Thursday, May 21, 2015

Millstone: Response to Special Inspection

Originally posted on 10/27/14

OCT 31

I am confused on why the SLOD system wasn't in Tech specs? Why didn’t the information notice response get them to put the SLOT system into tech specs?  As NRC Enforcement came out of these special inspections and declared the transmission system wasn't safety related according to the FSAR, why didn't the agency required them them to put the SLOD system in TS or find it as a flaw by Millstone with their FSAR?
I want to state here for the record, LOOPs never comes from a wrong switch movement or a short from an unexpected safety device. A LOOP takes many years of poor decisions and improper analysis…it always comes from a wounded and disease culture over years of sleeping on watch. A licensee can’t create a LOOP on there own…it takes a complicit regulator. A LOOP is always a pretty good indicator of the health of organizations. LOOPs are very hard to create!!  
In their response to IN 2012-03, why didn't that key Dominion and NU into the SLOD system wasn't properly characterized in the FSAR and controlled through tech specs?
If the SLOD system was in Tech Specs, there never would have been dual plant trip and loss of offsite power event. They would have been forced into getting a licensing amendment?

How are similar transmission system SLOD systems in the nuclear industry characterized in their FSARs and tech specs? This probably only has relevance in multi-unit sites.    
Inadequate Implementation of Dominion’s Design Change Process Enforcement: This finding does not involve enforcement action because no violation of regulatory requirements was identified, as SLOD was a non-safety related system, and therefore, not subject to 10 CFR Part 50, Appendix B requirements. Dominion entered  this performance deficiency into their corrective action program (CR 553968). Because this finding does not involve a violation of regulatory requirements and is of very low safety significance (Green), it is identified as a finding. (FIN 05000336, 423/2014011-02,Inadequate Implementation of Dominion’s Design Change Process).
Oct 30 12:00 New: what does the mean? 
Was the SAR seen by the NRC and is the SAR in Adams?
What is the extent of condition or cause with Dominion's declaring not needing a LAR and falsely saying these is no increase in risk or it is not a design change? Is their other missed Licence Amendment Requests?   
Was the NRC informed of the UFAR update and why didn't that cue the NRC it was a improper plant design change?  
These design change documents included a 10 CFR 50.59 screening and applicable safety analysis report (SAR) change  notices for both the Millstone Unit 2 and 3 UFSARs.
Pilgrim plant is recent years had LOOPs out the ying yank…all sorts transmission and on property line shorts and trips. So how are the Pilgrim power line problems related Millstone?
I sure would like to understand why and the duration of this maintenance activity on the lines.
Prior to the event, one transmission line had been OOS for scheduled maintenance.
This is the guys who started the cascade accident called a dual plant trip and loss of all offsite power.  I certainly would like to understand this short and then how it tripped the second line.
A suspected ground fault on the grid in the Northeast Utilities’ Card substation caused the loss of offsite line 383. (Seems it was caused insulator and some kind of trouble with the protection circuit.) 
So the question remains, in a change to a facilities licence, why can't the NRC catch a wrong call in the screening and 50.59 on a design change. Why does it depend on the licensee declaring they are breaking the rules?

But everyone in the "systems" feels protected and secure in operating in silowing, cubbyholes and meaningless categorizations. Holistic thinking is hard work.


Apparent Violation
As stated in the summary section of NRC Special Inspection Report,05000336/2014011 and 05000423/2014011, during an NRC team inspection conducted between June 2 and July 15, 2014, "the NRC identified a Severity Level Ill Apparent Violation (A V) of Title 10 of the Code of Federal Regulations (10 CFR) 50.59, "Changes, Tests, and
So the NRC inspectors should have been in many outage and design change meetings and seen their documents. What didn't the NRC on their own see the Millstone design change on the transmission system and the circuit change, this was big, and it entailed an increase of risk. Is the bifurcation of nuclear safety responsibilities and ownerships between a on site transmission authority and near site transmission authorities a unreviewed safety issue.  
Experiments," for Dominion's failure to complete a 10 CFR 50.59 evaluation and obtain a license amendment for a change made to the facility as described in the Updated Final Safety Analysis Report (UFSAR). Specifically, ... a
NRC OIG InspectionOn June 7, 2006, SCE notified NRC of its intent and timeline to replace Units 2 and 3 steam generators under 10 CFR 50.59. The SCE briefing document indicated there would be no associated power uprate and that associated technical specification changes were scheduled to be identified in 2007.
special protection system (SPS), known as severe line outage detection (SLOD), [was removed] which was described in the UFSAR. Dominion concluded in the 10 CFR 50.59 screening that a full 10 CFR 50.59 evaluation was
NRC OIG: An attachment to the inspection report listed, by number, the 15 screens, 8 evaluations, and 12 plant modifications the inspectors reviewed. Included within the list of eight evaluations reviewed was number 800071702, which OIG learned was the number SONGS assigned to its 10 CFR 50.59 screening and evaluation pertaining to its Unit 2 replacement steam generators. 
not required and, therefore, prior NRC approval was not needed to implement this change. The team concluded that prior NRC approval likely was required because the removal of SLOD may have resulted in more than a minimal increase in the likelihood of occurrence of a malfunction of the offsite power system as described in the UFSAR."

Response to the Apparent Violation

Dominion Nuclear Connecticut, Inc. (DNC) submits the following information in response to NRC Special Inspection Report 05000336/2014011 and 05000423/2014011 which was issued by the NRC on August 28, 2014. DNC chooses to respond in writing to AV 05000336/2014011 and 05000423/2014011 and declined the opportunity for a Pre-decisional Enforcement Conference (PEC) and the opportunity to request Alternative Dispute Resolution (ADR) during a phone call on September 8, 2014, between Lori Armstrong of DNC and Raymond McKinley, Chief, Division of Reactor Projects Branch 5, NRC Region I.

1) The reason for the Apparent Violation (AV) or, if contested, the basis for disputing the violation DNC does not contest the apparent violation.

NRC's review and approval of the change to the Millstone Power Station Unit 2 (MPS2) and 3 (MPS3) licensing basis for the removal of SLOD was not requested by DNC because
Well, there is lots of Millstone's management levels who had to sign off on this?
of an inadequately prepared 10 CFR 50.59 screen. In the 10 CFR 50.59 screen, Engineering personnel failed to consider that the removal of SLOD was an adverse change
So why didn't Dominion send a notification to the the Plant NRC inspector of major work on our local transmission system potentially affecting safety, we find no increase in risk...please cover our backs with checking out our work???

Why does the licensee and NRC sounds more like enemies to each other, at a complete state of total war with each other relationship, instead of everyone covering each other's back(morally and ethically)? Do it the right way and no taking shortcuts?    

Honestly, I can't imagine the NRC not nosing around the site on their own and finding the major work was going on in transmission system in the document and the list of potential and on going major work. Doesn't that say a lot they couldn't discover this on their own? How much else does the NRC miss with not being "intrusive".

According to the NRC OIG report on SONGs, the NRC is coming out with a major committee report on the agency's lessons learned on the SONGS SG debacle late this fall. I can't wait to see this guy?     
relating to DNC's compliance with General Design Criteria (GDC) 17, and therefore did not conclude that a 10 CFR 50.59 evaluation was needed.

The root cause evaluation for this AV identified the direct cause as a lack in proficiency and skill in performing 10 CFR 50.59 screens. The root cause for this AV was determined to be that continuing training was not adequate to maintain the proficiency and skills for consistent, accurate screens. Corrective actions were needed to address the screening deficiency identified in the apparent violation.

The complexities associated with the technical issue, multiple responsible entities involved, and understanding of the MPS2 and MPS3 licensing basis are also relevant to understanding the contributing factors for the AV. During review of this AV, it was determined that DNC's error of not performing a 10 CFR 50.59 evaluation occurred during the design development for the removal of SLOD by the transmission owner, Northeast Utilities (NU). During the design development, DNC did not recognize that NU's removal of SLOD resulted in a change in the method of compliance with GDC 17 that required DNC to perform a 10 CFR 50.59 evaluation. This matter is further addressed in the Additional Information provided below.

2) The corrective steps that have been taken and the results achieved

With removal of SLOD, and as discussed in the Additional Information provided below, the station no longer met the method for compliance with GDC 17 approved by the NRC at the time of original licensing of MPS3. As documented in NRC Special Inspection Report 05000336/2014011 and 05000423/2014011, DNC implemented a compensatory measure by issuing an Operations standing order for interim guidance on future offsite line outages and plant generation output. In March 2014, prior to the NRC Special Inspection, DNC had separately implemented improvements in the procedural guidance for performing 10 CFR 50.59 screenings.

These improvements were the result of DNC identified gaps in performance of 10 CFR 50.59 screenings. Improvements included a major rewrite and expansion of the guidance for completing 10 CFR 50.59 screens using a more user-

"According to the former NRR Director, if there were problems with the 50.59 process, it would have manifested itself in many more issues than just the steam generator issue."

"Although these reviews are never 100 percent because they are done through sampling, his expectations are that the inspectors look hard and that they challenge."
"The Team Leader thought existing 10 CFR 50.59 guidance could be improved."

"She recalled that each region interpreted the inspection procedures differently."

"Additionally, the Team Leader said there was no specific training for 50.59."

"Team Member 1 also thought the 50.59 guidance available to inspectors is too vague."

"From his experience, the licensee and NRC routinely get into disagreements because of interpretation of the guidance."

"He said while there may be an opportunity - if an inspector reviews something while it is being worked on - to identify something that can change the course of the licensee's path, but typically the activities are already done in the field, or on their way to being done, before NRC starts looking."

"The challenge is that there are so many different types of components, structures, and systems and it is hard to write a procedure that captures all those different circumstances."

 "Although these reviews are never 100 percent because they are done through sampling, his expectations are that the inspectors look hard and that they challenge."

"The former Regional Administrator wants them to be as thorough as they can be, but their time is limited."  

"So they can never look at everything."  

"However, he said that inspectors do not look at everything and are trained to sample."

"NRC does not have the resources, including time or manpower, to review everything and so inspectors sample."

"According to the former NRR Director, based on the information provided by OIG pertaining to methodology changes, it appeared that NRC may have done a bad job of reviewing the SONGS 50.59 during the 2009 inspection; however, one should be careful before concluding that this was a broader problem than SONGS."

"Nevertheless, as the NRR Director responsible for the operational safety of 100 nuclear power plants and research and test reactors, he has limited resources."

"Also, he said, "We're only going to be able to sample, and you always want to make sure that you're sampling the items with the highest likely safety significance input."

"The Deputy Executive Director commented that the high frequency with which licensees use the 50.59 process coupled with the relatively low frequency of issues identified by NRC suggests to him that training could be a factor."  

"We had a lot of stuff to look at. ..We didn't look at everything."

"He said the AIT's determination was - based on review of the FSAR, the engineering change package describing the new design, the 50.59 screen and evaluation, and other items - there was no indication that the licensee needed a license amendment."

"He said that reviewing the 50.59 entails reviewing a sampling and based on his years of experience as an inspector, he said, "you don't expect 100 percent of everything, but you review it. . . and you dig deeper into things that don't sound right."

"He said that all inspections are done by sampling."

"However, if the region missed some of the methodology changes it was because inspections have always been no more than a sampling."

"He said to make a definitive decision on whether a license amendment request was required, the agency would have to talk about the resources needed to accomplish that. He said, "It comes down to a prudent use of resources to go back and accomplish that."

 "The Project Manager said that the UFSAR reviews by project managers are a low priority and he was not sure if they could be given a higher priority because project managers have a lot of work already."
friendly format. The procedure now includes more detailed guidance for responses to each section of the screen form
NRC OIG: "In his opinion, the NEI 96-07 guidance is too vague, allows for too many judgment calls, and needs solidifying of definitions. From his experience, the licensee and NRC routinely get into disagreements because of interpretation of the guidance.
including direct references to NEI 96-07, Guidelines for 10 CFR 50.59 Implementation.
NRC OIG: “For example, he said "more than a minimal increase" should be defined by a specific value in 1O CFR 50.59. (OIG notes that "more than a minimal increase" is the terminology used in several of the 1O CFR 50.59(c)(2) screening criteria.” “Team Member 1 told OIG that training for 50.59 inspections could be improved. He said NRC needs to insure inspectors are fully trained and versed in the 50.59 process.”

“The Branch Chief also told OIG that training was an area that needed improvement and that the quality of a 10 CFR 50.59 inspection is dependent on the inspector's knowledge, experience, and background.  He said the guidance is complex and there is a lot of judgment that is applied in using it.” 
In August 2014, training was provided on an expedited basis to a select population (the majority) of 10 CFR 50.59 screeners. The training included discussion on the fundamentals of GDC compliance and the importance of identifying and reviewing the impacts of design changes upon the licensing basis, including the FSAR. Only personnel who have received the training are presently qualified to perform 10 CFR 50.59 screens.

Design changes scheduled for implementation in the remainder of 2014 have been reviewed by Design Engineering to determine whether adequate licensing basis reviews were conducted as part of the 10 CFR 50.59 screenings. No 10 CFR 50.59 screens were identified which should have concluded a 10 CFR 50.59 evaluation was required.

3) The corrective steps that will be taken

To become qualified to perform 10 CFR 50.59 screens, future training will include a discussion of the fundamentals of GDC compliance and the importance of identifying and reviewing the impacts of design changes upon the licensing basis, including the FSAR.
Why don't we need NRC national training on all licensing issues and qualification testing?  
A review of the 10 CFR 50.59 screens for FSAR changes processed in the past three years will be conducted by April 1, 2015 to determine whether adequate licensing basis reviews were conducted.

DNC is evaluating options for addressing compliance with GDC 17. To complete this work, engineering analysis, including consideration of potential design modifications, is necessary. Upon completion, a License Amendment Request (LAR) will be submitted to the NRC requesting review and approval of a licensing basis change to the MPS2 and MPS3 FSAR that addresses the removal of SLOD. DNC will keep the senior resident inspector informed of the status and schedule for resolution.

4) The date when full compliance will be achieved

Full compliance was achieved when training was provided in August 2014. To ensure future continued compliance, the 10 CFR 50.59 training module will be updated to include a discussion of the fundamentals of GDC compliance and the importance of identifying and reviewing the impacts of design changes upon the licensing basis, including the FSAR.

Additional Information:

The SLOD system was owned by the transmission system owner, NU. Removal of SLOD was a result of a major transmission line upgrade project to improve grid reliability by separating lines and towers leaving the MPS switchyard. This separation allowed NU to eliminate SLOD, which they no longer considered reliable or secure.
So the instrumentation was getting unreliable and obsolete...just rip it out without telling the NRC.  
The upgrade, as it was presented, reduced risk to MPS and improved grid reliability to MPS.
Why wasn't the NRC invited to a meeting?  
Representatives of DNC and NU participated in multiple Nuclear Plant Interface Meetings (NPIMs) coordinated by ISO New England (the transmission system operator). These meetings, which began several years in advance of the actual physical modifications, included discussions of proposed changes to the transmission system.

The transmission upgrade project by NU involved rerouting the transmission lines from four lines on two towers to four lines on four separate towers. The removal of SLOD was presented in the aggregate as an improvement in grid reliability, conforming to present transmission system standards. According to the North American Electric Reliability Corporation standard on special protection systems (SPSs), SPSs such as SLOD carry with them unique risks including, risk of failure on demand and inadvertent activation, and risk of interacting with other SPSs in unintended ways. Thus, at the time, DNC,
I bet you the overarching ideal was to yank this gear out of the system before it caused an inadvertent trip on fault.  
ISO New England, and NU believed that separation of the towers/lines removed the vulnerability which SLOD was installed to mitigate and represented an improvement in grid reliability. Therefore, following tower line separation, SLOD was disabled and eventually removed. DNC recognizes that during the design development for the modified transmission circuits, there were opportunities to understand that the Millstone licensing basis was impacted by the removal of SLOD and that a 10 CFR 50.59
What about worrying about the collapse of the Pennsylvania and New York grid on past LAR related(2000)documents?  
evaluation would be required. DNC accepted the changes proposed and approved by NU, ISO New England, and the Northeast Power Coordinating Council without adequately considering the impact to the MPS licensing basis. The complexities associated with the specific technical issue, multiple responsible entities involved, and understanding of the licensing basis all played a part in the failure to recognize the impact of the change on the licensing basis.

The 10 CFR 50.59 screen failed to consider that the removal of SLOD was an adverse change relating to DNC's compliance with GDC 17, and therefore did not conclude that a 10 CFR 50.59 evaluation was needed. It was the belief that the tower and line separation project, including SLOD removal, was undertaken by NU for the sole reason to enhance grid stability and reliability, providing a more stable source of offsite power to MPS. That belief resulted in the DNC mindset that the removal of SLOD references from the FSARs did not require further evaluation. Following the May 25, 2014 event, DNC recognized that SLOD was credited for GDC 17 compliance and its removal should have been considered an adverse change requiring a 10 CFR 50.59 evaluation.

Extensive engineering analysis, including consideration of potential design modifications, is ongoing to address DNC's compliance with GDC 17. Upon completion of this work, a LAR will be submitted to the NRC requesting review and approval of licensing basis changes to the MPS2 and MPS3 FSARs for GDC 17.

As noted in the response to Question 3, improving sensitivity to the license basis and the 10 CFR 50.59 requirements is being addressed by training to prevent future similar situations.
Of Interest:

"After filing the motion, however, the group learned that the plant’s final safety analysis report, a document required by the plant’s license, had been changed last year, altering the methodology for measuring seismic safety and stating that the plant can withstand shaking up to .75 times the force of gravity. Such a fundamental change, the group argues, requires amending the operating license itself, a process in which the commission must give the public the opportunity to comment.

Report not public

Instead, the revised safety analysis report wasn’t available to the public on the commission’s website. When Friends of the Earth requested a copy, they received a redacted version.

Commission spokeswoman Uselding said information related to nuclear plant safety is often released to the public on a case-by-case basis, after a commission staff member has reviewed the request to address national security concerns."
They needed 50.59 for this in July 2001 and then to rip the whole thing out in 2012? Who cares if they screwed Pennsylvania and New York by 2012? If new grid conditions made this non applicable today, why not fix the FSAR documents with a updated grid analysis? 
"The Severe Line Outage Detection (SLOD) system is designed to prevent instability and loss of all generation at Millstone Station. Besides avoiding unit instability, a distribution system casualty with generation above 1300-1400 MW at Millstone Station could have severe, adverse consequences on Pennsylvania and/or New York grid reactive and thermal operating conditions. The SLOD system is continuously armed and avoids instability and loss of all generation at Millstone by tripping only pre-selected units when certain conditions exist. The tripping logic associated with the SLOD system was modified to remove all trips associated with Millstone Unit No. 1. The Double Line and Breaker Failure Detection Unit Rejection Special Protection System (DBURS), two more Special Protection Systems (SPS) used to trip pre-selected units at Millstone, were deleted and removed since their functions were no longer needed due to the loss of Millstone Unit No. 1 generation. CRP-909 was connected to the master supervisory panel in the 345-kV switchyard via a new fiber optic cable. Switches on CRP-909 for control of Millstone Unit No. 1 switchyard circuit breakers and motor operated disconnects were removed."
"Summer Readiness of Offsite and Alternate Alternating Current (AC) Power Systems
a. Inspection Scope

The inspectors performed a review of plant features and procedures for the operation and continued availability of the offsite and alternate AC power system to evaluate readiness of the systems prior to seasonal high grid loading. The inspectors reviewed Dominion’s procedures affecting these areas and the communications protocols between the transmission system operator and Dominion. This review focused on changes to the established program and material condition of the offsite and alternate AC power equipment. The inspectors assessed whether Dominion established and implemented appropriate procedures and protocols to monitor and maintain availability and reliability of both the offsite AC power system and the onsite alternate AC power system. The inspectors evaluated the material condition of the associated equipment by interviewing the responsible system manager, reviewing condition reports (CR) and open work orders, and walking down portions of the offsite and AC power systems including the 345 kilovolt (KV) switchyard and transformers. Documents reviewed for each section of this inspection report are listed in the Attachment." 

Wednesday, May 20, 2015

WSJ: New York State Calls for Tougher Inspections at Indian Point

I bet you it is in the purchase specification of the transformer...getting a cheaper grade of transformer.

We got a national security issue with this. Most of the USA’s transformers are made outside the USA.

What country did this failed transformer come from?

You got some corporate financial pinhead with no idea how a nuclear plant works dictating the quality of the transformer through price and specification. 

Has the Plant transformer fire led to an intensification of the pissing match between Entergy and the state of new York?    

WSJ: New York State Calls for Tougher Inspections at Indian Point
By Joseph De AvilaUpdated May 20, 2015 2:55 p.m. ET 
New York state is renewing its call for tougher oversight of electrical transformers at the Indian Point Energy Center after the third failure in eight years of one of the power-transfer devices at the nuclear plant.

A transformer for Indian Point’s unit 3 exploded and caught fire May 9 in the nonnuclear section of the power plant 30 miles north of New York City. No one was hurt and no other equipment damaged.

The state’s call for more intensive inspections comes as Entergy Corp.ETR-0.05%, the owner of Indian Point, seeks to renew its operating licenses for units 2 and 3 with the federal Nuclear Regulatory Commission. The state has opposed the renewal.

During relicensing proceedings, the state has argued that Indian Point’s transformers should be subject to what is known as an aging-management program as a condition of the facility being re-licensed. Such programs apply to so-called passive components, such as those with no moving parts, and are inspected periodically for degradation due to aging.

The NRC, however, classifies transformers as so-called active components, subject to a different set of inspection rules.
A regulatory tribunal agreed in 2013 with New York state’s position. But that ruling was overturned in March by the NRC.
“As the history of explosions and fires at Indian Point make clear, transformers play an important role in nuclear plant safety,” said New York state’s Attorney General Eric Schneiderman, whose office has represented the state in Indian Point’s re-licensing process. “The time has come to require that transformers be closely and frequently monitored as a part of the facility’s aging management program as I have raised in the re-licensing proceeding.” 
The NRC is scheduled to hold a public meeting Wednesday in Tarrytown, N.Y. on its assessment of Indian Point’s safety performance in 2014. The assessment, issued in March, found that Indian Point “met all cornerstone objectives” and wouldn't be subject to additional inspections above and beyond normal reviews.

Jerry Nappi, a spokesman for Entergy, said both of unit 3’s transformers passed extensive electrical inspections in March. Transformers at Indian Point get these intensive inspections every two years. Aspects of the devices also are inspected daily. 
“Everything that can be done using best industry guidance to monitor transformers was done,” he said. “Three transformers in less than 10 years is unusual. We need to get to the bottom of that.”

NRC officials say that main transformers at nuclear power plants are subject to ongoing monitoring, inspection and testing programs that serve the same purpose as an aging management program. “There is no evidence at this point to support the idea that placing the transformer under an aging management program would have resulted in a different outcome,” said Neil Sheehan, an NRC spokesman. “All of that said, our inspections of the transformer failure event are continuing.” 
Mr. Sheehan said the commission hadn’t determined whether the May 9 transformer failure would warrant additional oversight at Indian Point’s unit 3 reactor. 
The NRC also announced Tuesday it had begun a special inspection at Indian Point to look into the presence of water in an electrical-supply room that had equipment that provided power to safety systems at the plant. Entergy officials said that water from the sprinkler system flows into this electrical-supply room into a floor drain by design. After the fire, the water didn't drain as quickly as expected, they said. 
Some 16,000 gallons of transformer oil called dielectric fluid is still unaccounted for after the fire, according to Entergy. An unknown amount of that oil spilled into the nearby Hudson River. Dielectric fluid is a light mineral oil used as an electrical insulator and coolant for transformers.

The transformer that failed earlier this month replaced another transformer that malfunctioned and caught fire in 2007. Another transformer failed in 2010, which had been in operation for four years.

“I find it very difficult to understand with the high number of failures that they have experienced at this site, that Entergy hasn’t taken the political bull by the horns and set up a monitoring procedure, which no one can argue with,” said Robert Degeneff, an engineer and consultant in transformer performance.Mr. Degeneff, who testified for the New York Attorney General’s office during relicensing proceedings, said the company also should develop monitoring procedures with an independent third party.

Over the past 40 years, there have been at least 85 transformer fires at U.S. nuclear power-plant facilities, according to records from Dave Lochbaum, director of the Nuclear Safety Project at the Union of Concerned Scientists.

Mr. Lochbaum said nuclear plants generally don’t inspect their transformers monthly basis because transformers don’t tend to degrade that quickly.

“I think [Entergy] will look at what they were inspecting and how they were inspecting rather than frequency,” Mr. Lochbaum said. “When they lose that transformer they also stop making revenue. They have a huge incentive to get a reliable transformer.”

Monday, May 18, 2015

Indian Point Needs New Yard Loop Fire System and Distribution Piping

Update May 20: 

The NRC is worrying about the poor attitude reflecting the care of the fire water system at the facility?
RAI 3.0.3–5 
The response to RAI 3.0.3 1 dated December 16, 2014, states that the fire protection water and city water systems have experienced recurring internal corrosion (RIC), as defined in LR-ISG- 2012-02. With regard to the fire protection water system, the response states, “[l]ocalized corrosion has resulted in minor through-wall leaks that have no impact on system performance and do not threaten the structural integrity of the piping or the safety function of nearby equipment.” No changes were proposed to the Fire Water System Program to address RIC.
With regard to the city water system, the response states, “[h]owever, based on past operating experience, they [through wall leaks] do not compromise the intended functions of these or any other system, and do not warrant aging management program activities beyond those provided by established aging management programs and the corrective action program.” Issue 
Past performance does not provide reasonable assurance that throughout the period of extended operation, internal general corrosion will be revealed by a through-wall leak prior to the general corrosion potentially impacting the structural integrity of the system. Nor does it provide reasonable assurance that larger through-wall flaws sufficient to challenge the pressure boundary function will not occur. It is also unclear to the staff that a sufficient representative sample exists for the carbon steel piping to demonstrate that general corrosion is progressing slowly enough that it will not prevent an in-scope component from performing its current licensing basis intended function during the period of extended operation. Although to date through-wall leaks have not affected the safety function of nearby equipment, the staff lacks sufficient information to conclude with reasonable assurance that this will be the case throughout the period of extended operation. Request 
1) State the basis and justification for concluding that existing inspection data are sufficient to demonstrate that general corrosion is progressing slowly enough that it will not prevent an in-scope component from performing its current licensing basis intended function during the period of extended operation. 2) State the basis and justification for concluding that through-wall leaks will not impact the safety function of nearby equipment throughout the period of extended operation. 3) Provide the staff with sufficient quantitative data for it to reach the same conclusion. Alternatively, propose periodic inspections in response to SRP-LR Section, “Loss of Material due to Recurring Internal Corrosion.” RAI 3.0.3–13 
As amended by letter dated December 16, 2014, LRA Sections A.2.1.13 and A.3.1.13 state that the enhancements to the Fire Water System Program will be implemented by December 31, 2019. Issue 
As stated in RAI 3.0.3 12, it is not clear whether an enhancement is necessary to address augmented testing for fire protection water systems that are normally dry but periodically subject to flow (e.g., dry-pipe or preaction sprinkler system piping and valves) that cannot be drained or allow water to collect. SRP LR Table 3.0 1, as amended by LR ISG 2-12 02, states that the augmented testing should commence 5 years prior to the period of extended operation. Given that IP2 is beyond the expiration of its initial license (September 2013) and IP3 will be beyond its initial license period in December 2015, the staff questions why the augmented testing would not commence sooner than December 31, 2019. RequestState and justify the basis for why the augmented testing for fire protection water systems that are normally dry but periodically subject to flow (e.g., dry-pipe or preaction sprinkler system piping and valves) that cannot be drained or allow water to collect will not commence until December 31, 2019

*** guess they mean once they pressurize the fire nozzle by the automatic fire system control valve and they then secure the system...water would stay in the pipes up to the nozzle unless they had a way to drain this water. It would cause corrosion in the pipe and it would freeze in the winter thus blocking off the water to fight the fire. So they have an automatic valve that opens upstream of the main automatic, or it actually it is in the main automatic valve that drains the upstream water down into the sump in the power room. . It sounds like the main valve stayed open while header drain valve was opened for some period of time. One or both of the valve had a maintenance problem.
“The spokesman for Indian Point's owner said water from a sprinkler system flows to a floor drain in the electrical room by design, but did not drain as quickly as expected.” 
They might test the main automatic value on yearly bases or every outage. They actually fake a fire signal...this opens up the main valve pressurizing all the transformer fire water nozzles. It is actually a great show with all the nozzles spraying. This is all documented. Did they know there were issues with main automatic fire system control valve, but didn’t get it fix. Did they have extra water in the sump before in the testing.

Bottom line, it is a terrible place to have a fire system header drain down line into a main electrical room sump...

Just submitted the to the NRC blog, I am pretty controversial talking about Gov Cuomo.   
I think the Independent National Transportation and Safety Board did a wonderful job at explaining the tragic crash of the Amtrak Philadelphia commuter train.  I’d give them an “A” plus.
I do miss NTSB chairperson Deborah Hersman’s pretty face and especially her ability to communicate.  
Hmmm, the NTSB is missing a commissioner just like the NRC? 
As I said earlier, if Indian point and the NRC did a proper 50.59 and License Amendment Request (LAR)...the replacement of nonflammable PCB coolant to flammable vegetable oil coolant...they would have hardened the area around the transformer expecting a big vegetable oil fire and tremendous amounts of fire hose water being used.

Published on May 18 at 12:45 pm: 
"Indian Point Needs New Yard Loop Fire System and Distribution Piping"My guesses are: 
1) A leaking fire water system piping or component.
2) The copious fire hose water leaked down outside of the concrete foundation and then entered though a concrete foundation crack into the power supply room. Are there many concrete foundation cracks in IP buildings?  The fire fighters must have directed copious hose water protecting the turbine building siding. Was there damage to the siding?
3) The building siding was damaged by the fire...that is how the water got into the power room?
4) The overflowing transformer holding tank backed up into the supply room if both connected to each other. Does the supply room have a drain and where does it go? 
Did the NRC shame Gov. Cuomo by not telling him about supply room water on the floor or did the Governor intentionally withhold the water leak in the said electrical room from the public for some reason? Why didn’t the Governor disclose the water on the floor? The information was big deal heading into a special inspection.
Bet you the equipment operator has to inspect that room every four to eight hours.
Mike Mulligan Hinsdale, NH
May 19 2015 at 2 pmNRC Begins Special Inspection at Indian Point 3 Nuclear Power Plant to Review Issue Associated with Transformer Event on May 9
A team of NRC inspectors will seek to better understand the presence of water in an electrical supply room at the Indian Point 3 nuclear power plant following a main transformer failure event at the site on May 9th.
Starting today (Tuesday, May 19), a three-member NRC Special Inspection Team will report to the Buchanan (Westchester County), N.Y., facility to review the issue. The room in question contains electrical equipment that provides power to plant safety systems.
“None of the electrical equipment became wet or experienced any damage or failures as a result of the water,” NRC Region I Administrator Dan Dorman. “Nevertheless, the NRC inspectors will be tasked with gathering information on how the water accumulated in the room and the potential for impacts had there been a significantly larger volume of water.”

At 5:50 p.m. on May 9th, with the plant operating at 100-percent power, one of its two main transformers experienced a failure, the cause of which is not yet known. The failure resulted in an automatic shutdown of the reactor that occurred without any complications. Plant operators declared an “Unusual Event” -- the lowest of four levels of emergency classification used by the NRC -- at 6:01 p.m. because of the fire that erupted following the transformer failure.

The Unusual Event was terminated at 9:03 p.m. after the fire was fully extinguished.

A fire suppression system for the transformer automatically doused the fire. In addition, the plant’s on-site fire brigade and off-site firefighters sprayed water and foam onto the transformer to help put out the fire. Among other things, the NRC inspectors will be reviewing whether those sources account for the water observed in the electrical equipment room.

A report summarizing the findings of the Special Inspection Team will be issued within 45 days after the conclusion of the inspection.

Indian Point 3 remains offline while work to replace the transformer. 
May 18 at 1245 pm:

Can you imagine a Unit 3 transformer fire and the big system supply pipes fail leading to flooding in other buildings and dry fire stand-pipes in a big fire. think of the media then? 

This site needs to rip all all their corrosion degraded fire system piping and replace with new. The whole site needs new piping and not piecemeal. 

Annual Sample: Review of Fire Protection Piping Failure

a. Inspection Scope

The inspectors performed an in-depth review of Entergy’s evaluation and corrective actions associated with through-wall piping leaks and a degraded piping section in the Unit 1 and Unit 2 common fire protection system. The piping section cracked and leaked on December 29, 2014, causing all fire protection pumps to auto-start. Operators stopped all of the pumps for a period of about two hours while isolating the failed piping section.

Entergy documented the piping failure in CR-IP2-2014-6668. The inspectors reviewed earlier CRs such as CR-IP2-2010-5187 and CR-IP2-2008-0044 which were written to document through-wall leaks in the same fire protection pipe section. The inspectors assessed Entergy’s problem identification threshold, cause analyses, extent of condition reviews, compensatory actions, and the prioritization and timeliness of corrective actions to determine whether Entergy was appropriately identifying, characterizing, and correcting problems associated with the degraded piping and whether the planned or completed corrective actions were appropriate, timely, and in accordance with Entergy’s procedural requirements. The inspectors compared the actions taken to the requirements of Entergy’s CAP, FPP plan, and operating license. In addition, the inspectors reviewed subsequent testing, performed field walkdowns, and interviewed engineering personnel to assess the effectiveness of the corrective actions.

Introduction: A self-revealing Green NCV of license condition 2.K. was identified when Entergy failed to take adequate corrective actions for degraded fire protection piping following leaks identified as early as 2008. These earlier leaks contributed to a large piping leak in a 10-inch fire protection line which required operators to secure all high pressure fire pumps until the affected section could be isolated.

Description: On December 29, 2014, plant operators received alarms for low pressure on the fire header and observed a start of all three fire pumps due to low fire system pressure. The low pressure was caused by an axial split in a 10-inch diameter fire protection piping spool piece. After verification that no fire existed, operators turned off both motor-driven fire main booster