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Search indexed NASA NTRS and DOE OSTI research on propulsion, heat transfer, battery materials and energy systems. Follow report and document links to the original sources.

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At least 73 records · Page 4
All sourcesNASA NTRSDOE OSTI
DOE OSTI2022

Full-scale FEED Study for Retrofitting the Prairie State Generating Station with an 816 MWe Capture Plant using Mitsubishi Heavy Industries Post-Combustion CO 2 Capture Technology

A full front-end engineering design (FEED) study to for a carbon capture system for Unit #2 (816 MWe) at the Prairie State Generating Company’s (PSGC) Energy Campus in Marissa, IL based on the KM CDR Process CO 2 capture technology from Mitsubishi Heavy Industries (MHI) using their proprietary solvent KS-21TM. If built this carbon capture plant would be the world's largest to date. The cost of capture of 100 percent of the plant emissions was calculated to be $43.42 per metric tonne of CO 2 based on levelized costs for 30 years of operation (85% capacity factor), and includes Interest on Debt and Return on Equity During Operation.

01 COAL, LIGNITE, AND PEAT↗
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 OSTI2020

A single-component water-lean post-combustion CO 2 capture solvent with exceptionally low operational heat and total costs of capture – comprehensive experimental and theoretical evaluation

A comprehensive evaluation of a recently developed water-lean amine-based solvent, namely N-(2-ethoxyethyl)-3-morpholinopropan-1-amine (2-EEMPA), has been performed to analyze its post-combustion CO 2 capture performance. This evaluation comprises (1) fundamental characterization of the solvent–CO 2 interaction using vapor–liquid equilibria, kinetics and viscosity measurements; (2) process characterization of the CO 2 capture performance as measured in a laboratory scale continuous flow system and via Aspen Plus® simulation using a flue gas simulant; as well as (3) a full techno economic analysis of the capture process at industrial scale with corresponding projections of critical metrics. This paper summarizes the many parts of this comprehensive evaluation and shows how the various parts come together to empower validated conclusions about its process performance. Notably, it is projected that this solvent can operate at a regeneration heat rate of 2.0 GJ per tonne CO 2 for post-combustion capture, and at a total cost of capture of $50.6/tonne CO 2 . Overall, with further process optimization significant reductions in the capture cost are predicted.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2023

Engineering Study of Svante’s Solid Sorbent Post-Combustion CO 2 Capture Technology at a Linde Steam Methane Reforming H 2 Plant

An initial engineering design study was performed for an advanced post combustion CO 2 capture (PCC) technology to be installed at a commercial-scale steam methane reforming (SMR) hydrogen plant located in the US Gulf Coast. The PCC process integrated the VeloxoTherm™ structured adsorbent technology from Svante for the CO 2 separation and CO 2 compression and purification and balance of plant systems provided by Linde. This pre-FEED equivalent study included following: (1) design basis, (2) basic engineering, including development of process flow diagrams and heat & material balances, (3) inside the battery limit (ISBL) equipment and systems specification, (4) balance of plant outside the battery limit (OSBL) equipment and systems specifications, (5) technology maturation plan, (6) hazard identification (HAZID) review, (7) environmental, health and safety (EH&S) assessment and environmental permitting analysis, (8) constructability review, (9) ISBL and OSBL EPC cost estimation, and (10) commercial-scale techno-economic analysis including capital expenditures (CAPEX) and operating expenditures (OPEX) and CO 2 capture cost estimates.

03 NATURAL GAS↗
DOE OSTI2022

Development of an innovative process for post-combustion CO 2 capture to produce high-value NaHCO 3 nanomaterials

An innovative post-combustion process using aqueous sodium glycinates solutions (SGS) for CO 2 capture from a split flue gas stream emitted from the 600 MWe coal power plant, used in the Wolverine Clean Energy Venture (WCEV) project, was developed in Aspen Plus v.10. The flue gas flow rate used in the process was 12.43 kg/s (at 353.15 K and 101.33 kPa) and contained 0.0023 and 13.33 mol% of SO 2 and CO 2 , respectively. The overall process includes 5 main units designed to remove all SO 2 and capture more than 90 mol% of CO 2 in the flue gas stream, while producing high-value, salable sodium bicarbonate (NaHCO 3 ) nanomaterials to offset the total process costs. The hydraulics, mass transfer characteristics, and process performance obtained using Aspen Plus were discussed. Also, the capital expenditure (CAPEX), operating expenditure (OPEX), and Levelized cost of CO 2 capture (LCOC) were calculated to assess the feasibility of this process. Further, the hydraulics in the SO 2 washing and CO 2 capture units showed a pressure drop of 12 and 1 kPa, respectively, and the behaviors of the liquid holdup and normalized packing specific wetted surface area were similar in both units. The gas-side mass transfer coefficients were orders of magnitude greater than the liquid-side mass transfer coefficients. The process was able to capture 2.352 kg/s of CO 2 and produce 4.486 kg/s of valuable NaHCO 3 nanomaterials. Also, the calculated CAPEX, OPEX, and LCOC of the process for a 30-year plant lifetime were ($\$ $4,450,552), (233.00 $\$ $/h) and (35.49 $\$ $/ton of CO 2 captured), respectively.

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

Front End Engineering Design of Linde-BASF Advanced Post-Combustion CO 2 Capture Technology at a Southern Company Natural Gas-Fired Power Plant (Final Scientific/Technical Report)

This document details the execution of Cooperative Agreement DE-FE0031847, “Front End Engineering Design of Linde-BASF Advanced Post-Combustion Carbon Dioxide (CO 2 ) Capture Technology at a Southern Company Natural Gas-Fired Power Plant” during the period of 10/1/2019 to 6/30/2022. The project was funded by the U.S. Department of Energy’s Office of Fossil Energy and Carbon Management (FECM) and managed by the National Energy Technology Laboratory (NETL). Southern Company Services, Inc. (SCS) was the prime recipient and led the project team. Other members of the project team included Linde, Inc. (Linde), Linde Engineering – Dresden (LED), and BASF. The overall goal of the project was to complete a front-end engineering design (FEED) study for installing the Linde-BASF post-combustion capture (PCC) technology at an existing domestic natural gas-fired combined cycle (NGCC) power plant within Southern Company’s portfolio of assets. The CO 2 capture plant was to be of commercial scale (at least 375 MWe) and include process units for pre-conditioning of the flue gas system, the CO 2 capture plant island, storage vessels, the CO 2 compression train, and any necessary components for integration into the NGCC plant. Mississippi Power’s Plant Daniel Unit #4 was chosen as the host site for the FEED with the target of capturing 90% of CO 2 emissions from the existing combustion turbines. The information produced by the FEED was used to develop a cost estimate of +/- 15% accuracy. Capital costs, excluding financing, are estimated at approximately $\$752$ million dollars (2021). The execution of a project based on this FEED study has an estimated duration of almost five years.

03 NATURAL GAS↗
DOE OSTI2023

Fog and Froth-based Post Combustion CO 2 Capture in Fossil Fuel Power Plants

The University of Kentucky (UK) project titled “Fog+Froth-Based Post-Combustion CO 2 Capture in Fossil Fuel Power Plant”, DE-FE0031733, was conducted from 5/1/2019 to 12/31/2023 in two Budget Periods (BPs), with BP1 from 5/1/2019 to 1/31/2021 and with BP2 from 2/1/2021 to 12/31/2023. The overall goal is to reduce the CO 2 capture capital and operating cost by reducing the absorber size. Other participants included Industrial Climate Solutions, Inc. (ICSI), ALL4 and NexantECA. All project deliverables, milestones, and success criteria were met. Scaled-up demonstration of the compact absorber is planned and two specific aspects of the project demonstration, the solvent spray and the low absorber bottom packing temperature, have been incorporated into the overall UK CO 2 capture process which is on the road to large scale verification and commercialization.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2023

Techno-economic Analysis of CO2 Capture From Pulp/Paper Plants

This poster presentation evaluates the cost of capturing CO2 from a 400,000 air dried tonne (adt)/year pulp production plant, using Shell’s CANSOLV post-combustion capture process. There are five steps in a pulp/paper process: wood preparation, pulping, chemical recovery, bleaching and papermaking. There are three sources of CO2: combustion of waste wood in the wood-preparation step; combustion of black liquor, a product of pulping; and combustion of natural gas coupled with CO2 generated from calcination of limestone in the lime kiln used in chemical recovery. Standalone (pulp only) and integrated (pulp + paper) mills are modeled. The base case results and sensitivity analyses are displayed.

Mantripragada, Hari↗
DOE OSTI2025

Biphasic solvents for post-combustion CO 2 capture from natural gas flue Gas

Fossil fuel fired power plants are generally expected to remain one of the most significant global sources of electricity for decades to come. Consequently, carbon management technologies are needed to reduce or eliminate ongoing emissions from these sources. Amongst the many techniques for carbon capture, aqueous amine-based absorbents (monoethanolamine, MEA, in particular) are, presently, considered the leading technology for post-combustion CO 2 point-source capture. These technologies are nevertheless limited by their high capital and regeneration energy costs. Biphasic solvents have been identified as an attractive alternative to traditional MEA based absorbents due to their potential energy savings. Thus far, however, the research on biphasic solvents has largely focused on their performance in coal flue gas while more dilute natural gas flue gas applications have received relatively little attention. Here, this work examines the performances of two novel biphasic solvent blends, diethylenetriamine (DETA) and triethylenetetramine (TETA), in CO 2 capture from a natural gas flue gas simulant. Across several regeneration tests, both solvents achieved considerable energy savings over the benchmark MEA solution. Specifically, the energy consumption per mol CO 2 recovered for the DETA-based and TETA-based solvents was 46 % and 35 % less than that of the benchmark MEA solution, respectively. Molecular dynamics simulations were also performed to gain a deeper understanding of the phase separation phenomena that occur as a consequence of CO 2 absorption. These simulations indicated that phase change was driven by the strong interaction between the absorption products and water, while the degree of separation depended on the CO 2 loading.

Biphasic solvents↗
DOE OSTI2025

Beta-Amino Carboxylate (BAC) non-aqueous physical solvents for enhanced CO2 separations in pre-combustion carbon capture, industrial CO 2 capture, and biogas upgrading processes

Novel beta-amino carboxylate (BAC) solvents have been synthesized and tested to efficiently capture carbon dioxide (CO 2 ) from process gas streams with CO 2 partial pressure intermediate between pre-combustion and post-combustion capture. The BAC solvents have molecular structures characterized by alkyl-substituted amides or esters containing a secondary amine functional group on the second carbon from the carbonyl carbon (referred to as the beta “β” carbon). The ester or amide functional group combined with optimal steric crowding around the amine nitrogen by proximate alkyl groups are tailored to modify the strength of CO 2 binding in the solvent. The solvents possess high CO 2 solubilities and high gas selectivity including good CO 2 /H 2 O selectivity and can be utilized for CO 2 absorption over a range of partial pressures. Due to low volatility, many of the solvents can be operated at or above ambient temperature which eliminates solvent chilling and allows regeneration using low grade waste heat. These novel solvents offer an opportunity for efficient carbon capture for a range of applications including biogas upgrading, hydrogen production, and pre-combustion carbon capture.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2024

Performance and Cost Potential of sCO2 Bottoming Cycle for Gas Turbines with Carbon Capture – Paper 32

This study investigates the performance and economic potential of sCO2 bottoming cycles for H-class gas turbine-based NGCC plants with a post-combustion capture system. A portion of the gas turbine exhaust heat is used for the generation of steam required for a solvent-based capture system while the rest of the waste heat is utilized in an sCO2 bottoming cycle for power generation. Overall, the performance and LCOE of investigated sCO2 bottoming cycles are similar to those of a state-of-the-art triple-pressure reheat steam Rankine cycle. As the gas turbine exhaust temperature increases (beyond 630oC), sCO2 bottoming cycles begin to show greater performance and economic benefits compared to a steam Rankine cycle with ~0.7 percentage point higher plant efficiency and 1.4% lower LCOE.

Pidaparti, Sandeep↗
DOE OSTI2023

Conclusions from 3 years of continuous capture plant operation without exchange of the AMP/PZ-based solvent at Niederaussem – insights into solvent degradation management

A many times heard mantra of solvent degradation management in amine-based post combustion capture is “keep the solvent clean” to minimize solvent consumption. It is assumed that the amine losses would decrease by the removal of metals, degradation products, and reactive trace components which are captured from the flue gas, like NO 2 (as potentially driving components of the amine degradation besides dissolved O 2 ). However, this theoretical hypothesis – based on results from laboratory experiments typically generated with fresh amines – disregards the complexity of the solvent matrix, interaction of potential metal catalysts with degradation products and oxidizing agents, and specific chemical requirements which must be fulfilled before a degradation mechanism can proceed. Degradation of the solvent CESAR1 (aqueous solution of 3.0 molar 2-amino-2-methylpropan-1-ol (AMP) and 1.5 molar piperazine (PZ)) is investigated in a unique long-time test campaign (testing time up to now 40 months; 24/7 operation) without replacement of the solvent inventory at the capture pilot plant at the lignite-fired power plant in Niederaussem. Three solvent management strategies with different effect mechanisms are investigated and evaluated: (a) removal of only anionic compounds and trace elements (within 75 days solvent inventory treated two times) and anionic as well as cationic compounds and trace elements (114 days, inventory treated four times) from the solvent by ion exchange, (b) adsorptive removal of trace elements from the solvent by active carbon in 35% of the operating time, and (c) removal of >80% NO 2 by flue gas pretreatment with thiosulfate/sulfite solution (dosing for 2,000 h). The results of the testing program clearly show that “solvent cleanliness” is not a well-defined parameter and that results from laboratory tests, tests without fully representative industrial flue gasses, and short-term testing of monoethanolamine cannot be generalized for other solvents and industrial application. Furthermore, these results showcase that specific degradation management considering solvent, capture plant and flue gas quality is reasonable. Overshooting efforts for solvent management are contra-productive and produce unnecessary waste streams, efficiency losses and costs.

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

Pilot Test of a Nanoporous, Super-hydrophobic Membrane Contactor Process for Post-combustion CO 2 Capture

GTI Energy and Air Liquide Advanced Separations (ALaS) have been developing a novel hollow fiber membrane contactor (HFMC) technology for post-combustion CO 2 capture. The process combines advantageous features of both absorption and membrane-based separation processes to separate CO 2 from flue gas cost-effectively. The key component of the HFMC technology is the super-hydrophobic, porous hollow fiber, which is made from polyether ether ketone (PEEK). Compared to conventional absorption/desorption technologies, the critical advantage of the HFMC process is the high contact surface area provided by the hollow fibers enabling an increased volumetric mass-transfer rate. In the PEEK HFMC process, the specific surface area has been increased by an order of magnitude over structurally packed or trayed columns, resulting in compact systems with small footprints.

20 FOSSIL-FUELED POWER PLANTS↗
DOE OSTI2021

Front-End Engineering Design (FEED) Study for a Carbon Capture Plant Retrofit to a Natural Gas-Fired Gas Turbine Combined Cycle Power Plant

A comprehensive front-end engineering design (FEED) study has been undertaken for a post-combustion capture (PCC) unit located at Panda’s Sherman natural gas–combined cycle (NGCC) power plant in Sherman, Texas. This is described in a full and unredacted FEED study report with all supporting documents, numbering over 150, also publicly available.

20 FOSSIL-FUELED POWER PLANTS↗
DOE OSTI2022

Engineering Design of a Linde-BASF Advanced Post-Combustion CO 2 Capture Technology at a Linde Steam Methane Reforming H 2 Plant

Linde carried out an initial engineering design study for a Linde-BASF advanced post combustion CO 2 capture technology to be installed at a commercial-scale steam methane reforming (SMR) hydrogen plant located in the US Gulf Coast. This pre-FEED equivalent study included following: (1) basic design, including specific project scope definition and design basis, (2) basic engineering, including development of process flow diagrams and heat & material balances, (3) inside the battery limit (ISBL) equipment and systems specification, (4) balance of plant outside the battery limit (OSBL) equipment and systems specifications, (5) technology maturation plan, (6) hazard and operability (HAZOP) review, (7) environmental, health and safety (EH&S) assessment and environmental permitting analysis, (8) constructability review, (9) ISBL and OSBL EPC cost estimation, and (10) commercial-scale techno-economic analysis including capital expenditures (CAPEX) and operating expenditures (OPEX) and CO 2 capture cost estimates.

08 HYDROGEN↗
DOE OSTI2021

Front-End Engineering Design (FEED) Study for a Carbon Capture Plant Retrofit to a Natural Gas-Fired Gas Turbine Combined Cycle Power Plant (2x2x1 Duct-Fired 758-MWe Facility with F Class Turbines)

A comprehensive front-end engineering design (FEED) study has been undertaken by Bechtel National Inc. (Bechtel) for locating a post-combustion capture and compression (PCC) unit at Panda’s Sherman natural gas–combined cycle (NGCC) power plant in Sherman, Texas. This is described in the unredacted FEED Study report (Attachment 1) with all supporting documents, numbering over 150. The Study Report is publicly available. Sizing of the PCC plant is based on treating an amount of flue gas equivalent to that produced when generating 420 MW, which is approximately 68% of the total flue gas emitted by the NGCC power plant operating at guarantee condition with duct burners off. A reduced power plant capacity factor was used for sizing the PCC plant because the gas turbines at the site often operate at reduced load due to the high penetration of renewable power in the ERCOT region. The cost of carbon capture is primarily driven by capital cost (and therefore is highly sensitive to capacity factor). Sizing the capture unit so that when used it is nearly always operating at full capacity is critical to the economic viability of the proposed investment.

03 NATURAL GAS↗
DOE OSTI2021

Lab-scaled performance evaluation of novel water-lean solvents for post combustion CO 2 capture

Here, this work focuses on demonstrating the energetic performance and operational reliability in a continuous system of RTI's water-lean solvents for post-combustion CO 2 capture applications. RTI's Non-Aqueous Solvent, NAS-1A was subjected to 100 h of continuous, CO 2 capture and regeneration operation using a Lab-scale Gas Absorption System (LsGAS) while the CO 2 capture efficiency, mass balance, and total energy inputs were monitored. Throughout the test period, NAS-1A demonstrated stable operation with 90% CO 2 capture while requiring about 15% lower total energy input for solvent regeneration compared to 30 wt% monoethanolamine (MEA) solution. The use of a slipstream of CO 2 -rich solvent from the absorber sump reduced the regenerated CO 2 temperature before the gas was further cooled by the overhead condenser at the top of the desorber. The rich-split setup combined with a wash section may be an effective approach to remove water and solvent vapor from the regenerated CO 2 as well as to recover heat at the top of the desorber. NAS-1B was later developed and included a modifier component that lowers the heat of CO 2 absorption and reduces the vapor pressure of the amine component. The total energy inputs for 90% CO 2 capture with NAS-1B was found to be 25% less than that of the MEA. A gas chromatograph was used to monitor the amine concentration in the gas leaving the absorber wash section. It was found that under similar operating conditions, the presence of the modifier in NAS-1B reduces the amine in the absorber off-gas from 143 ppm in NAS-1A to 20 ppm.

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

Advancing Post-Combustion CO 2 Capture through Increased Mass Transfer and Lower Degradation

The over-arching goal of the proposed project is to develop three techniques to enable aqueous post-combustion CO 2 capture technologies to meet the DOE performance and cost targets of 90% CO 2 capture, 95% purity, at a cost of less than $30/tonne CO 2 captured. This will be accomplished by the development of materials and processes to increase mass transfer in the absorber and reduce the environmental impacts. While constantly working to reduce the cost of CO 2 capture via solvent development and process & heat integration, increasing CO 2 mass transfer through development of custom dynamic packing materials and tuning solvent physical properties may offer a route to increased solvent capacity, lower energy consumption and reduced aerosol formation. The environmental concerns that have been identified in amine-based CO 2 capture systems, nitrosamines specifically, are another critical element that will be addressed in this project. The specific objectives of the project were to: 1) conduct detailed studies to understand how solvent physical properties and aerosol formation are impacted by additives; 2) quantify the CO 2 mass transfer improvement from the dynamic polarity packing in the absorber and the additive-modified solvent using the existing UK bench-scale CO 2 capture unit; 3) quantify the energy consumption savings associated with enhanced mass transfer; 4) quantify the benefits of the UK’s electrochemical cell to decompose nitrosamines; and 5) collect the necessary information/data to conduct a high-level TEA assessment of the proposed technologies. The project involved the fabrication and installation of customized dynamic polarity packing and an investigation into the understanding of the impact of chemical additives on solvent properties to increase CO 2 mass transfer in the absorber column, and lastly the design of an electrochemical cell to decompose nitrosamines in a water wash. After both systems were fabricated, they were tested at UK facilities, including on the bench-scale CO 2 capture unit under parametric and long-term operation.

20 FOSSIL-FUELED POWER PLANTS↗