Vineyard Wind said it has obtained federal approval to resume construction of the wind farm – work that was suspended following the partial collapse of a previously installed turbine blade on July 13.

A press release issued at 7 a.m. Tuesday morning said the Bureau of Safety and Environmental Enforcement had given the developers of the wind farm permission to resume the installation of towers and nacelles (which sit atop the tower and convert wind energy into electricity), but a suspension remains in effect for turbine blades and power generation.

Vineyard Wind is a 62-turbine project and only 24 had been completed at the time of the accident. Work is resuming on the remaining 38 turbines but blades cannot be installed nor power produced under the terms of the revised suspension order. Of the 24 completed turbines, 11 were generating electricity at the time of the incident and 13, including the one that broke, were undergoing testing.

In a joint press release, Vineyard Wind and GE Vernova, the manufacturer of the wind turbines, said a barge departed the New Bedford Marine Commerce Terminal Tuesday morning for the wind farm carrying turbine components, including several tower sections and one nacelle.

“The vessel will also carry a rack of three blades solely for the purpose of ensuring safe and balanced composition for the transport,” the press release said, adding that the blades will not be installed and will be returned to New Bedford later in the week.  

The press release said the Bureau of Safety and Environmental Enforcement revised its suspension order after examining records and a structural load analysis conducted by a third party. The federal agency had no mention of a revised suspension order on its website Tuesday morning.

Vineyard Wind and GE Vernova also said “a substantial amount” of what remained of the damaged blade was cut away on Sunday and Monday.

“During the operations, Vineyard Wind and GE Vernova mobilized maritime crews on multiple vessels nearby to secure as much debris as possible for immediate containment and removal as well as land-based crews managing debris recovery,” the press release said. ”Vineyard Wind and GE Vernova are currently assessing next steps to complete any additional cutting necessary at the earliest opportunity, secure and remove the debris on the turbine platform, remove the blade root, and address the debris on the seabed.”

The blade incident at Vineyard Wind, a joint venture of Avangrid and Vineyard Offshore, has been a major setback for the first industrial scale wind farm in the United States. Foam and fiberglass from the turbine has washed up on Nantucket and other beaches on the Cape and Martha’s Vineyard and raised questions about wind energy at a time when the industry is trying to ramp up production.

A preliminary investigation by GE Vernova has suggested the blade breakdown was caused by a “manufacturing deviation” – specifically insufficient bonding of the blade materials. The company has indicated no problems with the design of the Haliade-X blade, which is 853 feet tall.

It was unclear when Nantucket officials were notified about the resumption of construction of the wind farm. Updates posted on the town website indicated the Select Board was aware of the efforts beginning on Sunday to remove more of the damaged turbine blade.

During an executive session on Thursday, the Select Board met to discuss “strategy with respect to potential litigation in connection with Vineyard Wind,” according to the agenda.

This article first appeared on CommonWealth Beacon and is republished here under a Creative Commons license.

In their Q3 2024 results, the company announced an improved cash outlook, citing increasing demand for their grid and gas turbine businesses. Gas Services’ orders more than doubled year-over-year.

Specifically, Siemens Energy reports a new record for their order backlog at €120 billion ($131 billion) and revenue growth of 18.5%, with substantial growth in Grid Technologies, Transformation of Industry and Siemens Gamesa.

Commenting in a release, Siemens Energy’s president and CEO Christian Bruch attributed the positive backlog to increases in global energy consumption, which has resulted in demand and growth for their businesses.

Last year, the German government assisted with a counter-guarantee to support the company after their net loss of €4.5 billion ($5 billion) for the 2023 fiscal year, primarily due to the company’s ailing wind division, Siemens Gamesa.

For Q3 this year, the company reported a net loss of €102 million ($111.3 million).

Said Bruch: “The rapidly growing electricity market requires a wide range of our products. Especially our grid and gas turbine businesses are benefiting from this momentum.

“Importantly, with growing our order backlog, we have been able to improve its margin quality as well. Despite all the challenges, we are optimistic about the future and after the first nine months, we are well on track to meet our full-year guidance.”

Looking ahead, the company expects to achieve comparable revenue growth of 10 to 12% and free cash flow pre tax in a range of €1 billion ($1.1 billion) to €1.5 billion ($1.6 billion) for the fiscal year.

Said Bruch during a press conference call: “…quarter by quarter, we’re making headway. It’s not exciting, but it’s what we want to achieve.

“We expect that the global demand for power will continue to grow in addition to population growth and more electrification.”

Additionally, stated Bruch, new markets are opening up with the potential for growth: “New additional markets contribute to this. One topic, which is currently discussed everywhere is the power need for data centers – they make up a considerable part of our inquiries.

“And for the future, this means potential growth.”

Originally published by Power Engineering International.

Please visit us at www.prometheusgroup.com

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Problem: Steam turbines generate most of the world’s electricity, and approximately 42% in the US_[1]. Keeping them in operation is vital. Condensation in the low-pressure stage can result in corrosion pitting and corrosion fatigue. These failure mechanisms are two of the most common factors impacting repair and operating expenses. When cracks begin forming at the site of these mechanisms, the component, often a blade, must be replaced. Between the actual component replacement cost and the downtime required, the replacement process can cost millions of dollars. Sometimes replacement blades are new, but they’re often refurbished blades that have been weld-repaired and returned to service. This leads to the recurrence of many failures as condensation and resulting corrosion damage usually form in the same areas_[2].  

The primary way to address corrosion damage is by minimizing the chance of it forming. Martensitic stainless steels are often utilized in the production of parts because of the mild corrosion resistance offered by chromium_[3]. Coatings are commonly applied to provide further resistance. Shallow compression is provided by shot peening. Operators attempt to control the chemistry of the vapors entering the steam turbines to minimize impurities_[4]. All of these efforts offer protection, albeit with some disadvantages. Resistance through material selection is mild. Coatings wear over time and eventually require re-application. Surface damage can easily penetrate the relatively shallow layer of compression provided by shot peening. Ridding the vapors of impurities is challenging and offers no guarantee that corrosion will not still form.

Solution: Engineered compression has been proven to significantly improve the damage tolerance of many materials and components. This study examines the use of deep-engineered compression to combat corrosion pitting and corrosion fatigue in Alloy 450, a martensitic stainless steel widely employed in steam turbine blade manufacturing.

Specimen Design

Fatigue specimens were specially designed to test the benefits of compressive residual stress in 4-point bending. Samples were finished machined using low stress grinding (LSG). To simulate surface damage from any source (handling, FOD, corrosion pitting, or erosion), a semi-elliptical surface notch with a depth of a_o = 0.01 in. (0.25 mm) and surface length of 2c_o = 0.06 in. (1.5 mm) was introduced by electrical discharge machining (EDM). EDM produces a pre-cracked recast layer that is in residual tension at the bottom of the notch, producing a large fatigue debit with a high k_f.

Processing

Low plasticity burnishing (LPB®) was selected to impart the engineered compression due to the depth and stability of compression, as well as the ease of application. Process parameters were developed to impart a depth and magnitude of compression on the order of 0.04 in. (1 mm), sufficient to mitigate the simulated damage. Figure 1 shows a set of eight fatigue specimens in the process of being low plasticity burnished on the four-axis manipulator in a CNC milling machine.

Testing

Active corrosion fatigue tests were conducted in an acidic salt solution containing 3.5 wt% NaCl (pH = 3.5). At the start of cyclic loading, filter papers soaked with the solution were wrapped around the gauge section of the fatigue test specimen and sealed with a polyethylene film to avoid evaporation. There was no exposure to the corrosive solution before the fatigue tests. LPB and LSG baseline samples were tested with and without EDM damage. A few LPB samples were tested with increased damage levels of 2x to analyze the treatment’s effectiveness with deeper damage.

X-ray diffraction residual stress measurements were made to characterize the residual stress distribution from LPB. The results of these measurements are shown in Figure 2. Maximum compression is nominally -140 ksi (-965 MPa) at the surface, decreasing to zero over a depth of about 0.035 in. (0.89 mm). The corrosion fatigue performance in acidic NaCl solution is shown in Figure 3. The LSG baseline condition is compared with LPB with and without the EDM notch. With no notch, the baseline fatigue strength at 10⁷ cycles is nominally 100 ksi (689 MPa). The 0.01 in. (0.25 mm) deep EDM notch decreases the baseline fatigue strength to approximately 10% of its original value. The fatigue lives at higher stresses show a corresponding decrease of over an order of magnitude resulting from the notch. Unnotched LPB processed samples have a fatigue strength of about 160 ksi (1100 MPa). The notch had a marginal effect on the LPB fatigue strength, reducing it to 125 ksi (862 MPa), well above the fatigue strength of the undamaged baseline specimens. LPB-treated samples containing the 2x damage depth had fatigue lives comparable to undamaged LSG specimens within the limits of experimental scatter.

Conclusion

LPB imparted highly beneficial compressive residual stresses on the surface, sufficient to withstand pitting and/or surface damage up to a depth of nominally 0.02 in. (0.51 mm). LPB resulted in more than a 50% increase in corrosion fatigue strength without surface damage and a 12x increase in strength with 0.01 in. (0.25 mm) deep damage. The depth and magnitude of surface compression are responsible for improving fatigue strength.

The application of LPB effectively enhances corrosion damage tolerance, as shown by the improved fatigue strength even in the presence of simulated damage. The process has been used successfully in many power applications since the early 2000s. Implementing engineered compression with LPB significantly improves the durability and performance of steam turbine components, ultimately reducing costs associated with maintenance and downtime.

References

[1] US Energy Information Administration, “How Electricity is Generated.” https://www.eia.gov/energyexplained/electricity/how-electricity-is-generated.php October, 2023.

[2] R. Ravindranath, N. Jayaraman & P. Prevey, “Fatigue life Extension of Steam Turbine Alloys Using Low Plasticity Burnishing (LPB).” Proceedings of ASME Turbo Expo 2010: Power for Land, Sea and Air. Glasgow, UK, June 14-18, 2010.

[3] A. Rivaz, S.H. Mousavi Anijdan, M. Moazami-Goudarzi, “Failure Analysis and Damage Causes of a Steam Turbine Blade of 410 Martensitic Stainless Steel After 165,000 H of Working.” Engineering Failure Analysis, Volume 113, 2020.

[4] Zhou, S, Turnbull, A, “Steam Turbine Operating Conditions, Chemistry of Condensates, and Environment Assisted Cracking – A Critical Review.” NPL Report MATC (A) 95, May, 2002.

About the Author: As Research Engineer for both the Surface Integrity and Process Optimization (SIPO) laboratory and the Corrosion Characterization laboratory at Lambda Research, Kyle Brandenburg is part of a team responsible for providing materials testing solutions to clients. Additionally, the SIPO and Corrosion labs conduct in-house research and testing pertaining to the surface enhancement and optimization of materials and components. Laboratory capabilities include high and low cycle fatigue studies, DC electrochemical corrosion testing, stress corrosion cracking, and supporting capabilities like hardness testing, heat treating, SEM and metallographic analysis, and shot peening.

kbrandenburg@lambdatechs.com

www.lambdatechs.com

With coal plants retiring, the intermittent availability of renewable solar and wind energy, and data centers and artificial intelligence capabilities expanding, it’s clear that the U.S. is in need of reliable energy sources. Utilities face the complex challenge of firming capacity to continue to provide consistent services. 

Dispatchable, reliable power is crucial, but several obstacles complicate the issue, including the limited availability for procurement of gas turbines and gas engine-driven compressors; limitations of regional gas capacity; unpredictability of weather that can affect the availability of renewable energy sources, and the lengths of permitting processes. Understanding where greater energy capability is needed and what solutions might be available is the first step. There are a variety of options available to help firm capacity.

Compressor Stations

Compressor stations are facilities located along natural gas pipelines that compress the gas to maintain pressure and provide for continuous gas flow at the required delivery points. Increasing the number of compressor stations, or upgrading existing ones, can enhance the capacity and reliability of a natural gas network system. This is particularly useful in regions where the gas supply might be constrained.

While new compressor stations and pipelines face many regulatory hurdles, such stations offer a reliable solution to improve natural gas delivery. The increased capacity that comes with using compressor stations can help meet rising power demands without the need for entirely new pipelines.

Dual Fuel

Dual fuel systems allow power plants to switch between natural gas and an alternative fuel, typically diesel or oil. This flexibility can be invaluable during times of gas supply constraints or price spikes. A dual fuel system provides an immediate backup fuel source, allowing for continuous power generation.

Such systems enhance reliability and operational flexibility, reduce the risk of power outages and enable effective management of fuel costs. The systems may also require additional storage and handling facilities for the secondary fuel, which can drive up costs related to implementing the solution.

LNG Peak Shavers

LNG peak shavers are facilities that store liquefied natural gas (LNG) and can quickly vaporize and inject it into a natural gas pipeline during peak demand periods. These facilities produce LNG during periods of low natural gas demand, such as the summer months, allowing utilities to manage the cost of gas and power for customers. LNG peak shavers provide a buffer during periods of high demand, keeping the gas supply steady even when demand spikes unexpectedly.

The benefits that LNG can provide with a continuous gas supply during peak periods and enhanced system stability are hard to ignore. LNG can be stored and vaporized in a stand-alone facility, either connected to a pipeline or directly feeding an existing power generation station. If stored and vaporized in a stand-alone facility, the LNG is delivered via trucks rather than produced on-site.

Hydrogen

Hydrogen can be used as a fuel for power generation, either blended with natural gas or used in dedicated hydrogen turbines. Hydrogen is often a clean energy source that can significantly reduce greenhouse gas emissions. Hydrogen also can come from various sources, including renewable solutions, providing a versatile and sustainable option.

Hydrogen currently has high production costs and requires significant infrastructure development before operations can begin. However, the solution offers the hope for greater energy security through the diversification of fuel sources and the possibility of long-term energy sustainability.

Meeting the Demand

Firming generation in the face of changing power demands and shifting energy landscapes requires innovative solutions and strategic planning. Compressor stations, dual fuel systems, LNG peak shavers and hydrogen each offer unique benefits and challenges. By carefully considering these options, utilities can enhance stability and reliability while meeting the growing energy needs of the future.

Originally published by Burns & McDonnell.

About the Author: Sara O’Dell, PE, is an associate project engineer with nearly 20 years of engineer-procure-construct (EPC) project execution experience, spending the last 15 years working on LNG projects using both liquefaction and regasification processes for onshore and floating installations.

Top officials at GE Vernova said they believe a “manufacturing deviation” at a facility in Canada is the likely cause of a turbine blade breakdown at Vineyard Wind 1 that resulted in foam and fiberglass washing up on Nantucket.

Scott Strazik, the CEO of GE Vernova, said there is no indication of an engineering design flaw with the turbine blade. He said the company is re-inspecting all of the 150 blades that have been manufactured at a plant in Gaspe, Canada, to see if the problem occurred with other blades.

Strazik said the deviation — later identified as a “insufficient bonding” — should have been caught during the company’s quality assurance process. He said the re-inspection process will rely on ultrasound and other techniques to identify any problems. The Vineyard Wind 1 project will remain on pause while the investigation of what went wrong with the blade is conducted.

“I have a high degree of confidence we can do this,” Strazik said in a call with financial analysts in connection with the company’s second quarter earnings release. “We’re not going to talk about the timeline today. We have work to do.”

Strazik added: “We are going to be thorough instead of rushed.”

In a filing with the Securities and Exchange Commission, GE Vernova appeared to take full responsibility for the situation and the suspension of construction at Vineyard Wind 1 ordered by the US Bureau of Safety and Environmental Enforcement, or BSEE.

“We do not have an indication as to when BSEE will modify or lift its suspension order,” the filing states. “Under our contractual arrangement with the developer of Vineyard Wind, we may receive claims for damages, including liquidated damages for delayed completion, and other incremental or remedial costs. These amounts could be significant and adversely affect our cash collection timelines and contract profitability. We are currently unable to reasonably estimate what impact the event, any potential claims, or the related BSEE order would have on our financial position, results of operations, and cash flows.”

Strazik said the Cambridge-based company is continuing to install turbines at the Dogger Bank wind farm in the United Kingdom, which is using the same 13-megawatt Haliade-X turbines as Vineyard Wind 1. Previously, one of the blades there broke but that was blamed on a faulty installation.

The Nantucket Select Board met in executive session on Tuesday to discuss a legal strategy going forward with GE Vernova, the manufacturer of the turbines, and the wind farm developers, Avangrid and Copenhagen Infrastructure Partners. The board is expected to hold a public meeting where the situation will be discussed Wednesday evening.

This article first appeared on CommonWealth Beacon and is republished here under a Creative Commons license.

A battle over the state’s energy future resumes Wednesday with utility regulators hosting a hearing on Georgia Power’s plans to significantly expand fossil fuel generation over the next several years.

The Public Service Commission has scheduled hearings starting Wednesday for Georgia Power’s application to fast track the construction of three methane gas-burning units at Coweta County’s Plant Yates in order to meet increasing demands in the next decade.

Wednesday’s hearing will feature testimony and cross-examination of Georgia Power officials, PSC staff analysts and experts representing clean energy groups. The hearing would resume on Thursday if the five member commission finds it necessary. There will be another opportunity for the company’s lawyers, environmentalists and consumer watchdogs to make their case to a PSC committee on Aug. 15, prior to the commission’s vote on the proposed Yates expansion scheduled Aug. 20.

The Plant Yates expansion was among the major changes approved in 2023 to Georgia Power’s three-year strategic plan, which was approved by the five-member commission in a 4-1 vote April 16. The utility company’s revised outlook also calls for bringing more renewable energy online with the addition of a total of 1,000 megawatts of solar capacity with battery storage by early 2027 and the extension of purchasing agreements in Florida for natural gas, and with Mississippi Power, a subsidiary of Georgia Power’s parent company Southern Co.

Yates expansion opponents argue that adding more polluting fossil fuels that will be in operation for nearly 50 years will do more long-term harm to public health and the environment than clean energy alternatives. Several environmental groups criticized the company for avoiding a competitive bidding process, which could result in ratepayers paying more for the projects to be built.

Plant Yates opened as a coal-fired electricity generating plant in 1950 and operated until five of the seven units were retired in 2015 and the other two were converted to natural gas.

Georgia Power officials have argued that the Yates gas generators project needs to be fast tracked in order to meet the growth of massive data centers that continue to proliferate, primarily around metro Atlanta. The new energy sources are being promoted as a way to keep attracting companies building state-of-the-art facilities that operate around the clock to support data storage and artificial intelligence technology.

The debate over Georgia Power’s utility rates has intensified over the last several years as customers faced hikes in electric base rates and paid for soaring fuel costs, coal ash cleanup and construction overages at Plant Vogtle. The average Georgia Power residential bill will jump a total of $44 a month over two years, including $16 to pay for spikes in methane gas and coal costs.

An expert witness for the Sierra Club and Southern Alliance for Clean Energy is urging the five PSC commissioners to delay the Yates certification until a new fuel recovery policy ensures that Georgia Power customers don’t have to pay 100% of the expansion costs.

“In order to serve the public interest, the commission is obligated to create the proper incentives so that major risks to the cost of the electricity market are optimized by the parties who have the information and power  to make those decisions,” wrote Albert Lin, a California based economic and financial consultant, in June 21 testimony.

The potential $3 billion costs to implement the three-year plan update, of which approximately half is alloted for Yates’  new units, has also raised concerns about how the burden would be split between residential and small business customers versus large commercial manufacturers.

Georgia Power officials also say the company will not seek to recover from its customers any construction costs overruns, unless it’s caused by events beyond the company’s reasonable control, such as natural disasters. The terms of  the revised resource plan stem from a stipulated agreement between Georgia Power, PSC staff, and various organizations such as consumer watchdog Georgia Watch, MARTA, the Georgia Association of Manufacturers and the Southern Renewable Energy Association.

Throughout the IRP update process, the PSC members have acknowledged that the Yates expansion would play a crucial role in meeting the energy demand to support Georgia’s “extraordinary growth”, according to Jeffrey Grubb, director of resource and planning for Georgia Power, and Michael Bush, director of generation development for Southern Co.

“The expedited certification of Yates 8-10 (units) is a necessary part of the company’s commitment to continue serving our customers reliably and cannot be delayed,” their July 10 rebuttal testimony says.

Georgia Recorder is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Georgia Recorder maintains editorial independence. Contact Editor John McCosh for questions: info@georgiarecorder.com. Follow Georgia Recorder on Facebook and X.

The study, Investigation of potential sites for coal-to-nuclear energy transitions in the United States, ranks the feasibility of converting 245 operational coal power plants in the US into advanced nuclear reactors, a strategy being considered by electric utilities and the Department of Energy.

Converting coal plants into nuclear power plants allows for the same generation of stable, base-load power, but with less emissions. Also, the new nuclear plants can utilize the existing infrastructure, such as transmission lines and provide an economic boost for areas reliant on coal plants for jobs.

“With no new coal plants planned and many utilities aiming to retire all coal power plants within 15 years in the US, transitioning to cleaner energy sources is crucial,” said Md Rafiul Abdussami, a doctoral student of nuclear engineering and radiological sciences at U-M and corresponding author of the study published in Energy Reports.

The data set was generated using a tool called ‘Siting Tool for Advances Nuclear Development‘ co-developed by the University of Michigan, Argonne National Laboratory, Oak Ridge National Laboratory and the National Reactor Innovation Center.

The tool allowed researchers to factor in several variables to select the most feasible locations. These factors include safety, nearby population, regulatory situation, and socio-economic factors.

The results revealed the most feasible locations for transitioning from coal to nuclear, as well as the opportunities and challenges for each location.

For example, researchers identified that the R M Schahfer coal plant in Indiana emerged as the most feasible smaller electric capacity site, while the AES Petersburg plant in Indiana was top-ranked among the larger electric capacity sites.

“This data set can support economic revitalization plans in regions affected by coal plant closures and provide information for engagement efforts in coal communities considering hosting clean energy facilities,” said Aditi Verma, assistant professor of nuclear engineering and radiological sciences at U-M and senior author of the study.

Policymakers and utilities can use the study findings to guide strategic planning and investments, ensuring a smoother transition from coal to nuclear, while maximizing grid stability.

“My hope is that this work, which looks at the potential for coal-to-nuclear transitions in a very granular way, for each coal plant across the country, can inform the national and state-level conversations that are unfolding in real time,” Verma said.

According to Kirsty Gogan, co-founder and managing partner of TerraPraxis and co-founder Eric Ingersoll, repowering existing coal plant infrastructure is the largest single carbon abatement opportunity on the planet, which will sustain jobs and community tax revenues associated with existing coal plants

Repowering coal fleets “offers a fast, low-risk, large-scale and equitable contribution to decarbonizing the world’s power generation”.

Originally published by Pamela Largue in Power Engineering International.

The Phoenix (Performance Hydrogen Engine for Industrial and X) project, which is funded with almost €5 million ($5.4 million) by the German government, is aimed to generate the same electrical and thermal energy as currently available through natural gas CHP units in the higher power range of up to 2.5 MW.

When fueled by green hydrogen, this next-generation stationary energy plant, expected to be a first of its kind, should be able to run in a completely carbon-neutral manner.

“We are convinced that combustion engines will remain an essential part of the provision of a reliable energy supply during the energy transition,” said Dr Jörg Stratmann, CEO of Rolls-Royce Power Systems.

“We are making them climate-friendly with sustainable fuels. That’s why we at Rolls-Royce are investing in the development of next-generation hydrogen engines.”

The Phoenix project is being undertaken by a consortium including the sustainable mobile propulsion systems group at the Technical University of Munich, MAHLE Konzern, Fuchs Lubricants Germany GmbH, the German Federal Institute for Materials Research and Testing (BAM) and Robert Bosch AG.

The joint project is scheduled to run for three years to develop a technology concept that is sufficiently mature for use in a complete prototype engine.

Rolls-Royce already has developed a gas-powered combustion mtu engine which can use hydrogen as a fuel, but the Phoenix project will develop the technology for an even more efficient next generation hydrogen engine.

New developments from the partners include the injection system, the piston group and the ignition system, as well as a completely new lubricant.

Rolls-Royce reports that the German government as part of its power plant strategy, which includes the expansion of renewable energies, has decided in favor of building more gas-fired power plants to compensate for the variability of renewable resources – in particular, smaller, decentralized gas engine plants that can flexibly compensate for the fluctuating feed-in of wind and solar power to the grid, which varies depending upon weather conditions.

To reduce CO2 emissions, biogas gensets and, in some cases, the first gas engines converted for hydrogen are currently being used. But as soon as the availability of green hydrogen is ensured on a large scale, the technology of the hydrogen cogeneration plants promoted in the Phoenix project should be ready for use.

Originally published by Power Engineering International.