John C. Molburg

Allocation of Energy Use in Petroleum Refineries to Petroleum Products Implications for Life-Cycle Energy Use and Emission Inventory of Petroleum Transportation Fuels

Aim, Scope, and BackgroundStudies to evaluate the energy and emission impacts of vehicle/fuel systems have to address allocation of the energy use and emissions associated with petroleum refineries to various petroleum products because refineries produce multiple products. The allocation is needed in evaluating energy and emission effects of individual transportation fuels. Allocation methods used so far for petroleum-based fuels (e.g., gasoline, diesel, and liquefied petroleum gas [LPG]) are based primarily on mass, energy content, or market value shares of individual fuels from a given refinery. The aggregate approach at the refinery level is unable to account for the energy use and emission differences associated with producing individual fuels at the next sub-level: individual refining processes within a refinery. The approach ignores the fact that different refinery products go through different processes within a refinery. Allocation at the subprocess level (i.e., the refining process level) instead of at the aggregate process level (i.e., the refinery level) is advocated by the International Standard Organization. In this study, we seek a means of allocating total refinery energy use among various refinery products at the level of individual refinery processes.Main FeaturesWe present a petroleum refinery-process-based approach to allocating energy use in a petroleum refinery to petroleum refinery products according to mass, energy content, and market value share of final and intermediate petroleum products as they flow through refining processes within a refinery. The approach is based on energy and mass balance among refining processes within a petroleum refinery. By using published energy and mass balance data for a simplified U.S. refinery, we developed a methodology and used it to allocate total energy use within a refinery to various petroleum products. The approach accounts for energy use during individual refining processes by tracking product stream mass and energy use within a refinery. The energy use associated with an individual refining process is then distributed to product streams by using the mass, energy content, or market value share of each product stream as the weighting factors.ResultsThe results from this study reveal that product-specific energy use based on the refinery process-level allocation differs considerably from that based on the refinery-level allocation. We calculated well-to-pump total energy use and greenhouse gas (GHG) emissions for gasoline, diesel, LPG, and naphtha with the refinery process-based allocation approach. For gasoline, the efficiency estimated from the refinery-level allocation underestimates gasoline energy use, relative to the process-level based gasoline efficiency. For diesel fuel, the well-to-pump energy use for the process-level allocations with the mass- and energy-content-based weighting factors is smaller than that predicted with the refinery-level allocations. However, the process-level allocation with the market-value-based weighting factors has results very close to those obtained by using the refinery-level allocations. For LPG, the refinery-level allocation significantly overestimates LPG energy use. For naphtha, the refinery-level allocation overestimates naphtha energy use. The GHG emission patterns for each of the fuels are similar to those of energy use.ConclusionsWe presented a refining-process-level-based method that can be used to allocate energy use of individual refining processes to refinery products. The process-level-based method captures process-dependent characteristics of fuel production within a petroleum refinery. The method starts with the mass and energy flow chart of a refinery, tracks energy use by individual refining processes, and distributes energy use of a given refining process to products from the process. In allocating energy use to refinery products, the allocation method could rely on product mass, product energy contents, or product market values as weighting factors. While the mass- and energy-content-based allocation methods provide an engineering perspective of energy allocation within a refinery, the market-value-based allocation method provides an economic perspective. The results from this study show that energy allocations at the aggregate refinery level and at the refining process level could make a difference in evaluating the energy use and emissions associated with individual petroleum products. Furthermore, for the refining-process-level allocation method, use of mass — energy content- or market value share-based weighting factors could lead to different results for diesel fuels, LPG, and naphtha. We suggest that, when possible, energy use allocations should be made at the lowest subprocess level — a confirmation of the recommendation by the International Standard Organization for life cycle analyses.OutlookThe allocation of energy use in petroleum refineries at the refining process level in this study follows the recommendation of ISO 14041 that allocations should be accomplished at the subprocess level when possible. We developed a method in this study that can be readily adapted for refineries in which process-level energy and mass balance data are available. The process-level allocation helps reveal some additional energy and emission burdens associated with certain refinery products that are otherwise overlooked with the refinery-level allocation. When possible, process-level allocation should be used in life-cycle analyses.

Well-To-Wheels Energy Use and Greenhouse Gas Emissions of Plug-in Hybrid Electric Vehicles

Researchers at Argonne National Laboratory expanded the Greenhouse gases, Regulated Emissions, and Energy use in Transportation (GREET) model and incorporated the fuel economy and electricity use of alternative fuel/vehicle systems simulated by the Powertrain System Analysis Toolkit (PSAT) to conduct a well-to-wheels (WTW) analysis of energy use and greenhouse gas (GHG) emissions of plug-in hybrid electric vehicles (PHEVs). The WTW results were separately calculated for the blended charge-depleting (CD) and charge-sustaining (CS) modes of PHEV operation and then combined by using a weighting factor that represented the CD vehicle-miles-traveled (VMT) share. As indicated by PSAT simulations of the CD operation, grid electricity accounted for a share of the vehicles total energy use, ranging from 6% for a PHEV 10 to 24% for a PHEV 40, based on CD VMT shares of 23% and 63%, respectively. In addition to the PHEVs fuel economy and type of on-board fuel, the marginal electricity generation mix used to charge the vehicle impacted the WTW results, especially GHG emissions. Three North American Electric Reliability Corporation regions (4, 6, and 13) were selected for this analysis, because they encompassed large metropolitan areas (Illinois, New York, and California, respectively) and provided a significant variation of marginal generation mixes. The WTW results were also reported for the U.S. generation mix and renewable electricity to examine cases of average and clean mixes, respectively. For an all-electric range (AER) between 10 mi and 40 mi, PHEVs that employed petroleum fuels (gasoline and diesel), a blend of 85% ethanol and 15% gasoline (E85), and hydrogen were shown to offer a 40-60%, 70-90%, and more than 90% reduction in petroleum energy use and a 30-60%, 40-80%, and 10-100% reduction in GHG emissions, respectively, relative to an internal combustion engine vehicle that used gasoline. The spread of WTW GHG emissions among the different fuel production technologies and grid generation mixes was wider than the spread of petroleum energy use, mainly due to the diverse fuel production technologies and feedstock sources for the fuels considered in this analysis. The PHEVs offered reductions in petroleum energy use as compared with regular hybrid electric vehicles (HEVs). More petroleum energy savings were realized as the AER increased, except when the marginal grid mix was dominated by oil-fired power generation. Similarly, more GHG emissions reductions were realized at higher AERs, except when the marginal grid generation mix was dominated by oil or coal. Electricity from renewable sources realized the largest reductions in petroleum energy use and GHG emissions for all PHEVs as the AER increased. The PHEVs that employ biomass-based fuels (e.g., biomass-E85 and -hydrogen) may not realize GHG emissions benefits over regular HEVs if the marginal generation mix is dominated by fossil sources. Uncertainties are associated with the adopted PHEV fuel consumption and marginal generation mix simulation results, which impact the WTW results and require further research. More disaggregate marginal generation data within control areas (where the actual dispatching occurs) and an improved dispatch modeling are needed to accurately assess the impact of PHEV electrification. The market penetration of the PHEVs, their total electric load, and their role as complements rather than replacements of regular HEVs are also uncertain. The effects of the number of daily charges, the time of charging, and the charging capacity have not been evaluated in this study. A more robust analysis of the VMT share of the CD operation is also needed.

Oxygen-blown gasification combined cycle: Carbon dioxide recovery, transport, and disposal

This project emphasizes CO2-capture technologies combined with integrated gasification combined-cycle (IGCC) power systems, CO2 transportation, and options for the long-term sequestration of CO2. The intent is to quantify the CO2 budget, or an “equivalent CO2” budget, associated with each of the individual energy-cycle steps, in addition to process design capital and operating costs. The base case is a 458-MW (gross generation) IGCC system that uses an oxygen-blown Kellogg-Rust-Westinghouse (KRW) agglomerating fluidized-bed gasifier, bituminous coal feed, and low-pressure glycol sulfur removal, followed by Claus/SCOT treatment, to produce a saleable product. Mining, feed preparation, and conversion result in a net electric power production for the entire energy cycle of 411 MW, with a CO2 release rate of 0.801 kg/kWhe. For comparison, in two cases, the gasifier output was taken through water-gas shift and then to low-pressure glycol H2S recovery, followed by either low-pressure glycol or membrane CO2 recovery and then by a combustion turbine being fed a high-hydrogen-content fuel. Two additional cases employed chilled methanol for H2S recovery and a fuel cell as the topping cycle, with no shift stages. From the IGCC plant, a 500-km pipeline takes the CO2 to geological sequestering. For the optimal CO2 recovery case, the net electric power production was reduced by 37.6 MW from the base case, with a CO2 release rate of 0.277 kg/kWhe (when makeup power was considered). In a comparison of air-blown and oxygen-blown CO2-release base cases, the cost of electricity for the air-blown IGCC was 56.86 mills/kWh, while the cost for oxygen-blown IGCC was 58.29 mills/kWh. For the optimal cases employing glycol CO2 recovery, there was no clear advantage; the cost for air-blown IGCC was 95.48 mills/kWh, and the cost for the oxygen-blown IGCC was slightly lower, at 94.55 mills/kWh.

Hydrogen distribution infrastructure.

Whether produced from fossil or non‐fossil sources, the widespread use of hydrogen will require a new and extensive infrastructure to produce, distribute, store and dispense it as a vehicular fuel or for electric generation. Depending on the source from which hydrogen is produced and the form in which it is delivered, many alternative infrastructures can be envisioned. Tradeoffs in scale economies between process and distribution technologies, and such issues as operating cost, safety, materials, etc. can also favor alternative forms of infrastructure. This paper discusses several infrastructure alternatives and the associated “well‐to‐pump” or “fuel cycle” cost of delivered hydrogen.

The utility industry response to title. IV: Generation mix, fuel choice, emissions and costs

The Clean Air Act Amendments of 1990 incorporate, for the first time, provisions aimed specifically at the control of acid rain. These provisions restrict emissions of sulfur dioxide and oxides of nitrogen from electric power generating stations. The restrictions on sulfur dioxide take the form of an overall cap on the aggregate emissions from major generating plants, allowing substantial flexibility in the industrys response to those restrictions. This report describes one response scenario through the year 2030, which was examined by simulation of the utility industry under assumptions consistent with a reference case that was used for analysis of the National Energy Strategy. Emissions that would result from the use of existing and new capacity and the associated additional costs of meeting demand subject to the emission limitations imposed by the Clean Air Act are projected. Fuel use effects, including coal market shifts, consistent with the response scenario are also described. These results, while dependent on specific assumptions for this scenario, provide insight into the general character of the likely utility industry response to Title IV.

Chapter 6 – Clean Hydrogen from Coal with CO2 Capture and Sequestration

Publisher Summary This chapter discusses the opportunities for coal-derived hydrogen production technologies in the United States and their impact on environment. In the United States, the challenge to the continued use of natural gas creates an opportunity for coal-derived hydrogen. On a worldwide basis, approximately 18 percent of the worlds hydrogen is already derived from coal. Producing hydrogen from coal is more capital intensive than producing it from natural gas. Once the coal is converted to hydrogen, captured CO2, and electricity, the CO 2 must be transported to the site of sequestration. CO 2 can be transported as a compressed gas, a liquid, a solid, or in a high-pressure supercritical state. Furthermore, the US Department of Energys (DOE) Office of Fossil Energy is soliciting industrial interest in the FutureGen plant, a near-zero emissions coal-fed plant that will produce power and hydrogen. Unlike current coal-to-hydrogen technologies, FutureGen plants would employ integrated CO 2 management. The anticipated

- CO 2 capture for PC-boilers using oxy-fuels—A transition strategy

1.0 billion budget will support the design, construction, and operation of a 275 megawatt (MW) prototype plant to serve as a large-scale engineering laboratory for testing new clean power, carbon capture, and coal-to-hydrogen technologies.

Life-Cycle Analysis of a Shell Gasification-Based Multi-Product System with CO2 Recovery

This chapter discusses the fundamental concept that involves replacing combustion air with oxygen diluted by recirculated CO 2 from the flue gas. This eliminates N 2 -CO 2 separation, permitting more economical CO 2 recovery than competing amine systems. A CO 2 /O 2 molar ratio of ∼3 is necessary to preserve the heat-transfer performance and gas-path temperatures. In a site specific study retrofitting a low-sulfur coal-fed boiler, CO 2 recycle shows competitive, operating, and environmental release advantages when compared to amine scrubbing systems. Anticipated breakthroughs in O 2 production will further improve the advantages. For oxy-fuels high-sulfur operation using flue gas desulfurization (FGD) should be practical, and in a related experimental study, it is found that high CO 2 partial pressures from oxy-fuels have a negligible impact on SO 2 -reagent use although FGD solids handling will require redesign. One of the special opportunities afforded by CO 2 /O 2 recycle is that it should prove very attractive at sites considering repowering and converting to an integrated-gasification-combined-cycle (IGCC) to produce H 2 and electricity.