Two Important Reports about Steam Generators at SONGS Go Public

Victor Dricks
Senior Public Affairs Officer
 

The NRC made public today redacted versions of two reports prepared by Mitsubishi Heavy Industries concerning the steam generator replacement at the San Onofre Nuclear Generating Station (SONGS).

The Steam Generator Root Cause Analysis Report and a Supplemental Technical Evaluation Report  were prepared by Mitsubishi Heavy Industries as part of its effort to determine what contributed to the unusual wear in the steam generators after they were installed in 2010 and 2011 at Units 2 and 3, respectively.

The NRC is using a variety of regulatory actions, such as inspections and investigations, to ensure that it is comprehensively addressing the issues that have arisen at the SONGS nuclear power plant.

On Sept. 28, 2012, the NRC began an expansive investigation on the completeness and accuracy of information that Edison provided to the NRC regarding the steam generator degradation under the NRC’s regulatory requirements.

These reports are included in an array of documents being reviewed by the NRC as we investigate whether Edison demonstrated sufficient due diligence in its oversight of the redesign of the steam generators; how design changes that were made or rejected may have affected the safety of the steam generators; and the truthfulness and accuracy of all the information Edison has provided to the NRC regarding the redesign and replacement of the steam generators.

Separately from the ongoing investigation, the NRC is evaluating Edison’s responses to questions the NRC has raised about their request to restart Unit 2 at the plant.

Additionally, the Atomic Safety and Licensing Board is reviewing issues related to the Confirmatory Action Letter issued by the NRC staff to Southern California Edison.

Author: Moderator

Public Affairs Officer for the U.S. Nuclear Regulatory Commission

46 thoughts on “Two Important Reports about Steam Generators at SONGS Go Public”

  1. Hello friends,
    I am glad to visit on this site.. Time will tell whether safety and people win, or power and money win in a democratic society, but truth always wins, may be at some undetermined expense.. Thanks for sharing all that great information..

  2. If they try to repair the problems and it does not work, who pays for it or if the repairs cause a new problem. Who will insure this change? Who will be responsible if it goes bad, will they be charged with murder if people die and pay for all damages. NO, they will not so they have no risk if it goes bad 10 or 20 years from now. This will turn into a one of a kind plant with unique problems that no one has seen or experienced before so the out come is questionable at best. The top group to blame will be the NRC(Public Money) no matter who else will be next. The public’s risk is above what they want to take for the possible gain. This is uncharted water with extreme consequences. STOP

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  4. Sincere Thanks to NRC Chairman, Mr. Victor Dricks, Mr. Cale Young, Mr. Ryan Lantz, Mr. Randy Hall and entire NRC Staff. Thanks to NRC posting this blog. San Onofre NRC/SCE/MHI/Public Awareness Series – by Hahn Baba

    Albert Einstein, “Insanity: doing the same thing over and over again and expecting different results.”

    NRC, INPO, CPUC, NEI and Scientists expect a responsible nuclear utility to supply safe and reliable power at a reasonable cost and not conduct unsafe experiments at the expense of public safety and charge ratepayers for its mistakes.

    First Strike – 1992 – Decaying generator tubes helped push San Onofre’s Unit 1 reactor into retirement in 1992, even though it was designed to run until 2004.

    Second Strike – 2001Power Uprate – To generate more power, Edison Engineers increased the steam flows and lowered the steam generator pressures, which increased vibrations, and shortened the life of Rate Payers Paid Original Steam generators.

    Third Strike – 2011 – SONGS Unit 3 – To generate more power, believing that Unit 3 anti-vibration structure was built better than Unit 2, Edison Engineers tested the new supports by increasing the reactor coolant flows, steam flows and lowered the steam generator pressures, which increased vibrations, and destroyed the Rate Payers Paid brand New Replacement Steam generators. Edison has said that because of manufacturing differences, Unit 2’s generators did not suffer the extent of deep tube wear witnessed in its sister plant. Unit 2 was not operating in the test mode and did not experience fluid elastic instability because of lower reactor coolant flows, lower steam flows and higher steam generator pressures. Unit 2 better supports and double the contact forces unproven theory is just a conjecture on the part of SCE/MHI based on hideous data, faulty computer simulations and an excuse to start defectively designed and degraded Unit 2. Unit 2 better supports and double the contact forces unproven theory is just a cheap SCE scheme to charge insurance money from MHI and more money from ratepayers. This bogus and unconvincing theory is contested and challenged based on the available plant data and review of Dr. Pettigrew’s research papers and testimony, John Large, MHI, Westinghouse and AREVA Reports.

    Fourth Strike – 2013 – Edison officials are also preparing long-range plans under which the plant might run for years, even though some of Edison’s own research has suggested tube damage could cut short its life span. Precise projections about the future are dependent on a restart — Edison engineers need to study how the reactor behaves at 70 percent power before being able to sharpen longer-range calculations. The plant could be started then shut down, as many as five times during a trial run to assess its operation and safety. “To propose an experiment in which the damaged reactor is repeatedly turned on and off shows a disgraceful contempt for public safety,” said Kendra Ulrich, a spokeswoman for the Friends of the Earth. Unit 2 restart without complete and thorough review by NRC Brilliant Engineers and Public Hearings on the basis of meeting peak summer electricity demands is an unapproved experiment and just a cheap SCE scheme to charge more money from ratepayers.

    Last Strike – Albert Einstein, “Any intelligent …. can make things bigger, more complex, and more ….. It takes a touch of genius — and a lot of courage — to move in the opposite direction.” Ted Craver needs to tell Ron, Pete, Tom, Rich, John, Mike, Vic, Doug and others to stop wasting NRC and Public’s time and money and award a turnkey contract to Westinghouse and Bechtel to repair or replace both Units Steam generators. This will be expensive, but wise for Ted, Ron, Pete, Tom, Rich, John, Mike, Vic, Doug and EIX/SCE shareholders, and will be in the best interests of NRC, INPO, NEI, Nuclear Industry, CPUC and the Public.

  5. Sincere Thanks to the Honorable NRC Chairman, Mr. Victor Dricks, Mr. Cale Young, Mr. Ryan Lantz, Mr. Randy Hall and entire NRC Staff. Thanks to NRC posting this blog. Best of Luck to Mr. Elmo Collins on his retirement. San Onofre NRC/SCE/MHI/Public Awareness Series – Courtesy of DAB Safety Team and SONGS Insiders by Hahn Baba

    Analysis of Draft SCE License Amendment

    Small tube bundles and void fractions less than 98.5% in 200 Mitsubishi designed Steam Generators for the last 20 years are responsible for no tube-to-tube wear. A review of the Mitsubishi Root Cause indicates that the normal tube bundle in Mitsubishi Steam Generators was purposely made taller in San Onofre Steam Generators by SCE to achieve 11% additional heat transfer to generate more heat and more profits in the pockets of EIX/SCE officers and Shareholders. SCE intentionally subverted the regulatory process. The fluid elastic instability or void fractions of 99.6% in Unit 3 were caused due to higher reactor coolant flows, high steam flows, high fluid velocities, high dry steam, narrow tube pitch to tube diameter, low tube-to-tube clearances, low frequency in-plane tubes, absence of positive in-plane vibration restraints, inadequate out-of-the-plane restraints design, and operation with low steam generator pressures and poor circulation ratios. These adverse effects destroyed SONGs Unit 3. By making the tube bundle taller without a 10CFR 50.90 License Amendment Process, Public Hearings and CPUC’s Blessings, SCE increased the average length of 9727 tubes by 7 inches each to gain additional 7% heat transfer area equivalent to 700 new tubes to generate 120 more thermal megawatts per Steam Generator. Everybody is under the impression that SCE added only 377 tubes, but in reality, SCE added a total of effective 1,077 tubes including 700 tubes by making the tube bundle taller than contemporary successful operating Mitsubishi steam generators. SCE response to NRC RAI #13, states, “The RSGs have more tubes (9,727 versus 9,350) than the OSGs and a smaller value for the maximum number of plugged tubes (779 versus 2,000). RSG tubes have a larger average heated length (729.56 in. versus 680.64 in.) than the OSG tubes. These features result in larger values for the RSG for heat transfer area, tube bundle flow area, and tube bundle water volume. This is beneficial in the short and long term for SBLOCAs, which rely upon the steam generators for RCS heat removal. “

    Unit 2 better supports and double the contact forces unproven theory is just a conjecture on the part of SCE/MHI based on hideous data and is contested based on the available plant data evidence and review of John Large, MHI and AREVA Reports. Because of the unique flawed SCE replacement steam generator design dictated by profits over safety, dominant San Onofre negative safety culture and Mitsubishi’s negligence and complacence, this analysis only applies to Unit 2 and Unit 3 replacement steam generators. No other Mitsubishi Steam Generators and NRC rules for Steam Generator Tube Integrity and NEI Steam Generator Management programs are affected or challenged at this time. The adverse effect of this change is 100% opposite of the benefit what SCE is telling the NRC and Public in RAI # 13 and as we witnessed in SONGS Unit 3. Here is why:

    1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?
    SCE Response: No Significant Hazards Consideration. There is no significant increase in the probability or consequences of an accident previously evaluated.

    Rebuttal: This adverse, unanalyzed and unapproved change involved more than a significant increase in the probability or consequences of a steam generator tube rupture leak due to 100% tube-to-tube wear in one tube in SONGS Unit 3, failure of 8 tubes at MSLB testing pressures and loss of >35% wall thickness in more than 300 tubes. This event was caused due to the unexplained SCE/MHI design changes in the Mitsubishi Root Causes Analysis and misrepresented by SCE in response to NRC RAI #13. What, SCE did not tell the public that besides the leaking tube, there were 2 other additional tubes with a loss of wall thickness > 99%. If these tubes would have also leaked and resulted in SG over-pressurization causing lifting of safety relief valves, operator would not have been able to diagnose, manipulate, control and shutdown the reactor in a timely fashion and SONGS so called Engineered Safety Systems would not have been able to keep with the SG tube rupture LOCA. This would have caused a potential reactor meltdown and Southern Californians in the 10-mile Plume Pathway Zone would have experienced a Fukushima, or Mihama Unit 1 in their Backyards depending upon the direction of the wind and freeway traffic conditions. San Onofre, Interjurisdictional Planning Committee, Offsite Dose Assessment Committee, FEMA, NRC, State of California and Offsite Agencies tested Emergency Plans are totally inadequate to shelter and evacuate the affected transients, families, children, sick and disabled residents in such an event.
    Therefore, the probability or consequences of these changes are/were more significant than analyzed by SCE in 10CFR 50.59 and seen by the destruction of SONGS Unit 3 than previously evaluated in the NRC Approved FSAR?

    2. Does the proposed change create the possibility of a new or different kind of an accident from an accident previously evaluated?
    SCE Response: No Significant Hazards Consideration. There is no possibility of a new or different kind of accident introduced because of this amendment

    Rebuttal: The requested SCE proposed License Amendment changes based on the false pretense of running defectively designed and degraded Unit 2 at 70% power to meet Peak Summer Month Power Loads significantly increase the possibility of an accident at normal steady state 70% power operations, during anticipated operational transients and a concurrent steam line break and consequential cascading tube ruptures due to fluid elasticity or high dry steam and jet impingement forces created as a result of 100% void fractions in the generator. Based on benchmarking of SONGS Unit 3, multiple tube leakages and/or ruptures are postulated due to 100% FEI in faulted and un-isolated (Assumed failure of MSIV to close) SG from a MSLB. Potential Collapse of floating AVB structure due to failure of low frequency retainer bars and high energy jet impingement can change multiple tube leakages and/or ruptures into cascading tube ruptures. Current NRC rules consider main steam line break and steam generator tube ruptures as independent events. In addition, steam generator tube ruptures are considered to be a slow occurring event with plant operator able to detect the leak and take timely action to safely shut down reactor. This accident scenario applies and is unique to SONGS RSGs because of design flaws in the degraded AVB structure and is considered beyond design basis event. Consistent with Three Mile Island, Chernobyl, Mihama Unit 1, Fukushima and David–Besse Lessons Learnt, Operators cannot be relied on to control the plant and emphasis for accident controls and risk mitigations should be on defense-in-depth plant safety features. SONGS plant does not have such beyond design basis accident defense-in-depth safety features.
    Therefore, the proposed changes create: (1) The distinct possibility of a new or different kind of an accident than accidents previously evaluated, and (2) Involves more than significant reduction in the margin of safety previously evaluated in the FSAR and approved by NRC.

    3. Does the proposed change involve a significant reduction in margin of safety?
    SCE Response: No Significant Hazards Consideration. There is no change with this LAR that involves a significant reduction in margin of safety
    Rebuttal: The proposed License Amendment change operating Unit 2 at 70% power for 5 months involves more than a significant reduction in margin of safety. This is because of the high potential of beyond design basis steam generator tube ruptures caused by a main steam line break resulting in a potential nuclear meltdown beyond operator control, lack of SONGS Defense-in-Depth Features, single equipment and consequential equipment failures, communication problems, sonic booms, radiation/steam environment and access control in accordance with NRC Fukushima Task Force Lessons Learnt and offsite releases exceeding the limits than previously analyzed in the FSAR ? This condition is unique and applicable only to SCE/MHI defectively designed and degraded Unit 2 replacement steam generators. Please see Items 1 & 2 above for details.

  6. Sincere Thanks to Mr. Victor Dricks, Mr. Cale Young, Mr. Ryan Lantz, Mr. Randy Hall and entire NRC Staff. Thanks to NRC posting this blog. San Onofre NRC/SCE/MHI/Public Awareness Series – Courtesy of DAB Safety Team

    Comparing Davis- Besse Nuclear Power Plant with San Onofre Unit 2
    Davis-Besse Nuclear Power Station is a nuclear power plant in Oak Harbor, Ohio. On March 5, 2002, maintenance workers discovered that corrosion had eaten a football-sized hole into the reactor vessel head of the Davis-Besse plant. Although the corrosion did not lead to an accident, this was considered to be a serious nuclear safety incident. Some observers have criticized the NRC’s Commission work as an example of regulatory capture [See Note 1] and the NRC has been accused of doing an inadequate job by the Union of Concerned Scientists. The Nuclear Regulatory Commission kept Davis-Besse shut down until March 2004, so that First Energy was able to perform all the necessary maintenance for safe operations. The NRC imposed its largest fine ever—more than $5 million—against First Energy for the actions that led to the corrosion. The company paid an additional $28 million in fines under a settlement with the U.S. Department of Justice. The NRC closely monitored First Energy’s response and concluded in September 2009 that First Energy met the conditions of the 2004 order. From 2004 through 2009 the NRC reviewed 20 independent assessments conducted at the plant and verified the independent assessors’ credentials. The agency also conducted its own inspections and reviewed First Energy’s reactor vessel inspections conducted in early 2005. NRC inspectors paid particular attention to the order’s focus on safety culture and safety conscious work environment to ensure there were no new signs of weakness. The NRC task force concluded that the corrosion occurred for several reasons:
    • NRC, Davis-Besse and the nuclear industry failed to adequately review, assess, and follow up on relevant operating experience at other nuclear power plants;
    • Davis-Besse failed to ensure that plant safety issues received appropriate attention; and
    • NRC failed to integrate available information in assessing Davis-Besse’s safety performance.

    Southern California Edison wants to restart unsafe Unit 2 nuclear reactor at 70% power under false pretenses, just for profits, and as an unapproved risky experiment by subverting the NRC and Federal regulatory process. The true Root Cause (See Note 2) of the unprecedented tube-to-tube wear in Unit 3 has NOT been established, as required by NRC Confirmatory Letter Action 1 for restarting the defectively designed and degraded Unit 2. NRC has not even completed their review of Unit 2 Return to Service Reports, nor have they finished Special Unit 2 Tube Inspections, nor have they (publicly?)reviewed SCE’s Response to NRC’s Requests for Additional Information (RAIs). Now, SCE wants the NRC to approve a new shady License Amendment, undermining public safety and do it without the involvement of Public Safety Experts/Attorneys and Citizens/Ratepayers. After the review of the Mitsubishi Root Cause Evaluation and the Draft SCE License Amendment, it is crystal clear that the NRC needs to follow the example of their own enforcement at David Besse together with the lessons learned from Fukushima, when it comes to approving this new Shady License Amendment for restarting San Onofre Unit 2’s defectively designed and degraded replacement steam generators. In light of the unanticipated/unprecedented tube leakage at SONGS 3, the health and safety, along with the economic concerns/objections of 8.4 million Southern Californians’ MUST OVERRIDE and PREVENT the restarting of Unit 2at 70% or ANY power level. In a Democratic Society, truth must prevail over profit motivations, misleading propaganda of electricity service disruption and/or projected probabilistic temporary inconveniences to the public based on phony data, because America cannot afford a trillion dollar nuclear eco-disaster!
    Notes:
    1: Regulatory capture occurs when a regulatory agency, created to act in the public interest, instead advances the commercial or special concerns of interest groups that dominate the industry or sector it is charged with regulating. Regulatory capture is a form of government failure, as it can act as an encouragement for firms to produce negative externalities. The agencies are called “captured agencies”.
    2. Human performance errors resulting from the negative safety culture of production (profits) goals overriding public safety obligations.

  7. Sincere Thanks to Mr. Victor Dricks, Mr. Cale Young, Mr. Ryan Lantz, Mr. Randy Hall and entire NRC Staff. Thanks to NRC posting this blog.
    San Onofre Billion Dollar Debacle SCE/MHI/NRC Lessons Learnt and Public Awareness Series – HAHN BABA
    songscommunity.com website states, “SCE’s own oversight of MHI’s design review complied with industry standards and best practices,” said Pete Dietrich, SCE senior vice president and chief nuclear officer. “SCE would never, and did not, install steam generators that it believed would impact public safety or impair reliability. In fact, MHI states in its root cause report (page 41), that its analysis of conditions in the steam generator during the design phase (which calculated void fraction and steam flow velocity) concluded that the thermal hydraulic conditions in the San Onofre steam generators were acceptable, and specifically that there was no need to reduce void fraction. Additionally, SCE never rejected a proposed design change to address void fraction based on its impact on compliance with 10 CFR 50.59. “At no time was SCE informed that the maximum void fraction or flow velocities estimated by MHI could contribute to the failure of steam generator tubes,” said Dietrich. “At the time, the design was considered sound.” SCE is disappointed that MHI decided on its own to redact some information in its evaluation about the flaws in the computer codes. However, the NRC publicly disclosed the computer code flaws three months before MHI completed its evaluation. In addition, the corrective actions and other statements included in the evaluation make it evident that there were problems with the computer modeling that failed to predict conditions that led to the tube-to-tube wear. SCE has proposed operating Unit 2 at 70 percent to decrease velocity and decrease steam dryness to increase damping, thus preventing the conditions that led to excessive wear. The proposed restart plan was validated using a different computer model and has been reviewed by independent experts.”

    Pete Dietrich has in the past an enviable management success, public relations and safety conscious work environment record. But now, instead of conducting a through in-house investigation of SCE Engineer’s role, he is trying to cover up SCE’s own grave mistakes, blaming everything on MHI to collect the insurance money by quoting ongoing NRC AIT investigation to justify his 2 Million Dollar a Year Edison Package. NRC AIT Team has not completed and finalized its investigation on computer modeling. SCE is blaming Senator Barbara Boxer, because Pete has not read and interpreted the MHI Root Cause carefully and correctly. Firstly, AVB Team consisted jointly of SCE and MHI Engineers, who knew what was going on with void fractions and the AVB Design. Secondly, NRC Report says that SCE Engineers did not check the work of MHI as required by SONGS Procedures. NRC Chairman has publically stated that SCE is responsible for the work of MHI and all its contractors. Thirdly, It is no longer a secret that SCE encouraged MHI to avoid NRC review of design changes under the false pretense of “like for like” in order to expedite the design, fabrication of replacement steam generators and profits. Even Elmo Collins said that the guts of the machine inside are completely different. According to former SONGS Manager, “All the design changes were made were for only one purpose to maximize the profits for EIX/SCE Officers, Shareholders and Investors and not Rate Payers. Pete Dietrich has zero public credibility.” Fourth, SCE/MHI Engineers claimed “solid teamwork and alignment” in a joint paper published by SCE and MHI Engineers. Fifth, Pete Dietrich, SONGS Chief Nuclear Officer said in Jan 10 2012, ”The plant’s largest components — steam generators — are just two years old and represent the safest, most efficient 21st century machinery [Source: Market Watch]. Sixth, SCE still does not understand concept of fluid elastic instability. ATHOS Models calculate out-of-plane velocities. The concept of in-plane velocities is new to nuclear industry and in-plane velocities at void fractions can be 2.5 times more than the out-of plane velocities. Therefore, the computer model used by Independent Experts, EPRI and NRC are outdated. Seventh, SCE/MHI AVB designed anti-FEI out-of-plane vibration bars do not provide positive restraint against in-plane vibrations, therefore, this concept of better supports and double tube-to-AVB contact forces in Unit 2 is a conjecture theory and conflicts with the findings of DR. Pettigrew, AREVA and latest research paper published in 2011, of which NRC San Onofre Special panel was provided a copy. Pete needs to real ascertain the facts before making irresponsible comments about MHI, Senator Barbara Boxer, NRC AIT Team and Environmentalist Groups. This behavior is inconsistent with his past performance and will lead to exit like Ross Ridenoure, who abruptly resigned, because the Senior Leadership Team he appointed did not perform. Pete has still the same inefficient, profit motivated and retaliating Senior Leadership Team.

  8. Sincere Thanks to Mr. Victor Dricks, Mr. Cale Young, Mr. Ryan Lantz, Mr. Randy Hall and entire NRC Staff. Thanks to NRC posting this blog. San Onofre Billion Dollar Debacle SCE/MHI/NRC Lessons Learnt and Public Awareness Series – HAHN BABA

    songscommunity.com website states, “SCE’s own oversight of MHI’s design review complied with industry standards and best practices,” said Pete Dietrich, SCE senior vice president and chief nuclear officer. “SCE would never, and did not, install steam generators that it believed would impact public safety or impair reliability. In fact, MHI states in its root cause report (page 41), that its analysis of conditions in the steam generator during the design phase (which calculated void fraction and steam flow velocity) concluded that the thermal hydraulic conditions in the San Onofre steam generators were acceptable, and specifically that there was no need to reduce void fraction. Additionally, SCE never rejected a proposed design change to address void fraction based on its impact on compliance with 10 CFR 50.59. “At no time was SCE informed that the maximum void fraction or flow velocities estimated by MHI could contribute to the failure of steam generator tubes,” said Dietrich. “At the time, the design was considered sound.” SCE is disappointed that MHI decided on its own to redact some information in its evaluation about the flaws in the computer codes. However, the NRC publicly disclosed the computer code flaws three months before MHI completed its evaluation. In addition, the corrective actions and other statements included in the evaluation make it evident that there were problems with the computer modeling that failed to predict conditions that led to the tube-to-tube wear. SCE has proposed operating Unit 2 at 70 percent to decrease velocity and decrease steam dryness to increase damping, thus preventing the conditions that led to excessive wear. The proposed restart plan was validated using a different computer model and has been reviewed by independent experts.”

    Pete Dietrich of SCE is crying over SCE’s grave mistakes and blaming everything on MHI to collect the insurance money by quoting hastily conducted and ongoing NRC AIT investigation and justify his own 2 Million Dollar a Year Edison Package. NRC AIT Team has not completed and finalized its investigation on computer modeling. SCE has not interpreted the MHI Root Cause carefully and correctly. Firstly, AVB Team consisted jointly of SCE and MHI Engineers, who knew what was going on with void fractions and the AVB Design. Secondly, NRC Follow-up AIT Report says that SCE Engineers did not check the work of MHI as required by SONGS Procedures. NRC Chairman has publically stated that SCE is responsible for the work of MHI and all its contractors. Thirdly, It is no longer a secret that SCE encouraged MHI to avoid NRC review of design changes under the false pretense of “like for like” in order to expedite the design, fabrication of replacement steam generators and profits. Even Elmo Collins said that the guts of the machine inside are completely different. All the design changes were made were for only one purpose to maximize the profits for EIX/SCE Officers, Shareholders and Investors and not Rate Payers. Fourth, SCE/MHI Engineers claimed “solid teamwork and alignment” in a joint paper published by SCE and MHI Engineers. Fifth, Pete Dietrich, SONGS Chief Nuclear Officer said in Jan 10 2012, ”The plant’s largest components — steam generators — are just two years old and represent the safest, most efficient 21st century machinery [Source: Market Watch]. Sixth, SCE still does not understand concept of fluid elastic instability. ATHOS Models calculate out-of-plane velocities. The concept of in-plane velocities is new to nuclear industry and in-plane velocities at void fractions of 99.6% can be 2.5 times more than the out-of plane velocities. Therefore, the results of computer model calculated by Independent Experts, EPRI and NRC are outdated and incorrect. Seventh, SCE/MHI AVB designed anti-FEI out-of-plane vibration bars do not provide positive restraint against in-plane vibrations, therefore, this concept of better supports and double tube-to-AVB contact forces in Unit 2 is conjecture, based on hideous data and conflicts with the findings of DR. Pettigrew, AREVA and latest research paper published in 2011, of which NRC San Onofre Special Panel was provided a copy.

  9. We apologize for the delay in posting this comment. We asked our allegations staff to review it first. Once they cleared it, we were able to post it.

    Moderator

  10. Sincere Thanks to Mr. Victor Dricks, Mr. Cale Young, Mr. Ryan Lantz, Mr. Randy Hall and entire NRC Staff.
    Thanks to NRC posting this blog. San Onofre Billion Dollar Debacle SCE/MHI/NRC Lessons Learnt and Public Awareness Series – HAHN BABA – Please see the previous blog – The following analysis is applicable to San Onofre Units 2 & 3, unless proven otherwise by NRC

    Conclusions: Steam generator tubes have a very important safety role because they constitute one of the primary barriers between the radioactive and non-radioactive sides of the plant. For this reason, the integrity of the tubing is essential in minimizing the leakage of water between the two “sides” of the plant. There is the potential that if a tube bursts while a plant is operating, radioactivity from the primary coolant system – the system that pumps water through the reactor core – could escape directly to the atmosphere in the form of steam. Steam generators designers, specification writers and manufacturers have a fiduciary duty to the public and NRC to continuously keep up with the experimental academic research and industry benchmarking pertaining to steam generator tube vibrations during design, manufacturing and testing of steam generators.

    The MHI-supplied replacement SGs (RSGs) had a number of differences from the OSGs provided by Combustion Engineering. One of the main differences was the substitution of Inconel 690 for Inconel 600 as the tube material. Inconel 690 is more resistant to corrosion than Inconel 600. However, Inconel 690 has a thermal conductivity approximately 10% less than that of Inconel 600. The requirement that the SG’s thermal performance be maintained, in conjunction with maintaining a specified tube plugging margin, necessitated increasing the tube bundle heat transfer surface area from 105,000 ft2 to 116,100 ft2 (an 11% increase).The Certified Design Specification SO23-617-01, Rev. 3 stated that SCE intended to use the provisions of 10 C.F.R. §50.59 as the justification for the RSG design, which imposed physical and other constraints on the characteristics of the RSG design in order to assure compliance with that regulation. The RSGs were also required to fit within the same space occupied by the OSGs. The Certified Design Specification issued by SCE also required that MHI incorporate many design changes to minimize degradation and maximize reliability. The fundamental problem was created by the addition of 11% heat transfer surface area (to maintain the same level of thermal performance of 1729 thermal megawatts as OSGs) and high void fraction of 99.6% in the replacement steam generators (RSGs). Reducing the high void fraction of 99.6% would have meant increasing the circulation ratios and reducing the thermal megawatts in the RSGs and profit margins for SCE. If both SCE and MHI would have kept up with experimental academic research and industry benchmarking, they could have foreseen the adverse safety consequences of not making these changes, as we saw what happened to the RSGs. Instead, they rejected these changes by stating, “But each of the considered changes had unacceptable consequences and the AVB Design Team agreed not to implement them. Among the difficulties associated with the potential changes was the possibility that making them could impede the ability to justify the RSG design under the provisions of 10 C.F.R. §50.59. An analysis of the cumulative effects of the design changes including the departures from the OSG’s design and MHI’s previously successful designs would not have resulted in a design change that directly addressed in-plane FEI.”

    When a NEI Qualified, “US Nuclear Plant Designer” like MHI issues public statement and a Root Cause analysis stating, “The underlying reason for this insufficiency is that the MHI SONGS RSG design did not consider the phenomenon of in-plane FEI because contemporary knowledge and industry U-tube SG operation experience did not indicate a need to consider in-plane FEI”, that is a blatant violation of the US Federal Regulations and Public Trust. Furthermore, it is an admission of negligence, and an insult to manufacturers like Westinghouse/Combustion Engineering ant its subcontractors, who build the largest 6 CE replacement generators with the highest steam flows in the world for Palo Verde in 2000 and resolved the problems with Palo Verde Original CE Steam Generators by a combination of design and operational changes. These generators are running fine for more than 8 years with very few reported problems.

    Based on a review of Item 1, paragraph A through F, HAHN BABA concludes that SONGS Unit 3 RSG AVB restraints were built better than Unit 2 and in conformance with defective SCE specifications. The MHI “effective zero gap” and AVB restraint assembly design concept was effective only against “out-of-plane FEI”. Unit 3 in-plane FEI occurred prior to the out-of-plane FEI, because of high void fractions and high steam flows. However, the MHI designed tube-to-AVB contact force in 2005 to provide restraint in the in-plane direction were ineffective against the required undetermined tube-to-AVB contact forces to generate friction that was necessary to inhibit the large in-plane tube displacements due to more than the double the in-plane velocities than the out-of plane velocities created by void fractions of 99.6%. The high void fractions were created due to very high Unit 3 steam flows, narrow tube pitch to diameter ratio, low tube clearances and a very tall tube bundle. The way the RSGs tube bundle and restraint system was designed (to accommodate extra 11% heat transfer area by change of Tube Alloy Material and RSGs physical restraints imposed at the request of SCE), the untested and unanalyzed out-of-plane FEI restraint system was incapable of restraining in-plane movements created by void fractions of 99.6% or higher irrespective of the zero gaps, small gaps or amount of contact forces generated by the restraint system in the hot and pressurized conditions. The double the Tube-to-AVB contact forces, better supports in Unit 2 created due to manufacturing difference compared with Unit 3 Tube-to-AVB insufficient contact forces, loose supports based on statistical simulations, visual observations and ECT results/ding signals is a conjecture on part of SCE/MHI, because FEI did not occur in Unit 2 based on SONGS Procedures and Westinghouse Operational Assessment. Based on results of NRC AIT reports/inspections, it does not appear that MHI has the skills, technology or tools to build a new anti-vibration restraint system in 2013 for San Onofre RSGs capable of handling FEI at RSGs 100% RTP of 1729 MWts. No wonder, SCE/MHI AVB team could not have done it in 2005?

    SCE/MHI states, “Tube wear patterns similar to those observed at SONGS Unit 2 were reported at the St. Lucie Unit 2 large U-bend steam generators that were replacements for CE manufactured OSGs. St. Lucie Unit 2 steam generators were designed by AREVA.” According to Professor Daniel Hirsh, “NRC’s Advisory Committee on Reactor Safety concluded that the St. Lucie 2 tube wear is “different than the form of degradation reported to have occurred at San Onofre. There are a number of design differences between the SGs installed at San Onofre and those at St Lucie 2. Thus, the problems at St. Lucie 2 are not standard “settling in” but due to a serious manufacturing error and unrelated to San Onofre’s problems. It shows you that the SCE/MHI are making misleading statements to confuse NRC/Public and justify restart of damaged Unit 2 with hundreds of damaged and plugged/staked tubes in Unit 2 and an anti-vibration structure not designed for FEI. This damaged anti-vibration structure will most likely collapse during a MSLB due to 100% FEI, flashing feedwater and cause cascading tube ruptures resulting in a nuclear meltdown with devastating radiological effects for Southern California like Fukushima.

    HAHN Baba has shown you previously, that Unit 2 and Unit 3 RSGs had different operating and thermal hydraulic conditions causing FEI in Unit 3 and No FEI in Unit 2. These conclusions were based on the operating data from SONGS procedures, which is consistent with the data shown in the NRC AIT Report. No FEI in occurred in Unit 2, which is consistent with Westinghouse Operational Assessment. I have discussed in detail previously the impact of FEI, or tube-to-tube wear in Unit 3 and why it happened. To summarize, due to higher RCS pump flows, Unit 3 RSGs were producing 10 MWt more than Unit 2 (1737 MWt versus 1727 MWt) and only 2.5 MWt was required to raise the void fractions from 98.5 to 99.6% in the hot leg side high region of the wear to cause FEI in Unit 3. Unit 2/3 RSGs are rated for 1729 MWt with an instrument error of plus minus 0.58%, meaning if there is a calibration error, RSGs could be actually producing between 1719-1739 MWt. Therefore higher 2.5 MWt in unit 3 is within the upper bound tolerance limit of the instrument error and is consistent with higher Unit 3 RCS flows. This pattern is also consistent with the electricity generation records based on the generator outputs for Units 2 & 3 (SONGS Plant Daily Brief Sheets, Unit 3, 1186 MWt, Unit 2, 1183 MWt, Internet Survey, Unit 3, 1178 MWt, Unit 2, 1172 MWt). It is further assumed, that the balance of 7.5 MWt increased the void fractions in the entire Unit 3 U-tube bundle between 98.5 and 99% increasing the intensity of flow-induced random vibrations, fluid velocities and hydrodynamic pressures compared with Unit 2.

    SCE and MHI consistently has stated in various reports, that thermal-hydraulic conditions [high steam flows, higher void fractions (99.6%), maximum steam quality (87.6%), higher fluid velocities (28 ft/sec), Maximum Dynamic Pressure (4140 N/m2)] in all the RSGs were the same. MHI states that an explanation for the difference severe damage due to FEI in Unit 3 can be attributed to the manufacturing assessment, which concluded that the tube to AVB contact forces in Unit 3 were less than half those in Unit 2. NRC AIT Team states, “The result of the independent NRC thermal-hydraulic analysis indicated that differences in the actual operation between units and/or individual steam generators had an insignificant impact on the results and in fact, the team did not identify any changes in steam velocities or void fractions that could attribute to the differences in tube wear between the units or steam generators.”

    I along with and DAB Safety Team and their Expert Panel have discussed the fallacies and inconsistencies of SCE/MHI/NRC AIT Reports in numerous NRC Blogs, San Onofre Papers, Press Releases and Media Reports. Today, for the benefit of NRC Staff, 8.4 Million Southern Californians, various Congressional Committees, and Other/Independent Experts, I will summarize and clarify again the following subjects:
    1. Tube to Tube Wear due to in-plane FEI – See Below
    2. Tube to AVB Wear (for tubes without free span wear) due to random vibration –To be continued in the NRC Blog
    3 Wear at the TSPs (small bend radius tubes and tubes at the tube bundle periphery) –To be continued in the NRC Blog
    4. Retainer Bar to Tube Wear due to Flow Induced Vibration–To be continued in the NRC Blog
    5. St. Lucie Steam Generators and other topics … To be continued in the NRC Blog

    1. San Onofre Unit 3, Tube to Tube Wear due to in-plane FEI – In-plane FEI in Unit 3 had no precursor, which is based on a review of NRC AIT, MHI, SCE, Westinghouse, AREVA and John Large’s Reports and is summarized below:

    A. Type 1, tube-to-tube wear occurs when there is tube in-plane motion (vibration) with a displacement (amplitude) greater than the distance between the tubes in the adjacent rows, resulting in tube-to-tube contact. Some of the tubes with tube-tube wear did not experience large amplitude vibrations, but were damaged by tubes that did experience large amplitude vibrations. These tubes also exhibited significant wear at the AVBs and TSPs in addition to the free-span wear. The Type 1 wear pattern was found in the tube free-span sections between or crossing over the AVBs. Type 1 wear can be differentiated from the Type 2 wear by its location on the circumference of the tube. Type 2 wear is located on the sides of the tube that are adjacent to the AVBs while Type 1 wear is located on the extrados or intrados of the tube (the top or bottom of the tube cross section). Type 1 and Type 2 wear can be distinguished from each other by rotating ECT. 160 tubes in each steam generator in Unit 3 with long free-span indications were similar to that found on the leaking tube. The tubes containing the free-span indications were grouped together in a tightly packed zone near the center of the tube bundle. More than half of the free-span indications in each steam generator had maximum measured depths exceeding the 35 percent plugging limit in the technical specifications, and ranged to as much as 99 percent (for the non-leaking tubes).

    B. Tubes move in synchronous oval orbits, with a major in-plane component and a minor out-of-the plane component. Tubes are assumed to have mostly moved in the in-plane direction because of the observed locations and magnitudes of their wear scars. The wear scars indicate that the tubes were generally vibrating in their first fundamental in-plane mode, which implies that none of the twelve (12) AVB supports were capable of restraining the tube motion. However, either the tubes were not touching the AVBs because of the small out-of-the plane movement, or wear scars at AVB locations may have been too shallow to be evaluated properly and that possible undetected TTW would be less than 5 %TW.

    C. Based on Dr. Pettigrew’s (2006) and other research papers published in 2011, at the start of the U-bend SGs, the in-plane FEI critical velocity can vary 2.0-2.7 times more than the out-of-plane FEI critical velocity. In 2006 during the early design stages of the San Onofre RSGs, Dr. Pettigrew warned about the ineffectiveness of flat bars against in-plane vibrations. He said in 2013 again that San Onofre RSGs do not provide a positive restraint against in-plane vibrations. AREVA states, “After instability develops, the amplitude of in-plane motion continuously increases and the forces needed to prevent in-plane motion at any given AVB location become relatively large. Hence shortly after instability occurs, U-bends begin to swing in Mode 1 and overcome hindrance at any AVB location”

    D. While the number of tubes with tube-to-AVB wear without in-plane TTW is greatest at the top of the tube bundle, the number of TTW tubes with tube-to-AVB wear is almost uniformly distributed along the different AVB intersections. If random vibration wear were a precursor for in-plane FEI TTW, then the pattern of AVB wear for TTW tubes should resemble the tube-to-AVB wear pattern (i.e. be concentrated at the top of the tube bundle). However, this is not observed for tubes with TTW.

    E. While the tube-to-AVB wear depth for tubes without in-plane TTW is greatest at the top of the tube bundle, the tube-to-AVB wear depths for tubes with in-plane TTW is almost uniformly distributed along the AVB intersections. If random vibration wear were a precursor for in-plane FEI wear, then the AVB wear for the tubes with in-plane FEI would be greatest at the top of the U-bends. But for TTW tubes, the average wear depth is almost the same in all AVB support locations and there is no tendency to concentrate at the top of the tube bundle.

    F. The average 10% of AVB wear depth in Unit 2 and Unit 3 excluding TTW tubes is almost the same. Therefore, if random vibration were a precursor to in-plane FEI one would expect to see a similar number of tubes with tube-to-tube wear in the two RSG units.

    G. The primary source of tube-to-AVB contact forces is the restraint provided by the retaining bars and bridges, reacting against the component dimensional dispersion of the tubes and AVBs. Contact forces are available for both cold and hot conditions. Contact forces significantly increase at normal operating temperature and pressure due to diametric expansion of the tubes and thermal growth of the AVBs.

    H. There are several potential manufacturing considerations associated with review of the design drawings based on Westinghouse experience. The first two are related to increased proximity potential that is likely associated with the ECT evidence for proximity. Two others are associated with the AVB configuration and the additional orthogonal support structure that can interact with the first two during manufacturing. Another relates to AVB fabrication tolerances. These potential issues include:
    • The smaller nominal in-plane spacing between large radius U-bend tubes than comparable Westinghouse experience.
    • The much larger relative shrinkage of two sides (cold leg and hot leg) of each tube that can occur within the tubesheet drilling tolerances. Differences in axial shrinkage of tube legs can change the shape of the U-bends and reduce in-plane clearances between tubes from what was installed prior to hydraulic expansion.
    • The potential for the ends of the lateral sets of AVBs that are attached to the AVB support structure on the sides of the tube bundle to become displaced from their intended positions during lower shell assembly rotation.
    • The potential for the 13 orthogonal bridge structure segments that are welded to the ends of AVB end cap extensions to produce reactions inside the bundle due to weld shrinkage and added weight during bundle rotation.
    • Control of AVB fabrication tolerances sufficient to avoid undesirable interactions within the bundle. If AVBs are not flat with no twist in the unrestrained state they can tend to spread tube columns and introduce unexpected gaps greater than nominal inside the bundle away from the fixed weld spacing.
    • The weight of the additional support structure after installation could accentuate any of the above potential issues. There is insufficient evidence to conclude that any of the listed potential issues are directly responsible for the unexpected tube wear, but these issues could all lead to unexpected tube/AVB fit-up conditions that would support the amplitude limited fluidelastic vibration mechanism. None were extensively treated in the SCE root cause evaluation.

    I. AVB assembly, which features strongly in the onset of TTW, is clearly designed to cope only with out-of-plane tube motion since there is little designed-in resistance to movement in the in-plane direction – because of this, it is just chance (a virtually random combination of manufacturing variations, expansion and pressurization, etc.) that determines the in-plane effectiveness of the AVBs.

  11. Mr. Greene:

    Robust, proven designs and conservative operation of steam generators have historically prevented severe vibrations from occurring. NRC regulations do have requirements associated with maintaining the reactor coolant system pressure boundary, including steam generator tubes. Per the Standard Review Plan, rapid wear mechanisms are not allowed to occur, including designing against fluid elastic instability. As part of the design process, SCE and MHI did conduct numerous engineering calculations, including modeling, that at the time showed no concerns with abnormal vibration and no threat of damage to the reactor coolant pressure boundary. The technical specifications require SONGS (as well as all other pressurized water reactors) to conduct periodic inspections of the steam generator tubes. These inspections are done to identify and minimize any chemical or mechanical wear issues that could lead to loss of tube integrity. As part of the NRC’s review of the SONGS steam generator tube leak, the NRC is and will continue to look at changes to existing requirements.

    Victor Dricks

  12. It is great that the NRC is allowing folks to post very technical comments on these blogs, especially since they are concerning SAFETY.

    What would even be better is if different people within the NRC, the NRR and or the ACRS actually posted comments about these technical comments, if only to say Thank You, because it is obvious that “SOME” experts are NOT charging (the NRC) the same hourly rate* of $274, (soon to become $277) for their time that the NRC now charges!

    * https://public-blog.nrc-gateway.gov/2013/03/14/looking-to-hear-from-the-public-on-the-fy-2013-proposed-fees/comment-page-1/#comment-82259

  13. Sincere Thanks to Mr. Victor Dricks, Mr. Cale Young, Mr. Ryan Lantz, Mr. Randy Hall and entire NRC Staff.

    Thanks to NRC posting this blog. San Onofre Billion Dollar Debacle SCE/MHI/NRC Lessons Learnt and Public Awareness Series – HAHN BABA responding to Operational Differences between Units 2 & 3, impact on to SCE CAL ACTION 1 and SCE’s new attempt to seek License Amendment for San Onofre Nuclear Plant Unit 2 – The following analysis is applicable to Unit 2 operation between 70 to 100% power.

    Analysis/Conclusions: As shown below, approximately 34 Million Btu/hour extra heat was produced in Unit 3 RSGs due to higher Unit 3 RCS flows. Approximately 8 Million Btu/hour heat was probably consumed to produce the fatal 99.6 % void fraction steam in hot leg high region of wear and the remainder 26 Million Btu/hour was potentially rejected by the superhot steam generator tubes due to absence of water on tubes and conditions not conducive to nucleate boiling. This extra heat because of reduction in heat transfer coefficient was potentially returned to cold leg. That is why, probably (?) NRC Report stated, “It was noted that Unit 3 ran with slightly higher primary temperatures, about 4˚F higher than Unit 2.” 34 Million Btu/hour extra heat was available in Unit 3 due to operational differences between Unit 2 & 3. This 34 Million Btu/hour extra heat was much more than amount of heat required (7,924,800 Btu/hour) for raising the void fraction of steam-water mixture to 99.6% to cause FEI in a very small area Unit 3 RSGs (160 tubes experienced TTW out of 9727 tubes). So FEI happened in Unit 3, because of operational differences between Units 2 & 3, numerous untested and unanalyzed design changes to increase 11 % heat transfer area in RSGs and Billion Tons of human performance errors. FEI did not happen in Unit 2 because of what the operating data shows or something else, NRC/NRR Experts (not Region IV NRC AIT Team) will come up a definitive and clear answer to prevent recurrence of this type of Potential Public Safety Fukushima Mistakes. Since SCE and MHI are coming up every day with wrong conclusions and theories to bury their past grave mistakes as customary and restart Unit 2, NRC thermo-hydraulic experts need to figure out exactly what happed? The NRC AIT Report conclusions are unacceptable, because it states, “The result of the independent NRC thermal-hydraulic analysis indicated that differences in the actual operation between units and/or individual steam generators had an insignificant impact on the results and in fact, the team did not identify any changes in steam velocities or void fractions that could attribute to the differences in tube wear between the units or steam generators.” This analysis is consistent with Dr. Pettigrew’s Research Paper published in 2006 and his statements in 2013 regarding SONGS RSG AVB Design, AREVA’s Operational, John Large’s and Arnie Gundersen’s Assessments, SONGS Root Cause Members Statements and SONGS Operational Data. SCE/MHI have not determined the exact root cause of the tube-to- tube wear in Unit 3 per CAL ACTION 1, and have not implemented actions to prevent the loss of tube-to-tube wear and demonstrated via a deterministic safety analysis that the AVB structural integrity in the Unit 2 steam generator will be maintained (e.g., Collapse of AVB structure and failure of retainer bars will not occur due to 100% FEI, FIRV and MFE in entire SG U-tube bundle) during a Main Steam Line Break (e.g., Mihama, Turkey Point, Robinson), Station Blackout (Fukushima), SG Tube Ruptures ( Mihama, SONGS 3 & 20 other Incidents in US/Europe in the last 20 years) and other anticipated operational transients (stuck open main steam safety valves). It is worthy to note that nuclear power plants have spent billions of dollars in designing, installing and maintaining protective restraints to protect against adverse consequences of steam line breaks throughout the power plant.

    SCE is unyielding, adamant and persistent to Restart Unit 2 at any cost and keeps on giving the safety message, “If Intertek PRA calculations are incorrect or are not conservative, so what, then , “The differential pressure across the SG tubes necessary to cause a rupture will not occur if operators prevent RCS re-pressurization in accordance with Emergency Operating Instructions.” The Operators, If Southern Californians are lucky a third time (First Time, SONGS 3 Tube Leak with 8 tube Failures, 2nd time, a tube with 90% Unit 2 Retainer Bar wear was not publicly announced and Unit 2 was shutdown due to refueling outage before the leak became a reality like Unit 3), can deal with one tube rupture, but not many simultaneous tube ruptures as we observed in SONGS Unit 3. Restart of Unit 2 is a potential road leading to Fukushima, to which the NRC Regulators need to pay very careful attention to fulfill their public safety charter mission and duty despite SCE/Industry Pressures and Anonymous Pressures. Now SCE is making a mockery of the public safety, nuclear industry and NRC rules by seeking License Amendment for San Onofre Nuclear Plant Unit 2 because, “The San Onofre nuclear plant is the largest source of base-load generation and voltage support in the region and is a critical asset for reliability and in meeting California’s clean energy goals.” The bottom line is that if SCE wants to stay as a base-load generation and voltage support in California and does not want to cause another nuclear accident, it needs to award a sole source contract to Westinghouse to rebuild both San Onofre Units 2 & 3, because MHI and AREVA do not have the skills, tools and technology to build complex CE Replacement Generators as witnessed by tube wear in SONGS and St. Lucie 2 and successful operation of Palo Verde Units 1, 2 & 3 CE RSGs.

    Consistent with MHI and Westinghouse, High Heat flux in the hot leg region of Unit 3 tube-to-tube wear due to extra heat combined with narrow pitch tube to diameter ratio and extremely tall tube bundle exceeded the critical heat flux. This high heat caused void fraction of 99.6%, created in-plane velocities > 50 feet/sec and excessive hydrodynamic pressures (Mitsubishi Flowering Effect) in a very small portion (0016%) of the Unit 3. The only known flow induced vibration mechanism capable of producing large tube displacements, and in a contiguous group like that of the Unit 3 RSGs, is fluid elastic instability, high dry steam or tube dry-outs. Due to above adverse conditions, large U-bends in Unit 3 pushed the AVBs out of their way and produced large displacements of tubes in the in-plane direction. Tubes moved in the in-plane direction with large amplitudes. Tubes were generally vibrating in their first fundamental in-plane mode, which implies that none of the twelve (12) AVB supports were restraining the tube motion. Yet, it also indicates that the tube-to-AVB gaps are very small and uniform, because none of the tubes exhibited out-of-plane FEI, which is the tube’s preferential fluid elastic vibration mode. Since out-of-plane FEI did not occur in Unit 3 and instead only in-plane FEI occurred, it is concluded that the out-of-plane support conditions for the TTW tubes were active (as designed). This leads to the conclusion that the Unit 3 RSGs 24 tube-to-AVB intersections (AVB on both sides of a tube with 12 locations) have gaps small enough to be effective in the out-of-plane direction, but there were no positive restraints in the-plane direction. Therefore, there were zero tube-to-AVB contact forces to prevent in-plane tube displacement.

    Notes, Observations and Assumptions:
    1. Researchers have said long ago that nucleate boiling on the tube surfaces has a stabilizing damping effect to preclude fluid-elastic instability. At least 1.5 % water or void fraction less than 98.5% in a steam-water mixture and areas without localized tube dry-out conditions are required in a nuclear steam generator to preclude the onset of fluid elastic instability. A review of NUREG-1841 published during the SCE/MHI design stages of San Onofre Replacement Steam Generators indicates that innovative and experienced manufacturers of steam generators (like Westinghouse/CE & BW&I) including with very high steam flows such as the largest steam generators in the world (e.g., Palo Verde) have used a combination of design and operational features [(high circulation ratios(>4), high steam pressures (> 900 psi) and low friction losses] to keep the void fractions at 98.5% or below and have prevented localized tube dry-out conditions and steam blanketing in operating US Steam Generators.
    2. A review of the SONGS Power Generation and Supply Records on the internet and SONGS Plant Daily Brief Sheets confirms that SONGS Unit 3 SGs have historically generated more reactor thermal power than Unit 2 SGS because of higher Unit 3 RCS flows, which is consistent with SONGS Procedures and interpretation of NRC AIT and Westinghouse Operational Assessment reports.
    3. These preliminary and qualitative calculations are performed for the benefit of NRC Thermal-Hydraulic Experts as a tip to determine the exact root cause for differences between Units 2 & 3. The calculations are based on limited operational data and observations, and NRC Thermal-Hydraulic Experts need to obtain 9 Months data shown below from SCE for 2011 for Units 2 & 3 to arrive at unanimous and clear conclusions. If SCE does not have the data tabulated, NRC Thermal-Hydraulic Experts can accept the computer-generated data & charts by plant monitoring system (PMS), the core operating limit supervisory system (COLSS), backup computer system (CBCS), Crossflow UFM & UTM Systems and Control room Electronic Logs in lieu of the following data.
    • Reactor Thermal Power, MWt
    • Reactor Coolant Flow (at cold leg temperature), Million lbs./hour
    • Reactor Coolant Operating Temperature (Thot), degrees F
    • Reactor Coolant Operating Temperature (Tcold), degrees F
    • RSG Operating Pressure (@100% power), psi
    • Steam mass flow rate, Million lbm/hr
    • Feed-water mass flow rate, Million lbm/hr
    • Blow-down mass flow rate, Million lbm/hr
    • Steam quality at the outlet of SG, fraction
    •Feed-water temperature 0F
    • Feed-water pressure, psi
    • RSG Circulation Ratio
    A. SONGS Operational Data, Design Assumptions and Trend Calculations:
    A.1 – Feed-water Operating pressure is assumed to be 50 psi higher than Steam Operating pressure based on input from the SONGS Senior Shift Manager.
    A.2 – The difference in Reactor Coolant Specific Heat between Units 2 & 3 due to minor RCS temperature variation assumed to be negligible. Since the feed water blow down rate is common for Units 2 & 3, its effect on this calculation has no bearing.
    A.3 – NRC AIT Report (7/18/2012) pages 22 & 23 state, “Operational Differences: The team performed a number of different thermal- hydraulic analysis of Units 2 and 3 steam generators. The output of the various analyses runs where then compared and reviewed to determine if those differences could have contributed to the significant change in steam generator tube wear.
    • It was noted that Unit 3 ran with slightly higher primary temperatures, about 4˚F higher than Unit 2. Other differences were noted in steam and feedwater flow but none of the differences were considered sufficient to significantly affect thermal hydraulic characteristics inside the steam generators. The different analyses included:
    • Lower bounding thermal hydraulic analysis using the steam generator base design condition, where primary inlet temperature was 598˚F, and an upper bound case where primary inlet temperature was 611˚F as identified in Mitsubishi Document L5-04GA021, Revision 3
    • Varying steam generator pressures from 833 to 942 psi
    • Steam mass flow rates from 7.59 to 7.62 Mlbm/hr
    • Primary loop volumetric flow rate from 102,000 to 104,000 gpm, and
    • Recirculation ratio from 3.2 to 3.5.
    The result of the independent NRC thermal-hydraulic analysis indicated that differences in the actual operation between units and/or individual steam generators had an insignificant impact on the results and in fact, the team did not identify any changes in steam velocities or void fractions that could attribute to the differences in tube wear between the units or steam generators. It should be noted that increases in primary temperature and steam generator pressures has the effect of reducing void fractions and peak steam velocities, which slightly decreases the conditions necessary for fluid elastic instability and fluid-induced vibration.”
    A.4 – Ratio of Reactor Thermal Power Ratio between Units 3 and 2 = [Unit 3 (79.79 X 56.7)]/[Unit 2 (75.76 X 58)] = 1.03 (See Notes below)
    NOTES:
    a. Unit 3 RCS Flow – 79.79 Million lbs/Hour – SONGS Unit 3 RCS Flow per SONGS procedure, used 104,000 gpm value for Unit 3 from NRC AIT Report and Westinghouse Operational Assessment, Attachment 6D, Table 2-7, page 37 (Same Value Reported for Units 2 & 3)
    b. Unit 3 RCS Temperature Difference between Hot and Cold Legs – 56.7 degrees F – per SONGS procedure and Westinghouse Operational Assessment, Attachment 6D, Table 2-7, page 37 (Same Value Reported for Units 2 & 3)
    c. Unit 2 RCS Flow – 75.76 Million lbs/Hour – SONGS Unit 2 RCS Flow per SONGS procedure, used 102,000 gpm value for Unit 3 from NRC AIT Report
    d. Unit 2 RCS Temperature Difference between Hot and Cold Legs – 58 degrees F – per SONGS procedure
    A.5 – Differences Between SONGS Unit 2 and Unit 3 RSGs Operating Pressures
    A.5.1 – Case 1 – Unit 3, 833 psi, Steam Flow @ 7.62 Million lbs /hour (Consistent with NRC AIT Report)
    @ 100 % void fraction (Assumed for the purposes of Qualitative Calculations)
    A.5.1.1 – Enthalpy, Saturated Vapor, hg – 1,198.2 Btu/lb @ 833 psi (SONGS Procedure & efunda steam tables)
    A.5.1.2- Feedwater Enthalpy @ 440 0F @ 900 psi ~ 420 Btu/lb (SONGS Procedure)
    A.5.1.3 – Enthalpy, Extracted by Steam/Water Mixture into SG Evaporated, hfsg = 1,198.2 – 420 = 778.2 Btu/lb
    A.5.2. – Thermal Reactor Power for Unit 3 RSG = 7.62 X Million lbs./hr X 778.3 Btu/Lb.= 5,930,000,000 Btu/hour/(3,412,141 Btu/MWt) = 1737 Thermal MWt/hour
    A.5.2.1 – Case 2 – Unit 2, 892 psi, Steam Flow @ 7.59 Million lbs/hour (Consistent with NRC AIT Report No FEI in Unit 2 per Westinghouse, RCE Member Discussions, Industrial Data of several plants with no tube-to-tube wear), @ 100 % void fraction (Assumed for the purposes of Qualitative Calculations)
    A.5.2.2 – Feedwater Enthalpy @ 440 0F @ 900 psIa ~ 420 Btu/lb. (SONGS Procedure)
    A.5.2.3 – Enthalpy, Saturated Vapor, hg – 1,196.4 Btu/lb @ 892 psi (SONGS Procedure & efunda steam tables)
    A.5.2.4 – Enthalpy, Extracted by Steam/Water Mixture into SG Evaporated, hfsg = 1,196.3 – 420 = 776.3 Btu/lb
    A.5.2.5 – Thermal Power Unit 2 = 7.59 Million lbs./hr. X 776.3 Btu/lb = 5,892,000,000 Btu/hour/(3,412,141 Btu/MWt) = 1727 Thermal MWt/hour
    A.6 – Case 3 – Difference in Heat Flow between Units 2 and 3, which caused tube-to-tube wear (160 tubes out of 9727 tubes) area of the Unit 3 RSG = 1737 MWt – 1727 MWt = 10 MWT/Hour X 3412141 Btu/MWT = 34,121,410 Btu/hour
    A.7 – Case 4 –- Btu/hour required to raise void fraction from 98.5% to 99.6% of 4 percent of the feedwater flow in Unit 3 high region of wear to cause fluid elastic instability = 7.62 Million lbs/hour X 0.04 x 26 Btu/lb (Assumed, needs verification by NRC) = 7,924,800 Btu/hour – Please see Analysis/ Conclusions at the top of this article for continuation.

  14. Sincere Thanks to Mr. Victor Dricks, Mr. Cale Young, Mr. Ryan Lantz, Mr. Randy Hall and entire NRC Staff. Thanks to NRC posting this blog.

    HAHN BABA responding to MHI Root Cause – Part 3 – Responding to SCE CAL ACTION 1

    A. Conclusions: As shown below, the Root Cause determined by SCE and MHI for both Units 2 & 3 RSGs does not address the exact reason for RSG design and operational flaws. Root Cause is defined as the exact reason (e.g., hardware, process, or human performance) for a problem, which if corrected, will prevent recurrence of that problem. Therefore, SCE/MHI have not determined the exact root cause of the tube-to- tube wear in Unit 3 per CAL ACTION 1, and have not implemented actions to prevent the loss of tube-to-tube wear and demonstrated via a deterministic safety analysis that the AVB structural integrity in the Unit 2 steam generator will be maintained (e.g., Collapse of AVB structure and retainer bars failure due to FEI, FIRV and MFE) due to Main Steam Line Break (e.g., Mihama, Turkey Point, Robinson), Station Blackout (Fukushima), SG Tube Ruptures ( Mihama, SONGS 3 & 20 other Incidents in US/Europe in the last 20 years) and other anticipated operational transients at power operation between 70 t0 100% power . NRC Chairman has publicly stated that SCE is responsible for the work of MHI. Therefore, NRC/NRR San Onofre Special Members have to be extremely careful (to fulfill their mission of public safety) of all the false claims and wishy-washy Unit 2 Return to Service Reports, which are based on flawed statistical data, unreliable computer models, irrational logic and are nothing, but garbage, smoking mirrors, full of holes and contradictions.

    B.Background:
    B.1 – On March 27, 2012, the NRC issued a CAL to SCE describing actions that the NRC and SCE agreed would be completed prior to returning Units 2 and 3 to service. The purpose of this report is to provide detailed information to demonstrate fulfillment of Actions 1 and 2 of the CAL, which are required to be completed prior to entry of Unit 2 into Mode 2. The actions as stated in the CAL are as follows: CAL ACTION 1: “Southern California Edison Company (SCE) will determine the causes of the tube-to- tube interactions that resulted in steam generator tube wear in Unit 3, and will implement actions to prevent loss of integrity due to these causes in the Unit 2 steam generator tubes. SCE will establish a protocol of inspections and/or operational limits for Unit 2, including plans for a mid-cycle shutdown for further inspections.”
    B.2 – John L. Geesman, Council for Alliance For Nuclear responsibility (A4NR) states in a Letter to Dr. Robert B. Weisenmiller, Chairman California Energy Commission, states, “NRC’s Augmented Inspection Team report (“AIT Report”), certain “blind spots” continue to plague the assessment of Unit 2’s prospects. I believe it imperative that you demand a more robust, empirical analysis than either SCE or the NRC staff has performed to date. A4NR criticized the analytic sloppiness of the AIT Report’s abrupt dismissal of 10,854 indications of wear at the anti-vibration bars (“AVB wear”) and 3,315 at the tube support plates (“TSP wear”) based on vague and undocumented reliance on purported industry operating experience. The absence of any reference to actual data to support this conclusion (“the wear indications found are similar to those found at other replacement steam generators after one cycle of operation”3) is peculiar.”
    B.3 – John Large States, “SCE’s assertion that reducing power to 70% will at the best alleviate, but not eliminate, the TTW and other modes of tube and component wear is little more than hypothesis – the supporting Operational Assessments and analyses have not proven it to be otherwise. I am of the opinion that trialling this hypothesis by putting the SONGS Unit 2 back into service will, because of the uncertainties and unresolved issues involved, embrace a great deal of change, test and experiment. The terms of the Confirmatory Action Letter of March 11 2012, are versed such that to meet compliance the response of SCE via its Return to Service Report,11 must include considerable changes of conditions and procedures that are outside the reference bounds of the present FSAR – this is because the physical condition of the RSGs, and the means by which this is evaluated and projected into future in-service operation, have substantially and irrevocably changed since the current FSAR was approved. The fact that SCE fails to satisfy the requirements of the CAL is neither here nor there, although it illustrates the scope and complexity of the response required. At the time of preparing the CAL, the NRC being well-versed in the failures at the San Onofre nuclear plant, surely must have known that the only satisfactory response to the CAL would indeed require considerable changes, tests and experiments to be implemented. Put another way, the extensive and rapid rates of tube wear experience at the SONGS Unit 2 and Unit 3 RSGs, have necessitated an extensive raft of analysis, assessments and projections to qualify, or otherwise, that Unit 2 is fit for purpose. Not only is this prequalifying work unique to the San Onofre nuclear plant, much of it has never been undertaken before so, it follows, its inclusion in safety considerations must be a new and hitherto unconsidered component now required to be incorporated into an updated version of the FSAR. Hence, I am of the opinion that, on a technical basis alone, the CAL must be considered to have been at the time of its preparation, a de facto license amendment.”
    B.4.1- MHI Root Cause – Thus, the organizational and programmatic Root Cause for the in-plane FEI as set forth in this RCA is the insufficient programmatic requirement to assure effective AVB contact force to control in-plane FEI under high localized thermal-hydraulic conditions (steam quality (void fraction), flow velocity and hydrodynamic pressure). The underlying reason for this insufficiency is that the MHI SONGS RSG design did not consider the phenomenon of in-plane FEI because contemporary knowledge and industry U-tube SG operation experience did not indicate a need to consider in-plane FEI. The design control process did not provide sufficient direction to assure that an evaluation of the need for an analysis of flow induced vibration of the retainer bar was performed and verified.

    C. Background: Researchers have said long ago that nucleate boiling on the tube surfaces has a stabilizing damping effect to preclude fluid-elastic instability. At least 1.5 % water or void fraction less than 98.5% in a steam-water mixture and areas without localized tube dry-out conditions are required in a nuclear steam generator to preclude the onset of fluid elastic instability. A review of NUREG-1841 published during the SCE/MHI design stages of San Onofre Replacement Steam Generators indicates that innovative and experienced manufacturers of steam generators (like Westinghouse/CE & BW&I) including with very high steam flows such as the largest steam generators in the world (e.g., Palo Verde) have used a combination of design and operational features [(high circulation ratios(>4), high steam pressures (> 900 psi) and low friction losses] to keep the void fractions at 98.5% or below and have prevented localized tube dry-out conditions and steam blanketing in operating US Steam Generators.

    D. SONGS Operational Data, Design Assumptions and Trend Calculations:
    D.1 – Feedwater Operating pressure is assumed to be 50 psi higher than Steam Operating pressure based on input from the SONGS Senior Shift Manager.
    D.2 – The difference in Reactor Coolant Specific Heat between Units 2 & 3 due to minor RCS temperature variation is negligible is negligible.
    D.3 -Ratio of Reactor Thermal Power Ratio between Units 3 and 2 = [Unit 3 (79.79 X 56.7)]/[Unit 2 (75.76 X 58)] = 1.03 (SONGS Procedure)
    D.4 – Differences Between SONGS Unit 2 and Unit 3 RSGs Operating Pressures

    D.4.1 – Case 1 – Unit 3, 833 psia, Steam Flow @ 7.6 X 106 Pounds/hour (Consistent with NRC AIT Report)
    D.4.1.1 – Enthalpy, Saturated Vapor, hg – 1,198 Btu/Lb @ 850 Psi (SONGS Procedure)
    D.4.1.2- Feedwater Enthalpy @ 440 0F @ 900 psIa ~ 420 Btu/ lb. (SONGS Procedure)
    D.4.1.3 – Enthalpy, Extracted by Steam/Water Mixture into SG Evaporated, hfsg = 1,198 – 420 = 778 Btu/lb.
    D.4.1.4 – Thermal Power Unit 3 = 7.588 X Million lbs./hr X 778.6 Btu/Lb.= 775 Million Btu/Hour = 5,908,000,000 Btu//Hour = 1729 Thermal MWt/Hour

    D.4.2 – Case 2 – Unit 2, 892 ~ 900 psi, Steam Flow @ 7.6 X 106 Pounds/hour (Consistent with NRC AIT Report)
    D.4.2.1 – Feedwater Enthalpy @ 440 0F @ 900 psIa ~ 420 Btu/ lb. (SONGS Procedure)
    D.4.1.2 – Enthalpy, Saturated Vapor, hg – 1,196.2 Btu/Lb @ 900 Psi (SONGS Procedure)
    D.4.2.3 – Enthalpy, Extracted by Steam/Water Mixture into SG Evaporated, hfsg = 1,196.2 – 420 = 776.2 Btu/lb.
    D.4.2.4 – Thermal Power Unit 2 = 7.6 Million lbs./hr. X 776.2 Btu/lb = 1728 Thermal MWt/Hour

    D.4.3 – Case 3 – Difference in Heat Flow bewteen Units 2 and 3, which caused tube-to-tube wear in 1.5 percent Area of the Unit 3 = 0.015 X 7.6 Million lbs./hr. X 778.8 – 776.2 Btu/lb ~ 0.25 Million Btu/Hr

    D4.4 – Analysis: 0.25 Million Btu/Hr extra heat was rejected by Unit 3 RSGs produced due to higher Unit 3 RCS flows. Therefore, heat flux in the hot leg in the high region of tube wear due to narrow pitch tube to diameter ratio and extremely tall tube bundle exceeded the critical heat flux. This phenomena caused void fraction of 99.6%, created in-plane velocities > 50 feet/sec and excessive hydrodynamic pressures (Mitsubishi Floweing Effect). The only known flow induced vibration mechanism capable of producing large tube displacements, and in a contiguous group like that of the Unit 3 RSGs, is fluid elastic excitation. Due to void fractions of 99.6%, in-plane steam velocities > 50 feet/sec and excessive hydrodynamic pressures, large U-bends in Unit 3 pushed the AVBs out of their way and produced large displacements of tubes in the in-plane direction. Tubes are known to have moved in-plane because of the locations and magnitudes of their wear scars. The wear scars indicate that the tubes were generally vibrating in their first fundamental in-plane mode, which implies that none of the twelve (12) AVB supports were restraining the tube motion. Yet, it also indicates that the tube-to-AVB gaps are very small and uniform, because none of the tubes exhibited out-of-plane FEI, which is the tube’s preferential fluid elastic vibration mode. Since out-of-plane FEI did not occur in Unit 3 and instead only in-plane FEI occur, it is concluded that the out-of-plane support conditions for the TTW tubes were active (as designed). This leads to the conclusion that the Unit 3 RSGs 24 tube-to-AVB intersections (AVB on both sides of a tube with 12 locations) have gaps small enough to be effective in the out-of-plane direction, but there were no positive restraints in the-plane direction. Therefore, there were zero tube-to-AVB contact forces to prevent in-plane tube displacement. This analysis is consistent with Dr. Pettigrew’s Research Paper published in 2006 and his statements in 2013 regarding SONGS RSG AVB Design, AREVA’s Operational, John Large’s and Arnie Gundersen’s Assessments, SONGS Root Cause Members Statements and SONGS Operational Data. SCE/MHI have not determined the exact root cause of the tube-to- tube wear in Unit 3 per CAL ACTION 1, and have not implemented actions to prevent the loss of tube-to-tube wear and demonstrated via a deterministic safety analysis that the AVB structural integrity in the Unit 2 steam generator will be maintained (e.g., Collapse of AVB structure and retainer bars failure due to FEI, FIRV and MFE) due to Main Steam Line Break (e.g., Mihama, Turkey Point, Robinson), Station Blackout (Fukushima), SG Tube Ruptures ( Mihama, SONGS 3 & 20 other Incidents in US/Europe in the last 20 years) and other anticipated operational transients at power operation between 70 t0 100% power .

  15. Sincere Thanks to Mr. Victor Dricks, Mr. Cale Young, Mr. Ryan Lantz, Mr. Randy Hall and entire NRC Staff. Thanks to NRC posting this blog.
    HAHN BABA responding to MHI Root Cause – Part 3 – Mitsubishi explanation of low contact forces as the reason for Unit 3 FEI and increased out-of plane flat bars contact force serves to increase the in-plane natural frequency of the tubes does not make any sense. The Root Cause by SCE and MHI for both Units 2 & 3 RSGs does not address the exact reason for RSG design and operational flaws. Root Cause is defined as the exact reason (e.g., hardware, process, or human performance) for a problem, which if corrected, will prevent recurrence of that problem

    MHI Press Statement: An executive with the company that manufactured faulty equipment that led to the shutdown of the San Onofre nuclear plant defended decisions made in the design of the replacement steam generators. The company made choices in designing support structures at San Onofre that were intended to prevent one type of vibration, but ended up creating another type of vibration that ultimately led to the plant’s closure, said Frank Gillespie, senior vice president with Mitsubishi Nuclear Energy Systems. The problematic vibration, he said, had not been seen at any other plant before, although it had been observed in experimental conditions.

    Rebuttal: Researchers have said long ago that nucleate boiling on the tube surfaces has a stabilizing damping effect to preclude fluid-elastic instability. At least 1.5 % water or void fraction less than 98.5% in a steam-water mixture and areas without localized tube dry-out conditions are required in a nuclear steam generator to preclude the onset of fluid elastic instability. A review of NUREG-1841 published during the SCE/MHI design stages of San Onofre Replacement Steam Generators indicates that innovative and experienced manufacturers of steam generators (like Westinghouse/CE & BW&I) including with very high steam flows such as the largest steam generators in the world (e.g., Palo Verde) have used a combination of design and operational features [(high circulation ratios(>4), high steam pressures (> 900 psi) and low friction losses] to keep the void fractions at 98.5% or below and have prevented localized tube dry-out conditions and steam blanketing in operating US Steam Generators. The above statements by MHI are very damaging and affects its credibility as a NEI Qualified, “US Nuclear Plant Designer” and manufacturer of nuclear power plant components including the new APWRs. NRC Chairman has publicly stated that SCE is responsible for the work of MHI. Therefore, NRC/NRR San Onofre Special Members have to be extremely careful (to fulfill their mission of public safety) of all the false claims and wishy-washy Unit 2 Return to Service Reports, which are based on flawed statistical data, unreliable computer models, irrational logic and are nothing, but garbage, smoking mirrors, full of holes and contradictions.

    SUMMARY: As stated above and below, MHI is right with its limited knowledge and experience, when it states, “It was not recognized at the time that a certain amount of tube-to-AVB contact force was required to prevent in-plane FEI under high steam quality (void fraction) conditions, because the contact force serves to increase the in-plane natural frequency of the tube.” Let us examine why MHI says that: (1) MHI did not have the experience with building large Combustion Engineering Replacement Steam Generators (RSGs) like San Onofre with large steam flows with the potential for FEI, high dry steam or tube dry-outs, (2) MHI had experience with building only Combustion Engineering RSGs in Fort Calhoun with very small flows compared with San Onofre, which did not have the potential for FEI, high dry steam or tube dry-outs (3) The tube-to-AVB contact force MHI is discussing to prevent in-plane FEI under high steam quality (void fraction) conditions only prevents damage of the tubes due to flow induced random vibrations in the out-of-plane direction. That is why, San Onofre Unit 3 RSGs tubes did not move in the out-of-plane direction, but moved in the in-plane direction due to double the velocities calculated by ATHOS Models, (4) In-plane FEI at SONGS for MHI is a new padigram, but it has been observed in experimental conditions. Nuclear Manufacturers without large CE RSGs design and manufacturing experience like MHI design anti-vibration bar support structures for out-of-plane protection with the assumption that that in-plane FEI does not need to be considered if out-of-plane FEI is controlled, (5) MHI Engineers did not read Dr. Pettigrew’s research papers published in 2006 during the early design stages of the San Onofre RSGs, in which he warned about the ineffectiveness of flat bars against in-plane vibrations. He said in 2013 again that San Onofre RSGs do not provide a positive restraint against in-plane vibrations, (6) AREVA states, “After instability develops, the amplitude of in-plane motion continuously increases and the forces needed to prevent in-plane motion at any given AVB location become relatively large. Hence shortly after instability occurs, U-bends begin to swing in Mode 1 and overcome hindrance at any AVB location”, (7) Westinghouse/Combustion Engineering have successfully designed 6 CE replacement steam generators with high steam flows at Palo Verde and these generators have not experienced in-plane vibrations in almost 10 years of operation? Mitsubishi explanation of low contact forces as the reason for Unit 3 FEI and increased out-of plane flat bars contact force serves to increase the in-plane natural frequency of the tube does not make sense.

    Mitsubishi in its Root Cause, Document UES -20120254, Rev 0, page 20, Section 5.5, Discussion of Tube to Tube Wear – Tube Contact Force, states, “During the fabrication of the AVBs and the tubing and assembly of the tube bundle, MHI’s manufacturing practices achieved dimensional control that resulted in smaller tube-to-AVB gaps and smaller tube-to-AVB contact forces. It was not recognized at the time that a certain amount of tube-to-AVB contact force was required to prevent in-plane FEI under high steam quality (void fraction) conditions, because the contact force serves to increase the in-plane natural frequency of the tube. The technical investigations after the tube leak incident determined that the amount of contact force necessary to prevent in-plane FEI depends on the localized thermal-hydraulic conditions (steam quality (void fraction), flow velocity and hydro-dynamic pressure). As the steam quality (void fraction) increases, the amount of contact force necessary to prevent vibration increases. This increase in required contact force occurs because as the steam quality (void fraction) becomes higher, the damping provided by the liquid phase in the form of a liquid film decreases. The reduced in-plane contact force due to the SONGS “effective zero gap” design and the avoidance of “excessive preload” resulted in lowering the tubes’ natural frequency in the in-plane direction. The combination of the localized high steam quality (void fraction) and reduced tube to AVB contact force resulted in exceeding the in-plane critical velocity, which created a condition that led to tube to tube contact. The dominant role played by the low contact force is reflected by the differences in the tube-to-tube wear that was observed in the Unit 2 and the Unit 3 RSGs. Each of the Unit 3 RSGs had approximately 160 tubes that experienced tube-to-tube wear whereas only one of the Unit 2 RSGs experienced tube-to-tube wear in just two tubes, even though the Unit 2 RSGs have operated twice as long as the Unit 3 RSGs. MHI did a comprehensive statistical evaluation of the contact forces between the tubes and the AVBs of the two units and concluded, based on the manufacturing data , that the contact force between the tubes and the AVBs in the Unit 2 RSGs is approximately double the contact force in the Unit 3 RSGs. Thus, the lower contact forces in Unit 3 are consistent with the conditions determined necessary to permit in-plane FEI to occur and with the fact that tube-to-tube wear occurred almost exclusively in Unit 3.”

    Mitsubishi in its Root Cause, Document UES -20120254, Rev 0, page 21 through 22, Section 5.5, Discussion of Tube to Tube Wear & Thermal-hydraulic Conditions, states, Many analyses are performed during the steam generator design process. One of these is MHI’s FIT-III tube bundle flow analysis, which calculates tube bundle thermal / hydraulic parameters, including U-bend flow velocity and steam quality (void fraction).An after-the-fact comparison between the T/H parameters that FIT-III predicted and those predicted by ATHOS, another T/H code, determined that FIT-III’s calculated values are lower than those obtained using ATHOS. Part of the difference was because the pressure loss coefficients for the tube bundle and the two-phase mixture density utilized in the two codes were different. Also, during the computation of the flow velocity, MHI used an inappropriate definition of the gap between tubes, with the result that the flow velocities were underestimated. These differences between MHI’s use of the FIT-III model and the ATHOS model resulted in a higher margin to out-of-plane FEI than the margin that would have been determined using the appropriate the definition of the gap and an ATHOS-calculated steam quality (void fraction). The margin calculated using ATHOS, nonetheless, would still have resulted in adequate margin against out-of-plane FEI. Using the ATHOS outputs, with all AVBs assumed active, the stability ratio was less than 1.0 for out-of-plane FEI, even for those case studies assuming reduced damping that could occur under high void fraction conditions.3 Thus, the use of ATHOS as opposed to FIT-III would not have identified an inadequate design margin against FEI. Moreover, because industry practice was focused on out-of-plane FEI, use of ATHOS would not have identified the potential for in-plane vibration. Both the academic literature and subsequently conducted tests show that the thermal-hydraulic environment under which in-plane FEI arises is different from those that result inout-of-plane FEI. (See Supplemental Technical Evaluation Report). If the steam quality (void fraction) predicted by FIT-III had been the same as the ATHOS calculated value, and if the appropriate tube to tube gap value had been utilized to compute the flow velocity, MHI would have identified a decreased margin against out-of-plane FEI. In that case, MHI might have incorporated an additional AVB to increase the design margin against out-of-plane FEI, but would not have taken measures to protect against in-plane FEI, for it was assumed (as was the practice and guidance in the industry) that the controlling effect of a well-designed AVB system was adequate to preclude it. Thus, not using ATHOS, which predicts higher void fractions than FIT-III at the time of design represented, at most, a missed opportunity to take further design steps, not directed at in-plane FEI, that might have resulted in a different design that might have avoided in-plane FEI. However, the AVB Design Team recognized that the design for the SONGS RSGs resulted in higher steam quality (void fraction) than previous designs and had considered making changes to the design to reduce the void fraction (e.g., using a larger downcomer, using larger flow slot design for the tube support plates, and even removing a TSP). But each of the considered changes had unacceptable consequences and the AVB Design Team agreed not to implement them. Among the difficulties associated with the potential changes was the possibility that making them could impede the ability to justify the RSG design under the provisions of 10 C.F.R. §50.59. Thus, one cannot say that use of a different code than FIT-III would have prevented the occurrence of the in-plane FEI observed in the SONGs RSGs or that any feasible design changes arising from the use of a different code would have reduced the void fraction sufficiently to avoid tube-to-tube wear. For the same reason, an analysis of the cumulative effects of the design changes including the departures from the OSG’s design and MHI’s previously successful designs would not have resulted in a design change that directly addressed in-plane FEI.”

  16. Sincere Thanks to Mr. Victor Dricks, Mr. Cale Young, Mr. Ryan Lantz, Mr. Randy Hall and entire NRC Staff. Thanks to NRC posting this blog. HAHN BABA responding to MHI Root Cause – Part 2

    SCE/MHI misrepresenting Tube Wear Root Cause at St. Lucie Unit 2 Replacement Steam Generators built by AREVA. Root Cause is defined as the exact scientific and operating reason (e.g., hardware, process, or human performance) for a problem, which if corrected, will prevent recurrence of that problem

    SUMMARY: Plant A MHI is referring below is actually about St. Lucie 2 located in Florida. Professor Daniel Hirsch states (See reference below), “SCE has attempted to compare its San Onofre Unit 2 steam generator experience to St. Lucie 2, in order to assert that what is happening at San Onofre is typical for new replacement steam generators and is simply a “settling in” process common to them. These assertions are clearly misplaced. St. Lucie 2’s steam generators are having great trouble, and as the data shows, not in any fashion the norm. Indeed, St. Lucie 1 had only 17 damaged tubes at its first ISI. The serious problems at St. Lucie 2 have resulted in its operators having to conduct a root cause analysis which concluded that “the root cause was that the U-tubes were not effectively supported during SG [steam generator] manufacture, which caused the tubes to sag into the AVBs and led to slight AVB deformation that closed the tube-to-AVB gap at specific locations. This exacerbated tube wear in those locations.” NRC’s Advisory Committee on Reactor Safety concluded that the St. Lucie 2 tube wear is “different than the form of degradation reported to have occurred at San Onofre. There are a number of design differences between the SGs installed at San Onofre and those at St Lucie 2.” Thus the problems at St. Lucie 2 are not standard “settling in” but due to a serious manufacturing error and unrelated to San Onofre’s problems. Even with all the troubles St. Lucie 2 has, it had to plug only 14 tubes, compared to the hundreds plugged at San Onofre. The San Onofre Unit 2 tube-to-AVB damage has been caused due to flow-induced random vibrations and Mitsubishi flowering effects as a result of high steam flows, narrow tube to pitch diameter ratio and a very tall tube bundle (Outside the NORM compared with MHI SGs), high void fractions (< 98.5%) and high fluid velocities. Therefore the Root Causes of San Onofre and St. Lucie are completely different and misrepresented by SCE and MHI.

    Mitsubishi states in its Root Cause, Document L5-04GA588, Rev 0, Page 34, Section 3.2, Tube-to-AVB Wear Experience in Other Large CE-Plant RSGs, “Tube wear patterns similar to those observed at SONGS were reported at the Plant-A (St. Lucie Unit 2) large U-bend steam generators that were replacements for CE manufactured OSGs (See NRC ADAMS ML11270A015 and ML093230226). The Plant-A steam generators were designed by another vendor (AREVA). They are slightly smaller than the SONGS steam generators but have U-bend tubes, flat bar AVBs, and BEC type TSPs, that are similar to the SONGS RSGs, except SONGS features a 12 AVB design and Plant-A has an 8 AVB design. The Plant-A inspection results show a wear pattern with many tubes in the center of the U-bend that have tube-to-AVB wear similar to that found in the SONGS steam generators. Figure 3.2.1-2 shows the tubes with tube-to-AVB wear identified at Plant-A during the first inspection following installation of the RSGs and Figure 3.2.1-3 shows the tubes with tube-to-AVB wear identified at Plant-A during the second cycle inspection. Note that the locations of the Plant-A indications are very similar to those for SONGS shown in Figs. 3.1-1 and 3.1-2. Figure 3.2.1-4 compares the total number of tube-to-AVB wear indications for Plant-A, SONGS Unit 2, and SONGS Unit 3 as a function of time and Figure 3.2.1-5 shows the average wear depths for the three plants (six RSGs) as a function of time. As can be seen from these figures, the total number of indications and average wear depth at Plant-A are comparable to that at SONGS. Figure 3.2.1-5 suggests that the tube-to-AVB wear depths at Plant-A have reached a plateau. The reason for such a plateau is unclear. It may be indicative of the type of tube vibration mechanism or an effect of the support condition. But it is clear that the number of tubes with tube-to-AVB wear at Plant-A is growing (refer to Fig. 3.2.1-2 and 3.2.1-3).”

    Reference: Far Outside The Norm: The San Onofre Nuclear Plant’s Steam Generator Problems in the Context of the National Experience with Replacement Steam Generators by Daniel Hirsch and Dorah Shuey, “How does San Onofre compare with the experience with replacement steam generators (RSGs) more generally? A January 2002 article in Nuclear Engineering International, entitled “Replacement Steam Generators,” answers that question: “Of the 30 RSGs now in operation, 26 have received 100% eddy current inspection during in service inspection. Of these, 12 have experienced limited fretting wear. The other 14 RSGs have no evidence of any wear. ECT [Eddy Current Testing] indications have resulted in 23 plugged tubes out of a total population of 176,282 in the 26 inspected SGs. Thus, when the article was written, the majority of replacement steam generators showed “no evidence of any wear.” The remaining minority showed limited wear—so limited, that a total of only 23 tubes had to be plugged out of 176,282 tubes in the 26 inspected steam generators. Unit 2 of San Onofre, the reactor asserted to be far healthier than Unit 3, had plugged more than twenty times as many tubes as the 26 replacement steam generators considered in that 2002 review, combined. The NRC’s AIT report dismissed all but the tube-to-tube wear (which is primarily in Unit 3) and four wear indications at retainer bars in Unit 2 as common in new steam generators. The report stated that, with those exceptions, “the wear indications found are similar to those found at other replacement steam generators after one cycle of operation .”xiii (emphasis added). However, at other times NRC has stated the opposite. For example, the Los Angeles Times quoted an NRC spokesman on July 14: "Other large steam generators have exhibited wear after one cycle of operation which resulted in tube plugging…but not to the extent seen on San Onofre steam generators." Another NRC spokesperson was quoted as saying, "It is accurate to say San Onofre's demonstrated wear is unprecedented for the length of time the steam generators were used.” Also, SCE has made assertions similar to the statement in the NRC AIT report. In a July press statement about the release of the tube wear tables, for example, SCE stated, “The majority of this wear is related to support structures. The nature of the support structure wear is not unusual in new steam generators and is part of the equipment settling in.(emphasis added)”

  17. Sincere Thanks to Mr. Victor Dricks, Mr. Cale Young, Mr. Ryan Lantz, Mr. Randy Hall and entire NRC Staff. Thanks to NRC posting this blog – HAHN BABA responding to MHI Root Cause – Part 1

    SUMMARY: The Original San Onofre CE steam generators with high steam flows did not suffer fluid elastic instability. Dr. Pettigrew warned about the ineffectiveness of Flat Bars against in-plane vibrations in a paper published in 2006 during the early design stages of the San Onofre RSGs. He said in 2013 again that San Onofre RSGs do not provide a positive restraint against in-plane vibrations. AREVA states, “After instability develops, the amplitude of in-plane motion continuously increases and the forces needed to prevent in-plane motion at any given AVB location become relatively large. Hence shortly after instability occurs, U-bends begin to swing in Mode 1 and overcome hindrance at any AVB location.” Can MHI or NRC explain, how contact forces in an anti-vibration structure designed for out-of-plane vibrations can prevent in-plane vibrations in a CE replacement steam generators with high steam flows, when the tubes only moved in the in-plane direction and in-plane velocities were more than double than the out-of-plane velocities. How will MHI design an in-plane anti-vibration floating structure to prevent tube-to-tube wear caused by 100 % void fractions, high-in-plane velocities, flow-induced random vibrations and Mitsubishi Flowering Effects. May be NRC should ask Westinghouse/Combustion Engineering before they approve the new MHI anti-vibration bar design, because these companies have successfully designed 6 CE replacement steam generators with high steam flows at Palo Verde and these generators have not experienced in-plane vibrations in almost 10 years of operation? Westinghouse/Combustion Engineering can say no, or charge MHI a very high fee to help Desparate SCE get out of the San Onofre Billion Dollar Radiation Jam and potential exit as a base-load plant. What is the harm in asking? Mitsubishi explanation of low contact forces as the reason for Unit 3 FEI does not make sense. To get the right answers, MHI as a supplier of new APWR’s, its ambition to capture the US Commercial Nuclear Market and justify its technological superiority claims over Westinghouse and NEI Qualification of “US Power Plant designer”, MHI really needs to dig very deep in SCE’s Secret Caves of hidden data and operational differences between Units 2 & 3. Combination of careful analysis of minute operational differences between Units 2 & 3 and in-depth questioning scrutiny of SCE created design flaws (11% increase in heat transfer area without a 50.90 License Amendment, Refusal to make changes to reduce void fractions) to make more thermal megawatts out of the RSGs will provide the MHI………………..

    Mitsubishi states in its Root Cause, Document UES-20120254, Rev 0, Page 20, Section 5.5, Discussion of Tube to Tube Contact Force, “During the fabrication of the AVBs and the tubing and assembly of the tube bundle, MHI’s manufacturing practices achieved dimensional control that resulted in smaller tube-to-AVB gaps and smaller tube-to-AVB contact forces. It was not recognized at the time that a certain amount of tube-to-AVB contact force was required to prevent in-plane FEI under high steam quality (void fraction) conditions, because the contact force serves to increase the in-plane natural frequency of the tube. The technical investigations after the tube leak incident determined that the amount of contact force necessary to prevent in-plane FEI depends on the localized thermal-hydraulic conditions (steam quality (void fraction), flow velocity and hydro-dynamic pressure).As the steam quality (void fraction) increases, the amount of contact force necessary to prevent vibration increases. This increase in required contact force occurs because as the steam quality (void fraction) becomes higher, the damping provided by the liquid phase in the form of a liquid film decreases. The reduced in-plane contact force due to the SONGS “effective zero gap” design and the avoidance of “excessive preload” resulted in lowering the tubes’ natural frequency in the in-plane direction. The combination of the localized high steam quality (void fraction) and reduced tube to AVB contact force resulted in exceeding the in-plane critical velocity, which created a condition that led to tube to tube contact. The dominant role played by the low contact force is reflected by the differences in the tube-to-tube wear that was observed in the Unit 2 and the Unit 3 RSGs. Each of the Unit 3 RSGs had approximately 160 tubes that experienced tube-to-tube wear whereas only one of the Unit 2 RSGs experienced tube-to-tube wear in just two tubes, even though the Unit 2 RSGs have operated twice as long as the Unit 3 RSGs. MHI did a comprehensive statistical evaluation of the contact forces between the tubes and the AVBs of the two units and concluded, based on the manufacturing data , that the contact force between the tubes and the AVBs in the Unit 2 RSGs is approximately double the contact force in the Unit 3 RSGs. Thus, the lower contact forces in Unit 3 are consistent with the conditions determined necessary to permit in-plane FEI to occur and with the fact that tube-to-tube wear occurred almost exclusively in Unit 3.”

  18. Mind-boggling and twisting drill scenarios, unclear, cumbersome and interpretive procedures and poor-performing San Onofre Shift Managers and Operating Crews

    SUMMARY: As shown below, SCE is unyielding, adamant and persistent to Restart Unit 2 at any cost and keeps on giving the perception, “If Intertek PRA calculations fail or are not conservative, so what, then , “The differential pressure across the SG tubes necessary to cause a rupture will not occur if operators prevent RCS re-pressurization in accordance with Emergency Operating Instructions.” The Operators, If Southern Californians are lucky a third time (First Time, SONGS 3 Tube Leak with 8 tube Failures, 2nd time, a tube with 90% Unit 2 Retainer Bar wear was not publicly announced and Unit 2 was shutdown due to refueling outage before the leak became a reality like Unit 3), can deal with one tube rupture, but not many simultaneous tube ruptures as we observed in SONGS Unit 3. Restart of Unit 2 is a potential road leading to Fukushima, to which the NRC Regulators need to pay very careful attention to fulfill their public safety charter mission and duty despite SCE/Industry Pressures and Anonymous Pressures.

    Sincere Thanks to Mr. Victor Dricks, Mr. Cale Young, Mr. Ryan Lantz, Mr. Randy Hall and entire NRC Staff. Thanks to NRC posting this blog

    San Onofre NRC/SCE/MHI/ Public Education Series – Statement of facts unless proven wrong otherwise ……… March 18, 2013 – Southern California Edison Submits Operational Assessment Requested by NRC NRR RAI 32 – SCE Putting Production/Profits over Safety – HAHN BABA Response Continued … See Previous Blogs for more comments

    Last year, I was evaluating/observing for an extended period of time and ways to improve the San Onofre Shift Managers and Operating Crews performance in Drills/Exercises Performance in the simulator. I discussed with several San Onofre Shift Managers and Operating Crews the reason for their consistent poor performance. Here is what they said, “Training Drills/Exercises are designed with, ‘Mind-boggling and twisting drill scenarios.’ On top of that procedures are unclear, confusing, cumbersome and interpretive with a lot of notes from instructors attached to the procedures. A Shift Manager, Station Technical Advisor, Control Room Supervisor and Operating Crews have only 15 minutes to diagnose, independently verify and declare an emergency event. You think, that we can be 100% successful in 15 minutes under these conditions coupled with communication errors.”

    So after lengthy discussions with the affected organizations looking ways to improve consistently low performance, I wrote a SONGS Nuclear Notification resulting into a Root Cause Evaluation (First in the history of SONGS Operations/Emergency Preparedness Division). The credit goes to a highly dedicated and concerned Ex-NRC Staff Member and SCE Management Nuclear Oversight Board Member, who was sick with SCE’s Management poor performance with repeat failures to improve the Shift Managers Performance and perhaps false public safety overriding obligation announcements. Here is the problem statement in verbatim of that Nuclear Notification, unless changed… “ SONGS DEP indicator metric value is presently estimated to be approximately 92.3%. Three DEP and one non-DEP indicator failures in the last three weeks have created doubts regarding the ability of SONGS Emergency Response Organization (ERO) to achieve a Site Core DEP Indicator goal for 2012 of 96.1% (3rd Quartile). Previous Cause Evaluations and Corrective Actions (Completed and Planned) have addressed individual performance and technical issues in a piecemeal manner as opposed to smart and sustained actions for improving overall team performance. NOD has concluded that actions taken to date have not solved the performance issues. The planned actions do not systematically address some of the broader organizational and technical issues identified below, which are essential to prevent DEP classification failures by Shift Managers /STA and Operations Crew. With SONGS under NRC, INPO, NOB, Public and Media scrutiny, the Station cannot afford the luxury of dealing with adverse performance and publicity in Emergency Preparedness caused by declining SONGS Drill/Exercise Performance. Insights:

    1. Based on review of 1Q12 NTD Data of Control Room Simulator Crew for LOCT/DEP Evaluations (17 Total), the performance deficiency is evident in the areas overall crew competency (UNSAT -1, Needs Improvement -10), Operating Within Limits (Needs Improvement – 5), Control Board Operations (Needs Improvement – 4), Interpret / Diagnose Events (UNSAT -1, Needs Improvement – 8), Technical Specification Use (Needs Improvement — 4) and Communications (Needs Improvement -5).

    2. Below are some of the weaknesses witnessed by the NOD Auditor during review and or observation of LOCT/DEP Evaluations, EP Drills and based on discussions with the Shift Managers. Each weakness may be attributed to one or the other DEP Miss-classifications. Some of these weakness were also identified by NOB Member Jack Martin based on his observation of the August 2011 EP drill.

    • Unclear and confusing EALs and less than adequate Basis Documents
    • Too many Priority Reading Assignments to clarify the EALs and Basis Document
    • Lack of solid teamwork between the Operating Crew, CRS, STA and EC. Crew members confused and concerned about their roles and responsibilities. Crew members held back or failed to provide information, which resulted in SM and CRS to trip the reactor.
    • Poor communications between the Operating Crew, CRS, STA and EC. Briefs were ineffective at focusing on the crew priorities. Three way communication not used for direction or when providing information relative to plant status.
    • Poor diagnostics/interpretation of the transient events by the Operating Crew, CRS, STA and EC. Serious omissions, delays, or errors made in interpreting indications resulting in degraded plant conditions. Failed to use, or misused, or misinterpreted indications that resulted in improper diagnosis.
    • Procedures were not followed correctly which impeded plant recovery or caused unnecessary degradation of plant conditions. Crews did not recognize EOI Entry Conditions.
    • Failure of the STA to provide consistent & independent check of the EAL by EC.
    • Lack of Stringent OPS/NTD Evaluation and Remediation Criteria for SM/STA/OPS Crew to achieve excellence and eliminate above shortcomings to prevent DEP Failures
    • Lack of practice by the Operating Crews, CRS, STA and EC following the coaching/critique provided by the OPS SM Supervisor and NTD Evaluators. This statement was confirmed by NOD during a discussion with a former Shift manager this morning.”

    A Lot More to Come… Thanks NRC Staff… HAHN BABA

  19. I am not certain I fully answered all your questions (from the first paragraph (HelpAllHurtNeverBaba; March 15, 2013 at 9:06 pm).

    BatScan systems have multiple response levels, e.g. cautionary when signals are low and occur spasmodically or continuously. The next level is when signals exceed a level known to have the potential to cause a problem if they exist for an extended period of time, but signal characteristics do not indicate the need for immediate operator action. However the signal is such that it requires watchful waiting while preplanned actions to notify or begin corrective operations are initiated. If the signal characteristics change to the next level, the operator will begin to move the plant to a pre-shutdown condition. This controlled shutdown opportunity may be used to perform diagnostics to obtain further information on the causes for the signal. This is an important step since signal generation causes may disappear when plant operation is shutdown.. At all times a high level signal will be cause for operator or automatic shutdown. You will appreciate this overview of the approach includes many checks and balances, redundancies and other parallel processes to confirm signal validity .(not described here) before the operator shuts down the plant or component. This approach is viable because of the system sensitivity and reliability (low false alarm rate). A planned shutdown is always preferable to rapid shutdown (SCRAM) in terms of minimizing plant component transient shocks.

    BatScan was designed to prevent significant steam generator damage from a destructive failure mode with a measured and validated timescale of about 20 seconds. The detection time for this damage mode was set to two seconds, with a false alarm rate of better than once in thirty years. The automated response system did include steam generator secondary side water blow-down within seconds. Other damage modes allowed more detection or corrective action timescales. The system was developed and designed to meet requirements rather than “do the best possible”.

    You stated “SCE and NRC Region IV tried in vain to sell this concept to NRC NRR Office but were shot down by the NRC I&C Branch Engineer. ” I would appreciate contact information for NRC staff that made this initial decision or are still involved in solving this critical problem. I would like to fully understand what they define as the requirements for protective monitoring of SONGS steam generators. I appreciate your feedback and concerns about SONGS.

  20. Sincere Thanks to Mr. Victor Dricks, Mr. Cale Young, Mr. Ryan Lantz, Mr. Randy Hall and entire NRC Staff. Thanks to NRC posting this blog
    San Onofre NRC/SCE/MHI/ Public Education Series – Statement of facts unless proven wrong otherwise ……… March 18, 2013 – Southern California Edison Submits Operational Assessment Requested by NRC NRR RAI 32 – SCE Putting Production/Profits over Safety – HAHN BABA Response Continued … See Previous Blogs for more comments
    John Large, a London-based nuclear engineer for Friends of the Earth, said the report actually shows San Onofre will progressively destroy itself. “If the Intertek analysis is correct, the plant only has a remaining total service life of one year at full power, or 16 months at 70 percent power,” Large said. “After this I doubt if any option will exist for Edison to repair the plant’s steam generators because the problem lies deep within the tube bundle, being essentially inaccessible by human or machine. There are “enormous uncertainties” with predicting degradation of the tubes.”
    Brilliant NRC Federal Regulators have to be very patient to completely understand the full adverse impact and grave implications of “mind-boggling” fluid elastic instability’s unique and controversial concept to prudently perform their charter of ensuring public safety. San Onofre “Defectively Designed” Radiation Steaming Crucibles (RSGs) anti-vibrations and retainer bars even with plugged/staked tubes, and floating tube bundle with excessive and tall tubes, and narrow tube pitch to tube diameter ratio are not designed to handle fluid elastic instability, flow-induced random vibrations and Mitsubishi Flowering Effect for design bases accidents or anticipated operational occurences at 70% or 100% power without complete replacement of the Tube Bundle and Supports. SCE/MHI does not have the technology or skills to perform the repairs and make these sick RSGs safe because of the unique design of the San Onofre Combustion Engineering Original Steam generators and adverse design changes made to these sick RSGs (e.g., Similar Well Performing, Safe and Money Making, Well Managed and Reliable six Palo Verde Combustion Engineering Replacement Steam Generators built by Westinghouse/ABB/Combustion Engineering since 2000’s).
    A Lot More to Come… Thanks NRC Staff… HAHN BABA

  21. Sincere Thanks to Mr. Victor Dricks, Mr. Cale Young, Mr. Ryan Lantz, Mr. Randy Hall and entire NRC Staff. Thanks to NRC posting this blog

    San Onofre NRC/SCE/MHI/ Public Education Series – Statement of facts unless proven wrong otherwise ……… March 18, 2013 – Southern California Edison Submits Operational Assessment Requested by NRC NRR RAI 32 – SCE Putting Production/Profits over Safety – HAHN BABA Response Continued … See Previous Blogs for more comments

    Background: On March 27, 2012, the NRC issued a CAL to SCE describing actions that the NRC and SCE agreed would be completed prior to returning Units 2 and 3 to service. The purpose of this report is to provide detailed information to demonstrate fulfillment of Actions 1 and 2 of the CAL, which are required to be completed prior to entry of Unit 2 into Mode 2. The actions as stated in the CAL are as follows: “CAL ACTION 1: Southern California Edison Company (SCE) will determine the causes of the tube-to- tube interactions that resulted in steam generator tube wear in Unit 3, and will implement actions to prevent loss of integrity due to these causes in the Unit 2 steam generator tubes. SCE will establish a protocol of inspections and/or operational limits for Unit 2, including plans for a mid-cycle shutdown for further inspections.”, and, “CAL ACTION 2: Prior to entry of Unit 2 into Mode 2, SCE will submit to the NRC in writing the results of your assessment of Unit 2 steam generators, the protocol of inspections and/or operational limits, including schedule dates for a mid-cycle shutdown for further inspections, and the basis for SCE’s conclusion that there is reasonable assurance, as required by NRC regulations, that the unit will operate safely.”

    EXECUTIVE SUMMARY: HAHN Baba and DAB safety Team has shown you previously in numerous San Onofre Papers, Press Releases, Media Alerts and Allegations submitted to NRC and US Congress that Southern California Edison Company (SCE) has not determined the exact Root Cause of the tube-to- tube interactions that resulted in steam generator tube wear in Unit 3, and has not implemented actions to prevent loss of integrity due to these causes in the Unit 2 steam generator tubes. Southern California Edison submittal to NRC on March 18, 2013 of Intertek Operational Assessment Requested by NRR RAI 32 does not meet CAL Actions 1 & 2. This analysis does not meet the intent of the Federal Regulations, NRC Steam Generator Tube Structural Integrity Criteria, SONGS NRC Approved Technical Specifications, NRC Emergency Preparedness Reasonable Assurance Criteria, NRC Chairman’s Standards, NEI 97-06,“Steam Generator Integrity Assessment Guidelines”, Electric Power Research Institute, Steam Generator Management Program, and SCE’s Overriding Obligation for Public Safety.

    A. First Strike – SCE shortened the life of San Onofre Original Combustion Steam Generators (OSGs) due to accelerated tube wear and increased tube plugging by increasing the reactor thermal power/SG output in 2001 from 1705 MWt to 1729 MWt.

    B. Second Strike, SCE destroyed 4 brand new replacement steam generators (RSGs) by specifying numerous unanalyzed and untested design changes to generate 1729 MWt by not performing review of Academic Literature (e.g., Dr. Pettigrew, 2006, etc.) and not industry benchmarking their own World’s Largest Palo Verde CE Replacement Steam Generators installed between 2001-2005 with > 2% power uprate. Arizona Power Service, majority owner and operator of Palo Verde CE Replacement Steam Generators resolved the problems with Palo Verde OSGs, made with more design and operational changes than San Onofre OSGs and followed NRC’s Blessed 10CFR 50.90 License Amendment Process (SCE owns 20% of these generators, but complacent SCE Engineers did not contact their Palo Verde Counterparts to inquire how they performed the safety analysis to justify design changes). In addition, SCE Engineers, prepared defective 10 CFR 50.59, took safety short cuts and did not implement the MHI Recommendations to reduce void fractions, and subverted the NRC 50.90 regulatory process (Honorable Senator Barbara Boxer and Congressman Ed Markey). SCE/MHI Engineers did not design the San Onofre RSGs tubes for protection in-plane vibrations. In-plane vibrations, fluid elastic instability or high dry steam problems did not exist in the San Onofre OSGs, that is why these OSGs tubes lasted for 28 years even with severe corrosion problems, out-of-plane vibrations tube/support wear, increased tube plugging rate and frequent inspections.

    C. Third Strike, New Intertek Operational Assessment, with so many previous failed attempts by SCE’s World’s First Class Expert Team Panel* including three NEI Qualified “US Nuclear Plant designers”, Westinghouse , AREVA & MHI.

    1. An Operational Assessment (OA) of a prudently designed well operated and thoroughly inspected steam generator is a forward-looking evaluation of the steam generator (SG) tube conditions that is used to ensure that the structural integrity and accident leakage performance will not be exceeded during the next inspection interval. The acceptance performance standard for structural integrity is: (1) The worst-case degraded tube shall meet the Structural Integrity Performance Criteria (SIPC) margin requirements with at least a probability of 0.95 at 50% confidence. The worst-case degraded tube is established from the estimation of lower extreme values of structural performance parameters (e.g., burst pressure) representative of all degraded tubes in the bundle for a specific degradation mechanism, and (2) The acceptance performance standard for Accident Leakage Performance Criteria (ALPC) integrity is, “The probability for satisfying the limit requirements of the AILPC shall be at least 0.95 at 50% confidence For SONGS, the accident-induced leak rate is 0.5 gallons per minute (gpm) per generator cumulative for all degradation mechanisms.” These margins are compared and managed with the structural integrity and leakage performance criteria requirements of Nuclear Energy Institute (NEI) 97-06,“Steam Generator Integrity Assessment Guidelines, Revision 3,” Electric Power Research Institute, Steam Generator Management Program, EPRI Report 1019038, (November 2009).”

    2. Emergency Preparedness for adequate protection of public health and safety from radiological doses and offsite release due to potential of radiological accident due to defectively designed and degraded steam generator tubes such as San Onofre should be implemented as a matter of prudence, deterministic analysis and defense-in-depth actions rather than in response to a quantitative analysis of accident probabilities. The effectiveness of an emergency plan is independent of probability. When periodic reviews or new information indicates the potential for conditions that could significantly reduce safety margins or exceed current design assumptions, a timely, formal, and comprehensive assessment of the potential for substantial consequences should be conducted. An independent, cross-functional safety review should also be conducted to fully understand the nuclear safety implications. Plant design features and operating procedures alone cannot completely mitigate the risk posed by a beyond-design-basis event.

    3. The NRC places a high priority on ensuring that possible steam generator tube degradation is carefully addressed through inspections, strict repair criteria and the monitoring of water chemistry to detect radiation leaking from the primary to the secondary side of the plant. In addition, tubes must have an extremely low probability of abnormal leakage and must be periodically inspected and tested. To obtain an operating license, applicants must show that the consequences of a steam generator tube rupture would not exceed the NRC’s conservative limits for radiation doses offsite or outside the plant (described in the agency’s regulations in Title 10 of the Code of Federal Regulations, Part 100). Plant operators also are required to have emergency procedures for mitigating steam generator tube ruptures and leaks.

    4. There are more than 100 operating commercial nuclear reactors in USA, with more than 200 steam generators. These steam generator tubes have very little damage compared with San Onofre, (a) Fairewinds states, “Using NRC publicly available data, Fairewinds compared the replacement steam generator plugging at both San Onofre Units 2 and 3 to the replacement steam generator plugging history for all other replacement steam generators at US nuclear power plants. Fairewinds concludes that San Onofre’s has plugged 3.7 times as many steam generator tubes than the combined total of the entire number of plugged replacement steam generator tubes at all the other nuclear power plants in the US”, and (2) Professor Daniel Hirsch in his report, “Far Outside The Norm: The San Onofre Nuclear Plant’s Steam Generator Problems in the Context of the National Experience with Replacement Steam Generators” states, “This report assembles national data from inspections of similar replacement steam generators after one cycle of operation. The conclusion is that both San Onofre Unit 2 and Unit 3 have experienced damage greatly in excess of the typical reactor: (a) The median number of steam generator tubes nationally showing wear after one cycle of operation is—FOUR. San Onofre Unit 2 had 1595 damaged tubes, approximately 400 times the median; San Onofre Unit 3 had 1806, (b) The median number of indications of wear on steam generator tubes nationally after one cycle of operation is—FOUR. San Onofre Unit 2 had 4721, greater than a thousand times more. San Onofre Unit 3 had 10,284, and (3) The median number of steam generator tubes that were plugged after one cycle of operation is—ZERO. San Onofre Unit 2 had 510; Unit 3 had 807.’ ‘Additionally, the replacement steam generators at San Onofre Unit 2 and 3 suffer from the same fundamental design errors. Indeed, the number of damaged tubes in each unit is approximately the same. The conclusion is clear: San Onofre Unit 2 and Unit 3 are both very ill nuclear plants. Unit 3’s fever is slightly higher, but both are in serious trouble. What they are experiencing is not just normal wear due to “settling in” purportedly experienced with similar replacement steam generators. They are far, far outside the norm of national experience. And Unit 2 cannot be said to be acceptable for restart, any more than Unit 3. Unit 2 has hundreds of times more bad tubes and a thousand times more indications of wear on those tubes than the typical reactor in the country with a new steam generator, and nearly five times as many plugged tubes as the rest of the replacement steam generators, over a comparable operating period, in the country combined. Restarting either San Onofre reactor with crippled steam generators that have not been repaired or replaced would be a questionable undertaking at best.”

    5. The above rules and experience applies only to steam generators, which are expected to operate for the licensed life of the reactor for 40 years in which SG tubes, anti-vibration bars and other supporting structures have been designed to ensure extremely low probability of abnormal tube leakage. With 5 potential tube ruptures projected in less than 9 months based on deterministic analysis and linear benchmarking of Unit 3 SG E-088 tubes failures, San Onofre defectively designed and degraded Unit 2 replacement generators are outside the NORM of the Federal Emergency Preparedness Rules, and Steam Generator Tube Design Regulations. SCE/Intertek APTECH Operational Assessment does not meet the intent of the Federal Regulations, NRC Steam Generator Tube Structural Integrity Criteria, SONGS NRC Approved Technical Specifications, NRC Emergency Preparedness Reasonable Assurance Criteria, NRC Chairman’s Standards, NEI 97-06,“Steam Generator Integrity Assessment Guidelines”, Electric Power Research Institute, Steam Generator Management Program, and SCE’s Overriding Obligation for Public Safety.

    *John Large Report critiquing Westinghouse, SCE, MHI and AREVA Reports – His Conclusions: “Whereas the OAs commissioned by SCE broadly agree that the wear mechanics comprises two phases, there are strong differences over the cause of the first phase comprising in-planeAVB wear: AREVA claim this is caused by in-plane FEI whereas, the contrary, Mitsubishi (and Westinghouse) favor random perturbations in the fluid flow regime to be the tube motion excitation cause. Put simply: (i) if AREVA is correct then reducing the reactor power to 70% will eliminate FEI, AVB effectiveness will cease to decline further and TTW will be arrested; however, to the contrary, (ii) if Mitsubishi is right then, even at the 70% power level, the AVB restraint effectiveness will continue to decline thereby freeing up longer free-span tube sections that are more susceptible to TTW; or that, (iii) the assertion of neither party is wholly or partly correct. SCE’s assertion that reducing power to 70% will at the best alleviate, but not eliminate, the TTW and other modes of tube and component wear is little more than hypothesis – the supporting Operational Assessments and analyses have not proven it to be otherwise. I am of the opinion that trialling this hypothesis by putting the SONGS Unit 2 back into service will, because of the uncertainties and unresolved issues involved, embrace a great deal of change,test and experiment. The terms of the Confirmatory Action Letter of March 11 2012, are versed such that to meet compliance the response of SCE via its Return to Service Report, must include considerable changes of conditions and procedures that are outside the reference bounds of the present FSAR – this is because the physical condition of the RSGs, and the means by which this is evaluated and projected into future in-service operation, have substantially and irrevocably changed since the current FSAR was approved. The fact that SCE fails to satisfy the requirements of the CAL is neither here nor there, although it illustrates the scope and complexity of the response required. At the time of preparing the CAL, the NRC being well-versed in the failures at the San Onofre nuclear plant, surely must have known that the only satisfactory response to the CAL would indeed require considerable changes, tests and experiments to be implemented. Put another way, the extensive and rapid rates of tube wear experience at the SONGS Unit 2 and Unit 3 RSGs, have necessitated an extensive raft of analysis, assessments and projections to qualify, or otherwise, that Unit 2 is fit for purpose. Not only is this prequalifying work unique to the San Onofre nuclear plant, much of it has never been undertaken before so, it follows, its inclusion in safety considerations must be a new and hitherto unconsidered component now required to be incorporated into an updated version of the FSAR. Hence, I am of the opinion that, on a technical basis alone, the CAL must be considered to have been at the time of its preparation, a de facto license amendment.”

    A Lot More to Come… Thanks NRC Staff… HAHN BABA

  22. Sincere Thanks to Mr. Victor Dricks, Mr. Cale Young, Mr. Ryan Lantz, Mr. Randy Hall and entire NRC Staff. Thanks to NRC posting this blog

    San Onofre NRC/SCE/MHI/ Public Education Series by HAHN BABA– Statement of facts unless proven wrong otherwise ……… Southern California Edison Submits Operational Assessment Requested by NRC NRR RAI 32 – Putting Production/Profits over Safety

    1. BACKGROUND: ROSEMEAD, Calif., March 18, 2013 — A new technical evaluation of San Onofre Nuclear Generating Station Unit 2 demonstrates that the Unit 2 steam generators could be operated safely at 100 percent power and reinforces Southern California Edison’s (SCE) more conservative plan to begin operating Unit 2 at 70 percent power for five months. SCE submitted the operational assessment of potential Unit 2 steam generator tube wear to the Nuclear Regulatory Commission in response to NRC questions. The new evaluation determined Unit 2 could operate at full power for 11 months with full tube integrity. The assessment was performed by Intertek APTECH of Sunnyvale, CA, and supplements Intertek’s earlier assessment of Unit 2 operation at 70 percent power. Intertek performs operational assessments relating to steam generators for many nuclear power plants around the U.S. “This evaluation confirms the structural integrity of the Unit 2 steam generators at 100 percent power, as requested by the NRC,” said Pete Dietrich, SCE senior vice president and chief nuclear officer. “While we have no intent to restart Unit 2 at full power, this demonstrates the amount of safety margin we have built into our analyses. We welcome this additional safety analysis but remain steadfast in our commitment to restart Unit 2 at only 70 percent power.”

    2. Facts to Dispute/Refute SCE Claim

    A. San Onofre Unit 3 operation @100 Power – 11 Months- SONGS Unit 3 Failed In-situ Wear Data – Unit 3 SG 3E088 (www.nrc.gov). The following tube wear data is based on a result of actual tube degradation in SONGS Unit 3 SG 3E088 caused by fluid elastic instability.

    Row 106 Column 78, 100 percent through wall wear, length of wear – 29 inches
    Row 102 Column 78, 99 percent through wall wear, length of wear – 23 inches
    Row 104 Column 78, 99 percent through wall wear, length of wear – 27 inches
    Row 100 Column 80, 81 percent through wall wear, length of wear – 28 inches
    Row 107, Column 77, 80 percent through wall wear, length of wear – 34 inches
    Row 101, Column 81, 78 percent through wall wear, length of wear – 26 inches
    Row 98, Column 80, 72 percent through wall wear, length of wear – 29 inches
    Row 99, Column 81, 72 percent through wall wear, length of wear – 27 inches

    B. Mitsubishi Root Cause Document UES-20120254, Rev 0, page 13 of 64, Item 1, “Tube to Tube Wear due to in-plane FEI” states,” Tube to tube wear was found in the U-bend region, located between AVBs, in the free span. Many of the tubes exhibiting tube to tube wear also exhibited wear at the AVBs and TSPs, in particular at the top tube support plate. For tubes with wear at the top tube support plate, it is considered that the entire tube, including its straight region, is vibrating. Tube to tube wear occurs when there is tube in-plane motion (vibration) with a displacement (amplitude) greater than the distance between the tubes in the adjacent rows, resulting in tube-to-tube contact. Some of the tubes with tube-tube wear did not experience large amplitude vibration but were impacted by tubes that did experience large amplitude vibration. Also the two tubes in Unit 2 with tube-to-tube wear had different wear characteristics than the Unit 3 tube-to-tube wear.”

    C. Based on Dr. Pettigrew’s Research and other papers published between 2006 -2011 on fluid elastic instability experimental data, “The high dry steam velocities differ in the in-plane and out-of-plane directions. For the SONGS RSG tube geometry, based on experimental data, it is conservatively estimated that the high dry steam velocities for in-plane FEI are at least at least 200 % of the high dry steam velocities for out-of-plane FEI.”

    D. The SONGS Unit 2 SG tube wear rates calculated by AREVA, Westinghouse and Intertek Operational Assessments and Work Rates are based on the results of out-of-plane velocities, which are under conservative based on FEI Observations in SONGS 3 and Dr. Pettigrew’s Research acknowledged by MHI and NRC Chairman and Commissioners.

    E. Deterministic Analysis – Uniform Linear Tube-to Tube Wear Rate in Unit 2 based on Unit 3 Benchmarking = 100%/11 months = 9%/month, consistent with item D and Actual Observations in SONGS 3

    F. Westinghouse in SONGS Unit 2 Return to Service Report, Attachment 6, Appendix D, (www.songs.community.com), page 91 states, “Table 3-2. Wear Projection Results for Active Tubes with Limiting AVB Wear Indications” shows the following active tubes in Unit 2 SG E089 with the following data:

    Row 119 Column 89, 28 percent ECT reported through wall wear,
    Row 121 Column 91, 28 percent ECT reported through wall wear
    Row 131 Column 91, 21 percent ECT reported through wall wear
    Row 129 Column 93, 22 percent ECT reported through wall wear
    Row 126 Column 90, 21 percent ECT reported through wall wear

    G. Calculate SGE E-089 tube rupture time @ 9% wear/month for 100% Tube wear @ full power operation

    Row 119 Column 89, 28 percent wall wear + 72 % in 8 months = 100 % wear = Tube Rupture
    Row 121 Column 91, 28 percent wall wear + 72 % in 8 months = 100 % wear = Tube Rupture
    Row 131 Column 91, 21 percent wall wear + 81 % in 9 months = 101 % wear = Tube Rupture
    Row 129 Column 93, 22 percent wall wear + 81 % in 9 months = 102 % wear = Tube Rupture
    Row 126 Column 90, 21 percent wall wear + 81 % in 9 months = 102 % wear = Tube Rupture

    H. Intertek APTECH Operational Assessment referenced in item 1 above, page I-iv states, “Two OA analysis cases were evaluated based on the sizing techniques used to define the Unit 3 TTW depths. Case 1 evaluated the situation where voltage based sizing for Eddy Current Testing Examination Sheet (ETSS) 27902.2 was used to establish the TTW depth distributions and the correlated wear rate with wear index. The results for Case 1 indicate that the Structural Integrity Performance Criteria (SIPC) margin requirements are satisfied for an inspection interval length of 0.94 years (11.5 Months) at 100% power level. For Case 2, where the TTW depths were resized by AREVA using a more realistic calibration standard, the SIPC margins will be met for an inspection interval length of 1.04 years at 100% power level. The plan for Unit 2 is to operate for an inspection interval of 5 months at a 70% power to provide additional margin to the industry requirements for tube integrity. Tube burst at 3xNOPD (Normal Operating Pressure Differential) is the limiting requirement for inspection interval length. Therefore, the accident-induced leakage requirements will be satisfied provided that burst margins at 3xNOPD are maintained during the inspection interval.
    I. Deterministic Analysis results shown in item G shows that all the five tubes can rupture in 9 months or less than shown by Intertek in Probabilistic Analysis of 11 months. This Probabilistic Analysis does not meet the intent of NRR RAI 32, in which SCE promised to provide an OA that includes an evaluation of steam generator TTW for operation up to the RTP.

    CONCLUSIONS: SCE is once again trying to circumvent and gaming the NRC RAI #32, just like avoiding 10 CFR 50.90 for the Brand New $570 Million RSGs . MHI Anti-vibration bar structure, designed for out-of plane vibrations, is incapable of preventing the adverse effects of tube-to-tube wear or fluid elastic instability (high dry steam) at 100% power operation or main steam line break. We saw the destruction of SONGS Unit 3 RSGs due to tube-to-tube wear or fluid elastic instability (high dry steam) at 100% power operation or Main Steam Line Break Testing. According to the analysis of Unit 2 Plant Operational Data/Procedures and Westinghouse Operational Assessment, fluid elastic instability (high dry steam, high fluid velocities, in-plane vibrations) conditions did not occur in Unit 2. Therefore, this insufficient contact tube-to-AVB forces in Unit 3 causing the FEI is based on hideous data and unreliable MHI Computer Modeling once again. Taking credit for double contact tube-to-AVB forces (Better supports), which prevented in-plane vibrations or Tube-to-tube wear in Unit 2 by NRC Region IV AIT Team/SCE/MHI directly contradicts and conflicts with statements made by Dr. Pettigrew, Westinghouse, AREVA, John Large and in consistent with Unit 2 Operational data. This analysis by SCE does not meet the intent of Federal Regulations, NRC Steam Generator Tube Structural Integrity Criteria, SONGS NRC Approved Technical Specifications, NRC Reasonable Assurance Criteria, NRC Chairman’s Standards and SCE’s Overriding Obligation for Public Safety. A Lot More to Come… Thanks NRC Staff… HAHN BABA

  23. Sincere Thanks to Mr. Victor Dricks, Mr. Cale Young, Mr. Ryan Lantz, Mr. Randy Hall and entire NRC Staff. Thanks to NRC posting this blog

    As a part of San Onofre Public Awareness and SCE/MHI Lessons Learnt Series, Brilliant NRC Staff should summarize for the benefit of General Public an Unbiased Gap Analysis on San Onofre Degradation before Unit 2 restart based on the plant data and a review of following reports:
    1. NRC AIT and follow up reports
    2. SCE Root Cause Analysis Evaluations (Safety Short Cuts and Avoidance of 10 CFR 50.90)
    3. Westinghouse Operational Assessment
    4. AREVA Operational Assessment
    5. MHI Root Cause Analysis & Technical Reports (Safety Short Cuts and Avoidance of 10 CFR 50.90)
    6. SCE Enclosure 2 and Remaining Operational Assessments
    7. Internationally Known Chartered Engineer and Nuclear Scientist John Large Technical ASLB Paper
    8. Internationally Known Nuclear Engineer Arnie Gundersen’s Technical Papers
    9. Professor Daniel Hirsch’s Report
    10. Mitsubishi AVB Testing for San Onofre RSG Repairs
    11. Dr. Pettigrew’s and other research papers published between 2016 and 2011 on FEI & FIRV
    12. SONGS Special Tube Inspections & Insider Reports
    13. NUREG 1841- Comparison of CE Replacement Generators with San Onofre
    14. SCE Response to NRR RAI’s
    15. Fluid Elastic Instability, AVB Contact Forces and risks of Design Bases Accidents at 70% reduced power, Accuracy of Thermal-Hydraulic Computer Modeling and Reliability of SCE Operator Actions
    16. Analysis of San Onofre Units 2 & 3 Operational Data and its impact on Units 2 & 3 Cause Root Cause Evaluations and how it relates to Fluid Elastic Instability, Flow-induced Vibrations, Mitsubishi Flowering Effect and AVB Contact Forces
    17. SCE’s Compliance with NRC CAL and NRC Justification of SCE 10CFR 50.59 and Assurance to 8.4 Million Southern Californians based on Scientific Facts and Operating Experience

    Thanks…. HAHN BABA

  24. In answer to your question on the difference between the DMIMS-DX Loose Parts Monitors (LPM) and the BatScan Acoustic Monitoring system; LPMs are optimized for monitoring the reactor primary circuit, specifically to warn the Operator when foreign bodies (e.g. broken parts) which are being carried around the primary loop, impact with the vessel wall or piping. Its installation is mandated by NRC.

    In contrast, the BatScan system is designed to both monitor for and locate localized noise sources inside a SG, and notify Plant Operators in sufficient time to take appropriate action to mitigate damage propagation, e.g. that caused by a broken part. Monitoring from the outside of the SG, BatScan detects noise sources within 2 seconds, and locates to within a few centimeters inside the steam generator tube bundle even when totally masked by full power, background noise (-20 dB S/N), and has a false alarm rate of less than 1 false alarm in 30 years of continuous operation.

    BatScan algorithms, components and performance have been fully tested, verified and validated from detection of micro leaks to full SG tube bursts. The system was installed and operated successfully for two years on a full size SG, validating its performance characteristics. During operation, it detected and monitored an unexpected H2O leakage across the pressure seal of the SG head; the leak was equivalent of a shot glass of water per day. Its use is not limited to NPP steam generation monitoring; it also successfully monitors the exhaust noise from subsonic and supersonic jets engines, and can detect and locate fault operation in rotating machinery.

    It would seem from all reports that NRC has both failed to recognize that vibration technology is available today nor has it required its installation on current operating NPP SGs. A technology with performance characteristics such as the BatScan system offers would not only protect current SGs but could lead to broader and deeper knowledge of flow induced vibration issues in future. This can result in plant requirements and design enhancements.

  25. Thank you for your reference to the Allegation/Violation submitted to the Office of Chairman of NRC. It appears to be a comprehensive review of the steam generator tube/retainer bar vibration issues and seven possible violations that need to be addressed. I believe that aggressive questioning of any possible safety implications or responses by regulatory organizations is a very necessary and essential part of the safety process for safe nuclear power. I admire and encourage the oversight and dedication of individuals and organizers to ensure all possible efforts are made to ensure safety and reliability across the whole nuclear industry, including the seven issues documented.

    I want to again state that my concerns are at a higher level. NRC must have been aware that fluid flow induced vibration was considered an issue in the SG design, not only at SONGS but also with most SG designs. Even knowing this, NRC did not require continuous vibration monitoring of the SGs during all levels of power operation. It is this omission on NRCs part that needs to be addressed and rectified. How did the NRC, our ultimate safety agency fail to require a vibration monitor?

    A report was posted today “Audit of NRC’s Safety Training and Development for Technical Staff (OIG 13-A-14, March 14, 2013). This audit report suggests a possible contributing reason for lack of vibration monitoring. However, this does not remove the need for NRC to provide information of how they have already missed requiring vibration monitors, or how they plan to prevent other future deficiencies.

  26. Sincere Thanks to Mr. Victor Dricks, Mr. Cale Young, Mr. Ryan Lantz, Mr. Randy Hall and entire NRC Staff. Thanks to NRC posting this blog

    Nuclear Safety and Economic Lessons Learnt – San Onofre SCE Awareness Series by HAHN Baba
    1. Everyone is personally responsible for nuclear safety
    2. Leaders demonstrate commitment to safety
    3. Trust permeates the organization
    4. Decision-making reflects safety first
    5. Nuclear technology is recognized as special and unique
    6. A critical questioning and investigative attitude is cultivated
    7. Organizational learning is embraced
    8. Nuclear safety undergoes constant critical and thorough examination.

    Prepare for the Unexpected: When periodic reviews or new information indicates the potential for conditions that could significantly reduce safety margins or exceed current design assumptions, a timely, formal, and comprehensive assessment of the potential for substantial consequences should be conducted. An independent, cross-functional safety review should also be conducted to fully understand the nuclear safety implications. Plant design features and operating procedures alone cannot completely mitigate the risk posed by a beyond-design-basis event.

    The Unfortunate $1 Billon Dollar San Onofre Watergate and US Number 1 Nuclear Concern/Scandal could have been averted in one of the following ways:
    1. SCE should have not avoided the NRC 50.90 License Amendment Process, or
    2. SCE should have selected Westinghouse/Combustion Engineering or B&WI to design and manufacture San Onofre Replacement Steam Generators like Palo Verde Nuclear Generating Station Replacement Steam Generators, because SCE/Mitsubishi AVB Team did not have the skills or experience to design such complex CE Replacement Generators with all the added design changes, or
    3. SCE/MHI should have researched the Academic Papers published by Dr. Pettigrew and other researchers in 2006 and NUREG-1841 published in 2007 or contacted their Counterparts at Palo Verde Nuclear Generating Station (SCE is a 20% shareholder in Palo Verde) on how to prevent the adverse effects of fluid elastic instability and flow-induced vibrations on RSGs with high steam flows (e.g., Flat Bars, Retainer Bars, keep void fraction less than 98.5%, keep circulation ratios > 4, Operate at high steam pressures > 900 psi, Special AVB design Considerations, etc.) or
    4. Instead of rushing to make profits for SCE officers and Shareholders and speeding up the design and manufacture of Replacement Steam Generators, SCE Engineers should have analyzed the safety impact of each and every adverse design change discussed in the MHI Root Cause Report and DAB Safety San Onofre Papers (Lots More Interesting Technical Analysis to come …), or
    5. SCE should have accepted MHI recommendation to reduce void fraction, questioned the AVB and Retainer bar design, or
    6. Hired qualified CE Replacement Steam Generator, Thermal-Hydraulic, Computer Modeling, 50.59 and FSAR Experts to prepare the RSG design documents and Analyses.
    Now SCE is rushing once again to restart degraded Unsafe Unit 2 without really analyzing what can go wrong at 70% reduced power operations. Pete, Ron and Ted, Please be careful, Do not think about your millions, People do not care, but think about EIX/SCE Overriding Obligation to Public Safety, San Onofre Workers and EIX/SCE Shareholders and Creditors Hard Earned Money/Credibility (Please Read DAB Safety San Onofre Papers and Lots More Interesting Technical Analysis and Media Alerts to come ..U2 did not have FEI, operational conditions in Unit 2 and 3 were different according to Key Plant Personnel, Plant Procedures, Plant Daily Briefs & NRC AIT Report, and Statistical/ECT/Guessing/Hideous Double Tube-to- AVB Contact forces theory between Units 2 & 3 does not make any sense, SCE is forcing MHI to just…. stuff, New FEI Research….),

    Press Reports state, “The MHI Report appears to provide decisive evidence that the Southern California Edison Company (“SCE”) was imprudent in the design of the [steam generator] tubes, the failure of which has resulted in the shutdown of the San Onofre power plant. However, the costs of this plant remain in the rates that consumers are paying, and consumers remain potentially responsible for massive repair costs that would be incurred if SCE ultimately seeks to restart the whole plant. The dramatic new information revealed by . . . the MHI Report calls out for the Commission to address these key questions sooner rather than later. What is at stake in this case goes to the essence of the Commission’s responsibility to protect the rate-paying consumer. The existing rates that SCE’s customers are paying for the closed plant, even if eventually refunded, constitute an involuntary loan at low interest to SCE.”
    “The MHI report appears to squarely place the cause of and responsibility for the outages at San Onofre at Edison’s feet,” said S. David Freeman, former head of the Los Angeles Department of Water and Power and a senior advisor to Friends of the Earth. “It’s urgent that the Public Utilities Commission prioritize this phase of the investigation, and the additional documents we’ve requested from Edison are important to answering these questions.” Rinaldo S. Brutoco, president of the World Business Academy, said that California ratepayers should not be forced to pay hundreds of millions of dollars for Southern California Edison’s faulty steam generators. Brutoco said: “The Academy, which believes that companies can generate profits while being good corporate citizens, concludes that Edison’s actions, in circumventing federal nuclear safety regulations and playing radioactive Russian roulette with the health of Californians, represent an unscrupulous way of doing business.”

  27. Sir, How is the operation of your Company’s Batscan system different from Westinghouse DMIMS-DX™ system to detect tube-to-tube contact and tube leaks in a SG U-Tube bundle during fluid elastic instability conditions due a main steam line break with failure of the main steam isolation valve to close. How will operator use this reliable tool to take timely actions, when the SG is going to be empty in 5 minutes. How is this system tested, verified and validated in a Main Steam Line Break scenario. SCE and NRC Region IV tried in vain to sell this concept to NRC NRR Office but were shot down by the NRC I&C Branch Engineer. Thanks for your help in solving this critical problem.

    Westinghouse DMIMS-DX™ systems provides fast, reliable detection of loose part impacts within the Reactor Coolant System (RCS), while minimizing the generation of false alarms. This monitoring system is a greatly enhanced version of the previous Westinghouse DMIMS system, employing the latest digital technology and offering significant operational advantages to our customers.
    Loose parts monitoring is based on listening for the impact of loose parts against fixed components within the primary system as they are propelled by the coolant flow. This application appears simple on the surface, but its effective implementation is not an easy task. The noises typical of an operating plant can generate false alarms that reduce operator confidence, interfere with normal operations, and cause unnecessary expense. The Westinghouse DMIMS System uses a patented algorithm to determine the metallic characteristics typical of loose parts. This algorithm and the associated alarm algorithms, together, minimize the generation of false alarms and have established a reputation for reliability within the industry.

  28. Ted Craver says that SCE has a monopoly franchise agreement with every city to supply electricity. CPUC President is a former officer of SCE and is approving unjustified SCE Secretive Costs and passing it unfairly to customers without any accountability. Southern Californians require safe, reliable, affordable and well managed power. So, here are few things for Ron, Ted and Pete to consider and take appropriate action:
    1. San Onofre Unit 2 is not only unsafe for a design basis main steam line break accident but operating at 70% percent reduced power does not make any economic sense. Let SCE and Its Independent Experts prove not by probability and operator action, but by deterministic analysis and proven actions that San Onofre Unit 2 operation is safe during a design basis accident operating at 70% percent reduced power with FEI, FIRV and MFE in the entire U-tube bundle with jet impingement from flashing sub-cooled feed water. Assume that in-plane FEI velocities are double the out-of-plane FEI velocities.
    2. It is very clear from a review of the MHI Root Cause report and testing of AVB’s in Japan that MHI is not capable of re-building or repair damaged AVB’s. Please stop wasting time and EIX/SCE Shareholders, Creditors and Customer’s money and give Westinghouse the contract to repair/rebuild both San Onofre Units.
    3. Fire the San Onofre retaliatory and inefficient members of the Senior Leadership Team. These leaders are paid a lot of money, perks, performance bonuses and stocks, but SONGS performance has not improved under these leaders since 2007 and now both Units are shutdown with undetermined future, political, financial, safety culture and negligence consequences.
    4. Even if NRC gives permission and CPUC approves the funds to Restart Unit 2, Ron, Ted and Pete are still on the hook, because, “If an accident happens, Ron, Ted and Pete will lose their face and Million Dollar Jobs & Stock Portfolio. Additionally, EIX/SCE Shareholders, Workers, Creditors and Customers will lose money invested in San Onofre and Transmission & Distribution Infrastructure.”
    5. Ted Craver, The ultimate decision and risks are yours. NRC Moderator and San Onofre Public Affairs officer Mr. Victor Dricks is requested to send this Public Safety message to Ted Craver, Pete Dietrich and Ron Litzinger….
    Thanks to NRC for posting this blog. Hahn Baba

  29. I am in the electronic engineering field and fire alarm life safety was a major area, we have ULC requirements to abide by and if you change anything in the design and manufacturing of the product you will have to get it tested by ULC or in sum miner items have them go to the site to approve the changes which is usually a one of a kind ancillary type device like building graphic enunciator panels. The type of changes that require retesting are changes of all kinds even screw size, power supplies, relay type, bulbs, labels, changing electronic components to a different manufactures equivalents, wire gauge and type, etc.
    Here we have changes made
    [1] type of metal pipe
    [2] extend lengths of pipe
    [3] change its form by bending it differently
    [4] change and add supports
    [5] added pipe loops
    [6] reconfigure pipe loops
    [7] added restrictions (narrowed pipe inside diameter in areas of pipe)
    [8] probably others
    And they managed to bypass NRC rules for re-certification !!!
    This looks bad and makes it look like all that where involved new exactly what was being hatched up and maybe even NRC, everyone that has Experience in contracting and working in this industry knows the rules inside and out or they would never have been put in their position. If !!! NRC did not know, then to stop this from happening again they will have to make the rules more stringent so that any changes will require NRC to investigate to see if the changes require a recertification. This would put the responsibility on NRC totally. I do not believe NRC wants that, so they will leave it as is and hope that this experience will shape up the industry.

  30. Author: David A. Greene, C.Phys.; F.Inst.P.; F.Inst.M.C.

    OVERVIEW
    This blog submittal covers a review of the MHI document on SONGS steam generator issues and problems. Based on this review and my own experience, suggestions for moving forward to resolve the issues are suggested and discussed. The responsibilities of NRC in moving towards practical, safe and reliable return of the steam generators to operation are an important part of possible solutions.
    I have many decades of working in the US and UK in nuclear technology and engineering, and steam generators in particular; including thermodynamics, lead roles in instrumentation and control, and R&D in several specialized SG engineering and technology fields. I have been a member of National and International specialist information exchange and review teams. I have also had my engineering and R&D programs reviewed or been a member of review teams. It is against this background that I offer comments on this MHI report. I should also state I have never been employed by either MHI or SCE. I am a small business owner who has consulted in the nuclear field, but never for these companies. My company does have products which can be used in the nuclear field but they have not been purchased by either company.
    DISCUSSION
    NRC has published a non-proprietary, redacted version of the 135 page MHI report “Root Cause Analysis Report for tube wear identified in the Unit 2 and Unit 3 Steam Generators of San Onofre Nuclear Generating Station”. MHI have primarily protected the names of workers, and very detailed information on certain component or fabrication values they consider proprietary information which would be of value to competitors. Redactions in this report in no way prevent a full understanding of the report contents on issues with steam generator performance issues.
    First a general comment on the MHI document; the redacted report appears comprehensive and open in discussing both MHI design/fabrication process and their investigation into the root causes suspected for the tube wear problem. It is an engineering document presenting factual information and I saw no evidence of attempts to mislead or cloud issues.
    A Certified Design Specification SO23-617-01, Rev. 3, issued by SCE required an effective zero gap and gap uniformity and parallelism of the tube bundle in the out-of-plane direction. Establishing the goal to reduce tube-AVB gaps to an effective zero gap was in accordance with well accepted industry practice and understanding that minimizing gaps was highly desirable in preventing tube vibration wear. MHI had sought to minimize tube-AVB gaps in its previous SG designs. However, MHI took additional steps to minimize the tube-AVB gaps for the SONGs RSGs and to provide for gap uniformity throughout the U-bend region of the tube bundle.
    MHI and SCE augmented their design and fabrication teams with consultants who had experience of large U-bend style steam generators. They compared their design features to existing, successful operational steam generators. SONGS steam generator’s design was very robust, built to last a very long, long time. MHI put a lot effort into every step from design and material selections to fabrication. The design and fabrication is consistent with Industry efforts for Plant Life Management (PLiM) to safely increase the utility of older plants, both fossil fired and nuclear.
    In the report MHI provide full details of their design and manufacturing process; it becomes obvious from reading the report the intention of MHI and SCE was to produce a state of the art, safe, reliable steam generator. The MHI-supplied replacement SGs (RSGs) had a number of differences from the existing steam generators provided by Combustion Engineering. One of the main differences was the substitution of Inconel 690 for Inconel 600 as the tube material. Inconel 690 is more resistant to corrosion than Inconel 600. The Certified Design Specification issued by SCE also required that MHI incorporate many design changes to minimize degradation and maximize reliability. For example; an effective “zero” tube-to-flat bar gap, gap uniformity and parallelism of the tube bundle in the out-of-plane direction prior to tube fabrication. These steps included increasing the nominal thickness of the Anti-Vibration Bars compared to previous MHI successful SGs and reducing the manufacturing tolerance of AVB thickness and twist in order to achieve effective zero gaps and provide gap uniformity. Steps were taken as well to minimize tube ovality and to minimize variations from the design value. Also, numerous additional steps were taken in fabricating the tube bundle to assure gap uniformity throughout the U-bend region. Additionally, in the fabrication of the Unit 2 RSGs MHI identified other enhancements that were implemented in the fabrication of the Unit 3 RSGs.
    The adequacy of the design against out-of-plane FEI was confirmed through test data and analyses that conservatively assumed that one of the AVBs provided in the design was inactive (that is, ineffective against out-of-plane FEI). Analyses using this criterion showed that an adequate margin against out-of-plane FEI exists in the SONGS RSGs. An additional AVB had been added to the design to provide further margin against out-of-plane FEI.
    My overall impression from the report was MHI and SCE produced magnificently engineered, state of the art steam generators; the type of steam generators that would set future SG standards for both replacement and for use in new power plants. As a person knowledgeable in the field I was impressed with the depth and breadth of the engineering efforts made to design and fabricate a safe, reliable modern steam generator.
    The report also makes it obvious that both companies understood flow induced vibration was potentially a sever reliability issue for power plant steam generators. Significant design effort was expended to minimize or prevent vibration problems. They used computer code analyses to help check design variant impact on vibration potential. Experimental and analytical investigations were completed. However, computer codes are a “best effort” to simulate thermo-dynamic performance and vibration potential. None of these approaches can provide absolute assurance that the design is adequate.
    One major issue I have is MHI/SCE did not install or have a vibration/wear monitoring system that allowed the plant operators to continuously monitor for vibration. (add something about NRC also not requiring such as system.) Since this was essentially a new design approach for steam generators (and its components and sub-components) it seems that vibration monitoring should have been an essential requirement. I believe that it is still an essential requirement for continued operation.
    Another issue is that MHI and SCE have fully opened their coats on their actions and these steam generator issues, but where is NRC in this picture? NRC’s reason for existence is to provide overview of nuclear power plants. It was, and remains their responsibility, to ensure safe design and operation of the San Onofre Nuclear Power Plant. Why or where did their overview fail to ensure safe and reliable operation? Granted a secondary monitoring system provided an indication of a steam generator problem, but why did they accept that a major design parameter (tube vibration) would not be continuously monitored in the much modified steam generator design? And where is their ‘mea culpa’ (or better still mea maxima culpa) public document equivalent to the MHI document? Will they fall back to noting the loose parts monitor installed on the secondary loop? I hope not! The primary purpose of the loose part detection program is the early detection of loose metallic parts in the primary system (NUREG-0933, Main Report with Supplements 1–34). Will NRC say they only expect to detect a vibration problem when bits of steam generator tubing start to bounce around in the steam generators? I believe that their role was to require that an effective vibration monitoring system was in place on the new RSG design. This apparently did not happen.
    NRC is an independent Agency. I was pleased that our California Senators have involved themselves in the issues. They have not used SONGS problems to push political issues, but acted as California’s front line representatives to the US Government. I hope they will continue to ensure the local NRC will receive any additional resources or support needed to get San Onofre NPP back in service, and providing revenues and services to both the local communities and the State of California. Until the current issues are resolved SONGS remains a drain on our State economy as well as the Companies involved.
    I believe MHI/SCE need to provide a clear plan to return the steam generators to service. If this includes installing a continuous vibration monitor, I believe the MHI/SCE approach of running at partial load is a good option. The steam generators have existing ports and nozzles that might allow “fixes” to be tested and provide confirmation that the fixes are viable. Included in this approach would be an internal vibration source (temporary or permanent) to demonstrate viability of continuous monitoring. I think eventual test operation at all operating conditions is essential to demonstrate fixes and monitoring are viable I would feel uncomfortable with operating at a “safe” low power condition without a verified and validated vibration monitoring system. The science of vibration engineering in complex geometries with complex thermo/fluid dynamic conditions is not understood enough to precisely predict outcomes; not even with the most powerful CFD computer programs.
    NRC need to make clear up front to both companies and to the public what they expect or will demand, including criteria for measuring, verifying and validating fixes and steam generator monitoring. The “get me another rock!“ approach to setting requirements is not going to be suitable. I hope that the requirements will include plans for vibration monitoring for an extended period, possibly at partial power.
    We know the processes and procedures needed to achieve this objective. All parties now need to focus on making them work!
    GHI DOCUMENTATION OF OPERATING PROBLEM
    The report documents that a problem in all four SONGS Replacement Steam Generators (RSG) was found after a primary loop into secondary loop small water leak was indicated in one RSG. Primary to secondary unplanned water leakage of approximately 82 gallons/day was measured in one RSG. The direct cause of the leakage was determined to be tube to tube wear in the free span section of the U-bend region of the RSG, leading to a leak from one of the tubes in that region. It was determined all of the new generators had higher tube wear than expected. Since the incident MHI and SCE have worked together to establish what caused the problem, calling on specialized help as needed.
    So what does the document report about their operating problem? Firstly it provides factual power plant information on the extent of the damage. The degree of damage from the relatively short period of steam generator power operation was extreme, and MHI was obviously shocked by the extent and severity they discovered. Teams were set up to determine the cause of the problem, the so called Root Cause Analyses, by both MHI and SCE. These teams concentrated on the RSGs because original steam generators they replaced did not have this wear problem. Concurrently MHI technical teams conducted in-depth technical evaluations of the RSG design and fabrication.
    MHI, supported by SCE, provide full details of their investigation into possible causes for excessive wear resulting from design and manufacturing and operating process and procedures. A modern problem analysis technology was used to systematically investigate and guide SG Problem analyses: Root cause analysis is a technique to systematically define and assess a complex set of possible causes of a problem. It was initially developed for business analyses but rapidly expanded to engineering and scientific fields. I am familiar with them, having completed training in the technique and successfully used it for systematically assessing many potential problem causes and possible solutions. MHI and SCE used these techniques to point to possible causes of the wear problem in the RSGs. Concurrently, possible mechanistic reasons for tube wear were investigated to provide inputs to the comprehensive problem analyses. Coolant flow caused tube vibration was identified as a probable cause, especially vibrations due to a phenomenon called fluid elastic instability. The main conclusion was tube wear was caused by random vibrations of the tube. This is an important conclusion because it means the damage was not primarily caused by resonant tube vibrations, which would imply a possible design or manufacturing problem. The damage is believed to be due to turbulent flow driven phenomena.
    Secondly, MHI teams searched all their historical design, technical, and fabrication reports and records for the replacement steam generators. The teams were not searching blind; they had the advantage of hindsight and knowledge of the steam generator performance. They had the advantage of the root cause analyses and several years of actual steam generator operational experience.
    I have been both a member of such retrospective review teams, and also the subject of reviews. Every aspect of a design, drawing, document, calculation, test, test facility, test plan, test report, logbook, etc., etc., etc., is questioned or second guessed; often several times by different teams. I could use the term witch-hunt but this would give a very wrong impression; it is a cooperative, in-depth search for truth. It is revisiting results and conclusions, data reviews, questioning reasons and assumptions. It is searching for a needle in a haystack, the needle being possible reason (s) for the steam generator problem.
    MHI report content indicates there are no smoking guns. Review of ‘root causes’ (MHI report section 5.8) have a flavor of second guessing rather than identifying any really new possible cause. For example it was believed that having a ‘zero gap’ in the anti-vibration bar would lead to less wear, but the conclusion of the review team is this ‘improvement’ was possibly a contributing factor to tube wear damage rate.
    Tube Wear Damage: Technical evaluations suggested five possible types of tube wear were present, two types being the most significant; 1) tube wear in the upper U-tube bend region of the steam generator with sufficient movement for tubes to collide; and also cause wear along the whole tube length where they contacted the anti-vibration bars or tube support plates. 2) Retainer bar to tube wear due to flow induced vibration Tube wear occurred on tubes at the periphery of the U-bend, adjacent to the retainer bars; these tubes have no wear indications at any other location along their length, which indicates that they are stationary, and that the wear is caused by movement (vibration) of the retainer bars.
    CONCLUSION
    I believe NRC needs to now step up to the plate and require that a proven effective vibration monitoring system is in place on the RSG’s at SONGS prior to startup. This system must provide Operations staff with timely, continuous, real-time data on operating conditions such that potential problems are clearly located and identified prior to escalation, including information on when and how operators should proceed. Ideally the system should have been proven effective under similar operating conditions for an extended period. We know that a fully engineered, verified and validated SG monitor that uses external sensors for reliability, long life and ease of replacement is currently available, e.g. http://www.grdi.com.

  31. Compilation of SCE Retaliation and Fear Free Press, Friends of the Earth and DAB Safety Team Reports – San Onofre Public Awareness Series by HAHN BABA

    Redacted version of Mitsubishi root cause analysis of San Onofre replacement steam generators uncovers SCE Innocent Safety Role in $1 Billion Dollar Watergate Ratepayer Fiasco and Number 1 US Nuclear safety Concern. MHI report reads more like an apology than a Root Cause Analysis. Ignorance and False Innovative Claims are no excuse for violation of Federal Regulations and Public Trust.

    In a statement, Honorable Senator Barbara Boxer and Congressman Ed Markey state the reports “raise serious concerns about whether Southern California Edison and Mitsubishi Heavy Industries rejected safety modifications to avoid triggering the more rigorous license amendment and safety review process. A license change would have required plant operator Edison to go through a judicial-style review before installing the new generators. Boxer asserts that Edison tried ­— and succeeded — in getting around that review.”

    Last week, Mitsubishi Heavy Industries (MHI) released a report showing that both MHI and Southern California Edison (SCE) knew that replacement steam generators built by Mitsubishi for SCE’s San Onofre Nuclear Generating Station had major design problems as far back as 2005. The report further states that the companies chose to not make these findings public out of fear they would lead to costly public hearings and more rigorous oversight by the Nuclear Regulatory Commission.

    As it turned out, however, burying the information was probably the worst thing SCE could have done, as the faulty steam generators caused vital tubes to vibrate, producing such damage that the plant had to be shut down in January 2012 . A year later, San Onofre remains closed, and the release of MHI’s bombshell report last week has only fueled demands it never be allowed to reopen.

    Yesterday, for example, the environmental-watchdog nonprofit group Friends of the Earth called on SCE to release its own records on what it knew about the faulty replacement steam generators, when it knew it, and why it chose to bury the information.

    “The MHI report appears to squarely place the cause of and responsibility for the outages at San Onofre at Edison’s feet,” S. David Freeman, former head of the Los Angeles Department of Water and Power and a senior adviser to Friends of the Earth, says in the group’s announcement yesterday. “It’s urgent that the Public Utilities Commission prioritize this phase of the investigation, and the additional documents we’ve requested from Edison are important to answering these questions.”

    Another group monitoring the disaster at San Onofre is the World Business Academy, whose president, Rinaldo S. Brutoco, insists SCE must not pass on the cost–estimated to run into the hundreds of millions of dollars–of its misconduct to its customers. “The Academy, which believes that companies can generate profits while being good corporate citizens, concludes that Edison’s actions, in circumventing federal nuclear-safety regulations and playing radioactive Russian roulette with the health of Californians, represent an unscrupulous way of doing business,” he said.

    And here is what Southern California Edison says, “The anti-nuclear activists have called the MHI report a ‘bombshell’ which couldn’t be further from the truth,” said Pete Dietrich, SCE senior vice president and chief nuclear officer. “In fact, the MHI letter explains that SCE and MHI rejected the proposed design changes referenced in the evaluation because those changes were either unnecessary, didn’t achieve objectives or would have had adverse safety consequences. Our decisions were grounded in our commitment to safety. SCE did not, and would never install steam generators that it believed would impact public safety or impair reliability. MHI repeatedly reassured SCE that based on their testing, the steam generators met safety requirements and would function for 20 years. The MHI letter specifically confirms that at the time the replacement steam generators were designed, MHI and SCE believed that the “replacement steam generators had greater margin against U-bend tube vibration and wear than other similar steam generators.” MHI warranted the steam generators for 20 years.As with all engineering evaluations, the MHI letter and report describe a technical evaluation process and need to be read in their entirety to understand the conclusions reached,” said Dietrich. “The activists are taking portions of paragraphs and sentences out of context, and using them as the basis of their allegations that SCE knew of design defects when the generators were installed, but failed to make changes to avoid licensing requirements. That is untrue.”

    Southern California Edison, the utility which operates the San Onofre nuclear power station, had a strict list of requirements for MHI during the design and manufacturing process, specifically created in order that the utility might justify not allowing the Nuclear Regulatory Commission to approve the designs and regulate the replacement process, by using the justifications allowed in 10 C.F.R 50.59 to claim that it was a “like for like” exchange. Most of these restrictions limited the external physical changes to a minimum by ordering MHI to design replacement steam generators which would fit within the same physical space, rather than inhibit multiple changes from being made to internal components. There is an age-old axiom about what kinds of beauty are only skin deep.

    Excerpt of a Edison Contract Document received from a SONGS Anonymous Insider states, “The Supplier shall prepare and submit for Edison’s approval a …[Redacted]… demonstrating compliance of the RSG design with all SONGS …[Redacted]…. The report shall include an engineering evaluation, including all necessary analyses and evaluations, justifying that the RSGs can be replaced under the provisions of 10 CFR 50.59 (without prior NRC …[Redacted]…). The report format shall follow the guidelines of …[Redacted]… in order to facilitate preparation of the 10 CFR 50.59 evaluation. The 10 CFR 50.59 evaluation shall be performed by Edison. Specifically, the …[Redacted]… shall include, as a minimum, the following: Description of the RSG impact on the existing systems, structures, and components. Detailed calculations addressing the RSG impact on the UFSAR analyses, …[Redacted]… The calculations shall include a Summary of Transients Analysis that shall evaluate the RSG impact on each event. When required by the Summary of Transients, event specific calculations shall be performed. All evaluations, analyses, and calculations shall be consistent with the latest SONGS analyses of record, evaluation methodologies, analysis processes and computer codes existing at the time of performance. The Supplier shall achieve acceptable results by minimizing any reduction in operatingmargins (e.g., increasing Reactor Over Power Margin [ROPM] requirements). If the Supplier determines that reduction of operating margins is necessary, it will inform Edison as soon as practical, so that the impact can be mutually agreed to, such that there is no, or minimal, impact on plant operation. All evaluations, analyses and calculations performed by subcontractors shall be provided to Edison for review, and all Edison comments shall be resolved in a manner acceptable to Edison prior to Supplier internal document approval. All evaluations, analyses and calculations, including computer code input and output, in their entirety, will be provided to Edison for future Edison use.”
    The report quickly shoots down this argument, and details a list of changes that were made which the utility felt still fit within the 50.59 process.

    1. SCE imposed physical and other constraints on RSG design characteristics in order to assure compliance with 50.59. (RSGs must fit within same space)
    2. Increased heat transfer surface area 11% from 105,000 ft2 to 116,100 ft2.
    a. Higher void fraction (maximum steam quality) – Adverse 50.59 Design Change (Required a 50.90 License Amendment) – Caused Fluid Elastic Instability in Unit 3, one tube leak, failure of 8 tubes at MSLB test pressure and more than 300 tubes experienced > 35% loss in wall thickness.
    b. Added 377 more tubes (4% heat transfer surface area) and increased the average length of tubes by 50 inches – Adverse 50.59 Design Change (Required a 50.90 License Amendment)
    c.. Increased U-bend radius
    d. Added more AVBs – Adverse 50.59 Design Change (Requires a 50.90 License Amendment)
    e. Required more stringent tube-to-AVB gap requirement
    f. Distances between AVB tube supports are shorter

    Notes:
    A. In 2006, Dr. Pettigrew, the World’s Foremost Expert on Fluid Elastic Instability warned about the ineffectiveness of the AVB Flat bars for in-plane vibrations and increased in-plane velocities and told the designer and manufacturers to verify the design of flat bars for in-plane vibrations.
    B. A review of Arkansas Nuclear one Unit 2 indicates the AVBs in adjacent columns are inserted to different depths (i.e., staggered) to limit the U-bend pressure drop and to discourage the formation of flow stagnation regions. The AVBs are nearly perpendicular to the centerline of the tubes at all locations in the U-bend region to provide support without unnecessary tube contact. These features provide margin against flow stagnation, corrosion, and tube vibration.
    C. But SCE and MHI missed the boat and are now suffering the adverse financial, political and credibility consequences with both San Onofre Units Shutdown

    The San Onofre replacement steam generators had more tube vibration margin than comparison replacement steam generators at the Fort Calhoun Nuclear Generating Station, also designed by MHI, which only experienced a small number of tube wear occurrences. But, MHI and SCE decided to change the very alloy the tubes were made out of, for one which is more prone to fluid elastic stability, but was thought to be more resistant to corrosion. The tubes at San Onofre are longer, have thicker walls, and are stiffer, than those in the Fort Calhoun generators. The new replacement design also increased the heat transfer surface area, which increased the steam quality in the generators. On top of that, they elongated and thinner low frequency the retainer bars that are installed around the tubes, which caused an unexpected increase of amplitude vibration contact between tubes and bars causing even more wear (Caused a number of tubes to exceed > 35% loss in wall thickness plugging limit, with one with 90% tube wall thickness wear, almost caused another accident at Unit 2, if Unit 2 would have continued operating, but people were lucky because Unit 2 was shutdown due to refueling outage. NRC posted on its website, but SCE never told the public. NRC gave SCE a low level violation for not checking the design of the MHI Retainer Bar.

    Mitsubishi than revealed that in-plane instability like this had never been experienced in the nuclear industry prior to San Onofre, and that none of the predictive models were even capable of including it in their analysis. Even more, none of the 12 AVB supports were found to be restraining this tube motion. Because they did not even know about in-plane fluid elastic instability at time of design or manufacture, let alone preventing it, they never thought to question if with those changes, they would need more contact force to prevent vibration increases.

    Note: A review of Dr. Pettigrews and other papers between 2006 and 2011, the in-plane velocities are double than the out-of-plane velocities predicted by ATHOS out-of-plane models. See Notes A, & B above.

    Mitsubishi records two main root causes, and a redacted list of contributing causes. One root cause and all contributing causes are associated with the “decision-making” and “resources” processes. The other root cause and two of the above mentioned contributing causes are associated with standard “work practices”. Essentially, MHI states that the root causes all relate back to a lack of resources, a decision-making process which wasn’t properly regulated or guided, and assumptions made based on common “work practices”.

    NOTE: The actual causes are lack of “critical questioning & investigative attitude, financial greed over public safety, time pressure, lack of solid team work and alignment between SCE/MHI, complacency, lack of review of academic research papers by Dr. Pettigrew, lack of Industry Benchmarking of in CE Replacement Steam Generator improvements made by Westinghouse and BW&I described in NUREG-1841, Lack of knowledge by MHI in computer modeling, incomplete and inadequate mock-up testing and lack of knowledge in building very unique, complex and large CE Replacement Steam Generator, preparation of defective 10 CFR 50.59 evaluation and avoidance of NRC 50.90 License Amendment process by SCE.

    It is akin to admitting; first off, we didn’t even know that these particular types of problems existed, we know the general problems which plague our decisions are based on the fact that we do this all the time, we are always limited by a lack of resources, we tend to assume it is no big deal, this is standard operating procedure; except for this time no one stopped us, because no one thought it could go wrong. Maybe if we hadn’t spent so much time trying to get around the rules, had we only required the analyses which would’ve evaluated a little more, if only we hadn’t assumed these were acceptable industry practices.

    The questions which still need answering are focused if the utility hadn’t pre-determined it would use the 50.59 process to justify the design, would Mitsubishi have acted differently, and are all parties aware of the full implication and repercussions for their actions?

    Mitsubishi admitted that there were other design changes which could’ve been made, but would’ve had “unacceptable outcomes”, and failed to list what these changes would’ve been. They did however take particular care to point out that other replacement steam generators which had been in operation for longer, did not have the same wear problems witnessed at San Onofre, which is worthy of note.

    In answer to the second question is a resoundingly no. This appears to be a blatant attempt to manipulate the system to achieve an acceptable outcome and avoid unacceptable alternatives, which undermines the very faith in the system itself; for who could have faith in something which does not do what it claims to do, and has no ability to ensure that it does in the first place?

    For most people, their perception of the law is based less on what they read, as much as they are by precedent and the way it is carried out before them. What actions can we expect, what hope in the future, when so distracted and led astray the children are, by the examples of the leaders of today?

    8.4 Million Southern Californians should request His Excellency President of United States to order a US Justice Department Inquiry of

    San Onofre is an INPO 4 Plant, with the worst fire safety, cyber security, emergency preparedness, maintenance, configuration control, procedure violations, discrimination, harassment, intimidation and retaliation record.

    Thanks to the entire NRC staff for conducting a thorough Technical Analysis, determining the exact causes of damages to San Onofre Units 2 & 3 by analyzing the operational data for Unit 2 for 2 Years and Unit 3 for 1 year and posting this blog.

  32. Unit 3 experienced FEI in ~ 1.5% of each RSG tubes due to high heat flux in the hot leg, high steam flows, high void fraction (high dry steam), high velocities, mitsubishi flowering effect, low steam generator pressures, more tubes, narrow tube pitch to tube diameter ratio (Low tube clearances), poor circulation ratios and increase in average length of heated tubes. SCE/MHI and their hired consultants AVB Team as discussed in MHI Root Cause Report due to financial/time pressures and complacency did not benchmark NUREG-1841 (Palo Verde, ANO 2 RSG AVB Designs and Operational Improvements in Circulation ratios for similar CE Replacement Generators as San Onofre) and Dr. Pettigrews warnings in a 2006 research paper warnings about the ineffectviness of flat bars in preventing in-plane vibrations or fluid elastic instability. SCE/MHI AVB team jointly rejected safety modifications to reduce void fractions for reasons (Avoid NRC Review, Delay in Installation of RSGs, Financial Considerations…) left to the imagination of the readers. Now SCE is bad mouthing MHI, Honorable Senator Barbara Boxer and Congressman Ed Markey plus unnamed Brave NRC Staff for revealing the dark inner secrets of $1 Billion Dollar RSG Debacle. Unit 2 did not experience FEI due to operational differences. The double contact force Tube-AVB bogus and unconvincing theory in Unit 2, which is attritubed to less damage in Unit 2 propogated by SCE with the backing of some Sympathetic NRC Region IV Staff and put forward by pressured MHI is based on hideous testing data to defend restart of “defectively designed and degraded RSGs” for SCE to justify SONGS stay as a base-load and grid voltage stabilizer plant. Rumors are Edison’s Obvious Cabinet Connections are admant on Restart of Unit 2 irrrespective of Public Safety Questions and Pressures for Transparency and Accountability in violation of His Excelency, President of United States’s Open Goverment Initiative. This is unacceptable in Democratic America. SCE needs to release 2 years operational data for Unit 2 and one years Operational Data for Unit 3 to independent experts to determine the exact cause of damage in Units 2 & 3. It is easy to preach Public Safety Sermon by SCE but difficult to pass the Public Safety Truth Test. To cover one truth, you have to introduce and invent a new controversy, contradiction and blame everyday. Edison can influence a few with its political connections and money but has to co-exist in harmony and respect with 8.4 Million Southern Californians. Time will tell whether safety and people win, or power and money win in a democratic society, but truth always wins, may be at some undetermined expense.. HAHN Baba
    Thanks to Honorable Senator Barbara Boxer and Congressman Ed Markey plus unnamed Brave NRC Staff for revealing the dark inner secrets of $1 Billion Dollar RSG Debacle and NRC for posting this blog.

  33. Canadian law puts liability on the contractors and equipment manufacture and if manufacture goes under its all on contractors shoulders. It maybe different for nuclear plants though.

  34. SCE’s statement is premature and that it is best to wait until ALL the experts review MHI’s documents in detail, along with their implications to the NRC “handling” of SCE and their restart plan.
    +
    Ask yourself why did Senator Boxer and the NRC sit on this infomation for so long? Many think it is part of a larger delaying PLAN to make the SCE (and their Regulators [both the CPUC & the NRC]) look good while MHI redesigns the Anti Vibration Bars for Unit 2 which will be installed soon after the restart “testing”.

  35. Good report. Time to fix blame and SONGS and juice back on-line!

    James Greenidge
    Queens NY

  36. The public has been & will continue to call for an adjudicated review of So. Cal. Edison’s actions. We are rightly concerned, San Onofre plants hold the worse safety records of all 104 US nuclear plants. And of course, its location between 2 active earthquake vaults in unthinkable.

  37. It is sad to see Edison so disrespecting the NRC with their lies, putting the public at risk, and making a mockery of the regulatory process. The Government needs to come down hard on this one, or forever lose the respect of those they regulate and those they protect.

  38. Finally: MHI’s Root Cause Analysis Report for San Onofre http://pbadupws.nrc.gov/docs/ML1306/ML13065A097.pdf
    Among other things:
    snip
    ” However, the AVB Design Team recognized that the design for the SONGS RSGs resulted in higher steam quality (void fraction) than previous designs and had considered making changes to the design to reduce the void fraction (e.g., using a larger downcomer, using larger flow slot design for the tube support plates, and even removing a TSP). But each of the considered changes had unacceptable consequences and the AVB Design Team agreed not to implement them. Among the difficulties associated with the potential changes was the possibility that making them could impede the ability to justify the RSG design under the provisions of 10 C.F.R. §50.59. Thus, one cannot say that use of a different code than FIT-III would have prevented the occurrence of the in-plane FEI observed in the SONGs RSGs or that any feasible design changes arising from the use of a different code would have reduced the void fraction sufficiently to avoid tube-to-tube wear.

    For the same reason, an analysis of the cumulative effects of the design changes including the departures from the OSG’s design and MHI’s previously successful designs would not have resulted in a design change that directly addressed in-plane FEI.”

  39. Rebates may be issued… But the ratepayers are, as of now, still paying $54 million dollars a month for no energy!

  40. Good News for everyone in Southern California! It has been said before but it bears repeating, HOW CAN PUBLIC OVERSIGHT OCCUR, when documentation is with head from the public…

    The NRC is wasting valuable time and money enabling SCE attempt to justify restarting their already damaged Unit 2 in a test mode to see what happens, instead of telling them to replace its defective poorly designed replacement steam generators!

    This matter will not be “swept under the rug” since the safety of about 8 million people hangs in the balance of this 1.3 Billion Dollars debacle!

    Note: The NRC just assessed San Onofre 2 & 3 “as needing to resolve one or two items of low safety significance,” WHICH IS A BAD NUCLEAR JOKE, considering Unit 3 has failed and can’t be operated!
    http://www.nrc.gov/reading-rm/doc-collections/news/2013/13-013.pdf

    San Onofre Unit 2 and Unit 3 have given the NRC (and the nuclear industry) a pair of BLACK EYES!

    It is time for the NRC to restrict any restart discussion until every allegation has been answered completely and all 9,737 tubes of each steam generator have been inspected visually, using the most modern techniques for both external and internal fatigue/wear damage, which has not been done to date, instead SCE has used Bobbin-coil inspection methodology which is not as effective.

    To help readers learn more about how Steam Generators (SG) can “fail” here is a link to an amazing accurate animation that was done to illustrate San Onofre’s Replacement Steam Generators (RSG) problems (which included MULTIPLE SG tube failures) and the animation even illustrates a Main Steam Line Break (MSLB): http://www.acehoffman.org/sano/SanOnofreRSGsbyAceHoffman.swf
    
Note: By scrolling over the animation a large number of additional animations can be viewed!

  41. Who is paying for the tests by NRC, is it the owners, designer, manufacture, contractors or public?
    Probably the ownerbecause they can raise rates so public will end up paying for it all.

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