Uranium mining and nuclear cycle All pre-WW II uranium production (Jáchymov in Bohemia, Colorado, Cornwall, Congolese Katanga) was done underground, and a deep mine, Cameco’s McArthur River in northern Saskatchewan, is the world’s largest uranium-producing operation: it began producing in the year 2000 and by 2012 its cumulative extraction (by indirect methods, using freezing and raisebore mining in order to minimize exposure to radioactive surroundings) reached about 104,000 t and its annual output of about 7,500 t was 13% of the global total in 2012 (Cameco 2013). The mine occupies a compact main area of about 1,000 x 400 m, four smaller outlying areas and an airstrip facility, altogether about 100 ha, which means that only about 10 m2 have been required per tonne of output during 13 years of operation.
As 1 t of natural uranium can generate 42.2 GWh of electricity the mine’s 2000-2012 output produced 4.38 PWh of electricity (at the rate of roughly 38.5 GW), that is just 0.023 ha/TWh and a very high extraction power density of about 38,000 We/m2 of surface disturbance. The mine’s ore is milled at Key Lake, about 80 km southwest of McArthur River, at a former surface mine whose cumulative 1983-2002 production reached about 95,000 t of uranium between 1983 and 2002 and whose total disturbed area (pits, leaching ponds, tailings, roads) amounts to about 15 km2. By using the metal output for both sites (440,000 t in 30 years between 1983 and 2012) and their total disturbed area (some 16 km2) we can calculate a long-term (1983-2012) average of land claims that combines mining (surface and underground) and milling at the world’s two premiere uranium deposits: it has averaged less than 40 m2 (0.0036 ha)/t during the tree decades and its extraction/milling power density has been about 4,400 We/m2.
But this is an exceptionally high rate because northern Saskatchewan deposits have extraordinarily high concentration of uranium: at 16.36% U3O8 McArthur River ore grade is two orders of magnitude above the global average. Olympic Dam mine in southern Australia is the world’s second largest uranium producer from ore (U content of 0.12%) that also yields copper, silver and gold (WNA 2013). Its sprawling operations cover about 21 km2 and its cumulative 1988-2012 uranium output was about 65,000 t (WNA 2012): if the entire land claim is attributed to uranium mining the rate is about 0.03 ha/t, or (at roughly 12 GW) 600 We/m2. Ranger mine in Australia’s Northern Territories (the world’s third largest uranium enterprise) produced the metal by surface mining between 1981 and 2012; its operations yielded about 100,000 t and its pits, ponds, ore stores, tailings, buildings and road covered about 900 ha (with about 420 ha disturbed), and the overall operation claim prorated to about 0.009 ha/t, that is power density of roughly 1,700 We/m2.
Large open pit and associated mine structures of the Rössing deposit in Namibia (number six producer globally) cover nearly 25 km2 and the operation produced about 103,000 t U between 1976 and 2012 (WNA 2013a), requiring about 250 m2/t or less than 550 We/m2. But the share of surface mining has been declining as in situ leaching (ISL) has emerged as the most important method of uranium production. In 2012 that process supplied 45% of all uranium, followed by about 28% from underground seams and 20% from open pits, with the small remainder being a by-product of other extraction (WNA 2013b).
In large sheet-like deposits ISL is deployed as a gridded well field where injection wells (used to introduce an acid, or alkaline, leaching solution into an aquifer) alternate with extraction wells (from which submersible pumps lift the leachate to the surface) with spacing of 50-60 m; additional wells are drilled above and below the aquifers within the well field and around its perimeter to monitor the containment of leaching solutions (IAEA 2005). In narrower, channel-type, deposits well spacing is narrower, as close as 20-30 m. Recovery rates are 60-80% of the metal present in the deposit during 1-3 years of injection and withdrawal.
Kazakhstan, now the world’s leading producer of uranium, has the largest ISL operations, but there is an increasing number of smaller projects in Australia and the US. Data from these three countries –- annual and cumulative output, originally licensed extraction area, land actually affected by permanent structures and wellfields (WNA 2012; IAEA 2005, McKay and Miezitis 2001) –- show annual land requirements on the order of 0.1 ha/t U. Crow Butte in Nebraska has original license covering 1,320 ha but the land affected by mine’s structures and 11 wellfields has been only 440 ha and the project yielded about 3,800 t U between 2002 and 2012 (USNRC 2013); this translates to an average claim of about 0.11 ha/t in a decade and extraction power density of only about 380 We/m2. Australia’s Beverly mine contains deposit of about 16,300 t U of which 10,600 t are recoverable by ISL below an area of 800 ha (McKay and Miezitis 2001). With annual output close to 1,000 t U (recovery in 10-12 years) this implies extraction power density of 530-640 We/m2.
In contrast to underground and surface mining and ore milling, which leave behind voluminous tailings (usually behind tailing dams), processing of yellowcake, concentrated activities that claim minimal amount of space. Cameco’s Canadian conversion facility in Port Hope, Ontario is licensed to convert U3O8 into 12,500 t of UF6 and 2,800 t of UO2 (used to fuel Canada’s CANDU reactors) but it occupies only 9.6 ha on the northern shore of Lake Ontario (Cameco 2013a; Senes Consultants 2009). This means that even if it worked at half of its annual capacity the facility’s conversion power density would be on the order 105 We/m2. Fabrication of fuel rods to reactor specifications is a similarly highly concentrated process with negligible space requirements.
But additional space should be allocated due to relatively high electricity requirement of the enrichment process. This depends on the degree of enrichment, an effort measured in separative work units (SWU). Gaseous diffusion process, the original separation method, is highly energy intensive (about 2.3 MWh/SWU) while gas centrifuge plants, now the dominant way of enriching he fuel in the US, need only about 60 kWh/SWU (FAS 2013). The previously traced nuclear fuel chain material balance would require more than 116,000 SWU and the gaseous diffusion would need 267.7 GWh to enrich enough fuel to operate 1-GWe reactor at full capacity for a year. If the enriched fuel were supplied solely by gaseous diffusion then the total annual electricity consumption would be no less than 240 GWh, if only by centrifuge plants the requirement would be as low as 7 GWh.
If all the fuel were supplied by a combination of the two processes in one country, and if all the requisite electricity were to originate from a single source, it would be easy to calculate a weighted mean. But the US relies on foreign enrichment services to fuel its nuclear power plants: in 2012 owners and operators of America’s commercial nuclear power reactors purchased enrichment services totaling 16 million SWU (USEIA 2013b); electricity used to enrich it comes from different (and gradually changing) national mixtures of sources; and their power densities (as we have seen in preceding sections) range over several orders of magnitude, from large hydro to natural gas-fired generation.
Consequently, to do as Lovins (2011a) has done –- selecting gaseous separation as the only choice, estimating that about 10 TWh of electricity are needed to separate the isotopes during the 1-GW plant’s four decades of operation, and then assuming that all of that energy comes from coal-fired power plants whose annual land requirements add up to 580 ha/TWh –- is a questionable procedure. Its outcome would add about 150 ha/year to land claims of a 1-GWe nuclear station. In contrast, Fthenakis and Kim (2009) put enrichment’s land requirements at about 3 m2/GWh (assuming 70% centrifugal and 30% diffusion enrichment); for a 1-GWe plant with 90% capacity factor that would translate to roughly additional 2.6 ha/year, less than 2% of Lovins’s huge total. Even at double that rate (about 5 ha/year) this would a small addition that would have only a marginal effect on the aggregate count.
During the 1970s (the decade of the record expansion of the US nuclear capacities), Mielke (1977) put the claims of fissile fuel production follows (all prorated for one year of 1 GWe light water reactor operation) as follows: temporarily committed land for mining 22 ha, for milling 0.2 ha, for UF6 production 1 ha, for uranium enrichment 0.2 ha, and for fuel fabrication just 800 m2; corresponding totals for actually disturbed area were 6.8, 0.1, 0.08, 0.08 and mere 160 m2. Mielke considered only direct land claims of enrichment, but otherwise his numbers convey well the relative land demands of nuclear generation: differences for mining claims among underground, surface and ISL operations will be in most cases far more important in determining the overall requirements than will be the aggregates of all post-mining operations.
Finally, there is the matter of long-term storage of spent fuel. The fuel is removed from reactors to adjacent storage ponds where it can stay for months or years as its radioactivity decreases: this common practice creates no additional land claims beyond a plant’s confines. Cooling ponds, most of them at nuclear plant sites, now contain about 90% of the world’s 270,000 t of all used fuel, with the remainder in dry storage (WNA 2012). In the US about a quarter of all used fuel is in interim storage in sealed steel casks or modules at Independent Spent Fuel Storage Installations (USNRC 2012a). Relatively limited mass and volume of these wastes helps to explain why there has been no urgency to set-up permanent disposal site (NIMBY-syndrome resistance to their siting is, obviously, another matter).
While there is still no permanent national facility for long-term storage of highly radioactive waste, many years of planning for the Yucca Mountain project in Nevada (now essentially terminated) offer relevant insights into storage capacities and potential land claims of such depositories. The site’s intended capacity was 70,000 t of radioactive waste, the deposit’s footprint would have been 4.27 km2 but its controlled access area would have extended over 230 km2 (Cochrane 2009). Using the latter total the rate would have been about 3,300 m2/t and hence the waste from a 1-GWe reactor (nearly 29 t of spent fuel a year) would have an overall land claim of roughly 9.5 ha/year.
Two representative plants As in the case of coal-fired plants I will present two realistic but substantially divergent examples of aggregate power densities of nuclear electricity generation –- as well as an example of a more commonly encountered facility, all for a standard 1-GWe station with a high (90%) capacity factor. The first plant will be a compact operation (much like San Onofre) that will occupy just 50 ha and whose fuel will come from the world’s most productive Saskatchewan mines (land requirement a mere 40 m2/t U), and will be enriched only by centrifugal process (6 GWh/year) with electricity supplied by coal-fired generation operating with high power density of 1,000 We/m2 (that is 8.76 MWh/m2). Spent fuel will be eventually stored in a permanent depository whose land claim would amount to 10 ha/year. The plant’s land claim will be dominated by its site and it will operate with power density of about 1,600 We/m2.
Power density of a nuclear plant (high variant)
Power plant site 50 ha
Generation 1 GWe x 8,760 = 8.76 TWh
U requirement 217 t U/year
Mining and milling 217 t U x 0.004 ha/t U = 0.87 ha/year
Land for enrichment 6 GWh/8.76 MWh = ~ 680 m2/year
Spent fuel storage 10 ha/year
Total land requirement 50 + 0.87 + 0.07 + 10 = ~ 61 ha/year
Power density 1 GWe/610,000 m2 = ~ 1,600 We/m2
The second station will be a sprawling enterprise spread over 1,000 ha that receives uranium from a low-density ISL recovery (0.2 ha/t U) whose enrichment was split between gaseous diffusion (267 GWh) and the centrifugal process (6 GWh), requiring 137 GWh to produce the fuel for one year of the plant’s operation, with electricity generated by hydroenergy, and hence with a very low power density of 5 We/m2 (43.8 kWh/m2). This plant’s land claim will be also dominated by its site but fuel production will add another 30% and the plant will operate with power density of only about 70 We/m2.
Power density of a nuclear plant (low variant)
Power plant site 1,000 ha
Generation 1 GWe x 8,760 = 8.76 TWh
U requirement 217 t U/year
Mining and milling 217 t U x 0.2 ha/t U = ~ 43 ha/year
Land for enrichment 137 GWh/43.8 kWh = ~ 310 ha/year
Spent fuel storage 10 ha/year
Total land requirement 1,000 + 43 + 310 + 10 = ~ 1,360 ha
Power density 1 GWe/13.6 Mm2 = ~ 70 We/m2
The most representative of the three examples would be a station whose land claim would be in the middle of the US modal range (200-400 ha); it would receive uranium from several sources, including overseas imports; uranium extraction (including a significant share from ISL) and ore milling land claim would average 0.1 ha/t; and the weighted fuel enrichment cost (80% centrifugal, 20% gaseous process) would be about 58 GWh, with electricity coming from a mixture of source with average power density of about 500 We/m2 (4.38 MWh/m2). This plant’s land claim would be also dominated by its site, but fuel production and disposal would add roughly 50% to the plant’s area and the station would generate electricity with the overall power density of about 220 We/m2.
Power density of a nuclear plant (medium variant)
Power plant site 300 ha
Generation 1 GWe x 8,760 = 8.76 TWh
U requirement 217 t U/year
Mining and milling 217 t U x 0.1 ha/t U = ~ 22 ha/year
Land for enrichment 58 GWh/4.38 MWh = ~ 1.3 ha/year
Spent fuel storage 10 ha/year
Total land requirement 300 + 22 + 1.3 + 10 = ~ 333 ha/year
Power density 1 GWe/3.3 Mm2 = ~ 300 We/m2
These three realistic examples thus span annual claims of roughly 60-1,360 ha and power densities of 70-1,600 We/m2, attesting again to the fact that power densities of thermal electricity-generating stations –- while highly constrained and hence fairly uniform as far their core structures (boilers, reactors, turbogenerators) and indispensable infrastructures (transformers, connections to the grid, road and rail connections) are concerned -– can differ by two orders of magnitude, and do so mainly because of differences in fenced-in areas (including land that remains undisturbed), in cooling arrangements, and in the origins of fuel supply.
In closing, it might be interesting to note the single values offered by several studies as the averages for land requirements of nuclear electricity generation. Gagnon, Bélanger and Uchiyama (2002) estimated direct land requirements of nuclear generation at 0.5 km2/TWh, that is about 440 ha for a 1-GWe plant and power density of about 230 W/m2. Fthenakis and Kim (2009) concluded that US nuclear generation claims 119 m2/GWh; that implies a total claim of about 104 ha for 1 GWe and power density of roughly 960 We/m2. The largest component (42% of the total) of their account was the plant itself but it is obvious that with 42 ha (an area smaller than that controlled by the most compact US nuclear station) they counted only the footprint of its structures, not the total fenced-in area of the facility.
Their relatively high mining estimate is due to the assumed split of extraction methods (50% open pit, 50% underground, no ISL), and their indirect claim for fuel enrichment reflects the 70/30 split between centrifugal separation and diffusion. Lovins (2011a) arrived at an almost identical rate of roughly 120 m2/GWh. McDonald et al. (2009) offered a fairly narrow range, 3.02 km2/GW for the most compact and 4.78 km2/GW for the least compact nuclear plant, implying power densities of 210-330 We/m2. These claims, 302-478 ha for 1 GWe station, are based on a study by Spitzley and Keoleian (2004) whose assumptions were also cited by Lovins (2011a). Jacobson’s (2008) calculations for an 847-MW reactor (and including all land for uranium production and safety zone) ended up with 150 We/m2.
I could have quantified typical land requirements of modern electricity transmission already in the third chapter that is largely devoted to all commercially important forms of generation harnessing renewable energy flows. But the placement at the end of this chapter is more apposite. After all, for more than 130 years (Edison’s first power plant began operating in 1882) most of the world’s electricity has always began with the combustion of fuels, and since the late 1950s a rising share of thermal electricity has been supplied by nuclear fission –- and technical, infrastructural and economic imperatives make it certain that this primacy will continue for decades to come.
Much like fossil-fueled electricity generation –- where the fundamental components (boilers, turbogenerators) date to the 1880s but where gradual advances have multiplied their ratings and their efficiencies) –- electricity transmission retains its more than a century old innovative basics but its performance has been much improved as better transformers, higher voltages, taller towers, better wires and longer unsupported spans have kept up place with the rising demand for larger transfers across longer distances (Smil 2006). Early choices are also reflected in differences in consumer voltages (100 V in Japan, 120 V in North America and Japan, 230 V in Europe) and sockets but none of this affects land claims of high-voltage (HV) transmission.
Distribution lines bringing electricity to consumers have voltages less than 35 kV and in modern urban developments they are put underground. HV transmission of alternating current (AC) starts at 110 kV and the designation steps up to extra high voltage (EHV) above 230 kV, with 345 kV, 500 kV and 765 being the two most common ratings for HVAC. Higher voltages are used for direct current (DC) transmission, a more efficient alternative to connect load centers (cities, industries) with distant sources of power, usually with hydroelectric plants. Transmission losses are reduced by using higher voltages but capacities of HV lines are limited by their heating and by voltage drop.
Width of transmission rights-of-way increases with voltage but EHV lines make lower specific claims. In the US the National Electric Safety Code specifies minimal clearances of 36-46 m for 230 kV lines, 46 m for 345 kV links and 61 m for 765 kV (all AC) transmission (IEEE 2012). This means that one km of HV transmission claims 3.6-6.1 ha of ROW and power densities of annual electricity throughput in the US in 2012 (440 GW) would have been –- with 305,000 km of lines 230 kV and higher (USEIA 2014b) and assuming average ROW of 5 ha/km –-just short of 30 W/m2. Because the line conductors (made of aluminum alloys) are not insulated and can fall on the ground as a result of violent weather, icing or tower failure the ROW strip should have no permanently inhabited structures and no tall vegetation (the limit is usually 1.8 m, high enough to grow Xmas trees under HV lines).
Lines running through forests on flat or gently undulating land need adequate clearing (and its maintenance) but many HV lines that cross mountain valleys very high above the ground (often with spans of many hundreds of meters, even more than 1 km) do not require cleared strips underneath the lines. And when lines cross mountain terrain with low vegetation, natural shrub lands and grasslands and land planted to perennial or seasonal field crops there is also no need for ground clearances, existing land uses can continue and land claims are limited to small areas needed to anchor transmission towers, and can be further reduced with new monopole tower designs.
Consequently, land claims of HV transmission resemble those of wind turbines as tower foundations occupy only tiny shares (less than 1%) of the total ROW claim, and they are obviously in a different category than those of fuel extraction of electricity generation. Moreover, while land claimed by coal extraction for a mine-mouth power plant and space occupied by power plant buildings and infrastructures are clearly attributable to a specific rate of annual electricity generation, the only transmission land claims that can be attributed to a specific station are those of transmission lines that were built to connect it to the existing grid (usually short links for new thermal stations in countries with high rates of electricity generation) or dedicated HVDC links from large hydro stations to distant cities.
Advantages of DC transmission include not only reduced losses but also narrower rights of way. To transmit the same power single-circuit 500 kV AC line would take 105 m, double-circuit 500 kV AC would claim 65-76 and 500 kV DC lines would need just 55-60 m (ATCO Electric 2010). Manitoba Hydro’s HVDC link bringing electricity from the Nelson River power plants to converter stations near Winnipeg is an excellent example of this dedicated use (Manitoba Hydro 2013a). The link was a pioneering HVDC project (first phase completed in 1973) that consists of two bipole lines (900 kV, ± 450 kV 895 km, and 1,000 k V, ± 500 kV 937 km) whose capacity is about 4 GW. Two lines of 4,103 towers (averaging 38 m, spaced 427-488 m apart) claim ROW of 137 m and hence the total of about 12,300 ha of which 10,800 ha are cleared forest. This translates to power density of just over 30 W/m2.
Power densities for some other major HVDC lines (assuming 60 m ROW for 500 kV link) would be close to 50 W/m2 for each of the three lines from the Three Gorges Dam to Shanghai, Changzhou and Guangdong, each 3 GW capacity and length of, respectively, 1,060, 890 and 940 km (Kumar, Ma and Gou 2006). Higher power densities will be achieved with planned 800 kV lines. In contrast, formerly the world’s longest HVDC line from the Inga Dam on the Congo to Kolwezi in Katanga that is 1,700 km long but whose original design capacity was only 560 MW but with a wide clearance of about 100 m has maximum transmission power density of just 3 W/m2 (Clerici 2007).
The only logical way to calculate power densities of transmission is to quantify them on a national scale, that is by dividing nationwide electricity generation by aggregate of rights of way. But even that is not a satisfactory solution for many smaller and strongly interconnected countries that are engaged in vigorous electricity trade and whose lines are used continuously for imports and exports. For example, in 2011 Switzerland (whose hydro stations now act as storages for surplus German wind and solar generation) imported 83 TWh to the EU and exported 81 TWh while its domestic consumption was only 59 TWh (Pauli 2013). In any case, I will present approximate calculations of land claims and power densities of transmission for the US, and on the global scale, in the closing chapter.