For thermal power plants, this scaling is an expensive problem. It inhibits heat transfer and flow performance, negatively impacting plant operations. Researchers at ETH Zurich say scale buildup just 1 millimeter thick in heat exchanger pipes can lead to efficiency losses of approximately 1.5%.

But after studying the physics of microfouling adhesion, researchers say a possible solution comes in the form of a hydrogel-based coating with tiny ridges aimed at preventing the adhesion of crystals.

A joint research team from ETH Zurich and the University of California, Berkeley has been studying the effectiveness of such a coating under a European Research Council Grant. The study, led by former ETH Zurich professor Thomas Schutzius (now at UC Berkeley), began in 2019.

Experimenting with water content and microtexture

The research team began examining the interactions among growing crystals, the surrounding water flow and the surface at the microscopic level. They developed and tested several coatings from various soft materials.

“So far, not a lot of people looked into soft coatings,” said Julian Schmid, a PhD Student at ETH Zurich and a study author. “We started to have a look at silicones. But then we thought, let’s try hydrogels.”

Researchers experimented with different coating properties, primarily altering the polymer content. They found the lower the polymer content and the higher the water content, the less well calcium carbonate crystals adhered to the surface.

“We’re talking about lubricating the interface between the crystals and the coating,” said Schmid, in an interview with Power Engineering.

The hydrogel’s surface is also notably covered in tiny ridges. Researchers say they help reduce crystal contact – making the micro foulants easier to remove when water flows over the hydrogel-coated surface.

The team fabricated the microtextured molds using photolithography followed by deep reactive ion etching on a single-side polished silicon wafer.

The hydrogel’s microstructure was inspired by processes taking place in the natural world. For example, shark scales have a ribbed structure to reduce fouling on the shark’s skin.

The team said under shear-driven water flow conditions, up to 98% of the crystals were removed. This was 66% better than when using a rigid, uncoated substrate.

“It was very evident that we had achieved a really good solution,” said Schmid in an interview with Power Engineering.

Schmid stressed that this is only fundamental research he expects others will build upon. He said the next steps would be studying this coating against other types of fouling.

Researchers also plan to test the coating on other substrates, like metal. To this point researchers have only used glass, in order to have a transparent substrate for easier viewing through a microscope.

“I think there there’s more research to do,” said Schmid. “It’s not a final product yet.”

The team’s research was published in the journal Science Advances.

The servicing of boilers in the field can be highly variable. Sometimes, everything runs smoothly according to routine. At other times, unforeseen challenges can rear their head and place project timelines in jeopardy. Shawn Brewer, Director of Business Development and Field Services at Rentech Boiler Systems, a company that has serviced hundreds of boilers, offered an example concerning boiler re-tubing.

A customer requests the repair of one or two leaky tubes. By all accounts, this should be a straightforward project. All that needs to be done is to shut down the unit, let it cool off, access the drum and execute the repair by rolling the tubes i.e., a rotating tool is placed into the tube end that expands the tube and tightens the seal between the tube and the drum. This kind of tube repair happens all the time. But it can happen that you arrive onsite to execute the repair and discover that the tubes are shot. They need to be completely replaced. That is a whole different ball game in terms of complexity and scope. In such a case, the boiler must be taken apart in the middle of the facility, noted Brewer. If the parts and manpower aren’t onsite, there will be a scramble to get them there immediately. Days can be lost.

To avoid such occurrences, here are best practices gleaned from long experience in servicing boilers.

Planning and coordination

There are many facets involved in the planning and coordination of a boiler servicing project. These include:

Know-how

Know-how is difficult to fake. Even if you manage it, you will eventually be found out. A best practice is to use an experienced technician as your initial point of contact, someone with deep experience in the field.  Such a person will ask the right questions, evaluate the job and figure out what it will take to fix the problem. This person must be able to establish how many people may be needed for a project, what other experts might be required on site and what type of testing should be done (such as for water quality). An inexperienced person in this role will be unable to differentiate straightforward projects from the trickier tasks that might require more time and labor. They may miss warning signs of trouble that lies ahead and allocate insufficient manpower, materials, tools and components. An experienced hand minimizes the chances of completely misestimating the potential scope of a new project.

Inspection

Don’t rely only on the work of one expert based on what the customer thinks might be wrong. Send someone onsite in advance to verify what is already known and find any unknowns that might interfere with a smooth in-and-out visit. Talk to the customer on the ground, have them walk you through the job, and show you what they think is wrong. Then investigate it yourself to determine what it will take to complete the job.

Contingency planning

No matter how good your first point of contact is or how well you scope things out on the ground, there is still a need for contingency planning. It is best to arrive on site with replacement components in hand and to be ready to deal with any other eventualities.

“Once physically inside a unit, you may find there is a lot more wrong than suspected,” advised Brewer. “An action plan in place and some kind of a contingency plan to tackle issues in a timely manner.”

On-the-ground coordination

Project coordination on the ground is just as important as advance planning. The field service team, plant management and maintenance personnel must work in concert to take the project to swift resolution. Brewer stressed that a key aspect of this is liaison with plant safety personnel to understand their safety protocols and align these with how you intend to operate while onsite.

Equipment access

Carefully measure entrances, sharp turns, headway clearances and the area around the boiler to isolate any areas of difficulty. You want to avoid problems such as semis with large boiler parts being unable to turn into a facility or unable to deposit the components close to where the work needs to be done due to congestion within the facility.

Work spaces

Workers on site often need a trailer set up nearby, an area where systems and components can be laid down and enough room to remove parts of the boiler and place them somewhere near. Make sure these spaces are not used by moving vehicles. On the other side of the coin, don’t obstruct areas of the plant where personnel need to have right of way. Having enough space to work near the boiler is another key point of coordination.

Timeline

In most cases, a short window is available for maintenance and repairs during an outage. During this period, be aware that other work may be ongoing and that these other projects may sometimes collide with your own. Those maintaining or commissioning a turbine, for example, may want the boiler fired up at the same point that you want it offline. Go over these points carefully in advance. Preparation is the way to avoid conflict, said Brewer. Make sure you can do the work needed on the boiler in the time apportioned by preparing well for whatever needs to be done.

Manpower

Due to retirements, cutbacks and lack of training of the new generation in industrial operations, there is a shrinking pool of skilled resources. Finding boiler expertise can be difficult.

“Be sure the company you bring in possesses trained and experienced resources to do the job and has others on hand in the case of unforeseen circumstances,” said Brewer.

Failure to do so could mean exceeding the planned outage window.

Provider selection

An industrial boiler is generally a custom piece of equipment operating as part of a specific process. Those servicing them must understand how the boiler integrates with other equipment in the plant. In a refinery, for instance, the boiler plays a role in most workflows. The output from crackers and other refinery equipment can grind to a halt without a working boiler. Thus, boiler errors in the field can prove very expensive.

“It is usually best to align with a reputable service team that is part of an established boiler manufacturer,” said Brewer. “Manufacturers possess the deepest knowledge of how boilers work and what it takes to put them together. Their service groups can call upon this knowledge to successfully repair units and overcome any challenges that may crop up.”  

Boilers are under tremendous strain and are integral to so many processes within the facility. They deal with high temperatures, big changes from hot to cold, pressurized steam, fuel combustion, humidity and condensation. Everything may not be as it seems from the outside. A small problem can quickly escalate due to the pressure extremes they operate under. Anytime there is even a small issue, it is best to act. Call your local service company and get somebody in to look at it before something more serious occurs.

Author: Drew Robb has been working as a full-time freelance writer in engineering and technology for the last 25 years. For more information, contact drew@robbeditorial.com.

Why? “What got us to where we are is not going to get us where we need to be,” said Brian Roth, vice president O&M with PROENERGY. The company is a third-party solutions provider for the energy industry.

How does this connect to remote power plant operations? Divergent thinking, which is a process used to create ideas by exploring many possible solutions, is needed to help address challenges the industry is facing now and will be facing in the future. And yet convergent thinking, which focuses on reaching a single well-defined solution to a problem, often causes us to shut down potential solutions. Roth encouraged a focus on separating convergent thinking from divergent thinking within organizations. Thinking about a challenge without taking into account constraints encourages divergent thinking.

With this encouragement setting the stage, Roth discussed the difference between remote dispatch, which is a subset of remote operations that focuses on start/stop energy monitoring, remote operations (physically controlling a unit) and remote monitoring (and diagnostics) or RM&D. The latter involves looking at data trending, setting more narrow bands to get alarms earlier than the control system and enabling plant personnel to take action.

He was frank when sharing the value of remote operations centers (ROC), including pros and cons. The pros list is substantive: better coordination and resource allocation, safety enhancements, and improved reliability and sustainability. But the cons must also be acknowledged, with Roth highlighting two in particular: technology differences make it more challenging, and the importance of communication without the ability to meet face-to-face can’t be overlooked. In addition, it is easy to overload ROC operators with information.

Roth pointed out that tools don’t solve problems. With RM&D, the aspiration is to detect small anomalies and then do something with that information before there’s a problem. RM&D can empower a utility to reach peak efficiency using predictive technology. RM&D systems can deliver prescriptive alerts to operator, which Roth called alarms with recommendations.

Now, coming back to the concept of divergent thinking: Early in the session, Roth asked attendees: “Can a single operator run 100 units?” The knee-jerk answer to that question might be no, and in that case you would be thinking convergently, not divergently. Putting aside current technology and personnel constraints, your answer should change. Roth said at this time, the company has an ROC where a single operator runs 32 units, so taking today’s constraints out of the equation could perhaps see the aspirational goal of 100 units reached.

Once a wind turbine reaches the end of its operational life or becomes outdated, it must be decommissioned and removed from the site. As of the first quarter of 2023, data from the United States Geological Survey reveals the existence of 72,731 wind turbines spread across 43 states, encompassing territories such as Guam and Puerto Rico.

According to the latest introduced legislation, U.S. representatives from Colorado are proposing that wind energy companies should be required to remove decommissioned wind turbines from leased land before becoming eligible for federal tax credits.

Managing wind turbine waste: rise of regulations

As wind turbines reach the end of their operational lives, the disposal and recycling of wind turbine blades can become a complex issue. These blades, often made from composite materials like carbon fiber or glass, are challenging to recycle using conventional methods, leading to considerable waste.

Due to their large size and durable composition, finding sustainable solutions for handling used wind turbines is crucial. Landfill disposal has been a common approach, but this method presents a different set of environmental and lifecycle cost challenges. 

Wind turbines have an operational lifespan of several decades, so waste management during decommissioning is a long-term consideration. Waste regulation aims to address concerns related to the disposal, recycling, and environmental impact of wind turbine components at the end of their useful life. 

Because the wind energy industry is relatively young, U.S. wind farm operators and policymakers have yet to encounter decommissioning challenges. Several states are starting to develop specific waste regulations for wind turbines. 

One of them is Texas, which holds the top position among all states regarding the number of wind turbines and boasts the highest installed capacity, measured in megawatts. With the rapid growth of Texas wind farms, the issue of handling wind turbine waste, particularly the disposal and recycling of wind turbine blades, has become a significant concern. 

Texas has seen efforts to develop more sustainable wind turbine waste management solutions. Some initiatives focus on innovative recycling technologies, exploring ways to break down or repurpose the composite materials used in wind turbines. The Texas legislature defines decommissioning requirements on any person who leases property from a landowner to operate a wind farm. The state’s efforts reflect the recognition that addressing wind turbine waste is essential for the sustainability of the wind energy sector and minimizing the environmental footprint of renewable energy infrastructure as a whole.

As another example, wind turbine waste management in Oklahoma shares similarities with other states with a significant wind energy presence but has unique challenges and initiatives. Oklahoma defines steps related to the proper decommissioning of a wind energy facility and the requirement for energy companies to remove decommissioned wind turbines from leased land. Oklahoma is also actively exploring various strategies for more responsible wind turbine waste management.

Waste regulation for wind turbines is essential for the continued growth and sustainability of wind energy as a renewable energy source, as it helps mitigate potential negative impacts on the environment while maximizing the benefits of clean energy generation.

New legislation in Colorado

Colorado has been investing in wind energy projects, and its wind capacity has steadily increased over the years. Naturally, wind turbines are predominantly installed in regions with strong and consistent winds, such as the eastern plains and southern parts of the state. 

*Map shows the location of the operating wind farms in Colorado

According to the EIA’s latest available information, Colorado has an installed capacity of around 5,200 MW of wind energy. Their wind farms include nearly 2,800 wind turbines.

The graphs below show the growth in wind capacity within the state for the last 10 years.

Colorado’s Wind Energy for the last 10 years. Source:  FirmoGraphs Power Mart, including EIA data, created in Qlik Sense

Colorado lawmakers have introduced a new legislative proposal that mandates wind energy companies to be responsible for the removal of decommissioned wind turbines within the state.

The bill aims to modify the Internal Revenue Code, making it mandatory for energy companies to remove decommissioned wind turbines from leased land to be eligible for federal tax credits. Currently, there is no requirement for wind energy companies to take responsibility for removing decommissioned wind turbines from leased land. As a result, property owners, often farmers and ranchers, bear the burden of turbine removal. This shift in legislation underscores the growing importance of addressing the challenges associated with renewable energy infrastructure at the end of its useful life.

In Part 1 of this series, we examined the importance of heat transfer in steam surface condensers,
where waterside microbiological fouling and scale formation, or excess air in-leakage on the stem-side, can greatly inhibit energy transfer.¹ Waterside deposits may also generate under-deposit
corrosion of condenser tubes that can lead to premature failures.

Accordingly, condenser performance monitoring is a critical tool to detect problems and respond accordingly. This article outlines fundamental methods to do so, some of which the author reported on in Power Engineering over three decades ago,² but which are still valid today.

Condenser heat transfer

Figure 1 outlines the basic schematic of a two-pass condenser. Three temperature readings are
required for a perfunctory performance analysis, inlet water temperature, outlet water temperature
and the hotwell temperature.

Under normal conditions, the hotwell temperature is equivalent to the steam saturation temperature,
as the cooling process extracts the amount of heat necessary to convert the turbine exhaust steam to
condensate but does not sub-cool the condensate. (Some sub-cooling may occur in winter without
adjustments to the inlet water flow.)

Seasonal changes in the inlet water temperature will, of course, influence the hotwell temperature
(and the pressure in the condenser, often referred to as the backpressure) and the outlet temperature. Comparison of the inlet to outlet temperature is not effective for tracking performance, but a
measurement that does remain relatively constant over time, in the absence of tube fouling or excess
air in-leakage, is the terminal temperature difference (TTD); the difference between the hotwell
temperature and the outlet temperature. Regular TTD monitoring provides a simplified method for
tracking condenser performance, however, sometimes seemingly minor TTD increases can go
unnoticed when in actuality the onset of some heat transfer degradation issue is underway.

Condenser cleanliness factors

As outlined in references 2 and 4, the author was introduced to an excellent method for tracking
condenser performance per a training module developed by the General Physics Corp. (now GP
Strategies Corp.) utilizing data supplied by the Heat Exchange Institute. I first put the calculations
into BASIC language and then, as spreadsheet software emerged, converted the program to that
format. The program utilizes the three temperature readings mentioned above plus the following
data:

• Cooling water density
• Cooling water flow rate
• Circulating water correction factor
• Condenser tube correction factor
• Number of condenser tubes
• Number of tube passes
• Inside tube diameter
• Outside tube diameter
• Tube length
• A “C” value from tables given in the GP course

Because the tube dimensions and correction factors are constant for any particular condenser, over
half of the items above can be initially incorporated into the calculations with no further
modifications. Also, because water density does not change very much over ambient temperature
ranges, an average value can be utilized without compromising the calculations.

The program calculates an actual and a design heat transfer coefficient, where the ratio of actual to
design is the cleanliness factor. Because tube surfaces are typically coated with an oxide layer, the
calculations are designed to give a maximum factor of 85% for clean tubes, although this is not an
absolute guideline. Best is to establish baseline values after a condenser tube cleaning with the unit
at full load, and with the condenser air ejector system operating properly. Then track performance
over time to observe changes.

The program proved to be excellent for monitoring performance, as the following case histories
indicate.

Case histories

The following histories come from work at my first utility, City Water, Light & Power (CWLP)
in Springfield, Illinois. These will be followed by an additional example from my second utility.
All examples are from two-pass, once-through condensers, but the method is equally effective on
systems with circulating water supplied by cooling towers.

Case History #1

I had been performing thrice-weekly cleanliness factor analyses on the largest condenser, rated at
1,000,000 lb/hr at maximum load. The values remained very steady in the mid-70% range for
several months, but suddenly within two days dropped to 45%. Waterside fouling does not occur
this rapidly, and such drastic changes are more indicative of excess air in-leakage. Visual
inspection revealed a large crack in the condenser shell where a heater drips line penetrates.

Once maintenance sealed this crack, the cleanliness factors returned to previous values where
they remained for another two months until suddenly dropping again. The seal had failed. The
maintenance crew then welded a collar around the drips line, which totally sealed the crack and
cured the problem.

Case History #2

I had been collecting thrice-weekly readings on two, 690,000 lb/hr condensers. Suddenly, one
condenser began performing erratically. At maximum unit loads, the cleanliness factors ranged
between 70% to 75%, but at low loads the factor dropped as low as 18%. Again, such
fluctuations could not have been the result of waterside fouling. Plant management brought in a
leak detection firm to look for air leaks. The inspectors employed helium leak detection to
completely check the condenser and low-pressure end of the turbine. They classified leaks as
large, medium, and small, and found over a dozen leaks, including two large ones, one of which
was from a crack in the expansion joint between the turbine exhaust and condenser.

Maintenance crews repaired all leaks, but this did not solve the problem. Finally, an operator
discovered that a trap on a line from the gland steam exhauster was sticking open at low loads.
The trap and line are designed to return condensed gland steam from the condensate subcooler to
the condenser, but vent gases to the atmosphere. When the trap stuck open, the strong condenser
vacuum pulled outside air in through the vent. Once maintenance personnel replaced the trap,
the condenser performance problems disappeared. This is a classic example of the many
possibilities for condenser air in-leakage.

Case History #3

This history illustrates how the program detected a problem that had never occurred before. (It
can be quite significant in systems with cooling towers, where the circulating water typically
operates at several cycles of concentration.) The 1,000,000 lb/hr condenser from Case History #1 had been in operation for 10 years but had never suffered from scaling.

During one very dry summer, the lake volume decreased dramatically, and lab chemists calculated that the dissolved solids concentration in the lake increased four times over normal values. However, no thought was given to the possibility of scale formation. Throughout the summer the cleanliness factor declined slowly but noticeably from around 80% to 45%. When the unit came off line for an autumn outage, an inspection team found that the waterside of the tubes was completely covered with a layer of calcium carbonate (CaCO3), less than one millimeter in thickness. The deposits were a direct result of the drought. Plant management brought in a firm to mechanically scrape the tubes.

We observed an interesting peculiarity during this event. The condenser that scaled was
equipped with 90-10 and 70-30 copper-nickel tubes. The two other condensers, both tubed with
Admiralty brass, did not show scale buildups, even though operating temperatures were similar.
We surmised that heat transfer in the one condenser was just great enough to push the CaCO3
saturation index over the edge.

Case History #4

The program is very useful for detecting the onset of microbiological fouling, but if quick action is
not taken and microbiological colonies become established, heat transfer degradation may be very
swift. Also, deposit removal may be difficult. One year, when I was monitoring performance of the
1,000,000 lb/hr condenser from Case History #1, the cleanliness factor dropped from around 80% in
the early spring to 40% by early summer. Malfunction of the biocide feed system for a two-week
period proved to be the problem. Unfortunately, by the time the system was repaired the slime layer
produced by the microbial colonies inhibited the effectiveness of the biocide. (Additional details
regarding such issues are available in Reference 3.)

In mid-summer, we shock chlorinated the condenser, but this only restored the cleanliness factor to
around 65%. Visual inspection revealed that although the microorganisms had been killed, much of
the slime layer tenaciously remained. Again, plant management employed an outside contractor to
mechanically scrape the tubes.

Recognizing the data

At my second utility, which I joined approximately 10 years after performing the work above, I
found that a condenser cleanliness program had been incorporated into the distributed control
system (DCS) logic of each of the two units. It provided results that consistently matched my
spreadsheet program. But it became obvious that the plant staff was too busy to keep close track of
the data. After more attention was given to the program’s value, we observed the onset of
microbiological fouling in the condensers (again due to a biocide feed system malfunction) and a
sudden occurrence of excess air in-leakage in one condenser. Unfortunately, I do not recall the
issue that caused the air in-leakage difficulty.

A key takeaway from this example and Case History #4 above is the criticality of biocide feed
system design and diligent maintenance. Once microbes settle on cooling system surfaces, growth
can be extremely rapid.

Conclusion

Part 1 of this two-part series illustrated the significant penalties possible due to condenser upsets.
This part outlines reliable techniques for tracking condenser performance. The program that
colleagues and I developed at CWLP per training provided by GP Strategies proved to be very
valuable on numerous occasions. Even though coal-fired power plants have declined in number,
condensers remain a critical component for heat recovery steam generators at combined cycle and
co-gen facilities.

References

1. B. Buecker, “Condenser Performance Monitoring – Part 1”; Power Engineering, August
   2023.
2. B. Buecker, “Computer Program Predicts Condenser Cleanliness”; Power Engineering,
   June 1992.
3. B. Buecker (Tech. Ed.), “Water Essentials Handbook”; 2023. ChemTreat, Inc., Glen
   Allen, VA. Currently being released in digital format at www.chemtreat.com.
4. B. Buecker, “Condenser Chemistry and Performance Monitoring: A Critical Necessity
   for Reliable Plant Operation”; from the Proceedings of the 60th International Water
   Conference, Pittsburgh, Pennsylvania, October 18-20, 1999.
5. Post, R., Buecker, B., and S. Shulder, “Power Plant Cooling Water Fundamentals”; pre-conference seminar for the 37th Annual Electric Utility Chemistry Workshop, June 6,
   2017, Champaign, Illinois.

About the Author: Brad Buecker is president of Buecker & Associates, LLC, consulting and technical writing/marketing. Most recently he served as Senior Technical Publicist with ChemTreat, Inc. He has many years of experience in or supporting the power and industrial water treatment industries, much of it in steam generation chemistry, water treatment, air quality control, and results engineering positions with City Water, Light & Power (Springfield, Illinois) and Kansas City Power & Light Company’s (now Evergy) La Cygne, Kansas station. 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 has written three books on power plant chemistry and air pollution control. He is a member of the ACS, AIChE, AIST, ASME, AWT, the Electric Utility Chemistry Workshop planning committee, and he is active with the International Water Conference and Power-Gen International. He may be reached at beakertoo@aol.com.

The Ever-Changing Winds report, based on a global survey of wind turbine owner/operators, shows that reliability, or lack of it, is impacting all asset owners.

According to the report, nearly 50% of respondents foresee issues with both their existing fleet as well as new turbines coming off the production line.

Also, managing the risk of equipment failures coupled with the speed of development and the drive to reduce costs has introduced additional challenges.

According to the survey, the top five issues impacting turbine reliability are:

• Aging fleets
• Rapid growth of turbine size and compressed design cycles for new turbine
• Technologies
• Cost reduction pressure on the supply chain
• Declining profitability of Tier 1 turbine Original Equipment Manufacturers (OEMs)
• A challenging economic environment

While the introduction of larger turbines has been the primary driver behind rapidly reducing Levelized Cost of Electricity (LCOE), it has exacerbated problems around reliability and to some extent masked inefficiencies in operations and maintenance (O&M).

Part of the solution is greater, systematic adoption of automation and digital technologies across the full turbine lifecycle with a greater focus on whole-turbine PdM.

ONYX’s report underlines what progress has been made to digitalize assets. In 2020, 81% of respondents had barely started digitalization efforts, but this figure more than halved to 36% in 2023. However, only 14% of respondents indicated their digitalization of operations to be mature or market leading.

Key benefits from technology adoption, such as intelligent planning, additional turbine sensors, centralized data, advanced diagnostics and predictive analytics are still to be fully harnessed by the sector.

When it comes to supply chain problems and OEM challenges, survey participants are now citing lengthy delays on new projects due to longer lead times for the supply of new turbines and significant price increases.

Similarly for major components – particularly main bearings on newer turbines with large rotor diameters – lengthy delays are leaving turbines offline for extended periods.

Whilst these issues are creating challenges for operations teams, the biggest impact has been on OEMs, as evidenced in their recent financial results.

The ONYX report makes clear that technology advancements in predictive analytics and digitalized operations and maintenance are critical to improving the long-term cost-efficiency of the industry.

Report lead author Ashley Crowther, ONYX Insight’s chief commercial officer, said: “The wind industry faces a range of new challenges in the post-pandemic era. The supply chain, OEM headwinds and turbine reliability sit front and center of the issues facing operators as they look to reduce O&M expenditure in the face of increasing financial pressures.

“Supply chain pressures are compounding reliability problems caused by aging assets.

“However, challenges drive change and the industry can embrace technology to become more efficient. The best players are investing in digitalization, as their leaders know they will otherwise be left behind.

“We need to embed more knowledge into digital technology and leverage the output. We need to leverage our data for decision making and know ahead of time where, when and what for parts, people, and tools. It is clear from the report that there is a broad consensus that new predictive maintenance solutions are needed sooner rather than later. ONYX is working to develop the next generation of monitoring systems that will deliver a more complete picture for operators.”

Originally published by Power Engineering International.

Companies may have purchased or brought various wind turbines, solar farms or batteries into their portfolios. They often ask Emerson how they can integrate the data points from all of these assets into one place for optimal decision making.

That’s where Ovation Green comes in. To learn more, Power Engineering sat down with Emerson’s James Fraser at the company’s Emerson Exchange Immerse event in Anaheim, California.

“I heard a phrase yesterday in the exhibition hall: Frankenstein automation,” said Fraser, who is Vice President for Global Renewables of Emerson’s Power and Water Solutions. “You’ve got all these disparate pieces of equipment. And what we do with Ovation Green is allow access to information which is completely independent of the OEM.”

Emerson was already known for its Ovation platform, a control and automation system designed to help power plant operators with real-time monitoring and control of equipment, processes and systems.

But as the market has shifted toward renewables in the last few years, the company has made a series of strategic acquisitions to augment its expertise and technology platforms.

This all led up to the launch of Ovation Green earlier in 2023.

“It’s that understanding of the customer and where their challenges are that are the most important,” said Fraser. “We have the technology, we have the software, we have the capability. It’s then, how do you put those things together?”

By gathering and contextualizing vast amounts of data from renewable generation and storage assets, Emerson says the Ovation Green platform will drive faster, more informed decisions to increase availability and production while reducing operations and maintenance costs. 

Fraser said customers will better be able to understand or predict an asset reliability issue or make better economic decisions for dispatching power onto the grid.

Because the platform was designed with renewables in mind, he said asset owners will be able to report performance data to regulators more seamlessly.

Asset information through Ovation Green could be housed onsite, at a fleet management office or in the cloud.

“We give that flexibility of choice, because everybody has a slightly different requirement,” said Fraser.

See the full one-on-one video above.

B&W will manage and conduct maintenance for the three unit, 490 MW oil-fired plant’s boilers and boiler auxiliary equipment, including annual standard maintenance as well as capital projects for the plant’s units over the next three years.

The contract includes an option for additional work, if necessary.

Located in the Town of Holyrood and bordering Conception Bay South, the Holyrood Thermal Generating Station burns 0.7% sulphur fuel.

The plant is a major source of Newfoundland and Labrador’s energy, generating between 15% and 25% of the island’s electricity every year. If needed, the Holyrood plant has the capacity to generate up to 40% of the island’s annual energy needs.

By Denton Slovacek and Jean Holz, Hach

Introduction from Author

Frequently, author Buecker sees a post on LinkedIn offering a blanket recommendation for feedwater deaeration in high-pressure utility steam generators. The various authors of these commentaries seem to be unaware of the issue of flow-accelerated corrosion (FAC). Given the potentially large distribution of LinkedIn posts, many people may be exposed to critical misinformation in this regard. I wrote about FAC issues in a Power Engineering series last autumn,¹ followed by a recent article on trace metal analysis for feedwater corrosion monitoring.² The present article provides an overview of the details, with additional discussion from Hach on the importance of accurate dissolved oxygen (D.O.) monitoring for feedwater chemistry control.

 A review of important feedwater chemistry issues

The following bullets provide a condensed, mostly chronological review of high-pressure boiler feedwater chemistry evolution from the middle of last century to present times.

·  The common material of construction for condensate/feedwater piping and boiler tubes has always been mild carbon steel. It provides good strength at low cost.

·  Steam generator pressure and temperature were steadily increased from the 1930s into the middle of the century and beyond to improve boiler efficiency. Adoption of regenerative feedwater heating represented a major improvement to recover some energy that would otherwise be lost in the condenser. Copper alloys became a common choice for heater tube material, per copper’s decent strength and excellent heat transfer properties. Feedwater networks with carbon steel piping and copper alloys in the feedwater heaters are known as mixed-metallurgy systems.

Figure 1. Basic schematic of a large coal-fired power unit. Note the multiple feedwater heaters, including the deaerator.³

·  Iron and copper exhibit minimal general corrosion at a mildly alkaline pH, with the optimal value for iron shown below in the well-known Sturla diagram.

Figure 2. Feedwater carbon steel dissolution as a function of pH and temperature. Note: The pH analyses are at 25^o C.⁴

As is evident, general corrosion greatly diminishes as pH rises into a mid- to upper-9 range.   

However, a lower range in the mid-8s is better for the protective oxide that forms on copper.⁵ For mixed metallurgy systems, a common guideline for years was 8.8-9.1 to balance corrosion control between the two metals, but modern guidelines now suggest 9.1-9.3.⁶ Ammonia or in some cases a neutralizing amine (the new term is alkalizing amine) was, and still is, the treatment chemical to establish the proper pH range. Alkalizing amines offer potential benefits and drawbacks, and must be carefully evaluated.⁷

·  As power boilers grew in size and sophistication in the last century, researchers became convinced that even trace amounts of dissolved oxygen during operation would cause serious metal corrosion, which is true for copper alloys in ammoniated water. Virtually all units were equipped with a mechanical deaerator. The common DA effluent guarantee is 7 ppb D.O.

·  Even 7 ppb was considered excessive, so chemical oxygen scavenging became standard. Originally, hydrazine was the oxygen scavenger/reducing agent of choice, but health concerns from handling the chemical led to hydrazine replacement with such compounds as carbohydrazide, diethylhydroxylamine (DEHA) and others.

·  The combination of ammonia or an amine for pH control and oxygen scavenger feed became known as all-volatile treatment reducing (AVT(R)). The reducing chemistry generates the familiar gray-black iron oxide layer magnetite (Fe₃O₄) on carbon steel, and it maintains the reduced copper oxide layer, cuprous oxide (Cu₂O)), on copper alloys.

·  1986, “On December 9 of that year, an elbow in the condensate system ruptured at the Surry Nuclear Power Station [near Rushmere, Virginia.] The failure caused four fatalities and tens of millions of dollars in repair costs and lost revenues.” ⁸ This phenomenon is known as single-phase FAC. (Two-phase FAC, which can affect deaerators, feedwater heater drains, and low-pressure HRSG evaporators is discussed in greater detail in references 8 and 9.) Other single-phase FAC-induced failures over the last three decades have caused additional fatalities and much damage at several power plants. FAC has been observed in many HRSGs around the globe. Gradual metal loss occurs at FAC locations, until the affected area can no longer resist the fluid pressure.

Figure 3a. Photo of tube-wall thinning caused by single-phase FAC.³

Figure 3b. Surface view of single-phase FAC. Note the orange peel texture.³

Figure 3c. Catastrophic failures induced by FAC.⁹

·  In the late 1960s and early 1970s, chemists at supercritical units in Russia and western Europe discovered that with high-purity makeup water (conductivity after cation exchange (CACE) <0.15 mS/cm), direct injection of oxygen induced formation of ferric oxide hydrate (FeOOH) on carbon steel surfaces. (OT cannot be employed in systems with copper alloy feedwater heater tubes.) This oxide layer, a rather deep red in color, is denser and stronger than magnetite. After some evolution, this chemistry regime became known as oxygenated treatment (OT). Current guidelines from the International Association of the Properties of Water and Steam (IAPWS) call for a feedwater D.O. range of 30-150 parts-per-billion.⁶ OT has been adapted at most supercritical units around the world that have all-ferrous feedwater systems. With proper control and monitoring, total feedwater iron concentrations should remain at or below 1 ppb.

·  While OT can be employed for feedwater treatment in drum units, personnel from the Electric Power Research Institute (EPRI) developed all-volatile treatment oxidizing (AVT(O)) for high-pressure drum boiler feedwater. The primary source for oxygen is the small amount (usually) of oxygen that enters the condenser through small air leaks at condenser shell penetrations, turbine/condenser expansion joints, etc. Original AVT(O) guidelines recommended <20 ppb D.O. in the condensate with a 5-10 ppb residual at the economizer. EPRI has since expanded the latter range to 5-30 ppb.¹⁰ The key point is that with OT or AVT(O), all surfaces in the feedwater system and economizer should have the deep red color mentioned above. Patches of gray-black magnetite indicate insufficient protection. In some cases, and most notably for feed forward low-pressure HRSGs, direct oxygen injection (similar to OT applications but lower feed rates) may be needed to protect intermediate- and high-pressure economizer circuits.^{1, 8}

The importance of D.O. monitoring

As the discussion above indicates, each of the feedwater treatment programs has a well-defined D.O. range. Thus, along with analytical measurements for trace metal concentrations and, for mixed-metallurgy systems, oxidation-reduction potential (ORP), continuous on-line D.O. monitoring is of major importance.  Like other technologies, D.O. measurement has evolved and become more precise. For many years, amperometric methods were de rigueur for oxygen analyses. This is an electrochemical technique that can be quite accurate. However, amperometric instruments are labor intensive with frequent calibrations and sensor maintenance, the latter of which often requires replacement of a fragile membrane, especially if flow is discontinued and the membrane dries. These difficulties have only been exacerbated by the now common load cycling of most combined cycle (and even many remaining traditional) power plants. The figure below shows the response time of an amperometric sensor vs the luminescent dissolved oxygen (LDO) technology (in this case an Orbisphere K1100 instrument) that continues to increase in popularity.

Figure 4. Response time of an amperometric sensor vs. LDO. 

This graph outlines the analysis of a sample with D.O. concentrations that are common for OT applications, but “Since 2009, accurate measurement at levels below 1 ppb has now been made possible.” ¹¹ The technology is a practical example of quantum mechanics. In short, the instrument uses shorter-wavelength blue light to excite electrons in the atoms of the measuring device. The electrons release longer-wavelength red light as they return to an unexcited state. Oxygen molecules capture this released energy and lower the amount of red light to the sensor. O₂ also reduces the duration that the electrons exist in the excited state. Measurement of these two parameters allows very accurate calculation of D.O. concentrations, where “A constant alignment of the sensor occurs with the help of [a] red LED fitted in the probe. Before each measurement, this [LED] sends out a light beam of a known radiation characteristic.  Changes in the measurement system are hence detected without any time delay.” ¹²

Figure 5. Basic representation of a luminescent dissolved oxygen measurement system.¹²

Beyond the above-mentioned technical capabilities, the LDO instrument typically only requires one, 30-minute calibration per year. And, the analyzer is not affected if sample flow is discontinued. Startup is immediate. Most combined-cycle plants operate with minimal personnel, who often have limited chemistry training. Yet, proper operation of on-line water/steam chemistry analytical instruments is critical to prevent major upsets that can severely damage equipment and jeopardize employee safety.  Maintenance un-intensive instruments like LDO can be of great benefit in that regard.

Note: The choice of sample tubing for low-range dissolved oxygen analyzers is very important. Outside air can penetrate polyethylene tubing and significantly increase the oxygen concentration of the sample, making readings meaningless. Alternatives include stainless steel and specially-fabricated nylon.

Other applications

Water cooled stator coils for turbine generators are typically of copper-alloy construction. They are normally designed to operate with a either a very low dissolved oxygen concentration (<10 ppb) or in a several parts-per-million (ppm) range. The middle ground between these two ranges can lead to severe corrosion.  D.O. measurements are valuable for monitoring stator chemistry.

Increasingly, and especially in locations where water conservation is of concern, new power plants have air-cooled condensers (ACC) rather than water-cooled condensers. ACCs are enormously larger due to the much lower density of air than water. The extensive piping in an ACC offers many locations for air in-leakage.  Condensate D.O. monitoring can help plant technical personnel to select and adjust feedwater treatment chemistry. Because of high air in-leakage and subsequent carbon steel corrosion, often recommended is a particulate filter on the condensate discharge to remove iron oxide particulates and prevent transport to the steam generator.

Conclusion

The complexity of modern steam-based power generation requires up-to-date information sharing and analytical technology to maintain water/steam chemistry within acceptable parameters. This article hopefully serves as an additional reminder of issues related to flow-accelerated corrosion and that dissolved oxygen monitoring is an important tool for any chemistry program.   

References

1. B. Buecker, “HRSG issues: Re-emphasizing the importance of FAC corrosion control”; four-part series published on the Power Engineering website, September-October 2022, Water Treatment News – Power Engineering (power-eng.com)
2. B. Buecker, “Trace metal analysis for corrosion monitoring in cogeneration condensate systems”; Power Engineering, August 2023.
3. B. Buecker (Tech. Ed.), “Water Essentials Handbook”; 2023. ChemTreat, Inc., Glen Allen, VA.  Currently being released in digital format at www.chemtreat.com.
4. P. Sturla, Proceedings of the Fifth National Feedwater Conference, Prague, Czechoslovakia, 1973.
5. F. U. Leidich, “Chemistry Requirements of the Steam Turbine”; PPCHEM JOURNAL, 2023/04.
6. International Association for the Properties of Water and Steam, Technical Guidance Document: Volatile treatments for the steam-water circuits of fossil and combined cycle/HRSG power plants (2015).
7. Buecker, B., and S. Shulder, “Remember the 3Ds of Alkalizing Amines: Dissociation, Distribution, and Decomposition”; PPCHEM JOURNAL, 2023/01.
8. Guidelines for Control of Flow-Accelerated Corrosion in Fossil and Combined Cycle Power Plants, EPRI Technical Report 3002011569, the Electric Power Research Institute, Palo Alto, California, 2017.  This document is available to the industry as a free report because FAC is such an important safety issue.
9. Shulder, S. and B. Buecker, “Combined Cycle and Co-Generation Water/Steam Chemistry Control”; pre-workshop seminar for the 40^th Annual Electric Utility Chemistry Workshop, June 6-8, 2022, Champaign, Illinois.
10. Conversation with S. Shulder at the 40^th Annual Electric Utility Chemistry Workshop, June 6-8, 2022, Champaign, Illinois.
11. Hach Technical Bulletin LIT2192, “OPTICAL DISSOLVED OXYGEN MEASUREMENT IN POWER PLANTS”, 2012.
12. Hach Application Note: LDO Sensors, “Optical Dissolved Oxygen Measurements in Power and Boiler Applications.”  (DOC043.52.30333)

About the Author: Brad Buecker is president of Buecker & Associates, LLC, consulting and technical writing/marketing. Most recently he served as Senior Technical Publicist with ChemTreat, Inc. He has over four decades of experience in or supporting the power and industrial water treatment industries, much of it in steam generation chemistry, water treatment, air quality control, and results engineering positions with City Water, Light & Power (Springfield, Illinois) and Kansas City Power & Light Company’s (now Evergy) La Cygne, Kansas station. 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 has written three books on power plant chemistry and air pollution control. He may be reached at beakertoo@aol.com.

Combined-cycle power plants are frequently located in or near residential or commercial areas, with many people residing or working near the plant. The high energy required for power production generates much noise, which, without abatement controls, would be intolerable to the public and would present a safety hazard. One potential source of intense noise are the steam vents on heat recovery steam generators (HRSGs). Design, inspection and maintenance of steam vent silencers (SVS) are critical items of a plant’s noise abatement plan.

SVS Design

A heat recovery steam generator has several steam vents including:

• Drum relief (most HRSGs are multi-pressure units)
• Safety relief
• Blowdown tank
• Deaerator
• Startup

These vents are located at or extend to the top of the unit for safety reasons. Even at a high elevation, when a safety valve lifts the noise can be intense. Accordingly, the vents on many HRSG units are equipped with vent silencers to dampen the noise. The basic diagram of a steam vent silencer (SVS) is shown in Figure 1.

Vent silencers must be designed to handle a variety of steam pressures with high velocity inlet flow. The silencers manufactured by SVI Bremco have three major components, an inlet radial diffuser, lower plenum section and an upper absorptive (passive) silencer. Let’s examine how these components work together to dampen noise.

Inlet Radial Diffuser

This is shown as the floating diffuser in Figure 1. The diffusers can be designed in a one-, two-, or three-wall arrangement based on system conditions. Each layer has a specifically-designed perforation pattern that allows the steam to expand through mesh material located between the wall stages and the core of the diffuser. The floating basket design allows for thermal expansion in both the axial and transverse directions.

This stage helps to dissipate the incoming acoustic energy of the stream and splits the single stream into hundreds of smaller streams at each wall stage. This begins the noise attenuation process and decelerates the flow for further attenuation in the upper absorptive silencer.

Lower Plenum Section

The lower plenum section serves as an expansion chamber for radial dispersion of the steam. This arrangement provides for uniform flow to the absorptive silencer upper stage.

Upper Absorptive (Passive) Silencer

Several designs are possible for this final noise silencing stage:

• Concentric baffle
• Tubular array
• Bar array
• Parallel baffle

General illustrations of these designs are shown below.

These baffles provide the final noise attenuation.

Silencer stress and failure mechanisms

As can readily be surmised, silencers, and especially the inlet radial diffuser, are subject to large mechanical and thermal stress. Material degradation over time is the result. SVI Bremco can, to some extent, proactively address these issues by replacing older pressure safety valves (PSV) with modern designs that reduce steam-flow mechanical stress on silencer components. Even so, wear and tear on silencer components is still of primary concern. The photos below illustrate several of the most important issues.

Figure 6. Corrosion from water accumulation at the bottom of the diffuser.

Not only do these corrosion mechanisms affect silencer performance, but failed components can blow out of the silencer, presenting a potential safety hazard.

Of course, thermal stress issues in combined cycle units and HRSGs are usually quite substantial because of the regular load cycling of most units. However, numerous proactive techniques are available to improve performance and longevity of silencers. Primary concepts include:

1. Design and fabrication

a. Materials metallurgical composition. Higher grade alloys than plain carbon steel, although adding expense, may pay for themselves in increased durability. 

b. Materials thickness and well-designed support components. Techniques such as computational fluid dynamics (CFD) can help determine the stresses on components and provide maximized structural design. CFD is also a critical technique in evaluating the aerodynamics of silencers and optimizing designs to reduce high steam velocity and back pressure.

c. Welding techniques. Proper welding techniques and selection of weld filler material are critical throughout steam generating systems including silencers. Welding induces localized stresses that can become rapid failure points if the welding is not planned and performed properly.

2. Excessive Water-Induced Corrosion. To the greatest extent possible, silencers and their discharge vent should be designed to minimize water collection from rain and condensation. Given the cycling nature of combined cycle units, control of water accumulation can be a challenging task.

3. Inspections. Silencers, like some other power plant components, often fit in the “out of sight, out of mind” category; that is until a major failure brings the equipment to everyone’s attention. The next section outlines important items for silencer inspections.

Silencer inspection details

A recommendation at any industrial plant is to develop written protocols for every process and inspection, and to strictly follow the guidelines at all times. However, in this era of minimal staffing at many plants (combined cycle facilities are prime examples) plant personnel may not have the expertise to evaluate all situations. A solution is to work with an industry expert or company to develop inspection guidelines and perhaps assist directly with the inspections. The following lists outline primary inspection parameters for SVI silencers.

Visual Inspection

• Silencer support brackets and welds for degradation, corrosion, and cracking
• Outer shells for corrosion, degradation, cracks, or thinning
• Inlet pipe connection for missing or loose bolts, or corrosion
• Inlet pipe welding for cracks
• Drainage pipe for corrosion
• Exterior paint integrity

Internal Video

• Baffle frame for degradation or cracking
• Baffle support for degradation or cracking
• Baffle perforated sheets for degradation or cracking
• Weld between the diffuser base plate and inlet pipe for cracking
• Weld between the diffuser basket and base plate for cracking
• Diffuser perforated plates for degradation, corrosion, or cracking
• Diffuser cap condition for corrosion

Early detection of component degradation allows repairs before a major failure occurs.

Conclusion

Safety vent silencers are an important component of steam generators. These components operate under high mechanical and thermal stress, and will fail without regular inspection and maintenance. A failure may raise noise to unacceptable levels. Furthermore, pieces of failed components may discharge from the vent to produce a safety hazard. SVI Bremco provides the services and equipment to protect and maintain these vital power plant items.

Contributing editor for this SVI Bremco article is Brad Buecker.

About the Author: Brad Buecker is president of Buecker & Associates, LLC, consulting and technical writing/marketing. Most recently he served as Senior Technical Publicist with ChemTreat, Inc. He has over four decades of experience in or supporting the power and industrial water treatment industries, much of it in steam generation chemistry, water treatment, air quality control, and results engineering positions with City Water, Light & Power (Springfield, Illinois) and Kansas City Power & Light Company’s (now Evergy) La Cygne, Kansas station. His work also included 11 years with two engineering firms, Burns & McDonnell and Kiewit, and he also 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 has written three books on power plant chemistry and air pollution control.  He may be reached at beakertoo@aol.com.