The index, sponsored by Carnegie Mellon University and Mitsubishi Hitachi Power Systems, indicated electrical sector emissions reached 1,001 pounds of CO₂ per MWh in the fourth quarter of 2016, which is an increase of one percent compared to the fourth quarter of 2015.

The report concluded that, overall, the entire power sector is getting cleaner and more efficient, even with the rise this year.

“A lot of people would be surprised to hear that, since we usually hear bad news about climate change,” said Paul Browning, CEO of Mitsubishi Hitachi Power Systems. “In fact, we’ve made quite a bit of progress in the power sector.”

Coal generation rose 12 percent year-over year to 31.8 percent of total generation, while natural gas generation fell nine percent to 30.6 percent of total generation.

Even with the rise in generation, carbon intensity of coal and natural gas both fell by two percent to 2231 pounds of CO₂ per MWh for coal and 930 pounds of CO₂ per MWh for natural gas.

Renewable generation rose seven percent to 16 percent of total generation, while nuclear rose four percent to 20.6 percent of the total.

Even with President Trump’s order to revisit the Clean Power Plan, Browning said he expects that trend to continue, as emissions from new generation have been dropping since the second Bush administration thanks to renewables and growing efficiencies of gas turbines.

“We feel that it’s markets and technologies that are driving this trend,” he said. “Government regulations are important to this trend, but it’s less important than markets and technology.”

Browning said he’s an alumnus of Carneghie Mellon and serves on the dean’s advisory board, though the company considered multiple universities for partnership on the carbon index.

“Ultimately we were very impressed by the faculty we brought forward on this project,” he said.

The Nuclear Energy Institute’s (NEI) “Delivering the Nuclear Promise” initiative was launched in December 2015 with the goal of increasing efficiency across the nuclear industry in order to ensure its long-term viability. With more than a year of evidence, it’s clear the initiative is working. According to a February speech from NEI President Maria Korsnick, the program’s efforts identified $650 million in potential savings that could be realized through new programs and processes in 2016. Additionally, people from across the industry collaborated to produce 46 efficiency bulletins which outline efficiency improvements across all aspects of nuclear plant operations. Korsnick said that 95 percent of those recommendations are being implemented across the industry.

As encouraging as the program has been, there is still significant work left to do. Engaging suppliers will be crucial to the initiative’s ultimate success. Last June, as part of an effort to reach out, industry leaders met with a group of suppliers to provide more information about how the initiative works. While it was an important gesture, suppliers cannot wait for nuclear utilities to engage them. A proactive approach to helping to deliver the nuclear promise is needed. Here are some initiatives that industry suppliers can take.

Share Improvement Opportunity Ideas

NEI has set-up a mechanism for suppliers to participate in the nuclear promise initiative by submitting improvement opportunity ideas. This is the most obvious way for suppliers to help and they should take advantage of it early and often. That’s because they are in a unique position to make recommendations. Suppliers often work at multiple sites and with multiple utility companies from across the industry. Many suppliers have been in the industry for decades and have seen what works and what doesn’t work when it comes to efficiently managing projects.

Suppliers must leverage their experiences and identify new ways to bring value to nuclear plant operations by passing on what they have learned and making sure best practices are incorporated into all of the projects they work on. This, accompanied with a detailed, well-executed change management plan is critical to success.

Watts Bar Nuclear Plant is on 1,700 acres on the northern end of the Chickamauga Reservoir near Spring City, in East Tennessee. Each unit produces about 1,150 megawatts of electricity-enough to service 650,000 homes-without creating any carbon emissions.

Be a Partner, Not a Participant

It’s one thing to share improvement opportunities ideas, but if those ideas are to be incorporated effectively, there must be an increase in collaboration between both utilities and suppliers. They must work together at the site and fleet levels to understand the unique context of the challenges utilities face and to identify opportunities for efficiencies savings, and innovations throughout the value chain. While suppliers and utilities always work together to complete projects, the level of collaboration can vary.

Suppliers are not always brought in at the earliest levels of project planning, making it difficult to ensure that projects are executed efficiently. Without a conversation before work begins, it is more difficult to accurately define project scope. This can leave both sides in a poor position if projects go over budget or past schedule. Suppliers need a seat at the table as a true partner in order to deliver the most efficiency possible. As the nuclear promise initiative continues to evolve, supplier and utility collaboration will be an essential part of its success.

Standardizing Training & Qualifications

Effective worker training is a key contributing factor to the efficiency and reliability that nuclear plants currently enjoy. Workers are the ones on the ground that make sure tasks are executed safely and properly. Unfortunately, there is currently no standardized training certificate for workers in the nuclear industry. This means that workers often receive duplicative training when working for new plants or utilities. When a contract worker is a proven commodity — one that has worked on numerous projects and passed previous training programs — requiring them take an additional training course simply because they are working at a new plant is inefficient. While there should be some plant-specific orientation programs, the standardization of general practices and procedures across the industry would make for a better training experience for workers and utility operators. Steps are currently in place to address this through common “Hard Hat Ready” courses, yet work still needs to be done in terms of developing and recognizing standardized qualifications in welding, rigging, torqueing, and other tasks.

Suppliers must take an active role with their utilities to identify these redundancies and collectively work with industry resource groups to develop and implement standardized task evaluations that can be recognized from site to site.

Engage with Other Suppliers

The nuclear promise initiative encourages utilities to work collaboratively to solve problems. It also encourages suppliers to participate by sharing ideas. But there is one notable gap in this system. It does not address the need for suppliers to collaborate with other suppliers. On any given nuclear project multiple suppliers are involved upstream and downstream. During outages the number of staff from outside vendors can double or even surpass the number of permanent on-site staff. There is natural interaction between vendors during the course of projects, but much like utilities, there needs to be more conversation that takes place outside of the vacuum of specific projects.

Groups like the Nuclear Suppliers Association are one way for suppliers to connect and share ideas, but they also must be conversing in more informal ways and more frequently; particularly at the site level. While suppliers are often competing against each other, they must find ways to collaborate to make each utility successful and maintain the viability of nuclear power. Suppliers do not need to share proprietary processes, but they can find ways to work more efficiently together and improve project coordination. Utilities can become much more efficient if suppliers show a willingness and ability to collaborate to solve problems.

A Continued Commitment to Safety Improvement

Safety cannot be taken for granted, especially in the midst of significant change. While the nuclear industry as a whole has a tremendous track record for safety performance, suppliers must be daring enough, along with their utility counterparts, to imagine a future with zero injuries. Such a drastic change won’t happen by executive mandate. It’ll happen when workers at every level believe it’s possible and are actively engaged in the process.

Suppliers and utilities must have one voice for safety that is modeled by leadership and supervision and reinforced through mutual accountability. This is the kind of bold thinking of years past that challenged the status-quo and helped us achieve unparalleled results. It’s time to challenge the status-quo again, to think beyond an incident rate and get to zero.

Working Together In an Uncertain Future

An increasing shift toward lowering carbon emissions in power generation, the regulatory policies of a new administration, and advances in nuclear reactors and other types of generation will play a role in the industry’s ability to grow and prosper. Some of these factors are difficult or impossible to control.

That’s why the nuclear promise initiative was focused on what the industry can control: driving down costs and improving efficiency. Suppliers have a choice to make.

They can choose to be another outside factor that is difficult to control, or they can choose to be part of the solution. Collaboration between suppliers and utilities will be necessary to put the industry in the best possible position to succeed.

Author
Michael McMahon is President of Day & Zimmermann’s Engineering, Construction and Maintenance Group, a provider of total plant lifecycle solutions for the power, process, and industrial markets.

Ineffective gas turbine inlet filtration will cost a power plant a lot of money through reduced turbine efficiency, increased maintenance costs and lower turbine availability. In the face of these impacts on the bottom line, many turn to (High Efficiency Particulate Air) HEPA filters to increase the efficiency of their inlet filtration system and, in turn, their gas turbine. Unfortunately a higher filter efficiency rating alone will not give an operator a complete picture and may even cause more problems than it solves. This article will look into some of the main points operators should consider to ensure they get the best from their filtration solution.

Because of the volumes of air a gas turbine consumes, the choice of inlet filtration system has a huge impact on turbine performance. Selecting an inappropriate solution will leave the turbine exposed to contaminants that can corrode and impede its performance. The wrong type of filter for an installation can also lead to sudden restrictions to the inlet air flow causing pressure spikes and unexpected turbine shutdown. Selecting a solution that will protect the turbine as well as optimize maintenance and performance requires an understanding of the local environmental challenges a filter needs to face.

Harsh conditions make filter choices tougher. HEPA-rated filters will perform differently depending on design and construction. Make sure your filter choice is right for your specific site conditions.

Gas turbines are often installed in harsh conditions. The local environment can contain high volumes of sand; salt, if near to the coast; pollution and hydrocarbon mists; snow; excessive rainfall; elevated levels of moisture from mist, fog or high humidity levels – or, of course a combination of any or all of these with seasonal variations. To effectively protect the gas turbines, a filtration solution needs to handle the local, real-world conditions in which it is installed.

Fine particles that reach the turbine blades can stick to them and, as they build up, affect aerodynamic performance. This will cause a reduction in output power and increase in heat rate that will ultimately require an offline wash. The more frequently this maintenance procedure needs to be carried out, the greater the cost impact through lost MW output and increased rates of fuel usage. Filters use media that captures particulates and prevents them reaching and harming the internal parts of the gas turbine. The higher the efficiency of the filter, the finer the particles it captures.

Does salt threaten your turbine?

If a power plant is located within 12 miles of the sea, salt may be a particular contaminant that puts turbine performance in peril. While dry salt will be captured in the same way as other dry particulates, the affinity salt has for absorbing water and moisture means it needs special consideration.

As with other contaminants, salt can stick to turbine blades and reduce aerodynamic efficiency. Its stickiness, however, can increase the rate at which this occurs. Salt is also particularly harmful because, if allowed into the turbine internals, the sodium in the salt can combine with sulfur in the fuel in the hot section of the turbine to cause accelerated corrosion. In the cold end, the chlorine in the salt will additionally act as a pitting corrosion initiator. The overall impact salt can have on a gas turbine can lead to exceptionally high maintenance levels and premature failure of the turbine.

Operating Data Comparison

Turbine operating data can help show how different HEPA filters perform in the same environment.

Will a HEPA filter better protect a turbine?

To improve turbine protection some may conclude that a high efficiency particulate air (HEPA) filter will be the best option. To capture finer particles, however, means finer media is used which, in the presence of moisture or hydrocarbon mists, may be prone to sudden blockages that can have a serious impact on turbine operation. This is because moisture caused by mist or fog consists of tiny droplets that can work their way into the media matrix and become stuck – blocking pathways for the air to pass through. The presence of captured hydrocarbons from pollution in the media generally concentrates this effect further, making it even harder for tiny water droplets to escape, increasing the filters sensitivity.

This same effect does not generally happen with the larger droplets of rain, as these coalesce on the media surface and drain, being too big to get into the media matrix itself. Similarly, as high humidity does not contain droplets, this will generally pass through with little effect.

Standard filter efficiency ratings are based on laboratory testing in a controlled, dry atmosphere- an environment that is a long way from that of a power plant’s. Just relying on filter efficiency rating alone, therefore, does not give a complete picture of how a filter will perform once installed in a specific installation environment. For example, simply selecting a fine filter media may not allow for the effects of moisture which can result in shortened filter life expectancy, bypass of corrosives, increased maintenance cycles (and cost), and the need for fast operator reaction times to deal with sudden pressure spikes. Indeed, the hydrophobicity of a filter, it’s ability to keep liquid contaminants out should be a major consideration for the power industry, where unexpected turbine outage can be a costly occurrence.

HEPA filters are typically constructed from two media choices – PTFE membrane or microglass. The thickness of the media can play a large role in filter operating performance.

Not all HEPA filters are the same…

When it comes to HEPA filtration, there are two main options to select from: a filter made from Microfiber glass (glass fiber) or PTFE membrane. Both can provide HEPA level filtration and filter out fine particles from the gas turbine inlet. To achieve this, both use fine media but they are constructed and perform very differently.

PTFE is a simple polymer composed of carbon and fluorine. Expanded polytetrafluoroethylene (ePTFE) filter membranes consist of a single, very thin layer of finer media that creates a ‘sieving’, surface filtration effect. While highly efficient at capturing fine particles, this means the membrane has a relatively low filtration surface area. Any moisture droplets that become trapped, therefore, can quickly cause a complete blockage of the inlet filter. In real-world installations, the complete blocking of these filters can occur in as little as three weeks after installation.

Microfiber glass filters use a media layer that is ten times thicker than ePTFE, greatly increasing the filtration surface area. Rather than using the ePTFE model of a thin layer of finer pores, it uses its depth to capture particles as they travel inside its matrix. Even if moisture droplets block pores within the media, the volume of pores means the media will take much longer to become completely blocked. Any deterioration will happen slower than with ePTFE membranes; extending the life of the filter and giving operators plenty of warning that cleaning or replacement is required. It is this predictable performance that, for the time being, continues to make microfiber glass the preferred choice in heavy industrial applications.

Robustness of filter design

Many filters are designed for use in HVAC or laboratory-style conditions. To withstand the rigors of a power plant, a filter needs to be designed to handle a tougher environment and greater operating pressures.

Particular areas of weakness to consider when reviewing a filter’s construction include the gasket that seals the filter to its holding frame. Any joins in this gasket may be potential break points. The protection provided to the media pleat packs, i.e. does it have supporting mesh downstream to enable the pleats to cope with the increased working pressures in this application? For cartridge filters, the way the media pleats are glued to hold the pleats is important as any glue beads formed in the assembly process if not done correctly may break off the filter once it is installed. The overall materials of construction, including the compatibility of any adhesives also needs to be appropriate for the site conditions to avoid brittleness or cracking and to ensure the filter frame does not become warped over time or under the wider extremes of operating temperature.

Optimizing a filtration solution

Selecting a filtration solution will depend on a number of factors beyond filter media and unit design. The best solution may not be the most expensive and, ultimately, it is how the turbine performs that shows the suitability of a filter for its application. The level of output and heat rate of the turbine and how this varies over time are the best forms of data in establishing the effectiveness of a filtration solution. If an operator sees unacceptable increases in heat rate and decreases in output, then the filtration solution should be re-evaluated and other types considered.

Although testing standards continue to be researched and developed as environmental factors become more clearly understood, one of the problems operators face today is that the standard efficiency rating of the filter will not necessarily equate to the performance of the installed system. Recent comparative studies carried out by a major gas turbine OEM on the performance of equivalent ePTFE membrane and microfiber glass HEPA filter products covered overall efficiency, pressure loss, hydrophobic performance, wet performance and the dust holding capacity of each technology. The tests showed the microfiber glass filters to produce equal or better performance than the ePTFE equivalents, and at a lower cost.

This article is not trying to say microfiber glass media is better than ePTFE. CLARCOR manufactures ePTFE membranes which are successfully installed in many other filtration applications and future developments may well deliver improved resilience to moisture and hydrocarbons of this media type. As the technology stands today, however, the unpredictable response ePTFE membranes have to the wide-ranging air contaminants found at gas turbine installations means CLARCOR does not recommend them for use on turbine installations.

Summary

Filter test standards and materials for use in gas turbine filtration solutions continue to develop as we learn more about environmental impacts. What is clear is that operators need to take a wider view of filter and turbine performance rather than considering only standard efficiency ratings.

Both microfiber glass and ePTFE membranes can provide HEPA filtration levels. While ePTFE membranes can deliver a typical lifespan of two years, however, this is still much shorter than microfiber glass equivalents for power plant gas turbine installations. Where moisture levels are high or there is likelihood of fog or mist weather events, the thicker microfiber glass media will give a more predictable response. ePTFE solutions will require close monitoring and quick change out to protect machinery if they suddenly become blocked.

As technology and understanding develops, it is recommended that power plant operators consult filter manufacturers to understand the options available to them. By working with filter suppliers that appreciate and understand the varying needs of different environments, a turbine can be better protected and this may not be the most expensive option. By eliminating unnecessary maintenance or shutdowns and improving turbine performance, the right solution can give a very quick return on investment.

Author:
Steve Hiner is chief engineer of Gas Turbine Inlet Systems at CLARCOR Industrial Air.

Many large power generation fleet owners have deployed centralized monitoring and diagnostic (M&D) centers to improve generating performance and reliability. These M&D centers use advanced pattern recognition (APR) software to provide an early warning of changes in equipment condition that might indicate an impending failure. It is well documented that these centralized M&D centers have saved millions of dollars in avoided outage, maintenance and lost opportunity costs. However, a significant investment of human and capital resources must be made to achieve these benefits. False alerts are common and can distract M&D personnel from focusing on actual problems. Furthermore, interpreting what is causing the changes and determining the time horizon for action requires manual analysis and intervention by a time-constrained staff of experts and a dedicated monitoring team. This increases the cost of monitoring and can result in a delayed, inconsistent, or inaccurate diagnosis that wastes time, money or can put equipment and/or safety at greater risk. As a result, many smaller fleet operators are delaying implementation of a centralized M&D capability or are looking to outsource their M&D needs to third parties.

APR Signals

APR creates expected data signals corresponding with observed plant data signals.

Next generation “Lean M&D” solutions are now available that can more accurately detect and characterize an anomaly with fewer false alerts and then apply automated online diagnostics and prognostics to determine the likely cause of the anomaly and predict the remaining useful life of the asset. This more advanced approach captures and automates existing expert knowledge to provide more valuable and timely information to the plant staff or remote monitoring team. This, in turn, allows the operations team to better manage the risk of the potential failure, expedite the repair before a serious failure occurs, and reduce the overall (actual and avoided) cost to the plant.

Key Elements of a Lean M&D Solution

1. Scalable software minimizes the cost of implementation
2. Accurate anomaly detection reduces the number of false alarms
3. Automated diagnostics determines the cause for an anomaly
4. Automated remaining life estimates guide the urgency for corrective action
5. Well-defined alarm management and workflow processes maximize business value

By reducing the number of false alerts and automating the key expertise of subject matter experts (SMEs), fleet operators can benefit from online monitoring with a much smaller capital and human resource investment. This Lean M&D approach can be an enabler for smaller fleet operators who cannot afford the cost of a dedicated team of experts and monitoring staff. As the Lean M&D approach becomes more widely deployed, increasing efficiency will follow from the ability to capture and share valuable diagnostic and prognostic expertise across the industry. Taken together, these new analytics become a core element of harnessing the Industrial Internet in the power generation industry.

One of the key factors enabling Lean M&D is the availability of solutions designed to scale easily across the Industrial Internet. These solutions are designed to operate in the same way and perform the same services when running on a network edge device, on an engineering laptop or within a corporate or public cloud. This creates multiple points of entry for introducing powerful analytics that are interoperable across a deployment. Many new users benefit from solutions that can be run in full function mode on a single desktop or laptop. Few of the APR solutions deployed today offer this option and most require a large upfront information technology (IT) investment that has priced many smaller power generating companies out of the APR market. An ability to develop monitoring solutions locally and then scale up to the cloud or down to the device or control platform, when needed, is a new paradigm that is an enabling factor for Lean M&D.

The primary value of an APR-based solution is that it can be used to characterize plant operating anomalies in detail. Similar function can also be established using first principle models, such as a heat balance, when the variables of interest can be modeled based on physical, thermodynamic or electrical principles. The rise of APR solutions is mostly attributable to the fact that it is extremely easy to create an APR model of these same physical, thermodynamic or electrical principles using machine learning methods. Figure 1 on page 32 illustrates how APR is used to transform an observed data signal into a residual signal that has very useful properties for online monitoring. The APR model uses patterns in a set of signals to estimate the expected value of each of its input signals. The deviation between the observed and expected signals, often called the residual signal, will have a near zero mean and predictable statistics when the monitored system is operating normally and the APR model matches the data. When the monitored system moves away from normal operation, the change in properties of the residual signal can be characterized to define a set of symptoms that describe the change in behavior.

It is no surprise that all APR solutions are not equally capable of creating accurate expected data signals for plant operating data signals. However, the accuracy of the APR model’s expected data signal is very important when implementing Lean M&D. More accurate APR predictions translate directly to earlier problem detection and a more accurate initial diagnosis. More accurate APR predictions also mean fewer false alarms and lower staffing costs for alarm management. Managers of most large fleet remote monitoring centers cite false alarm management as the single greatest cost and inefficiency within their operations. Reducing the false alarm rate and improving the accuracy of problem detection and diagnosis is essential for moving to a Lean M&D implementation.

What then are the attributes that support a highly accurate APR solution? First, the APR algorithm itself controls the quality of the predicted values based on the observed values of the plant data. Most algorithms in use today are proprietary, but in general, those that use regression based methods will interpolate the expected data values more accurately than those that use cluster distance based methods or principle component based methods. A summary of several key features of a highly accurate solution are listed in Figure 2 on page 32.

Accurate APR solutions will also provide excellent support to help a user avoid the “garbage in-garbage out” problem. It is no surprise that a poorly designed APR model will be less accurate than a well-designed model. One key attribute of a well-designed model is that there is good correlation within the set of modeled plant data signals. In other words, there are actual patterns in the data for the model to learn and work with. Another key attribute of a well-designed model is the historical data used for calibration (a.k.a training) contains the full range of normal operation for the monitored equipment and does not contain any data from conditions that should be recognized as abnormal by the APR solution. Well-designed models also tend to require less on-going maintenance therefore further reducing the resources needed to maintain aLean M&D deployment.

Some next generation APR solutions go even further for improving APR accuracy by including tools for adaptive online calibration and operating mode optimization of the APR models and alerting thresholds. Adaptive calibration assures that false alarm rates remain low, despite normal aging related changes in the monitored equipment. This can help avoid the time and effort needed for periodic manual recalibration of the APR models and alerting threshold settings.

Operating mode model partitioning offers even greater benefit for accuracy by automatically optimizing the APR models and alarm thresholds for individual modes of operation of the equipment (i.e. high load versus low load) or variable equipment line-ups. Mode selection is automatic based on monitoring the plant control variables or operating data values. Mode partitioning allows finely tuned models to be engaged transparently as the monitored system moves through start-up, changing power levels, maintenance, and shut-down periods of operation. Alarm suppression and enablement are also mode specific so that user intervention is not required for managing mode-related false alarms.

Accurately characterizing changes in the plant data when a problem occurs is an essential prerequisite for analyzing the cause for anomalies automatically and providing the user with a diagnosis. Lean M&D solutions continuously update the diagnosis and advise the user based on the evolving state of the alarm events produced during monitoring. Alarm types useful for online diagnostics should include detectors for abnormal changes in plant data including: positive and negative mean value changes, increases and decreases in variance, excessive positive and negative rates of change, and values outside of reasonable ranges. These are available for application to observed data, predicted data and residual data and are configurable for each operating mode. Alarm settings used to characterize anomalies are learned during initial model calibration and are updated over time using adaptive calibration.

The diagnosis process itself can take one of three primary forms, all of which can be driven by the online monitoring alarm events. One common approach uses a rule-based expert system to process the alarm events. Most engineers are familiar with the IF-THEN rules approach used in an expert system and these can be effective in simple diagnostic scenarios. In the alternative, model-based reasoners and case-based reasoners are better suited for more complex scenarios, wherein multiple concurrent causes and overlapping symptoms are involved. Automated diagnostics for critical plant equipment often falls into this complex scenario.

As an example of a model-based approach, consider the diagnosis options for an observed increase in heat rate during operation of a combustion turbine. Figure 3 shows that an increase in heat rate will often be accompanied by one or more other symptoms, seven of which are identified on the bottom two rows of the diagram. Each of these symptoms can be activated or deactivated by the online anomaly detection system, for example using APR models and fault detectors. On the top row of the diagram, three possible causes for the increase in heat rate are shown: compressor fouling, turbine inlet temperature control error, and compressor discharge temperature measurement error. If the alarm state of the fault detectors is as illustrated by the yellow highlight, the compressor fouling diagnosis is the best supported cause for the observed anomaly.

Diagnosis Model       Fig 3

Diagnosis model for several combustion turbine problems having common symptoms.

Determining the remaining time available to take a corrective action in response to an anomaly condition depends strongly on making the correct diagnosis. In a simple example for a human being, a high core temperature might indicate for a flu or, in the alternative, appendicitis. When additional symptoms confirm appendicitis, a very different time horizon for corrective action will apply. Lean M&D solutions link the online diagnostic system with appropriate online prognostic models.

Accurate APR methods provide a valuable resource for implementing a wide range of effective prognostic models useful for moving to condition-based and predictive maintenance strategies. By effectively characterizing the way a monitored system is moving away from a normal condition, these solutions provide a unique prognostic opportunity for many practical maintenance planning problems. In the simplest cases, data driven prognostics can predict how long before a filter should be backwashed or changed, or how long before an operations limit will cause an alarm to occur in a control room. Once again, the accuracy of the estimated values will influence the result. An accurate prediction of the expected values provides an accurate measure of the rate and magnitude of the deviation of the monitored system away from normal conditions.

Prognostic Methods     Figure 4

Predicting the time horizon for condition-based maintenance of a gas turbine compressor.

As an example of a prognostic model, consider the problem of determining when the compressor section of a gas turbine should be scheduled for a water wash to correct compressor fouling and the resulting loss in cycle efficiency. In the plots shown in Figure 4, an aircraft gas turbine progresses from an acceptable condition at the beginning of the data set to a maintenance needed condition at the end of the data set. APR models are used to monitor the airflow parameters and the temperature parameters from the compressor inlet to the exhaust section. Remaining time until required maintenance is predicted using a combination of the abnormal change in static pressure aft of the compressor section and the abnormal change in exhaust temperature aft of the low-pressure turbine. When both conditions occur simultaneously, the diagnostic system alerts for a decrease in compressor section efficiency. The diagnostic alert activates the prognostic model for compressor efficiency loss, which begins tracking the degradation in efficiency and estimating the remaining number of flights before the monitored engine must be scheduled into a depot for inspection and maintenance.

The power of these prognostic methods is evident in the four plots presented in Figure 4. In the upper left, the blue trace shows the turbine exhaust temperature measured at cruise for a series of flights. The temperature values have a wide dynamic range because each data point can be taken at a different altitude, ambient temperature and power lever angle setting. In comparison, the corresponding APR expected values are shown in the lower left plot. The expected values track the observed values well. By computing a residual degradation signal from the observed and expected values, as shown in the plot on the upper right, it is evident that the exhaust gas temperature is slowly creeping up as the data progresses from flight-to-flight.

At 177 flights into this data set, the diagnostic model alerts with a diagnosis of compressor efficiency loss. This activates the prognostic model to automatically evaluate and track the number of flights remaining before maintenance is required, as shown in the lower right plot. In this case, a perfect prediction would be a straight line from fifty-six (56) flights remaining at flight number 177, which is the time of the initial diagnosis, to zero (0) flights remaining at flight number 233, which is the known condition where maintenance is required for this engine. As is often observed, the remaining life predictions in this example are more uncertain at first and improve as the path of the degradation signal becomes better defined.

Lean M&D combines anomaly detection with advanced diagnostics and prognostics to assemble an integrated and automated system that significantly reduces the resources needed for a central monitoring team of experts. This allows smaller power generators to enjoy all the remote monitoring center benefits enjoyed by larger power generators who today can afford to retain expert staff for performing diagnostics and prognostics. All of this comes with a much lower initial investment and lower overall cost for operations.

Author:
Randy Bickford is president of Expert Microsystems Inc.

By John Solan, P.E., Mike Ruckhaus, P.E., and Chilkoot Ward, P.E.

On a quiet Friday at 5 p.m. in December, 1998, the outdoor thermometer at the University of Alaska Fairbanks showed minus 20 degrees Fahrenheit. Inside the UAF Atkinson power plant, an aging tube in the Unit 1 power stoker burst under 625 pounds per square inch of pressure, filling the facility with steam.

Steam condensation tripped off the plant uninterruptable power supply, which in turn shut off power to the control system, shutting down the plant and pitching the entire campus into darkness. Frigid air began attacking the buildings and dorms that were heated by the steam system from the Atkinson combined heat and power plant. Meanwhile, computer networks and communications systems at the sister campuses in Juneau and Anchorage failed due to their reliance on facilities and equipment located on the Fairbanks campus.

Cold weather tenting for the Atkinson Heat and Power Plant retrofit project at the University of Alaska Fairbanks campus. The plant is being overhauled at a cost of $245 million. Photo courtesy: Stanley Consultants.

If the plant staff didn’t move quickly enough, untold millions of dollars’ worth of damages would occur, from frozen plumbing and HVAC systems to the water treatment plant to damaged research equipment and lose priceless in-progress research specimens and samples.

The top priority was to dry out the campus switchgear and restore the power supply to the campus. Once the switchgear was functional, the staff restarted the three undamaged boilers. Working through the night, they restored light and heat to the campus in 12 hours. They would repair the ruptured tube and restart the remaining boiler later that week.

Thankfully, no one was hurt in the Dec. 11, 1998 incident. Although a crisis was averted, the event served as notice to UAF that its two end-of-life boilers, installed in 1964, were a catastrophe away from significant damage to the university’s infrastructure.

A Campaign Begins

UAF is a university looking to the future. Founded in 1917, the university has 10,000 students and 2,000 faculty and staff at the Fairbanks campus, which includes 3.4 million square feet of academic, research, administrative and housing space. Research funding, which grew from $56 million in 1997 to $108 million in 2010, was one of the key drivers in its expansion.

UAF needs energy generation to grow. A $108 million life sciences teaching and research building, a $5.3 million arctic health greenhouse, $4.7 million energy technology facility and a $110 million engineering building have been built or are in the construction stage. In addition, partly because it has its own source of heat and power, UAF is considered a place of sanctuary for the surrounding community in case of emergency, including floods and earthquakes, therefore a reliable source of energy was important.

UAF was witnessing campus growth that exceeded its aging utility service capacity, which operated on technology developed in the 1890s. No significant utilities investment had been made since 1999. As a result, it developed a campus utilities development plan in 2006, which was followed by a series of reports and discussions with local and state political bodies. It culminated in the state funding $3 million for a preliminary engineering study to evaluate technology and fuel options, and the effort was awarded to and performed by GLHN Engineers in 2010.

The Coal Decision

Engineers started their analysis with the big picture: Fuel supply and emissions. The mission was to produce energy and more of it; yet because Fairbanks is in a valley clouded with wood smoke from homes and businesses, the area was classified as a non-attainment area for Pm².⁵ under EPA standards. UAF needed a larger plant that produced more energy for future campus expansion but couldn’t exceed its current emissions level. It would need a solution with emissions characteristics that were far lower than the existing equipment could accommodate.

Temperatures in Fairbanks range from 90 degrees Fahrenheit in the summer, to 60 below in the winter. In 2011, the university generated 57,000 MW-hrs annually and purchased another nearly 9,000 MW-hrs from the local utility. Chilled water production for air conditioning amounted to 3.9 million ton hours.

While UAF would have loved to use alternative energy sources to generate power, it wasn’t realistic. In January, it would require 4,900 acres of photovoltaic panels in the paltry available light, even if energy storage was available. Biomass – wood or other organic fuel — requires 54,000 acres per year, or 50 acres per day. Installing wind turbines would require hundreds of miles of transmission lines due to the low average of wind speed in the area. Hydro power on the nearby Chena and Tanana rivers would take decades to develop and there is no viable source of geothermal.

Fuel cost was another major factor. The nearest natural gas pipeline is 400 miles away, so it wasn’t an option in the near or even long term. Liquefied natural gas ($17/MMBTU) must be trucked into Fairbanks, re-vaporized and then distributed via city gas lines, but the supply can become limited as the temperature falls. Fuel oil ($18.85/MMBTU) and buying power ($50/MMBTU) were also high cost alternatives. Coal, supplied by rail from 130 miles away, costs $3.67/MMBTU.

Fuel costs were only part of the formula, of course, along with capital and operational costs. In all, Stanley Consultants evaluated several options for UAF:

1. Do nothing different and rehab existing boilers. The two older coal-fired boilers would produce 100,000 pounds of steam per hour and the remaining diesel boilers would generate 200,000 pounds of steam per hour. Cost, $25 million through 2024, including capital and operating costs. No allowance for campus growth. Reliability issues.
2. Coal-fired gasifier, reciprocating engine and heat recovery system. Complicated arrangement with an estimated cost of $26 million, through 2024, including capital and operating costs. It produces power first rather than heat.
3. Gasifier, gas boiler and steam turbine. Generates heat first, which is attractive in a cold climate, but is also complicated and costs $31 million through 2024. Would not net out emissions.
4. Gas turbine generator, heat recovery steam generator. Would need liquefied natural gas storage and vaporization facility. Produces power first, rather than heat. Fuel costs high and no reliable source. Cost projected at $38 million through 2024.
5. Gas boilers and steam turbines. Cost and issues same as gas turbine generator.
6. Municipal solid waste gasifier and gas boiler with steam turbine was looked at but there were too many unknowns to develop a cost model.
7. Buying electricity from the local utility to generate steam was cost prohibitive.
8. Circulating fluidized bed boiler and steam turbine. Two 140 Kpph CFB boilers would provide 100 percent of future needs. Creates heat first with high efficiency. Cleaner technology that would net out emissions in the present and future. Cost, $24 million through 2024.

Given the economic and reliability factors, the decision for the last option surfaced as the best option. This also had the benefit that would allow UAF to retain its efficient combined heat and power generation that averages up to 70 percent efficiency. A circulating fluidized bed boiler creates heat first, ideal for a cold climate generation system. The two new boilers would be clean enough so that the steam capacity could be increased to meet future energy needs while staying under the existing emissions cap.

Building a new coal plant in today’s generation environment is unusual to say the least. The Department of Energy’s inventory of planned generators as of November 2016, lists only five planned conventional steam coal plants, including UAF. Three of those have indefinite construction dates, and the fourth, Two Elk Generating Station in Wyoming, has completed minimal construction. The UAF plant is 60 percent complete and scheduled for commissioning in early 2018 with commercial operation in November 2018. The new boilers could be the last conventional coal-fired units built in America, at least for many years.

Steam drum lift. Photo courtesy: Stanley Consultants

The Funding Campaign

UAF filed an initial capital request in Juneau for the plant’s funding and gained the support of Alaska Senator Pete Kelly, who served on the Senate finance committee. The state approved $245 million for the new plant in 2014, after failing to approve funding in 2013. It was just in time. Plunging oil prices caused a ripple of state budget slashing. One year’s delay would have killed the project.

With funding in hand, the project commenced. An issue arose immediately. It became apparent that two new boilers and new facilities would cost $50 million more than was funded, due to the realities of building a power plant in Alaska. The project team went to work on new plans: UAF would install one large boiler in place of two smaller ones. It would produce 240,000 pounds of steam per hour instead of 280,000 and forfeit some flexibility, but its redesign, along with eliminating administrative, maintenance and storage facilities, would allow the project to meet the budget.

Detailed Design Underway

In September 2014 UAF procured a Babcock & Wilcox CFB boiler. The company states that fluidized-bed technology reduces NOx and SO₂ emissions by allowing the control of bed temperature and using reagents such as limestone as bed material. It can also burn biomass or waste fuels, which are difficult to burn in conventional boiler systems. The manufacturer’s experience and design shows that the CFB boiler brings high combustion efficiency, an economical design, higher reliability and availability, lower maintenance costs, reduced erosion, fuel flexibility and low emissions.

The key for UAF was to obtain a guaranteed Pm2.5 emissions rate from Babcock & Wilcox, and therefore not derail the emissions permitting process. While there was some debate, the manufacturer ultimately made the guarantee, despite its high-performance level. It would be one of the lowest Pm2.5 emissions guarantee for a coal boiler in the U.S.

As the detailed design process began, UAF had selected the construction manager at risk (CMAR) contractor; this early involvement would allow the project team to capitalize on the contractor’s construction expertise and implement it in the design effort. The CMAR contractor, Haskell Davis Joint Venture (Haskell Corp. and Davis Constructors), provided independent cost estimating and design review as each segment of the project developed. Stanley Consultants partnered with a local firm, Design Alaska, which performed civil, architectural, HVAC, plumbing and fire protection planning. Design Alaska also provided insight into artic engineering practices.

Engineering challenges for seismic, extreme weather conditions, and a space constrained site were increased when the design was also to account for UAF’s role as an essential facility in the community, a place of refuge. Buildings had to be able to functionally withstand seismic events. The soils underneath the facility were porous and sandy, therefore were subject to liquification in an earthquake. They had to be consolidated down to 50 feet deep before construction began.

The final design produced some novel features. Combustion air can be pulled from out outside or inside the building, depending on the time of year. In warm weather, an intake duct takes air from higher in the building, which takes advantage of heat collected in the upper building. It reduces the amount of pre-heating required before air enters the boiler.

Steam turbines exhaust low-grade heat that normally goes to waste. During winter, UAF’s heat recovery system captures exhaust heat from the turbine and transfers it via the chilled water distribution system for preheating the air into the buildings throughout campus. In the summer, the surface condenser is removed from service and the chilled water system functions normally.

The air-cooled condenser controls are designed for sub-arctic conditions. The system varies air flow over the ACC cells to ensure that no cells stagnate and potentially form ice. In addition to these features, some renewable energy generation will be installed. Solar panels that will be installed on the entire south side wall of the ash handling building will generate up to 45 kilowatts during summer.

Installation of the steam turbine on its pedastal at the UAF Atkinson Power Plant. Photo courtesy: Stanley Consultants

Permitting

The permitting process was unremarkable. The emissions netting approach allowed the project to avoid non-attainment new source review for Pm².⁵ as well as standard new source review for the remaining pollutants. Ambient dispersion modeling was also avoided.

The Alaska Department of Environmental Conservation granted a minor source permit for the redesigned boiler on Aug. 26, 2015 and a revised permit on Oct. 21, 2016. There was little public comment, because most residents understood there was no viable alternative to coal, and that the plant’s efficiency and pollution control capability would be an improvement of the continued operation of the existing coal boilers

Construction

Construction started during the summer of 2015 with compacting soils six months before the building’s foundation was laid in spring 2016. The soil was heated to prevent freezing. Construction was fully underway by the spring of 2016. The power island foundations were completed by fall of 2016 and structural steel erection had commenced and was proceeding.

Sub-arctic conditions continue to affect construction, with a plan to continue construction through the winter until temperatures hit minus 30. To date, only a few days have been cold enough to halt construction. To minimize productivity and schedule impacts, the temporary and permanent siding was installed on the turbine and baghouse buildings early so that workers would be able to work in climate-controlled conditions.

The new plant is designed to achieve a miniscule .012 pounds of Pm².⁵ per MMBTU; to triple the plant’s heat and power output while improving efficiency by 20 percent. The new plant will emit only 20 percent of the nitrogen oxide 2 and 3 produced by the previous plant. Sulphur emissions are lower as well, while it allows reduced oil consumption and renewable energy can be purchased using the CFB boilers as a reliable base load. It will have one of the lowest emission rates for Pm².⁵ of any coal plant in the U.S. For the near- and mid-term future, coal, using the latest available technology, was the right choice to power UAF’s growth.

Authors

John Solan is a senior mechanical engineer at Stanley Consultants in Denver. Mike Ruckhaus is senior project manager at the University of Alaska Fairbanks. Chilkoot Ward is UAF’s Director of Utilities.

Over the past decade, fossil and hydro generation plants have increasingly experienced significant changes in their operating strategies, or “mission profiles,” compared to their original designs. These changes include new operating regimes with increased cycling, extended unit layups, and prolonged periods of low turndown.

The changes, in turn, are creating a multitude of challenges for the plants and their operating staff in areas ranging from component degradation to staffing levels, O&M budgets, and meeting environmental compliance under non-baseload conditions.

The Brunswick County Power Station. Flexible operation of power generation assets is not new. What is new today is the frequency and level of cycling required. Increased operational flexibility is becoming more commonplace. Photo courtesy: Dominion Virginia Power

Several years ago, to help the utility industry address these challenges, the Electric Power Research Institute (EPRI) launched a multi-utility, collaborative research project to identify the critical technical issues associated with these trends and to collect best practices and new technologies and processes to mitigate damage and increase flexibility. The project, called “Changing Mission Profiles,” has consisted of a pilot project of power plant case studies to evaluate the experiences of different unit types and an industry working group that convenes to share effective solutions and strategies.

To date, seven case studies have been conducted, and the results have been summarized in an EPRI report entitled Changing Mission Profiles Pilot Project (3002005859). In addition, the working group has held multiple sessions to identify the technical issues and solutions for different combinations of unit types and mission profiles.

Challenges of Increased Operating Flexibility

Flexible operation of power generation assets is not new. What is new today is the frequency and level of cycling required.

Several years ago, a generation planning research study, funded jointly by EPRI and the U.S. Department of Energy, found that the extent and diversity of increased flexible operations will be profound over the next 20+ years. The majority of dispatchable units will experience the necessity for flexible operations, and possibly multiple mission profiles. Flexible operations will also be geographically widespread; most power companies will have to support multiple mission profiles across their fleets in managing current and future assets.

According to this same research, flexible operation is the principal issue arising from increased variable generation, and key hurdles are operations at minimum loads and significant amounts of ramping at high rates (Figure 1). The study also projected frequent, large changes in average hourly generation for combined cycle and conventional fossil assets, as well as significant periods of low-load operations and reserve standby.

As many generation units find that the need for increased operational flexibility is becoming more commonplace, they are facing several challenges:

• Complex Operations. Flexible operations are inherently more complex. As units are operated more flexibly and/or with specific retirement horizons, plants need to operate closer to design limits. As a result, there may be greater levels of dependence on more accurate measurement of key parameters, optimization and process controls, remote monitoring systems, and more burdens on the operator.
• Integrated Impacts. Integrated plant impacts are not well understood or documented. Plant design margins and the consequences of reducing them are integral to understanding the impacts of modifications, installation of new systems, and alternative operational and maintenance strategies. For example, an equipment design life consumption rate under off-design operation might be an important consideration in a decision to balance costs or risks. Not understanding these margins or impacts can lead to unanticipated consequences.
• Burden on Staff. Changes to plant design and/or operational mission tend to place a larger burden on plant staff. These changes can place more responsibility, knowledge requirements, restrictions, and error traps on plant staff. For example, the technical basis (that is, failure modes, degradation rates, preventive maintenance frequencies, equipment monitoring needs, etc.) for maintenance may need to be modified, implemented, and maintained by limited staff resources.
• New Skill Sets Needed. Implementation of advanced technologies and data integration in response to increased flexible operations requires new skill sets. Driven by the availability of increasing amounts of quality data, a changing work force, and the economic need for a leaner O&M staff, data analytics and centralized monitoring and diagnostics will become increasingly important tools for managing overall plant performance.

Pilot Project

The Pilot Project portion of Changing Mission Profiles sought to drill down to better understand how these challenges manifest themselves in different unit types and under different mission profiles. The Pilot Projects consisted of in-depth assessments of central station generation units that are experiencing operational modes that differ from their original design basis. These assessments were comprehensive, unit-level “deep dives” into the technical issues associated with specific generation types, the relative importance of these issues, and the extent to which these issues are generic.

The approach consisted of on-site visits by utility and EPRI subject-matter experts (SMEs) to generation units to discuss with the host utility personnel the actual experience of units managing significant flexible operation.

Central generation station units-including hydro, coal, and gas plants-were visited. Unit types and their missions were as follows:

• Francis-type hydropower plant (four units) / load following and part-load operation; increased diversion (spillage) during times of low demand.
• Subcritical natural gas boiler units (one plant, two units) / load following with frequent low turndown and shutdowns.
• Supercritical natural gas boiler units (one plant, two units) / load following with frequent low turndown and shutdowns.
• Gas turbine combined cycle (six units) / increased variability in operations centered on higher capacity factor; significant decrease in starts/year; minimum load during evenings.
• Subcritical coal plant (one unit) / extended layup with months that separate operational periods; load-following mode.
• Subcritical and supercritical coal plant (seven units) / subcritical units experience combination of load follow and extended layup (shutdown) ranging from two days to two months; supercritical units experience load-follow mode.
• Supercritical coal plant (three units) / long-term layup; turndown to as low as possible.

The site visits incorporated on-site workshops with SMEs and plant personnel. These workshops employed a standardized process to identify, discuss, and prioritize key technical issues for that unit / mission configuration. For each issue, the process captured critical assumptions, options and tradeoffs, key interrelationships, vulnerabilities, unanticipated consequences, and gaps and uncertainties in industry knowledge and understanding.

Ranking of Issues

The site visit workshops produced a ranking of technical issues related to plant operations, equipment, and environmental controls. For each unit / mission, experts and stakeholders applied evaluation criteria to the issues via a template. The criteria for ranking included:

• Impact on corporate metrics-How does this issue affect corporate performance and related metrics?
• Acceptable options available-Are there good solution alternatives?
• Technical resources available-Are solutions available through EPRI or other organizations?
• Degree of uncertainty-Do we understand the technical basis for the issue and for the solution path forward?
• Impact on plant staff and O&M-How will the solution to the issue be sustained and affect the plant staff?

For each issue, the criteria were used in a scoring system that established a numerical rating. Examples are shown in Tables 1 and 2 on pages 18 and 20.

This perspective was useful in understanding the complex interrelationships between these issues from the standpoint of both the technical/scientific disciplines and the power company organization, plant processes, and related resources.

Bayside Power Station was among the nation’s top 20 power-producing combined cycle plants in 2015. Photo courtesy: Tampa Electric

Key Insights on Technical Issues from Pilot Project Site Visits

The site visit workshops conducted for the Pilot Project identified a number of key insights on technical issues:

• Increased Changing Mission Profiles. Discussions at the site workshops supported the projection that an increasing number of coal and gas units are likely to continue to see changing mission profiles. Moreover, units experiencing new missions may likely experience multiple mission profiles in the future.
• Timeframe. Given that most existing coal units were designed based on the assumption of baseload operations, and considering the relatively slow turnover in the existing coal fleet, it will take a long time (on the order of decades) for new generation technologies inherently designed for multiple mission profiles to significantly penetrate the U.S. generation fleet.
• Ramp Rates. With increased shutdowns and low-load operation, high ramp rates and the corresponding impacts on equipment and systems are becoming an even more critical concern.
• Low-load Operation. Low-load or low-turndown operation was the predominant operating regime experienced by the pilot sites. The second most prevalent mode was shutdown where the duration was uncertain, thus complicating the planning and layup/equipment preservation efforts.
• Avoiding Shutdowns. Enabling lower-load operation of coal plants was identified as a key strategy for avoiding or minimizing shutdowns and the damage associated with on/off cycling. An alternative strategy was switching fuel to a lower-cost coal and/or gas co-firing. Both strategies come with plant-specific technical challenges.
• Layup Practices. Developing effective and “progressive” layup practices (that is, where the selection of layup practices and associated costs/ resources are commensurate with the duration of shutdown and startup demands) are perhaps the most widely felt, high-priority need across all unit types.
• Component Issues. Key issues involving major components that are experiencing low-load operation and frequent shutdown/startups included chemistry concerns and mechanical stresses of turbines, pitting damage and corrosion fatigue of boilers/heat recovery steam generators (HRSGs), and core integrity issues with main generators.
• Environmental Controls. For coal units experiencing low-load operation and frequent shutdown, issues related to the performance and reliability of the environmental controls equipment consistently ranked very high. The nature of these issues ranges from the cost of compliance and balancing the impacts on air/water/solids emissions to maintenance and effective layup practices for environmental controls equipment. For coal units with selective catalytic reduction (SCR) for NOx control, the minimum operating temperature of the SCR is often the first limit to low-load operation.
• Teams. Cross-functional, multi-disciplinary teams provide significant value in identifying and evaluating technical issues of importance from the standpoint of: (1) determination of new issues and areas of concern; (2) identification of solution options; and (3) assessment of impacts on plant staff and related resources.
• Holistic Approach. Breakout sessions at all pilot site workshops yielded new issues that were not initially identified. Both the identification of technical issues and potential solutions have benefitted from a holistic perspective. It ensured that insights from all aspects of the plant design, operations, and maintenance were included in the evaluation, as well as broader company-wide concerns such as emissions compliance strategies.
• Cost Factors. Budget uncertainties limit available options. The viability of solution options was an important consideration during discussion of each issue. In many cases, the cost of the solution option and the uncertainty in getting corporate financial support to deploy that option were key factors. This observation reinforces the need for multiple solution options with clear assessment of the compromises that would be made with a non-optimum “fix.”
• Monitoring and Diagnostics. A key aspect of the sustainability of potential solutions and the impact on plant staffs is the expectation of increased monitoring and diagnostics and the resultant significant increase in data. Data acquisition/monitoring centers could play a key role in addressing this challenge.

Key Insights on Generic Solutions

The site visit workshops also identified a number of insights on generic solutions:

• New Design or Technical Basis. With the advent of changing missions across the central station generation fleet, developing an improved understanding of the off-design operational impacts on plant processes and equipment becomes an important first step. Many plants are conducting tests to measure these impacts and the effectiveness of remedial actions. This includes characterizing specific impacts of flexible operation on major components, such as the boiler, turbine, etc. These efforts enable the development of a new design basis or technical basis for actions to correct or mitigate the negative consequences of the new mission.
• Monitoring Equipment. Possible damage could be avoided if the operations staff had information on the unit’s condition. For example, the addition of wireless thermocouples in and around the furnace could assist with monitoring operating conditions and also facilitate tuning of the burners. Novel high-temperature semiconductor strain gages would facilitate more effective monitoring of conditions that exacerbate creep and thermal fatigue.
• Measurement. Measurement of key process parameters are needed for automated control of critical and complex processes, which lessens the burden on operators and reduces human errors.
• Burden on Staff. Impacts of more frequent startups challenge the plant staff. Industry guidance on proper layup, greater levels of automation, and on-line monitoring systems may help alleviate this burden.
• Training. It is essential to capture the knowledge from current O&M staff before they retire. It may be necessary to retrain staff as they shift from one generation asset to another. A plant simulator capable of simulating several different operational modes would be helpful but may be seen as too expensive.
• Cost Impacts. Discussions during several site visits suggest that quantifying the impacts of new missions such that costs can be determined would help in risk management and resource (O&M and capital) planning.
• Need for Holistic Solutions. The issues associated with changing mission profile require solutions that span technical disciplines. For example, environmental compliance under changing mission profiles requires understanding the technical basis of key processes (e.g., mercury oxidation, sorbent effectiveness) such that effective process controls can be implemented. However, to successfully implement and sustain this solution, new instrumentation and controls, advanced monitoring and diagnostic systems, a new maintenance basis, and operator training will likely be needed.

Future EPRI Activities

The Pilot Project indicated the need for future EPRI activities, including the following:

• Industry Resource. There is a need for an industry resource that defines, acquires, organizes, and disseminates unit-level lessons learned and experiences.
• Review Process. For plants undergoing new missions and planning an analysis of technical issues, it would be beneficial to have a systematic, cross-discipline SME review process that identifies issues, solutions options, and unanticipated consequences.
• Environmental Controls and O&M. A number of needs have arisen involving the connection between environmental controls and O&M. For example, an analysis is needed of air/water/solids emissions such that capture of a pollutant does not inadvertently cause a more expensive or complex problem of disposal.

Working Group

To proactively address the R&D needs identified above and to bring the value of the Pilot Project to all companies with generation assets facing new missions, a broad new industry collaboration was established. The collaboration, called the Mission Profiles Working Group (MPWG), consists of 13 utilities, representing over 200,000 MW of fossil generation, and organizes groups that seek to produce insights on how individual units can most cost-effectively accommodate new mission profiles.

Over two years, the MPWG has organized multiple working groups around different high-priority design/mission profile combinations. These groups consist of cross-disciplinary subject-matter experts who are identifying key issues and solution options or work-arounds, not just “gold-plated fixes.” The MPWG is also establishing an industry resource in the form of a living database of issues and solutions. Under development, too, are a self-assessment process based on the database that provides a systematic approach to assessing issues in an individual unit, and a progressive layup guidance.

Author

Mike Caravaggio is EPRI Senior Program Manager, Major Component Reliability.

Norris Hirota is a Senior Technical Executive at EPRI.

Using Creep-FatiguePro Software to Monitor Boiler Life

Like other coal-fired plants in Spain, the As Pontes Power Station in Galicia, Spain is required to cycle extensively and operate relatively infrequently due to the power market and the extensive base of renewable energy that dispatches first.

This cyclic (start-stop) operation can result in accumulation of fatigue damage, particularly in thick-walled components such as high-temperature headers that experience the greatest thermal transients. In addition, components exposed to high temperature and pressure experience creep damage over time. Tracking the accumulation of fatigue and creep in these components is a critical element of an overall strategy to manage the life of boiler components.

In the early 1990s, EPRI developed Creep-FatigueProâ„¢ (CFPro) software as a way to trace the accumulation of creep and fatigue damage, while a plant is being operated, based on actual operating conditions-temperature, pressure, and flow rate. Over the years, the software has been upgraded and new features added.

Recently the international utility Enel employed CFPro software to monitor accumulation of creep and fatigue damage at several locations in its As Pontes Power Station. The software helped the utility to track the level of damage occurring, to understand the direct effects on the plant of operational changes, and to plan remedial actions.

CFPro software was installed in the As Pontes Power Station and integrated with the plant instrumentation (PI) system. Eight locations were monitored on the super¬heater (SH) outlet header, and three locations were monitored on the hot reheat steam piping.

Over a several month test period, the CFPro system at the As Pontes plant clearly showed the impact of plant start-up on fatigue accumulation in the SH outlet header and identified an increase in the creep damage rate as a result of a 15°C temperature increase in the SH header. These findings provided important insights into the operation of the plant to minimize fatigue and creep damage accumulation as a result of flexible operation. The online component life assessment, made possible by the CFPro system, is being used to support timely decisions regarding: (1) unit operational strategy management, (2) impact of plant operating modes on component life, (3) component inspection need and schedule, and (4) run/repair/replace decisions for detected damage.

In their search for reliable, flexible, low-cost sources of power, investor-owned utilities, municipal utilities and rural cooperatives have varying pressures and selection factors but many of them choose the same technology solution: reciprocating engines.

Overall power trends affecting their choices in the U.S. are readily visible: Decommissioning of small and medium coal-fired units, natural gas-fired power generation for peaking and base-load capacity, rapid growth of renewables; growth of distributed generation and mixing of power generation technologies within a utility.

The versatile reciprocating engine is increasingly being selected as the solution to these challenges, from one small engine to a bank of larger engines. While the engines can operate on fuel oil or other liquid fuels, they primarily burn natural gas.

Individual producer needs vary: A tale of a few cities

The city of Alexandria, Louisiana’s contract with the local utility had ended. How could the city upgrade its aging fleet, be self-sufficient and stabilize rates for 20 to 30 years while joining the Midcontinent Independent System Operator? City officials also wanted a diverse, sustainable fuel source.

The city’s prior fuel mix for generation was 80 percent coal, 17 percent gas and 3 percent hydroelectric. As part of the EPC team selected for the project, Stanley Consultants acted as engineer-of-record for the balance of plant for the installation of the seven, 9 MW Wartsila reciprocating engines that satisfied Alexandria’s requirements.

The engines can be started up in about five minutes, which means that sudden demands from the grid could be accommodated. All or one of the engines can be used at any time, providing more reliability and flexibility. The engines even fit in a tight space adjacent to the city’s existing plant in the middle of town and meet the city’s stringent noise requirements. After installation, the fuel mix is 47 percent coal, 50 percent gas and 3 percent hydro.

Tallahassee Florida: Build this plant fast

Tallahassee needed to add power generation quickly, and reciprocating engines fit the bill.

Power production manager Triveni Singh said the multiple small units fits the city’s load profile and will complement the planned 20 MW solar facility. Efficiency, low maintenance and high reliability in addition to the quick-start capability were also keys, Singh said, as well as lower C02 emissions and the ability to be located at distributed sites.

Palmer, Alaska: Extreme temperature changes, earthquake concerns

Matanuska Electric Association is Alaska’s oldest existing and second-largest electric cooperative. MEA’s service area includes more than 4,300 miles of power lines in Southcentral Alaska. MEA had purchased power from another Alaska cooperative but wanted to be more self-sufficient and generate their own. Stanley Consultants served as owner’s engineer for the project.

The needs? Reliable, affordable energy and the ability to operate in temperatures as low as 40 degrees below zero Fahrenheit. In addition, in case the supply of natural gas was interrupted, the plant could switch to fuel oil stored onsite. The cooperative would also be asked to produce as much as 145 MW during the winter and as little as 50 MW during the summer. The installation of 10 new Wartsila 17.1 MW engines met MEA’s needs because of their ability to add grid reliability and fast response time in case of load following. The plant is 30 percent more efficient than its former power supply. MEA is producing electricity for its members at a lower cost and generating additional revenue from selling excess capacity to other utilities.

The benefits of the reciprocating engine

Reciprocating engines provide a proven, reliable technology, but recent upgrades in efficiency and reliability are making them the go-to choice for the addition of small to medium-sized power generation.

For larger applications, reciprocating engines may not be a fit. The overall plant footprint is smaller for a combustion turbine, and the heat rate, or efficiency looks better, especially in combined cycle mode. In larger plants, capital costs can be lower with combustion turbines as well.

According to the U.S. Department of Energy, “Gas-fired reciprocating engines are the fastest-selling, least expensive distributed generation technology in the world today.” The technology does not fit every situation, but has found its way into the power generation ecosystem.

Environmental interest groups celebrate with each utility project’s cancellation; every project delay is also a success. President Trump’s proposed “America First” budget cuts $2.6 billion, or 31 percent, from 2017 funding and discontinues funding for the Clean Power Plan, international climate change programs, and climate change research and partnership programs. This budget, if enacted, will have an opposite effect from that intended. Power plant projects which benefit on paper from the cuts to EPA will in fact be delayed by citizen suits attempting to restore EPA’s power.

The Clean Air Act (CAA), which cannot be changed without an act of Congress, explicitly authorizes citizen suits to enforce CAA provisions. Section 304, aptly titled “Citizen Suits,” states “any person may commence a civil action” against the United States to enforce “an emission standard or limitation,” “against the Administrator where there is alleged a failure of the Administrator to perform any act or duty,” or “against any person who proposes to construct or constructs any new or modified major emitting facility.”

Intervener groups are intimately familiar with this power granted to them under the CAA, most recently in regards to EPA’s delay in promulgating air toxics standards. On March 22, 2017, a federal judge in the District Court for the District of Columbia ordered EPA to promulgate emission standards for 13 sources of hazardous air pollutants by June 30, 2020. EPA admitted that they had missed the regulatory deadline and four intervener groups sued to force EPA to act. Seth Jaffe, of the blog www.lawandenvironment.com, says “if Congress enacts even a significant portion of the budget cuts requested by President Trump, we’re going to see a lot more such cases.”

The court order includes several key statements:

• The Clean Air Act provides that the district courts of the United States shall have jurisdiction to compel nondiscretionary agency action that is unreasonably delayed.
• Courts should be wary of agency arguments that more time is needed to improve the quality or soundness of the regulations.
• If the EPA finds the schedule set by the Clean Air Act to be unreasonable, the agency’s remedy lies with Congress, not with the Courts.

In response to the proposed presidential budget, the EPA estimates 25% of its staff will be laid off. This budget blueprint serves merely as a guideline for any final enacted congressional budget. However, with a Republican majority in both houses of Congress, massive cuts to EPA will no doubt occur.

Following quickly after the presidential budget blueprint, two additional actions occurred that on the surface seem to favor utility companies. First President Trump’s executive order on “Promoting Energy Independence and Economic Growth” declared: “It is in the national interest to promote clean and safe development of our Nation’s vast energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production, constrain economic growth, and prevent job creation.” Then EPA administrator Pruitt wrote to the governors of each state that they are neither “required nor expected to work towards meeting the compliance date set in the” Clean Power Plan.

The rally cry for intervener groups is now prewritten. They will surely focus their efforts on climate change regulations. Acknowledging both that utilities emit a large portion of U.S. greenhouse gases and that public passion centers on climate change, public uproar and lawsuits will center on utilities.

Utility companies learned from the lessons of the Clean Air Mercury Rule, the Clean Air Interstate Rule, and the Cross-State Air Pollution Rule that legal challenges to environmental rules create economic uncertainty when funding power plant maintenance or expansion projects. Nothing in the executive order nor the new EPA policy negates the fact that the Supreme Court ruled that greenhouse gases are a pollutant under the Clean Air Act. Although not perfect, the Clean Air Act at least had become well understood by utilities over the last 45 years of its implementation. Utilities, through their interest groups, had input into the pending regulations. Now, certainty has been thrown out the window.

Therefore, the utility which argues against EPA cuts would both curry favor with the public while advocating for EPA policies which reduce economic and regulatory uncertainty for their power plant projects.

Energy storage has been called a “game changer,” a “panacea,” and a “disruptor.” It has garnered widespread interest from electric companies, residential customers, businesses, manufacturers, regulators, and policymakers. Its potential for growth has been described as “astronomical” and “colossal,” and its benefits sometimes touted as incalculable. Indeed, energy storage has the potential to be a true game changer.

It is a very promising technology that, along with other elements of a diverse resource mix, will benefit consumers by allowing greater penetration of renewable energy; creating more dynamic generation, transmission, and distribution systems; and enabling transportation electrification, microgrids, smart grids, smarter cities and communities, and all the visions of the future energy grid.

Southern California Edison’s Tehachapi Energy Storage Project, which was built near one of the largest wind power hubs in the U.S. – the Tehachapi Wind Resource Area. The project uses lithium ion batteries to store excess wind power. Photo courtesy: Southern California Edison.

Energy storage technologies include batteries, flywheels, compressed air, thermal storage, and pumped hydropower. These technologies all provide a way to save previously generated energy and to use it at a later time, which is why energy storage is such a useful and versatile resource for electric companies and their customers.

Although energy storage has been around for decades in one form or another, only recently has it become a viable technology able to provide multiple benefits to customers as well as the energy grid, and energy storage is well on its way to becoming an integral part of our electricity system. While costs are still relatively high for many energy storage devices, costs are rapidly declining for some storage technologies, facilitating their deployment.

Yet, as penetration of energy storage increases, the limitations of existing rules and regulations are becoming increasingly apparent, prompting a review of state and federal policies aimed at reducing regulatory barriers and allowing these technologies to participate in the marketplace on a comparable basis with other resources.

Electric Companies Driving the Deployment of Energy Storage

Electric companies are the largest owners and operators of energy storage. They use energy storage facilities through the assets that they own directly and also through the ones that they contract via long term contracts, or power purchase agreements. Many large-scale storage projects – including pumped hydropower storage and thermal storage projects -would not be economical without a guarantee of use by electric companies in the form of a long term contract. According to the U.S. Department of Energy, electric companies represent more than 98 percent of energy storage projects in the United States, including pumped hydropower, and are a significant contributor to the sector’s rapid growth. Looking only at newer energy storage technologies, and excluding large-scale pumped hydropower projects, electric companies remain the largest users, representing 75 percent of U.S. energy storage capacity.

Of the 22 electric company-owned storage projects commissioned in 2015 and 2016, all but one were battery storage systems. Lithium-ion systems represented 98 percent of the battery projects, making electric companies a significant contributor to the adoption of the fastest growing energy storage technology in the United States

The Benefits of Energy Storage

Energy storage can bring benefits to electric companies, businesses, and residential customers. For electric companies, the primary benefits of energy storage are added flexibility, reliability, and resiliency. More specifically, energy storage can be used in various ways to optimize and support the energy grid; increase reliability, resiliency and operational flexibility; improve the integration of variable resources such as solar and wind power; and enhance the customer experience.

Flexibility

Storage allows energy grid operators to better manage constant fluctuations in supply and demand. As electric companies integrate more renewable energy sources like solar and wind, energy storage can provide more flexibility to the energy grid by helping to manage these variable resources.

Energy storage can help with renewables integration in two primary ways. First, storage can help to address the variability of renewable energy production systems like wind and solar. While weather forecasting is improving, there is still uncertainty about when the wind will blow and the sun will shine. Energy storage provides an option for storing wind or solar energy that may be in excess of immediate demand and saving it until demand is high enough to draw it out of storage. In this way, certain types of storage technologies can allow a variable renewable energy resource, like wind or solar, to perform like one that is more steady and measurably reliable.

Second, the rapid response time of some types of energy storage makes them effective tools for managing changes in energy output that can occur with some renewables, such as when wind speeds fluctuate or clouds pass over solar panels. In addition to the uncontrollable weather changes, there are inherent operational challenges with variable resources. For example, when the sun rises, output from solar resources escalates quickly (and vice versa in the evening), resulting in either a steep increase or decrease in output that can make it challenging to match available resources with load requirements in real-time operations. The ability of certain types of energy storage to meet, shift, or smooth peaks in demand for energy becomes an important tool for grid operators. As it takes less than one second to dispatch many forms of energy storage, the speed of operation is a key consideration when weighing storage as an option for providing both flexibility and reliability.

Convergent Energy + Power worked with Central Maine Power to install a 3-MWh battery asset engineered by Lockheed Martin. A single energy storage system can yield multiple, complementary sources of value, known as “value stacking.” Photo courtesy: Convergent Energy +

Reliability

The reliability of the energy grid is enhanced by energy storage in a variety of ways. Storage can provide a host of grid-support or ancillary services – including managing peak load, essential reliability services, and reserves – that are critical to managing the energy grid and maintaining service without interruption.

One use of energy storage is as a resource to help manage peak load. Traditionally, peak load is met with resources that are able to start quickly but run for limited times (i.e., peaker plants) -most often simple-cycle natural gas combustion turbine plants. Energy storage technologies can provide an alternative. Storage systems can hold several hours of energy that is generated during off-peak hours at lower cost and then deployed during more costly high-demand periods.

Energy storage can provide essential reliability services – frequency regulation and voltage support – two important aspects of system reliability. Frequency regulation is the moment-to-moment reaction to frequency deviations from the standard 60 Hz. Some types of energy storage, with near-instantaneous response times, play a key role in correcting for unintended fluctuations in output from generators. Voltage support is necessary to maintain proper operation of equipment, prevent damage to generators from overheating, and reduce transmission losses. Energy storage can serve as voltage support by providing or absorbing reactive power and by helping to maintain a specific voltage level on the grid.

Reserve capacity is another important aspect of grid reliability in which energy storage can play a role. Electric companies are required to keep certain amounts of available generation capacity that can be accessed quickly in cases of power disruption or unexpected swings in demand. Similar to the way it can be dispatched quickly for peak load management, energy storage can be used to help meet or reduce the need for these reserve requirements.

Resiliency

Electric companies constantly plan and prepare for restoring service safely and efficiently in the event of disruptions. In order to re-energize the energy grid after a power outage, electric companies use black-start resources to restore service quickly. Energy storage has some particular characteristics that fit the requirements of black-start resources-specifically, the ability to operate on standby and be disconnected from the energy grid until needed. Storage also provides the short-term benefit of fast response, a crucial attribute for quickly restoring power in a black-start situation, although the duration of discharge may limit the effectiveness of some storage devices for this application.

Energy storage also can serve as a backup power source to individual loads or even entire substations in the event of a transmission or distribution outage. This may be an effective alternative to a transmission or distribution upgrade or serve as an interim solution while a long-term plan is implemented. Similarly, storage resources play a vital role in microgrids. These standalone energy systems can operate in parallel with or independently of the energy grid. The value of a microgrid is its ability to maintain service when the broader energy grid experiences interruptions. Electric companies, the U.S. military, industries, and cities and communities around the country are using or considering microgrids as a way to increase their resiliency and manage their own energy needs. In all of these systems, energy storage is a vital component.

Customer benefits

In addition to the many benefits that energy storage can provide to the energy grid, energy storage technologies also can provide services to customers directly. As mentioned above, resiliency is an important service valued by many types of customers. Other customer uses include the opportunity to maximize the benefits of private solar production by reducing the demand for grid-provided electricity, for example.

Challenges Remain to Wider Deployment of Energy Storage

Despite its growing popularity, energy storage continues to face challenges that are preventing these technology options from achieving their market potential and maximizing the benefits that they can provide. Today, some of the main challenges for energy storage include the relatively high cost for some technologies, as well as regulatory requirements and ownership restrictions that can make it difficult for these technologies to participate in the markets on a comparable basis with other resources.

Allowing energy storage to capture multiple value streams increases its cost-effectiveness

High costs are still a challenge to wider deployment of energy storage solutions. Although the costs of some technologies are declining, energy storage devices remain expensive relative to other technologies and services. While some storage technology costs are decreasing rapidly, it is critical to remove other barriers for energy storage adoption, so that the full benefits of energy storage can be realized as these resources become more and more prominent.

The early days of energy storage development are revealing a path toward market growth and industry maturity that is sustainable and cost-effective and that relies on policy and regulatory changes rather than mandates and incentives. In this context, lowering barriers for market participation and ensuring that regulations recognize the operational flexibility of energy storage will be key to ensuring that energy storage technologies and applications develop a viable business case.

For example, although energy storage devices often are able to provide multiple energy grid services and to participate in different markets, they sometimes cannot capture all value streams due to existing market rules, requirements or restrictions. The ability of energy storage to provide the services that it is technically able to provide and to capture multiple value streams will be critically important to make these resources more cost-effective.

Rules need to recognize the flexibility of energy storage

Because existing regulations were developed at a time when pumped hydropower was essentially the only form of energy storage, they do not account for the particular characteristics and intrinsic flexibility of some newer storage technologies, such as batteries. Energy storage is a unique resource in that it requires a two-way flow as it both charges and discharges electricity. It is also a very flexible resource that can provide different types of energy grid services. It can support generation, transmission, and/or distribution operations as well as customer-sited applications.

Classification rules at the state and federal levels may need to be updated to accommodate resources like storage that are able to provide multiple services. Updating these rules will help to ensure that how a resource is classified (e.g. as generation, transmission, distribution, or load) does not hamper or preclude its ability to provide other services on a comparable basis with other resources. Market rules should be clarified or modified so that all resources that are capable of providing a product be able to participate in that market. Market products should be defined in a technology-neutral way so that market products and rules are geared toward the service needed rather than toward specific resource types. This will help ensure that product requirements and eligibility are tied to the underlying operational needs of the system and not the characteristics of specific types of generation. The Federal Energy Regulatory Commission and Regional Transmission Organizations already are working toward modifying existing rules so that classification rules accommodate multiple uses and allow energy storage devices to maximize their applications and, thus, enhance their energy grid and societal benefits.

Ownership restrictions limit growth

In certain areas of the country that have restructured their electricity markets, electric companies may not be allowed to own generation assets. Access restrictions derived from existing asset classification rules (when, for example, storage is classified as a generation asset), mean that electric companies in some parts of the country may not be allowed to invest in energy storage devices. Yet electric companies are responsible for ensuring the reliability of the energy grid. Their inability to own energy storage in some cases takes away an option to enhance the reliability and resiliency of the nation’s energy grid to the benefit of all customers.

For example, electric companies – with their extensive knowledge of the electric system – are in the best position to be able to identify the most valuable applications and the optimal locations to site resources on the energy grid. The location matters when it comes to the deployment of distribution system assets, including energy storage. The same resource can help or hurt the reliability and resiliency of the energy grid depending upon where it is located – by alleviating or enhancing congestion, for example. This is not only important for reliability, but it also has a direct impact on costs as new technologies have the potential to defer or to reduce the need for incremental investments or, on the contrary, require additional investments in new capacity or distribution upgrades.

Electric companies are uniquely positioned to continue to promote a variety of advanced technologies, including storage, due to their broad geographic reach, direct interaction with customers, experience with system optimization, experiences in deploying energy efficiency and demand response, and expertise in integrating distributed energy resources. As operators of these systems, electric companies employ advanced technologies to reduce outages by anticipating challenges and taking steps to resolve them before they create reliability problems. Energy storage will be an important tool to achieve that common goal.

A Better Way to Promote Energy Storage

Energy storage will continue to gather support as a key resource able to provide much-needed flexibility, as well as to enhance the reliability and resiliency of the energy grid. Yet, solving the regulatory challenges mentioned above will be important to ensure that the energy storage market thrives and that storage systems not only are able to fully provide all of the services that they are technically able to provide, but also that they are integrated in a way that maximizes the benefits that they can offer. Only by maximizing its grid benefits, will energy storage be able to maximize revenue streams, while also enhancing the reliability and resiliency of the electric system for the benefit of all customers.

Allowing all stakeholders, including electric companies under all regulatory models, to own storage devices will ensure that the market achieves its full potential. Equally important, it is in the interest of all energy stakeholders to ensure that electric companies have visibility and control of the systems on the energy grid. Similarly, electric companies should be involved in resource deployments across the entire electric value chain. Because energy storage can help operations in all segments of electricity production and delivery, it is a natural fit for electric company ownership and control.

Ultimately, electric companies are the ones responsible for the reliability of the energy grid and are in the unique position to plan for and promote new advanced technologies, including energy storage.

Authors:
Richard McMahon is vice president of Energy Supply and Finance for the Edison Electric Institute. Lola Infante is senior director of Generation Fuels and Market Analysis for the Edison Electric Institute.

Westinghouse Electric Company filed for Chapter 11 bankruptcy last month.

Though parent company Toshiba had promised it would ensure new nuclear development projects undertaken by Westinghouse would continue, including the Virgil C. Summer nuclear station in South Carolina and the Alvin W. Votgle nuclear plant in Georgia, it is not yet clear how the bankruptcy filing would ultimately affect construction of those projects, both of which are three years overdue.

In a media statement, Westinghouse indicated the restructuring was due to financial and construction challenges with its nuclear power plant projects.

The New York Times indicated the nuclear construction projects undertaken by Scana Energy and Georgia Power may face new contract terms, lawsuits and losses. Cost estimates for Sumner and Votgle are $1 billion to $1.3 billion higher than budgeted, and could exceed $8 billion.

Experts indicated the bankruptcy might terminate the construction contracts and force Scana and Georgia Power to find another builder. Stan Wise, chairman of the Georgia Public Service Commission, said the utilities developing the Votgle station would need to re-evaluate the project and determine whether it would make sense to continue.

Black & Veatch to Provide EPC Services for FPL

Black & Veatch announced it will provide engineering, procurement and construction services for four solar developments for Florida Power & Light.

The Barefoot Bay, Blue Cypress and Loggerhead solar plants are being constructed in the Vero Beach area, while the Hammock plant will be built just east of Fort Myers. The project sites range from 400 to 600 acres with a combined total of more than one million solar panels to be installed, and will begin operations by the end of 2017.

The four are part of the eight solar projects FPL announced it will build, each with a capacity of 74.5 MW.

Black & Veatch built three 74.5 MW solar developments for FPL in 2016, which tripled the utility’s solar capacity.

Sale of FitzPatrick Plant to Exelon Finalized

Exelon officially completed its purchase of the James A. FitzPatrick Nuclear Power Plant in Scriba, New York.

Entergy Corp. sold the 850-MW facility for $110 million. Entergy had originally planned to shut down the plant.

The state of New York authorized up to $7.6 billion in ratepayer subsidies to keep FitzPatrick, as well as two other nuclear plants in the state, operational.

Exelon named Joseph Pacher, former site vice president at R.E. Ginna Nuclear Power Plant, as the site vice president for FitzPatrick. Brian Sullivan, former FitzPatrick site vice president, was retained by Entergy.

Exelon noted the acquisition is part of the company’s broader effort to preserve the nation’s existing nuclear facilities.

Enel Completes 400-MW Wind Farm

Enel Green Power North America has begun operations at the 400-MW Cimarron Bend wind facility in Clark County, Kansas.

The $610 million project has a long-term power purchase agreement with Google and the Kansas City Board of Public Utilities.

“We are pleased to announce the entry into service of this major wind farm, which is also the first in Enel’s US portfolio to generate energy for a corporate off-taker,” said Rafael Gonzalez, Head of EGPNA. “Thanks to this significant achievement, in Kansas we are now managing our largest portfolio of North American wind farms and we are further strengthening EGPNA REP, the joint venture which is supporting our dynamic, sustainable growth in North America.”

EGPNA also owns four additional wind facilities totaling 1.1 GW in Kansas.

Toshiba America Energy Systems President and CEO Departs

Toshiba announced Ali Azad, president and CEO of Toshiba America Energy Systems Corporation, departed the company effective March 31. Though the company thanked Azad and wished him well, there was no further information.

Toshiba America Energy Systems Corporation was created on April 1, 2015, to integrate the company’s thermal, hydropower and nuclear steam turbine and generator business for both Toshiba and its Westinghouse subsidiary. Azad was the division’s only president and CEO.

The news came the same week Westinghouse filed for bankruptcy protection after $6 billion in losses from nuclear development. Though the company reasserted it would complete new nuclear development projects undertaken by Westinghouse, experts were uncertain how the bankruptcy would affect future development.

Wartsila to Supply 28-MW CHP Plant to Canada

Wartsila announced it will supply a 28-MW combined heat and power plant to the Meliadine Gold Mine project in Canada for owners Agnico Eagle Mines Ltd.

The order includes five Wartsila 34DF dual-fuel engines running light fuel oil or natural gas. Wartsila’s scope includes the power generation and CHP equipment supply, plant commissioning and training. The plant is expected to become operational during the first quarter of 2019.

The power plant will provide baseload power for this new mine and mining facilities located in the Nunavut Territory of Canada. In addition to supplying electricity for the equipment and operations, the plant will also capture heat from the engines and engine exhaust and deliver that heat to the underground mine and buildings.

Initially the power plant will run on light-fuel oil, but natural gas may be available in the future.

Burns & McDonnell, Tampa Electric Complete Solar Plant

Burns & McDonnell announced it has completed the Big Bend Solar project, which will beowned and operated by Tampa Electric.

The 23-MW facility, built adjacent to the Big Bend Power Station in Apollo Beach, is now the single-largest source of solar power in the Tampa area. Big Bend features over 202,000 solar panels with motors that can track the movement of the sun.

“The Big Bend Solar Plant is significant in proving utility-scale PV is cost competitive with traditional generation for regulated utilities,” said Matt Brinkman, Burns & McDonnell principal and national director of solar projects for the firm. “Solar costs have decreased dramatically.”

Public Service Co. of New Mexico to Retire Two Coal Units

Officials from Public Service Co. of New Mexico reconfirmed their commitment to shutting down two of the four units at the San Juan Generating Station in the Four Corners area of the state.

Additionally, the utility has yet to decide whether it will operate the remaining two units beyond 2022, the Associated Press reported.

Pahl Shipley, a spokesman for the utility, said it will take some time to determine how President Trump’s order to review the Clean Power Plan will impact its business.

Public Service Co. of New Mexico reached an agreement with federal and state regulators to close the two units in the face of pressure to limit emissions.

Duke Energy Sues Insurance Companies for Coal Ash Costs

Duke Energy announced it has filed legal claims against 30 insurance companies due to liabilities associated with coal ash.

The suit, filed in association with the state of North Carolina and Mecklenburg County, claims breach of contract for failure to pay claims for coal ash costs at 14 plants in North Carolina and one in South Carolina.

Duke and Carolina Power & Light, which was eventually absorbed by Duke, purchased excess-level liability insurance from the companies from 1973 through 1986. The suit asserts the policies provide coverage for Duke’s coal ash liabilities, and that Duke’s coal ash has been infiltrating groundwater “over a long period of time.”

NTE Energy Wins PUC Approval for Gas Plant

NTE Energy announced the company has received final approval from the North Carolina Utilities Commission for its proposed Reidsville Energy Center, a 500-MW gas-fired facility to be built in Rockingham County, North Carolina.

The company noted it’s currently negotiating long-term power purchase agreements with several entities in the Carolinas, and is in the study phase of interconnecting the facility with Duke Energy’s transmission system. The facility also needs to obtain the final permits and approvals.Construction is slated to begin in the fourth quarter of 2017, with commercial operations in 2021.

NTE Energy is also constructing the 475-MW Kings Mountain Energy Center in Cleveland County, North Carolina, which is expected to reach commercial operations in 2018.

Xcel’s Plans for New Wind Generation Grow

Xcel Energy announced it has proposed the development of 11 new wind facilities in seven states, which would add 3,380 MW in new wind generation.

The proposals would boost the utility’s wind portfolio by 50 percent, and increase wind’s share of Xcel’s total generation to 35 percent.

The proposals, a mix of owned wind farms and power purchase agreements, would come online through 2021. Xcel plans to use federal production tax credits to secure low wind energy prices.

Xcel had already announced 1,500 MW of new wind generation last week in the Midwest. The new developments are proposed for New Mexico, Texas and Colorado.