By Robert Evatt, Online Editor

For the energy industry, change isn’t just constant – it’s accelerating. All the speakers at the 2016 POWER-GEN International keynote address, held at the Orange County Convention Center in Orlando, addressed the evolving landscape with the theme The Power to Change.

Power Engineering‘s Chief Editor Russell Ray moderated the Dec. 13 keynote session. Speakers included Anthony Wilson, chairman, president and CEO of Mississippi Power; Alex Glenn, president of Duke Energy Florida; Rick Halil, senior vice president and general manager of energy at Burns & McDonnell; and Willi Meixner, CEO of the power and gas division of Siemens AG.

The morning’s first speaker, Rick Halil, said he’s been in the energy industry for 27 years, but he feels the current environment is experiencing more change than he’s ever seen before. Numerous factors are driving this change, including government policy, an increasing focus on environment, abundant and cheap natural gas, advancing technology, load swings and growing numbers of online devices.

He said the overall power grid needs to be flexible, and that battery storage and simple cycle power stations can help address fluctuation of wind power. However, even older technologies like combined-cycle plans are also becoming more flexible to meet moment-to-moment power generation needs.

Halil said that these changes are also coming to the consumer side of the power grid, as internet-connected lights, HVAC units and other devices have given customers more control than ever over their consumption and management of energy.

Alex Glenn started his talk by saying the last transformational moment in the electrical industry was in the late 19th century, when Thomas Edison and George Westinghouse battled over AC and DC currents. The next biggest change came June 29, 2007, when Apple founder Steve Jobs introduced the iPhone.

The smartphone revolution gave customers more choice, convenience and control than ever before. Combine that with the ability to use their own residential-scale or business-scale power generation devices such as roof solar or power storage, and utilities now have to work harder to build brand loyalty.

“We’re not measured against other power companies,” he said. “We’re measured against Google, Amazon Prime and Uber.”

Glenn said energy storage will define the investment cycle of power generation companies for the next 20 years, especially as existing peaking technology ages and faces replacement.

Duke Energy Florida President Alex Glenn

Mississippi Power CEO Anthony Wilson

Willi Meisener said that, while every region faces change, they often are confronting unique challenges when it comes to meeting demand and incorporating new technology.

For example, developing companies such as India plan to put up 175 GW of renewable energy by 2022 as they strive to bring affordable power to the 40 percent of their populations that don’t have reliable electricity at all.

By contrast, the New Jersey city of New Brunswick installed smart grid technology in order to manage the distribution of energy in a more flexible, intelligent and efficient way.

Anthony Wilson discussed the way Mississippi Power is addressing the future – its nearly-commissioned Kemper County Energy Facility.

This first-of-its-kind facility generates electricity by taking lignite and converting it to gas. Kemper County’s process is self-contained from start to finish, with a neighboring lignite mine, two gasifiers and a chemical plant that strips out by-products such as anhydrous ammonia, sulfuric acid and carbon dioxide and packages them in forms that Mississippi Power can sell to other user.

Though Kemper County has faced years of delays, Wilson said that any time you do something new, you’ll face adversity. The gasifiers are producing electricity and the plant is scheduled to be commissioned next month.

A power generating station located in Southwest Kansas was preparing to come back online from a scheduled six-week outage. During startup testing of the isolated phase bus duct, ‘B’ phase experienced a failed megger test. Following the failed megger, the plant performed high potential testing, which also failed.

The operators had neither the time nor expertise to identify what was causing the issue, much less fix it. The plant was scheduled to go back online, and they simply were not ready. Any extended delay would not only be an inconvenience, but a failure that would cost hundreds of thousands in lost revenue, not including the cost of emergency response repairs. One of the power plant’s units needed to be assessed and returned to working order as soon as possible.

The plant needed help. They needed expertise from a company that not only possessed the necessary skill set and knowledge to address such an issue, but also had the flexibility to be on site the very next day. The plant could not afford to lose potential revenue from an extended outage.

A call was immediately placed to Powell Electrical Systems, Delta Unibus Division to take advantage of its Repair Replacement and Refurbishment bus program. As a key piece of the program, SE Energy was dispatched within hours to the site to arrive the next day, Friday at 7:30 a.m. Although the power generating station’s bus was not a Powell designed bus, SE Energy was well equipped to addres the issue. After it was determined that the problem was more extensive than anticipated, SE Energy mobilized additional crew members. Poised and ready in standby mode, the SE Energy crew arrived on Saturday at 7:30 a.m.

Assessment

After assessing the test conditions and work completed by the owner, the step was to inspect all the insulators on the B Phase. Once removed, the gaskets were inspected and discovered that many had been twisted during insulation, causing damage to the gasket.

Although the interior of the B phase was clean and dry, evidence of water ingress could be observed at the bottom of several insulators. It was discovered that a broken insulator with visible tracking was located on the bottom of one of the insulators. Once the hardware was removed for re-use the insulator was turned over to the plant’s owner. Once this broken insulator was removed, a 2.5kV megger was completed on A, B and C phase. Consequently, the B phase megger readings had improved to the point where they were now in line with both A and C.

Indication of water ingress was additionally found at the top of one of the insulators. The culprit in this situation was that the bolt holes had rusted, leading to additional corrosion. Finally, an inspection of the outer shell was conducted in order to check for cracks or other issues, and none were identified. The team now knew what the root causes of the problems were, and they would lay out a game plan to solve them.

Solutions

The gaskets discovered were either wiped clean and re-installed or replaced completely. The nature of the gaskets was determined to be a very likely source of the water ingress found at the bottom of one of the insulator and at the top of the other. SE Energy recommended installing additional drains at the low point in the bus in the area of the first broken insulator on all phases. In order to clean up the water ingress evidence and establish a baseline for future inspections, SE Energy vacuumed and hand-wiped the B phase at the point where the water ingress had been previously detected in order to establish a baseline for future inspections. Additionally, a visual inspection was conducted on the outdoor bellows which revealed that they were in fact near the end of their functional life.

Testing

A visual inspection of the indoor bellow was completed. This bellow was painted and, just as the outdoor bellow, this one was also nearing the end of its functional life. The bus was closed up, and preparations began for high potential testing. SE Energy cleaned up the work area, separated tools and closed out activities with the owner before demobilizing.

Preparation for testing was made by flagging off affected areas, verifying isolation and notifying other contractors working on the combustion turbine and generator. SE Energy conducted high potential testing. A, B and C phases were found within acceptable limits, and with similar results from the owner acceptance testing when the bus was originally installed. Test conditions were very favorable, 75°F with 75 percent relative humidity. After a successful test, the bus was released for return service, allowing the plant to keep its downtime to an absolute minimum, saving hundreds of thousands in both lost revenue and emergency service.

Recommendations

SE Energy addressed the immediate issues the plant was having which caused the failed high potential testing in order to safely return the unit to service. However, additional corrective actions would need to be taken during the next scheduled outage prevent further failures. The first recommendation was to replace all the insulator gaskets and stainless steel mounting hardware. Additionally, the power plant operators were instructed to inspect and hand wipe all the remaining insulators and the inside of the Isophase shell. New low point drains should be fabricated and installed at specific locations where the problems were detected. The rubber expansion bellows would need to be replaced in-kind along with the door gaskets and hardware both at the GSU and the generator.

A big stride forward towards energy efficiency at your plant begins with understanding how essential the plant condenser is to the overall operation of the unit. Power engineers often overlook the performance of the condenser, but they do so at their peril. Good condenser upkeep, or the absence of it, is a “pay me now or pay me later” proposition. The condenser can make or break unit efficiency and the ability to meet power output goals.

At last count, there are more than 7,600 power generation plants in the U.S. and virtually all of them are working towards greater energy and operational efficiency. What’s more, many power engineers regard conservation of energy as a moral imperative and view process efficiency as a means to that end. Efficiency can be a moving target, though, and many Rankine-cycle engineers feel challenged to move the needle on efficiency improvements. Engineers face daily pressures to comply with emissions regulations, to operate effectively when staff and budget cuts have occurred, and to remain competitive within the marketplace of renewable energy providers and natural gas turbines, and this can leave the work of efficiency far down on the to-do list.

These challenges require a sharpened focus on the unit components in the power generation system that account for significant energy loss and-by extension-financial cost. The condenser is one of these components. Ignoring the signs of poor condenser performance is a missed opportunity to improve efficiency, especially because condenser technology is well defined, the causes of compromised condenser performance are well understood and correction is usually straightforward and effective.

CONDENSER DESIGN

Design specifications for condensers typically define a maximum effective rate of removal of the latent heat in the exhaust vapor from the turbine entering the condenser as well as its transfer into the circulating water. Some variables affecting the heat transfer can include:

• Backpressure
• Cooling Water Flow Rate
• Inlet Cooling Water Temperature

A poorly designed or poorly maintained condenser will contribute to:

• Increased unit heat rate
• Increased losses to cooling water
• Increased CO₂ emissions
• Reduced generation capacity
• Increased fuel consumption

Most utility scale steam condensers in use at electric generating stations are either single or multiple compartment condenser designs. In most single compartment condensers, the cooling water passes through the compartment one time. The single compartment condenser may also be built with two-pass flow. Regardless of the number of passes in the single compartment condenser it has one backpressure, it is much easier to monitor the performance with accuracy. There is only one cooling water inlet temperature and one outlet temperature. The turbine exhaust steam enters the condenser, is cooled, and returns to the feedwater heaters for reheating in accordance with Rankine cycle principles. Since a pound of steam takes up more volume than a pound of water, the condensation process creates a vacuum. The vacuum optimizes the performance of the turbine.

Larger fossil and nuclear plants are designed with multi compartment condensers. The multiple compartment designs relate directly to turbine design, i.e. multistage turbine, multi compartment condenser, the relationship has to do with the desire for separation of the steam flow and the pressure in the condenser. A variety of layouts and configurations exist to accommodate the need for multiple compartments. There are many inputs and outputs to monitor the performance. The performance monitoring must be done for all compartments.

In achieving the maximum effect rate of removal of the latent heat, the amount of surface area required, the number of tubes, and tube material selection must all be considered. Starting with the Total Duty (MMBtu/hr) required from the turbine exhaust and steam inlet (lbs/hr), along with known cooling water temperatures the amount of surface area necessary to perform under the most difficult environmental, thermal and mechanical conditions can then be calculated. All manufacturers in the United States currently design and build to the Heat Exchanger Institute’s (HEI) Standards for Steam Surface Condensers (2012, Cleveland, OH) currently in their Eleventh Edition specifications and requests for quotations are written to it, as well offers and designs are presented on the basis of it. HEI is the standard for the industry and the members of the Steam Surface Condenser Section are from well-established national and international condenser manufacturers. HEI have now been active for over 70 years.

The HEI standards include formula, symbols, nomenclature, performance calculations, required service connections, venting capacities for removal of non-condensable and material construction details and all the associated mechanical and thermal properties under consideration.

When a condenser is delivered to a utility, its design, though based on HEI Standards, will have to be accepted by the owner/operator and, in most cases, the test parameters for acceptance will be based on the ASME PTC 12.2-2010 Steam Surface Condenser Performance Test Code (2010 NY, NY). The Condenser Performance Test Code (PTC), once quite comprehensive and difficult to apply in the field, has been modified to be practical and useful, and the code has been updated to reflect the most current condenser technology in practice.

How well a condenser is operating is largely a function of how efficiently heat is being transferred from steam to cooling water. If heat is being transferred quickly, so, too, is the turbine exhaust quickly being condensed into liquid water. One important metric in monitoring condenser performance is condenser vacuum. When a condenser pulls a strong vacuum it has increased cycle efficiency and is likely to produce more power. Close attention to condenser monitoring will reveal developing trends in condenser function.

Condenser Tube Fouling

No matter the configuration of the steam condenser, they all share a propensity towards tube fouling. The cause of deteriorating condenser performance is often progressive fouling of internal tube surfaces, and is frequently found within a condenser when reduced heat transfer capability is observed. Condenser tubes are fouled when unwanted material has accumulated on the tube wall and fouling almost always interferes with the efficient operation of the condenser. Fouling results in higher backpressure in the condenser and less efficient turbine performance, requiring increased fuel and even limiting generation capacity. Tube fouling is a perpetual problem with condensers, but careful management of condenser maintenance can significantly contribute to improving a unit’s economic performance.

The types of condenser tube fouling fall into five categories: microbiological, scale, deposition, corrosion products and tubesheet pluggage.

• Microbiological fouling routinely occurs at plants that use seawater or river water in their circulating water system, and can consist of marine plants and animals, mud and organic slime.
• Scale deposits occur when there are high temperature conditions and dissolved mineral content, such as calcium carbonate and calcium phosphate. Scale fouling can drastically reduce heat transfer in the condenser, and crevice corrosion can form beneath the hard scale coating.
• Deposition of particles onto the interior of the tube wall generally occurs when water flow rates are not adequate to keep particles in suspension. Common deposits include sediment, silt, diatoms, coal dust and minerals. Areas of low water flow in the condenser often result from partial blockage on the tubesheet or a tube obstruction.
• The formation of corrosion products within condenser tubes is a potentially serious problem that is more likely to occur when source water is corrosive. Corrosion products can become relatively thick on the surface of some tubes, particularly tubes made of copper alloys. Tubes that contain hard scale fouling are prone to copper oxide growth and, in some cases, a thin surface scale will inhibit heat transfer and promote crevice corrosion.

The inlet of the condenser tubesheet is vulnerable to blockage by a variety of material and debris, including rocks, concrete, broken pipes, cooling tower materials like plastic fill and wood, chunks of ash and coal, rusted metal, leaves and other vegetation, and aquatic animals like fish, clams and crawfish. The reduced water flow to some of the tubes results in particulate deposition and increased likelihood of microbiological growth. If the tubesheet blockage is severe, the condenser vacuum can be significantly degraded.

CONDENSER MAINTENANCE

On-line Condenser Maintenance

Preventing or minimizing fouling in the first place is the best medicine for the condenser. Online foulant removal measures can be enacted to minimize accumulation, and are more successful when the probable foulant is known. Water chemistry modifications, such as reducing the pH of the circulating water by injecting additives, have been used to reduce calcium carbonate and calcium phosphate fouling. Online mechanical cleaning systems, such as sponge balls or recirculating cleaning tools, can be effective with very soft deposits and some microbiological fouling. On-line systems are less effective when there is hard scale fouling or corrosion in the tubes. Some plants have opted to use high doses of biocides for a short period to remove biofilms from condenser tube walls, although many microbiological growths are resistant to biocides.

Off-line Condenser Maintenance

For many plants, fouling processes have been underway for some time, and more aggressive foulant removal measures should be taken. Removal of fouling from the condenser tubes when a unit is off-line is usually the most effective approach. When the unit is off-line, condenser tubes can be directly evaluated for fouling and overall condition, and this allows for an accurate diagnosis of the problem and precise mitigation strategy. The direct approach to fouling assessment by deposit sampling is one of the later and more practical aspects of performance diagnostics included in the ASME’s Steam Surface Condenser Performance Test Code, designed specifically to confirm the necessity of mechanical cleaning.

Chemical removal of corrosion and scale can be successful, provided the process is correctly designed and implemented. There are drawbacks to chemical cleaning, including: safety, cost, waste disposal, duration of cleaning, incomplete foulant removal and damage to the base metal of the condenser tube.

There are several off-line mechanical cleaning techniques that are commonly used to remove foulants. Metal and plastic tube cleaners (scrapers) have been developed to remove virtually all types of foulants, even hard mineral scale such as calcium carbonate. Typically, mechanical tube cleaners are propelled through the length of the condenser tube with pressurized water at approximately10-20 feet per second and loosened debris is rinsed from the tube with the scraping process. The advantage of metal scrapers is that they are effective at removing a variety of common foulants, and careful evaluation over many years has determined that there is virtually no risk of base metal damage when well-designed cleaners are used properly.

Other common mechanical foulant removal techniques are metal wire brushes and high-pressure water. Much like mechanical cleaners, wire brushes are propelled down the length of the condenser tube with pressurized water. Brushes are particularly useful with tubes that have inlet-end metal inserts or inlet epoxy coating, because these can reduce the internal diameter of the tube. High-pressure water cleaning of condenser tubes, commonly called hydroblasting, is a useful strategy with particularly soft foulants like particulate deposits and microbiological films. Using hydroblasting for harder and more adherent fouling conditions will result in an incomplete cleaning. With use of high-pressure water, caution and care must be taken: if the sharp stream of water is allowed to pause for too long, it can quickly cut through softer condenser tubing like copper alloys. What’s more, hydroblasting is not recommended for use with condenser tubes that contain inlet-end metal inserts or epoxy coatings, as the blast of water can severely deform the inserts. Utilizing high-pressure water consumes eight times more water than mechanical cleaning.

LEAK DETECTION TESTING

Condenser Air Inleakage

Condenser air in-leakage negatively impacts plant performance and tube leaks can lead to costly forced outages. Condensers are designed with air removal systems to allow for a certain amount of air in-leakage that will support peak operating efficiency. Sometimes, though, air leaks exceed the capability of the air removal system and the condenser’s efficiency is compromised. One of the indications of air in-leakage is climbing condenser backpressure. There are a number of root causes for excessive air in-leakage. The problem can be related to the shell, rupture disks, shaft seals, man ways, vacuum pumps, flanges and one or more of the numerous holes made by bolts throughout the equipment. Tube fouling can contribute to the rise in backpressure, it’s true, but an air in-leakage inspection can be done while the unit is online and at minimal expense, and is a prudent first response in diagnosing a problem in the condenser. Today, reputable service providers are now using helium and SF6 tracer gas technology to effectively detect condenser air in-leakage, condenser tube leaks, sources of dissolved oxygen, stator water system leakage and main generator leakage. Once leaks are detected and repaired an immediate improvement in condenser performance is achieved.

Condenser Water Leaks

Circulating water leaks in main condensers can result from penetrations through the tube walls, from joints between the tubes and tubesheet, or from penetrations between the water box and condenser shell. Contaminants in the circulating water can change condensate chemistry, which can cause boiler or steam generator corrosion, and caustic water chemistry can cause stress corrosion fractures of turbine components. As with air in-leakage, water leaks are successfully detected with helium and ultra-sensitive SF6 tracer gas. Leaking tubes are then plugged, or repairs are made, depending on the type of leak discovered.

Eddy Current Testing

The best medicine for your condenser is preventative, and the best way to monitor a condenser unit’s tube integrity, detect patterns of tube wear and damage, and determine the specific wear and damage to a particular tube is with Eddy Current non-destructive testing.

Depending on the tube material, the best non-destructive testing method to employ would be either eddy current testing or other electromagnetic techniques including Remote Field Testing (RFT), eddy current testing being the most common and effective for non-ferromagnetic tubing.

Electromagnetic testing techniques have been proven effective for many years and continue to provide viable inspection data for heat exchanger tubing condition assessment.

Armed with the detailed information on a unit’s tube integrity provided by Eddy Current Testing, power engineers can take proactive steps to either repair, replace or plug damages tubes before they fail, preventing a forced outage.

Eddy Current Testing uses an electromagnetic field to identify defects in the tubing. An electron flow (eddy current) is induced in electrically conductive material and an electromagnetic field is generated with use of a probe inside the condenser tube. Once a baseline or standard is established, variations in the eddy currents are recorded and compared to those produced by the standard.

Any defect or anomaly in the tubing that disrupts the flow of the eddy currents can be detected and graphically output to a tubesheet map. Depending on the number of frequencies and channels used, defects with unique characteristics can be discovered.

Small defects such as pitting and cracking can be detected in the differential mode, and wall thinning defects such as steam erosion or inlet-end erosion are detected in the absolute mode. Additionally, higher frequencies are more sensitive to near surface flaws, and lower frequencies are more sensitive to subsurface flaws and conditions on the outer diameter (OD) tube surface.

The complex and varied nature of anomalies and defects necessitate the use of multiple frequencies for accurate identification. Eddy Current Testing is one more important tool in the condenser maintenance toolbox.

Together with condenser tube cleaning and leak detection testing, Eddy Current Testing enables power engineers to maintain optimal condenser performance, which improves energy output and decreases downtime. Condenser availability and reliability are improved.

The performance of your condenser impacts the performance of the turbine and the performance of the feedwater systems.

Put another way, condenser performance impacts the entire power plant. It is wise for plants to invest in combustion controls and turbine upgrades, but earmark a little in the maintenance budget to take care of this important component.

Proper condenser maintenance will improve condenser performance, extend the life of the condenser, and return significant improvements to the plant heat rate.

Reputable condenser maintenance firms have refined diagnostic and cleaning technologies to make them fast, safe and effective. In other words, there’s never been a better time to take good care of your condenser.

Author

Beth Foley-Saxon is a staff writer in the Marketing Department at Conco Services Corporation.

By Tim Miser, Associate Editor

Every year-usually in January-the editors of Power Engineering (PE) magazine like to step back and look at renewable energy through a wide-angle lens. It’s a big-picture kind of exercise, not intended to serve as a nuts-and-bolts exposition on any particular technology or innovation. Rather, we try to regain some overall perspective, to get a general feel for where the renewable industry is heading. How will the renewable industry evolve in the coming year? How do renewables fit into conventional fossil-fired portfolios? How do they affect business models and markets? What are their advantages? What are their disadvantages? You get the idea.

Prognostication can be a fool’s errand, particularly when it concerns an industry as nuanced as power generation. But PE called in the experts and asked them the hard questions. However, making large proclamations about the future can be an exercise in humility, so even the experts were rightly cautious about making sweeping pronouncements. Nevertheless, those who immerse themselves in the day-to-day aspects of renewable power, and who do this year after year, are sure to fare better in the fortune telling business than the rest of us. Here’s what they had to say.

“The outlook for renewables over the next five years looks very robust,” says Tim Light, senior vice president of commercial operations at American Electric Power (AEP). Light explains that this trend is driven in large part by the scheduled phase out of the production and investment tax credits for renewables. “These will be phasing out over the next four years or so,” he says, “so if you’re going to invest in renewables, now is the time. If you wait, you’re simply going to pay more.” And the savings are very substantial, he continues. The production tax credit for wind energy is equivalent to roughly $23 per megawatt hour (MWh) produced over the next 10 years. If the market price of energy is $25 to $30, that is a very substantial subsidy that companies will forego if they wait. “For that reason,” Light says, “I see a very substantial buildout in the coming years.” Numbers in the industry have suggested an addition of up to 50 GW of renewable energy over the next five years.

Even as the investment and production tax credits are scheduled to expire, Light says, AEP’s plans will not change. “We continue to have renewables in our plans beyond tax credits,” he explains. “We believe that’s what our investors and our customers want us to do. So we will continue down that path, even when the economics change following the expiration of the credits.

Solar is different, says Light. “That’s because the technology and cost profile is declining so fast that it may not be viewed as being quite as significant as wind. Wind is just a much more mature cost profile.” Solar is more expensive than wind today, he says, though that curve is coming down.

Indeed, solar power has made some impressive strides in the last year. If solar power has lagged behind wind power in certain areas, it seems poised to close that gap in short order.

According to the Department of Energy, utility-scale solar capacity is expected to grow to 27,000 MW in 2017, up from 10,000 MW in 2014. That’s an annual growth rate of 39 percent, which makes solar the fastest-growing renewable resource for U.S. electric utilities. The Solar Energy Industries Association (SEIA) also reports that the third quarter of 2016 shattered all previous quarterly solar photovoltaic installation records. Approximately 4,143 MW of solar were installed in the United States during that period, a rate of one megawatt every 32 minutes. But even this record might not stand long, as SEIA estimates the fourth quarter will see even higher solar installations.

Solar, in fact, has been gaining momentum even prior to 2016. In November 2015, SolarReserve’s 110-MW Crescent Dunes Solar Energy Facility near Tonopah, Nevada passed the necessary test to enter commercial operation. It now provides power to NV energy under a 25-year power purchase agreement. The facility is the world’s first utility-scale installation to feature advanced molten salt power tower energy storage capabilities, storing solar energy in the day to generate power after the sun goes down. It can power the equivalent of more than 640,000 homes.

AEP is quick to recognize these trajectories in renewable energy. The utility is looking to acquire more renewables in the near term, Light says. Over the last decade, renewables have primarily been procured by utilities through power purchase agreements. In the past, utilities chose to use their capital to invest in environmental retrofits and a number of other projects. “AEP’s involvement in the renewables space was to buy energy from a third party that built their own facilities,” says Light. “Now that is changing. We are no longer investing money into environmental retrofits of our coal fleet. Instead, we are investing in renewable assets directly, instead of just buying output. We want to own them.”

There are several driving factors that inform a utility’s decision to procure renewables, Light continues. Utilities always want to procure the lowest cost of energy they can, but this does not always culminate in a simple mathematical formula. “Wind and solar resources vary greatly by geographic region,” he explains. “The best wind resources are in the midsection of the country, right down the plains.” But even though this is where the lowest-cost wind energy is generated, it is not where the loads are. “So the challenge is how to get this energy to the load centers,” says Light. This is where transmission infrastructure becomes critically important. Congestion represents a real challenge for renewable power, he says. “It’s kind of like the freeway on a holiday, when you can’t move.” Power generated renewably is of no use if it can’t be delivered to where it is needed. Transmission has to keep pace with the buildout of renewables, says Light, or growth is curtailed.

Light continues: “Markets typically try to manage this congestion through price signals, by telling the generator when supply has exceeded demand. They say, we don’t really need all this power, so if you’re going to send it, we’ll have to pay you less for it.” This can create a number of issues. If the problem becomes significant enough, regional transmission organizations (RTO) may even stop accepting power. “This isn’t always the case,” says Light, “but in isolated geographic areas, under certain seasonal variations in demand, these sorts of challenges can arise.” The wind continues to blow even in the shoulder months when air conditioners don’t run as much. Energy storage technologies like chemical batteries, compressed air energy storage, or pumped hydro can allay some of these bottlenecks, but Light contends that the financial cases for such technologies do not always add up.

Renewables notwithstanding, AEP continues to plan for new gas builds. Light explains that the grid has to maintain enough capacity-either online or available for quick start-to fill the void when renewables aren’t flowing. As renewable penetrations increase, he says, baseload capacity may be utilized at a minimal level. “The market is driven by economics. If renewables are cheaper than fossil generation at a particular point in time, that fossil generation will rightly be displaced, as long as you continue to have enough capacity online to meet peak demand.” Utilities can forecast what they think the wind will do, but they better have some contingency plans, says Light, who also says that fossil units will probably be ramped up and down more to accommodate the intermittency of renewables.

Of course, wind and solar are not the only renewables in town. There’s biomass, which despite its renewable nature, does produce greenhouse gases. And there’s geothermal power, which relies on the earth’s own thermal properties to generate power. Though AEP has not invested much in either of these technologies, in the past the utility has invested substantially in hydropower, which represents a huge portion of the country’s renewable assets. Nevertheless, the utility has no new plans for hydropower installations. “It comes down to economics and permitting issues,” Light says, “which are more restrictive than they are for wind or solar power.”

LeRoy Coleman acknowledges this problem. He’s the senior manager of strategic communications at the National Hydropower Association (NHA). The organization has been working on licensing reform, bringing more timeliness, collaboration, and coherency to the licensing process. “Right now it takes a decade or more to get through the licensing process,” he explains. “If two investors are sitting around deciding what to spend money on, they are likely going to choose a natural gas-fired plant, which can be permitted in two years, unlike a hydropower installation, which has a much more exhaustive licensing process that takes a long time.” Coleman says the industry can’t grow unless its licensing processes are “brought into this century”.

That isn’t to say that the future of hydropower is restricted, though. In fact, Coleman cites a recent (and first of its kind) report published by the U.S. Department of Energy in July 2016 about the future of hydropower. “People have a misguided view of hydropower-that it’s been tapped out, that we can’t do anymore, that there’s no room to grow,” he says. “But this is absolutely not true. In 2016 we hit the reset button on how we approach hydropower.” Today hydropower is right around 100 GW in capacity-80 MW conventional, 20 or 22 MW pumped storage, Coleman explains. “But this number can grow by another 50 GW by 2050,” he asserts.

NHA’s Jeff Leahey says hydropower makes a great partner for solar and wind. Technologies like pumped storage can be utilized to smooth peak demand, reduce bottlenecks in transmission infrastructure, and minimize intermittency issues-all problems that affect renewables.

It’s no surprise hydropower maintains such a presence; it’s comprised of so many sub-categories of technologies. In addition to conventional hydropower-these are the dams we’re used to seeing-hydropower also includes pumped storage, marine energy technologies like wave and tidal generation, and small-scale hydro in which irrigation ditches and municipal water supplies are leveraged to generate power from small amounts of water using micro-turbine technology.

Another boon to hydropower is its good working relationships with both wind and solar power. Jeff Leahey, deputy executive director of NHA, explains that the grid services and operational capacities which hydropower brings to the electric system enable greater penetrations of renewables across the landscape. “While we are different industries for sure,” says Leahey, “we work together very well.” Technologies like pumped storage, which are enormous energy storage facilities, can be utilized to smooth peak demand, reduce bottlenecks in transmission infrastructure, and minimize intermittency issues-all problems that affect wind and solar power. While hydropower can experience some seasonal variability in capacity and output, says Leahey, it does not suffer the intra-day, or even intra-hour, intermittency issues incumbent to wind and solar power. Additionally, insofar as there exist century-old hydropower installations in the United States, the industry is a mature one, depending on technologies that have been well tried and proven true.

That’s not to say that hydropower doesn’t face some challenges. There are the aforementioned issues of licensing and permitting, which right now take too long and cost too much. Because of this, hydropower is losing share to investors who prefer to put their money into projects that can be completed more quickly and for less money. Additionally, hydropower equipment is itself very expensive. That’s because every project is a one-off, explains Leahey. “Hydropower projects are always unique,” he says. “They are projects unto themselves which must be custom designed and manufactured to fit particular purposes, geographies, and geologies. Nothing is off-the-shelf.” Technologies, for instance, must be developed which are specific to the particular flow of a portion of a river, he continues.

Like all forms of power generation, hydropower is also susceptible to political winds. There’s some good news though. “Hydropower has always been a bi-partisan issue,” says Leahey. “I think there will be opportunities in the coming administration. They may look different than those in the old administration, but there has been a discussion in the Trump administration and in Congress about some sort of infrastructure package in 2017. We believe hydropower should play a role in that.”

There’s also been discussion about comprehensive tax reform. “Over the course of the next five or 10 years,” says Leahey, “we are trying to ensure that the value proposition for hydro is recognized and compensated for.” Too often, energy policy debates undervalue hydropower for the services it provides, he explains. “We will be looking at these issues in the coming year.”

By Joseph Klobucar, Brian Barth, Jeff Hoefer and Robert Newell

The Columbia Energy Center near Pardeeville, Wisconsin.

Interstate Power and Light Company and Wisconsin Power and Light Company, subsidiaries of Alliant Energy Corporation, along with their owner’s engineer, HDR Inc. (Omaha NE), have recently completed construction of air quality control systems (AQCS) on two major coal-fired generating stations in Iowa and Wisconsin. Both of these award-winning projects included rotary-atomized spray dryer (SDA) for SO₂ control, pulse-jet fabric filter (PJFF) baghouses for particulate control, powdered activated carbon (PAC) injection for mercury control, draft system modifications, and associated balance of plant equipment.

While the same AQCS original equipment manufacturer (OEM) designed and supplied the major equipment for each project, the site configurations and additional work being performed at each site differed substantially.

This article summarizes the successes, challenges, and lessons learned in completing these two major projects. Successful system implementation, including performance, will be discussed in the context of project goals. The challenges associated with the systems will be discussed and the successful resolution of challenges will be presented. The lessons learned during project execution, commissioning, and commercial operation will be presented.

COLUMBIA ENERGY CENTER

The Columbia Energy Center (Columbia) is located near Pardeeville, Wisconsin.

Columbia Units 1 and 2 began operation in 1975 and 1978 and have nameplate generation capacities of 512 and 511 MW, respectively. The Units are jointly owned by Wisconsin Power and Light Company (WPL), Wisconsin Public Service Corporation (WPS), and Madison Gas and Electric (MGE). The Units are operated by WPL.

Boiler/Generator System

The units burn sub-bituminous Powder River Basin (PRB) coal from various mines. The Units use electrostatic precipitators (ESPs) to collect particulate matter (PM) or flyash. Unit 1 operates with a hot-side ESP and Unit 2 operates a cold-side ESP. Both Units operate low-NOx burners and overfire air combustion technology to reduce emissions of nitrogen oxides (NOx).

An ACI system was installed on Unit 2, upstream of the existing ESP in 2008 for mercury removal.

New System

Alliant Energy has been moving toward a cleaner energy future by installing cost-effective environmental controls and utilizing state-of-the-art technology at Columbia.

These investments are designed to improve air quality and provide customers with competitive and reliable power. This emissions reduction project is referred to hereafter as the AQCS project and includes the following:

• Installation of dry FGD systems on both Units. Specifically, two SDA vessels and a downstream PJFF were installed on each unit (four SDA vessels and two PJFF in total) for SO₂ and PM emissions reduction.
• Expansion of the existing ACI system to Unit 1 to provide carbon injection upstream of the new PJFF and SDA. The PJFF will capture spray dryer solids, residual flyash, and activated carbon, including bound mercury.
• Modification of the previously installed ACI system at Unit 2 to relocate the carbon injection point downstream of the existing ESP. Moving this injection point allows the plant to maintain beneficial reuse of the flyash.

The emissions reduction project included the following auxiliary equipment:

• Lime storage and lime slurry preparation equipment (common to Units 1 and 2 dry FGD)
• Activated carbon storage and handling (modification to the Unit 2 ACI system)
• Induced draft booster fans
• SDA byproduct material handling and recycle equipment
• Associated ductwork
• A new controls building and new electrical equipment.

PROJECT SUCCESSES

Emission Reduction Performance

The following emission reduction goals for the unit were set forth at the start of the project.

At the conclusion of the project, an extensive performance testing procedure was undertaken to verify that all emission reduction goals were met.

In all cases, the emission reduction goals were exceeded by a wide margin. In addition, process performance guarantees for reliability, lime consumption, pressure drop, PAC consumption, water consumption, and auxiliary power consumption were verified during this testing and found to be well within the guarantees made.

Safety Performance

The construction of the AQCS system included expenditure of over 1.9 million man-hours of craft labor on site. This major construction effort was accomplished with no lost-time injuries. This level of performance is extraordinary when compared to the OSHA reported average lost-time rate for 2014 of 1.1 incidents per 200,000 man-hours.

CHALLENGES

In general, the project execution proceeded smoothly with no major disruptions.

Unit 2 Tie-In During Extreme Winter of 2013-2014

The tie-in outages for the systems occurred in mid-January through the end of February 2014 for unit 2 and in mid-April through the end of May for unit 1. According to NOAA, the winter of 2013-2014 was one of the coldest on record for Wisconsin with the period of January/February 2014 being the second coldest on record for parts of the state. Despite this severe weather, the unit 2 tie-in outage was completed on time and with no significant safety incidents.

SDA Byproduct Bin Vent Filter Damage

During commissioning, a relief valve on one SDA byproducts waste storage silo was frozen shut while the material handling system was being tested. This resulted in a build-up of pressure in the silo. The excess pressure deformed the casing of the bin vent filter for the silo. There was no damage to the silo proper or other equipment. The bin vent filter was replaced and there was no significant impact to project schedule as the other silo was available for use.

LESSONS LEARNED

Lime Unloading

Pebble lime was used as a reagent for this project in truck-load quantities. The lime reagent was received in pneumatic trailers and these trailers were unloaded into a pair of lime silos for use in the process. Because of the height of these silos (top height 129′ above grade), the on-truck blowers were not capable of unloading the trucks in acceptable time. Therefore a system was designed with external blowers to assist the on-truck blowers in transporting the lime into the silos.

The procedure that was initially used for this lime unloading was to transport the lime out of the truck using the on-truck blower to inject the transported material into the line leading to the silo while an external blower added additional transport air into the same line. While this method was capable of the required unload time, it resulted in excessive velocity in the transport line (owing to the fact that two blowers were used, the on-truck blower and the fixed blower). This excessive transport velocity resulted in excessive breakdown of the pebble lime particles leading to handling difficulty downstream. It also resulted in accelerated wear of the transport line, resulting in several premature failures of elbows in this line.

The procedure was reviewed after the difficulties were identified and it was revised so that only the fixed transport blower was used both for truck evacuation and transport of the material to the silo. Since the revised procedure was implemented, lime breakdown and accelerated wear problems have abated.

SDA Byproduct Silo Unload Building Dusting

SDA byproduct material from the process was pneumatically transported to a pair of silos. From there, it was conditioned by the addition of water and loaded into trucks for on-site landfill disposal. Because of concerns about fugitive dust emissions, a fully enclosed truck loading facility was provided as part of this system. This facility included roll-up doors for truck entry and was intended to be operated with the doors closed to prevent fugitive emissions of dust from the truck-loading process.

Shortly after start-up, it was recognized that if the system was operated as designed, the levels of dust and steam generated by the process were in excess of the capacity of the HVAC system. Experimentation with various setting and procedures for operating this process were not effective in remedying these problems. Eventually, the HVAC system was re-designed with the exhaust from the system ducted to the PJFF inlet. This largely resolved the issues and enabled operation of the loading facility as designed.

Stack Icing

During winter months after tie-in of the system, some ice accumulation at the stack outlets occurred. Pieces of this ice broke free from the stack tops and cause some damage to nearby ductwork cladding. The exact mechanism of this icing is not well understood as there are numerous variables in play, including process flow rate, ambient temperature, wind speed, and humidity, however, it was determined that a solution was required to prevent future recurrence. As a result, electric heaters were installed at the top of each stack to prevent ice from forming and adhering to the stack caps. This modification was completed in the spring of 2016 and will be monitored for effectiveness during upcoming cold weather.

The Ottumwa Generating Station near Chillicothe, Iowa.

Fouling of Atomizer Gearbox Coolers

The SDA process uses high-speed rotary atomizers to achieve proper atomization of the feed slurry into the flue gas and to achieve the emission performance required. The system uses two atomizers per unit with each atomizer driven by a 1000 hp medium voltage electric motor. A drive gearbox is required to achieve the proper atomizer rotation speed. This drive is equipped with integral oil cooler that uses a thermostatically controlled mechanism to maintain the oil temperature within the required range. The oil is cooled by a shell-and-tube heat exchanger that is cooled (on the tube side) by process water from the plant. Process water for the plant is sourced from Lake Columbia, a man-made body of water that is fed from the Wisconsin River and used primarily for plant cooling.

After start of operations, it was found that the water (tube) side of the atomizer cooler was becoming fouled. This fouling resulted in an excessive need to clean the atomizer coolers, with cleaning required on a nearly monthly basis during some periods. It was believed that the fouling was primarily caused by biological growth in the cooler. A chlorination system was added to the service water. Since the chlorination system was started-up in 2015, no fouling issues have been encountered.

Spray Dryer Motor and Spindle Vibration

Upon initial startup of the system, the SDA rotary atomizers experienced motor trips on high vibration with unusually high frequency. These trips were found to happen as often as 50 times per month. Following instructions from the equipment OEM, each atomizer was removed from service and replaced with a spare after three motor trips. This was causing the owner excessive labor for atomizer maintenance.

The OEM made various efforts to resolve this issue including re-piping of the slurry feed system, but their efforts were not effective. Eventually, two changes were made which were largely effective in resolving these issues. First, the vibration monitoring software was modified through the installation of a filtering algorythem. Second, the trip logic was changed so that instead of tripping the medium voltage motor on high vibration, the slurry feed would be tripped. This resulted in the motor and atomizer continuing to rotate through a trip and the slurry feed being shut-off. With this arrangement, it was found that the slurry feed could be re-established after a water flush and this was sufficient to resolve many trip events.

Recycle Slurry Tank Material Accumulation

Shortly after tie-in, an agitator failed in the recycle slurry mix tank. This failure was investigated, including sending slurry samples out to an agitator manufacturer for testing. Based on the result of this testing, it was determined that an improper agitator design was the root cause of the failure. The agitator was not adequate to maintain suspension of solids in the recycle slurry tank. As a result, the impellor, motor, and tank-baffles were replaced on both recycle slurry tanks. This repair work required a forced outage of one unit to accomplish. The repairs on the other unit were coordinated to coincide with a planned plant outage.

OTTUMWA GENERATING STATION

The Ottumwa Generating Station (Ottumwa) is located near Chillicothe, Iowa. Ottumwa Unit 1 began operation in 1981 and has a nameplate generation capacity of 726 MWg. The Unit is jointly owned by Interstate Power and Light (IPL) and Mid-American Energy. The Unit is operated by IPL.

Boiler/Generator System

The Unit burns sub-bituminous Powder River Basin (PRB) coal from various mines. The Unit uses hot-side ESPs to collect PM. The unit operates low-NOx burners and overfire air combustion technology to reduce emissions of nitrogen oxides (NOx).

New AQCS System

Alliant Energy has been moving toward a cleaner energy future by installing cost-effective environmental controls and utilizing state-of-the-art technology at Ottumwa. These investments are designed to improve air quality and provide customers with competitive and reliable power. This emissions reduction project is referred to hereafter as the AQCS project includes the following:

• Installation of a dry FGD system. Specifically, two SDA vessels and downstream PJFFs (two SDA vessels and two PJFF in total) for SO₂ and PM emissions reduction.
• Installation of an ACI system to remove mercury from the flue gas.

The emissions reduction project included the following auxiliary equipment:

• Lime storage and lime slurry preparation equipment
• Activated carbon storage and handling
• New induced draft fans
• SDA byproduct handling and recycle equipment
• Associated ductwork
• A new controls building and new electrical equipment.

The AQCS system was designed for extended operation both with and without ESP in service. This dual-mode capability allows the operators flexibility to either use the ESP to gain beneficial use of flyash sales or shut down the ESP to avoid maintenance cost and power consumption.

Efficiency / Output Improvements

In addition to the AQCS project, efficiency and output improvements were concurrently implemented at the plant. These improvements included a new turbine, new high pressure heater and added a convection surface area to the boiler (reheat and economizer).

PROJECT SUCCESSES

Emission Reduction Performance

The following emission reduction goals were set forth at the start of the project.

At the conclusion of the project, extensive performance testing was undertaken to verify that all emission reduction goals were met.

In all cases, the emission performance goals were exceeded by a wide margin. In addition, process performance guarantees for reliability, lime consumption, pressure drop, PAC consumption, water consumption, and auxiliary power consumption were verified during this testing and found to be within the guarantees made.

Plant Efficiency/Output Improvements

Modifications were also made to the plant to improve output and efficiency. These modifications had the goals as stated:

After the completion of the project, testing was conducted to verify that these performance gains were realized. The results found that all performance goals were exceeded by the new system.

CHALLENGES

Turbine/Boiler Work Coordination

Implementation of the efficiency and output improvements during the same outage as the AQCS project resulted in several challenges to the project. First, the AQCS system needed to be designed to accommodate the changes to flue gas condition of the revised boiler system. The efficiency / output improvement projects resulted in a flue gas flow that was approximately 25% higher and 25 to 50 degrees cooler that the pre-modification conditions. This was accommodated by careful design of the new AQCS system.

A second challenge of this project was to coordinate the tie-in (fall of 2014) and commissioning of the new AQCS system, the new turbine, and major boiler work during the same outage. This meant that major work was being performed on the boiler, turbine/generator, and AQCS system simultaneously before and during the outage.

This challenge was successfully handled by thorough planning and careful execution.

Byproduct Handling System Plugging

The SDA process causes the reaction of SO₂ with pebble lime to produce SDA byproducts which becomes mixed with flyash from the boiler in the PJFF. This mixed byproduct material is transported by a pneumatic transport system and either used for recycle into the process (increasing the efficiency of lime utilization) or sent to a silo for disposal. Plugging of the pneumatic transport system was encountered.

This required changes to baghouse discharge valves and transport switching valves to a design that was less prone to pluggage. In addition, rubber elbows were installed in place of hard pipe elbows at several points in the transport system. These rubber elbows are capable of some flexing that allows accumulated material to break-away during normal operation. These modifications were found to substantially eliminate buildup problems in the pneumatic transport system and increase transport capability.

Recycle Silo Plugging

The system design incorporated a recycle injection system to increase lime utilization.

In this system, byproduct material is retained in a separate silo and mixed with water to create slurry. This slurry is metered to the atomizers along with fresh lime slurry to accomplish the SO₂ reduction requirements. This enabled use of residual lime and alkalinity in the byproduct material to reduce the amount of fresh lime required, increasing system lime utilization efficiency.

Shortly after the project tie-in (during tuning) the entire AQCS system was voluntarily shut down for several weeks for the year-end holidays. During this time, byproduct material was retained in the recycle silo and continued to be fluidized.

At the conclusion of this period, it was found that this byproduct material could not be withdrawn from the silo.

Further investigation determined that the byproduct material had solidified in the silo.

The byproduct material also was found to have entered an auto-thermal event in some areas, reaching temperatures high enough to burn the paint off the silo walls and sinter some byproduct material in the silo.

Material had to be manually removed from the silo, a time consuming and expensive process.

An investigation of this event determined that because the byproduct silo was not insulated, condensation of water in the silo occurred during the winter down-time which lead to the solidification and most likely initiated the auto-thermal reaction that damaged the silo paint.

The remedy for this problem was to insulate the silo and adopt operating procedures to prevent retention of non-moving byproduct material in the silo for extended periods.

These solutions were implemented and no repeat events of this type have been encountered.

Byproduct Handling System Issues

During commissioning, a number of problems were encountered with the byproduct handing system. The byproduct handing system was a vacuum type system with transport blowers and collectors pulling byproduct to the destination. After start-up, a vacuum blower failed in service prompting a thorough inspection of the system.

With this inspection, it was found that bags and cages had failed in some filter separators leading to dust in the clean air plenums and blowers. A root cause investigation revealed a number of contributing causes, including improper setup, failed pulse valves, failed equalizer valves, incorrect level switches, and some bag fit-up issues.

All of the issues were corrected and the system has operated normally since that time.

LESSONS LEARNED

Fugitive Dust at SDA Flop Gates

At the bottom if each SDA vessel there is a “flop gate.” This is a simple gravity valve that allows any solid material that accumulates in the SDA vessel to exit under the influence of gravity. Below each flop gate is concrete bunker with a roll up door to contain any material produced. Experience has shown two problems with this arrangement.

First, there is no way to lock the flop gate so when working in this bunker solids can emerge from the SDA and present a hazard to workers in this vicinity. Second, the enclosure is too small to accommodate a truck, so loading has to be done by withdrawing material by loader and loading a truck external to the bunker.

Because this material can be dry and friable, some dust can be generated in this process, creating a potential fugitive dust emission problem. A fix or work-around for these situations is under development at the current time.

O&M Access

After start-up, it was found that access to the unit was not satisfactory for service of the systems and equipment. Among the issues noted were a) the system included a single elevator and if the elevator was down for service, long stair climbs were required to the atomizers and related equipment on the top of the SDA and b) the top of the lime and recycle silos were accessible by stairway only. As a remedy to this problem, access platforms connecting the top of the SDA to the top of the silos were added. In addition, access platforms connecting the existing ESP elevator to the SDA platforms were added so some redundancy now exists on the elevator.

Slurry Feed Line Failures

During operation, some slurry transport elbows failed resulting in spillage of significant quantities of slurry. These failures were related to rubber elbows and connections incorporated into the transport lines and excessive flexing of some of the lines as a result of their pipe support design.

As a result of these spills, the lines were analyzed and most of the rubber elbows were replaced with steel elbows. In addition, pipe supports were upgraded in certain areas to reduce movement of the lines.

It is believed that these modifications will eliminate any lime piping failures in the future.

Overall POTY 2016 natural gas-fired poty 2016 -Overall Project of the Year (POTY) and Natural Gas-fired POTY-Dominion Virginia Power’s 1,358-MW, natural gas-fired Brunswick County Power Station relies on Mitsubishi Hitachi Power Systems M501GAC combustion turbines in a 3-on-1 combined-cycle arrangement.

The winners of the 2016 “Projects of the Year” (POTY) awards were announced Dec. 13 in front of a capacity crowd during the keynote session at POWER-GEN International in Orlando, Florida.

In addition to the year’s greatest honor-an overall POTY chosen from across all power industry segments-winning projects were also selected from industry-nominated projects in four categories: natural gas, renewables, coal, and combined heat and power (CHP). To be eligible, projects had to come online between Aug. 1, 2015 and July 31, 2016.

“Companies like those represented by this year’s project finalists are instrumental in meeting public demands for cleaner, more efficient electricity,” said Richard G. Baker, publisher of Power Engineering and senior vice president of PennWell’s Power Generation Group. “Power Engineering and Renewable Energy World are once again pleased to be able to recognize some of the exceptional power projects that were completed in the past year.”

Finalists were selected based on four criteria: technological innovation, local impact, logistical challenges and creativity, and capacity. Before deciding winners, editors of Power Engineering and Renewable Energy World magazines analyzed dozens of nominations from representatives across the power generation landscape.

So without further ado, here are the 2016 POTY award winners:

Overall POTY

Brunswick County Power Station

Dominion Virginia Power

This year’s Overall POTY honor belongs to Dominion Virginia Power’s gas-fired Brunswick County Power Station in Southside, Virginia.

Commissioned in April 2016, the 3-on-1 combined-cycle facility generates 1,358 MW of power via three Mitsubishi Hitachi Power Systems M501GAC combustion turbines outputting 275 MW each, alongside three GE/Alstom heat recovery steam generators (HRSG) that contribute an additional 530 MW through Mitsubishi steam turbines. Selective catalytic reduction (SCR) and CO catalysts ensure strict compliance with environmental regulations at both cycling and base loads. A 140-foot tall, 72-cell air-cooled condenser (ACC)-the largest in the United States-significantly reduces water usage at the plant.

The facility was needed to meet increasing demand and to replace power from older fossil-fired facilities being retired to comply with federal air standards within Dominion’s service territory. With state-of-the-art design and technology, the station has a low carbon-intensity rate and meets best available control technology (BACT) standards.

In the first full year of operation, the project is expected to provide approximately 9 percent of Dominion Virginia Power’s total energy requirements. As one of the most efficient power plants in the country, the facility is expected to create savings exceeding $1 billion over its lifetime, compared with the cost of purchasing power from the market.

Fluor served as the project’s engineering, procurement, and construction (EPC) contractor, beginning work at the site in August 2013. The project required 38,000 cubic yards of concrete, 142,000 linear feet of pipe, and 420 miles of cable. At the height of construction, more than 1,500 workers were on hand.

Project components were delivered by ship and rail from three continents: North America, Europe, and Asia. For final nighttime delivery to the site, local roads and bridges were temporarily reinforced to accommodate the project’s heaviest load, which exceeded 100,000 pounds. The project also weathered Hurricane Joaquin, which dumped 5.84 inches of rainfall at the site in 10 days. Despite these logistical constraints, the project was completed ahead of schedule and under budget.

Natural Gas-Fired POTY

Brunswick County Power Station

Dominion Virginia Power

Dominion Virginia Power’s Brunswick County Power Station also won the 2016 Natural Gas-Fired POTY award.

Runner-Up: Port Everglades Next Generation Clean Energy Center, Florida Power & Light

Renewable POTY

Village of Minster Energy Storage Project

Half Moon Ventures

Winning this year’s Renewable POTY award, the Village of Minster Energy Storage Project is one of the largest facilities of its kind to be connected through a municipal utility in the United States. Developed by Half Moon Ventures (HMV), the energy storage installation relies on a utility-scale, 7-MW/3-MWh battery provided by LG Chem. The facility is co-located with a 4.2-MW solar plant and is capable of providing multiple revenue streams (flowing to multiple parties) by integrating frequency-regulation services, transmission and distribution deferral, demand response services, and voltage support.

The facility in Minster, Ohio is one of the largest energy storage installations in the state. HMV participates in the PJM frequency regulation market , capitalizing on this relationship for revenue. The Village of Minster avoids costs associated with peak load contribution (PLC) charges assessed by PJM by utilizing energy storage to lower their coincident peaks and subsequent demand. Additionally, the village was able to cancel a planned purchase of power factor correction equipment, instead utilizing the concurrent reactive compensation characteristics of the PureWave SMS system installed at the facility.

Renewable POTY 2016

Half Moon Venture’s Village of Minster Energy Storage Project is one of the largest facilities of its kind to be connected through a municipal utility in the United States. The installation relies on a 7-MW/3-MWh battery provided by LG Chem, and is co-located with a 4.2-MW photovoltaic solar plant.

The Village of Minster benefits from three of the four revenue streams from the project-demand response and transmission, voltage support, and distribution deferral. In addition, because the system is co-located with 4.2 MW of photovoltaic solar power, the village is able to reduce its carbon footprint while simultaneously increasing the reliability and decreasing the operating costs of the system.

S&C Electric Company served as the project’s EPC contractor, reducing project expenses and eliminating scope gaps to ensure the best long-term solution. The project faced logistic hurdles incumbent to Ohio’s winter weather. S&C Electric countered this by completing all foundation and underground work in late fall. All batteries and inverters were installed in mid-January.

Because of the pre-work completed in the fall, the team was able to install technology efficiently over a six week period. Following commissioning and startup, the facility met PJM commissioning deadlines with the help of Viridian. From start to finish, S&C Electric put units on the market 10 weeks after setting the first building.

Runner-Up: Crescent Dunes Solar Energy Center, SolarReserve

Coal-Fired POTY

Mill Creek Generating Station Air Compliance Project

Louisville Gas & Electric

This year’s Coal-Fired POTY goes to Louisville Gas & Electric (LG&E), whose 1,472-MW Mill Creek Generating Station in Louisville, Kentucky-the largest coal-fired power plant in the utility’s fleet-undertook one of the largest air-quality control system (AQCS) installations in the United States, upgrading AQCS equipment on all four of the plant’s units.

Zachry Group served as the project’s EPC contractor, managing an onsite project team of more than 1,600 employees and 140 engineers and designers at the project’s peak. The plant remained in operation through demolition of old equipment, and through installation and interconnection of new equipment.

Coal-fired POTY 2016

Louisville Gas & Electric’s 1,472-MW coal-fired Mill Creek Generating Station undertook one of the largest air-quality control system installations in the United States, upgrading equipment on all four of the plant’s units.

The facility’s four units share a common coal-handling system, requiring them to be closely located. Because of this, construction and installation of new equipment took place in highly restrictive environments, amidst a plant that continued to generate power. To facilitate construction within these tight spaces, the engineering and design team created a three-dimensional (3D) model from a digital laser scan of the existing facilities. The end result is an impressive interweaving of new construction with old, one in which new installations stand only inches from existing equipment.

Work at the plant included the installation of four new sorbent injection systems, three wet flue gas desulfurization (WFGD) systems with Stebbins Absorbers, four pulse jet fabric filters (PJFF) with sulfuric acid mist mitigation (SAMM) systems and powder activated carbon (PAC) injection systems, flue gas induced draft fan upgrades for all units, as well as ancillary balance of plant systems/components. Additionally, all units received new chimneys in shared configurations.

The project demonstrated the integrated project delivery capabilities that an EPC team can achieve through effective use of laser scanning and 3D modeling. The model served as the foundation for design and fabrication/construction drawings, and also as the basis for regular constructability reviews, to illustrate the sequence of work, and to conduct web-based reviews with the design team. The model provided a forward-looking view of the work and scope of different crafts throughout the project. Zachry also embedded a designer in the field to support construction, using the model to address any questions.

The plant achieved final mechanical completion in June 2016, having met or exceeded all performance testing guarantees.

Runner-Up: Longview Power Plant Rehabilitation, Longview Power

Combined Heat and Power POTY

Eight Flags Energy CHP Plant

Chesapeake Utilities Corp.

Chesapeake Utilities Corp. takes home the CHP POTY in 2016. The company’s new ~20-MW Eight Flags Energy CHP plant on Amelia Island in Florida uses natural gas to generate three sources of energy: electricity, hot water, and steam. Chesapeake subsidiary Florida Public Utilities (FPU) will purchase the electricity for distribution to its 16,000 retail customers on Amelia Island, while Rayonier Performance Fibers (Rayonier), a pulp mill owned by Rayonier Advanced Materials, will purchase the hot water and steam for use at its cellulose specialties production facility. The project is a perfect example of the ways in which utilities can take advantage of the high efficiencies and lower environmental footprints associate with CHP technologies.

CHP POTY 2016

Chesapeake Utilities Corp.’s 20-MW Eight Flags Energy CHP plant provides retail electricity to 16,000 residents on Florida’s Amelia Island, while simultaneously delivering hot water and steam to manufacturing facilities operated by Rayonier Advanced Materials.

Discussions between FPL and Rayonier revealed a need for more thermal energy at Rayonier’s plant. Additionally, FPU was seeking to lower costs and improve electrical reliability for their customers. To meet these potentially synergistic needs, Chesapeake Utilities created Eight Flags Energy and constructed the CHP plant. Prior to construction, the company did not own any generation facilities and relied exclusively on wholesale power contracts delivered through a marsh to the island via a single transmission line.

The new plant relies on a 21.7-MW Solar Titan 250 gas turbine operating at over a 95-percent capacity factor. A Rentech HRSG recovers waste heat to produce over 75,000 lbs/hour of superheated steam at 150 psig. The system also includes a secondary hot water economizer to route over 600 gpm of heated demineralized water to Rayonier’s boilers, recovering another 16 mmBtu/hour of waste heat. In the end, unutilized heat leaves the exhaust stack at just over 210°F, in the process raising Rayonier’s demineralized water from ambient temperature to over 140°F. Design efficiencies at the plant break 80 percent after factoring for improvements to losses during transmission and delivery.

In order to be adjacent to Rayonier’s facility and increase the overall efficiency of the CHP plant, Eight Flags was built on challenging site conditions. It sits at just eight feet above sea level, requiring an advanced structural design to elevate all critical components above category-4 storm surge elevations. The site also required underground vaults for electric and natural gas lines. Upper structure elements were built on 600 piles driven 60 feet into the site’s soft soil below. Inclined piles were also installed to meet Florida’s standards for high wind loads.

Sterling Energy served as owner’s engineer for the $40 million project, while C.R. Meyer Construction served as project construction manager. The plant was commissioned in June 2016.

Runner-Up: Coldwater BPU Peaking Plant, Michigan South Central Power Agency

Each year about this time, we spend a large part of an issue discussing renewable energy. Something about renewable energy harmonizes nicely with the prospect of happy days ahead.

As I sit here at my desk not long after Christmas, considering both renewable energy and nuclear power, it’s probably inevitable that the two ideas would bump into one another inside my brain. It’s got me thinking; just what is the relationship between renewable energy and nuclear power? Are the two fast friends or strange bedfellows? Can nuclear power rightly be considered a form of renewable energy?

Type any of these questions into Google and you’ll get lots of disparate opinions. Seems like everyone from political pundits to hard-charging investigative journalists have some take on the issue. (And every one of them is right, of course. Just ask them.) It occurs to me, though, that we editors of nuts-and-bolts magazines like this one have a peculiar advantage over many other sources of information on the topic-access to a highly technical readership that is disproportionately informed on matters such as these.

Problem is-and maybe this will surprise you-we don’t hear from you folks enough. Maybe it’s because we’re somehow insulated from the public by the vagaries of an opaque publication process, or maybe you guys out there in magazine-land are just like the rest of us, too busy getting through your day to sit down and fire off an unsolicited tweet. No matter. You may now consider yourselves officially solicited; I’m asking for your comments.

So what do you say? Is nuclear power renewable or merely sustainable? Is it even worth making such a distinction, or is that splitting hairs?

Will the combination of technologies like fast breeder reactors and seawater uranium extraction render nuclear fuel effectively limitless, or at least, as some say, in sufficient supply to outlast the solar system? If the answer is no, and nuclear power cannot technically be labeled renewable, can more efficient mining render uranium ore plentiful enough to liberate us from pedantic debates about the shaded meanings of words?

And what about greenhouse gases? Certainly it can be argued that the low-carbon nature of nuclear power is at least in keeping with the “first do no harm” environmental ethos of the renewables movement.

But then what are we to make of that elephant in the room-the great quantities of spent nuclear fuel that must be stored as waste at great cost and for untold years?

I won’t claim to know the answers to all of these questions. Nuclear power has suffered some setbacks in recent years, both from the economic pressures of low-cost natural gas and the political and environmental fallout of nuclear disasters.

If nuclear power is not exactly the poster child for economical and safe energy, does it continue to have a role to play in an increasingly renewable landscape? Can it play well with wind and solar?

When calling on other forms of power to prop up intermittent renewables, the industry tends to turn to fast-start combined-cycle plants, or energy storage facilities like pumped hydro and chemical batteries.

A lumbering nuclear plant is not exactly top of mind when the wind stops blowing or the sun stops shining, and demand exceeds supply. What then? Does this curtail the utility of nuclear power in a future filled with solar-powered flying cars and wind-charged robot servants?

I’d like to ask our readers to weigh in on these issues. I invite your comments on the matter. Let us know your opinions on the issue. We care about what you think. Share your thoughts using the Twitter handle @PwrEngineering. And as always, you can email us at pe@pennwell.com.

As the country makes its inexorable move from coal to natural gas electricity production, the headlines are filled with power plant conversion announcements. Those utilities considering fuel conversions should understand that several obstacles potentially stand in the way to obtaining environmental permits, and that planning needs to start three years or more in advance.

From 2015 to 2040, natural gas consumption will rise 1 percent per year, the Energy Information Association predicts. From 2016 to 2018 alone, nearly 19,000 MW of gas-fired power will be commissioned in the Unites States. Gas is setting power generation records, accounting for 33.5 percent during the first half of 2016, compared to coal’s 28 percent. With shale fracking production stabilized, gas is no longer the wild hare of the oil patch. Combining low prices and plentiful supply with more stringent emissions standards, cleaner burning gas is on every utility manager’s mind.

Crafting a road map to permitting and building a gas-fired plant should also be on the utility manager’s mind. It requires multiple permitting steps and long-lead analyses that have to be funded and planned for as part of the capital project execution. And finally, the general public isn’t always convinced that natural gas is viable and in their best interests.

New Gas Plant Modeling Scenario Shows Likely Regulations

Gas-fired power plants are affected by three general permitting challenges. They include the Environmental Protection Agency’s (EPA) 316(b) rule that regulates how utilities draw and use water in their cooling processes; federal air pollution standards, and local government permitting.

In order to illustrate typical permitting challenges, Stanley Consultants developed a model for a fictitious gas-fired combined cycle plant of 500 MW to be built in the Midwest. The scenario featured a standard vendor turbine package in a 2×1 arrangement with a heat recovery steam generator (HRSG), cooling tower, and evaporative coolers. The model assumed 1 percent blowdown and no duct firing in the HRSG. The water consumption rate predicted was 889 Kilo-Pascals per hour, which equates to 2,560,320 gallons per day.

316(b) Requirements

Under Phase I of the 316(b) rule, a new power plant must implement measures to reduce impingement and entrainment at facilities which require a NPDES permit, have design intake rates of greater than 2 million gallons per day (MGD), and use at least 25 percent of the water withdrawn for cooling purposes. It’s not difficult to meet these thresholds. Say, for example, our fictitious plant did not have a cooling tower and relied on once-through cooling. Our model calculated a water use approaching 200 MGD.

Two Section 316(b) compliance tracks present different levels of compliance depending on whether you are using a cooling tower (Track 1) or alternate methods of complying with the regulatory standards (Track 2). Both tracks require meeting technical criteria for the water intake structures; however Track 2 involves a source water biological study. Both tracks involve long lead items because they require technology studies. In the case of Track 2, it also takes two years to gather information on aquatic life and the ecosystem, and project the extent of impact to the ecosystem.

Air Quality

Air quality standards play a role in gas-fired power plants. In 2015, the EPA strengthened the ozone standard from 75 to 70 parts per billion. This may not seem like a lot, but it could lead to significant cost increases for a new plant, as natural gas combustion is a source of NOx and VOC emissions.

Lowest achievable emission rate (LAER) technology is required in plant design. The severity of a nonattainment status will require emission offsets so that there is a greater reduction of pollution overall. It can easily take nine months to permit the LAER determination.

Local Permitting

Finally, local permitting is required to build the plant, bring in construction equipment, and deal with dust and traffic issues. Certain permits require a period of public comment. If there is known resistance, outside help will be needed to address stakeholder concerns. Gas pipelines and transmission are another major concern and frequently the target of opposition.

Gas-fired plants offer many benefits but are no slam dunk. A comprehensive plan will help operators avoid costly issues down the road.

We have all seen it. “Tonight, on news at 6 — a big retailer has lost millions of credit card numbers.” As consumers and individuals, the idea of exposure to a computer virus seems less sensational every day. This year alone, many have received multiple identity theft protection services free due to a corporate or government breach. However, securing the data required for operation of the nationwide power grid is orders of magnitude more important for the security of our nation than that of personal data.

Data security for the power industry is regulated by the Federal Energy Regulatory Commission (FERC). However, let’s take a step back from these complicated regulations and talk about holistic cybersecurity concepts.

Cybersecurity is seen by many as a sunk cost. In the business world and in the Federal government, compliance frameworks are constantly forced, but typically miss the mark due to their implementation and enforcement strategy. These regulations are often filled with “one size fits all” paper drills and annual assessments with extreme penalties for failure. These “flexible” frameworks all too often become a “check-the-box” system where resources are wasted on simply meeting the minimum compliance standard but not an inch further.

One word describes why utilities should care about cybersecurity: risk. On a personal level, the integrity of a family’s memories are the most important. To ensure this data is always available, parents regularly backup photos and videos locally on an external hard drive as well as to a cloud storage provider. This same concept is vital to power producers. This provides local redundancy as well as remote redundancy — the likelihood of all three drives being destroyed is very low. The likelihood that a computer hard drive and local external hard drive failing or being destroyed simultaneously is small, but considering one natural disaster could take out both of them easily, having backups off-site minimizes the risk to a tolerable level. The same principles should be utilized for any data of tangible or intangible value.

The real goal is risk tolerance. To achieve this goal, you must establish a thorough understanding of your facility’s cybersecurity risk. When trying to evaluate a utility’s cybersecurity program, start with a basic question — what is the critical data?

What part of your Information Technology (IT) or Operational Technology (OT) infrastructure is the most important to you and your business interests? For a utility, the most vital business process is probably the ability to monitor and respond to the ebb and flow of grid demand. It may be the customer financial information sitting in a dormant state, it might be the prioritization of power service restoration, or it could be another critical business process–many times, it is a blend of all three.

Once the critical data sets and priorities are identified-figure out what state of the data is important. Is it keeping the data confidential? Is it ensuring the integrity of the data? Perhaps the most important priority is availability – building a resilient system where non-critical portions of the network are acceptable to fail while others must stay online. Again, you need a blend of the three components, but it is important to understand where your priorities are in order to provide your cybersecurity team clear direction.

This strategic focus helps build a foundation to utilize in assessing the extremely complex and multidimensional cybersecurity risk to power providers. It provides a starting point and will mature and enhance an understanding of the risk to the data. At this point, executives need to establish a relationship with a set of trusted advisors to provide an honest look from the outside in. This should be above and beyond a typical audit — starting at a strategic level and systematically work through maturity layers to ensure a holistic approach has been taken while identifying any gaps.

Continual maturing is paramount for utilities – most cybersecurity programs can be drastically improved through strategic incremental improvements. Assessing risk, prioritizing efforts, implementing solutions, and re-assessing are key to ensure that a cybersecurity program is moving in the right direction while verifying results along the way. Through this method, an understanding of the business’ cybersecurity risk will enable leadership to better understand their risks and invest in the cybersecurity solutions that provide the highest return on investment to the business.

The reason to care about cybersecurity is to enable risk management and tolerance.

General Electric on Dec. 13 announced more than $660 million in orders for GE Power, including equipment for the gas-fired Riverside power plant expansion project in Wisconsin. This new business was announced in conjunction with Power-Gen International 2016 in Orlando, Florida. The orders include a new F-class gas turbine project in Wisconsin and continued customer adoption of GE’s Operations Optimization and Asset Performance Management suites of digital solutions. The Dec. 13 announcements include more than $450 million in orders from GE’s Power Services business, providing customers with other OEM service capabilities and enhanced upgrades.

Block Island Offshore Wind Facility Begins Operation

Deepwater Wind’s Block Island Wind Farm has become the first offshore wind farm to deliver energy to the United States.

The company officially commissioned the five turbine, 30-MW development this month. Energy produced will be transmitted by National Grid’s new sea2shore submarine transmission cable system.

Block Island was built with the help of GE Renewable Energy, which also supplied the project’s wind turbines. The testing period ran four months, though one of the turbines encountered a minor technical problem.

Crew for the facility’s two-year development were transferred via the vessel Atlantic Pioneer.

The project’s investors include Deepwater Wind’s principal owner, an affiliate of the D.E. Shaw group, Citi, and GE Energy Financial Services, along with lenders Societe Generale, KeyBank, HSBC, SMBC, Cobank, and La Caixa.

Deepwater estimated the full offshore wind potential in the United States could be as much as four times the generating capacity of the current grid.

Southern Company Commissions 200-MW California Solar Facility

Southern Company announced its subsidiary, Southern Power, and Recurrent Energy, a subsidiary of Canadian Solar, officially began commercial operations of the Garland Solar Facility.

The 200-MW development, built on 2,000 acres of land in Kern County, California, began construction in November 2015.

Southern Power has announced, acquired or is constructing more than 2,700 MW of renewable generation ownership with 33 solar, wind and biomass projects. The Southern Company system has added or announced more than 4,000 MW of renewable energy projects since 2012.

Recurrent Energy currently has 1,000 MW of utility-scale solar projects under construction.

Energy from Garland Solar is under long-term power purchase agreements with Southern California Edison.

Burns & McDonnell Acquires AZCO

Burns & McDonnell Inc. announced the acquisition of industrial contractor AZCO Inc.

The acquisition will create a comprehensive environmental, engineering, procurement and direct-hire construction and fabrication company, as AZCO also operates a 71,000 square-foot fabrication center that produces carbon steel, stainless, chrome-moly and exotic alloy pipe and metal fabrication.

A purchase price was not disclosed.

Alabama Power RFP Results in 200 Renewable Project Proposals

Alabama Power announced the company has received 200 renewable energy project ideas through an RFP that recently closed to bidders.

The company is now reviewing the proposals to determine which, if any, will be suitable for construction. The projects will be narrowed to a short list by next April, and surviving projects will undergo a more detailed analysis.

Most of the proposals involved solar energy, with some hydro and biomass projects submitted. Individual projects had to range between five and 80 MW and be located in Alabama. The projects could be owned by Alabama Power or owned by third parties with a power purchase agreement with the utility.

The target date for submitted projects to enter operation is March 31, 2019.

Plans for Carlsbad Energy Center Upheld by Appeals Court

The First District Court of Appeals in San Francisco has ruled it will let stand a ruling by the California Public Utilities Commission clearing the way for a new power plant to be constructed by NRG Energy.

The move clears the way for development on NRG’s natural gas-fired, 558-MW, $2.2 billion Carlsbad Energy Center, reported the Los Angeles Times.

NRG’s original plans were to bring the center online at the end of 2017 to compensate for the retirement of the Encina Generating Station. Power will be purchased by San Diego Gas & Electric.

A number of environmental groups sued to try to stop the construction of Carlsbad, claiming it violated California’s efforts to reduce carbon emissions.

However, the court ruled the California Public Utilities Commission was “just and reasonable” in its decision to award a contract for construction of the plant.

Dominion Virginia Power Breaks Ground on Natural Gas Plant

Dominion Virginia Power held its official groundbreaking on its natural gas-fired Greensville County Power Station.

The $1.3 billion, 1,588-MW plant is expected to be the largest gas-fired combined-cycle facility in North America when it begins operations near the end of 2018, the Richmond Times-Dispatch reported.

Greensville County Power Station follows in the footsteps of Dominion’s 1,358-MW Brunswick County power station, which came on line earlier this year. The two have a combined development cost of $2.5 billion.

Greensville County officials hope to use the plant as a draw to attract large businesses into the area, including international companies. Dominion expects the station to generate $8 million in property taxes and $36 million in annual economic benefits.

Alberta Okays Change for 98-MW Peace River Project

The Alberta Utilities Commission on approved a Nov. 16 application from Peace River Power GP Ltd. for the alteration of a 98-MW natural gas-fired plant in Northern Sunrise County, with the alteration needed to support future plant expansion.

Peace River Power has an Aug. 31 approval from the commission to construct and operate this 98-MW natural gas-fired plant, located approximately 40 kilometers northeast of the town of Peace River.

Peace River Power requested approval to alter the type of transformers at the power plant.

The project would consist of two 49-MW simple cycle General Electric LM6000-PH gas turbine generators.

Peace River Power stated that the plant would utilize conventional sales and associated gas from the existing production wells in the vicinity of the project site.

The power will be exported to the Alberta Interconnected Electric System.

Siemens Announces U.S. Leadership Changes

Siemens Corporation announced Eric Spiegel, chief executive officer of Siemens in the U.S., will leave the company at the end of the year.

Lisa Davis has been appointed Chair and CEO of Siemens Corporation, effective Jan. 1, 2017. Judith Marks has been appointed Siemens CEO U.S., effective the same date.

Marks began her career at Siemens in 2011 as President and CEO of Siemens Government Technologies Inc., where she led the company’s approach to the federal market.

Before coming to Siemens, she spent 27 years with Lockheed Martin and its predecessor companies.

She will assume the CEO U.S. role, in addition to her current position as executive vice president at Dresser-Rand, a Siemens business.

Siemens has been in the U.S. for more than 160 years and has 50,000 U.S. employees and 75 manufacturing sites.

NRC Approves Transfer of Susquehanna Nuclear Plant Licenses

The U.S. Nuclear Regulatory Commission today announced approval of the indirect transfer of operating licenses for Units 1 and 2 of the Susquehanna Steam Electric Station in Berwick, Pennsylvania. The licenses will pass from Talen Energy to Riverstone Holdings as part of Riverstone’s proposed acquisition of Talen.

The Susquehanna plant has two boiling water reactors and a dry cask spent fuel storage installation. Units 1 and 2 are licensed to operate through July 17, 2042 and March 23, 2044, respectively. The plant is operated by a subsidiary of Talen, Susquehanna Nuclear, which owns a 90-percent stake in the plant and will continue to oversee operations at the facility.

The “indirect” nomenclature used to describe the transfer refers to a change in the holding company of a nuclear license.

NRC Renews Operating License for Grand Gulf Nuclear Plant

The U.S. Nuclear Regulatory Commission announced today it has renewed the operating license for Unit 1 of the Grand Gulf Nuclear Station in Mississippi. The license clears the way for the plant to operate into 2044.

GGNS is a boiling-water reactor operated by Entergy in Port Gibson, about 20 miles southwest of Vicksburg. As part of the re-licensing process, the NRC reviewed the plant’s safety, publishing an evaluation in October. In November, it also published a supplemental statement concerning the reactor’s environmental impact.

The GGNS license brings to 86 the number of commercial nuclear reactors with renewed licenses in the country, though three of these plants have since shut down. Renewal applications for another nine nuclear reactors are currently under review.