Marianne Mintz

Water consumption in the production of ethanol and petroleum gasoline.

We assessed current water consumption during liquid fuel production, evaluating major steps of fuel lifecycle for five fuel pathways: bioethanol from corn, bioethanol from cellulosic feedstocks, gasoline from U.S. conventional crude obtained from onshore wells, gasoline from Saudi Arabian crude, and gasoline from Canadian oil sands. Our analysis revealed that the amount of irrigation water used to grow biofuel feedstocks varies significantly from one region to another and that water consumption for biofuel production varies with processing technology. In oil exploration and production, water consumption depends on the source and location of crude, the recovery technology, and the amount of produced water re-injected for oil recovery. Our results also indicate that crop irrigation is the most important factor determining water consumption in the production of corn ethanol. Nearly 70% of U.S. corn used for ethanol is produced in regions where 10–17 liters of water are consumed to produce one liter of ethanol. Ethanol production plants are less water intensive and there is a downward trend in water consumption. Water requirements for switchgrass ethanol production vary from 1.9 to 9.8 liters for each liter of ethanol produced. We found that water is consumed at a rate of 2.8–6.6 liters for each liter of gasoline produced for more than 90% of crude oil obtained from conventional onshore sources in the U.S. and more than half of crude oil imported from Saudi Arabia. For more than 55% of crude oil from Canadian oil sands, about 5.2 liters of water are consumed for each liter of gasoline produced. Our analysis highlighted the vital importance of water management during the feedstock production and conversion stage of the fuel lifecycle.

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.

Optimization of Compression and Storage Requirements at Hydrogen Refueling Stations

The transition to hydrogen-powered vehicles requires detailed technical and economic analyses of all aspects of hydrogen infrastructure, including refueling stations. The cost of such stations is a major contributor to the delivered cost of hydrogen. Hydrogen refueling stations require not only dispensers to transfer fuel onto a vehicle, but also an array of such ancillary equipment as a cascade charging system, storage vessels, compressors and/or pumps/evaporators. This paper provides detailed information on design requirements for gaseous and liquid hydrogen refueling stations and their associated capital and operating costs, which in turn impact hydrogen selling price at various levels of hydrogen demand. It summarizes an engineering economics approach which captures the effect of variations in station size, seasonal, daily and hourly demand, and alternative dispensing rates and pressures on station cost. Tradeoffs in the capacity of refueling station compressors, storage vessels, and the cascade charging system result in many possible configurations for the station. Total costs can be minimized by optimizing that configuration. Using a methodology to iterate among the costs of compression, storage and cascade charging, it was found that the optimum hourly capacity of the compressor is approximately twice the station’s average hourly demand, and the optimum capacity of the cascade charging system is approximately 15% of the station’s average daily demand. Further, for an hourly demand profile typical of today’s gasoline stations, onsite hydrogen storage equivalent to at least 1/3 of the station’s average daily demand is needed to accommodate peak demand.Copyright

Hydrogen Delivery Scenario Analysis Model for Hydrogen Distribution Options

As with the distribution of any commodity, distribution of hydrogen depends on how the hydrogen is packaged, how far it must travel, and how much must be delivered. Few would argue that transporting a high-pressure gas is markedly different from transporting a cryogenic liquid— or even a liquid at standard temperature and pressure. Packaging affects not only density (weight/volume) but also the operation of potential delivery modes and onboard storage, a problem that has been called the grand challenge of the hydrogen economy. These three factors—packaging (which in turn affects shipment size and modal attributes), delivery distance, and demand—affect both the structure of potential delivery systems and their contribution to unit costs. This paper describes the hydrogen delivery scenario analysis model, a generalized model of hydrogen delivery that can be used to analyze the economic feasibility of various options for hydrogen distribution to markets of different sizes and types. Inputs may be user define...

Building a hydrogen infrastructure in the United States

More than 9 million metric tons of hydrogen are produced annually in the United States. The majority of the infrastructure is dedicated to supplying hydrogen to the petroleum refining and ammonia manufacturing industries. However, the hydrogen refueling infrastructure in the United States is in its early market phase for fueling hydrogen fuel cell electric vehicles (FCEVs). The hydrogen refueling infrastructure includes the production and delivery of hydrogen, which includes packaging, distributing, storage, and dispensing of hydrogen. Currently, the majority of the hydrogen infrastructure development activities is in the state of California, primarily to support the deployment of FCEVs and meet the 1.5 million zero emissions vehicle (ZEV) sales target by 2025. In this chapter, we discuss the various initiatives, deployment strategies, and marketing strategies being actively pursued in the United States to enable commercialization of FCEVs. The current technologies, processes, and associated challenges of the storage, packaging, transport, and dispensing operations are discussed.

Rethinking hydrogen fueling insights from delivery modeling.

Over the past century gasoline fueling has evolved from being performed by a variety of informal, diverse methods to being performed through the use of a standardized, highly automated system that exploits the fuels benefits and mitigates its hazards. Any effort to transition to another fuel with different properties–-with both advantages and disadvantages–- must make similar adjustments. This paper discusses the existing gasoline refueling infrastructure and its evolution. It then describes the hydrogen delivery scenario analysis model, an Excel-based tool that calculates the levelized cost of delivering hydrogen from a central production facility to a vehicle by the use of currently available technologies and a typical profile of vehicle use and fueling demand. The results are shown for a status quo, or gasoline-centric case, in which demand reflects the current gasoline-based system and supply responds accordingly, and a hydrogen-centric case, in which some of those patterns are altered. The paper highlights fueling requirements that are particularly problematic for hydrogen and concludes with a discussion of alternative fueling paradigms.

Potential Coverage of Alternative Fuel Industries Under EPACT Section 501

The Energy Policy Act (EPACT) has the goal of replacing 10 percent of transportation petroleum fuel with alternative fuels and replacement fuels by the year 2000 and 30 percent by 2010. Sections 501 and 507 of EPACT mandate use of alternative fuel vehicles (AFVs) in fleet applications. In particular, Section 501 requires that certain percentages of new light-duty vehicles (LDVs) acquired by alternative fuel providers be AFVs. The first step in estimating the effects of these mandates entails identifying affected fleets that are covered by the act. An assessment of potential fleet coverage of Section 501 is presented. This assessment concludes that a limited number of companies in the methanol, ethanol, propane, and hydrogen industries are likely to be covered by this mandate. On the other hand, many of the large crude-oil producers, petroleum refiners, natural-gas producers and transporters, and natural gas and electric utilities are likely to be subject to this mandate.

Fuel-Cycle Energy and Emissions Effects of Tripled Fuel-Economy Vehicles

Estimates of the full fuel-cycle energy and emissions effects of lightduty vehicles with tripled fuel economy (3X vehicles) as currently being developed by the Partnership for a New Generation of Vehicles are presented. Seven engine and fuel combinations were analyzed: reformulated gasoline, methanol, and ethanol in spark-ignition, direct-injection engines; low-sulfur diesel and dimethyl ether in compression-ignition, direct-injection engines; and hydrogen and methanol in fuel-cell vehicles. Results were obtained for two market share scenarios. Under the higher of the two scenarios, the fuel-efficiency gain by 3X vehicles translated directly into reductions in total energy demand, petroleum demand, and carbon dioxide emissions. The combination of fuel substitution and fuel efficiency resulted in substantial reductions in emissions of nitrogen oxide, carbon monoxide, volatile organic compounds, sulfur oxide, and particulate matter smaller than 10 microns (PM10) for most of the engine-fuel combinations examined. The key exceptions were diesel- and ethanol-fueled vehicles, for which PM10 emissions increased.

ISSUES AND COSTS ASSOCIATED WITH TRANSITION TO ALTERNATIVE TRANSPORTATION FUELS AND VEHICLES

Key issues and barriers that must be overcome for the successful introduction of alternative-fuel vehicles are summarized. A host of market and institutional barriers faced by vehicle purchasers, vehicle manufacturers, fuel suppliers, and the vehicle service industry are broadly described. Although specific estimates of the costs of overcoming these barriers are highly uncertain, an initial estimate of the general magnitude of these transition costs is presented. This is done by analyzing the transition to a specific alternative-fuel vehicle market penetration for the year 2010. Transition costs are shown to be substantial.

Energy and Greenhouse Gas Emissions of Renewable Natural Gas as Vehicle Fuel

Today more than 300 million standard cubic feet per day of natural gas and 1,680 MW of electricity are produced from the decomposition of organic waste at 541 U.S. landfills. Since landfill gas (LFG) is a renewable resource, this energy is considered renewable. When used as a vehicle fuel, LFG-based compressed natural gas (CNG) consumes up to 1,100 Btu of fossil fuel and generates up to 120 g of carbon dioxide equivalent (gCO2e) greenhouse gas emissions per mile on a well-to-wheel basis. This amount compares with about 7,500 Btu and 500 gCO2e per mile for CNG from fossil natural gas and 8,000 Btu and 650 gCO2e per mile for petroleum gasoline. Liquefying the LFG consumes another 400+ Btu of fossil fuel and 30+ gCO2e per mile if grid electricity is used for the process. However, if some of the LFG is used to generate electricity for gas cleanup and liquefaction (or compression), liquefied natural gas (or CNG) produced from LFG can have no fossil fuel input and only minimal CO2e emissions on a well-to-wheel basis. This renewable natural gas is among the lowest carbon fuels in compressed or liquid form.