Fuel Delivery and Storage
The fuels model covers the delivery and storage of fuels required to connect primary supply and conversion to the point of end-use. In reality, fuel delivery networks are highly complex. US-REGEN captures these activities at a relatively high level and does not attempt to resolve these networks in detail. It is primarily designed to reflect the economic costs of the storage and delivery components of alternative energy pathways, but it does include an explicit structural representation of inter-regional pipeline flow of natural gas (or a blended equivalent) and hydrogen and of the storage requirements for temporal balancing of these commodities. Intra-region costs for pipeline gas and hydrogen delivery, similar to electricity, are represented as levelized costs. For liquid fuels, which have much higher energy density and thus lower relative costs of delivery and storage, the model assumes a flat levelized cost adder to reflect aggregate distribution costs. Levelized cost estimates are based on observed differences in wholesale and retail prices in current EIA data.
The existing pipeline network is represented in terms of capacity in mmbtu per day flow rate between connected model regions. The resulting capacity based on current state-level EIA data is summarized in Figure 1 for the default configuration in US-REGEN. There is also extensive existing capacity for natural gas storage in underground reservoirs, which is used for seasonal balancing of gas demands, particularly for space heating during winter months. Figure 1 also shows the scale of regional distribution existing gas storage capacity.
In the US-REGEN fuels model, pipeline gas supply and demand in each region is required to balance on a weekly basis. The available capacity for inter-regional movements and storage withdrawals and injections is a potentially binding constraint on these weekly regional balances. In a given scenario, depending on the evolution of regional supply and demand, the model includes the option to add new inter-regional pipeline capacity and storage capacity to the existing pipeline gas infrastructure.
The model also includes the option to move and store hydrogen with new dedicated infrastructure. The assumptions for bulk storage of hydrogen are based on an underground geologic reservoir in a salt cavern or similar formation.[1] Capital costs are divided into those costs that scale with withdrawal capacity ("door" costs) and those that scale with reservoir storage capacity ("room" costs). Withdrawal capacity costs include compression and drilling of wells, while reservoir capacity costs include geology, excavation, brine disposal, and cushion gas. The costs for these options are shown in Table 1.
| Natural Gas (or blended equivalent) | Hydrogen (dedicated infrastructure) | |
|---|---|---|
| Inter-regional pipeline capacity ($ per mmbtu per day per mile) | 11 | 22 |
| Storage energy capacity ("room") ($ per mmbtu) | 10 | 65 |
| Storage withdrawal capacity ("door") ($ per mmbtu per day) | 700 | 2800 |
US-REGEN considers the option to blend several gas commodities together for delivery through existing natural gas infrastructure. In additional to conventional fossil-based natural gas, the blend can include renewable natural gas (from either waste methane sources of via gasification of cellulosic biomass), synthetic natural gas (from hydrogen and captured carbon), and hydrogen, up to a share of 20% of by volume, which translates to roughly 7% in energy terms. There are no constraints on the blended shares of renewable and synthetic natural gas, as these are considered to be essentially identical substitutes.
Intra-regional fuel delivery costs for non-electric fuels are shown in Table 2. Hydrogen delivery costs are based on an assumed pipeline network, with higher levelized costs for smaller customers in the residential and commercial sectors. Assumed hydrogen delivery costs are significantly lower than observed costs today based on smaller scale truck deliveries. Transport applications also include the cost of dispensing hydrogen at pressure into vehicles, which is a significant cost component, even assuming declines relative to today based on scale and learning. Delivery costs for ammonia are based on observed differences in producer and consumer prices from the USDA.
| Residential | Commercial | Transport Light-Duty/ Retail | Transport Fleet/Depot | Industry Small | Industry Large | |
|---|---|---|---|---|---|---|
| Pipeline Gas (existing NG) | 7.1 (varies by region, US average) | 4.7 (varies by region, US average) | Commercial price + 8 compression +3-6 taxes | Commercial price + 8 compression +3-6 taxes | 1.8 (varies by region, US average) | 1.8 (varies by region, US average) |
| Hydrogen (new pipeline) | 14 | 11 | 8 + 24 ($3/kg dispensing) | 8 + 16 ($2/kg dispensing) | 8 | 6 |
| Diesel Gasoline | 8 | 6 | 3 + 3-6 taxes (varies by region) | 3 + 3-6 taxes (varies by region) | 3 | 3 |
| Jet Fuel | N/A | N/A | N/A | 1 | N/A | N/A |
| Ammonia | N/A | N/A | 6 | 6 | 6 | 4 |
EPRI is conducting further research under the Low-Carbon Resources Initiative to examine regional constraints on suitable geology for hydrogen storage, including the costs and potential for other types of formations. ↩︎