Search NASA⌕ Search

SEARCH · Search NASA

Results for “refinery processes”

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.

Quote a phrase for an exact phrase match. Source license links do not imply unrestricted reuse.

At least 55 records · Page 3
All sourcesNASA NTRSDOE OSTI
NASA NTRS1980

The impact of fuels on aircraft technology through the year 2000

In the future, it may be necessary to use jet fuels with a broader range of properties in order to insure a more flexible and reliable supply and to minimize energy consumption and processing costs at the refinery. This paper describes research being conducted to (1) determine the potential range of properties for future jet fuels, (2) establish a data base of fuel property effects on propulsion system components, (3) evolve and evaluate advanced component technology that would permit the use of broader property fuels and (4) identify technical and economic trade-offs within the overall fuel production-air transportation system associated with variations in fuel properties.

Grobman, J.↗
DOE OSTI2021

BETO 2021 Peer Review - Process Monitoring and Predictions of Biorefinery Performance

Online process monitoring coupled with rapid predictive tools will be essential to refineries of the future to provide real-time feedback and process control on new, renewable feeds and their accompanying processes and products. This project will provide refinery operators with tools to predict product component concentrations in minutes from online, slip stream mass spectra, allowing for rapid detection of off-specification product. We will arrive at a template for predictive tool generation through the development of a specific tool as a starting point -- co-processing of pyrolysis oils and vacuum gas oil over fluid catalytic cracking (FCC) catalysts.

29 ENERGY PLANNING, POLICY, AND ECONOMY↗
DOE OSTI2023

Cost of Capturing CO 2 from Industrial Sources

The objective of this study is to provide an estimate of the cost to capture carbon dioxide (CO 2 ) from select industrial processes (ammonia, ethylene oxide, ethanol, natural gas processing, coal-to-liquids, gas-to-liquids, refinery hydrogen, cement, iron/steel, and pulp/paper). Each of the ten processes were chosen for analysis due to either the high purity of the CO 2 emission source (99–100 mole percent CO 2 ) or the large quantity of CO 2 potentially available. For each industrial process considered, available plant information, such as existing average plant size, projected new development plant size, or existing plant operations data was used to develop a reference plant for this study.

20 FOSSIL-FUELED POWER PLANTS↗
DOE OSTI2023

Chapter 4 - Pretreatment Technologies for Lignocellulosic Biomass Refineries

Pretreatment is a critical step in processing lignocellulosic biomass into biofuel and bioproducts and is considered the energy and cost center of the biomass conversion process. Although a large number of pretreatment technologies have been developed, not all the techniques are viable on a commercial scale at this stage. Moreover, the technology choice and process conditions depend highly on the type of biomass and the overall biorefinery scheme. This chapter provides an overview of different pretreatment methods, including their mechanism, important process parameters, current status, and challenges. The opportunities associated with new technologies and approaches are presented. Emphasis is placed on low-severity thermal pretreatment technologies. The chapter also provides a brief discussion of the challenges to achieving the economic viability of the technologies on a commercial scale.

BIOMASS FUELS↗
DOE OSTI2024

The Novel Charfuel® Coal Refining Process 18 TPD Pilot Plant Project for Co- Producing an Upgraded Coal Product, and Commercially Valuable Co- Products: Area of Interest #3 – Coal Beneficiation Pilot Plant Testing (Final Report)

Operation of Carbon Fuels, LLC’s (“CF”) existing, permitted 18 TPD pilot plant located in Golden, Colorado using two individually ranked (ASTM D 388) coal types (two campaigns), employing the novel Charfuel® coal refining process to produce an upgraded coal product and a number of high-valued organic and inorganic coproducts (for which there presently exists large commercial markets) in order to produce engineering and product data which will then be utilized toward the design of a commercial scale integrated facility (pre-feed document). Carbon Fuels, LLC has developed the Charfuel® Coal Refining Process which refines domestically abundant, raw coal (in the same manner as crude oil is refined) to produce the identical, high value co-products that are refined from crude oil. Thus, gasoline, jet fuel, “green diesel”, fuel oil, and marine fuels, as well as petrochemicals such as benzene, toluene, xylene, and methanol are refined from raw coal using this process. The Charfuel® Coal Refining Process is not a coal conversion process, like pyrolysis, or indirect liquefaction. Nor is it an alternative energy system. Rather it is a coal refining process that has the ability to economically produce products traditionally associated with the refining of crude oil but using only abundant, raw coal as the refinery feed stock. The Charfuel® Coal Refining Process is more economical than crude oil refining and is environmentally benign. Therefore, this value added process yields a return on investment well above 50% for a commercial facility. Furthermore, the Charfuel® process, unlike alternatives such as ethanol and hydrogen, can utilize the existing transportation, delivery, and other petroleum based systems. Hence, there is no need for new engines, pipelines, tankers, or product acceptance. As a result, the profitability of the process is increased. Objectives: (1) Operation of the integrated 18 tpd pilot plant, using two coal types (ranks); (2) Demonstration of process flexibility in being able to produce different products (gas, liquid, and char), as well as determination of operating parameters for identifying scale up criteria for two coal types (ranks); (3) Generation of engineering and design information (process specifications) for use in designing a commercial scale plant (scale-up); (4) Determination of important environmental issues surrounding the process and the products such as fate of trace elements (mercury and other heavy metals) and distributions of SO2, NOx, and CO 2 by analysis of effluent streams; (5) Production of sufficient product to allow reliable commercial economic evaluation of both the refined coal product and the coproducts; and, (6) Assessment of longer-term reliability of unit operations. Period 1: reconfiguration of the 18 TPD plant to meet specific FOA requirements and to qualify the facility for operation; and, Period 2: operation of the 18 TPD plant for two campaigns using two coals types (ranks) which are widely commercially used and abundant - the first being a subbituminous (Powder River Basin (“PRB”)) coal, and the second a bituminous (Illinois #6) coal.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2025

Using Separation-Enhanced Isotope Ratio Mass Spectrometry to Enable Increased Renewable Carbon Content in Transportation Fuels (CRADA 525)

Stable isotope ratio measurements of carbon atoms using isotope ratio mass spectrometry (IRMS) can be an effective tool for quantifying biogenic carbon in co-processed fuels, with results approaching the precision and accuracy of accelerator mass spectrometry (AMS). The lower cost of an IRMS may enable deployment to refineries, improving access and analysis turnaround times (≤2 hours), and, by extension, provide data that can allow process optimization to maximize renewable carbon in desired refinery products. This project explored the integration of chemical separation with IRMS analyses to enable highly detailed tracking of biogenic carbon into fuel product streams separated by boiling point range, chemical class, or specific compound. Forty-nine fuels and fuel components of fossil and biogenic origin, spanning gasoline and diesel boiling point ranges, were received from three refiners and were analyzed for their δ 13 C values via IRMS. Results spanned a 13 C range from ca. 10‰ to 44‰ and reflect materials derived from sustainable sources (e.g., C4 or C3 plants, animal-based pathways, syngas) or from fossil-derived fuels. Common ranges are approximately 18‰ to 9‰ and approximately 30‰ to 20‰ for C4 and C3 plants, respectively, and approximately 34‰ to 24‰ and approximately 70‰ to 33‰ for petroleum-derived fuels and methane, respectively. Fuel-like standards were developed and tested using direct-injection elemental analyzer (EA) IRMS for liquid fuels. This method was compared with the published methods, yielding statistically similar results. Four blend curve sets were produced ranging from 0% to 100% of a fuel containing biogenic carbon, focusing on 0% to 10% biogenic carbon. Linear fits were the most applicable for two of the four blend curve sets; however, two sets were found to exhibit slightly quadratic behavior, which was more pronounced in low biogenic blend samples, necessitating second-order fits. The origin of the slight quadratic behavior remains unclear; however, the discussion points to possible interpretations. CanmetENERGY thoroughly characterized a majority of the samples using one- and two-dimensional gas chromatography (GC and GC×GC, respectively) and other analyses. Selected samples were subjected to solid phase extraction (SPE) for saturate, olefin, aromatic, and polar (SOAP) analysis, and the resulting solvent-diluted fractions containing saturates and aromatics were returned to Pacific Northwest National Laboratory (PNNL), where the solvent was removed via evaporation or physical separation using GC techniques. Characterization and separations provided an understanding of saturate and aromatic content, as well as boiling point ranges for each sample and sample fraction. Samples resulting from SPE were examined using EA-IRMS and gas chromatography combustion IRMS (GC-C-IRMS) analyses. Both approaches suggest that the range in values between end-members can be increased by selecting the paraffinic or aromatic fraction of the end-member or by selecting among individual compounds resulting from GC separation of the paraffinic fractions. Considerable work remains to put these approaches into practice and statistically validate the benefit for using a fraction or individual compound over bulk analysis of a sample. However, initial results suggest that separations provide advantages for samples having blend ratios of less than 10% biogenic blendstocks. 13 C results showed statistically similar biofuel blend results to those obtained at PNNL, although additional work is needed to obtain better reproducibility. Select samples were sent to Los Alamos National Laboratory (LANL) for IRMS measurements and Beta Analytics for AMS measurements. This work suggests that IRMS and AMS yield closely comparable results and in some circumstances, IRMS could serve as a surrogate for AMS. While additional work is needed to better resolve statistical advantages for separations and better show the comparable nature of IRMS and AMS in both the biogenic carbon analysis of bulk chemical classes, initial results from this study suggest that these should be pursued in order to proliferate this approach for quantifying biogenic carbon in transportation fuels to the refinery level, thereby potentially enabling process optimization in co-processing scenarios.

09 BIOMASS FUELS↗
DOE OSTI2022

Utilization of lignocellulosic biofuel conversion residue by diverse microorganisms

Lignocellulosic conversion residue (LCR) is the material remaining after deconstructed lignocellulosic biomass is subjected to microbial fermentation and treated to remove the biofuel. Technoeconomic analyses of biofuel refineries have shown that further microbial processing of this LCR into other bioproducts may help offset the costs of biofuel generation. Identifying organisms able to metabolize LCR is an important first step for harnessing the full chemical and economic potential of this material. In this study, we investigated the aerobic LCR utilization capabilities of 71 Streptomyces and 163 yeast species that could be engineered to produce valuable bioproducts. The LCR utilization by these individual microbes was compared to that of an aerobic mixed microbial consortium derived from a wastewater treatment plant as representative of a consortium with the highest potential for degrading the LCR components and a source of genetic material for future engineering efforts. We analyzed several batches of a model LCR by chemical oxygen demand (COD) and chromatography-based assays and determined that the major components of LCR were oligomeric and monomeric sugars and other organic compounds. Many of the Streptomyces and yeast species tested were able to grow in LCR, with some individual microbes capable of utilizing over 40% of the soluble COD. For comparison, the maximum total soluble COD utilized by the mixed microbial consortium was about 70%. This represents an upper limit on how much of the LCR could be valorized by engineered Streptomyces or yeasts into bioproducts. To investigate the utilization of specific components in LCR and have a defined media for future experiments, we developed a synthetic conversion residue (SynCR) to mimic our model LCR and used it to show lignocellulose-derived inhibitors (LDIs) had little effect on the ability of the Streptomyces species to metabolize SynCR. We found that LCR is rich in carbon sources for microbial utilization and has vitamins, minerals, amino acids and other trace metabolites necessary to support growth. Testing diverse collections of Streptomyces and yeast species confirmed that these microorganisms were capable of growth on LCR and revealed a phylogenetic correlation between those able to best utilize LCR. Identification and quantification of the components of LCR enabled us to develop a synthetic LCR (SynCR) that will be a useful tool for examining how individual components of LCR contribute to microbial growth and as a substrate for future engineering efforts to use these microorganisms to generate valuable bioproducts.

09 BIOMASS FUELS↗
DOE OSTI2022

Coprocessing Biomass Fast Pyrolysis and Catalytic Fast Pyrolysis Oils with Vacuum Gas Oil in Refinery Hydroprocessing

Fast pyrolysis and catalytic fast pyrolysis (CFP) have been considered to be promising approaches for converting lignocellulosic biomass into liquid bio-oils followed by upgrading to produce fuel-range hydrocarbon products. Co-processing fast pyrolysis and CFP bio-oils with petroleum feedstocks leverages the existing petroleum refining infrastructure, which reduces Capex for the overall conversion technologies for biomass to fuel and enables fast adoption of the technologies and biofuels. Here, we reported the co-processing of different woody fast pyrolysis and CFP bio-oils with petroleum vacuum gas oil (VGO) at 5-25% bio-oil blending levels over a NiMo sulfide catalyst for mild hydrocracking. The catalyst activities over ~300 hours time on stream, the product yield and properties, and the biogenic carbon content in products are provided. Co-processing of the raw fast pyrolysis bio-oil in our configuration was not successful because the instability of the bio-oil resulted in reactor plugging and bio-oil stabilization by hydrogenation enabled their stable co-processing with VGO, whereas the CFP bio-oil can be co-processed without pretreatment. Simultaneous hydrodesulfurization, hydrodeoxygenation, and hydrocracking reactions occurred during co-processing and no obvious decrease in hydrodesulfurization and hydrocracking conversion of VGO was observed, suggesting the minimal impact of co-processed bio-oils on the reaction of VGO and also the simultaneous conversion of bio-oil and VGO to produce fuel products with much-reduced S and O content. Biogenic carbon content in co-processed products calculated by yield mass balance, together with results from isotopic measurements, indicates high biogenic carbon incorporation into liquid hydrocarbon products. In conclusion, higher biogenic carbon incorporation into fuel products was observed when co-processing CFP bio-oils than the fast pyrolysis bio-oils and over 90% of carbon in CFP bio-oil was incorporated into liquid hydrocarbon products.

09 BIOMASS FUELS↗
DOE OSTI2025

Opportunity Assessment for Sustainable Aviation Fuel Production from Woody Biomass via Ex Situ Catalytic Fast Pyrolysis and Refinery Hydroprocessing

Biofuels have become a promising solution to reduce emissions in hard-to-electrify transportation sectors, such as aviation. However, several biofuel conversion pathways will likely be needed to scale sustainable aviation fuel (SAF) production to meet lower carbon intensity goals when biomass feedstock availability constraints are considered. This study evaluates the future potential of the catalytic fast pyrolysis (CFP) pathway to contribute to U.S. SAF production goals as outlined in the U.S. Department of Energy’s (DOE) SAF Grand Challenge, understanding that the CFP pathway is still under development toward maturity and scaleup. National forestland resource data from the DOE’s 2023 Billion Ton Study are integrated with recent experimental results demonstrating end-to-end woody biomass conversion to SAF via CFP and hydroprocessing in a novel bioeconomy optimization framework. U.S. refinery hydroprocessing capacity is also considered with repurposing and coprocessing strategies. Results indicate that the CFP process can contribute up to 4.6 billion gallons of SAF annually by 2040, meeting 13% of the 2050 SAF Grand Challenge target while reducing the carbon intensity (CI) of the U.S. jet fuel pool by 16%. The study further explores optimal processing strategies, suggesting that colocating CFP operations with existing petroleum refineries and repurposing some U.S. hydrocracking capacity may offer significant cost advantages and enhance the commercial viability of the CFP pathway. These results underscore the CFP pathway’s potential to support the global aviation industry’s lower carbon intensity objectives while producing other renewable fuels and products.

09 BIOMASS FUELS↗
DOE OSTI2022

Front-End Engineering Design for Piperazine with the Advanced Stripper

This Department of Energy (DOE) funded project was executed with the goal of preparing a Front-End Engineering Design (FEED) for the capture and compression of 90% of the CO2 that would normally be emitted from an existing natural gas combined cycle (NGCC) plant. The FEED focused on the application of the piperazine advanced stripper (PZAS) process at Mustang Station of the Golden Spread Electric Cooperative (GSEC), which consists of two gas turbines with common heat recovery steam generator (HRSG). The University of Texas at Austin (UT) served as the prime contractor, and subcontracted AECOM Technical Services and Trimeric Corporation to support FEED development. This project team has worked together to advance PZAS for more than a decade. ExxonMobil, Chevron, and Total provided project co-funding. The objectives of this work included: 1. To advance engineering design such that a comprehensive estimate for the total installed cost of a full-scale PZAS CO2 Capture Plant with CO2 compression can be developed on an existing NGCC power plant. a. These detailed costs can also be used to qualify PZAS and other related second generation (2G) amine scrubbing processes for use on cogeneration facilities in refineries and chemical plants that use gas turbines with HRSGs to produce steam. b. These detailed costs will help qualify 2G amine scrubbing for use on NGCC power plants and establish a more accurate baseline cost to be used as a target by other capture technologies. 2. To provide cost details to be used in the economic optimization of the process features of PZAS and other 2G amine scrubbing processes. 3. To provide DOE with a more detailed understanding of carbon capture costs in a commercial application, enabling DOE to better design its R&D program to improve the economics for carbon capture. 4. To provide the host site and cost share partners with the information necessary to determine whether a commercial project to capture and use CO2 for enhanced oil recovery (EOR) or for sequestration can be justified (when accounting for the 45Q tax credit). A key component of the FEED is the estimated total installed cost, which provides a basis for the likely capital investment necessary to implement the PZAS carbon capture process at this location and scale. In combination with the included economic analysis, which accounts for potential revenue from the produced CO2, potential avenues to profitability are explored. The major findings of the FEED are as follows: The Mustang Station PZAS CO2 Capture Plant estimated total project cost of $698 MM of which $384 MM was direct costs. The annual operating costs were $32.6 MM. The total investment for a PZAS facility at Mustang Station is $725 MM. This estimate includes owner’s cost of $25 million and a contingency of $110 MM. • The study estimated the CO2 capture plant at Mustang Station would generate CO2 at $110/tonne for EOR, assuming a 12% IRR (internal rate of return) and an 85% capacity factor. For CO2 storage, the same case would achieve a 12% IRR at about $114/tonne. At a capacity factor of 52%, the storage and EOR cases would break even when carbon is priced ~$150/tonne. The economic analysis determined that the capacity factor and utility pricing, among other variable factors, had a significant effect on the economics and will need additional studied. • The energy penalty of the PZAS plant would be about 46 MW in connected power and 35 MW in operating load. The natural gas requirement (for the Gas Boiler package) would be about 354 MMBTU/hr. • The FEED revealed no major risks in process maturity. However, some areas were outlined for further engineering during detailed design, which included the Gas Boiler system, general arrangement and site layout, air coolers, schedule development, and optimization of the process for higher CO2 removal. • If PZAS were to be implemented at another host site, additional opportunities for cost reduction for would include cost reduction through use of cooling water and steam extraction.

03 NATURAL GAS↗
DOE OSTI2023

Refinery Perspective on Decarbonizing with Marine Biofuels

This work seeks to understand what biofuel production pathways a refinery might prefer to produce very low sulfur fuel oil (VLSFO) for marine applications. A comprehensive refinery optimization model was modified to allow for (1) direct blending of soy biodiesel, renewable diesel, Fischer-Tropsch diesel, and several pyrolysis oils and (2) indirect blending of all pyrolysis oils via co-processing in a fluidized catalytic cracker (FCC) and diesel hydrotreater into the marine fuel pool. Results showed that preferred pathways to bio-VLSFO production included co-processing low-quality pyrolysis oil in a FCC to blend the resulting biogenic light cycle oil, directly blending soy biodiesel, and directly blending small quantities of pyrolysis oil. Bio-VLSFO production costs were compared to those of fossil VLSFO subject to different marine fuel demands, benchmark crude oil prices, and biogenic fractions in the finished product. Given benchmark crude oil prices over 60 $/bbl, bio-VLSFO production appeared to be significantly cheaper than fossil VLSFO. Corresponding marginal abatement costs of CO 2 mostly ranging from -300 to 350 $/ton of CO 2 were also determined using a simplified but novel approach to allow for a comparison to other decarbonization strategies. In conclusion, this work indicates that low-sulfur contents in biofuels, relatively relaxed specifications for marine fuels, and current difficulties in meeting VLSFO specifications with crude oils can combine to make bio-VLSFO production cost-effective. Moreover, marine fuels appear to be a good entry point for refiners to start decarbonizing with biofuel pathways that could eventually be extended to other product pools.

09 BIOMASS FUELS↗
DOE OSTI2024

A Carbon Dioxide Refinery: The Core of a Sustainable Carbon-based Circular Economy

The atmospheric carbon dioxide (CO 2 ) accumulation (2–2.5 ppmv/year) is the result of the enormous gap between its emissions (37 Gton/year) and its capture, storage, and utilization (<500 Mton/year). Climate has been dramatically affected due to the failure of natural sinks, in working effectively. To address this Gton-scale gap, numerous uses and applications are needed particularly, those consuming vast volumes of this compound and/or rendering longevous products or long lifecycle services. Thus, carbon utilization (CU) can be seen as the step to close the carbon cycle. Among CU, R&D on CO 2 chemical conversion has proposed a variety of processes, with different degrees of developmental maturity. These chemical process technologies could be efficiently and effectively integrated into refineries to upgrade emitted CO 2 . A technology pipeline consisting of a database of these processes and the technology market status should be defined based on published scientific results and patents. Then, an innovative top-down methodology is proposed to eco-design configurations of that refinery, to warrant a sustainable carbon cycle (in terms of energy, environment, and economy) and to change the ways of producing fuels, chemicals, and materials. Additionally, the proposed methodology could be used to identify research and development gaps and needs, for orienting science and technology investments and measures. Hopefully, sustainable CO 2 refineries will be implemented to close the carbon cycle of a circular C-based economy and underpin a decarbonized chemical industry.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2024

Technical and Economic Assessment and Gap Analysis of Advanced Nuclear Reactor Integration with a Reference Oil Refinery

Efforts to identify the most-economic methods to decarbonize several sectors of the U.S. economy are underway. Industrial processes such as crude-oil refining rely heavily on energy-dense and easily stored and transported fossil fuels for powering their operations. Refineries use large amounts of energy, primarily derived from fossil sources to separate crude-oil components, break down heavier hydrocarbons into lighter compounds, remove impurities, reform hydrocarbon molecules, and generate steam and electricity for pumps and compressors and other various auxiliary systems. Crude-oil refining operations such as distillation, cracking, desulfurization, reforming, utilities systems and some offsite facilities collectively account for most of the energy consumption. Other operations such as hydrocracking or hydrotreating also require hydrogen for developing hydrogenation reactions which involve substantial heating to keep the reactors at high-temperature and pressure levels. All heat and energy demands are typically provided by natural gas (NG), oil, or other fuels, which makes refinery industry one of the most-difficult sectors to decarbonize. Nuclear power is a viable and energy-dense source of clean electricity, heat, and hydrogen to provide the large, sustainable energy supply that the refining industry demands. The U.S. Department of Energy’s (DOE’s) Integrated Energy Systems (IES) program is working to perform research and development, design, economic siting, and risk analysis. This state-of-the-art work will enable the first on-site demonstrations and commercial deployments of advanced small modular nuclear reactors (SMNRs) integrated with industries such as chemical production, refining, iron and steel making, and more. IES seeks to demonstrate the ability of advanced nuclear reactors to meet the heat and power demands of these industries while reducing carbon emissions in a sustainable and cost-competitive way. The primary objective of this research effort is to analyze industrial-scale SMNR integration intended to decarbonize refining facilities. The foreseen outcome is the provision of reliable, cost-competitive, and sustainable clean energy, alongside a reduction of carbon emissions. Specifically, the focus of this work lies on meeting the reference facilities’ heat and electricity demands with nuclear power while also supplying clean hydrogen via integrated high-temperature steam electrolysis (HTSE). This report presents a comprehensive technical and economic assessment of the integration of advanced nuclear reactors into a reference refinery, leveraging financial incentives from the Inflation Reduction Act (IRA). The evaluation aims to explore the potential economic benefits and challenges associated with incorporating advanced nuclear reactors into refinery operations, particularly in terms of energy efficiency, economic implications and environmental impact. By examining both the technical feasibility and economic viability, this analysis seeks to identify existing gaps and propose solutions for successful nuclear integration implementation. The findings are intended to provide valuable insights for stakeholders considering the adoption of advanced nuclear reactors in the refining sector. A refinery reference-plant was developed, using an open-source refinery model, Petroleum Refinery Lifecycle Inventory Model (PRELIM) and expert assessment, as a base case for comparison with various nuclear integration options. The capacity of 100 kbd/day (KBD) of heavy crude-oil feed was selected to represent a general coking-type refinery with deep conversion capabilities (incorporating heavy-oil upgrading with FCC, coking, and associated hydrotreating process units), using a heavy crude-oil feed, which represents about 70% of U.S. refineries configurations. A summary of all cases considered in this study is shown in Table 1.

13 HYDRO ENERGY↗
DOE OSTI2022

Cost of Capturing CO 2 from Industrial Sources

This systems analysis by the National Energy Technology Laboratory's Strategic Systems Analysis and Engineering directorate) evaluates the cost and performance impacts of capturing CO 2 emissions from nine industrial sources (ammonia, ethylene oxide, and ethanol production, natural gas process, coal- and gas-to-liquids, refinery hydrogen production, iron and steel, and cement manufacturing). The industrial sectors examined are segregated according to the CO 2 purity level of the flue gas stream, prior to treatment. Certain sectors naturally produce a gas stream that is inherently high in CO 2 purity, and these sectors can achieve 99-100% removal. Other sectors produce a lower purity CO 2 flue gas stream and achieving 90-99% removal requires deeper levels of treatment, adding cost. In addition to the report that documents the analysis, a Carbon Capture Retrofit Database tool was also created that allows users to apply CO 2 capture to selected industries, to evaluate the cost of capture and compare across multiple plants, as well as across different industries. Users have the ability to change select input parameters (such as fuel price, capture rate, and financing assumptions) to evaluate the impact on industrial CO 2 capture economics.

20 FOSSIL-FUELED POWER PLANTS↗
NASA NTRS1995

Hydrogen Annealing Of Single-Crystal Superalloys

Annealing at temperature equal to or greater than 2,200 degrees F in atmosphere of hydrogen found to increase ability of single-crystal superalloys to resist oxidation when subsequently exposed to oxidizing atmospheres at temperatures almost as high. Supperalloys in question are principal constituents of hot-stage airfoils (blades) in aircraft and ground-based turbine engines; also used in other high-temperature applications like chemical-processing plants, coal-gasification plants, petrochemical refineries, and boilers. Hydrogen anneal provides resistance to oxidation without decreasing fatigue strength and without need for coating or reactive sulfur-gettering constituents. In comparison with coating, hydrogen annealing costs less. Benefits extend to stainless steels, nickel/chromium, and nickel-base alloys, subject to same scale-adhesion and oxidation-resistance considerations, except that scale is chromia instead of alumina.

Smialek, James L.↗
DOE OSTI2022

Design for Carbon Conversion Product Pathways with Nuclear Power Plant Integration (PCC)

Coal is a globally abundant resource that historically has been used for power generation via combustion. As the power industry replaces coal with cleaner methods of generation, energy rich coal could be used in other chemical and fuel applications. This study presents a coal utilization option in which coal combustion is replaced with a carbon-free nuclear power plant and the coal is upgraded to valuable products for a variety of markets. Coal is prepared for conversion first by the pyrolysis process, which will optimize solid, liquid, and gaseous products based on the market size and potential product value, maximizing the monetary value of coal. This process is designed using bituminous coal from the Appalachian region as a basis to provide a pathway to preserve or transition coal-related jobs and create new jobs associated with the clean energy transition. Process modeling will be used to determine each component’s sensitivities, costs, inputs, and outputs Advanced and light-water reactors are considerations to supply the heat, steam, and electricity to the process. This paper focuses on the technical and market analysis used to determine the optimal processes and product pathways for the carbon refinery. Product pathways are on activated carbon, formic acid synthesis, and methanol synthesis for further upgrading to marketable chemical and polymer products.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2023

Comparative Techno-economic Analysis and Life Cycle Assessment of Producing High-Value Chemicals and Fuels from Waste Plastic via Conventional Pyrolysis and Thermal Oxo-degradation

The rapid rise in global plastic production in recent decades has resulted in the massive generation of plastic waste. Over 75% of the plastic waste generated in the United States was sent to landfills, with a meager 8.7% recycled. Plastics are valuable feedstocks for platform chemicals and fuels. Chemical upcycling of waste high-density polyethylene (HDPE) is gaining more attention as a potentially feasible and environmentally friendly plastic waste management technology. Conventional pyrolysis (CPY) and thermal oxo-degradation (TOD) are two chemical upcycling technologies actively researched for decomposing waste HDPE into valuable chemicals and fuels. However, there are few studies on the techno-economic analysis (TEA) and life cycle assessment (LCA) of these technologies for converting waste HDPE to valuable products. This study conducts a comparative TEA and LCA study of the thermochemical decomposition of waste HDPE to produce gaseous (ethylene and propylene) and liquid (naphtha, diesel, and wax) products by CPY and TOD. The study elucidates and compares the impact of hydrocracking longer chain hydrocarbons to produce more valuable products on the TEA and LCA. The TEA showed that the fixed capital investment could range from $\$32.5$ million for TOD without hydrocracking to $\$244$ million for CPY with hydrocracking scenarios. Annual revenues range from $\$28.1$ million to $\$71.5$ million in favor of scenarios with hydrocracking. However, the net present value ranges from $\$1.4$ million to $\$265.8$ million in favor of scenarios without hydrocracking. Sensitivity analysis showed that fixed capital cost, facility capacity, and product prices have the biggest impact on the process economics of the facilities, while utilities and waste transportation to refineries have the biggest impact on environmental impacts. Here, the LCA showed that primary products from scenarios without hydrocracking can be more environmentally friendly than virgin products from petroleum processes. However, TOD and CPY with hydrocracking primary products have more emissions than those of virgin products.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗