San Onofre steam generator tubes leaking - why?

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San Onofre's steam generators are experiencing significant leaks and corrosion, raising concerns about potential manufacturing defects or installation issues. The replacement generators, installed in 2010 by Mitsubishi Heavy Industries, are under investigation for unusual wear patterns, including tube-to-tube contact and structural wear. The chemistry of the water used in the system is critical, as even minor impurities can lead to significant operational problems. Concerns have been raised about the materials used, particularly Inconel alloys, and the welding processes involved in their construction. The situation is being closely monitored, with ongoing inspections and investigations to determine the root causes of these failures.
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Steam generator tubes are [STRIKE]leaking[/STRIKE] thinning .
This was a big problem stateside 1n 1970's.

Chemistry of water on secondary side is extremely important.
We measured impurities in parts-per--billion. One cup of tap water was enough to cause a shutdown to flush the steam generators, i know because one of our technicians used a cup of tapwater to top off a level instrument... once.

Metallurgy was important also. Copper contributed to corrosion.
We replaced the admiralty brass tubes in condenser with titanium, and feedwater heaters with stainless steel.

These lessons were learned almost forty years ago. Our replacement generators from Westinghouse-Tampa are doing fine.
So - what's going on now? That's REAL good question.
First question pops to mind is "Where did Mitsubishi procure the metal for the tubes in those replacement steam generators?"

Second is "How's the plant's water chemistry ?"

It'll be interesting to follow this one.

Edited first line. sorry.
 
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http://www.clipsyndicate.com/video/playlist/1510/3242180?cpt=8&title=ans_nuclear_clips&wpid=752

The San Onofre plant replaced its steam generators in 2010; it is almost certain this is a manufacturing defect.
 
jensjakob said:
Hi,

San Onofre, menioned durring the Japan crisis, is leaking and corroding pipes fast:
http://www.scpr.org/blogs/news/2012/03/22/5205/san-onofre-reactors-down-indefinitely/

http://sciencedude.ocregister.com/2012/02/02/nuclear-leak-damage-to-both-reactor-units/167503/

What is going on- any ideas?

Take care

Jens Jakob
The fact that these are replacement SG's and the tubes failed during the first cycle of operation would implicate 1) a manufacturing defect or 2) a problem with installation.

SCE replaced SGs in SONGS2 during 2009.
24 February 2009

Two replacement steam generators have been delivered for the second unit of Southern California Edison's (SCE's) San Onofre Nuclear Generating Station (SONGS). Mitsubishi Heavy Industries (MHI) made the components.
http://www.world-nuclear-news.org/newsarticle.aspx?id=24719

04 October 2010

Mitsubishi Heavy Industries (MHI) has delivered two replacement steam generators for the third unit of Southern California Edison's (SCE's) San Onofre Nuclear Generating Station (SONGS).

MHI said that the replacement steam generators delivered for SONGS 3 are among the world's largest, each measuring approximately 20 metres in length, seven metres in diameter and weighing some 580 tonnes. Each of them contains about 10,000 heat transfer tubes.
http://www.world-nuclear-news.org/C-New_steam_generators_for_SONGS_3-0410105.html

'Why' is the question - indeed! There is an ongoing investigation. It must be determined if any corrosion (intergranular stress-corrosion) and/or cracking is occurring, and if it is initiated on the primary or secondary side.

I believe the material is Inconel 690, which is supposed to be superior to Inconel 600. However, Inconels are notoriously tricky alloy systems.
 
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"The company has received overseas orders for 31 units, mainly from North America and Europe. "

Hmmm - could be interesting to track those and compare corrosion.
 
More info at the SONGS website:

http://www.songscommunity.com/news.asp

Confirms Unit 2 S/G replacement in 2009 and Unit 3 in 2010. The following link is good info on the testing methods being used:

http://www.songscommunity.com/docs/Test_Inspections.pdf
 
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Picture of Steam Generator (MHI):

http://www.mhi.co.jp/en/products/detail/steam_generator.html

Unit 3 S/G had leakage before delivery. Note that this was not tube leakage so current problems may not be directly related.

http://mdn.mainichi.jp/mdnnews/news/20120229p2g00m0dm058000c.html

If there is a manufacturing problem, Mitsubishi has already delivered over 100 steam generators around the world.I am less worried about the 31 on order.
 
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  • #10
NUCENG said:
Unit 3 S/G had leakage before delivery. Note that this was not tube leakage so current problems may not be directly related.

http://mdn.mainichi.jp/mdnnews/news/20120229p2g00m0dm058000c.html
The article states
According to the NRC documents, Mitsubishi Heavy discovered a 5 inch (12.7 centimeter) long crack in the dissimilar metal weld between the divider plate and the channel head of the steam generator of the unit 3 reactor during its routine visual inspection in March 2009.
If that is the replacement S/G, that's rather troubling. In 2009, that SG would have been at the Mitsubishi shop - ostensibly before shipment. Or did Mitsubishi inspect the older in-service SG, which was replaced in 2010?

A crack in the divider plate is not bad as long as it doesn't propagate. A breach in the divider plate would allow leakage from the hot leg to the cold leg, thus by-passing the SG tube bundle. It is still within the primary system.

From the description, it sounds like the crack was at the edge of the divider plate where it joins the vessel (channel) head.
 
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  • #11
Astronuc said:
The article states If that is the replacement S/G, that's rather troubling. In 2009, that SG would have been at the Mitsubishi shop - ostensibly before shipment. Or did Mitsubishi inspect the older in-service SG, which was replaced in 2010?

A crack in the divider plate is not bad as long as it doesn't propagate. A breach in the divider plate would allow leakage from the hot leg to the cold leg, thus by-passing the SG tube bundle. It is still within the primary system.

From the description, it sounds like the crack was at the edge of the divider plate where it joins the vessel (channel) head.

I understand the crack was on the Unit 3 replacement S/G and was repaired before shipment and installation in 2010.
 
  • #12
NUCENG said:
I understand the crack was on the Unit 3 replacement S/G and was repaired before shipment and installation in 2010.
That would seem to be what the article implicates. I was hoping for confirmation.

Nevertheless, I'm puzzled about the crack, and also about welding dissimilar metals. I would expect the vessel shell to be line with stainless steel, and the divider plate to be made of the same stainless steel. Certainly if one welds a low carbon stainless steel to a high carbon steel, cracking can be an issue.

I'm curious about their process and procedures, since the procedures should be such that cracking is prevented/avoided.

I'd like to know if the Inconel tubes are cracking (which would imply either poor material and/or poor fabrication practice) or leaking about the fitup at the tube sheet (which would imply a poor process).

Nevertheless, it is very troubling that such failures occur in something that is designed to last 20 to 30 years.

Original SGs were supposed to last the life of the plant (40) years, and if possible now 60 years. They represent a substantial capital cost, and the economic models, which I studied at university, never included SG replacement. After I finished by undergrad, I learned about how Inconel 600 components (and certainly welding materials) were failing prematurely.

Primary water chemistry, and in some cases, secondary water chemistry are certainly factors.
 
  • #13
Astronuc said:
That would seem to be what the article implicates. I was hoping for confirmation.

Nevertheless, I'm puzzled about the crack, and also about welding dissimilar metals. I would expect the vessel shell to be line with stainless steel, and the divider plate to be made of the same stainless steel. Certainly if one welds a low carbon stainless steel to a high carbon steel, cracking can be an issue.

I'm curious about their process and procedures, since the procedures should be such that cracking is prevented/avoided.

I'd like to know if the Inconel tubes are cracking (which would imply either poor material and/or poor fabrication practice) or leaking about the fitup at the tube sheet (which would imply a poor process).

Nevertheless, it is very troubling that such failures occur in something that is designed to last 20 to 30 years.

Original SGs were supposed to last the life of the plant (40) years, and if possible now 60 years. They represent a substantial capital cost, and the economic models, which I studied at university, never included SG replacement. After I finished by undergrad, I learned about how Inconel 600 components (and certainly welding materials) were failing prematurely.

Primary water chemistry, and in some cases, secondary water chemistry are certainly factors.

And anytime you open a system there is a chance for loose parts or materials to enter a system. Flow induced vibration can cause wear and tear. A few years ago replacement condensate pumps for a nuclear plant were exposed to road grime and sludge during shipment because penetration seals were not properly installed. I too am concerned this has developed so soon after S/G replacement and that is likely why NRC sent the AIT. I am not a welding or S/G expert, but if I find additional information I will post it. We should learn more when the NRC AIT has their exit meeting.
 
  • #14
I'd like to know if the Inconel tubes are cracking (which would imply either poor material and/or poor fabrication practice) or leaking about the fitup at the tube sheet (which would imply a poor process).



From Nuceng's http://pbadupws.nrc.gov/docs/ML1207/ML12075A219.pdf

Continuing inspections of 100% of the steam generator tubes in both Unit 3
steam generators discovered unexpected wear, including tube to tube as well as tube to tube
support structural wear.
and http://www.nrc.gov/reading-rm/doc-collections/event-status/event/2012/20120319en.html
Steam generators do experience some wear during the first year of operation but the level of tube wear at Unit 3 is unusual.


Chemistry problems can deposit solids in the support to tube annulus and squeeze the tubes.
But tube-to-tube wear sounds more like a vibration issue arising from mechanical design.
It's hard to believe mechanical vibration trouble after this many years experience making Steam Generators.

As you said, it'll be interesting to see what they find.
 
  • #15
jim hardy said:
Chemistry problems can deposit solids in the support to tube annulus and squeeze the tubes.
But tube-to-tube wear sounds more like a vibration issue arising from mechanical design.
It's hard to believe mechanical vibration trouble after this many years experience making Steam Generators.

As you said, it'll be interesting to see what they find.
The chemistry practices are pretty standard these days. There could be an issue with commissioning a fresh surface.

Replacement generators may have higher flow rates. I can't remember if there was a plant uprate with the steam generator replacement.

Tube wear after one cycle of operation would be troubling. Despite experience, designer make 'improvements' that sometime may introduce performance problems. There was a case of two BWRs* in which new advanced turbines developed cracks in one of the late stages in the LP turbine. Subsequent CFD reveal a design flaw. The CFD analysis (which is very mature these days) should have been part of the initial design process.

*Hamaoka 5 and Shika 2 off line after turbine vane failures
http://www.neimagazine.com/story.asp?storyCode=2038314


High cycle fatigue (either mechanical (FIV) or thermo-mechanical) is a possibility if the frequency is in the acoustic range (10-1000s Hz) with 3.156E7 s/yr.
 
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  • #16
Astronuc said:
The chemistry practices are pretty standard these days. There could be an issue with commissioning a fresh surface.

Replacement generators may have higher flow rates. I can't remember if there was a plant uprate with the steam generator replacement.

Tube wear after one cycle of operation would be troubling. Despite experience, designer make 'improvements' that sometime may introduce performance problems. There was a case of two BWRs* in which new advanced turbines developed cracks in one of the late stages in the LP turbine. Subsequent CFD reveal a design flaw. The CFD analysis (which is very mature these days) should have been part of the initial design process.

*Hamaoka 5 and Shika 2 off line after turbine vane failures
http://www.neimagazine.com/story.asp?storyCode=2038314 High cycle fatigue (either mechanical (FIV) or thermo-mechanical) is a possibility if the frequency is in the acoustic range (10-1000s Hz) with 3.156E7 s/yr.

San Onofre Units 2 and 3 have both got approved Margin Uncertainty Recovery Power Uprates of 1.4% in 2001.
 
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  • #17
NUCENG said:
San Onofre Units 2 and 3 have both got approved Margin Uncertainty Recovery Power Uprates of 1.4% in 2001.
That's enough time to incorporate into the current replacement design. In terms of uprate, I was thinking more along the lines of an extended or stretch uprate with 5+% increase in reactor/plant output.

Mitsubishi is a Westinghouse licensee, and they have probably replaced more W-SG than CE SGs. The large CE plants (mostly 16x16 fueled) typically use 2 steam generators - with one hot leg and two cold legs. They are therefore typically larger than W-SGs. Could that be a factor?
 
  • #18
Hamaoka 5 and Shika 2 off line after turbine vane failures
http://www.neimagazine.com/story.asp?storyCode=2038314

Ahhh,, Turbine blades - another of those fascinating industry "niches" .
Rotor dynamics is fascinating.


High cycle fatigue (either mechanical (FIV) or thermo-mechanical) is a possibility if the frequency is in the acoustic range (10-1000s Hz)

Tubes will rattle.
I suppose it's quite a calculation to get the natural frequency and vibration modes of a long hollow tube that's pressurized with the fluid inside having considerable velocity.
When i read how a Coriolis Flowmeter works , i just felt like saluting the entire Mechanical Engineering community.
http://en.wikipedia.org/wiki/Mass_flow_meter#Operating_principle_of_a_coriolis_flow_meter
it somewhat resembles the u-tubes in steam generator, see this graphic
http://en.wikipedia.org/wiki/File:Coriolis_meter_vibrating_no-flow_512x512.gif

I'm admitting my abysmal ignorance here. I know just enough to not cast stones, and that wasn't intent of previous post...
 
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  • #19
NRC Region IV Administrator Elmo E. Collins said. “Until we are satisfied that has been done, the plant will not be permitted to restart.”

On Jan. 31, operators performed a rapid shutdown of the Unit 3 reactor after indications of a steam generator tube leak. Unit 2 has been shut down since Jan. 9 for a planned refueling and maintenance outage. Subsequent inspections at both units have identified unusual wear in many tubes of the steam generators, which were replaced in January 2010 at Unit 2 and January 2011 in Unit 3.

SCE has identified two causes of the unusual wear: tubes are vibrating and rubbing against adjacent tubes and against support structures inside the steam generators. They are still working to determine why this is occurring.

Only one tube required pressure testing on Unit 2. However, six other tubes required plugging, and 186 additional tubes were plugged as a precautionary measure. Eight tubes failed pressure testing at Unit 3, indicating that these tubes could have failed under some accident conditions. Evaluation for additional plugging or other corrective actions are continuing for Unit 2, based on ongoing evaluations of Unit 3 test results.
CAL 4-12-001 - http://www.nrc.gov/reading-rm/doc-collections/news/2012/12-011.iv.pdf
CONFIRMATORY ACTION LETTER – SAN ONOFRE NUCLEAR GENERATING STATION, UNITS 2 AND 3, COMMITMENTS TO ADDRESS STEAM GENERATOR TUBE DEGRADATION

For both Units 2 and 3, this was the first cycle of operation with new replacement steam generators. Unit 2 replaced its steam generators in January 2010, and Unit 3 in January 2011. Each steam generator has 9,727 steam generator tubes.
 
  • #20
Story on San Onofre Steam Generator Leakage.

http://www.power-eng.com/news/2012/04/02/expert-cites-reasons-for-san-onofre-troubles.html

Story above is based on Arnie Gunderson Report prepared for the Friends of the Earth environmental and anti-nuclear group.

http://fairewinds.com/content/foe-report-steam-generator-failures-san-onofre

Biggest error is that the quote from NRC chairman Jaczco that NRC approval is not required for restart is not current. The Confirmatory Action Letter issued to SCE requires NRC approval. I am still looking for a copy of the CAL itself. I haven’t found it on ADAMS yet.

I do like the list of changes implemented in the new steam generators. Arnie is correct that the increased number of tubes, change in tube alloy, changes in tube support structure (egg crate - implying fragility?) and increased coolant flow are potential causes.

I think pulling in the issue of BWR Dryer Cracking is a stretch though. Anyway this is a potential for a good discussion here on PF.
 
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  • #21
The CAL is in my previous post.

I don't think switching to 690 from 600 (?) is an issue, as that is the industry practice over the last two decades. Smaller tubes and increased flow rates might play a role, but I'd have expected a CFD analysis would have caught that - but maybe not if not done right.

BWR dryer is different material in a different environment over a longer period. That's mixing apples with oranges, but it is an interesting topic nevertheless.
 
  • #22
Astronuc said:
The CAL is in my previous post.

I don't think switching to 690 from 600 (?) is an issue, as that is the industry practice over the last two decades. Smaller tubes and increased flow rates might play a role, but I'd have expected a CFD analysis would have caught that - but maybe not if not done right.

BWR dryer is different material in a different environment over a longer period. That's mixing apples with oranges, but it is an interesting topic nevertheless.

Thanks, I was not paging down far enough to see the CAL - operator error!

You expressed interest in the divider plate defect in the rplacement S/G for unit 3. Here are the references I found. (I am not a weld engineer and won't even try to comment.)

IN 2010-07
http://pbadupws.nrc.gov/docs/ML1000/ML100070106.pdf

Slide Presentation on root cause:
http://pbadupws.nrc.gov/docs/ML0925/ML092590470.pdf

Non Proprietary Root Cause Report:

http://pbadupws.nrc.gov/docs/ML0926/ML092600513.pdf
http://pbadupws.nrc.gov/docs/ML0926/ML092600515.pdf
http://pbadupws.nrc.gov/docs/ML0926/ML092600516.pdf
 
  • #23
Somewhat relevant - Effects of Alloy Chemistry, Cold Work, and Water Chemistry on Corrosion Fatigue and Stress Corrosion Cracking of Nickel Alloys and Welds
http://www.nrc.gov/reading-rm/doc-collections/nuregs/contract/cr6721/cr6721.pdf

They process used low carbon Alloy 152 in butter welds as expected.

They used gouging to remove the SS cladding in Unit 3 RSGs rather than the machining used in Unit 2 RSGs.
 
  • #24
I came across this news article that may be of interest.

It sounds as though anti-vibration supports were removed to increase the number of tubes in the generator. This has led to more vibration and mechanical wear as a result.
 
  • #25
Hologram0110 said:
I came across this news article that may be of interest.

It sounds as though anti-vibration supports were removed to increase the number of tubes in the generator. This has led to more vibration and mechanical wear as a result.

The source of that position is Arne Gunderson speculation on a cause. In previous posts we have listed other possible causes. Clearly the NRC recognizes the need to determine a root cause (as evidenced by the CAL). I urge you to reserve judgment until the facts are determined. I am certain that the root cause evaluation will be released (although some proprietary information may be withheld). I am also certain that NRC staff, ACRS, and every "nuclear watchdog" organization will subject the root cause to independent review. It is possible that Arnie is right, just not certain based on his previous record.
 
  • #26
You're absolutely right. From the article:

The report on San Onofre by Fairewinds Associates, a Vermont-based consultant that has worked with groups critical of nuclear power, suggests that "imprudent design and fabrication decisions" may be to blame for accelerated wear on generator steam tubes. Friends of the Earth commissioned the analysis.

The article just popped up in my news feed this morning and I remembered there was a thread about it on Physics Forums. I wasn't following the tread so I assumed that this was a 'new' analysis. Seems I missed that the tread was dead. Sorry about that.
 
  • #27
Hologram0110 said:
You're absolutely right. From the article:

The article just popped up in my news feed this morning and I remembered there was a thread about it on Physics Forums. I wasn't following the tread so I assumed that this was a 'new' analysis. Seems I missed that the tread was dead. Sorry about that.

Here is the latest - a Part 21 report from MHI.

http://www.nrc.gov/reading-rm/doc-collections/event-status/event/2012/20120416en.html

Part 21 Event Number: 47833
Rep Org: MITSUBISHI NUCLEAR ENERGY SYSTEMS
Licensee: MITSUBISHI HEAVY INDUSTRIES, LTD
Region: 1
City: ARLINGTON State: VA
County:
License #:
Agreement: Y
Docket:
NRC Notified By: EI KADOKAMI
HQ OPS Officer: JOHN KNOKE Notification Date: 04/13/2012
Notification Time: 15:58 [ET]
Event Date: 04/13/2012
Event Time: [EDT]
Last Update Date: 04/16/2012
Emergency Class: NON EMERGENCY
10 CFR Section:
21.21(a)(2) - INTERIM EVAL OF DEVIATION
Person (Organization):
BLAKE WELLING (R1DO)
KATHLEEN O'DONOHUE (R2DO)
DAVID HILLS (R3DO)
VINCENT GADDY (R4DO)
PART 21 GROUP (EMAI)


Event Text

PART 21 INTERIM REPORT - STEAM GENERATOR TUBE WEAR

This interim Part 21 is in regard to San Onofre Nuclear Generating Station, Unit 2, Steam Generator replacement.

"During the first refueling outage following steam generator replacement, eddy current testing identified ten total tubes with depths of 90 to 28 percent of the tube wall thickness. Some of the affected tubes were located adjacent to retainer bars. The retainer bars are part of the floating anti-vibration bar (AVB) structure that stabilizes the u-bend region of the tubes.

"Other tubes in the two steam generators had detectable wear associated with support points elsewhere in the AVB structure. Each steam generator has 9727 tubes with an 8 percent (778 tubes) design margin for tube plugging.

"Discovery Date: February 13, 2012

"Evaluation completion schedule date: May 31, 2012"

"Those Mitsubishi Heavy Industries customers potentially affected by this issue have been notified and will receive a copy of this interim report."

Reference Document: UET-20120089
Interim Report No: U21-018-IR (0)
 
  • #28
  • #30
i'm sure curious why the new tubes fail .

...limited to operate at a lower power rating to avoid the possibility that flow induced vibration is a cause.

Vibration can be excited from either inside or outside a tube.
Flow inside those tubes barely changes with power.
Seems to me a microphone on the steam generator could hear tubes clattering.
I'd instrument a steam generator and listen. If they clatter at zero power then excitation is from primary flow not secondary.
Most plants have loose parts monitors that are basically microphones at natural collection points like reactor vessel bottom and steam generator inlet side tubesheet. Move one up to vicinity of the tube wear region.

old jim
 
  • #31
jim hardy said:
i'm sure curious why the new tubes fail .

Vibration can be excited from either inside or outside a tube.
Flow inside those tubes barely changes with power.
If the tubes are contacting each other, then that's some relatively large amplitude vibration, which means the tubes are not sufficiently stiff, or there is some pretty substatial excitation mechanism.

Flow might have increased because of the reduced pressure drop, and perhaps flow was increased slightly, on the primary and/or secondary side in order to increase power output. Increased flow in the primary circuit always an issue when replacing steam generators.

I'm puzzled about what kind of analysis was performed concerning the design. In this day and age, we have pretty advanced CFD capability. I'm left wondering - what did they miss, or not consider, in the design and the analysis.

Seems to me a microphone on the steam generator could hear tubes clattering.
I'd instrument a steam generator and listen. If they clatter at zero power then excitation is from primary flow not secondary.

Most plants have loose parts monitors that are basically microphones at natural collection points like reactor vessel bottom and steam generator inlet side tubesheet. Move one up to vicinity of the tube wear region.
Acoustic emissions (noise) analysis would be appropriate, but I'm not sure it if is done on SGs.
 
  • #32
If the tubes are contacting each other, then that's some relatively large amplitude vibration, which means the tubes are not sufficiently stiff, or there is some pretty substatial excitation mechanism.

iirc the tube diameter was decreased and bending moment is in proportion to moment of inertia of cross section, i think 3rd or 4th power of diameter ?
http://en.wikipedia.org/wiki/List_of_area_moments_of_inertia
(Pardon me I'm no mechanical engineer) so reducing diameter will reduce stiffness ? Surely they calculated that. The tubes get additional stiffness due to internal-external Δp and i don't know how to calculate that. That Δp is not constant as main steam pressure changes from ~ 1000 psi to ~ 800 with power.
As you said surely they couldn't have missed that.

It gets curioser and curioser.
They'll figure it out. They have my genuine sympathy .

Acoustic emissions (noise) analysis would be appropriate, but I'm not sure it if is done on SGs.

we had loose parts sensors at entry point of feedwater line to steam generator. You could hear internals of check valve tinkling at low flow. That'd be the closest point i know of. Sound telegraphs pretty well through steel , so one might hear something at primary tube sheet.



old jim
 
  • #33
Installing such acoustic monitors might have been possible as part of the RSG startup, but I don't think they will be heating the unit up / running the RCPs just so they can listen in and try to identify the problem. Too late for that. They will have to figure it out with inspections, whatever operating data is available now, and some fancy analysis.
 
  • #35
Astronuc, How do you feel this affects MHI's reputation in the USA industry after this?
 
  • #36
Thermalne said:
Astronuc, How do you feel this affects MHI's reputation in the USA industry after this?
I think it's a blow to their credibility - at least the division responsible. If I were a utility, I'd be very cautious concerning their products.

One thing I review in component design and manufacturing is 'anything new'. It's a question I ask each and every time (or a variant, "what's different"), particularly as part of a design review or technical surveillance.

There were manufacturing changes, and apparently design changes, as well as a faulty CFD analysis. That's why design reviews and oversight (by competent engineers who know at what and where to look) are so critical.
 
  • #37
One thing I review in component design and manufacturing is 'anything new'.

There exixts a mechanism in design review process called "Item Equivalency Evaluation" that is intended to allow replacing parts with equivalent parts.
It exists to allow for obsolescence, eg procuring newer transistors or electric motors or pumps to replace old models that have been discontinued by manufacturers, or to allow use of manufacturers' improved parts.
It requires that competent people study the equipment and make an honest assessment that the proposed new part will in fact perform its function at least as well as the original part did.
I understand that this IEE process was used for San Onofre's steam generator replacement.

The extent of alterations was described in a January article for Nuclear Engineering International magazine; it was written by a top-level Edison engineer and a collaborator from Mitsubishi. In that piece, published before the tubing crisis became public, they also described how the project was configured to meet federal guidelines without triggering a prolonged regulatory review.

Ultimately, the engineers couldn’t guarantee that their redesign would function flawlessly without putting them to work at San Onofre.

“Even though all design and fabrication challenges were addressed during manufacturing, it was not known if the as-designed and fabricated replacement steam generators would eventually perform as specified,” the authors wrote.
http://www.utsandiego.com/news/2012/may/26/did-san-onofre-fix-cause-the-problem/?print&page=all


To accomplish a design change via IEE pushes the intent a bit , so must be done with extreme caution and attention to detail if at all.


Looks like the mechanics and hydro-dynamics up around the top of u-tubes weren't studied quite well enough. Somebody should have hollered for help if he was in over his head.


It's a black eye for all involved
but before the floggings begin, one should find out how much of that analysis was assigned by the contract to each party.

For as Astro pointed out, responsibility rests with "Responsible Design Organization".

old jim
 
  • #39
Lengthy review possible at damaged Cal nuke plant
http://news.yahoo.com/lengthy-review-possible-damaged-cal-nuke-plant-235404211.html
The Nuclear Regulatory Commission is considering if the complex proposal submitted by operator Southern California Edison last week to repair and start the damaged Unit 2 reactor will require an amendment to San Onofre's operating license, Regional Administrator Elmo Collins told reporters.

Such reviews can involve a thicket of public hearings, appeals and commission actions on safety and design issues that can take as long as two years to complete.

In a March letter, federal regulators outlined a series of benchmarks Edison must reach to restart the plant, including determining the cause of vibration and friction that damaged scores of steam generator tubes, how it would be fixed and then monitored during operation.

Those requirements, however, did not involve amending the plant's operating license.

. . . .

It's "an open question" if a license amendment is needed, Collins said during a news conference. "It's a possibility. I'm not saying yes or no."

. . . .
The utility is hoping to operate Unit 2 at reduced power.
 
  • #40
Four months later: Uncertainty clouds future of Calif nuke plant
http://news.yahoo.com/uncertainty-clouds-future-calif-nuke-plant-222737326.html

LOS ANGELES (AP) — The mounting bill tied to the shuttered San Onofre nuclear power plant in California jumped to more than $400 million through December, as the company that runs it contends with costly repairs and a host of questions about its future, regulatory filings and officials said Tuesday.
. . . .
The figures come as SCE pushes the Nuclear Regulatory Commission for permission to restart one of the twin reactors, Unit 2, and run it at 70 percent power for five months in hopes of ending vibration and friction blamed for tube damage.
. . . .
 
  • #42
SONGS Closing

Pulling the plug:

http://www.cbsnews.com/8301-201_162-57588196/calif-utility-to-retire-troubled-san-onofre-nuclear-power-plant/
 
  • #43
NUCENG said:
Pulling the plug:

http://www.cbsnews.com/8301-201_162-57588196/calif-utility-to-retire-troubled-san-onofre-nuclear-power-plant/
Ouch! So much for the Renaissance.

Crystal River is also down and out, and Kewaunee was just permantely shutdown. So the number of operating reactors has dropped to 100, down from 104.
 
  • #44
Astronuc said:
Ouch! So much for the Renaissance.

Crystal River is also down and out, and Kewaunee was just permantely shutdown. So the number of operating reactors has dropped to 100, down from 104.

And Fort Calhoun hasn't got a restart from the CAL (confirmatory Action Letter) yet as far as I know.
 
  • #45
  • #46
Thermalne said:
Astronuc, How do you feel this affects MHI's reputation in the USA industry after this?

I know of a plant who is discussing not even doing steam generator replacement after looking at CR3 and SONGS. They would just shut down after their SGs reach the ASME code limits. They are seeing that the potential risk might not be worth the reward. (this is partially influenced by natgas prices as well). It's kind of a blow in reputation of anyone making SGs.
 
  • #47
Ouch! So much for the Renaissance.

It sure hurt the industry's image.

This article
https://s3.amazonaws.com/s3.documentcloud.org/documents/347889/col-nrc-tech-paper.pdf

describes an administrative process used by the utility to avoid some reviews of changes to the design.

At SONGS, the major premise of the steam
generator replacement project was that it
would be implemented under the 10CFR50.59
rule, that is, without prior approval by the US
Nuclear Regulatory Commission (USNRC). To
achieve this goal, the RSGs were to be
designed as ‘in-kind’ replacement for the
OSGs in terms of form, fit and function.

That is a very useful shortcut for little things like replacing obsolete transistors or when a vendor changes his paint color.
But there's a fine line somewhere between parts replacement and redesign.

A little further down same article:
The term ’AVB structure’ describes tube
supports in the tube bundle U-bend region.
The AVB structure had to be designed such
that the potential for tube wear due to flow
induced vibration was minimized.
To achieve this objective, six sets of Vshaped
AVBs made from Type 405 ferritic
stainless steel, providing up to 12 support
points per tube bend, were installed in the U
bend region to provide support in the region
where the tubes are most susceptible to
degradation due to wear from flow-induced
vibration. The single major challenge here
was control of the AVB thickness and
flatness, and tube-to-AVB gap size. This
challenge was addressed by customizing the
fabrication and assembly processes and
implementing strict quality control in various
stages of AVB fabrication and AVB structure
assembly.

Scuttlebutt is that the high void fraction in that region gave less fluid damping than assumed so the tubes rattled more than expected.

Whether additional NRC review would have caught the design mistakes beforehand I don't know.
But they sure found them after the fact, around page 56 here:
http://www.nrc.gov/info-finder/reactor/songs/ML12188A748.pdf
The team developed an independent model of the new steam generators using the ATHOS thermal hydraulic code3
Mitsubishi provided a comparison of their ATHOS model to their FIT-III model results. The Mitsubishi ATHOS model fluid velocities were approximately 3 times higher than the FIT-III model velocities with the 1.5 multiplier applied. Other independent code calculations, including an analysis by Westinghouse using their in-house modified version of ATHOS and an analysis by AREVA using their French code CAFCA4 showed similar thermal-hydraulic results (up to 4 times higher velocities than FIT-III) as those computed in the Mitsubishi ATHOS results and the NRC independent ATHOS calculations. Based on these comparisons, it was concluded that the FIT-III code and model results used for design were non-conservative even with the multiplier applied. . The calculations were intended to assess operating cycle differences between Units 2 and 3 steam generators and review thermal hydraulic phenomena within the steam generators in order to investigate key parameters and causal factors for the excessive tube wear rates. The NRC ATHOS calculations determined that the differences in primary inlet temperature and steam flow between the units were negligible. NRC ATHOS results indicated high void fractions and high u-bend gap velocities existed in the bundle as compared to Mitsubishi FIT-III analyses used for design.

It's always obvious to close the barn door after the horse has got out.

but IMHO the old bureaucratic dodge of "just blame the vendor" isn't honest.
SCE needed to provide Mitsubishi any help they needed, even if they had to pay CE for some trade secrets and Westinghouse for some consulting.

That's my opinion.

Thanks guys for all the links and info

old jim
 
Last edited:
  • #48
jim hardy said:
It sure hurt the industry's image.

This article
https://s3.amazonaws.com/s3.documentcloud.org/documents/347889/col-nrc-tech-paper.pdf

describes an administrative process used by the utility to avoid some reviews of changes to the design.



That is a very useful shortcut for little things like replacing obsolete transistors or when a vendor changes his paint color.
But there's a fine line somewhere between parts replacement and redesign.

A little further down same article:


Scuttlebutt is that the high void fraction in that region gave less fluid damping than assumed so the tubes rattled more than expected.

Whether additional NRC review would have caught the design mistakes beforehand I don't know.
But they sure found them after the fact, around page 56 here:
http://www.nrc.gov/info-finder/reactor/songs/ML12188A748.pdf


It's always obvious to close the barn door after the horse has got out.

but IMHO the old bureaucratic dodge of "just blame the vendor" isn't honest.
SCE needed to provide Mitsubishi any help they needed, even if they had to pay CE for some trade secrets and Westinghouse for some consulting.

That's my opinion.

Thanks guys for all the links and info

old jim



This could have been done under 50.59...EVALUATION.

The SONGS 50.59 is available on the NRC website, and they claim that the RSGs are not adverse and can be changed under just a screening. They claim the only things that are adverse are the tech spec changes, but that the RSGs were not adverse to the design function of an SSC. Being familiar with the 'new' 50.59 rule, I have no idea why they would have thought this was ok...but o well.
 
  • #49
SONGS is certainly not the first unit to install RSGs under 50.59. Not saying I agree that that path is appropriate. In fact the first time I read a 50.59 screening for RSGs I was very surprised. But licensing types tend to emulate lawyers and thus place stock in precedents. Again, not saying I agree with that approach, either.

All that aside, I seriously doubt that the NRC would have "caught" anything had SCE done the change under a license amendment. The NRC is not a SG designer much less a manufacturer. there's a slim chance that they might have asked a question that would have led MHI to uncover the problem, but who knows?

In the end, I think beating SCE up over the 50.59 is a red herring. Old Jim is right, SCE should have had some input from Westinghouse née CE. The guys in Chattanooga know a few tricks.
 
  • #50
jim hardy said:
It sure hurt the industry's image.

This article
https://s3.amazonaws.com/s3.documentcloud.org/documents/347889/col-nrc-tech-paper.pdf

describes an administrative process used by the utility to avoid some reviews of changes to the design.
That is a very useful shortcut for little things like replacing obsolete transistors or when a vendor changes his paint color.
But there's a fine line somewhere between parts replacement and redesign.

A little further down same article:Scuttlebutt is that the high void fraction in that region gave less fluid damping than assumed so the tubes rattled more than expected.

Whether additional NRC review would have caught the design mistakes beforehand I don't know.
But they sure found them after the fact, around page 56 here:
http://www.nrc.gov/info-finder/reactor/songs/ML12188A748.pdfIt's always obvious to close the barn door after the horse has got out.

but IMHO the old bureaucratic dodge of "just blame the vendor" isn't honest.
SCE needed to provide Mitsubishi any help they needed, even if they had to pay CE for some trade secrets and Westinghouse for some consulting.

That's my opinion.

Thanks guys for all the links and info

old jim

Combustion Engineering's IP are owned by Westinghouse since ABB merged Westinghouse Nuclear Services and CE together.
 

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