Nuclear Wind Hydrogen Systems For
Variable Electricity and Hydrogen Production
Charles Forsberg and Geoffrey Haratyk
Massachusetts Institute of Technology
In a low-carbon world, the primary energy sources will be nuclear and renewables. Both energy sources are capital intensive with low operating costs; thus, such plants should be operated at maximum capacity. However, the outputs of these facilities do not match the demand for electricity. In the United States, renewable energy outputs are seasonal with high wind conditions in the spring and high solar outputs in the summer. There is a massive mismatch between potential production and demand. Last, the cost of renewables is highly site dependent with the potential for low-wind costs on the upper Great Plains and solar in the southwest.
To address these challenges we have been investigating the economics of a nuclear wind hydrogen system with the capability of meeting variable electricity demand and producing constant-output pipeline hydrogen for refineries and other industrial applications. The goal is to develop an economic system. Based on analysis of the Midwest electrical grid using actual electricity demand data and measured local wind conditions, such a system may be possible if reasonably priced high-temperature electrolysis systems (HTE) are developed, these systems can operate reversibly as fuel cells for peak electricity production and the cost of wind systems continues to decrease.
We chose for economic analysis the Midwest electrical grid. First, the upper Midwest has some of the best wind conditions in the United States and thus the lowest cost wind. Second, there are large hydrogen markets in the refineries near Chicago and in Alberta. In this system there are two markets for hydrogen (peak electricity and refineries) with different characteristics.
The proposed system is shown in Figure 1. It produces two products: variable electricity on demand and hydrogen for industrial customers. The primary product is electricity. The base-case system consists of the following components.
- Nuclear power plants. Nuclear power plants provide 40 GW(e) of base load electricity. Added plants provide steam for nuclear hydrogen production or electricity when hydrogen is not being produced.
- Wind power plants. The system contains 57 GW(e) of wind capacity.
- Natural Gas Turbines. The system contains 57 GW(e) of gas turbines match electricity production with demand when there is insufficient wind.
- High-temperature electrolysis (HTE). These plants produce hydrogen using steam from the nuclear plants and electricity from the grid (nuclear and wind). Because steam costs a third as much as electricity, HTE has the potential to be a much lower cost method to produce hydrogen. About 20% of the energy is provided in the form of steam rather than electricity. For every 100 MW of heat and 540 MW of electricity, 4.22 kg/sec of H2 is produced. The other characteristic is that HTE systems have the potential to be operated in reverse as fuel cells to produce electricity.
- Hydrogen pipelines. Hydrogen pipelines move hydrogen to the refinery markets in Chicago or Alberta. It is a low-cost long-distance way to export energy
- Hydrogen storage. Hydrogen is stored underground using the same technologies used to store natural gas.
Three components of this system have high capital costs: nuclear plants, wind turbines, and hydrogen pipelines. For viable economics, these systems must operate at high capacity factors. Hydrogen storage is cheap. HTE is in the developmental stage and has the potential to be a low cost technology. We undertook and economic assessment of this system under a variety of conditions for the Midwest electrical grid but always using actual electricity demands and wind conditions. Our economic assessment came to several conclusions.
- System design. The economics of the proposed system are much better than an all wind system. All wind systems produce very expensive electricity because one must store massive amounts of energy to match wind production with electricity demands. Wind production is primarily in the spring but peak demand is in the late summer. The inefficiencies in converting electricity to hydrogen and back to electricity imply massive high costs.
- Economics. The proposed system architecture has the potential to be economic with wind providing a quarter or more of the total electricity. The design minimizes large-scale conversion of electricity to hydrogen and back to electricity. Hydrogen is used for both peak electricity and industrial customers; thus, the economics depends upon both markets. This is unlike pumped hydro storage and other energy storage technologies with a fixed ratio of energy into and out of storage. The economics are dependent upon major reductions in wind turbine costs and that HTE is successfully developed.
- Economic sensitivities. The system economics are strongly dependent upon the HTE technology.
- Capital costs must be reasonable ($400/kW). This appears to be achievable but has not yet been demonstrated
- The HTE systems should be designed to operate for a few hundred hours per year as fuel cells. This is done in the laboratory but has not been a design goal of HTE developers.
- Role of gas turbines. The electrical grids today have tens of gigawatts of gas turbines that are operated only a few hundred hours per year to meet peak power demand. If there is the large scale use of renewables, many more gas turbines will be required to meet electricity demand when the wind slows. Many of these gas turbines produce very high-cost power because of the capital charges to build the turbines that are only operated for a few hundred hours per year. In such an operating mode, fuel is not a major cost. There are large savings in system capital costs if HTE can replace these gas turbines by operating in reverse as fuel cells when wind conditions are poor and electricity demand is high. Our models indicated that only 0.5% of the total electricity would be produced by the HTE systems operating as fuel cells?but significant savings would result by avoiding the capital charges associated with the gas turbines that are not built.
The details of the assessment are in the paper.
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