The blade tip, which is being developed in ORNL’s carbon fiber technology center, incorporates two layers each of standard glass fiber and a low-cost lab developed carbon fiber, with such customized conductive carbon fiber key to dispersing electrical energy across the blade surface.

The researchers also declare using industry-standard equipment and methods to show that the technology can be easily integrated with established manufacturing processes.

“We don’t have enough data to know the true scope of the challenge [of lightning strike damage], but we know it’s a concern to industry and utilities,” said ORNL researcher Vipin Kumar.

“We know wind energy is a reliable source of electricity that supports energy security, but I believe anything we can do to make it more resilient and reliable is important.”

Lightning strikes to wind turbine blades are known to be frequent but are rarely catastrophic.

Nevertheless, they are believed to be able weaken blades with internal damage that can translate to increased repair costs over time, and they are the second leading cause of blade-related downtime.

In the project an entire 2m turbine blade tip was built using the novel materials. This was then tested against the forces of simulated lightning in a specialized lab at Mississippi State University, where the blade tip emerged pristine after tests that isolated the effects of high voltage.

Separate tests in the same lab found that isolated high current remained destructive.

The cost of carbon fiber has generally limited its use to the wind blade’s load bearing structure, but ORNL’s efforts to lower the cost of carbon fiber may make it economical to replace glass fibers in the blade tip, where the lightning strikes most often.

With the demonstration highlighting the possibilities of a new approach to protecting blades using conductive materials or coatings, further innovations are being investigated.

With resin making up the largest portion of the blade tip, these include the use of a more conductive resin.

Another notable benefit of the hybrid carbon fiber composite blade tip is its weight, about 41% lighter than a pure glass fiber blade tip, opening the way for larger blades of the same weight, with the potential to generate more electricity.

The approach also is considered of potential for preventing lightning damage to the composites used in airplanes.

Originally published by Power Engineering International.

The news came out of the large power producer’s third-quarter earnings call last week.

Stacey Doré, Vistra’s Chief Strategy and Sustainability Officer, told investors the company was pursuing deals based around multiple plants in its portfolio. She said one approach being discussed would be pursuing co-location deals at multiple sites in combination with building new generation.

Doré said Vistra specifically in discussions with two large companies about building new gas plants to support a data center project. Gas plants in both PJM and ERCOT are drawing interest, she said.

The company is also in early discussions with some of the hyperscalers about nuclear uprates, Doré said. The hyperscalers are considered the companies that are predominately driving large-scale buildout of AI data centers, like Amazon, Google and Microsoft

The topic of co-locating large loads with generation facilities is not unique to Vistra. Earlier this month, the Federal Energy Regulatory Commission (FERC) rejected a revised Interconnection Service Agreement (ISA) proposal that would have allowed expanded co-located load at an Amazon Web Services (AWS) data center connected to Talen Energy’s Susquehanna Nuclear plant in northeast Pennsylvania.

While Vistra President and CEO Jim Burke said the company was disappointed with the FERC ruling, he said it hasn’t impacted conversations with potential customers.

“Nothing precludes us from moving on with our plans,” said Burke. “We will need to address open issues and find the path for approval of interconnection service agreements, which we believe is doable.”

In Vistra’s latest 10-Q, the company said it was seeing multiple electricity demand drivers in its service territories, including the emergence of large data centers and the electrification of oil field operations, specifically in the Permian Basin of west Texas.

Other macroeconomic factors

Vistra’s 10-Q noted continued supply chain constraints and labor shortages that have reduced the availability of certain equipment and supply relevant to construction of renewables projects.

These challenged increased the lead time to procure certain materials necessary to maintain its generating fleet, the company said. Labor costs have also gone up, Vistra said.

The company said it is proactively managing rising material costs and supply chain issues, while carefully reassessing the timing and business cases for our planned projects. This has resulted in a “deferral of some of our planned capital spend for our renewables projects,” the 10-Q reads.

Vistra said it has proactively engaged suppliers to secure key materials needed to maintain its fleet prior to future planned outages.

The company began implementing AI more than five years ago and is now leveraging the technology to support operational and environmental goals.

Key examples of the initiative include:

Energy Optimizer

• The Energy Optimizer tool leverages AI to provide real-time operational insights, which is meant to help control center operators make decisions about how to move the energy Enbridge transports in more efficient ways. By managing the amount of power required, Enbridge claims it can achieve cost savings and GHG reductions while ensuring the safe and reliable operations of its liquid pipelines.

Right of way monitoring

• Enbridge utilizes aerial surveillance to patrol its pipelines, detecting potentially damaging activities, conditions, or loss of containment. With AI, the company says it can now monitor the right of way more efficiently, reviewing data and detecting issues quicker and more accurately, reducing the risk of third-party damage.

Integrity Engine

• Enbridge employs intelligent automation for pipeline integrity, using AI to identify potential maintenance needs. Through workflow automation, data controls, advanced analysis, and machine learning models, the company said it now gains new insights for asset maintenance, enhancing safety and efficiency while reducing process complexity and maintaining the health of our assets.

“Our long-term collaboration with Microsoft has enabled us to apply cutting-edge technology, which is helping to solve critical business problems and deliver powerful outcomes,” said Bhushan Ivaturi, Senior Vice President and Chief Information Officer at Enbridge. “The investments we’re making today will play a critical role in enabling technological solutions to the biggest challenges in the evolution of our energy systems as we transition to a lower-carbon future.”

Enbridge began a “digital transformation” in 2020 to drive productivity and efficiency. At the core of this strategy was a technology foundation enabled by Microsoft.

This led to a cloud migration and modernization program, with over 80% of workloads moved to Microsoft Azure cloud platform within two years, Enbridge said. The company said this initiative enhanced computing, network, and storage capabilities, but also bolstered cybersecurity measures and reduced data center emissions through server decommissioning and a smaller physical facility footprint. Earlier this year, Enbridge rolled out Microsoft 365 Copilot to nearly one-third of all employees, while the entire workforce has access to Bing Enterprise and ChatENB, an internal chatbot using Azure OpenAI Service.

“The Enbridge leadership team drove a cloud-first strategy, a big bet that opened the door to a broader opportunity that positions Enbridge today to take full advantage of AI,” said Tom Kubik, Enterprise Commercial Multi-Industry Lead at Microsoft Canada. “We are proud of the work we’ve done together and are working towards our common goals of supporting a more connected and collaborative workforce and increasing data and analytics capabilities.” 

“Looking forward, we see ongoing opportunities and benefits of AI, in terms of data analytics, asset and process optimization, security, and cost and emissions savings,” said Ivaturi. “At Enbridge, we are enabling the accessibility, sustainability, and security of energy through applied technology and innovation, and our collaboration with Microsoft will continue to play a pivotal role in that.”

The initiative is taking place at EDF’s 3.6 GW Bugey Nuclear Power Plant in France, where Infinite Cooling’s technology will capture water from cooling tower plumes. Cooling towers, which are the largest consumers of water in nuclear plants, could benefit from this technology, which the companies expect to recover between 1% and 15% of the evaporated water depending on operating conditions.

The reclaimed water, which the companies noted for its high purity, can then be reused, which could reduce both water treatment costs and wastewater discharge.

The testing phase, running from August 2024 to March 2025, is taking place on a test setup at the Bugey Nuclear power plant and will assess the technology’s performance in multiple environments and measure the amount of water recovered, the quality of the reclaimed water, and the system’s operational impact. The Infinite Cooling team will oversee the process, with the intent of ensuring the solution meets the standards required for widespread adoption across EDF’s cooling tower network.

“Working closely with EDF marks a significant milestone for Infinite Cooling. Our mission is to address one of the most urgent challenges in industrial processes—water scarcity,” said Maher Damak, CEO and Co-Founder of Infinite Cooling. “The tests at Bugey are a pivotal step in demonstrating the power of our technology and its potential to enable sustainable water management in power plants worldwide.”

Infinite Cooling’s technology uses a process that captures fine water droplets in cooling tower plumes using an electrically charged collection mesh. This recovered water, which the company claims is more than 100 times purer than the circulating water in the cooling system, could reduce the need for water treatment and decrease wastewater discharge volumes, resulting in cost savings and enhanced environmental performance.

The primary goals of the testing are to quantify the amount of recoverable water, evaluate the quality of the reclaimed water for reuse within the plant, and gauge the technology’s impact on overall tower performance. Additionally, the project will gather insights to guide the large-scale deployment of the solution, considering installation and operational factors.

Some simple cycle design basics

Anyone who has flown in a modern commercial airliner has experienced the effects of combustion turbines. Jet engines, of course, generate thrust for flight, whereas in power units, the energy drives a stationary turbine to provide the mechanical energy for an electrical generator. An outlet duct and stack convey the turbine exhaust gas to atmosphere. Important components within the exhaust system include internally lined ductwork and stacks and silencers. Noise regulations are common for simple and combined cycle plants, as many facilities are located within or near residential areas.  Silencers reduce noise levels below local guidelines. Ducts also typically have an internal liner to inhibit transient heat transfer through the duct walls. 

The combustion products that power gas turbines reach very high temperatures, perhaps up to 2,700^o F. Even though much of this energy is utilized by the turbine generator (and to drive inlet air compressors), the exhaust gas temperature may still exceed 1,100^o F. The hot exhaust gas and the wide temperature ranges that occur from unit load cycling place much stress and wear on the outlet duct and internal components. Periodic inspections and maintenance are necessary to keep this equipment in reliable condition.   

The following list outlines critical outlet duct and stack maintenance issues that developed over time at the plant highlighted in this article:

• Repair of silencer baffles and support brackets
• Replacement of failed internally lined exhaust system sections
• Installation of new test ports (depending on condition and new silencer design)
• Repair of cracks in the casing

Solutions

Following a complete system survey, the maintenance contractor, SVI BREMCO, addressed each of these issues and others during a several-week maintenance outage. A primary task was to replace the silencer baffles and support brackets. SVI BREMCO replaced the traditional parallel baffle silencer design with a proprietary bar silencer design. The bar silencer design is very popular for simple cycle exhaust system retrofits because it provides better acoustics, reduces pressure drop (better turbine performance and project ROI), and optimizes aerodynamics (improving durability).

This work required coordination of multiple personnel, including equipment specialists, welders, crane operators and safety personnel. These specialists also installed new test ports and made duct liner repairs during the outage window.

Testports are critical for flue gas monitoring, including flow dynamics. Adjustments to test port location can often improve monitoring capabilities. Installation of new ports was a key part of this project, along with improved silencer design, as was the installation of liner material at these locations.

The maintenance crews also repaired duct/stack metal cracks in the casing. The peaking nature of simple cycle operation places much cyclic stress on liners, which in turn can cause cause liner failure and cracked casing. Cracks that breach welds or duct walls allow flue gas to escape. Once cracking begins, the damage typically continues to propagate.

Safety – The overall critical issue

No matter how competently maintenance personnel and contractors perform the work, the foremost concern is that everyone arrives home safely at the end of the day. A sampling of the topics discussed during SVI BREMCO safety meetings (conducted at the start of each shift) includes fall protection, electrical safety, hot work issues, and lock out/tag out (LOTO) procedures.  
 
Conclusion

Even though a large amount of the energy generated in a simple cycle power plant is converted to mechanical energy in the combustion turbine, the exhaust duct, duct liners, silencers, support brackets, and other components are still subject to harsh conditions. As with all equipment, these components degrade over time and require maintenance. SVI BREMCO has a highly experienced staff to evaluate and offer solutions for these and many other simple and combined cycle maintenance needs. Contact information is available on the company website.
 
Industrial Contracting Services for HRSGs- SVI BREMCO (svi-bremco.com)

About the Author: Brad Buecker is president of Buecker & Associates, LLC, consulting and technical writing/marketing. Most recently he served as a senior technical publicist with ChemTreat, Inc. He has many years of experience in or supporting the power industry, much of it in steam generation chemistry, water treatment, air quality control, and results engineering positions with City Water, Light & Power (Springfield, Ill.) and Kansas City Power & Light Company’s (now Evergy) La Cygne, Kan., station. His work has also included eleven years with two engineering firms, Burns & McDonnell and Kiewit, and he spent two years as acting water/wastewater supervisor at a chemical plant. Buecker has a B.S. in chemistry from Iowa State University with additional course work in fluid mechanics, energy and materials balances, and advanced inorganic chemistry. He has authored or co-authored over 250 articles for various technical trade magazines, and he has written three books on power plant chemistry and air pollution control. He is a member of the ACS, AIChE, AIST, ASME, AWT, CTI, the Electric Utility Chemistry Workshop planning committee, and he is active with the International Water Conference and POWERGEN International.

Our electric system is evolving at an unprecedented rate and scale. Placing tremendous pressure on traditionally stable processes are the acceleration of renewables penetration, onshoring of manufacturing and development of data centers feeding off AI’s growth.

While the demand for reliable and efficient power generation is booming, the supply side for new capacity continues to face an exceptional mix of challenges. Supply-chain constraints affecting the procurement of gas turbines, large transformers and high-voltage breakers, as well as the congested interconnection queues themselves, have expanded the timeline to bring new dispatchable generation online to new record lengths. 

The market has responded to this increased challenge of obtaining new generation capacity to meet demand by shifting the focus toward optimization of existing facilities. Power producers nationwide have aggressively invested in plant improvement projects to increase the reliability of their existing assets, multiply efficiencies and reiterate commitments to safety.

Efficiency upgrades to maximize output

Upgrades driven by the desire for increased efficiency are being implemented at a large scale across traditional generation facilities powered by coal, gas and nuclear. Many operators have been reviewing key plant infrastructure to identify bottlenecks where investments could improve the efficiency of the generating units. As an example, the implementation of inlet air fogging in simple-cycle plants has generated an output increase of 8% in certain markets.

The nuclear sector welcomed the demand for efficiency and performance upgrades by making large capital investments targeting significant plant uprates for aging facilities. In support of this increased output, owners have been assessing cooling towers, condensers and other plant systems to see that the facility can handle large increases in capacity. Upgrades like these not only extend the useful operating lives of the plants but also provide timely solutions to the power market challenges at hand.

Reliability enhancements to prepare for the unexpected

In the wake of severe weather conditions in recent years, the importance of maintaining reliability and keeping the lights on has never been more important. Winter Storm Uri, for example, caused devastating effects on the power grid in Texas and the lower Midwest, and many plants were unable to come online due to the lack of available natural gas.

As a result, an increased number of power producers have been evaluating options to retrofit their facilities with backup fuel options or black start capabilities to continue supporting communities through emergency situations. Black start units have gained traction in the Northeast, particularly, and have the power to bring a plant online without a grid connection. Retrofits that include backup fuels like diesel or liquefied natural gas also have the power to keep plants running during severe weather events when pipeline gas is not available; such projects gained traction mostly in the Midwest.

Safety improvements to protect workers and facilities

As part of these new investments into existing assets, many power generators have used the opportunity to reiterate a commitment to safety for their plant personnel. In older facilities, common projects include adding railings and access platforming to improve maneuverability for employees. Additionally, refreshed arc-flash studies, control upgrades and even switchgear replacements are being performed to strengthen electrical safety.

Maintaining the resilience and capability of the power grid is more critical and challenging today than ever before. Plant service and improvement projects have been a key solution for generators nationwide as they grapple with extended project timelines, increased service area demand and regulatory uncertainty.

Originally published by Burns & McDonnell.

About the Author: With a bachelor’s degree in electrical engineering from the University of Alabama, Albert Gabberty has experience as an electrical design engineer for gas-fired power plants and other heavy industrial facilities. He was involved in the engineering and construction of a natural gas reciprocating engine plant in Wisconsin. He leverages this experience in a business development role where he supports clients across the country in developing projects and advising on current market conditions.

One of the largest generators in the U.S., Vistra, tapped McKinsey & Company to develop a machine-learning model to improve the efficiency and emissions of the coal-fired Martin Lake Power Plant in Rusk County, Texas.

The effort began when Vistra wanted to build and deploy a heat-rate optimizer (HRO) for the plant. The company worked with McKinsey data scientists and machine learning engineers from QuantumBlack AI to build a “multilayered neural-network model,” or an AI-powered algorithm that learns about the effects of complex nonlinear relationships.

The team fed the model two years of plant data to see which combination of external factors and internal decisions could produce the optimal HRO for any given time. External factors included temperature and humidity, and internal decisions included variables that operators can control.

It wasn’t a “one-and-done” solution, though. Vistra’s team continued to provide guidance on how the plant worked and identified data sources from sensors, which McKinsey said helped its engineers refine the model by adding and removing variables to see how the heat rate changed.

Through the training process and “introducing better data,” the models eventually made predictions with 99% accuracy or higher. After running the model through a series of real-world tests, the engineers turned the model into an “AI-powered engine.” After implementing the engine, the plant’s operators received recommendations every 30 minutes on how to improve the plant’s heat-rate efficiency.

“There are things that took me 20 years to learn about these power plants,” said Lloyd Hughes, Vistra’s operations manager. “This model learned them in an afternoon.”

With higher efficiency came more carbon reduction. Martin Lake was running more than 2% more efficiently after three months of operating with the machine-learning tool, which McKinsey said resulted in savings of $4.5 million per year and 340,000 tons of abated carbon.

Following the success at the Martin Lake Power Plant, Vistra distributed the AI-enabled HRO to another 67 generation units across 26 plants, which resulted in an average of 1% improvement in efficiency, McKinsey said, in addition to more than $23 million in savings.

Overall, Vistra’s AI initiatives have helped the company avoid around 1.6 million tons of carbon per year, McKinsey said.

Read the full case study here.

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

Terry Schoenborn has certainly noticed this renewed interest, which he attributes to projected rising electricity demand from data centers and manufacturing.

“In the last 10 years, there hasn’t been as many new greenfield sites going in, but we’re starting to see some of that activity pick up,” said Schoenborn, who is Senior Vice President of Operations and Maintenance (O&M) at EthosEnergy.

This was just one trend discussed in a recent interview with Schoenborn, who highlighted the evolving market dynamics that are shaping plant O&M.

Plants are changing hands

Schoenborn told us there is a lot of Merger & Acquisition (M&A) activity right now in the power generation market, driven by factors like the Inflation Reduction Act and a renewed interest in reliable gas capacity.

“I just think it’s a dynamic market right now,” he said, “and there are opportunities for investors to take advantage.”

As assets flip, adaptation is important for EthosEnergy, which has operated more than 100 generation facilities (mostly gas) dating back to its inception in 2014.

For example, the company was recently awarded O&M contracts for six natural gas combined-cycle (NGCC) plants in Mexico. This was shortly after the Iberdrola-owned facilities were sold to private equity firm Mexico Infrastructure Partners (MIP).

When EthosEnergy takes over O&M for multiple, let alone six plants at once, the process of scaling up manpower and training can be challenging. The work starts with assessing the condition and staffing levels of those facilities.

Schoenborn said some plants EthosEnergy takes on are in good condition and others require more care and effort.

“We may have to have more resources, spend time at that plant to get it up to speed or the level that our customers expect,” said Schoenborn.

A plant’s condition often depends on where it is in its lifecycle and how much a customer thinks it can extract out of it, he said.

“It could be just as simple as, if the customer knew they were selling the asset, they are probably not going to invest as much into it,” he said. “So it just gets into disrepair.”

While EthosEnergy has close to 800 employees in its O&M division, the company has brought in approximately 100-150 just in the last two years as it has taken on new contracts.

The importance of peaking power

Gas turbines are taking an increasingly important role as peaking power sources, since they can be ramped up and down quickly to meet demand spikes, filling in gaps when renewable resources are not generating electricity.

For that reason EthosEnergy earlier this year launched its Houston-based Performance Center, where the company monitors generators in 20 different countries.

The center combines 24/7 remote start-stop capabilities with monitoring and diagnostics. EthosEnergy operators control start-stop operations through encrypted cyber-secure VPN technology. They can use video surveillance to monitor a customer’s assets using real-time thermal imaging.

Schoenborn noted a lot of peaking plants with low capacity factors are fully-staffed and operate almost on-call. He said using the performance center is a good solution to optimize the reliability of these assets that sit idle most of the time, and from a cost perspective.

“We felt like it was a something we needed to have to play in this market,” Schoenborn told us.

Schoenborn said the capabilities of the performance center have opened up new discussions with customers, particularly as the energy transition may run slower than anticipated.

As customers target aggressive net-zero goals, EthosEnergy works with them to develop realistic maintenance strategies. Schoenborn emphasized the importance of maintaining reliability without overinvesting in assets that could be repurposed or shut down in the near-future.

“How we’re working with them is saying, ‘Let’s really sit down and talk about what maintenance you need to have to make sure you maintain the same level of reliability,’” he said.

Watch the full interview with Terry Schoenborn above.

The Electric Utility Chemistry Workshop was organized in the early 1980s as a conference to provide solid, practical information about steam generation chemistry, makeup water and cooling water treatment, air emissions control, environmental regulations and other topics to power plant personnel in the Great Lakes region.

Direct utility participation and abundant networking opportunities were key features of the EUCW. These benefits attracted personnel from other parts of the country, and now, as the workshop emerges from the disruption of the pandemic, we are seeing more national and international participation, including this year from Power Engineering’s/POWERGEN International’s Kevin Clark. A heretofore somewhat overlooked benefit of this conference is its potential value for those employed at cogeneration and large industrial plants, as water/steam treatment issues cut across many industries.

The following discussion highlights several important topics from this year’s event. The positive response to the diversity of topics has the committee considering a rename of the conference to the Electric Utility and Cogeneration Chemistry Workshop (EUC²W).

Cooling water

Virtually all large industrial plants have multiple cooling water systems. While some large heat exchangers such as power plant steam surface condensers may be on once-through cooling, many cooling systems are of the open-recirculating design that have a cooling tower as the core heat discharge process.

A universal feature of cooling towers is that evaporation increases the dissolved and suspended solids concentration of the recirculating water, which requires a combination of blowdown and precise chemistry control to minimize scale formation and corrosion. (Sidestream filtration is a common, but not always employed method for suspended solids removal.¹) Furthermore, cooling systems provide an excellent environment for microbiological fouling that can cause extreme problems.

With the substantial aid of expert colleagues, this author has discussed cooling water treatment methods and program evolution numerous times during the last 15 years of the EUCW. Key points include:

• The very popular acid/chromate programs of the middle of the last century have disappeared due to concerns over the toxicity of hexavalent chromium (Cr⁶⁺).
• The primary replacement programs relied on inorganic and organic phosphates, with perhaps a small dosage of zinc, for scale and corrosion protection. However, calcium phosphate deposition became a major problem with these programs, requiring development of polymers to control this deposition. In recent years, concerns have dramatically grown about phosphate in cooling tower blowdown and its influence on receiving water bodies such as lakes and rivers. Phosphorus is a primary nutrient for algae growth in surface waters.
• The major water treatment companies have developed non-phosphorus (non-P) programs that rely on specialized organic compounds and additives to establish a direct barrier on metal surfaces to minimize corrosion. The formulations typically include advanced polymeric compounds for scale control.
• Microbiological fouling control continues to be of paramount importance. However, the higher pH (typically near or slightly above 8) of modern scale/corrosion control programs can reduce the efficacy of chlorine (usually fed as bleach) treatment. Alternative oxidizers such as chlorine dioxide and monochloramine may be more effective in these moderately alkaline environments. Periodic treatment with non-oxidizing biocides can also be beneficial. Careful evaluation is necessary for selection of the best treatment method. And, changes to a biocide feed program are not allowed without approval of the proper regulatory authorities.

Makeup water treatment

Makeup water treatment technology has evolved substantially in the last several decades. This section provides an overview of important developments, starting with a fundamental requirement for new projects and finishing with discussion directly related to co-generation and industrial applications.

Importance of comprehensive raw water analyses

One of this author’s important tasks for several years was review of proposed makeup water treatment configurations for new combined cycle power plants and other industrial facilities. Comprehensive, and ideally historical, raw water chemistry data is very important to correctly size and select treatment systems and treatment programs, but only on rare occasions did the design specs for new projects contain complete analyses. Even when a report offered comprehensive data, it was usually based on a single “snapshot” analysis. The chemistry of many supplies can change significantly over seasons and often after heavy precipitation, necessitating the need for more than a single analysis. Cases are known in which the original treatment system had to be replaced because it could not process the makeup water per improper design based on faulty or missing raw water quality data. Understandably, replacement costs were quite large.

Pretreatment system evolution

In the last century, clarification/sand filtration was a standard method for raw water suspended solids removal. Clarifiers were typically circular in shape and had a large footprint to allow the particles produced by coagulation and flocculation to settle into a sludge blanket within the outer clarifier zone. A common metric for clarifier operation is the rise rate, which is the ratio in gallons-per-minute of effluent divided by the surface area at the top of the clarifier. A reasonable rise rate for large circular clarifiers was around 1 gpm/ft². Periodic sludge blowdown is important to maintain the blanket at a proper depth.

Detailed discussion of clarifier evolution is beyond the scope of this article, but a modern clarifier technology, which utilizes microsand ballast that is recycled to the process, is shown in Figure 3.

An immediate observation is the rectangular nature of the unit and the inclined plates (lamella style) to improve floc settling. A key feature is the use of microsand to enhance floc formation, with sand recovery and recycle in hydrocyclones. Rise rates of 25 gpm/ft² or greater may be possible in such units, greatly reducing the footprint.

It should be noted that other similar systems have appeared. A prime example is Xylem’s CoMag® process with a ballast material of the iron oxide, magnetite (Fe₃O₄). This process has emerged as a treatment method for some industrial wastewaters containing heavy metals, where some metals co-precipitate with magnetite and are directly removed from solution.

Yet another twist to makeup water treatment is the increasing use of alternative sources, most notably municipal wastewater treatment plant effluent, for industrial plant makeup. These waters may require additional treatment equipment such as membrane bioreactors (MBR) or moving-bed bioreactors (MBBR) to reduce the concentrations of microbiological nutrients and food.^{1, 3}

Advancements in high-purity water production for utility boilers

When this author began his career in the early 1980s, a very common method for high-purity makeup production for utility boilers was pretreatment by clarification/filtration followed by ion exchange (IX) for dissolved solids reduction to part-per-billion (ppb) concentrations. The typical but by no means exclusive IX arrangement was strong acid cation (SAC)-strong base anion (SBA)-mixed bed (MB). This process proved effective, but service runs were relatively short, especially with feed water having high dissolved solids concentrations. An outcome was frequent IX resin regenerations that consumed significant quantities of acid and caustic.

Within the last four decades, the membrane technology of reverse osmosis (RO) has evolved and become quite mature. RO membranes can remove 99% of dissolved solids, which made them ideal for retrofit at plants with IX units and excellent as the core demineralization process in new makeup systems. Also emerging during this time period was membrane-based micro- and ultrafiltration (MF and UF, respectively) pretreatment technology.

In many cases, these units can replace clarifiers/filters for suspended solids removal of RO feed water. (The author once initiated a project to replace an aging clarifier with MF at a former power plant, and the unit performed superbly.) Accordingly, a common makeup water configuration for modern combined cycle power plants is MF (or UF) / RO / MB polishing. Popular is an arrangement that includes mixed-bed portable units, aka “bottles,” that an outside vendor swaps out and regenerates at their facility.

Paradoxically, makeup water treatment for low pressure boilers (<600 psig) may be more troublesome than for high-pressure units, but the difficulties can be mindset- rather than technology-based. Because low-pressure boilers have reduced heat fluxes as compared to utility boilers, makeup quality requirements are more relaxed.⁴ Critical, however, is hardness removal to minimize the potential for scale formation. Ion exchange sodium softening, sometimes with downstream dealkalization, has been a popular technique for decades. Sodium softeners are straightforward to operate, and resin regeneration only requires simple brine solutions.

Unfortunately, way too many cases are known where plant management has focused on process chemistry and engineering to the neglect of water treatment support, both from an infrastructure and staffing perspective. Periodic softener upsets (and sometimes complete unit failure) allow hardness excursions. Figure 4 illustrates one outcome.

One of the first items a consultant often examines when called in to investigate boiler tube failures is softener operating history. Further information is available in references 3 and 5.

Cogeneration presents a wild card with condensate return

One other major issue exists when comparing cogeneration/industrial boiler operation to utility units. The water/steam path for fossil-fired power boilers is usually straightforward. Steam produced in the boiler and superheater/reheater drives a turbine to generate electricity. The turbine exhaust steam is condensed in a water-cooled (or perhaps air-cooled) condenser, with the condensate returning directly to the boiler. The condensate and steam typically remain pure unless a condenser cooling water leak, or, more rarely, a makeup water system upset, introduces contaminants. The situation is often quite different at co-generation and large industrial plants, where condensate may come from a variety of heat exchangers and processes. Impurities can potentially include inorganic ions, suspended solids, acids and alkalis, and organic compounds.

Depending on the intermediate and final products that circulate through process heat exchangers and reaction vessels, a wide variety of compounds can potentially enter the condensate. These impurities include inorganic ions, acids and bases, suspended solids, and organics. The author once visited a chemical plant where organic contamination of the condensate return caused foaming in four, 550 psig package boilers, which in turn required frequent and costly superheater replacements.

Several possibilities may be available to minimize impurity transport from condensate to steam generators. The root cause solution is to repair heat exchanger leaks and eliminate problems at the source. This may be easier said than done given that large plants can have dozens if not hundreds of heat exchangers with complicated configurations.

Condensate polishing is a viable option in some cases. For example, ion exchange is a mature technology for removing inorganic ions from condensate (it is an absolute requirement for protecting supercritical power boilers). Activated carbon may perhaps be effective for some organic compounds, but molecular size, presence of active groups, and other factors can influence the reactivity of the organics towards carbon. Laboratory and pilot testing are often needed to determine the viability of activated carbon polishing.

Sometimes necessary (and as Figure 4 includes) are automatic dump valves that, as the name implies, dump the condensate to drain if on-line instrumentation detects contaminant ingress. Of course, condensate dumping requires increased makeup water production and it adds to the load on a plant’s wastewater treatment system.

A key takeaway from this section is that while several solutions may be available to protect boilers from condensate contamination, careful analysis and testing is necessary to determine the proper solution. But the investment can pay for itself many times over.

Conclusion

Many industries face water/steam treatment issues that are well known in the power industry. The EUCW is a place to hear presentations and participate in valuable discussions about these issues and modern technologies to address them. Because I am also actively involved with POWERGEN International, I hope to address several of these topics at PGI 2025 next January.

References

1. Water Essentials Handbook (Tech. Ed.: B. Buecker). ChemTreat, Inc., Glen Allen, VA, 2023.  Currently being released in digital format at https://www.chemtreat.com/.
2. R. Post, B. Buecker, and S. Shulder, “Power Plant Cooling Water Fundamentals”; pre-conference seminar for the 37^th Annual Electric Utility Chemistry Workshop, June 6, 2017, Champaign, Ill.
3. B. Buecker and E. Sylvester, “Foundational and Modern Concepts in Makeup Water Treatment”; pre-conference seminar for the 42^nd Annual Electric Utility Chemistry Workshop, June 4, 2024, Champaign, Ill.
4. Consensus on Operating Practices for the Control of Feedwater and Boiler Water Chemistry in Modern Industrial Boilers, The American Society of Mechanical Engineers, New York, NY, 2021.
5. E. Sylvester, “Makeup Water Treatment Processes – Ignore at Your Peril”; presentation at the 42^nd Annual Electric Utility Chemistry Workshop, June 4-6, 2024, Champaign, Ill.

About the Author: Brad Buecker is president of Buecker & Associates, LLC, consulting and technical writing/marketing. Most recently he served as a senior technical publicist with ChemTreat, Inc. He has many years of experience in or supporting the power industry, much of it in steam generation chemistry, water treatment, air quality control, and results engineering positions with City Water, Light & Power (Springfield, Ill.) and Kansas City Power & Light Company’s (now Evergy) La Cygne, Kan., station. His work has also included eleven years with two engineering firms, Burns & McDonnell and Kiewit, and he spent two years as acting water/wastewater supervisor at a chemical plant. Buecker has a B.S. in chemistry from Iowa State University with additional course work in fluid mechanics, energy and materials balances, and advanced inorganic chemistry. He has authored or co-authored over 250 articles for various technical trade magazines, and he has written three books on power plant chemistry and air pollution control. He is a member of the ACS, AIChE, AIST, ASME, AWT, CTI, the Electric Utility Chemistry Workshop planning committee, and he is active with the International Water Conference and POWERGEN International.