Question 6 of 6: Energy Generation and Storage

Question 6: Energy Generation and Storage (15 marks)

Question text not reproduced: the examination questions are © Engineers and Geoscientists BC. Open the official past paper (linked at the top of this page) to read the question, then follow the worked solution below.

Part I — nuclear power against fossil and renewable alternatives. The decisive technical advantage of nuclear power is energy density. Fission of one uranium-235 nucleus releases about 200 MeV, so a kilogram of U-235 yields roughly 82 TJ against 27 MJ for a kilogram of coal — a factor of about three million. Every practical consequence follows from that number: fuel transport and storage are trivial where a coal plant needs a unit train a day, the fuel cost is a small fraction of the generating cost so the plant is insensitive to commodity prices, and several years of fuel can be held on site, which is a genuine energy-security argument. Operationally, a modern reactor is a firm, high-capacity-factor machine: Canadian CANDU units routinely exceed 85 % capacity factor and run for eighteen months between refuellings, which makes nuclear the natural base-load complement to variable renewables. Environmentally, the plant emits no CO₂, no SO₂, no NO_x and no particulate in operation, its land footprint is the smallest of any source per MW, and its waste, though intensely hazardous, is small enough in volume to be fully contained and accounted for.

The disadvantages are equally structural. Capital cost dominates — a large unit costs several times a combined-cycle gas plant per kW and takes eight to twelve years from decision to service, so the financing cost, and the risk of schedule overrun, dwarf every other economic consideration. Thermodynamically the plant is penalised by its own safety envelope: fuel-cladding temperature limits cap the steam conditions, so a CANDU works a saturated-steam cycle at about 33 % efficiency where a supercritical coal unit reaches 41 % and a combined cycle 58 %. That low efficiency shows up directly as thermal discharge, quantified in Question 3 at 2147 MW for a 1000 MW station, more than the coal plant of the same output. Operationally, large reactors manoeuvre poorly and are uneconomic to cycle, so they are ill-suited to a grid with growing variable generation unless paired with storage. Waste management demands institutional continuity over a hundred thousand years, and no repository is yet operating in Canada. Proliferation of fissile material and enrichment technology is a security concern that no other generating technology raises. And public acceptance, shaped by Three Mile Island, Chernobyl and Fukushima, remains the practical constraint on new build in most jurisdictions — the technical risk figures are low, but the consequence of a severe release is uniquely long-lived and uniquely visible.

The balanced conclusion is that nuclear power is not a substitute for renewables but a complement to them. It is the only firm, dispatchable, near-zero-carbon source that can be sited where the load is and does not depend on the weather; its weakness is capital cost and inflexibility, precisely the areas in which small modular reactors — factory-built, of a few hundred MW, load-following, and the subject of active Canadian development at Darlington — are intended to improve.

Part II — large-scale energy storage. Grid-scale storage exists to decouple the time at which energy is generated from the time at which it is used, and the requirement grows with the share of wind and solar because those sources are neither dispatchable nor correlated with demand. Three technologies reach the scale required, and they differ in what they store.

Pumped hydroelectric storage accounts for the overwhelming majority of installed storage worldwide. Its configuration, shown in Figure 6.1, is two reservoirs separated by a few hundred metres of head, connected by a penstock through a reversible pump-turbine coupled to a motor-generator. When surplus energy is available — overnight, or on a windy afternoon — the machine runs as a pump and lifts water to the upper reservoir; at peak demand the flow reverses and the same machine generates. The stored energy is simply potential energy, so for a plant of 300 m head, 12 million cubic metres of working volume and a 78 % round-trip efficiency the delivered energy is$$E=\frac{\rho\,g\,H\,V\,\eta}{3.6\times 10^{12}}=\frac{1000\times 9.81\times 300\times 12\times 10^{6}\times 0.78}{3.6\times 10^{12}}=7.65\ \text{GWh}$$or 15.3 hours at a 500 MW discharge rate. Modern variable-speed machines can also regulate while pumping, which makes them valuable for frequency control as well as for energy arbitrage. The limitation is siting: the scheme needs two reservoirs, suitable topography and geology, and the environmental objections of any impoundment.

Compressed-air energy storage stores work in a pressurised underground cavern, usually solution-mined in salt. Off-peak electricity drives a multi-stage intercooled compressor that charges the cavern to 40–70 bar; on discharge the air is withdrawn, heated (in the diabatic plants built to date, by burning natural gas) and expanded through a turbine. Because the compression work has already been paid for, the expander produces around three times the output of a simple-cycle gas turbine for the same fuel. The two operating plants, Huntorf in Germany and McIntosh in Alabama, are of 290 and 110 MW; McIntosh delivers 110 MW for 26 hours, 2860 MWh, consuming about 0.69 kWh of compression electricity and 4330 kJ of natural gas per kWh sent out, so on a primary-energy basis its round trip is about 53 %. Adiabatic schemes that store the compression heat in a solid regenerator and reuse it on expansion would eliminate the fuel entirely, at the cost of a large high-temperature thermal store.

Electrochemical and thermal storage complete the picture. Lithium-ion battery installations now reach several hundred MW with one to four hours of duration, offer round-trip efficiencies near 90 %, respond in milliseconds and can be sited anywhere, which makes them ideal for frequency response, ramping and the evening peak, but their energy cost still rules them out for multi-day storage. Molten-salt thermal storage, integrated with concentrating solar plants, holds sensible heat in a hot tank at around 565 °C and lets a conventional steam cycle run for six to fifteen hours after sunset — storing heat rather than electricity, and so avoiding one conversion entirely. The general engineering point is that no single technology serves every duty: the selection is made on the required discharge duration and cycle frequency, with batteries for minutes to hours, compressed air and pumped hydro for hours to days, and only pumped hydro at present offering seasonal-scale energy at acceptable cost.