Every year, our power industry is facing more and more intense impact from climate change, whether the result of blizzardy, icy winter conditions or scorching summer heat waves.

In early September 2022, a heat dome settled over the U.S. West Coast and brought temperatures that set all-time record highs. The extreme heat fueled wildfires and caused major power outages before a tropical storm moved in and cooled things down. Mere months later, an arctic outbreak that occurred in February 2023 shattered records in the Northeast, including –108 F wind chill, and again put a dire strain on the region’s power supply causing numerous outages.

There has never been a more important time in history for utility providers to be on their A-game and proactively addressing potential issues but imagine this real-world situation. A key unit in a power plant goes down and they are immediately facing a struggle to get it back online as quickly as possible because every day that facility remains out of action, the hit to their bottom line grows and grows.

But what if this outage happened right before the high, hot season…and not at one facility, but at three separate locations? Suddenly the difficulties up against them have more than dramatically intensified and it is said, bad things come in threes. 

With labor and materials in short supply, it is of the utmost importance for major power providers facing crisis situations such as this to find a reliable third-party service provider that can offer fast-acting solutions. Experience and knowledge are a key component to get energy-producing units back up and running, or plants of this magnitude could suffer absolutely disastrous consequences to their organization.

This article features a real-world example of an emergency situation a major utility in the U.S. faced during the winter of 2021 that continued into the spring of 2022. Three outage situations. Three headaches to deal with. All within three months’ time.

Extensive damage reported at Power Plant #1

Compressor failure calls for comprehensive know-how. Going into 2022, the utility knew it was going to be critical to have their units at their operational prime for the hot summer run. Why? Missing an energy dispatch could be catastrophic to a power industry business. It’s hard to survive a loss of all financial gains that would have typically been made for the year when the resulting penalties kick in.

When the utility suffered a compressor failure at their peaking power plant in Indiana, they knew they had a significant job on their hands. Foreign object damage (FOD) had taken out operations of the whole compressor. This wasn’t a situation where the utility’s internal crew had the know-how to fix themselves. As such, the utility called upon a rotating equipment service provider – EthosEnergy – for their knowledge and expertise.

In December 2021, the service provider got to work starting with a planned short-term outage and mobilization of all the replacement components the unit needed, including new compressor blades and vanes. By early-January 2022, EthosEnergy was onsite disassembling the machine. However, the damage was far more extensive than what was previously thought. When looking downstream, the service provider discovered additional issues and determined it must migrate the utility’s repairs into a major outage in order to completely resolve the situation.

Two days to mobilize at Power Plant #2

Not long after the utility had come to grips with the peaking plant issues in Indiana, the organization experienced a forced outage at their combined-cycle power plant in Florida. This was due to second-stage blade failure on a GE 7FA gas turbine. Extremely high vibrations led to the machine tripping and causing extensive damage in the hot section down through the exhaust.

The utility’s second power plant was scheduled to carry out a major outage in the fall of 2022, but it asked EthosEnergy to speed it forward. The challenge was that the utility needed EthosEnergy to mobilize and be on site…within just two days. Further, the spring of 2022 was one of the busiest power outage seasons the industry had seen in years due to extreme weather conditions.

Nimble and responsive, the service provider stepped up to the plate and made sure to answer the utility’s challenge of a tight timetable. They were on site within two days to assess the situation and fully staffed with experienced crews ready to get the job done within four.

Overlapping issue at Power Plant #3

Unbelievable, but true, while EthosEnergy was working at power plant #2, there was a problem arising at another of the utility’s facilities located in Florida. A peaking power plant started experiencing combustion issues on one of its GE 7EA gas turbine units. The utility asked the service provider to carry out a modified combustion inspection.

As it happened, EthosEnergy was dispatched nearby and able to support the third power plant with the same field service personnel. The service provider sent the team 90 miles up the road where they performed a fuel nozzle change-out. A few more issues came to light, but within five days EthosEnergy had the machine up and running.

But just when everything seemed to be on track for completing the major outage, more problems arose for the utility. 

Revisiting Power Plant #2

A week after EthosEnergy had demobilized from the combined-cycle power plant in Florida, the facility experienced an explosion and resulting fire. Fortunately, nobody was injured, and the service provider would come to discover that it was not a result of the previous work they had conducted on behalf of the utility. However, there were understandable concerns about what had transpired and why.

Once again, EthosEnergy was able to mobilize their team within two days. On inspection, the service provider ascertained that there was a crack in the atomizing air vessel containing the filter strainer.

As such, EthosEnergy launched a 30-day outage and essentially stripped everything down. The service provider repaired and refurbished the machine, replaced combustion components and various other items, and got the unit back up and running.

For EthosEnergy, safety is of the utmost importance, as it also was for this particular utility. It was a great achievement for the service provider to not only have answered the call at these three sites, but to have done so without one safety issue.

The agility and flexibility demonstrated by EthosEnergy’s field services teams ensured all three of the utility’s facilities were fully operational in time for the key summer season. This was a season that saw particularly high demand in 2022 due to scorching temperatures and one in which every one of the client’s units were able to run each and every day.

Westinghouse will design, manufacture, and deliver six steam generators with delivery in 2028 with installation beginning in 2029. The steam generators will be fabricated at the Westinghouse Italy (WEI) facility in Monfalcone, Italy.

The contract supports Dominion’s efforts to extend the life of Surry Units 1 and 2 through 2053.

In 2021, Westinghouse and Dominion inked a contract for a major instrumentation and control (I&C) upgrade.

By Justin Goodwin, Director of the Steam Conditioning Group at Emerson Automation Solutions

When combined cycle plants are run at low loads, problems often arise with overspray from attemperators using traditional mechanical atomization. To address this issue, power plants can upgrade to steam atomization attemperators.

Controlling steam temperature in the various stages of a combined cycle plant is always challenging—particularly during startup, shutdown, and major load changes. Attemperators are often installed between the primary and secondary superheaters and reheaters to inject water into the steam and control the high pressure (HP) superheat and hot reheat (RH) outlet temperatures (Figure 1).

Many combined cycle power plants were originally designed for baseload power generation. However, due to intermittent power generation from solar and wind sources, combined cycle plants are increasingly used to level the power generation profile. This forces some combined cycle units to operate across a wide band of varying load conditions, known as load following.

As the generating load changes, the gas turbine (GT) exhaust temperatures and heat transfer rates in the heat recovery steam generator (HRSG) also change. During low load conditions, startup, shutdown—and even during significant load changes—steam temperatures can quickly exceed limits if not properly controlled.

Attemperators are carefully selected for the expected range of process conditions. As the power generating landscape changes, however, many combined cycle plants are often required to run at very low power generation rates.

GT manufacturers continue to evolve their technology to decrease the minimum GT load range, but this has also made steam temperature control more challenging. Some GT models operate at higher temperatures during low or partial load operation, and during these times steam flows are much lower. The result is many existing attemperators being stretched beyond their capabilities.

Attemperator issues

Attemperator problems are prevalent with combined cycle units. While the concept of spraying water to a steam flow stream seems simple enough, in practice it is much more difficult to accomplish, and if done incorrectly, can create significant damage (Figure 2).

An attemperator controls steam temperature by injecting a spray of very fine water droplets into the steam flow, and these droplets should ideally evaporate immediately. The evaporating liquid reduces the steam temperature, and if the water droplets do not hit the extremely hot pipe walls, the process works well. Unfortunately, attemperators often do not function as designed, and significant problems often result, including:

• Large droplets or jets from malfunctioning spray nozzles fail to evaporate and impinge on the walls of the pipe. The resulting thermal shock created by the liquid water hitting the elevated temperature pipe walls causes cracks over time. This excess water can also flow through secondary superheater or reheater tubes, causing them to warp (Figure 2, left).
• Thermal cycling from constantly turning the attemperator on/off causes thermal fatigue cracking in attemperators, leading to mechanical failure such as broken probes.
• High steam velocities subject poorly designed probe-style attemperators to significant vibration due to vortex shedding, which can cause the probe to break off. This leads to dumping un-atomized water into the steam pipe.
• Leaking attemperator spray block valves drip water into the pipe, quenching the steam pipe and leading to cracking of the internal liner (Figure 2, right)
• Spray nozzles stick open or shut, with oxide debris trapped in the seat of the nozzle, affecting spray patterns or flow characteristics.

Different designs have been applied to address these issues, with varying degrees of success.

Attemperator designs

An attemperator is designed to create a spray of uniform, small water droplets that will evaporate quickly in the process steam pipe. If the water flow and pressure drop through the nozzle are constant and adequate steam flow is present, it is straightforward to design an attemperator nozzle that will accomplish this task.

Attemperator designs have changed significantly through the years. Simple, fixed orifice nozzles are used in many constant load desuperheating applications, but they should not be used in today’s combined cycle plants because they do not have the dynamic range required to handle different water flow rates and nozzle pressure drops. When the combined cycle plant load changes, the required water flow can change quickly, even as the pressure and velocity of the steam in the process pipe are also changing.

When the water flow requirement reduces, the attemperator will throttle a control valve to reduce the water flow, but this changes the pressure drop across the nozzle and impacts its performance. Figures 3A, 3B, 3C, and 3D demonstrate the effect of pressure drop across a fixed orifice nozzle. Although some of these examples are extreme and represent poor design selection, the effect is clear.

Another style of attemperator that was installed in many plants built in the 1998-2003 timeframe is the probe or mast style with simple fixed geometry nozzles, which control flow by exposing varying numbers of nozzles to the incoming water flow. The throttling range on this type of design can be good since all the pressure drop occurs at the spray nozzle, but these designs are often highly susceptible to thermal fatigue in today’s cycling attemperator service. Opening and closing of the spray water valve thermally shocks the valve trim and probe pipe leading to fatigue problems.

Another approach to this application utilized spring-loaded spray nozzles (Figure 4) to handle a wider range of nozzle pressure drops, while still atomizing the water as required. Historically, the best and longest-lasting attemperator installations use a number of these nozzles in a ring-style attemperator, which injects radially into the flow stream, with no probe or valve trim inside the hot steam pipe.

While spring-loaded designs certainly provide improved performance with varying load conditions, the rangeability requirements of some combined cycle plants are stretching these nozzles past their operating limits.

To detect this condition, multiple thermocouples can be installed downstream of the attemperator in the process steam piping. If the measured temperature approaches the saturation temperature of the steam, this can indicate an attemperator problem. Overspray is usually indicated by a wide variation of downstream temperature readings, which occur as water droplets hit individual temperature sensor probes (Figure 5).

An alternative

One of Duke Energy’s combined cycle power plants in North Carolina was having issues with its ring-style, spring-loaded nozzle attemperators. The plant’s generating load was varying dramatically, and the plant often operated under low load conditions when the GT exhaust gas temperatures were highest. During some of these operating modes, the attemperators were unable to control temperature.

The issue was occurring in the hot reheat (HRH) system due to a perfect storm of process conditions. The low GT load and higher resulting exhaust temperatures produced lower reheat (RH) steam flows and steam pressures, but it required high attemperator spray flow rates.

Normally, high velocity and higher pressure (i.e., higher density) steam flows help dissipate and evaporate water droplets from an attemperator, but at low load conditions, the greatly reduced steam flow cannot adequately perform this function, and the water droplets take longer to evaporate. The spray carries further downstream, impinging on pipe walls and creating damage. These conditions were making this application very challenging.

The attemperator spray flow was being injected in a vertical configuration at the side of the HRSG units. Thermocouples were added to the downstream elbow 21 feet from the attemperator spray injection point, and temperature differentials up to 400 degrees F were observed between the elbow intrados and extrados during these low load conditions. Additionally, the three thermocouples that measure the steam temperatures downstream of the HRH attemperator were being wetted by unevaporated spray flow even though they are located an additional 15 feet past the elbow.

Duke Energy plant and regional engineers were concerned that this thermal quenching would eventually lead to damage to the steam piping, tubes and other HRSG pressure parts. Analysis showed crack initiation expected in another 4.7 years of operation. The problem was predicted to get worse since the combined cycle power plant was operating at low loads at an increasing frequency as more solar capacity was added to Duke Energy’s power grid.

To address these and other issues, plant personnel began searching for alternative attemperators. The replacement had to handle a wider range of flow conditions and ensure long life in a heavy cycling environment. Ideally, the new attemperator would require the same or reduced downstream pipe lengths to make installation less expensive and easier.

Emerson engineers worked with Duke Energy plant and regional engineering personnel to develop a hot reheat steam atomizing attemperator. Steam was sourced from the high-pressure steam system (Figure 6) with no fabrication joints, shrink-fits, threads, or other joints within the nozzle. Emerson also found a way to fit the solution into the existing attemperator body, avoiding significant field piping rework.

A small amount of steam from the high-pressure steam drum outlet is now piped to the new attemperator and injected at the attemperator nozzle to atomize the water into a fine mist, maintaining attemperator performance across a wide variety of process steam and water flow conditions.

The resulting fog-like mist is readily evaporated in the process steam line. The new attemperator nozzle was specifically designed to replace the existing Fisher TBX-T ring-style attemperator nozzles and use the same nozzle housing.

Rapid Results

The new steam atomizing attemperator was installed in the hot reheat system at one of Duke Energy’s combined cycle power plants as a trial of the new concept. The process improvement was immediate and significant. Figure 7 shows a side-by-side comparison of the thermocouples downstream of the attemperator as the gas or combustion turbine (CT) load (indicated by the light blue line at the bottom of the graph) increases from a low to normal load condition.

The new steam attemperator effectively controls the reheater outlet temperature, even under very demanding low load conditions where the maximum amount of water is required, and the RH steam flow is very low. The temperature is maintained well above the saturated steam temperature (green line in the Figure 7 diagrams) and there is very little sign of downstream temperature variation, which would indicate overspray. In comparison, the traditional nozzle attemperator in Unit 12 is controlling much closer to steam saturation, with erratic downstream temperature readings indicating water droplets reaching the downstream equipment and likely causing damage.

It is important to note that this type of steam-atomized attemperator cannot be used in an HP system due to a lack of higher-pressure steam to use for atomization. However, the need is often greater in the RH system for the following reasons:

• The higher pressure, higher density HP steam is more capable of breaking up spray droplets.
• The higher density HP steam can carry the water droplets further down the pipe giving them time to evaporate. 
• The higher density HP steam transfers its heat faster, and thus evaporates the injected water faster / more efficiently than RH steam. 

After evaluating the field trial results, Duke Energy moved forward to upgrade the hot reheat attemperator in the second unit of this 2×1 CC power block to the new steam atomized design. Duke Energy has also completed the same upgrade at a 2×1 CC sister site, as well as executed a replacement project to remove and replace two HRH attemperators in a third power station. These projects were complete replacements of the existing attemperators versus retrofit replacements. They have now been commissioned and are working well.

Conclusion

Historically, mechanically atomized nozzles have provided effective control over the traditional attemperator operating ranges. However, as power market demands evolve with the addition of renewables and GT upgrades enable ever-lower combined cycle load operation, attemperators are required to operate across a much wider range of conditions, increasing the risk of damaging overspray.

With these changes, mechanical nozzles may be reaching the limits of their capability to provide sufficient atomization. As demonstrated in this article, this issue can be addressed with steam-atomized nozzle technology.

About the Authors

Eugene Eagle graduated from North Carolina State University in 2005 with a bachelor’s degree in Mechanical Engineering. He started his career with Progress Energy that year as an Auxiliary Operator at the Shearon Harris Nuclear Power Plant, later earning an NRC license as a Reactor Operator. For the past seven years, Eagle has served as heat recovery steam generator (HRSG) engineer and subject matter expert for Duke Energy in the Carolinas region, supporting a fleet currently comprised of 18 HRSG units. In addition to annual inspections, condition assessments, and responding to various problems and issues, his focus is on monitoring operational data and working to improve HRSG unit operations and reliability. Eagle is a registered Professional Engineer in the State of North Carolina, Mechanical Engineering with focus in Thermal and Fluids. He also works closely with the Electric Power Research Institute in Program 88 – HRSG as an advisor for Duke Energy, and he serves as the program utility chair.

Justin Goodwin is the Director of the Steam Conditioning Group at Emerson. He has a B.S. in Mechanical Engineering from Iowa State University and a B.A. in Applied Math from Grand View University. Justin has been responsible for the design and technical support of steam conditioning and desuperheating equipment since 2005. Today, Goodwin provides direction, technical oversight and training for Emerson’s global steam conditioning business.

Figures all courtesy of Emerson and Duke Energy.

The contract is worth more than $310 million U.S. dollars. Aecon holds a 55% share in the project, SNC-Lavalin has a 30% share and United Engineers & Constructors holds 15%.

The work at the nuclear power plant involves modernizing reactor-related components – 480 fuel channels and calandria tubes, 960 end fittings and 980 feeder pipes. The partners will also be responsible for operations, robotics and employee management and training.

Planning is expected to start in conjunction with a scheduled outage at the nuclear station in early 2022, with a project completion target of 2026.

The joint venture partners collectively make up the Shoreline Power Group, which was awarded a contract to refurbish the nuclear power plant’s Unit 6 in 2018. That job is expected complete by the end of 2022.

RELATED: SNC-Lavalin’s Candu Energy gains service extension at 6.4-GW Bruce nuclear plant in Canada

Shoreline is already a preferred parts supplier of Bruce Power and could get similar refurbishing contracts in the future.

“We are making this significant contract award with the confidence that the members of the Shoreline Power Group have demonstrated the experience and commitment to safety, quality and innovation to successfully deliver this key part of our Life Extension program,” said Mike Rencheck, Bruce Power’s President and CEO.

Bruce Power is refurbishing its nuclear fleet so the plant can safely operate through 2064. The Canadian company’s life-extension program involves the gradual replacement of older systems in the plant’s eight reactors during scheduled maintenance outages.

More on Bruce Power’s nuclear life-extension program here.

School researchers say the technology could significantly reduce CO2 emissions from combustion flue gases at power plants.

Through the process, carbon dioxide is absorbed and then sent to a stripper, where the CO2 is separated from the solvent. It is then compressed for geological sequestration or used for other purposes. UT researchers say the technology can be retrofitted within existing plants or included as part of new installation.

The school says for a single power plant, applying the carbon capture technology would enable the capture of about 3.4 million tons of carbon dioxide annually, equivalent to removing nearly 735,000 cars from the road each year.

Honeywell said it believes the technology will lower the cost of capturing carbon emissions. The company plans to commercialize the carbon capture technology created by the UT researchers, eventually scaling it for use around the world.

“As the world proactively seeks technology solutions that limit greenhouse gas emissions, we recognize that carbon capture technology is an important lever available today to reduce emissions in carbon-intensive industries that have few alternative options, such as steel plants and fossil fuel power plants,” said Ben Owens, Vice-President of Honeywell Sustainable Technology Solutions.

Honeywell aims to become carbon-neutral by 2035. The company says it already captures and uses 15 million tons of CO2 per year.

More on the Texas Carbon Management Program here.

AUSTIN, Texas (AP) — Regulators of Texas’ oil and gas industry that buckled during February’s deadly freeze moved Tuesday toward making some producers more prepared for cold weather, but not in time for this winter as the nation’s power grid monitor warned the state is still at risk of blackouts.

Republican Gov. Greg Abbott is guaranteeing the lights will stay on this winter. But energy experts are less confident and say Texas’ response over the last nine months to a winter storm that killed hundreds of people — including some who froze to death after power was knocked out to the proud energy capital of the U.S. for days — has been insufficient.

Some were concerned that gas operators that froze up in February — cutting off fuel to power plants — would be able to skirt new weatherization mandates by seeking exemptions. But gas supply deemed critical by the state could not avoid doing so under new rules passed Tuesday, according to state regulators, which critics agreed amounted to an improvement.

Power Challenges Greater than Texas is the topic of the POWERGEN Leadership Summit Keynote roundtable with former Texas Governor Rick Perry and Acting ERCOT CEO Brad Jones. Learn more about POWERGEN’s Leadership Summit and register to attend the event today.

“It is not simply a get-out-of-jail-free card,” said Matt Garner, an attorney with the Texas Railroad Commission, the state’s peculiarly named agency that regulates the oil and gas industry.

A recent annual winter forecast by the North American Electric Reliability Corporation, which oversees the reliability of the nation’s electrical sector, projected Texas could have a nearly 40% shortfall in available power to meet demand in the event of another severe storm this winter. Officials behind that forecast said such an extreme scenario is not highly likely, but cannot be ruled out.

The February storm led to one of the biggest power outages in U.S. history, knocking out electricity to more than 4 million customers and leading to hundreds of deaths. Some homes were left without heat and water for days.

According t o a report by federal officials in September, freezing issues were the largest cause of outages, at 44%. That included frozen instruments and wind turbine blades. Fuel supply problems were the next biggest factor, at 31%. Supply issues were mostly related to natural gas, including frozen wellheads.

The process for requiring gas operators to weatherize won’t begin until next year.

“They won’t be prepared for this winter, and that’s something everybody needs to be clear about,” said Virginia Palacios, executive commissioner of Commission Shift, a group that calls for more accountability from state energy regulators.

(This story originally appeared as a blog on the Burns & McDonnell website).

Oil spill response plans are required for facilities regulated by the U.S. Environmental Protection Agency (EPA) that store more than 1 million gallons of oil and can potentially impact a sensitive environment. A facility response plan (FRP) documents response strategies and defines roles in the event of an oil spill, giving facilities such as power plants, aviation fuel farms or bulk storage terminals a road map for spill management.

While all regulated facilities will have an FRP on hand, the real test is putting this FRP into action. Facilities are required to conduct various drills and exercises — some quarterly, others semiannually or annually — to help test the strength of the response plan. The EPA takes this one step further with a government-initiated unannounced exercise (GIUE), performing thorough spot-checks annually. A GIUE is not conducted at every regulated facility each year, but randomly, to test the effectiveness of spill response, which directly impacts the resulting environmental damage and cleanup cost.

An FRP, as well as a GIUE, should be taken seriously. Without an effective spill response plan, a facility could face significant violation costs or be more vulnerable to safety hazards. The EPA’s objective for these exercises is not to penalize any facility. The agency approaches these exercises in a collaborative fashion, with a willingness to work closely with facilities until they have effective FRPs. As a bonus, when a facility runs its response plan smoothly and successfully, it becomes exempt from this federal exercise for the next three years.

What to Expect

Facilities are commonly given about a week’s notice from the EPA before a GIUE. When the agency arrives at the facility, EPA personnel will walk facility staff through the exercise guidelines. The facility is then expected to conduct its spill response and equipment deployment as if there was a small discharge and the oil had already reached the water.

At this point, EPA personnel step back and simply observe. They will only intervene if health and safety issues arise. This exercise, which engages the facility’s contractors and the deployment of booming techniques, finishes when the facility has equipment in place and is ready to start pumping water through an oil skimming device, if applicable, without actually doing so.

Common Violations

Across industries, there are two common violations seen in a GIUE. If the EPA indicates that a facility has not successfully completed its exercise, the facility may be required to participate in another GIUE until the facility passes. If another exercise is required, the EPA will work with facility staff on areas of improvement and then conduct another exercise later.

• Facilities often forget to stop the source of the release as the first step of the spill response.
• Facilities find shortcomings in their plan during the exercise when they haven’t collaborated with their contractors to develop the plan or run a spill response test. In these situations, it’s common for facilities to learn during the GIUE that their contractors are actually unable to meet the response plan timeline, such as having a containment boom in place within one hour of spill discovery or having oil recovery devices in place within two hours.

How to Prepare

Facility personnel should engage with oil spill response organizations (OSROs) early. OSROs can have a hand in creating an FRP by visiting the site and informing the most effective approach. This also helps establish a relationship between the facility personnel and the OSROs, which can lead to a more efficient response.

Facilities should conduct and take drill and exercise requirements seriously to know exactly how facility personnel will respond to an oil release in a time of crisis. Conducting a series of tabletop exercises and drills is both advantageous and mandatory as part of the FRP requirement. As a best practice, facilities should include any OSROs involved in the FRP on exercises and drills.

Regulatory specialists can help industries navigate the complex and ever-changing environmental health and safety compliance programs that are so critical to their work.

About the author: Amy Reed, PE, is a senior environmental engineer, compliance audit team member and project manager at Burns & McDonnell. A chemical engineer by training with over 20 years of experience, she specializes in helping industrial and utility clients prepare for EPA regulations.

UL will inspect Siemens Gamesa’s new 5.X onshore platform, the SG5.8-170 and SG5.8-155 wind turbines with a capacity of 5.8MW and rotor diameters of 170 and 155 meters — representing some of the largest turbines in the global onshore wind industry. 

The inspection services will include checking the electrical characteristics of wind turbines to assess their reliability and safety in generating electricity. UL will assess the compatibility of Siemens Gamesa’s wind turbines with certification and grid codes for the Spanish, German and UK markets.

Certification and compliance with the standards will enable Siemens Gamesa to deploy its turbines across the markets and Europe, according to a statement.

The certification will also allow Siemens Gamesa to launch its new 5.X onshore platform worldwide.

Kai Grigutsch, head of wind certification for UL, said: “Confirming that new turbine technologies can support the power grid while optimising energy production is crucial to accelerating the development of wind farms and Europe’s green energy transition.”

See our full coverage of the onshore and offshore wind sector

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The wind energy sector has been expanding rapidly over the past decade ender efforts by governments and utilities to decarbonise power generation and economies. However, the pandemic has to some extent disturbed the growth in 2020 and 2021 due to disruptions in the supply chains of equipment.

Trade tensions between the US/Europe and China have also caused delays on rollout, as well as factors including the lack of adequate funding and lack of appetite by other utilities and governments to invest in green technologies.

This has resulted in the establishment of regional mechanisms and regulations such as Fit for 55, Joe Biden’s 2030 wind energy target and the establishment of GWEC’s Africa WindPower to help move the energy transition agenda ahead. Technology companies have also embarked on the development of innovative wind technologies to enhance the generation capacity of projects.

Irene Alli Oños, head of SG5.X Certification at SGRE, added: “We needed a trustworthy strategic supplier that could help us efficiently to certify our latest turbine design platform for international deployment and to support our customers.

“Our collaboration with UL will enable us to swiftly meet market-specific certification requirements.”

BWXT’s Canadian subsidiary will deliver on the $40 million (CA, $31M U.S.) contract with Bruce Power. The company will engineer and fabricate the specialized components for the moderator heat exchangers, which remove heat from the moderator system on CANDU nuclear reactors.

The  Bruce Nuclear Generating Station is an eight-unit pressurized heavy water reactor plant along the eastern shore of Lake Huron (pictured). The Bruce station’s eight units all came online from the late 1970s to late ‘80s and in total can generate more than 6,000 MW of carbon-free electricity.

BWXT Canada has started engineering work and fabrication is expected to begin later this year at its Cambridge, Ontario facility. The first two moderator heat exchangers are scheduled to be delivered in 2024 and the remaining two units in the following year.

Read our full coverage of the nuclear reactor power generation sector

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“These components are designed for reliable, long-term operation to help Bruce Power continue to provide Ontario with non-emitting, stable and cost-effective electricity for many years to come,” said John MacQuarrie, president of BWXT’s Nuclear Power Group. “This contract, along with several others we have with Bruce Power, is sustaining a very significant number of highly skilled jobs for our Cambridge operations.”

BWXT was spun off from Babcock & Wilcox six years ago to focus on nuclear power components and generation fuel.

The work by JCP&L, a subsidiary of FirstEnergy Corp., was done to enhance electric service reliability to New Jersey’s barrier islands.

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Dredging operations in recent years are believed to have damaged the underwater transmission line that ran through the area, necessitating its replacement. The new 34.5-kV line is one of four high-voltage power sources serving approximately 30,000 JCP&L customers on the barrier islands, including the communities of Point Pleasant Beach, Bay Head, Mantoloking, Normandy Beach, Brick, Lavallette, Dover/Toms River, Ortley Beach, Seaside Heights, Seaside Park, Berkeley and Island Beach State Park.

The new line now safely sits 10 feet below the bay’s soft, sandy base. Each of the three cables that make up the line are wrapped with 28 strands of aluminum armor wire, providing robust protection and eliminating the need for a bundled armor casing commonly used in underwater power line projects.

“This project supports our commitment to using new, innovative ways to improve service reliability by utilizing an emerging technology that placed the submarine line in a safer location while also minimizing the work’s impact on the bay’s fragile ecosystem,” said Jim Fakult, president of JCP&L. “The new line helps ensure that our barrier island customers will have the reliable service they need in these peak summer months.”

To bury the line, JCP&L brought in a special underwater trenching sled, marking the first time the technology was used by any FirstEnergy company. The sled used water jets at 150 pounds-per-square-inch pressure to blast a trench about one foot wide and 10 feet deep in which to lay the new power cables.

A large barge carried massive reels of armored submarine cable, hydraulic and water pumps, surveillance monitors, control systems, and other gear as it pulled the 12-ton, school bus-sized sled at rates up to 10 feet per minute. As the sled was pulled along the bottom of the bay, the trench simply collapsed behind it, leaving only a shallow depression marking the location of the line. The 5,800-foot crossing was completed in a matter of days.

JCP&L serves 1.1 million customers in the counties of Burlington, Essex, Hunterdon, Mercer, Middlesex, Monmouth, Morris, Ocean, Passaic, Somerset, Sussex, Union and Warren.