Abstract

The use of hydrogen in the energy sector of the United States is projected to increase significantly in the future. Current uses are predominantly in the petroleum refining sector, with hydrogen also being used in the manufacture of chemicals and other specialized products. Growth in hydrogen consumption is likely to appear in the refining sector, where greater quantities of hydrogen will be required as the quality of the raw crude decreases, and in the mining and processing of tar sands and other energy resources that are not currently used at a significant level. Furthermore, the use of hydrogen as a transportation fuel has been proposed both by automobile manufacturers and the federal government. Assuming that the use of hydrogen will significantly increase in the future, there would be a corresponding need to transport this material. A variety of production technologies are available for making hydrogen, and there are equally varied raw materials. Potential raw materials include natural gas, coal, nuclear fuel, and renewables such as solar, wind, or wave energy. As these raw materials are not uniformly distributed throughout the United States, it would be necessary to transport either the raw materials or the hydrogen long distances to the appropriate more » markets. While hydrogen may be transported in a number of possible forms, pipelines currently appear to be the most economical means of moving it in large quantities over great distances. One means of controlling hydrogen pipeline costs is to use common rights-of-way (ROWs) whenever feasible. For that reason, information on hydrogen pipelines is the focus of this document. Many of the features of hydrogen pipelines are similar to those of natural gas pipelines. Furthermore, as hydrogen pipeline networks expand, many of the same construction and operating features of natural gas networks would be replicated. As a result, the description of hydrogen pipelines will be very similar to that of natural gas pipelines. The following discussion will focus on the similarities and differences between the two pipeline networks. Hydrogen production is currently concentrated in refining centers along the Gulf Coast and in the Farm Belt. These locations have ready access to natural gas, which is used in the steam methane reduction process to make bulk hydrogen in this country. Production centers could possibly change to lie along coastlines, rivers, lakes, or rail lines, should nuclear power or coal become a significant energy source for hydrogen production processes. Should electrolysis become a dominant process for hydrogen production, water availability would be an additional factor in the location of production facilities. Once produced, hydrogen must be transported to markets. A key obstacle to making hydrogen fuel widely available is the scale of expansion needed to serve additional markets. Developing a hydrogen transmission and distribution infrastructure would be one of the challenges to be faced if the United States is to move toward a hydrogen economy. Initial uses of hydrogen are likely to involve a variety of transmission and distribution methods. Smaller users would probably use truck transport, with the hydrogen being in either the liquid or gaseous form. Larger users, however, would likely consider using pipelines. This option would require specially constructed pipelines and the associated infrastructure. Pipeline transmission of hydrogen dates back to late 1930s. These pipelines have generally operated at less than 1,000 pounds per square inch (psi), with a good safety record. Estimates of the existing hydrogen transmission system in the United States range from about 450 to 800 miles. Estimates for Europe range from about 700 to 1,100 miles (Mohipour et al. 2004; Amos 1998). These seemingly large ranges result from using differing criteria in determining pipeline distances. For example, some analysts consider only pipelines above a certain diameter as transmission lines. Others count only those pipelines that transport hydrogen from a producer to a customer (e.g., those pipelines designed for in-plant transport of hydrogen for use as feedstock or fuel are not counted). Operational status and hydrogen purity levels are also factors in defining these ranges. Hydrogen pipelines in the United States are predominantly along the Gulf Coast and connect major hydrogen producers with well-established, long-term customers. These hydrogen transmission systems pall by comparison with the 180,000-mile natural gas transmission pipeline. Since 1939, Germany has had a 130-mile pipeline carrying 20,000 lb/hour of hydrogen in a 10-inch pipe at 290 psi gauge (psig). The longest hydrogen pipeline in Europe is owned by Air Liquide and extends 250 miles from Northern France to Belgium. In theory, a blend of up to 20% hydrogen in natural gas can be transported without modifying natural gas pipelines (Oney et al. 1994). « le Document type: Report

Abstract

This work studies the development of a sustainable hydrogen infrastructure that supports the transition towards a low-carbon transport system in the United Kingdom (UK). The future hydrogen demand is forecasted over time using a logistic diffusion model, which reaches 50% of the market share by 2070. The problem is solved using an extension of SHIPMod, an optimisation-based framework that consists of a multi-period spatially-explicit mixed-integer linear programming (MILP) formulation. The optimisation model combines the infrastructure elements required throughout the different phases of the transition, namely economies of scale, road and pipeline transportation modes and carbon capture and storage (CCS) technologies, in order to minimise the present value of the total infrastructure cost using a discounted cash-flow analysis. The results show that the combination of all these elements in the mathematical formulation renders optimal solutions with the gradual infrastructure investments over time required for the transition towards a sustainable hydrogen economy. Document type: Article

Abstract

Hydrogen can be transported over long distances when stored in Liquid Organic Hydrogen Carriers (LOHC). This transport is possible under the following conversion steps: first, hydrogen is stored inside a LOHC molecule (exothermic hydrogenation) at the starting point of the provision chain. Then, the loaded LOHC can be stored and transported. At the point of consumption, hydrogen is released (endothermic de-hydrogenation) and the unloaded LOHC returns to the point of hydrogen production. The optimal LOHC for transport should be liquid at ambient conditions and show similar properties to crude oil-based liquids (e.g., diesel, gasoline). This allows for a stepwise implementation using the existing crude oil-based infrastructure. However, there is a large variety of different LOHCs and other competing transport options; e.g., the transport of compressed hydrogen gas in pipelines or the transport of liquefied hydrogen in tanker ships. Against this background, this paper investigates the energy consumption and costs of these different hydrogen transport options. Therefore, the production of hydrogen is considered in areas with favorable renewable energy sources, followed by international transport logistics, and a local distribution in Germany. The assessment shows that the distance and the way heat is supplied to de-hydrogenate the LOHCs - especially for methanol - define the cost performance compared to a transport of compressed or liquid hydrogen. If the heat needed for dehydrogenation is covered by waste heat, dibenzyltoluene (DBT) or toluene can show benefits in terms of efficiency and costs. Furthermore, the different transport systems have different specific niches in which they are competitive; i.e., no specific transportation chain is superior to all systems under all circumstances. Nevertheless, the assessment shows that long-distance transport favors LOHC, while short-distance transport via pipelines can be used for lower costs.