Project Tundra Carbon Capture System

The US Department of Energy (DOE), through its Office of Fossil Energy and Carbon Management (FECM), has funded several Front-End Engineering and Design (FEED) studies for retrofitting existing fossil fuel power plants with carbon capture technology. These comprehensive studies are publicly available on the US DOE Office of Scientific and Technical Information (OSTI) website as part of the knowledge sharing requirements associated with the funding. 

This study is our effort to help stakeholders quickly understand the key findings in lengthy reports highlighting methodologies, and unique design aspects that could shape future carbon capture plant designs.  Our objective is to highlight the most relevant sections of each study.

Overview

This FEED study, conducted by Minnkota Power Cooperative (MPC), examines adding a post-combustion carbon capture facility to an existing coal-fired power plant located in North Dakota. For the study, Milton R. Young Station’s Unit 2 was the host facility, a 477 MW unit fueled by North Dakota lignite. This FEED study focuses on retrofitting a 90% carbon dioxide (CO₂) capture system using Fluor’s Econamine FG Plus℠ (EFG+) technology.

FEED study link: Front-End Engineering and Design: Project Tundra Carbon Capture System

Total CO₂ captured: 4.3 MM tonnes/yr

Total As-Spent CAPEX ($MM USD in 2021): $1,939

Objective

This summary highlights the unique design and planning aspects from this FEED study which include:

• Use of Fluor’s Econamine FG Plus℠ (EFG+) technology and capture design
• Steam sourcing and flue gas integration strategy
• Incorporation of winterization considerations
• Implementation of a continuous solvent maintenance system
• Application of value engineering for cost savings
• Environmental requirements 

Use of Fluor’s Econamine FG Plus℠ (EFG+) Technology and Capture Design

What is it:

Fluor’s EFG+ is an amine-based technology used for post-combustion carbon capture. It is particularly effective for low-pressure flue gas streams with high oxygen content (up to 15% by volume). The process uses a proprietary solvent with chemistry similar to primary amines, such as Monoethanolamine (MEA).

In this study:

The table below summarizes the EFG+ solvent capability in comparison to a conventional MEA-based process:

This study incorporated a unique pre-treatment configuration in which a blower directs the flue gas to an impurity removal package, filtering the fine aerosol particles (commonly formed during the combustion of typical North Dakota lignite coal) before the flue gas enters the absorber. Additionally, Fluor collaborated with column internal suppliers to design a direct contact cooler (DCC) and absorber that reduced pressure drops in the system. This was achieved by using advanced internal designs and packing in both units, resulting in a 65% power reduction required for the blower compared to conventional carbon capture plants.

Additional Information: 

In post-combustion carbon capture systems, the blower is one of the largest energy consumers as it drives the flue gas through the capture process. Its primary role is to supply enough force to overcome pressure losses in downstream equipment, such as the DCC vessel and absorber, while ensuring that flue gas pressure at the duct tie‑in point remains at atmospheric levels. 

What is it: 

A steam sourcing and flue gas integration strategy examines options for supplying steam for solvent regeneration and evaluates the impacts of combining flue gas streams from different combustion sources prior to entering the capture system. The ability to combine flue gas from different units provides operational flexibility, helping the capture plant maintain a sufficient flue gas flow in order to meet capture targets.

In this study:

This FEED study was developed on the basis of installing new auxiliary natural gas boilers to supply steam for the capture plant, along with the construction of a pipeline to deliver natural gas to the facility. In this scenario, flue gas produced from Unit 2 of the host facility and the new auxiliary natural gas boilers would be routed to the capture plant. If Unit 2 was out of operation, Unit 1 would be used as an alternate flue gas source. This scenario was selected based on findings from an earlier pre-FEED study, where it was deemed the lowest technical risk and most cost-effective option. However, a key finding of this FEED study revealed that the new auxiliary natural gas boilers scenario was significantly more expensive than previously estimated during the pre-FEED phase.

An alternative approach for steam supply was also evaluated in the pre-FEED study. This strategy involved extracting steam from Unit 2’s existing steam turbine generators at the intermediate and low-pressure crossover points. While this reduced Unit 2’s power output by 80 MW, it also eliminated the need for new auxiliary natural gas boilers, resulting in capital savings. Without the need for new auxiliary boilers, this created unused capacity in the capture plant. To fill this gap, the flue gas routing was modified, combining the flue gas from Unit 1 and 2 into a single stream before entering the capture plant. Under this configuration, the capture plant would process approximately 34% of Unit 1’s flue gas and 100% of Unit 2’s flue gas during normal operation. This ability to process flue gas from both units provides operational flexibility, allowing the capture plant to adjust the mix as needed to maintain full capacity. 

The pros and cons of both steam sourcing options (installing new auxiliary natural gas boilers vs. extracting steam from the existing Unit 2 steam turbine) were included in this FEED study, but detailed technical or cost estimates for the impact of this change were not provided. The study recommended that future work should reconsider the steam extraction option as a potential cost-reduction measure.

A key challenge when mixing the flue gas streams is the risk of rapid and extreme pressure fluctuations within the large ductwork during transient operating conditions. These fluctuations, which may be caused by the operation of several large horsepower fans in the flue gas system, can compromise the duct’s mechanical integrity. To mitigate this risk, parallel blade guillotine dampers on the ducts from each flue gas source (i.e., Unit 1 and Unit 2) were included in the design. These dampers provide double isolation between the flue gas sources and the capture plant, allowing flue gas to be vented when required via the main stack. In addition, a seal air system was also incorporated to ensure an airtight seal when the dampers are closed.

An emissions monitoring strategy was also developed that includes continuous emissions monitoring systems (CEMS) located upstream of the capture plant, where flue gas remains untreated. Under this plan, the existing CEMS on Unit 1 and 2 stacks remain in service, monitoring emissions whenever flue gas is exhausted through those stacks. Additional CEMS were also installed at the capture plant’s inlet duct and at the CO₂ absorber stack to measure flow and pollutant concentrations, including CO₂, sulfur dioxide (SO₂), nitrogen oxides (NO_x), particulate matter, and mercury, as applicable. Together, this monitoring configuration provides accurate emissions measurement, proper calculation of heat input and emission rates, and ensures regulatory compliance across all anticipated capture plant operating modes.

Additional information:

An emissions monitoring plan accounts for the capture plant operation, including the routing of flue gas from multiple sources and flexible operating configurations.  Standard emission monitoring methods rely on knowing how much CO₂ was produced during combustion. If CO₂ is removed from the process before this measurement occurs, the results can be misleading. 

What is it:

Winterization involves protecting all personnel, equipment, piping, and chemical storage from freezing, icing (i.e., the formation of ice on exposed surfaces, equipment, or piping), and other cold induced damage. To ensure safe and continuous operation of facilities despite severe seasonal weather variations, winterization is a crucial design consideration. 

In this study:

North Dakota experiences cold winters, making winterization a mandatory and critical aspect of the capture plant design. The design approach included heated buildings and enclosures, electrical heat tracing, insulation, and a glycol-water heating system. Equipment such as pumps, compressors, and heat exchangers will be located inside buildings with heating, ventilation, and air conditioning systems designed to maintain a minimum internal temperature of 40°F (4.4°C). This minimum temperature prevents freezing and other operational issues in a climate where the ambient dry bulb temperature can drop as low as −45°F (-42.8°C). 

Freeze protection using electrical heat tracing was applied to piping and the triethylene glycol storage tank. Storage tank heaters, such as the spent solvent tank heater, used glycol water to keep the solvent warm, preventing it from becoming highly viscous or freezing in colder conditions.

To assess the risk of ice formation, an icing model was developed for the absorber and cooling tower. The FEED study recommended additional analysis to update this model and evaluate cold-weather protection requirements and mitigation strategies, including whether heat tracing is needed in these critical areas. 

North Dakota’s cold climate causes the ground to freeze as deep as 6.5 feet, making foundation design a critical consideration. Project Tundra accounted for this by ensuring building foundations were either placed below 6.5 feet or insulated with special materials like polystyrene boards to prevent movement or cracking during the freeze-thaw cycles. For deeper foundations like drilled piles and shafts, frozen soil can stick to the structure and exert upward forces. To counter this, engineers use reinforced concrete and steel to design foundations strong enough to resist these forces.

Additional information: 

During cold temperatures, a key operational risk for the capture plant is the potential of ice formation on the absorber stack, cooling tower, adjacent structures and surrounding areas. When exhaust streams from the absorber stack damper and the cooling tower are saturated with water vapor, this can condense and form ice. This creates structural risks and safety hazards, including the potential for large quantities of ice to fall from significant heights. 

What is it:

A solvent maintenance system, sometimes referred to as solvent reclaiming, consists of specialized equipment designed to preserve the high quality and performance of the circulating solvent in capture processes. Over time, the solvent’s ability to capture CO₂ declines due to interactions with flue gas impurities and exposure to high temperatures, causing solvent degradation. The solvent maintenance system maintains solvent integrity by removing these degradation products, allowing the solvent to be reused time and time again. This process can be carried out either in batch or continuous mode. Batch reclaiming cleans the solvent at set intervals with downtime, while continuous reclaiming removes impurities during operation without interruption. For large scale capture projects, continuous reclaiming is increasingly favored due to its ability to manage high solvent volumes with minimal disruptions.

In this study:

One of the unique features of the EFG+ process is its ability to remove heat stable salts and other non-volatile degradation products, preserving the solvents integrity. Unlike some amine processes that rely on batch reclaiming, this study applies Fluor’s proprietary Solvent Maintenance System, which operates continuously to maintain low levels of degradation products in the solvent. Fluor’s continuous reclaiming method has been shown to reduce solvent loss, makeup requirements, and waste generation by approximately 95% compared to traditional batch reclaiming. The system integrates purification directly into the solvent loop, minimizing the need for frequent solvent replacement and reducing overall losses. By keeping degradation products and certain metallic contaminants at very low concentrations, the system reduces unwanted volatile organic compound emissions. This continuous approach enhances both the economic efficiency and environmental performance of the plant.

Additional information: 

The table below compares key operational differences between batch and continuous solvent reclaiming approaches in carbon capture systems:

What is it:

To identify practical ways to lower the overall project costs, value engineering is a structured review conducted during the FEED phase. It involves evaluating the design to select more cost-effective alternatives while ensuring that functionality and performance are not compromised.

In this study:

For this project to “break even” (i.e., to cover the total cost of the project including capital and operating expenses), it would have to earn $80.60 (levelized over life of the project) for every metric ton of CO₂ captured, transported and stored. However, the main source of income came from the U.S. government’s 45Q tax credit program, which was estimated to provide only $59.93 per metric ton of CO₂ captured as of 2022. Because the cost of capturing CO₂ exceeded the income from the government tax credit, the project faced a financial deficit. This cost gap forced the project team to seek ways to reduce the construction design and expenses.

The most significant outcome from the cost review was the decision to change the capture plant’s steam source. Eliminating the new auxiliary natural gas boilers provided several benefits:

1. Reduced plot plan, resulting in significant capital cost savings.
2. Eliminated the construction of a 25-mile natural gas pipeline, leading to significant operating cost savings.
3. Removed the price risk and cost of purchasing natural gas, improving long-term financial stability.

The detailed technical and financial evaluation of the steam extraction was reserved for the next project phase.

In addition to the steam source change, the study identified over seventy potential value engineering and cost reduction opportunities which were not itemised in this report. These items were estimated using a Rough Order of Magnitude approach to potentially reduce the capture plant portion of the project cost by an estimated $100 million to as much as $350 million.

Another major cost reduction opportunity that was identified was to modify the existing water treatment system instead of building a separate, new water treatment system for the capture plant. The study concluded that upgrading the host facility’s existing water treatment plant was a practical option, offering major cost savings by avoiding construction of a separate water treatment building and reducing the overall space required for the project.

The impurity removal package in the capture system was also studied due to the uncertainty about particulate levels in the flue gas. The cost of this unit was included in the initial design to ensure emissions remained within acceptable limits. However, depending on the results of pilot testing with actual flue gas, the package may prove unnecessary, which could lead to significant cost savings.

Additional information:

To reduce site construction hours, modularization was investigated as a potential value engineering strategy. However, limited water access and the road system meant that modularization was not considered beneficial as these introduced more scheduled risks.

What is it: 

Environmental requirements establish the regulatory mandate for the project, covering air emissions, water discharge, and waste disposal. Compliance is required with federal, state, and local standards, and for major permits such as the Air Permit to Construct and Class I well permits for wastewater disposal. These requirements are important because they ensure legal compliance, protect the environment, and secure the permits needed for the project to progress. 

In this study:

This report confirmed that the project must secure an Air Permit to Construct, with the CO₂ absorber and cooling tower identified as key emission sources. Air dispersion modeling demonstrated that all project emissions remain within National Ambient Air Quality Standards. 

In addition, the project requires a water appropriation permit from the Missouri River to secure a steady supply of raw make-up water for operational utility systems. For wastewater management, MPC decided to pursue a Class I (non-hazardous) injection well for capture plant wastewater disposal. This approach requires both a Class I permit and an Aquifer Exemption from the U.S. Environmental Protection Agency to inject the non-hazardous wastewater into a geologic formation. Meanwhile, effluents from the solvent maintenance system (i.e., heat stable salts and other degradation products) will be handled through offsite waste disposal by a third-party contractor. 

The construction ready engineering schedule, and pricing terms phase of future work includes a more detailed emissions analysis of lignite flue gas. This future work will also involve gaseous dispersion modeling to support revisions in permitting parameters due to the elimination of the auxiliary natural gas boilers and the subsequent change in the project’s steam supply source.