, of course, the reduction in operating costs outtiveness approaches 100 percent. weighs the capital investment required to achieve them, such Net LHV electric efficiency increases as fuel gas temperature that a relatively quick payback time is possible. increases (Figure 7) because the high effectiveness of the comIf we assume the flow rate of the gas to be 2,000 lbs/min at pact heat exchangers ensures that the extra fuel used to heat the a pressure of 725 psi, by varying the fuel gas exit temperature feedwater is less than the energy saved by bringing the fuel to we can analyze the impact heat exchanger effectiveness (i.e., oxidation temperature before combustion. closer temperature approach) has on fuel gas heating duty. To Now, as we saw in Figure 6, the relationship between heat evaluate increases in net LHV electric efficiency as a function duty and UA vs. effectiveness is based on a similar analysis, but of increasing heat exchanger effectiveness, we further assume this time using a HP feedwater/fuel gas heat exchanger. The that the fuel gas has a lower heating value (LHV) of 18,000 heat duty is the extra heat required to further increase the fuel Btu/lbs and that without fuel gas heating the overall cycle has a net electric efficiency of 56 percent. The estimated net power output of the plant we are visualizing is then 420 MWe. In its simplified form, a heat exchanger’s Dunn’s specialized facility offers complete services for shell and effectiveness can be expressed as: tube type heat exchangers and related process equipment.

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Equation 1

Where minimum temperature approach is calculated by: Equation 2

In general, as the effectiveness of the heat exchanger increases there is a steady increase in the heat added to the fuel gas, Q. (Figures 5 and 6) But the increasing effectiveness also requires higher UA values, which is the product of the heat transfer coefficient (U) multiplied by the heat transfer area (A). With the heat transfer coefficient constant, a higher UA requires a greater heat transfer area – in other words, a larger exchanger – with obvious consequences for capital costs. Not surprisingly the increase in UA (and

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August 2015 ENERGY-TECH.com

FEATURES

Figure 7. Net electric efficiency and fuel gas heat recovery duty vs. exchanger effectiveness IP Feed water/Fuel gas heating section.

Figure 8. Net electric efficiency and fuel gas heat recovery duty vs. exchanger effectiveness HP Feed water/Fuel gas heating section.

Figure 9. Plant operating hours required to return investment in IP feed/fuel gas heating.

Figure 10. Plant operating hours required to return investment in HP feed/fuel gas heating.

gas temperature beyond what was achieved by the IP section alone. There is a steep rise in heat recovery as effectiveness increases, with a significant rise in UA value at very high effectiveness levels. The corresponding additional increase in plant efficiency is shown in Figure 8. Additional increases in electric efficiency in the range 0.3-0.5 percent – not possible with shell and tube – are achieved with further temperature increases of between 140˚F and 240˚F. Thus, with IP and HP feed water used in series to raise total fuel gas exit temperature to 660˚F, the overall increase in net electric efficiency from fuel gas heating can reach 1.2 percent. Considering a fixed exchanger price per UA and a fuel cost of $2.5 per MMBTU, the fuel saving due to improved efficiency can now be used to estimate the number of plant operation hours required to pay for the capital investment in the exchangers. Figures 9 and 10, respectively, plot this for different levels of exchanger effectiveness for both the IP and HP systems. In addition to the fuel saving of approximately 40 lb/ min, there is also a carbon dioxide emission reduction of more than 100 lb/min. Due to the high pressure, and hence the mechanical strength requirements, the HP exchanger inevitably has a higher price per UA and so a longer operational payback period for the

investment. But overall the PCHE’s native abilities to handle high pressures and multi-streams in a single unit help minimize overall capital investment, increase plant availability and lower operating costs, all within an easy-to-integrate, skid-mounted system well-suited to CCGT applications. ~

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Robert Broad is business development manager at Heatric Ltd. A graduate in chemical engineering from Bath University, he has spent nearly 20 years in the compact heat exchanger business, working in design, product development and commissioning in many industries, including power generation and oil and gas. Broad holds an MBA from the UK’s Henley Management College, is a Fellow of the Institute of Chemical Engineers in the UK and a member of the European Professional Engineers Register. You may contact him by emailing editorial@woodwardbizmedia.com. Dr. Dereje Shiferaw is design development manager at Heatric Ltd. and has more than 10 years’ experience in heat exchanger design. He holds an MSc from KTH, Stockholm, (where he specialized in sustainable power generation systems and conducted extensive research into nanofluids for nuclear reactor safety) and a Ph.D. from Brunel University, London (two phase flow boiling in small and microchannel exchangers). He is a chartered member of the Institute of Mechanical Engineers. You may contact him by emailing editorial@woodwardbizmedia.com.

August 2015

REGULATIONS COMPLIANCE

Getting the most from environmental analyzers Stay in compliance by verifying your analyzer’s mixed gas flows By Danielle Adams, AliCat

Accurate flue gas flow analysis is an important aspect of remaining in compliance with environmental regulations. In flue gases, where gas composition is constantly changing, the mixed gas flows increase the complexity of accurate measurement exponentially. So how do you know if your environmental analyzers are reading accurately? Adding a portable mass flow meter to your maintenance routine provides the opportunity to identify and troubleshoot potential analyzer issues before they become a source of costly fines. Environmental analyzers require a pressure or mass flow controller to manage the flow of gas through the analyzer. Analyzer accuracy depends on knowing how much of a gas or gas mixture is flowing through it, and each gas or gas mixture has its own set of gas properties. As environmental factors such as ambient temperature, humidity and pressure change, the measurement accuracy of an analyzer can drift. Validating analyzer flow rates is a key maintenance step to ensure analyzer accuracy. New equipment and software utilities have simplified this task greatly, even in complex applications like electric power generation that involves mixed gas flows. Portable handheld instruments can now be used for quick and easy field calibration. One such instrument is Alicat Scientific’s MB series portable mass flow meter. Alicat’s portables include its Gas Select™ 5.0 firmware and new Composer™ utility for defining mixed gas compositions. The utility gives users the ability to quickly program and store up to 20 personalized gas compositions directly on the portable mass flow meters, simplifying the management of mixed gas flows. To better understand how this software impacts the calibration process, an overview of the traditional calibration methods for mixed glass flows is helpful.

Traditional gas mix calibration methods Accuracy for most flow meters requires knowing the precise compositions of the gases that are flowing through them. When a user’s gas composition changes, flow measurement and control are no longer accurate, and by extension neither are the environmental analyzers that depend on them. Calibration of mass flow instruments is traditionally done in one of three ways: factory calibration, K-factor estimation or volumetric flow validation, all of which have inherent drawbacks. As the name implies, factory calibration involves calibrating a mass flow meter at the factory to an expected typical com-

position for the flue gas mixture. While measurements for this particular composition will produce accurate results, departures from this typical composition will increasingly introduce measurement inaccuracy. The nature of flue gases practically guarantees fluctuation from the typical composition used in the original calibration. Achieving higher accuracy by this method requires complex calculations of the gas properties of the actual gas mix at the actual validation pressure and temperature. When using K-factors, a mass flow meter is calibrated for nitrogen or air as a default, and then single-point mathematical conversion factors are applied to approximate the actual gas flow. This method introduces inaccuracies through the K-factors, which do not take into account full gas property models. Outside of the specific temperatures, pressures and flow rates for which a K-factor is optimized, inaccuracy increases. K-factors that do not match the specific gas mixture introduce even greater inaccuracy. A bubble meter or piston prover is used to conduct flow validation with volumetric flow measurement. Conversion to mass flow then requires the use of complex tables and calculations to account for the mixture of gas properties, including compressibility, for the temperature and pressure conditions used for validation. This process can take a long time for the volumetric flow measurement itself, and then much greater time for the back-calculation of mass flow rates.

Figure 1. Portable instruments quickly and easily validate flow rates in the field. Source: Alicat August 2015 ENERGY-TECH.com

REGULATIONS COMPLIANCE

Figure 2. Users can define, change and remove custom gas mixes right from the front control panel of the instrument.

Gas mix calibration with portable meters and software Alicat’s Composer defines new gas compositions on the instrument itself using gas properties data for up to 130 preloaded pure and mixed gases. The ability to generate gas calibrations for customized gas mixes eliminates the need to use inaccurate K-factors or spending time researching gas viscosities to generate new calibration curves. Composer allows users to change gas compositions without incurring the downtime and expense of factory recalibrations for varying gas mixtures. This allows their portable meters to quickly adapt to changing flue gas conditions and accurately calibrate analyzers’ mass flow equipment. Alicat’s pressure-based mass flow meters and controllers monitor absolute pressure, differential pressure and temperature to provide simultaneous volumetric and mass flow readings that are accurate to 0.8 percent of the reading, even in changing pressure and temperature conditions. To maintain this level of accuracy for mixed gases, Composer calculates gas properties data based on molar

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August 2015

REGULATIONS COMPLIANCE (volumetric) percentages of the gas mixes, to a precision of 0.01 percent for each of up to five constituent gases. This operation is performed by the instrument’s onboard processor, so users can add a custom mix right from the front control panel of the instrument in just a couple of minutes without an external computer. Up to 20 user mixes can be stored at a time, and individual mixes can be updated over RS-232 by writing the updated composition to the same Figure 3. A portable meter verifies gas flow from an analyzer. gas number. Users may also issue single-line serial commands multiple calibration readings can be taken in seconds with no via RS-232 or RS-485, which post-analysis time required. ~ enables the automated measurement and control of changing gas compositions. Most Composer gas compositions draw from NIST Ref Prop 9 gas properties data and retain Alicat’s standard Alicat’s Danielle Adams is the mind behind the “Ask Alicat” 0.8 percent of reading measurement accuracy. Real-time moncustomer education series. You may contact her by emailing itoring of gas stream temperature and absolute pressure allows editorial@woodwardbizmedia.com. use of Composer mixes for both volumetric and mass flow measurement while maintaining flow accuracy.

Composer for environmental ﬂue gas analyzers In general, the downtime required to calibrate an analyzer can be inconvenient. The changing composition of flue gas streams can increase this downtime by requiring lengthy calculations that delay calibration results. Flow calibration for environmental analyzers is often performed by using the purely volumetric flow validation method described above. The actual mass flow rates must then be back-calculated from the volumetric data and recorded temperatures and pressures using complex tables and calculations to derive gas properties estimates for the gas mix under calibration conditions. This process often requires analysis by another individual and a wait of as much as a day to receive the calibration results. The use of Composer firmware dramatically reduces calibration time and analyzer downtime. Once a user’s gas mixes have been entered, the calibrator selects the gas composition that matches the current readings from the analyzer. Real-time readings of mass flow, volumetric flow, absolute pressure and temperature mean

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MR. MEGAWATT

A place to start By Frank Todd, True North Consulting

One of the interesting elements of married life is knowing just where the starting point is, for both the overall relationship as well as specific events. The conversation might go like this, “Ok dear, we will leave at 6:30.”Your assumption may be that leaving at 6:30 means everybody is in the car with the garage door open and the engine running. In other words the starting point for leaving is the car driving out of the garage.Your wonderful spouse’s assumption may be that leaving at 6:30 is the beginning of the “leaving process;” with time remaining to look for the purse, wipe up any last crumbs on the counter, start the hunt for the shopping list, answer the six pertinent texts on the cell phone, put the dog in the crate, go after the smudge on the kitchen window that has been bugging you, search for the lens cleaner, etc … Depending on the starting point you could actually roll out anywhere between 6:30 or 7:30. The problem of “starting point confusion” is actually fairly common in power plants centered on how much electricity the plant should be generating. We often call it the “baseline” generation for a given set of environmental conditions and operating assumptions expressed as wet bulb temperature, condenser cooling water inlet temperature or condenser pressure. For the given set of conditions such as condenser pressure of 2.5 inHGA the plant should generate 1,000 Mwe. Often, this baseline value is derived from the design heat balance that the turbine vendor provided as part of a “thermal kit” back when the plant was built. In a perfect world, where the “as built” is the same as the design, this would work fine. However, most of us know from experience that “that ain’t the way it always is.” One of the most common occurrences is that the turbine vendor and the people designing the rest of the plant make different assumptions; such as what is cooling the air ejector condensers, condensate or water from the river. I have even seen some plants where they had a different number of feedwater heaters than the turbine vendor assumed. That creates a big difference in the baseline, not to mention the different assumed values for the terminal temperature difference and the drain cooler approach temperatures. I know this is hard to believe, but sometimes the installed equipment does not perform the same as the design documents indicate. Perhaps it would be more accurate to say that most of the time actual performance is different than designed performance. So when Henrietta Hardthinker (HH) was sitting at her desk trying to disposition the next deficiency report in a stack of 1,000 and her supervisor said the plant manager (PM) wanted to see her about plant generation, she knew the car would not be leaving the parking lot at 6:30. Knowing that she would not meet the month’s quota for deficiency report resolutions, she climbed up to the 6th floor to engage the most powerful person on the site; the administrative 16 ENERGY-TECH.com

assistant Gwendoline E. Gristenhammer (GEG). Too late, Henrietta realized that she forgot to send GEG the list of the quantity, type and serial number of pens she has used in the last year. She found GEG on the phone immersed in a private conversation about her children’s body piercings. After what seemed like an eternity of awkward waiting, GEG finally ended the call and gave Henrietta her classic ‘why are you bothering me’ glare. Henrietta told her that she received a summons from the PM. With a doubtful look, GEG begrudgingly sent her in. After complaining about what took her so long, the PM launched into an important technical discussion he had with the CEO on the golf course last Wednesday. Apparently the CEO’s new assistant, Kevin K. Up (KKU) is a self-proclaimed thermal performance expert because he is able to read a heat balance. He is questioning the plant generation numbers. KKU was looking at the morning report and said the plant was only generating 1,110 Mwe instead of 1,125 Mwe as is on the vendor heat balance, so there must be something wrong. When KKU told the CEO how much that was worth (about $6 million per year) the PM said he only averted a full blown Root Cause Evaluation by allowing the CEO to win and that Henrietta had better figure it out soon because hitting every sand trap and 5 putting every hole might cause some suspicion, or not. Henrietta went back to her supervisor and said she would not be getting her health report out in time. After Henrietta described the situation, her supervisor suggested the M5T protocol (Expert = More than 50 miles away with a tie). “The M5T protocol, do we have money for that?” Henrietta asked, surprised. While her monthly health report and was her No. 1 priority, her supervisor added that the investigation also was her No. 1 priority. Henrietta shrugged her shoulders, went back to her desk and began implementing M5T, placing a direct call to me. Henrietta described the situation and indicated that there would have to be a face-to-face meeting with the PM and KKU. I knew that it would be out of my league since I do not golf, so I called on Richey Reynolds to step up to the teeing ground. Henrietta provided the necessary information: thermal kit, plant data, the morning report in question, how to get on Gwendoline’s good graces, etc., and we began our investigation. The first problem we noticed was that the condenser pressure on the morning report was about 0.3 inHga higher than the design value, which was worth about 7.5 Mwe. This is a common mistake made by assistants to the CEO and it would be easy to just point and laugh, but there was more to the story and the M5T protocol does not allow for any pointing August 2015

MR. MEGAWATT out of the obvious as, well, obvious. Therefore we took out our favorite thermal performance brain helper, the thermodynamic model. Evaluating the plant drawings and the turbine vendor thermal kit heat balance, we put the information in our model and identified various differences between the plant and the heat balance. Since it was a nuclear BWR (boiling water reactor) plant we knew that the nuclear side of the house often doesn’t communicate with the turbine side of the house, resulting in some different assumptions. For example: • Control Rod Drive Flow – The thermal kit assumed that the flow leaves the cycle.Yes, this is confusing, but that was their assumption. In reality the water coming from the condensate system does not leave the cycle but bypasses all the feedwater heaters and goes to the Control Rod’s (surprising huh?) which are in the reactor. Therefore, the water eventually ends up as steam coming out of the reactor and going to the turbines. • Steam Seal Evaporator Steam Flow (SSE) – Since this is a BWR and all the water in the cycle ends up radioactive, they use a tube and shell heat exchanger to make the steam for the turbine sealing system. The vendor heat balance assumed the tube side exiting flow (radioactive water) was directed to the first feedwater heater (FWH) but in the plant it is all directed to the condenser. • Shaft Leakage Flow – The vendor heat balance assumed that all the flow ultimately ends up in the first feedwater heater, but it is actually split between the third feedwater heater and the condenser. • Drain Cooler Arrangement – The vendor heat balance assumed that all the feedwater heaters had internal drain coolers and the plant configuration shows that the first heater had no drain cooler and the second feedwater heater had an external drain cooler. • Steam Jet Air Ejector (SJAE) and Steam Packing Exhauster (SPE) heat exchanger arrangements – The vendor heat balance had these two heat exchangers in series, but the plant had them as parallel. This difference had no effect on generation. • Steam Jet Air Ejector Supply Steam Flow – The vendor assumed 15,000

lbm/hr steam flow to SJAE, but the plant actually uses 40,000 lbm/hr – ouch! • Reactor Feed Pump Steam Supply flow – While both the vendor heat balance and the plant assumed the same location for the flow (Moisture Separator Outlet) the vendor assumed about 198,282 lbm/hr and plant uses 200,893 lbm/hr. The first step was to model the vendor heat balance in our thermodynamic model so it matched the configuration and output. Then we went through the changes one at a time to

August 2015 ENERGY-TECH.com

MR. MEGAWATT Table 1 – Plant and Thermal Kit Differences Component

Thermal Kit

Plant Config

Baseline Generation

MW diff MWe

125

Condenser Pressure

2.0 InHga

2.3 InHga

1117.538

7.5

Control Rod Drive Flow

Flow leaves cycle

Flow directed to reactor vessel

1116.732

0.81

SSE Flow

Flow directed to FWH 1

Flow directed to condenser

1116.623

0.11

Shaft Leakage Flow

Flow directed to FWH 1

Flow split btwn FWH 3 & condenser

1116.073

0.55

Drain Cooler Arrangement

All heaters have internal drain coolers

FWH 1 no drain cooler, FWH 2 external drain cooler

1114.792

1.28

SJAE & SPE Arrangement

SJAE & SPE series tube side arrangement

SJAE & SPE parallel tube side arrangement

1114.792

0.00

SJAE supply steam flow

15,000 lbm/hr flow to SJAE

40,000 lbm/hr flow to SJAE

1112.346

2.45

Reactor Feed Pump flow

198,282 lbm/hr flow to feed pump

200,893 lbm/hr flow to feed pump

1112.175

0.17

Sum of differences btwn Vendor and Actual

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

Results MWe

12.83

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understand the effect of the parameter or configuration difference. The results of this analysis are shown in Table 1. Including the condenser pressure difference and the vendor to plant differences, the total generation difference was about 13 Mwe. So their starting point should have been a lot less than what the vendor thermal kit indicated. We sent this table to Henrietta. Richey and I jumped on a plane so we could see how much snow was still up in the San Juan Mountains in the middle of June, as well as be present for the meeting with KKU and the PM. As we approached the PM’s office, Gwendolyn and KKU were in conversation comparing their children’s body piercings. They gave us a combined smirk as we entered the office. Richey presented the information that the plant was down 2 Mwe instead of 15 and Henrietta had an explanation for the 2 Mwe. Knowing the difference between $6 million and zero, the smirk suddenly disappeared from KKU’s face and we knew he was already contemplating where his new position would be located. The PM recognized the panicked look and informed KKU that the Nuclear Federation Of Operational Latency (NFOOL) might have some openings. Walking out of the meeting we overheard KKU asking Gwendolyn if she had the NFOOL handicap list. On our way out of the plant Richey and I commented to the PM on the nice charts displaying all the red, yellow and green indicators and how their staff must be doing a good job since most of them were green. We bid farewell to Henrietta and she thanked us for the distraction from her pile of dispositions, now she was down to 999. Driving up the bluff, I received a text from Mrs. Megawatt asking about going out to dinner. “Sure,” I replied (after I pulled over of course), “what time do you want to leave?” ~ Mr. Megawatt is Frank Todd, manager of Thermal Performance for True North Consulting. True North serves the power industry in the areas of testing, training and plant analysis. Todd’s career, spanning more than 30 years in the power generation industry, has been centered on optimization, efficiency and overall Thermal Performance of power generation facilities. You may email him at editorial@woodwardbizmedia.com. August 2015

ASME FEATURE

High pressure feedwater heater cup forging alteration By Thomas R. Muldoon, American Exchanger Services Inc., Bob Cashner and Sara Vestfals, American Electric Power

The Wilkes high pressure feedwater heater has an integral tubesheet/channel forging with a breech lock full access closure (Figure 1 and Figure 5) and was found to have cracking in the corner radius on the tube side (Figure 2, Figure 3 and Figure 4). The feedwater heater is 1964 vintage, where it was standard industry practice for tubesheets to be designed without a significant corner radius. The corner radius designs vary by vendor, but as established in the 1988 EPRI paper, people were aware of the benefits of reducing stresses at the tubesheet-channel junction by increasing the radius. The cracks in the E heater propagated radially and occurred 360 degrees around the small knuckle radius in the tubesheet to channel interface. The worst case cracks were found to be approximately 1½˝ deep. The cracks found in this forging are typically caused by thermal gradients and/or cycling issues.[1] These thermal gradients, coupled with inherently higher stresses due to

an improperly sized corner radius, could lead to the cracks exhibited in the Wilkes E feedwater heater. The expected stresses in the original equipment were calculated by Finite Element Analysis and found to be higher than the material minimum yield stress. These values are past the safe limit for design stress and could singularly cause failure if the actual yield strength of the material was exceeded. These types of failures are usually indicative of higher ramp/cool down rates during start-up and shut-down operation than standard practice, although this is a hard number to quantify. The failure mechanism with the Wilkes heater was most likely due to a high stress concentration that was being cycled over time. There have been very few indications of problems when the heating cooling rate is kept at 200°F/hr, which is the AM-EX standard and how Wilkes personnel have operated the heater. A rate of 200°F is on the con-

Figure 1. Wilkes HP FWH with breech-lock closure. Source: AM-EX Inc. August 2015 | ASME Power Division Special Section

ENERGY-TECH.com

ASME FEATURE the part (Figure 2). These can arise during the forging of the material. The channel and tubesheet material is SA266 Gr2. The current recommendation for forged carbon steel tubesheets is SA350 LF2, preferably in the normalized or normalized and tempered condition. Nozzle loads imposed by the feedwater piping can affect the expected stress analysis. This heater was shop retubed where the feedwater nozzles were field cut and no misalignment was noted during reassembly. The Wilkes heater is vertical head up with the pipe coming up through the floor, which tends to minimize these loads. Oxygenated water chemistry, with dissolved Figure 2. Crack in the tubesheet to channel radius â&#x20AC;&#x201C; pocket defect uncovered with grinding. oxygen in excess of 100 servative side, typically the industry recommendation is to ppb, can affect crack fatigue keep the rate below 350Â°F/hr. crack propagation in carbon steels. However, Wilkes Unit Additional factors that could impact future crack propa1 is not operated with oxygenated treatment and has disgation are, metallurgical discontinuities, nozzle loads, water solved oxygen levels of less than 10 ppb, so water chemistry chemistry and tube failures. The original material might not should not be an issue. Tube plugging could have an effect have uniform grains (e.g. hard-spots) that are inherent to on crack propagation, and this analysis was done without any plugs. The plugs could cause local higher stress concentrations due to pressure loading and variances in thermal gradients, since water is not cooling the tubesheet in these areas. If a high number of plugs are on the periphery, it could lead to unexpected thermal gradients. However, this was not specifically investigated. There was not sufficient time to do a detailed operational analysis with thermal couples and strain gages, and it was beyond the scope of this paper and the project. A secondary issue also was found. The pass partition welds to the tubesheet/channel barrel Figure 3. Crack in the tubesheet to channel radius indicated by dye penetrant testing (PT).

20 ENERGY-TECH.com

ASME Power Division Special Section | August 2015

ASME FEATURE ASME Power Division: Heat Exchanger Committee

A Message from the Chair

Figure 4. Close-up of crack in Figure 3 with dye penetrant wiped off.

were cracked over almost their entire length. These welds were undersized, single-sided fillet welds. These welds typically crack due to the high stress nature of the attachment created by differential thermal gradients between the thick channel barrel and the thin pass partition plate. These partition welds were replaced with full penetration welds and controlled preheat was applied to the channel prior to welding. A ground in radius into the weld also was designed to additionally relieve stresses in these partition welds. However, these welds will always be highly stressed since they restrict radial growth of the channel and produce a thermal gradient at the attachment to the channel/ tubesheet.

The use of a machined radius to completely remove a crack will significantly reduce stresses at the corner junction of a tubesheet-channel junction. The corner radius concept was applied to designs and repairs in the past and can be applied today in much the same manner, however, greater accuracy can be achieved with modern computing. The 1985 and follow-up 1988 EPRI paper were an investigation by Florida Power & Light (FPL) into a series of similar cracking issues in similar high pressure heater channels. The primary investigation was at the Port Everglades station, but it was reported that several other utilities uncovered similar cracking problems to those found on the Wilkes E feedwater heater. It should be noted that in the 1985 and 1988 EPRI papers, cracking also was found in the shear lugs of the breech lock. The lugs on the Wilkes HP Feedwater Heater were examined by Penetrant Examination (PT) and no cracks were found. A design modification for the Wilkes heater was chosen, based on the desire to quickly place this vessel back

August 2015 | ASME Power Division Special Section

Greetings from the ASME Heat Exchanger Committee! Our committee 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 workshop short courses, the committee organizes the introduction of innovations in relevant technology, case and application studies and industry best practices that are shared with 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 conference phone calls and/or email. We invite you to join us by contacting Heat Exchanger Committee Membership Coordinator Jim Mitchell at JEMPlastocor@aol.com or by phone 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 ASME, HEI, EPRI, ASTM and CTI. This interface ensures a continuous and timely update of information on standards, codes and industry events. We meet twice a year to organize the delivery of valuable conference content. An excellent example of the material presented at one of our technical sessions in 2014 can be found in the following pages; “High Pressure Feedwater Heater Cup Forging Alteration” by Thomas R. Muldoon of AM-EX, and Bob Cashner and Sara Vestfals of AEP. I’m sure you will enjoy this timely and relevant article. Sincerely, Suchat Sonchaiwanich, P.E. ASME Power Division Heat Exchanger Committee Chair Florida Power & Light Company Power Generation Division Engineering Technical Services Principal Engineer Phone: 561 758 0614 E-mail: suchat.sonchaiwanich@gmail.com

ENERGY-TECH.com

ASME FEATURE

Figure 5. 2D sectional view – sketch of vessel and repair.

in service, keep costs down and that the re-tube was in a machine shop environment with easy access to machining centers. Additionally, the crack could be machined out without affecting the ASME minimum wall channel thickness and reinforcement of the nozzle, and no welding was required. The repair method was determined and validated by “design-by-analysis” approach and to verify fitness for service and followed NBIC recommendations for alterations. The crack was machined out and the vessel placed back in service.

Background AEP is one of the largest electric utilities in the United States, delivering electricity to more than 5 million customers in 11 states. It ranks among the nation’s largest generators of electricity, owning more than 38,000 MW of generating capacity in the U.S., with individual unit ratings ranging from 25 MW to 1,300 MW. AEP oversees the design, operation and maintenance of 650+ low pressure (LP) and high pressure (HP) feedwater heaters on subcritical and supercritical pressure fossil generating units. Wilkes Unit 1 is a 178 MW gas-fired subcritical unit that was placed into commercial operation in 1964. There are three vertical low pressure heaters, a deaerator and two

Figure 6. 2D sectional view – original and crack repair details.

22 ENERGY-TECH.com

ASME Power Division Special Section | August 2015

ASME FEATURE vertical (head up) high pressure heaters (designated as E and F) on this unit. The E heater is the subject of this paper and has design inlet and outlet feedwater temperatures of 345°F and 382°F, respectively. The Wilkes Unit 1 E high pressure heater was the original Griscom-Russell heater with Cufenloy tubes (29.1% Ni, 0.35% Mn, 0.5% FE, balance Cu) seal welded to a copper alloy on the tubesheet face. AEP’s experience with 70/30 CuNi tubes in high pressure heaters is that exfoliation of the tube exterior starts to occur after about 25 years of operation. The E heater saw very limited operation from 2005-2011 because new tube leaks would occur within days or a few weeks after the previous plugging event. The E heater was valved out of service in early 2011 because a catastrophic tube failure could have resulted in a turbine water induction incident. Funds were then budgeted to shop retube this heater during an 8-week outage in late 2012. When the shell was removed during the shop retubing, the exterior tube surface had significant exfoliation and about five 55-gallon barrels of scale was removed.

Analysis method Alterations of a pressure vessel design should be done to the original code of construction, according to NBIC (Part 3 Section 1.2).[3] The tubesheet (considered a separate part) for this feedwater heater was not an ASME Code pressure boundary in 1964, therefore, standardized calculations were not available to re-calculate/check the design. The current calculation for tubesheet thickness in ASME Section VIII Division 1, Part UHX is not applicable for this design due to the large un-tubed areas, therefore the tubesheet was chosen to be designed and validated by analysis in accordance with paragraph U-2(g) of ASME Section VIII Division 1. The ASME Section II material property tables were used to determine the minimum yield stresses, elastic modulus, thermal expansion coefficient, thermal conductivity and thermal diffusivity (Table 1). These values were at design temperatures and are governed by time-independent properties. Since the

Table 1 – Material Properties Material

Design Temp (°F)

Yield Stress (psi)

Allow Stress (psi)

Elastic Modulus

SA266 Gr2 (tubesheet)

422

30,470

17,500

27.6e6

SA266 Gr2 (tubesheet)

36,000

17,500

29.2e6

SA212 GrB (skirt)

650

28,200

17,500

25.9e6

SA212 GrB (skirt)

38,000

17,500

29.2e6

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ASME FEATURE materials were from 1964, a 4:1 safety factor was used (i.e. 17,500 psi allowable stress) compared to 3.5:1 safety factor (20,000 psi allowable) for SA266 GR2 today. The material was shown to be SA266 Gr2 on the U-1 data report, and verified by Positive Material Identification (PMI). A 3D design by analysis was chosen to satisfy the requirements of ASME Section VIII Div. 1 U-2(g).[5] The guidelines for this analysis are specified in ASME Section

Figure 7. Mesh – shell side view shown without plates.

VIII Division 2 Part 5 [4], ASME Section VIII Division 1 Part UHX, TEMA Appendix A and RCB 8 and HEI. A linear numerical static Finite Element Analysis (FEA) using ANSYS v14 Static Structural and Design Modeler software was used. The model meshing is shown in Figure 7 and Figure 8, and the boundary conditions are shown in Figure 9. The load cases that were run are summarized in Table 2. These load cases were chosen based on ASME Section VIII Division 1 UHX-12.4 [5] guidelines. These load cases are Tube Side pressure acting only, Shell Side pressure acting only, both Shell and Tube Side acting simultaneously, and the hydro-test conditions. No material nonlinearity was utilized in the FEA, Elastic-Plastic analysis was performed and the stress values were checked to satisfy that plastic buckling would not occur. Deflection, Strain and Maximum Shear Stress were additionally calculated, as well as the equivalent stresses occurring at the shell side face of the tubesheet and in the new machined radius. Each component was calculated individually and compared to the appropriate stresses ASME Code stress limits for both Division 1 and Division 2. The unit has been in operation since 1964, and there was no noticeable corrosion/erosion on the channel side of the tubesheet. Therefore, the vessel was run in the “as-is” state. No additional allowance for corrosion was provided in the calculations. The tubesheet face also is protected from erosion/corrosion by the 70/30 Cu-Ni weld overlay. The shell side exhibited a wash-out/corrosion area in the tube pattern that was measured to be approximately 7/16˝ deep x 3˝ diameter, with smooth transition. This was accounted for in the calculations and is shown in Figure 5.

Analysis The worst load case was found to be tube side pressure acting only as defined by ASME Part UHX-12.4. First a check of the existing design “as-is” geometry, was done with a “Code of Construction” analysis in accordance with NBIC[3] for Alterations Part 3 (See Table 2 for the result). The equivalent stress and maximum principle stress were found to exceed ASME Code limits. This was found as expected in the corner radius (where cracking occurred). The maximum prinFigure 8. Mesh – shell side of tubesheet (DSH and DC zone plates shown).

24 ENERGY-TECH.com

ASME Power Division Special Section | August 2015

ASME FEATURE Table 2 – Load Cases Load Case

Description

Pt (psi)

Ps (psi)

Governing Max Prin Stress (psi)

Governing Yield Stress (psi)

Principle Stress (psi)

Equiv. Stress

Org Design

Tube Side Only

2,500

26,250

30,470

48,532

38,533

Mod Design

Tube Side Only

2,500

26,250

30,470

22,407

26,004

Noe: Pt = Tube side pressure; Ps = Shell side pressure

ciple stress and equivalent stress were significantly above allowable. (Table 2) Analysis of the lugs was not performed since there was not any observed cracking when Penetrant Tested (PT). The stresses induced on the lugs by the cover might have affected the lugs, but should not have had an impact on the tubesheet radius design. The low pressure side (back of tubesheet) and the skirt attachment appeared to be adequately designed. Then analysis was performed on the modified geometry. (Figure 6) It was found that when the modified corner radius was added, the highest stresses moved from the corner radius to the center of the tube pattern. This indicated that bending stresses in the center of the tubesheet, instead of rim stresses, were driving the design. This also indicated that increasing the radius farther would not help the design. Even though the higher stresses moved to the center, the values were fairly close between the rim and the center, and both were within allowable. This channel barrel had additional thickness over Code required minimum for the pressure due to the breech lock design, and this helped add stuffiness to the rim and provide adequate nozzle reinforcement. Next the drains cooler (DC) plates, and desuperheating zone (DSH) plates attached to the shell side of the tubesheet were added to the model. Then several FEA runs were done with various stiffening members to try to beef up the design. An additional stiffener was installed on the shell side of the tubesheet (a symmetric angled flat plate connecting the DSH plate to the skirt) to resist the extra bending expected. These stiffeners help reduce stresses, even though stiffeners of this nature might induce higher localized

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ASME FEATURE stress concentrations and might be susceptible to thermal fatigue type failures. Therefore, conservatively designed full penetration welds with a ground radius were used to mitigate these areas of concern. The boundary conditions for the FEA were determined based on the location of the fixed support attached to the base of the shell (See Figures 5 and 9), or a fixed support through the skirt 9˝ from the shell side face of the

Figure 9. Boundary conditions tube-side pressure acting only.

tubesheet. The length of the skirt used was 9˝, which is greater than calculated using the UHX formula for minimum length to be used in calculations.

Summary and recommendations The repair of the Wilkes heater reduced stress levels at the tubesheet to channel interface (compared to the original vessel), there is a small risk that cracks could reoccur in this area. The machined pocket was Dye Penetrant Tested (PT) in September 2013 (after approximately one year of returning to service), and no defects were noted. It appears the design by analysis approach effectively modeled the repair, and that there was a significant stress reduction in the corner radius due to the repair that was chosen. It is recommended that: • Gradual heating and/or pre-warming of the heater should be maintained with a maximum rate of 350°F per hour and a target of 200°F per hour. Slower introduction of heat will ensure longer operation. • The previous EPRI paper calculated that about 170 cycles (start-up and shut-down) would cause the cracking to reoccur. Prior to 2009, Wilkes Unit 1 typically had less than 20 start-ups and shut-downs each year. Wilkes Unit 1 was designated a black start unit in 2009 and currently experiences less than 10 start-ups each year. As a result, the cracking is not expected to reoccur on the Wilkes Unit 1 E HP heater. • Hydrostatic testing at a pressure above design should NOT be done. Hydrotesting should be done at 2,500 psig maximum for the remaining life of this feedwater heater. If testing must take place over this new specified condition, evaluation of the vessel at the proposed test pressure should be done, such that there will not be an overstressed condition. Conclusion The use of a machined radius to completely remove a crack will significantly reduce stresses at the corner junction of a tubesheet-channel junction. The corner radius concept was applied to designs and repairs in the past and can be applied today in much the same manner, however, greater accuracy can be achieved with modern

Figure 10. Equivalent stress (tube-side view) – original design.

26 ENERGY-TECH.com

ASME Power Division Special Section | August 2015

ASME FEATURE computing. This type of radius is frequently used in modern high pressure feedwater heaters to prevent problems related to thermal and cyclic fatigue and to greatly reduce stress concentrations caused by pressure acting on the tubesheet. If a failure does occur, future inspection and NDE can mitigate additional problems. ~

References 1. EPRI 1988 Feedwater Heater Workshop Proceedings High Pressure Feedwater Heater Channel Head Cracking Update - by R.J Dyr, M.R. Millares, Florida Power and Light 2. E.W. Pianka, “Florida Power and Light High Pressure Feedwater Heater Channel Head Assembly Stress Analysis,” Westinghouse Electric Corporation, STCTR-85-005, June, 1985. EPRI Report CS-4723 3. 2012 National Board Inspection Code - Part 3 Alterations 4. 2012 American Society of Mechanical Engineering Boiler and Pressure Vessel Code, SECTION VIII DIVISION 2 - Part 4 and Part 5 5. 2012 American Society of Mechanical Engineering Boiler and Pressure Vessel Code, SECTION VIII DIVISION 1 - U- 2(g), Part UHX, and NONMANDATORY APPENDIX A

Figure 11. Maximum principle stress (tube-side view) – original design.

This paper, PWR2014-32217, 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. Thomas R. Muldoon, is an engineering manager with American Exchanger Services Inc. (AM-EX), dealing with all aspects of engineering and shop operations for design, fabrication and repair of heat exchangers and condensers. He has a bachelor’s degree in Materials Science & Engineering from the University of Minnesota. You may contact him by emailing editorial@woodwardbizmedia.com. Bob Cashner, P.E., is principal engineer with AEP Mechanical Engineering, dealing with heat exchangers, pumps and balance of plant equipment. He has a bachelor’s degree in mechanical engineering from the University of Missouri – Rolla. You may contact him by emailing editorial@woodwardbizmedia.com.

Figure 12. Equivalent stress (highest stresses in DC/DSH Plates) – new design.

Sara Vestfals, P. E., is the maintenance supervisor at Wilkes Power Plant. She has a bachelor’s degree in mechanical engineering from LeTourneau University. You may contact her by emailing editorial@woodwardbizmedia.com.

Figure 13. Maximum principle stress – new design.

August 2015 | ASME Power Division Special Section

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TURBINE TECH

On-site hydrogen gas for generator cooling More efficient, cost effective and safer By John Speranza, Proton OnSite

The majority of coal-fired plants around the world rely on deliveries of bottled gas to cool their generators. In most parts of the world, hydrogen is cheap and bountiful, but even a small amount of impurity can adversely affect the performance of a plant by many thousands of megawatt hours a year. Stations as diverse as the Alinta Energy Northern Power Station (NPS) in South Australia, the Puerto Rico Electric Power Authority Aguirre Power Plant and the AES-VCM Mong Duong Power Company (AES-VCM) Mong Duong 2 (MD2) Plant in the Quang Ninh Province of Vietnam have all switched to an on-site hydrogen gas generator for their cooling gas needs, and all have experienced improvements in their plant’s operability, safety and bottom line.

Figure 1. The Puerto Rico Electric Power Authority’s Aguirre Power Plant on the Southern shore of the island uses a Proton OnSite C10 Hydrogen Generator to cool its two, 450 MW units. Source: Proton Onsite

Safety is paramount Gas impurity is a worry for power plants, but the primary concern when it comes to hydrogen gas is safety. Hydrogen is highly explosive if not handled carefully, but a plant with numerous generators might need to handle truckloads of heavy cylinders on a weekly basis. “Safety is the top problem with stored hydrogen,” said Justo Gonzalez Torres, head of operations at Aguirre. Many plants choose to keep enough hydrogen to refill their generators in tanks, on-site, but tanks of this size pose significant safety risks, as was the case at Aguirre before it switched to on-site generation. If a standard pressurized tank holding 75,000 standard sq. ft. (scf) of hydrogen gas exploded, it would be equivalent to more than 5,500 lbs of TNT. A stored hydrogen supply also requires more

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manpower to manage. Aguirre employees needed to drive and align large gas trucks, refill vessels and unload the smaller tanks to ensure the plant had enough cooling gas in case the generators had to be shut down and purged. The risks of receiving and handling hydrogen cylinders are real. On Jan. 8, 2007, a truck delivering two, 6,500 scf hydrogen gas cylinders arrived outside the walls of the American Electric Power’s Muskingum River Power Plant in Waterford, Ohio. As operators were unloading the gas, a ruptured relief valve released hydrogen gas, which accumulated underneath a roof and exploded, killing the driver and injuring nine plant operators.

Purity means safety Delivered gas suppliers will ensure their supplies are industrial-grade hydrogen gas, at least 99 percent pure, but it is difficult to be sure that will be the case, and then it is unknown what impurities might still be present. The purity of a plant’s hydrogen gas supply is a crucial issue when it comes to safety. MD2 operators have had past experiences at remote plants, where a temporary hydrogen supply problem meant the delivered gas was less than 90 percent pure hydrogen, and was continuing to fall. At such low purity levels, plant operators began to consider the Upper Explosion Limit (UEL) of hydrogen in the air. The UEL is the upper reaches of the Flammable Range - the range where a concentration of a gas or vapor will burn (or explode) if an ignition source is introduced. Depending on the impurities in August 2015

TURBINE TECH the delivered gas, if the purity falls below 75 percent, a generator’s environment can become explosive, which is a major risk to a plant and its operators. Damon Tohill, the engineering manager at MD2, said his MD2 plant is able to produce Ultra High Purity gas with its on-site hydrogen generator. He noted that MD2’s recorded dew points indicate that it is producing UHP hydrogen upwards of 99.999 percent purity.

Efficient generators use on-site gas Aguirre’s hydrogen-cooled generator casing purity stood at around 96.9 percent purity prior to the installation of an on-site hydrogen generator and gas control system. All generator OEMs agree that even small reductions in hydrogen purity directly correlate to windage friction losses inside the generators, which have a direct impact on a power plant’s bottom line. Even a small percentage of air or carbon dioxide can be detrimental to the performance of a generator. Impurities in a hydrogen supply increase the density of the gas, and the density of a gas affects its ability to remove heat. Air is the most likely impurity to affect hydrogen within the generator casing. Plus, because air is 14.4x as dense as hydrogen, even relatively low levels of air considerably increase the density of the gas mixture. This is shown as:

Equation 1

Where: Gdens = Increase in gas density (%) Hpur = Purity of hydrogen in generator casing (%) Abal = Balance of impurity (air) in generator casing (%) Alexis Cruz, senior shift engineer at Aguirre and his team estimated that for every 1 percent of air trapped in the hydrogen-cooled generator casing there was a 224 kW drop in power production. And because carbon dioxide is even less thermally conductive and more dense, it has an even bigger impact on power production. An additional percent of carbon dioxide in the hydrogen threatens to reduce power production by 345 kW.

Lower dew points, safer power plants For power plants in warmer climates, maintaining low dew points inside a generator is critical. Ideally, hydrogen dew points should be at around -15°C to -20°C to ensure no condensation is formed. Moisture increases the density of the ambient gas in the casing, which affects windage, but more importantly, moisture can lead to generator failure. “If moisture gets into the rotor retaining rings, they are prone to cracking and corrosion,” said Darwin Chellachamy, production manager at NPS, “damage to the retaining rings can be catastrophic.” Nonmagnetic retaining rings, particularly those of an 18 percent manganese-5 percent chromium composition that the

Figure 2. The Proton OnSite C-10 Hydrogen Generator needs minimal supervision and training to maintain and operate. It uses deionized wanted and electricity to produce compressed hydrogen gas only when it’s needed.

industry has used for many years, are susceptible to corrosion attack in the presence of moisture. It is possible for a corroded ring to rupture or explode, damaging the stator end winding, rotor winding and end cover. Explosion and fire from the flammable insulation resins, oil lines and hydrogen gas are also a risk. Not only could moisture destroy a multi-million dollar generator, but it could also lead to operator injury or death. Ensuring UHP hydrogen gas is being supplied to the generator can mitigate these risks. In just over a year of using on-site gas generation, NPS saw marked improvement in the purity and the dew points of its hydrogen. In January 2010, before the switch to on-site generation, the two generators’ average hydrogen purity was 95.95 percent and the average dew point was just -1.87°C. In mid-2013, with on-site generation NPS’ hydrogen supply was averaging at more than 99.5 percent purity and dew points had fallen even further to -21.94°C.

Saving money in the short and long term Delivered hydrogen is cheap and some plant operators will continue to receive hydrogen cylinders in lieu of

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a more expensive, on-site generator. But the costs add up: Aguirre tallied up the costs associated with refilling, transporting and storing hydrogen tanks and discovered it was costing the plant around $103,500 each year. AES-VCM estimated local hydrogen deliveries would have cost the plant more than $6 per Nm3, whereas the plant’s on-site hydrogen generator produces 1 Nm3 of hydrogen gas for just 13 cents, using water and electricity. MD2 estimates that it saves nearly $52,000 each year by producing hydrogen on-site. As well as the cost saving of producing hydrogen on-site, when it’s needed, improved efficiencies also lead to cost savings. By ensuring that it is using UHP hydrogen in its generators, MD2 is reducing windage by more than 872,660 KWh each year. Once AES-VCM hands over its new plant to the Vietnamese government in 2040, it will have saved more than $2.5 million by cooling both its units with an on-site hydrogen generator. Aguirre factored in the impact of higher purity plus improved gas pressure and humidity control, and discovered it had reduced windage by more than 500,000 KWh each year, saving $2.3 million.

Clean, on-site hydrogen gas generation is win-winwin for power plants Taking delivery and handling cylinders of hydrogen gas is an unnecessary risk for power plant operators. It requires more manpower and adhering to additional, onerous safety regulations. It also can be unreliable. Power plants in remote locations might have to wait days or weeks for a delivery of hydrogen gas in the case of extreme weather, or in some countries political and social unrest. Impure hydrogen gas can also have short- and long-term detrimental effects on the performance and life of a generator. Even 1 percent of impurities in a cylinder of hydrogen can cause undue stresses on a generator, allow more moisture into the casings and reduce the performance of the generators. Proton Exchange Membrane (PEM) technology converts water and electricity into hydrogen gas, on-site. It is being used around the world by power plants to cheaply and efficiently produce UHP hydrogen gas when it’s needed. The technology has been proven to work in the most extreme environments on Earth, and is continuing to be developed and enhanced with more efficient membranes and catalysts. For many power plants, the decision to switch hydrogen gas supplies has improved safety, efficiency and bottom lines. ~ John Speranza is vice president of Commercial Hydrogen Product Sales at Proton OnSite. Speranza joined Proton OnSite in 1997 and was involved in the development of its core technology and industrial product line. Prior to joining Proton, Speranza spent 12 years at Hamilton Sundstrand division of United Technologies Corp., developing PEM fuel cell and electrolyzer products for military and aerospace applications. He has a degree in Electrical Engineering Technology from the University of Hartford. You may contact him by emailing editorial@woodwardbizmedia.com.

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

August 2015

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