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.

That was the verdict from TVA’s Final Environmental Impact Statement issued by the federal utility Feb. 16 after a public review process last year over how to replace the coal-fired units at Kingston. TVA anticipates making a final decision in March 2024.

TVA mainly evaluated two options to provide at least 1,500 MW of generation to replace the capacity to be lost, plus additional capacity to support anticipated load growth.

The first option would include the construction of a single combined-cycle gas plant paired with 16 dual-fuel Aeroderivative combustion turbines, a 3 to 4 MW solar site and a 100 MW battery energy storage system on the Kingston Reservation. The combined-cycle plant would be capable of burning 5 percent hydrogen by volume at commissioning and 30 percent hydrogen with modifications to the balance of plant once a reliable source of H2 was identified, TVA said.

The first option would also include Eastern TN Natural Gas (ETNG) constructing and operating a 122-mile natural gas pipeline, gas compressor station and metering and regulator stations.

The second option would consist of constructing multiple solar and energy storage facilities at alternate locations, including in Eastern Tennessee. The construction of a pipeline would be subject to Federal Energy Regulatory Commission (FERC) jurisdiction and additional review.

TVA said its preferred option is the first. The federal utility said a combined-cycle plant paired with dual-fueled aero turbines would be the “best overall solution to provide low-cost, reliable energy to TVA’s power system, and could be built and become operational sooner” than the solar and storage in the second option.

The utility said it also preferred the gas plant option to provide the flexibility needed to bring 10,000 MW of solar onto the system by 2035.

‘Increased wear and tear’ for coal units

Kingston’s nine units can generate about 1.4 GW of electricity at capacity. The plant, located about 35 miles west of downtown Knoxville, entered operations in the 1950s.

TVA said frequent cycling of Kingston’s units, reflected in start-up and shutdown events, are currently averaging more than 85 times per year, which the utility said is outside the intended design of the plant.

This is resulting in “increased wear and tear, which presents reliability challenges that are difficult to anticipate and expensive to mitigate.”

TVA also said Kingston has experienced a “significant decline” in material condition over the last five years, including the need for repairs to the lower boiler drum, which the utility said are symptomatic of age-driven material condition failures which are difficult to proactively address.

The utility said based on these factors, it has developed planning assumptions for the timing of the proposed retirement of Kingston.

In general, TVA said its aging coal fleet is experiencing deterioration of material condition and performance challenges. Performance challenges are expected to increase because of the fleet’s advancing age and the difficulty of adapting coal within the changing generation profile.

TVA has reduced carbon emissions from its entire generating fleet by about 60% since 2005, thanks to a combination of closing coal plants and building solar and wind.

It’s yet another sign of the growing recognition for nuclear power’s dispatchable, carbon-free characteristics and its place in a net-zero world.

But there are still hurdles to jump. Despite growing support, the economics are daunting. Smaller reactors are viewed as an antidote to the cost overruns that have plagued large-scale nuclear projects, but their promise of offering simplicity and standardization has yet to be tested.

Additionally, first of a kind (FOAK) small modular reactor (SMR) costs could be as high as $8,000 per kilowatt (kW) and as low as $6,000 per kW, according to industry estimates cited by Wood Mackenzie.

“There’s quite a lot of financial risk for the companies bringing these products to market, about how long the licensing process is going to take and how much it’s going to cost,” said Eric Ingersoll, Founding Director and Co-CEO of Terra Praxis.

Terra Praxis – through its REPOWER initiative and partnership with governments, regulators and other industry stakeholders – is a nonprofit which aims to speed up the nuclear project regulatory process, from feasibility evaluation and design to construction and operation. The idea is to reduce time, cost and risk in order to stimulate further investment and fulfill the industry’s potential.

As Ingersoll noted, traditional project licensing involves extensive documentation, often resulting in multi-year timelines and significant costs. He said costs are driven by “hiring lots of expensive people to write huge long documents, and then hiring even more expensive people to read them over and make sure they’re correct.”

Nuclear’s Evolution is an educational track at the POWERGEN International® exhibition and summit, which serves as an education, business and networking hub for electricity generators, utilities, and solution providers engaged in power generation. Join us from January 23-25, 2024, in New Orleans, Louisiana!

But tapping into artificial intelligence (AI) could be pivotal in streamlining these activities.

Terra Praxis and Microsoft together are exploring the use of generative AI to expedite the drafting of documents, such as environmental impact statements, by providing specific site details to a large language model.

In addition to document preparation, Ingersoll sees a significant opportunity for AI in the review and verification of license applications, potentially creating a more interactive and collaborative process between developers and regulators.

“We think the possibility to accelerate the licensing process by more than 90% is there,” said Ingersoll.

He said another area of focus for the organization involves automated design using AI. By incorporating rules and smart design systems with built-in regulatory compliance, the aim would be to expedite the path to a compliant design that could then undergo human review.

Accelerating these processes make it feasible for large-scale projects like repowering coal fleets, Ingersoll said.

A previous U.S. Department of Energy (DOE) study found hundreds of coal-fired power plant sites could convert to advanced nuclear sources, potentially reducing capital costs by 15% to 35% when compared to a greenfield construction project. This range would depend on the reuse of coal plant infrastructure, including office buildings and electric switchyard components and transmission infrastructure, heat-sink components and steam-cycle components.

Terra Praxis believes its solutions should increase the market opportunity even beyond the DOE’s assessment. The organization’s Repowering Coal solution is targeting a Levelized Cost of Energy of $35-$40 per megawatt-hour (MWh).

The company notes that when factoring in the production tax credit of $30/MWh from the Inflation Reduction Act, repowering coal-fired plants with advanced nuclear power “has the potential to be a highly profitable investment opportunity.”

Ingersoll said REPOWER customers, such as coal plant owners aiming to convert their assets, would have access to automated project design tools and site licensing and permitting template-based standardized applications.

See our interview with Terra Praxis Founding Director Eric Ingersoll from Enlit Europe above. For more exclusive content, visit Enlit.world.

Valley Children’s Hospital in Madera, California aims to replace diesel generators with cleaner sources yet ensure uninterrupted power supply.

Australia-based Redflow will collaborate with Faraday Microgrids on the project, named the Children’s Hospital Resilient Grid with Energy Storage (CHARGES).

The project is receiving funding from the U.S. Department of Energy (DOE) for 15 long-duration energy storage projects across 17 states and one tribal nation. The $325 million LDES program comes from the Infrastructure Investment and Jobs Act (IIJA). The awards were announced last week.

CHARGES is sponsored and expected to be co-funded by the California Energy Commission (CEC).

Valley Children’s Hospital, located in California’s Central Valley, frequently faces extreme environmental challenges, including heatwaves, droughts, smog and poor air quality. California has a goal of installing 45-55 GW of long-duration energy storage by 2045 to support grid reliability and clean energy adoption.

The microgrid system is designed to safeguard critical hospital operations during utility outages, ensuring at least 18 hours of continued functionality following earthquakes or other natural disasters.

Redflow’s systems are based on zinc-bromine flow battery chemistry. Flow batteries use liquid electrolytes that flow through the battery cells during charging and discharging processes. Zinc is the primary element in the Redflow battery’s anode, while bromine is used in the cathode.

Reaction to the U.S. Environmental Protection Agency’s proposal to cut carbon pollution from coal and natural gas-fired power plants has been mixed, according to comments filed with the federal agency.

Some utility trade groups say the EPA’s proposed rule should not be finalized, while others say improvements are needed. Still other utilities have thrown their support behind it.

The Edison Electric Institute (EEI), the association that represents U.S. investor-owned utilities, said its members are not confident that technologies designated as the main compliance options under the proposed rule will be technically feasible given the projected implementation timelines.

Those technologies are carbon capture and sequestration (CCS) and hydrogen co-firing.

EEI said the rule as proposed should not be finalized, saying it would negatively impact reliability and affordability for utility customers. The EPA rule would not be made final until next year.

The group said if EPA does move forward with the standards as proposed, it should provide electric companies as well as states with “as much compliance flexibility as possible” to address achievability concerns. EPA also should commit to providing broad enforcement discretion should the technologies not perform reliably or be available on the agency’s projected timeframes, EEI said.

The proposed rule was announced by EPA in May and would require coal-fired plants that plan to operate past 2039 to install CCS to capture 90% of their CO2 emissions. Coal plants intending to retire before 2032 or retire by 2035 and run at a 20% capacity factor or less would not face limits under the rule.

Gas-fired combustion turbines larger than 300 MW and with at least a 50% capacity factor would have to capture 90% of their carbon by 2035 or co-fire with 30% hydrogen starting in 2032. Those plants would need to co-fire with 96% hydrogen starting in 2038.

Other groups echoed EEI’s concerns about the ability of hydrogen and CCS technologies to emerge and deliver under the proposed timelines.

“EPA couples these inadequately demonstrated technologies with unworkable timelines that will be impossible to achieve,” said the National Rural Electric Cooperative Association (NRECA), which represents 900 nonprofit electric co-ops and other rural electric utilities.

In order to get around EPA’s combustion turbine requirements, NRECA said the proposal would likely lead to the building of more, smaller units that operate at less than 50% capacity.

The Electric Power Supply Association (EPSA) said the EPA is underestimating how much gas- and coal-fired capacity would retire due to the proposal. EPSA represents the interests of independent power producers.

“At a time when our nation should be retaining needed existing resources and investing in new infrastructure in response to policy decisions which are driving an increase in electricity demand, this proposal will likely force a substantial amount of generation to either run less or pull the plug on their power plants entirely,” EPSA said in its comments.

A rosier outlook

Some utility interest groups are looking at EPA’s proposal more favorably.

The Energy Strategy Coalition–whose members include Calpine, New York Power Authority and Pacific Gas and Electric–said the EPA is on solid legal grounds to use CCS and clean hydrogen as best available compliance technologies.

With the support of favorable incentives in the Infrastructure Investment and Jobs Act (IIJA) and Inflation Reduction Act (IRA), the group said its members are investing to scale up CCS and clean hydrogen for emission reduction at fossil-fired plants.

The coalition said a technology can be “adequately demonstrated” even if it is new and not yet broadly adopted.

“Given adequate lead time, both technologies meet this standard,” the group said.

Constellation Energy, which has invested in both CCS and hydrogen blending initiatives, also offered strong support for the EPA proposal.

“Far from being too restrictive, the guidelines offer flexibility and build on technology and processes that the industry is already putting in use to great effect today,” said Joe Dominguez, Constellation President and CEO. Constellation also operates one of the largest fleets of nuclear power plants in the country.

He added: “I am disappointed to see many of my peers represented by the Edison Electric Institute and others working to block these very practical measures rather than offering constructive solutions and recognizing the imperative of moving our industry toward a carbon-free future, as we inevitably must do.”

Xcel Energy said it believes much of the EPA’s proposal is workable but added recommendations for certain compliance flexibilities where necessary. For example, the utility urged EPA to set the capacity factor limit for new low-load natural gas units at 25%, assessed over a 36-month period.

According to DOE, this will be the world’s largest investment in engineered carbon removal in history.

Together, these projects are expected to remove more than 2 million metric tons of carbon dioxide emissions each year from the atmosphere.

The two projects are the first to be selected from the Bipartisan Infrastructure Law-funded Regional Direct Air Capture (DAC) Hubs program, which aims to kickstart a network of large-scale carbon removal sites.

Their development will help inform future public and private sector investments and jumpstart a new industry critical to addressing the climate crisis on a global scale.

“Cutting back on our carbon emissions alone won’t reverse the growing impacts of climate change; we also need to remove the CO2 that we’ve already put in the atmosphere—which nearly every climate model makes clear is essential to achieving a net-zero global economy by 2050,” said U.S. Secretary of Energy Jennifer Granholm.

“With this once-in-a-generation investment…DOE is laying the foundation for a direct air capture industry crucial to tackling climate change—transforming local economies and delivering healthier communities along the way.”

The two DAC projects selected by DOE include:

• Project Cypress (Calcasieu Parish, LA): Battelle, in coordination with Climeworks Corporation and Heirloom Carbon Technologies, Inc., aims to capture more than 1 million metric tons of existing CO2 from the atmosphere each year and store it permanently deep underground. This hub intends to rely on Gulf Coast Sequestration for offtake and geologic storage of captured atmospheric CO2.
• South Texas DAC Hub (Kleberg County, TX): 1PointFive, a subsidiary of Occidental, and its partners, Carbon Engineering Ltd. and Worley, plan to develop and demonstrate a DAC facility designed to remove up to 1 million metric tons of CO2 annually with an associated saline geologic CO2 storage site.

DOE will now begin hosting community briefings to engage with local stakeholders in Texas and Louisiana.

To assess the viability of future DAC Hub demonstrations, DOE also announced 19 additional projects selected for award negotiations that will support earlier stages of project development, including feasibility assessments and front-end engineering and design (FEED) studies.

DOE intends to issue additional funding opportunity announcements in the coming years to fully implement the Regional DAC Hubs mandate from Congress.

Direct air capture

Direct air capture (DAC) technologies extract CO2 directly from the atmosphere at any location after which the carbon can be stored in geological foundations or used in a variety of applications.

DAC is unlike carbon capture which is usually carried out at the point of emissions.

According to the International Energy Agency, DAC is significantly more expensive than carbon capture and is a highly energy-intensive process. A great deal of land and water are also required for DAC projects.

Globally, twenty-seven DAC plants have been commissioned to date, capturing almost 0.01 Mt CO2/year. Plans for at least 130 DAC facilities are now at various stages of development.

Stryten Energy said its 20 kW/120 kWh VRFB was installed at Snapping Shoals EMC’s headquarters in Covington, Georgia. The partners commemorated the installation on August 2.

Stryten said its battery, the first vanadium redox flow battery to be manufactured and installed in Georgia, is suited for applications that require medium- to long-duration energy storage of six or more hours. The company said its battery can operate for more than 20 years without the electrolyte losing energy storage capacity.

The VRFB is currently connected to the grid. Engineers from Snapping Shoals EMC and Stryten Energy will be working together to monitor the system under different real-world conditions and learn how the battery interacts with the grid. The pilot project is expected to take about six months.

“We are ultimately looking at this from a grid resiliency standpoint,” said Robbie Young, Snapping Shoals EMC’s Vice President of Engineering and Developing Technologies.

Different from more prevalent stacked lithium-ion battery cells, vanadium redox flow batteries consist of tanks of liquid electrolytes and pumps that charge and discharge electrons to the grid.

“VRFB technology was appealing to us for its long-life expectancy, long discharge times, and the ease of scalability,” said Young. “Stryten Energy has been in the energy storage business for many years. They have a strong technology base and U.S.-based manufacturing. It just seemed like a good fit.”

Young expects VRFB technology to become a cost-effective, viable solution at some point for larger scale storage needs, such as at community solar installations or at substations.

Stryten Energy is working to establish a domestic supply chain for all components of its VRFB system, including vanadium electrolyte. For the Snapping Shoals project, the company said the electrolyte was manufactured in Maryland. Stryten said it is currently evaluating other vendors with manufacturing locations in Utah and Nevada.

The company noted it has seen “quite a bit of interest” in its VRFB energy storage systems due to the investment tax credits for domestically sourced and manufactured energy storage in the Inflation Reduction Act.

“As we install more renewable energy generation, whether that be wind or solar, the need for long-duration energy storage is also increasing,” a spokesperson for Stryten told Power Engineering. “VRFBs fill that important role in the clean energy transition by providing energy storage that is rapidly scalable, domestically available, sustainable, safe and resilient.”

The spokesperson said while it is too early to determine the steps beyond this project, Stryten is already applying the learnings gained from its generation three systems to be installed for upcoming demonstration projects.

B&W said its BrightLoop technology is a chemical looping technology that can produce hydrogen from nearly any feedstock, including solid fuels such as waste wood and other types of biomass. The company said its process also produces an isolated CO2 stream for capture, use or sequestration, as well as nitrogen that can be combined with hydrogen to create ammonia.

Babcock & Wilcox also said it reached an agreement for General Hydrogen, a CGI Gases subsidiary, to purchase hydrogen from the facility. General Hydrogen would purchase and transport off-site up to 15 tons of hydrogen per day, according to the terms of the agreement.

CGI Gases would purchase and transport compressed carbon dioxide (CO2) captured during the process.

Joe Buckler, B&W Senior Vice President of Clean Energy, said the hydrogen could be used in power production, industrial processes or as transportation fuel.

Bill Gates-backed Terrapower said the companies will make up key elements of the supply chain for the next-generation, small nuclear plant.

Western Service Corporation will provide the software platform and engineering services for the Natrium Engineering Simulator. TerraPower is developing a simulator that can replicate normal operation and plant protective functions, which the company said offers opportunities to integrate system functions and perform virtual commissioning in early stages.

James Fisher Technologies is designing and building an injection casting furnace system that will be implemented in TerraPower’s Everett laboratory and will demonstrate the basic functionality of the injection casting process.

BWXT Canada will design the Intermediate Heat Exchanger for the Natrium Reactor Demonstration Project. The Intermediate Heat Exchanger transfers heat from the primary sodium in the primary heat transport system to the intermediate sodium in the intermediate heat transport system.

Curtiss-Wright will develop the Reactor Protection System for the project. The RPS performs important safety functions in accordance with regulatory requirements. This specific contract includes the provision of a prototype system and planning and engineering support prior to the detailed design, manufacture, testing and delivery of the RPS.

The Natrium technology features a 345 MWe sodium-cooled fast reactor with a molten salt-based energy storage system. The storage technology can boost the system’s output to 500 MWe for more than five and a half hours when needed. TerraPower said this addition allows a Natrium plant to integrate well with renewable resources.

In December 2022 TerraPower said it expected operation of the Natrium reactor to be delayed by at least two years due to not enough commercial capacity to manufacture high-assay low-enriched uranium (HALEU) fuel in time to meet the proposed 2028 in-service date.

The company since agreed with Centrus Energy on a collaboration aimed at establishing commercial-scale, domestic HALEU production capabilities. The U.S. Nuclear Regulatory Commission (NRC) had approved Centrus’ request to make HALEU fuel at its Piketon, Ohio facility. The plant is now the only licensed HALEU production facility in the United States.

The Republicans told EPA Administrator Michael Regan that the agency overstepped its legal authority under the Clean Air Act to curb emissions from the plants.

The EPA proposal would require coal plants to capture 90% of their emissions by 2030. Gas plants, new and existing, would need to capture 90% of their emissions by 2035 or run mostly on hydrogen energy by 2038.

In its proposal the EPA cited multiple examples of existing and planned power generating projects that use carbon capture and sequestration (CCS) and hydrogen co-firing technologies, which are bedrock strategies for achieving its newly proposed carbon emission reductions.

Senate Republicans said these were “sweeping claims” about the future availability of CCS and hydrogen co-firing. They said these technologies “are still nascent and have not yet been adequately demonstrated.”

The new rules replace the Obama administration’s Clean Power Plan, which was proposed in 2015 but ran into multiple legal challenges and never took effect. Even so, in the 2022 ruling of West Virginia v. EPA, the U.S. Supreme Court found that the Obama administration’s approach exceeded the EPA’s authority to regulate power plant emissions under the Clean Air Act. Specifically, the court said EPA couldn’t direct plants to shift from dirty sources of energy to cleaner ones like wind and solar.

The GOP senators claimed in their latter that the latest EPA proposal was in “direct conflict” with West Virginia v. EPA.

“While the Agency falsely claims this does not run afoul of the Supreme Court’s decision, it is undeniable the proposal would require generation shifting that the Court has definitively found Congress has never granted EPA the authority to require under the Clean Air Act,” the letter reads.

EPA is allowing public comment on the proposed rules until August 8.