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.

This research was originally published in the journal Nature Communications. Teams said the coating, made with fluorinated diamond-like carbon, or F-DLC, is suited for industrial use after researchers subjected coated metals to steam condenser conditions for 1,095 days, the longest durability test they’d reported. The coated metals maintained their hydrophobic properties for this entire length of time.

According to the university, the new F-DLC coating improves heat transfer because the material is hydrophobic. When the steam condenses into water, it does not form a thin film that coats the surface, like water does on many clean metals and their oxides.

Instead, researchers said the water forms droplets on the F-DLC surface, putting the steam into direct contact with the condenser and allowing heat to be directly transferred. The researchers reported this translating to a 2% overall process boost.

Researchers said if fossil-burning plants were 2% more efficient, then, every year, there could be 460 million fewer tons of carbon dioxide released and 2 trillion fewer gallons of water used.

“A lot of CO2 is going to be emitted before we get to a place where we can lean on renewable,” said Nenad Miljkovic, a professor of mechanical science and engineering at UIUC and the project lead.  If our F-DLC coating were adopted globally, it would noticeably curtail carbon emissions and water usage for the existing power infrastructure.”

The research team will now study the coating’s performance for six months of steady condensation exposure under industrial conditions at the university’s Abbott Power Plant.

Introduction

In previous Power Engineering articles, we examined the importance of trace iron monitoring to determine the extent of carbon steel corrosion in heat recovery steam generator (HRSG) condensate and feedwater circuits. ^{(1, 2)} HRSG feedwater systems typically contain no copper alloys, except perhaps rarely a condenser with copper alloy tubes. However, cogeneration and large industrial steam systems may have numerous heat exchangers containing copper alloy tubes.

Accordingly, both iron and copper monitoring of condensate are important for evaluating the efficacy of chemical treatment programs in minimizing corrosion and the secondary effect of corrosion product transport to steam generators. In this article, we will briefly revisit several important aspects of steam generator condensate/feedwater iron analyses. We will also examine why copper monitoring is needed at cogeneration facilities, along with modern analytical methods for trace metal analysis.

Some background history

During the age of large fossil plant construction in the middle of the previous century, the condensate/feedwater network typically contained several closed feedwater heaters plus an open heater, the deaerator.

Copper alloys were a common materials choice for closed feedwater heater tubes because of copper’s excellent heat transfer properties. However, copper is susceptible to corrosion from the combined effects of dissolved oxygen and ammonia, the latter being the common chemical for feedwater pH control (although at some plants alkalizing, aka neutralizing, amines remain the choice). ^{(3, 4)}

Oxygen converts the protective Cu₂O layer on the copper surface (where copper is in the +1 oxidation state) to CuO, with copper transforming to a +2 oxidation state. Cu²⁺ reacts with ammonia to form a soluble compound. So, for virtually any system containing copper alloys, a combination of mechanical deaeration and chemical oxygen scavenging was, and still is, necessary to protect the alloys. The oxygen scavenger also serves as a passivating agent to convert CuO back to Cu₂O.

The combination of ammonia or an ammonia/amine blend for pH control and oxygen scavenger feed is known as all-volatile treatment reducing (AVT(R)). It produces the familiar dark magnetite layer (Fe₃O₄) on carbon steel but is no longer recommended for utility units and HRSGs with no copper alloys.

Rather, all-volatile treatment oxidizing (AVT(O)) as outlined in Reference 1 (with no oxygen scavenger feed but still ammonia or an ammonia/amine blend for pH control) is the proper choice. AVT(O) produces a red oxide layer, α-hematite (alternatively known as ferric oxide hydrate (FeOOH)) on carbon steel. AVT(O) requires high-purity feedwater with a cation conductivity of <0.2 mS/cm to be successful. For cogeneration and industrial steam generation systems, the (usually) lower-purity feedwater and/or presence of copper alloy-tubed heat exchangers prohibits AVT(O), with AVT(R) being the required option.

Careful chemistry control is necessary to find the balance between minimal iron and copper corrosion. A key ingredient in the treatment program is corrosion product monitoring to ensure that the chemistry is optimized.

Corrosion product monitoring

Regarding iron monitoring, several discussion points from Reference 2 bear brief repetition. 

Typically, 90% or greater of steel corrosion products exist as iron oxide particulates. Thus, measurements of just dissolved iron do not come close to the total corrosion product concentration. Hach developed a benchtop procedure that utilizes a 30-minute digestion process to convert all iron to soluble form for subsequent analysis on a standard spectrophotometer.

The lower detection limit is 1 part-per-billion (ppb), which is satisfactory for even high-pressure steam generators where the recommended feedwater iron concentration is <2 ppb. As events have shown over the last nearly four decades, iron monitoring is highly important for tracking flow-accelerated corrosion (FAC) in condensate/feedwater systems and in the low-pressure economizer and evaporator (and often some intermediate pressure circuits) of multi-pressure HRSGs. This benchtop technique provides snapshot readings only, but those are often sufficient with a system protected by proper chemistry. ⁽⁵⁾

Sometimes, however, continuous online measurements are important to quickly detect changing conditions. Hach has developed a laser nephelometry technique for that purpose, with additional details available in Reference 2. This method must be calibrated at each site and is dependent on whether an AVT(O) or AVT(R) program is in place. 

Now we reach a second key point of this article, as summarized in Reference 5.

For a cogeneration plant that sends steam to a steam host for use in a process (either via direct or indirect use) and then receives all or a portion of the condensate back, monitoring corrosion products in the steam condensate indicates whether corrosion and FAC are minimized in the process part of the steam plant. . . .  For mixed-metallurgy plants the copper levels can be extremely variable depending on the plant design and operation, but with chemistry optimized as far as possible, levels of total copper less than 10 [ppb] can be expected.

As with iron, the analytical process must account for dissolved and particulate metal. When this author began his power plant career over four decades ago as a laboratory chemist, the lab was equipped with a flame/graphite furnace atomic absorption spectrophotometer (AAS). Sample acidification with nitric acid solubilized particulate copper, and the total could then be accurately analyzed by the AAS. However, many labs do not have such sophisticated equipment and the trained personnel to operate these instruments. One method for accurate measurements, albeit where samples are collected over time, is corrosion product sampling.

This CPS utilizes a fine-pore mechanical filter paper for particulate collection and cation exchange (and if desired anion exchange) filter papers for dissolved ion collection. Any sampling period may be chosen (one to two weeks is common), after which the filters are sent to a laboratory for accurate analyses. The unit has a precise flow totalizer so that the analytes can be converted to concentration units for the time-period that the sample was collected. 

Consider the extract below from the recently-revised industrial boiler water guidelines produced by the American Society of Mechanical Engineers (ASME).

As the reader will note, recommended feedwater iron and copper limits are stringent, even for low-pressure industrial steam generators, and the values decrease with increasing pressure. For high-pressure utility steam generators, the suggested upper limits are 2 ppb for both iron and copper. A CPS can provide very valuable data on corrosion control in condensate systems with mixed metallurgies. Consider the following example, in which a CPS assisted with corrosion monitoring in a utility steam generator.

CPS case history

The author once consulted for an electric utility whose main unit was and still is a coal-fired boiler at full-load operating conditions of 1, 900psig drum pressure and 1, 005°F main and reheat steam temperatures. The feedwater system had heaters with copper-alloy tubes, requiring an AVT(R) feedwater chemistry regimen. (At the time of this project, plant personnel were developing a plan to replace the copper alloy heater tubes with steel.) Carbohydrazide served as the reducing agent, with a blend of morpholine and cyclohexylamine for pH conditioning.  Chemical injection is at the deaerator storage tank. Even though the chemical feed system could maintain feedwater pH within a range of 9.0–9.3 (the recommended range for balancing steel and copper corrosion control), the condensate pH typically remained in an 8.8–8.9 range.  It became clear that the condensate pH depression resulted from amine decomposition products that carried over with the steam.⁽⁴⁾

Per our recommendation, utility personnel installed a Sentry corrosion product sampler, with the flexibility for monitoring either feedwater or condensate pump discharge (CPD). Sampling indicated that iron concentrations were often five to fifteen times greater than the 2-ppb recommended limit, which suggested serious flow-accelerated corrosion in the condensate/feedwater network. Furthermore, the iron concentrations in the CPD were higher than in the feedwater. These results suggested that the lower pH induced by alkalizing amine decomposition had more of an influence on mild steel corrosion than the higher feedwater temperatures, both of whose influences are well known per the following famous diagram.

Regarding copper analyses, the CPS revealed concentrations very near the 2-ppb limit mentioned above, which should be expected in an oxygen-free environment with a pH close to 9.0. Accordingly, carbon steel corrosion became the primary focus in this unit. Plant personnel have recently incorporated a film-forming amine (FFA) into the chemical treatment program. Film-forming amines and related non-amine products are designed to directly establish a protective layer on metal surfaces. ⁽⁸⁾ Both successful and unsuccessful applications have been reported, but space does not permit a detailed discussion at present. In this application, no CPS data is yet available to confirm the efficacy of the FFA, but Millipore filter tests suggest that carbon steel corrosion has been reduced.   

Film-forming chemistry should be incorporated into and not serve as a full-blown substitute for either AVT(R) or AVT(O) methodologies. An issue that has been problematic regarding FFA applications is direct calculation of reagent concentrations. Significant strides are being made in this respect, which Hach personnel highlighted in a paper at the recent Electric Utility Chemistry Workshop. ⁽⁹⁾

While copper monitoring has proven to be less critical than iron monitoring in the example above, it is often much more important at cogeneration and industrial steam plants. As mentioned, certain conditions such as the combination of dissolved oxygen and ammonia can cause significant copper corrosion and reduce the life expectancy of heat exchanger tubes. 

Another corrodent that can cause severe damage to many metals including copper is sulfide (S^2-). The author once observed a situation where thousands of new 90-10 copper-nickel tubes in a steam surface condenser failed from multiple pitting leaks within 18 months because the machining lubricant contained sulfide that was not removed before the tubes were placed in service. An online measurement often recommended for chemistry control in mixed-metallurgy systems is oxidation-reduction potential (ORP). The data provided by trace metal monitoring methods can be correlated to ORP measurements to then serve for continuous chemical feed control.

Conclusion

Trace metal monitoring continues to become better recognized as a critical tool for optimizing steam generator chemical treatment programs and controlling corrosion. A primary concern with utility units is minimizing carbon steel flow-accelerated corrosion, but for cogen and industrial steam/condensate networks, copper corrosion monitoring is often also very important.

References

1. B. Buecker, “HRSG Steam Generation Issues: Reemphasizing the Importance of FAC Corrosion Control, Parts 1-4” Power Engineering, September-October 2022.
2. Buecker, B., Kuruc, K., and L. Johnson, “The Integral Benefits of Iron Monitoring for Steam Generation Chemistry Control”; Power Engineering, January 2019.
3. B. Buecker, Tech., Ed., Water Essentials.  (The new ChemTreat industrial water handbook, currently being released in digital format at www.chemtreat.com.)
4. Shulder, S. and B. Buecker, “Remember the 3Ds of Alkalizing Amines: Dissociation, Distribution, and Decomposition”; PPCHEM Journal, 2023/01.
5. International Association of the Properties of Water and Steam, Technical Guidance Document: Corrosion Product Sampling and Analysis for Fossil and Combined Cycle Plants.  www.iapws.org.
6. 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.
7. P. Sturla, Proceedings of the Fifth National Feedwater Conference, Prague, Czechoslovakia, 1973.

In a recent article for Power Engineering ^[1], I wrote about the special properties of limestone, and especially high-purity stone, that have made it a common flue gas desulfurization reagent for numerous coal-fired power plants over the last five decades. Of course, in many areas of the world coal-fired power is being phased out, which makes flue gas desulfurization (FGD) chemistry moot to some readers.  However, coal-fired power plants are still common in some countries. And, as I was reminded from feedback to the previous article, many metal-ore smelting facilities exist around the globe where a principal emission is gaseous sulfur dioxide. Wet-limestone FGD (WFGD) scrubbing is becoming a proven process for these applications. ^[2]

Accurate analysis of scrubber solids is critical for determining reaction efficiency and limestone utilization. This article outlines a technology that a colleague and I helped pioneer in the power industry way back in the late-1980s ^[3], but which may be unfamiliar to many plant personnel today. The technique is thermogravimetry (TGA). The analytical method allowed us to eliminate time-consuming and often inaccurate wet-chemistry test methods and improve scrubber performance. I brought the concept with me to a second coal-fired power plant, where TGA again proved its value. ^[4]

TGA analysis of scrubber byproduct

Analysis by thermogravimetry is simple in concept. A TGA functions by weighing samples on a precise analytical balance as they are heated. The main features of some designs are a top mounted balance, vertically supported sample pan, an automatically-operated furnace that raises for sample analysis and lowers when analysis is complete, an automatic sample loader, and a personal computer for instrument operation and data analysis. The furnace compartment typically has a port that allows samples to be analyzed in various atmospheres via bottled gases that are connected to the compartment by a manifold, tubing system, and automated sample-switching device. Nitrogen is common to provide an inert atmosphere that eliminates oxidation reactions that might occur with air. Additional discussion of this topic appears later in this document.

A TGA is a quantitative not a qualitative instrument, so the operator needs to have a good idea of the primary constituents in the sample before analysis. If the compounds decompose at distinct and separate temperatures, it becomes easy to calculate the concentration of the original materials. Wet-limestone scrubber byproducts lend themselves well to this technique. (The reader can refer to Reference 1 for a more detailed description of scrubber process chemistry.) The following equations illustrate the decomposition temperatures and chemistry of wet-limestone FGD solids.

CaSO₄·2H₂O –> CaSO₄ + 2H₂O↑­  (160^oC to 200^oC)            Eq. 1

(CaSO₃·CaSO₄) ·½H₂O –> CaSO₃·CaSO₄ + ½H₂O­↑  (400^oC to 430^oC) Eq. 2

CaCO₃ –> CaO + CO₂↑­  (650^oC to 800^oC)    Eq. 3

Figure 2 illustrates a TGA analysis of a pre-dried scrubber solids sample from Reference 4 containing all three of the major constituents listed above. For the moment, we will ignore the decomposition shown at 600^oC.  This will be addressed shortly.

The calculations to determine constituent concentrations are straightforward. The molecular weight of gypsum is 172 and that of the water forced out is 36, so the initial gypsum content is determined by multiplying the weight loss (5.772 percent) times a factor of 172 ÷ 36 (4.78). For calcium sulfite-sulfate hemihydrate, the factor is 131.9 ÷ 9 (14.6), where the mole ratio of calcium sulfite to calcium sulfate is assumed to be 85:15. For the calcium carbonate decomposition, the factor is 100.1 ÷ 44 (2.27). Thus, for the analysis shown in Figure 2, the gypsum content is 27.6 percent, the calcium sulfite-sulfate hemihydrate content is 12.0 percent, and the calcium carbonate content is 22.3 percent.

This sample came from a wet-limestone scrubber that served the dual purpose of removing SO₂ and the fly ash from the flue gas of a Cyclone boiler. The fly ash loading was much lower than it would have been for a pulverized coal unit, but nonetheless the unburned carbon effects upon the analyses were important. We first attempted to analyze the scrubber solids in a nitrogen atmosphere from beginning to end of the run, but found that volatile discharge and accompanying weight loss from the unburned carbon blended in with the calcium carbonate decomposition. So, we modified the procedure to introduce air to the furnace at 600^oC. (We subsequently lowered the temperature to 500^oC). The step was isothermal with a 20-minute hold time that allowed all volatile matter and carbon to burn away. The effect is clearly illustrated by the vertical slope at 600^oC in Figure 2. Following the isothermal hold step, the computer automatically resumed sample heating to a final temperature of 1000^oC. This step clearly separated the carbon vaporization from the calcium carbonate decomposition.

When this boiler and scrubber were installed, no plans were in place to produce a high-gypsum byproduct for potential sale. In part, this probably was because of the relatively poor-quality limestone in the area (CaCO₃ content less than 90%), which would not have produced a high-purity byproduct. Instead, the scrubber solids were discharged as a slurry to large, lined holding ponds. Some readers may ask why byproduct analyses were needed at all with the slurry being discarded.  Two answers emerged quickly. Initial TGA data indicated unused CaCO₃ concentrations in the byproduct of 15-25%, as is evident in Figure 3. When we informed plant operators of this gross inefficiency, they adjusted limestone grinding mill settings to produce a finer reagent size. Subsequently, the unused limestone concentrations dropped to 5-10%, which translated into a large savings in limestone costs. Also, and again referring to Figure 3, a rise in unburned carbon content in the daily scrubber samples typically indicated a problem with one or more of the boiler’s coal crushers. The lab technicians would usually detect such upsets before the boiler operators, so they made it a point to notify the operators immediately after seeing a sample weight loss due to carbon decomposition. This allowed for expedient adjustments of a poorly performing coal mill.

High-purity byproduct analyses

My initial work with TGA, which extended over half a decade, was with a forced-oxidation, wet-limestone scrubber that was designed to produce a byproduct suitable for sale to wallboard manufacturers. The required gypsum concentration was 94% or greater. Figure 3 is an analysis of the typical byproduct. (Like many other units in the US, the boiler and scrubber have been retired.)

TGA proved extremely valuable in helping plant chemists verify that the forced oxidation system was operating properly. For starters, the TGA data showed that the scrubber manufacturer had not installed sufficient oxidation capacity to convert all of the calcium sulfite (CaSO₃) to CaSO₄. Per language in the original contract, the supplier had to install an additional air compressor to ensure complete oxidation.

Following this correction, we periodically noticed an oxidation loss per TGA data. Investigation revealed that the high temperatures of the oxidation air would cause crystal deposition at the openings in the perforated air-injection laterals. As airflow to the slurry dropped the loss of oxidation efficiency was detectable due to an increase in (CaSO₃·CaSO₄)·½H₂O. The unit manager had a water injection system installed to the lateral headers that lowered the oxidation air temperature and eliminated the scale formation.

In another very prominent example of the TGA importance at this plant, over a two-year period we performed several full-scale tests on limestones in close proximity to the plant to see if we could lower transportation costs of the material. All of these stones were of lower quality than the standard. Performance data confirmed that none were suitable as a replacement; a conclusion which in large part was confirmed by TGA results that showed a significant drop in byproduct gypsum content and a significant rise in unreacted CaCO₃.

A Quirky Observation

For those contemplating use of a TGA for FGD solids analyses, a special point should be noted. The author discovered early on that calcium sulfite will break down at high temperatures when analyzed in an atmosphere devoid of oxygen. A colleague found a description of this chemistry in a somewhat obscure reference that I no longer have. 

CaSO₃ –> CaO + SO₂­↑           Eq. 4

This phenomenon reappeared during subsequent work at my second utility. Figure 4 illustrates this effect.

The trained analyst can distinguish the end of the calcium carbonate decomposition and the beginning of the calcium sulfite decomposition. This transition is apparent at the shoulder in the decomposition pattern at 750^oC. The calcium sulfite breakdown can be eliminated by analyzing the sample in air, and Figure 5 shows a duplicate sample as analyzed in an air atmosphere.

Rather than decompose, a portion of the calcium sulfite appears to oxidize to calcium sulfate at the high temperature, but I do not have actual confirmation of this chemistry.

Conclusion

Thermogravimetry is an excellent method for tracking wet-limestone FGD chemistry, especially when quick results are required, when checking for process upsets, and when making process changes. While its application in the coal-fired power industry may not be as valuable as in the past, it is a technique that may be valuable for other industries such as metal refining, where SO₂ scrubbing may be an important process.

References

1. B. Buecker, “Limestone – The Amazing Scrubbing Reagent”; Power Engineering, April 2023. www.power-eng.com.
2. “Antimony Roaster Project: FGD Flue Gas Desulfurization Plant”; The ERG Group, www.ergapc.co.uk. 
3. Buecker, B., and D. Dorsey, “TGA Identifies Scrubber Materials”; Research and Development, Vol. 28, No. 5, May 1986.
4. B. Buecker, “Wet Limestone FGD Solids Analysis by Thermogravimetry”; paper for the 24^th Annual Electric Utility Chemistry Workshop, May 11-13, 2004, Champaign, Illinois

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.

While the conference and exposition officially begin on Tuesday, February 21, enthusiastic attendees from all over the globe flew in early to take in a tour of the Orlando Utilities Commission (OUC) Gardenia Innovation and Operations Center followed by a tour of the 740-MW Cane Island Power Park.

Grid-edge R&D

OUC’s facility is where the municipal utility tests pre-commercialized or newly commercialized technology and includes a floating solar array, a vehicle-to-grid bi-directional charger, a 50-kW DC fast charger (soon to be upgraded to 120 kW), several Level 2 EV chargers, a 10-kW/40-kWh vanadium redox flow battery and two underground 8-kW/32-kWh flywheels.

“We want to make sure we understand how they work, their operational characteristics and build new business cases around them before we put them in a position where they could be affecting our customers,” explained Rubin York, one of the three OUC engineers leading the tour.

In addition, OUC is testing a site controller that can operate the system in three main modes: PV smoothing, demand mitigation, which performs autonomous peak shaving, and contingency mode, which collects the assets into a microgrid.

“That is only possible thanks to these flywheels,” said York.

They go through a grid-forming bi-directional inverter which, in contingency mode, assess the frequency and voltage of the buildings and meters and disconnects the EV chargers, the PV inverter (per the IEEE standard), and any other load until the flywheels can output a good 60 hertz, 480-volt AC signal, said York. Once the flywheel generation is firm, OUC can slowly bring the loads back up and charge the EVs.

York also showed off the Cloud Impact Mapping System (CIMS), an in-house developed system that was designed to predict the ramp rate of solar PV as clouds come over and depart the solar PV. Should the technology scale, it could prove to be useful to electric utilities in Florida that are relying on a large amount of solar PV generation because Florida generally experiences a large amount of clouds.

“The goal is to build an array of these all around our territory, build a central repository, and have them effectively ‘hand off’ cloud systems to one another,” said York.

The OUC Gardenia site is also host to a rooftop solar array with bifacial solar panels and a solar parking canopy, which covers the parking lots for the facility.

Exceptional availability

After a quick bus ride and lunch, attendees toured the 740-MW Cane Island Power Park, which was available more than 90% of the time in the 2021 and won an award for its exceptional availability.

Unit 3 of the park ran for eight months with no trips said Ken Rutter, COO of the Florida Municipal Power Agency (FMPA), which owns the plant along with Kissimmee Utility Authority (KUA). He added that the unit ran through Hurricane Ian and supplied power to customers who were able to accept it.

The POWERGEN group was split into four smaller groups and taken all throughout the park, viewing each generating unit, one turbine (that was not currently operating), condensers, cooling towers, the control center, and more.  Rutter encouraged attendees to ask their tour guides anything at all – and they certainly took him up on that offer.

POWERGEN International 2024 takes place in New Orleans, January 23-25, 2024.

Allied Power will continue to provide maintenance at 12 Constellation nuclear plants through mid-August 2028, per an extension signed by the companies. The new agreement includes staff augmentation and has an option for a five-year renewal.

The 12 plants are located in Illinois, Maryland, New York and Pennsylvania.

Allied Power provides a range of services, from routine maintenance to outage services and management, capital construction and specialized support – for power plants throughout the U.S.

Constellation is the largest owner and operator of nuke plants in the U.S. In October 2022 we reported the Exelon spinoff plans to ask the Nuclear Regulatory Commission (NRC) to extend the operating licenses of its Clinton and Dresden nuclear plants in Illinois by an additional 20 years.

If approved by the NRC, Clinton could operate until 2047 and Dresden could operate until 2049 (Unit 2) and 2051 (Unit 3).

GSE Solutions announced it will work with NuScale Power on a hydrogen plant model for NuScale’s small modular reactor (SMR) power plant simulator.

It comes after a recent announcement that several partners would assess the potential of hydrogen production using electricity and process heat from NuScale’s SMR.

The idea is to modify the existing NuScale control room simulator to include GSE’s models for hydrogen production. This would include modeling for a solid oxide electrolysis system to produce hydrogen, in addition to a fuel cell for electricity production.

Research will consider the number of NuScale power modules needed for use in solid oxide fuel cell hydrogen production and the quantity of hydrogen stored for subsequent electricity production.

The scaled–up model is estimated to be complete by the middle of March 2024.

Portland-based NuScale’s power module is a small pressurized water reactor, which can generate 77 MW of electricity (MWe). Its six-module VOYGR-6 can generate 462 MWe. The company also offers a 12-module VOYGR-12 (924 MWe) and a four-module VOYGR-4 (308 MWe).

VOYGR is the official name of NuScale’s SMR, which it plans to deploy for Utah Associated Municipal Power Systems’ (UAMPS) Carbon Free Power Project (CFPP) at the Idaho National Lab (INL).

The CFPP project’s first module is projected to come online in 2029, with all six modules online by 2030. NuScale believes the six-module CFPP will act as a catalyst for subsequent SMR plant deployments across the U.S. and beyond.

Hydrogen is viewed as a way to decarbonize energy systems. In these markets, hydrogen would be used as an end-use product or as a stored energy source to be processed through a solid oxide fuel cell for electricity generation.

According to the Sandia scientists, the model combines a restoration-optimization model with a computer model of how grid operators would make decisions when they don’t have complete knowledge of every generator and distribution line.

Researchers say the model can help provide insight into how individual power generators, distribution substations and power lines would react during the process of restoring power.

The model also can simulate black starts that are triggered by disruptions such as a successful cyberattack.

In terms of optimizing restoring power, the model assesses the grid and its components to determine how to restore power as quickly as possible, said Bryan Arguello, a Sandia computer scientist.

Arguello said an example of an optimal approach might be to start with generator 1 to power up substation A. Once substation A is energized, generators 2-4 can safely power up. These, in turn, will provide power to substations B, C and D, as well as some critical infrastructure such as a water purification plant or an area hospital. Once substation D is energized, power plants 5-8 can power up, and so on until power is restored to the entire grid.

Once the power-restoration schedule is developed, the algorithm compares it against physical limitations to determine if the schedule is feasible, Arguello said. This process is based off a similar model created by researchers at Lawrence Livermore National Laboratory and the University of California Berkeley.

“The challenge here is bringing in just the right amount of information so that the model can make wise decisions, without bogging it down in too much detail,” said Arguello.

The model can also accurately approximate alternating current power flow, according to the researchers, which they say is more complex than direct current. The model also offers a more accurate representation of the grid during severe disruptions such as black start conditions.

Modeling operator decision-making

The operator decision-making code plays an essential role in the overall model, researchers said.

This algorithm takes the results from the optimization code and enacts it on a third code, which they described as a “physics-based simulation of the grid and how it dynamically responds to the operator’s actions.”

The decision-making model is based on a model created by scientists at Carnegie Mellon University, but adapted for power restoration by coding in expert knowledge about the steps required to start a generator and then connect it to the nearest substation.

This also includes safeguards so the cognitive model wouldn’t freeze if the grid behaved unexpectedly, Sandia scientists said.

The operator model interacts with the grid model through a simulated console and is limited to the knowledge presented by the console, rather than presuming the grid operator knows everything, which is typically assumed in power-restoration models.

Researchers said the operator model can assess whether the network model’s behavior matches up with what it is expecting based on the results of the optimization algorithm. The simulated console can also allow the team to swap in actual feeds of information from the grid for the network dynamic model, if a partner provides the information, they added.

“Black starts are really rare, extreme events, but when one happens it’s really bad,” said Systems Analyst Casey Doyle. “Even in partial blackouts, like what happened in Texas in 2021, people died because they didn’t have power, they didn’t have heat. If you have a complete blackout, it’s likely that it would be caused by a hurricane or earthquake and operators are trying to restore power to whole communities. Delays in power restoration could cause even more damage or loss of life. It’s hugely impactful to understand how to bring the power back as quickly as possible.”

The three-year project was funded by Sandia’s Laboratory Directed Research and Development program. The researchers are currently looking for sponsors to continue and expand the project.

Click here for more on the effort.

This article is the first of a multi-part series on how plant owners and operators can cyberharden their physical generation assets. Our key point is that the same competencies that the industry has developed over the last decades in terms of monitoring centers, monitoring software and digital twins of their generation assets can be leveraged to protect these same assets from hostile intrusions.

Where are we now?

A rash of new buzzwords, standards, and activity has emerged related to cybersecurity in the electric power sector, and many plant operators have made great strides in recent years to protect themselves from cyber-attacks. Many layers of a business can be disrupted due to an attack including billing, customer data, protected personal data (social security numbers or health information), and disruption of the power plant operations.

To date, a heavy emphasis has been rightly focused on IT systems. Most of us are familiar with IT systems, but a growing concern is focused on protecting OT systems. To help understand the difference, consider this simplified example. The internet router you have in your home is an IT system. If you have a smart bulb system, that’s an OT system; it might consist of several smart bulbs and a control bridge. The IT and OT systems communicate with each other, but they have different purposes. The IT system controls the flow of digital information. The OT system serves a specific purpose (providing light).

As another example, consider what is publicly known about the Colonial Pipeline hack, that led to major disruptions in gasoline for the east coast. The company obviously has a host of IT (routers, servers) and OT (valves, regulators, pumping stations) systems. In this case the hackers installed ransomware which compromised the IT systems involving billing and accounting. ^[1] This prevented normal business operations and operations were curtailed until systems were operational.

OT devices might also communicate amongst themselves and use different methods or protocols than the IT system. Your router (IT) has a firewall to prevent intrusion, but OT devices are often hacked to provide access. If an attack makes it past the IT systems, can the OT system detect that it is malfunctioning? In almost every case the answer is, no. While a hacked lightbulb might be an annoyance as the attacker could rapidly turn it on and off, a hacked generating asset OT system could be used to cause catastrophic damage. Most readers will have heard of the Target hack in 2013 when hackers obtained access to the business network through an HVAC system.

It’s also important to realize that most OT systems at a power plant consist of cyber-physical systems. In simple terms there’s often a controller, a sensor, and an actuator integrated to provide a useful purpose. In our light bulb example, you might set the control to turn on at dusk and off at dawn. A sensor on the bulb might detect when dusk and dawn happen, and an internal switch (the actuator) will turn the bulb on and off. If any of these three items are compromised, the light bulb will fail to function as intended by the user. Hacking the controller settings will obviously change on and off behavior. Hacking the actuator could cause the bulb to fail to turn on or off. Finally, compromising the sensor signal could cause the bulb to behave strangely, such as turning on when it’s daylight because the controller thinks it’s dark.

Ok, what does all of this have to do with power plants? As shown above, a power plant has a large number of OT systems, including sensors, actuators, controllers and communication infrastructure. A few examples of types of devices that could be compromised are listed, but the reality is the list is much longer. In the light bulb example, you would most likely notice it’s hacked because you can physically see the light. In a power plant, we’re often reliant on the sensor reading as the truth. An operator doesn’t often have the luxury of direct observation of the cyber-physical OT system.

Nonetheless, the industry has developed very sophisticated approaches to monitoring and diagnostics of their sensitive generation assets – approaches built upon development of digital twins that build out physics-based models of the plant, down to models of each component and even the sensors, including things like what a reasonable sensor reading will look like, or be correlated with other sensors.  These models are augmented with (1) data from the plant and/or aggregated over a set of plants, (2) sophisticated software, often based upon artificial intelligence approaches to detect anomalies, and (3) dedicated monitoring centers that are staffed by professionals who have developed a highly tuned ear and eye for “when something just doesn’t seem right.” Integration of these O&M competencies and assets with cybersecurity operations is low hanging fruit for the industry.

Unfortunately, a large amount of existing monitoring and diagnostics are focused on correlating the sensor signals. This leaves the middle of the OT information chain unmonitored. Consider that attackers often test their ability to make changes before committing to a full-scale attack. Has your credit card ever been stolen? Sometimes thieves will apply a small charge first to see if it works before purchasing something larger.

In a power plant, they may make a minor control change to test access before causing more severe damaging of the asset. In fact, this occurred in 2012 when, according to the U.S. Justice Department, Iran conducted an attack on the Bowman Dam in New York. The dam controls storm surges and the SCADA system was accessed in an apparent test to see if direct control of the infrastructure was possible. ^[2]

There are other incidents where the OT systems were compromised and hardware was destroyed or severely compromised. In 2014, attackers gained access to the IT business network of a German steel mill which provided further access to the control systems. The attackers disabled the ability to shutdown a blast furnace properly, resulting in significant damage. ^[3] Obviously, some attacks are more likely to be carried out than others, but actively monitoring OT assets for attacks creates a second line of defense.

This article is the first of a series that will explore examples and suggestions for auditing your current monitoring practices for gas turbines, photovoltaics, and wind to examine where you can add additional OT attack monitoring. Not all attack vectors are critical or the optimum pathway for an attacker. Creating cyber-attack specific models for detecting sensor, actuator, and controller attacks will help provide the second line of defense needed to prevent critical remote attacks.

References:

[1] Colonial Pipeline hack explained: Everything you need to know (techtarget.com)

[2] S. Prokupecz, T. Kopan, and S. Moghe, Former social: Iranians hacked into New York dam, CNN, www:cnn:com/2015/12/21/politics/iranian-hackers-new-york-dam/index:html), December 22, 2015.

[3] Hemsley, K., Fisher, R., “History of Industrial Control System Cyber Incidents,” INL/CON-18-44411-Revision-2

About the Authors:

Chris Perullo is Director of Engineering at Turbine Logic. He leads day-to-day development of customized monitoring and diagnostic solutions and services for natural gas and renewable energy assets.

Tim Lieuwen is Regents’ Professor and Executive Director of the Strategic Energy Institute at Georgia Tech, and founder of Turbine Logic.

Turbine Logic (www.turbinelogic.com) is an analytics firm specializing in the power generation industry, that develops software for monitoring power generating assets, and provides consulting services to OEM’s, utilities, users, and related organizations around the world. Applications of this work include O&M, financial plant models, energy markets, and cybersecurity.

Nuclear will play a crucial role in the transition to net-zero, not only because it’s the second-lowest emitter of CO2, but also because its resilience and reliability ensures security of supply in a system using increasing amounts of intermittent renewables. We need a resilient energy supply to power the transition to net-zero, one that can also tackle the increase in demand that electrification of transport and heat will create.

The UK’s target to fully decarbonize its energy generation by 2035 is no small task. Replacing aging plants and ensuring sufficient energy capacity to meet demand is estimated to require around 159 to 203 GW of new assets: that’s equivalent to building the UK’s entire energy system twice over in under 13 years.

By 2030, power generation is scheduled to have ended at seven UK advanced gas reactor nuclear power stations, yet many of the new generation assets won’t come online before 2036.

Time is not on our side

Time is not on our side: it can take over a decade to design, construct and commission new assets. The clock is ticking and we need to find ways to not only increase the pace of new build development but also extend the useful life of existing plants.

Extensive manpower is also required to achieve these goals and the sector has a skills gap that’s cause for concern. This reaches across all stages of the nuclear lifecycle, from design and development through to operations, maintenance to decommissioning. The reason? An aging workforce – a third of which is expected to retire in the next 15 years.

Without digital, nuclear will fail to achieve its true potential

If we’re to overcome these challenges and ensure nuclear fulfils its potential in the future energy mix, the sector simply must embrace digital tools and the benefits they bring.

Every major engineering industry is embracing a digital future, and the supply chain is starting to demand it. If nuclear doesn’t adapt, then it risks being left behind, operating with the same on-site uncertainty, bottlenecks and lack of early warnings while others move forward and reap digital’s rewards.

The simple truth is this: digital can make a difference at every point of the nuclear lifecycle, and the sector needs to take advantage of the tools at its disposal.

Digital’s role in plant design and construction

The related cost savings will ensure the necessary funds are available to meet the UK’s required build rate of the next generation of nuclear plants, which can also be enhanced through the use of digital tools.

The design and construction of plants are incredibly complex and processes often could – and should – be optimized. Prioritization of tasks may be inefficient or KPIs subjective, for example, but when a fully collaborative and consistent digital approach is adopted it’s not just a digital transformation that takes place.

By pulling all data into one single digital source, transparency and risk awareness is transformed, which in turn helps to optimize processes and decision-making.

Capturing, reusing, codifying and analyzing data also has the ability to speed up the traditional design process by up to 80%. With time sorely of the essence, why wouldn’t you take advantage of such abilities?

A process digital twin, for example, transforms the design process by integrating a simulation model into the early stages. This way the design is completed in a digitally-integrated way to ensure everything remains up-to-date. This improves workflows between disciplines, significantly reducing the chance of repetition to improve efficiencies.

As well as cutting start-up time and overall risk, costs can also be saved. 3D modelling can lower costs by up to 30%, for example, while 15% can be saved on the overall installed cost through design optimization.

Data captured during design and construction can also add value throughout the nuclear lifecycle.

One of the main challenges the sector faces is scattered, unstructured data from legacy plants. By recording and storing data from the start, we can also help to optimize processes in the operations and decommissioning stages.

Digital’s role in asset management and plant life extension

Digital twins can simulate and evaluate alternative maintenance and operational strategies, enabling you to identify the most cost-effective options for your plant.

Then there’s AI-powered predictive maintenance, which can lower unplanned downtime by 35%, saving tens of millions in asset failure prevention and providing a secure energy supply. Its use has also been proven to extend a site’s useful life by 10% – critical given the plant life extensions currently being implemented across the UK.

Digital’s role in decommissioning and waste management

As an operational plant comes to the end of its life, digital plays a part. By capturing and making data available, those involved can have a 360° view of a plant and can determine efficiencies that will accelerate the dismantling and demolition of plants, freeing up valuable real estate for new nuclear facilities to be built.

Webcast recording: The Decommissioning & Re-purposing eco-system – vital to the energy transition

Plugging the skills gap

We also need digital to overcome the challenge of a shrinking skilled workforce. The knowledge of industry stalwarts should be gathered and stored before it becomes lost, plus automation can provide efficiencies and help tackle workforce attrition by augmenting human personnel.

Furthermore, robotics can ensure the continued safety of staff. By replacing people with remotely-operated robots in hazardous situations, workers’ exposure to radiation is lowered, if not entirely removed.

Robots also aren’t restricted to how long they can work in a hazardous environment. Using such tools means time working onsite can be increased and tasks completed faster. Consider this – a 20% schedule saving over a 120-year decommissioning program could reduce overall timescales by a generation.

Barriers to break

Looking forward, nuclear simply cannot afford not to embrace technology. If it’s to meet its potential, we need the benefits of digital – efficiency, reduced costs, increased safety and sustainability – but there are several barriers standing in the way of the sector’s digital transformation.

Firstly, we need to ensure people don’t feel threatened by technologies such as AI and robotics, which have been developed to augment rather than replace. Then we need to improve confidence in cybersecurity. Trust is low, yet it’s actually been proven that people are the weakest link, as 99% of cyberattacks use techniques such as phishing to trick users into installing malware.

The boardroom also has a role to play by embracing new business models that require investment up front to realize long-term efficiencies. However, that shouldn’t be too tough, as the pandemic brought to the forefront how invaluable technology can be and has already accelerated investment.

We need to take learning from the rapid progress achieved during the last three years, as well as the sense of urgency that powered it. If we don’t, nuclear simply won’t be able to achieve its full potential as a central part of the UK’s net zero energy system.

Read more about the nuclear sector’s digitalization journey in SNC-Lavalin’s report, Digital in nuclear: our vision for 2035.