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All sourcesNASA NTRSDOE OSTI
DOE OSTI2026

Dual-loop Solvent-based CCS for Net Negative CO 2 Emissions with Lower Cost

This final technical report details the successful design, construction, and operational validation of an innovative dual-loop CO 2 capture technology designed to achieve deep decarbonization (>99%) from Natural Gas Combined Cycle (NGCC) power plants that results in the electricity with carbon intensity of approximate 42 kg CO 2 -eq/MWh, less than the electricity produced by solar PV. The integrated process couples a primary aqueous solvent (in this project, a water lean solvent – WLS) absorption loop for bulk CO 2 removal with a secondary potassium hydroxide (KOH) polishing loop featuring electrochemical regeneration. This architecture leverages the higher exergy efficiency of the primary loop while utilizing the fastest kinetic of the secondary loop to capture dilute residual CO 2 , achieving an overall capture rate of 99.9% and co-producing pure hydrogen after moisture being condensed and dehydrated. Technical feasibility was established through a comprehensive 2,000-hour experimental campaign on a bench-scale fully-integrated unit (using 4” absorber and 4” stripper) with the feeding flue gas flowrate in the range of 8-20 cfm, confirming the attainment of Technology Readiness Level (TRL) 4. The project executed extensive parametric testing followed by 1,000 hours of continuous steady-state testing, demonstrating exceptional process stability with the electrochemical regenerator exhibiting less than a 10% reduction in electrical conductivity over the duration of the campaign. Operational characterization gathering on the bench unit revealed distinct energy profiles for the hybrid system: the primary loop required approximately 280 kJ mol -1 for bulk removal, while the polishing loop required approximately 1,600 kJ mol -1 specifically when reducing dilute CO 2 concentrations from ~740 ppm down to <50 ppm. (Please note those energy values/numbers can only be viewed as relative relationship and should not be extrapolated as absolute values required for CO 2 capture). Furthermore, dynamic testing validated the system’s flexibility for utility applications, demonstrating a rapid process response time of <30 minutes to changes in flue gas flowrate. Emission monitoring confirmed that the dual-loop architecture effectively mitigates solvent losses, utilizing a water wash to remove entrained aerosols to <1 ppm. The Techno-Economic Analysis (TEA) indicates a cost of capture of $\$$59.3/tonne and a Levelized Cost of Electricity (LCOE) of 71.7 $\$$/MWh at the overall capture efficiency of 99.8% of total carbon in the flue gas stream, with sensitivity analysis identifying an economic optimum when the primary loop captures 97% of the total CO 2 . A Life Cycle Assessment (LCA) confirms the technology’s potential for net-negative emissions, determining a Global Warming Potential (GWP) of 52 kg CO 2 -eq/MWh—significantly lower than the baseline—which further decreases to 42 kg CO 2 -eq/MWh when crediting the displacement of conventional hydrogen production.

03 NATURAL GAS↗
DOE OSTI2025

Conversion of CO 2 from power plant into CaCO 3 nanoparticles

Carbon dioxide (CO 2 ), a main composition of flue gas, represents a significant and largely untapped carbon resource. Herein, mediated by glycine (Gly), we captured and converted CO 2 into CaCO 3 nanoparticles using real flue gas from a power plant, demonstrating for the first time the feasibility of using amino acid to convert CO 2 from power plant flue gasses. The method did not require extraneous energy and CaCO 3 nanoparticles with a size of ∼25 nm were obtained. Moreover, the potential toxicity of CO 2 -converted nanoparticles was investigated. It appeared that both the initial CO 2 loading and the carbamate percentage significantly influence the shape and size of the CaCO 3 particles. Our method was also proven effective for flue gas with varying CO 2 concentrations (4 %, 12 %, and 20 %). By tuning flue gas bubbling time and flow rate to achieve consistent CO 2 loading and carbamate levels, we produced CaCO 3 nanoparticles with similar shapes and sizes across all CO 2 concentrations studied. In addition, our data indicated that although real flue gas contains small amounts of gases like oxygen and CO, they insignificantly influence the shape and size of our nanoparticles but did impact the phase component of CaCO 3 . In conclusion, the toxicity experiments found that CaCO 3 nanoparticles produced from both real flue gas and simulated flue gas exhibited concentration- and time-dependent effects on cell viability.

36 MATERIALS SCIENCE↗
DOE OSTI2024

Development of Self-Assembly Supports Enabling Transformational Membrane Performance for Cost-Effective Carbon Capture

This final technical report describes work conducted by Membrane Technology and Research, Inc. (MTR) for the U.S. Department of Energy (DOE), National Energy Technology Lab (NETL) on the development of membranes with transformational performance for carbon capture under award number DE-FE0031596. The work was performed from June 1, 2018 through May 31, 2024. For more than a decade, MTR has worked in partnership with DOE to develop an innovative membrane-based CO 2 capture process. This effort has included the first test of membrane modules with coal-fired flue gas at the Arizona Public Services (APS) Cholla plant in 2010; the accumulation of >11,000 hours of flue gas operation for Polaris modules on a bench-scale 1 tonne/day (TPD) system at the National Carbon Capture Center (NCCC); scale-up of first-generation (Gen-1) Polaris to a 20 TPD small pilot system, and successful operation of this system on a flue gas slipstream at NCCC and in integrated boiler testing at Babcock & Wilcox (B&W). Through continued development efforts, a second-generation (Gen-2) version of the Polaris membrane has been scaled-up to pilot production. This membrane offers 70% higher CO 2 permeance with similar selectivity to the base case Polaris. MTR also developed planar modules designed specifically for the low-pressure, high-volumetric flow rate process conditions of flue gas operation. These new modules have significantly lower pressure-drop values compared to the type originally used (spiral-wound modules), which results in significant energy savings. The goal of the work described in this report was to improve on the Polaris Gen-2 membrane with the ultimate aim to reduce the cost of carbon capture. The majority of the effort was to develop improved support membranes for the multi-layer composite structure of MTR’s Polaris membrane. Earlier work at MTR had identified the support structure as limiting membrane permeances, not because the support itself represents a permeation resistance, but because the distribution of pores at the surface of the support imposes a geometric restriction to diffusion in the layers above it. Support membranes were prepared from a range of polymers, including commercially available block copolymers and a custom synthesized block copolymer alternative. The best support membranes developed in this project reduced the geometric restriction by a factor of two to three. These supports then were used to produce Polaris composite membranes with improved permeances. The second topic was to create a high-selectivity version of the Polaris membrane. The high-selectivity version uses a novel selective polymeric material and high selectivities were confirmed in experiments at MTR. The material is not easily made into very thin films. Consequently, the permeances are significantly lower than the Polaris Gen-2 membrane. The utility of this membrane is therefore limited to the carbon dioxide purification step that produces liquid CO 2 . A Technical and Economic Analysis (TEA) was performed for a carbon capture system that uses both advanced membrane types. The TEA shows the novel advanced membranes reduce the cost of capture by 10%, from $63.32/tonne CO 2 to $56.90/tonne CO 2 (2022 USD). Most of the development work was carried out with laboratory-scale casting and coating equipment. A number, but not all, of the improvements identified have been implemented on commercial-scale manufacturing equipment. The focus of future work at MTR is to incorporate the advancements made into the Polaris membrane manufacturing process.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2019

Large Bench-Scale Development of a Non-Aqueous Solvent (NAS) CO 2 Capture Process for Coal-Fired Power Plants Utilizing Real Coal-Derived Flue Gas (Final Report)

This advanced non-aqueous solvent (NAS) technology led by RTI International in collaboration with Norwegian research organization SINTEF and industry partner Linde LLC, represents a disruptive advance in carbon capture to meet the Department of Energy’s critical mission to lower the cost associated with reducing carbon emissions from existing coal-fired power plants. This technology may reduce the energy required to remove carbon dioxide from flue gas by approximately 50%, decreasing the cost of carbon capture by 35% compared to earlier technologies. This report shows the results from testing at SINTEFs demonstration facility in Tiller, Norway.

20 FOSSIL-FUELED POWER PLANTS↗
DOE OSTI2023

Understanding the performance of membrane for direct air capture of CO 2

Abstract Direct air capture (DAC) of CO 2 is becoming increasingly important for reducing greenhouse gas concentrations in the atmosphere. However, the cost and energy requirements associated with DAC make it less economically feasible than carbon capture from flue gases. While various methods like solid sorbents and gas–liquid absorption have been explored for DAC, membrane processes have only recently been investigated. The objective of this study is to examine the separation performance of a membrane unit for capturing CO 2 from ambient air. The performance of a membrane depends on several factors, including the composition of the feed gas, pressure ratio, material selectivity, and membrane area. The single‐stage separation process with the co‐current flow and constant permeability flux model is evaluated using a commercial module integrated with a process simulator to separate a binary mixture of carbon dioxide and nitrogen to assess the sensitivity of selectivity on purity and recovery of CO 2 in permeate, and power requirement. Additionally, three levels of CO 2 reduction from the feed stream to the retentate stream (25%, 50%, and 75%) are studied. A trade‐off between purity and recovery factor is observed, and achieving high purity in permeate requires high concentration in the retentate.

Panja, Palash↗
DOE OSTI2024

Achieving Unprecedented CO 2 Utilization InCO 2 Concrete™: System Design, Product Development and Process Demonstration

Anthropogenic sources of carbon dioxide are generated from a number of sources, but the key among these are ordinary Portland cement (OPC) production and combustion of fossil fuels. Cement production is the largest global CO 2 source from the mineral decomposition of carbonates. This is due to the clinkering process whereby limestone (mainly consisting of CaCO 3 ) is decomposed into CaO and CO 2 , and combined with silica rich clays at high temperatures to form clinkers (i.e. the four key minerals that comprise cement). The high temperature range of 1400 – 1550°C required for this process accounts for up to 60% of the generated CO 2 from cement production. Combination of the limestone decomposition and thermal requirements of the clinkering process causes cement production to contribute 8-9% of annual global CO 2 emissions. Combustion of fossil fuels (coal, oil and gas) was shown to contribute a much larger portion of global CO 2 emissions. As of 2018, combustion of fossil fuels accounted for 65% of global CO 2 , where 41% was derived from stationary sources for electricity and heat generation and the other 24% was related to transport. To reduce these contributions, key steps forward in CO 2 utilization technologies are required. Therefore, a CO 2 mineralization technology (CO 2 mineralization concrete) to reduce the OPC content in concrete, while utilizing flue gas emissions from fossil fuel combustion has been developed to address both areas simultaneously. This Reversa™ technology utilizes low-carbon cementation agents produced by in situ CO 2 mineralization (“mineral carbonation reactions”) to offer a promising alternative to OPC. CO 2 mineralization relies upon the reaction of dissolved CO 2 with inorganic alkaline reactants to precipitate mineral carbonates (e.g., CaCO 3 ), which bind proximate particles and achieve cementation. Herein, a concrete green body, which is composed of a mixture of binder, water, and mineral aggregates, is exposed to CO 2 borne in industrial flue gas streams. This manner of CO 2 mineralization allows the production of construction components that feature equivalent engineering attributes as their OPC-based counterparts while featuring a much smaller embodied carbon intensity (eCI). The purpose of this project is to demonstrate the feasibility of the Reversa process evolving from a TRL-3 technology at the bench-scale up to TRL-6 technology at the pilot-scale. The reliability of the Reversa technology was tested to prove the effective production of three standard industrial concrete products selected during the course of the project. The results detailed herein will demonstrate the evolution of this technology to the industrial scale. The culmination of this work resulted in 9 production runs completed at the National Carbon Capture Center (NCCC), Wilsonville, AL, using natural gas (NG) flue gas as the CO 2 source. Over the course of the production runs at NCCC, the CO 2 utilization as a function of time, 24-h CO 2 uptake, electricity usage, and 28-d net area compressive strength recorded for each run. Collection of this data will be used to determine the success of the demonstration goals: (1) achieving in excess of 0.2gCO 2 /g reactant , (2) achieving greater than 50% reduction in global warming potential compared to standard produced units, and (3) ensuring compliance of carbonated concrete with industry standard specifications.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2022

Additional Analysis of Carbon Capture at Industrial Facilities

This poster provides summary cost details for a technoeconomic analysis of CO2 capture from flue gas generated by cement plants, conducted by U.S. Department of Energy National Energy Technology Laboratory and presented at the 2022 Carbon Management Project Review Meeting held in Pittsburgh, PA (August 15-19, 2022). A range of modern cement plant configurations was considered, along with different fuel types (coal, coke, and natural gas) and two levels of CO2 capture (95% and 99%). The sensitivity of capture cost to a range of modeling assumptions (such as fuel price, financing assumptions, utilization rate, and plant size) was also conducted, to show possible cost ranges that could be expected for decarbonization of typical cement plants in the U.S.

Hughes, Sydney↗
DOE OSTI2020

Cross-Linked Polyphosphazene Blends as Robust CO2 Separation Membranes

An effective cross-linking technique allows a viscous, highly gas permeable hydrophilic polyphosphazene to be cast as solid membrane films. By judicious blending with other polyphosphazenes to improve mechanical properties, a membrane exhibiting the highest CO2 permeability (610 barrer) combined with good CO2/N2 selectivity (35) among polyphosphazenes is described here. The material demonstrates performance stability after 500 hours of exposure to a coal-fired power plant flue gas, making it attractive for use in carbon capture applications. Its CO2/N2 selectivity under conditions up to full humidity is also stable, and although the gas permeability does decline, the performance is fully recovered upon drying. The high molecular weight of these heteropolymers also allows them to be cast as a thin selective layer on an asymmetric porous membrane, yielding CO2 permeance of 1200 GPU, CO2/N2 pure gas selectivity of 31, which does not decline over 2000 hours due to physical aging. In addition to gas separation membranes, this cross-linked polyphosphazene can potentially be extended to other applications such as drug delivery or proton exchange membranes which take advantage of the polyphosphazene’s versatile chemistry.

Kusuma, Victor↗
DOE OSTI2022

Large-Scale Commercial Carbon Capture Retrofit of the San Juan Generating Station

Enchant Energy, L.L.C. (Enchant) was selected to conduct a Front-End Engineering Design study (FEED) for the addition of a full-scale carbon capture system to remove carbon dioxide from the flue gas emissions of the two coal-fired generating units (total of 847 MW net) at San Juan Generating Station (SJGS), using Mitsubishi Heavy Industries Americas (MHIA) KM CDR Process™. Sargent & Lundy LLC (S&L) was selected as the primary technical lead, and along with various other organizations, were able to support Enchant’s completion of the following FEED tasks: Task 1 – Project Management & Planning; Task 2 – FEED Study; Task 3 - Final FEED Study Package. The FEED study period was between October 15, 2019 to September 30, 2022.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2021

Fuel cell system having enhanced CO2 capture

A carbon dioxide capture system for removing carbon dioxide from a flue gas produced by a combustion power plant. The system includes an electrolyzer cell configured to receive a flue gas comprising carbon dioxide and output a first exhaust stream comprising an enriched flue gas comprising carbon dioxide. The system further includes a fuel cell configured to receive the first exhaust stream and output a second exhaust stream comprising carbon dioxide. The second exhaust stream contains a higher concentration of carbon dioxide than the first exhaust stream.

Jahnke, Fred C.↗
DOE OSTI2019

Enabling Staged Pressurized Oxy-Combustion: Improving Flexibility and Performance at Reduced Cost

Introduction: The staged pressurized oxy-combustion (SPOC) process, developed by Washington University in St. Louis (WUSTL), is an oxy-combustion carbon capture technology that employs a steam power cycle to generate electricity. As with atmospheric-pressure oxy-combustion processes, carbon dioxide (CO 2 ) capture rates of 90% or higher can be achieved. The staged-combustion approach of the SPOC process, when operated at elevated gas pressure, allows for near elimination of flue gas recycle (FGR) and leads to significant improvements in efficiency and reduced costs. The primary goal of this project was to investigate the potential for SPOC for flexible operation beyond the capabilities of conventional coal-fired power plants, particularly those employing carbon capture and storage (CCS). Oxy-combustion differs from conventional coal combustion in that the combustion of coal is carried out using oxygen as opposed to air. The resultant flue gas is a mixture of primarily CO 2 and water, greatly simplifying CO 2 capture. As SPOC does the oxy-combustion process under pressure, it is higher efficiency and lower cost than atmospheric oxy-combustion. The project was led by the Electric Power Research Institute, Inc., with the assistance of WUSTL, Doosan Babcock (DBL – boiler plant original equipment manufacturer), and Air Liquide (AL – air separation experts). The specific objectives of the project were to: (1) Evaluate the SPOC concept and develop a risk-based approach to the heating surface layout ensuring that performance (gas and steam side), manufacturing, transportation, and plant erection considerations were fully accounted for in the system design. (2) Improve the technology to ensure its performance and cost potential are substantially better than today’s baseline pulverized coal power plant with post-combustion capture (PCC) or atmospheric oxy-combustion, and show progress toward performance commensurate with projected commercial operation, including 90% or more CO 2 capture. (3) Address critical technology gaps and improving overall system performance for the technology. (4) Perform combustion tests at scale under commensurate pressure to the commercial operating system validate combustor and advance the SPOC combustion modeling tools that will facilitate full-scale design. Combustion Testing: Testing was initially carried out at atmospheric pressure with methane to ensure that all systems were correctly operating. Following this, the testing then proceeded to moderate pressure operation at 4 bara, where different stoichiometric conditions were used across an extended heat input range, showing that a stable flame could be maintained. Testing then proceeded at 10 and 15 bara where it was shown that the ignition system needed to be replaced at these operating conditions. When testing recommenced, a similar stable flame shape was achieved, without any methane support, and the full 100 kWth coal oxy-combustion was demonstrated. Heat flux measurements showed 400 kW/m 2 (0.126 MMBtu/hr-ft 2 ) from the flame, within the 450 kW/m 2 (0.142 MMBtu/hr-ft 2 ) preferred limit defined by DBL for the full-scale design case. Carbon monoxide and carbon-in-ash measurements showed that complete combustion was possible with ultra-low excess oxygen at 1 vol % in the product flue gas. This allowed the full-scale models to be calculated based on this level of excess oxygen, improving the performance of the system as lower feed oxygen is produced in the air separation unit (ASU), saving auxiliary power. Full-Scale Design: The full-scale design is sized to deliver 550 MWe net electrical power output to allow direct comparison with the National Energy Technology Laboratory (NETL) baseline cases using the same Montana Powder River Basin (PRB) fuel. The cases used for direct comparison are: Case S12A (supercritical [SC] coal without CO 2 capture), Case S12B (SC coal with PCC at 90% CO 2 capture, and Case S12F (atmospheric oxy-combustion SC coal with 90% CO 2 capture). The SPOC stages were configured to be identical arrangements, allowing for a more straightforward design, construction, and control strategy. Each stage consists of two PVs, the first being the combustor PV module and the second being the convective PV module. The combustor module is the tallest vessel, with local coal feeding equipment and the burner FGR and oxygen plenums at the top and ash management at the bottom. The combustor module is effectively an open cross section with membrane tubes around the circumference – this unobstructed slender profile ensures that the relatively slower burnout mechanism needed for the low-speed turbulent mixing burner can proceed unimpeded and that molten ash will not attach to any surfaces at an angle to the predominant flue gas flow. The steam turbine used in the SPOC design is essentially the same unit utilized in the atmospheric oxy-combustion case except the degree of heat recovery possible allows the low-pressure (LP) feedwater heater train to be eliminated. This is a result of being able to capture the latent heat of evaporation of the moisture produced in the combustion (normally lost to the stack). The SPOC system outperforms the NETL atmospheric oxy-combustion baseline case by 3.3% points and the PCC case by 7.5% points. This performance increase is mainly a result of the improved heat recovery possible from the product flue gas and from the reduced auxiliary power consumption from the ASU and the CO 2 compression and purification unit over the atmospheric equivalent. The combined improvement in boiler efficiency and reduction in the steam turbine heat rate resulted in a net improvement in the overall plant efficiency by 0.61%, to 35.6% on a HHV basis. This relatively small improvement in plant efficiency between sub-bituminous and bituminous coals shows the value of useful moisture latent heat recovery offered by the SPOC system when using low rank fuels. Flexibility and Turndown: The SPOC system has inherent high turndown capabilities because of a demonstrated high range of combustion stability and the ability to bypass stages, thereby reducing steam generation rates proportionally without altering firing rates in operating stages. ASU units do not generally offer significant turndown opportunities as they are limited by the performance of the compression plant. The baseline SPOC design has a 2-train ASU configuration, needed to be able to meet the 10,500 tonnes per day duty, that can deliver efficient turndown points between 85–100% load with both trains operating, and at 45–50% load with a single train operating. Outside these operating points, the flexibility and efficiency are limited and may be uncompetitive at loads below 45% as the ASU systems are unable to turndown beyond 85% for the base case and 70% for the flexible case. The ASU cold box for the flexible case was designed to operate at loads between 40-100%, below this operating range the purity of the produced oxygen cannot be guaranteed, resulting in additional load for the CPU equipment. The additional power consumption of these cases yields an uneconomic operating condition with poor efficiency when operating at low loads such as 25% and 12%. To address this flexibility constraint, AL evaluated how the ASU configuration could be altered to deliver efficient oxygen supply over the load range. This involved integrating the compressor duties across both ASU trains into a shared duty arrangement with multiple compressors, strategically sized to deliver the duty required across all load ranges between 40–100% by enabling different combinations of the main air compressors and the booster air compressors. The oxygen purity cannot be guaranteed below 40% load for each train – the power consumption at 25% and 12% loads were estimated based on the multi-compressor configuration at maximum turndown as these load cases were not considered in the flexible ASU design. With a different cold box configuration, i.e. number of trains, the entire load range could be delivered within oxygen purity specifications. Although there is a small efficiency reduction at full load, there are significant improvements in overall plant performance during low-load operation. The exact ASU configuration needed will therefore be dependent on the expected operating profile of the unit. Economic Analysis: Cost estimates for the baseline and the flexible cases were developed using NETL baseline case data for common BOP items and an Association for the Advancement of Cost Engineering International Class 5 (conceptual/screening study) assessment of key components unique to the SPOC system. The capital, operating, and maintenance costs were assessed along with the first-year power cost, levelized cost of electricity, and CO 2 captured and avoided cost for the SPOC cases were compared against the relevant NETL baseline cases in January 2019 dollars. Both SPOC cases achieve a lower cost that the alternative NETL baseline cases (with the flexible SPOC case being slightly higher than the baseline SPOC case due to the compounded impact of higher capital costs and lower efficiency at full load). The SPOC cases deliver a lower cost of CO 2 avoided than the NETL baseline cases due to greater efficiency in generating low-carbon power. However, the cost of CO 2 captured is higher because the higher efficiency of the SPOC process generates less CO 2 , hence less needs to be captured, resulting in a high capital cost being shared over a reduced CO 2 quantity. The flexible ASU adds 1.6% overall to the plant cost in comparison to the baseline case, but the efficiency improvements at loads below 50% are significant. Subsequently, depending on the plant load-profile expectation, the flexible ASU would be beneficial if the plant spends a significant portion of its operating life below 50% load. This kind of operating profile is likely to be required for all fossil plants when more renewable electricity generators are installed on the local grid, particularly solar power that can be predicted ahead of time, allowing for appropriate pricing signals to be incorporated into the diurnal cycle. R&D Recommendations: SPOC, while a promising technology, is a relatively recent concept and, as such, operability issues of combustor design and steam-side integration for such systems at a scale relevant to commercial deployment have not been evaluated. WUSTL has conducted extensive small pilot-scale (100 kWth) research to understand and advance pressurized oxy-combustion processes, including investigation of combustion and flame characteristics, radiative heat flux, burner operability, turn down, char burnout, ash characteristics, water-wash column operation, etc. for pressurized oxy-combustion systems. Nonetheless, at this stage in the development of the SPOC process, what is needed is a large-scale pilot plant that can serve to study pressurized oxy-combustion systems and components at a scale commensurate with the maturity of the technology. A scale of 10 MWth, which includes steam-side integration and two stages would yield essential information with respect to heat transfer characteristics both in the radiative and convective sections of the pressure vessels, and the ability to operate the fuel staging process. In addition, while modeling results indicate that combustion and flame characteristics improve with scale, direct studies of the combustor at this scale will ensure that the models can be relied upon for scale up to commercial scale. Furthermore, a detailed analysis must be performed to understand the scaling aspects of key components and systems.

20 FOSSIL-FUELED POWER PLANTS↗
DOE OSTI2020

W.A. Parish Post-Combustion CO 2 Capture and Sequestration Demonstration Project (Final Technical Report)

The Petra Nova Project (Project) is a commercial scale post-combustion carbon capture project developed by a joint venture between NRG Energy, Inc. (NRG) and JX Nippon Oil Exploration (EOR) Limited (JX). The Project is designed to separate and capture carbon dioxide (CO2) from an existing coal-fired unit’s flue gas slipstream at NRG’s W.A. Parish Electric Generating Station (WAP) located southwest of Houston, Texas. The captured CO2 is dried, compressed, and transported via an 81-mile pipeline to the West Ranch oilfield (West Ranch) in Jackson County, Texas, where it is injected to boost oil production. The Project, which is partially funded by a grant (Grant) from the United States (U.S.) Department of Energy (DOE) under the Clean Coal Power Initiative (CCPI) Round 3, uses the Kansai Mitsubishi Carbon Dioxide Recovery advanced amine-based CO 2 absorption technology (KM-CDR Process®), which was jointly developed by Mitsubishi Heavy Industries, Ltd. (MHI) and the Kansai Electric Power Co. Inc., to treat and capture at least ninety percent (90%) of the CO 2 from a 240-megawatt equivalent (MWe) flue gas slipstream off of Unit 8 at WAP. When operating at full capacity, the Project captures approximately 5,200 short tons of CO 2 per day, which would otherwise be emitted into the atmosphere, representing the largest commercial scale deployment of post-combustion CO2 capture technology at a coal power plant to date. Under the Grant, the Project was managed in 3 phases: (1) Phase 1: Project Definition / Front End Engineering Design (FEED) (2) Phase 2: Detailed Engineering, Procurement & Construction (3) Phase 3: Demonstration and Monitoring. On December 29, 2016, commercial operation of the Project was achieved, ending Phase 2 and starting Phase 3, a 3-year demonstration period running from January 1, 2017 through December 31, 2019. The key objectives of Phase 3 were to (a) demonstrate the specific advanced technologies constructed during Phase 2 and (b) monitor the injected CO 2 at West Ranch to demonstrate technologies and protocols for monitoring, verification, and accounting (MVA). As of the end of Phase 3, Petra Nova captured 3,904,978 short tons of CO 2 (3,542,537 metric tons) that was transported to West Ranch. To support the DOE obligation to monitor, verify, and account for the sequestered CO 2 at West Ranch, Petra Nova contracted with the Bureau of Economic Geology (in the Jackson School of Geosciences at The University of Texas at Austin) to (a) design a monitoring program, (b) draft an MVA Plan for DOE review and approval, and (c) working with Petra Nova and the operator of West Ranch to manage and report on the MVA activity. This report discussed the technical aspects of the project during each of the 3 phases of the project as identified above.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2021

A Scalable Process for Upcycling Carbon Dioxide (CO 2 ) and Coal Combustion Residues into Construction Products

Anthropogenic sources of carbon dioxide are generated from a number of sources, but the key among these are ordinary Portland cement (OPC) production and combustion of fossil fuels. Cement production is the largest global CO 2 source from the mineral decomposition of carbonates. Combination of the limestone decomposition and thermal requirements of the clinkering process causes cement production to contribute 8-9% of annual global CO 2 emissions. Combustion of fossil fuels (coal, oil and gas) was shown to contribute a much larger portion of global CO 2 emissions. As of 2018, combustion of fossil fuels accounted for 65% of global CO 2 , where 41% was derived from stationary sources for electricity and heat generation and the other 24% was related to transport. To reduce these contributions, key steps forward in CO 2 utilization technologies are required. The purpose of this project is to demonstrate the feasibility of the Reversa process evolving from a TRL-3 technology at the bench-scale up to TRL-6 technology at the pilot-scale. The reliability of the Reversa technology was tested to prove the effective production of concrete masonry units (CMUs) at bench scale, where the units exceeded the required 13.8 MPa compressive strength requirements. The overall goal of this project was to accelerate the development of a CO 2 mineralization process that synergistically utilizes CO 2 in flue gas and coal combustion residues (CCRs) to synthesize carbonated concrete, a functional replacement for traditional concrete. The culmination of this work resulted in 12 successful production runs at the Integrated Test Center (ITC), Gillette, WY using coal flue gas as a CO 2 source. This was followed by 6 production runs which were completed at the National Carbon Capture Center (NCCC), Wilsonville, AL, using coal-fired and natural gas (NG) flue gas as the CO 2 source. Over the course of the production runs at NCCC and ITC, the CO 2 utilization as a function of time, 24-h CO 2 uptake, electricity usage, and 28-d net area compressive strength recorded for each run. The ITC and NCCC demonstrations achieved an average of 0.19 and 0.1 g CO 2 /g reactant, respectively. Both demonstrations exceeded the project’s target goals of uptake > 0.05 g CO 2 /g reactant. Average compressive strength of the ITC blocks was 18.24 MPa at 28-days. This exceeded the target strength of 13.8 MPa specified by ASTM C90. ITC and NCCC produced an average CO 2 utilization efficiency of 74.9 and 57.9%, respectively. Both demonstration averages were within the target range of 50 to 90% utilization efficiency. For some production runs the NCCC demo did exceeded the a CO 2 utilization efficiency of 75%. An LCA of the Reversa process compared to an industry standard product revealed a net CO 2 reduction of 39% to 42%. This exceeded the target requirement of >25% net CO 2 reduction. Collection of this data was used to determine that the project was successful as the demonstration goals were achieved: (1) achieving in excess of 75% CO 2 utilization efficiency, (2) utilizing greater than 250 kg of CO 2 per production batch/run, and (3) ensuring compliance of carbonated blocks with industry standard specifications (ASTM C90).

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2026

Carbon Capture on Air Liquide United States Gulf Coast Steam Methane Reformer using the Cryocap TM Flue Gases Process

The objective of this DOE-funded project is to execute and complete a Front-End Engineering and Design (FEED) study for a commercial-scale carbon capture project for Air Liquide’s Steam Methane Reformer (SMR) located at La Porte, near Houston, Texas. The Host Site is one of Air Liquide’s largest SMR assets, and supplies hydrogen to the Air Liquide Gulf Coast Hydrogen System, which serves refiners and petrochemical manufacturers through an existing H2 pipeline spanning roughly 200 miles from Port Arthur, TX to Bay City, TX. The Host Site produces up to 116.5 million standard cubic feet per day (MMSCFD) of gaseous hydrogen and emits approximately 950 ktpy CO 2 at the nameplate capacity. The evolving importance of decarbonized H2 for both existing customers and new markets, as well as the availability and intent of prominent third-party partners to transport and sequester captured CO 2 in locally abundant geological sites for 45Q credits, make the AL US Gulf Coast SMR an ideal site for the proposed FEED study. The envisioned carbon capture system is based on Air Liquide’s proprietary Cryocap™ Flue Gas (FG) process. The integration of the Cryocap™ FG technology to the existing SMR would enable the capture of 900 ktpy of CO 2 , with a net carbon capture rate of >95% and with minimum impact on the levelized cost of hydrogen produced at 99.97% purity.

03 NATURAL GAS↗
DOE OSTI2025

Mixed-Integer Linear Programming Formulation with Embedded Machine Learning Surrogates for the Design of Chemical Process Families

In previous work, we introduced process family design. The main idea is to design a platform of common elements, and, allowing us to capture additional cost savings, simultaneously design a family of processes, and reducing both engineering and deployment timelines. We formulate this as an optimization problem, specifically a nonlinear generalized disjunctive program (GDP). We have proposed two approaches for reformulating and solving this problem: one based on full-discretization of the design space and one that uses Machine Learning (ML) surrogates to replace the nonlinear process models. Using ML surrogates to predict required system costs and performance indicators allows us to reformulate the nonlinearities in the GDP generate an efficient MILP formulation. In this work, we apply the ML surrogate approach to two case studies. One case study involves designing a family of carbon capture systems to cover a set of different flue gas flow rates and inlet CO 2 concentrations, where we consider the absorber and stripper as common unit module types. The second case study focuses on a water-desalination process, where we design a family of these processes for a variety of salt concentrations and flow rates. In both of these case studies, we demonstrate a scalable optimization approach that enables the design of multiple processes simultaneously, reducing the time-to-market and overall costs by maximizing the cost savings due to both economies of scale and economies of numbers.

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DOE OSTI2025

Systems Analysis of Biomass and Coal Co-firing Power Plants with Deep Carbon Capture Toward Net-zero Emissions

Achieving a net-zero emission economy in the United States requires integrating diverse low-carbon and negative-emission technologies into the existing fossil fuel-dominant power fleet. Potential technologies from the low-carbon portfolio include renewable power, fossil power with carbon capture and storage (CCS), bioenergy with CCS (BECCS), and direct air capture (DAC). Renewable power is a clean energy source but has to pair with costly battery storage to provide dispatchable electricity. Fossil power with CCS offers dispatchable electricity yet still relies on DAC to offset residual emissions, even when deploying deep CCS with more than 90% CO2 capture. Coal-biomass co-firing with CCS, a subset of BECCS, is a reliable energy production technology that can be retrofitted from existing electricity generation units (EGUs). Power plant retrofit maximizes the use of the current U.S. coal power fleet without the need for large-scale deployment of new renewable power, battery storage, or DAC. Retrofitting coal-biomass co-firing with deep CCS in EGUs is a promising option, but not a universal solution. Biomass co-firing at a power plant introduces economic challenges and indirectly poses pressure on land and water resources. Meanwhile, retrofitting deep CCS affects plant efficiency and raises electricity generation costs. Overall, the technical feasibility and economic viability of plant retrofits vary across EGUs, as they are contingent upon the regional availability of biomass, unit-specific characteristics, site-specific fuel supply costs, and adjacent CO2 storage potential. Government incentives like 45Q can improve the retrofit viability, though the impact requires further quantification. A comprehensive analysis at the unit level is essential to address the question regarding the fate of the U.S. coal-fired electricity generation fleet toward the net-zero emission goal. This study conducts a systematic techno-economic-environmental assessment of EGUs to identify the viability of biomass co-firing and deep CCS retrofits in the U.S. coal-fired power fleet. Specifically, it characterizes the techno-economic performance of deep carbon capture, estimates life cycle greenhouse gas (GHG) emissions, and conducts a fleet-level assessment on retrofit viability. The key objectives are (1) to estimate the unit-specific performance and retrofitted cost under various biomass co-firing levels and CO2 capture rates; (2) to determine the possibility of reaching net-zero emission at the fleet level; (3) to quantify the cumulative capacities that are suitable for plant retrofits under current and future biomass supply scenarios; and (4) to improve the understanding of policy impacts on such retrofits to help the power sector’s transition to a net-zero economy. Techno-economic Model of Deep Carbon Capture. This study develops the performance and economic models for Monoethanolamine-based post-combustion CO2 capture at 95–99% capture rates. The process is simulated in Aspen Plus, analyzing the performance of carbon capture technology by varying the plant sizes, solvent lean loading, CO2 concentrations, and flue gas inlet temperature. Based on the key inputs and output parameters of CO2 capture, a reduced-order performance model of deep carbon capture is formulated. In addition, an engineering-economic model integrating the performance metrics is developed to estimate the capital as well as operation and maintenance (O&M) costs. Capital cost estimations follow the framework of the Integrated Environmental Control Model (IECM) and incorporate data regressions from three technical reports by IECM, the National Energy Technology Laboratory (NETL), and the National Renewable Energy Laboratory. The O&M cost estimation utilizes the actual inventory consumption rate and labor requirements. Both performance and cost models are embedded into IECM v13.0-beta, a fossil-fuel power plant modeling tool. Life Cycle Assessment of Power Plants. This study estimates the GHG emissions of power plants through life cycle assessment (LCA). The LCA scope includes fuel supply, combustion-based power generation, and CO2 transport and storage. The fuel-based life cycle module is designed following the framework of the NETL Unit Process Library and CO2U LCA Guidance Toolkit. The module is then incorporated into IECM v13.0-beta. The process-based LCA is applied to estimate the GHG emissions of coal and biomass supply, coal- and coal-biomass co-firing power plant operation, as well as CO2 pipeline transport and geographical sequestration. An uncertainty analysis is conducted to quantify the variability and uncertainty associated with the LCA using the Latin Hypercube Sampling (LHS) method. Fleet-level Assessment. This study evaluates the technical and economic feasibility of selected coal-fired EGUs, examines the role of tax credits in retrofit viability, and assesses the competitiveness of retrofitted units against other low-carbon options. Unit screening identifies EGUs for the study, focusing on new, efficient baseload units with air pollution controls. The power plant databases are then established to organize unit-specific information on performance and operating conditions from the relevant public databases. Biomass for co-firing retrofits is selected based on home and neighboring county availability, ensuring sustained operation with at least a 5% co-firing level. The CO2 storage site is determined by state-level storage potential, with ArcGIS Pro and NETL CO2 Saline Storage Cost Model used to identify the optimal balance between the nearest transport distances and affordable storage costs. The latest IECM v13.0-beta is then employed to configure and evaluate the eligible EGUs with or without the deployment of deep CCS and biomass co-firing. A supply curve is established to illustrate the cumulative installed capacity suitable for retrofits at different cost levels. A sensitivity analysis on tax credits for carbon sequestration is performed. Finally, a unit-level cost comparison is conducted among retrofitted plants, renewable power with battery storage, and abated fossil fuels with DAC. Expected Results. This study evaluates the technical, economic, and environmental metrics of each EGU across an array of CO2 capture rates and biomass co-firing level scenarios. Unit-level comparisons will identify critical factors influencing technical performance. The supply curves with and without tax incentives will provide insights into the impact of tax credits on biomass co-firing and CCS deployment. The cost comparisons with renewables and DAC-retrofit will assess the competitiveness of the retrofitted units. Life cycle emissions from each unit will be assessed to identify the scenarios under which net-zero emissions can be achieved. These analyses are expected to determine the total coal-fired capacity suitable for serving as a low-carbon energy source with or without tax incentives. The study results are novel in identifying optimal unit-specific strategies for producing carbon-neutral power, whether through retrofitting EGUs with deep CCS, biomass co-firing, DAC, or installing renewable power with battery. The findings will provide insight into nationwide efforts to ensure reliable, affordable, and low-carbon electricity. It also will inform investment decisions and policies in the deployment of deep carbon capture and negative emission technologies for a net-zero energy future.

Biomass Co-firing↗
DOE OSTI2019

Data-driven design of metal–organic frameworks for wet flue gas CO 2 capture

Limiting the increase of CO 2 in the atmosphere is one of the largest challenges of our generation. Because carbon capture and storage is one of the few viable technologies that can mitigate current CO 2 emissions, much effort is focused on developing solid adsorbents that can efficiently capture CO 2 from flue gases emitted from anthropogenic sources. One class of materials that has attracted considerable interest in this context is metal-organic frameworks (MOFs), in which the careful combination of organic ligands with metal-ion nodes can, in principle, give rise to innumerable structurally and chemically distinct nanoporous MOFs. However, many MOFs that are optimized for the separation of CO 2 from nitrogen do not perform well when using realistic flue gas that contains water, because water competes with CO 2 for the same adsorption sites and thereby causes the materials to lose their selectivity. Although flue gases can be dried, this renders the capture process prohibitively expensive. Here we show that data mining of a computational screening library of over 300,000 MOFs can identify different classes of strong CO 2 -binding sites-which we term 'adsorbaphores'-that endow MOFs with CO 2 /N 2 selectivity that persists in wet flue gases. We subsequently synthesized two water-stable MOFs containing the most hydrophobic adsorbaphore, and found that their carbon-capture performance is not affected by water and outperforms that of some commercial materials. Testing the performance of these MOFs in an industrial setting and consideration of the full capture process-including the targeted CO 2 sink, such as geological storage or serving as a carbon source for the chemical industry-will be necessary to identify the optimal separation material.

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