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COMPLAINTS HANDLING PROCEDURE

Kenya Nuclear Electricity Board is dedicated to ensuring utmost professionalism when it comes to service delivery.

What is a complaint

A complaint is an expression of dissatisfaction made against the Board or about the service delivery of the members of staff of the Board or about any policy of the Board.

 KNEB will invesitgate any complaints in confidence and act on them accordingly.

The standard procedure for handling complaints is as follows:

  1. The Complaints Handling Officer designated by the committee shall receive complaints on a monthly basis
  2. The designated Complaints Handling Officer shall pass the information in writing on the number and natures of complaints in writing to the chairperson of the committee within the first three working days of the month
  3. The chairperson shall make arrangements for the Complaints Handling & Management committee to meet within three working days from the date s/he was informed of the complaints.
  4. The Complaints Handling Officer shall investigate all the complaints and decide on their eligibility
  5. If the complaints are not eligible, the committee shall dismiss them through the Complaints Handling Officer who will transmit the information to the complainant in writing within seven days. The process shall end there. If the complaints are eligible, the process shall continue from iv.
  6. The committee shall after the investigations, discuss and recommend the corrective actions to the appropriate Head Of Department in writing, for implementations of the actions within a stipulated period of time.
  7. The Head Of Department shall report in writing on the corrective actions undertaken
  8. The Complaints Handling Officer shall investigate the corrective actions taken. If satisfied with the actions, the Complaints Handling & Management committee shall communicate in writing to the user, through the CHO.
  9. If the Complaints Handling Officer is not satisfied with the corrective actions taken, the Complaints Handling & Management committee shall communicate back in writing to the Head Of Department for necessary actions to be implemented. If the Head Of Department refuses to cooperate the Complaints Handling & Management committee shall communicate in writing to the Commission on Administration of Justice for further action

 Click to download the standard procedure for handling complaints for more details

 

 

 

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Welcome to KNEB E-learning on Nuclear Power

KNEB Nuclear E-learning is an open elearning platform that is designed to provide stakeholders with knowledge and understanding on various aspects of Nuclear power. The stakeholders include

Decision makers, advisers and senior managers in governmental organizations, regulatory bodies, utilities and industries, as well as donors, suppliers and other related bodies;

Students, academics and researchers in the nuclear field and;

Those involved in expanding existing nuclear power programmes.

Click to visit KNEB Nuclear Elearning

  • Natural sources account for most of the radiation we all receive each year.
  • The nuclear fuel cycle does not give rise to significant radiation exposure for members of the public, and even in two major nuclear accidents – Three Mile Island and Fukushima – exposure to radiation has caused no harm to the public.
  • Radiation protection standards assume that any dose of radiation, no matter how small, involves a possible risk to human health. This deliberately conservative assumption is increasingly being questioned. 
  • Fear of radiation causes much harm. Expressed particularly in government edicts following the Fukushima accident (and also Chernobyl), it has caused much suffering and many deaths.

Radiation is energy in the process of being transmitted. It may take such forms as light, or tiny particles much too small to see. Visible light, the ultra-violet light we receive from the sun, and transmission signals for TV and radio communications are all forms of radiation that are common in our daily lives. These are all generally referred to as 'non-ionizing' radiation, though at least some ultra-violet radiation is considered to be ionizing.

Radiation particularly associated with nuclear medicine and the use of nuclear energy, along with X-rays, is 'ionizing' radiation, which means that the radiation has sufficient energy to interact with matter, especially the human body, and produce ions, i.e. it can eject an electron from an atom.

X-rays from a high-voltage discharge were discovered in 1895, and radioactivity from the decay of particular isotopes was discovered in 1896. Many scientists then undertook study of these, and especially their medical applications. This led to the identification of different kinds of radiation from the decay of atomic nuclei, and understanding of the nature of the atom. Neutrons were identified in 1932, and in 1939 atomic fission was discovered by irradiating uranium with neutrons. This led on to harnessing the energy released by fission.

A 2016 United Nations Environment Programme (UNEP) publication notes: “Today, we know more about the sources and effects of exposure to [ionizing] radiation than to almost any other hazardous agent, and the scientific community is constantly updating and analysing its knowledge... The sources of radiation causing the greatest exposure of the general public are not necessarily those that attract the most attention. In fact, the greatest exposure is caused by natural sources ever present in the environment, and the major contributor to exposure from artificial sources is the use of radiation in medicine worldwide.”

Types of radiation

Nuclear radiation arises from hundreds of different kinds of unstable atoms. While many exist in nature, the majority are created in nuclear reactionsa. Ionizing radiation which can damage living tissue is emitted as the unstable atoms (radionuclides) change ('decay') spontaneously to become different kinds of atoms.

The principal kinds of ionizing radiation are:

Alpha particles

These are helium nuclei consisting of two protons and two neutrons and are emitted from naturally-occurring heavy elements such as uranium and radium, as well as from some man-made transuranic elements. They are intensely ionizing but cannot penetrate the skin, so are dangerous only if emitted inside the body.

Beta particles

These are fast-moving electrons emitted by many radioactive elements. They are more penetrating than alpha particles, but easily shielded – the most energetic of them can be stopped by a few millimetres of wood or aluminium. They can penetrate a little way into human flesh but are generally less dangerous to people than gamma radiation. Exposure produces an effect like sunburn, but which is slower to heal. The weakest of them, such as from tritium, are stopped by skin or cellophane. Beta-radioactive substances are also safe if kept in appropriate sealed containers.

Gamma rays

These are high-energy electromagnetic waves much the same as X-rays. They are emitted in many radioactive decays and may be very penetrating, so require more substantial shielding. Gamma rays are the main hazard to people dealing with sealed radioactive materials used, for example, in industrial gauges and radiotherapy machines. Radiation dose badges are worn by workers in exposed situations to detect them and hence monitor exposure. All of us receive about 0.5-1 mSv per year of gamma radiation from rocks, and in some places, much more. Gamma activity in a substance (e.g. rock) can be measured with a scintillometer or Geiger counter.

X-rays are also electromagnetic waves and ionizing, virtually identical to gamma rays, but not nuclear in origin. They are produced in a vacuum tube where an electron beam from a cathode is fired at target material comprising an anode, so are produced on demand rather than by inexorable physical processes. (However the effect of this radiation does not depend on its origin but on its energy.)

Cosmic radiation consists of very energetic particles, mostly high-energy protons, which bombard the Earth from outer space. They comprise about one-tenth of natural background exposure at sea level, and more at high altitudes.

Neutrons are uncharged particles mostly released by nuclear fission (the splitting of atoms in a nuclear reactor), and hence are seldom encountered outside the core of a nuclear reactor.* Thus they are not normally a problem outside nuclear plants. Fast neutrons can be very destructive to human tissue. Neutrons are the only type of radiation which can make other, non-radioactive materials, become radioactive.

* Large nuclei can fission spontaneously, since the so-called strong nuclear force holding each nucleus together is not overwhelmingly stronger than the repulsive force of charged protons.

Units of radiation and radioactivity

In order to quantify how much radiation we are exposed to in our daily lives and to assess potential health impacts as a result, it is necessary to establish a unit of measurement. The basic unit of radiation dose absorbed in tissue is the gray (Gy), where one gray represents the deposition of one joule of energy per kilogram of tissue.

However, since neutrons and alpha particles cause more damage per gray than gamma or beta radiation, another unit, the sievert (Sv) is used in setting radiological protection standards. This weighted unit of measurement takes into account biological effects of different types of radiation and indicates the equivelent dose. One gray of beta or gamma radiation has one sievert of biological effect, one gray of alpha particles has 20 Sv effect and one gray of neutrons is equivalent to around 10 Sv (depending on their energy). Since the sievert is a relatively large value, dose to humans is normally measured in millisieverts (mSv), one-thousandth of a sievert.

Note that Sv and Gy measurements are accumulated over time, whereas damage (or effect) depends on the actualdose ratee.g. mSv per day or year, Gy per day in radiotherapy.

The becquerel (Bq) is a unit or measure of actual radioactivity in material (as distinct from the radiation it emits, or the human dose from that), with reference to the number of nuclear disintegrations per second (1 Bq = 1 disintegration/sec). Quantities of radioactive material are commonly estimated by measuring the amount of intrinsic radioactivity in becquerels – one Bq of radioactive material is that amount which has an average of one disintegration per second, i.e. an activity of 1 Bq. This may be spread through a very large mass.

Radioactivity of some natural and other materials

1 adult human (65 Bq/kg) 4500 Bq
1 kg of coffee 1000 Bq
1 kg of brazil nuts 400 Bq
1 banana 15 Bq
The air in a 100 sq metre Australian home (radon) 3000 Bq
The air in many 100 sq metre European homes (radon) Up to 30 000 Bq
1 household smoke detector (with americium) 30 000 Bq
Radioisotope for medical diagnosis 70 million Bq
Radioisotope source for medical therapy 100 000 000 million Bq (100 TBq)
1 kg 50-year old vitrified high-level nuclear waste 10 000 000 million Bq (10 TBq)
1 luminous Exit sign (1970s) 1 000 000 million Bq (1 TBq)
1 kg uranium 25 million Bq
1 kg uranium ore (Canadian, 15%) 25 million Bq
1 kg uranium ore (Australian, 0.3%) 500 000 Bq
1 kg low level radioactive waste 1 million Bq
1 kg of coal ash 2000 Bq
1 kg of granite 1000 Bq
1 kg of superphosphate fertilizer 5000 Bq

N.B. Though the intrinsic radioactivity is the same, the radiation dose received by someone handling a kilogram of high-grade uranium ore will be much greater than for the same exposure to a kilogram of separated uranium, since the ore contains a number of short-lived decay products (see section on Radioactive Decay), while the uranium has a very long half-life.

Older units of radiation measurement continue in use in some literature:
1 gray = 100 rads
1 sievert = 100 rem
1 becquerel = 27 picocuries or 2.7 x 10-11 curies
One curie was originally the activity of one gram of radium-226, and represents 3.7 x 1010 disintegrations per second (Bq).

The Working Level Month (WLM) has been used as a measure of dose for exposure to radon and in particular, radon decay productsb.

Since there is radioactivity in many foodstuffs, there has been a whimsical suggestion that the Banana Equivalent Dose from eating one banana be adopted for popular reference. This is about 0.0001 mSv.

Routine sources of radiation

Radiation can arise from human activities or from natural sources. Most radiation exposure is from natural sources. These include: radioactivity in rocks and soil of the Earth's crust; radon, a radioactive gas given out by many volcanic rocks and uranium ore; and cosmic radiation. The human environment has always been radioactive and accounts for up to 85% of the annual human radiation dose.

Helpful depictions of routine sources of radiation can be found on the information is beautiful and xkcd websites.

Radiation arising from human activities typically accounts for up to 20% of the public's exposure every year as global average. In the USA by 2006 it averaged about half of the total. This radiation is no different from natural radiation except that it can be controlled. X-rays and other medical procedures account for most exposure from this quarter. Less than 1% of exposure is due to the fallout from past testing of nuclear weapons or the generation of electricity in nuclear, as well as coal and geothermal, power plants.

Backscatter X-ray scanners being introduced for airport security will gives exposure of up to 5 microsieverts (μSv), compared with 5 μSv on a short flight and 30 μSv on a long intercontinental flight across the equator, or more at higher latitudes – by a factor of 2 or 3. Aircrew can receive up to about 5 mSv/yr from their hours in the air, while frequent flyers can score a similar incrementc. On average, nuclear power workers receive a lower annual radiation dose than flight crew, and frequent flyers in 250 hours would receive 1 mSv.

The maximum annual dose allowed for radiation workers is 20 mSv/yr, though in practice, doses are usually kept well below this level. In comparison, the average dose received by the public from nuclear power is 0.0002 mSv/yr, which is of the order of 10,000 times smaller than the total yearly dose received by the public from background radiation.
 

Sources of Radiation pie graph


Natural background radiation, radon

Naturally occurring background radiation is the main source of exposure for most people, and provides some perspective on radiation exposure from nuclear energy. Much of it comes from primordial radionuclides in the Earth’s crust, and materials from it. Potasssium-40, uranium-238 and thorium-232 with their decay products are the main source.

The average dose received by all of us from background radiation is around 2.4 mSv/yr, which can vary depending on the geology and altitude where people live – ranging between 1 and 10 mSv/yr, but can be more than 50 mSv/yr. The highest known level of background radiation affecting a substantial population is in Kerala and Madras states in India where some 140,000 people receive doses which average over 15 millisievert per year from gamma radiation, in addition to a similar dose from radon. Comparable levels occur in Brazil and Sudan, with average exposures up to about 40 mSv/yr to many people. (The highest level of natural background radiation recorded is on a Brazilian beach: 800 mSv/yr, but people don’t live there.)

Several places are known in Iran, India and Europe where natural background radiation gives an annual dose of more than 100 mSv to people and up to 260 mSv (at Ramsar in Iran, where some 200,000 people are exposed to more than 10 mSv/yr). Lifetime doses from natural radiation range up to several thousand millisievert. However, there is no evidence of increased cancers or other health problems arising from these high natural levels. The millions of nuclear workers that have been monitored closely for 50 years have no higher cancer mortality than the general population but have had up to ten times the average dose. People living in Colorado and Wyoming have twice the annual dose as those in Los Angeles, but have lower cancer rates. Misasa hot springs in western Honshu, a Japan Heritage site, attracts people due to having high levels of radium (up to 550 Bq/L), with health effects long claimed, and in a 1992 study the local residents’ cancer death rate was half the Japan average.* (Japan J.Cancer Res. 83,1-5, Jan 1992) A study on 3000 residents living in an area with 60 Bq/m3 radon (about ten times normal average) showed no health difference. Hot springs in China have levels reaching 3270 Bq/L radon-222 (Liaoning sanatorium), 2720 Bq/L (Tanghe hot spring) and 230 Bq/L (Puxzhe hot spring), though associated exposure from airborne radon are low**.

* The waters are promoted as boosting the body’s immunity and natural healing power, while helping to relieve bronchitis and diabetes symptoms, as well as beautifying the skin. Drinking the water is also said to have antioxidant effects. (These claims are not known to be endorsed by any public health authority.)
** 
Chinese figures from Liu & Pan in NORM VII.

Radon is a naturally occurring radioactive gas resulting from the decay of uranium-238, which concentrates in enclosed spaces such as buildings and underground mines, particularly in early uranium mines where it sometimes became a significant hazard before the problem was understood and controlled by increased ventilation. Radon has decay products that are short-lived alpha emitters and deposit on surfaces in the respiratory tract during the passage of breathing air. At high radon levels, this can cause an increased risk of lung cancer, particularly for smokers. (Smoking itself has a very much greater lung cancer effect than radon.) People everywhere are typically exposed to around 0.2 mSv/yr, and often up to 3 mSv/yr, due to radon (mainly from inhalation in their homes) without apparent ill-effectd. Where deemed necessary, radon levels in buildings and mines can be controlled by ventilation, and measures can be taken in new constructions to prevent radon from entering buildings.

However, radon levels of up to 3700 Bq/m3 in some dwellings at Ramsar in Iran have no evident ill-effect. Here, a study (Mortazavi et al, 2005) showed that the highest lung cancer mortality rate was where radon levels were normal, and the lowest rate was where radon concentrations in dwellings were highest. The ICRP recommends keeping workplace radon levels below 300 Bq/m3, equivalent to about 10 mSv/yr. Above this, workers should be considered as occupationally exposed, and subject to the same monitoring as nuclear industry workers. The normal indoor radon concentration ranges from 10 to 100 Bq/m3, but may naturally reach 10,000 Bq/m3, according to UNEP.

Public exposure to natural radiatione

Source of exposure Annual effective dose (mSv)
Average Typical range
Cosmic radiation Directly ionizing and photon component 0.28  
Neutron component 0.10  
Cosmogenic radionuclides 0.01  
Total cosmic and cosmogenic 0.39 0.3–1.0e
External terrestrial radiation Outdoors 0.07  
Indoors 0.41  
Total external terrestrial radiation 0.48 0.3-1.0e
Inhalation Uranium and thorium series 0.006  
Radon (Rn-222) 1.15  
Thoron (Rn-220) 0.1  
Total inhalation exposure 1.26 0.2-10e
Ingestion K-40 0.17  
Uranium and thorium series 0.12  
Total ingestion exposure 0.29 0.2-1.0e
Total 2.4 1.0-13

Crews of nuclear submarines have possibly the lowest radiation exposure of anyone, despite living within a few metres of a nuclear reactor, since they are exposed to less natural background radiation than the rest of us, and the reactor compartment is well shielded.1 US Naval Reactors’ average annual occupational exposure was 0.06 mSv per person in 2013, and no personnel have exceeded 20 mSv in any year in the 34 years to then. The average occupational exposure of each person monitored at Naval Reactors' facilities since 1958 is 1.03 mSv per year.

Effects of ionizing radiation

Some of the ultraviolet (UV) radiation from the sun is considered ionizing radiation, and provides a starting point in considering its effects. Sunlight UV is important in producing vitamin D in humans, but too much exposure produces sunburn and, potentially, skin cancer. Skin tissue is damaged, and that damage to DNA may not be repaired properly, so that over time, cancer develops and may be fatal. Adaptation from repeated low exposure can decrease vulnerability. But exposure to sunlight is quite properly sought after in moderation, and not widely feared.

Our knowledge of the effects of shorter-wavelength ionizing radiation from atomic nuclei derives primarily from groups of people who have received high doses. The main difference from UV radiation is that beta, gamma and X-rays can penetrate the skin. The risk associated with large doses of this ionizing radiation is relatively well established. However, the effects, and any risks associated with doses under about 200 mSv, are less obvious because of the large underlying incidence of cancer caused by other factors. Benefits of lower doses have long been recognised, though radiation protection standards assume that any dose of radiation, no matter how small, involves a possible risk to human health. However, available scientific evidence does not indicate any cancer risk or immediate effects at doses below 100 mSv per year. At low levels of exposure, the body's natural mechanisms usually repair radiation damage to DNA in cells soon after it occurs (see following section on low-level radiation). However, high-level irradiation overwhelms those repair mechanisms and is harmful. Dose rate is as important as overall dose.

The UN Scientific Commission on the Effects of Atomic Radiation (UNSCEAR) currently uses the term low dose to mean absorbed levels below 100 mGy but greater than 10 mGy, and the term very low dose for any levels below 10 mGy. High absorbed dose is defined as more than about 1000 mGy. For beta and gamma radiation, these figures can be taken as mSv equivalent dose.

Some comparative whole-body radiation doses and their effects
2.4 mSv/yr Typical background radiation experienced by everyone (average 1.5 mSv in Australia, 3 mSv in North America).
1.5 to 2.5 mSv/yr Average dose to Australian uranium miners and US nuclear industry workers, above background and medical.
Up to 5 mSv/yr Typical incremental dose for aircrew in middle latitudes.
9 mSv/yr Exposure by airline crew flying the New York – Tokyo polar route.
10 mSv/yr Maximum actual dose to Australian uranium miners.
10 mSv Effective dose from abdomen & pelvis CT scan.
20 mSv/yr Current limit (averaged) for nuclear industry employees and uranium miners. (In Japan: 5 mSv per three months for women)
50 mSv/yr Former routine limit for nuclear industry employees, now maximum allowable for a single year (average to be 20 mSv/yr max). It is also the dose rate which arises from natural background levels in several places in Iran, India and Europe.
50 mSv Allowable short-term dose for emergency workers (IAEA).
100 mSv Lowest annual level at which increase in cancer risk is evident (UNSCEAR). Above this, the probability of cancer occurrence (rather than the severity) is assumed to increase with dose. No harm has been demonstrated below this dose.
Allowable short-term dose for emergency workers taking vital remedial actions (IAEA).
Dose from four months on international space station orbiting 350 km up.
130 mSv/yr Long-term safe level for public after radiological incident, measured 1 m above contaminated ground, calculated from published hourly rate x 0.6. Risk too low to justify any action below this (IAEA).
170 mSv/wk 7-day provisionally safe level for public after radiological incident, measured 1 m above contaminated ground (IAEA).
250 mSv Allowable short-term dose for workers controlling the 2011 Fukushima accident, set as emergency limit elsewhere.
250 mSv/yr Natural background level at Ramsar in Iran, with no identified health effects (Some exposures reach 700 mSv/yr). Maximum allowable annual dose in emergency situations in Japan (NRA).
350 mSv/lifetime Criterion for relocating people after Chernobyl accident.
500 mSv Allowable short-term dose for emergency workers taking life-saving actions (IAEA).
680 mSv/yr Tolerance dose level allowable to 1955 (assuming gamma, X-ray and beta radiation).
700 mSv/yr Suggested threshold for maintaining evacuation after nuclear accident.
(IAEA has 880 mSv/yr over one month as provisionally safe.
800 mSv/yr Highest level of natural background radiation recorded, on a Brazilian beach.
1,000 mSv short-term Assumed to be likely to cause a fatal cancer many years later in about 5 of every 100 persons exposed to it (i.e. if the normal incidence of fatal cancer were 25%, this dose would increase it to 30%).
Highest reference level recommended by ICRP for rescue workers in emergency situation.
1,000 mSv short-term Threshold for causing (temporary) radiation sickness (Acute Radiation Syndrome) such as nausea and decreased white blood cell count, but not death. Above this, severity of illness increases with dose.
5,000 mSv short-term Would kill about half those receiving it as whole body dose within a month. (However, this is only twice a typical daily therapeutic dose applied to a very small area of the body over 4 to 6 weeks or so to kill malignant cells in cancer treatment.)
10,000 mSv short-term Fatal within a few weeks.

The main expert body on radiation effects is the UN Scientific Commission on the Effects of Atomic Radiation (UNSCEAR), set up in 1955 and reporting to the UN General Assembly. It involves scientists from over 20 countries and publishes its findings in major reports. The UNSCEAR 2006 report dealt broadly with the Effects of Ionizing Radiation. Another valuable report, titled Low-level Radiation and its Implications for Fukushima Recovery, was published in June 2012 by the American Nuclear Society.

In 2012 UNSCEAR reported to the UN General Assembly on radiation effects. It had been asked in 2007 "to clarify further the assessment of potential harm owing to chronic low-level exposures among large populations and also the attributability of health effects" to radiation exposure. It said that while some effects from high acute doses were clear, others including hereditary effects in human populations were not, and could not be attributed to exposure, and that this was especially true at low levels. "In general, increases in the incidence of health effects in populations cannot be attributed reliably to chronic exposure to radiation at levels that are typical of the global average background levels of radiation." Furthermore, multiplying very low doses by large numbers of individuals does not give a meaningful result regarding health effects. UNSCEAR also addressed uncertainties in risk estimation relating to cancer, particularly the extrapolations from high-dose to low-dose exposures and from acute to chronic and fractionated exposures. Earlier (1958) UNSCEAR data for leukaemia incidence among Hiroshima survivors suggested a threshold of about 400 mSv for harmful effects.

Average Annual Radiation Doses

Epidemiological studies continue on the survivors of the atomic bombing of Hiroshima and Nagasaki, involving some 76,000 people exposed at levels ranging up to more than 5,000 mSv. These have shown that radiation is the likely cause of several hundred deaths from cancer, in addition to the normal incidence found in any populationg. From this data the International Commission on Radiological Protection (ICRP) and others estimate the fatal cancer risk as 5% per sievert exposure for a population of all ages – so one person in 100 exposed to 200 mSv could be expected to develop a fatal cancer some years later. In Western countries, about a quarter of people die from cancers, with smoking, dietary factors, genetic factors and strong sunlight being among the main causes. About 40% of people are expected to develop cancer during their lifetime even in the absence of radiation exposure beyond normal background levels. Radiation is a weak carcinogen, but undue exposure can certainly increase health risks.

In 1990, the US National Cancer Institute (NCI) found no evidence of any increase in cancer mortality among people living near to 62 major nuclear facilities. The NCI study was the broadest of its kind ever conducted and supported similar studies conducted elsewhere in the USA as well as in Canada and Europe.h

About 60 years ago it was discovered that ionizing radiation could induce genetic mutations in fruit flies. Intensive study since then has shown that radiation can similarly induce mutations in plants and test animals. However there is no evidence of inherited genetic damage to humans from radiation, even as a result of the large doses received by atomic bomb survivors in Japan.

In a plant or animal cell the material (DNA) which carries genetic information necessary to cell development, maintenance and division is the critical target for radiation. Much of the damage to DNA is repairable, but in a small proportion of cells the DNA is permanently altered. This may result in death of the cell or development of a cancer, or in the case of cells forming gonad tissue, alterations which continue as genetic changes in subsequent generations. Most such mutational changes are deleterious; very few can be expected to result in improvements.

The relatively low levels of radiation allowed for members of the public and for workers in the nuclear industry are such that any increase in genetic effects due to nuclear power will be imperceptible and almost certainly non-existent. Radiation exposure levels are set so as to prevent tissue damage and minimize the risk of cancer. Experimental evidence indicates that cancers are more likely than inherited genetic damage.

Some 75,000 children born of parents who survived high radiation doses at Hiroshima and Nagasaki in 1945 have been the subject of intensive examination. This study confirms that no increase in genetic abnormalities in human populations is likely as a result of even quite high doses of radiation. Similarly, no genetic effects are evident as a result of the Chernobyl accident.

Life on Earth commenced and developed when the environment was certainly subject to several times as much radioactivity as it is now, so radiation is not a new phenomenon. If there is no dramatic increase in people's general radiation exposure, there is no evidence that health or genetic effects from radiation could ever become significant.

Low-level radiation effects

Linear Hypothesis

A lot of research has been undertaken on the effects of low-level radiation. The findings have failed to support the so-called linear no-threshold (LNT) hypothesis. This theory assumes that the demonstrated relationships between radiation dose and adverse effects at high levels of exposure also applies to low levels and provides the (deliberately conservative) basis of occupational health and other radiation protection standards.

Increasing evidence suggests that there may be a threshold between 100 and 700 mSv below which no harmful effects of radiation occur without effective cellular repair. However, this is not yet accepted by national or international radiation protection bodies as sufficiently well-proven to be taken into official standards. Nevertheless, at low levels of exposure, the body's natural mechanisms do repair radiation and other damage to cells soon after it occurs, and some adaptive response is stimulated which protects cells and tissues, as with exposure to other external agents at low levels. The ICRP recommends that the LNT model should be assumed for the purpose of optimising radiation protection practices, but that it should not be used for estimating the health effects of exposures to small radiation doses received by large numbers of people over long periods of time.

A November 2009 technical report from the Electric Power Research Institute in USA drew upon more than 200 peer-reviewed publications on effects of low-level radiation and concluded that the effects of low dose-rate radiation are different and that "the risks due to [those effects] may be over-estimated" by the linear hypothesis3. "From an epidemiological perspective, individual radiation doses of less than 100 mSv in a single exposure are too small to allow detection of any statistically significant excess cancers in the presence of naturally occurring cancers. The doses received by nuclear power plant workers fall into this category because exposure is accumulated over many years, with an average annual dose about 100 times less than 100 mSv". It quoted the US Nuclear Regulatory Commission that "since 1983, the US nuclear industry has monitored more than 100,000 radiation workers each year, and no workers have been exposed to more than 50 mSv in a year since 1989." A 2012 Massachusetts Institute of Technology study4 exposing mice to low-dose rate radiation for an extended period showed no signs of DNA damage, though a control group receiving the same dose acutely did show damage. This test on live animals confirms other work and epidemiological studies suggesting that people exposed to as much as 1000 mSv/yr at low dose rate will not suffer adverse health effects.

In addition, there is evidence of beneficial effect from low-level radiation (up to about 10 mSv/yr). This 'radiation hormesis' may be due to an adaptive response by the body's cells, the same as that with other toxins at low doses. In the case of carcinogens such as ionizing radiation, the beneficial effect is seen both in lower incidence of cancer and in resistance to the effects of higher doses. This potential hormetic effect is most clearly evident in the data (see Appendix) for over 50,000 survivors of the Hiroshima bomb 1.5 to 3 km from the hypocenter, with dose range 1 to 100 mSv, compared with a large control group.

Further research is underway and a debate continues, as helpfully evident in a June 2016 paper published in Biological Theory, titled Epidemiology Without Biology: False Paradigms, Unfounded Assumptions, and Specious Statistics in Radiation Science. Meanwhile standards for radiation exposure continue to be deliberately conservative.

In the USA, The Low-Dose Radiation Research Act of 2015 calls for an assessment of the current status of US and international low-dose radiation research. It also directs the National Academy of Sciences to “formulate overall scientific goals for the future of low-dose radiation research in the United States” and to develop a long-term research agenda to address those goals. The Act arises from a letter from a group of health physicists who pointed out that the limited understanding of low-dose health risks impairs the nation’s decision-making capabilities, whether in responding to radiological events involving large populations such as the 2011 Fukushima accident or in areas such as the rapid increase in radiation-based medical procedures, the cleanup of radioactive contamination from legacy sites and the expansion of civilian nuclear energy.

Fear of radiation effects

The main effect of low-level radiation arises from fear, not the radiation itself. People who are conditioned to fear any level of ionizing radiation tend to take action to avoid it, and those actions are sometimes much more harmful than any exposure to low-dose radiation could be*. Concerns about low doses of radiation from CT scans and X-rays are not only misguided, but may lead to suffering and deaths from avoided or delayed diagnosis. Also therapeutic benefits of nuclear medicine greatly outweigh any harm that might come from the controlled radiation exposure involved.

* After the Chernobyl accident, some pregnant women in Europe sought abortions without any medical justification, the exposure levels being vastly below those likely to have any effects. Sometimes the fear is promoted by misguided governments, as in Japan where maintaining the evacuation of many people beyond a few weeks has resulted in over 1000 deaths, though exposure levels if people had returned to homes would not be hazardous except possibly in some limited areas, easily defined.

Limiting exposure

Public dose limits for exposure from uranium mining or nuclear plants are usually set at 1 mSv/yr above background.

In most countries the current maximum permissible dose to radiation workers is 20 mSv per year averaged over five years, with a maximum of 50 mSv in any one year. This is over and above background exposure, and excludes medical exposure. The value originates from the International Commission on Radiological Protection (ICRP), and is coupled with the requirement to keep exposure as low as reasonably achievable (ALARA) – taking into account social and economic factors.

Radiation protection at uranium mining operations and in the rest of the nuclear fuel cycle is tightly regulated, and levels of exposure are monitored.

There are four ways in which people are protected from identified radiation sources:

  • Limiting time. In occupational situations, dose is reduced by limiting exposure time.
  • Distance. The intensity of radiation decreases with distance from its source.
  • Shielding. Barriers of lead, concrete or water give good protection from high levels of penetrating radiation such as gamma rays. Intensely radioactive materials are therefore often stored or handled under water, or by remote control in rooms constructed of thick concrete or lined with lead.
  • Containment. Highly radioactive materials are confined and kept out of the workplace and environment. Nuclear reactors operate within closed systems with multiple barriers which keep the radioactive materials contained.

UNEP notes: “While the release of radon in underground uranium mines makes a substantial contribution to occupational exposure on the part of the nuclear industry, the annual average effective dose to a worker in the nuclear industry overall has decreased from 4.4 mSv in the 1970s to about 1 mSv today. However, the annual average effective dose to a coal miner is still about 2.4 mSv and for other miners about 3 mSv." The mining figures are probably for underground situations.

About 23 million workers worldwide are monitored for radiation exposure, and about 10 million of these are exposed to artificial sources, mostly in the medical sector where the annual dose averages 0.5 mSv.

Standards and regulation of radiation exposure

Radiation protection standards are based on the conservative assumption that the risk is directly proportional to the dose, even at the lowest levels, though there is no actual evidence of harm at low levels, below about 100 mSv as short-term dose. To the extent that cell damage is made good within a month (say), chronic dose rates up to 100 mSv per month could also be safe, but the standard assumption, called the 'linear no-threshold (LNT) hypothesis', discounts the contribution of any such thresholds and is recommended for practical radiation protection purposes only, such as setting allowable levels of radiation exposure of individuals.

LNT was first accepted by the International Commission on Radiological Protection (ICRP) in 1955, when scientific knowledge of radiation effects was less, and then in 1959 by the United Nations Scientific Committee on the Effects of Atomic Radiation (UNSCEAR) as a philosophical basis for radiological protection at low doses, stating outright that “Linearity has been assumed primarily for purposes of simplicity, and there may or may not be a threshold dose”. (Above 100 mSv acute dose there is some scientific evidence for linearity in dose-effect.) From 1934 to 1955 a tolerance dose limit of 680 mSv/yr was recommended by the ICRP, and no evidence of harm from this – either cancer or genetic – had been documented.

The LNT hypothesis cannot properly be used for predicting the consequences of an actual exposure to low levels of radiation and it has no proper role in low-dose risk assessment. For example, LNT suggests that, if the dose is halved from a high level where effects have been observed, there will be half the effect, and so on. This would be very misleading if applied to a large group of people exposed to trivial levels of radiation and even at levels higher than trivial it could lead to inappropriate actions to avert the doses. At Fukushima following the March 2011 accident, maintaining the evacuation beyond a few days did in fact lead to about 1100 deaths, according to the Japan Reconstruction Agencyi.

Much of the evidence which has led to today's standards derives from the atomic bomb survivors in 1945, who were exposed to high doses incurred in a very short time. In setting occupational risk estimates, some allowance has been made for the body's ability to repair damage from small exposures, but for low-level radiation exposure the degree of protection from applying LNT may be misleading. At low levels of radiation exposure the dose-response relationship is unclear due to background radiation levels and natural incidence of cancer. However, the Hiroshima survivor data published in 1958 by UNSCEAR for leukaemia (see Appendix) actually shows a reduction in incidence by a factor of three in the dose range 1 to 100 mSv. The threshold for increased risk here is about 400 mSv. This is very significant in relation to concerns about radiation exposure from contaminated areas after the Chernobyl and Fukushima accidents.

The International Commission on Radiological Protection (ICRP), set up in 1928, is a body of scientific experts and a respected source of guidance on radiation protection, though it is independent and not accountable to governments or the UN. Its recommendations are widely followed by national health authorities, the EU and the IAEA. It retains the LNT hypothesis as a guiding principle.

The International Atomic Energy Agency (IAEA) has published international radiation protection standards since 1962. It is the only UN body with specific statutory responsibilities for radiation protection and safety. Its Safety Fundamentals are applied in basic safety standards and consequent Regulations. However, the UN Scientific Committee on the Effects of Atomic Radiation (UNSCEAR) set up in 1955 is the most authoritative source of information on ionizing radiation and its effects.

In any country, radiation protection standards are set by government authorities, generally in line with recommendations by the ICRP, and coupled with the requirement to keep exposure as low as reasonably achievable (ALARA) – taking into account social and economic factors. The authority of the ICRP comes from the scientific standing of its members and the merit of its recommendations.

The three key points of the ICRP's recommendations are:

  • Justification. No practice should be adopted unless its introduction produces a positive net benefit.
  • Optimisation. All exposures should be kept as low as reasonably achievable, economic and social factors being taken into account.
  • Limitation. The exposure of individuals should not exceed the limits recommended for the appropriate circumstances.

National radiation protection standards are framed for both Occupational and Public exposure categories.

The ICRP recommends that the maximum permissible dose for occupational exposure should be 20 millisievert per year averaged over five years (i.e. 100 millisievert in 5 years) with a maximum of 50 millisievert in any one year. For public exposure, 1 millisievert per year averaged over five years is the limit. In both categories, the figures are over and above background levels, and exclude medical exposure.j

Post-accident exposure

These low exposure levels are achievable for normal nuclear power and medical activities, but where an accident has resulted in radioactive contamination their application has no net health benefit. There is a big difference between what is desirable in the normal planned operation of any plant, and what is tolerable for dealing with the effects of an accident. Here, restrictive dose limits will limit flexibility in managing the situation and thus their application may increase other health risks, or even result in major adverse health effects, as near Fukushima since March 2011 (see earlier endnote). The objective needs to be to minimize the risks and harm to the individual and population overall, rather than focusing on radiation in isolation.

This is recognised to some extent in the occupational health limits set for cleaning up such situations: the IAEA sets 100 mSv as the allowable short-term dose for emergency workers taking vital remedial actions, and 500 mSv as allowable short-term dose for emergency workers taking life-saving actions. At Fukushima, 250 mSv was set as the allowable short-term dose for workers controlling the disabled reactors during 2011. Following NRA consideration of the Fukushima experience, as well as overseas standards and the science, 250 mSv is now the proposed allowable dose in emergency situations in Japan from April 2016.

But even these levels are low, and there has been no corresponding allowance for neighbouring members of the public – ALARA was the only reference criterion regardless of its collateral effects due to prolonging the evacuation beyond a few days. The death toll and trauma from prolonged evacuation at Fukushima were clearly very much greater than the risks of elevated radiation exposure after the first few days.

This led to the IAEA in May 2013 publishing allowable dose rates for members of the public living normally in affected areas, measured 1m above the contaminated ground. A level of 220 mSv/yr over a full year is "safe for everyone" providing any ingested radioactivity is safe. Shorter term, at 40 times this level, 170 mSv for one week is provisionally safe, and at four times the yearly level – 880 mSv – is provisionally safe for one month.

In March 2011, soon after the Fukushima accident, the ICRP said that it “continues to recommend reference levels of 500 to 1000 mSv to avoid the occurrence of severe deterministic injuries for rescue workers involved in an emergency exposure situation.” For members of the public in such situations, it recommends “reference levels for the highest planned residual dose in the band of 20 to 100 millisieverts (mSv)”, dropping to 1 to 20 mSv/yr when the situation is under control.

When making decisions on evacuations, optimization of all the health risks (not just radiation exposure) is required. Rather than ALARA, a concept of As High As Relatively Safe – AHARS – would be more appropriate in dealing with emergency or existing high exposure situations, based on scientific evidence. This would be similar to the 680 mSv Tolerance Dose allowable to 1950s (assuming gamma & beta radiation), and it would take into account the dose rate. This AHARS approach is supported by Allison (2011) and Cuttler (2012 & 2013) among others, and an AHARS level of 1000 mSv/yr or 100 mSv per month is suggested. This would also mean that most or all of the displaced residents from near the Fukushima plant could return home, without any elevated cancer risk.

Another proposal is for As High as Naturally Existent – AHANE. That is, the highest naturally occurring radiation exposures in the world experienced by a large number of people without discernable negative health effects. At Ramsar in Iran, about 2000 people are exposed to at least 250 mSv/yr with no adverse effect. But in Guarapari, Brazil (pop. 73,000), Kerala, India (pop. 100,000), and Yangjiang, China (pop. 80,000) the average exposures are about 50 mSv/year, 38 mSv/year and 35 mSv/year respectively. In all cases, the residents have life expectancies at least as long as their national peers, and cancer rates slightly lower than fellow countrymen. US Navy shipyard worker data confirm the safety of 50 mSv/yr.

Nuclear fuel cycle radiation exposures

The average annual radiation dose to employees at uranium mines (in addition to natural background) is around 2 mSv (ranging up to 10 mSv). Natural background radiation is about 2 mSv. In most mines, keeping doses to such low levels is achieved with straightforward ventilation techniques coupled with rigorously enforced procedures for hygiene. In some Canadian mines, with very high-grade ore, sophisticated means are employed to limit exposure. (See also information page on Occupational Safety in Uranium Mining.) Occupational doses in the US nuclear energy industry – conversion, enrichment, fuel fabrication and reactor operation – average less than 3 mSv/yr.

Reprocessing plants in Europe and Russia treat used fuel to recover useable uranium and plutonium and separate the highly radioactive wastes. These facilities employ massive shielding to screen gamma radiation in particular. Manual operations are carried by operators behind lead glass using remote handling equipment.

In mixed oxide (MOX) fuel fabrication, little shielding is required, but the whole process is enclosed with access via gloveboxes to eliminate the possibility of alpha contamination from the plutonium. Where people are likely to be working alongside the production line, a 25mm layer of perspex shields neutron radiation from the Pu-240. (In uranium oxide fuel fabrication, no shielding is required.)

Interestingly, due to the substantial amounts of granite in their construction, many public buildings including Australia's Parliament House and New York Grand Central Station, would have some difficulty in getting a licence to operate if they were nuclear power stations.

Accidental radiation exposure (nuclear and other)

(ARS = Acute radiation syndrome)

The death toll from the Chernobyl accident is about 56, that from misuse of radiotherapy and orphan radioisotope sources is less than 50 – half of those from deliberate therapeutic doses due to faulty equipment or procedures.

Three Mile Island – nuclear power reactor

The March 1979 accident at Three Mile Island nuclear power plant in the USA caused some people near the plant to receive very minor doses of radiation, well under the internationally recommended level. Subsequent scientific studies found no evidence of any harm resulting from that exposure. In 1996, some 2,100 lawsuits claiming adverse health effects from the accident were dismissed for lack of evidence. INES rating 5.

Chernobyl – nuclear power reactor

Immediately after the Chernobyl nuclear power plant disaster in 1986, much larger doses were experienced. Apart from the residents of nearby Pripyat, who were evacuated within two days, some 24,000 people living within 15 km of the plant received an average of 450 mSv before they were evacuated. A total of 5200 PBq of radioactivity (iodine-131 equivalent) was released.

In June 1989, a group of experts from the World Health Organization agreed that an incremental long-term dose of 350 mSv should be the criterion for relocating people affected by the 1986 Chernobyl accident. This was considered a "conservative value which ensured that the risk to health from this exposure was very small compared with other risks over a lifetime". (For comparison, background radiation averages about 150-200 mSv over a lifetime in most places.)

Out of the 134 severely exposed workers and firemen, 28 of the most heavily exposed died as a result of acute radiation syndrome (ARS) within three months of the accident. Of these, 20 were from the group of 21 that had received over 6.5 Gy, seven (out of 22) had received between 4.2 and 6.4 Gy, and one (out of 50) from the group that had received 2.2-4.1 Gy.5 A further 19 died in 1987-2004 from different causes (see information page on Chernobyl Accident Appendix 2: Health Impacts).

Regarding the emergency workers with doses lower than those causing ARS symptoms, a 2006 World Health Organization report6 referred to studies carried out on 61,000 emergency Russian workers where a total of 4995 deaths from this group were recorded during 1991-1998. "The number of deaths in Russian emergency workers attributable to radiation caused by solid neoplasms and circulatory system diseases can be estimated to be about 116 and 100 cases respectively." Furthermore, although no increase in leukaemia is discernible yet, "the number of leukaemia cases attributable to radiation in this cohort can be estimated to be about 30." Thus, 4.6% of the number of deaths in this group are attributable to radiation-induced diseases. (The estimated average external dose for this group was 107 mSv.)

The report also links the accident to an increase in thyroid cancer in children: "During 1992-2000, in Belarus, Russia and Ukraine, about 4000 cases of thyroid cancer were diagnosed in children and adolescents (0-18 years), of which about 3000 occurred in the age group of 0-14 years. For 1152 thyroid cancer patient cases diagnosed among Chernobyl children in Belarus during 1986-2002, the survival rate is 98.8%. Eight patients died due to progression of their thyroid cancer and six children died from other causes. One patient with thyroid cancer died in Russia."

There has been no increase attributable to Chernobyl in congenital abnormalities, adverse pregnancy outcomes or any other radiation-induced disease in the general population either in the contaminated areas or further afield.

Reports two decades after the accident make it clear that the main health effects from the accident are due to the evacuation of many people coupled with fear engendered, and thousands have died from suicide, depression and alcoholism. The 2006 Chernobyl Forum report said that people in the area suffered a paralysing fatalism due to myths and misperceptions about the threat of radiation, which contributed to a culture of chronic dependency. Some "took on the role of invalids." Mental health coupled with smoking and alcohol abuse is a very much greater problem than radiation, but worst of all at the time was the underlying level of health and nutrition. Psycho-social effects among those affected by the accident are similar to those arising from other major disasters such as earthquakes, floods and fires.

After the shelterf was built over the destroyed reactor at Chernobyl, a team of about 15 engineers and scientists was set up to investigate the situation inside it. Over several years they repeatedly entered the ruin, accumulating individual doses of up to 15,000 mSv. Daily dose was mostly restricted to 50 mSv, though occasionally it was many times this. None of the men developed any symptoms of radiation sickness, but they must be considered to have a considerably increased cancer risk. INES rating 7.

Fukushima – nuclear power reactors

The March 2011 accident at Fukushima Daiichi nuclear power plant in Japan released about 940 PBq (iodine-131 equivalent) of radioactive material, mostly on days 4 to 6 after the tsunami. In May 2013 UNSCEAR reported that "Radiation exposure following the nuclear accident at Fukushima Daiichi did not cause any immediate health effects. It is unlikely to be able to attribute any health effects in the future among the general public and the vast majority of workers." The only exception are the 146 emergency workers that received radiation doses of over 100 mSv during the crisis.7 Thyroid doses in children were significantly lower than from the Chernobyl accident. Some 160,000 people were evacuated as a precautionary measure, and prolonging the evacuation resulted in the deaths of about 1100 of them due to stress, and some due to disruption of medical and social welfare facilities. The highest internal radioactivity from ingestion was 12 kBq, some 1000 times less than the level causing adverse health effects at Goiania

  • From the outset, there has been a strong awareness of the potential hazard of both nuclear criticality and release of radioactive materials from generating electricity with nuclear power. 
  • As in other industries, the design and operation of nuclear power plants aims to minimise the likelihood of accidents, and avoid major human consequences when they occur. 
  • There have been three major reactor accidents in the history of civil nuclear power – Three Mile Island, Chernobyl and Fukushima. One was contained without harm to anyone, the next involved an intense fire without provision for containment, and the third severely tested the containment, allowing some release of radioactivity. 
  • These are the only major accidents to have occurred in over 16,000 cumulative reactor-years of commercial nuclear power operation in 33 countries. 
  • The evidence over six decades shows that nuclear power is a safe means of generating electricity. The risk of accidents in nuclear power plants is low and declining. The consequences of an accident or terrorist attack are minimal compared with other commonly accepted risks. Radiological effects on people of any radioactive releases can be avoided.

Context

In relation to nuclear power, safety is closely linked with security, and in the nuclear field also with safeguards. Some distinctions:

  • Safety focuses on unintended conditions or events leading to radiological releases from authorised activities. It relates mainly to intrinsic problems or hazards.
  • Security focuses on the intentional misuse of nuclear or other radioactive materials by non-state elements to cause harm. It relates mainly to external threats to materials or facilities.
  • Safeguards focus on restraining activities by states that could lead to acquisition of nuclear weapons. It concerns mainly materials and equipment in relation to rogue governments. (See also Safeguards paper.)

Harnessing the world's most concentrated energy source

In the 1950s attention turned to harnessing the power of the atom in a controlled way, as demonstrated at Chicago in 1942 and subsequently for military research, and applying the steady heat yield to generate electricity. This naturally gave rise to concerns about accidents and their possible effects. However, with nuclear power, safety depends on much the same factors as in any comparable industry: intelligent planning, proper design with conservative margins and back-up systems, high-quality components and a well-developed safety culture in operations. The operating lives of reactors depend on maintaining their safety margin.

A particular nuclear scenario was loss of cooling which resulted in melting of the nuclear reactor core, and this motivated studies on both the physical and chemical possibilities as well as the biological effects of any dispersed radioactivity.  Those responsible for nuclear power technology in the West devoted extraordinary effort to ensuring that a meltdown of the reactor core would not take place, since it was assumed that a meltdown of the core would create a major public hazard, and if uncontained, a tragic accident with likely multiple fatalities.

In avoiding such accidents the industry has been very successful. In over 16,000 cumulative reactor-years of commercial operation in 32 countries, there have been only three major accidents to nuclear power plants - Three Mile Island, Chernobyl, and Fukushima - the second being of little relevance to reactor design outside the old Soviet bloc.

The three significant accidents in the 50-year history of civil nuclear power generation are:

  • Three Mile Island (USA 1979) where the reactor was severely damaged but radiation was contained and there were no adverse health or environmental consequences
  • Chernobyl (Ukraine 1986) where the destruction of the reactor by steam explosion and fire killed 31 people and had significant health and environmental consequences. The death toll has since increased to about 56.
  • Fukushima (Japan 2011) where three old reactors (together with a fourth) were written off and the effects of loss of cooling due to a huge tsunami were inadequately contained.

A table showing all reactor accidents, and a table listing some energy-related accidents with multiple fatalities areappended.

These three significant accidents occurred during more than 16,000 reactor-years of civil operation. Of all the accidents and incidents, only the Chernobyl and Fukushima accidents resulted in radiation doses to the public greater than those resulting from the exposure to natural sources. The Fukushima accident resulted in some radiation exposure of workers at the plant, but not such as to threaten their health, unlike Chernobyl.  Other incidents (and one 'accident') have been completely confined to the plant.

Apart from Chernobyl, no nuclear workers or members of the public have ever died as a result of exposure to radiation due to a commercial nuclear reactor incident. Most of the serious radiological injuries and deaths that occur each year (2-4 deaths and many more exposures above regulatory limits) are the result of large uncontrolled radiation sources, such as abandoned medical or industrial equipment. (There have also been a number of accidents in experimental reactors and in one military plutonium-producing pile – at Windscale, UK, in 1957, but none of these resulted in loss of life outside the actual plant, or long-term environmental contamination.)  See also Table 2 in Appendix.
 


It should be emphasised that a commercial-type power reactor simply cannot under any circumstances explode like a nuclear bomb – the fuel is not enriched beyond about 5%, and much higher enrichment is needed for explosives.

The International Atomic Energy Agency (IAEA) was set up by the United Nations in 1957. One of its functions was to act as an auditor of world nuclear safety, and this role was increased greatly following the Chernobyl accident. It prescribes safety procedures and the reporting of even minor incidents. Its role has been strengthened since 1996 (see later section). Every country which operates nuclear power plants has a nuclear safety inspectorate and all of these work closely with the IAEA.

While nuclear power plants are designed to be safe in their operation and safe in the event of any malfunction or accident, no industrial activity can be represented as entirely risk-free. Incidents and accidents may happen, and as in other industries, will lead to progressive improvement in safety. Those improvements are both in new designs, and in upgrading of existing plants. The long-term operation (LTO) of established plants is established by significant investment in such upgrading.

The safety of operating staff is a prime concern in nuclear plants. Radiation exposure is minimised by the use of remote handling equipment for many operations in the core of the reactor. Other controls include physical shielding and limiting the time workers spend in areas with significant radiation levels. These are supported by continuous monitoring of individual doses and of the work environment to ensure very low radiation exposure compared with other industries.

The use of nuclear energy for electricity generation can be considered extremely safe. Every year several thousand people die in coal mines to provide this widely used fuel for electricity. There are also significant health and environmental effects arising from fossil fuel use. To date, even the Fukushima accident has caused no deaths, and the IAEA reported in June 2011: "to date, no health effects have been reported in any person as a result of radiation exposure." Subsequent WHO and UNSCEAR reports have supported this.

Achieving safety: the reactor core

Concerning possible accidents, up to the early 1970s, some extreme assumptions were made about the possible chain of consequences. These gave rise to a genre of dramatic fiction (eg The China Syndrome) in the public domain and also some solid conservative engineering including containment structures (at least in Western reactor designs) in the industry itself. Licensing regulations were framed accordingly.

It was not until the late 1970s that detailed analyses and large-scale testing, followed by the 1979 meltdown of the Three Mile Island reactor, began to make clear that even the worst possible accident in a conventional western nuclear power plant or its fuel would not be likely to cause dramatic public harm. The industry still works hard to minimize the probability of a meltdown accident, but it is now clear that no-one need fear a potential public health catastrophe simply because a fuel meltdown happens.  Fukushima has made that clear, with a triple meltdown causing no fatalities or serious radiation doses to anyone, while over two hundred people continued working on the site to mitigate the accident's effects.

The decades-long test and analysis program showed that less radioactivity escapes from molten fuel than initially assumed, and that most of this radioactive material is not readily mobilized beyond the immediate internal structure. Thus, even if the containment structure that surrounds all modern nuclear plants were ruptured, as it has been with at least one of the Fukushima reactors, it is still very effective in preventing escape of most radioactivity.

It is the laws of physics and the properties of materials that mitigate disaster, as much as the required actions by safety equipment or personnel. In fact, licensing approval for new plants now requires that the effects of any core-melt accident must be confined to the plant itself, without the need to evacuate nearby residents.

A mandated safety indicator is the calculated probable frequency of degraded core or core melt accidents. The US Nuclear Regulatory Commission (NRC) specifies that reactor designs must meet a 1 in 10,000 year core damage frequency, but modern designs exceed this. US utility requirements are 1 in 100,000 years, the best currently operating plants are about 1 in 1 million and those likely to be built in the next decade are almost 1 in 10 million. While this calculated core damage frequency has been one of the main metrics to assess reactor safety, European safety authorities prefer a deterministic approach, focusing on actual provision of back-up hardware, though they also undertake probabilistic safety analysis (PSA) for core damage frequency.

Even months after the Three Mile Island (TMI) accident in 1979 it was assumed that there had been no core melt because there were no indications of severe radioactive release even inside the containment. It turned out that in fact about half the core had melted. Until 2011 this remained the only core melt in a reactor conforming to NRC safety criteria, and the effects were contained as designed, without radiological harm to anyone.* Greifswald 5 in East Germany had a partial core melt in November 1989, due to malfunctioning valves (root cause: shoddy manufacture) and was never restarted. At Fukushima in 2011 (a different reactor design with penetrations in the bottom of the pressure vessel) the three reactor cores evidently largely melted in the first two or three days, but this was not confirmed for about ten weeks. It is still not certain how much of the core material was not contained by the pressure vessels and ended up in the bottom of the drywell containments, though certainly there was considerable release of radionuclides to the atmosphere early on, and later to cooling water**.

* About this time there was alarmist talk of the so-called 'China Syndrome', a scenario where the core of such a reactor would melt, and due to continual heat generation, melt its way through the reactor pressure vessel and concrete foundations to keep going, perhaps until it reached China on the other side of the globe! The TMI accident proved the extent of truth in the proposition, and the molten core material got exactly 15 mm of the way to China as it froze on the bottom of the reactor pressure vessel. At Fukushima, cooling was maintained just long enough apparently to avoid testing the containment in this way.

** Ignoring isotopic differences, there are about one hundred different fission products in fuel which has been undergoing fission. A few of these are gases at normal temperatures, more are volatile at higher temperatures, and both will be released from the fuel if the cladding is damaged. The latter include iodine (easily volatalised, at 184°C) and caesium (671°C), which were the main radionuclides released at Fukushima, first into the reactor pressure vessel and then into the containment which in unit 2 apparently ruptured early on day 5. In addition, as cooling water was flushed through the hot core, soluble fission products such as caesium dissolved in it, which created the need for a large water treatment plant to remove them.

However apart from these accidents and the Chernobyl disaster there have been about ten core melt accidents – mostly in military or experimental reactors – Appendix 2 lists most of them. None resulted in any hazard outside the plant from the core melting, though in one case there was significant radiation release due to burning fuel in hot graphite (similar to Chernobyl but smaller scale).  The Fukushima accident should also be considered in that context, since the fuel was badly damaged and there were significant off-site radiation releases.

Regulatory requirements today for new plants are that the effects of any core-melt accident must be confined to the plant itself, without the need to evacuate nearby residents.

The main safety concern has always been the possibility of an uncontrolled release of radioactive material, leading to contamination and consequent radiation exposure off-site. Earlier assumptions were that this would be likely in the event of a major loss of cooling accident (LOCA) which resulted in a core melt. The TMI experience suggested otherwise, but at Fukushima this is exactly what happened.  In the light of better understanding of the physics and chemistry of material in a reactor core under extreme conditions it became evident that even a severe core melt coupled with breach of containment would be unlikely to create a major radiological disaster from many Western reactor designs, but the Fukushima accident showed that this did not apply to all. Studies of the post-accident situation at Three Mile Island (where there was no breach of containment) supported the suggestion, and analysis of Fukushima is pending.

Certainly the matter was severely tested with three reactors of the Fukushima Daiichi nuclear power plant in Japan in March 2011. Cooling was lost after a shutdown, and it proved impossible to restore it sufficiently to prevent severe damage to the fuel. The reactors, dating from 1971-75, were written off. A fourth is also written off due to damage from a hydrogen explosion.

Achieving optimum nuclear safety

A fundamental principle of nuclear power plant operation worldwide is that the operator is responsible for safety. The national regulator is responsible for ensuring the plants are operated safely by the licensee, and that the design is approved. A second important concept is that a regulator’s mission is to protect people and the environment.

Design certification of reactors is the responsibility of national regulators. There is international collaboration among these to varying degrees. Also there are a number of sets of mechanical codes and standards related to quality and safety.

With new reactor designs being established on a more international basis since the 1990s, both industry and regulators are seeking greater design standardisation and also regulatory harmonization. The role of the World Nuclear Association's CORDEL Working Group and the OECD/NEA's MDEP group are described in the Cooperation paper.

An OECD/NEA report in 2010 pointed out that the theoretically-calculated frequency for a large release of radioactivity from a severe nuclear power plant accident has reduced by a factor of 1600 between the early Generation I reactors as originally built and the Generation III/III+ plants being built today. Earlier designs however have been progressively upgraded through their operating lives.

It has long been asserted that nuclear reactor accidents are the epitome of low-probability but high-consequence risks. Understandably, with this in mind, some people were disinclined to accept the risk, however low the probability. However, the physics and chemistry of a reactor core, coupled with but not wholly depending on the engineering, mean that the consequences of an accident are likely in fact be much less severe than those from other industrial and energy sources. Experience, including Fukushima, bears this out.

A 2009 US Department of Energy (DOE) Human Performance Handbook notes: "The aviation industry, medical industry, commercial nuclear power industry, U.S. Navy, DOE and its contractors, and other high-risk, technologically complex organizations have adopted human performance principles, concepts, and practices to consciously reduce human error and bolster controls in order to reduce accidents and events." "About 80 percent of all events are attributed to human error. In some industries, this number is closer to 90 percent. Roughly 20 percent of events involve equipment failures. When the 80 percent human error is broken down further, it reveals that the majority of errors associated with events stem from latent organizational weaknesses (perpetrated by humans in the past that lie dormant in the system), whereas about 30 percent are caused by the individual worker touching the equipment and systems in the facility. Clearly, focusing efforts on reducing human error will reduce the likelihood of events." Following the Fukushima accident the focus has been on the organisational weaknesses which increase the likelihood of human error.

In passing, it is relevant to note that the safety record of the US nuclear navy from 1955 on is excellent, this being attributed to a high level of standardisation in over one hundred naval power plants and in their maintenance, and the high quality of the Navy's training program. Until the 1980s, the Soviet naval record stood in marked contrast.

Defence in depth

To achieve optimum safety, nuclear plants in the western world operate using a 'defence-in-depth' approach, with multiple safety systems supplementing the natural features of the reactor core. Key aspects of the approach are:

  • high-quality design & construction,
  • equipment which prevents operational disturbances or human failures and errors developing into problems,
  • comprehensive monitoring and regular testing to detect equipment or operator failures,
  • redundant and diverse systems to control damage to the fuel and prevent significant radioactive releases,
  • provision to confine the effects of severe fuel damage (or any other problem) to the plant itself.

These can be summed up as: Prevention, Monitoring, and Action (to mitigate consequences of failures).

The safety provisions include a series of physical barriers between the radioactive reactor core and the environment, the provision of multiple safety systems, each with backup and designed to accommodate human error. Safety systems account for about one quarter of the capital cost of such reactors. As well as the physical aspects of safety, there are institutional aspects which are no less important - see following section on International Collaboration.

The barriers in a typical plant are: the fuel is in the form of solid ceramic (UO2) pellets, and radioactive fission products remain largely bound inside these pellets as the fuel is burned. The pellets are packed inside sealed zirconium alloy tubes to form fuel rods. These are confined inside a large steel pressure vessel with walls up to 30 cm thick – the associated primary water cooling pipework is also substantial. All this, in turn, is enclosed inside a robust reinforced concrete containment structure with walls at least one metre thick.  This amounts to three significant barriers around the fuel, which itself is stable up to very high temperatures.

These barriers are monitored continually. The fuel cladding is monitored by measuring the amount of radioactivity in the cooling water. The high pressure cooling system is monitored by the leak rate of water, and the containment structure by periodically measuring the leak rate of air at about five times atmospheric pressure.

Looked at functionally, the three basic safety functions in a nuclear reactor are:

  • to control reactivity,
  • to cool the fuel and
  • to contain radioactive substances.

The main safety features of most reactors are inherent - negative temperature coefficient and negative void coefficient. The first means that beyond an optimal level, as the temperature increases the efficiency of the reaction decreases (this in fact is used to control power levels in some new designs). The second means that if any steam has formed in the cooling water there is a decrease in moderating effect so that fewer neutrons are able to cause fission and the reaction slows down automatically.

In the 1950s and 1960s some experimental reactors in Idaho were deliberately tested to destruction to verify that large reactivity excursions were self-limiting and would automatically shut down the fission reaction. These tests verified that this was the case.

Beyond the control rods which are inserted to absorb neutrons and regulate the fission process, the main engineered safety provisions are the back-up emergency core cooling system (ECCS) to remove excess heat (though it is more to prevent damage to the plant than for public safety) and the containment.

Traditional reactor safety systems are 'active' in the sense that they involve electrical or mechanical operation on command. Some engineered systems operate passively, eg pressure relief valves. Both require parallel redundant systems. Inherent or full passive safety design depends only on physical phenomena such as convection, gravity or resistance to high temperatures, not on functioning of engineered components. All reactors have some elements of inherent safety as mentioned above, but in some recent designs the passive or inherent features substitute for active systems in cooling etc. Such a design would have averted the Fukushima accident, where loss of electrical power resulted is loss of cooling function.

The basis of design assumes a threat where due to accident or malign intent (eg terrorism) there is core melting and a breach of containment. This double possibility has been well studied and provides the basis of exclusion zones and contingency plans. Apparently during the Cold War neither Russia nor the USA targeted the other's nuclear power plants because the likely damage would be modest.

Nuclear power plants are designed with sensors to shut them down automatically in an earthquake, and this is a vital consideration in many parts of the world. (See Nuclear Power Plants and Earthquakes paper)

Severe accident management

In both the Three Mile Island (TMI) and Fukushima accidents the problems started after the reactors were shut down – immediately at TMI and after an hour at Fukushima, when the tsunami arrived. The need to remove decay heat from the fuel was not met in each case, so core melting started to occur within a few hours. Cooling requires water circulation and an external heat sink. If pumps cannot run due to lack of power, gravity must be relied upon, but this will not get water into a pressurised system – either reactor pressure vessel or containment. Hence there is provision for relieving pressure, sometimes with a vent system, but this must work and be controlled without power. There is a question of filters or scrubbers in the vent system: these need to be such that they do not block due to solids being carried. Ideally any vent system should deal with any large amounts of hydrogen, as at Fukushima, and have minimum potential to spread radioactivity outside the plant. Filtered containment ventilation systems (FCVSs) are being retrofitted to some reactors which did not already have them, or any of sufficient capacity, following the Fukushima accident. The basic premise of a FCVS is that, independent of the state of the reactor itself, the catastrophic failure of the containment structure can be avoided by discharging steam, air and incondensable gases like hydrogen to the atmosphere.

The Three Mile Island accident in 1979 demonstrated the importance of the inherent safety features. Despite the fact that about half of the reactor core melted, radionuclides released from the melted fuel mostly plated out on the inside of the plant or dissolved in condensing steam. The containment building which housed the reactor further prevented any significant release of radioactivity. The accident was attributed to mechanical failure and operator confusion. The reactor's other protection systems also functioned as designed. The emergency core cooling system would have prevented any damage to the reactor but for the intervention of the operators.

Investigations following the accident led to a new focus on the human factors in nuclear safety. No major design changes were called for in western reactors, but controls and instrumentation were improved significantly and operator training was overhauled.

At Fukushima Daiichi in March 2011 the three operating reactors shut down automatically, and were being cooled as designed by the normal residual heat removal system using power from the back-up generators, until the tsunami swamped them an hour later. The emergency core cooling systems then failed. Days later, a separate problem emerged as spent fuel ponds lost water. Analysis of the accident showed the need for more intelligent siting criteria than those used in the 1960s, and the need for better back-up power and post-shutdown cooling, as well as provision for venting the containment of that kind of reactor and other emergency management procedures.

Nuclear plants have Severe Accident Mitigation Guidelines (SAMG, or in Japan: SAG), and most of these, including all those in the USA, address what should be done for accidents beyond design basis, and where several systems may be disabled. See section below.

In 2007 the US NRC launched a research program to assess the possible consequences of a serious reactor accident. Its draft report was released nearly a year after the Fukushima accident had partly confirmed its findings. The State-of-the-Art Reactor Consequences Analysis (SOARCA) showed that a severe accident at a US nuclear power plant (PWR or BWR) would not be likely to cause any immediate deaths, and the risks of fatal cancers would be vastly less than the general risks of cancer. SOARCA's main conclusions fall into three areas: how a reactor accident progresses; how existing systems and emergency measures can affect an accident's outcome; and how an accident would affect the public's health. The principal conclusion is that existing resources and procedures can stop an accident, slow it down or reduce its impact before it can affect the public, but even if accidents proceed without such mitigation they take much longer to happen and release much less radioactive material than earlier analyses suggested.  This was borne out at Fukushima, where there was ample time for evacuation – three days – before any significant radioactive releases.

In 2015 the Canadian Nuclear Safety Commission (CNSC) released its Study of Consequences of a Hypothetical Severe Nuclear Accident and Effectiveness of Mitigation Measures. This was the result of research and analysis undertaken to address concerns raised during public hearings in 2012 on the environmental assessment for the refurbishment of Ontario Power Generation's (OPG's) Darlington nuclear power plant. The study involved identifying and modelling a large atmospheric release of radionuclides from a hypothetical severe nuclear accident at the four-unit Darlington power plant; estimating the doses to individuals at various distances from the plant, after factoring in protective actions such as evacuation that would be undertaken in response to such an emergency; and, finally, determining human health and environmental consequences due to the resulting radiation exposure. It concluded that there would be no detectable health effects or increase in cancer risk. A fuller write-up of it is on the World Nuclear News website.

A different safety philosophy: Early Soviet-designed reactors

The April 1986 disaster at the Chernobyl nuclear power plant in Ukraine was the result of major design deficiencies in the RBMK type of reactor, the violation of operating procedures and the absence of a safety culture. One peculiar feature of the RBMK design was that coolant failure could lead to a strong increase in power output from the fission process ( positive void coefficient). However, this was not the prime cause of the Chernobyl accident. It once and for all vindicated the desirability of designing with inherent safety supplemented by robust secondary safety provisions. By way of contrast to western safety engineering, the Chernobyl reactor did not have a containment structure like those used in the West or in post-1980 Soviet designs.

The accident destroyed the reactor, and its burning contents dispersed radionuclides far and wide. This tragically meant that the results were severe, with 56 people killed, 28 of whom died within weeks from radiation exposure. It also caused radiation sickness in a further 200-300 staff and firefighters, and contaminated large areas of Belarus, Ukraine, Russia and beyond. It is estimated that at least 5% of the total radioactive material in the Chernobyl-4 reactor core was released from the plant, due to the lack of any containment structure. Most of this was deposited as dust close by. Some was carried by wind over a wide area. However, the problem here was not burning graphite as popularly quoted. The graphite was certainly incandescent as a result of fuel decay heat - sometimes over 1000°C - and some of it oxidised to carbon monoxide which burned along with the fuel cladding.

About 130,000 people received significant radiation doses (i.e. above internationally accepted ICRP limits) and continue to be monitored. About 4000 cases of thyroid cancer in children have been linked to the accident. Most of these were curable, though about nine were fatal. No increase in leukaemia or other cancers have yet shown up, but some is expected. The World Health Organisation is closely monitoring most of those affected.

The Chernobyl accident was a unique event and the only time in the history of commercial nuclear power that radiation-related fatalities occurred. The main positive outcome of this accident for the industry was the formation of the World Association of Nuclear Operators (WANO), building on the US precedent.

The destroyed unit 4 was enclosed in a concrete shelter which is being replaced by a more permanent structure.

An OECD expert report on it concluded that "the Chernobyl accident has not brought to light any new, previously unknown phenomena or safety issues that are not resolved or otherwise covered by current reactor safety programs for commercial power reactors in OECD Member countries.  In other words, the concept of 'defence in depth' was conspicuous by its absence, and tragically shown to be vitally important.

Apart from the RBMK reactor design, an early Russian PWR design, the VVER-440/V-230, gave rise to concerns in Europe, and a program was initiated to close these down as a condition of EU accession, along with Lithuania’s two RBMK units. See related papers on Early Soviet Reactors and EU Accession, and RBMK Reactors.

However, after the US Atomic Energy Commission published General Design Criteria for Nuclear Power Plants in 1971, Russian PWR designs conformed, according to Rosatom. In particular, the VVER-440/V-213 Loviisa reactors in Finland were designed at that time and modified to conform. The first of these two came on line in 1977.

A broader picture – other past accidents

There have been a number of accidents in experimental reactors and in one military plutonium-producing reactor, including a number of core melts, but none of these has resulted in loss of life outside the actual plant, or long-term environmental contamination. Elsewhere (Safety of Nuclear Power info paper appendix) we tabulate these, along with the most serious commercial plant accidents. The list of ten probably corresponds to incidents rating 4 or higher on today’s International Nuclear Event Scale (Table 4). All except Browns Ferry and Vandellos involved damage to or malfunction of the reactor core. At Browns Ferry a fire damaged control cables and resulted in an 18-month shutdown for repairs; at Vandellos a turbine fire made the 17-year old plant uneconomic to repair.

Mention should be made of the accident to the US Fermi-1 prototype fast breeder reactor near Detroit in 1966. Due to a blockage in coolant flow, some of the fuel melted. However no radiation was released off-site and no-one was injured. The reactor was repaired and restarted but closed down in 1972.

The well-publicized criticality accident at Tokai Mura, Japan, in 1999 was at a fuel preparation plant for experimental reactors, and killed two workers from radiation exposure. Many other such criticality accidents have occurred, some fatal, and practically all in military facilities prior to 1980. A review of these is listed in the References.

In an uncontained reactor accident such as at Windscale (a military facility) in 1957 and at Chernobyl in 1986, (and to some extent: Fukushima in 2011,) the principal health hazard is from the spread of radioactive materials, notably volatile fission products such as iodine-131 and caesium-137. These are biologically active, so that if consumed in food, they tend to stay in organs of the body. I-131 has a half-life of 8 days, so is a hazard for around the first month, (and apparently gave rise to the thyroid cancers after the Chernobyl accident). Caesium-137 has a half-life of 30 years, and is therefore potentially a long-term contaminant of pastures and crops. In addition to these, there is caesium-134 which has a half-life of about two years. While measures can be taken to limit human uptake of I-131, (evacuation of area for several weeks, iodide tablets), high levels of radioactive caesium can preclude food production from affected land for a long time. Other radioactive materials in a reactor core have been shown to be less of a problem because they are either not volatile (strontium, transuranic elements) or not biologically active (tellurium-132, xenon-133).

Accidents in any field of technology provide valuable knowledge enabling incremental improvement in safety beyond the original engineering. Cars and airliners are the most obvious examples of this, but the chemical and oil industries can provide even stronger evidence. Civil nuclear power has greatly improved its safety in both engineering and operation over its 55 years of experience with very few accidents and major incidents to spur that improvement. The Fukushima Daiichi accident is the first since Three Mile Island in 1979 which will have significant implications, at least for older plants.

Scrams, Seismic shutdowns

A scram is a sudden reactor shutdown. When a reactor is scrammed, automatically due to seismic activity, or due to some malfunction, or manually for whatever reason, the fission reaction generating the main heat stops. However, considerable heat continues to be generated by the radioactive decay of the fission products in the fuel. Initially, for a few minutes, this is great - about 7% of the pre-scram level. But it drops to about 1% of the normal heat output after two hours, to 0.5% after one day, and 0.2% after a week. Even then it must still be cooled, but simply being immersed in a lot of water does most of the job after some time. When the water temperature is below 100°C at atmospheric pressure the reactor is said to be in "cold shutdown".

European "stress tests" and US response following Fukushima accident

Aspects of nuclear plant safety highlighted by the Fukushima accident were assessed in the 143 nuclear reactors in the EU's 27 member states, as well as those in any neighbouring states that decided to take part. These comprehensive and transparent nuclear risk and safety assessments, the so-called "stress tests", involved targeted reassessment of each power reactor’s safety margins in the light of extreme natural events, such as earthquakes and flooding, as well as on loss of safety functions and severe accident management following any initiating event. They were conducted from June 2011 to April 2012. They mobilized considerable expertise in different countries (500 man-years) under the responsibility of each national Safety Authority within the framework of the European Nuclear Safety Regulators Group (ENSREG).

The Western European Nuclear Regulators' Association (WENRA) proposed these in response to a call from the European Council in March 2011, and developed specifications. WENRA is a network of Chief Regulators of EU countries with nuclear power plants and Switzerland, and has membership from 17 countries. It then negotiated the scope of the tests with the European Nuclear Safety Regulators Group (ENSREG), an independent, authoritative expert body created in 2007 by the European Commission comprising senior officials from the national nuclear safety, radioactive waste safety or radiation protection regulatory authorities from all 27 EU member states, and representatives of the European Commission.

In June 2011 the governments of seven non-EU countries agreed to conduct nuclear reactor stress tests using the EU model. Armenia, Belarus, Croatia, Russia, Switzerland, Turkey and Ukraine signed a declaration that they would conduct stress tests and agreed to peer reviews of the tests by outside experts. Russia had already undertaken extensive checks. (Croatia is co-owner in the Krsko PWR in Slovenia, and Belarus and Turkey plan to build nuclear plants but have none now.)

The reassessment of safety margins is based on the existing safety studies and engineering judgment to evaluate the behaviour of a nuclear power plant when facing a set of challenging situations. For a given plant, the reassessment reports on the most probable behaviour of the plant for each of the situations considered. The results of the reassessment were peer-reviewed and shared among regulators. WENRA noted that it remains a national responsibility to take or order any appropriate measures, such as additional technical or organisational safety provisions, resulting from the reassessment.




The scope of the assessment took into account the issues directly highlighted by the events in Fukushima and the possibility for combination of initiating events. Two 'initiating events' were covered in the scope: earthquake and flooding. The consequences of these – loss of electrical power and station blackout, loss of ultimate heat sink and the combination of both – were analysed, with the conclusions being applicable to other general emergency situations. In accident scenarios, regulators consider power plants' means to protect against and manage loss of core cooling as well as cooling of used fuel in storage. They also study means to protect against and manage loss of containment integrity and core melting, including consequential effects such as hydrogen accumulation.

Nuclear plant operators start by documenting each power plant site. This analysis of 'extreme scenarios' followed what ENSREG called a progressive approach "in which protective measures are sequentially assumed to be defeated" from starting conditions which "represent the most unfavourable operational states." The operators have to explain their means to maintain "the three fundamental safety functions (control of reactivity, fuel cooling confinement of radioactivity)" and support functions for these, "taking into account the probable damage done by the initiating event."

The documents had to cover provisions in the plant design basis for these events and the strength of the plant beyond its design basis. This means the "design margins, diversity, redundancy, structural protection and physical separation of the safety relevant systems, structures and components and the effectiveness of the defence-in-depth concept." This had to focus on 'cliff-edge' effects, e.g. when back-up batteries are exhausted and station blackout is inevitable. For severe accident management scenarios they must identify the time before fuel damage is unavoidable and the time before water begins boiling in used fuel ponds and before fuel damage occurs. Measures to prevent hydrogen explosions and fires are to be part of this.

Since the licensee has the prime responsibility for safety, they performed the reassessments, and the regulatory bodies then independently reviewed them. The exercise covered 147 nuclear plants in 15 EU countries – including Lithuania with only decommissioned plants – plus 15 reactors in Ukraine and five in Switzerland.

Operators reported to their regulators who then reported progress to the European Commission by the end of 2011. Information was shared among regulators throughout this process before the 17 final reports went to peer-review by teams comprising 80 experts appointed by ENSREG and the European Commission. The final documents were published in line with national law and international obligations, subject only to not jeopardising security – an area where each country could behave differently. The process was extended to June 2012 to allow more plant visits and to add more information on the potential effect of aircraft impacts.

The European Commission adopted, with ENSREG, the final stress tests Report on April 26, 2012 and issued the same day a joint statement underlining the quality of the exercise. The full report and a summary of the 45 recommendations were published on www.ensreg.eu. Drawing on the peer reviews, the EC and ENSREG cited four main areas for improving EU nuclear plant safety:

  • Guidance from WENRA for assessing natural hazards and margins beyond design basis.
  • Giving more importance to periodic safety reviews and evaluation of natural hazards.
  • Urgent measures to protect containment integrity.
  • Measures to prevent and mitigate accidents resulting from extreme natural hazards.

The results of the stress tests pointed out, in particular, that European nuclear power plants offered a sufficient safety level to require no shutdown of any of them. At the same time, improvements were needed to enhance their robustness to extreme situations. In France, for instance, they were imposed by ASN requirements, which took into account exchanges with its European counterparts. A follow-up European action plan was established by ENSREG from July 2012.

The EU process was completed at the end of September 2012, with the EU Energy Commissioner announcing that the stress tests had showed that the safety of European power reactors was generally satisfactory, but making some other comments and projections which departed from ENSREG. An EC report was presented to the EU Council in October 2012.

In the USA the Nuclear Regulatory Commission (NRC) in March 2012 made orders for immediate post-Fukushima safety enhancements, likely to cost about $100 million across the whole US fleet. The first order requires the addition of equipment at all plants to help respond to the loss of all electrical power and the loss of the ultimate heat sink for cooling, as well as maintaining containment integrity. Another requires improved water level and temperature instrumentation on used fuel ponds. The third order applies only to the 33 BWRs with early containment designs, and will require 'reliable hardened containment vents' which work under any circumstances. The industry association, NEI, told the NRC that licensees with these Mark I and Mark II containments “should have the capability to use various filtration strategies to mitigate radiological releases” during severe events, and that filtration “should be founded on scientific and factual analysis and should be performance-based to achieve the desired outcome.” All the measures are supported by the industry association, which has also proposed setting up about six regional emergency response centres under NRC oversight with additional portable equipment.

In Japan similar stress tests were carried out in 2011 under the previous safety regulator, but then reactor restarts were delayed until the newly constituted Nuclear Regulatory Authority devised and published new safety guidelines, then applied them progressively through the fleet.

Severe Accident Management

In addition to engineering and procedures which reduce the risk and severity of accidents, all plants have guidelines for Severe Accident Management or Mitigation (SAM). These conspicuously came into play after the Fukushima accident, where staff had immense challenges in the absence of power and with disabled cooling systems following damage done by the tsunami. The experience following that accident is being applied not only in design but also in such guidelines, and peer reviews on nuclear plants will focus more on these than previously.

In mid-2011 the IAEA Incident and Emergency Centre launched a new secure web-based communications platform to unify and simplify information exchange during nuclear or radiological emergencies. The Unified System for Information Exchange on Incidents and Emergencies (USIE) has been under development since 2009 but was actually launched during the emergency response to the accident at Fukushima.

Earthquakes and Volcanoes

The International Atomic Energy Agency (IAEA) has a Safety Guide on Seismic Risks for Nuclear Power Plants, and the matter is dealt with in the WNA paper on Earthquakes and Nuclear Power Plants. Volcanic hazards are minimal for practically all nuclear plants, but the IAEA has developed a new Safety Guide on the matter. The Bataan plant in Philippines which has never operated, and the Armenian plant at Metsamor are two known to be in proximity to potential volcanic activity.

Flooding – storms, tides and tsunamis

Nuclear plants are usually built close to water bodies, for the sake of cooling. The site licence takes account of worst case flooding scenarios as well as other possible natural disasters and, more recently, the possible effects of climate change. As a result, all the buildings with safety-related equipment are situated on high enough platforms so that they stand above submerged areas in case of flooding events. As an example, French Safety Rules criteria for river sites define the safe level as above a flood level likely to be reached with one chance in one thousand years, plus 15%, and similar regarding tides for coastal sites.

Occasionally in the past some buildings have been sited too low, so that they are vulnerable to flood or tidal and storm surge, so engineered countermeasures have been built. EDF's Blayais nuclear plant in western France uses seawater for cooling and the plant itself is protected from storm surge by dykes. However, in 1999 a 2.5 m storm surge in the estuary overtopped the dykes – which were already identified as a weak point and scheduled for a later upgrade – and flooded one pumping station. For security reasons it was decided to shut down the three reactors then under power (the fourth was already stopped in the course of normal maintenance). This incident was rated 2 on the INES scale.

In 1994 the Kakrapar nuclear power plant near the west coast of India was flooded due to heavy rains together with failure of weir control for an adjoining water pond, inundating turbine building basement equipment. The back-up diesel generators on site enabled core cooling using fire water, a backup to process water, since the offsite power supply failed. Following this, multiple flood barriers were provided at all entry points, inlet openings below design flood level were sealed and emergency operating procedures were updated. In December 2004 the Madras NPP and Kalpakkam PFBR site on the east coast of India was flooded by a tsunami surge from Sumatra. Construction of the Kalpakkam plant was just beginning, but the Madras plant shut down safely and maintained cooling. However, recommendations including early warning system for tsunami and provision of additional cooling water sources for longer duration cooling were implemented.

In March 2011 the Fukushima Daiichi nuclear plant was affected seriously by a huge tsunami induced by the Great East Japan Earthquake. Three of the six reactors were operating at the time, and had shut down automatically due to the earthquake. The back-up diesel generators for those three units were then swamped by the tsunami. This cut power supply and led to weeks of drama and loss of the reactors. The design basis tsunami height was 5.7 m for Daiichi (and 5.2 m for adjacent Daini, which was actually set a bit higher above sea level). Tsunami heights coming ashore were about 14 metres for both plants. Unit 3 of Daini was undamaged and continued to cold shutdown status, but the other units suffered flooding to pump rooms where equipment transfers heat from the reactor circuit to the sea – the ultimate heat sink.

The maximum amplitude of this tsunami was 23 metres at point of origin, about 160 km from Fukushima. In the last century there had been eight tsunamis in the Japan region with maximum amplitudes above 10 metres (some much more), these having arisen from earthquakes of magnitude 7.7 to 8.4, on average one every 12 years. Those in 1983 and in 1993 were the most recent affecting Japan, with maximum heights 14.5 metres and 31 metres respectively, both induced by magnitude 7.7 earthquakes. This 2011 earthquake was magnitude 9.

For low-lying sites, civil engineering and other measures are normally taken to make nuclear plants resistant to flooding. Lessons from Blayais have fed into regulatory criteria since 2000, and those from Fukushima will certainly do so. Sea walls are being built or increased at Hamaoka, Shimane, Mihama, Ohi, Takahama, Onagawa, and Higashidori plants. However, few parts of the world have the same tsunami potential as Japan, and for the Atlantic and Mediterranean coasts of Europe the maximum amplitude is much less than Japan.

Hydrogen

In any light-water nuclear power reactor, hydrogen is formed by radiolytic decomposition of water. This needs to be dealt with to avoid the potential for explosion with oxygen present, and many reactors have been retrofitted with passive autocatalytic hydrogen recombiners in their containment, replacing external recombiners that needed to be connected and powered, isolated behind radiological barriers. Also in some kinds of reactors, particularly early boiling water types, the containment is rendered inert by injection of nitrogen. It was reported that WANO may require all operators to have hydrogen recombiners in PWRs. As of early 2012, a few in Spain and Japan did not have them.

In an accident situation such as at Fukushima where the fuel became very hot, a lot of hydrogen is formed by the oxidation of zirconium fuel cladding in steam at about 1300°C. This is beyond the capability of the normal hydrogen recombiners to deal with, and operators must rely on venting to atmosphere or inerting the containment with nitrogen.

International collaboration to improve safety

There is a lot of international collaboration, but it has evolved from the bottom, and only in 1990s has there been any real top-down initiative. In the aviation industry the Chicago Convention in the late 1940s initiated an international approach which brought about a high degree of design collaboration between countries, and the rapid universal uptake of lessons from accidents. There are cultural and political reasons for this which mean that even the much higher international safety collaboration since the 1990s is still less than in aviation. See also: paper on Cooperation in Nuclear Power Industry, especially for fuller description of WANO, focused on operation.

World Association of Nuclear Operators

There is a great deal of international cooperation on nuclear safety issues, in particular the exchange of operating experience under the auspices of the World Association of Nuclear Operators (WANO) which was set up in 1989.  In practical terms this is the most effective international means of achieving very high levels of safety through its four major programs: peer reviews; operating experience; technical support and exchange; and professional and technical development. WANO peer reviews are the main proactive way of sharing experience and expertise, and by the end of 2009 every one of the world's commercial nuclear power plants had been peer-reviewed at least once.  Following the Fukushima accident these have been stepped up to one every four years at each plant, with follow-up visits in between, and the scope extended from operational safety to include plant design upgrades. Pre-startup reviews of new plants are being increased.

IAEA Convention on Nuclear Safety

The IAEA Convention on Nuclear Safety (CNS) was drawn up during a series of expert level meetings from 1992 to 1994 and was the result of considerable work by Governments, national nuclear safety authorities and the IAEA Secretariat. Its aim is to legally commit participating States operating land-based nuclear power plants to maintain a high level of safety by setting international benchmarks to which States would subscribe.

The obligations of the Parties are based to a large extent on the principles contained in the IAEA Safety Fundamentals document The Safety of Nuclear Installations. These obligations cover for instance, siting, design, construction, operation, the availability of adequate financial and human resources, the assessment and verification of safety, quality assurance and emergency preparedness.

The Convention is an incentive instrument. It is not designed to ensure fulfillment of obligations by Parties through control and sanction, but is based on their common interest to achieve higher levels of safety. These levels are defined by international benchmarks developed and promoted through regular meetings of the Parties. The Convention obliges Parties to report on the implementation of their obligations for international peer review. This mechanism is the main innovative and dynamic element of the Convention.  Under the Operational Safety Review Team (OSART) program dating from 1982 international teams of experts conduct in-depth reviews of operational safety performance at a nuclear power plant. They review emergency planning, safety culture, radiation protection, and other areas. OSART missions are on request from the government, and involve staff from regulators, in these respects differing from WANO peer reviews.

The Convention entered into force in October 1996. As of September 2009, there were 79 signatories to the Convention, 66 of which are contracting parties, including all countries with operating nuclear power plants.

The IAEA General Conference in September 2011 unanimously endorsed the Action Plan on Nuclear Safety that Ministers requested in June. The plan arose from intensive consultations with Member States but not with industry, and was described as both a rallying point and a blueprint for strengthening nuclear safety worldwide. It contains suggestions to make nuclear safety more robust and effective than before, without removing the responsibility from national bodies and governments. It aims to ensure "adequate responses based on scientific knowledge and full transparency". Apart from strengthened and more frequent IAEA peer reviews (including those of regulatory systems), most of the 12 recommended actions are to be undertaken by individual countries and are likely to be well in hand already.

Following this, an extraordinary general meeting of 64 of the CNS parties in September 2012 gave a strong push to international collaboration in improving safety. National reports at future three-yearly CNS review meetings will cover a list of specific design, operational and organizational issues stemming from Fukushima lessons. They include further design features to avoid long-term offsite contamination and enhancement of emergency preparedness and response measures, including better definition of national responsibilities and improved international cooperation. Parties should also report on measures to "ensure the effective independence of the regulatory body from undue influence."

In February 2015 diplomats from 72 countries unanimously adopted the Vienna Declaration of Nuclear Safety, setting out “principles to guide them, as appropriate, in the implementation of the objective of the CNS to prevent accidents with radiological consequences and mitigate such consequences should they occur” but rejected Swiss amendments to the CNS as impractical. However, in line with Swiss and EU intentions, "comprehensive and systematic safety assessments are to be carried out periodically and regularly for existing installations throughout their lifetime in order to identify safety improvements... Reasonably practicable or achievable safety improvements are to be implemented in a timely manner."

IAEA Design Safety Reviews and Generic Reactor Safety Reviews

An IAEA Design Safety Review (DSR) is performed at the request of a member state organization to evaluate the completeness and comprehensiveness of a reactor's safety documentation by an international team of senior experts. It is based on IAEA published safety requirements. If the DSR is for a vendor’s design at the pre-licensing stage, it is done using the Generic Reactor Safety Review (GRSR) module. IAEA Safety Standards applied in the DSR and GRSR at the fundamental and requirements level, are generic and apply to all nuclear installations. Therefore, it is neither intended nor possible to cover or substitute licensing activity, or to constitute any kind of design certification.

DSRs have been undertaken in Pakistan, Ukraine, Bulgaria and Armenia. GRSRs have been done on AP1000 (USA & UK), Atmea1, APR1400, ACPR-1000+, ACP1000, and AES-2006 and VVER-TOI.

Eastern Europe from 1980s

In relation to Eastern Europe particularly, since the late 1980s a major international program of assistance was carried out by the OECD, IAEA and Commission of the European Communities to bring early Soviet-designed reactors up to near western safety standards, or at least to effect significant improvements to the plants and their operation. The European Union also brought pressure to bear, particularly in countries which aspired to EU membership.

Modifications were made to overcome deficiencies in the 11 RBMK reactors still operating in Russia. Among other things, these removed the danger of a positive void coefficient response. Automated inspection equipment has also been installed in these reactors.

The other class of reactors which has been the focus of international attention for safety upgrades is the first-generation of pressurised water VVER-440 reactors. The V-230 model was designed before formal safety standards were issued in the Soviet Union and they lack many basic safety features. Four are still operating in Russia and one in Armenia, under close inspection.

Later Soviet-designed reactors are very much safer and have Western control systems or the equivalent, along with containment structures.

Europe since 1999

The main European safety collaboration is through the European Nuclear Safety Regulators Group (ENSREG), an independent, authoritative expert body created in 2007 by the European Commission to revive the EU nuclear safety directive, which was passed in June 2009. It comprises senior officials from the national nuclear safety, radioactive waste safety or radiation protection regulatory authorities from all 27 EU member states, and representatives of the European Commission. It was preceded in 1999 by the Western European Nuclear Regulators' Association (WENRA), a network of Chief Regulators of EU countries with nuclear power plants and Switzerland, with membership from 17 countries.

Ageing of nuclear plants; knowledge management

Engineering

Several issues arise in prolonging the lives of nuclear plants which were originally designed for nominal 30- or 40-year operating lives. Systems, structures and components (SSC) whose characteristics change gradually with time or use are the subject of attention, which is applied with vastly greater scientific and technical knowledge than that available to the original designers many decades ago.

Some components simply wear out, corrode or degrade to a low level of efficiency. These need to be replaced. Steam generators are the most prominent and expensive of these, and many have been replaced after about 30 years where the reactor otherwise has the prospect of running for 60 years. This is essentially an economic decision. Lesser components are more straightforward to replace as they age, and some may be safety-related as well as economic.

In PHWR units, notably CANDU reactors, pressure tube replacement has been undertaken on some older plants, after some 30 years of operation. Fuel channel integrity is another limiting factor for Candu reactors, and mid-life inspection and analysis can extend the original 175,000 full-power operating hours design assumption to 300,000 hours.

A second issue is that of obsolescence. For instance, older reactors have analogue instrument and control systems, and a question must be faced regarding whether these are replaced with digital in a major mid-life overhaul, or simply maintained.

Thirdly, the properties of materials may degrade with age, particularly with heat and neutron irradiation. In some early Russian pressurized water reactors, the pressure vessel is relatively narrow and is thus subject to greater neutron bombardment that a wider one. This raises questions of embrittlement, and has had to be checked carefully before extending licences.

In some Russian and UK plants (RBMK, AGR), graphite is used as the moderator. The graphite blocks cannot be replaced during the operating life of the reactors. However, radiation damage changes the shape and size of the crystallites that comprise graphite, giving some dimensional change and degradation of the structural properties of the graphite. For continued operation, it is therefore necessary to demonstrate that the graphite can still perform its intended role irrespective of the degradation, or undergo some repair. In Russia, after dismantling the pressure tubes, longitudinal cutting of a limited number of deformed graphite columns returns the graphite stack geometry to a condition that meets the initial design requirements. Leningrad 1 was the first RBMK reactor to undergo this over 2012-13.

In respect to all these aspects, periodic safety reviews are undertaken on most older plants in line with the IAEA safety convention and WANO's safety culture principles to ensure that safety margins are maintained. The IAEA undertakes Safety Aspects of Long-Term Operation (SALTO) evaluations of reactors on request from member countries. These SALTO missions check both physical and organizational aspects, and function as an international peer review of the national regulator. They are backed up by the IAEA International Generic Ageing Lessons Learned (IGALL) program which is documented in databases and publications, in the form of downloadable safety guides and reports on ageing.

Equipment performance is constantly monitored to identify faults and failures of components. Preventative maintenance is adapted and scheduled in the light of this, to ensure that the overall availability of systems important for both safety and plant availability are within the design basis, or better than the original design basis. Collecting reliability and performance data is of the utmost importance, as well as analysing them, for tracking indicators that might be signs of ageing, or indicative of potential problems having been under-estimated, or of new problems. The results of this monitoring and analysis are often shared Industry-wide through INPO and WANO networks. The use of probabilistic safety analysis makes possible risk-informed decisions regarding maintenance and monitoring programs, so that adequate attention is given to the health of every piece of equipment in the plant. This process is similar to that in other industries where safety is paramount, eg aviation. Reliability Centered Maintenance was adapted from civil aviation in the 1980s for instance, and led to nuclear industry review of existing maintenance programs.

In the USA most of the one hundred reactors are expected to be granted licence extensions from 40 to 60 years. This justifies significant capital expenditure in upgrading systems and components, including building in extra performance margins. There is widespread agreement that further extensions may be justified, to 80 years, and this prospect is driving research on ageing to ensure both safety and reliability in older plants.

Knowledge management

The IAEA has a safety knowledge base for ageing and long-term operation of nuclear power plants (SKALTO) which aims to develop a framework for sharing information on ageing management and long term operation of nuclear power plants. It provides published documents and information related to this.

Knowledge management in relation to the original design basis of reactors becomes an issue with corporate reorganisation or demise of vendors, coupled with changes made over several decades. While operators usually have good records, some regulators do not. Design Basis Knowledge Management (DKM) is an issue receiving a lot of attention in the last ten years or so.

Nuclear DKM addresses the specific needs of nuclear plants and organizations. Its scope extends from research and development, through design and engineering, construction, commissioning, operations, maintenance, refurbishment and long-term operation (LTO), waste management, to decommissioning. Nuclear DKM issues and priorities are often unique to the particular circumstances of individual countries and their regulators as well as other nuclear industry organizations. Nuclear DKM may focus on knowledge creation, identification, sharing, transfer, protection, validation, storage, dissemination, preservation or utilization. Nuclear DKM practices may enhance and support traditional business functions and goals such as human resource management, training, planning, operations, maintenance, and much more.

There must always be a responsible owner of the DKM system for any plant. In most cases this will be the operator, however, based on a variety of changes such as market conditions, the responsible owner may change over time. An effective nuclear DKM system should be focused on strengthening and aligning the knowledge base in three primary knowledge domains in an organization: people, processes and technology, each of which must also be considered within the context of the organizational culture. Knowledge management policies and practices should help create a supportive organizational culture that recognizes the value of nuclear knowledge and promotes effective processes to maintain it.

In Canada, the Pickering A – Bruce A saga is a cautionary tale (and classic industry case study) regarding DKM. By the mid-1990s there was a divergence between drawings and modifications which had progressively been made, and also the operating company had not shared operating experience with the designer. Maintenance standards fell and costs rose. A detailed audit in 1997-98 showed that the design basis was not being maintained and that 4000 additional staff would be required to correct the situation at all Ontario Hydro plants, so the two A plants (eight units) were shut down so that staff could focus on the 12 units not needing so much attention. From 2003, six of the eight A units were returned to service with design basis corrected, having been shut down for several years – a significant loss of asset base for the owners.

Reporting nuclear incidents

The International Nuclear Event Scale (INES) was developed by the IAEA and OECD in 1990 to communicate and standardise the reporting of nuclear incidents or accidents to the public. The scale runs from a zero event with no safety significance to 7 for a "major accident" such as Chernobyl. Three Mile Island rated 5, as an "accident with off-site risks" though no harm to anyone, and a level 4 "accident mainly in installation" occurred in France in 1980, with little drama. Another accident rated at level 4 occurred in a fuel processing plant in Japan in September 1999.  Other accidents have been in military plants .

The International Nuclear Event Scale 
For prompt communication of safety significance

Level, Descriptor Off-Site Impact, release of radioactive materials On-Site Impact Defence-in-Depth Degradation Examples
7
Major Accident
Major Release:
Widespread health and environmental effects
    Chernobyl, Ukraine, 1986 (fuel meltdown and fire); 
Fukushima Daiichi 1-3, 2011 (fuel damage, radiation release and evacuation)
6
Serious Accident
Significant Release:
Full implementation of local emergency plans
    Mayak at Ozersk, Russia, 1957 'Kyshtym' (reprocessing plant criticality)
5
Accident with Off-Site Consequences
Limited Release:
Partial implementation of local emergency plans, or
Severe damage to reactor core or to radiological barriers   Three Mile Island, USA, 1979 (fuel melting);
Windscale, UK, 1957 (military)
 
4
Accident Mainly in Installation, with local consequences.
either of:
Minor Release:
Public exposure of the order of prescribed limits, or
Significant damage to reactor core or to radiological barriers; worker fatality   Saint-Laurent A1, France, 1969 (fuel rupture) & A2 1980 (graphite overheating);
Tokai-mura, Japan, 1999 (criticality in fuel plant for an experimental reactor).
3
Serious Incident
any of:
Very Small Release:
Public exposure at a fraction of prescribed limits, or
Major contamination; Acute health effects to a worker, or Near Accident:
Loss of Defence in Depth provisions - no safety layers remaining
Fukushima Daiichi 4, 2011 (fuel pond overheating);
Fukushima Daini 1, 2, 4, 2011 (interruption to cooling); 
Vandellos, Spain, 1989 (turbine fire); 
Davis-Besse, USA, 2002 (severe corrosion);
Paks, Hungary 2003 (fuel damage)
2
Incident
nil Significant spread of contamination; Overexposure of worker, or Incidents with significant failures in safety provisions  
1
Anomaly
nil nil Anomaly beyond authorised operating regime  
0
Deviation
nil nil No safety significance  
Below Scale nil nil No safety relevance  

Source: International Atomic Energy Agency

Security – terrorism, etc

Since the World Trade Centre attacks in New York in 2001 there has been increased concern about the consequences of a large aircraft being used to attack a nuclear facility with the purpose of releasing radioactive materials. Various studies have looked at similar attacks on nuclear power plants. They show that nuclear reactors would be more resistant to such attacks than virtually any other civil installations – see Appendix 3. A  thorough study was undertaken by the US Electric Power Research Institute (EPRI) using specialist consultants and paid for by the US Dept. of Energy. It concludes that US reactor structures "are robust and (would) protect the fuel from impacts of large commercial aircraft".

The analyses used a fully-fuelled Boeing 767-400 of over 200 tonnes as the basis, at 560 km/h – the maximum speed for precision flying near the ground. The wingspan is greater than the diameter of reactor containment buildings and the 4.3 tonne engines are 15 metres apart. Hence analyses focused on single engine direct impact on the centreline – since this would be the most penetrating missile – and on the impact of the entire aircraft if the fuselage hit the centreline (in which case the engines would ricochet off the sides). In each case no part of the aircraft or its fuel would penetrate the containment. Other studies have confirmed these findings.

Penetrating (even relatively weak) reinforced concrete requires multiple hits by high speed artillery shells or specially-designed "bunker busting" ordnance – both of which are well beyond what terrorists are likely to deploy. Thin-walled, slow-moving, hollow aluminum aircraft, hitting containment-grade heavily-reinforced concrete disintegrate, with negligible penetration. But further (see Sept 2002 Science paper and Jan 2003 Response & Comments), realistic assessments from decades of analyses, lab work and testing, find that the consequence of even the worst realistic scenarios – core melting and containment failure – can cause few if any deaths to the public, regardless of the scenario that led to the core melt and containment failure. This conclusion was documented in a 1981 EPRI study, reported and widely circulated in many languages, by Levenson and Rahn inNuclear Technology.

In 1988 Sandia National Laboratories in USA demonstrated the unequal distribution of energy absorption that occurs when an aircraft impacts a massive, hardened target. The test involved a rocket-propelled F4 Phantom jet (about 27 tonnes, with both engines close together in the fuselage) hitting a 3.7m thick slab of concrete at 765 km/h. This was to see whether a proposed Japanese nuclear power plant could withstand the impact of a heavy aircraft. It showed how most of the collision energy goes into the destruction of the aircraft itself – about 96% of the aircraft's kinetic energy went into the its destruction and some penetration of the concrete – while the remaining 4% was dissipated in accelerating the 700-tonne slab. The maximum penetration of the concrete in this experiment was 60 mm, but comparison with fixed reactor containment needs to take account of the 4% of energy transmitted to the slab. See also video clip.

As long ago as the late 1970s, the UK Central Electricity Generating Board considered the possibility of a fully-laden and fully-fuelled large passenger aircraft being hijacked and deliberately crashed into a nuclear reactor. The main conclusions were that an airliner would tend to break up as it hit various buildings such as the reactor hall, and that those pieces would have little effect on the concrete biological shield surrounding the reactor. Any kerosene fire would also have little effect on that shield. In the 1980s in the USA, at least some plants were designed to take a hit from a fully-laden large military transport aircraft and still be able to achieve and maintain cold shutdown.

The study of a 1970s US power plant in a highly-populated area is assessing the possible effects of a successful terrorist attack which causes both meltdown of the core and a large breach in the containment structure – both extremely unlikely. It shows that a large fraction of the most hazardous radioactive isotopes, like those of iodine and tellurium, would never leave the site.
Much of the radioactive material would stick to surfaces inside the containment or becomes soluble salts that remain in the damaged containment building. Some radioactive material would nonetheless enter the environment some hours after the attack in this extreme scenario and affect areas up to several kilometres away. The extent and timing of this means that with walking-pace evacuation inside this radius it would not be a major health risk. However it could leave areas contaminated and hence displace people in the same way as a natural disaster, giving rise to economic rather than health consequences.

Looking at spent fuel storage pools, similar analyses showed no breach. Dry storage and transport casks retained their integrity. "There would be no release of radionuclides to the environment".

Similarly, the massive structures mean that any terrorist attack even inside a plant (which are well defended) and causing loss of cooling, core melting and breach of containment would not result in any significant radioactive releases.

However, while the main structures are robust, the 2001 attacks did lead to increased security requirements and plants were required by NRC to install barriers, bulletproof security stations and other physical modifications which in the USA are estimated by the industry association to have cost some $2 billion across the country.

See also Science magazine article 2002 and Appendix 3.

Switzerland's Nuclear Safety Inspectorate studied a similar scenario and reported in 2003 that the danger of any radiation release from such a crash would be low for the older plants and extremely low for the newer ones.

The conservative design criteria which caused most power reactors to be shrouded by massive containment structures with biological shield has provided peace of mind in a suicide terrorist context. Ironically and as noted earlier, with better understanding of what happens in a core melt accident inside, they are now seen to be not nearly as necessary in that accident mitigation role as was originally assumed.

Advanced reactor designs

The designs for nuclear plants being developed for implementation in coming decades contain numerous safety improvements based on operational experience. The first two of these advanced reactors began operating in Japan in 1996.

One major feature they have in common (beyond safety engineering already standard in Western reactors) is passive safety systems, requiring no operator intervention in the event of a major malfunction.

The main metric used to assess reactor safety is the likelihood of the core melting due to loss of coolant. These new designs are one or two orders of magnitude less likely than older ones to suffer a core melt accident, but the significance of that is more for the owner and operator than the neighbours, who - as Three Mile Island and Fukushima showed - are safe also with older types. (As mentioned in the box above, studies related to the 1970s plant in USA show that even with a breach of containment as well, the consequences would not be catastrophic.)

Safety relative to other energy sources

Many occupational accident statistics have been generated over the last 40 years of nuclear reactor operations in the US and UK. These can be compared with those from coal-fired power generation. All show that nuclear is a distinctly safer way to produce electricity.

Deaths from energy-related accidents per unit of electricity

Deaths per TWh

Source: Paul Scherrer Institut 1998, considering 1943 accidents with more than five fatalities.

One TW.yr is the amount of electricity used by the world in about five months.

Coal-fired power generation has chronic, rather than acute, safety implications for public health. It also has profound safety implications for the mining of coal, with thousands of workers killed each year in coal mines (see Appendix).

Hydro power generation has a record of few but very major events causing thousands of deaths. In 1975 when the Banqiao, Shimantan & other dams collapsed in Henan, China, at least 30,000 people were killed immediately and some 230,000 overall, with 18 GWe lost. In 1979 and 1980 in India some 3500 were killed by two hydro-electric dam failures, and in 2009 in Russia 75 were killed by a hydro power plant turbine disintegration.

Three simple sets of figures are quoted in the Tables below and that in the appendix.  A major reason for coal's unfavourable showing is the huge amount which must be mined and transported to supply even a single large power station. Mining and multiple handling of so much material of any kind involves hazards, and these are reflected in the statistics.

Summary of severe* accidents in energy chains for electricity 1969-2000

  OECD   Non-OECD  
Energy chain Fatalities Fatalities/TWy Fatalities Fatalities/TWy
Coal  2259 157 18,000 597
Natural gas 1043 85 1000 111
Hydro 14 3 30,000 10,285
Nuclear 0 0 31 48

Data from Paul Scherrer Institut, in OECD 2010. * severe = more than five fatalities

Comparison of accident statistics in primary energy production
(Electricity generation accounts for about 40% of total primary energy)

Fuel Immediate fatalities
1970-92
Who? Normalised to deaths
per TWy* electricity
Coal
6400
workers
342
Natural gas
1200
workers & public
85
Hydro
4000
public
883
Nuclear
31
workers
8

* Basis: per million MWe operating for one year, not including plant construction, based on historic data which is unlikely to represent current safety levels in any of the industries concerned.
Sources: Sources: Ball, Roberts & Simpson, 1994; Hirschberg et al, Paul Scherrer Institut 1996, in: IAEA 1997; Paul Scherrer Institut, 2001.

 

In the UK, Friends of the Earth commissioned a study by the Tyndall Centre, which drew primarily on peer-reviewed academic literature, supplemented by literature from credible government, consultancy and policy sources. It concluded in January 2013 that “Overall the safety risks associated with nuclear power appear to be more in line with lifecycle impacts from renewable energy technologies, and significantly lower than for coal and natural gas per MWh of supplied energy.”

  • The USA is the world's largest producer of nuclear power, accounting for more than 30% of worldwide nuclear generation of electricity.
  • The country's 100 nuclear reactors produced 798 billion kWh in 2015, over 19% of total electrical output. There are four reactors under construction.
  • Following a 30-year period in which few new reactors were built, it is expected that four more new units will come online by 2021, these resulting from 16 licence applications made since mid-2007 to build 24 new nuclear reactors.
  • Government policy changes since the late 1990s have helped pave the way for significant growth in nuclear capacity. 
  • Some states have liberalized wholesale electricity markets, which makes the financing of capital-intensive power projects difficult, and coupled with lower gas prices since 2009, have put the economic viability of some existing reactors and proposed projects in doubt.
  • South Africa has two nuclear reactors generating 5% of its electricity.
  • South Africa's first commercial nuclear power reactor began operating in 1984.
  • Government commitment to the future of nuclear energy is strong, with firm plans for further 9600 MWe progressively in the next decade, but financial constraints are severe.
  • Construction of a demonstration pebble bed modular reactor has been cancelled.

Electricity consumption in South Africa has been growing rapidly since 1980 and the country is part of the Southern African Power Pool (SAPP), with extensive interconnections. Total installed generating capacity in the SAPP countries is 54.7 GWe, of which around 80% is South African1, mostly coal-fired, and largely under the control of the state utility Eskom.

Eskom supplies about 95% of South Africa's electricity and approximately 45% of Africa's. Of its total installed net capacity of 40.5 GWe (44.2 GWe gross), coal-fired stations account for 34.3 GWe and nuclear 1.8 GWe2. Early in 2008, demand in South Africa was uncomfortably close to thisa. In 2008, Eskom power stations produced 230.0 billion kWh (TWh) of electricity (out of total South African electricity production of 239.5 TWh), of which the Koeberg nuclear plant generated 12.7 TWh – about 5.3% of total South African generation3.

In 2014 the country produced 253 TWh, this being 232 TWh from coal, 14 TWh from nuclear and 4 TWh from hydro. That year it imported 11 TWh and exported 14 TWh. Consumption was about 4800 kWh per capita.

Over the five years to March 2013, Eskom planned to spend R385 billion (around US$ 50 billion) on new capacity – mainly coal- and gas-fired plants, as well as on returning mothballed coal-fired stations to service. Eskom said the country needs 40 GWe of new generation by 2025, about half of which should be nuclear. In the meantime the country remains heavily dependent on coal, with power plants built near the mines, and the two largest coal-fired plants in the world under construction – 4800 MWe each. Also the country gets 40% of its oil/gasoline needs from coal-to-liquids plants.

In October 2010, the Department of Energy released its draft Integrated Electricity Resource Plan (IRP) for 2010-2030. The IRP outlines the country’s electricity demand, how this demand might be supplied, and what it is likely to cost. Its balanced scenario represents the best trade-off between least-investment cost, climate change mitigation, diversity of supply, localization, and regional development. The IRP requires 52 GWe of new capacity by 2030, assuming 3.4 GWe of demand-side savings. After public consultation the IRP was revised early in 2011 and passed by cabinet in March. According to this scenario, South Africa’s generation mix by 2030 should include: 48% coal; 13.4% nuclear; 6.5% hydro, 14.5% other renewables; and 11% peaking open cycle gas turbine. Although nuclear is included in the energy mix only from 2023, a decision on this "must be finalized as quickly as possible" and a procurement process set up. At least 9.6 GWe new nuclear capacity by 2030 is included in the plan confirmed in mid-2011, significantly less than the 2007 target. In December 2013 the projected 2030 demand was reduced by 6600 MWe to no more than 61.2 GWe.

In the May 2011 budget speech the energy minister reaffirmed that 22% of new generating capacity by 2030 would be nuclear and 14% coal-fired. The budget also provided R586 million ($85 million) for the Nuclear Energy Corporation of South Africa (Necsa) "to continue with its central role as the anchor for nuclear energy research and development and innovation."

The main discussion in the country has been on the need for base-load capacity, rather than specifically nuclear. The IRP remains as policy though the schedule has slipped.

Operating South African power reactors

Reactor Type Net capacity First power Planned closure
Koeberg 1 PWR 930 MWe April 1984 2024
Koeberg 2 PWR 900 MWe July 1985 2025
Total (2)   1830 MWe    

Nuclear industry development in South Africa

South Africa's main coal reserves are concentrated in Mpumalanga in the northeast, while much of the load is on the coast near Cape Town and Durban. Moving either coal or electricity long distance is inefficient, so it was decided in the mid-1970s to build some 1800 MWe of nuclear capacity at Koeberg near Cape Town.

The Koeberg plant was built by Framatome (now Areva) and commissioned in 1984-85. It is owned and operated by Eskom and has twin 900 MWe class (970 & 940 MWe gross) pressurised water reactors (PWRs), the same as those providing most of France's electricity. Stress tests similar to those in the EU were carried out in 2011 with IAEA help. The government plans to extend Koeberg’s operating life from 30 to 40 years, and Eskom solicited tenders for six new steam generators to be installed at Koeberg about 2017-18, aligned with planned maintenance. In August 2014 it awarded the contract to Areva, despite protests from Westinghouse.

The government announced early in 2006 that it was considering building a further conventional nuclear plant, possibly at Koeberg, to boost supplies in the Cape province.

Then early in 2007, the Eskom board approved a plan to double generating capacity to 80 GWe by 2025, including construction of 20 GWe of new nuclear capacity so that nuclear contribution to power would rise from 5% to more than 25% and coal's contribution would fall from 87% to below 70%. The new program would start with up to 4 GWe of PWR capacity to be built from about 2010, with the first unit commissioned in 2016. The environmental assessment process for the so-called 'Nuclear-1' project considering five sites, and selection of technology was to follow in 2008. Areva's EPR and Westinghouse AP1000 were short-listed. Areva headed a consortium of South African engineering group Aveng, the French construction group Bouygues and EDF which submitted a bid to supply two 1600 MWe EPR units. Westinghouse matched this with a bid of three 1134 MWe AP1000 units. The Westinghouse-led consortium included The Shaw Group and the South African engineering firm Murray & Roberts.

Areva and Westinghouse also offered to build the full 20 GWe – with a further ten large EPR units or 17 AP1000 units by 2025. This would have been coupled with wider assistance for the local nuclear industry, in the Westinghouse case including development of the Pebble Bed Modular Reactor (Westinghouse was an investor in the PBMR company and also sponsored the design in the USA – see section on PBMR below).

However, in December 2008, Eskom announced that it would not proceed with either of the bids from Areva and Westinghouse, due to lack of finance, and the government confirmed a delay of several years4.

Proposed South African power reactors

Reactor Type Gross capacity Construction start First power
Thyspunt and/or Duynefontein
(total about 8)
VVER-TOI?
CAP1400?
9600 MWe   2024-2030

In the 2011 Draft Integrated Electricity Resource Plan for South Africa – 2010 to 2030 (IRP),5 nuclear prospects were revived, for 9600 MWe, supplying 23% of the electricity. In November 2011 the National Nuclear Energy Executive Coordination Committee (NNEECC) was established as the authority for decision-making, monitoring, and general oversight of the nuclear energy expansion program. An IAEA Integrated Nuclear Infrastructure Review (INIR) was carried out in 2013.

Although the draft IRP included six new 1600 MWe reactors coming online in 18-month intervals from 2023, Eskom has said that it would be looking for lower-cost options than the earlier AP1000 or EPR proposals, and would consider Generation II designs from China (perhaps CPR-1000) or South Korea (perhaps OPR). The capital cost per installed MWe of a CPR-1000 was said to be about half that of an AP1000 or EPR. Before approval, a safety report for the selected specific design must be submitted to the National Nuclear Regulator for evaluation and approval and a nuclear installation licence obtained. Following the Fukushima accident it is likely that a Generation III design will be favoured.

Early in 2011 Areva stepped up its involvement with the Nuclear Energy Corporation of South Africa (Necsa), and early in 2013 Rosatom declared its interest in bidding. Bids were expected to be called early in 2014 so that the contractor/vendor could be on site in 2016, with a view to 2023 operation of the first unit. Initially about 30% local content was expected in the project, rising to 40% later.

In November 2013 Necsa signed a broad agreement with Russia's NIAEP-Atomstroyexport and its subsidiary Nukem Technologies, to develop a strategic partnership including nuclear power plants and waste management, with financial assistance from Russia. It is uncertain just what this means, but Rosatom said that it “offers South Africa to build the entire process chain of NPP construction and operation.” “The strategic partnership implies joint implementation of the national nuclear power development program of South Africa. The key project is construction of new nuclear power plants with the Russian VVER reactors totaling 9.6 GW (up to eight power units) in South Africa. Besides, the parties intend to build a research reactor to the Russian technology, which would lay the basis for joint business in the area of isotope production and sales in the international market.”

“A small-scale analysis says that implementation of a NPP construction project will allow placing 40% up to 60% of equipment orders with the RSA companies, and this will give not less than US $16 billion at the stage of construction only, US $40 billion at the stage of operation; 15,000 up to 30,000 high-skill highly salaries jobs will be created. In the framework of our partnership we will be happy to invite RSA’s companies to the third country markets,” according to Rosatom. Finance was not mentioned then.

In September 2014 Rosatom signed an agreement with South Africa’s energy minister to advance the prospect of building up to 9.6 GWe of nuclear capacity by 2030. The minister said: “This agreement opens up the door for South Africa to access Russian technologies, funding, infrastructure, and provides proper and solid platform for future extensive collaboration." It is expected to involve some $10 billion in local supply chain provision, with localisation of up to 60%. Necsa later said that the new agreement "initiates a preparatory phase for the procurement process for the new nuclear build in South Africa. Similar agreements will be signed with other vendor countries that have expressed an interest in assisting South Africa with the build program...No vendor country has been chosen yet and no technology has been decided. The agreement refers only to what Russia could provide if chosen.” Rusatom Overseas confirmed the likelihood of a Russian government loan, and said that the build-own-operate (BOO) model was preferable. OKB Gidropress and NIAEP-ASE subsequently presented the VVER-TOI design as appropriate, each unit 1255 MWe gross, 1115 MWe net. The reported cost would be $6 billion for the first two units.

In October 2014 a nuclear cooperation agreement with France was signed. The energy minister said, "This paves the way for establishing a nuclear procurement process." Areva welcomed the agreement, and said that it was ready to support the development of new RSA nuclear projects, “notably through its Generation III+ EPR reactor technology."

In November 2014 a similar inter-governmental cooperation agreement was signed with China. The energy ministry said that the agreement "initiates the preparatory phase for a possible utilization of Chinese nuclear technology in South Africa." Three further agreements in December were between Necsa and China National Nuclear Corp (CNNC) to establish a cooperative partnership supporting the country’s nuclear industry, between China’s State Nuclear Power Technology Corp (SNPTC), the Industrial & Commercial Bank of China and South Africa's Standard Bank Group with a view to financing new nuclear plants, and between Necsa and SNPTC for training South African nuclear professional staff. In February 2015 Necsa signed a further skills development and training agreement with SNPTC and China General Nuclear Power Corp (CGN), funded up to 95% by China. CGN has had an office in Johannesburg since 2010.

Agreements with the USA and South Korea are in place, and a further agreement is pending with Japan.

Westinghouse has been active in South Africa's nuclear industry, mainly through support to Koeberg, since the 1990s. In October 2013 Westinghouse signed an agreement with the Sebata Group of engineering companies to prepare for ‘potential construction’ of new nuclear plants in RSA.

In March 2014 it was reported that China’s main nuclear power companies were lining up to bid for a $93 billion contract to build six reactors by 2030. China’s Ministry of Commerce reported that negotiations towards a nuclear cooperation agreement were proceeding. The Energy Minister said that this could involve the joint marketing and supply of nuclear energy products along with infrastructure funding to promote nuclear power developments across the region. SNPTC is focused on the possible supply of CAP1400 reactors. Chinese industry officials in December 2015 expressed confidence in securing the $80 billion order for CAP1400 units, though the first of these in China was not yet under construction.

The environmental impact assessment (EIA) process initiated in 2006 confirmed the selection of three possible sites for the next nuclear power units: Thyspunt, Bantamsklip, and Duynefontein, the last of which is very near the existing Koeberg nuclear plant. All are in the Cape region and were subject to further assessment. A draft environmental impact report (EIR) was published in March 2010 recommending the Thyspunt site in Eastern Cape province near Oyster Bay, Jeffrey’s Bay and a few kilometres west of Cape St Francis. Bantamsklip is east of Cape Town near Gansbai. A final EIR was to be submitted to the Department of Environmental Affairs early in 2011. In March 2016 Eskom submitted site licence applications to NNR for both Thyspunt and Duynefontein to construct and operate "multiple nuclear installations (power reactors) and associated auxiliary nuclear installations.”

The Renewable Energy Plan launched in October 2011 called for 17,800 MWe of "green" energy by 2030, and invited tenders for 1450 MWe of solar PV, 200 MWe of CSP, 1850 MWe of wind power, and various smaller contributions, total US$ 11 billion. In December 2011 the energy minister said that some $50 billion would be spent on nuclear capacity to 2030. The National Development Plan then cast doubt on nuclear power's financial viability, but in November 2012 the cabinet endorsed a "phased decision-making approach for implementation of the nuclear programme", along with the "designation of Eskom as the owner-operator as per the Nuclear Energy Policy of 2008".

The president’s annual state-of-the-nation address in February 2015 reaffirmed the 9.6 GWe target with the first unit on line in 2023 and said that bids would be sought from the USA, China, France, Russia and South Korea. In May, the energy minister said that the procurement process for the new nuclear power plant would begin by September, and she expected that a strategic partner would be selected by March 2016. Early in June Eskom ceded control of the new build programme to the Department of Energy.

Following cabinet approval in December 2015, the Department of Energy prepared to issue its request for proposals for 9600 MWe of nuclear power capacity. Five reactor vendors will be invited to make proposals: Rosatom, SNPTC, KEPCO, EDF/Areva and Westinghouse. Proposals should specify reactor design, the degree of localization, financing, and price. Funding will be decided following responses to this, and will be in line with the 2011 Integrated Resource Plan for Energy. Necsa stressed in September 2016 that the field was wide open and that an initial contract might be for up to three PWR units, about one-third of the total, with an operating reference plant in the country of origin. It did not want a BOO arrangement or a turnkey contract, but favoured a build-own-transfer model such as in the UAE.

PBMR

Over 1993 to 2010, Eskom (in collaboration with others since 1999b) was developing the Pebble Bed Modular Reactor (PBMR). It is a high-temperature gas-cooled reactor (HTR) design, for both electricity generation (through a steam turbine or direct cycle) and process heat applications. From 1999 to 2009, the South African government, Eskom, Westinghouse, and the Industrial Development Corporation of South Africa invested R9.244 billion (about US$ 1.3 billion) in the projectc. The original concept was for a 400 MWt direct (Brayton) cycle unit, but later a 200 MWt (80 MWe) steam cycle version was proposed.

In September 2010, the Minister of Public Enterprises announced that the Government would stop investing in the PBMR9. The Minister gave the following reasons for this decision:

  • No customer for the PBMR had been secured.
  • In addition to the R9.244 billion ($1.3 billion) already invested in the project over the previous decade, a further R30 billion ($4.2 billion) or more was needed.
  • The project has consistently missed deadlines.
  • The opportunity to participate in the USA’s Next Generation Nuclear Plant (NGNP) program had been lost (see below).
  • Any new nuclear build program in South Africa would use Generation II or III technology. (The PBMR is considered a Generation IV technology.)
  • Government spending had to be reprioritized in the light of the economic downturn.

The project had received a certain amount of interest, but not enough to secure the financing it required. The domestic need in South Africa is for larger units.

Further information is in the Appendix below.

Eskom is managing the PBMR assets. The main PBMR test facilities (fuel development laboratory and helium test facility) are in care and maintenance. The government is concerned to protect the intellectual property involved.

An August 2013 application for federal US funds from National Project Management Corporation (NPMC) in the USA is for an HTR of 165 MWe, apparently the earlier direct-cycle version of the PBMR, emphasising its ‘deep burn’ attributes in destroying actinides and achieving high burn-up at high temperatures.

Uranium mining in South Africa

Uranium production in South Africa has generally been a by-product of gold or copper mining.

In 1951, a company was formed to exploit the uranium-rich slurries from gold mining and in 1967 this function was taken over by Nuclear Fuels Corporation of South Africa (Nufcor), which in 1998 became a subsidiary of AngloGold Ltd, now Anglo Gold Ashanti. Over nearly 30 years to 1980 it had produced some 100,00 tonnes of uranium oxide from varied feed, at a peak rate of almost 6000 t/yr in 1960. The plant is 60 km west of Johannesburg, adjacent to West Rand mines, in Gauteng province. It produces over 600 tonnes U3O8 per year from uranium slurries such as ammonium diuranate (yellowcake) trucked in from various gold mines and the Palabora copper mine. In May 2009 AngloGold announced plans to construct a new uranium recovery plant at its Kopanang mine to lift production to 900 t/yr from 2012.

The road tankers in Nufcor's fleet have two separate stainless steel compartments, each with capacity for about 25 tonnes of ammonium diuranate (ADU) as an aqueous slurry, containing the equivalent of about 7.8 t of U3O8 (earlier: 13 t and 3.5 t respectively).

There are about 400 tailings dams and dumps arising from gold mining in the Witwatersrand area of Gauteng province, and much of the available uranium today is in these. There are further tailings near Klerksdorp, close to the Vaal River. There is some radionuclide and heavy metal pollution arising from some of these and acid mine drainage. Many of the tailings dams and dumps are being re-treated to recover gold and sometimes uranium.

Uranium Production - tonnes U

  2011 2012 2013 2014 2015
Ezulwini-Cooke 34 0 0 69 47
Vaal River 548 465 531 504 346
Total 582 465 531 573 393

Much of the productive and prospective ground for uranium as gold by-product is in the Witwatersrand Basin, an area about 330 km x 150 km south and southwest of Johannesburg. Klerksdorp, Welkom, Carltonville, Parys and Evander are towns also on its fringes, associated with gold mines.

Cooke, with Ezulwini – Sibanye

First Uranium Corp of Canada, built a US$ 55 million uranium processing plant at Ezulwini gold-uranium mine in the West Rand, 40 km southwest of Johannesburg, which has 3200 tU in measured and indicated resources and 85,000 tU inferred resources. The main part of the plant, part of a $280 million recommissioning project, was completed and the first uranium produced in May 2009. Calcining is off-site, by Nufcor. A seven-year ramp-up of underground production from the Middle Elsburg reef was planned, but the uranium plant was placed on care and maintenance in February 2012. FY 2012 production (to end March) was 34 tU. The mine earlier produced over 6000 tU from 1961 to 2001. In August 2012 Gold One bought the mine and plant for $70 million, and it became Cooke 4.

Gold One planned to recommission the Ezulwini plant by March 2013, to treat both gold and uranium separately. The mine would form part of the company’s Cooke underground operations, but in August 2013 Sibanye Gold Ltd (spun off from Goldfields in February 2013) bought the whole Cooke operation, with all of the underground and surface plant, and including the dumps. Sibanye issued Gold One with about 150 million shares, some 17% of the company.

Nearby, Rand Uranium was spun off from Harmony Gold Mining Co and in joint venture with Pamodzi Resource Fund was reopening part of the Randfontein mine (also in Gauteng, 40 km west of Johannesburg). The mine, at the western end of the main Witwatersrand gold orebody, produced uranium in the 1980s, though its Cooke section had only been mined for gold. Rand identified JORC-compliant resources of some 41,000 tU both in tailings and underground. This included probable reserves of 15,200 tU in the Cooke tailings, which comprised the chief asset of the new company. Production at 1000 tU/yr was envisaged, but Randfontein Surface Operations (RSO) became part of the Cooke underground operations of Sibanye by about 2013.

The shallow Cooke 1, 2, & 3 mines, Cooke 4 including Ezulwini, and Randfontein Surface Operations comprise the Cooke operation of Sibanye, which describes it as a short- to medium-term asset, with life of mine estimated to extend to 2023. Cooke A1 proved & probable reserves were 1180 tU at 0.028%U in total A1 resources of 9420 tU at 0.045%U, with 16,950 tU as B1 inferred resources at the end of 2015. The Ezulwini plant enables recovery of uranium as by-product of about 4 tonnes of gold production annually. Cooke 4 is a 1634 m deep mine adjacent to Ezulwini plant, and a separate part of the operation.

Underground material from Cooke 1, 2 and 3 is processed at the Doornkop plant, operated by Harmony Gold Mining Company Ltd, on a toll treatment basis for recovery of gold. Run-of-mine ore from Cooke 4 is treated at the Ezulwini gold-uranium plant near Cooke 4 Shaft. Ore from the uranium section at Cooke 3 is hoisted separately and trucked to the Ezulwini gold-uranium plant for treatment.

In May 2014 Sibanye sent its first consignment, of 10 tonnes ammonium diuranate, from Ezulwini/Cooke to Nufcor for calcining to U3O8. In 2014, 69 tonnes of by-product uranium from Cooke was stockpiled. Production in 2015 was 47 tU, also stockpiled. The company earlier expected to ramp up to 230 tU/yr by-product by 2016.

West Rand Tailings Retreatment Project (Driefontein and Kloof)

The measured and indicated resources/probable reserves at Sibanye’e West Rand Tailings Retreatment Project (Driefontein, Kloof and Cooke historical tailings) in Gauteng province were 38,190 tU at 0.0054%U at the end of 2015. A feasibility study is under way in 2016.

(Driefontein has six operating shaft systems and three metallurgical plants, and operates at depths of 700 m to 3400 m below surface. Kloof is an intermediate to ultra-deep level mine with operating depths of between 1300 m and 3500 m below surface. Both are major gold producers.)

In July 2016 Sibanye Gold said that over 17 months the deep Cooke 4 operation had failed to meet production and cost targets, and losses had accumulated. Its continued operation was in question.

Beatrix

Sibanye Gold has its main operation at Beatrix, 20 km south of Welkom, in the Free State province 240 km southwest of Johannesburg. The company describes it as a low-cost and high-productivity operation with life of mine to about 2029. Sibanye announced uranium resources (SAMREC code) at December 2013 for Beatrix West Section – previously Oryx – on the Beisa reef of 9900 tU at 0.079%U. In February 2016 the company announced a maiden A1 probable reserve for Beisa of 4490 tU at 0.06%U, in A1 measured and indicated resources of 10,390 tU at 0.09%U. Beisa North has inferred resources of 13,630 tU at 0.09%U. In early 2016 the company completed a feasibility study on the project. The Beisa mine had been closed in 1984 by the predecessor of Goldfields. The company said it might construct a uranium plant at Beatrix or ship all the uranium north to be processed at the Cooke 4 Ezulwini plant in West Rand.

Buffelsfontein, Vaal River – Anglo Gold Ashanti Surface Operations

First Uranium had been building a larger $260 million uranium processing plant at the Buffelsfontein gold mine in the North West province, 160 km from Johannesburg and within the Klerksdorp gold field of the Witwatersrand basin. It is about 10 km east of Klerksdorp, and has some 21,000 tU as proven and probable reserves in old mine tailings, some near Stilfontein – its Mine Waste Solutions (MWS) project. The MWS tailings dams cover an area about 14 km across. Uranium production was expected to be 600 tU/yr over 16 years at full capacity, ramping up to 350 tU/yr from late 2010. The provincial government in July 2009 approved construction of a large new tailings storage facility for MWS, and a new plant was due to be commissioned in 2014. AngloGold Ashanti acquired the operation for $335 million in mid-2012.

Anglo Gold Ashanti produces uranium as by-product from its Surface Operations division which extracts gold from marginal ore dumps and tailings storage facilities on surface at various Vaal River and West Wits operations. Surface Operations includes MWS which operates independently. The company quoted by-product resources (mostly indicated) of 130,560 tonnes U3O8 including by-product reserves (mostly probable) of 53,700 t U3O8 at the end of 2015. Some 60% of the resources were in MWS or other surface tailings.

Uranium is produced at Vaal River by processing the reef material from Moab Khotsong, Great Noligwa and Kopanang, all next to to the Buffelsfontein mine. The reef ore is milled at the Noligwa Gold Plant and processed at the South Uranium Plant for uranium oxide extraction by the reverse leach process. Ammonium diuranate (‘yellowcake’) is the final product of the South Uranium Plant and is transported to Nufcor (located in Gauteng) where the material is calcined and packed for shipment to the converters.

Total production in 2013 was 532 tU, partly as by-product from the Great Noligwa mine. In 2014, 504 tU was produced.

Both Shiva and MWS operations are in the Klerksdorp area southwest of Johannesburg, and in 2008 First Uranium announced plans to build an acid plant using pyrite from MWS and 30 MWe of power generating capacity to service the two operations.

Shiva/Dominion Reefs

In 2006, Uranium Onei obtained its mining right for the Dominion Reefs project at Haartebeesfontein, 20 km east of Klerksdorp in the North West province,160 km southwest of Johannesburg. This had been the northern part of the adjacent Buffelsfontein Gold Mine operation. Production commenced early in 2007 and was planned to increase to 1730 t/yr U3O8 by 2011. Production cost was earlier expected to be US$ 14.50/lb U3O8 from the conglomerate reefs to 500 metres depth, but evidently increased well beyond this. The first sales contract for 680 tonnes was announced in November 2006. Production in 2007 was 78 tonnes and that for 2008 was 86 tonnes U3O8, reflecting slower and more difficult underground development than anticipated. A small amount of uranium was purchased from Australia in 2008 to meet sales commitments.

Dominion, including the Rietkuil section, had indicated resources of 51,000 tonnes U3O8 at 0.063% and inferred resources of 62,800 tonnes U3O8 at 0.036%. Within these, reserves however are only 14,240 tonnes at 0.077% and with US$ 46.50/lb production cost. The mine was closed in October 2008 due to a labour dispute coupled with power shortages and increased project costs in the context of lower uranium spot prices. The mine was then put on care and maintenance.

Uranium One sold it in April 2010 for $37 million to Shiva Uranium, a 74% subsidiary of Oakbay Resources & Energy Ltd, which is 85% Indian-owned. Shiva resumed uranium production early in 2011, but since then only gold has been produced while uranium workings are developed with a view to substantial production. The onsite uranium plant is the only one in South Africa using pressure leaching, which achieves uranium recovery of up to 92%, significantly more than other leaching methods.

Karoo

Australian-based Peninsula Energy has reported a JORC-compliant resource of 21,930 tU at its Karoo project straddling the East and West Cape provinces. This includes indicated resource of 8440 tU grading 0.089%U in sandstone. Drilling continues to convert historical resource information from 1970s to JORC-compliant. Some of the resources in the Ryst Kuil channel have molybdenum by-product. Peninsula holds a 74% interest in the project, the remaining 26% is held by black economic development partners.

Uranium and molybdenum mineralisation is hosted in fluvial channel sandstone deposits chiefly in the western and central parts of the Main Karoo basin. The occurrences are epigenetic, tabular and sandstone-hosted, and the thickest sandstone bodies tend to contain the highest proportion of mineralisation. The company’s further exploration target is up to 110,000 tU.

The Ryst Kuil part of the Karoo project was held by Uramin Inc, which was then taken over by Areva to become Areva Resources Southern Africa. The deposit had been discovered by Esso in the 1970s. Some 16,000 tU resources were estimated on historic basis at 0.1% grade. Areva suspended the project at the end of 2011, and in April 2014 it was acquired by Peninsula Energy to form part of the Karoo project. The Ryst Kuil channel is the focus of ongoing exploration.

Namakwa/Henkries

The Namakwa Henkries uranium project in the Northern Cape province is being explored by Namakwa Uranium, which is now owned 74% by Aarvark Uranium Ltd and 26% by the company's black economic development partner, Gilstra Exploration. Anglo American did a feasibility study on the project in 1979. Xtract Resources investigated the prospect in 2014, but did not proceed with acquisition.

Fuel cycle, historical R&D

Eskom procures conversion, enrichment and fuel fabrication services on world markets. Nearly half of its enrichment is from Tenex, in Russia. However, historically South Africa has sought self-sufficiency in its fuel cycle, and this is again becoming a priority. In December 2012, the Draft Mineral and Petroleum Resources Development Amendment Bill was approved. This aims to regulate uranium production and provides for the implementation of an approved beneficiation strategy through which strategic minerals can be processed domestically.

The South African nuclear industry dates back to the mid-1940s, when the predecessor organisation to the Atomic Energy Corporation (AEC) was formedj. In 1959, the government approved the creation of a domestic nuclear industry and planning began the next year on building a research reactor, in cooperation with the US Atoms for Peace program. The Pelindaba site near Pretoria was established in 1961, and the 20 MWt Safari-1 reactor there went critical in 1965k. In 1970, the Uranium Enrichment Corporation (UCOR) was established as South Africa commenced an extensive nuclear fuel cycle program, as well as the development of a nuclear weapons capability. In 1985, UCOR was incorporated into the AEC, which was restructured to become the South African Nuclear Energy Corporation (Necsa) as a state-owned public company in 1999.

A 1200 tU/yr conversion plant was established and ran in the 1980-90s.

Enrichment was undertaken at Valindaba (also referred to as Pelindaba East) adjacent to the Pelindaba site by the unique Helikon aerodynamic vortex tube process developed in South Africa, based on a German design. Construction of the Y-Plant pilot uranium enrichment plant commenced in 1971 and was completed in 1975 by UCOR. At this time, the USA stopped exporting highly enriched uranium (HEU) fuel for the Safari-1 reactor in protest against the construction of Y-Plant and South Africa's nuclear weapons program. Due to technical problems, Y-Plant only started producing 45%-enriched uranium in 1979 and in 1981 the first fuel assemblies for Safari-1 from Valindaba were fabricated. The Y-Plant produced about 990 kg of HEU with average enrichment of 68% until operations ceased in 1990, 336 kg of average 45% enrichment being assigned to Safari-1 for fuel or irradiation targets. The Y-Plant has been dismantled under International Atomic Energy Agency (IAEA) supervision. Much of the high-enriched uranium is stored.

On the neighbouring Pelindaba site, construction on a semi-commercial enrichment plant commenced in the late 1970s. This Z-Plant began commissioning in 1984, with full production in 1988. It had a capacity of 300,000 SWU/yr and supplied 3.25%-enriched uranium for the Koeberg plant. (Originally fuel for Koeberg was imported, but at the height of sanctionsl the AEC was asked to set up and operate conversion, enrichment and fuel manufacturing services.) Z-Plant was uneconomic and closed in 1995. It has been fully demolished.

Both centrifuge and molecular laser isotope processes were also being explored. Construction of the prototype module for the Molecular Laser Isotope Separation (MLIS) project was carried out in the Y-Plant building. The MLIS program started in 1983 and was joined by Cogema of France in a 50:50 funding arrangement in 1995. In 1997 the program was cancelled due to technological difficulties and AEC budget cuts.

Some fuel fabrication facilities operated from 1962. The BEVA fuel fabrication plant with 100 t/yr capacity operated in 1980-90s and supplied 330 PWR fuel assemblies for the Koeberg reactors.

A pebble fuel plant at Pelindaba was planned. Meanwhile, in December 2008, PBMR’s pilot fuel plant manufactured 9.6% enriched fuel particles, which were shipped to the USA for testing at the Idaho National Laboratory. In August 2009, PBMR (Pty) shipped 16 graphite spheres (containing 9.6%-enriched fuel particles) to Russia for irradiation tests to demonstrate the fuel’s integrity under reactor conditions. The irradiation tests, conducted by the Institute of Nuclear Materials in Zarechny near Ekaterinburg, were the final step in the development of the fuel for the PBMR demonstration unit.

A 2007 draft nuclear energy policy outlined an ambitious program to develop all aspects of the nuclear fuel cycle, including a return to conversion, enrichment, fuel fabrication and also reprocessing of used fuel as strategic priorities related to energy security. A new 5.0 to 10.0 million SWU/yr centrifuge enrichment plant built in partnership with Areva, Urenco or Tenex was envisaged, the larger version allowing scope for exports. These ideas seem to have faded but with 9600 MW of new capacity being built a significant level of local content in fuel cycle services is anticipated.

Initial feasibility studies on the re-establishment of nuclear fuel cycle programs were completed in 2011. Necsa’s pre-feasibility study for enrichment capacity, in collaboration with potential partners, is proceeding and the study is to be reviewed every two years. South Africa’s proposed new power plants are expected to need about 465 tonnes of enriched uranium annually by 2030. Necsa proposes to establish fuel fabrication capacity for PWRs ‘to ensure eventual security of fuel supply for South Africa’. In March 2013 Westinghouse signed a cooperation agreement with Necsa on development of local facilities for fuel assembly components.

In 2012 the vision was for 1800 tU/yr conversion plant,1.3 million SWU/yr enrichment plant and 200 tU/yr fuel fabrication plant, all established at one fuel cycle site from 2016. The conversion capacity might involve re-commissioning the old plant, or an international joint venture to commission in 2026. Enrichment would be by centrifuge, possibly with international partner, to commission 2026-257. Fuel fabrication was to be in partnership with the new NPP vendor, commissioning in 2023-25.

Research & development today

Necsa was established from AEC as a public company under the 1999 Nuclear Energy Act, and is wholly owned by the State. Its main functions are to undertake and promote research and development in the field of nuclear energy and radiation sciences and technology, and to process source material, special nuclear material and restricted material.

Necsa operates the 20 MWt Safari-1 reactor at its Pelindaba nuclear research centre. Safari-1 is the main supplier of medical radioisotopes in Africa and can supply up to 25% of the world's molybdenum-99 needs. By 2009 the reactor was converted from using HEU to low enriched uranium (LEU) fuel11, and conversion of the targets used for radioisotope production from HEU to LEU was achieved in 2010.12 Following this, Necsa and its subsidiary NTP Radioisotopes (Pty) Ltd in October 2010 were awarded a $25 million contract by the US Department of Energy's (DoE's) National Nuclear Security Administration (NNSA) to supply Mo-99. The commercial-scale production of the medical isotope from low-enriched uranium will be in collaboration with the Australian Nuclear Science and Technology Organization (ANSTO), whose 20 MWt Opal reactor also uses LEU fuel and targets for Mo-99 production.

With the end of operating life of Safari in sight, proposals have been for Dedicated Isotope Production Reactor (DIPR) and, with more probability, a new research reactor which includes isotope production among other roles.

In mid 2013 a nuclear cooperation agreement was signed with the EU, to support research, with PBMR and medical isotopes mentioned. This will be implemented by Euratom.

Klydon Corporation, which emerged from the AEC, has been developing its Aerodynamic Separation Process (ASP) employing so-called stationary-wall centrifuges with UF6 injected tangentially. It is based on Helikon but, pending regulatory authorisation from Necsa, has not yet been tested on UF6 – only light isotopes such as siliconmwhich it is evidently most suited to. Klydon Element 92 Division is focused on uranium prospects, while its Stable Isotopes Division is concerned with silicon-28, zirconium-90 and medical isotopes.

A private company, Steenkampskraal Thorium Limited (STL), is designing the TH-100, a 35 MWe (100 MWth) pebble bed HTR reactor.

Radioactive waste management

The 2008 National Radioactive Waste Disposal Institute Act provides for the establishment of a National Radioactive Waste Disposal Institute (NRWDI) to be responsible for radioactive waste disposal in South Africa. Establishment of this was announced in March 2014.

Necsa had been operating the national repository for low- and intermediate-level wastes at Vaalputs in the Northern Cape province. This was commissioned in 1986 for wastes from Koeberg and is financed by fees paid by Eskom. From about 2008 this Vaalputs facility became the National Radioactive Waste Disposal facility, and continued to be managed by Necsa until 2014 when NRWDI was set up. Some low- and intermediate-level waste from hospitals, industry and Necsa itself is disposed of at Necsa's Pelindaba site.

Used fuel is stored at Koeberg. In May 2015 Holtec won a contract from Eskom to supply HI-STAR 100 dual-purpose metal casks for transport and storage of used fuel by September 2018.

In August 2008, the nuclear safety director of the Minerals and Energy department announced that Eskom would seek commercial arrangements to reprocess its used fuel overseas and utilize the resulting mixed oxide (MOX) fuel.

Regulation and safety

In 1948, the Atomic Energy Act created the Atomic Energy Board, which later became the Atomic Energy Corporation (AEC). In 1963, the Nuclear Installations Act provided for licensing and in 1982 the Nuclear Energy Act made the AEC responsible for all nuclear matters including enrichment. An amendment to it created the autonomous Council for Nuclear Safety, responsible for licensing.

The Nuclear Energy Act of 1999 gives responsibility to the Minister of Minerals & Energy for nuclear power generation, management of radioactive wastes and the country's international commitments. The South African Nuclear Energy Corporation (Necsa) is a state corporation established from the AEC under the Act, and is responsible for most nuclear energy matters including wastes and safeguards, but not power generation.

The National Nuclear Regulator Act of 1999 sets up the National Nuclear Regulator (NNR) – previously the Council for Nuclear Safety – covering the full fuel cycle from mining to waste disposal, and in particular the siting, design, construction, operation and decommissioning of nuclear installations. The NNR is being strengthened in preparation for an expanded role with new nuclear power plants. In November 2015 NNR established a relationship with China’s National Nuclear Safety Administration (NNSA) to collaborate on several fronts and benchmark its regulatory practices.

The Department of Minerals and Energy (DME) has overall responsibility for nuclear energy and administers the above Acts. However, Eskom is under the Department of Public Enterprises.

The Department of Environmental Affairs is responsible for environmental assessment of projects, and has a cooperative agreement with the National Nuclear Regulator for nuclear projects.

An IAEA Integrated Nuclear Infrastructure Review (INIR) mission was undertaken early in 2013 to evaluate the status of the country’s nuclear infrastructure development. It was the first such mission to a country with established nuclear power, and was valuable.

Non-proliferation

Having been a foundation member of the IAEA in 1957, South Africa is the only country to develop nuclear weapons and voluntarily give them up. It embarked on a nuclear weapons programme around 1970 and had a nuclear device ready by the end of the decade. The weapons programme was terminated by President F. W. de Klerk in 1990 and, in 1991, the country signed the Nuclear Non-Proliferation Treaty (NPT). In 1993, de Klerk announced that six nuclear weapons and a seventh uncompleted one had been dismantled. In 1995, the International Atomic Energy Agency (IAEA) was able to declare that it was satisfied all materials were accounted for and the weapons programme had been terminated and dismantled.

In 1996, South Africa signed the African Nuclear Weapon Free Zone Treaty – also called the Pelindaba Treaty. In 2002, the country signed the Additional Protocol in relation to its safeguards agreements with the IAEA. South Africa is member of the Nuclear Suppliers' Group, and the country’s dual-use capabilities are regulated by the South African Council for the Non-Proliferation of Weapons of Mass Destruction (NPC).


Further Information

Notes

a. In January 2008, Eskom was forced to curtail power exports as well as introduce load shedding. The reserve margin of the electricity system was around 5% in January 2008 but by January 2009 the reserve margin had recovered to about 14%. This was due to economic slowdown, and hence lower electricity demand, as well as the recovery of coal-related problems experienced by the company in early 2008. [Back]

b. Eskom holds all the shares in the PBMR company, PBMR (Pty) Ltd., but several investment partners have provided financing for the feasibility stage of the project. In June 2000, the UK's British Nuclear Fuels Limited (BNFL) took a 22.5% stake in the venture. Soon after, US utility PECO (later Exelon, following the merger with Commonwealth Edison) took a 12.5% stake. The South African government-owned Industrial Development Corporation (IDC) took 25%, leaving Eskom with 40%, of which 10% was reserved (but never taken up) for an Economic Empowerment Entity. Exelon withdrew from the project in April 2002. Also, around the same time, BNFL reduced its stake to 15%, and IDC reduced its to 13%. In 2006, BNFL's 15% stake was transferred to its Westinghouse subsidiary, which was later sold to Toshiba.

Under an investors' agreement made in 2005, BNFL/Westinghouse had a 15% stake, IDC 14%, the South African government 30%, leaving Eskom with 41%. These shares were expected to move to 4% Westinghouse, 15% IDC, 30% South African government and 5% Eskom by 2012, with 46% being held by another investor. However, in August 2006, this agreement lapsed and a new agreement could not be reached. (Had a new investors' agreement been reached, Westinghouse would have had rights to 5% of the company, the South African Industrial Development Corporation to 5%, and 81% for the government, leaving Eskom with 9%.)

Although PBMR (Pty) Ltd continued to list its investors as the South African government, IDC, Westinghouse and Eskom, its funding following the completion of the feasibility stage in 2004 was principally from the South African government (through its Department of Public Enterprises). In March 2010, the government drastically cut funding for the PBMR, then in September 2010 it announced that all funding was to be cut. [Back]

c. Of the R9.244 billion (about US$ 1.3 billion) invested in the PBMR project, the South African government contributed 80.3%, Eskom 8.8%, Westinghouse 4.9%, the Industrial Development Corporation of South Africa 4.9%, and Exelon 1.1%. Figures given by Barbara Hogan, Minister of Public Enterprises, to the National Assembly on 16 September 2010 (see Reference 9 below). [Back]

d. Developed from the 200 MWt Siemens/Interatom HTR-Modul reactor design, the initial PBMR was a 268 MWt (110 MWe) design. In order to lower the capital costs of the plant, relatively minor changes led to a 302 MWt design. However, as a result of issues arising during more detailed analysis, in 2002 it was decided that a complete review of the design was to be carried out. This resulted in the 400 MWt (165 MWe) version with a fixed central reflector in the core (the 268 MWt design has a dynamic central reflector column of graphite spheres). In addition, the power conversion unit was changed from three-shaft vertical to single-shaft horizontal turbine-compressor configuration. Reactor outlet temperature is 900ºC.6 [Back]

e. In 2009, the PBMR company announced it had decided to focus on a 200 MWt (80 MWe) design for the PBMR rather than the 400 MWt version (see Note d above). The 200 MWt version uses a conventional Rankine cycle to deliver super-heated steam (750ºC) through a steam generator for electricity generation and process heat applications. [Back]

f. Construction of the 400 MWt demonstration plant was originally envisaged to commence in April 2007 but, partly due to delays in licensing, was put back to 2009. Later, following the decision in 2009 to focus on the 200 MWt PBMR design, the construction schedule was delayed indefinitely. A total of R 1 billion was spent on equipment, including R 268 million of reactor vessel parts made by Spain's Equipos Nucleares.

In 2003, the South African Department of Environmental Affairs and Tourism (DEAT) issued positive Record of Decisions on the environmental impact assessment (EIA) studies for the PBMR demonstration module and pilot fuel plant. However, these decisions were set aside by the Cape High Court following appeals from anti-nuclear group Earthlife Africa. This ruling, along with design changes to the PBMR – the Brayton cycle turbine design was simplified from 3-shaft vertical to single shaft horizontal configuration and the reactor capacity increased from 302 MWt to 400 MWt (see Note d above) – led to the decision to enter into a new EIA process for the demonstration PBMR. This process remains unfinished and is not likely to be completed in light of the change to a 200 MWt version of the PBMR - and the subsequent cancellation of funding in 2010. In January 2007, the Minister of Environmental Affairs and Tourism upheld the positive Record of Decision for the pilot fuel plant EIA.

Several contracts for the 400 MWt design had been awarded. In April 2005, PBMR (Pty) awarded a US$ 20 million contract to Uhde, a local subsidiary of Germany's Thyssenkrupp Engineering, to build a plant at Pelindaba near Pretoria to manufacture the fuel pebbles for the planned demonstration PBMR. The fuel plant was expected to be completed by 2010 but was delayed by regulatory issues. In August 2008, a contract was awarded to the joint venture company Murray & Roberts SNC-Lavalin Nuclear (Pty) Ltd for the provision of engineering, procurement, project and construction management (EPCM) services for the demonstration PBMR plant, then envisaged to be at Koeberg. [Back]

g. In September 2010, Barbara Hogan, South African Minister of Public Enterprises, told the National Assembly that one reason for the withdrawal of government support for the PBMR was: "The opportunity afforded to PBMR to participate in the USA’s Next Generation Nuclear Plant (NGNP) program as part of the Westinghouse consortium was lost in May this year when Westinghouse withdrew from the program" (see Reference 9 below). In fact, Westinghouse did not withdraw from the NGNP project, but did withdraw from the conceptual design phase (sometimes referred to as Phase 1). Following Hogan's September announcement, Westinghouse released a statement which it says was made in May 2010 by Kate Jackson, Senior Vice President of Research and Technology and Chief Technology Officer of Westinghouse: "In early March, the team of Westinghouse, PBMR (Pty) and Shaw Group was selected by the Department of Energy (DOE) to negotiate an award under a funding opportunity announcement for Phase 1 of the DOE's NGNP project. Since that time, the team has not been able to reach agreement on a way forward, and therefore, will not participate together in this project phase." [Back]

h. The small operating HTR-10 research reactor at China's Tsinghua University is the basis of the 250 MWt (105 MWe) HTR-PM reactor (one 210 MWe module consisting of twin reactor units driving a single steam turbine), which also derives from the earlier German development. [Back]

i. See the Uranium One website (www.uranium1.com) [Back]

j. In 1944, the USA and UK requested forecasts from South Africa on its potential to supply mineable uranium. This led to the formation of the Uranium Committee in 1945, and, in 1948, the Atomic Energy Board (AEB) was formally established to oversee uranium production and trade. In 1959, research, development and utilisation of nuclear technology was added to AEB's remit. In 1970, the Uranium Enrichment Corporation (UCOR) was established, initiating an extensive fuel cycle program. In 1982, the AEB was re-established as the Nuclear Development Corporation of South Africa (NUCOR) under a new controlling body – the Atomic Energy Corporation of South Africa (AEC). In 1985, UCOR was incorporated into the AEC. The South African Nuclear Energy Corporation (NECSA) was formed out of the AEC in 1999. [Back]

k. The Safari-1 (South African Fundamental Atomic Research Installation) reactor initially operated at 6.75 MW and was upgraded to 20 MW in 1968. The pool-type reactor is an Oak Ridge National Laboratory (ORNL) design fuelled by highly enriched uranium (HEU). A program to convert to low enriched uranium (LEU) fuel commenced in 2006. [Back]

l. South Africa's policy of apartheid – which ended with the 27 April 1994 general election – attracted extensive international sanctions. However, it was not until the late 1970s/early 1980s that international pressure intensified, culminating in 1985-1991 with trade sanctions by the USA, British Commonwealth and Europe, as well as disinvestment campaigns in many countries. [Back]

 

m. Extrapolating from test results, ASP is expected to have an enrichment factor in each unit of 1.10 (cf 1.03 in Helikon) with about 1000 kWh/SWU. Development of it is aiming for 1.15 enrichment factor and less than 500 kWh/SWU (compared with about 10,000 kWh/SWU in the Z-plant). However, to achieve gas speeds sufficient for enrichment, heavy elements such as uranium need to be greatly diluted with hydrogen, and the process appear uneconomic for uranium

  • Jordan imports most of its energy and seeks greater energy security as well as lower electricity prices.
  • It is aiming to have two 1000 MWe nuclear power units in operation by 2025 to provide nearly half the country’s electricity.
  • Jordan has significant uranium resources, some in phosphorite deposits.

Jordan imports over 95% of its energy needs, at a cost of about one-fifth of its GDP. It generated 17.3 TWh, mostly from oil, and imported 0.3 TWh net in 2013 for its six million people, consumption being 14.5 TWh. In 2012, due to gas supply constraints from Egypt, its electricity supply supply was 84% from heavy fuel oil and diesel, instead of natural gas which previously provided the majority, and 5% was imported. In 2013, 74% of electricity was from oil.

It has 2400 MWe of generating capacity and expected to need 3600 MWe by 2015, 5000 MWe by 2020 and 8000 MWe by 2030 when it expects doubled electricity consumption. About 6800 MWe of new plant is needed by 2030, with one third of this projected to be nuclear. Per capita electricity consumption is about 2000 kWh/yr. Jordan has regional grid connection of 500 MWe with Egypt, 300 MWe with Syria, and it is increasing links with Israel and Palestine. This will both increase energy security and provide justification for larger nuclear units.

Also it has a "water deficit" of about 600 million cubic metres per year (1500 demand, 900 supply). It pumps about 60 million m3/yr of fossil subartesian water from the Disi/Saq aquifer, and this is set to rise to 160 million m3/yr in 2013. It contains elevated, but not hazardous, levels of radionuclides, principally radium. (Drinking 2 litres per day would give a dose of 1.0 to 1.5 mSv/yr.)

Jordan's 2007 national energy strategy envisaged 29% of primary energy from natural gas, 14% from oil shale, 10% from renewables and 6% from nuclear by 2020.

  • About 20 million consignments of all sizes containing radioactive materials are routinely transported worldwide annually on public roads, railways and ships.
  • Radioactive materials are shipped in robust and secure containers.
  • Some 300 sea voyages have been made carrying used nuclear fuel or separated high-level waste over a distance of more than 8 million kilometres. These cargoes are generally carried in purpose-built ships.
  • Since 1971 there have been some 7000 shipments of used fuel (over 80,000 tonnes) over many million kilometres on land and sea.
  • There have been accidents over the years, but never one in which a container with highly radioactive material has been breached, or has leaked.
  • Though transport is a very minor cost in the nuclear fuel cycle, lack of harmonisation and over-regulation in authorisation create problems for transport between countries.

About 20 million consignments of radioactive material (which may be either a single package or a number of packages sent from one location to another at the same time) take place around the world each year. This adds up to over one billion safe consignments since 1961 when the IAEA safe transport regulations were issued. Radioactive material is not unique to the nuclear fuel cycle and only about 5% of the consignments are fuel cycle related. Radioactive materials are used extensively in medicine, agriculture, research, manufacturing, non-destructive testing and minerals' exploration.

International regulations for the transport of radioactive material have been published by the International Atomic Energy Agency (IAEA) since 1961. These regulations have been widely adopted into national regulations, as well as into modal regulations, such as the International Maritime Organisation’s (IMO) Dangerous Goods Code. Regulatory control of shipments of radioactive material is independent of the material's intended application. Because safety of any material being shipped depends primarily on the package, regulations set out several performance standards for packaging. They provide for five different categories of primary packages and set the criteria for their design according to both the activity and the physical form of the radioactive material.

Nuclear fuel cycle facilities are located in various parts of the world and materials of many kinds need to be transported between them. Many of these are similar to materials used in other industrial activities. However, the nuclear industry's fuel is mildly radioactive while some wastes are very much more so, and it is these 'nuclear materials' about which are the focus of concern. Transport is a very minor direct cost in the nuclear fuel cycle.

A Euratom Supply Agency study in 2015 identified lack of harmonisation and over-regulation in transport authorisation for radioactive materials, particularly between countries, as a significant risk from a security of supply perspective.

Nuclear materials have been transported since before the advent of nuclear power over 60 years ago. The procedures employed are designed to ensure the protection of the public and the environment both routinely and when transport accidents occur. For the generation of a given quantity of electricity, the amount of nuclear fuel required is very much smaller than the amount of any other fuels. Therefore, the conventional risks and environmental impacts associated with fuel transport are greatly reduced with nuclear power.

In the USA one percent of the 300 million packages of hazardous material shipped each year contain radioactive materials. Of this, about 250,000 contain radioactive wastes from US nuclear power plants, and 25 to 100 packages contain used fuel. Most of these are in robust 125-tonne Type B casks carried by rail, each containing 20 tonnes of used fuel.

Materials being transported

Transport is an integral part of the nuclear fuel cycle. There are some 440 nuclear power reactors in operation in 32 countries but uranium mining occurs in only about 20 countries, with most production being in countries without nuclear power. Furthermore, in the course of over 40 years of operation by the nuclear industry, a number of specialised facilities have been developed in various locations around the world to provide fuel cycle services. Hence there is a need to transport nuclear fuel cycle materials to and from these facilities. Indeed, most of the material used in nuclear fuel is transported several times during its its progress through the fuel cycle. Transport is frequently international, and often over large distances. Any substantial quantities of radioactive materials are generally transported by specialised transport companies.

The term 'transport' is used in this document only to refer to the movement of material between facilities, i.e. through areas outside such facilities. Most consignments of nuclear fuel material occur between different stages of the cycle, but occasionally material may be transported between similar facilities. When the stages are directly linked (such as mining and milling), the facilities for the different stages are usually on the same site, and no transport is then required.

With very few exceptions, nuclear fuel cycle materials are transported in solid form. The following table shows the principal nuclear material transport activities:

From: To: Material: Notes:
Mining Milling Ore Rare: usually on the same site
Milling Conversion Uranium oxide concentrate ('Yellowcake') Usually 200-litre drums in standard 6m transport container
Conversion Enrichment Natural uranium hexafluoride
(UF6)
Special UF6 containers, type 48Y
Enrichment Fuel fabrication Enriched UF6 Special UF6 containers, type 30B
Fuel fabrication Power generation Fresh (unused) fuel  
Power generation Used fuel storage used fuel After on-site storage, large Type B casks
Used fuel storage Disposal* used fuel Large Type B casks
Used fuel storage Reprocessing used fuel  
Reprocessing Conversion Uranium oxide Called reprocessed uranium (RepU)
Reprocessing Fuel fabrication Plutonium oxide  
Reprocessing Disposal* Fission products Vitrified (incorporated into glass)
All facilities Storage/disposal Waste materials Sometimes on the same site

* Not yet taking place

Although some waste disposal facilities are located adjacent to the facilities that they serve, utilising one disposal site to manage the wastes from several facilities usually reduces environmental impacts. When this is the case, transport of the wastes from the facilities to the disposal site will be required.

Classification of radioactive wastes

There are several systems of nomenclature in use, but the following is generally accepted:

  • Exempt waste – excluded from regulatory control because radiological hazards are negligible.
  • Low-level waste (LLW) – contains enough radioactive material to require action for the protection of people, but not so much that it requires shielding in handling or storage.
  • Intermediate-level waste (ILW) – requires shielding. If it has more than 4000 Bq/g of long-lived (over 30 year half-life) alpha emitters it is categorised as 'long-lived' and requires more sophisticated handling and disposal.
  • High-level waste (HLW) – sufficiently radioactive to require both shielding and cooling,
    generates >2 kW/m3 of heat and has a high level of long-lived alpha-emitting isotopes.

Packaging

The principal assurance of safety in the transport of nuclear materials is the design of the packaging, which must allow for foreseeable accidents. The consignor bears primary responsibility for this. Many different nuclear materials are transported and the degree of potential hazard from these materials varies considerably. Different packaging standards have been developed by the IAEA according to the charactristics and potential hazard posed by the different types of nuclear material, regardless of the mode of transport.

Regulations setting out several performance standards for packaging provide for five different categories of primary packages, and set the criteria for their design according to both the activity and the physical form of the radioactive material. The categories are: Excepted, Industrial, Type A, Type B and Type C.

Ordinary industrial containers are used for low-activity material such as uranium oxide concentrate shipped from mines – U3O8. About 36 standard 200-litre drums fit into a standard 6-metre transport container. They are also used for low-level wastes within countries.

'Type A' packages are used for the transport of relatively small, but significant, quantities of radioactive material. They are designed to withstand accidents and are used for limited quantities of medium-activity materials such as medical or industrial radioisotopes as well as some nuclear fuel materials.

A particular ‘Type B’ package is used for shipping uranium hexafluoride (‘hex’), where the main accident hazard is chemical rather than radiological. Natural uranium is usually shipped to enrichment plants in type 48Y cylinders, 122 cm diameter and each holding about 12.5 tonnes of uranium hexafluoride. These cylinders are then used for long-term storage of DU as hexafluoride, typically at the enrichment site. Due to criticality concerns, enriched uranium is shipped to fuel fabricators in smaller type 30B cylinders 76 cm diameter and 2.1 m long, each holding 2.27 t UF6. These may be shipped with overpacks. Both kinds of hex cylinders must withstand a pressure test of at least 1.4 MPa, withstand a drop test and survive a fire of 800°C for 30minutes.

'Type B' packages used for high-level waste (HLW), used fuel, and MOX fuel are robust and very secure casks. They range from drum-size to truck-size and maintain shielding from gamma and neutron radiation, even under extreme accident conditions. Designs are certified by national authorities. There are over 150 kinds of Type B packages, and the larger ones cost some US$1.6 million each.

Flask

In France alone, there are some 750 shipments each year of Type B packages.  This is in relation to 15 million shipments classified as 'dangerous goods', 300,000 of which are radioactive materials of some kind.

Smaller amounts of high-activity materials (including plutonium) transported by aircraft are be in 'Type C' packages, which give even greater protection in all respects than Type B packages in accident scenarios. They can survive being dropped from an aircraft at cruising altitude.

An example of a Type B shipping package is Holtec’s HI-STAR 80 cask (STAR = storage, transport and repository), a multi-layered steel cylinder which holds 12 PWR or 32 BWR high-burnup used fuel assemblies (above 45 GWd/t) which have had cooling times as short as 18 months. The HI-STAR 60 can transport 12 PWR used fuel assemblies, and two aluminium impact limiters. The HI-STAR 180 was the first one licensed to transport high-burnup fuel, and holds 32 or 37 PWR used fuel assemblies. The HI-STAR 190 cask has the world’s highest heat load capacity, at 38 kW, and is to be used domestically in Ukraine for PWR fuel. The HI-STAR 100 is based on a sealed multi-purpose canister containing the fuel which can be transferred to HI-STORM storage systems, exchanging one overpack for another.

In the UK 47- or 53-tonne rectangular Type B flasks have long been used to transport Magnox and AGR fuel, which is held in internal skips.

Radiation protection

When radioactive materials, including nuclear materials, are transported, it is important to ensure that radiation exposure of both those involved in the transport of such materials and the general public along transport routes is limited. Packaging for radioactive materials includes, where appropriate, shielding to reduce potential radiation exposures. In the case of some materials, such as fresh uranium fuel assemblies, the radiation levels are negligible and no shielding is required. Other materials, such as used fuel and high-level waste, are highly radioactive and purpose-designed containers with integral shielding are used. To limit the risk in handling of highly radioactive materials, dual-purpose containers (casks), which are appropriate for both storage and transport of used nuclear fuel, are often used.

As with other hazardous materials being transported, packages of radioactive materials are labelled in accordance with the requirements of national and international regulations. These labels not only indicate that the material is radioactive, by including a radiation symbol, but also give an indication of the radiation field in the vicinity of the package.

Personnel directly involved in the transport of radioactive materials are trained to take appropriate precautions and to respond in case of an emergency.

Environmental protection

Packages used for the transport of radioactive materials are designed to retain their integrity during the various conditions that may be encountered while they are being transported thus ensuring that an accident will not have any major consequences. Conditions which packages are tested to withstand include: fire, impact, wetting, pressure, heat and cold. Packages of radioactive material are checked prior to shipping and, when it is found to be necessary, cleaned to remove contamination.

Although not required by transport regulations, the nuclear industry chooses to undertake some shipments of nuclear material using dedicated, purpose-built transport vehicles or vessels.

Regulation of transporta

Since 1961 the International Atomic Energy Agency (IAEA) has published advisory regulations for the safe transport of radioactive material. These regulations have come to be recognised throughout the world as the uniform basis for both national and international transport safety requirements in this area. Requirements based on the IAEA regulations have been adopted in about 60 countries, as well as by the International Civil Aviation Organisation (ICAO), the International Maritime Organisation (IMO), and regional transport organisations.

PNTL vessel 

The IAEA has regularly issued revisions to the transport regulations in order to keep them up to date. The latest set of Regulations for the Safe Transport of Radioactive Material is the 2012 edition.

The objective of the regulations is to protect people and the environment from the effects of radiation during the transport of radioactive material.

Protection is achieved by:

  • Containment of radioactive contents.
  • Control of external radiation levels.
  • Prevention of criticality.
  • Prevention of damage caused by heat.

The fundamental principle applied to the transport of radioactive material is that the protection comes from the design of the package, regardless of how the material is transported.

Challenges in Class 7 transport

Most transport of Class 7 materials is for radioisotopes for medical and industrial use (including some cobalt-60 sterilisation sources in 4-tonne type B packages). But all of it requires some training of people who handle the packages, hence there is cost and inconvenience to both shippers and others handling the packages, leading to occasional denial of shipment. Multiple layers of regulation with lack of international consistency provide disincentives to shippers. There are also problems with the competent authority on one country not being accepted in another. Occasionally there is de facto refusal to issue permits, and certain insurances for vessels carrying material with more than 1% fissile may need to be taken out by the consignor or consignee.

Most reports of denial of shipment relate to non-fissile materials, either type B packages (mainly cobalt-60) or tantalum-niobium concentrates. For uranium concentrates the main problem is limited ports which handle them, and few marine carriers which accept them.

Transport of uranium oxide from mines

Uranium oxide concentrate, sometimes called yellowcake, is transported from the mines to conversion plants in 200-litre drums packed into normal shipping containers. No radiation protection is required beyond having the steel drums clean and within the shipping container.

The importance of this is indicated by the fact that 80% of uranium is mined in five countries, only one of which (Canada) uses uranium for nuclear power.

In Australia, over more than three decades to 2014, 11,000 shipping containers with drums of U3O8 were moved from mines to ports with no incident affecting public health.

Transport of uranium hexafluoride

To and from enrichment plants, the uranium is in the form of uranium hexafluoride (UF6), which again is barely radioactive but has significant chemical toxicity. Natural uranium as hexafluoride is usually shipped to enrichment plants in type 48Y cylinders, each 122 cm diameter and holding about 12.5 tonnes of uranium hexafluoride (8.4 tU). These cylinders are then used for long-term storage of DU as hexafluoride, typically at the enrichment site. Enriched uranium is shipped to fuel fabricators in smaller type 30B cylinders, each 76 cm diameter and holding 2.27 t UF6(1.54 tU).

Transport of uranium fuel assemblies

Uranium fuel assemblies are manufactured at fuel fabrication plants. The fuel assemblies are made up of ceramic pellets formed from pressed uranium oxide that has been sintered at a high temperature (over 1400°C). The pellets are aligned within long, hollow, metal rods, which in turn are arranged in the fuel assemblies, ready for introduction into the reactor.

Different types of reactors require different types of fuel assembly, so when the fuel assemblies are transported from the fuel fabrication facility to the nuclear power reactor, the contents of the shipment will vary with the type of reactor receiving it.

In Western Europe, Asia and the US, the most common means of transporting uranium fuel assemblies is by truck. A typical truckload supplying a light water reactor contains 6 tonnes of fuel. In Russia and Eastern Europe rail transport is most often used. Intercontinental transports are mostly by sea, though occasionally transport is by air.

The annual operation of a 1000 MWe light water reactor requires an average fuel load of 27 tonnes of uranium dioxide, containing 24 tonnes of enriched uranium, which can be transported in 4 to 5 trucks.

The precision-made fuel assemblies are transported in packages specially constructed to protect them from damage during transport. Uranium fuel assemblies have a low radioactivity level and radiation shielding is not necessary.

Fuel assemblies contain fissile material and criticality is prevented by the design of the package, (including the arrangement of the fuel assemblies within it, and limitations on the amount of material contained within the package), and on the number of packages carried in one shipment.

Transport of LLW and ILW

Low-level and intermediate-level wastes (LLW and ILW) are generated throughout the nuclear fuel cycle and from the production of radioisotopes used in medicine, industry and other areas.  The transport of these wastes is commonplace and they are safely transported to waste treatment facilities and storage sites.

Low-level radioactive wastes are a variety of materials that emit low levels of radiation, slightly above normal background levels. They often consist of solid materials, such as clothing, tools, or contaminated soil. Low-level waste is transported from its origin to waste treatment sites, or to an intermediate or final storage facility.

A variety of radionuclides give low-level waste its radioactive character. However, the radiation levels from these materials are very low and the packaging used for the transport of low-level waste does not require special shielding.

Low-level wastes are transported in drums, often after being compacted in order to reduce the total volume of waste. The drums commonly used contain up to 200 litres of material. Typically, 36 standard, 200 litre drums go into a 6-metre transport container.  Low-level wastes are moved by road, rail, and internationally, by sea. However, most low-level waste is only transported within the country where it is produced.

The composition of intermediate-level wastes is broad, but they require shielding. Much ILW comes from nuclear power plants and reprocessing facilities.

Intermediate-level wastes are taken from their source to an interim storage site, a final storage site (as in Sweden), or a waste treatment facility. They are transported by road, rail and sea.

The radioactivity level of intermediate-level waste is higher than low-level wastes. The classification of radioactive wastes is decided for disposal purposes, not on transport grounds. The transport of intermediate-level wastes take into account any specific properties of the material, and requires shielding.

In the USA there had been 9000 road shipments of defence-related transuranic wastes for permanent disposal in the deep geological repository near Carlsbad, New Mexico, by October 2010, without any major accident or any release of radioactivity. Almost half the shipments were from the Idaho National Laboratory. The repository, known as the Waste Isolation Pilot Plant (WIPP), is about 700 m deep in a Permian salt formation.

Transport of used nuclear fuel

When used fuel is unloaded from a nuclear power reactor, it contains: 96% uranium, 1% plutonium and 3% of fission products (from the nuclear reaction) as well as a small amount of transuranics.

Used fuel will emit high levels of both radiation and heat and so is stored in water pools adjacent to the reactor to allow the initial heat and radiation levels to decrease. Typically, used fuel is stored on site for at least five months before it can be transported, although it may be stored there long-term.

From the reactor site, used fuel is transported by road, rail or sea to either an interim storage site or a reprocessing plant where it will be reprocessed.

Used fuel assemblies are shipped in Type B casks which are shielded with steel, or a combination of steel and lead, and can weigh up to 110 tonnes when empty. A typical transport cask holds up to 6 tonnes of used fuel.

Since 1971 there have been some 7000 shipments of used fuel (over 80 000 tonnes) over many million kilometres with no property damage or personal injury, no breach of containment, and very low dose rate to the personnel involved (e.g. 0.33 mSv/yr per operator at La Hague). This includes 40,000 tonnes of used fuel shipped to Areva's La Hague reprocessing plant, at least 30,000 tonnes of mostly UK used fuel shipped to UK's Sellafield reprocessing plant, 7040 t used fuel in over 160 shipments from Japan to Europe by sea (see below) and over 4500 tonnes of used fuel shipped around the Swedish coast. In the USA naval spent fuel is routinely shipped by rail to Idaho National Laboratory.

Some 300 sea voyages have been made carrying used nuclear fuel or separated high-level waste over a distance of more than 8 million kilometres. The major company involved has transported over 4000 casks, each of about 100 tonnes, carrying 8000 tonnes of used fuel or separated high-level wastes. A quarter of these have been through the Panama Canal.

In Sweden, more than 80 large transport casks are shipped annually to a central interim waste storage facility called CLAB. Each 80 tonne cask has steel walls 30 cm thick and holds 17 BWR or 7 PWR fuel assemblies. The used fuel is shipped to CLAB after it has been stored for about a year at the reactor, during which time heat and radioactivity diminish considerably. Some 6000 tonnes of used fuel had been shipped to CLAB by mid-2015, much of it around the coast by ship.

Shipments of used fuel from Japan to Europe for reprocessing used 94-tonne Type B casks, each holding a number of fuel assemblies (e.g. 12 PWR assemblies, total 6 tonnes, with each cask 6.1 metres long, 2.5 metres diameter, and with 25 cm thick forged steel walls). More than 160 of these shipments took place from1969 to the 1990s, involving more than 4000 casks, and moving several thousand tonnes of highly radioactive used fuel – 4200t to UK and 2940t to France.

Within Europe, used fuel in casks has often been carried on normal ferries, e.g. across the English Channel.

Canada’s Nuclear Waste Management Organization has published a paper showing spent nuclear fuel shipments worldwide:

  • Canada: 5 per year by road.
  • USA: 3000 up to 2013 by road, rail and ship.
  • Sweden: 40 per year by ship.
  • UK: 300 per year by rail.
  • France: 250 per year by rail.
  • Germany: 40 per year by rail.
  • Japan: 200 to 2013 by ship.

Areva TN and EdF report 5000 rail and road shipments of used fuel from 1981 to 2015, with a current rate of more than 200 per year. More than 16,000 high burn-up fuel assemblies have been transported.

Transport of plutonium

Plutonium is separated during the reprocessing of used fuel. It is normally then made into mixed oxide (MOX) fuel.

Plutonium is transported, following reprocessing, as an oxide powder since this is its most stable form.  It is insoluble in water and only harmful to humans if it enters the lungs.

Plutonium oxide is transported in several different types of sealed packages and each can contain several kilograms of material. Criticality is prevented by the design of the package, limitations on the amount of material contained within the package, and on the number of packages carried on a transport vessel.  Special physical protection measures apply to plutonium consignments.

A typical transport consists of one truck carrying one protected shipping container. The container holds a number of packages with a total weight varying from 80 to 200 kg of plutonium oxide.

A sea shipment may consist of several containers, each of them holding between 80 to 200 kg of plutonium in sealed packages.

Transport of vitrified waste

The highly radioactive wastes (especially fission products) created in the nuclear reactor are segregated and recovered during the reprocessing operation. These wastes are incorporated in a glass matrix by a process known as 'vitrification', which stabilises the radioactive material.

The molten glass is then poured into a stainless steel canister where it cools and solidifies. A lid is welded into place to seal the canister. The canisters are then placed inside a Type B cask, similar to those used for the transport of used fuel.

The quantity per shipment depends upon the capacity of the transport cask. Typically a vitrified waste transport cask contains up to 28 canisters of glass.

Return nuclear waste shipments from Europe to Japan since 1995 are of vitrified high-level wastes in stainless steel canisters. Up to 28 canisters (total 14 tonnes) are packed in each 94-tonne steel transport cask, the same as used for irradiated fuel. Over 1995-2007 twelve shipments were made from France of vitrified HLW comprising 1310 canisters containing almost 700 tonnes of glass. Return shipments from the UK commenced in 2010, and there will be about 11 shipments over at least eight years to move about 900 canisters.

Purpose-built ships

In 1993, the International Maritime Organisation (IMO) introduced the voluntary Code for the Safe Carriage of Irradiated Nuclear Fuel, Plutonium and High-Level Radioactive Wastes in Flasks on Board Ships (INF Code), complementing the IAEA Regulations. These complementary provisions mainly cover ship design, construction and equipment. The INF Code came into force in January 2001 and introduced advanced safety features for ships carrying used fuel, MOX or vitrified high-level waste.

There are at least five small purpose-built ships ranging from 1250 to 2200 tonnes (DWT), and four purpose-built ships almost of 3800 to 4900 tonnes (DWT), and able to carry class B casks and other materials. They conform to all relevant international safety standards, notably INF-3 (Irradiated Nuclear Fuel class 3) set by the IMO. This allows them to carry highly radioactive materials such as high-level wastes and used nuclear fuel, as well as mixed-oxide (MOX) fuel and plutonium.

The three largest ships belong to a British-based company Pacific Nuclear Transport Ltd (PNTL), a subsidiary of International Nuclear Services Ltd (INS)*. They all have double hulls with impact-resistant structures between the hulls, together with duplication and separation of all essential systems to provide high reliability and also survivability in the event of an accident. Twin engines operate independently. Each ship can carry up to 20 or 24 transport casks. The three PNTL vessels now in service, Pacific HeronPacific Egret and Pacific Grebe, were launched in Japan in 2008, 2010 and 2010 respectively. They are 4916 tonnes deadweight and 104 metres long.Pacific Grebe carries mainly wastes, the other two mainly MOX fuel. Earlier ships in the PNTL fleet mainly carried Japanese used fuel to Europe for reprocessing. The PNTL fleet has successfully completed more than 180 shipments with more than 2000 casks over some 40 years, covering about 10 million kilometres, without any incident resulting in release of radioactivity.

* PNTL is now owned by International Nuclear Services Ltd (INS, 68.75%), Japanese utilities (18.75%) and Areva (12.5%). INS is owned by the UK's Nuclear Decommissioning Authority.

VT Transport flask

PNTL diagram

Sweden’s SKB has commissioned a slightly larger replacement for its 1982 Sigyn, the Sigrid, launched in Romania in 2012 and designed by Damen Shipyards in Netherlands. It is used for moving used fuel from reactors to the interim waste storage facility. Sigrid is equipped with a double hull, four engines and redundant systems for safety and security. It was commissioned in 2013 and carried its first shipment in January 2014. Sigrid is 99.5 metres long and 18.6 metres wide, 1600 deadweight tonnes (DWT) and capable of carrying twelve nuclear waste casks. (Sigyn was 1250 tonnes deadweight and carried ten casks. It awaits further assignment.)

Rosatomflot is operating the 1620 deadweight tonne (DWT) Rossita, built in Italy and completed in 2011. It is designed for transporting spent nuclear fuel and materials of decommissioned nuclear submarines from Russian Navy bases in North-West Russia. It will be used on the Northern Sea Route, between Gremikha, Andreyeva Bay, Saida Bay, Severodvinsk and other places hosting facilities which dismantle nuclear submarines. Spent fuel is to be delivered to Murmansk for rail shipment to Mayak. Rosatomflot has the Serebryanka (1625 DWT, 102 m long, built 1974) already in service. The Imandra (2186 DWT, 130 m long, built 1980) is described as a floating technical base but is reported to be already in service transporting used fuel and wastes from the Nerpa shipyard and Gremikha to Murmansk.  (Andreyeva Bay is the primary spent nuclear fuel and radioactive waste storage facility for the Northern Fleet, some 60 km from the Norwegian border. It has about 21,000 spent nuclear fuel assemblies and about 12,000 m3 of solid and liquid radioactive wastes.)

Rossita is an ice-class vessel and is designed to operate in harsh conditions of the Arctic. The ship is 84 m long and 14 m wide, with two engines, and has two isolated cargo holds holding up to 720 tonnes in total. On board, the radiation monitoring is carried out by both an automated multi-channel system and a set of portable instrumentation. The EUR 70 million vessel was given to Russia as part of Italy’s commitment to the G-8 partnership program for cleaning up naval nuclear wastes, and is designed to cover all needs in spent nuclear fuel and radwaste shipments in northwest Russia throughout the entire period of cleaning up these territories

See also paper on Japanese waste and MOX shipments from Europe.

Accident scenarios

There has never been any accident in which a Type B transport cask containing radioactive materials has been breached or has leaked.

For the radioactive material in a large Type B package in sea transit to become exposed, the ship's hold (inside double hulls) would need to rupture, the 25 cm thick steel cask would need to rupture, and the stainless steel flask or the fuel rods would need to be broken open. Either borosilicate glass (for reprocessed wastes) or ceramic fuel material would then be exposed, but in either case these materials are very insoluble.

The transport ships are designed to withstand a side-on collision with a large oil tanker. If the ship did sink, the casks will remain sound for many years and would be relatively easy to recover since instrumentation including location beacons would activate and monitor the casks.


Notes

a. Any goods that pose a risk to people, property and the environment are classified as dangerous goods, which range from paints, solvents and pesticides up to explosives, flammables and fuming acids, and are assigned to different classes ranging from 1 to 9 under the UN Model Regulations:

  • Class 1: Explosives
  • Class 2: Gases
  • Class 3: Flammable liquids
  • Class 4: Other flammables
  • Class 5: Oxidising agents
  • Class 6: Toxic and infectious substances
  • Class 7: Radioactive materials (regardless of degree of chemical or radiological hazard)
  • Class 8: Corrosives
  • Class 9: Miscellaneous: asbestos, lithium batteries, etc.

When transported these goods need to be packaged correctly as laid out in the various international and national regulations for each mode of transport, to ensure that they are carried safely to minimise the risk of an incident.

 

The US NRC defines, for transport purposes only, radioactive materials as those with specific activity greater than 74 Bq per gram. This definition does not specify a quantity, only a concentration. As an example, pure cobalt-60 has a specific activity of 37 TBq per gram, which is about 500 billion times greater than the definition. However, uranium-238 has a specific activity of only 11 kBq per gram, which is only 150 times greater than the definition.

  • Nuclear power capacity worldwide is increasing steadily, with over 60 reactors under construction in 15 countries.
  • Most reactors on order or planned are in the Asian region, though there are major plans for new units in Russia.
  • Significant further capacity is being created by plant upgrading.
  • Plant life extension programs are maintaining capacity, in USA particularly.

Today there are some 440 nuclear power reactors operating in 31 countries plus Taiwan, with a combined capacity of over 385 GWe. In 2014 these provided 2411 billion kWh, over 11% of the world's electricity.

Over 60 power reactors are currently being constructed in 13 countries plus Taiwan (see Table below), notably China, South Korea, UAE and Russia.

Each year, the OECD's International Energy Agency (IEA) sets out the present situation and also reference and other, particularly carbon reduction scenarios. World Energy Outlook 2014 had a special focus on nuclear power, and extends the scope of scenarios to 2040. In its New Policies scenario, installed nuclear capacity growth is 60% through 543 GWe in 2030 and to 624 GWe in 2040 out of a total of 10,700 GWe, with the increase concentrated heavily in China (46% of it), plus India, Korea and Russia (30% of it together) and the USA (16%), countered by a 10% drop in the EU. Despite this, the percentage share of nuclear power in the global power mix increases to only 12%, well below its historic peak. Low-Nuclear and so-called High-Nuclear cases give 366 and 767 GWe nuclear respectively in 2040. The low-carbon ‘450 Scenario’ gives a cost-effective transition to limiting global warming assuming an effective international agreement in 2015, and this brings about more than doubling nuclear capacity to 862 GWe in 2040, while energy-related CO2 emissions peak before 2020 and then decline. In this scenario, almost all new generating capacity built after 2030 needs to be low-carbon.

"Despite the challenges it currently faces, nuclear power has specific characteristics that underpin the commitment of some countries to maintain it as a future option," it said. "Nuclear plants can contribute to the reliability of the power system where they increase the diversity of power generation technologies in the system. For countries that import energy, it can reduce their dependence on foreign supplies and limit their exposure to fuel price movements in international markets."

It is noteworthy that in the 1980s, 218 power reactors started up, an average of one every 17 days. These included 47 in USA, 42 in France and 18 in Japan. These were fairly large - average power was 923.5 MWe. So it is not hard to imagine a similar number being commissioned in the years ahead. But with China and India getting up to speed in nuclear energy and a world energy demand increasing, a realistic estimate of what is possible (but not planned at this stage) might be the equivalent of one 1000 MWe unit worldwide every 5 days.

Increased capacity

Increased nuclear capacity in some countries is resulting from the uprating of existing plants. This is a highly cost-effective way of bringing on new capacity.

There is a question of scale, and large units will not fit into small grids. A conservative guide is that peak power demand must be met with effective installed capacity and about 20% reserve margin. Also, the largest single plant should not be more than 10% of base-load, or 5% of peak demand.

Numerous power reactors in USA, Belgium, Sweden and Germany, for example, have had their generating capacity increased.

In Switzerland, the capacity of its five reactors has been increased by 13.4%.

In the USA, the Nuclear Regulatory Commission has approved more than 140 uprates totalling over 6500 MWe since 1977, a few of them "extended uprates" of up to 20%.

Spain has had a program to add 810 MWe (11%) to its nuclear capacity through upgrading its nine reactors by up to 13%. Most of the increase is already in place. For instance, the Almarez nuclear plant was boosted by 7.4% at a cost of US$ 50 million.

Finland Finland boosted the capacity of the original Olkiluoto plant by 29% to 1700 MWe. This plant started with two 660 MWe Swedish BWRs commissioned in 1978 and 1980. The Loviisa plant, with two VVER-440 (PWR) reactors, has been uprated by 90 MWe (10%).

Sweden's utilities have uprated all three plants. The Ringhals plant was uprated by about 305 MWe over 2006-14. Oskarshamn 3 was uprated by 21% to 1450 MWe at a cost of €313 million. Forsmark 2 had a 120 MWe uprate (12%) to 2013.

Nuclear plant construction

Most reactors currently planned are in the Asian region, with fast-growing economies and rapidly-rising electricity demand.

Many countries with existing nuclear power programs (Argentina, Armenia, Brazil, Bulgaria, China, Czech Rep., India, Pakistan, Romania, Russia, Slovakia, South Korea, South Africa, UAE, Ukraine, UK, USA) have plans to build new power reactors (beyond those now under construction).

In all, over 160 power reactors with a total net capacity of some 182,000 MWe are planned and over 300 more are proposed. Energy security concerns and greenhouse constraints on coal burning have combined with basic economics to put nuclear power back on the agenda for projected new capacity in many countries.

In the USA there are plans for five new reactors, beyond the five under construction now. It is expected that some of the new reactors will be on line by 2020.

In Finland, construction is now under way on a fifth, very large reactor which is expected to come on line in 2018, and plans are progressing for another large one to follow it.

France is building a similar 1600 MWe unit at Flamanville, for operation from 2018.

In the UK, four similar 1600 MWe units are planned, and a further 6000 MWe is proposed.

Romania's second power reactor istarted up in 2007, and plans are being implemented for two further Canadian units to be built there.

Slovakia is completing two 470 MWe units at Mochovce, to operate from 2017.

Bulgaria is planning to build a large new reactor at Kozloduy.

Belarus is building two large new Russian reactors at Ostrovets.

In Russia, several reactors and two small ones are under active construction, and one recently put into operation is a large fast neutron reactor. About 25 further reactors are then planned, some to replace existing plants. This will increase the country's present nuclear power capacity significantly by 2030. In addition about 5 GW of nuclear thermal capacity is planned. A small floating power plant is expected to be commissioned by 2018 and others are planned to follow.

Poland is planning two 3000 MWe nuclear power plants.

South Korea plans to bring a further further four reactors into operation by 2018, and another eight by about 2030, giving total new capacity of 17,200 MWe. All of these are the Advanced PWRs of 1400 MWe. These APR-1400 designs have evolved from a US design which has US NRC design certification, and four been sold to the UAE (see below).

Japan has two reactors under construction but another three which were likely to start building by mid-2011 have been deferred.

In China, now with 32 operating reactors on the mainland, the country is well into the growth phase of its nuclear power programme. There were eight new grid connections in 2015. Over 20 more reactors are under construction, including the world's first Westinghouse AP1000 units, and a demonstration high-temperature gas-cooled reactor plant. Many more units are planned, including two largely indigenous designs – the Hualong One and CAP1400. China aims to more than double its nuclear capacity by 2020.

India has 21 reactors in operation, and six under construction. This includes two large Russian reactors and a large prototype fast breeder reactor as part of its strategy to develop a fuel cycle which can utilise thorium. Over 20 further units are planned. 18 further units are planned, and proposals for more - including western and Russian designs - are taking shape following the lifting of trade restrictions.

Pakistan has third and fourth 300 MWe reactors under construction at Chashma, financed by China. Two larger Chinese power reactors are planned.

In Kazakhstan, a joint venture with Russia's Atomstroyexport envisages development and marketing of innovative small and medium-sized reactors, starting with a 300 MWe Russian design as baseline for Kazakh units.

In Iran a 1000 MWe PWR at Bushehr came on line in 2011, and further units are planned.

The United Arab Emirates awarded a $20.4 billion contract to a South Korean consortium to build four 1400 MWe reactors by 2020. They are under construction, on schedule.

Jordan has committed plans for its first reactor, and is developing its legal and regulatory infrastructure.

Turkey has contracts signed for four 1200 MWe Russian nuclear reactors at one site and four European ones at another. Its legal and regulatory infrastructure is well-developed.

Vietnam has committed plans for its first reactors at two sites (2x2000 MWe), and is developing its legal and regulatory infrastructure. The first plant will be a turnkey project built by Atomstroyexport. The second will be Japanese.

Fuller details of all the above are in linked country papers.

Plant life extension and retirements

Most nuclear power plants originally had a nominal design lifetime of 25 to 40 years, but engineering assessments of many plants have established that many can operate longer. In the USA over 75 reactors have been granted licence renewals which extend their operating lives from the original 40 out to 60 years, and operators of most others are expected to apply for similar extensions. Such licence extensions at about the 30-year mark justify significant capital expenditure for replacement of worn equipment and outdated control systems.

In France, there are rolling ten-year reviews of reactors. In 2009 the Nuclear Safety Authority (ASN) approved EdF's safety case for 40-year operation of the 900 MWe units, based on generic assessment of the 34 reactors. There are plans to take reactor lifetimes out to 60 years, involving substantial expenditure.

The Russian government is extending the operating lives of most of the country's reactors from their original 30 years, for 15 years, or for 25 years in the case of the newer VVER-1000 units, with significant upgrades.

The technical and economic feasibility of replacing major reactor components, such as steam generators in PWRs, and pressure tubes in CANDU heavy water reactors, has been demonstrated. The possibilities of component replacement and licence renewals extending the lifetimes of existing plants are very attractive to utilities, especially in view of the public acceptance difficulties involved in constructing replacement nuclear capacity.

On the other hand, economic, regulatory and political considerations have led to the premature closure of some power reactors, particularly in the United States, where reactor numbers have fell from 110 to 99, in eastern Europe, in Germany and likely in Japan.

It should not be assumed that reactors will close when their licence is due to expire, since licence renewal is now common. However, new plants coming on line are balanced by old plants being retired. Over 1996-2015, 75 reactors were retired as 80 started operation. There are no firm projections for retirements over the next two decades, but the World Nuclear Association estimates that at least 60 of those now operating will close by 2030, most being small plants. The 2015 WNA Nuclear Fuel Report reference case has 132 reactors closing by 2035, using very conservative assumptions about licence renewal, and 287 coming on line, including many in China.

The World Nuclear Power Reactor table gives a fuller and (for current year) possibly more up to date overview of world reactor status.

Power reactors under construction

Start †   Reactor Type Gross MWe
2016 India, NPCIL Kudankulam 2 PWR 950
2016 India, NPCIL Kakrapar 3 PHWR 640
2016 India, Bhavini Kalpakkam FBR 470
2016 Russia, Rosenergoatom Novovoronezh II-1 PWR 1070
2016 USA, TVA Watts Bar 2 PWR 1180
2016 China, CNNC Sanmen 1 PWR 1250
2016 China, SPI Haiyang 1 PWR 1250
2016 China, CNNC Changjiang 2 PWR 650
2016 China, CNNC Fuqing 3 PWR 1080
2016 China, CGN Fangchenggang 2 PWR 1080
2016 India, NPCIL Rajasthan 7 PHWR 640
2016 Pakistan, PAEC Chashma 3 PWR 300
         
2017 Slovakia, SE Mochovce 3 PWR 440
2017 Russia, Rosenergoatom Pevek FNPP PWR x 2 70
2017 Russia, Rosenergoatom Leningrad II-1 PWR 1070
2017 UAE, ENEC Barakah 1 PWR 1400
2017 China, CGN Taishan 1 PWR 1700
2017 China, CGN Taishan 2 PWR 1700
2017 China, CNNC Sanmen 2 PWR 1250
2017 China, SPI Haiyang 2 PWR 1250
2017 China, CGN Yangjiang 4 PWR 1080
2017 China, CNNC Fuqing 4 PWR 1080
2017 China, China Huaneng Shidaowan HTR 200
2017 China, CNNC Tianwan 3 PWR 1060
2017 Russia, Rosenergoatom Rostov 4 PWR 1200
2017 Korea, KHNP Shin-Kori 4 PWR 1350
2017 Korea, KHNP Shin-Hanul 1 PWR 1350
2017 India, NPCIL Kakrapar 4 PHWR 640
2017 India, NPCIL Rajasthan 8 PHWR 640
2017 Pakistan, PAEC Chashma 4 PWR 300
         
2018 Russia, Rosenergoatom Novovoronezh II-2 PWR 1070
2018 Slovakia, SE Mochovce 4 PWR 440
2018 France, EdF Flamanville 3 PWR 1600
2018 Finland, TVO Olkilouto 3 PWR 1720
2018 Korea, KHNP Shin-Hanul 2 PWR 1350
2018 UAE, ENEC Barakah 2 PWR 1400
2018 Brazil Angra 3 PWR 1405
2018 Argentina Carem25 PWR 27
2018 China, CGN Yangjiang 5 PWR 1080
2018 China, CNNC Tianwan 4 PWR 1060
         
2019 USA, Southern Vogtle 3 PWR 1200
2019 USA, SCEG Summer 2 PWR 1200
2019 UAE, ENEC Barakah 3 PWR 1400
2019 China, CGN Fangchenggang 3 PWR 1150
2019 China, CGN Hongyanhe 5 PWR 1120
2019 China, CGN Yangjiang 6 PWR 1080
2019 China, CNNC Fuqing 5 PWR 1150
2019 Romania, SNN Cernavoda 3 PHWR 720
         
2020 Russia, Rosenergoatom Leningrad II-2 PWR 1070
2020 China, CGN Hongyanhe 6 PWR 1120
2020 China, CGN Ningde 5 PWR 1150
2020 China, CGN Fangchenggang 4 PWR 1150
2020 China, CNNC Fuqing 6 PWR 1150
2020 UAE, ENEC Barakah 4 PWR 1400
2020 Romania, SNN Cernavoda 4 PHWR 720

† Latest announced year of proposed commercial operation

Sources:
World Nuclear Association information papers

 

  • Nuclear power is the only large-scale energy-producing technology which takes full responsibility for all its wastes and fully costs this into the product.
  • The amount of radioactive wastes is very small relative to wastes produced by fossil fuel electricity generation.
  • Used nuclear fuel may be treated as a resource or simply as a waste.
  • Nuclear wastes are neither particularly hazardous nor hard to manage relative to other toxic industrial wastes.
  • Safe methods for the final disposal of high-level radioactive waste are technically proven; the international consensus is that this should be geological disposal.

All parts of the nuclear fuel cycle produce some radioactive waste (radwaste) and the relatively modest cost of managing and disposing of this is part of the electricity cost, i.e. it is internalised and paid for by the electricity consumers.

At each stage of the fuel cycle there are proven technologies to dispose of the radioactive wastes safely. For low- and intermediate-level wastes these are mostly being implemented. For high-level wastes some countries await the accumulation of enough of it to warrant building geological repositories; others, such as the USA, have encountered political delays.

Unlike other industrial wastes, the level of hazard of all nuclear waste – its radioactivity – diminishes with time. Each radionuclidea contained in the waste has a half-life – the time taken for half of its atoms to decay and thus for it to lose half of its radioactivity. Radionuclides with long half-lives tend to be alpha and beta emitters – making their handling easier – while those with short half-lives tend to emit the more penetrating gamma rays. Eventually all radioactive wastes decay into non-radioactive elements. The more radioactive an isotope is, the faster it decays.

The main objective in managing and disposing of radioactive (or other) waste is to protect people and the environment. This means isolating or diluting the waste so that the rate or concentration of any radionuclides returned to the biosphere is harmless. To achieve this, practically all wastes are contained and managed – some clearly need deep and permanent burial. From nuclear power generation, none is allowed to cause harmful pollution.

All toxic wastes need to be dealt with safely, not just radioactive wastes. In countries with nuclear power, radioactive wastes comprise less than 1% of total industrial toxic wastes (the balance of which remains hazardous indefinitely).

Types of radioactive waste

Exempt waste & very low level waste

Exempt waste and very low level waste (VLLW) contains radioactive materials at a level which is not considered harmful to people or the surrounding environment. It consists mainly of demolished material (such as concrete, plaster, bricks, metal, valves, piping etc) produced during rehabilitation or dismantling operations on nuclear industrial sites. Other industries, such as food processing, chemical, steel etc also produce VLLW as a result of the concentration of natural radioactivity present in certain minerals used in their manufacturing processes (see also information page on Naturally-Occurring Radioactive Materials). The waste is therefore disposed of with domestic refuse, although countries such as France are currently developing facilities to store VLLW in specifically designed VLLW disposal facilities.

Low-level waste

Low-level waste (LLW) is generated from hospitals and industry, as well as the nuclear fuel cycle. It comprises paper, rags, tools, clothing, filters etc, which contain small amounts of mostly short-lived radioactivity. It does not require shielding during handling and transport and is suitable for shallow land burial. To reduce its volume, it is often compacted or incinerated before disposal. It comprises some 90% of the volume but only 1% of the radioactivity of all radioactive waste.

Intermediate-level waste

Intermediate-level waste (ILW) contains higher amounts of radioactivity and some requires shielding. It typically comprises resins, chemical sludges and metal fuel cladding, as well as contaminated materials from reactor decommissioning. Smaller items and any non-solids may be solidified in concrete or bitumen for disposal. It makes up some 7% of the volume and has 4% of the radioactivity of all radwaste. By definition, its radioactive decay generates heat of less than about 2 kW/m3 so does not require heating to be taken into account in design of storage or disposal facilities.

High-level waste

High-level waste (HLW) arises from the 'burning' of uranium fuel in a nuclear reactor. HLW contains the fission products and transuranic elements generated in the reactor core. It is highly radioactive and hot due to decay heat, so requires cooling and shielding. It has thermal power above about 2 kW/m3 and can be considered as the 'ash' from 'burning' uranium. HLW accounts for over 95% of the total radioactivity produced in the process of electricity generation. There are two distinct kinds of HLW:

HLW has both long-lived and short-lived components, depending on the length of time it will take for the radioactivity of particular radionuclides to decrease to levels that are considered no longer hazardous for people and the surrounding environment. If generally short-lived fission products can be separated from long-lived actinides, this distinction becomes important in management and disposal of HLW.

HLW is a major focus of attention regarding nuclear power, and is managed accordingly.

Mining and milling

Traditional uranium mining generates fine sandy tailings, which contain virtually all the naturally occurring radioactive elements naturally found in uranium ore. These are collected in engineered tailings dams and finally covered with a layer of clay and rock to inhibit the leakage of radon gas and ensure long-term stability. In the short term, the tailings material is often covered with water. After a few months, the tailings material contains about 75% of the radioactivity of the original ore. Strictly speaking these are not classified as radioactive wastes.

Conversion, enrichment, fuel fabrication

Uranium oxide concentrate from mining, essentially 'yellowcake' (U3O8), is not significantly radioactive – barely more so than the granite used in buildings. It is refined then converted to uranium hexafluoride gas (UF6). As a gas, it undergoes enrichment to increase the U-235 content from 0.7% to about 3.5%. It is then turned into a hard ceramic oxide (UO2) for assembly as reactor fuel elements.

The main byproduct of enrichment is depleted uranium (DU), principally the U-238 isotope, which is stored either as UF6 or U3O8. About 1.2 million tonnes of DU is now stored. Some is used in applications where its extremely high density makes it valuable, such as the keels of yachts and military projectiles. It is also used (with reprocessed plutonium) for making mixed oxide fuel and to dilute highly-enriched uranium from dismantled weapons which is now being used for reactor fuel (see pages on Uranium and Depleted Uranium and Military Warheads as a Source of Nuclear Fuel).

Electricity generation

In terms of radioactivity, high-level waste (HLW) is the major issue arising from the use of nuclear reactors to generate electricity. Highly radioactive fission products and also transuranic elements are produced from uranium and plutonium during reactor operations and are contained within the used fuel. Where countries have adopted a closed cycle and utilised reprocessing to recycle material from used fuel, the fission products and minor actinidesbare separated from uranium and plutonium and treated as HLW (uranium and plutonium is then re-used as fuel in reactors). In countries where used fuel is not reprocessed, the used fuel itself is considered a waste and therefore classified as HLW.

Low- and intermediate-level waste is produced as a result of operations, such as the cleaning of reactor cooling systems and fuel storage ponds, the decontamination of equipment, filters and metal components that have become radioactive as a result of their use in or near the reactor.

How much waste is produced?

As already noted, the volume of nuclear waste produced by the nuclear industry is very small compared with other wastes generated. Each year, nuclear power generation facilities worldwide produce about 200,000 m3 of low- and intermediate-level radioactive waste, and about 10,000 m3 / 12,000 tonnes of high-level waste including used fuel designated as waste1.

In the OECD countries, some 300 million tonnes of toxic wastes are produced each year, but conditioned radioactive wastes amount to only 81,000 m3 per year.

In the UK, for example, the total amount of radioactive waste (including radioactive waste expected to arise from existing nuclear facilities) is about 4.7 million m3, or around 5 million tonnes. A further 1 million m3 has already been disposed. Of the UK's total radioactive waste, about 94% (i.e. about 4.4 million m3) falls into the low-level radioactive waste (LLW) category. About 6% (290,000 m3) is in the intermediate-level radioactive waste (ILW) category, and less than 0.1% (1000 m3) is classed as high-level waste (HLW). Although the volume of HLW is relatively small, it contains about 95% of the total inventory of radioactivity12.

A typical 1000 MWe light water reactor will generate (directly and indirectly) 200-350 m3 low- and intermediate-level waste per year. It will also discharge about 20 m3 (27 tonnes) of used fuel per year, which corresponds to a 75 m3disposal volume following encapsulation if it is treated as waste. Where that used fuel is reprocessed, only 3 m3 of vitrified waste (glass) is produced, which is equivalent to a 28 m3 disposal volume following placement in a disposal canister.

This compares with an average 400,000 tonnes of ash produced from a coal-fired plant of the same power capacity. Today, volume reduction techniques and abatement technologies as well as continuing good practice within the work force all contribute to continuing minimisation of waste produced, a key principle of waste management policy in the nuclear industry. Whilst the volumes of nuclear wastes produced are very small, the most important issue for the nuclear industry is managing their toxic nature in a way that is environmentally sound and presents no hazard to both workers and the general public.

Managing high-level waste

Used fuel gives rise to high-level waste (HLW) which may be either the used fuel itself in fuel rods, or the separated waste arising from reprocessing this (see next section on Recycling used fuel). In either case, the amount is modest – as noted above, a typical reactor generates about 27 tonnes of used fuel which may be reduced to 3 m3 per year of vitrified waste. Both can be effectively and economically isolated, and have been handled and stored safely since nuclear power began.

Storage of used fuel is mostly in ponds associated with individual reactors, or in a common pool at multi-reactor sites, or occasionally at a central site. See later section below.

If the used fuel is reprocessed, as is that from UK, French, German, Japanese and Russian reactors, HLW comprises highly-radioactive fission products and some transuranic elements with long-lived radioactivity. These are separated from the used fuel, enabling the uranium and plutonium to be recycled. Liquid HLW from reprocessing must be solidified. The HLW also generates a considerable amount of heat and requires cooling. It is vitrified into borosilicate (Pyrex) glass, encapsulated into heavy stainless steel cylinders about 1.3 metres high and stored for eventual disposal deep underground. This material has no conceivable future use and is unequivocally waste. The hulls and end-fittings of the reprocessed fuel assemblies are compacted, to reduce volume, and usually incorporated into cement prior to disposal as ILW. France has two commercial plants to vitrify HLW left over from reprocessing oxide fuel, and there are also plants in the UK and Belgium. The capacity of these Western European plants is 2,500 canisters (1000 t) a year, and some have been operating for three decades.

If used reactor fuel is not reprocessed, it will still contain all the highly radioactive isotopes, and then the entire fuel assembly is treated as HLW for direct disposal. It too generates a lot of heat and requires cooling. However, since it largely consists of uranium (with a little plutonium), it represents a potentially valuable resource and there is an increasing reluctance to dispose of it irretrievably.

Either way, after 40-50 years the heat and radioactivity have fallen to one thousandth of the level at removal. This provides a technical incentive to delay further action with HLW until the radioactivity has reduced to about 0.1% of its original level.

After storage for about 40 years the used fuel assemblies are ready for encapsulation or loading into casks ready for indefinite storage or permanent disposal underground.

Direct disposal of used fuel has been chosen by the USA and Sweden among others, although evolving concepts lean towards making it recoverable if future generations see it as a resource. This means allowing for a period of management and oversight before a repository is closed.

Used fuel is subject to international safeguards due to its uranium and plutonium content. Separated (and vitrified) HLW is not subject to safeguards, which is another factor in easier handling.

Radioactive Decay in Fuel

Both direct disposal and reprocessing are in accordance with the definition of sustainable used fuel management set out by the World Nuclear Association.*

* The World Nuclear Association considers used fuel management to be sustainable if it meets the following key criteria:

  • It covers all the steps of used fuel management from the generation of used fuel up to and including final disposal in accordance with a well defined practical plan.
  • It proves to be feasible with a sustainable impact level.
  • It includes a realistic financing plan.
  • It is able to demonstrate to a practicable extent that it is technically and economically viable.
  • It protects human health and the environment and has no greater impact on the health of future generations than is allowed today.
  • It answers to a present need but does not impose burdens on future generations.

Due to the long-term nature of these management plans, sustainable options must have one or more pre-defined milestones where a decision could be taken on which option to proceed with.

Recycling used fuel

Any used fuel will still contain some of the original U-235 as well as various plutonium isotopes which have been formed inside the reactor core, and the U-238c. In total these account for some 96% of the original uranium and over half of the original energy content (ignoring U-238). Reprocessing, undertaken in Europe and Russia, separates this uranium and plutonium from the wastes so that they can be recycled for re-use in a nuclear reactor (see page onProcessing of Used Nuclear Fuel). Plutonium arising from reprocessing is recycled through a MOX fuel fabrication plant where it is mixed with depleted uranium oxide to make fresh fuel (see page on Mixed Oxide Fuel). European reactors currently use over 5 tonnes of plutonium a year in fresh MOX fuel.

Major commercial reprocessing plants operate in France, UK, and Russia with a capacity of some 5000 tonnes per year and cumulative civilian experience of 80,000 tonnes over 50 years. A new reprocessing plant with an 800 t/yr capacity at Rokkasho in Japan is undergoing commissioning. France and UK also undertake reprocessing for utilities in other countries, notably Japan, which has made over 140 shipments of used fuel to Europe since 1979. Until now most Japanese used fuel has been reprocessed in Europe, with the vitrified waste and the recovered uranium and plutonium (as MOX fuel) being returned to Japan to be used in fresh fuel (see page on Japanese Waste and MOX Shipments From Europe). Russia also reprocesses some used fuel from Soviet-designed reactors in other countries.

There are several proposed developments of reprocessing technologies (described in the page on Processing of Used Nuclear Fuel). One technology under development would separate plutonium along with the minor actinides as one product. This however cannot be simply put into MOX fuel and recycled in conventional reactors; it requires fast neutron reactors which are as yet few and far between. On the other hand, it will make disposal of high-level wastes easier.

So the options for used fuel are:

  • Direct disposal (after storage) to a geological repository. The material has very long-lived radioactivity, and will take about 300,000 years to reach the same level as the original ore.
  • Aqueous reprocessing to remove only uranium and plutonium. The material then only takes about 9000 years to reach the same level of radioactivity as the original ore.
  • Advanced electrometallurgical reprocessing which removes uranium, plutonium and minor actinides together for recycling in a fast reactor. The wastes then only need 300 years to reach the same level of radioactivity as the original ore. This is not yet operational on any commercial scale.

THORP Fuel Storage

Storage pond for used fuel at the Thermal Oxide Reprocessing Plant at the UK's Sellafield site
(Sellafield Ltd)

Storage and disposal of used fuel and separated HLW

There is about 240,000 tonnes of used fuel in storage, much of it at reactor sites. About 90% of this is in storage ponds (smaller versions of that illustrated above), the balance in dry storage. Much of the world's used fuel is stored thus, and some of it has been there for decades. Annual arisings of used fuel are about 7,000 tonnes (6,000 t from LWRs), and up to 3,000 tonnes of this are intended for reprocessing. Final disposal is not urgent in any logistical sense.

According to GE Hitachi, in 2015 funds set aside for managing and disposal of used fuel totaled about $100 billion, about $51 billion of this in Europe, $40 billion in the USA and $6.5 billion in Canada.

Storage ponds at reactors, and those at centralized facilities such as CLAB in Sweden, are 7-12 metres deep, to allow several metres of water over the used fuel comprising racked fuel assemblies typically about 4 m long and standing on end. The multiple racks are made of metal with neutron absorbers incorporated in it. The circulating water both shields and cools the fuel. These pools are robust constructions made of thick reinforced concrete with steel liners. Ponds at reactors are often designed to hold all the used fuel for the life of the reactor.

Some storage of fuel assemblies which have been cooling in ponds for at least five years is in dry casks, or vaults with air circulation inside concrete shielding. One common system is for sealed steel casks or multi-purpose canisters (MPCs) each holding about 80 fuel assemblies with inert gas. Casks/ MPCs may be used also for transporting and eventual disposal of the used fuel. For storage, each is enclosed in a ventilated storage module made of concrete and steel. These are commonly standing on the surface, about 6m high, cooled by air convection, or they may be below grade, with just the tops showing. The modules are robust and provide full shielding. Each cask has up to 45 kW heat load.

A collection of casks or modules comprises an Independent Spent Fuel Storage Installation (ISFSI), which in the USA is licensed separately from any associated power plant, and is for interim storage only. About one quarter of US used fuel is stored thus.

For disposal, to ensure that no significant environmental releases occur over tens of thousands of years, 'multiple barrier' geological disposal is planned. This immobilises the radioactive elements in HLW and some ILW and isolates them from the biosphere. The main barriers are:

  • Immobilise waste in an insoluble matrix such as borosilicate glass or synthetic rock (fuel pellets are already a very stable ceramic: UO2).
  • Seal it inside a corrosion-resistant container, such as stainless steel.
  • Locate it deep underground in a stable rock structure.
  • Surround containers with an impermeable backfill such as bentonite clay if the repository is wet.

Vitrification

Loading silos with canisters containing vitrified HLW in the UK. Each disc on the floor covers a silo holding ten canisters

HLW from reprocessing must be solidified. France has two commercial plants to vitrify HLW left over from reprocessing oxide fuel, and there are also significant plants in the UK and Belgium. The capacity of these western European plants is 2,500 canisters (1000 t) a year, and some have been operating for three decades. By mid-2009, the UK Sellafield vitrification plant had produced it 5000th canister of vitrified HLW, representing 3000 m3 of liquor reduced to 750 m3 of glass. The plant fills about 400 canisters per year.

The Australian Synroc (synthetic rock) system is a more sophisticated way to immobilise such waste, and this process may eventually come into commercial use for civil wastes. (see page on Synroc).

To date there has been no practical need for final HLW repositories, as surface storage for 40-50 years is first required so that heat and radioactivity can decay to levels which make handling and storage easier.

The process of selecting appropriate deep geological repositories is now underway in several countries. Finland and Sweden are well advanced with plans for direct disposal of used fuel in mined repositories, since their parliaments decided to proceed on the basis that it was safe, using existing technology. Both countries have selected sites, in Sweden, after competition between two municipalities. The USA has opted for a final repository at Yucca Mountain in Nevada, though this is now stalled due to political decision. There have also been proposals for international HLW repositories in optimum geology2. (See also information page on International Nuclear Waste Disposal Concepts.)

Relative activity of used fuel with 38 GWd/t burn-up

Relative activity of used fuel with 38 GWd/t burn-up
Source: IAEA (referenced in Radioactive Waste in Perspective NEA 2010, p74)

A current question is whether wastes should be emplaced so that they are readily retrievable from repositories. There are sound reasons for keeping such options open – in particular, it is possible that future generations might consider the buried waste to be a valuable resource. On the other hand, permanent closure might increase long-term security of the facility. After being buried for about 1,000 years most of the radioactivity will have decayed. The amount of radioactivity then remaining would be similar to that of the naturally-occurring uranium ore from which it originated, though it would be more concentrated. In mined repositories, which represent the main concept being pursued, retrievability can be straightforward, but any deep borehole disposal is permanent.

Deep boreholes are more appropriate for smaller amounts of wastes than national programs involving direct disposal of used fuel, and hence are more likely to be used for smaller volumes of shorter-lived wastes arising from Generation IV fuel cycles.

France's 2006 waste law says that HLW disposal must be "reversible", which was clarified in a 2015 amendment to mean guaranteeing long-term flexibility in disposal policy, while “retrievable” referred to short-term practicality. France, Switzerland, Canada, Japan and the USA require retrievability, and that is policy also in most other countries, though this presupposes that in the long-term, the repository would be sealed to satisfy safety requirements.

The measures or plans that various countries have in place to store, reprocess and dispose of used fuel and wastes are described in Appendix 3: National Policies and summarised in the following Table. Storage and disposal options are described more fully in Appendix 2.

Waste management for used fuel and HLW from nuclear power reactors

Country Policy Facilities and progress towards final repositories
Belgium Reprocessing
  • Central waste storage at Dessel
  • Underground laboratory established 1984 at Mol
  • Construction of repository to begin about 2035
Canada Direct disposal
  • Nuclear Waste Management Organisation set up 2002
  • Deep geological repository confirmed as policy, retrievable
  • Repository site search from 2009, planned for use 2025
China Reprocessing
  • Central used fuel storage at LanZhou
  • Repository site selection to be completed by 2020
  • Underground research laboratory from 2020, disposal from 2050
Finland Direct disposal
  • Program start 1983, two used fuel storages in operation
  • Posiva Oy set up 1995 to implement deep geological disposal
  • Underground research laboratory Onkalo under construction
  • Repository planned from this, near Olkiluoto, open in 2023
France Reprocessing
  • Underground rock laboratories in clay and granite
  • Parliamentary confirmation in 2006 of deep geological disposal, containers to be retrievable and policy "reversible"
  • Bure clay deposit is likely repository site to be licensed 2015, operating 2025
Germany Reprocessing
but moving to direct disposal
  • Repository planning started 1973
  • Used fuel storage at Ahaus and Gorleben salt dome
  • Geological repository may be operational at Gorleben after 2025
India Reprocessing
  • Research on deep geological disposal for HLW
Japan Reprocessing
  • Underground laboratory at Mizunami in granite since 1996
  • • Used fuel and HLW storage facility at Rokkasho since 1995
    • Used fuel storage under construction at Mutsu, start up 2013
  • NUMO set up 2000, site selection for deep geological repository under way to 2025, operation from 2035, retrievable
Russia Reprocessing
  • Underground laboratory in granite or gneiss in Krasnoyarsk region from 2015, may evolve into repository
  • Sites for final repository under investigation on Kola peninsula
  • Pool storage for used VVER-1000 fuel at Zheleznogorsk since 1985
  • Dry storage for used RBMK and other fuel at Zheleznogorsk from 2012
  • Various interim storage facilities in operation
South Korea Direct disposal, wants to change
  • Waste program confirmed 1998, KRWM seet up 2009
  • Central interim storage planned from 2016
Spain Direct disposal
  • ENRESA established 1984, its plan accepted 1999
  • Central interim storage at Villar de Canas from 2016 (volunteered location)
  • Research on deep geological disposal, decision after 2010
Sweden Direct disposal
  • Central used fuel storage facility – CLAB – in operation since 1985
  • Underground research laboratory at Aspo for HLW repository
  • Osthammar site selected for repository (volunteered location), likely to open in 2028
Switzerland Reprocessing
  • Central interim storage for HLW and used fuel at ZZL Wurenlingen since 2001
  • Smaller used fuel storage at Beznau
  • Underground research laboratory for high-level waste repository at Grimsel since 1983
  • Deep repository by 2020, containers to be retrievable
United Kingdom Reprocessing
  • Low-level waste repository in operation since 1959
  • HLW from reprocessing is vitrified and stored at Sellafield
  • Repository location to be on basis of community agreement
  • New NDA subsidiary to progress geological disposal
USA Direct disposal
but reconsidering
  • DoE responsible for used fuel from 1998, accumulated $32 billion waste fund
  • Considerable research and development on repository in welded tuffs at Yucca Mountain, Nevada
  • The 2002 Congress decision that geological repository be at Yucca Mountain was countered politically in 2009
  • Central interim storage for used fuel now likely

Note: in most countries repositories or at least storage facilities for low-level wastes and intermediate-level wastes are operating. See also individual country papers.

Wastes from decommissioning nuclear plants

In the case of nuclear reactors, about 99% of the radioactivity is associated with the fuel. Apart from any surface contamination of plant, the remaining radioactivity comes from 'activation products' such as steel components which have long been exposed to neutron irradiation. Their atoms are changed into different isotopes such as iron-55, cobalt-60, nickel-63 and carbon-14. The first two are highly radioactive, emitting gamma rays, but with correspondingly short half-lives so that after 50 years from final shutdown their hazard is much diminished. Some caesium-137 may also be in decommissioning wastes.

Some scrap material from decommissioning may be recycled, but for uses outside the industry very low clearance levels are applied, so most is buried and some is recycled within the industry.

Generally, short-lived intermediate-level wastes (mainly from decommissioning reactors) are buried, while long-lived intermediate-level wastes (from fuel reprocessing) will be disposed of deep underground. Low-level wastes are disposed of in shallow burial sites.

Disposal of other radioactive wastes

Some low-level liquid wastes from reprocessing plants are discharged to the sea. These include radionuclides which are distinctive, notably technetium-99 (sometimes used as a tracer in environmental studies), and this can be discerned many hundred kilometres away. However, such discharges are regulated and controlled, and the maximum radiation dose anyone receives from them is a small fraction of natural background radiation.

Nuclear power stations and reprocessing plants release small quantities of radioactive gases (e.g. krypton-85 and xenon-133) and trace amounts of iodine-131 to the atmosphere. However, they have short half-lives, and the radioactivity in the emissions is diminished by delaying their release. Also the first two are chemically inert. The net effect is too small to warrant consideration in any life-cycle analysis.  A little tritium is also produced but regulators do not consider its release to be significant.

The US Nuclear Regulatory Commission classifies low-level wastes into four categories based on radioactivity corresponding to management and disposal requirments: Class A waste has the lowest radioactivity level and decays to background level after about 100 years. It accounts for about 99% of the volume of LLW generated in the USA and includes slightly contaminated paper products, clothing, rags, mops, equipment and tools, as well as depleted uranium. Class B and C wastes include filters, resins, irradiated hardware with activation products, and longer-lived radioisotopes that decay after 300 and 500 years, respectively. Greater-than-Class C LLW has radionuclide concentration limits greater than those specified for Class C waste.

Following the Fukushima accident, large areas were contaminated mainly with caesium fallout. In 2016 the government announced that material with less than 8 kBq/kg caesium would no longer be subject to restriction regarding disposal or use for embankments. This is about six times the average radioactivity of the Earth’s crust and about three times the average radioactivity of Australian coal ash.

It is noteworthy that coal burning produces some 280 million tonnes of ash per year, most of it containing low levels of natural radionuclides3. Some of this could be classified as LLW. It is simply buried. (See also page on Naturally-Occurring Radioactive Materials.)

Costs of radioactive waste management

Financial provisions are made for managing all kinds of civilian radioactive waste. The cost of managing and disposing of nuclear power plant wastes represents about 5% of the total cost of the electricity generated.

Most nuclear utilities are required by governments to put aside a levy (e.g. 0.1 cents per kilowatt hour in the USA to 2014, 0.14 ¢/kWh in France) to provide for management and disposal of their wastes (see Appendix 4: National Funding). So far some US$ 35 billion has been accumulated in the US waste fund from electricity consumers, including some interest.

The actual arrangements for paying for waste management and decommissioning also vary. The key objective is however always the same: to ensure that sufficient funds are available when they are needed. There are three main approaches4:

Provisions on the balance sheet

Sums to cover the anticipated costs of waste management and decommissioning are included on the generating company's balance sheet as a liability. As waste management and decommissioning work proceeds, the company has to ensure that it has sufficient investments and cashflow to meet the required payments.

Internal fund

Payments are made over the life of the nuclear facility into a special fund that is held and administered within the company. The rules for the management of the fund vary, but many countries allow the fund to be re-invested in the assets of the company, subject to adequate securities and investment returns.

External fund

Payments are made into a fund that is held outside the company, often within government or administered by a group of independent trustees. Again, rules for the management of the fund vary. Some countries only allow the fund to be used for waste management and decommissioning purposes, others allow companies to borrow a percentage of the fund to reinvest in their business.

Natural precedents for geological disposal

Nature has already proven that geological isolation is possible through several natural examples (or 'analogues'). The most significant case occurred almost 2 billion years ago at Oklo in what is now Gabon in West Africa, where several spontaneous nuclear reactors operated within a rich vein of uranium ore5. (At that time the concentration of U-235 in all natural uranium was about 3%.) These natural nuclear reactors continued for about 500,000 years before dying away. They produced all the radionuclides found in HLW, including over 5 tonnes of fission products and 1.5 tonnes of plutonium, all of which remained at the site and eventually decayed into non-radioactive elements.

The study of such natural phenomena is important for any assessment of geologic repositories, and is the subject of several international research projects. However, it must be noted that the Oklo reactions proceeded because groundwater was present as a moderator in the 'enriched' and permeable uranium ore.

Legacy wastes

In addition to the routine wastes from current nuclear power generation there are other radioactive wastes referred to as 'legacy wastes'. These wastes exist in several countries which pioneered nuclear power and especially where power programmes were developed out of military programmes. These are sometimes voluminous and difficult, and arose in the course of those countries getting to a position where nuclear technology is a commercial proposition for power generation. They represent a liability which is not covered by current funding arrangements. In the UK, some £73 billion (undiscounted) is estimated to be involved in addressing these6 – principally from Magnox and some early AGR developments – and about 30% of the total is attributable to military programmes. In the USA, Russia and France the liabilities are also considerable.

Regulation

The nuclear and radioactive waste management industries work to well-established safety standards for the management of radioactive waste. International and regional organisations such as the International Atomic Energy Agency (IAEA), the Nuclear Energy Agency (NEA) of the Organisation for Economic Co-operation and Development (OECD), the European Commission (EC) and the International Commission on Radiological Protection (ICRP) develop standards, guidelines and recommendations under a framework of co-operation to assist countries in establishing and maintaining national standards. National policies, legislation and regulations are all developed from these internationally agreed standards, guidelines and recommendations. Amongst others, these standards aim to ensure the protection of the public and the environment, both now and into the future.

International agreements in the form of conventions have also been established such as the Joint Convention on Nuclear Safety and the Joint Convention on the Safety of Spent Fuel Management and on the Safety of Radioactive Waste Management. The latter was adopted in 1997 by a diplomatic conference convened by the IAEA and came into force in June 2001 following the required number of ratifications.

Other international conventions and directives seek to provide for inter alia, the safe transportation of radioactive material, protection of the environment (including the marine environment) from radioactive waste, and the control of imports and exports of radioactive waste and transboundary movements.

International Atomic Energy Agencyd

The IAEA is the international organisation that advises on the safe and peaceful uses of nuclear technology. It is an agency of the United Nations, based in Vienna, Austria founded in 1957 and it currently has 134 member states from countries with and without nuclear energy programmes. The IAEA develops safety standards, guidelines and recommendations and inter alia provides technical guidance to member states on radioactive waste principles. Member states use the standards and guidelines in developing their own legislation, regulatory documents and guidelines. It also verifies through a safeguards inspection programme compliance with the Nuclear Non-Proliferation Treaty (NPT).

The IAEA's Waste and Environmental Safety Section works to develop internationally agreed standards on the safety of radioactive waste. The Radioactive Waste Safety Standards Programme (RADWASS) provides guidance to member states to produce their own policies and regulations for the safe management of radioactive waste, including disposal7.

In addition, the IAEA helps member states by providing technical assistance with services, equipment and training and by conducting radiological assessments.

Nuclear Energy Agencye

The Nuclear Energy Agency of the OECD is based in Paris, France. It has a variety of waste management programmes involving its 28 member states. The organisation aims to assist these states in developing safe waste disposal strategies and policies for spent nuclear fuel, HLW and waste from decommissioning nuclear facilities. It also works closely with the IAEA on nuclear safety standards and other technical activities.

The NEA has a project aimed at preserving records, knowledge and management (RK&M) of long-lived nuclear waste disposal for future generations.

European Commission

For several years, the European Commission (EC) has attempted to pass Directives aimed at ensuring a common approach to nuclear safety and radioactive waste management. The so-called 'Nuclear Package' of Directives on nuclear safety and waste management was a top-down approach which met with considerable opposition from several Member States and was revised on several occasions leading to the 2011 adoption of a scaled-back version.8

In July 2011 the European Union adopted a directive for the disposal of used nuclear fuel and radioactive wastes which required member countries to develop national waste management plans for European Commission review by 2015. The plans must include firm timetables for the construction of disposal facilities, descriptions of needed implementation activities, cost assessments, and financing schemes. Safety standards promulgated by the IAEA would become legally binding within the EU-wide policy framework. International peer reviews should be invited at least every ten years.

The agreement allows two or more member nations to develop joint disposal facilities and allows transport of used fuel and radioactive wastes within the EU. Exports outside the EU will only be possible to countries that already have a repository in operation that meets IAEA standards. For overseas reprocessing, ultimate wastes must be returned to the originating EU country. The directive acknowledges that no country currently operates such a repository and projects that a minimum of 40 years would be required to develop one. The shipment of used fuel and radioactive wastes to African, Pacific and Caribbean countries and to Antarctica is explicitly banned. Plans are expected to use a step-by-step approach to geologic disposal based on the voluntary involvement of potential host communities. Two routes are acknowledged: one to dispose of used nuclear fuel as waste; the other to reprocess the fuel and recycle the uranium and plutonium while disposing of the remainder as waste.

The directive became effective in August 2011, and national governments, which retain ultimate responsibility for wastes, had two years to bring their nuclear waste legislation into line with it. There are 143 nuclear energy facilities generating used fuel in 14 of the EU’s 27 member nations. The remaining nations possess radioactive waste requiring disposal that has been produced by research, medicine and industry.

International Commission on Radiological Protectionf

The International Commission on Radiological Protection (ICRP) is an independent registered charity that issues recommendations for protection against all sources of radiation. The IAEA interprets these recommendations into international safety standards and guidelines for radiological protection. National regulators may also adopt the recommendations by the ICRP for their own radiation protection standards.

In March 2007, the ICRP approved its new fundamental Recommendations on radiological protection (ICRP Publication 103)11, replacing the Commission’s previous Recommendations from 1990. Amongst others, the new recommendations include for the first time an approach for developing a framework to demonstrate radiological protection of the environment.

Perspective

Nuclear wastes are a significant part of the nuclear power picture, and need to be managed and disposed of properly. However in more than 50 decades of civil nuclear power experience they have not caused any serious health or environmental problems, nor posed any real risks to people.

 

Alternatives for power generation are not without challenges, and for a variety of reasons they – particularly those from coal combustion – have not always been well controlled. Both flyash and bottom ash are often loaded with heavy metals (including uranium and thorium – see NORM paper). Flyash is mostly retained for land disposal today, and bottom ash is normally buried also, but not always securely and without effects on groundwater. Groundwater pollution with arsenic, boron, cobalt and mercury is not unusual, and the US EPA in 2011 listed 181 US coal ash ponds which posed a significant hazard, 47 of these a high hazard and threat to life. Burning any fossil fuels gives rise to carbon dioxide emissions, and gaseous pollutants such as nitrogen oxides and often sulfur oxides.

  • The first commercial nuclear power stations started operation in the 1950s.
  • There are over 440 commercial nuclear power reactors operable in 31 countries, with over 390,000 MWe of total capacity. About 60 more reactors are under construction.
  • They provide over 11% of the world's electricity as continuous, reliable base-load power, without carbon dioxide emissions.
  • 55 countries operate a total of about 245 research reactors, and a further 180 nuclear reactors power some 140 ships and submarines.

Nuclear technology uses the energy released by splitting the atoms of certain elements. It was first developed in the 1940s, and during the Second World War to 1945 research initially focussed on producing bombs which released great energy by splitting the atoms of particular isotopes of either uranium or plutonium.

In the 1950s attention turned to the peaceful purposes of nuclear fission, notably for power generation. Today, the world produces as much electricity from nuclear energy as it did from all sources combined in the early years of nuclear power. Civil nuclear power can now boast over 16,800 reactor years of experience and supplies almost 11.5% of global electricity needs, from reactors in 31 countries. In fact, through regional transmission grids, many more than those countries depend on nuclear-generated power.

Many countries have also built research reactors to provide a source of neutron beams for scientific research and the production of medical and industrial isotopes.

Today, only eight countries are known to have a nuclear weapons capability. By contrast, 55 countries operate about 245 civil research reactors, over one-third of these in developing countries. Now 31 countries host some 447 commercial nuclear power reactors with a total installed capacity of over 390,000 MWe (see linked table for up to date figures). This is more than three times the total generating capacity of France or Germany from all sources. About 60 further nuclear power reactors are under construction, equivalent to 16% of existing capacity, while over 160 are firmly planned, equivalent to nearly half of present capacity.
 

Nuclear Electricity Production column graph

Sixteen countries depend on nuclear power for at least a quarter of their electricity. France gets around three-quarters of its power from nuclear energy, while Belgium, Czech Republic, Finland, Hungary, Slovakia, Sweden, Switzerland, Slovenia and Ukraine get one-third or more. South Korea and Bulgaria normally get more than 30% of their power from nuclear energy, while in the USA, UK, Spain, Romania and Russia almost one-fifth is from nuclear. Japan is used to relying on nuclear power for more than one-quarter of its electricity and is expected to return to that level. Among countries which do not host nuclear power plants, Italy and Denmark get almost 10% of their power from nuclear.

In electricity demand, the need for low-cost continuous, reliable supply can be distinguished from peak demand occurring over few hours daily and able to command higher prices. Supply needs to match demand instantly and reliably over time. There are number of characteristics of nuclear power which make it particularly valuable apart from its actual generation cost per unit – MWh or kWh. Fuel is a low proportion of power cost, giving power price stability, and is stored onsite (not depending on continuous delivery). The power from nuclear plants is dispatchable on demand, it can be fairly quickly ramped-up, it contributes to clean air and low-CO2 objectives, it gives good voltage support for grid stability. Reactors can be made to load-follow. These attributes are mostly not monetised in merchant markets, but have great value which is increasingly recognised where dependence on intermittent sources has grown.

There is a clear need for new generating capacity around the world, both to replace old units which contribute a lot of CO2 emissions, and to meet increased expectations for electricity in many countries. There are about 127,000 generating units worldwide, 96.5% of these of 300 MWe or less, and one-quarter of the fossil fuel plants are over 30 years old. There is scope for both large new plants and small ones to replace existing units 1:1, all with near-zero CO2 emissions.

World Nuclear Association projections made in 2016 suggest a 26.7% increase to 494 GWe in operation in 2030 and overall 40% increase to 546 GWe in 2035. (Low and high projections are 368 and 631 GWe for 2030, and 365 and 719 GWe for 2035.)

Improved performance from existing nuclear reactors

As nuclear power plant construction returns to the levels reached during the 1970s and 1980s, those plants now operating are producing more electricity. In 2011, production was 2518 billion kWh. The increase over the six years to 2006 (210 TWh) was equal to the output from 30 large new nuclear power plants. Yet between 2000 and 2006 there was no net increase in reactor numbers (and only 15 GWe in capacity). The rest of the improvement was due to better performance from existing units.

In a longer perspective, from 1990 to 2010, world capacity rose by 57 GWe (17.75%, due both to net addition of new plants and uprating some established ones) and electricity production rose 755 billion kWh (40%). The relative contributions to this increase were: new construction 36%, uprating 7% and availability increase 57%. In 2011 and 2012 both capacity and output diminished due to cutbacks in Germany and Japan following the Fukushima accident.

Considering 400 power reactors over 150 MWe for which data are available: over 1980 to 2000 world median capacity factor increased from 68% to 86%, and since then it has maintained around 85%. Actual load factors are slightly lower: 80% average in 2012 (excluding Japan), due to reactors being operated below their full capacity for various reasons. One-quarter of the world's reactors have load factors of more than 90%, and nearly two-thirds do better than 75%, compared with only about a quarter of them over 75% in 1990. The USA now dominates the top 25 positions, followed by South Korea, but six other countries are also represented there. Four of the top ten reactors for lifetime load factors are South Korean.

US nuclear power plant performance has shown a steady improvement over the past 20 years, and the average load factor in 2012 was 81%, up from 66% in 1990 and 56% in 1980. US average capacity factors have been over 90% in most years since 2000

 

 

- 92.7% in 2015. This places the USA as the performance leader with nearly half of the top 50 reactors, the 50th achieving 94% in 2015-16 (albeit without China and South Korea in those figures). The USA accounts for nearly one-third of the world's nuclear electricity.

In 2015-16, twelve countries with four or more units averaged better than 80% load factor, to which China and South Korea should probably be added, and  French reactors averaged 83%, despite many being run in load-following mode, rather than purely for base-load power.

Some of these figures suggest near-maximum utilisation, given that most reactors have to shut down every 18-24 months for fuel change and routine maintenance. In the USA this used to take over 100 days on average but in the last decade it has averaged about 40 days. Another performance measure is unplanned capability loss, which in the USA has for the last few years been below 2%.
 

World Electricity Production 2012 pie graph

World overview

All parts of the world are involved in nuclear power development, and a few examples follow.

China

The Chinese government plans to increase nuclear generating capacity to 58 GWe with 30 GWe more under construction by 2021. China has completed construction and commenced operation of over 30 new nuclear power reactors since 2002, and some 20 new reactors are under construction. These include the world's first four Westinghouse AP1000 units and a demonstration high-temperature gas-cooled reactor plant. Many more are planned, with construction due to start within about three years. China is commencing export marketing of a largely indigenous reactor design. R&D on nuclear reactor technology in China is second to none.

India

India’s target is to have 14.5 GWe nuclear capacity on line by 2020 as part of its national energy policy. These reactors include light- and heavy water reactors as well as fast reactors. In addition to the 22 online, of both indigenous and foreign design, five power reactors are under construction, including a 500 MWe prototype fast breeder reactor. This will take India's ambitious thorium programme to stage 2, and set the scene for eventual utilization of the country's abundant thorium to fuel reactors.

Russia

Russia plans to increase its nuclear capacity to 30.5 GWe by 2020, using its world-class light water reactors. A large fast breeder unit, the country's second, is producing power and development proceeds on others. An initial floating power plant is under construction, with delivery due in 2018. Russia leads the world in nuclear reactor exports, building and financing new nuclear power plants in several countries.

Europe

Finland and France are both expanding their fleets of nuclear power plants with the 1650 MWe EPR from Areva, two of which are also being built in China. Several countries in Eastern Europe are currently constructing or have firm plans to build new nuclear power plants (Bulgaria, Czech Republic, Hungary, Romania, Slovakia, Slovenia and Turkey).

A UK government energy paper in mid-2006 endorsed the replacement of the country’s ageing fleet of nuclear reactors with new nuclear build, and four 1600 MWe French units are planned for operation by 2023. The government aims to have 16 GWe of new nuclear capacity operating by 2030.

Sweden is closing down some older reactors, and has invested heavily in life extensions and uprates. Hungary, Slovakia and Spain are all implementing or planning for life extensions on existing plants. Germany agreed to extend the operating lives of its nuclear plants, reversing an earlier intention to shut them down, but has again reversed policy following the Fukushima accident and is phasing out nuclear generation by about 2023.

Poland is developing a nuclear program, with 6000 MWe planned. Estonia and Latvia are involved in a joint project with established nuclear power producer Lithuania. Belarus has started construction of its first two Russian reactors.

United States

In the USA, there are four reactors under construction, all new AP1000 designs. One of the reasons for the hiatus in new build in the USA to date has been the extremely successful evolution in maintenance strategies. Over the last 15 years, changes have increased utilization of US nuclear power plants, with the increased output corresponding to 19 new 1000 MW plants being built.

South America

Argentina and Brazil both have commercial nuclear reactors generating electricity, and additional reactors are under construction. Chile has a research reactor in operation and has the infrastructure and intention to build commercial reactors.

South Korea

South Korea has three new reactors under construction domestically as well as four in the UAE. It plans for eight more. It is also involved in intense research on future reactor designs.

SE Asia

Vietnam intends to have it first nuclear power plant operating about 2028 with Russian help and a second soon after with Japanese input. Indonesia and Thailand are planning nuclear power programs.

South Asia

Bangladesh has contracted with Russia to build its first nuclear power plant. Pakistan with Chinese help is building three small reactors inland and two large ones near Karachi.

Central Asia

Kazakhstan with its abundance of uranium is working closely with Russia in planning development of small new reactors for its own use and export.

Middle East

The United Arab Emirates is building four 1450 MWe South Korean reactors at a cost of over $20 billion and is collaborating closely with IAEA and experienced international firms. Iran’s first power reactor is in operation, and more are planned.

Saudi Arabia, Jordan and Egypt are also moving towards employing nuclear energy for power and desalination.

Africa

South Africa is committed to plans for 9600 MWe of further nuclear power capacity.

Nigeria has sought the support of the International Atomic Energy Agency to develop plans for two 1000 MWe reactors.

New countries

In September 2012 the International Atomic Energy Agency (IAEA) expected seven newcomer countries to launch nuclear programs in the near term. It did not name these, but Lithuania, UAE, Turkey, Belarus, Vietnam, Poland, and Bangladesh appear likely candidates. Others had stepped back from commitment, needed more time to set up infrastructure, or did not have credible finance.

See also WNA paper Emerging Nuclear Energy Countries.

Other nuclear reactors

In addition to commercial nuclear power plants, there are about 245 research reactors operating, in 55 countries, with more under construction. These have many uses including research and the production of medical and industrial isotopes, as well as for training.

The use of reactors for marine propulsion is mostly confined to the major navies where it has played an important role for five decades, providing power for submarines and large surface vessels. At least 140 ships, mostly submarines, are propelled by some 180 nuclear reactors and over 13,000 reactor-years of experience has been gained with marine reactors. Russia and the USA have decommissioned many of their nuclear submarines from the Cold War era.

Russia also operates a fleet of six large nuclear-powered icebreakers and a 62,000 tonne cargo ship. It is also completing a floating nuclear power plant with two 40 MWe reactors for use in remote regions.
 

Nuclear Generation by Country 2013 bar graph

 

Note: Taipower used nuclear energy to generate 16% of electricity on the island of Taiwan in 2014.

  • Like all industries, the thermal generation of electricity produces wastes. Whatever fuel is used, these wastes must be managed in ways which safeguard human health and minimise their impact on the environment.
  • Nuclear power is the only energy industry which takes full responsibility for all its wastes, and costs this into the product.

Nuclear power is characterised by the very large amount of energy available from a very small amount of fuel. The amount of waste is correspondingly very small. However, much of the waste is radioactive and therefore must be carefully managed as hazardous waste.

Since the radioactive wastes are essentially created in a nuclear power reactor, it is accepted that they are the responsibility of the country which uses uranium to generate power. There is no moral or legal basis for the responsibility to be elsewhere. 

Radioactive wastes comprise a variety of materials requiring different types of management to protect people and the environment. They are normally classified as low-level, medium-level or high-level wastes, according to the amount and types of radioactivity in them.

Another factor in managing wastes is the time that they are likely to remain hazardous. This depends on the kinds of radioactive isotopes in them, and particularly the half-lives characteristic of each of those isotopes. (The half-life is the time it takes for a given radioactive isotope to lose half of its radioactivity. After four half lives the level of radioactivity is 1/16th of the original and after eight half lives 1/256th, and so on.)

The various radioactive isotopes have half-lives ranging from fractions of a second to minutes, hours or days, through to billions of years. Radioactivity decreases with time as these isotopes decay into stable, non-radioactive ones.

The rate of decay of an isotope is inversely proportional to its half-life; a short half life means that it decays rapidly. Hence, for each kind of radiation, the higher the intensity of radioactivity in a given amount of material, the shorter the half lives involved.

Three general principles are employed in the management of radioactive wastes:

  • Concentrate-and-contain.
  • Dilute-and-disperse.
  • Delay-and-decay.

The first two are also used in the management of non-radioactive wastes. The waste is either concentrated and then isolated, or it is diluted to acceptable levels and then discharged to the environment. Delay-and-decay however is unique to radioactive waste management; it means that the waste is stored and its radioactivity is allowed to decrease naturally through decay of the radioisotopes in it.

Radioactivity arises naturally from the decay of particular forms of some elements, called isotopes. Some isotopes are radioactive, most are not, though here the focus is on the former.There are three kinds of radiation to consider: alpha, beta and gamma. A fourth kind, neutron radiation, generally only occurs inside a nuclear reactor.

Different types of radiation require different forms of protection: 

  • Alpha radiation cannot penetrate the skin and can be blocked out by a sheet of paper, but is dangerous in the lung.
  • Beta radiation can penetrate into the body surface but can be blocked out by a sheet of aluminium foil.
  • Gamma radiation can go deeply into the body and requires several centimetres of lead or concrete, or a metre or so of water, to block it.

Alpha beta gamma

All of these kinds of radiation are, at low levels, naturally part of our environment, where we are all naturally exposed to them at low levels. Any or all of them may be present in any classification of radioactive waste

Types of radioactive waste (radwaste)

Low-level waste is generated from hospitals, laboratories and industry, as well as the nuclear fuel cycle. It comprises paper, rags, tools, clothing, filters etc. which contain small amounts of mostly short-lived radioactivity. It is not dangerous to handle, but must be disposed of more carefully than normal garbage. Usually it is buried in shallow landfill sites. To reduce its volume, it is often compacted or incinerated (in a closed container) before disposal. Worldwide it comprises 90% of the volume but only 1% of the radioactivity of all radwaste.

Intermediate-level waste contains higher amounts of radioactivity and may require special shielding. It typically comprises resins, chemical sludges and reactor components, as well as contaminated materials from reactor decommissioning. Worldwide it makes up 7% of the volume and has 4% of the radioactivity of all radwaste. It may be solidified in concrete or bitumen for disposal. Generally short-lived waste (mainly from reactors) is buried, but long-lived waste (from reprocessing nuclear fuel) is disposed of deep underground.

High-level waste may be the used fuel itself, or the principal waste separated from reprocessing this. While only 3% of the volume of all radwaste, it holds 95% of the radioactivity. It contains the highly-radioactive fission products and some heavy elements with long-lived radioactivity. It generates a considerable amount of heat and requires cooling, as well as special shielding during handling and transport. If the used fuel is reprocessed, the separated waste is vitrified by incorporating it into borosilicate (Pyrex) glass which is sealed inside stainless steel canisters for eventual disposal deep underground.

On the other hand, if used reactor fuel is not reprocessed, all the highly-radioactive isotopes remain in it, and so the whole fuel assemblies are treated as high-level waste. This used fuel takes up about nine times the volume of equivalent vitrified high-level waste which is separated in reprocessing. Used fuel treated as waste must be encapsulated ready for disposal.

Both high-level waste and used fuel are very radioactive and people handling them must be shielded from their radiation. Such materials are shipped in special containers which shield the radiation and which will not rupture in an accident.

Whether used fuel is reprocessed or not, the volume of high-level waste is modest – about 3 cubic metres per year of vitrified waste, or 25-30 tonnes of used fuel for a typical large nuclear reactor. The relatively small amount involved allows it to be effectively and economically isolated.

Radioactive materials in the natural environment

Naturally-occurring radioactive materials are widespread throughout the environment, although concentrations are very low and they are not normally harmful. However, human activity may concentrate these so that they need careful handling – e.g. in coal ash and gas well residues.

Soil naturally contains a variety of radioactive materials – uranium, thorium, radium and the radioactive gas radon which is continually escaping to the atmosphere. Many parts of the Earth's crust are more radioactive than the low-level waste described above. Radiation is not something which arises just from using uranium to produce electricity, although the mining and milling of uranium and some other ores brings these radioactive materials into closer contact with people, and in the case of radon and its daughter products, speeds up their release to the atmosphere. (See also What is radiation?.)

Wastes from the nuclear fuel cycle

Radioactive wastes occur at all stages of the nuclear fuel cycle – the process of producing electricity from nuclear materials. The fuel cycle comprises the mining and milling of the uranium ore, its processing and fabrication into nuclear fuel, its use in the reactor, the treatment of the used fuel taken from the reactor after use, and finally, disposal of the wastes.

The fuel cycle is often considered as two parts – the 'front end' which stretches from mining through to the use of uranium in the reactor – and the 'back end' which covers the removal of used fuel from the reactor and its subsequent treatment and disposal. This is where radioactive wastes are a major issue.

Residual materials from the 'front end' of the fuel cycle

The annual fuel requirement for a 1000 MWe light water reactor is about 27 tonnes of enriched uranium oxide. This requires the mining and milling of tens of thousands of tonnes of ore to provide about 200 tonnes of uranium oxide concentrate (U3O8) from the mine.

At uranium mines, dust is controlled to minimise inhalation of radioactive minerals, while concentrations of radon gas (seeping out of the rocks) are kept to a minimum by good ventilation and dispersion in large volumes of air. At the mill, dust is collected and fed back into the process, while radon gas is diluted and dispersed to the atmosphere in large volumes of air.

At the mine, residual ground rock from the milling operation contain most of the radioactive materials from the ore, such as radium. This material is discharged into tailings dams which retain the remaining solids and prevent any seepage of the liquid. The tailings contain about 70% of the radioactivity in the original ore.

Eventually these tailings may be put back into the mine or they may be covered with rock and clay, then revegetated. In this case considerable care is taken to ensure their long-term stability and to avoid any environmental impact (which would be more from acid leaching or dust than from radioactivity as such).

The tailings are usually around ten times more radioactive than typical granites, such as used on city buildings. If someone were to live continuously on top of the Ranger mine tailings they would receive about double their normal radiation dose from the actual tailings (i.e. they would triple their received dose).

With in situ leach (ISL) mining, dissolved materials other than uranium are simply returned underground from where they came, as the water is recirculated.

Uranium oxide (U3O8) produced from the mining and milling of uranium ore is only mildly radioactive – most of the radioactivity in the original ore remains at the mine site in the tailings.

Turning uranium oxide concentrate into a useable fuel has no effect on levels of radioactivity and does not produce significant waste.

First, the uranium oxide is converted into a gas, uranium hexafluoride (UF6), as feedstock for the enrichment process.

Then, during enrichment, every tonne of uranium hexafluoride becomes separated into about 130 kg of enriched UF6(about 3.5% U-235) and 870 kg of 'depleted' UF6 (mostly U-238). The enriched UF6 is finally converted into uranium dioxide (UO2) powder and pressed into fuel pellets which are encased in zirconium alloy tubes to form fuel rods.

Depleted uranium has few uses, though with a high density (specific gravity of 18.7) it has found uses in the keels of yachts, aircraft control surface counterweights, anti-tank ammunition and radiation shielding. It is also a potential energy source for particular (fast neutron) reactors.

Wastes from the 'back end' of the fuel cycle

It is when uranium is used in the reactor that significant quantities of highly radioactive wastes are created. When the uranium-235 atom is split it forms fission products, which are very radioactive and make up the main portion of nuclear wastes retained in the fuel rods.

About 27 tonnes of used fuel is taken each year from the core of a l000 MWe nuclear reactor. This fuel can be regarded entirely as waste (as, for 40% of the world's output, in USA and Canada), or it can be reprocessed (as in Europe and Japan). Whichever option is chosen, the used fuel is first stored for several years under water in cooling ponds at the reactor site. The concrete ponds and the water covering the fuel assemblies provide radiation protection, while removing the heat generated during radioactive decay.

Thorp spent fuel storage

Storage pond for spent fuel at UK reprocessing plant

The costs of dealing with this high-level waste are built into electricity tariffs. For instance, in the USA, consumers pay 0.1 cents per kilowatt-hour, which utilities pay into a special fund. So far more than US$ 32 billion has been collected thus.

There is also a relatively small amount of radioactivity induced in the reactor components by neutron irradiation. When the reactor is retired and dismantled these materials become wastes. 

Reprocessing

Reprocessing graphic

If the used fuel is later reprocessed, it is dissolved and separated chemically into uranium, plutonium and high-level waste solutions. About 97% of the used fuel can be recycled leaving only 3% as high-level waste. The recyclable portion is mostly uranium depleted to less than 1% U-235, with some plutonium, which is most valuable.

Arising from a year's operation of a typical l000 MWe nuclear reactor, about 230 kilograms of plutonium (1% of the spent fuel) is separated in for recycle. This can be used in fresh mixed oxide (MOX) fuel (but not weapons, due its composition).

The separated high-level wastes – about 3% of the typical reactor's used fuel – amounts to 700 kg per year and it needs to be isolated from the environment for a very long time.

Immobilising separated high-level waste

Solidification processes have been developed in several countries over the past fifty years. Liquid high-level wastes are evaporated to solids, mixed with glass-forming materials, melted and poured into robust stainless steel canisters which are then sealed by welding.

Vitrified waste

Borosilicate glass from the first waste vitrification plant in UK in the 1960s. This block contains material chemically identical to high-level waste from reprocessing. A piece this size would contain the total high-level waste arising from nuclear electricity generation for one person throughout a normal lifetime.

The vitrified waste from the operation of a 1000 MWe reactor for one year would fill about 12 canisters, each 1.3m high and 0.4m diameter and holding 400 kg of glass. 

Vitrified Waste Canister
Loading silos with canisters containing vitrified high-level waste in UK, each disc on the floor covers a silo holding ten canisters

A more sophisticated method of immobilising high-level radioactive wastes has been developed. Called 'SYNROC' (synthetic rock), the radioactive wastes are incorporated in the crystal lattices of the naturally-stable minerals in a synthetic rock. In other words, copying what happens in nature. This process is still being developed for specialist application.

Waste disposal

Final disposal of high-level waste is delayed for 40-50 years to allow its radioactivity to decay, after which less than one-thousandth of its initial radioactivity remains, and it is much easier to handle. Hence canisters of vitrified waste, or used fuel assemblies, are stored under water in special ponds, or in dry concrete structures or casks, for at least this length of time.

The ultimate disposal of vitrified wastes, or of used fuel assemblies without reprocessing, requires their isolation from the environment for a long time. The most favoured method is burial in stable geological formations some 500 metres deep. Several countries are investigating sites that would be technically and publicly acceptable, and in Sweden and Finland construction is proceeding in 1.9 billion year-old granites.

One purpose-built deep geological repository for long-lived nuclear waste (though only from defence applications) is already operating in New Mexico, in a salt formation.

After being buried for about 1000 years most of the radioactivity will have decayed. The amount of radioactivity then remaining would be similar to that of the corresponding amount of naturally-occurring uranium ore from which it originated, though it would be more concentrated.

Layers of protection after disposal

To ensure that no significant environmental releases occur over a long period after disposal, a 'multiple barrier' disposal concept is used. The radioactive elements in high-level (and some intermediate-level) wastes are immobilised and securely isolated from the biosphere. The principal barriers are:

  • Immobilise waste in an insoluble matrix, e.g. borosilicate glass (or leave them as uranium oxide fuel pellets – a ceramic).
  • Seal inside a corrosion-resistant container, e.g. stainless steel.
  • Surround containers with bentonite clay to inhibit any groundwater movement if the repository is likely to be wet.
  • Locate deep underground in a stable rock structure.

For any of the radioactivity to reach human populations or the environment, all of these barriers would need to be breached, and this would need to happen before the radioactivity decayed to innocuous levels.

A natural precedent

 

One particular example in nature provides strong reassurance concerning final disposal of high-level wastes underground. Two billion years ago at Oklo in Gabon, West Africa, chain reactions started spontaneously in concentrated deposits of uranium ore. These natural nuclear reactors continued operating for hundreds of thousands of years forming plutonium and all the highly radioactive waste products created today from exactly the same processes in a nuclear power reactor. Despite the existence at that time of large quantities of water in the area, these materials stayed where they were formed and eventually decayed into non-radioactive elements. The evidence remains there.

  • Energy resources are available to supply the world's expanding needs without environmental detriment.
  • Wastes remain a major consideration whether they are released to the environment or not.
  • Ethical principles seem increasingly likely to influence energy policy in many countries, which augurs well for nuclear energy.
  • The competitive position of nuclear energy "is robust from a sustainable development perspective since most health and environmental costs are already internalised."1

Until about 30 years ago, energy sustainability was thought of simply in terms of availability relative to the rate of use. Today, in the context of the ethical framework of sustainable development, including particularly concerns about global warming, other aspects are also very important. These include environmental effects and the question of wastes, even if they have no environmental effect. Safety is also an issue, as well as the broad and indefinite aspect of maximising the options available to future generations. Geopolitical questions of energy security are central to the assessment of sustainability for individual countries, along with the affordability of the electricity produced.

Sustainable development criteria have been pushed into the front line of energy policy. In the light of concerns about climate change due to apparent human enhancement of the greenhouse effect, there is growing concern about how we address energy needs on a sustainable basis.

Energy demand

A number of factors are widely agreed. The world's population will continue to grow for several decades at least. Energy demand is likely to increase even faster, and the proportion supplied by electricity will also grow faster still. However, opinions diverge as to whether the electricity demand will continue to be served predominantly by extensive grid systems, or whether there will be a strong trend to distributed generation (close to the points of use). That is an important policy question itself, but either way, it will not obviate the need for more large-scale grid-supplied power, especially in urbanised areas, over the next several decades. Much demand is for continuous, reliable supply of electricity on a large scale, and this qualitative consideration will continue to dominate.

The key question is how we generate that electricity. Today, worldwide, 68% comes from fossil fuels (41% coal, 21% gas, 5.5% oil), 13.4% from nuclear fission and 19% from hydro and other renewable sources. There is no prospect that we can do without any of these (though oil has a more vital role in other applications).

Sources of energy

Harnessing renewable energy such as wind and solar is an appropriate first consideration in sustainable development, because apart from constructing the plant, there is no depletion of mineral resources and no direct air or water pollution. In contrast to the situation even a few decades ago, we now have the technology to access wind on a significant scale for electricity, and with some subsidy on a minority of supply being from those sources, they are affordable. But harnessing these 'free' sources cannot be the only option. Renewable sources other than hydro – notably wind and solar – are diffuse, intermittent, and unreliable by nature of their occurrence. These aspects offer a technological challenge of some magnitude, given that electricity cannot be stored on any large scale. For instance, solar-sourced electricity requires collecting energy at a peak density of about 1 kilowatt (kW) per square metre when the sun is shining to satisfy a quite different kind of electricity demand – one which mostly requires a relatively continuous supply.

Wind is the fastest-growing source of electricity in many countries, and there is a lot of scope for further expansion. While the rapid expansion of wind turbines in many countries has been welcome, capacity is seldom more than 30% utilised over the course of a week or year, which testifies to the unreliability of the source and the fact that it does not and cannot match the pattern of demand. Wind is intermittent, and when it does not blow, back-up capacity such as hydro or gas is needed. When it does blow, and displaces power from other sources, it reduces the economic viability of those sources and hence increases prices.

The rapid expansion of wind farms and solar power capacity is helped considerably by generous government-mandated grants, subsidies and other arrangements ultimately paid for by consumers. Where the financial inducements to build wind and solar capacity result in a strong response however, the subsidies become unaffordable and are now being cut back in many countries. Also there is often a strong groundswell of opposition on aesthetic grounds from the countryside where wind turbines are located.

Renewable sources such as wind and solar are intrinsically unsuited to meeting the demand for continuous, reliable supply on a large scale – which comprises most demand in developed countries.

A fuller treatment of electricity from renewable sources is in the information page on Renewable Energy and Electricity.

Apart from renewables, it is a question of what is most abundant and least polluting. Today, to a degree almost unimaginable even 30 years ago, there is known to be an abundance of many energy resources in the ground. Coal and uranium (not to mention thorium) are available and unlikely to be depleted this century.

The criteria for any acceptable energy supply will continue to be cost, safety, and security of supply, as well as environmental considerations. Addressing environmental effects usually has cost implications, as the current climate change debate makes clear. Supplying low-cost electricity with acceptable safety and low environmental impact will depend substantially on developing and deploying reasonably sophisticated technology. This includes both large-scale and small-scale nuclear energy plants, which can be harnessed directly to industrial processes such as hydrogen production or desalination, as well as their traditional role in generating electricity.

IAEA classification of nuclear energy scenario sustainability

  • Level 1. Safe, secure, economical and publicly acceptable nuclear power with security of supply – addresses conditions necessary for newcomers to deploy nuclear energy.
  • Level 2. Safe disposal of all nuclear wastes in a complete once-through fuel cycle with thermal reactors and with retrievable spent nuclear fuel disposal. Level 2 addresses political issue of 'solving the waste problem'. Retrievability is required to not limit future generations’ options.
  • Level 3. Initiate recycling of used nuclear fuel to reduce wastes. Limited recycle that reduces high-level waste volumes, slightly improves U utilisation, and keeps most of the U more accessible (Depleted U and Recovered U/Th). A branch of Level 3 is a once-through breed and burn option, providing significant improvement in resource utilization (up to 10 times).
  • Level 4. Guarantee nuclear fuel resources for at least the next 1000 years via complete recycle of used fuel. Closed fuel cycle with breeding of fissile material (from 238U or 232Th) to improve natural resource utilisation by a factor of 10 to 100. Solves the resource utilisation issue by providing fuel for thousands of years while also significantly reducing long-lived radioactivity burden (Pu-233/U recycle).
  • Level 5. Reduce radiotoxicity of all wastes below natural uranium level. Closed fuel cycle recycling all actinides and only disposing fission products to minimise long-term radiotoxicity of nuclear waste. Achieves additional substantial reduction of long-lived radioactivity burden (Pu-233/U/minor actinide recycle) and reduces radiotoxicity of waste down to natural uranium levels within 1000 years. As an option, transmutation of long-lived fission produces could be considered to further reduce waste radiotoxicity.

Is nuclear energy renewable?

Generally 'renewable' relates to harnessing energy from natural forces which are renewed by natural processes, especially wind, waves, sun and rain, but also heat from the Earth's crust and mantle. Although it shares many attributes with technologies harnessing these natural forces – for instance radioactive decay produces much of the heat harnessed geothermally – nuclear power is usually categorised separately from ‘renewables’.

Conventional nuclear power reactors do use a mineral fuel and demonstrably deplete the available resources of that fuel. In such a reactor, the input fuel is uranium-235 (U-235), which is part of a much larger mass of uranium – mostly U-238. This U-235 is progressively 'burned' to yield heat. But about one-third of the energy yield comes from something which is not initially loaded in: plutonium-239 (Pu-239), which behaves almost identically to U-235. Some of the U-238 turns into Pu-239 through the capture of neutron particles, which are released when the U-235 is 'burned'. So the U-235 used actually renews itself to some extent by producing Pu-239 from the otherwise waste material U-238.

This process can be optimised in fast neutron reactors, which are likely to be extensively deployed in the next generation of nuclear power reactors. A fast neutron reactor can be configured to 'breed' more Pu-239 than it consumes (by way of U-235 + Pu-239), so that the system can run indefinitely. While it can produce more fuel than it uses, there does need to be a steady input of reprocessing activity to separate the fissile plutonium from the uranium and other materials discharged from the reactors. This is fairly capital-intensive but well-proven and straightforward. The used fuel from the whole process is recycled and the usable part of it increases incrementally.

As well as utilizing about 60 times the amount of energy from uranium, fast neutron reactors will unlock the potential of using even more abundant thorium as a fuel (see information page on Thorium).  Using a fast neutron reactor, thorium produces U-233, which is fissile. This process is not yet commercialised, but it works and if there were ever a pressing need for it, development would be accelerated. India is the only country concentrating on this now, since in a world context uranium is so abundant and relatively cheap.  In addition, some 1.5 million tonnes of depleted uranium now seen by some people as little more than a waste, becomes a fuel resource. The consequence of this is that the available resource of fuel for fast neutron reactors is so plentiful that under no practical terms would the fuel source be significantly depleted.

Regardless of the various definitions of 'renewable', nuclear power therefore meets every reasonable criterion for sustainability, which is the prime concern.

Energy resources

There is abundant coal in many parts of the world, but with the constraints imposed by concern about global warming, it is likely that this will increasingly be seen as chemical feedstock and its large-scale use for electricity production will be scaled down. Current proposals for 'clean coal' technologies may change this outlook. The main technology involves the capture and subsequent storage of the carbon dioxide from the flue gas. Elements of the technology are proven but the challenge is to actually commercialize it and bring the cost down sufficiently to compete with nuclear power.

Natural gas is also reasonably abundant, especially with the advent of technologies for tapping that in coal seams and shales, but is so valuable for direct use after being reticulated to the point where heat is required, and as a chemical feedstock, that its large-scale use for power generation makes little sense and is arguably unsustainable. However, while abundant supply keeps prices down in the short to medium-term, it is the most economical means of generating electricity in some places, notably North America.

Fuel for nuclear power is abundant, and uranium is even available from sea water at costs which would have little impact on electricity prices. Furthermore, if well-proven but currently uneconomic fast neutron reactor technology is used, or thorium becomes a nuclear fuel, the supply is almost limitless. (See information page on Supply of Uranium.)

The hydrogen economy

Someday, hydrogen is expected to come into great demand as a transport fuel which does not contribute to global warming. It may be used in fuel cells to produce electricity or directly in internal combustion motors – as experimentally now.

Fuel cells are at an early stage of technological development and still require substantial, research and development input, although they are likely to be an important technology in the future.

Hydrogen may be provided by steam reforming of natural gas (in which case the emission of by-product CO2 has to be taken into account), by electrolysis of water, or (in future) by thermochemical processes using nuclear heat. Today, about 96% of hydrogen is made from fossil fuels: half from natural gas, 30% from liquid hydrocarbons and 18% from coal. This gives rise to quantities of carbon dioxide emissions - each tonne produced gives rise to 11 tonnes of CO2.

 Some new types of nuclear reactor such as high-temperature gas cooled reactors (HTRs), operating at around 950°C have the potential for producing hydrogen from water by thermochemical means, without using natural gas, and without any CO2 arising.

Large-scale use of electrolysis would mean a considerable increase in electricity demand. However, this need not be continuous baseload supply, as hydrogen can be accumulated and stored, and solar or wind generation may well serve this purpose better than supplying consumer electricity demand.

However, pending the development of affordable mass-produced fuel cells, a significant increase in base-load electricity demand may result from the adoption of plug-in electric hybrid vehicles and full electric vehicles (see information page on Electricity and Cars). These are on the threshold of commercial availability (today's hybrid vehicles only need bigger battery capacity and the facility to use mains power for recharging).

Wastes

Wastes – both those produced and those avoided – are a major concern in any consideration of sustainable development.

Burning fossil fuels produces primarily carbon dioxide as waste, which is inevitably dumped into the atmosphere. With black coal, approximately one tonne of carbon dioxide results from every thousand kilowatt hours generated. Natural gas contributes about half as much CO2 as coal from actual combustion, and also some (including methane leakage) from its extraction and distribution. Oil and gas burned in transporting fossil fuels adds to the global total. As yet, there is no satisfactory way to avoid or dispose of the greenhouse gases which result from fossil fuel combustion.

Nuclear wastes

Nuclear energy produces both operational and decommissioning wastes, which are contained and managed. Although experience with both storage and transport over half a century clearly shows that there is no technical problem in managing any civil nuclear wastes without environmental impact, the question has become political, focussing on final disposal. In fact, nuclear power is the only energy-producing industry which takes full responsibility for all its wastes, and costs this into the product – a key factor in sustainability.

Ethical, environmental and health issues related to nuclear wastes are topical, and their prominence has tended to obscure the fact that such wastes are a declining hazard, while other industrial wastes retain their toxicity indefinitely.

Regardless of whether particular wastes remain a problem for centuries or millennia or forever, there is a clear need to address the question of their safe disposal. If they cannot readily be destroyed or denatured, this generally means that they need to be removed and isolated from the biosphere. This may be permanent, or retrievable.

An alternative view asserts that indefinite surface storage of high-level wastes under supervision is preferable. This may be because such materials have some potential for recycling as a fuel source, or negatively because progress towards successful geological disposal would simply encourage continued use and expansion of nuclear energy. However, there is wide consensus that dealing effectively with wastes to achieve high levels of safety and security is desirable in a 50-year perspective, ensuring that each generation deals with its own wastes.

According to the OECD's Nuclear Energy Agency: "The scientific and technical community generally feels confident that there already exist technical solutions to the spent fuel and nuclear waste conditioning and disposal question. This is a consequence of the many years of work by numerous professionals in institutions around the world... There is a wide consensus on the safety and benefits of geologic disposal."2

Ethical aspects of nuclear wastes

In a 1999 OECD article3, Claudio Pescatore outlines some ethical dimensions of this question. He starts on a very broad canvas, quoting four fundamental principles proposed by the US National Academy of Public Administration4:

  • Trustee Principle: Every generation has obligations as trustee to protect the interests of future generations.
  • Sustainability Principle: No generation should deprive future generations of the opportunity for a quality of life comparable to its own.
  • Chain of Obligation Principle: Each generation's primary obligation is to provide for the needs of the living and succeeding generations. Near-term concrete hazards have priority over long-term hypothetical hazards.
  • Precautionary Principle: Actions that pose a realistic threat of irreversible harm or catastrophic consequences should not be pursued unless there is some compelling, countervailing need to benefit either current or future generations.

These four principles resulted from a request by the US Government to elucidate principles for guiding decisions by public administrators on the basis of the international Rio and UNESCO Declarations5 which acknowledge responsibilities to future generations. The principles can be applied to the question of nuclear wastes, and in particular to their deep geological disposal, a system with inherent passive safety. Referring to relevant 1995 IAEA and NEA publicationsa, Dr Pescatore summarises the principles in this context as follows:

  • The generation producing the waste is responsible for its safe management and associated costs.
  • There is an obligation to protect individuals and the environment both now and in the future.
  • There is no moral basis for discounting future health and risks of environmental damage.
  • Our descendants should not knowingly be exposed to risks which we would not accept today. Individuals should be protected at least as well as they are at present.
  • The safety and security of repositories should not presume a stable social structure for the indefinite future or continued technological progress.
  • Wastes should be processed so they will not to be a burden to future generations. However, we should not unnecessarily limit the capability of future generations to assume management control, including possible recovery of the wastes.
  • We are responsible for passing on to future generations our knowledge concerning the risks related to waste.
  • There should be enough flexibility in the disposal procedures to allow alternative choices. In particular information should be made available so the public can take part in the decision-making process which, in this case, will proceed in stages.

Deep geological disposal is considered as the final stage in waste management. It should ensure security and safety in a way that will not require surveillance, maintenance, or institutional control.

External costs

Some energy sources dispose of wastes to the environment or have health effects which are not costed into the product. These implicit subsidies, or external costs as they are generally called, are nevertheless real and usually quantifiable, but are borne by society at large. Their quantification is necessary to enable rational choices of energy sources. Nuclear energy has always provided for waste disposal and decommissioning costs in the actual cost of electricity (ie it has internalised them), so that external costs are minimal.

The External costs of Energy (ExternE) European Research Network has compared the external costs of various means of generating electricityb. It showed that coal has the highest external costs (and about the same for all other generation costs), followed by gas, while nuclear and wind were one tenth or less of coal. The methodology included the risk of accidents and covered full fuel cycle. Hence if external costs are taken into account, nuclear energy is shown as very competitive.

Safety

The safety of nuclear energy has been well demonstrated, notwithstanding the continued operation of a small number of reactors which are, by western standards, distinctly unsatisfactory. These include two old Soviet designs, one of which – before some very extensive modifications to the type – precipitated the 1986 Chernobyl disaster. Over 14,500 reactor-years of operation have shown a remarkable lack of problems in any of the reactors which are licensable in most of the world.  The only serious accident to a Western plant in over 30 years was that precipitated by an unprecedented tsunami at Fukushima in March 2011. Even then, and despite massive inconvenience to many people due to evacuation, the lack of human casualties from the accident contrasted with some 25,000 killed by the actual tsunami.

There is probably no other large-scale technology used worldwide with a comparable safety record. This is largely because safety was given a very high priority from the outset of the civil nuclear energy program, at least in the West. The safety provisions include a series of physical barriers between the hot radioactive reactor core and the environment, and the provision of multiple safety systems, each with back-up, and designed to accommodate human error. Safety systems, in the sense of back-ups and containment, account for a substantial part of the capital cost of nuclear power reactors - a higher proportion even than in aircraft design and construction.

Any statistics comparing the safety of nuclear energy with alternative means of generating electricity show nuclear to be the safest. In fact, Chernobyl and Fukushima are the only blemishes on the record, and Chernobyl is of very little relevance to the safety of most of the world's reactors.

Energy security

From a national perspective, the security of future energy supplies is a major factor in assessing their sustainability. Whenever objective assessment is made of national or regional energy policies, security of supply is a priority.

France's decision in 1974 to expand dramatically its use of nuclear energy was driven primarily by considerations of energy security. However, the economic virtues have since become more prominent. Various EU reports over the last decade have highlighted the importance of nuclear power for Europe's energy security and climate goals.  Many governments are clear that nuclear energy must play an increasing role by 2030, and in recent years the formerly rather negative UK government has been foremost in declaring this.

Opportunity costs

Nuclear energy and renewables have one important feature in common. They give us access to virtually limitless resources of energy with negligible opportunity cost – we are not depleting resources useful for other purposes, and we are using relatively abundant rather than less abundant energy. We can envisage a time when fossil carbon-based fuels will be too valuable to burn on the present scale.

Outlook

Recent analyses fail to come up with any 50-year scenario based on sustainable development principles which does not depend significantly on nuclear fission to provide large-scale, highly intensive energy, along with renewables to meet some small-scale (and especially dispersed) low-intensity needs. The alternative is either to squander fossil carbon resources or deny the aspirations of hundreds of millions of people in the next generation.

Alternative low-CO2 means of producing base-load electricity have not been credibly proposed, and wildly unrealistic projections for renewables of a few years ago have tended to become muted. Certainly all the reputable energy scenarios show the main load being carried by coal, gas, and nuclear, with the share between them depending on economic factors in the context of various levels of CO2 emission constraints.

 As the notion of sustainability is increasingly supported politically, all external costs are likely to be factored in, thus affecting the economic choices among fuels for electricity generation in nuclear power's favour.

 

There is now sufficient solar and wind capacity operating on grid systems for their advantages and limitations to be widely evident. That will help focus public discussion on the real options for continuous, reliable (baseload) electricity generation on the large scale required. Nuclear power can – and must – contribute significantly to sustainable development.

  • Used nuclear fuel has long been reprocessed to extract fissile materials for recycling and to reduce the volume of high-level wastes.
  • Recycling today is largely based on the conversion of fertile U-238 to fissile plutonium.
  • New reprocessing technologies are being developed to be deployed in conjunction with fast neutron reactors which will burn all long-lived actinides, including all uranium and plutonium, without separating them from one another.
  • A significant amount of plutonium recovered from used fuel is currently recycled into MOX fuel; a small amount of recovered uranium is recycled so far.

A key, nearly unique, characteristic of nuclear energy is that used fuel may be reprocessed to recover fissile and fertile materials in order to provide fresh fuel for existing and future nuclear power plants. Several European countries, Russia, China and Japan have policies to reprocess used nuclear fuel, although government policies in many other countries have not yet come round to seeing used fuel as a resource rather than a waste.

Over the last 50 years the principal reason for reprocessing used fuel has been to recover unused plutonium, along with less immediately useful unused uranium, in the used fuel elements and thereby close the fuel cycle, gaining some 25% to 30% more energy from the original uranium in the process. This contributes to national energy security. A secondary reason is to reduce the volume of material to be disposed of as high-level waste to about one-fifth. In addition, the level of radioactivity in the waste from reprocessing is much smaller and after about 100 years falls much more rapidly than in used fuel itself.

These are all considerations based on current power reactors, but moving to fourth-generation fast neutron reactors in the late 2020s changes the outlook dramatically, and means that not only used fuel from today’s reactors but also the large stockpiles of depleted uranium (from enrichment plants, about 1.5 million tonnes in 2015) become a fuel source. Uranium mining will become much less significant.

Another major change relates to wastes. In the last decade interest has grown in recovering all long-lived actinides* together (i.e. with plutonium) so as to recycle them in fast reactors so that they end up as short-lived fission products. This policy is driven by two factors: reducing the long-term radioactivity in high-level wastes, and reducing the possibility of plutonium being diverted from civil use – thereby increasing proliferation resistance of the fuel cycle. If used fuel is not reprocessed, then in a century or two the built-in radiological protection will have diminished, allowing the plutonium to be recovered for illicit use (though it is unsuitable for weapons due to the non-fissile isotopes present).

* Actinides are elements 89 to 103, actinium to lawrencium, including thorium, protactinium and uranium as well as transuranics, notably neptunium, plutonium, americium, cerium and californium. The minor actinides in used fuel are all except uranium and plutonium.

Reprocessing used fuela to recover uranium (as reprocessed uranium, or RepU) and plutonium (Pu) avoids the wastage of a valuable resource. Most of it – about 96% – is uranium, of which less than 1% is the fissile U-235 (often 0.4-0.8%); and up to 1% is plutonium. Both can be recycled as fresh fuel, saving up to 30% of the natural uranium otherwise required. The RepU is chiefly valuable for its fertile potential, being transformed into plutonium-239 which may be burned in the reactor where it is formed.

So far, some 90,000 tonnes (of 290,000 t discharged) of used fuel from commercial power reactors has been reprocessed. Annual reprocessing capacity is now about 4500 tonnes per year for normal oxide fuels, but not all of it is operational.

Between 2010 and 2030 some 400,000 tonnes of used fuel is expected to be generated worldwide, including 60,000 t in North America and 69,000 t in Europe.

World commercial reprocessing capacity1,2

(tonnes per year)
LWR fuel France, La Hague 1700
UK, Sellafield (THORP) 600
Russia, Ozersk (Mayak) 400
Japan (Rokkasho) 800*
Total LWR (approx) 3500
Other nuclear fuels UK, Sellafield (Magnox) 1500
India (PHWR, 4 plants) 330
Japan, Tokai MOX 40
Total other (approx) 1870
Total civil capacity   5370

* now expected to start operation in 2016

Processing used nuclear fuel is in accordance with the definition of sustainable used fuel management set out by the World Nuclear Association.*

* The World Nuclear Association considers used fuel management to be sustainable if it meets the following key criteria:

  • It covers all the steps of used fuel management from the generation of used fuel up to and including final disposal in accordance with a well-defined practical plan.
  • It proves to be feasible with a sustainable impact level.
  • It includes a realistic financing plan.
  • It is able to demonstrate to a practicable extent that it is technically and economically viable.
  • It protects human health and the environment and has no greater impact on the health of future generations than is allowed today.
  • It answers to a present need but does not impose burdens on future generations.

Due to the long-term nature of these management plans, sustainable options must have one or more pre-defined milestones where a decision could be taken on which option to proceed with.

Processing perspective, and products of reprocessing

Conceptually, processing used fuel is the same as processing the concentrate of any metal mineral to recover the valued metals contained in it. Here the ‘ore’ (or effectively the concentrate from it) is hard ceramic uranium oxide with an array of other elements (about 4% in total), including both fission products and actinides formed in the reactor.

There are three broad kinds of metallurgical treatment at metal smelters and refineries:

  • Pyrometallugy using heat to initiate separation of the metals from their mineral concentrate (e.g. copper smelting to produce blister copper, lead smelting).
  • Electrometallurgy using electric current to separate the metals (e.g. alumina smelting to produce aluminium).
  • Hydrometallurgy using aqueous solutions that dissolve the metal, with sometimes also electrolytic cells to separate them (e.g. zinc production, copper refining).

The main historic and current process is Purex, a hydrometallurgical process. The main prospective ones are electrometallurgical – often called pyroprocessing since it happens to be hot. With it, all actinide anions (notably U & Pu) are recovered together.

Used fuel contains a wide array of nuclides in varying valency states. Processing it thus inherently complex chemically, and made more difficult because many of those nuclides are also radioactive.

The composition of reprocessed uranium (RepU) depends on the initial enrichment and the time the fuel has been in the reactor, but it is mostly U-238. It will normally have less than 1% U-235 (typically about 0.5% U-235) and also smaller amounts of U-232 and U-236 created in the reactor. The U-232, though only in trace amounts, has daughter nuclides which are strong gamma-emitters, making the material difficult to handle. However, once in the reactor, U-232 is no problem (it captures a neutron and becomes fissile U-233). It is largely formed through alpha decay of Pu-236, and the concentration of it peaks after about 10 years of storage.

The U-236 isotope is a neutron absorber present in much larger amounts, typically 0.4% to 0.6% – more with higher burn-up – which means that if reprocessed uranium is used for fresh fuel in a conventional reactor it must be enriched significantly more (e.g. up to one-tenth more) than is required for natural uraniumb. Thus RepU from low burn-up fuel is more likely to be suitable for re-enrichment, while that from high burn-up fuel is best used for blending or MOX fuel fabrication.

The other minor uranium isotopes are U-233 (fissile), U-234 (from original ore, enriched with U-235, fertile), and U-237 (short half-life beta emitter). None of these affects the use of handling of the reprocessed uranium significantly. In the future, laser enrichment techniques may be able to remove these isotopes.

Reprocessed uranium (especially from earlier military reprocessing) may also be contaminated with traces of fission products and transuranics. This will affect its suitability for recycling either as blend material or via enrichment. Over 2002-06 USEC successfully cleaned up 7400 tonnes of technetium-contaminated uranium from the US Department of Energy.

Most of the separated uranium (RepU) remains in storage, though its conversion and re-enrichment (in UK, Russia and Netherlands) has been demonstrated, along with its re-use in fresh fuel. Some 16,000 tonnes of RepU from Magnox reactors in UK has been usedc to make about 1650 tonnes of enriched AGR fuel. In Belgium, France, Germany and Switzerland over 8000 tonnes of RepU has been recycled into nuclear power plants. In Japan the figure is over 335 tonnes in tests and in India about 250 t of RepU has been recycled into PHWRs. In Russia RepU is used in all fresh RBMK fuel, and over 2500 tonnes has been recycled thus. Allowing for impurities affecting both its treatment and use, RepU value has been assessed as about half that of natural uranium.

Plutonium from reprocessing will have an isotopic concentration determined by the fuel burn-up level. The higher the burn-up levels, the less value is the plutonium, due to increasing proportion of non-fissile Pu isotopes (and minor actinides), and depletion of fissile plutonium isotopesd. Whether this plutonium is separated on its own or with other actinides is a major policy issue relevant to reprocessing (see section on Reprocessing policies below).

Most of the separated plutonium is used almost immediately in mixed oxide (MOX) fuel. World MOX production capacity is currently around 200 tonnes per year, nearly all of which is in France (see page on Mixed Oxide (MOX) Fuel). In future the Russian REMIX fuel may become established for recycling, though whether minor actinides remain with wastes or are recycled with REMIX depends on the reprocessing procedure. 

Inventory of separated recyclable materials worldwide3

  Quantity (tonnes) Natural U equivalent (tonnes)
Plutonium from reprocessed fuel 320 60,000
Uranium from reprocessed fuel 45,000 50,000
Ex-military plutonium 70 15,000
Ex-military high-enriched uranium 230 70,000

Estimated savings in natural uranium requirements due to recycled U & Pu (tU)

  Use of enriched RepU Use of Pu in MOX Total Unat replaced
2015 820 900 1720
2020 1920 1150 3070
2025 2090 1350 3440
2030 2090 1800 3890
2035 1890 2000 3890

Source: World Nuclear Association Nuclear Fuel Report 2015, Table 5.21 (includes US weapons Pu)

History of reprocessing

A great deal of hydrometallurgical reprocessing has been going on since the 1940s, originally for military purposes, to recover plutonium for weapons (from low burn-up used fuel, which has been in a reactor for only a very few months). In the UK, metal fuel elements from the Magnox generation gas-cooled commercial reactors have been reprocessed at Sellafield for about 50 yearse. The 1500 t/yr Magnox reprocessing plant undertaking this has been successfully developed to keep abreast of evolving safety, occupational hygiene and other regulatory standards. From 1969 to 1973 oxide fuels were also reprocessed, using part of the plant modified for the purpose, and the 900 t/yr Thermal Oxide Reprocessing Plant (THORP) at Sellafield was commissioned in 1994.

In the USA, no civil reprocessing plants are now operating, though three have been built. The first, a 300 t/yr plant at West Valley, New York, was operated successfully from 1966-72. However, escalating regulation required plant modifications which were deemed uneconomic, and the plant was shut down after treating 650 tonnes of used oxide and metal fuel using the Purex process. The second was a 300 t/yr plant built at Morris, Illinois, incorporating new technology based on the volatility of UF6 which, although proven on a pilot-scale, failed to work successfully in the production plant. It was declared inoperable in 1974. The third was a 1500 t/yr Purex plant at Barnwell, South Carolina, which was aborted due to a 1977 change in government policy which ruled out all US civilian reprocessing as one facet of US non-proliferation policy. In all, the USA has over 250 plant-years of reprocessing operational experience, the vast majority being at government-operated defence plants since the 1940s.

The main one of these is H Canyon at Savannah River, which commenced operation in 1955. It historically recovered uranium and neptunium from aluminium-clad research reactor fuel, both foreign and domestic. It could also recover Np-237 and Pu-238 from irradiated targets. H Canyon also reprocessed a variety of materials for recovery of uranium and plutonium both for military purposes and later high-enriched uranium for blending down into civil reactor fuel. In 2011 reprocessing of research reactor fuel was put on hold pending review of national policy for high-level wastes. Currently it is preparing plutonium for use in the new MOX plant at Savannah River.

In 2014, H Canyon completed reprocessing the long-stored uranium-thorium metal fuel from the 20 MWt Sodium Reactor Experiment (SRE), which had a high proportion of U-233. The sodium-cooled graphite-moderated SRE operated in California over 1957-64 and was the first US reactor to feed electricity to a grid. The uranium and actinides will be vitrified.

In France a 400 t/yr reprocessing plant operated for metal fuels from gas-cooled reactors at Marcoule until 1997. At La Hague, reprocessing of oxide fuels has been done since 1976, and two 800 t/yr plants are now operating, with an overall capacity of 1700 t/yr.

French utility EDF has made provision to store reprocessed uranium (RepU) for up to 250 years as a strategic reserve. Currently, reprocessing of 1150 tonnes of EDF used fuel per year produces 8.5 tonnes of plutonium (immediately recycled as MOX fuel) and 815 tonnes of RepU. Of this about 650 tonnes is converted into stable oxide form for storage. EDF has demonstrated the use of RepU in its 900 MWe power plants, but it is currently uneconomic due to conversion costing three times as much as that for fresh uranium, and enrichment needing to be separate because of U-232 and U-236 impurities. The presence of the gamma-emitting U-232 requires shielding and so should be handled in dedicated facilities; and the presence of the neutron-absorbing U-236 isotope means that a higher level of enrichment is required compared with fresh uranium.

The plutonium is immediately recycled via the dedicated Melox mixed oxide (MOX) fuel fabrication plant. The reprocessing output in France is co-ordinated with MOX plant input, to avoid building up stocks of plutonium. If plutonium is stored for some years the level of americium-241, the isotope used in household smoke detectors, will accumulate and make it difficult to handle through a MOX plant due to the elevated levels of gamma radioactivity.

India has two 100 t/yr oxide fuel plants operating, one at Tarapur since 1982, with another at IGCAR Kalpakkam, and a smaller one at BARC Trombay. Japan is starting up a major (800 t/yr) plant at Rokkasho while having had most of its used fuel reprocessed in Europe meanwhile. To 2006 it had a small (90 t/yr) reprocessing plant operating at Tokai Mura. 

Russia has an old 400 t/yr RT-1 oxide fuel reprocessing plant at Ozersk (near Chelyabinsk, Siberia), the main feed for which has been VVER-440 fuel, including that from Ukraine and Hungary. The partly-built 3000 t/yr RT-2 plant at Zheleznogorsk in Siberia has been redesigned and first stage completion of 700 t/yr is expected about 2025. Another 800 t/yr is planned for 2028. This is apparently Purex though that is not confirmed. An underground military reprocessing plant there is decommissioned.

Reprocessing policies 

Conceptually reprocessing can take several courses, separating certain elements from the remainder, which becomes high-level waste. Reprocessing options include:

  • Separate U, Pu, (as today).
  • Separate U, Pu+U (small amount of U).
  • Separate U, Pu, minor actinidesf.
  • Separate U, Pu+Np, Am+Cm.
  • Separate U+Pu all together.
  • Separate U, Pu+actinides, certain fission products.

In today's reactors, reprocessed uranium (RepU) needs to be enriched, whereas plutonium goes straight to mixed oxide (MOX) fuel fabrication. This situation has two perceived problems: the separated plutonium is a potential proliferation risk, and the minor actinides remain in the separated waste, which means that its radioactivity is longer-lived than if it comprised fission products only.

As there is no destruction of minor actinides, recycling through light water reactors delivers only part of the potential waste management benefit. For the future, the focus is on removing the minor actinides along with uranium and plutonium from the final waste and burning them all together in fast neutron reactors. (The longer-lived fission products may also be separated from the waste and transmuted in some other way.) Hence the combination of reprocessing followed by recycling in today’s reactors should be seen as an interim phase of nuclear power development, pending widespread use of fast neutron reactors.

All but one of the six Generation IV reactors being developed have closed fuel cycles which recycle all the actinides. Although US policy has been to avoid reprocessing, the US budget process for 2006 included $50 million to develop a plan for "integrated spent fuel recycling facilities", and a program to achieve this with fast reactors has become more explicit since.

In November 2005 the American Nuclear Society released a position statement4 saying that it "believes that the development and deployment of advanced nuclear reactors based on fast-neutron fission technology is important to the sustainability, reliability and security of the world's long-term energy supply." This will enable "extending by a hundred-fold the amount of energy extracted from the same amount of mined uranium". The statement envisages on-site reprocessing of used fuel from fast reactors and says that "virtually all long-lived heavy elements are eliminated during fast reactor operation, leaving a small amount of fission product waste which requires assured isolation from the environment for less than 500 years."

In February 2006 the US government announced the Global Nuclear Energy Partnership (GNEP) through which it would "work with other nations possessing advanced nuclear technologies to develop new proliferation-resistant recycling technologies in order to produce more energy, reduce waste and minimise proliferation concerns." GNEP goals included reducing US dependence on imported fossil fuels, and building a new generation of nuclear power plants in the USA. Two significant new elements in the strategy were new reprocessing technologies at advanced recycling centres, which separate all transuranic elements together (and not plutonium on its own) ­starting with the UREX+ process (see section on Developments of PUREX below), and 'advanced burner reactors' to consume the result of this while generating power.

GE Hitachi Nuclear Energy (GEH) is developing this concept by combining electrometallurgical separation (see section on Electrometallurgical 'pyroprocessing' below) and burning the final product in one or more of its PRISM fast reactors on the same site. The first two stages of the separation remove uranium which is recycled to light water reactors, then fission products which are waste, and finally the actinides including plutonium.

In mid-2006 a report5 by the Boston Consulting Group for Areva and based on proprietary Areva information showed that recycling used fuel in the USA using the COEX aqueous process (see Developments of PUREX below) would be economically competitive with direct disposal of used fuel. A $12 billion, 2500 t/yr plant was considered, with total capital expenditure of $16 billion for all related aspects. This would have the benefit of greatly reducing demand on space at the planned Yucca Mountain repository.

Boston Consulting Group gave four reasons for reconsidering US used fuel strategy which has applied since 1977:

  • Cost estimates for direct disposal at Yucca Mountain had risen sharply and capacity was limited (even if doubled)
  • Increased US nuclear generation, potentially from 103 to 160 GWe
  • The economics of reprocessing and associated waste disposal have improved
  • There is now a lot of experience with civil reprocessing.

Soon after this the US Department of Energy said that it might start the GNEP (now IFNEC) program using reprocessing technologies that "do not require further development of any substantial nature" such as COEX while others were further developed. It also flagged detailed siting studies on the feasibility of this accelerated "development and deployment of advanced recycling technologies by proceeding with commercial-scale demonstration facilities."

In 2007 the US Nuclear Regulatory Commission’s Advisory Committee on Nuclear Waste and Materials published a report on Background, Status, and Issues Related to the Regulation of Advanced Spent Nuclear Fuel Recycle Facilities, which canvassed the advantages of reprocessing US civil spent fuel. The report states: “The DOE’s current program for implementing SNF recycle contemplates building three facilities: an integrated nuclear fuel recycle facility, an advanced reactor for irradiating Np, Pu, Am, and Cm, and an advanced fuel cycle research facility to develop recycle technology. The first two of these are likely to be NRC-licensed.” The report is a thorough overview of reprocessing but does not provide conclusions or recommendations.

The NRC report points out how the Purex process had been greatly improved since its military origins, but still suffered the drawback of producing a separated pure plutonium stream. It points to the virtues of the UREX processes.

Reprocessing today – PUREX

All commercial reprocessing plants use the well-proven hydrometallurgical PUREX (plutonium uranium extraction) process, which separates uranium and plutonium very effectively. This involves dissolving the fuel elements in concentrated nitric acid. Chemical separation of uranium and plutonium is then undertaken by solvent extraction steps (neptunium – which may be used for producing Pu-238 for thermo-electric generators for spacecraft – can also be recovered if required). The Pu and U can be returned to the input side of the fuel cycle – the uranium to the conversion plant prior to re-enrichment and the plutonium straight to MOX fuel fabrication.

Alternatively, some small amount of recovered uranium can be left with the plutonium which is sent to the MOX plant, so that the plutonium is never separated on its own. This is known as the COEX (co-extraction of actinides) process, developed in France as a 'Generation III' process, but not yet in use (see next section). Japan's new Rokkasho plant uses a modified PUREX process to achieve a similar result by recombining some uranium before denitration, with the main product being 50:50 mixed oxides.

In either case, the remaining liquid after Pu and U are removed is high-level waste, containing about 3% of the used fuel in the form of fission products and minor actinides (notably Np, Am, Cm). It is highly radioactive and continues to generate a lot of heat. It is conditioned by calcining and incorporation of the dry material into borosilicate glass, then stored pending disposal. In principle any compact, stable, insoluble solid is satisfactory for disposal.

THORP

The Thermal Oxide Reprocessing Plant (THORP) at Sellafield , UK
The smaller black building to the rear is the vitrification plant.
(Sellafield Ltd.)


Chemistry of Purex (see flowsheet below)

The used fuel is chopped up and dissolved in hot concentrated nitric acid. The first stage separates the uranium and plutonium in the aqueous nitric acid stream from the fission products and minor actinides by a countercurrent solvent extraction process, using tributyl phosphate dissolved in kerosene or dodecane. In a pulsed column uranium and plutonium enter the organic phase while the fission products and other elements remain in the aqueous raffinate. 

In a second pulsed column uranium is separated from plutonium by reduction with excess U4+ added to the aqueous stream. Plutonium is then transferred to the aqueous phase while the mixture of U4+ and U6+ remains in the organic phase. It is then stripped from the organic solvent with dilute nitric acid.

The plutonium nitrate is concentrated by evaporation then subject to an oxalate precipitation process followed by calcination to produce PuO2 in powder form. The uranium nitrate is concentrated by evaporation and calcined to produce UO3 in powder form. It is then converted to UO2 product by reduction in hydrogen.

Reprocessing Used Fuel: Purex Flow Sheet


Developments of PUREX 

A modified version of the PUREX that does not involve the isolation of a plutonium stream is the suite of UREX (uranium extraction) processes. These can be supplemented to recover the fission products iodine, by volatilisation, and technetium, by electrolysis. Research at the French Atomic Energy Commission (Commissariat à l'énergie atomique, CEA) has shown the potential for 95% and 90% recoveries of iodine and technetium respectively. The same research effort has demonstrated separation of caesium.

The US Department of Energy was developing the UREX+ processes under the Global Nuclear Energy Partnership (GNEP) programme (see information paper on Global Nuclear Energy Partnership, now International Framework for Nuclear Energy Cooperation – IFNEC). In these, only uranium and then technetium are recovered initially (in the organic solvent extraction phase) for recycle, then Cs & Sr, and the residual is treated in various possible ways to recover plutonium with other transuranics. The fission products then comprise most of the high-level waste. The central feature of this system was to increase proliferation resistance by keeping the plutonium with other transuranics – all of which are then destroyed by recycling in fast reactors.*  However, there are chemical safety problems with the Pu-Np recovery in the aqueous phase, and the process has been abandoned since 2008.

* Several variations of UREX+ have been developed, with the differences being in how the plutonium is combined with various minor actinides, and lanthanide and non-lanthanide fission products are combined or separated. UREX+1a combines plutonium with three minor actinides, but this gives rise to problems in fuel fabrication due to americium being volatile and curium a neutron emitter. Remote fuel fabrication facilities would therefore be required, leading to high fuel fabrication costs and requiring significant technological development. An alternative process, UREX+3, was therefore considered. This left only neptunium with the plutonium and the result is closer to a conventional MOX fuel. However, it is less proliferation-resistant than UREX+1a.

Energy Solutions holds the rights to PUREX in the USA and has developed NUEX, which separates uranium and then all transuranics (including plutonium) together, with fission products separately. NUEX is similar to UREX+1a but has more flexibility in the separations process.

Areva and CEA have developed three processes on the basis of extensive French experience with PUREX:

  • The COEX process based on co-extraction and co-precipitation of uranium and plutonium (and usually neptunium) together, as well as a pure uranium stream (eliminating any separation of plutonium on its own). It is close to near-term industrial deployment, and allows high MOX performance for both light-water and fast reactors. COEX may have from 20 to 80% uranium in the oxide product (apart from U stream), the baseline is 50%. Waste comprises fission products and minor actinides, for vitrification.
  • The DIAMEX-SANEX processes involving selective separation of long-lived radionuclides (with a focus on Am and Cm separation) from short-lived fission products. This can be implemented with COEX, following separation of U-Pu-Np. U-Pu and minor actinides are recycled separately in Generation IV fast neutron reactors.
  • The GANEX (grouped extraction of actinides) process co-precipitates some uranium with the plutonium (as with COEX), but then separates minor actinides and some lanthanides from the short-lived fission products. The uranium, plutonium and minor actinides together become fuel in Generation IV fast neutron reactors, the lanthanides become waste, with other fission products. It is being demonstrated at ATALANTE and La Hague from 2008 as part of a French-Japanese-US Global Actinide Cycle International Demonstration (GACID) with the product transmutation being initially in France's Phenix fast reactor (see Transmutation section below) and subsequently planned in Japan's Monju.

Initial work is at ATALANTEg at Marcoule, which started operation in 1992 to consolidate reprocessing and recycling research from three other sites. By 2012, it is expected to have demonstrated GANEX, and fabrication of oxide fuel pins combining U, Pu, Am, Np & Cm. Then work will proceed at La Hague on partitioning and fabrication of minor actinide-bearing fuels without the curium. From 2020 these will be irradiated in the Monju fast reactor, Japan.

All three processes were to be assessed in 2012, so that two pilot plants could be built to demonstrate industrial-scale potential:

  • One – possibly based on COEX – to make the driver fuel for the Generation IV reactor planned to be built by CEA by 2020.
  • One to produce fuel assemblies containing minor actinides for testing in Japan's Monju fast reactor and in France's Generation IV fast reactor.

In the longer term, the goal is to have a technology validated for industrial deployment of Generation IV fast reactors about 2040, at which stage the present La Hague plant will be due for replacement.

US research in recent years has focused on the TALSPEAK process which would come after a modified PUREX or COEX process to separate trivalent lanthanides from trivalent actinides, but this is only reached bench scale. Originally in the 1960s it was developed to separate actinides, notably Am & Cm from lanthanides.

Another alternative reprocessing technology being developed by Mitsubishi and Japanese R&D establishments is Super-DIREX (supercritical fluid direct extraction). This is designed to cope with uranium and MOX fuels from light water and fast reactors. The fuel fragments are dissolved in nitric acid with tributyl phosphate (TBP) and supercritical CO2, which results in uranium, plutonium and minor actinides complexing with TBP.

A new reprocessing technology is part of the reduced-moderation water reactor (RMWR) concept. This is the fluoride volatility process, developed in the 1980s, which is coupled with solvent extraction for plutonium to give Hitachi's Fluorex process. In this, 90-92% of the uranium in the used fuel is volatalised as UF6, then purified for enrichment or storage. The residual is put through a Purex circuit which separates fission products and minor actinides, leaving the unseparated U-Pu mix (about 4:1) to be made into MOX fuel.

Used MOX fuel can be handled through the PUREX process, though it contains more plutonium (especially even-numbered isotopes) and minor actinides than used U oxide fuel. In 1991-92 2.1 tonnes of MOX was reprocessed at Marcoule and 4.7 tonnes was reprocessed La Hague.

Partitioning goals

Several factors give rise to a more sophisticated view of reprocessing today, and use of the term partitioning reflects this. First, new management methods for high and intermediate-level nuclear wastes are under consideration, notably partitioning-transmutation (P&T) and partitioning-conditioning (P&C), where the prime objective is to separate long-lived radionuclides from short-lived ones. Secondly, new fuel cycles such as those for fast neutron reactors (including a lead-cooled one) and fused salt reactors, and the possible advent of accelerator-driven systems, require a new approach to reprocessing. Here the focus is on electrolytic processes ('pyroprocessing') in a molten salt bath. The term 'electrometallurgical' is also increasingly used to refer to this in the USA.

The main radionuclides targeted for separation for P&T or P&C are the actinides neptunium, americium and curium (along with U & Pu), and the fission products iodine-129, technetium-99, caesium-135 and strontium-90. Removal of the latter two significantly reduces the heat load of residual conditioned wastes. In Japan, platinum group metals are also targeted, for commercial recovery. Of course any chemical process will not separate different isotopes of any particular element.

Efficient separation methods are needed to achieve low residuals of long-lived radionuclides in conditioned wastes and high purities of individual separated ones for use in transmutation targets or for commercial purposes (e.g.americium for household smoke detectors). If transumation targets are not of high purity then the results of transmutation will be uncertain. In particular fertile uranium isotopes (e.g. U-238) in a transmutation target with slow neutrons will generate further radiotoxic transuranic isotopes through neutron capture.

Achieving effective full separation for any transmutation program is likely to mean electrolytic processing of residuals from the PUREX or similar aqueous processes.

A BNFL-Cogema study in 2001 reported that 99% removal of actinides, Tc-99 & I-129 would be necessary to justify the effort in reducing the radiological load in a waste repository. A US study identified a goal of 99.9% removal of the actinides and 95% removal of technetium and iodine. In any event, the balance between added cost and societal benefits is the subject of considerable debate.

Electrometallurgical 'pyroprocessing' 

Electrometallurgical processing techniques ('pyroprocessing') to separate nuclides from a radioactive waste stream have been under development in the US Department of Energy laboratories, notably Argonne, as well as by the Korea Atomic Energy Research Institute (KAERI) in conjunction with work on DUPIC (see section on Recycled LWR uranium and used fuel in PHWRs below). Their main development has possibly been in Russia, where they are to be the mainstay of closing the fuel cycle fully by about 2020. There has been particular emphasis on fast reactor fuels, since all actinides with uranium can be burned together. The fact that uranium, plutonium and minor actinides are recovered together is seen as great advantage from a non-proliferation perspective.

They involve a smaller plant than hydrometallurgical/aqueous processes, so are well suited to closing the fuel cycle at reactor sites, with the need to store only a small volume of actual fission products as waste. Integral fast reactor and molten salt reactor (MSR) fuel cycles are based on on-site pyroprocessing. Separating all actinides together for recycle gives a very radioactive fuel which is thus self-protecting.

Electrometallurgical technology is able to carry out all of the deposit production operations in one apparatus – a chlorinator-electrolyzer – which simplifies the process. However, the specific separation achieved is not as great as with PUREX.

So-called pyroprocessing involves several stages. First, any oxide fuels need to be reduced to metal, Argonne/INL uses an electro-reduction process for this with LiCl-Li2O. The metal as anode can then be electro-refined in molten salt to deposit uranium and actinides (including Pu) together on to a liquid cadmium cathode, leaving fission products behind. A cathode processor then cleans up the cathode materials (removing salt and cadmium) at about 1200°C ready for fuel fabrication for a fast reactor. Fission products are recovered from the salt by ion exchange in zeolite columns and encapsulated into a durable vitreous wasteform.

Other pyroprocessing has stages described as: volatilisation; liquid-liquid extraction using immiscible metal-metal phases or metal-salt phases; electrolytic separation in molten salt; and fractional crystallisation. They are generally based on the use of either fused salts such as chlorides or fluorides (e.g. LiCl+KCl or LiF+CaF2) or fused metals such as cadmium, bismuth or aluminium.

Electrometallurgical 'pyroprocessing' can readily be applied to high burn-up fuel and fuel which has had little cooling time, since the operating temperatures are high already. However, such processes are at an early stage of development compared with hydrometallurgical processes already operational.

So far only one electrometallurgical technique has been licensed for use on a significant scale. This is the IFR (integral fast reactor) electrolytic process developed by Argonne National Laboratory in the USA and used for pyroprocessing 4.6 tonnes of used fuel from the EBR-II experimental fast reactor which ran from 1963-1994. (21 tonnes remains, designated for pyroprocessing.) The used uranium metal fuel is dissolved in a LiCl+KCl molten bath, the U is deposited on a solid cathode, while the stainless steel cladding and noble metal fission products remain in the salt, and are consolidated to form a durable metallic waste. The highly-enriched uranium recovered from the EBR-II driver fuel is down-blended to less than 20% enrichment and stored for possible future use.

The PYRO-A process, being developed at Argonne to follow the UREX process, is a pyrochemical process for the separation of transuranic elements and fission products contained in the oxide powder resulting from denitration of the UREX raffinate. The nitrates in the residual raffinate acid solution are converted to oxides, which are then reduced electrochemically in a LiCl-Li2O molten salt bath. The more chemically active fission products (eg Cs, Sr) are not reduced and remain in the salt. The metallic product is electrorefined in the same salt bath to separate the transuranic elements on a solid cathode from the fission products. The salt bearing the separated fission products is then mixed with a zeolite to immobilize the fission products in a ceramic composite waste form. The cathode deposit of transuranic elements is then processed to remove any adhering salt and is formed into ingots for subsequent fabrication of transmutation targets or fast reactor fuel.

The PYRO-B process, has been developed for the processing and recycle of used fuel from a transmuter reactor – a fast reactor designed to burn all transuranics. A transmuter fuel may be free of uranium and contains recovered transuranics in an inert matrix such as metallic zirconium. In the PYRO-B processing of such fuel, an electrorefining step is used to separate the residual transuranic elements from the fission products and recycle the transuranics to the reactor for fissioning. Newly-generated technetium and iodine are extracted for incorporation into transmutation targets, and the other fission products are sent to waste.

GE Hitachi is designing an Advanced Recycling Centre (ARC) which integrates electrometallurgical processing with its PRISM fast reactors. The main feed is used fuel from light water reactors, and the three products are fission products, uranium, and transuranics (Np, Pu, Am, Cm), which become fuel for the fast reactors (with some of the uranium). The uranium can be re-enriched or used as fuel for Candu reactors. As the cladding reaches its exposure limits, used PRISM fuel is recycled after removal of fission products. Waste forms are metallic for noble metal fission products, and ceramic for group 1 & 2 metals and halogen fission products. A full commercial-scale ARC would comprise an electrometallurgical plant and three power blocks of 622 MWe each (six 311 MWe reactor modules), but a 'full-scale building block' of ARC is a 50 t/yr electrometallurgical plant coupled to one 311 MWe reactor module, with breeding ratio of 0.8.

The KAERI advanced spent fuel conditioning process (ACP) involves separating uranium, transuranics including plutonium, and fission products including lanthanides. It utilises a high-temperature lithium-potassium chloride bath from which uranium is recovered electrolytically to concentrate the actinides, which are then removed together (with some remaining fission products). The latter product is then fabricated into fast reactor fuel without further treatment. The process is intrinsically proliferation-resistant because it is so hot radiologically, and the curium provides a high level of spontaneous neutrons. It recycles over 96% of the used fuel. Development of this process is at the heart of US-South Korean nuclear cooperation, and is central to the renewal of the bilateral US-South Korean nuclear cooperation agreement in March 2014, so is already receiving considerable attention in negotiations.

With US assistance through the International Nuclear Energy Research Initiative (I-NERI) program KAERI built the Advanced Spent Fuel Conditioning Process Facility (ACPF) at KAERI. This led to KAERI’s Pyro-process Integrated Inactive Demonstration Facility (PRIDE), which began testing operations in 2012. Demonstration work is proceeding to 2016, as effectively the first stage of a Korea Advanced Pyroprocessing Facility (KAPF) to start experimentally in 2016 and become a commercial-scale demonstration plant in 2025.

South Korea has declined an approach from China to cooperate on electrolytic reprocessing, and it has been rebuffed by Japan's CRIEPI due to government policy.

Russian pyroprocessing consists of three main stages: dissolution of the used nuclear fuel in molten salts, precipitation of plutonium dioxide or electrolytic deposition of uranium and plutonium dioxides from the melt, then processing the material deposited on the cathode or precipitated at the bottom of the melt for granulated fuel production. The process recovers the cathode deposits without changing their chemical composition or redistributing the plutonium. All used fuel is reprocessed with the goal of having a complete recycle of plutonium, neptunium, americium, and curium as well as the uranium. This process, combined with vibropacking* in fuel fabrication will be used to produce fuel for the BN-800 fast reactor. The technologies complement one another well and involve high levels of radioactivity throughout, making them self-protecting against diversion or misuse.

* Vibropacked MOX fuel (VMOX) has been seen as a promising way forward in Russia. This is made by agitating a mechanical mixture of (U, Pu)O2 granulate and uranium powder, which binds up excess oxygen and some other gases (that is, operates as a getter) and is added to the fuel mixture in proportion during agitation. The getter resolves problems arising from fuel-cladding chemical interactions. The granules are crushed (U, Pu)O2 cathode deposits from pyroprocessing. VMOX needs to be made in hot cells. It has been used in BOR-60 since 1981 (with 20-28% Pu), and tested in BN-350 and BN-600. However, its future is uncertain.

At MCC Zheleznogorsk which hosts a pyroprocessing module, civil PuO2, ex-weapons metal Pu and DU are combined into granulated MOX. This is sent to the Russian Institute of Atomic Reactors (RIAR) at Dimitrovgrad for vibropacking and producing fuel assemblies for the BN-800 fast reactor. In future fuel for BREST will follow the same route. RIAR has substantial experience in reprocessing used fuel from BOR-60 and BN-350 fast reactors and has developed a pilot scale pyroprocessing demonstration facility for fast reactor fuel.

Recycled LWR uranium and used fuel in PHWRs

The established approach to using RepU is recycling it through conversion and enrichment, for light water reactors. Another approach to used nuclear fuel recycling is directing recycled uranium (referred to as RepU, reprocessed uranium), or actual used light water reactor (LWR) fuel, into pressurized heavy water reactors (PHWRs). This may be directly using RepU, or by blending RepU with depleted uranium to give natural uranium equivalent (NUE), or by direct use of used PWR fuel in CANDU reactors (DUPIC).

PHWRs (such as CANDU reactors) normally use as fuel natural uranium which has not undergone enrichment and so can operate fuelled by the uranium and plutonium that remains in used fuel from LWRs. This might typically contain about 0.5 to 0.9% U-235 and 0.6% Pu-239 but with significant neutron absorbers.

In unit 1 of the Qinshan Phase III plant in China, there has been a demonstration using fuel bundles with RepU from PWRs blended with depleted uranium to give natural uranium equivalent (NUE) fuel with 0.71% U-2356. It behaved the same as natural uranium fuel. Subject to supply from reprocessing plants, a full core of natural U equivalent (NUE) is envisaged. Following design, licensing, etc, full core implementation in both China's CANDU reactors is envisaged by the end of 2013. (Recycled plutonium will be used in MOX fuel for fast reactors.)

AECL says that it is also possible to use the RepU directly in CANDUs, without blending it down, and Qinshan III envisages this possibility with recycled uranium (RU) having 0.9% U-235.

With DUPIC, the direct use of used PWR fuel as such in CANDUs, used fuel assemblies from LWRs would be dismantled and refabricated into fuel assemblies the right shape for use in a CANDU reactor. This could be direct, involving only cutting the used LWR fuel rods to CANDU length (about 50 cm), resealing and re-engineering into cylindrical bundles suitable for CANDU geometry.

Alternatively, a "dry reprocessing" technology has been developed which removes only the volatile fission products from the used LWR fuel mix. After removal of the cladding, a thermal-mechanical process is used to reduce the used LWR fuel pellet to a powder. This could have more fresh natural uranium added, before being sintered and pressed into CANDU pellets.  It would contain all the actinides and most of the fission products from irradiation in LWR.

The DUPIC technique was promoted as having certain advantages:

  • No materials are separated during the refabrication process. Uranium, plutonium, fission products and minor actinides are kept together in the fuel powder and bound together again in the DUPIC fuel bundles.
  • A high net destruction rate can be achieved of actinides and plutonium.
  • Up to 25% more energy can be realised compared to other PWR used fuel recycling techniques.
  • And a DUPIC fuel cycle could reduce a country's need for used PWR fuel disposal by 70% while reducing fresh uranium requirements by 30%.

However, as noted above, used nuclear fuel is highly radioactive and generates heat. This high activity means that the DUPIC manufacture process must be carried out remotely behind heavy shielding. While these restrictions make the diversion of fissile materials much more difficult and hence increase security, they also make the manufacture process more complex compared with that for the original PWR fuel, which is barely radioactive before use.  (NUE would be more radioactive than natural U, due to U-232 in the RU.)

Canada, which developed the CANDU reactor, and South Korea, which hosts four CANDU units as well as many PWRs, initiated a bilateral joint research program to develop DUPIC.  This included the reactor physics of DUPIC fuel and the impacts on safety systems. However, as of 2013 plans for DUPIC are on hold.

The Korean Atomic Energy Research Institute (KAERI) has had a development program since 1992 to demonstrate the DUPIC fuel cycle concept. KAERI believes that although it is too early to commercialise the DUPIC fuel cycle, the key technologies are in place for a practical demonstration of the technique. Challenges which remain include the development of a technology to produce fuel pellets of the correct density, the development of remote fabrication equipment and the handling of the used PWR fuel. However, KAERI successfully manufactured DUPIC small fuel elements for irradiation tests inside the HANARO research reactor in April 2000 and fabricated full-size DUPIC elements in February 2001. AECL is also able to manufacture DUPIC fuel elements.

A further complication is the loading of highly radioactive DUPIC fuel into the CANDU reactor. Normal fuel handling systems are designed for the fuel to be hot and highly radioactive only after use, but it is thought that the used fuel path from the reactor to cooling pond could be reversed in order to load DUPIC fuel, and studies of South Korea's Wolsong CANDU units indicate that both the front- and rear-loading techniques could be used with some plant modification. 

Transmutation

The objective of transumutation is to change (long-lived) actinides into fission products and long-lived fission products into significantly shorter-lived nuclides. The goal is to have wastes which become radiologically innocuous in only a few hundred years. The need for a waste repository is certainly not eliminated, but it can be smaller and simpler and the hazard posed by the disposed waste materials is greatly reduced.

Transmutation of one radionuclide into another is achieved by neutron bombardment in a nuclear reactor or accelerator-driven device. In the latter, a high-energy proton beam hitting a heavy metal target produces a shower of neutrons by spallationh. The neutrons can cause fission in a subcritical fuel assembly, but unlike a conventional reactor, fission ceases when the accelerator is turned off. The fuel may be uranium, plutonium or thorium, possibly mixed with long-lived wastes from conventional reactors. See also page on Accelerator-Driven Nuclear Energy.

Transmutation is mainly initiated by fast neutrons. Since these are more abundant in fast neutron reactors, such reactors are preferred for transmutation. Some radiotoxic nuclides, such as Pu-239 and the long-lived fission products Tc-99 and I-129, can be transmuted (fissioned, in the case of Pu-239) with thermal (slow) neutrons. However, a 2001 BNFL-Cogema study found that full transmutation in a light water reactor would take at least several decades, and recent research has focused on use of fast reactors. The minor actinides Np, Am and Cm (as well as the higher isotopes of plutonium), all highly radiotoxic, are much more readily destroyed by fissioning in a fast neutron energy spectrum (see Table), where they can also contribute to the generation of power.

Transmutation probabilities (%)

Isotope thermal spectrum fast spectrum
Np-137 3 27
Pu-238 7 70
Pu-239 63 85
Pu-240 1 55
Pu-241 75 87
Pu-242 1 53
Am-241 1 21
Am-242m 75 94
Am-243 1 23
Cm-242 1 10
Cm-243 78 94
Cm-244 4 33

Chang 2014

 

One of the main functions of France's Phenix fast neutron reactor in its last two years of operation was test burning fuel assemblies containing high concentrations of minor actinides. From mid-2007 it irradiated four fuel pins containing actinides from the US Department of Energy, two from the CEA, and two from the European Commission's Institute for Transuranics.

  • The human enhancement of global warming leading to climate change is seen as a worldwide problem.
  • Policy responses have been led by international negotiation, but have been qualified or indecisive at the national level, and so far largely ineffective, despite strong international agreement on the matter. 
  • The principal focus is on reducing carbon dioxide emissions.
  • Nuclear power is seldom acknowledged as the single most significant means of limiting the increase in greenhouse gas concentrations while enabling access to abundant electricity.

Emissions of greenhouse gases have a global impact, unlike some other forms of pollution. Whether they are emitted in Asia, Africa, Europe, or the Americas, they rapidly disperse evenly across the globe. This is one reason why efforts to address climate change have been through international collaboration and agreement.

The principal forum for international climate change action has been the United Nations, which has led to the Framework Convention on Climate Change (UNFCCC) and the Kyoto Protocol. However, more recently other international approaches have been put in place, the Asia Pacific Partnership and agreements under the G8, starting with their 2005 meeting in Gleneagles, UK. In December 2015 the Paris agreement consolidated years of negotiations with agreement among 188 countries to limit carbon dioxide emissions.

Although climate change agreements emphasising carbon emission reduction have been reached through international approaches, the policy measures to meet the obligations and objectives set by such agreements have been implemented at the national or regional level. Here they are supplemented by policy instruments such as efficiency standards and incentives to invest in infrastructure which does not give rise to carbon emissions. Pricing carbon emissions is seen as putting a price on a major external cost from energy production and transformation.

The UN climate change negotiations, early phase

In 1988 the World Meteorological Organization (WMO) and the United Nations Environment Programme (UNEP) set up the Intergovernmental Panel on Climate Change (IPCC), an expert body that would assess scientific information on climate change. As a reaction to the concerns raised in the IPCC's First Assessment Report the UN General Assembly established the Intergovernmental Negotiating Committee for a Framework Convention on Climate Change. The UN Framework Convention on Climate Change (UNFCCC) was adopted in May 1992 and entered into force in 1994. The convention included the commitment to stabilise greenhouse gas emissions at 1990 levels by 2000.

The first Convention of the Parties to the UNFCCC (COP 1) was held in 1995. Negotiations at this and two subsequent COPs led to agreement on the Kyoto Protocol in 1997. The Kyoto Protocol set out specific commitments by individual developed countries to reduced emissions by an average of 5.2% below 1990 levels by the period 2008-2012. However, it would take three further meetings until the "Marrakesh Accords" were agreed, which provide sufficient detail on the procedures for pursuing objectives set out in the Kyoto Protocol.

The Kyoto Protocol involved several decisions:

  • By 2012, developed countries would reduce their collective emissions by 5.2% from 1990 levels, each country being committed to a particular figure.
  • The emissions covered by the Protocol are not only carbon dioxide, but also methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride.
  • These commitments would be reckoned on a net basis, considering sinks as well as sources, and each country must credibly measure its contribution and meet its commitment.
  • Countries may fulfil their commitments jointly (such as with regional agreements) and they may improve the efficiency of compliance through "flexibility mechanisms".

In order for the Kyoto Protocol to enter into force and become legally binding it had to be ratified by at least 55 countries and for those ratifying countries to include enough Annex I (developed) countries to represent at least 55% of the total emissions from those Annex 1 countries in 1990. In 2001 the US Government (which had earlier signed the Protocol) announced that it would not ratify the Protocol. As the USA emits more than a quarter of all greenhouse gas emissions from developed countries, this put the ratification of the Protocol in jeopardy. Australia also declared that it would not ratify, though it would pursue emission reductions as agreed.

Eventually, entry into force depended on the decision of Russia, another large greenhouse gas emitter. After some delay Russia notified the United Nations of its decision to ratify the Protocol in November 2004 and 90 days later, on February 19, 2005, the Protocol finally came into force. Australia subsequently ratified the Protocol in December 2007.

While countries that are party to the Protocol are expected to rely mainly on reducing their own emissions domestically, three "flexibility mechanisms" were identified to improve the economic efficiency of reductions and make it easier for parties to comply. The three mechanisms are emissions trading, Joint Implementation and the Clean Development Mechanism.

Emissions Trading: A market-based approach to achieving environmental objectives that allows those countries or entities reducing greenhouse gas emissions below what is required to use or trade the excess reductions to offset emissions at another source, inside or outside the country. In general, trading can occur at the domestic, regional (EU), international and intra-company levels. A precedent is the USA acid rain program, which successfully trades permits for sulfur dioxide.

Joint Implementation (JI): A project-based mechanism, whereby one developed country – with emissions caps – can work with another to reduce emissions or enhance sinks, and share the resulting emission reduction units accordingly.

The Clean Development Mechanism (CDM): A project-based mechanism where certified projects proposed by developed countries – or companies from those countries – can be used to reduce emissions in developing countries. The developed country – or company – earns certified emission reduction units, which may be used against the country's own reduction commitment. CDM is primarily focused on development aid and secondly on emission reduction.

The Kyoto Protocol and nuclear energy

The role of nuclear energy in combating climate change received a lot of attention during the UNFCCC negotiations between COP 4 and COP 7 (1998-2002). This was due to the entrenched anti-nuclear position of some of the environment NGOs lobbying at the negotiations and the tendency for national delegations to be dominated by those from Environment Departments, with a historically more negative position towards nuclear energy than their overall national position.

Nuclear energy is discriminated against within the Marakesh Accords, specifically within the sections dealing with the Clean Development Mechanism and Joint Implementation, but currently the effect of this discrimination is largely symbolic.

The Marakesh Accords state:
"Recognizing that Parties included in Annex I are to refrain from using credits (from CDM or JI projects) generated from nuclear facilities to meet their commitments under Article 3, paragraph 1" This text is convoluted, reflecting perhaps a compromise reached during the negotiations. It should be noted that CDM and JI projects involving nuclear facilities are not banned. Parties are free to put forward such projects, as they would do any other candidate project.

However, the text says that developed counties (Annex I) Parties should refrain from using any credits earned from those projects for meeting their commitments – which are the emissions targets agreed under the Kyoto Protocol. The meaning of "should refrain" is a matter of debate. Annex I Parties are also meant not to exceed their emissions targets. Should they refrain from using nuclear project credits unless it means they would miss their target?

Ultimately, this is a symbolic discussion, as the current low price of CDM and JI credits and the short time period over which credits would be awarded mean that the availability of such credits is unlikely to be a significant factor in the decision on whether to invest in nuclear energy.

Concerns over the efficacy of CDM and JI in general have been expressed, many potential investors in projects being frustrated by the bureaucratic process involved in gaining approval for a project and the relatively small rewards for doing so. Moreover, there are concerns over the limited geographical distribution of CDM projects, with the majority of projects taking place in China, India and Brazil.

However, in the longer term the CDM and JI may become a more viable mechanism for encouraging low carbon projects and development. However, it is also possible that new mechanisms will be introduced in subsequent agreements and the role of the CDM and JI may diminish.

Approaches to emissions trading and alternatives, European ETS

The question of emission permits of some kind as a basis for trading in them or trading them off has been approached in several different ways. They may be auctioned, or they can be allocated to firms on the basis of historical emissions (known as grandfathering). Within countries, emissions (eg carbon) taxes may be used rather than emissions trading, but still linked to the price of permits. An attractive feature of tradable permits is that any national scheme can be linked internationally. However, the emission caps need to be set by regulators, who have an impossible task in the light of normal uncertainties, as shown the first decade of the EU system. Also it tends to reward traders more than innovators.

The best-developed arrangement is the European Emission Trading System (ETS), which is the cornerstone of EU policy to counter climate change. The ETS is a cap-and-trade system which is seen as providing the core of a wider scheme to limit carbon emissions worldwide. By mid-2012 the ETS covered some 11,000 installations (power stations and industrial plants) in 27 EU countries plus Norway, accounting for half of the EU’s carbon emissions, or an estimated 40% in 2015. In 2011, carbon to the value of about EUR 112 billion was traded on ETS, but in 2012 this dropped to about EUR 75 billion, its lowest level since 2008.

After a positive start in 2005, in May 2006 the price of emission allowances under the ETS for the first commitment period (2005-2007) plunged to less than half their previous value, causing intense discussion on the efficacy of the whole scheme and making it clear that the caps in some states were too low to promote investment in emission reduction. Most EU countries had issued so many allowances on the basis of padded applications that they did not reach their quotas in the first year of phase one (2005-07) of the ETS, which undercut the value of traded allowances. Allowances in mid-2006 were trading at €18/tonne CO2, representing over 1.5 cents/kWh on coal-fired generation and providing a weak disincentive to using coal, especially in Germany where output constraints apply on nuclear power. For most of 2005 and until May 2006, permits were trading at over €25.

Overall in the EU, 1785 million tonnes of CO2 were emitted in 2005 against quotas of 1829 Mt, though this did not necessarily represent any decrease from what emissions would have been in the absence of the EU ETS. The UK was 33 Mt (16%) over its quota, reflecting the low target set by its government, and a swing back to coal from gas. This meant that generators (particularly) in the UK needed to purchase allowances and pass the cost on to consumers. However, it was thought that many generators had already passed on much of the price of the carbon allowances allocated to them as an "opportunity cost".

In the second commitment/ trading period of the EU ETS (Phase II, 2008-2012) emissions allowance allocations were reduced 6.5% from those in the first commitment period. However the economic crisis radically altered the situation, and from 2009 the ETS had a growing surplus of allowances and international credits because the global economic crisis had depressed emissions more than anticipated, which significantly weakened the price signal. Installations received trading credits from their national allocation plans (NAPs), administered by the governments of the 30 participating countries.

At one level it may be argued that the low price of emissions allowances in the first period could be considered as a success of the EU ETS, promoting the discovery of low-cost carbon avoidance measures. However, the credibility of the EU ETS as a part of broader climate change policies will depend on whether governments setting emissions allocations sufficiently tightly that they ensure the industries covered make a proportionate contribution towards meeting national targets, as part of the EU's overall target.

In January 2008 the European Commission (EC) proposed changes to the EU ETS in the third commitment and trading period 2013-20 which would strengthen and extend the scope of the trading scheme. NAPs would be replaced by centralised allocation by an EU authority and a single EU-wide cap on emissions which is to decrease by 1.74 % each year to 2020, when the cap would be 21% lower than the 2005 starting level. It was intended that the annual reduction would continue after 2020, with a review of the magnitude of the annual reduction to take place by 2025 at the latest. During the third commitment period a much larger share of emissions allowances would be auctioned instead of allocated free of charge. The scheme would broadened to include new industries (e.g. aluminium and ammonia producers) and new gases (nitrous oxide and perfluorocarbons). Due to the ETS having a growing surplus of allowances, the EC postponed the auctioning of some allowances as an immediate measure, and in November 2012 proposed other changes. These include increasing the EU’s 2020 emission reduction target from 20% to 30%, making the annual 1.74% reduction steeper, retiring some Phase III allowances permanently, bringing more sectors into the ETS, and limiting access to international credits. These were considered in 2013.

In January 2014 the EC published its 2030 Framework for Climate and Energy Policies, including a legislative proposal for the ETS to establish a market stability reserve (MSR) to operate in the fourth commitment and trading period (Phase IV) running 2021 to 2030. The reserve would both address the surplus of emission allowances that has built up during Phase II and which keeps the carbon price very low, and also improve the system's robustness by automatically adjusting the supply of allowances to be auctioned. Together with postponing in auctions of 900 million allowances (“backloading”), the proposal was widely supported in addressing the problems facing the rather discredited ETS. In February 2014 backloading was approved with the withdrawal of 400 million allowances that year. In May 2014 the EC said it was open to introducing the market stability measures before 2021, since the oversupply remained large.

In February 2015 the European Parliament voted in favour of a market stability reserve to operate from 2019, and for the 900 million surplus allowances to be added to it, along with 750 million unallocated allowances. In July 2015 the EC proposed putting about 250 million unallocated MSR allowances (from Phase II) plus 100 million unallocated from phase III into a phase IV new entrant reserve (NER), earmarked for new installations and significant capacity expansions. Any unused allowances due to plant closures or reduced production in phase IV will be added to the NER, making a likely total of about 395 million. It also proposed putting 50 million MSR allowances to top up an innovation fund of 400 million phase IV allowances sold by the European Investment Bank (EIB), for CCS, innovative and breakthrough technologies in energy-intensive industries. At €25/t this is worth €11.25 billion. These funding proposals are instead of keeping the MSR allowances off the market, or cancelling them.

The EC also increased the rate of reduction after 2020 to 2.2% per year, in line with the 40% domestic greenhouse gas reduction target for EU by 2030 (relative to 1990). It proposed auctioning 57% of a total 15.5 billion allowances available under the ETS cap for 2021-30, leaving 43%, about 6.3 billion, for free issue. The 57% is the same as in 2015. The original ETS Directive envisaged the free allocation of allowances to diminish to zero in 2027. Analysts expect the ETS carbon price to reach at least €20 by 2020 and €30 by 2030.

The shift from free allocation to auctioning of emissions allowances, as well as the tightening of emissions allowance caps, will benefit nuclear energy and other forms of low carbon generation. Although it is thought that the cost of emissions allowances has already been incorporated as an opportunity cost, the free allocation of allowances means that fossil fuel power plant operators have not faced a true cost themselves for much of the emissions of their plant. In particular, when new electricity generation capacity is considered, fossil fuel generation will have to incorporate the cost of carbon allowances into the economic assessment of the plant. In addition, the tightening allowance cap is likely to lead to higher allowance prices, increasing the cost of greenhouse gas emissions.

However, the ETS has arguably exported rather than reduced CO2 emissions. While the UK’s carbon emissions fell some 15% over 1990 to 2005, when imports were taken into account, carbon emissions on a world basis attributable to UK went up more than 19%, according to Professor Dieter Helm. The general trend for western countries, which substitute imports from countries like China for domestic production, is obvious. The EC is addressing this carbon leakage issue with some free allowances, and in July 2015 considered creating four “at risk” categories, from very high to low, eligible for different levels of free allowances.

Elsewhere a simple carbon emission tax has been applied (contentiously in Australia, at a level far above EU ETS but still too low and with too many exemptions to drive change, before being abandoned). This is straightforward, but the level set is arbitrary and may be out of kilter with ETS systems. Also, like the ETS, it exempts certain industries on an arbitrary or politically-driven basis, creating major inequities. And like the ETS it penalizes exporters while exempting imports.

A carbon consumption tax has been proposed, which is applied like a normal consumption tax but on the basis of CO2 implications in the production of goods and services. This would require certification of sources, not just at manufacturing level but also upstream to power generation, and at the border for imports (where assumptions re electricity inputs would need to be made). It would be equitable between domestic production and imports.Professor Dieter Helm in the UK is a proponent of this, but it is not implemented anywhere.

The ongoing UNFCCC negotiations

The protracted delays before the eventual entry into force of the Kyoto Protocol have meant that theUNFCCC negotiations began to consider what emissions reduction regime should follow the first commitment period, which ended in 2012.

Discussions followed two parallel tracks, the first considering future emissions reduction commitments for Annex I Parties to the Kyoto Protocol, the second considering long-term global cooperative action to address climate change. This second track had a more sensitive task, as it included the USA, without emissions reduction targets for the first commitment period, and also developing countries, which did not have emissions reduction targets.

Decisions on appropriate action beyond 2012 have generated a great deal of controversy. Emissions from developing countries are expected to rise as they increase their use of fossil fuels to meet their need for energy for development. Many developed countries want developing countries to limit the growth in their emissions. Developing countries point out that their per capita emission are still much lower than developed countries and believe that developed countries should show their commitment to reducing emissions first, before expecting developing countries to take action.

In 2008 and 2009 the number of meetings under the UNFCCC increased as parties worked towards a target of agreeing a legally binding agreement for after the first Kyoto Protocol commitment period. However, progress has been slower than hoped. The COP 15/CMP 5 meeting in Copenhagen in December was intended to lead to result in a high-level political agreement, with a more detailed agreement to follow, however an agreement of all Parties was not reached. The Copenhagen Accord, drawn up in the last days of the conference, included non-binding declarations of emissions reduction policies and commitments from individual governments, but no international agreement.

The COP 15/CMP 5 meeting at Copenhagen had attracted tens of thousands of delegates and had been promoted by some as the last chance to reach an agreement in time to succeed the first commitment period of the Kyoto Protocol. In addition, controversy over leaked emails from the influential University of East Anglia's Climate Research Unit had called some to question the case for action on climate change. COP 16/CMP 6 meeting in Mexico in December 2010 made little progress, but was seen as a success in that it managed to re-establish the negotiation process. However, both European and US climate change negotiators had dismissed the possibility that the COP 17/CMP 7 meeting would result in a new binding agreement. Attention turned to implementing a short-term extension of the Kyoto Protocol's first commitment period, to allow a more permanent agreement to be developed. In addition, negotiators sought to implement a number of 'fast-start' funding mechanisms that were intended to support emission reduction or avoidance projects in developing countries.

Short-term and long-term focus of UNFCCC negotiations

The ultimate objective of the Framework Convention on Climate Change is the stabilization of greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system. This is a long-term objective that will require emissions paths to be reduced progressively over the 21st century and beyond.

However, the Kyoto Protocol focussed attention on a relatively short-term emissions objective, namely the first commitment period between 2008 and 2012. The targets set for this period were first agreed in 1997, which gave governments 10-15 years to put in place policies to reach these targets, and only three years between the Protocol's entry into force in 2005 and the start of the first commitment period. This bias towards short-term targets did not provide incentive to make the investments in long-term infrastructure changes, such as energy, transport and buildings, which are needed to bring sustainable reductions in greenhouse gas emissions.

Ahead of the Copenhagen COP15 meeting a number of countries declared their own national emissions reduction targets, applying to a range of timeframes. In some cases, as with the EU, parties agreed to take on more stringent emissions targets if a new agreement could eventually be reached under the UNFCCC.

A useful database of CO2 emissions per capita is EDGAR.

UN climate change conference November-December 2015, Paris

The major emphasis of the COP21 meeting in Paris was on producing a global, binding agreement to cut carbon emissions. At the Paris meeting there was clear international agreement that reducing carbon dioxide emissions was a global priority built on a groundswell of public opinion in many countries, albeit with a range of different timelines involved. It was agreed to aim for a temperature increase below 2°C and with the aim of moving to 1.5 degrees, which suggests that governments will have to introduce additional mitigation actions to move more rapidly to low-carbon technologies, especially in electricity generation. The main and widely recognised implication (which fuelled some extravagant hype stigmatising coal) is that more use must be made of low- or zero-carbon energy sources, including nuclear power.

The International Energy Agency (IEA) described it as "nothing less than a historic milestone for the global energy sector" that would "speed up the transformation of the energy sector by accelerating investments in cleaner technologies and energy efficiency." With wide support, a clean energy innovation fund is being set up to develop cleaner, more affordable and more reliable energy sources. Whatever the advances in electricity storage associated with intermittent renewables, there is now more clearly an inexorable logic for low-cost continuous reliable supply from expanded nuclear power. The IEA had already made it plain that achieving the 2°C goal would require a significant contribution from nuclear energy.

Agneta Rising, Director General of the World Nuclear Association said: "We welcome the commitments that governments have made, and the nuclear industry stands ready to help achieve the goals of the Paris agreement. This agreement should lead to a more positive outlook for nuclear investments, as nuclear is an important part of the response to climate change in countries across the world. What governments need to do now is convert the global agreement they have reached in Paris into national policies, including a progressive decarbonisation of the electricity generation sector. We have proposed that there should be 1000 GWe of nuclear new build by 2050 as part of a balanced low-carbon future energy mix. To achieve this, we need to see the introduction of energy markets with level playing fields which recognise the value of low carbon and reliable generation. We need to see the adoption of harmonised nuclear regulatory processes internationally. We also need to ensure that actions do not lead to clean nuclear power plants being closed prematurely and replaced with more polluting alternatives. Ongoing investment is also needed to help develop the next generation of nuclear technology, along with a clear and achievable pathway for deployment.”

Ahead of COP21, 188 nations had submitted their individual climate action plans, including how much they were intending to cut emissions. There is a wide range of targets in these Intended Nationally Determined Contributions (INDCs), from ambitious cuts by 2030 to almost doubling emissions by 2030, according to individual national circumstances. Collectively the INDCs, if met, are projected to result in a global temperature rise above pre-industrial levels of 2.7°C, which is considered insufficient constraint. National targets are not binding, there are no defined sanctions for failing to meet them, and they need verification anyway as well as five-yearly reviews ratcheting up the good intentions.

First stocktaking talks are planned for 2018. Countries with targets for 2025 should have new targets for 2020, while those with 2030 targets are invited to update them. This process is to be repeated every five years, with a first post-2020 review in 2023. The agreement requires countries regularly to update climate commitments, with each pledge being more ambitious than the last. It also invites countries to write long-term, mid-century low carbon emission strategies by 2020. In contrast to the Kyoto Protocol, the agreement binds all countries equally to these processes (but not targets), though developed countries are expected to “continue taking the lead by undertaking economy-wide absolute emission reduction targets.”

In the power sector, 70% of additional electricity generation to 2030 would be low-carbon. The full implementation of these pledges will require the energy sector to invest $13.5 trillion in energy efficiency and low-carbon technologies from 2015 to 2030, an annual average of $840 billion, according to the IEA. Excluded from all this is the role of forest and peat fires in contributing to emissions.

The Paris Agreement was made available in April 2016 for signature and ratification by individual countries. Following EU ratification, early in October 2016 it had been ratified by countries responsible for 55% of global greenhouse gas emissions, and by over 55 of the 197 signatories.  This implies consent to be bound by the terms of the Agreement. It will come into legal force, to the limited extent that is envisaged, on 4 November 2016. The USA and China - together representing 40% of global emissions - ratified the agreement together in early September.

"The entry into force of the Paris Agreement ... is an extraordinary political achievement which has opened the door to a fundamental shift in the way the world sees, prepares for, and acts on climate change through stronger action at all levels of government, business, investment and civil society," according to the UNFCCC. "The ratification of the Paris Agreement commits governments to making significant reductions in greenhouse gas emissions to limit the effects of climate change. This can only happen if we use all sources of low-carbon electricity, including nuclear energy," Agneta Rising, director general of the World Nuclear Association, said.

Group of 8 (G8)

The Group of 8 (Canada, France, Germany, Italy, Japan, the Russian Federation, the United Kingdom, and the USA) hold annual economic and political summit meetings of the heads of government with international officials.

The 2005 meeting held in Gleneagles, Scotland under the UK Presidency placed Climate Change and Africa as joint priority agenda items. Throughout the preceding year a series of events were held in preparation for the final summit in July.

In February 2005, the Scientific Conference on Climate Change was held at the Hadley Centre for Climate Research and Prediction in Exeter, where the latest scientific understanding of climate change was discussed. The proceedings of the meeting include a discussion of technology options, which recognises that the potential contribution of nuclear energy is almost without technical limits.

A ministerial roundtable meeting of Energy and Environment Ministers held in March 2005, involved 20 countries, including Brazil, China, India, Mexico and South Africa. The meeting concluded that the countries shared common goals of:

  • creating the conditions for economic development and poverty eradication by improving the accessibility and affordability of modern energy services;
  • providing security of supply with energy systems that are resilient, reliable and diversified; and
  • protecting local and global environmental quality, including addressing greenhouse gas emissions.

The Gleneagles Summit itself was distracted by other events and as a result limited progress was made in discussions on climate change. However, it was agreed that the topics of energy and climate change would continue to be discussed at future G8 meetings.

The meeting in St Petersburg, Russia in 2006 focused on global energy security and climate change. There was agreement that the G8 would take action in the following key areas:

  • Increasing transparency, predictability and stability of global energy markets;
  • Improving the investment climate in the energy sector;
  • Enhancing energy efficiency and energy saving;
  • Diversifying the energy mix;
  • Ensuring physical security of critical energy infrastructure;
  • Reducing energy poverty;
  • Addressing climate change and sustainable development.

Included in the details of what was proposed to address these key areas included an endorsement of nuclear energy: "Those of us who have or are considering plans relating to the use and/or development of safe and secure nuclear energy believe that its development will contribute to global energy security, while simultaneously reducing harmful air pollution and addressing the climate change challenge."

The agreement highlighted the INPRO project and the Generation IV International Forum, interim solutions to address back-end fuel cycle issues and the importance of independent effective regulation of nuclear installations. The agreement also highlighted the USA GNEP proposal and the complementary proposals by Russia and the IAEA.

Global energy security and climate change were discussed further at meetings in Germany (June 2007) and Japan (2008). Discussions also took place among the broader G20 group.

Europe

In many respects Europe has been a leader in promoting action on climate change, as set out in some detail above.

In March 2007 the European Council endorsed the European Commission's Strategic Energy Review and agreed on a unilateral cut of 20% in EU greenhouse gas emissions by 2020, relative to 1990 levels. The previous commitment was 8% reduction by 2012. This required strengthening and extending carbon trading arrangements as well as deploying low- or zero-carbon technology. The European Council also endorsed the objective of making a 30% reduction in greenhouse gas emissions by 2020 and said that it would commit to this 30% target if other developed countries committed to (unspecified) comparable reductions in emissions and the more advanced developing countries (e.g. India, Brazil, China) "contributed adequately according to their responsibilities and respective capabilities". French President Chirac described the outcome as "one of the great moments of European history."

The European Council also set a target of meeting 20% of EU energy needs from renewables by 2020, leaving individual countries to decide their own policies in such a way as to allow nuclear power as part of their energy mix to be taken into consideration in allocating individual country targets for renewables. The Council noted "the European Commission's assessment of the contribution of nuclear energy in meeting the growing concerns about safety of energy supply and CO2 emission reductions" and it acknowledged the role of nuclear energy "as a low CO2-emitting energy source." In the event the 2008 policy set was “20-20-20” – 20% reduction in CO2 emissions, 20% of electricity from renewables and 20% improvement in energy efficiency by 2020.

The European Commission’s 2030 Policy Framework for Climate and Energy in January 2014 moved away from major reliance on renewables to achieve emission reduction targets and allows scope for nuclear power to play a larger role. It is focused on CO2 emission reduction, not the means of achieving that, and allows more consideration for cost-effectiveness.

The centerpiece is a binding 40% reduction in domestic greenhouse gas emissions by 2030 (compared with a 1990 baseline) which will require strong commitments from EU member states. Current policies and measures if followed through should deliver 32% reduction by then, so 40% “is achievable” and widely supported. It implies a 43% cut from 2005 for CO2 in sectors covered by the EU emissions trading scheme (ETS). There are to be no post-2020 national renewables targets, and individual states are free to use whatever technology they wish to achieve emission reductions in the longer term, though a 27% “headline target at European level for renewable energy” is included. The framework also proposes reform of the ETS to make it the principal driver of climate policy (see Emission Trading section above), and it drops a binding energy efficiency target and a directive for use of biofuels in transport.

Impetus for the profound change in emphasis from the 2008 policy framework appears to have come from EU member states which are winding back renewables programs due to escalating costs. The International Energy Agency has pointed out the huge difference in energy prices between USA and EU, with gas prices three times as high and electricity twice as high in the EU. The EU is evidently concerned about loss of international competitiveness and the increasingly chaotic retreat from subsidy schemes related to its 2020 renewables target. More generally, it acknowledges that “the rapid development of renewable energy sources now poses new challenges for the energy system”.

The key change from 2020 goals is “providing flexibility for Member States to define a low-carbon transition appropriate to their specific circumstances, preferred energy mix and needs in terms of energy security, and allowing them to keep costs to a minimum.” An early test of this will be approval for UK plans to set long-term electricity prices to enable investment in nuclear plants.

The WNA said that the “flexible” approach outlined allows nuclear power to play an expanded role in decarbonising electricity supply. The ambitious target “is a bare minimum if the EU wishes to achieve its objective of an 80% reduction by 2050, and do its part in averting a 2°C rise in global temperatures. Unfortunately the target of 27% for renewable energy continues to undermine the possibility for cost efficiency in meeting the carbon target. It also again demonstrates an unjustified preference in EU policy for renewable energy over other carbon reduction pathways – such as nuclear energy – regardless of cost, maturity and the preferences of individual Member States.”

However, only weeks later the EU parliament in a non-binding resolution voted by 341 to 263 to claw back some of the previous provisions by changing the EC draft policy to call for binding national targets of 30% of power from renewables (not 27% overall) and reinstating the energy efficiency goal to 40% improvement by 2030, along with the EC 40% greenhouse gas reduction. Member states can however go with the EC draft policy rather than this.

Asia Pacific Partnership (APP)

The Asia-Pacific Partnership on Clean Development and Climate, known informally as APP, is a non-treaty partnership established by Australia, India, Japan, China, South Korea and the United States in July 2005 and launched in 2006. The Partnership involved countries that account for about half of the world's population and more than half of the world's economy, energy use, and greenhouse gas emissions. In October 2007, Canada joined APP.

The objectives of the partnership included:

  • To work together and with private companies to expand markets for investment and trade in cleaner, more efficient energy technologies, goods, and services in key sectors.
  • To work with multilateral development banks on financing for initiatives and programs identified by the task forces that will expand the use of technologies and practices designed to promote objectives of the Partnership.
  • To work on areas of collaboration including Energy Efficiency, Methane Capture and Use, Rural/Village Energy Systems, Clean Coal, Civilian Nuclear Power, Advanced Transportation, Liquefied Natural Gas, Geothermal, Building and Home Construction/Operation, Bioenergy, Agriculture/Forestry, Hydropower, Wind Power and Solar Power.

In April 2011 the APP wound up, though some programs continued under other auspices. The APP Power Generation and Transmission Task Force was transitioned into a new "Global Superior Energy Performance Partnership (GSEP)" that will form part of the Clean Energy Ministerial that had been established in 2010. The Clean Energy Ministerial initiative includes representatives from 24 governments representing 70% of global GDP and 80% of global greenhouse gas emissions.

Contraction & Convergence

The concept of Contraction and Convergence is a long-term framework towards the ultimate object of climate change policy in terms of 'safe' emissions levels. The concept has gained some interest amongst politicians and climate change experts and is seen as potentially superseding the arbitrary short-term target setting of the current Kyoto Protocol process.

Under a Contraction and Convergence regime an international agreement would define to what level atmospheric greenhouse gas concentrations could rise before becoming unacceptable. Once this is defined, an estimate would be made of how much reduction in global greenhouse gas emissions is required to meet the target, taking into account the effect of sinks, and how quickly the target should be reached. This represents the 'contraction' element, and in itself it does not differ substantially from the aims of the UNFCCC to stabilize "greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system."

The key differentiating factor of Contraction and Convergence is the proposal that ultimately the 'right' to emit carbon dioxide is a human right which should be shared equally. Therefore, emissions targets should ultimately be allocated to countries on the basis of their populations. Emissions rights would be on a per capita basis and therefore require convergence from the present very unequal per capita levels to a universal per capita level.

During the convergence period, which should not be protracted, emission permits would be progressively adjusted from status quo to these new levels. Permits could be traded, and this would cause a major economic transfer from countries that have used fossil fuels to create wealth to those still struggling to alleviate poverty. After convergence, each country would receive the same allocation of carbon dioxide emission rights per head of population and further trading in permits is envisaged.

The fundamental principles of Contraction and Convergence have received some support from those who see the equal allocation of emissions rights as promoting social equity. However, these fundamental principles alone do not provide an alternative to the UNFCCC process, as they are no more than conceptual and much would be needed to turn them into a policy framework. Achieving political backing in developed countries is unlikely.

There are also concerns as to the fairness of the proposal. There are concerns that countries with rapidly expanding populations could be rewarded through this scheme, as their expanding populations could result in them having a greater allocation of emissions on a country basis. It might therefore be necessary to fix the overall country allocation on a specific national population on a specific date.

It has also been suggested that some countries have conditions that inherently require greater energy usage and consequent emissions, so therefore there should be differentiated emissions rights depending on local circumstances. For example someone living in the Arctic would have greater energy needs for heating and lighting than someone living in a more temperate region.

Carbon emission stocktake

The first complete set of data for the 41 industrialised parties of the UN Framework Convention on Climate Change (FCCC) was released at the Nairobi meeting and shows that greenhouse gas emissions continued to rise despite measures under the Kyoto Protocol. Figures for 1990 to 2004 showed that apart from the temporary effect of restructuring in eastern Europe, emissions from industrialised countries rose 11% over the period. For all those countries emissions were down by 3% and for the 36 parties to the Protocol, emissions declined by 15%. Emissions from the USA were 16% up, those from Australia 25% up, and energy-related CO2 emissions for China rose 110% and for India 89% over the period – those from China exceeding Europe's. Most developed countries were targeting an 8% reduction to 2008-12.

In May 2011 the OECD International Energy Agency (IEA) released figures for 2010 energy-related CO2 emissions, which reached a new high of 30.6 billion tonnes. The previous record was 29.3 Gt in 2008 (emissions in 2009 dipped because of the global financial crisis).  Non-OECD countries – particularly China and India – saw much stronger increases in emissions as their economic growth accelerated. On a per capita basis, OECD countries emitted an average of 10 tonnes of CO2, compared with 5.8 tonnes in China and 1.5 tonnes in India. In terms of fuel, some 44% of the estimated CO2 emissions in 2010 came from the burning of coal, 36% from oil, and 20% from natural gas. The IEA estimated that some 80% of projected CO2 emissions from the power sector in 2020 were already 'locked in', as they will come from either existing power plants or plants currently under construction.

CO2 emissions in 2014 were 35.7 billion tonnes, including 10.5 Gt from China, 5.3 Gt from the USA, 3.4 Gt from the EU, and 2.3 Gt from India.

 

Apart from policies to use low or zero-carbon sources for electricity generation, some countries have favoured the use of natural gas to replace coal, on the basis that emissions from actually burning the fuel are around half of those from coal. However, methane leakage from the drilling and pipeline delivery of natural gas can offset any CO2 benefits that natural gas may bring over coal during combustion and use. A 3% leakage of natural gas will push the global warming effect of natural gas used for electricity to the same level as that of coal per kWh.

  • Most nuclear electricity is generated using just two kinds of reactors which were developed in the 1950s and improved since.
  • New designs are coming forward and some are in operation as the first generation reactors come to the end of their operating lives.
  • Over 11% of the world's electricity is produced from nuclear energy, more than from all sources worldwide in 1960.

This paper is about the main conventional types of nuclear reactor. For more advanced types, see Advanced Reactors and Small Reactors papers, and also Generation IV reactors.

A nuclear reactor produces and controls the release of energy from splitting the atoms of certain elements. In a nuclear power reactor, the energy released is used as heat to make steam to generate electricity. (In a research reactor the main purpose is to utilise the actual neutrons produced in the core. In most naval reactors, steam drives a turbine directly for propulsion.)

The principles for using nuclear power to produce electricity are the same for most types of reactor. The energy released from continuous fission of the atoms of the fuel is harnessed as heat in either a gas or water, and is used to produce steam. The steam is used to drive the turbines which produce electricity (as in most fossil fuel plants).

The world's first nuclear reactors operated naturally in a uranium deposit about two billion years ago. These were in rich uranium orebodies and moderated by percolating rainwater. The 17 known at Oklo in west Africa, each less than 100 kW thermal, together consumed about six tonnes of that uranium. It is assumed that these were not unique worldwide.

Today, reactors derived from designs originally developed for propelling submarines and large naval ships generate about 85% of the world's nuclear electricity. The main design is the pressurised water reactor (PWR) which has water at over 300°C under pressure in its primary cooling/heat transfer circuit, and generates steam in a secondary circuit. The less numerous boiling water reactor (BWR) makes steam in the primary circuit above the reactor core, at similar temperatures and pressure. Both types use water as both coolant and moderator, to slow neutrons. Since water normally boils at 100°C, they have robust steel pressure vessels or tubes to enable the higher operating temperature. (Another type uses heavy water, with deuterium atoms, as moderator. Hence the term ‘light water’ is used to differentiate.)

Components of a nuclear reactor

There are several components common to most types of reactors:

Fuel. Uranium is the basic fuel. Usually pellets of uranium oxide (UO2) are arranged in tubes to form fuel rods. The rods are arranged into fuel assemblies in the reactor core.*
* In a new reactor with new fuel a neutron source is needed to get the reaction going. Usually this is beryllium mixed with polonium, radium or other alpha-emitter. Alpha particles from the decay cause a release of neutrons from the beryllium as it turns to carbon-12. Restarting a reactor with some used fuel may not require this, as there may be enough neutrons to achieve criticality when control rods are removed.

Moderator. Material in the core which slows down the neutrons released from fission so that they cause more fission. It is usually water, but may be heavy water or graphite.

Control rods. These are made with neutron-absorbing material such as cadmium, hafnium or boron, and are inserted or withdrawn from the core to control the rate of reaction, or to halt it.*  In some PWR reactors, special control rods are used to enable the core to sustain a low level of power efficiently. (Secondary control systems involve other neutron absorbers, usually boron in the coolant – its concentration can be adjusted over time as the fuel burns up.)
In fission, most of the neutrons are released promptly, but some are delayed. These are crucial in enabling a chain reacting system (or reactor) to be controllable and to be able to be held precisely critical.

Coolant. A fluid circulating through the core so as to transfer the heat from it.  In light water reactors the water moderator functions also as primary coolant. Except in BWRs, there is secondary coolant circuit where the water becomes steam. (See also later section on primary coolant characteristics)

Pressure vessel or pressure tubes. Usually a robust steel vessel containing the reactor core and moderator/coolant, but it may be a series of tubes holding the fuel and conveying the coolant through the surrounding moderator.

Steam generator. Part of the cooling system of pressurised water reactors (PWR & PHWR) where the high-pressure primary coolant bringing heat from the reactor is used to make steam for the turbine, in a secondary circuit. Essentially a heat exchanger like a motor car radiator*. Reactors have up to six 'loops', each with a steam generator. Since 1980 over 110 PWR reactors have had their steam generators replaced after 20-30 years service, 57 of these in USA.

* These are large heat exchangers for transferring heat from one fluid to another – here from high-pressure primary circuit in PWR to secondary circuit where water turns to steam. Each structure weighs up to 800 tonnes and contains from 300 to 16,000 tubes about 2 cm diameter for the primary coolant, which is radioactive due to nitrogen-16 (N-16, formed by neutron bombardment of oxygen, with half-life of 7 seconds). The secondary water must flow through the support structures for the tubes. The whole thing needs to be designed so that the tubes don't vibrate and fret, operated so that deposits do not build up to impede the flow, and maintained chemically to avoid corrosion. Tubes which fail and leak are plugged, and surplus capacity is designed to allow for this. Leaks can be detected by monitoring N-16 levels in the steam as it leaves the steam generator.

Containment. The structure around the reactor and associated steam generators which is designed to protect it from outside intrusion and to protect those outside from the effects of radiation in case of any serious malfunction inside. It is typically a metre-thick concrete and steel structure.

Newer Russian and some other reactors install core melt localisation devices or 'core catchers' under the pressure vessel to catch any melted core material in the event of a major accident.

There are several different types of reactors as indicated in the following table.

Nuclear power plants in commercial operation

Reactor type Main Countries Number GWe Fuel Coolant Moderator
Pressurised water reactor (PWR)
US, France, Japan, Russia, China
277
257
enriched UO2
water
water
Boiling water reactor (BWR)
US, Japan, Sweden
80
75
enriched UO2
water
water
Pressurised heavy water reactor (PHWR)
Canada, India
49
25
natural UO2
heavy water
heavy water
Gas-cooled reactor (AGR & Magnox)
UK
15
8
natural U (metal),
enriched UO2
CO2
graphite
Light water graphite reactor (RBMK & EGP)
Russia
11 + 4
10.2
enriched UO2
water
graphite
Fast neutron reactor (FBR)
Russia
2
0.6
PuO2 and UO2
liquid sodium
none
  TOTAL 438 376      
IAEA data, end of 2014.  GWe = capacity in thousands of megawatts (gross)
Source: Nuclear Engineering International Handbook 2011, updated to 1/1/12
For reactors under construction: see paper Plans for New Reactors 

Fuelling a nuclear power reactor

Most reactors need to be shut down for refuelling, so that the pressure vessel can be opened up. In this case refuelling is at intervals of 1-2 years, when a quarter to a third of the fuel assemblies are replaced with fresh ones. The CANDU and RBMK types have pressure tubes (rather than a pressure vessel enclosing the reactor core) and can be refuelled under load by disconnecting individual pressure tubes.

If graphite or heavy water is used as moderator, it is possible to run a power reactor on natural instead of enriched uranium. Natural uranium has the same elemental composition as when it was mined (0.7% U-235, over 99.2% U-238), enriched uranium has had the proportion of the fissile isotope (U-235) increased by a process called enrichment, commonly to 3.5 - 5.0%. In this case the moderator can be ordinary water, and such reactors are collectively called light water reactors. Because the light water absorbs neutrons as well as slowing them, it is less efficient as a moderator than heavy water or graphite.

During operation, some of the U-238 is changed to plutonium, and Pu-239 ends up providing about one third of the energy from the fuel.

In most reactors the fuel is ceramic uranium oxide (UO2 with a melting point of 2800°C) and most is enriched. The fuel pellets (usually about 1 cm diameter and 1.5 cm long) are typically arranged in a long zirconium alloy (zircaloy) tube to form a fuel rod, the zirconium being hard, corrosion-resistant and transparent to neutrons.* Numerous rods form a fuel assembly, which is an open lattice and can be lifted into and out of the reactor core. In the most common reactors these are about 4 metres long. A BWR fuel assembly may be about 320 kg, a PWR one 655 kg, in which case they hold 183 kg uranium and 460 kgU respectively. In both, about 100 kg of zircaloy is involved.

*Zirconium is an important mineral for nuclear power, where it finds its main use. It is therefore subject to controls on trading. It is normally contaminated with hafnium, a neutron absorber, so very pure 'nuclear grade' Zr is used to make the zircaloy, which is about 98% Zr plus about 1.5% tin, also iron, chromium and sometimes nickel to enhance its strength. 

Burnable poisons are often used in fuel or coolant to even out the performance of the reactor over time from fresh fuel being loaded to refuelling. These are neutron absorbers which decay under neutron exposure, compensating for the progressive build up of neutron absorbers in the fuel as it is burned. The best known is gadolinium, which is a vital ingredient of fuel in naval reactors where installing fresh fuel is very inconvenient, so reactors are designed to run more than a decade between refuellings. Gadolinium is incorporated in the ceramic fuel pellets. An alternative is zirconium diboride integral fuel burnable absorber (IFBA) as a thin coating on normal pellets.

Gadolinium, mostly at up to 3g oxide per kilogram of fuel, requires slightly higher fuel enrichment to compensate for it, and also after burn-up of about 17 GWd/t it retains about 4% of its absorbtive effect and does not decrease further. The ZrB2 IFBA burns away more steadily and completely, and has no impact on fuel pellet properties. It is now used in most US reactors and a few in Asia. China has the technology for AP1000 reactors.

The power rating of a nuclear power reactor

Nuclear power plant reactor power outputs are quoted in three ways:

  • Thermal MWt, which depends on the design of the actual nuclear reactor itself, and relates to the quantity and quality of the steam it produces.
  • Gross electrical MWe indicates the power produced by the attached steam turbine and generator, and also takes into account the ambient temperature for the condenser circuit (cooler means more electric power, warmer means less). Rated gross power assumes certain conditions with both.
  • Net electrical MWe, which is the power available to be sent out from the plant to the grid, after deducting the electrical power needed to run the reactor (cooling and feed-water pumps, etc.) and the rest of the plant.*

Net electrical MWe and gross MWe vary slightly from summer to winter, so normally the lower summer figure, or an average figure, is used. If the summer figure is quoted plants may show a capacity factor greater than 100% in cooler times. Watts Bar PWR in Tennessee is reported to run at about 1125 MWe in summer and about 1165 MWe net in winter, due to different condenser cooling water temperatures. Some design options, such as powering the main large feed-water pumps with electric motors (as in EPR) rather than steam turbines (taking steam before it gets to the main turbine-generator), explains some gross to net differences between different reactor types. The EPR has a relatively large drop from gross to net MWe for this reason.

Gross and Net Power

The relationship between these is expressed in two ways:

  • Thermal efficiency %, the ratio of gross MWe to thermal MW. This relates to the difference in temperature between the steam from the reactor and the cooling water. It is often 33-37%.
  • Net efficiency %, the ratio of net MWe achieved to thermal MW. This is a little lower, and allows for plant usage.

In WNA papers and figures and WNN items, generally net MWe is used for operating plants, and gross MWe for those under construction or planned/proposed.

Pressurised water reactor (PWR)

This is the most common type, with over 230 in use for power generation and several hundred more employed for naval propulsion. The design of PWRs originated as a submarine power plant. PWRs use ordinary water as both coolant and moderator. The design is distinguished by having a primary cooling circuit which flows through the core of the reactor under very high pressure, and a secondary circuit in which steam is generated to drive the turbine. In Russia these are known as VVER types – water-moderated and -cooled.

 

A Pressurized Water Reactor (PWR) diagram

 

A PWR has fuel assemblies of 200-300 rods each, arranged vertically in the core, and a large reactor would have about 150-250 fuel assemblies with 80-100 tonnes of uranium.

Water in the reactor core reaches about 325°C, hence it must be kept under about 150 times atmospheric pressure to prevent it boiling. Pressure is maintained by steam in a pressuriser (see diagram). In the primary cooling circuit the water is also the moderator, and if any of it turned to steam the fission reaction would slow down. This negative feedback effect is one of the safety features of the type. The secondary shutdown system involves adding boron to the primary circuit.

The secondary circuit is under less pressure and the water here boils in the heat exchangers which are thus steam generators. The steam drives the turbine to produce electricity, and is then condensed and returned to the heat exchangers in contact with the primary circuit.

Boiling water reactor (BWR)

This design has many similarities to the PWR, except that there is only a single circuit in which the water is at lower pressure (about 75 times atmospheric pressure) so that it boils in the core at about 285°C. The reactor is designed to operate with 12-15% of the water in the top part of the core as steam, and hence with less moderating effect and thus efficiency there.  BWR units can operate in load-following mode more readily then PWRs.

The steam passes through drier plates (steam separators) above the core and then directly to the turbines, which are thus part of the reactor circuit. Since the water around the core of a reactor is always contaminated with traces of radionuclides, it means that the turbine must be shielded and radiological protection provided during maintenance. The cost of this tends to balance the savings due to the simpler design. Most of the radioactivity in the water is very short-lived*, so the turbine hall can be entered soon after the reactor is shut down.

* mostly N-16, with a 7 second half-life

A BWR fuel assembly comprises 90-100 fuel rods, and there are up to 750 assemblies in a reactor core, holding up to 140 tonnes of uranium. The secondary control system involves restricting water flow through the core so that more steam in the top part reduces moderation.

 

 A Boiling Water Reactor (BWR) diagram

 

Pressurised heavy water reactor (PHWR)

The PHWR reactor design has been developed since the 1950s in Canada as the CANDU, and from 1980s also in India. PHWRs generally use natural uranium (0.7% U-235) oxide as fuel, hence needs a more efficient moderator, in this case heavy water (D2O).** The PHWR produces more energy per kilogram of mined uranium than other designs, but also produces a much larger amount of used fuel per unit output.

** with the CANDU system, the moderator is enriched (i.e. water) rather than the fuel – a cost trade-off.

The moderator is in a large tank called a calandria, penetrated by several hundred horizontal pressure tubes which form channels for the fuel, cooled by a flow of heavy water under high pressure in the primary cooling circuit, reaching 290°C. As in the PWR, the primary coolant generates steam in a secondary circuit to drive the turbines. The pressure tube design means that the reactor can be refuelled progressively without shutting down, by isolating individual pressure tubes from the cooling circuit. It is also less costly to build than designs with a large pressure vessel, but the tubes have not proved as durable.

 

 A Pressurized Heavy Water Reactor (PHWR/Candu) diagram

 

A CANDU fuel assembly consists of a bundle of 37 half metre long fuel rods (ceramic fuel pellets in zircaloy tubes) plus a support structure, with 12 bundles lying end to end in a fuel channel. Control rods penetrate the calandria vertically, and a secondary shutdown system involves adding gadolinium to the moderator. The heavy water moderator circulating through the body of the calandria vessel also yields some heat (though this circuit is not shown on the diagram above).

Newer PHWR designs such as the Advanced Candu Reactor (ACR) have light water cooling and slightly-enriched fuel.

CANDU reactors can accept a variety of fuels. They may be run on recycled uranium from reprocessing LWR used fuel, or a blend of this and depleted uranium left over from enrichment plants. About 4000 MWe of PWR might then fuel 1000 MWe of CANDU capacity, with addition of depleted uranium. Thorium may also be used in fuel.

Advanced gas-cooled reactor (AGR)

These are the second generation of British gas-cooled reactors, using graphite moderator and carbon dioxide as primary coolant. The fuel is uranium oxide pellets, enriched to 2.5-3.5%, in stainless steel tubes. The carbon dioxide circulates through the core, reaching 650°C and then past steam generator tubes outside it, but still inside the concrete and steel pressure vessel (hence 'integral' design). Control rods penetrate the moderator and a secondary shutdown system involves injecting nitrogen to the coolant.

 

 An Advanced Gas-cooled Reactor (AGR) diagram

 

The AGR was developed from the Magnox reactor, also graphite moderated and CO2 cooled, and one of these is still operating in UK to late 2014. They use natural uranium fuel in metal form. Secondary coolant is water.

Light water graphite-moderated reactor (RBMK)

This is a Soviet design, developed from plutonium production reactors. It employs long (7 metre) vertical pressure tubes running through graphite moderator, and is cooled by water, which is allowed to boil in the core at 290°C, much as in a BWR. Fuel is low-enriched uranium oxide made up into fuel assemblies 3.5 metres long. With moderation largely due to the fixed graphite, excess boiling simply reduces the cooling and neutron absorbtion without inhibiting the fission reaction, and a positive feedback problem can arise, which is why they have never been built outside the Soviet Union. See appendix on RBMK Reactors for more detail.

Advanced reactors

Several generations of reactors are commonly distinguished. Generation I reactors were developed in 1950-60s and only one is still running today. They mostly used natural uranium fuel and used graphite as moderator. Generation II reactors are typified by the present US fleet and most in operation elsewhere. They typically use enriched uranium fuel and are mostly cooled and moderated by water. Generation III are the Advanced Reactors evolved from these, the first few of which are in operation in Japan and others are under construction and ready to be ordered. They are developments of the second generation with enhanced safety. There is no clear distinction Gen II to Gen III.

Generation IV designs are still on the drawing board and will not be operational before 2020 at the earliest, probably later. They will tend to have closed fuel cycles and burn the long-lived actinides now forming part of spent fuel, so that fission products are the only high-level waste. Of seven designs under development, 4 or 5 will be fast neutron reactors. Four will use fluoride or liquid metal coolants, hence operate at low pressure. Two will be gas-cooled. Most will run at much higher temperatures than today’s water-cooled reactors. See Generation IV Reactors paper.

More than a dozen (Generation III) advanced reactor designs are in various stages of development. Some are evolutionary from the PWR, BWR and CANDU designs above, some are more radical departures. The former include the Advanced Boiling Water Reactor, a few of which are now operating with others under construction. The best-known radical new design has the fuel as large 'pebbles' and uses helium as coolant, at very high temperature, possibly to drive a turbine directly.

Considering the closed fuel cycle, Generation 1-3 reactors recycle plutonium (and possibly uranium), while Generation IV are expected to have full actinide recycle.

Fast neutron reactors (FNR)

Some reactors (only one in commercial service) do not have a moderator and utilise fast neutrons, generating power from plutonium while making more of it from the U-238 isotope in or around the fuel. While they get more than 60 times as much energy from the original uranium compared with the normal reactors, they are expensive to build. Further development of them is likely in the next decade, and the main designs expected to be built in two decades are FNRs. If they are configured to produce more fissile material (plutonium) than they consume they are called Fast Breeder Reactors (FBR). See also Fast Neutron Reactors and Small Reactors papers.

Floating nuclear power plants

Apart from over 200 nuclear reactors powering various kinds of ships, Rosatom in Russia has set up a subsidiary to supply floating nuclear power plants ranging in size from 70 to 600 MWe. These will be mounted in pairs on a large barge, which will be permanently moored where it is needed to supply power and possibly some desalination to a shore settlement or industrial complex. The first has two 40 MWe reactors based on those in icebreakers and will operate at a remote site in Siberia. Electricity cost is expected to be much lower than from present alternatives.

The Russian KLT-40S is a reactor well proven in icebreakers and now proposed for wider use in desalination and, on barges, for remote area power supply. Here a 150 MWt unit produces 35 MWe (gross) as well as up to 35 MW of heat for desalination or district heating. These are designed to run 3-4 years between refuelling and it is envisaged that they will be operated in pairs to allow for outages, with on-board refuelling capability and used fuel storage. At the end of a 12-year operating cycle the whole plant is taken to a central facility for 2-year overhaul and removal of used fuel, before being returned to service. Two units will be mounted on a 21,000 tonne barge. A larger Russian factory-built and barge-mounted reactor is the VBER-150, of 350 MW thermal, 110 MWe. The larger VBER-300 PWR is a 325 MWe unit, originally envisaged in pairs as a floating nuclear power plant, displacing 49,000 tonnes. As a cogeneration plant it is rated at 200 MWe and 1900 GJ/hr. See also Nuclear Power in Russia paper.

Lifetime of nuclear reactors

Most of today's nuclear plants which were originally designed for 30 or 40-year operating lives. However, with major investments in systems, structures and components lives can be extended, and in several countries there are active programs to extend operating lives. In the USA most of the more than one hundred reactors are expected to be granted licence extensions from 40 to 60 years. This justifies significant capital expenditure in upgrading systems and components, including building in extra performance margins.

Some components simply wear out, corrode or degrade to a low level of efficiency. These need to be replaced. Steam generators are the most prominent and expensive of these, and many have been replaced after about 30 years where the reactor otherwise has the prospect of running for 60 years. This is essentially an economic decision. Lesser components are more straightforward to replace as they age. In Candu reactors, pressure tube replacement has been undertaken on some plants after about 30 years operation.

A second issue is that of obsolescence. For instance, older reactors have analogue instrument and control systems. Thirdly, the properties of materials may degrade with age, particularly with heat and neutron irradiation. In respect to all these aspects, investment is needed to maintain reliability and safety. Also, periodic safety reviews are undertaken on older plants in line with international safety conventions and principles to ensure that safety margins are maintained.

Another important issue is knowledge management (KM) over the full lifecycle from design, through construction and operation to decommissioning for reactors and other facilities. This may span a century and involve several countries, and involve a succession of companies. The plant lifespan will cover several generations of engineers. Data needs to be transferable across several generations of software and IT hardware, as well as being shared with other operators of similar plants.* Significant modifications may be made to the design over the life of the plant, so original documentation is not sufficient, and loss of design base knowledge can have huge implications (eg Pickering A and Bruce A in Ontario). Knowledge management is often a shared responsibility and is essential for effective decision-making and the achievement of plant safety and economics.

* ISO15926 covers portability and interoperability for lifecycle open data standard. Also EPRI in 2013 published Advanced Nuclear Technology: New Nuclear Power Plant Information Handover Guide.  

See also section on Ageing, in Safety of Nuclear Power Reactors paper.

Load-following capability

Nuclear power plants are essentially base-load generators, ideally running continuously at high capacity. This is because their power output cannot efficiently be ramped up and down on a daily and weekly basis, and in this respect they are similar to most coal-fired plants. (It is also uneconomic to run them at less than full capacity, since they are expensive to build but cheap to run.) However, in some situations it is necessary to vary the output according to daily and weekly load cycles on a regular basis, for instance in France, where there is a very high reliance on nuclear power.

BWRs can be made to follow loads reasonably easily without burning the core unevenly, by changing the coolant flow rate. Load following is not as readily achieved in a PWR, but especially in France since 1981, so-called 'grey' control rods are used. The ability of a PWR to run at less than full power for much of the time depends on whether it is in the early part of its 18 to 24-month refuelling cycle or late in it, and whether it is designed with special control rods which diminish power levels throughout the core without shutting it down. Thus, though the ability on any individual PWR reactor to run on a sustained basis at low power decreases markedly as it progresses through the refueling cycle, there is considerable scope for running a fleet of reactors in load-following mode. European Utility Requirements (EUR) since 2001 specify that new reactor designs must be capable of load-following between 50 and 100% of capacity with a rate of change of electric output of 3-5% per minute. The economic consequences are mainly due to diminished load factor of a capital-intensive plant. Further information in the Nuclear Power in Francepaper and the 2011 Nuclear Energy Agency report, Technical and Economic Aspects of Load Following with Nuclear Power Plants.

As fast neutron reactors become established in future years, their ability to load-follow will be a benefit.

Primary coolants

The advent of some of the designs mentioned above provides opportunity to review the various primary heat transfer fluids used in nuclear reactors. There is a wide variety – gas, water, light metal, heavy metal and salt:

Water or heavy water must be maintained at very high pressure (1000-2200 psi, 7-15 MPa, 150 atmospheres) to enable it to function well above 100°C, up to 345°C, as in present reactors. This has a major influence on reactor engineering. However, supercritical water around 25 MPa can give 45% thermal efficiency – as at some fossil-fuel power plants today with outlet temperatures of 600°C, and at ultra supercritical levels (30+ MPa) 50% may be attained.

Water cooling of steam condensers is fairly standard in all power plants, because it works very well, it is relatively inexpensive, and there is a huge experience base. Water is a lot more effective than air for removing heat, though its thermal conductivity is less than liquid alternatives.

Helium must be used at similar pressure (1000-2000 psi, 7-14 MPa) to maintain sufficient density for efficient operation. Again, there are engineering implications, but it can be used in the Brayton cycle to drive a turbine directly.

Carbon dioxide was used in early British reactors, and their current AGRs which operate at much higher temperatures than light water reactors. It is denser than helium and thus likely to give better thermal conversion efficiency. It also leaks less readily than helium. There is now interest in supercritical CO2 for the Brayton cycle.

Sodium, as normally used in fast neutron reactors at around 550ºC, melts at 98°C and boils at 883°C at atmospheric pressure, so despite the need to keep it dry the engineering required to contain it is relatively modest. It has high thermal conductivity. However, normally water/steam is used in the secondary circuit to drive a turbine (Rankine cycle) at lower thermal efficiency than the Brayton cycle. In some designs sodium is in a secondary circuit to steam generators. Sodium does not corrode the metals used in the fuel cladding or primary circuit, nor the fuel itself if there is cladding damage, but it is very reactive generally. In particular it reacts exothermically with water or steam to liberate hydrogen. It burns in air, but much less vigorously. Sodium has a low neutron capture cross section, but it is enough for some Na-23 to become Na-24, which is a beta-emitter and very gamma-active with 15-hour half-life, so some shielding is required. If a reactor needs to be shut down frequently, NaK eutectic which is liquid at room temperature (about 13°C) may be used as coolant, but the potassium is pyrophoric, which increases the hazard.

Lead or lead-bismuth eutectic in fast neutron reactors are capable of higher temperature operation at atmospheric pressure. They are transparent to neutrons, aiding efficiency due to greater spacing between fuel pins which then allows coolant flow by convection for decay heat removal, and since they do not react with water the heat exchanger interface is safer. They do not burn when exposed to air. However, they are corrosive of fuel cladding and steels, which originally limited temperatures to 550°C. With today's materials 650°C can be reached, and in future 800°C is envisaged with the second stage of Gen IV development, using oxide dispersion-strengthened steels. They have much higher thermal conductivity than water, but lower than sodium. Westinghouse is developing a lead-cooled fast reactor concept. While lead has limited activation from neutrons, a problem with Pb-Bi is that it yields toxic polonium (Po-210) activation product, an alpha-emitter with a half-life of 138 days. Pb-Bi melts at a relatively low 125°C (hence eutectic) and boils at 1670°C, Pb melts at 327°C and boils at 1737°C but is very much more abundant and cheaper to produce than bismuth, hence is envisaged for large-scale use in the future, though freezing must be prevented. The development of nuclear power based on Pb-Bi cooled fast neutron reactors is likely to be limited to a total of 50-100 GWe, basically for small reactors in remote places. In 1998 Russia declassified a lot of research information derived from its experience with submarine reactors, and US interest in using Pb generally or Pb-Bi for small reactors has increased subsequently. The Gen4 Module (Hyperion) reactor will use lead-bismuth eutectic which is 45% Pb, 55% Bi. A secondary circuit generating steam is likely.

SALT:  Fluoride salts boil at around 1400°C at atmospheric pressure, so allow several options for use of the heat, including using helium in a secondary Brayton cycle circuit with thermal efficiencies of 48% at 750°C to 59% at 1000°C, or manufacture of hydrogen. Fluoride salts have a very high boiling temperature, very low vapour pressure even at red heat, very high volumetric heat capacity (carry more heat than the same volume of water), good heat transfer properties, low neutron absorbtion, good neutron moderation capability, are not damaged by radiation, are chemically very stable so absorb all fission products well and do not react violently with air or water, are compatible with graphite, and some are also inert to some common structural metals. Some gamma-active F-20 is formed by neutron capture, but has very short half-life (11 seconds).

Lithium-beryllium fluoride Li2BeF4 (FLiBe) salt is a eutectic version of LiF (2LiF + BeF2) which solidifies at 459°C and boils at 1430°C. It is favoured in MSR and AHTR/FHR primary cooling and when uncontaminated has a low corrosion effect. LiF without the toxic beryllium solidifies at about 500°C and boils at about 1200°C. FLiNaK (LiF-NaF-KF) is also eutectic and solidifies at 454°C and boils at 1570°C. It has a higher neutron cross-section than FLiBe or LiF but can be used intermediate cooling loops.

Chloride salts have advantages in fast-spectrum molten salt reactors, having higher solubility for actinides than fluorides.  While NaCl has good nuclear, chemical and physical properties its high melting point means it needs to be blended with MgCl2 or CaCl2, the former being preferred in eutectic, and allowing the addition of actinide trichlorides. The major isotope of chlorine, Cl-35 gives rise to Cl-36 as an activation product – a long-lived energetic beta source, so Cl-37 is much preferable in a reactor.

All low-pressure liquid coolants allow all their heat to be delivered at high temperatures, since the temperature drop in heat exchangers is less than with gas coolants. Also, with a good margin between operating and boiling temperatures, passive cooling for decay heat is readily achieved. Since heat exchangers do leak to some small extent, having incompatible primary and secondary coolants can be a problem. The less pressure difference across the heat exchanger, the less is the problem.

The removal of passive decay heat is a vital feature of primary cooling systems, beyond heat transfer to do work. When the fission process stops, fission product decay continues and a substantial amount of heat is added to the core. At the moment of shutdown, this is about 6.5% of the full power level, but after an hour it drops to about 1.5% as the short-lived fission products decay. After a day, the decay heat falls to 0.4%, and after a week it will be only 0.2%. This heat could melt the core of a light water reactor unless it is reliably dissipated, as shown in 2011 at Fukushima, where about 1.5% of the heat was being generated when the tsunami disabled the cooling. In passive systems, some kind of convection flow is relied upon.

Primary Coolant Heat Transfer

The top AHTR/FHR line is potential, lower one practical today. See also paper on Cooling Power Plants.

There is some radioactivity in the cooling water flowing through the core of a water-cooled reactor, due mainly to the activation product nitrogen-16, formed by neutron capture from oxygen. N-16 has a half-life on only 7 seconds but produces high-energy gamma radiation during decay. It is the reason that access to a BWR turbine hall is restricted during actual operation.

Nuclear reactors for process heat

Producing steam to drive a turbine and generator is relatively easy, and a light water reactor running at 350°C does this readily. As the above section and Figure show, other types of reactor are required for higher temperatures. A 2010 US Department of Energy document quotes 500°C for a liquid metal cooled reactor (FNR), 860°C for a molten salt reactor (MSR), and 950°C for a high temperature gas-cooled reactor (HTR). Lower-temperature reactors can be used with supplemental gas heating to reach higher temperatures, though employing an LWR would not be practical or economic. The DOE said that high reactor outlet temperatures in the range 750 to 950°C were required to satisfy all end user requirements evaluated to date for the Next Generation Nuclear Plant.

Primitive reactors

The world's oldest known nuclear reactors operated at what is now Oklo in Gabon, West Africa. About 2 billion years ago, at least 17 natural nuclear reactors achieved criticality in a rich deposit of uranium ore. Each operated intermittently at about 20 kW thermal, the reaction ceasing whenever the water turned to steam so that it ceased to function as moderator. At that time the concentration of U-235 in all natural uranium was about three percent instead of 0.7 percent as at present. (U-235 decays much faster than U-238, whose half-life is about the same as the age of the Earth.) These natural chain reactions, started spontaneously with the presence of water acting as a moderator, continued overall for about 2 million years before finally dying away. It appears that each reactor operated in pulses of about 30 minutes – interrupted when the water turned to steam, thereby switching it off for a few hours until it cooled. It is estimated that about 130 TWh of heat was produced. (The reactors were discovered when assays of mined uranium showed only 0.717% U-235 instead of 0.720% as everywhere else on the planet. Further investigation identified significant concentrations of fission products from both uranium and plutonium.)

During this long reaction period about 5.4 tonnes of fission products as well as up to two tonnes of plutonium together with other transuranic elements were generated in the orebody. The initial radioactive products have long since decayed into stable elements but close study of the amount and location of these has shown that there was little movement of radioactive wastes during and after the nuclear reactions. Plutonium and the other transuranics remained immobile.

 


 

 
  • Nuclear power is cost competitive with other forms of electricity generation, except where there is direct access to low-cost fossil fuels.
  • Fuel costs for nuclear plants are a minor proportion of total generating costs, though capital costs are greater than those for coal-fired plants and much greater than those for gas-fired plants.
  • Providing incentives for long-term, high-capital investment in deregulated markets driven by short-term price signals presents a challenge in securing a diversified and reliable electricity supply system.
  • In assessing the economics of nuclear power, decommissioning and waste disposal costs are fully taken into account.
  • Nuclear power plant construction is typical of large infrastructure projects around the world, whose costs and delivery challenges tend to be under-estimated.

Assessing the relative costs of new generating plants utilising different technologies is a complex matter and the results depend crucially on location. Coal is, and will probably remain, economically attractive in countries such as China, the USA and Australia with abundant and accessible domestic coal resources as long as carbon emissions are cost-free. Gas is also competitive for base-load power in many places, particularly using combined-cycle plants.

Nuclear power plants are expensive to build but relatively cheap to run. In many places, nuclear energy is competitive with fossil fuels as a means of electricity generation. Waste disposal and decommissioning costs are included in the operating costs. If the social, health and environmental costs of fossil fuels are also taken into account, the economics of nuclear power are outstanding.

On a levelised (i.e. lifetime) basis, nuclear power is an economic source of electricity generation, combining the advantages of security, reliability, very low greenhouse gas emissions and cost competitiveness in many markets. Existing plants function well with a high degree of predictability. The operating cost of these plants is lower than almost all fossil fuel competitors, with a very low risk of operating cost inflation. Plants are now expected to operate for 60 years and even longer in the future. The main economic risks to existing plants lie in the impacts of subsidised intermittent renewable and low-cost gas-fired generation. The political risk of higher, specifically-nuclear, taxation adds to these risks.

Assessing the costs of nuclear power

The economics of nuclear power involves consideration of several aspects:

Capital costs, which include the cost of site preparation, construction, manufacture, commissioning and financing a nuclear power plant. Building a large-scale nuclear reactor takes thousands of workers, huge amounts of steel and concrete, thousands of components, and several systems to provide electricity, cooling, ventilation, information, control and communication. To compare different power generation technologies the capital costs must be expressed in terms of the generating capacity of the plant (for example as dollars per kilowatt). Capital costs may be calculated with the financing costs included or excluded. If financing costs are included then the capital costs change in proportion to the length of time it takes to build and commission the plant and with the interest rate or mode of financing employed. It is normally termed the ‘investment cost’. If the financing costs are excluded from the calculation the capital costs is called the ‘overnight cost’, because it imagines that the plant appeared fully built overnight.

Plant operating costs, which include the costs of fuel, operation and maintenance (O&M), and a provision for funding the costs of decommissioning the plant and treating and disposing of used fuel and wastes. Operating costs may be divided into ‘fixed costs’ that are incurred whether or not the plant is generating electricity and ‘variable costs’, which vary in relation to the output. Normally these costs are expressed relative to a unit of electricity (for example, cents per kilowatt-hour) to allow a consistent comparison with other energy technologies. To calculate the operating cost of a plant over its whole life (including the costs of decommissioning and used fuel and waste management), we must estimate the ‘levelised’ cost at present value. It represents the price that the electricity must fetch if the project is to break even (after taking account of the opportunity cost of capital through the application of a discount rate).

External costs to society from the operation, which in the case of a nuclear power is usually assumed to be zero, but could include the costs of dealing with a serious accident that are beyond the insurance limit and in practice need to be picked up by the government. The regulations that control nuclear power typically require the plant operator to make a provision for disposing of any waste, thus these costs are ‘internalised’ (and are not external). Electricity generation from fossil fuels is not regulated in the same way, and therefore the operators of such thermal power plants do not yet internalise the costs of greenhouse gas emission or of other gases and particulates released into the atmosphere. Including these external costs in the calculation gives nuclear power a significant advantage over fossil fuelled electricity generation.

Considering these costs in turn, with information from numerous studies:

Capital cost

Construction costs comprise several things: the bare plant cost (usually identified as engineering-procurement-construction – EPC – cost), the owner's costs (land, cooling infrastructure, administration and associated buildings, site works, switchyards, project management, licences, etc.), cost escalation and inflation. Owner's costs may include some transmission infrastructure. Recent studies have shown an increase in the capital cost of building both conventional and nuclear power plants.

The term 'overnight capital cost' is often used, meaning EPC plus owners’ costs and excluding financing, escalation due to increased material and labour costs, and inflation. Construction cost – sometimes called 'all-in cost' – adds to overnight cost any escalation and interest during construction and up to the start of construction. It is expressed in the same units as overnight cost and is useful for identifying the total cost of construction and for determining the effects of construction delays. In general the construction costs of nuclear power plants are significantly higher than for coal- or gas-fired plants because of the need to use special materials, and to incorporate sophisticated safety features and back-up control equipment. These contribute much of the nuclear generation cost, but once the plant is built the cost variables are minor. About 80% of overnight costs are EPC costs, with about 70% of these consisting of direct (physical plant equipment with labour and materials to assemble them) and 30% indirect (supervisory engineering and support labour costs with some materials) costs. The remaining 20% of overnight costs are contingencies and owners’ costs (essentially the cost of testing systems and training staff).

The OECD Nuclear Energy Agency’s (NEA) calculation of the overnight cost for a nuclear power plant built in the OECD rose from about $1,900/kWe at the end of the 1990s to $3,850/kWe in 2009. In the 2015 edition of its report on Projected Costs of Generating Electricity, the overnight costs in OECD countries ranged from $2021/kWe in Korea to $6215/kWe in Hungary. For China, two comparable figures were $1807/kWe and $2615/kWe.

The NEA figures for the 1990s must be treated with caution as they are not in line with some other data sources. The US Energy Information Administration (EIA) calculated that, in constant 2002 values, the realized real overnight cost of a nuclear power plant built in the USA grew from US$ 1,500/kWe in the early 1960s to US$ 4,000/kWe in the mid-1970s. The EIA cited increased regulatory requirements (including design changes that required plants to be back-fitted with modified equipment), licensing problems, project management problems and mis-estimation of costs and demand as the factors contributing to the increase during the 1970s. Its 2010 reportUpdated Capital Cost Estimates for Electricity Generation Plants, gave an estimate for a new nuclear plant of US$ 5,339/kW.

There is also significant variation of capital costs by country, particularly between the emerging industrial economies of East Asia and the mature markets of Europe and North America, which has a variety of explanations, including differential labour costs, more experience in the recent building of reactors, economies of scale from building multiple units and streamlined licensing and project management within large civil engineering projects. With few new orders, the data set for new build costs is lacking. The shift to Generation III reactors has added further uncertainty. Other non-nuclear generation technologies also show variation and as do major infrastructure projects such as roads and bridges, depending upon where they are built. However, the variation is particularly crucial for electricity generation as its economics depend so much on minimising its capital investment cost which must be passed onto consumers, unlike roads, bridges and dams which usually have less complexity. Large infrastructure projects of all kinds tend to be over-budget and late in most parts of the world according to research by the University of Lincoln (UK) and the Megaproject database.

The French national audit body, the Cour des comptes, said in 2012 that the overnight capital costs of building NPPs increased over time from € 1,070/kWe (at 2010 prices) when the first of the 50 PWRs was built at Fessenheim (commissioned in 1978) to € 2,060/kWe when Chooz 1 and 2 were built in 2000, and to a projected € 3,700/kWe for the Flamanville EPR. It can be argued that much of this escalation relates to the smaller magnitude of the programme by 2000 (compared with when the French were commissioning 4-6 new PWRs per year in the 1980s) and to the subsequent loss of economies of scale.

In several countries, notably the UK, there is a trend to greater vendor involvement in financing projects, but with an intention to relinquish equity once the plant is running.

A presentation by Dr. N. Barkatullah, UAE Regulation & Supervision Bureau, at the World Nuclear Association 2014 Symposium showed the risk in construction costs (per kilowatt of capacity), much of it due to financing cost incurred by delays:

Challenge: Construction Risk

The same presentation showed the following ranges of figures for overnight capital cost in different parts of the world:

Challenge: NPP investment cost uncertainty

The IEA-NEA Nuclear Energy Roadmap 2015 estimates China’s average overnight costs of approximately USD 3,500/kW are more than a third less than that in the EU of USD 5,500/kW. Costs in the US are about 10% lower than the EU, but still 30% higher than in China and India, and 25% above South Korea. In its main scenario, 2050 assumptions for overnight costs of nuclear in the United States and European Union are estimated to decline somewhat, reaching levels closer to those in the Republic of Korea, while costs in Asia are assumed to remain flat.

In China it is estimated that building two identical 1000 MWe reactors on a site can result in a 15% reduction in the cost per kW compared with that of a single reactor.

Financing costs will depend on the rate of interest on debt, the debt-equity ratio, and if it is regulated, how the capital costs are recovered. There must also be an allowance for a rate of return on equity, which is risk capital.

Long construction periods will push up financing costs, and in the past they have done so spectacularly. In Asia construction times have tended to be shorter, for instance the new-generation 1300 MWe Japanese reactors which began operating in 1996 and 1997 were built in a little over four years, and 48 to 54 months is typical projection for plants today. The last three South Korean reactors not delayed by cabling replacement averaged 51 months construction time. See also Construction Risk graphic above.

An insight on the relationship among ingredients of capital cost was provided by testimony to a Georgia Public Service Commission hearing concerning the Vogtle 3&4 project in June 2014. Here, for Georgia Power‘s 45.7% share, EPC cost was $3.8 billion, owners cost $0.6 billion, and financing cost $1.7 billion if completed 2016-17. The cost of possible delayed completion was put at $1.2 million per day. This puts the total cost of the project at about $14 billion.

The conclusion of a study published in 2016 on the Historical construction costs of global nuclear power reactors,* presented a new data set for overnight nuclear construction costs across seven countries. Some conclusions emerged that are in contrast to the past literature. While several countries, notably the USA, show increasing costs over time, other countries show more stable costs in the longer term, and cost declines over specific periods in their technological history. One country, South Korea, experiences sustained construction cost reductions throughout its nuclear power experience. The variations in trends show that the pioneering experiences of the USA or even France are not necessarily the best or most relevant examples of nuclear cost history. These results showed that there is no single or intrinsic learning rate expected for nuclear power technology, nor any expected cost trend. How costs evolve over time appears to be dependent on several different factors. The large variation in cost trends over time and across different countries – even with similar nuclear reactor technologies – suggests that cost drivers other than learning-by-doing have dominated the experience of nuclear power construction and its costs. Factors such as utility structure, reactor size, regulatory regime, and international collaboration may have a larger effect. Therefore, drawing any strong conclusions about future nuclear power costs based on one country's experience – especially the US experience in the 1970s and 1980s – would be ill-advised.

* Lovering, J.R., Yip, A, Nordhaus, Ted, in Energy Policy 91, 371-382 (April 2016)

Operating costs

Fuel costs have from the outset given nuclear energy an advantage compared with coal, oil and gas-fired plants. Uranium, however, has to be processed, enriched and fabricated into fuel elements, and about half of the cost is due to enrichment and fabrication. In the assessment of the economics of nuclear power allowances must also be made for the management of radioactive used fuel and the ultimate disposal of this used fuel or the wastes separated from it. But even with these included, the total fuel costs of a nuclear power plant in the OECD are typically about a third of those for a coal-fired plant and between a quarter and a fifth of those for a gas combined-cycle plant. The US Nuclear Energy Institute suggests that for a coal-fired plant 78% of the cost is the fuel, for a gas-fired plant the figure is 89%, and for nuclear the uranium is about 14%, or double that to include all front end costs.

In July 2015, the approx. US $ cost to get 1 kg of uranium as UO2 reactor fuel (at current long-term uranium price):

Uranium: 8.9 kg U3O8 x $97 US$ 862 46%
Conversion: 7.5 kg U x $16 US$ 120 6%
Enrichment: 7.3 SWU x $82 US$ 599 32%
Fuel fabrication: per kg (approx) US$ 300 16%
Total, approx:   US$ 1880  

At 45,000 MWd/t burn-up this gives 360,000 kWh electrical per kg, hence fuel cost: 0.52 ¢/kWh.

Fuel costs are one area of steadily increasing efficiency and cost reduction. For instance, in Spain the nuclear electricity cost was reduced by 29% over 1995-2001. This involved boosting enrichment levels and burn-up to achieve 40% fuel cost reduction. Prospectively, a further 8% increase in burn-up will give another 5% reduction in fuel cost.

Uranium has the advantage of being a highly concentrated source of energy which is easily and cheaply transportable. The quantities needed are very much less than for coal or oil. One kilogram of natural uranium will yield about 20,000 times as much energy as the same amount of coal. It is therefore intrinsically a very portable and tradable commodity.

The contribution of fuel to the overall cost of the electricity produced is relatively small, so even a large fuel price escalation will have relatively little effect (see below). Uranium is abundant and widely available.

There are other possible savings. For example, if used fuel is reprocessed and the recovered plutonium and uranium is used in mixed oxide (MOX) fuel, more energy can be extracted. The costs of achieving this are large, but are offset by MOX fuel not needing enrichment and particularly by the smaller amount of high-level wastes produced at the end. Seven UO2 fuel assemblies give rise to one MOX assembly plus some vitrified high-level waste, resulting in only about 35% of the volume, mass and cost of disposal.

Operating costs include operating and maintenance (O&M) plus fuel. Fuel cost figures include used fuel management and final waste disposal. These costs, while usually external for other technologies, are internal for nuclear power (i.e. they have to be paid or set aside securely by the utility generating the power, and the cost passed on to the customer in the actual tariff).

This 'back end' of the fuel cycle, including used fuel storage or disposal in a waste repository, contributes up to 10% of the overall costs per kWh – rather less if there is direct disposal of used fuel rather than reprocessing. The $26 billion US used fuel program is funded by a 0.1 cent/kWh levy.

Decommissioning costs are about 9-15% of the initial capital cost of a nuclear power plant. But when discounted, they contribute only a few percent to the investment cost and even less to the generation cost. In the USA they account for 0.1-0.2 cent/kWh, which is no more than 5% of the cost of the electricity produced.

System costs

System costs are the total costs above plant-level costs (capital and operating) to supply electricity at a given load and given level of security of supply. They include grid connection, extension and reinforcement, short-term balancing costs and long-term costs of maintaining adequate back-up.

They are external to the building and operation of any power plant, but must be paid by the electricity consumer, usually as part of the transmission and distribution cost. From a government policy point of view they are just as significant as the actual generation cost, but are seldom factored in to comparisons among different supply options, especially comparing base-load with dispersed variable renewables. In fact that the total system cost should be analysed when introducing new power generating capacity on the grid. Any new power plant likely requires changes to the grid, and hence incurs a significant cost for power supply that must be accounted for. But this cost for large base-load plants is small compared with integrating variable renewables to the grid.

The integration of intermittent renewable supply on a preferential basis despite higher unit cost creates significant diseconomies for dispatchable supply, as is now becoming evident in Germany, Austria and Spain, compromising security of supply and escalating costs. At 40% share of electricity being from renewables, the capital cost component of power from conventional thermal generation sources increases substantially as their capacity factor decreases – the utilisation effect. This has devastated the economics of some gas-fired plants in Germany, for instance.

The overall cost competitiveness of nuclear, as measured on a levelised basis (see figures below on comparison of LCOE and system costs), is much enhanced by its modest system costs. However, the impact of intermittent electricity supply on wholesale markets has a profound effect on the economics of base-load generators, including nuclear, that is not captured in the levelised cost comparisons given by the IEA/NEA reports. The negligible marginal operating costs of wind and solar means that, when climatic conditions allow generation from these sources, they undercut all other electricity producers. At high levels of renewable generation, e.g. as implied by the EU’s 30% renewable penetration target, the nuclear load factor is reduced and the volatility of wholesale prices greatly increased whilst the average wholesale price level falls. The increased penetration of intermittent renewables thereby greatly reduces the financial viability of nuclear generation in wholesale markets where intermittent renewable energy capacity is significant. The integration of intermittent renewables with conventional base-load generation is a major challenge facing policymakers in the EU and certain states in the USA, and until this challenge is resolved, e.g. by the introduction of long-term capacity markets or power purchase agreements, then investment in base-load generation capacity in these markets is likely to remain insufficient.

An OECD study found that the integration of large shares of intermittent renewable electricity is a major challenge for the electricity systems of OECD countries and for dispatchable generators such as nuclear. Grid-level system costs for variable renewables are large ($15-80/MWh) but depend on country, context and technology (onshore wind < offshore wind < Solar PV). Nuclear system cost is $1-3/MWh.

See also paper on Electricity Transmission Grids

External costs

External costs are not included in the building and operation of any power plant, and are not paid by the electricity consumer, but by the community generally. The external costs are defined as those actually incurred in relation to health and the environment, and which are quantifiable but not built into the cost of the electricity.

The report of a major European study of the external costs of various fuel cycles, focusing on coal and nuclear, was released in mid 2001 – ExternE. It shows that in clear cash terms nuclear energy incurs about one-tenth of the costs of coal. If these costs were in fact included, the EU price of electricity from coal would double and that from gas would increase 30%. These are without attempting to include the external costs of global warming.

The European Commission launched the project in 1991 in collaboration with the US Department of Energy, and it was the first research project of its kind "to put plausible financial figures against damage resulting from different forms of electricity production for the entire EU". The methodology considers emissions, dispersion and ultimate impact. With nuclear energy the risk of accidents is factored in along with high estimates of radiological impacts from mine tailings (waste management and decommissioning being already within the cost to the consumer). Nuclear energy averages 0.4 euro cents/kWh, much the same as hydro, coal is over 4.0 cents (4.1-7.3), gas ranges 1.3-2.3 cents and only wind shows up better than nuclear, at 0.1-0.2 cents/kWh average. NB these are the external costs only.

A further study commissioned by the European Commission in 2014 and carried out by the Ecofys consultancy calculated external costs for nuclear as €18-22/MWh, including about €5/MWh for health impacts, €4/MWh for accidents and €12/MWh for so-called ‘resource depletion’, relating to the “costs to society of consumption of finite fuel resources now, rather than in the future.” Although Ecofys acknowledged that the resource depletion cost is difficult to calculate since the scarcity of a finite natural resource is already reflected in its market price, and could therefore just as well be zero, a high estimate was asserted using questionable methodology and without taking account of the potential for recycling nuclear fuel.

Another report for the European Commission made by Professor William D’haeseleer, University of Leuven, in November 2013, estimated the cost of a potential nuclear accidents to be in a range of €0.3-3/MWh.

Tax costs

In several EU countries, nuclear power generation is specifically taxed without environmental justification. In 2012 Belgium raised some €479 million from a €0.005/kWh tax, in France €350 million from a tax on nuclear plants, in Germany €1400 million from a fuel tax, in Sweden €424 million from a nuclear tax of €0.0067/kWh, and in the UK €427 million from €0.0061/kWh climate change levy. The total was about €3 billion per year.

See also paper on Energy subsidies and external costs.

Comparing the economics of different forms of electricity generation

In 2013 the US Energy Information Administration published figures for the average levelized costs per unit of output for generating technologies to be brought on line in 2018, as modeled for its Annual Energy Outlook. These show advanced nuclear, natural gas (advanced combustion turbine), and conventional coal in the bracket 10-11c/kWh. Combined cycle natural gas is 6.6 cents, advanced coal with CCS 13.6 cents, and among the non-dispatchable technologies: wind onshore 8.7 cents, solar PV 14.4 cents, offshore wind 22.2 cents and solar thermal 26.2 c/kWh. The actual capital cost of nuclear is about the same as coal, and very much more than any gas option.

The 2015 edition of the OECD study on Projected Costs of Generating Electricity showed that the range for levelised cost of electricity (LCOE) varied much more for nuclear than coal or CCGT with different discount rates, due to it being capital-intensive. The nuclear LCOE is largely driven by capital costs. At 3% discount rate, nuclear was substantially cheaper than the alternatives in all countries, at 7% it was comparable with coal and still cheaper than gas, at 10% it was comparable with both. At low discount rates it was much cheaper than wind and PV. Based on a 0% discount rate, LCOE for nuclear soared to three times as much as the 10% discount rate, while that for coal was 1.4 times and for CCGT it changed very little. Solar PV increased 2.25 times and onshore wind nearly twice at 10% discount rate, albeit with very different capacity factors to the 85% for the three base-load options. For all technologies, a $30 per tonne carbon price was included. LCOE figures omit system costs.

Comparative LCOEs and System Costs in Four Countries (2014 and 2012)

* LCOE plant costs have been taken from Projected Costs of Generating Electricity 2015 Edition. System costs have been taken fromNuclear Energy and Renewables (NEA, 2012). A 30% generation penetration level for onshore wind, offshore wind and solar PV has been assumed in the NEA estimates of system costs, which include back-up costs, balancing costs, grid connection, extension and reinforcement costs. A discount rate of 7% is used throughout, which is therefore consistent with the plant level LCOE estimates given in the 2015 edition of Projected Costs of Generating Electricity. The 2015 study applies a $30/t CO2 price on fossil fuel use and uses 2013 US$ values and exchange rates.

Projected nuclear LCOE costs for plants built 2015-2020, $/MWh

Country At 3% discount rate At 7% discount rate At 10% discount rate
Belgium 51.5 84.2 116.8
Finland 46.1 77.6 109.1
France 50.0 82.6 115.2
Hungary 53.9 89.9 125.0
Japan 62.6 87.6 112.5
South Korea 28.6 40.4 51.4
Slovakia 53.9 84.0 116.5
UK 64.4 100.8 135.7
USA 54.3 77.7 101.8
China 25.6-30.8 37.2-47.6 48.8-64.4

Source: OECD/IEA-NEA, Projected Costs of Generating Electricity, 2015 Edition, Table 3.11, assuming 85% capacity factor

Overnight capital costs for nuclear technologies in OECD countries ranged from $2021 per kWe of capacity (in South Korea) to $6125 per kWe (in Hungary) in the 2015 report.

Rosatom claimed in November 2015 that due to its integrated structure, the LCOE of new VVER reactors exported is no more than $50-$60 per MWh in most countries.

The 2010 edition of the report had noted a significant increase in costs of building base-load plants over the previous five years. The 2015 report shows that this increase has stopped, and that this is particularly significant for nuclear technologies, "undermining the growing narrative that nuclear costs continue to increase globally."

The 2010 edition of Projected Costs of Generating Electricity set out some actual costs of electricity generation, showing nuclear as very competitive at 5% discount rate, especially if CCS was added to fossil fuel sources, but much less so at 10% (details in section below on Major studies on future cost competitiveness).

It is important to distinguish between the economics of nuclear plants already in operation and those at the planning stage. Once capital investment costs are effectively “sunk”, existing plants operate at very low costs and are effectively “cash machines”. Their operations and maintenance (O&M) and fuel costs (including used fuel management) are, along with hydropower plants, at the low end of the spectrum and make them very suitable as base-load power suppliers. This is irrespective of whether the investment costs are amortized or depreciated in corporate financial accounts – assuming the forward or marginal costs of operation are below the power price, the plant will operate.

US figures for 2012 published by NEI show the general picture, with nuclear generating power at 2.40 c/kWh, compared with coal at 3.27 cents and gas at 3.40 cents.

 

U.S. Electricity Production Costs, 1995-2012 line graph

Note: the above data refer to fuel plus operation and maintenance costs only, they exclude capital, since this varies greatly among utilities and states, as well as with the age of the plant.

A Finnish study in 2000 also quantified fuel price sensitivity to electricity costs:
 

The Impact of Fuel Costs on Electricity Generation Costs line graph

These show that a doubling of fuel prices would result in the electricity cost for nuclear rising about 9%, for coal rising 31% and for gas 66%. Gas prices have since risen significantly.

The impact of varying the uranium price in isolation is shown below in a worked example of a typical US plant, assuming no alteration in the tails assay at the enrichment plant.

Effect of Uranium Price on Fuel Cost line graph

Doubling the uranium price (say from $25 to $50 per lb U3O8) takes the fuel cost up from 0.50 to 0.62 US cents per kWh, an increase of one quarter, and the expected cost of generation of the best US plants from 1.3 US cents per kWh to 1.42 cents per kWh (an increase of almost 10%). So while there is some impact, it is comparatively minor, especially by comparison with the impact of gas prices on the economics of gas generating plants. In these, 90% of the marginal costs can be fuel. Only if uranium prices rise to above $100 per lb U3O8 ($260 /kgU) and stay there for a prolonged period (which seems very unlikely) will the impact on nuclear generating costs be considerable.

Nevertheless, for nuclear power plants operating in competitive power markets where it is impossible to pass on any fuel price increases (ie the utility is a price-taker), higher uranium prices will cut corporate profitability. Yet fuel costs have been relatively stable over time – the rise in the world uranium price between 2003 and 2007 added to generation costs, but conversion, enrichment and fuel fabrication costs did not followed the same trend.

In February 2014 the US Nuclear Energy Institute presented figures from the Electric Utility Cost Group on US generating costs comprising fuel, capital and operating costs for 61 nuclear sites in 2012. The average came to $44/MWh, being $50.54 for single-unit plants and $39.44 for multi-unit plants (all two-unit except Browns Ferry, Oconee and Palo Verde). The $44 represented a 58% increase in ten years, largely due to a threefold increase in capital expenditure on plants which were mostly old enough to be fully depreciated. Over half of the capital expenditure (51%) in 2012 related to power uprates and licence renewals, while 26% was for equipment replacement.

For prospective new nuclear plants, the fuel component is even less significant (see below). The typical front end nuclear fuel cost is typically only 15-20% of the total, as opposed to 30-40% for operating nuclear plants.

Competitiveness in the context of increasing use of power from renewable sources, which are legally preferred, is a major issue today. The most important renewable sources are intermittent by nature, which means that their supply to the electricity system does not necessarily match demand from customers. In power grids where renewable sources of generation make a significant contribution, intermittency forces other generating sources to ramp up their supply or power down at short notice. This volatility can have a large impact on non-intermittent generators’ profitability.A variety of responses to the challenge of intermittent generation are possible. Two options currently being implemented are increased conventional plant flexibility and increased grid capacity and coverage. Flexibility is seen as most applicable to gas and coal fired generators, but nuclear reactors, normally regarded as base-load producers, also have the ability to load-follow, eg, by the use of ‘grey rods’ to modulate the reaction speed.

As the scale of intermittent generating capacity increases however, more significant measures will be required. The establishment and extension of capacity mechanisms, which offer payments to generators prepared to guarantee supply for defined periods, are now under serious consideration within the EU. Capacity mechanisms can in theory provide security of supply to desired levels but at a price which might be high, for example, Morgan Stanley has estimated that investors in a 800 MWe gas plant providing for intermittent generation would require payments of €80 million per year whilst Ecofys calculate that a 4 GWe reserve in Germany would cost €140-240/year. Almost by definition, investors in conventional plant designed to operate intermittently will face low and uncertain load factors and will therefore demand significant capacity payments in return for the investment decision. In practice, until the capacity mechanism has been reliably implemented, investors are likely to withhold investment. Challenges for EU power market integration are expected to result from differences between member state capacity mechanisms.

The 2014 Ecofys report for the European Commission on Subsidies and Costs of EU Energy purported to present a complete and consistent set of data on electricity generation and system costs, as well as external costs and interventions by governments to reduce costs to consumers. The report attributed €6.96 billion to nuclear power in the EU in 2012, including €4.33 billion decommissioning costs (shortfall from those already internalised). Geographically the total broke down to include EU support of €3.26 billion, and UK €2.77 billion, which was acknowledged as including military legacy clean-up. Consequently there are serious questions about the credibility of such figures.

Economic implications of particular plants

Apart from considerations of cost of electricity and the perspective of an investor or operator, there are studies on the economics of particular generating plants in their local context.

Early in 2015 a study, Economic Impacts of the R.E. Ginna Nuclear Power Plant, was prepared by the US Nuclear Energy Institute. It analyzes the impact of the 580 MWe PWR plant’s operations through the end of its 60-year operating licence in 2029. It generates an average annual economic output of over $350 million in western New York state and an impact on the U.S. economy of about $450 million per year. Ginna employs about 700 people directly, adding another 800 to 1,000 periodic jobs during reactor refueling and maintenance outages every 18 months. Annual payroll is about $100 million. Secondary employment involves another 800 jobs. Ginna is the largest taxpayer in the county. Operating at more than 95% capacity factor, it is a very reliable source of low-cost electricity. Its premature closure would be extremely costly to both state and country – far in excess of the above figures.

In June 2015 a study, Economic Impacts of the Indian Point Energy Center, was published by the US Nuclear Energy Institute, analyzing the economic benefits of Entergy’s Indian Point 2&3 reactors in New York state (1020 and 1041 MWe net). It showed that they annually generate an estimated $1.6 billion in the state and $2.5 billion across the nation as a whole. This includes about $1.3 billion per year in the local counties around the plant. The facility contributes about $30 million in state and local property taxes and has an annual payroll of about $140 million for the plant’s nearly 1,000 employees. The total tax benefit to the local, state and federal governments from the plant is about $340 million per year, and the plant’s direct employees support another 5,400 indirect jobs in New York state and 5,300 outside it. It also makes a major contribution to grid reliability and prevents the release of 8.5 million tonnes of CO2 per year.

In September 2015 a Brattle Group report said that the five nuclear facilities in Pennsylvania contribute $2.36 billion annually to the state's gross domestic product and account for 15,600 direct and secondary full-time jobs.

Future cost competitiveness

Understanding the cost of new generating capacity and its output requires careful analysis of what is in any set of figures. There are three broad components: capital, finance and operating costs. Capital and financing costs make up the project cost.

Calculations of relative generating costs are made using levelised costs, meaning average costs of producing electricity including capital, finance, owner's costs on site, fuel and operation over a plant's lifetime, with provision for decommissioning and waste disposal.

It is important to note that capital cost figures quoted by reactor vendors, or which are general and not site-specific, will usually just be for EPC costs. This is because owner's costs will vary hugely, most of all according to whether a plant is Greenfield or at an established site, perhaps replacing an old plant.

There are several possible sources of variation which preclude confident comparison of overnight or EPC (Engineering, Procurement & Construction) capital costs – eg whether initial core load of fuel is included. Much more obvious is whether the price is for the nuclear island alone (Nuclear Steam Supply System) or the whole plant including turbines and generators – all the above figures include these. Further differences relate to site works such as cooling towers as well as land and permitting – usually they are all owner's costs as outlined earlier in this section. Financing costs are additional, adding typically around 30%, and finally there is the question of whether cost figures are in current (or specified year) dollar values or in those of the year in which spending occurs.

The 2015 edition of the OECD study on Projected Costs of Generating Electricity considered the cost and deployment perspectives for small modular reactors (SMRs) and Generation IV reactor designs – including very high temperature reactors and fast reactors – that could start being deployed by 2030. Although it found that the specific per-kWe costs of SMRs are likely to be 50% to 100% higher than those for large Generation III reactors, these could be offset by potential economies of volume from the manufacture of a large number of identical SMRs, plus lower overall investment costs and shorter construction times that would lower the capital costs of such plants. "SMRs are expected at best to be on a par with large nuclear if all the competitive advantages … are realised," the report noted.

Major studies on future cost competitiveness

There have been many studies carried out examining the economics of future generation options, and the following are merely the most important and also focus on the nuclear element.

A May 2016 draft declaration related to the European Commission's Strategic Energy Technology Plan lists target LCOE figures for the latest generation of light-water reactors (LWRs) 'first-of-a-kind' new-build twin reactor project on a brownfield site as €48/MWh to €84/MWh, falling to €43/MWh to €75/MWh for a series build (5% and 10% discount rate, in 2012€). The LCOE figures for existing Generation II nuclear power plants integrating post-Fukushima stress tests safety upgrades following refurbishment for extended operation (10-20 years on average) are €23/MWh to €26/MWh (5% and 10% discount rate, in 2012€).

The 2010 edition of the OECD study on Projected Costs of generating Electricity compared 2009 data for generating base-load electricity by 2015 as well as costs of power from renewables, and showed that nuclear power was very competitive at $30 per tonne CO2 cost and low discount rate. The study comprised data for 190 power plants from 17 OECD countries as well as some data from Brazil, China, Russia and South Africa. It used levelised lifetime costs with carbon price internalised (OECD only) and discounted cash flow at 5% and 10%, as previously. The precise competitiveness of different base-load technologies depended very much on local circumstances and the costs of financing and fuels.

Nuclear overnight capital costs in OECD ranged from US$ 1556/kW for APR-1400 in South Korea through $3009 for ABWR in Japan, $3382/kW for Gen III+ in USA, $3860 for EPR at Flamanville in France to $5863/kW for EPR in Switzerland, with world median $4100/kW. Belgium, Netherlands, Czech Rep and Hungary were all over $5000/kW. In China overnight costs were $1748/kW for CPR-1000 and $2302/kW for AP1000, and in Russia $2933/kW for VVER-1150. EPRI (USA) gave $2970/kW for APWR or ABWR, Eurelectric gave $4724/kW for EPR. OECD black coal plants were costed at $807-2719/kW, those with carbon capture and compression (tabulated as CCS, but the cost not including storage) at $3223-5811/kW, brown coal $1802-3485, gas plants $635-1747/kW and onshore wind capacity $1821-3716/kW. (Overnight costs were defined here as EPC, owner's costs and contingency, but excluding interest during construction.)

OECD electricity generating cost projections for year 2010 on – 5% discount rate, c/kWh

country nuclear coal coal with CCS Gas CCGT Onshore wind
Belgium 6.1 8.2 - 9.0 9.6
Czech R 7.0 8.5-9.4 8.8-9.3 9.2 14.6
France 5.6 - - - 9.0
Germany 5.0 7.0-7.9 6.8-8.5 8.5 10.6
Hungary 8.2 - - - -
Japan 5.0 8.8 - 10.5 -
Korea 2.9-3.3 6.6-6.8 - 9.1 -
Netherlands 6.3 8.2 - 7.8 8.6
Slovakia 6.3 12.0 - - -
Switzerland 5.5-7.8 - - 9.4 16.3
USA 4.9 7.2-7.5 6.8 7.7 4.8
China* 3.0-3.6 5.5 - 4.9 5.1-8.9
Russia* 4.3 7.5 8.7 7.1 6.3
EPRI (USA) 4.8 7.2 - 7.9 6.2
Eurelectric 6.0 6.3-7.4 7.5 8.6 11.3

* For China and Russia: 2.5c is added to coal and 1.3c to gas as carbon emission cost to enable sensible comparison with other data in those fuel/technology categories, though within those countries coal and gas will in fact be cheaper than the Table above suggests.
Source: OECD/IEA NEA 2010, table 4.1.

At 5% discount rate comparative costs are as shown above. Nuclear is comfortably cheaper than coal and gas in all countries. At 10% discount rate (below) nuclear is still cheaper than coal in all but the Eurelectric estimate and three EU countries, but in these three gas becomes cheaper still. Coal with carbon capture is mostly more expensive than either nuclear or paying the $30 per tonne for CO2 emissions, though the report points out "great uncertainties" in the cost of projected CCS. Also, investment cost becomes a much greater proportion of power cost than with 5% discount rate.

OECD electricity generating cost projections for year 2010 on – 10% discount rate, c/kWh

country nuclear coal coal with CCS Gas CCGT Onshore wind
Belgium 10.9 10.0 - 9.3-9.9 13.6
Czech R 11.5 11.4-13.3 13.6-14.1 10.4 21.9
France 9.2 - - - 12.2
Germany 8.3 8.7-9.4 9.5-11.0 9.3 14.3
Hungary 12.2 - - - -
Japan 7.6 10.7 - 12.0 -
Korea 4.2-4.8 7.1-7.4 - 9.5 -
Netherlands 10.5 10.0 - 8.2 12.2
Slovakia 9.8 14.2 - - -
Switzerland 9.0-13.6 - - 10.5 23.4
USA 7.7 8.8-9.3 9.4 8.3 7.0
China* 4.4-5.5 5.8 - 5.2 7.2-12.6
Russia* 6.8 9.0 11.8 7.8 9.0
EPRI (USA) 7.3 8.8 - 8.3 9.1
Eurelectric 10.6 8.0-9.0 10.2 9.4 15.5

* For China and Russia: 2.5c is added to coal and 1.3c to gas as carbon emission cost to enable sensible comparison with other data in those fuel/technology categories, though within those countries coal and gas will in fact be cheaper than the Table above suggests.
Source: OECD/IEA NEA 2010, table 4.1.

A 2004 report on The Economic Future of Nuclear Power from from the University of Chicago, funded by the US Department of Energy, compared the levelised power costs of future nuclear, coal, and gas-fired power generation in the USA. Various nuclear options were covered, and for an initial ABWR or AP1000 they ranged from 4.3 to 5.0 c/kWh on the basis of overnight capital costs of $1200 to $1500/kW, 60-year plant life, five-year construction and 90% capacity. Coal gave 3.5-4.1 c/kWh and gas (CCGT) 3.5-4.5 c/kWh, depending greatly on fuel price.

The levelised nuclear power cost figures included up to 29% of the overnight capital cost as interest, and the report noted that up to another 24% of the overnight capital cost needs to be added for the initial unit of a first-of-a-kind advanced design such as the AP1000, defining the high end of the range above. For plants such as the EPR or SWR1000, overnight capital cost of $1800/kW was assumed and power costs were projected beyond the range above. However, considering a series of eight units of the same kind and assuming increased efficiency due to experience which lowers overnight capital cost, the levelised power costs dropped 20% from those quoted above and where first-of-a-kind engineering costs are amortised (e.g. the $1500/kW case above), they dropped 32%, making them competitive at about 3.4 c/kWh.

Nuclear plant: projected electrcity costs (c/kWh)

Overnight capital cost $/kW 1200 1500 1800
First unit 7 yr build, 40 yr life
5.3
6.2
7.1
  5 yr build, 60 yr life
4.3
5.0
5.8
4th unit 7 yr build, 40 yr life
4.5
4.5
5.3
  5 yr build, 60 yr life *
3.7
3.7
4.3
8th unit 7 yr build, 40 yr life
4.2
4.2
4.9
  5 yr build, 60 yr life *
3.4
3.4
4.0

* calculated from above data

The study also showed that with a minimal carbon control cost impact of 1.5 c/kWh for coal and 1.0 c/kWh for gas superimposed on the above figures, nuclear is even more competitive. But more importantly it went on to explore other policy options which would offset investment risks and compensate for first-of-a-kind engineering costs to encourage new nuclear investment, including investment tax breaks, and production tax credits phasing out after 8 years. (US wind energy gets a production tax credit which has risen to 2.1 c/kWh.)

In May 2009 an update of a heavily-referenced 2003 MIT study on The Future of Nuclear Power was published. This said that "since 2003 construction costs for all types of large-scale engineered projects have escalated dramatically. The estimated cost of constructing a nuclear power plant has increased at a rate of 15% per year heading into the current economic downturn. This is based both on the cost of actual builds in Japan and Korea and on the projected cost of new plants planned for in the United States. Capital costs for both coal and natural gas have increased as well, although not by as much. The cost of natural gas and coal that peaked sharply is now receding. Taken together, these escalating costs leave the situation [of relative costs] close to where it was in 2003." The overnight capital cost was given as $4000/kW, in 2007 dollars. Applying the same cost of capital to nuclear as to coal and gas, nuclear came out at 6.6 c/kWh, coal at 8.3 cents and gas at 7.4 cents, assuming a charge of $25/tonne CO2 on the latter.

The French Energy & Climate Directorate published in November 2008 an update of its earlier regular studies on relative electricity generating costs. This shied away from cash figures to a large extent due to rapid changes in both fuel and capital, but showed that at anything over 6000 hours production per year (68% capacity factor), nuclear was cheaper than coal or gas combined cycle (CCG). At 100% capacity CCG was 25% more expensive than nuclear. At less than 4700 hours per year CCG was cheapest, all without taking CO2 cost into account.

With the nuclear plant fixed costs were almost 75% of the total, with CCG they were less than 25% including allowance for CO2 at $20/t. Other assumptions were 8% discount rate, gas at 6.85 $/GJ, coal at EUR 60/t. The reference nuclear unit is the EPR of 1630 MWe net, sited on the coast, assuming all development costs being borne by Flamanville 3, coming on line in 2020 and operating only 40 of its planned 60 years. Capital cost apparently EUR 2000/kW. Capacity factor 91%, fuel enrichment is 5%, burnup 60 GWd/t and used fuel is reprocessed with MOX recycle. In looking at overall fuel cost, uranium at $52/lb made up about 45% of it, and even though 3% discount rate was used for back-end the study confirmed the very low cost of waste in the total - about 13% of fuel cost, mostly for reprocessing.

A detailed study of energy economics in Finland published in mid 2000 was important in making the strong case for additional nuclear construction there, showing that nuclear energy would be the least-cost option for new generating capacity. The study compared nuclear, coal, gas turbine combined cycle and peat. Nuclear had very much higher capital costs than the others – €1749/kW including initial fuel load, which was about three times the cost of the gas plant. But its fuel costs were much lower, and so at capacity factors above 64% it was the cheapest option.

August 2003 figures from Finland put nuclear costs at €2.37 c/kWh, coal 2.81 c/kWh and natural gas at 3.23 c/kWh (on the basis of 91% capacity factor, 5% interest rate, 40-year plant life). With emission trading @ €20/t CO2, the electricity prices for coal and gas increased to 4.43 and 3.92 c/kWh respectively:
 

Projected Electricity Costs for Finland 2003 - cent/kWh stacked column graph


In the middle three bars of this graph the relative effects of capital and fuel costs can be clearly seen. The relatively high capital cost of nuclear power means that financing cost and time taken in construction are critical, relative to gas and even coal. But the fuel cost is very much lower, and so once a plant is built its cost of production is very much more predictable than for gas or even coal. The impact of adding a cost or carbon emissions can also be seen.

In 2013 the Nuclear Energy Institute announced the results of its financial modelling of comparative costs in the USA, based on figures from the US Energy Information Administration’s 2013 Annual Energy Outlook. NEI assumed 5% cost of debt, 15% return on equity and a 70/30 debt equity capital structure. The figures are tabulated below. The report went on to show that with nuclear plant licence renewal beyond 60 years, power costs would be $53-60/MWh.

NEI 2013 Financial Modelling

  EPC cost capacity Electricity cost
Gas combined cycle, gas @ $3.70/GJ $1000/kW 90% $44.00/MWh
Gas combined cycle, gas @ $5.28/GJ $1000/kW 90% $54.70/MWh
Gas combined cycle, gas @ $6.70/GJ $1000/kW 90% $61.70/MWh
Gas combined cycle, gas @ $6.70/GJ, 50-50 debt-equity $1000/kW 90% c $70/MWh
Supercritical pulverised coal, 1300 MWe $3000/kW 85% $75.70/MWh
Integrated gasification combined cycle coal, 1200 MWe $3800/kW 85% $94.30/MWh
Nuclear, 1400 MWe (EIA's EPC figure) $5500/kW 90% $121.90/MWh
Nuclear, 1400 MWe (NEI suggested EPC figure) $4500-5000/kW 90% $85-90/MWh
Wind farm, 100 MWe $1000/kW 30% 112.90/MWh

5% cost of debt, 15% return on equity and a 70-30 debt equity capital structure.

In mid-2015 the NEI published figures from the Institute for Energy Research (IER) report The Levelized Cost of Electricity from Existing Generation Resources, including the finding that nuclear energy had the lowest average costs of electricity for operating facilities. For new plants, it showed nuclear at just over $90/MWh, compared with coal almost $100/MWh and gas just over $70/MWh.

The China Nuclear Energy Association estimated in May 2013 that the construction cost for two AP1000 units at Sanmen are CNY 40.1 billion ($6.54 billion), or 16,000 Yuan/kW installed ($2615/kW) – about 20% higher than that of improved Generation II Chinese reactors, but likely to drop to about CNY 13,000/kW ($2120/kW) with series construction and localisation as envisaged. Grid purchase price is expected to exceed CNY 0.45/kWh at present costs, and drop to 0.42 with reduced capital cost.

A striking indication of the impact of financing costs is given by Georgia Power, which said in mid 2008 that twin 1100 MWe AP1000 reactors would cost $9.6 billion if they could be financed progressively by ratepayers, or $14 billion if not. This gives $4363 or $6360 per kilowatt including all other owners costs.

Finally, in the USA the question of whether a project is subject to regulated cost recovery or is a merchant plant is relevant, since it introduces political, financial and tactical factors. If the new build cost escalates (or is inflated), some cost recovery may be possible through higher rates can be charged by the utility if those costs are deemed prudent by the relevant regulator. By way of contrast, a merchant plant has to sell all its power competitively, so must convince its shareholders that it has a good economic case for moving forward with a new nuclear unit.

Financing new nuclear power plants

There is a range of possibilities for financing, from direct government funding with ongoing ownership, vendor financing (often with government assistance), utility financing and the Finnish Mankala model for cooperative equity. Some of the cost is usually debt financed. The models used will depend on whether the electricity market is regulated or liberalised.

Apart from centrally-planned economies, many projects have some combination of government financial incentives, private equity and long-term power purchase arrangements. The increasing involvement of reactor vendors is a recent development.

Some options are described in the WNA 2012 report on Nuclear Power Economics and Project Structuring.

Providing investment incentives

As more electricity markets become deregulated and competitive, balancing supply and demand over the short-term can result in significant price volatility. Price signals in the spot market for electricity supply do not provide a guide on the return that might be achieved over the long term, and fail to create incentive for long-term investment in generation or transmission infrastructure, nor do they value diversity of supply.

World Nuclear News editorial in February 2015 addressed this issue helpfully.

Deregulated electricity markets with preferential grid access for renewables have left some utilities with stran