The Oct. 6 filing noted that Southern Nuclear has started the process of replacing the faulty reactor coolant pump (RCP) with an onsite spare one from inventory. The new in-service timeframe is projected for the first quarter of 2024.

The filing said since Unit 3’s four RCPs operated as designed, Southern Nuclear believes that the motor fault in this case is an isolated event. Vogtle Unit 3 entered commercial operation on July 31, 2023.

Utility officials said the projected schedule for Unit 4 primarily depends on the “continued progression of pre-operational testing and start-up, which may be impacted by further equipment, component, and/or other operational challenges.”

They added future challenges could also include management of contractors and related cost increases.

Further updates will be provided in connection with Southern Company’s earnings call in November 2023.

Vogtle Units 3 and 4, representing 2,200 MW, are the first nuclear units to be built in the U.S. in more than three decades. But the journey hasn’t been easy: Cost overruns and construction problems have delayed the project. Project partners have disputed over rising construction costs and their stake in the venture.  

As defined by the U.S. Nuclear Regulatory Commission (NRC), each ITAAC closure notice must be verified before fuel load.

The company now awaits receipt of the 103(g) finding from NRC documenting that license acceptance criteria for Unit 4 have been met. This will indicate that the new unit has been constructed and will be operated in conformance with NRC regulations.

All 157 fuel assemblies required for the operation of the Unit 4 reactor have been delivered to the site, Southern Nuclear said. Each fuel assembly was inspected and transferred to the new fuel storage racks before being placed into the spent fuel pool where all the assemblies will be stored until they are loaded into the Unit 4 reactor during fuel load.

Georgia Power said fuel load is expected at Unit 4 in the third quarter of 2023. The unit is projected to enter service in late fourth quarter 2023 or the first quarter 2024.

Vogtle Unit 3 missed its most recent deadline of June to come online, due to a problem in the hydrogen system used to cool its main electrical generator. Last month Georgia Power estimated the reactor will begin reliably sending electricity to the grid this month.

Units 3 and 4 at Plant Vogtle are the first new reactors built from scratch in decades in the United States. The first two reactors have been generating electricity at Vogtle for decades.

The project, which is seven years behind schedule, has seen the cost that its owners will pay double to more than $31 billion. That doesn’t include $3.7 billion that original contractor Westinghouse paid to the owners after going bankrupt, which brings total spending to almost $35 billion.

The utility plans to install docks onsite at its plants to enable inspections. The docks can be compared to aircraft hangars for drones.

For the last year, Southern Co. has used Plant Barry in Alabama as the test site to capture data and prove to the FAA this technology could be used safely.

The utility called the latest development a “huge step” in advancing autonomous and remote operations at scale.

Mat Spurlock, Sr. UAS Pilot for Southern Company, told Power Engineering inspections now can be done remotely from a control center, keeping employees out of potentially hazardous environments. Previously, a pilot and visual observer had to be onsite.

“Efficiency and safety are the two drivers for this,” he said.

For example, proactive inspections of cooling towers, turbines, dry cask storage at nuclear facilities or panels at solar farms could be done more often and efficiently.

At a nuclear plant’s dry cask storage facility, inspections are conducted on a daily occurrence, with a radiation protection technician, engineer and security officer all needed onsite. Now, a dock could be installed at the plant, with a drone completing that mission and delivering data automatically to the engineer.

“The goal is to build a [machine learning] model to even eventually remove the engineer from having to inspect that data,” said Spurlock. “It would point out, this is different than it was yesterday, or this is an obstructed vent.”

Spurlock also noted the benefit of O&M cost reductions, with multi-day processes reduced to 45 minutes.

“Say we have a fault in the switchyard at a plant, we can immediately launch that aircraft, go to that location and try to determine what caused it without sending personnel out there,” said Spurlock. “Then when we do dispatch personnel or equipment, we already know what they’re getting into.”

The only two notifications required for an inspection would be NOTAMS, or notifications to other pilots if there’s an airport nearby, and to Southern Company’s own personnel where the drone will be launched.

Spurlock said future inspections will be pre-programmed. Inspectors could view the flights in real-time or examine the post-process data after it’s recovered.

“It’s really just game-changing to us,” he said.

On March 6, Unit 3 achieved initial criticality and on April 1, the generator successfully synchronized to the power grid and generated electricity for the first time.

According to the filings, the projected schedule for Unit 3 primarily depends on the progression of pre-operational testing and start-up, which may be impacted by further equipment, component or other operational challenges.

Operators are continuing to perform tests at different power levels and address various equipment and component issues as they are identified.

On March 15 with Unit 3 in Mode 1 at 18%, the reactor automatically tripped due to the loss of two reactor coolant pumps when their electrical buses failed to transfer after a main generator excitation protective relay tripped. The incident was reported to the Nuclear Regulatory Commission.

Operators responded and stabilized the plant by engaging relief valves that removed decay heat. Units 1, 2, and 4 were not affected.

The two AP-1000 reactors at Vogtle Units 3 and 4, each with a capacity of approximately 1,100 MW, are the first new nuclear units to be built in the U.S. in more than 30 years. Cost overruns and construction problems have long delayed the project.

Southern Nuclear will operate Vogtle Units 3 and 4 on behalf of co-owners Georgia Power, Oglethorpe Power, MEAG Power and Dalton Utilities.

Hot functional testing for Unit 4 began on March 20, and fuel load is projected for the third quarter of 2023. Unit 4 is projected to be placed in service during late fourth quarter 2023 or the first quarter 2024.

According to the quarterly filings, the timeline for Unit 4 depends on potential impacts from testing activities overlapping with Unit 3 start-up and commissioning, as well as overall construction productivity and production levels, particularly in subcontractor scopes of work; and maintaining appropriate labor levels.

A newly-formed coalition of some of the largest utilities in the U.S. will pursue a “six-state hydrogen hub” in the Southeast and plans to apply for funding from an $8 billion U.S. Department of Energy program.

The coalition includes Dominion Energy, Duke Energy, Louisville Gas & Electric Company and Kentucky Utilities Company (LG&E and KU), Southern Company, and the Tennessee Valley Authority (TVA), along with Battelle and others, according to an announcement Nov. 1.

Other members of the group will include hydrogen users from a variety of industries in Alabama, Georgia, Kentucky, North Carolina, South Carolina and Tennessee.

Many believe hydrogen is poised to play a major role in addressing climate change. In power generation, the advantages of hydrogen include fuel flexibility through the ability to blend hydrogen with natural gas, fuel security through integration with hydrogen storage and the flexibility to follow loads from variable generation.

Major OEMs like GE, Siemens and Mitsubishi Power have been focusing their efforts on hydrogen combustion in gas turbines, particularly for large-scale generation.

MORE: Should we just burn hydrogen for electricity?

“By working together, the coalition can focus on developing scalable, integrated projects at key locations across the entire Southeast in support of these carbon-reduction goals and encourage the broad-based development of a regional energy ecosystem that will allow members to deploy hydrogen as a decarbonization solution for customers and communities,” said a joint release from the utilities.

DOE’s $8 billion regional hydrogen hub program comes from the Infrastructure Investment and Jobs Act (IIJA) passed in 2021.

According to program criteria, hubs would need to demonstrate the production, processing, delivery, storage and end use of clean hydrogen.

Hydrogen hubs would be sited in different regions of the U.S. DOE said it envisions selecting between 6-10 hubs at a total of $6-7 billion, depending on the number, quality and funding needs of applications received. The remaining $1-2 billion could be reserved for future hub launches or other supporting activities.

To the maximum extent possible, the DOE would choose projects based on several objectives:

-At least one hub would produce hydrogen from fossil fuels, one hub from renewable energy, and one hub from nuclear energy.

-At least one hub would demonstrate the end-use of clean hydrogen in the electric power generation sector, one in the industrial sector, one in the residential and commercial heating sector and one in transportation.

-Each hub would be located in a different region of the United States and leverage energy resources abundant to that region, including at least two hubs in regions with abundant natural gas resources.

-DOE would give priority to hubs likely to create opportunities for skilled training and long-term employment to the largest number of residents in the region.

Southern Company and TerraPower completed installing a test facility at TerraPower’s laboratory in Everett, Washington, a step toward advancing its next-generation nuclear reactor.

The Integrated Effects Test (IET) is a multi-loop test facility with a non-nuclear system that is heated by an external power source and used to help validate the thermal hydraulics needed to demonstrate molten salt reactor systems.

TerraPower, backed by Bill Gates, is working on a chloride salt-fueled reactor without a moderator, the Molten Chloride Fast Reactor (MCFR). The MCFR technology operates at higher temperatures than conventional reactors and offers potential for process heat applications and thermal storage.

TerraPower says the reactor can operate using several fuel sources – including depleted and natural uranium or even spent fuel from existing reactors. The company hopes to demonstrate it in the early 2030s.

“The project culminates years of separate effects testing and is expected to demonstrate how the MCFR technology will perform in delivering a commercial-scale, cost-effective, carbon-free molten salt reactor energy source by 2035,” said Southern Co. in a statement.

The installation of the IET was part of a seven-year, $76 million project with the Department of Energy (DOE) to further develop the MCFR system. Work began in 2015 and is intended to promote the design, construction and operation of Generation-IV nuclear reactors. The project team also included CORE POWER, EPRI, Idaho National Laboratory, Oak Ridge National Laboratory and Vanderbilt University.

The system will also support development and operation of the Molten Chloride Reactor Experiment (MCRE) at Idaho National Laboratory, a less than 200 KW reactor meant to provide experimental and operational data.

The MCFR is separate from TerraPower’s natrium reactor and integrated energy storage technology under development.

With partner GE-Hitachi, TerraPower plans to build the natrium reactor in Kemmerer, a southwestern Wyoming city of 2,600 where the coal-fired Naughton power plant operated by PacifiCorp subsidiary Rocky Mountain Power is set to close in 2025.

Nothing to be salty about here 🧂 By placing a new sodium-cooled fast reactor + molten salt energy storage system near a retiring WY coal plant, advanced nuclear reactor tech will help keep jobs local and bring clean energy to homes across the country:https://t.co/s0Nn2OEe6f pic.twitter.com/aWgDfspiZ8

— Secretary Jennifer Granholm (@SecGranholm) October 18, 2022

Proponents of the project, featuring a 345 MW sodium-cooled fast reactor and molten salt-based energy storage, say it would perform better, be safer and cost less than traditional nuclear power.

The high-operating temperature of the Natrium reactor, coupled with thermal energy storage, would allow the plant to provide flexible electric output that complements variable renewable generation such as wind and solar. In addition, this project would establish a new metal fuel fabrication facility that is scaled to meet the needs of this demonstration program.

Nuclear operators and technicians are now moving fuel into Plant Vogtle Unit 3 as the nuclear generating unit moves closer to entering service.

During fuel load, technicians and operators from Westinghouse and Southern Nuclear are scheduled to transfer 157 fuel assemblies one-by-one from the Unit 3 spent fuel pool to the unit’s reactor core.

Startup testing will begin next and is designed to demonstrate operation of the primary coolant system and steam supply system at design temperature and pressure. Operators will also bring the plant from cold shutdown to initial criticality, synchronize the unit to the electric grid and systematically raise power to 100%. Southern Nuclear will operate the new unit.

The fuel load process marks a milestone toward startup and commercial operation. Plant Vogtle Units 3 and 4, representing 2,200 MW, are the first to be built in the U.S. in more than three decades. 

Reaching the milestone hasn’t been easy: Cost overruns and construction problems have delayed the project. Project partners have disputed over rising construction costs and their stake in the venture. Vogtle Unit 3 is currently expected to come online by the end of the first quarter of 2023, and Unit 4 is expected at the end of 2023.

Oglethorpe Power gave a more specific target operation date of March 2023, pending the results from testing.

“We are one step closer to bringing Unit 3 online to deliver emission-free, reliable baseload energy… for the next 60 to 80 years,” said Oglethorpe Power President and CEO Michael Smith. 

In August, The Nuclear Regulatory Commission (NRC) authorized Southern Nuclear to begin fuel loading at Vogtle Unit 3.

The unit is the first reactor to reach this stage under the NRC’s combined license process. The decision moved the 1,117 MW AP1000 generating unit out of NRC construction monitoring and into the regulatory body’s operating reactor oversight process.

FILL’ER UP: @GeorgiaPower announces fuel loading at Vogtle Unit 3 has begun! @WECNuclear & @SouthernNuclear are scheduled to load 157 fuel assemblies into the reactor core.

Unit 3 is projected to enter service in the first quarter of 2023.

Learn more: https://t.co/Ma1bHgXcCh pic.twitter.com/nUgF3euice

— Office of Nuclear Energy (@GovNuclear) October 14, 2022

In July 2022, Southern Nuclear told the NRC that it had completed all inspections, tests, analyses and acceptance criteria needed to show Vogtle Unit 3 is ready for operation.

The milestone came with the receipt of the NRC’s so-called 103(g) finding, which signified that the new unit has been constructed and will be operated in conformance with the Combined License and NRC regulations.

During fuel load, technicians and operators from Westinghouse and Southern Nuclear are scheduled to transfer 157 fuel assemblies one-by-one from the Unit 3 spent fuel pool to the unit’s reactor core.

Plant Vogtle is located near Waynesboro in eastern Georgia near the South Carolina border and is jointly owned by Georgia Power (45.7%), Oglethorpe Power Corporation (30%), Municipal Electric Authority of Georgia (22.7%) and Dalton Utilities (1.6%).

Climate change, energy independence, renewable power, the hydrogen economy, etc., are all terms used in recent years (or even decades) to describe the most important challenges of society today. 

While arguments are made over the proper direction to face these challenges, it is important to estimate the potential of candidate technologies for reaching these goals before society commits completely to them. While it is popular to look for a “quick-fix”, solutions almost always require an assortment of varied technologies implemented throughout the entire energy value chain, involving millions of people and costing hundreds of billions (if not trillions) of dollars.  These solutions are also likely to involve technologies that require incremental steps to gain public acceptance and/or prove parts of the process are feasible. 

Combustion or “gas” turbines are highly valuable power generation and heating commodities. In many gas turbines, natural gas (NG) is the fuel of use.  NG is generally a low cost and relatively high energy density fuel with a lower carbon content then coal or liquid fuels. This leads to reduced carbon emissions relative to those fossil fuels. However, while burning NG, carbon dioxide (CO₂) remains a primary constituent of the exhaust emissions.  Therefore, shutting down gas turbines or re-envisioning them for a low-carbon future is a popular research, discussion and development topic. One such proposed re-configuration is blending Hydrogen (H₂) with the NG fuel stream to further reduce CO₂ emissions.

The reduction in CO₂ emissions trends generally with the mass ratio of H₂ in the fuel, such that burning 100% H₂ reduces the CO₂ emissions by 100%. Note the reduction of CO₂ is non-linear with volume % of H₂ in the fuel, with the largest reductions being realized at the higher H₂ volumetric percentages (20% by vol is 3% by mass and 80% by volume is 33% by mass).  

OEMs have been working for many years now to prove out or upgrade their combustion systems for higher H₂ content for which they were originally designed.  Mitsubishi Power has been doing this same work for its M501G advanced class gas turbine. 

Overall, this case study is focused on the H₂/NG blending and burning project conducted at Southern Company/Georgia Power’s Plant McDonough in the Atlanta, GA metro area.  The unit is a Mitsubishi Power M501G gas turbine with a nameplate load of 265MW at baseload and a dry, low NO_x (DLN) combustion system. 

Getting to a H₂ economy which provides H₂ for fueling gas turbines for low- or no-carbon emissions will require many technological advancements. However, this fact should not dissuade the reader.  These advancements appear achievable as several OEMs and 3^rd party vendors are working on viable options.  Included here, are details of the work of Mitsubishi Power, EPRI, and Southern Company who have teamed together to advance the technology further. The value of this project cannot be overstated.  This allows the industry and society to view H₂ as a potentially viable fuel for modern turbines to reduce CO₂ emissions, CO emissions and allow further flexibility of operation of gas turbines with no, or minimal, changes to NOx emissions compared to traditional NG gas turbines. 

Hydrogen impacts on gas turbines

The impacts of H₂, whether in blends or pure form, on gas turbines is varied and often misunderstood.  Recent reports have been issued, or are in progress, to provide more information regarding the influence of H₂ containing fuels on emissions, performance, durability, and service life[1]^,[2],[3].  Albeit details can be found with these and other additional sources, it is important to baseline some considerations when contemplating H₂ inclusion.

Flame Speed

As indicted in Figure 1, the flame speed of H₂ is much faster than NG.  Higher flame speeds require design variation in the DLN combustion systems, which is a primary driver for current gas turbine DLN technology %H₂ blend limitations².   The prominent way to include H₂ in NG fueling up to the allowable % by volume is through control of fuel to air ratios in the combustor.  To push further, total redesigns are needed, which typically aim to increase axial flow velocity and/or staging combustion to combat the wide flame speed ranges between NG and H₂. 

Heating Value

Heating value is a measure of the amount of energy contained in a specific volume (or mass) of fuel, and the heating value of H₂ is significantly different than that of NG. It is the impact of the low density of H₂ that makes the comparison with NG heating values a topic which can lead to incorrect conclusions.  Figure 1 compares the heating values of H₂ and NG in mass and volume bases. 

Performance and Emissions

An increase of H₂ content in the fuel gas will result in a performance and efficiency impact (in a positive direction) on the gas turbine; however, not due to volumetric- or mass-based heating value impacts.  The impact is related to the exchange of CO₂ emissions for H₂O emissions with H₂. As CO₂ decreases in the exhaust, the concentrations of other constituents, namely oxygen and water, increase. Figure 2 shows the general trend of exhaust products with increasing H₂. 

The change in exhaust products results in an exhaust with a higher energy content relative to its temperature (specific heat, c_p).  This results in more work for the same temperature and/or higher efficiency of the gas turbine, depending on the type of control used.  This nominal trend in efficiency, performance, and CO₂ reduction with increasing H₂ is shown in Figure 3. Note that this is shown for a nominal turbine and specific benefits will be model specific.  

KEY takeaways

Major project team members

System design modifications

A temporary blending system was added to the NG supply to introduce specific concentrations of H₂ gas to the fuel gas sufficiently upstream of the gas turbine to ensure adequate mixing, as shown in Figure 4.

Safety and code compliance

The importance of safety during the design and execution phases of the project cannot be overstated.  All team members served critical roles in ensuring that all applicable design codes and regulations were reviewed and complied with.  Systems constructed specifically for hydrogen service were designed or modified in accordance with current ASME B31.12 piping and pipeline code and other relevant standards and/or recommended practices. Functional testing, final inspection, and review of quality documents was performed in person by qualified personnel from each member organization.  While the project itself was intended to operate for only for the duration of the test program, the systems were designed to comply with industry codes and standards applicable to permanent installations. 

Summary and conclusions

Overall, the Georgia Power, Southern Company, EPRI, and Mitsubishi Power consortium successfully operated a M501G with H₂ blending up to ~20.9% by volume. The results of the preparation and testing execution exhibit the feasibility of utilizing H₂ on-site with an existing DLN gas turbine asset while maintaining emissions compliance.  This project constitutes the first of a kind in blending large volume flows of H₂ in an advanced, high efficiency gas turbine operating in combined cycle mode.  Testing results show the promise that H₂ blending holds in the Energy Transformation to a low- to zero-carbon future.

About the authors:

Bobby Noble is the program manager of Gas Turbine R&D at EPRI and a Fellow of American Society of Mechanical Engineers. He is a key global leader in gas turbine combustion and diagnostics, authoring a number of EPRI reports and conference papers on GT hydrogen combustion.

Jim Harper is a Principle Technical Leader in the Gas Turbine programs at EPRI and has extensive Gas Turbine design, control, testing and fleet experience.  In addition to Gas Turbines he has automotive and EV battery thermal systems design experience. He has authored over 10 patents in Gas Turbine Design and Gas Turbine as well as EV Control architectures.

Michael Gagliano is a Technical Executive at EPRI executing material-based research for the Low Carbon Resources Initiative.  He has a Ph.D in Materials Science and Engineering and has expertise in boiler materials, low and high temperature degradation mechanisms, and metallurgical failure analysis.

Dr. Robert Steele is a Technical Executive for Gas Turbine Advanced Components and Technologies at EPRI and has 35 years of experience in gas turbine combustion research, development and testing, and electric power generation industry technologies including carbon capture, compression, and sequestration. 

[1] Douglas, C. M., Shaw, S. L., Martz, T. D., Steele, R. C., Noble, D. R., Emerson, B. L., and Lieuwen, T. C. (July 28, 2022). “Pollutant Emissions Reporting and Performance Considerations for Hydrogen–Hydrocarbon Fuels in Gas Turbines.” ASME. J. Eng. Gas Turbines Power. September 2022; 144(9): 091003. https://doi.org/10.1115/1.4054949

[2] Noble, D., Wu, D., Emerson, B., Sheppard, S., Lieuwen, T., and Angello, L. (February 9, 2021). “Assessment of Current Capabilities and Near-Term Availability of Hydrogen-Fired Gas Turbines Considering a Low-Carbon Future.” ASME. J. Eng. Gas Turbines Power. April 2021; 143(4): 041002. https://doi.org/10.1115/1.4049346

[3] Emerson, B., Lieuwen, T., Noble, B., and Espinoza, N. “Hydrogen substitution for natural gas in turbines: Opportunities, issues, and challenges,” Power Engineering, June 18, 2021. https://www.power-eng.com/gas/hydrogen-substitution-for-natural-gas-in-turbines-opportunities-issues-and-challenges/#gref

The PGA Tour Championship tournament said it has swapped diesel with renewable fuels for all onsite generation to power the East Lake Golf Club in Atlanta.

Renewable fuels are often produced from a combination of previously used materials, such as combining waste and residues with renewable and vegetable oils.

PowerSecure, a Southern Company subsidiary, will provide the renewable fuel.

“The deployment of renewable fuel at the PGA TOUR Championship represents a major milestone for PowerSecure and the energy users and producers we serve,” said PowerSecure CEO Chris Cummiskey.

The company previously partnered with the PGA Tour to Install distributed energy resources at PGA Tour headquarters in Ponte Vedra Beach, Florida in 2021.

The 187,000 square foot facility incorporates a microgrid comprised of rooftop solar and natural gas backup generation.

PowerSecure has developed, installed, managed and serviced more than 2 GW of microgrid capacity over the past 20 years.

Southern Company’s Joseph M. Farley nuclear power plant in Columbia, Alabama will be the location of a direct air capture (DAC) study, boosted by about $2.5 million from the U.S. Department of Energy.

Columbus, Ohio-based Battelle will conduct a front-end engineering design (FEED) study to deploy the DAC system developed by AirCapture LLC.

The project will define system costs, performance and business-case options for leveraging available energy from the nuclear plant to separate CO₂ from ambient air for off-site geologic storage. Although nuclear plants do not produce any carbon emissions, direct air capture would remove CO₂ directly from the atmosphere, a possible next-generation technology being explored to help combat the climate crisis.

Battelle will be collaborating in the study with Carbonvert Inc, Sargent & Lundy, Southern Company and the University of Alabama.

The project is part of a $14 million investment from the DOE aimed at scaling up direct air capture and storage technology.

In April 2022 we reported Constellation and several partners would receive $2.5 million in DOE funding to study DAC at the company’s Byron nuclear plant in northern Illinois.

In that proposed study, a chemical solution would be added to water flowing through the facility’s main condenser on the non-nuclear side of the Byron plant. After traveling through the condenser, the water would travel out to the cooling towers, where CO₂ in the air would attach itself to the chemical solution and be captured and sequestered. It would then, potentially, be used later in industrial processes that would have net zero emissions, from creating sustainable aviation fuel to beverage industry production.