||Steam Eruption from Nuclear Power Plant Cooling System.
||August 9, 2004
||The third in Kansai Electric Power Company Mihama nuclear plant machine
||Pressurized Water Reactor (PWR), turbine, condenser-steam generator connecting pipe.
||On August 9th, 2004, in the 3rd floor turbine hall of an active nuclear reactor, a steam eruption occurred. An inspection team on the 2nd floor was caught in the eruption, resulting in 4 deaths, 2 serious illnesses and 5 injuries. One of the 2 taken ill subsequently died.
Active nuclear power plant accidents represent what is potentially the greatest source of danger in modern times.
As the cooling system was two-stage in nature, there was no risk of radioactive contamination.
The cause of the eruption was erosion/corrosion. In order to measure the coolant flow rate in the pipe network, an orifice plate was installed. This caused a reduction in cross-sectional area and resulted in a belt-shaped (BELL-SHAPED?) section of pipe being subjected to increased water pressure. This eventually led to a rupture in the pipe. As a result, large quantities of high temperature steam were released.
This part of the pipe was widely suspected of erosion/corrosion, and many thought that it should be targeted for inspection. However, due to oversights the power plant and maintenance companies, a log of the inspections was not kept properly, and as such the pipe thickness was not checked for 27 years. Fukui Prefecture's police have begun procedures to charge those responsible with professional negligence.
||Active nuclear power plant accidents represent what is potentially the greatest source of danger in modern times.
The rupture occurred in the carbon steel pipe connecting the condenser and steam generator. The specifications are as follows: outer diameter: 560mm, thickness: approximately 10mm, coolant pressure: 10 mPa, temperature: 142 degrees Celsius. The explosion caused 800 tonnes of coolant to erupt from the pipes.
The portion of the pipe that ruptured was the thinnest part, having a thickness of 0.4mm, which had degraded from the original thickness of around 2-3 mm. In order to satisfy safety standards, the section should have had a thickness of at least 4.7mm.
In order to measure the coolant flow rate within the pipe, an orifice plate had been installed. Downstream of the orifice plate, a belt-shaped section of pipe was subjected to increased water pressure, eventually causing it to rupture.
As a result large quantities of high temperature steam were released.
Kansai Electric Power Company had commissioned a dedicated inspector for a different nuclear reactor between 1990 and 2003, which utilized a cooling network exactly identical to that of the Mihama plant.
As a result of the inspection, the exact same section of pipe that failed at Mihama was replaced with an Austenite stainless steel section.
In the case of the Mihama plant, because of oversights by Kansai Electric Power Company and the company in charge of maintenance (part Mitsubishi Heavy Industries and part Nihon Arm), the thickness of the pipe was not checked.
||The first documented case of investigation into pipe thickness reduction of a Pressurized Water Reactor (PWR) was in the second half of 1976.
Subsequent to this, the Sally plant accident in the USA that occurred in December 1986 prompted a wide ranging study into the state of repair of Japan's PWR's.
As a consequence of this study, in May 1990, a common set of rules for the maintenance of PWR's was decided.
Although the rules were decided in 1990 based on more than ten years of data, the most recent data was not taken into account. Between 1985 and 1989, Kansai Electric Power Company had outsourced the checking of pipe thickness and data collection to Mitsubishi Heavy Industries.
This data (THE DATA FROM BEFORE 1985?) was used in formulating the 1990 decision. In 1990, Mitsubishi Heavy Industries, using the new methods decided upon that same year, found an error in the number 3 turbine but did not enter the problem properly in the maintenance checklist.
In 1996, Kansai Electric Power Company changed its contract from Mitsubishi Heavy Industries to Nihon Arm. However, even at this time the maintenance checklist had still not been revised, and thus the fault in the number 3 turbine remained unnoticed.
In fiscal year 2001-2002, Nihon Arm carried out maintenance of the plant. In April 2003, a maintenance worker discovered the (A?) leak in the number 3 turbine and registered the discovery with the management. As a result, Nihon Arm mentioned the leak in their 20th report to Kansai Electric Power Company (June 2003) and proposed a solution to fix it by the time of the 21st report (November 2003).
Kansai Electric Power Company paid no notice to the reported damage.
In summary, although the component was known to be important, it was missed in the checklist and completely ignored, and as a result, no thickness check was made for 27 years. Ironically the pipe was scheduled for a check in the year when it finally ruptured.
||The location of the damage to the PWR is shown in Figure 2. The piping was situated in the 2nd floor turbine room.
The damaged piping was situated on the de-aerator side of the 2nd floor turbine room ceiling, connecting to the 4th floor pressurized water absorption heater.
There were two piping assemblies, labelled A and B. In order to assess the flow rate through the piping, an orifice plate was installed downstream of assembly A.
An orifice plate must reduce the stream cross-sectional area in order to allow measurement of the quantity of flow. The material used for the piping was Carbon Steel (SB42), having an outer diameter of 538.8mm, a thickness of 10mm, a maximum temperature of around 140 degrees Celsius, a maximaum pressure of around 0.93 Mpa, and a maximum flow rate of 1700 cubic meters per hour.
At its thinnest, the piping thickness was a mere 0.4mm.
It was decided to add a flange to support the orifice plate downstream of the vent. The vent was included to relieve pressure on the orifice plate; it was 4mm in diameter. Downstream of the vent, the signs of erosion/corrosion developed. However, the section of the pipe that did not get included in the check list did not get noticed for its signs of erosion/corrosion.
- The damage occurred in the easily eroded/corroded carbon steel at a vulnerable location downstream of the orifice plate.
- Data related to water quality (pH, percentage dissolved oxygen, etc.) was kept within the management department.
- At the area of eventual rupture, the temperature was around 140 degrees Celsius, which is ideal for erosion/corrosion.
- In general, when there is significant reduction in pipe thickness through erosion/corrosion, distinctive patterns are visible, but those patterns were not observed.
The pipe ruptured because erosion/corrosion of the pipe downstream of the orifice plate occurred, leading to eventual plastic collapse and rupture.
Usually, erosion/corrosion failure downstream of the vent occurs before failure downstream of the orifice plate. In order to support the orifice plate, a flange was installed. Therefore, even though the rupture happened unexpectedly it occurred at one of the most likely places.
Despite this, the region downstream of the vent was thought to be impossible to get to, and as such no checks were carried out.
Furthermore, the turbulent stream that caused erosion/corrosion downstream of the vent combined with the stream that caused erosion/corrosion downstream of the orifice plate, hence accelerating the overall degradation of the tubing.
The technical cause of the problem was reduction in thickness due to erosion/corrosion. However, the direct cause of the accident was negligence on the part of Kansai Electric Power Company, Mitsubishi Heavy Industries, and Nihon Arm to make the problem known to the management.
Therefore the accident was a result of the failure in quality assurance techniques used by Kansai Electric Power Company.
- The damage occurred in a place that was missed by inspections
- Even after the realization that the area was being repeatedly missed, inadequate liaison with relevant persons led to the lack of an appropriate inspection plan being formed.
||The Nuclear and Industrial Safety Agency appointed an accident investigation commissioner to investigate the problem. In a series of meetings between August 11th and September 27th, 2004, he examined the results of the post accident investigation.
We will now consider the methods of dealing with pipe degradation in PWR's, Boiling Water Reactors (BWR's) and thermal power stations.
Like with PWR's, thickness reduction in BWR piping due to erosion/corrosion is a problem. However, BWR's use a special Oxygen injection system in order to preserve water quality and also apply a Hematite coating (Fe203) on the surface of the pipes in order to help prevent corrosion.
The Sally reactor plant accident prompted a nationwide collection of pipe thickness degradation data in the USA. Electric power companies based their revised inspection protocols on this data.
If we compare the safety protocols of BWR's with those of PWR's, we find that the inspection range and frequency are both higher in BWR's.
The rate of pipe degradation is less in a BWR than in a PWR, due to the higher water quality in the BWR.
The secondary cooling circuit in a PWR employs a de-aeration alkali extraction treatment, which causes the development of magnetite (Fe304) on the pipe surface.
As for standard thermal power stations, the operating companies reported that as of August 20th, 2004, out of the 1467 units in 802 power stations, 704 units enforced pipe thickness checks and 763 did not.
||Until the accident? Until now?, inspection guidelines for all PWR plants have been based on gathering large amounts of secondary cooling circuit data. It was thought that by using some of that data, an appropriate inspection framework could be devised.
However, in order to effectively analyze the phenomenon of cooling pipe thickness reduction, nuclear power plant operators should consult with experts from abroad (OUTSIDE THE COMPANY?) and should make sure that the process they use is fully transparent and monitored by a neutral 3rd party. Therefore, it is important to consider the following factors:
- Base measurement results on thickness reduction rate should be made
- The range of the measurement results should be kept in mind
- When taking samples of a range of inspection data, one should make sure to get sufficient samples for the results to be statistically significant.
- Examination checks should be carried out in accordance with results showing the remaining lifetime
- New forms of diagnosis should be used for wall thickness (area of smallest thickness, greatest thickness reduction rate, variability of reduction rate)
- It is to be hoped that BWR companies will cooperate with PWR companies in order to ensure the development of improved measurement techniques.
Furthermore, even though at the present time there are no guidelines covering pipe thickness in thermal power stations, from now on all data taken from measurements of thermal power stations should be collected and used to set engineering guidelines.
Under present measurement techniques, one cross-section has 8 by 4 measurement points. If the thickness fails to meet the fixed criteria at one or more of these measurement points, more detailed measurements are performed and a decision is made after comparison with tabulated values.
As a consequence of this method, for the rest of the pipe, until it reaches the measured level of smallest thickness it is complete hypothesis as to what the exact level of degradation is. Although this method is thought to be conservative, in practice it has been found that the rates of pipe thickness reduction vary greatly from section to section.
When considering the direct cause of the accident, it is clear that there was a failure in quality control by Kansai Electric Power Company, Mitsubishi Heavy Industries and Nihon Arm.
The inspection system revision made in October 2003 made concrete requirements regarding quality assurance and maintenance necessary by law. Furthermore, a fixed (PERMANENT?) term inspection commissioner was employed. The new system of maintenance and quality assurance is the complete responsibility of this man. Finally, the Nuclear and Industrial Safety Agency commissioned a probe into inspection and safety management. Based on this state of affairs, quality assurance and maintenance counter-measures have been established as described below.
- Unified control in drawing up inspection lines
- Regulations to enforce proper collaboration when outsourcing pipe thickness maintenance
- Universal regulations on pipe thickness
- Information sharing with inspectors in order to prevent future accidents.
||Fluid flow within pipes reduces the pipe thickness leading to an eventual rupture. The thickness reduction mechanism is erosion/corrosion. One example is "cavitation corrosion".
Erosion and corrosion occur at the same time, and it is difficult to determine which one is dominant. Therefore, the term, "erosion/corrosion," is used. In the atomic energy field, the terms "Flow Accelerated Corrosion" and "Flow Induced Corrosion" are also used. This is similar to the formation of an oxidized layer of Fe304 on carbon steel due to water flow.
Erosion/corrosion does not degrade the whole surface equally, but rather it occurs accumulatively in specific sections.
-We differentiate between thickness lost over the whole surface ("General Metal Loss") and thickness lost in a particular region ("Localized Metal Loss").
In addition, we differentiate between crack-like flaws, planar defects, and non-equilibrium defects. That is, for a section of depleted thickness, fatigue cracks that are exacerbated by stress corrosion are all given equal importance when performing inspections.
-When predicting rates of erosion/corrosion, pipe sections of non-standard geometry tend degrade faster than the rest of the pipe. Certain parts of the pipe will be subject to differing conditions (due to stream turbulence). These conditions can include temperature, chemical species, and fluid flow rate. As the rate of reduction in pipe thickness is determined by process conditions and materials, predictions cannot be made based on common corrosion data. The same is true of stress corrosion.
Pipe wall thickness reduction is mostly found in the secondary cooling circuit of PWR's and the cooling circuit of BWR's. These pipes are made of carbon steel and hence management of water quality (temperature, dissolved oxygen, pH, etc.) as well as material properties (low alloy steel, Austenite stainless steel, etc.) is important.
Carbon steel generally suffers from wall thickness reduction whilst Austenite stainless steel is vulnerable to stress corrosion cracking.
There is no such thing as a fail-safe method. The prudent approach is to try and control the reduction in thickness.
-Fault assessment of pipe sections affected by wall thickness degradation should be made a priority.
-The accident involving the 6th H-2A rocket on November 29th, 2003 is a related example. Due to a turbulent stream of combustion gas, carbon fiber reinforced plastic was eroded away leading to a hole eventually opening in the nozzle wall through which the combustion gas escaped.
The rate of localized erosion is very difficult to predict.
||On September 29th, 2004, a report was presented by Tohoku Electric Power Company to the Nuclear and Industrial Safety Agency concerning the reduction in pipe thickness of piping in the Onnagawa plant downstream of the orifice plate.
At the Onnagawa plant, pipes downstream of the high pressure feed water heaters had to be repeatedly replaced due to thickness degradation. The details of the inspections leading to these replacements are presented below (There were two high pressure water heaters, each consisting of a pair of units with two connecting pipes labeled A and B)
1st High Pressure Feed Water Heater:
- The 5th inspection in 1989 led to the replacement of the carbon steel pipes A and B of unit 1 with new pipes.
- The 6th Inspection in 1990 led to the replacement of both pipes in units 1 and 2 with low alloy steel pipes.
- The 9th inspection in 1993 led to the replacement of pipe A in units 1 and 2 with a new low alloy steel pipe.
- The 11th inspection in 1997 led to the replacement of both pipes in units 1 and 2 with stainless steel pipes.
2nd High Pressure Feed Water Heater
- The 2nd inspection in 1997 led to the replacement of both low alloy steel pipes in units 1 and 2 with stainless steel pipes.
In summary, in the 1st high pressure feed water heater carbon steel could not deal with the reduction in pipe thickness and thus Austenite stainless steel had to be used.
As for the second heater, based on the experience gained from operation of the first heater, a low alloy steel was chosen at the design stage. However, despite this, the results were the same as for the first heater.
In the design of the 3rd high pressure feed water heater, Austenite stainless steel was used, and there has been no documented reduction in pipe thickness since that heater began operations.
The same design was used in Tokyo Electric Power Company's Kashiwazaki Karima plant, and although there were no signs of pipe thickness reduction the carbon steel was changed to a low alloy steel.
The problem is not erosion/corrosion itself but rather the erosion caused by water condensation from the vent. The mechanism leading to the erosion is presented below
1. The feed water heater's vent hole for sucking in steam and gas was overlooked by maintenance checks
2. As a result, condensated water made it all the way to the orifice plate
3. This water and steam passed out of the orifice plate at close to the speed of sound
4. The orifice plate spread this mixture of water and steam at a 45 degree angle, causing a belt shaped section of tubing to become saturated and begin to erode.
The Onnagawa numbers 1 and 2 feed water heaters had 45 degree tapers on their orifice plates whereas the number 3 feed water heater's orifice plate had no taper.
Tohoku Electric Power Company is considering changing the geometry of the orifice plates in order to prolong pipe lifetimes.
The dominant mechanism in the Kansai Electric Power Company accident was FAC, whereas the example involving the Tohoku Electric Power Company was primarily related to standard erosion.
Erosion/corrosion problems occur regularly in nuclear power plants, and thus it is important to have standardized counter-measures in place to deal with them. After the accident at Kansai Electric Power Company, another accident occurred on August 15th, 2004, this time at a thermal power plant in Fukushima Prefecture. Again there was a rupture in the cooling pipes (diameter 300mm, depth 10mm) downstream of a valve where the pipe thickness had been reduced by about 1.4 mm. This is a classic case of erosion/corrosion.
This rupture had occurred while the investigation was being carried out by the Nuclear and Industrial Safety Agency into the piping used in thermal power stations. The piping that exploded had started operation in 1995.
Erosion/corrosion problems are not limited to nuclear power stations but also occur in thermal power stations, petrochemical plants, oil refining facilities, etc.
||The results of the study into erosion/corrosion in nuclear power plants are presented below.
Under several laws and regulations (High Pressure Gas Safety Law, Petroleum Use Law etc.) explosions and ruptures must be reported to the government. Erosion/corrosion is most often the cause of these accidents.
Between 1971 and 1997 there were 53 ruptures and 19 cases of potential ruptures being detected before they occurred, giving 72 cases for study. Out of these 72 cases, 22 were erosion/corrosion related (see figure 4).
Once the entire thickness of a component is penetrated a rupture occurs. The slope of the graph in figure 4 represents the rate of thickness reduction. Data relating to non-erosion/corrosion incidents is not shown. We arrive at the following conclusions regarding the rate of thickness reduction due to erosion/corrosion*
-In general, corrosion proceeds at a rate of 0.15-0.3mm/year
-Acceleration of corrosion occurs at a rate of 0.3-0.5mm/year
-In general, erosion/corrosion proceeds at a rate of 0.5-1.0mm/year
-Acceleration of erosion/corrosion occurs at a rate of 4mm/year
In general, acceleration of corrosion is caused by two factors: water impurities (sea water etc.) and mechanical stress. Furthermore, the rate of thickness reduction caused by erosion/corrosion is much higher than that caused by corrosion only.
Erosion/corrosion causes are discussed below*
- Position (T-junction, curve, joint, valve and so on, downstream of an orifice etc.)
- Downstream events (water injection, collision, hot water flushing)
- Design (inappropriate structure, unsuitable materials)
Erosion/corrosion is rarely caused by just one of the above factors. It is most often caused by a combination of several factors. Some of these composite causes are described below:
-Inappropriate structure composite, e.g T-junction and water injection
- Fluid-position composite, e.g. hot water flushing through an orifice
- Unsuitable structure and unsuitable fluid complex, e.g. water injection and joint (see figure 6). The structure was unsuitable for the injection of water.
The turbulence of the injected water stream caused erosion/corrosion at the joint. The thickness reduction rate was at about 4mm/year. This is similar to the problem that occurred at Kansai Electric Power Company where the combination of the vent and orifice plate caused erosion/corrosion downstream.
An example of hot water flushing combined with an orifice plate can be seen in figure 7. Under hot water flushing conditions (where liquid and gas phases are separate) erosion/corrosion is induced downstream of the orifice plate. Taking the example of the Kansai Electric Power Company accident again, the opening caused by the rupture is roughly analogous to the orifice plate.
It is advisable to use specialized equipment when dealing with pipe thickness degradation.
Through the continuing analysis of case studies, appropriate changes can be made to reduce the seriousness of pipe thickness degradation.
Erosion/corrosion is still very much a statistical event, but changes in conditions still represent a large source of the problems.
| Primary Scenario
Organizational Problems, Poor Management, Insufficient Analysis or Research, Insufficient Prior Research, No inspection logs kept, Usage, Maintenance/Repair, Inspection/examination, Lack of inspection, Usage, Operation/Use, Piping, Bad Event, Thermo-Fluid Event, Fluid phenomenon, Stream turbulence, Orifice, Failure, Abrasion, Erosion/corrosion, Failure, Fracture/Damage, Explosion, Steam release, Bodily Harm, Death, Accidental death, Loss to Organization, Social Loss, Loss of confidence
(1) Nuclear and Industrial Safety, "Kansai Electric Power Company number 3 turbine secondary cooling accident interim report", 27th September 2004
(2) Hideo Kobayashi, "Standardized Procedures necessary for accurate Technical Control", Nuclear energy Culture 35-10, 11-13, October 2004
(3) Tohoku Electric Power Company, "On the Onnagawa plant high pressure feed water heaters wall thickness reduction," 29th September 2004
(4) Hideo Kobayashi et al, "Research into stressed component damage due to corrosion and corrosion speed," High Pressure Gas 35-3, 203/214 (1998)
(5) Hideo Kobayashi et al, "Research into stressed component erosion/corrosion," High Pressure Gas, 36-8, 720/728 (1999)
|Number of Deaths
|Number of Injuries
Fig_2.Main damaged area of PWR
Fig_4.Downstream of Vent
Fig_5.Erosion/Corrosion Reduction Speed
Fig_6.Damage from cold water Injection
Fig_7.Damage from hot water flushing
KOBAYASHI, Hideo (Yokohama National University)