June 23, 2015
By: Donald Jones, P.Eng., retired nuclear industry engineer – 2015 June 22
How far can we extend the continuous on-line power operation (breaker-to-breaker runs) of the world’s commercial Generation II and Generation III nuclear power plants. Is 1,000 days possible?
To date the world record for PWR (Pressurized Water Reactor) continuous on-line operation is the 705 day run by Three Mile Island unit 1 an 819 MWe (net) unit in the U.S. that went into commercial operation in 1974 September. The run ended in 2009 October when the unit went into a planned refuelling outage. This run broke the previous world record of 692 days of another PWR, Calvert Cliffs unit 2, an 850 MWe (net) unit in the U.S. that was put into commercial operation in 1977 April. This run ended in 2009 February with a refuelling outage.
LaSalle unit 1, a 1137 MWe (net) unit in the U.S., that was put into commercial operation 1984 January, holds the world record for a BWR (Boiling Water Reactor) with 739 days when it came off-line in 2006 February. As it happens its twin, LaSalle unit 2, became the second place world record holder when it completed a run of 711 days on 2007 February. LaSalle unit 2 went into commercial operation in 1984 October. LaSalle units now hold first and second places in the world for a continuous run of any LWR (Light Water Reactor).
The world record for any type of reactor is held by a CANDU. This is Pickering unit 7, a 516 MWe (net) unit in Ontario, Canada, with a continuous run of 894 days when it came off-line for maintenance in 1994 October. This unit was put into commercial operation in 1985 January. CANDU is a PHWR (Pressurized Heavy Water Reactor). Rajasthan unit 5, a 202 MWe (net) PHWR in India, put into commercial operation in 2010 February, holds second place to Pickering unit 7 in world ranking after completing a 765 day continuous run and going into its planned biennial maintenance outage in 2014 September. Besides these record breaking runs there have been many runs of over 400 days by the different types of reactors.
These long runs are terminated when it is time for the planned maintenance outage and are not extended until safety targets can no longer be met, which would mean shutting down the unit at an inopportune time. The practical limit of continuous operation of PWRs and BWRs is set by the need to replace about a third of the nuclear fuel and do maintenance after about two years (720 days) or less. In the U.S. most light water reactors units operate on a 18 month fuel cycle and have maintenance outages scheduled for the spring and autumn months when electricity demand is low. Since a pressure tube PHWR like CANDU can refuel on-line at power the length of continuous operation is indeterminate but in practice there is a need to come off-line for certain tests, maintenance and inspections and upgrades that cannot be done at power. For a PHWR the run could be terminated by initiating one of the two reactor safety shutdown systems with the other reactor safety shutdown system being tested during the maintenance outage. The Enhanced CANDU 6 (EC6) is designed to operate for about three years (1080 days) before coming off line for a month for maintenance and inspections. Having some testing and maintenance done on-line reduces the inspection load during unit maintenance outage. Read the rest of this entry »
March 29, 2015
By: Donald Jones, P.Eng., retired nuclear industry engineer
Most of India’s nuclear reactors are of the pressurized heavy water reactor (PHWR) type with horizontal pressure tubes, just like the Canadian designed CANDU. In fact the first PHWR in India was the Rajasthan Atomic Power Project (RAPP) unit and was a CANDU designed by Atomic Energy of Canada Limited (AECL) that used the Douglas Point unit in Ontario as reference design but modified to aid localization. RAPP-1 entered commercial operation 1973 December. While RAPP-1 was being constructed the design of RAPP-2 was started (Author’s note: I know because I was part of design team). However the detonation of a nuclear device by India in 1974 curtailed completion of the design by AECL and India was on its own as far as nuclear technology was concerned. The design was completed by India and RAPP-2 eventually entered commercial operation in 1981 April. Since those early days India has developed its own indigenous designs of PHWRs with net electrical outputs of 202 MW, 490 MW, and 630 MW. They bear little to no relation to Douglas Point. All 18 PHWR units operating in 2014 (including RAPP-1 which has been shutdown since 2004) were 202 MW (220 MW gross) except for two 490 MW (540 MW gross) units. There were four 630 MW (700 MW gross) units under construction with none in operation. All nuclear power units, except for RAPP-1, are designed, owned, and operated by Nuclear Power Corporation of India Ltd. Several of the country’s PHWRs have been refurbished for extended life operation. For more detailed information on the Indian nuclear program see, Nuclear Power in India (reference 1). Read the rest of this entry »
March 25, 2015
By: Donald Jones, P.Eng., retired nuclear industry engineer, 2015 March 24
Following on from some early conceptual work by Canadian General Electric (CGE), Atomic Energy of Canada Limited (AECL) based the CANDU 6 design on the four unit Pickering A station (that was brought into service 1971-1973) but as a single unit station with a significant power increase, major equipment simplifications, improvements in shutdown and emergency core cooling systems, extensive use of digital computers for control and safety systems etc. In fact the CANDU 6 is unrecognizable as being based on Pickering except maybe for the fuel channel sizing, even though fewer channels are in CANDU 6, and the two loop primary heat transport system that were retained. Since Ontario Hydro was enamored by multi-unit stations CANDU 6 was intended as a single unit for out of province build including off shore. The two lead CANDU 6 projects were Gentilly 2 in Quebec and Point Lepreau in New Brunswick and these were quickly followed by Embalse in Argentina and Wolsong, now Wolsong 1, in South Korea and all came into service in the early to mid 1980s. These can be regarded as the first tranche of CANDU 6 build.
The second tranche of CANDU 6 units came with Wolsong 2, 3 and 4 in South Korea, Cernavoda 1 and 2 in Romania, and Qinshan 4 and 5 in China (the other units at Qinshan site are not CANDU), all entering service between 1996 to 2007. Each of the second tranche CANDU 6 units incorporate lessons learned from operation of the earlier units with changes to meet latest regulatory codes and standards. All three Wolsong units came in on budget and on schedule and the two Qinshan units came in under budget and ahead of schedule. In fact the total project schedule for the CANDU 6 units at the Qinshan site in China was 81 months from contract effective date to in-service.
Unlike the 2013 CANDU 6 performance figures (reference 1) the Capacity Factors are taken from the Power Reactor Information System (PRIS) database of the International Atomic Energy Agency (IAEA). Note that the Load Factor term used in the PRIS database has the same meaning as Capacity Factor. Capacity Factors are based on the (net) Reference Unit Power and on the (net) Electricity Supplied figures, as defined in the PRIS database.
CANDU 6 Units
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March 24, 2015
By: Donald Jones, P.Eng., retired nuclear industry engineer, 2015 March 23
At the end of 2014 Darlington had a four unit average lifetime Capacity Factor (CF) of 84.0 percent and an average annual CF of 91.1 percent. Bruce A had a four unit average lifetime CF of 68.2 percent and an average annual CF of 79.6 percent. Bruce B had a four unit average lifetime CF of 83.5 percent and an average annual CF of 87.3 percent. The six unit Pickering station had a six unit average lifetime CF of 74.5 percent and an average annual CF of 74.4 percent.
Unlike the 2013 performance figures (reference 1) the raw performance data for 2014 are taken from the Power Reactor Information System (PRIS) database of the International Atomic Energy Agency (IAEA). Note that the Load Factor term used in the PRIS database has the same meaning as CF. CFs are based on the (net) Reference Unit Power and on the (net) Electricity Supplied, as defined in the PRIS database.
The performance of some of Ontario’s nuclear generating stations is affected by the surplus of generation in the province. The surplus usually arises because of unreliable intermittent wind generation coming in at times of low demand and wind generation is expected to increase even more over the next several years. Some nuclear units saw electricity output reductions during periods of surplus baseload generation (SBG). This means the CFs are not a true performance indicator for those units (reference 2). A better metric of performance in these cases would be the Unit Capability Factor (UCF – used by Ontario Power Generation and by Bruce Power) or the Energy Availability Factors (EAF) that are shown in the PRIS database. The EAF adjusts the available energy generation for energy losses attributed to plant management and for external energy losses beyond the control of plant management while the UCF only includes energy losses attributed to plant management and excludes the external losses attributed to grid related unavailability and other things. This means that on unreliable grids, for example, UCF will be significantly higher that EAF but for Ontario there will be no significant difference. The UCF and the EAF take into account reductions in plant output due to load cycling and load following. For units that load cycle and/or load follow the CF will be significantly lower than the EAF. For example, Bruce A unit 4 has a 2014 annual CF of 94.3 percent and an EAF of 99.4 percent. The UCF and the EAF are based on reference ambient conditions so, unlike the CF, they cannot exceed 100 percent. The only reason for using the EAF here (see later for Bruce units) instead of the UCF is that EAFs are now available in PRIS and UCFs are not presently available (well, the author could not find them). Read the rest of this entry »
February 26, 2015
By: Donald Jones, P.Eng., retired nuclear industry engineer, 2015 February
Wolsong unit 1, a CANDU 6 unit in South Korea operated by the Korea Hydro and Nuclear Power (KHNP) Company, was cleared for continued operation on 2015 February 27 by the Korean nuclear regulator (the Nuclear Safety and Security Commission – NSSC) after being out of service since 2012 November. Wolsong 1 was the first CANDU 6 unit in South Korea (reference 1) and went into commercial operation in 1983 April. The unit was taken out of service for refurbishment in 2009 April. At the end of 2008, the last full year of operation before the shutdown for refurbishment, the annual capacity factor was 93.2 percent and the lifetime capacity factor was 87.0 percent. The capacity factors are taken from the Power Reactor Information System (PRIS) database of the International Atomic Energy Agency (IAEA). Note that the Load Factor term used in the PRIS database has the same meaning as capacity factor. Capacity factors are based on the (net) Reference Unit Power and on the (net) Electricity Supplied, as defined in the PRIS database. For the 5 years prior to the refurbishment outage the average annual capacity factor was 89.4 percent.
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January 12, 2015
By: Donald Jones, P.Eng., retired nuclear industry engineer, 2015 January
It seems that the more wind there is on the Ontario electricity grid the more pollution there is. Case in point, a snapshot of the Independent Electricity System Operator’s (IESO) Generator Output and Capability Report for 2015 January 8 at 7 pm, which was a high wind high demand day. Wind was generating 2,631 MW, natgas or frackgas was generating 3,783 MW with the balance of the demand being met by nuclear and hydro. There were net exports of 3,500 MW. Now if there were no exports, natgas generation could have been reduced to 283 MW (assuming this low generation were achievable technically and under the must-run contracts) with a clean supply of nuclear, hydro and wind meeting the major part of the Ontario demand. Obviously 283 MW of natgas generation produces less greenhouse gases (GHGs) than 3,783 MW of natgas generation. So why did we need to export any gas generation in the first place since exports are highly subsidized by Ontario ratepayers to the benefit of the recipient jurisdiction?
This large amount of gas generation was likely exported because of the concern the IESO may have had with the risk of losing substantial wind generation under these circumstances (reference 1). Since most of the gas generation would be shutdown without exports the potential loss of 2,631 MW from wind would have had to be met from hydroelectric generation. With hydroelectric generation at this time already at a high 5,535 MW there may not have been enough extra MW and MWh available to cover the time period until the combined cycle gas turbine (CCGT) units could be fired up and dispatched to meet the wind shortfall. Ontario has only one quick start simple cycle gas turbine (SCGT) unit of 393 MW. Imports from other jurisdictions may not be available since wind failures affect large geographical areas and Quebec may have needed all its generation in house or had it already committed. The solution seems to have been to keep the CCGTs running at around their lowest dispatchable load so that they would always be available in case wind generation failed and the only way to do this was to feed an export market (reference 2). If sufficient extra MW and MWh of hydroelectric generation were available until the demand dropped there would be less or even no need to fire up the CCGTs. However, over the next five years or so several thousand MWs of additional wind will be coming onto the grid. With hydro generation limited the grid will see more use of the GHG emitting CCGTs (in MW and in MWh) and of exports (as in this snapshot) to maximize the use of the wind generation investment and minimize wind curtailment. The Ontario grid will depend even more on an export market and on reliable wind forecasting.
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November 25, 2014
By: Donald Jones, P.Eng., retired nuclear industry engineer, 2014 November 24
Major automobile manufacturers are continuing their development of cars powered by fuel cells using hydrogen (reference 1). Like cars powered by electric batteries the cars themselves will emit no greenhouse gas (GHG). Bulk quantities of hydrogen are mainly derived from natural gas (increasingly frackgas) but the process results in the production of carbon dioxide, a GHG, so fuel cell cars will not reduce overall GHG emissions. However hydrogen can also be produced from the electrolysis of water using electricity. If this electricity is generated from a power grid of non-fossil fuelled generation then zero overall GHG emissions can be achieved – this applies to battery cars as well as fuel cell cars.
Since fuel cell cars and battery cars can significantly reduce GHG emissions in at least part of the transportation sector the market for such vehicles could expand and one of the key questions will be how will these cars affect the demand for electricity and the stability of the grid. Battery cars and fuel cell cars will affect the power grid in different ways. Battery charging is uncontrolled and people will charge their car batteries when convenient, day and night. Fast battery charging at home from a dedicated house circuit can overload the street transformers. Smart controls at the distribution level may alleviate this but ultimately the distribution system might need upgrading to handle the extra demand. All ratepayers will pay for this including those without battery cars. Increasing the day time peak loads on the grid by uncontrolled battery charging will require an increase in generating capacity, likely from frackgas-fired GHG emitting units. Ideally battery charging should be done overnight when surplus generation is available at the lowest carbon dioxide emission intensity and at lowest cost. Read the rest of this entry »