Results for “REFINERIES” — Page 2

DOE OSTI2019

Air Pollutant Emissions and Regulatory Implications of a Biorefinery Co-Processing Bio-Oil in a Petroleum Refinery

Pyrolysis oil, often referred to as bio-oil when derived from biomass through a fast pyrolysis process, has attracted considerable attention because of the high carbonaceous matter and high heating value compared to the original biomass. Pyrolysis oil provides a viable link between the agriculture/forestry and (petro-) chemical industry. Utilizing existing fossil fuel infrastructure by introducing bio-oil in petroleum refineries to produce renewable hydrocarbon fuels (i.e., repurposing existing assets) is appealing due to its relatively low capital requirement. Our analysis examined the air pollutant emissions for a biorefinery utilizing an ex situ catalytic fast pyrolysis process to produce raw bio-oil, with a design capacity of 2,000 dry metric tons of biomass per day. Such a biorefinery is capable of providing sufficient bio-oil to a 4,200 barrels per day capacity of fluidized catalytic cracking unit if the bio-oil is co-processed at 5% (by volume) feed rate. This research is focused on understanding the potential air pollutant regulatory and permitting implications for a refinery co-processing 5% bio-oil with 95% vacuum gas oil in a fluidized catalytic cracking unit for two scenarios: the first case assumes that an ex situ biorefinery is collocated with a petroleum refinery, and the second one assumes that a petroleum refinery will receive bio-oil from a stand-alone biorefinery. We estimated the potential-to-emit values for 4 biorefinery and FCC sizes and assessed technically feasible emission control options that could help to avoid being subject to prevention of significant deterioration requirements due to petroleum refinery modifications to co-process bio-oil. This research fills gaps and overcomes barriers related to air permitting requirements for co-processing bio-oil in existing refineries for various stakeholders. The insights gained from this analysis can facilitate decision making and help expedite permitting processes for petroleum refineries, which seek opportunities to produce lower carbon fuels in their existing infrastructure.

09 BIOMASS FUELS↗

DOE OSTI2015

Refinery Upgrading of Hydropyrolysis Oil From Biomass

Cellulosic and woody biomass can be converted to bio-oils containing less than 10% oxygen by a hydropyrolysis process. Hydropyrolysis is the first step in Gas Technology Institute’s (GTI) integrated Hydropyrolysis and Hydroconversion IH2®. These intermediate bio-oils can then be converted to drop-in hydrocarbon fuels using existing refinery hydrotreating equipment to make hydrocarbon blending components, which are fully compatible with existing fuels. Alternatively, cellulosic or woody biomass can directly be converted into drop-in hydrocarbon fuels containing less than 0.4% oxygen using the IH2 process located adjacent to a refinery or ethanol production facility. Many US oil refineries are actually located near biomass resources and are a logical location for a biomass to transportation fuel conversion process. The goal of this project was to work directly with an oil refinery partner, to determine the most attractive route and location for conversion of biorenewables to drop in fuels in their refinery and ethanol production network. Valero Energy Company, through its subsidiaries, has 12 US oil refineries and 11 ethanol production facilities, making them an ideal partner for this analysis. Valero is also part of a 50- 50 joint venture with Darling Ingredients called Diamond Green Diesel. Diamond Green Diesel’s production capacity is approximately 11,000 barrels per day of renewable diesel. The plant is located adjacent to Valero’s St Charles, Louisiana Refinery and converts recycled animal fats, used cooking oil, and waste corn oil into renewable diesel. This is the largest renewable diesel plant in the U.S. and has successfully operated for over 2 years For this project, 25 liters of hydropyrolysis oil from wood and 25 liters of hydropyrolysis oils from corn stover were produced. The hydropyrolysis oil produced had 4-10% oxygen. Metallurgical testing of hydropyrolysis liquids was completed by Oak Ridge National Laboratories (Oak Ridge) and showed the hydropyrolysis oils had low acidity and caused almost no corrosion in comparison to pyrolysis oils, which had high acidity and caused significant levels of corrosion.

09 BIOMASS FUELS↗

DOE OSTI2013

Petroleum Refinery Jobs and Economic Development Impact (JEDI) Model User Reference Guide

The Jobs and Economic Development Impact (JEDI) models, developed through the National Renewable Energy Laboratory (NREL), are user-friendly tools utilized to estimate the economic impacts at the local level of constructing and operating fuel and power generation projects for a range of conventional and renewable energy technologies. The JEDI Petroleum Refinery Model User Reference Guide was developed to assist users in employing and understanding the model. This guide provides information on the model's underlying methodology, as well as the parameters and references used to develop the cost data utilized in the model. This guide also provides basic instruction on model add-in features, operation of the model, and a discussion of how the results should be interpreted. Based on project-specific inputs from the user, the model estimates job creation, earning and output (total economic activity) for a given petroleum refinery. This includes the direct, indirect and induced economic impacts to the local economy associated with the refinery's construction and operation phases. Project cost and job data used in the model are derived from the most current cost estimations available. Local direct and indirect economic impacts are estimated using economic multipliers derived from IMPLAN software. By determining the regional economic impacts and job creation for a proposed refinery, the JEDI Petroleum Refinery model can be used to field questions about the added value refineries may bring to the local community.

29 ENERGY PLANNING, POLICY, AND ECONOMY↗

DOE OSTI2022

Carbon Intensities of Refining Products in Petroleum Refineries with Co-Processed Biofeedstocks

Petroleum refineries increasingly seek to generate fuels with lower carbon intensities (CIs; a measure of life cycle greenhouse gas [GHG] emissions per unit of energy of fuel; well-to-wheel [WTW]) to meet growing demand. Co-processing refers to a process that adds biomass-derived feedstocks to the fossil-based feedstocks of existing petroleum refinery process units. With the use of biofeedstocks, it is expected that co-processed fuels would have lower CIs than their petroleum counterparts without requiring changes in the existing infrastructure for producing, transporting, and using fuels. To quantify the GHG emissions reduction benefits of co-processing, this study uses a linear programming model to simulate petroleum refinery conditions with and without co-processing. The co-processing cases include three biofeedstocks (soy oil, tallow, and used cooking oil or UCO) used as 10 vol.% of the feedstock to a hydrotreater or hydrocracker since these lipid-based feedstocks have favorable properties to be treated in a hydrotreater or hydrocracker. In addition, we considered pyrolysis oil used as 10 vol.% of the feedstock to a fluid catalytic cracking (FCC) unit in the modeled refinery due to its higher oxygen content compared to other lipid-based feedstocks. Life cycle analysis (LCA) using two distinct approaches—process-level energy allocation and a refinery-level marginal approach—has been conducted for each case. The LCA results using process-level allocation show that there are no noticeable changes in emissions or energy use impacts at the facility level. The life cycle GHG emission reductions of co-processing cases are mainly related to the fraction of biogenic carbon embedded in each fuel product. For example, co-processed jet fuels (a mixture of fossil and biogenic fuels) made via hydrotreating or hydrocracking have higher biogenic carbon, which results in jet fuel CI reductions of 3.9%–8.6% compared to the CI of baseline petroleum jet fuels on a WTW basis. However, analysis of co-processed pyrolysis oil in an FCC shows that a higher fraction of biofeedstocks (29%) becomes process emissions (i.e., CO and CO 2 ), mainly due to the oxygenates in pyrolysis oil, and so it generates less renewable fuel than biofeedstocks co-processed via hydrotreating or hydrocracking. Using the refinery-level marginal approach, the changes in energy use and emissions of co-processing cases compared to the petroleum-only baseline case are allocated to the changes in fuel production (assuming renewable fuels). This approach generates the life cycle GHG emission values of co-processed renewable fuels, which are comparable to the CIs of standalone biofuel production pathways. However, as this approach relies on a rough assumption that product yields and emissions from co-processing units on fossil feedstocks remain the same with and without biofeedstock inputs, co-processing cases like FCC pyrolysis oil may generate quite skewed results.

02 PETROLEUM↗

DOE OSTI2025

Trends and Effects of Changes in Business Cases for Petroleum Refineries

This study investigates trends and effects in business cases for petroleum refineries with a focus on effects for the state of Oregon for finished gasoline. Recently, the Oregon Department of Energy released the 2024 Oregon Energy Security Plan (ESP) which highlighted the reliance on out of state gasoline imports primarily from refineries located in the state of Washington. This study compiled a list of recent refinery closures in the United States and analyzed the drivers and impacts each refinery closure had to its respective region. The study dives into exploring three refinery closure business cases and past events that impacted gasoline prices in Oregon. Lastly, the paper outlines a potential framework of indicators to analyze the risk of future refinery closures based on the findings. This study hopes to inform stakeholders about the vulnerabilities in Oregon’s fuel supply chain and provide information that can guide strategic planning for future energy security.

02 PETROLEUM↗

DOE OSTI2023

Integration of Experimental Hydroprocessing and FCC Data with Process (Aspen Plus) and Refinery Optimization (Aspen PIMS) Models

NREL's Economic, Sustainability, and Market Analysis (ESMA) team develops process models in Aspen Plus to support techno-economic analysis (TEA) and life-cycle assessment (LCA) of conversion pathways from renewable and circular resources to fuels and chemicals. These tools are being applied to assess probable operational constraints or bottlenecks associated with refinery co-processing and repurposing opportunities. The team also utilizes optimizable refinery models to quantify opportunities for biofuel and bioproduct pathways through integration with existing refining infrastructure. The goals of analysis are to model the transition of refineries to renewable and circular feedstocks and quantify the costs production and CO2 abatement through utilization of existing refineries. At the core of the ESMA team's work is the process data derived from conversion experiments on hydroprocessing and fluid catalytic cracking performed at NREL. The objective of this presentation is to highlight new analysis approaches and capabilities in pathway analysis and refinery optimization modeling with specific emphasis on integration of experimental data.

BIOMASS FUELS,ENERGY PLANNING, POLICY, AND ECONOMY↗

DOE OSTI2021

Online Biogenic Carbon Analysis Enables Refineries to Reduce Carbon Footprint during Coprocessing Biomass- and Petroleum-Derived Liquids

To mitigate green-house gas (GHG) emissions, governments around the world are enacting legislation to reduce carbon intensity in transportation fuels. Coprocessing biomass and petroleum-derived liquids in existing refineries is a near-term, cost-effective approach for introducing renewable carbon in fuels and enabling refineries to meet regulatory mandates. However, coprocessing biomass-derived liquids in refineries results in variable degrees of biogenic carbon incorporation, necessitating accurate quantification to verify compliance with mandates. Existing refinery control and instrumentation systems lack the means to measure renewable carbon accurately, reliably, and quickly. Furthermore, accurate measurement of biogenic carbon is key to ensuring refineries meet regulatory mandates. In this Perspective, we present existing methods for measuring biogenic carbon, point out their challenges, and discuss the need for new online analytical capabilities to measure biogenic carbon in fuel intermediates.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗

DOE OSTI2024

Thermal Integration of Advanced Nuclear Reactors with a Reference Refinery, Methanol Synthesis, and a Wood Pulp Plant (Rev.1)

The present report is intended to provide process flow diagrams (PFDs) and energy and mass balance data sheets for a U.S. industrial sector subset with which nuclear heat and power could be integrated—a subset that includes the oil refining, methanol and pulp and paper industries. Coupling options for integrating nuclear energy into these industries are quantitatively outlined for reference systems, and future work will extend this analysis in greater detail. Opportunities for integrating small modular nuclear reactors (SMNRs) were investigated for each of the industrial process configurations. Aspen HYSYS and Cycle-Tempo models for a high-temperature gas-cooled reactor were developed to evaluate the proposed integration. This introductory evaluation provides a general description and assessment of the operating principles, reactor coolant core outlet temperature, and reactor size to be integrated with industry. The industrial processes of oil refining and the production of methanol, pulp and paper were simulated by using Aspen HYSYS, Aspen Plus, and the PRELIM (Petroleum Refinery Life Cycle Inventory Model) tool to develop process details. Cycle-Tempo models then extend the process modeling results to obtain net energy demands (e.g., heat, steam, and electricity) when accounting for process steam and waste heat recovery. This information is intended to foster the analysis of integrating an SMNR to decarbonize industrial facilities. The SMNR would provide reliable, competitive, and sustainable clean energy while reducing carbon emissions and other environmental impacts, such as water withdrawals, consumption, and contamination. The refining industry, exhibited in Figure ES1, is a leading consumer of fossil -fuel-based heat, power, and hydrogen in the U.S. industrial sector, generating over 164 million metric tons (MMT) of CO 2 emissions in 2023. The overall mass and energy pertaining to a generalized complex refinery in the United States is reflected in Figure ES1, along with energy metrics regarding integration with a nuclear power plant (NPP). Data sheets were developed to indicate the energy requirements for the overall refinery and each refinery process. The data sheet for the overall refinery is shown in Table ES2.

22 GENERAL STUDIES OF NUCLEAR REACTORS↗

NASA NTRS1979

Use of refinery computer model to predict fuel production

Several factors (crudes, refinery operation and specifications) that affect yields and properties of broad specification jet fuel were parameterized using the refinery simulation model which can simulate different types of refineries were used to make the calculations. Results obtained from the program are used to correlate yield as a function of final boiling point, hydrogen content and freezing point for jet fuels produced in two refinery configurations, each one processing a different crude mix. Refinery performances are also compared in terms of energy consumption.

Flores, F. J.↗

DOE OSTI2020

Refinery Products Volatile Organic Compounds Emissions Estimator (RP-VOC): User Manual and Technical Documentation

The estimation of well-to-distributor volatile organic compound (VOC) emissions resulting from the extraction of crude oil in an oilfield, transportation to a crude oil terminal upstream of the refinery, operation of the refinery, and subsequent pipeline and product distribution has previously been approached as a top-down industry-wide average; RP-VOC performs its core calculations using a “from-the-ground-up” approach. By taking this approach, the tool results can be used for the supply network of a single refinery, or to generalize the average performance of all refineries.

12 MANAGEMENT OF RADIOACTIVE AND NON-RADIOACTIVE W↗

DOE OSTI2022

Techno-Economic Analysis for Co-Processing Fast Pyrolysis Liquid in Fossil Refineries

Recent work at the National Renewable Energy Laboratory (NREL) and throughout the bioenergy community has highlighted incentives associated with co-processing bio-intermediates in existing refineries to reduce capital costs associated with renewable fuels and chemicals production and reduce overall risk for emerging biomass conversion technologies. This presentation summarizes the techno-economic analysis results from the NREL-Petrobras collaboration that focused on refinery integration of fast pyrolysis oil through co-processing in the fluid catalytic cracking (FCC) process. The NREL-Petrobras work highlights the economic opportunity for refiners to engage in co-processing for low-carbon products and introduces the risks for refiners based on variability in crude and fossil-product markets. The NREL-Petrobras results also serve as a basis to inform policy design that reduces economic risk for refinery co-processing and repurposing opportunities. The final topics in the presentation highlight experimental capabilities and emerging analysis approaches at NREL and partner laboratories that support the development and commercial deployment of refinery utilization strategies.

bio-fuels↗

DOE OSTI2023

Refinery gas processing method

A process for hydrogen recovery from refinery gas system comprising supplying the refinery gas to an inlet manifold fluidly coupled to a conditioning stage, the conditioning stage comprising a reactor having a reforming catalyst deposited on an ultra-short-channel-length metal substrate; supplying oxidant to the conditioning stage via the inlet manifold; supplying steam from a steam generator to the conditioning stage via the inlet , manifold; reacting the refinery gas in the conditioning stage; and discharging a product through a discharge outlet fluidly coupled to the conditioning stage, the discharge outlet configured to flow the product for use by a downstream reformer. The process allows to either increase the H2 production rate or lower the firing rate while maintaining a constant H2 production rate for the downstream steam reformer, independent of the feed compositional variability of the refinery or still gas.

Vilekar, Saurabh↗

DOE OSTI2022

Model quantification of the effect of coproducts and refinery co-hydrotreating on the economics and greenhouse gas emissions of a conceptual biomass catalytic fast pyrolysis process

Here we present model results for a scaled-up conceptual process informed by bench scale biomass catalytic fast pyrolysis (CFP) and hydrotreating experimental data. This process uses a Pt/TiO 2 catalyst during CFP, which produces a partially deoxygenated organic biocrude intermediate that is then hydroprocessed to a hydrocarbon fuel blendstock; the catalyst also enables high yields of acetone and methyl-ethyl-ketone (MEK) coproducts. Two options for hydroprocessing were modeled: (A) co-hydrotreating at a petroleum refinery using hydrogen sourced from steam reforming of natural gas and (B) standalone hydrotreating at a biorefinery using hydrogen sourced from CFP off gases. The results revealed that Case A was economically advantageous with a modeled minimum fuel selling price (MFSP) of $\$$2.83/GGE or gallon gasoline equivalent (in 2016 US dollars), while the additional cost of standalone hydrotreating facilities in Case B increased the MFSP to $3.13/GGE. Conversely, greenhouse gas (GHG) emissions were lower for Case B (3.9 g CO 2 e/MJ) compared to Case A (21.5 g CO 2 e/MJ) due to the use of biogenic (Case B) and fossil-derived (Case A) hydrogen. In a third option (Case C), the requirements for separation and purification of acetone and MEK were removed from the refinery co-processing scenario (Case A) to evaluate the impacts of this process simplification. Elimination of these coproducts increased the MFSP to $3.21/GGE and GHG emissions to 35 g CO 2 e/MJ. These comparisons based on our detailed conceptual models provide economic and sustainability guidance regarding processing choices for future biorefineries. While refinery coprocessing using existing equipment and the production of relatively valuable coproducts can benefit the economics, the hydrogen-source and biogenic coproducts can have significant impacts on the sustainability of the process, and feasibility to use CFP off-gases or other renewable sources for hydrogen production can help lower GHG emissions.

09 BIOMASS FUELS↗

DOE OSTI2024

Site Integration and Regulatory Considerations for a Nuclear Power Plant Colocated with Industrial Facilities: Colocation Studies for a Petroleum Refinery, Methanol Plant, and Wood Pulp Plant

This research explores the colocation of nuclear power plants (NPPs) with industrial applications. Three existing industrial sites were considered to demonstrate the siting process and illuminate technological gaps for future work. The three applications demonstrated for colocation here are a petroleum refinery, a methanol production plant, and a pulp and paper plant. This study uses a modified version of the EPRI siting criteria to explore the geological and demographic characteristics of the location of the current industrial site, as well as exploring external hazards from the industrial plant and its surrounding land use. Data was collected from public databases to estimate site characteristics. We then discuss how the site characteristics may impact the ability to colocate an NPP with an industrial application. The application site and 5 additional sites were explored for each application to give a general indication of the siting implications for an NPP in each area. The hazards for each industrial application was also explored to determine how colocation may impact reactor safety. The following gaps have been identified and should be explored in future research on colocation of NPPs with petroleum refineries, methanol plants, and pulp and paper plants: - There is a variety of industrial use, hazards, and pipelines in the surrounding area. A more thorough review of these hazards should be considered for colocation. - In general, the whole region around some applications seems to have softer soil, with implications for large site preparation costs. Further site investigations should prioritize looking into the geotechnical conditions. - Applications along coastlines are susceptible to flooding and hurricanes. The benefits of colocation should be weighed against the potential design implications. - The benefits of natural gas pipeline infrastructure in place should be explored further. If heat supply from the NPP is not required or not feasible due to the distance between the NPP and the application, there may be an opportunity to supply hydrogen to the plant through an existing pipeline. - Because there are several collocated industrial plants in the regions for the refinery and methanol plant, the benefits of sharing resources from the NPP should be explored further. This may open up additional sites for colocation. The following knowledge gaps were identified for the colocation of NPPs with these three industries, and industrial applications in general. These gaps are: - While the STAND tool contains many important characteristics for the reactor siting process, it is not calibrated for the colocation of NPPs with industrial facilities. - There are aspects of both the NPP and industrial application that need to be quantified for a siting analysis. Particularly, we need to understand the water intake requirements for NPPs and each application. - Further work may focus on adapting the STAND site comparison methodology to comparison of sites for co-location. This will involve using the data documented in this report as a starting point and performing a comprehensive and quantitative comparison. - Without spending significant resources, it would be impossible to gather data for each site to evaluate all aspects of siting. One approach to finding data and understanding its implications to siting is looking at FSARs for existing plants. For example, most sites considered in this study have small Vs30 values, indicating soft soil. However, there are NPPs located in the vicinity of most of the sites (e.g., Waterford Steam Electric Station near New Orleans) and reviewing available site characteristics and geotechnical data for these NPPs, might provide further information for siting. - The siting analysis in this study indicates that colocation of the NPP with the industrial site could be difficult based on external hazards, cooling requirements, weather, or population. We need to determine the impact of distance between the two facilities on cost and quality of energy transport. - This study did not touch on socioeconomic impacts for NPP colocation with industrial facilities. The input-output analysis methodology could be applied to the communities referenced in this study to determine the socioeconomic impact of these projects. - Similarly, the impacts of colocation on emergency planning was not explored in this study. The impacts on emergency planning infrastructure are somewhat related to the socioeconomic impacts, and could be explored using a similar methodology. - This study also did not address physical and cybersecurity, which will be important aspects of co-location [ref] . Cybersecurity will be important, regardless of the distance, but physical security will be important if the facilities are located very closely. Physical security might also be important for the steam lines between the plants, unless they are determined to be non-safety significant. - In many site l

08 HYDROGEN↗

DOE OSTI2025

Site Integration and Regulatory Considerations for an NPP Colocated with a Petroleum Refinery, Methanol Plant, and Wood Pulp Plant

This research explores the colocation of nuclear power plants (NPPs) with industrial applications. Three existing industrial sites were considered to demonstrate the siting process and illuminate technological gaps for future work. The three applications demonstrated for colocation here are a petroleum refinery, a methanol production plant, and a pulp and paper plant. This study uses a modified version of the EPRI siting criteria to explore the geological and demographic characteristics of the location of the current industrial site, as well as exploring external hazards from the industrial plant and its surrounding land use. Data was collected from public databases to estimate site characteristics. We then discuss how the site characteristics may impact the ability to colocate an NPP with an industrial application. The application site and 5 additional sites were explored for each application to give a general indication of the siting implications for an NPP in each area. The hazards for each industrial application was also explored to determine how colocation may impact reactor safety. The following gaps have been identified and should be explored in future research on colocation of NPPs with petroleum refineries, methanol plants, and pulp and paper plants: - There is a variety of industrial use, hazards, and pipelines in the surrounding area. A more thorough review of these hazards should be considered for colocation. - In general, the whole region around some applications seems to have softer soil, with implications for large site preparation costs. Further site investigations should prioritize looking into the geotechnical conditions. - Applications along coastlines are susceptible to flooding and hurricanes. The benefits of colocation should be weighed against the potential design implications. - The benefits of natural gas pipeline infrastructure in place should be explored further. If heat supply from the NPP is not required or not feasible due to the distance between the NPP and the application, there may be an opportunity to supply hydrogen to the plant through an existing pipeline. - Because there are several collocated industrial plants in the regions for the refinery and methanol plant, the benefits of sharing resources from the NPP should be explored further. This may open up additional sites for colocation. The following knowledge gaps were identified for the colocation of NPPs with these three industries, and industrial applications in general. These gaps are: - While the STAND tool contains many important characteristics for the reactor siting process, it is not calibrated for the colocation of NPPs with industrial facilities. - There are aspects of both the NPP and industrial application that need to be quantified for a siting analysis. Particularly, we need to understand the water intake requirements for NPPs and each application. - Further work may focus on adapting the STAND site comparison methodology to comparison of sites for co-location. This will involve using the data documented in this report as a starting point and performing a comprehensive and quantitative comparison. - Without spending significant resources, it would be impossible to gather data for each site to evaluate all aspects of siting. One approach to finding data and understanding its implications to siting is looking at FSARs for existing plants. For example, most sites considered in this study have small Vs30 values, indicating soft soil. However, there are NPPs located in the vicinity of most of the sites (e.g., Waterford Steam Electric Station near New Orleans) and reviewing available site characteristics and geotechnical data for these NPPs, might provide further information for siting. - The siting analysis in this study indicates that colocation of the NPP with the industrial site could be difficult based on external hazards, cooling requirements, weather, or population. We need to determine the impact of distance between the two facilities on cost and quality of energy transport. - This study did not touch on socioeconomic impacts for NPP colocation with industrial facilities. The input-output analysis methodology could be applied to the communities referenced in this study to determine the socioeconomic impact of these projects. - Similarly, the impacts of colocation on emergency planning was not explored in this study. The impacts on emergency planning infrastructure are somewhat related to the socioeconomic impacts, and could be explored using a similar methodology. - This study also did not address physical and cybersecurity, which will be important aspects of co-location [ref] . Cybersecurity will be important, regardless of the distance, but physical security will be important if the facilities are located very closely. Physical security might also be important for the steam lines between the plants, unless they are determined to be non-safety significant. - In many site l

08 - HYDROGEN↗

DOE OSTI2019

Potential synergies of drop-in biofuel production with further co-processing at oil refineries

Drop-in biofuels have been defined as functionally equivalent to petroleum-based transportation fuels and are fully compatible with the existing petroleum infrastructure. They will be essential in sectors such as aviation if we are to achieve emission reduction and climate mitigation goals. Currently, 'conventional' drop-in biofuels, which are primarily based on upgrading of lipids / oleochemicals, are the only significant source of commercial volumes of drop-in biofuels. However, the necessary increased, future volumes will likely come from 'advanced' drop-in biofuels based on biomass feedstocks such as forest and agriculture residues. Biocrudes / bio-oils produced from lignocellulosic feedstocks using thermochemical technologies such as gasification, pyrolysis, and hydrothermal liquefaction need to be further upgraded to drop-in biofuels. However, advanced drop-in biofuels have been slow to reach commercial maturity due to significant technical challenges, high capital costs, and the challenge of generally lower oil prices. It is likely that the co-processing of drop-in biofuels with conventional petroleum refining could considerably reduce capital costs. Initially, co-processing is likely to be established through the upgrading of conventional / oleochemical feedstocks (lipids). Lipids are readily available in large volumes (global production in 2017 was ~185 million metric tonnes) and can be more easily integrated into oil-refinery processes. In contrast, lignocellulose-derived biocrudes / bio-oils are not yet available in significant volumes and are more complex to co-process in a refinery. The likely strategies for co-processing of oleochemicals (lipids) and bio-oil and biocrude feedstocks based on different insertion points within the refinery infrastructure are discussed.

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

Co-Processing Fast Pyrolysis Bio-Oils and Hydrothermal Liquefaction Biocrudes in Fluid Catalytic Cracking and Hydroprocessing in Refineries

Co-processing of biogenic feedstocks within the existing petroleum infrastructure represents an opportunity to incorporate large volumes of bio-carbon into transportation fuels. However, upgrading intermediate liquids from biomass and waste to final products efficiently and economically, while minimizing impacts to existing refinery infrastructure, remains a notable barrier to commercialization. The co-processing project, Bio-oil Co-processing with Refinery Streams, aimed to generate foundational knowledge for processing renewable intermediates in petroleum refineries and offer co-processing strategies, as well as develop new methods for biogenic carbon tracking and measurement.

bio-oil↗