The power sector is on the cusp of unprecedented transformation, which is being driven by technological forces outside the power sector. It’s not surprising, considering the convergence of digital solutions, power plant technologies and technical advancements in automation.

Expect both great collaboration and intense competition between these brash newcomers and the industry’s established players. These new drivers of change are creating new possibilities for power producers and consumers. The established players and these new drivers of change will be gathering Dec. 5-7 in Las Vegas, Nevada, for POWER-GEN International 2017.

POWER-GEN is where the greatest minds in power generation gather once a year for the world’s largest forum for power professionals. It’s where the best and brightest in power generation have been meeting for 29 years to discuss the mechanics, chemistry, operation and regulation of power generation.

Attendees of POWER-GEN International can also choose from 18 pre-conference workshops on Sunday Dec. 3 and Monday Dec. 4. All workshop attendees receive a certificate of completion. Certificates of completion may be submitted to your professional organization for Professional Development Hours.

About 20,000 power professionals from around the world are expected to attend the three-day event to discuss the most innovative and cost-effective solutions for maintaining, operating and building new power projects. In addition, about 1,400 exhibiting companies from every sector of the industry will be showcasing their products and services on the exhibit floor. The exhibition opens at 11:30 a.m. Tuesday Dec. 5 following the keynote session.

POWER-GEN International offers a wealth of networking opportunities with leading professionals and key decision makers. About 280 speakers will share their thoughts on trends, technology and project development in 60 conference sessions. A wide range of topics, from data analytics to gas turbine design, will be discussed by high-ranking regulators, developers, power producers and manufacturers.

“You can attend some great technical sessions. You can walk the exhibit floor and learn about hundreds of companies,” said Tom Ghesquiere, chairman of POWER-GEN’s Gas Turbine Technologies Track. “If you want to expand your experience beyond that, you could attend the pre-conference workshops or the power plant tours.”

The keynote session on Dec. 5 will feature five high-ranking executives, including J. Patrick Kennedy, founder and chief executive officer of OSIsoft; Stefan Bird, president and CEO of Pacific Power; Stan Connally Jr., chairman, president and CEO of Gulf Power; Blake Moret, president and CEO of Rockwell Automation; and Paul Browning, president and CEO of Mitsubishi Hitachi Power Systems Americas.

More than 20,000 power professionals are expected to attend POWER-GEN International 2017, Dec. 5-7 at the Las Vegas Convention Center.

Conference sessions will be held under 14 tracks or topics: Emissions Control; Flexible Generation and On-Site Power; Plant Performance; Gas Turbine Technologies; Energy Storage; Business Trends and Regulatory Issues; The Digital Power Plant; Power Project Financing; Material Handling; Utility-Scale Renewable Power; Distributed Renewable Power; Clean Coal Technologies; and Gas-Fired Power Plants; and Nuclear Power.

“We’ll be doing a deeper dive into areas such as performance and efficiency gains and other trends and developments,” Ghesquiere said. “I’m really looking forward to some excellent sessions throughout the Gas Turbine Technologies Track.”

Here’s a sample of some of the sessions that will be offered at POWER-GEN: “Smart Analytics to Improve Plant Performance;” “Cybersecurity: Avoiding the Dark Side;” “Energy Storage Project Deployment Around the World;” “Integrated Energy Storage;” “Combined Cycle O&M Considerations in Today’s Dispatch Market;” “Technology Solutions for Fast Starting Natural Gas Fired Plants;” “Gas Turbine Maintenance, Upgrades and Field Experiences;” “Gas Turbine Fuel Flexibility;” “Making CHP Work for You;” “Material Handling and Maintenance Upgrades;” and “Financing Trends in Grid-of-the-Future Power Projects.”

Six mega-sessions are also scheduled: “Large Frame Combustion Turbine Technology Update;” “Remote Monitoring and Diagnostics: Opportunities for Analytics to Improve Plant Performance and Reliability;” “North America is Long on Natural Gas: Will Power Generators Be Able to Get It;” “Can Carbon Capture Save Us?”

POWER-GEN International attendees will see or hear about new technologies that promise to change the way the industry generates power. Several sessions will center on the promise of energy storage, an emerging market driven by new mandates and demands for cleaner, more reliable power.

“We are going to cover some of the most recent advancements in Energy Storage, including new projects installed over the last year,” said Vibhu Kaushik, principal manager of Asset Management & Generation Strategy for Southern California Edison and chairman of POWER-GEN’s Energy Storage Track.

During POWER-GEN, about 280 speakers will share their thoughts on trends, technology and project development in 60 conference sessions. A wide range of topics, from data analytics to gas turbine design, will be discussed by high-ranking regulators, developers, power producers and manufacturers.

THREE TECHNICAL TOURS

Technical tours of two power generation facilities will be offered to attendees on Monday, Dec. 4:

Hoover Dam

Just a short drive from the glitter and glamour of Las Vegas, the Hoover Dam is a testimony to America’s ability to construct monolithic projects amid adverse conditions. Built during the Great Depression between 1931 and 1935, thousands of men and their families came to Black Canyon to tame the Colorado River. It took less than 5 years to build the largest dam of its time.

Now, 82 years later, Hoover Dam still stands as a world-renowned structure. Hoover Dam is a National Historic Landmark and has been called one of the Seven Engineering Wonders of the Modern World. This engineering project not only enabled the industrial development of the Pacific Southwest, but it also forms Lake Mead, the largest man-made reservoir in the Western Hemisphere.

Before your guided tour of Hoover Dam, you will have a short presentation on how the west was won with. Next, your guide will take you over 500′ down one of our enormous elevators to the Nevada wing of the power plant, where you overlook the massive 7-story tall generators. From there you will go on your own out to the Observation Deck on top of the Tour Center, where you can view the river flow, the lake and the massive expansive of the Hoover Dam.

Walter M. Higgins Generating Station

The Walter M. Higgins Generating Station is a clean-burning natural gas-fueled power plant located in Southern Nevada near the California border. The plant utilizes two highly efficient Siemens-Westinghouse 501FD2 combustion turbines to produce electricity. Additionally, the exhaust from the two turbines is recycled to produce steam for an Alstom STF30C steam turbine to make additional electricity for NV Energy customers.

The plant went into service in 2004. Unlike conventional power plants that use substantial amounts of water for cooling, the Higgins Station uses a six-story-high dry cooling system. Similar to a car radiator, 40 massive fans (34 feet in diameter) are used to condense the steam and cool plant equipment.

Goodsprings Energy Recovery Station

The Goodsprings Energy Recovery Station achieved commercial operation in 2010 and uses hot exhaust from a neighboring natural gas compressor station to generate electricity. The hot exhaust heats a thermal oil transfer fluid at the compressor station, which is then circulated to the Goodsprings power plant equipment and is utilized to vaporize an organic working fluid into a gas. The expansion force of this gas drives a small turbine generator to make electricity.

This creative renewable energy approach to making use of such waste heat is the first in Nevada. In the normal operation of the Kern River Gas Transmission Co. compressor station – which primarily is used to move natural gas through Nevada to California – some waste heat is released to the atmosphere. This thermal energy is captured and converted to electricity in much the same way that some geothermal energy power plants capture heat from hot water deep below the earth’s surface.

PRE-CONFERENCE WORKSHOPS and CEU Credits

Attendees of POWER-GEN International can also choose from 18 pre-conference workshops on Sunday Dec. 3 and Monday Dec. 4. All workshop attendees receive a certificate of completion. Certificates of completion may be submitted to your professional organization for Professional Development Hours.

Some of the workshop topics include: “Effective Project management for the Power Project professional,” “Secrets to Executing a Successful Turbine-Generator Outage,” “Energy and Electricity Storage: Grid and Distributed Storage with a Discussion of Variables Related to Storage Options,” “Cycle Chemistry for the Power Industry: A Practical Course on Best Practices,” “Machine Learning for Power Plant Managers,” “HRSG Fundamentals: Operations, Inspections, Trouble Shooting and Maintenance of Combined Cycle HRSGs.”

For a complete list of pre-conference workshops, go to http://www.power-gen.com/conference.html.

Several sessions at POWER-GEN will be devoted to the industry’s transition to power fueled with natural gas and renewable resources. This trend will continue, which means gas-fired plants must be faster and more flexible to effectively offset the inherent fluctuations of renewable power.

In addition to speed and flexibility, POWER-GEN speakers will be exploring new methods and strategies for maximizing net fuel efficiency. Air quality control system upgrades for existing coal-fired plants and operation and maintenance practices for nuclear plants will continue to be chief staples of our conference program in 2017. What’s more, we will be taking a closer look at the technologies driving the digital transformation of power generation.

To attend POWER-GEN, to www.power-gen.com to register. See you in Las Vegas!

Editor’s Note: This article is based on a paper presented at POWER-GEN International on Dec. 14, 2016.

The United States electric energy sector that includes utilities, independent power producers, public power authorities, renewable developers etc. has been traditionally considered a relatively safe and defensive investment due to its potential for providing a steady stream of dividend income.

The Crescent Dunes Solar Energy Project near Tonopah, about 190 miles northwest of Las Vegas, Nevada.

The electric energy sector’s vulnerability to shifting market conditions has become more evident in recent years due to environmental regulations, a sustained push for higher penetration of renewables and continued volatility in fuel prices. While part of the problem facing renewable developers includes a heavy debt burden and an inflexible market structure that is not necessarily aligned with the changing mix of resources, the conundrum that other market participants are facing include the relentless pressure on coal market participants due to various environmental regulations1 and lower natural gas prices and the adverse impact on the profitability of certain nuclear power plants due to lower natural gas prices.

Figure 1 shows capacity additions by fuel type in gigawatts from 2000 to 2020 while Figure 2 lists the retirement of power generating facilities during the same time period. The first five years starting year 2000 saw the emergence of merchant power facilities across the nation followed by a period of high natural gas prices. While new coal facilities were being proposed around the 2009-2012 time frame, stricter environmental regulations forced cancelation of new coal units as well as shutting down of uneconomic coal-fired plants. Renewable resources started leveraging the federal tax credits and state level mandates starting 2008, with occasional spikes in construction activity following the extension of federal tax credits, and continue to grow at a steady pace. Nuclear facilities, while currently facing losses in certain market areas in the country, the Southeast is experiencing growth for second generation nuclear facilities by 2020.

The current electric energy landscape, while promoting fuel diversity through the use of fossil-fired power plants running on coal, natural gas, oil etc. along with plants running on energy generated from the sun, wind, nuclear fuel, hydro, biomass, geothermal, landfill gas, fuel cell etc., also attempts to maintain a diversified set of resources while taking into account the potential and limitations of various regions in the country.

Figure 3 lists the resource mix, in percentage for three representative years (i.e. 2005, 2016 and 2040) across five regions that include ERCOT or Texas, MW (Midwest), NE (Northeast), SE (Southeast) and Western Electricity Coordinating Council (WECC) or areas covering California, the Northwest Power Pool, Rocky Mountain Power Area etc., under the ABB Base Case as forecasted by ABB EPM Advisors2.

The ABB Base Case is a forecast of future conditions based on fundamentals of demand or load forecast and supply or fossil-fired and renewable resources as well as fuel prices (natural gas, oil, uranium, coal), non-power demand curves, energy efficiency, demand response, distributed generation, power market, emission, and renewables rules, transmission topology etc. Markets covered include the Electric Reliability Council of Texas market or ERCOT, the MW region that includes the PJM Regional Transmission Organization (RTO) covering 13 states and District of Columbia, the MISO RTO covering 15 U.S. states and the Canadian Province of Manitoba, the Southwest Power Pool (SPP), Saskatchewan region, the Northeast region that includes the New York ISO, the New England ISO and the Canadian provinces of Ontario, Quebec and Ontario, the Southeast region of United States and the WECC region that includes the California ISO, the Northwest Power Pool, Rocky Mountain Power Area, the Desert Southwest etc.

The resource mix graph listed above shows the decline in coal from 19 percent in 2005 to 15 percent by 2040 in ERCOT, from 43 percent in 2005 to 22 percent by 2040 in the Midwest, from 36 percent in 2005 to 17 percent by 2040 in the Southeast, from 9 percent in 2005 to 1 percent by 2040 in the Northeast region and from 19 percent in 2005 to 8 percent by 2040 in the WECC region. As indicated earlier, these coal retirements (i.e. announced, age-based and economic3) are driven not just by environmental regulations but also by lower natural gas prices in the ABB Base Case. In order to maintain reserve margins across the five regions and to meet future forecasted load growth, new power plants, typically natural gas-fired, are added to the resource mix and by 2040, they account for 57 percent in ERCOT, 56 percent in the Midwest, 64 percent in the Southeast, 61 percent in the Northeast and 36 percent in the WECC region.

Lower natural gas prices and the ability of natural gas-fired units (i.e. Combined Cycle Gas Turbine) to run as baseload units are an obvious driver for resource additions in the ABB Base Case but it is also important to note the level of uncertainty associated with the natural gas market. Examples include the price spikes related to hurricane Katrina in 2005, the polar vortex of 2014 as well as the 2016 methane leak at a Southern California natural gas storage facility. But the share of renewable resources increases by 2040 across all the regions due to favorable federal and state policies4 and declining cost of solar and wind assets. By 2040, the share of renewables increases to 24 percent in ERCOT, 14 percent in the Midwest, 5 percent in the Southeast, 16 percent in the Northeast and 36 percent in the WECC region. In sharp contrast, the corresponding 2005 share of renewables in ERCOT is 2 percent, 1 percent in the Midwest and Southeast regions, 3 percent in the Northeast region and 4 percent in the WECC region. The share of nuclear resources in 2005 that range from 6 percent in ERCOT and WECC regions, 11-12 percent in the Midwest and Southeast regions to 13 percent in the Northeast region is reduced to 4 percent in ERCOT and the Midwest regions, 5 percent in the Northeast region, 3 percent in the WECC region and 8 percent in the Southeast region. The decline in nuclear power capacity by 2040 is driven by lower natural gas prices as well as expiration of their operational licenses.

Carbon Emissions in the Power Sector (United States)

What does the forecasted change in resource mix between 2005 and 2040 mean for carbon emissions? Figure 4 lists the impact on CO₂ emissions5 under three scenarios6 that include the ABB Base Case, the High Renewable Penetration and Nuclear Life Extension scenarios. Carbon emissions in 2005 were at 2,500 millions of tons but the forecasted capacity additions and retirements in the ABB Base Case result in lower carbon emissions throughout the forecast horizon of 2016 to 2040. CO₂ emissions peak at 22 percent below 2005 levels by 2019 and decline to 6 percent below 2005 levels by the end of forecast period in the ABB Base Case.

While CO₂ emissions are also lower in the High Renewable Penetration and the Nuclear Life Extension scenarios7, the option of choosing a particular type of resource mix becomes clearer under these scenarios. There is no denying the fact that higher penetration of renewables is inevitable given their declining cost (i.e. solar and wind) and favorable renewable policies in the country but if United States is to cost effectively meet its carbon emission reduction targets while preserving fuel diversity, perhaps a rethinking of our expectation for the future resource mix is warranted?

High Renewable Penetration Scenario

The High Renewable Penetration scenario that reflects the same assumptions as those in the ABB Base Case except for an additional 173 gigawatts of renewable resources results in carbon emissions that is 11 percent below 2005 levels. In contrast to the High Renewable Penetration scenario, carbon emissions under the Nuclear Life Extension scenario are 13 percent below 2005 levels. The Nuclear Life Extension scenario has the same assumptions as the ABB Base Case except for the assumption that all nuclear units receive approval for life extension beyond their current license period thus resulting in the availability of approximately 100 gigawatts of nuclear capacity through 2040. Key takeaways from these scenarios is not the just the potential for reductions in carbon emissions8, but also the level of investment involved and the cost-to-benefit impact.

Figure 5 that displays the resource mix under the High Renewable Penetration scenario9 depicts the expected decline in nuclear and coal resources through the forecast period as driven by lower natural gas prices and environmental regulations. In order to meet load growth and reserve margin requirements, the resource mix is supplemented by new natural gas-fired resources and a large number of renewable resources during the forecast horizon. But renewable resources such as solar and wind, while effective at lowering carbon emissions, are also weather dependent, may end up being curtailed during periods of over-production and have lower capacity factors necessitating dependence on flexible natural-gas fired resources as a backup resource.

Nuclear Life Extension Scenario

Extending the life of nuclear resources, on the other hand, not only reduces the investment flows related to new natural gas-fired resources that are added during the forecast period but also ensures compliance with the 2012 carbon emissions target at a more sustainable pace in comparison to the ABB Base Case. Figure 6 lists the resource mix under the Nuclear Life Extension scenario10. In comparison to the ABB Base Case, this scenario results in a decline in new natural gas-fired resource additions through the forecast period due to the availability of additional baseload power from nuclear resources that run at relatively higher capacity factors.

Despite the advantages that nuclear resources appear to display in comparison to other types of resources, whether renewable resources or fossil-fired plants, a number of nuclear power plants today are in a near crisis state. Nuclear power plants in New York, California, and Illinois11 are some prime examples and the plant owners and operators blame lower natural gas prices, lack of price for carbon, and higher cost of operating the power plants for the looming crisis. Higher investment and financing costs, waste disposal costs, lingering safety issues especially after the Fukushima accident regarding radioactive contamination risks and longer lead times for new nuclear power plants are cited as constraints for new nuclear facilities. Despite these concerns, it is important to note that there are some nuclear plants that are well located in certain markets, are profitable and therefore not facing the threat of closure.

Does this mean that it is a doom-and-gloom scenario for nuclear facilities across the country? Not if you take into consideration the United States Department of Energy’s (DOE) target of 200 gigawatts of nuclear capacity additions by mid-century in its June 2016 Vision & Strategy report for advanced reactors. The DOE has called for at least two advanced reactor concepts to be developed, and to have reached technical maturity and completed licensing reviews, by 2030. It has also announced $82 million in funding to support advanced nuclear energy research, with 93 projects in 28 states receiving awards. The federal agency has also indicated that it would support cost-shared, industry-led research and development for concept-level development and conduct research into high-temperature reactor concepts, liquid metal cooled fast reactors, gas fast reactors and molten salt cooled reactors to further enhance its testing capabilities and support the timely deployment of advanced reactors.

In New York, the Public Service Commission (NYPSC) Staff proposed and the Governor of the state recently approved, a nuclear tier12 under its Clean Energy Standard (CES) to extend a lifeline to the struggling upstate nuclear power plants and to provide a ‘bridge’ until renewable resources are developed on a large scale. Under the state’s nuclear tier, the nuclear operators are eligible to earn Zero Emission Credits (ZECs) although the maximum price for the ZEC would be administratively set by the NYPSC. Also like RECs, ZECs will be tradable, but the two types of products would not be interchangeable under the CES.

Low Carbon and/or Carbon-free Outlook

While there are undeniable benefits under a Low Carbon13 or a Carbon-free14 outlook in terms of lower carbon emissions for the future electricity grid, there are numerous challenges that need to be addressed. Both wind and solar powered facilities can look forward to lower capital costs over the next decade or more. Figure 7 displays the wind and solar experience curves15 which represents the percent decrease in prices with the doubling of worldwide installed capacity. For onshore wind, the percent decrease in prices is 19 percent with four doubling of capacity in the past 15 years and for solar PV modules, the percent decrease in prices is 24 percent with 7 doubling of capacity in the past 15 years. The extension of federal tax credits also bodes well for the renewables sector.

All the same, the Low Carbon or a Carbon-free grid outlooks will need to take into consideration challenges such as vast dollar outflows related to strengthening of the transmission infrastructure to deliver power from remote locations to consumption markets, financing difficulties, existing market designs16, variable generation, rate structures etc.

One of the many challenges to highlight would be the lack of tax equity capacity posing a strong impediment for further growth in the renewables market. The Production Tax Credit (PTC), a key driver for wind projects has allowed developers to monetize tax credits17. The monetization involves a ‘partnership flip’ structure that removes the tax credits and delivers them to an equity owner in a partnership. The project developer thus holds a minimum level of equity with about 90 percent of the equity transferred to a partner that can use the credits to offset taxable earnings, or that can package those credits and sell them to other parties with a tax appetite. When the after tax rate of return is achieved, usually timed with the 10-year expiration of the PTC, the partnership structure flips, with the developer taking 99 percent of the equity in the project. The dearth in these types of innovative mechanisms post expiration of the tax credits will continue to pose a challenge.

Another potential area to re-evaluate is reconciliation of policies that require economic competitiveness as well as cost effectiveness for consumers at the same time. As an example, let’s look at the potential conflict arising from the re-design of the Regional Greenhouse Gas Initiative (RGGI) market versus state of Maryland’s objectives. In 2014, RGGI set an emissions cap of 91 million tons that declines by 2.5 percent annually to 78.2 million tons by 2020. Environmental advocates and Massachusetts state officials have called for doubling the rate of decrease to 5 percent annually but that could potentially create problems for Maryland. Power plants in this state operate and sell into the PJM markets and compete against generators in Pennsylvania, Ohio, West Virginia and Kentucky states that aren’t impacted by the same restrictions. Under the proposed RGGI market re-design, the proposed emissions cuts could price power producers in Maryland out of the market. Therefore, the state of Maryland has requested a consideration of economic competitiveness and the cost of energy to local ratepayers in the re-design of RGGI market.

Does the current market structure create sufficient incentives to meet the objectives under the Low Carbon or Carbon-free grid Outlooks? Rate design challenges is another area that will need to be looked at under the Low Carbon or Carbon-free grid Outlook. A large portion of a typical utility’s costs are fixed but a major portion of their revenues is variable. The typical utility rate design consisting of a small monthly fixed charge and a volumetric energy charge does not help in recovering the utility’s fixed costs. The expectation of a higher penetration of renewables and load dampening through demand response and energy efficiency will slow down the already anemic growth in sales and therefore the typical utility rate design will not be able to assist in recovering the utility’s required revenues.

Another aspect to consider is the level of technological and market structure related changes that will be required to achieve carbon emission reductions under the Low Carbon or the Carbon-free grid Outlooks. The magnitude of technological and market structure related changes to achieve, for example, the 2030 carbon emission reductions, may be very different from what will be required to get to the next frontier in carbon emission reductions (i.e. 2040 and/or 2050 carbon emission reductions).

The future as envisaged under the Low Carbon or Carbon-free grid Outlooks may appear daunting but remains feasible provided policies and implementation mechanisms, whether technological and/or regulatory, are allowed to develop and evolve. This will require bringing about changes in rate structures, market design, regulatory policy, operating procedures etc. in addition to innovative technical solutions.

Author
Shilpa Kokate is an advisory consultant for ABB Enterprise Software Inc.

Breakdowns of the electrical insulation system have been documented to cause catastrophic failure of critical equipment. Partial Discharges (PD) are measured on rotating machines in order to prevent early failures occurring in stator insulation. However, only a few electrical generation companies have adopted permanent PD continuous monitoring solutions, while most use only periodic tests.

The Tennessee Valley Authority (TVA) has engaged periodic on-line PD tests for several years with mixed results regarding the agency confidence and understanding of PD system results. Sporadic acquisition of PD data is one of the barriers to widespread deployment of permanent monitoring systems, and the clear understanding of results is another drawback. In particular, TVA recognized the need for an easy to interpret ‘picture’ that can intuitively show PD results to power-plant operators and asset managers, without the need of an expert in PD theory to review and to provide data interpretation.

This article details real case studies using a new technology, designed specifically for generators, which shows continuous PD monitoring data in an intuitive and informative format. This information will help the plant to plan corrective actions, improve operating conditions, and defer the need for experts in data interpretation. These results are achieved by continuously monitoring PD activity and automatically correlating recorded PD with operating condition parameters such as active power and temperatures. Periodical comparison of data recorded at the same operating conditions provides reliable trending to trigger alarms. Visual maps provide immediate understanding of PD behaviour with respect to copper temperature and load. This comparison enables the machine owner to manage machine loading and cooling to extend insulation reliability. Additional diagrams provide a cumulative summary of PD activity at machine start, stop, low, medium and high load, all of which is of particular interest when generators operate at peak demand, cycling, or at system automatic loads.

Several stator failure mechanisms have reported a close correlation with PD activity. Some of the most common defects generating PD are described as follows:

• Thermal deterioration: chemical ageing process increasing internal gas pressure and decreasing the adhesive strength of the epoxy-mica interface, resulting in voids, delaminations and PD;
• Thermal cycling: thermomechanical stress due to different thermal expansion coefficients of the materials involved weakening and breaking the bond between the copper and insulation, generating delaminations within the insulation and PD;
• Poor resin impregnation: leaving distributed air bubbles within insulation and generating PD;
• Loose stator bars: due to the vibrations, the bar moves in the slot, damaging and abrading the slot conductive coating and generating PD (Slot PD);
• Semicon coating: generating PD within the space between the stator and the coil (Slot PD) due to too excessive initial resistance or poor application of the conductive coating;
• Semicon/Stress-grading junction: poor connection between the stress grading tape and the conductive coating, generating PD between the junction between the two materials;
• Inadequate end-winding spacing: causing insufficient clearance between the bars and generating PD between the bars in the end-winding;
• Contamination: causing surface tracking in th e end winding.

It is well known that the analysis of PD trends over the years establishes an effective method to assess the insulation degradation rate, since an increase of the defect size (volume of void, gap between coil and stator, surface tracking path, etc.) generally leads to an increase of PD intensity in terms of amplitude and/or number of discharges. Potentially, the trend analysis can be obtained by comparing periodic measurements (off-line and on-line) or using a continuous 24/7 monitoring system.

Off-line PD measurements (machine not running, external voltage source applied phase by phase) are generally inadequate to detect loose-bars defects (load is absent during the test), to confirm deterioration of the voltage stress coatings (temperature and humidity cannot be varied during the test) and to investigate discharges between phases.

On-line measurements represent the most effective method to detect all possible PD sources since the machine is tested at real operating conditions. However, periodic on-line tests have limitations since it is difficult to replicate the PD measurement at the same identical operating and environmental conditions, resulting in an uncertain and unreliable comparison. As a matter of fact, PD intensity can significantly vary hour after hour in normal conditions due to the load and temperature changes. For example, high discharges can occur at generator start-up, due to open gaps in the ground-wall insulation, and disappear in few hours due to the coil temperature increase, which causes the copper to expand and fill the gaps [5-6]. In other cases, high load or high temperature can result in a sudden increase of slot discharges which would disappear at cold temperature or low load. For this reason, PD trend evaluations must take into account environmental and operating conditions. The key point is to compare PD intensity at nearly the same voltage/load/temperature/humidity conditions.

The use of permanent monitoring systems, recording diagnostic (PD), operational (voltage, active power, reactive power, copper temperature, cooling temperatures, H₂ pressure) and environmental (temperature, humidity) parameters represent the only way to carry out a meaningful correlation over the time at the same identical operating condition. The collected data shall be easily grouped basing on the chosen parameters to show a summary of the insulation status at cold or warm machine, at low or high load, etc. The importance of making the recorded data meaningful and easy-to-interpret is fundamental to allowing decision makers to compare the status of the generators, manage operational stresses in time, and devise a real condition-based maintenance plan.

The following paper describes a trial project, carried out by TVA and Camlin Power, which equipped four generators with a continuous PD monitoring system. The results from three of the four generators are reported due to two of the generators showing no PD. These results highlight the benefits of the applied technology within the TVA monitoring and maintenance program.

TVA ROUTINE MAINTENANCE AND EXPERIENCE

TVA Kingston Fossil Plant (KIF) has 9 generators, all of which were installed from 1954-1956. Four of them are rated 175 MW while the others are 200 MW. All machines are Hydrogen cooled and have VPI single-bar insulation, except one stator that is Resin Rich. A full rotor-out major outage is carried out every 10 to 12 calendar years. Wedge and endwinding tightness inspections, as well as routine electrical tests (winding resistance and 2500 volt megger/10 minute polarization index) are included in the outage scope. Minor outages are spaced between the major inspections and include routine electrical tests. Over the past decade, TVA Kingston has invested in partial discharge analysis on the generators. Most of the nine generators have bus couplers installed, and the units were tested annually. However, the data obtained from these tests did not prove to be useful. While the plant was supplied with Qm+ and Qm- levels from a testing vender, there was no indication of what was acceptable or unacceptable. In addition, the data seemed erratic. There would be a higher magnitude PD level one year, followed be a lower level the next. A PD expert had to be contacted to translate the data to be beneficial for onsite employees. Still, the information obtained did not contain operational recommendations that could be used to lower PD levels. As a result, partial discharge levels in Kingston generators were never fully valued and were only kept for trending purposes.

PD MONITORING SYSTEM DESCRIPTION

TVA has decided to engage a trial evaluating a permanent, continuous PD monitoring solution. The permanent monitoring system consists of a set of three capacitive couplers and an acquisition unit. Existing couplers already installed in the generator can be used, thus there is no need to replace the hardware installed in the past. For the TVA KIF trial, existing sets of 80 pF couplers were used. The acquisition system module includes an acquisition board, a module for external inputs, an embedded PC with integrated server, and modem. This module connects to the machine side bus couplers and records continuously. A de-noising logic algorithm uses the simultaneous signal acquisition from the three phases and automatically rejects what is considered noise. The resulted data is saved in an embedded database. A summary of the recorded activity is performed every 10 minutes. The output data includes the well-known parameters such as Qmax (Volts and pC), Repetition Rate (pulse-per-seconds), Qm+, Qm-, NqN+ and NqN-. Additionally, Qmax and Repetition Rate are combined into a non-dimensional parameter called PD Energy (PDE), which is evaluated for each phase of the machine. Operational and environmental parameters (megawatts, megavars, stator temperature, etc. are recorded simultaneously and continuously with the PD data. A total report is then produced with the correlated data (PD and machine parameters).

Using the report data, a 3-D PDE map is created. A dot is plotted every N minutes (N = data sample rate) with X, Y coordinates representing the operating conditions. The user can choose the parameter to be used in both axes depending on his needs, experience and parameter availability. Each dot is coded by color using a scale from green (low PDE) to red (high PDE), depending on the PDE level recorded.

As an example, Fig. 1 summarizes 4 months of data from a 300 MW turbo-generator with a sample rate of 10 minutes. The X and Y axis are active power and copper temperature respectively. The meaning of the shape of the cluster is straightforward: each PDE dot corresponds to a certain operating condition with a certain active power and copper temperature. As a result, four areas can be easily segmented in the plot:

• SS: Start-Stop region, characterized by low power (below minimum-technical)
• LT: low-temperature region, the machine operates at significantly low temperature, generally after the start
• MT: mid-temperature region, it should represent the “normal” operating condition
• HT: high temperature region, the machine operates at temperatures not far from the maximum from design

The thresholds for defining the four areas are configurable and is customizable to each machine.

As an example of interpretation, the PDE Map in Fig. 1 shows that the monitored machine is load-base (very few dots in the SS and LT area) with very low PDE activity at the start and low temperature conditions (mostly green dots). The machine is mainly operating at medium and high temperatures. The PDE is low in the MT region (still green predominance). However, the HT region, especially above 85°C, correlates to a higher PDE (red predominance).

In this particular example case, the utility previously used periodic PD testing (every 6 months). The owner was not aware of the correlation between PD and temperature. With the above results provided, the owner took action to increase cooling at higher loads. Thus, they were able to bring the machine to operate mainly in the MT area (even at high loads). The result generated a predominately green PDE map which depicts slower degradation.

In terms of trending PD, the monitoring system has the capability to extract a weekly summary indicating the PDE level at each of the designated operating temperatures. Figure 2 shows an example of the same machine above, monitored for a certain week where a few start-ups/shutdowns were also made. The weekly summary is in agreement with the PDE Map. It confirms that PDE increases with temperature and it is maximum at high temperature (HT), i.e. above 90 °C. The summary also shows PDE for each phase, highlighting the predominance of PD activities in C phase (red).

The values shown in Fig. 2 are then generated weekly. These reports create meaningful trends at similar operating conditions. Three different alarms can be sent to the owners/operators – one for each operating range (LT, MT, and HT). In addition to the three temperature ranges, the correlated PDE and operational data can separate start-up and shutdown periods. These operational conditions provide the potential for two additional alarms (start and stop). This feature is important for cycling units, which sometimes show higher PD levels during these periods due to voids and delaminations. Typically, these time periods go unmonitored when using the conventional periodic PD testing techniques.

TVA TRIAL

The trial has taken place at the TVA Kingston Fossil Plant. Four generators where monitored for several months each. Table 1 shows the characteristics of the generators.

Figure 3 below shows PDE maps collected from Units 6, 7, and 8. Using the same PDE color scale (max PDE=90) and the same operational parameters on the X and Y axis, the maps are comparable between all three sister units. The comparison reveals that all three insulation systems are in different conditions. This fact alone stresses the importance of knowing which factors (temperature, loading, voltage, etc.) of PD are contributing to the resultant PDE levels. From these initial maps, each unit was analysed deeper.

Unit 6

The PDE map shows that this unit is mainly affected by PD at low temperatures. When temperatures exceed 60 °C, PDE levels are significantly attenuated. Note that when the machine operates at maximum power and temperature, PDs are not active (predominance of green dots). This could be due to presence of voids in the insulation when the copper is not fully expanded, producing PD when gaps are still present. As soon as stator temperature increases, copper expands and squeezes the voids reducing the PD activity. The analysis is confirmed by the weekly data aggregation for trending purposes shown in Fig. 4 (LT=55°C, HT=60 °C) which emphasises the PD decrease with temperature increase. This is an opposite behaviour with respect to the machine shown in the example in Fig. 1. – again stressing the importance of the correlation between PD and temperature.

After having noted this relationship, TVA took an action by raising hydrogen temperature from 90°F to 95°F which, in turn, raised the stator temperature of about 5 to 10 °C depending on the power. The mitigation effect on the PD activity was observed immediately. Figure 5 shows the PDE Map of about 3 weeks of data before and after the new “temperature setup”.

As highlighted in the picture above, there is a clear benefit of the temperature change when looking at the PDE at around 120 MW. Before the change, the temperature was ranging between 52 and 58°C with the color of the PDE dots mainly red. By increasing the temperature in the stator to 60-67°C at the same load, the PD activity is significantly reduced (predominately green dots). To confirm the results, Phase Resolved Partial Discharge (PRPD) patterns (for Phase A) are provided in Figure 6. Note that PD activity is considerably reduced; in turn, the degradation process will be lessened. At the same time, an increase from 58 to 67°C in the stator does not lead to any detrimental consequence since the machine is still operated at a relatively low temperature with respect to its insulation class.

Unit 7

Unit 7 shows red dots more or less in every operating condition, thus with no evident separation between low or high load and temperature. In this case the PDE Map is further analysed for each phase (depicted below in Figure 7). This figure allows the user to easily identify that there is just one phase particularly affected – phase B.

The Phase Resolved Partial Discharge (PRPD) pattern was analysed in this case, for phase B. The pattern, shown in Fig. 8, shows a predominant stress-grading activity [11] which suggests a visual inspection of the end-windings, in particular the corona protection tapes. A preliminary boroscope and bushing box inspection has been scheduled to identify potential issues in this area.

Unit 8

Unit 8 shows small PD activity. All of the PDE dots are green in each operating condition. This information allows TVA to defer any planned projects or inspections relative to the insulation condition of this machine. Also, this PDE map can serve as a baseline for weekly alarms. The recorded operational conditions will assist in troubleshooting and analysis if a step change in PDE should occur.

CONCLUSION

The results on Unit 6 have demonstrated that mitigation actions can be taken if meaningful information is provided to decision makers. Delivering periodic reports from on-line or off-line measurements, indicating just PD magnitude with no correlation to load or temperature, is insufficient to adequately describe and assess the insulation condition.

The system installed in TVA is the first monitoring equipment able to automatically perform an easy-to-interpret correlation with operating conditions. It can be used to suggest how to change operating conditions to mitigate PD effects and what offline tests can be planned or deferred. Data points are automatically aggregated at the same operating condition at the end of each week allowing reliable warnings and alarms to be set.

The PDE Map represents a powerful tool for O&M and Asset Managers to easily compare the condition of all generators by using just one image. It is simple to setup the same full-scale for the PDE level for each machine in order to quickly highlight overall condition. Useful, but complicated, tools such as PRPD patterns are still available. However, they are no longer used as a “first” level of information. Rather, they are used as an investigative mean only in case a particular PD behaviour is observed. A PD expert is no longer needed to determine that a machine is PD free, which frees up asset owners’ capital to invest in other areas of need. Not only can maintenance outages now reflect actual machine condition needs (as reflected in Unit 8), but asset owners can also avoid PD testing technician expenses and scheduling conflicts with a permanent continuous monitoring system.

Ultimately, a continuous PD monitoring system puts useful data in the hands of asset owners and helps identify corrective actions and maintenance recommendations. All asset owners look to extend material life and get the most payback from every maintenance investment. The system described in this report serves as an essential tool to accomplish these goals for generators.

Author

Samuel Clemmons is a systems engineer for the Tennessee Valley Authority. James Hovious is a generator specialist at the Tennessee Valley Authority. Marco Tozzi is an electrical engineer for Camlin Power Ltd. Enrico Savorelli is product manager for Camlin Power Ltd.

Many power plant personnel are aware that chemistry upsets in a steam generator may cause severe corrosion and failure of boiler waterwall tubes and other components.

These failures place the staff at risk, and also lead to severe economic hardships for the plant.

However, often overlooked is that even trace levels of some impurities in steam can induce severe to catastrophic corrosion of turbine blades and rotors under certain conditions.

These issues are often magnified by the high cycling duty of most plants, including formerly base-loaded units.

With the aid of some excellent information presented at the recent 37th Annual Electric Utility Chemistry Workshop, the author will outline several of the most important issues with regard to protecting this most valuable piece of equipment.

How Do Impurities Enter Steam?

Because steam generating power plants, both conventional units and heat recovery steam generators (HRSGs), operate at high temperatures and pressures, very pure makeup water is a requirement to prevent corrosion and scaling. The core treatment process at many plants for high-purity water production is, following suitable pretreatment methods, two-pass reverse osmosis with either mixed-bed ion exchange or electrodeionization polishing of the RO effluent. Regardless of the exact makeup system design, it must produce water with very low part-per-billion (ppb) impurity concentrations. So, in the absence of condenser tube leaks or contaminated boiler water treatment chemicals, the water entering the steam generator is typically quite pure, with the normal sodium concentration less than 2 ppb and cation conductivity less than 0.2 μS/cm. More on these measurements appears shortly.

Many power plant personnel are aware that chemistry upsets in a steam generator may cause severe corrosion and failure of boiler waterwall tubes and other components. This article outlines the most important issues related to protecting this valuable piece of equipment.

The issue with drum units is that impurities “cycle up” in concentration due to production of steam, which leaves dissolved solids (typically analyzed and reported as total dissolved solids [TDS]) behind in the boiler. Dissolved and suspended solids are controlled via boiler blowdown, but the fact remains that some impurities can enter steam via any of three methods, mechanical carryover, vaporous carryover, or direct introduction from attemperator sprays. With regard to the former, virtually all high-pressure steam drums are equipped with moisture separators to remove entrained water droplets from the steam. But no separator is 100 percent efficient, and some moisture escapes the drum. The density difference between water and steam is the primary driving factor in moisture separation efficiency, and because this density difference decreases with increasing pressure, mechanical carryover becomes more pronounced in high-pressure steam generators. At a pressure of say 2,500 psia, moisture carryover may reach 0.2 percent of the steam flow. Mechanical carryover is the typical method by which most impurities, and particularly those which we will most focus upon in this article, chloride and sulfate, enter steam.

Some elements and compounds, most notably silica (SiO2), will vaporize on their own and enter steam. As with mechanical carryover, vaporous carryover becomes more pronounced as pressure increases. Consider for example the recommended boiler water silica concentrations designed to limit the steam concentration to 10 ppb. At 1,000 psia the general boiler water limiting concentration is around 2.3 ppm, but at 2,500 psi the limit drops to about 0.18 ppm. Silica does not cause turbine corrosion, but as the steam pressure decreases during passage through the intermediate- and low-pressure turbines, the compound will precipitate and modestly degrade turbine aerodynamic efficiency.

An element that once was quite problematic with regard to vaporous carryover is copper, especially in many of the coal-fired units from decades past. A large number of these steam generators were originally equipped with copper-alloy feedwater heater tubes, where corrosion introduced copper and copper oxides to the boiler. At pressures above 2,000 psi and especially at 2,400 psi and above, vaporous carryover of copper becomes quite troublesome. Deposition typically occurs in the HP turbine, and just a few pounds of copper deposits can cause the loss of several megawatts. Very few if any HRSGs have feedwater heaters, so this is a non-issue in modern combined cycle units. And, of course, other materials besides copper alloys are possible for any units that still have feedwater heaters.

Impurities may also be introduced to steam in a direct manner, via attemperator sprays. This is normally not an issue unless the feedwater has been contaminated from a condenser tube leak, or, less likely, a makeup water system upset. Then, harmful compounds will enter the entire system. This is yet another example why comprehensive on-line sampling, including condensate pump discharge and feedwater, is critical for protecting steam generators.

Current normal steam purity limits are outlined in the table below. These values may seem very minute, but as we shall see, even slight impurity ingress, especially of chloride, can still present serious difficulties.

Stress Corrosion Cracking.

How Impurities, Even at Trace Levels, Can Damage the Turbine

Power-generating steam turbines are typically divided into three sections, high-pressure (HP), intermediate pressure (IP), and low-pressure (LP). In virtually all modern units, HP exhaust steam returns to the steam generator for reheating, and then is introduced to the IP turbine, whose exhaust “crosses over” to the LP turbine(s). (Often, the configuration may have two or perhaps occasionally even three LP turbines per overall system.) Consider as an example of common operating conditions the following approximate values from a planned combined cycle project. The data is based on an average summer day at the site, with no supplemental duct firing to the HRSGs.

• HP Inlet Steam: ~2,000 psia, ~1,050o F
• Cold Reheat Steam: ~570 psia, ~700o F
• Hot Reheat Steam to IP Turbine: ~510 psia, ~1,050o F
• LP Inlet Steam: ~60 psia, ~610o F
• LP Exhaust to Condenser: ~1.2 psia, ~110o F

This data clearly illustrates the drop in steam pressure and temperature across the turbine sections as the energy is converted to mechanical work and electrical output. We have already noted that silica will precipitate from the steam as pressure drops in the IP and LP turbines. But what about the really bad actors, chloride and, to a lesser extent sulfate? Most difficulties with these salts occur in the LP turbine. The entering steam still has a reasonable amount of superheat, but as the steam reaches the last few rows of turbine blades, some of it begins to condense. This location is known as the phase transition zone (PTZ), and it is in the PTZ that chloride and sulfate salts precipitate on the turbine blades and rotor. During steady-state operation, the precipitated salts are neutral, but in units that cycle on and off regularly (many plants nowadays) the LP turbine may be frequently exposed to humid, outside air. When the salt deposits become moist, they can initiate pitting of blades and rotors. Pitting in itself is a very serious issue, but other factors exacerbate the problem. Rotating turbine blades, and particularly the long blades in LP turbines, develop stress points during operation. Pitting is often the precursor to stress corrosion cracking (SCC), in which the combination of a corrosive environment and metal stress can induce severe localized corrosion.

Another problematic mechanism is corrosion fatigue (CF), which, as the name implies, is influenced by repeated cycling. A simple example of basic fatigue is to bend a paperclip at one spot back and forth several times until it fails. Cycling duty in a plant initiates fatigue points at many locations, including rotating turbine blades and attachments. If a corrosive environment exists, the time to fatigue failure is shortened. Weakening of turbine blades and attachments from SCC and CF can lead to blade failure while the turbine is in operation. The only word that applies to this situation is “catastrophe.”

Information from the Electric Utility Chemistry Workshop

The corrosion issues outlined in this article were the subject of an excellent paper at the most recent Electric Utility Chemistry Workshop (EUCW). The lead author outlined in the first half of the paper that during scheduled outages on two power generating units at his company, non-destructive testing (NDT) revealed stress corrosion cracking in blade attachments within the last three stages of some of the LP turbines. Prompt blade and blade attachment repair prevented the problem from becoming a serious issue. This work came in conjunction with upgrades to the plant’s on-line chemistry monitoring system. Accurate and reliable monitoring are aspects that seem to often be overlooked by the plant staff, even though the cost for instrumentation and training for plant personnel can be recovered many times over by prevention of chemistry upsets. Critical sample points include:

• Makeup water system effluent
• Condensate pump discharge
• Feedwater and economizer inlet (economizer outlet is also a good location)
• Boiler / HRSG evaporator water
• Superheat, reheat, and saturated steam

With regard to steam chemistry, Table 1 previously illustrated current steam purity guidelines as established by the Electric Power Research Institute (EPRI) and other top organizations such as the International Association for the Properties of Water and Steam (IAPWS). But, the author is aware from these sources that the values are considered to be too high, particularly with regard to chloride and sodium, if the latter occurs in the form of caustic (NaOH) carryover. (Caustic can also induce stress corrosion cracking.)

For years, the primary power plant steam measurements have included some or all of sodium, silica, and cation conductivity (more properly known as conductivity after cation exchange [CACE]). CACE is essentially the electrical measurement of any anions, generally chloride and sulfate, after the cations (in steam generator water primarily ammonium and sodium) have been stripped from the sample. Because carbon dioxide (CO₂) influences CACE, now being recommended is degassed CACE, where the sample is routed through a reboiler or perhaps a nitrogen-sparged compartment to remove CO₂. For a long time, plant owners, startup personnel, and equipment manufacturers focused on a cation conductivity limit of 0.2 μS/cm as a good guideline for steam purity. But, CACE is only a surrogate for chloride and sulfate, and it is now known that 0.2 μS/cm corresponds to a chloride or sulfate concentration greater than 10 ppb. This is at a time when many consider 2 ppb of these ions to be excessive. The question has naturally arisen, “What about measuring trace chloride and sulfate directly?”

Heretofore, such measurements have been possible with ion chromatography (IC), but from direct experience the author will attest that although the technique can provide accurate results, it is expensive and requires trained chemistry personnel (something combined cycle plants unfortunately don’t always have) to keep IC units in proper working order. However, changes in the ability to monitor trace Cl and SO4 are imminent. Another paper at the EUCW outlined results from several field tests of a new trace chloride/sulfate analyzer.

A key aspect of this technology is that the instrument uses a process with the ponderous name of microfluidic capillary electrophoresis to separate chloride and sulfate, which may then be detected at concentrations down to 0.1 ppb. The electrophoresis module is calibrated at the factory, thus the instrument can be started up in the field without additional calibration. The field tests so far have provided excellent results. The technology could be expanded to detect other anions that may be in the steam samples.

A notable example is phosphate, which is often a mechanical carryover product in those plants that utilize tri-sodium phosphate (TSP) for boiler water chemistry control. Although TSP is not a corrosive agent in the steam system, carryover and deposition in superheater and reheater U-bends have been known to cause overheating failures.

Don’t Forget About Shutdowns and Layups

Often, plant personnel tend to focus on issues that may occur during normal operation. But, off-line corrosion is a very serious issue that must be addressed to ensure good unit reliability.

Author:

Brad Buecker is a senior process specialist in the Water Technologies group of Kiewit Engineering Group Inc.

The need for fast start up and cycling of combined cycle power plants in response to the growth of renewables is well understood in the power industry. Both trends have been widely discussed. This need is supported with the Rapid Response combined cycle system employing the new 7HA and 9HA gas turbines and others with hot start times around 30 minutes and operational efficiencies as high as 62 percent.

The need for both high efficiency and cycling puts conflicting requirements on Heat Recovery Steam Generation (HRSG) pressure parts. Application of new or higher-grade materials is an option. However, considering the long industry experience and cost of the plant, exploring the capacity of the existing materials, with improved design and analysis, is desired to meet the current challenge. For existing materials to endure higher pressure and temperature, thicker components are needed. The thicker components result in higher through wall temperatures and thermal stress, which is further increased due to faster cycling.

Heat Recovery Steam Generators must be designed to accommodate fast and increased cycling over the life of a power plant. This should include a design life assessment that accounts for fatigue caused by cycling and creep from long term operation at high temperature and pressure.

Critical to designing HRSG pressure parts is a life assessment analysis that takes into account all aspects of imposed steady state and transient thermal and pressure loads along with material and geometry of components. Both the EN and ASME codes provide guidance on life assessment approaches, however the simplified methods provided can result in either over or anticonservative predictions of component life. GE uses an approach generally based on EN 12952-3 and 12952-4 for fatigue and creep assessment along with robust transient modeling to define transient operating conditions. This article outlines the approach used by GE for HRSG life assessment.

Transient Analysis

It is necessary to define the transient operating conditions that the HRSG pressure parts must endure. For units that are not yet in operation, this requires a dynamic model to predict steam/water flow pressure and temperature in the pressure parts as a function of time. Additionally, the heat transfer to the pressure parts must be determined as a function of the flow conditions as this defines the thermal transient that the component is subjected to. The primary inputs to the dynamic model are the gas turbine flow and temperature curves as these provide the energy into the HRSG. If the HRSG has a duct burner the ramp rate of that heat input must also be included. The dynamic model must include the operational logic and constraints for the various control valves, bypasses and attemperators. Figure 1 shows typical transients for an operating cycle.

It is noted that a complete transient should be defined as a combination of a ramp up (startup) and ramp down (shutdown) progress, not a single ramp. As will be discussed later, Finite Element Analysis (FEA) is required for determination of component stresses that affect lifetime. The required transient inputs for the FEA include the local heat transfer coefficients on the component. It is important to evaluate these with Computational Fluid Dynamics (CFD) and to validate with field measurements. Figure 2 shows a CFD analysis of local heat transfer coefficients inside a superheater manifold. Use of a simplified calculation on heat transfer based on uniform conditions can result in significant under prediction on local stresses and hence life usage.

Component Selection

EN12952-3, 5.5 provides a method of screening components for fatigue but this is based strictly on component material, dimensions and operating pressure and does not consider the operational transient that the component would be subjected to. The operating temperature/pressure and the rates of temperature/pressure change based on the dynamic model or operating data must be used to select the components subjected to the most severe operating transients. These factors must be considered as well as the component design. Typically, it can be assumed that the final superheater or reheater and the high pressure drum will be subjected to fast temperature increases at startup. Components directly downstream of attemperators can also be subject to fast transients. These can occur multiple times over a single start stop cycle so the anticipated load change scenarios must be considered as well as the numbers of startups and shutdowns. In this study, a manifold of the final stage superheater, as shown in Figure 3, is selected to show the fatigue evaluation of cyclic load.

Fatigue Evaluation Methods

ASME BPVP Code Section I does not provide specific rules or procedures to evaluate the fatigue usage of an HRSG. The general philosophy is stated in the Forward of ASME BPVP Code Section I, “to afford reasonable protection of life and property and to provide a margin for deterioration in service so as to give a reasonably long safe period of usefulness.” The increasing number of cyclic operations on HRSGs requires a better understanding of the fatigue evaluation methods and the margins associated with them. The American Boiler Manufacturers Association (ABMA) has discussed the different methods to calculate fatigue usage for HRSGs and compared the results. The ABMA paper also discussed the strengths and weaknesses of each method. As EN 12952-3 provides detailed procedures specifically focused on water tube boiler fatigue, in this analysis, EN 12952-3 is chosen to be the calculation method to show the effect of input parameters of the fatigue analysis.

EN 12952-3 provides a procedure for fatigue calculation of boiler pressure parts of boilers in Section 13 and associated Annexes, which can be completed by hand in the form of a table calculation as shown in the sample problems in Annex C of EN 12952-3. The code also allows using more complicated methods such as FEA to get more exact life predictions to reduce the conservatism, “Due to the simplicity of this analysis, the results may be conservative with respect to life prediction. More complex methods, e.g. finite element analysis, may be applied to obtain more exact life predictions.” Regardless of the methods used in the analysis, the key inputs include geometry, material properties and transient load boundary conditions. The assumptions in selecting these input parameters can make the results different even if the calculations are following the same code methodology.

Effect of Ramp Rate Selection

EN 12952-3 provides two sample calculations in Annex C, illustrating the fatigue calculation procedure described in Section 13 (hereinafter referred to as “sample method”). The samples show the procedures of calculation of the admissible number of load cycles and calculation of the admissible temperature gradient. Due to the simplicity of the method, the calculation assumes a constant fluid (steam or water) temperature ramp rate for the start-up and shutdown transient. This constant fluid temperature ramp rate is used as the metal temperature ramp rate on the inside surface of the component. The effect of heat transfer coefficient (HTC) is included in the thermal stress concentration factor (αt) in the sample method. The HTC values are also simplified to two constant values for steam and water. Then the thermal stress is combined with the stress due to internal pressure to obtain the stress range. This simplified method does not reflect the nonlinearity and combination of the internal fluid conditions, e.g., fluid temperature ramp rate, pressure and flow rate.

The determination of the transient temperature ramp rate can be subjective. The Ramp Rates 1, 2 and 3 in Figure 1 illustrate different selections of the simplified linear transient steam ramp rates. Ramp Rate 1 assumes a detailed transient analysis has been performed and uses the actual steam ramp rate of startup and shutdown as the constant ramp rate. Ramp Rate 2 assumes the transient starts when the pressure starts to increase, ends when the steam temperature reaches the operating temperature. For the shutdown, the transient is assumed to start and end with the change of the flow and pressure. Ramp Rate 3 assumes the startup transient starts with pressure increase and ends when pressure, flow and temperature all reach the operating conditions. The ramp rates can be significantly different and result in errors of the fatigue assessment, as shown in Table 1. Ramp Rate 1 considers the most conservative steam ramp rate only, in the entire startup and shutdown transients, resulting in a very high stress range and low allowable number of cycles on fatigue. However, this information is not available unless a detailed transient analysis is performed from a complete dynamic model simulation. In many cases, the ramp rates will be calculated a straight line connecting two steady states, which is closer to the Ramp Rate 3 case. It can be seen that the difference in allowable number of cycles are two orders of magnitude between Ramp Rates 1 and 3, in Table 1.

The effect of transient ramp rate selection might not be as sensitive for long transients with slow ramp rates. With safety factors, this simplified sample method using constant ramp rate can be reasonably conservative. However, the design requirement of today’s HRSGs is for faster response time and more cycles. The selection of transient ramp rates is critical in fatigue life assessment. As suggested in ERPI report, a detailed transient analysis is needed for HRSG fatigue life assessment.

Effect of Discrete Time Steps and HTC

To take advantage of the time history of the transient details, one improvement over the sample method can be separating the transient by discrete time steps (hereinafter referred to as “discrete method”). At each time step, the through wall temperature difference can be calculated to reflect the conditions provided by the advanced transient analysis. The resultant stresses due to thermal and internal pressure will be combined at each time step instead of only maximum and minimum values in the sample method. The discrete method fully represents the results from transient analysis and better calculates the through-wall temperature distribution.

The stress calculation is still based on the equations and parameters presented in EN 12952-3, assuming one dimensional through-wall heat transfer with corresponding stress concentration factors.

EN 12952-3 suggests the heat-transfer coefficient (HTC) values as follows:

Heat-transfer coefficient:

These HTC values reasonably represent a general average value during a relatively long transient. However, it does not fully represent the heat transfer conditions during the thermal transient. For example, if the constant HTC value for steam is used, then the enhanced thermal transfer due to condensation will be neglected in the analysis. The market is requiring faster response and the HRSG start-up period becomes shorter. A more detailed HTC estimation is needed with respect to the associated transient. Correlations such as Dittus Boelter [5] can be used as the basis for calculating the convective inside HTC assuming well-developed turbulent flow. Direct application of the Dittus Boelter correlation on HTC considers the effect the fluid conditions, e.g., temperature, flow rate, etc. It is a significant improvement on HTC estimation comparing to a constant average value during the entire transient. However, flow in a typical HRSG critical component, e.g., a manifold or a header, does not have the same heat transfer coefficient characteristics as a well developed flow in a pipe.

Typically, flow enters from a pipe in a fully developed turbulent state, which is then decelerated by the expansion into the cavity or by impinging onto the walls of the manifold. In addition to the deceleration, the flow changes direction to follow the path required to reach the exit from the cavity. Then at the exit of the cavity the flow is accelerated through a contraction and begins to redevelop a turbulent boundary layer. These flow patterns typically increase turbulence levels and enhance local heat transfer. All of these flow characteristics need to be accounted for in the thermal boundary conditions. It was found that these characteristics enhance heat transfer to the metal and therefore simple correlations need a multiplier to account for the increased heat transfer. This heater transfer coefficient correction factor (HTCCF) is determined by comparing the heat transfer coefficient determined from CFD to that from the simple correlation as shown in Figure 2.

The stress ranges and corresponding fatigue allowable number of cycles are presented in Table 2, using discrete method with different HTC values and the transient shown in Figure 1. For the default constant HTC values from EN 12952-3 assuming the fluid is all steam during the startup and shutdown process, the stress range and fatigue allowable number of cycles is in between the ones of Ramp Rate 1 and 3, smaller than the ones of Ramp Rate 2. Using Dittus Boelter correlation to calculate HTC, without correction factors from CFD analysis, the stress range is smaller and the allowable number of cycles is higher. Using Dittus Boelter correlation with HTCCF, the stress range is the highest among the three cases, and the allowable number of cycles is the lowest. It can be noted that, comparing the case of Ramp Rate 2, the 520 Mpa stress range is lower than 574 MPa, but the allowable number of cycles are 6235, lower than the 7494 Ramp Rate 2 allowable number of cycles. It is because, using the discrete method, the reference temperature is calculated using the temperatures at the maximum and minimum stress time points, while in the simple method, the reference temperature is calculated from the maximum and minimum temperature of the transient.

Generally, the discrete method provides results closer to Ramp Rate 2 using the simplified sample method. The results from discrete methods shows much smaller difference based on different assumptions of HTC values. It represents more details of the transient and is more robust compared to the sample method.

Application of FEa Effect of 3D Geometry

Both the sample method and discrete method are based on the equations and parameters presented in EN 12952-3, assuming one dimensional through-wall heat transfer with corresponding stress concentration factors. There are no 3D effects or interactions between non-isolated penetrations considered in the calculation. For example, due to fluid impingement, the component can be heated up much faster on one side and bows to create additional bending moment. If the penetrations are close to each other, the area around the penetrations can be heated up or cooled down faster, such that a hot/cold spot is formed and resulting in additional stresses. This could lead to an anticonservative estimation of the stress and thus an anticonservative fatigue life prediction. The application of 3D finite element analysis (FEA) better represents the actual condition and provides more accurate stress and fatigue results.

Figure 4 plots a color contour of the stress range distribution over a sample manifold in HRSG. The manifold has 3 tube penetrations marked as Tube A, B and C, and a larger nozzle penetration. They are numbered as Position 1, 2, 3 and 4 at 12, 3, 6 and 9 o’clock position, for each of the penetrations, respectively. Table 4 lists the stress ranges at different positions around the penetration for the tubes and the nozzle. It can be seen that the stress ranges at the tube locations are generally higher than the ones at the nozzle locations. This is consistent with the trend shown in the results from the sample method and discrete method. The stress ranges at the nozzle of all 4 positions and the stress ranges at the tube of Positions 2 and 4 are reasonably close to the stress ranges calculated from discrete method with HTCCF. For the nozzle location, the stress range values do not vary, while the stress range values at Positions 2 and 4 are significantly higher than the ones at Positions 1 and 3, for the tube locations. Due to design limitation, the tubes are located on one side of the manifold and heat up or cool down the manifold on one side of the manifold faster than the other side. The interaction between the tube connections produces more thermal stress during the transient and leads to higher stress ranges at Positions 1 and 3, while the stress range values at Positions 2 and 4 are less affected. The nozzle penetration is isolated, and hence, shows less difference in stress range around the penetration edge.

Inelastic FEA

For cases with stress range fully exceeding the elastic range, a plastic correction is provided in Annex B of EN 12952-3.

This correction is essentially Neuber’s rule correction. When plastic strains are small, it provides a reasonable correction to the results calculated from elastic analysis. For cases with larger plastic strains, the Neuber’s rule correction will be too conservative or under conservative, depending on the type of loads. EN 12952-3 allows using total strain range to calculate the virtual stress range as:

The total strain range can be calculated using inelastic FEA. After obtaining the virtual stress range, following the same procedure, the fatigue life can be calculated.

Table 4 presents the stress ranges and allowable number of cycles calculated from discrete method, elastic FEA and inelastic FEA.

It can be seen the results from linear elastic FEA is most conservative, while results from discrete method and inelastic FEA are closer. It should be noted that it does not mean the discrete method always provides results close to the inelastic FEA.

The stress range value from discrete method is lower than elastic FEA is because it does not consider the interaction between the tube penetrations. The inelastic FEA leads to lower stress range and higher allowable than elastic FEA, because of the redistribution of local high stress in elastic FEA and the more accurate strain range.

Conclusions and Recommendations

1. The HRSG design needs to accommodate higher efficiency and more cycling over the life. Higher efficiency requires higher pressures and temperatures, resulting in thicker components. Both thicker components and faster cycling bring challenge to the fatigue life of the components. The results from simplified methodology can be over or anticonservative. An understanding of the true fatigue life of the critical components is needed. The following are required to achieve this.
2. Transient analysis is critical to the fatigue evaluation of cyclic loading, although it is not required by the codes. For new designs, this requires a dynamic model. It provides the detailed history of fluid conditions, including pressure, temperature and flow rate of each of the critical components, while the simplified method generally determines a constant transient ramp of all the fluid conditions by linearly connecting two steady states. With the more cycling and shorter startup time, the results from the simplified method can be misleading. The difference between the predicted fatigue lives can be 1 to 2 orders of magnitudes, depending on the different assumptions, as shown in Table 1. The transient analysis results provide the basis of the detailed analysis on stress and fatigue life.
3. Fatigue can be calculated for simple geometries using the discrete method taking advantage of the time history of the fluid conditions, based on the transient analysis results. The discrete method is based on the same equations and stress concentration factors in the sample method. One factor that can contribute to the difference in fatigue life prediction is the selection of heat transfer coefficient. However, the difference is small compared to the difference due to more arbitrary ramp rate selection in the sample method. The Dittus Boelter correlation with correction factors from CFD is recommended for the discrete method.
4. FEA is strongly recommended especially for the fatigue assessment of the critical components. It is a GE requirement on HRSGs. The 3D FEA model can not only appreciate the detailed fluid conditions from transient analysis, but also includes the actual geometry effect, e.g., non-uniform heat up and the interaction between the penetrations. Neglecting these effects can lead to anticonservative fatigue life prediction in the design stage. For cases with large strain/stress ranges, inelastic FEA is recommended to reduce the error produced when using general plastic correction equations. It should be noted that using FEA is allowed in most of the design codes as an option for detailed analysis, when the code calculation is too conservative. This study shows that due to the wide range of possible assumptions where the codes are not specifically written, results calculated from code equations are not always conservative.
5. An online monitoring system is highly recommended for the HRSGs.

The life assessment at design stage can only be based on limited operating conditions obtained from the dynamic models. The plants can be operated differently from the analyzed conditions. With a monitoring system, the life assessment can be done based on the field measured data. The plant life management will be improved based on more information and better analysis. GE provides “HRSG Life Monitor” as the online life monitoring tool for HRSGs.

Among generator starting professionals, it is widely accepted that the most prevalent reason for generator set (genset) failure-to-start is issues with the lead-acid battery starting system. Service providers have said that approximately 80 percent of genset failures-to-start can be attributed to battery system failure resulting from poorly maintained batteries, charger failure, or cable and terminal corrosion. After several decades of these challenges, the genset industry is embarking on a new trend toward ultracapacitor-based starting systems, which offer advantages over traditionally used lead-acid battery-based starting systems.

Ultracapacitors are fast-responding, power-packed energy storage devices that have been adopted in a variety of applications and industries, including commercial truck engine starting. Ultracapacitors are successful in starting large truck engines in the face of problems unique to the trucking industry, like dead or discharged batteries. Depending on operation, an ultracapacitor stores energy in a static electric field, rather than in a chemical reaction like batteries do, which can slow dramatically in very cold weather. Because they don’t depend on a chemical reaction to produce electricity, ultracapacitors can operate in much lower and higher temperatures than batteries.

When a power outage happens, commercial transaction-based businesses can be susceptible to exorbitant expenses related to data loss and customer service downtime. Power failure in hospitals or hotels presents a high risk of injury or loss of life to people in the facility. Ultracapacitors installed in emergency or standby backup generator sets can provide a more reliable way to meet strict starting requirements, avoid losses associated with power failures, and improve building safety. When used to start backup generators, ultracapacitors can either completely replace lead-acid batteries or operate alongside them, providing primary or backup assistance to the battery system. Seamless transition from ultracapacitors to batteries in a hybrid installation can take place during cranking, yielding the fastest possible starts.

Applying ultracapacitors to gensets also reduces battery maintenance costs. Ultracapacitor-based genset starting systems require minimal maintenance due to their high cycle life and ruggedness in wider temperature ranges. Depending on operation and use, ultracapacitors can achieve 10 or more years without replacement versus much more frequent battery changes. Batteries for genset starting generally have to be replaced every two to three years. Generally speaking, batteries must be inspected and tested on a weekly or monthly basis. This involves checking all cables and connections for corrosion caused by sulfuric acid fumes, checking water levels in each battery, and load testing each battery individually to ensure that its cold cranking amperage (CCA) rating is still within specification. In addition to costs of replacing batteries that fail testing, the cost of technician hours spent on maintenance is thrown in the mix. With ultracapacitors, there is no sulfuric acid to cause corrosion, no water levels to check and no load test requirements. As a result, maintenance costs are significantly less than those of batteries.

Because of their low internal resistance, ultracapacitors are capable of sourcing higher current with lower voltage drop during cranking than batteries. As a result, cranking revolutions per minute can be as much as 20 percent higher than with batteries alone. This results in starting the genset in a shorter period of time, often in the range of 10 percent to 20 percent less cranking time.

Electric utilities are beginning to adopt ultracapacitors to start large engines that, in turn, start gas-fired turbines. This benefits utilities because their smaller plants are in remote locations. The engine and turbine are started remotely by the grid manager in response to increased demand. In this case, failure of the lead-acid battery system to start the engine has significant consequences to the utility because power to the grid is not supplied on demand. Alternate arrangements must be made quickly to obtain power from another source. Most often, personnel need to make an emergency service call from the central site to the remote site to diagnose and correct the problem.

Lead-acid batteries have been the standard technology for starting commercial engines since the 1930s and now, ultracapacitors are emerging as an alternative starting technology for critical applications like backup generators. Ultracapacitors make a strong business case for replacing batteries in a genset or specifying the starting system for a new installation, leading genset professionals to increasingly rely on the technology. Ultracapacitor-based systems for genset starting give building owners and facility managers confidence that operations will always run smoothly – even in periods of power outages.

The windshield wipers on that new car you bought a year ago are leaving that annoying streak right across your line of vision when it rains. No big deal, right? You stop by the auto parts store and pick up a new pair of wiper replacements. Are you sure, however, that those replacement blades will provide the same or comparable performance as the original wipers that came with the new vehicle?

Procurement decisions like this may seem unimportant, but wipers can impact the safe operation of your car. They play a role in protecting your life, those in the car with you, and those in other cars on the road with you.

The importance is just as high for a nuclear plant when it purchases replacement parts. Safety-related nuclear plant equipment MUST operate successfully when called upon to safely shut down a reactor, MUST maintain the reactor in a safe shutdown condition, and MUST be able to prevent harmful public exposure to radiation.

In the United States, the legal and regulatory importance of procurement derives from 10CFR50 Appendix B, which codifies the quality assurance criteria for nuclear power plants. Many of the sections in 10CFR50 Appendix B – from design control to handling, storage and shipping – are applicable to procurement decisions and actions. While regulatory compliance is a critical and consistent driver for effective procurement engineering, there are recent and emerging issues that further reinforce its relevance today:

• Counterfeit parts: Counterfeit parts are making their way to the receiving docks at some nuclear plants. Commodity items such as breakers and relays – which can be produced in large lots by counterfeiters to maximize economic return – are particularly susceptible. Although the operational impacts have been minimal, the potential for counterfeiting highlights the need for diligence in procuring replacement parts.
• Obsolete parts: Not a new issue, but as nuclear plants age and the population of nuclear suppliers declines, the population of obsolete parts keeps growing. Nuclear procurement engineers, in turn, need to provide assurance that replacement parts perform their intended design functions.
• New technology: 3D printing and other additive manufacturing processes introduce a new class of replacement parts that may require a fresh look with respect to procurement practices. And as component suppliers look to modify or replace hardware with digital devices that include software, the functional performance of the part may be the same, but other differences must be addressed, such as software validation or the need for additional RFI/EMI shielding.
• Employee turnover: Your friendly procurement engineer is not getting any younger, which means that transferring knowledge from the veterans to the newcomers is paramount. Incoming engineers will need access to modern training tools that can accelerate their transition.

Procurement engineering is a core nuclear plant discipline. And despite the new drivers, the principles that provide the foundation for effective procurement engineering remain the same:

• Design and qualification establishes the suitability of the design. Design control measures must be in place to control the original design.
• Supplier quality controls play an important role in assuring product quality. Procurement processes must assure that purchased items conform to procurement documents, including source evaluation and selection, objective evidence of quality, inspection at source, and examination of products upon delivery.
• Technical evaluations translate design and quality requirements into procurement requirements that are communicated to the supplier in procurement documents. For example, the licensee is responsible for ensuring that regulatory requirements and the applicable design basis are correctly reflected in specifications, drawings, procedures, and instructions.
• Acceptance answers the questions of whether the licensee received what was ordered and whether the item meets the design requirements. Licensees must establish measures to assure that purchased material, equipment and services conform to the procurement documents.
• Post acceptance and installation controls provide assurance that the item meets design requirements and can perform its intended function. This element encompasses handling, storage, inspections, maintenance, testing, and corrective actions.

Basically, procurement engineers must be familiar with everything from designing, purchasing and handling…to installing, maintaining, and repairing. Plus, they need to be cognizant of challenges posed by counterfeiters, new technology, and regulators. It’s like having someone at home who will research the right parts for your car, make sure they’re not fake, and then check to make sure they work as promised.

Wouldn’t that be nice?

Forces are at work to update the Environmental Protection Agency’s (EPA) archaic and perplexing New Source Review (NSR) Rules. These rules, more so than greenhouse gas or mercury regulation, prevent power plants from making efficiency improvements, which would reduce emissions on a per megawatt basis.

The lack of a basic definition of “routine” in determining if a replacement or upgrade requires a new permit with modern controls leaves utilities fearing change. NSR lookback lawsuits have forced at least 113 power plants to install new control devices, pay fines, or shutdown at a cost of more than $21 billion over the last 17 years.

The main guidance document for NSR remains the draft 1990 New Source Review Workshop Manual, aptly nicknamed the “puzzle book.” Never finalized due to controversy and EPA inertia, this document has been supplemented over the decades with guidance memos and applicability determinations. The result is a confusing Frankenstein-like mess that leaves industry without a clear path to updating and repairing their infrastructure. This guidance document was finally updated Sept. 1, 2017, not by the EPA but by the Air and Waste Management Associate (AWMA), and is available for purchase. Although not EPA-reviewed or approved, it does provide clarity on the NSR rules and incorporates the few 2002 NSR reforms that survived court challenge.

However, outside of AWMA’s repackaging of the 25 years of guidance documents, there remains a push to alter the actual regulations. The current administration has called for a rollback on regulations and the EPA has indicated it plans to overhaul NSR. Additionally, the Department of Energy released a report in August 2017 on the “reliability and resilience of the electric grid.” The report correctly states, “The uncertainty stemming from NSR creates an unnecessary burden that discourages rather than encourages installation of CO₂ emission control equipment and investments in efficiency because of the additional expenditures and delays associated with the permitting process.”

• The following are common and sensible suggestions to reform NSR into a vehicle that encourages innovation and pollution reduction instead of inhibiting modernization:
• Remove the undefined exemption for “routine maintenance” and replace it with a discrete definition for substantial modifications (such as changing the frame model of a turbine) that trigger installation of Best Available Control Technology (BACT) on existing facilities. Simple and common repairs such as boiler tube replacements or turbine overhauls should not be limited by regulatory uncertainty and should be considered “routine maintenance.”
• Provide an exemption for pollution control projects that will survive court challenge. The 2002 NSR Reform attempted to regulate projects which decreased emissions of one pollutant at the expense of increasing another pollutant. For example, installing over-fire air on a boiler reduces nitrogen dioxides (NO2) but increases carbon monoxide (CO). NO2 is arguable more important than CO since NO2 contributes to ground level ozone and fine particulate (Pm².5) formation. However, this reform was struck down by the courts.
• Regulate emissions on an efficiency basis (pounds per megawatt-hour) to encourage innovation. Retrofitting an existing boiler or turbine can be more cost effective than building a new unit. If the modified unit is more efficient, its operation should be encouraged versus operating an older, less efficient unit.
• Remove the NSR incentive to pollutant as much as possible the two years before a facility triggers NSR permitting. Currently, a facility’s post project emissions are measured against its actual emissions in the five years preceding the modification on a ton per year basis, not against the potential or even the permitted emissions. A project could decrease emissions on a pound per hour basis but if the boiler subsequently increases its capacity factor, it triggers NSR and control device retrofit. In contrast, New Source Performance Standard regulations require a short-term emission increase before triggering new applicability.

Stable, affordable electricity and clean air are not mutually exclusive. It is time to reform regulations to permit technical advances in power generation.