Entergy's Business Philosophy Beating The Hell Out Of Pilgrim..

So basically obsolete and poorly designed equipment beating the hell of of the plant, the switchard gear, main condenser tubes and SRV valves.

A host of  preventable scams, shutdowns and  down powers continue to plague this plant. This damages equipment and risk of a much more significant accident.  

May 11, 2015

PILGRIM NUCLEAR POWERSTATION – NRC INSPECTION REPORT 05000293/2015001 AND INDEPENDENT SPENT FUELSTORAGE INSTALLATION (ISFSI) REPORT 07201044/2015001

Summary of Plant Status

PNPS began the inspection period at 100 percent power. On January 27, 2015, during a severe winter storm, operators reduced reactor power to 52 percent due to degrading switchyard conditions when an automatic reactor scram occurred with the loss of 345 kilovolt (kV) offsite electrical power sources (line 355 and line 342). The operators took the unit to cold shutdown that same day and remained in that condition for restoration of the 345kV offsite electrical power sources, replacement of

So they replace the 3A and 3C SRV values. They only admitted one was broken, These new safety valves within weeks of first startup in 2011 began to leak and since have been plagued with premature degradation, leaks and failures. I solely blame the NRC for not using their so called big hammer to enforce safety reliability issues.  

the 3A and 3C safety relief valves (SRVs), and repairs to the Y2 vital instrument bus. Operators commenced a

This is the first time we hear this, they had some damage on the Y2 vital "instrument" bus. The storm and the shutdown damaged the vital instrument bus. Just saying, the NRC and Entergy doesn't disclose all the safety problems on a event, they slowly leak it out for months knowing everyone is sleeping.   

reactor startup on February 6, 2015, and returned the unit to 100 percent power on February 8, 2015. Operators reduced reactor power to 55 percent on February 9, 2015, to perform a rod pattern exchange, and returned to 100 percent power that same day. On February 14, 2015, the operators performed a controlled shutdown and proceeded to cold shutdown based on procedural requirements during blizzard conditions. Operators performed a reactor startup on February 17, 2015. On February 18, 2015, after achieving 20 percent power, troubleshooting of the main

Well never know how many down power and shutdown there will be in the future with a degraded condenser. Remember all those down powers and shutdowns over Fitzpatrick's leaking main condenser tubes until they replace them all. I think for reliability of the NE grid Pilgrim needs a new main condenser or extra glue.

condenser was performed due to condenser tube leaks. Following repair of the condenser tube leaks, operators proceeded with power ascension on February 19, 2015. Operators returned the unit to 100 percent power on February 20, 2015. On February 21, 2015, operators reduced reactor power to 60 percent to perform a rod pattern adjustment. Operators returned the unit to 100 percent the same day. On March 18, 2015, operators reduced power to 70 percent to perform a rod pattern adjustment. The unit was returned to 100 percent power the same day and remained at 100 percent power for the remainder of the inspection period.

Did they think the "A" degraded or weak...didn't want to use it? Usually they cycle using all the remain operating valves?

3B and 3D SRV continued use after 3C SRV

Description. 4160V undervoltage relays 127-509/1 & 2 are designed to provide an alarm to the control room operators in the event of an undervoltage and overvoltage condition on 4160V safety-related electrical bus A5. In 1989, problem report PR-1989-2244 was issued regarding a degraded voltage scenario that was identified from operating experience at other boiling water reactors (BWRs). The scenario specifically looked at the potential for a voltage regulator failure of the operating EDG during a simultaneous LOOP and LOCA. Given that the LPCI valves are powered from 480V electrical bus B6, which receives power from 4160V Bus A5 and A6, a failure of the EDG voltage regulator during a LOOP/LOCA would cause the LPCI valves to fail to open or fail in place and not fully open. This would prevent the ECCS from injecting at low pressures and potentially lead to core damage. The corrective action to this scenario included two parts that were implemented at different times. First, in 1989, to ensure this event did not impact the ECCS injection

I wonder how often the shift practice this kind of failure. I basically call the shift in a Cat 4 complexity hurricane. There are so far out on the limb with complexity at this point, humans are very unreliable. They are solving a technical problem...not thinking holistically and pondering the complexity storm this shift is entrained in.  Basically there are tons of blinking annunciation and alarms going on all over the place in the control room. 

function, a step was added in alarm response procedure ARP-C3L to trip the operating EDG to protect the 4160V bus and other associated electrical equipment. Second, in 1997, relays were installed to protect respective electrical feeds to the B6 480V electrical bus; preventing potential damage to the LPCI injection valves if the EDG were to fail during a LOOP/LOCA.

On March 6, 2015, Entergy staff performed 4160V electrical bus A5 relay testing in accordance with work

So they never tested the new relays...operators go to bed with nightmares thinking the engineering staff could screw the operating staff in a accident. In the heart of a terrible accident equipment and alarms would't works. A plant have 100,000 of relays and compo-nets, how many of the not working components in very complex accident would it take to confuse the shift?

How many none tested critical to protect the core relays aren't tested for decades?   

order 52425333 and procedure 3.M.3-1, “A5/A6 Buses 4kV Protective Relay Calibration/Functional Test and Annunciator Verification – Critical Maintenance,” Revision 140. In preparation for this testing, Entergy staff noted a change in the drawing which contains the acceptance criteria for the 127-509/1 and 127-509/2 relays. The Entergy staff appropriately updated their relay testing equipment with the proper acceptance criteria; however, did not recognize that the relays had not been tested for the undervoltage dropout setting prior to this date. Testing of the undervoltage dropout setting for relays 127-509/1 & 2 revealed the “as-found” set point to be at 82V compared to the requirement of 106V. Upon inspectors request for information regarding past performance of relays 127-509/1 & 2, Entergy staff discovered that no prior testing for the undervoltage dropout setting had ever been performed. Given that Entergy had not tested these relays over the life of the plant, there was no method to effectively track and trend relay drift from required setpoints which impacted operators’ ability to carry out actions in alarm response procedures. Entergy entered CR-PNP- 2015-1614 and CR-PNP-2015-1623 into the CAP to address the degraded condition. An immediate operability determination was performed and the relays were re-calibrated to their required set points successfully prior to restoration of the X107A EDG. UFSAR Section 8.4.7 for the auxiliary power distribution system establishes a testing frequency for non-technical specification, safety-related 4160V relays in Table 8.4-3 for every four years. These relays are typically tested in accordance with Entergy’s preventive maintenance program and implementation of procedure 3.M.1-1. However, Entergy did not establish testing requirements or a testing frequency to ensure that the undervoltage dropout relay was properly being maintained and functional. Entergy entered CR-2014-1898 into the CAP to address this issue. The immediate operability determination noted that the 480V electrical bus relays installed in 1997 would have performed a similar function to protect the ECCS injection equipment; however, it would not have protected other safety-related equipment in the event of a voltage regulator failure during a LOOP/LOCA. The inspectors confirmed that the 480V electrical bus relays were properly tested and within acceptance criteria as of 2013 to ensure it could have prevented LPCI injection failure.

So you get it, relays critical in a accident to prevent core damage indicating their only remaining power source is failing only gets a insignificant violation. Over all these years with the money spent on inspector and a assortment of inspections, take the starling noneffective CDBI in-depth inspections...why didn't the NRC uncover this first decades ago. What do these inspector do on site???  

(NCV 05000293/2015001-01, Failure to Perform Testing of Safety Related Undervoltage Alarm Relays)

This not a professional staff: Bet you the NRC whispered in their ears fix it. 

The inspectors performed an in-depth review of Entergy’s apparent cause evaluation and corrective actions associated with CR-PNP-2014-1851, “A Negative Trend of Valves\ Trended to Satisfy IST Requirements Has Been Identified.” Specifically, the monitoring of valve stroke times for multiple safety-related valves was not identifying adverse trends in an effective and timely manner, which resulted in equipment operability issues and emergent repairs.

Entergy staff determined there were two apparent causes: 1) component and system engineers and supervisors were generally unaware of their responsibilities to review and trend IST component data as required by Entergy fleet procedures, and 2) the IST engineer did not take timely action to initiate CRs in accordance with program requirements. Entergy staff also determined that system monitoring challenge board meetings were not conducted on a regular basis during this period as required by procedure EN-DC-159, “System Monitoring Program.” 

The inspectors concluded that Entergy staff conducted an appropriate review to identify the likely causes of the IST trending issue. The inspectors also concluded that Entergy staff identified the extent of condition which was mostly the trending of IST program data for the in scope systems; however, the review included an evaluation of the other programs where trending is performed as part of condition monitoring. Corrective actions included a review of the procedure requirements conducted between the system engineers and their supervisors, establishment of a reoccurring schedule for system monitoring challenge board meetings, training for system engineers on monitoring and trending expectations, and revisions of system monitoring plans to include IST data parameter. 

Grave National Crisis, Time To Declare A All Out War: HERION

New Hampshire Union Leader: City streets rife with drug dealers and users

By TIM BUCKLAND

A Manchester police officer displays three packets of freshly confiscated heroin, on left, and two packets of crack. Each packet contains a single dose. (Thomas Roy/Union Leader)

MANCHESTER - The young woman sidled up to the unmarked police car. She knows the men inside are cops, despite their jeans and T-shirts. And they know her.

"I'm not using right now," Kendra Johnson said before asking for $20 and jokingly offering a sexual service.

Officer Matt Jajuga politely told Johnson she has to try to stay off drugs and avoid the type of behavior that recently landed her a stint in Valley Street Jail and notoriety in the news - she was the woman found in January with New Hampshire Motor Speedway General Manager Jerry Gappens engaged in what police called a "sexual act" at the time.

Jajuga, whose brain is a steel trap of names - he knows everyone walking around the area just east of downtown - said the approach he and his partner, Officer Paul Rondeau, take while on plainclothes duty is to talk to people. Each time they stopped during a recent shift where The Sunday News was allowed to ride along, the conversations were light and friendly, whether it was to ask a "known prostitute" to stop sitting on private property or to run a check for warrants on a young man who darted in front of their car.

"You don't want to treat people like they're worthless. That doesn't serve any purpose," Jajuga said.

"It doesn't help to be abrasive. They'll shut down," Rondeau said.

During recent patrol shifts, Rondeau and Jajuga focused on looking for people breaking into cars, a problem in the area on and around Lincoln Street, while Officer Tony Battistelli patrolled a similar area, looking for any laws being broken. 

But the officers' real work is combatting the heroin epidemic, the root cause of most crime in the city. With many state officials focused on trying to increase funding for anti-drug education efforts and to provide more treatment options for heroin addicts, it is police officers who are on the front lines 

***A bigger problemManchester Police Chief David Mara said the problem is more acute now - as opposed to previous so-called drug epidemics involving meth, crack cocaine and even heroin - because of the increase of drug overdoses. The state had more than 300 deaths in 2014 and the city has had more than 30 people die from oversdoses so far this year.

He said he was a patrol officer in the early 1990s when crack cocaine was that era's problem drug.

"I think this is a worse long-term problem," he said of heroin. 

Boston Globe: Heroin exacts an especially savage toll in Plymouth

PLYMOUTH — Fire Chief G. Edward Bradley carries Narcan, the drug that reverses heroin overdoses, nearly everywhere he goes around this sprawling town. Even to the Little League field when he watches T-ball games.It’s part of a personal mission, gnawing and never-ending, that Bradley sees as the greatest challenge of his long career. 

“You see all the alarms around town for the nuclear plant we have here. I wish we had one for heroin,” Bradley said last week. 

Plymouth counted 15 drug-related deaths last year and 313 overdoses, a total 50 percent greater than Taunton’s, a city of similar size that once had been considered the face of the drug epidemic. 

This year, Plymouth is on track to smash its own grim record. By Saturday, the town had recorded 136 overdoses — an average of exactly one a day — and 10 related deaths. 

• Opioid abuse considered widespread, poll finds 

Mass. residents are more worried about drug abuse than are Americans generally, a Boston Globe poll found.

It’s a tally that has risen so quickly, so stunningly, that many Plymouth leaders did not realize the town had an opioid crisis until it overwhelmed them. That includes Police Chief Michael Botieri. 

“It took time for me to become a believer in this epidemic,” Botieri said. Now, nearly everyone believes.“It’s not getting any better, obviously,” Bradley said. “We realized we’re as bad as some of the biggest cities in the state, if not worse.” 

Plymouth’s per-capita overdose rate is significantly higher than hard-hit Worcester’s, a city three times its size that saw a 59 percent rise in overdoses last year.While the numbers grow, so has Plymouth’s response... 

Opioid abuse considered widespread, poll finds

Nearly three-quarters of Massachusetts adults believe heroin use is an extreme or very serious problem in the state, and almost four in 10 adults know someone who has abused prescription painkillers in the last five years, according to a survey by The Boston Globe and the Harvard T.H. Chan School of Public Health. 

The poll also found that Massachusetts residents are more worried about opioid abuse than are Americans generally, and that more adults here believe prescription drug abuse is getting worse...

Brunswick's DG Flex Building Already has Roof Leaks?

Oh, brother,

WO 13354886, March 30, 2015, FLEX diesel building roof leaks

So basically a backup, backup system much likes the flex program that the utilities don’t spend the resources to keep these machines fully operable. It is so predictable and foreseeable...

Limerick Generating Station 2015-001 

“fire safe shutdown diesel (FSSD) generator 

Introduction. The inspectors identified a Green NCV of LGS Units 1 and 2 operating license condition 2.C(3), Fire Protection, because Exelon did not implement and maintain in effect all provisions of the NRC approved fire protection program. Specifically, Exelon did not implement and maintain a maintenance program to ensure the operability of the FSSD generator by not ensuring a fuel oil supply was specified or was protected for typical winter cold temperatures.
 The FSSD generator is provided to power portable ventilation fans used for smoke removal and indoor temperature control in the control room, remote shutdown panel room, and auxiliary equipment room following fires which could impact normal ventilation systems. The portable ventilation fans and FSSD generator enable LGS to reach and maintain fire safe cold shutdown conditions assuming ventilation failures due to fire damage. However, the unavailability of the FSSD generator would not by itself prevent LGS from reaching and maintaining safe shutdown. 

Entergy's CEO Denault Sizing Up Environment

 Entergy (ETR) Stock Rises After CEO Denault Appears on Jim Cramer's 'Mad Money'

NEW YORK (TheStreet) -- Shares of Entergy (ETR - Get Report) rose 0.65% to $74.24 in morning trading Thursday after chairman and CEO Leo Denault appeared on Jim Cramer's Mad Money show on CNBC.

Denault said the industrial renaissance in America's south and along the Mississippi River is ongoing. Furthermore, industries are taking advantage of Entergy's

Does Denault think their nuclear fleet should be producing electricity 20% lower than the nuclear fleet average across the USA? Is that the root of their problem. These guys are the Walmart of the Utility industry. Do you want Walmart running a nuclear power plant? 

electricity rates, which are 20% below the national average, in order to build new plants. This gives Entergy numerous growth opportunities to increase its dividend, he added.

Entergy has a 4.5% yield.

Denault also talked about the recent transformer fire outside the company's Indian Point nuclear plant in Westchester County, New York. He noted the fire was extinguished quickly and the plant was safely shut down, but it must stay offline for a few weeks because the transformers are what transmit the power from the plant to the grid.

Cramer asked about new plants under construction, and the CEO explained that the company is working quickly to replace outdated plants and increase its capacity in order to meet demand. Many of the new plants are natural gas, which are the quickest to construct, but the company is also building nuclear and solar plants.

Cramer again recommended Entergy on the show.

Separately, TheStreet Ratings team rates ENTERGY CORP as a Buy with a ratings score of A-. TheStreet Ratings Team has this to say about their recommendation:

"We rate ENTERGY CORP (ETR) a BUY. This is based on the convergence of positive investment measures, which should help this stock outperform the majority of stocks that we rate. Among the primary strengths of the company is its attractive valuation levels, considering its current price compared to earnings, book value and other measures. We feel its strengths outweigh the fact that the company has had sub par growth in net income."

Highlights from the analysis by TheStreet Ratings Team goes as follows:

§  ENTERGY CORP's earnings per share declined by 26.3% in the most recent quarter compared to the same quarter a year ago. This company has reported somewhat volatile earnings recently. But, we feel it is poised for EPS growth in the coming year. During the past fiscal year, ENTERGY CORP increased its bottom line by earning $5.22 versus $3.98 in the prior year. This year, the market expects an improvement in earnings ($5.50 versus $5.22).

§  ETR, with its decline in revenue, underperformed when compared the industry average of 2.8%. Since the same quarter one year prior, revenues slightly dropped by 9.0%. Weakness in the company's revenue seems to have hurt the bottom line, decreasing earnings per share.

§  In its most recent trading session, ETR has closed at a price level that was not very different from its closing price of one year earlier. This is probably due to its weak earnings growth as well as other mixed factors. The stock's price rise over the last year has driven it to a level which is somewhat expensive compared to the rest of its industry. We feel, however, that other strengths this company displays justify these higher price levels.

§  Net operating cash flow has decreased to $610.96 million or 20.36% when compared to the same quarter last year. Despite a decrease in cash flow of 20.36%, ENTERGY CORP is in line with the industry average cash flow growth rate of -25.99%.

The Blaa, Blaa Blaa NRC Chairman

You notice all the print space devoted to bureaucratic issues and Fukushime...they never talk about plant problems. This sounds like the language of a captured regulator.

What is the NRC chairman's perspective on the top five problems at the plant level...this guy got a lot of experience.  

Remarks by NRC Chairman Stephen G. Burns to the 2015 Nuclear Energy Assembly May 13,2015 – Washington, D.C.
 Good afternoon. I appreciate the opportunity to appear before you today at NEI’s annual Nuclear Energy Assembly. I plan to touch on a few topics that I hope will be of interest to the audience here today. I have now served for about four and a half months as Chairman of the NRC, having been designated by President Obama as Chairman on January 1 of this year. As you may know, I had earlier retired from the NRC in 2012 after a nearly 34-year career that culminated in my service as the agency’s General Counsel. To describe the experience as a bit surreal doesn’t do it justice. As a young attorney entering the NRC in 1978, I could never have imagined that someday I would be Chairman of this great organization. Now, returning to the NRC after my three-year hiatus in Paris at the OECD Nuclear Energy Agency, I have the unique opportunity to experience the agency yet again from an entirely new vantage point...

Arkansas Nuclear One (Entergy) rated worst nuke plant in U.S

Arkansas Nuclear One rated worst nuke plant in U.S.

RUSSELLVILLE, Ark. (KTHV) - Arkansas Nuclear One in Russellville ranks among the worst nuclear plants in the country for federal performance ratings. The low rating comes as a result of two major issues that have led to what the U.S. Nuclear Regulatory Commission calls "a significant decline in plant performance." "We're taking this very seriously, I do view this as an opportunity. It's an unfortunate place to be but it also yields a lot of good opportunity for us," said Arkansas Nuclear One Site V.P. Jeremy Browning. "You don't just want to fix the symptom, you want to fix the underlying cause that drove that symptom so it doesn't ever happen again." 

Browning said he's not happy about his plant being the only one in the country being scrutinized this heavily by the federal Nuclear Regulatory Commission, but he was quick to point out that the plant is fully committed to getting back on track. Nuclear One's decline in performance is related to a 2013 accident that killed 24-year-old Wade Walters and injured eight others. Then, in January of this year, regulators found problems with the plant's flood protection systems. "What I'm talking about is: why did we not detect those issues before they became self-revealing" added Browning. "That's what we need to do. We are not going to have another failed project like we did in 2013, we're not going to have a problem with our flood barriers, we have fixed that – but something allowed those to self-reveal themselves to us and we can't tolerate that." Part of the fix will include a safety culture assessment according to NRC spokesperson Lara Uselding. "Safety culture is just good decision-making by the workers, good problem identification and understanding that when you have a problem how to prioritize it and then how to fix it," said Uselding. "The NRC does believe that the plant can operate safely and therefore they have not been asked to shut down, they have demonstrated sustained improvement so far with making corrective action to some of these issues that we've discussed." Browning says he's confident Nuclear One will be able to address the issues and continue production without any further issues. 

Sequotah: Many Fuel Pin Leaks Spewing Radiation All Over The Plant

This got to be going again all over the place? It is a repeated industry crisis. 

SUBJECT: SEQUOYAH NUCLEAR PLANT - AMENDED NRC INTEGRATED INSPECTION REPORT05000327/2014003 AND 05000328/2014003

Source Term Reduction and Control: The inspectors reviewed the collective exposure three-year rolling average (TYRA) from 2011 - 2013 and reviewed historical outage collective exposure trends. Through interviews with licensee staff and document review, the inspectors assessed the licensee’s current activities related to source term reduction, including elevated zinc injection on U2, on-line chemistry using pH 7.4 to minimize corrosion product transport, extended reactor coolant pump run time to allow better cleanup during shutdown, ultrasonic fuel cleaning, and response to fuel defects during previous operating cycles. The inspectors discussed the unexpectedly high activity o shutdown crud burst and changes expected in the short and long term relative abundances of Cobalt-58 and Cobalt-60 that would result from the change in the steam generator tube alloys and increasing the number of steam generator tubes by about a third. The dose implications of the various cobalt reduction activities coupled to the
change in tube alloys for the next few outages was also discussed

Plant Maintenance Big Picture By The Professional Reactor Operator Society

NORTH ANNA POWER STATION – NRCINTEGRATED INSPECTION REPORT

By Bob Meyer

Maintenance, maintenance safety culture, maintenance procedures, maintenance wrench time are a weak link in most nuclear plants. Years ago INPO by the direction of their board of directors reduced maintenance training and knowledge of the nuclear plant to a weaken state it is today. Take a look at the NRC violation, the rework and errors that are made. The landscape has changed since INPOs inception, and the lack of focus on all departments has caused significant degradations to the integrated wellbeing of the organization. There has been multiple paradigm shifts in work control and yet no new training or qualifications have changed. Work control provides directions and guidance on safety related equipment, with no training analysis on their performance… they have no training. Everyone that puts their hands on the equipment need detailed training, everone that writes procedures, work instructions for safety related training need detailed training. They all need to be part of the Systematic Approach to Training (SAT) process.

Here is the report...

The Ghost Monticello's HPCI

This is how risk perspectives looks like while on drugs.

In a big accident, the operating staff at the beginning has very limited resources. They would have no capability to assess if the steam lines were clear. They would assume HPCI was broken and to use it would create new dangers with the condensate damaging other components. So the operators would walk right past the damaged equipment.

This is another huge flaw in risk perspectives. It doesn't matter what the condition is of the component is...it only matter what the operators perception is of safety equipment. These are the lessons of TMI and Davis Besse.

I would consider this equipment broken until proven safe...not available to the accident. Calling it this way would jack up the worth of a broken HPCI...incentive not to let it happen again.  

HIGH PRESSURE COOLANT INJECTION INOPERABLE DUE TO CONDENSATION IN STEAM LINE 

"At 0537 CDT on March 21, 2015, following the High Pressure Coolant Injection (HPCI) system quarterly pump and valve surveillance, after HPCI was removed from service, an alarm for the HPCI Turbine Inlet High Drain Pot Level did not reset. This indicated that LS-23-90 (HPCI Steam Supply Drain High Level Bypass) did not reset, which could be an indication that condensate exists in the steam line. The system responded as designed but the alarm did not clear as expected. Without assurance that the condensate has been removed from the HPCI steam line, HPCI remains inoperable for reasons other than the planned surveillance. As a result, this condition is being reported under 10 CFR 50.72(b)(3)(v)(D) as a condition that could have prevented fulfillment of the safety function at the time of discovery.

"The health and safety of the public was maintained as the plant was in a normal condition with no initiating event in progress.

"The NRC Resident Inspector has been notified."
The State of Minnesota will be notified.

* * * RETRACTION FROM RANDY SAND TO DANIEL MILLS AT 1445 EDT ON 5/11/15 * * *
"On March 21, 2015, Northern States Power Minnesota reported a condition that could have prevented the fulfillment of a safety function under 10 CFR 50.72(b)(3)(v)(D). The High Pressure Coolant Injection (HPCI) System was declared inoperable for a reason other than planned maintenance due to the failure of the HPCI Steam Supply Drain Hi Level Bypass Level Switch to clear the high level alarm subsequent to actuation. 

"An engineering evaluation was performed and concluded that the function of the primary pathway to remove condensate remained unchallenged by the condition present

Do they got this thermography gear available to the operators...so they can immediately see if the condensate is clear??? Is thermography qualified to check the conditions of safety equipment. 

on the level switch This conclusion was also validated via thermography with the HPCI steam supply pressurized and bypass valve open. The verification that the primary pathway was functional provides reasonable assurance that the HPCI steam supply was always clear of condensate supporting the ability of HPCI to perform its required safety function. Therefore, the condition present on the level switch did not render HPCI inoperable. The conclusions of the engineering evaluation provide the basis for retraction of the ENS report made on March 21.
"The NRC Resident Inspector has been notified."
The licensee will also notify the State of Minnesota.

Number 2 event report:

HIGH PRESSURE COOLANT INJECTION INOPERABLE DUE TO CONDENSATION IN STEAM LINE

"At 0537 CDT on March 21, 2015, following the High Pressure Coolant Injection (HPCI) system quarterly pump and valve surveillance, after HPCI was removed from service, an alarm for the HPCI Turbine Inlet High Drain Pot Level did not reset. This indicated that LS-23-90 (HPCI Steam Supply Drain High Level Bypass) did not reset, which could be an indication that condensate exists in the steam line. The system responded as designed but the alarm did not clear as expected. Without assurance that the condensate has been removed from the HPCI steam line, HPCI remains inoperable for reasons other than the planned surveillance. As a result, this condition is being reported under 10 CFR 50.72(b)(3)(v)(D) as a condition that could have prevented fulfillment of the safety function at the time of discovery.

"The health and safety of the public was maintained as the plant was in a normal condition with no initiating event in progress.

"The NRC Resident Inspector has been notified."

The State of Minnesota will be notified.

* * * RETRACTION FROM RANDY SAND TO DANIEL MILLS AT 1445 EDT ON 5/11/15 * * *

"On March 21, 2015, Northern States Power Minnesota reported a condition that could have prevented the fulfillment of a safety function under 10 CFR 50.72(b)(3)(v)(D). The High Pressure Coolant Injection (HPCI) System was declared inoperable for a reason other than planned maintenance due to the failure of the HPCI Steam Supply Drain Hi Level Bypass Level Switch to clear the high level alarm subsequent to actuation.

"An engineering evaluation was performed and concluded that the function of the primary pathway to remove condensate remained unchallenged by the condition present on the level switch This conclusion was also validated via thermography with the HPCI steam supply pressurized and bypass valve open. The verification that the primary pathway was functional provides reasonable assurance that the HPCI steam supply was always clear of condensate supporting the ability of HPCI to perform its required safety function. Therefore, the condition present on the level switch did not render HPCI inoperable. The conclusions of the engineering evaluation provide the basis for retraction of the ENS report made on March 21.

"The NRC Resident Inspector has been notified."

The licensee will also notify the State of Minnesota.

Notified R3DO (Peterson).

Oyster Creek: Unreviewed Safety Problem

Seem they had another trip over a transformer short. Is this the end of Oyster Creek? Will plant operation become more chaotic as 2019 approaches? 

Licensing never considered the closing or heading to permanent shutdown problems with nuclear power plants. Do we need new rules???

It is when the parent company starts throttling down money to the plant, because after all, we are going to be shutting down in a few years. It not prudent wasting money on a dying plant. 

In the closing period of the life of the plant, the NRC doesn't fully enforce the license or rules of agency because we feel so sorry for these employees..all we got to do is get through another year or two, then the site will finally be silent.

We are massively dropping our shields in the closing period of plant operation. It would be a terrible shame if in the last year of a plant's life, an event or accident shames the whole industry.

And spinning in the background is Exelon whining (begging) to save financially a host of wounded Illinois nuclear plants.

(I not sure if shutting down a host of nuclear plant is a way to booster grid electricity prices or stabilize the decline of electricity prices because of fracting? 

Traitor Matt Wald: NYT's Nuclear Industry Expert

One wonders now if we ever got a objective, complete and honest nuclear plant story out of him while he was a reporter for the New York Times. 

We certainly live in such corrupt times...

"The following is a guest post from Matt Wald, senior director of policy analysis and strategic planning at NEI. Matt joined us in April after 38 years at The New York Times." 

Clinton 50.59

works in progress....when do you think they made the switch gear fully seismically  qualified...was it a recent fix...

What is going on here? The NRC recently tazed Millstone in a 2002 10 CFR 50.59 violation and now Clinton is being zapped by a non sited  1979 50.59 violation. What is the message the NRC is trying to say?

The national problem with screenings, 50.59 and LAR...you never know what the sample size is compared to all  screenings, 50.59 and LARs. The complaint with the San Onofre SG 50.59 is the agency is resourced restrained and the agency is a sample agency. The only get to sample a small amount of the documents and report. Basically a plant with  more than 800 employees can bury the two or more inspectors on site with paperwork.

Basically a 50.59 is a analysis if a issue needs permission to change the licencing conditions of a plant.

I still don't understand what caused Clinton in 1997 to discover their Div 1,2 and 3  breaker weren't fully seismically qualified in the racked out position. It is interesting, why not always remove the racked out breaker from the compartment? An empty breaker bus  cabinet has to seismically safety.  Then it will be seismically qualified

On February 27, 1997, the licensee generated Condition Report (CR) 1-97-02-273, “ABB [ASEA Brown Boveri] and General Electric Breakers Not Seismically Qualified in Racked Out Position.”

So once they discovered the breakers weren't fully seismically qualified, they were  required to enter Tech Specs and enter a LCO. At some near point, if not fixed they were facing a shutdown. Millions of bucks a day were on the line by shutting down unnecessarily.

So the solution was to write up a silly evaluation saying if the racked out breaker was a short time duration, the risk were so slight as to not required NRC permission. What this really is doing by getting NRC permission according to the lessens learn from San Onofre, is to informing the public and bring them along on licencing changes. But this is circa 1997. It also required Clinton to write a public evaluation about the possible change.

The inspectors reviewed NEI 96-07, Section 4.3.2, “Does the Activity Result in More Than a Minimal Increase in the Likelihood of Occurrence of a Malfunction of an structure, system, or component (SSC) Important to Safety?,” which stated that changes in design requirements for earthquakes, tornadoes, and other natural phenomena should be treated as potentially affecting the likelihood of malfunction.

It does increase risk if the Inop is a short duration? This risk perspective goes to their heads if they are not careful. Again it is certainty/uncertainty gaming...selectively releasing information to what is favorable.

On March 20, 1997, the licensee completed “Risk Evaluation for Seismically Indeterminate Switchgear Configurations,” which was included as an attachment to the licensee’s letter Y-106400 to address the switchgear’s seismically unanalyzed conditions. The purpose of the evaluation was to address the risk significance of the seismically unanalyzed conditions. The evaluation concluded there were no adverse impacts on the intended safety function of the affected switchgear, and other adjacent cubicles’ in-service devices (i.e., relays, instruments, etc.); provided the duration of the seismically unanalyzed conditions only existed for a limited period of time.

This is when it was entered into the USAR.  So it was inop from Feb 27 to the illegal, unethical and inappropriate April 22 entry into the USAR. So why didn't the NRC enforce tech specs and a shutdown? You want to make these guys pay a horrendous price for not purchasing and acquiring appropriate grade and tested safety equipment. You want to give them a incentive to fix tier shaky bureaucracy. See, this is what I am talking about with incentivizing a big corporation to do the right thing. Was the 1982 $92 million dollar fine to the Clinton nuclear plant the largest fine by the agency? This was three years after TMI???

So in the below, we see the terrible flaw in the NRC oversight of nuclear plants. We get to see the hyper technical violations and how they proportion violations through risk perspectives in the NRC inspection reports that nobody understands. We never get to see the real story behind the ultra technical story...the real mover with why the problem develops. Illinois Power was right in their 199 evaluation and the 2015 NRC 50.59 inspection report was completely off base according to the perspectives on  the condition of the plant in 1997. A grievous wrong has been done to Illinois power and the Clinton nuclear plant by this 50.59 violations.

So maybe a 1997 historic perspective is in order with the Clinton plant.

Most of the nukes is Illinois including all of Comed/ Exelon nuke plants were in big trouble with the NRC towards the end of the 1990s.  Illinois Power tried to build a single plant nuclear plant...they made a mess out of it. By 1997, the plant had been shutdown for a year, two more years of shutdown was ahead of them. At the 1997 inspection violation point, the future of the Clinton nuclear plant was very bleak.  Maine Yankee was permanently shutdown in 1997 and the two plant Zion plant owned by Commonwealth Ed was heading towards a permanent shutdown in 1998. Region III had to be a absolute basket case in 1997. In 1997 the QA and safety bureaucracy in the Clinton plant was in total disarray and utter breakdown? 

• In 1982 the Nuclear Regulatory Commission issued ten separate stop-work orders at the Clinton site resulting from concerns that inspection and documentation of completed work was not keeping pace with construction. That same year IP agreed to pay a $90 million NRC fine, stemming from charges that NRC quality control inspectors had been intimidated at the construction site and the company failed to appropriately document and implement electrical quality assurance programs.

• In 1997, it was also said to be producing "some of the highest electric rates in the midwest". After less than a decade of operation the plant's original owner, Illinois Power, had to close it in 1996 following some technical problems and safety violations resulting in a $450,000 fine.( Shutdown from 1996 to 1999) 

• Having deduced that it was not economical to own and operate only one nuclear generating station in the newly deregulated market, they kept it shut down during around 3 years whilst looking for an interested buyer.^[6] Exelon Corporation bought it for a more modest price of $40 million, with the purchase including the fuel in the reactor vessel and responsibility of all the radioactive waste in the spent fuel storage pool. The Operator and Owner is the Exelon Corporation. 

• On April 22, 1997, the licensee applied the results of the evaluation and updated the safety analysis report per USAR Change 7-209, “Section 3.10, Qualification of Seismic Category I Instrumentation and Electrical Equipment.”

In 1982 the Nuclear Regulatory Commission issued ten separate stop-work orders at the Clinton site resulting from concerns that inspection and documentation of completed work was not keeping pace with construction. That same year IP agreed to pay a $90 million NRC fine, stemming from charges that NRC quality control inspectors had been intimidated at the construction site and the company failed to appropriately document and implement electrical quality assurance programs. 

 
This issue was a
  

On February 27, 1997, the licensee generated Condition Report (CR) 1-97-02-273, “ABB [ASEA Brown Boveri] and General Electric Breakers Not Seismically Qualified in Racked Out Position.”

What is going on here? The NRC zapped Millstone of a 2002 10 CFR 50.59 violation. And now Clinton is being zapped by a non sited  1979 50.59 violation.

Basically in 1997 Clinton discovered  having a switchgear in a racked out position, they had  no proof this position was seismically qualified. At this point, they were supposed to enter tech specs, I am not sure of the TS requirement and when they needed to be shutdown.

Instead Clinton changed the UFSAR without NRC permission saying if it was less than 24 hours.

On February 27, 1997, the licensee generated Condition Report (CR) 1-97-02-273, “ABB [ASEA Brown Boveri] and General Electric Breakers Not Seismically Qualified in Racked Out Position.”

The evaluation concluded there were no adverse impacts on the intended safety function of the affected switchgear, and other adjacent cubicles’ in-service devices (i.e., relays, instruments, etc.); provided the duration of the seismically unanalyzed conditions only existed for a limited period of time. On April 22, 1997, the licensee applied the results of the evaluation and updated the safety analysis report per USAR Change 7-209, “Section 3.10, Qualification of Seismic Category I Instrumentation and Electrical Equipment.”

The evaluation concluded there were no adverse impacts on the intended safety function of the affected switchgear, and other adjacent cubicles’ in-service devices (i.e., relays, instruments, etc.); provided the duration of the seismically unanalyzed conditions only existed for a limited period of time.

On April 22, 1997, the licensee applied the results of the evaluation and updated the
safety analysis report per USAR Change 7-209, “Section 3.10, Qualification of Seismic
Category I Instrumentation and Electrical Equipment.”

April 23, 2015: CLINTON POWER STATION, EVALUATIONS OF CHANGES, TESTS, AND EXPERIMENTS AND PERMANENT PLANT MODIFICATIONS BASELINE

INSPECTION REPORT05000461/2015008

Severity Level IV-Green. The inspectors identified a finding of very-low safety significance, and an associated Non-Cited Violation of Title 10, Code of Federal Regulations Part 50, Section 59, “Changes, Tests and Experiments,” (effective January 1, 1997) for a procedure change dated May 2, 1997, where the licensee allowed safety-related switchgear to operate for a limited period of time during plant operation in equipment configurations that were seismically unanalyzed. Specifically, for Safety Evaluation Log 97-060, “CPS [Clinton Power Station] Procedure No. 1014.11,” Revision 0, the licensee failed to include a written safety evaluation which provided the bases that concluded for all switchgear configurations that a seismically unanalyzed condition does not involve an unreviewed safety question, and the possibility for a malfunction of a different type than any evaluated previously in the Safety Analysis Report may be created. The licensee entered the issue into their Corrective Action Program as Action Request 02471583, “NRC Mod 50.59 Inspection Safety Eval 97-060 for CPS 1014.11,” dated March 20, 2015.

On May 2, 1997, the licensee issued Procedure CPS 1014.11, “6900/4160/480V Switchgear/Circuit Breaker Operability Program,” which allowed switchgear in a seismically unanalyzed condition to be considered operable for up to 48 hours as long as administrative controls were implemented. After the 48 hours, the switchgear was then declared inoperable. The licensee’s associated Safety Evaluation Log 97-060, “CPS Procedure No.  1014.11

See, this is what I am talking about with incentivizing a big corporation to do the right thing. Was the 1982 $92 million dollar fine to the Clinton nuclear plant the largest fine by the agency? This was three years after TMI???

Millstone

???

Palisades Plant Is Such A Dog: NRC Finally Says Palisades has A Pattern Of PCP Pump problems

May 2014: Finding a chunk of PCP impeller lodged in the core barrel inspection report. 

Issues of concern:

1) You see with the PCP seal and the  CCW seal the pattern of not following procedures and bum procedures.This place and the NRC reeks with the smell of procedure problems.

2)  With the safety injection tank, this is on the NRC with letting them get away with leaks from 2010. Hasn't anyone learned the lessen with the safety injection/refueling water tank. Basically making assumption on incomplete information...this is a pattern with thee guys.

3) I have issues the of the timelessness of the of the PCP seal failure.     

April 30, 2015:  PALISADES NUCLEAR PLANT NRC INTEGRATED INSPECTION REPORT

05000255/2015001

***Green. A finding of very low safety significance and an associated NCV of Technical Specification (TS) 5.4.1(a) was self-revealed when the ‘C’ primary coolant pump (PCP) seal degraded as a result of an inadequate maintenance procedure. Specifically, maintenance procedure PCS–M–54, “N–9000 Primary Coolant Pump Shaft Seal Assembly,” did not identify critical steps in the assembly of the PCP seal and, as a result, the work activity was not adequately controlled. This issue was entered into the licensee’s Corrective Action Program (CAP) as CR–PLP–2014–03495, Planned Outage Required Due to Two Stages of the Primary Coolant Pump P-50C Seal Not Performing as Expected, dated June 21, 2014.

***Green. A finding of very low safety significance and an associated NCV of TS 5.4.1(a) was self-revealed on January 6, 2015, after the licensee identified smoke coming from the ‘C’ component cooling water (CCW) pump (P–52C) as a result of incorrect assembly of the inboard pump bearing in December 2014, due to an inadequate maintenance procedure. This issue was entered into the licensee’s CAP as CR–PLP–2015–00063, Workers Reported Smoke Coming from Shaft of P–52C, dated January 6, 2015. Inoperability of Safety Injection Tank Due to Long-Term Leakage

Introduction: A finding of very low safety significance (Green) and an associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, “Corrective Action,” was identified by the inspectors when licensee personnel failed to ensure that leakage out of the ‘B’ SIT, a condition adverse to quality, was corrected in a timely manner. Specifically, although minor water leakage out of the ‘B’ SIT had been occurring since at least 2010, the licensee failed to adequately address the leakage despite several plant outages that provided an opportunity to perform maintenance.

***Green. A finding of very low safety significance and an associated NCV of 10 CFR 50, Appendix B, Criterion XVI, “Corrective Action,” was identified by the inspectors when licensee personnel failed to assure that leakage out of the ‘B’ safety injection tank (SIT), a condition adverse to quality, was corrected in a timely manner. Specifically, although minor water leakage out of the ‘B’ SIT had been occurring since at least 2010, the licensee had not corrected the leakage despite several plant outages that provided an opportunity to address the issue. This issue was entered into the licensee’s CAP as CR–PLP–2014–04861, B SIT Declared Inoperable Due to Reaching Technical Specification Low Level Setpoint, dated October 7, 2014

***Green. A finding of very low safety significance and an associated NCV of 10 CFR 50, Appendix B, Criterion III, “Design Control,” was identified by the inspectors when the licensee credited fire doors for High Energy Line Break (HELB) protection without a supporting test or evaluation. Specifically, Procedure 4.02 credited fire doors with protection of safety-related equipment against a HELB when the primary HELB barrier was disabled without a test or evaluation to demonstrate the doors could withstand the HELB environment. This issue was entered into the licensee’s CAP as CR–PLP–2015–00371, NRC Concerns with Calculation EA–PSA–CCW–HELB–02–17, dated January 22, 2015.

Severity Level IV. A Severity Level IV NCV of 10 CFR 50.59(d)(1), “Changes, Tests, and Experiments,” and an associated finding of very low safety significance was identified by the inspectors when licensee personnel failed to maintain a written safety evaluation that provided a basis that the use of temporary alligator clip jumpers to maintain emergency diesel generator (EDG) operability during certain maintenance activities did not require a license amendment. Specifically, the licensee did not address the adverse effects of the use of alligator jumpers on the design and qualification of the diesel generator (DG) circuit breaker used per Engineering Change 50310 and changes to procedure SPS–E–1, “2400 Volt and 4160 Volt Allis Chalmers and Siemens Vacuum Circuit Breaker Auxiliary Switch Adjustments,” Revision 34. This issue was entered into the licensee’s CAP as CR–PLP–2014–04859, NRC Identified 50.59 Issue, dated October 7, 2014.

***Severity Level IV. A Severity Level IV NCV of 10 CFR 50.59(d)(1), “Changes, Tests, and Experiments,” and an associated finding of very low safety significance was identified by the inspectors when licensee personnel failed to maintain a written safety evaluation that provided a basis that the use of temporary alligator clip jumpers to maintain emergency diesel generator (EDG) operability during certain maintenance activities did not require a license amendment. Specifically, the licensee did not address the adverse effects of the use of alligator jumpers on the design and qualification of the diesel generator (DG) circuit breaker used per Engineering Change 50310 and changes to procedure SPS–E–1, “2400 Volt and 4160 Volt Allis Chalmers and Siemens Vacuum Circuit Breaker Auxiliary Switch Adjustments,”

This should have been 50.59 and indicates 50.59 violations are more widespread than known. It is a failure of the NRC enforce regulations (50.59s).

Revision 34. This issue was entered into the licensee’s CAP as CR–PLP–2014–04859, NRC Identified 50.59 Issue, dated October 7, 2014. 

More primary coolant problems...so now for the first time the NRC admits there is a pattern with numerous PCP issues?  

Selected Issue Follow-up Inspection: Primary Coolant Pumps

a. Inspection Scope

The inspectors have documented several issues related to PCPs at Palisades over the past several years. The inspectors documented completion of an Operability Determination inspection sample that reviewed increased vibrations on the ‘C’ PCP in IR 05000255/2011005. A Green finding and associated NCV was documented in Section 1R15.b of IR 05000255/2012003 for the operation of PCPs outside their design operating criteria. Another Operability Determination inspection sample was documented in IR 05000255/2013002, which reviewed an oversized PCP impeller. The inspectors documented completion of a post-maintenance testing inspection sample following replacement of the ‘C’ PCP impeller in Section 1R19 of IR 05000255/2014002. Section 1R20 of that same IR documented a comprehensive review of the history of PCP issues at Palisades and the review of a piece of PCP impeller that was unable to be removed from the reactor vessel. The inspectors documented completion of another Operability Determination inspection sample that reviewed degradation of the ‘C’ PCP seal in IR 05000255/2014003. Section 1R20 of that same IR documented that the licensee performed a maintenance outage to replace the degraded ‘C’ PCP seal and Section 4OA2.4 documented a review of the licensee’s planned actions to address the NCV documented in 2012.

During this inspection period, the inspectors continued their collective and ongoing review of the numerous PCP issues at Palisades. Of particular focus was a review of the licensee’s root cause evaluation for degradation of the ‘C’ PCP seal that was initially installed during refueling outage 1R23 in spring 2014 and replaced during a summer 2014 maintenance outage. The inspectors also remained aware of the licensee’s plans and progress in resolving the NCV issued in 2012, and planned to continue to assess the timeliness of corrective action implementation.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152–05.

b. Findings

Inadequate Procedure Leads to Primary Coolant Pump Seal Degradation

Introduction: A finding of very low safety significance (Green) and an associated NCV of TS 5.4.1(a) was self-revealed when the ‘C’ PCP seal degraded as a result of an inadequate maintenance procedure. Specifically, maintenance procedure PCS–M–54, “N–9000 Primary Coolant Pump Shaft Seal Assembly,” did not identify critical steps in the assembly of the PCP seal and, as a result, the work activity was not adequately controlled.

Description: During RFO 1R23, from January through March 2014, the ‘C’ PCP seal was replaced as a planned maintenance activity. Prior to the RFO, the vendor provided training to plant maintenance personnel on seal disassembly, assembly, and installation. The seal package was assembled by site personnel using procedure PCS-M-54, “N–9000 Primary Coolant Pump Shaft Seal Assembly,” Revision 6, on the spent fuel pool floor with oversight from the vendor. This activity also included pre-installation testing and cleaning. The seal was then lifted into containment and installed in the pump.

On March 16, 2014, a few days after plant startup from RFO 1R23, the licensee identified that the ‘C’ PCP seal package breakdown pressures for the middle and lower stages were not trending as expected. An operational decision-making instruction (ODMI) was written to provide guidance to the operators on steps to take if the pressures increased, the pressure breakdowns between the seals decreased, or the controlled bleed-off flow increased. On May 13, 2014, following safety injection system surveillance testing, the control room received an alarm for ‘C’ PCP seal abnormal pressure and entered the abnormal operating procedure (AOP). This also exceeded trigger points in the ODMI. The middle seal stage was declared failed and an engineering evaluation was performed to determine the condition of the remaining seals and if the pump could continue to operate safely. The pump was deemed safe for continued operation and the ODMI trigger point criteria were revised based on the most recent data.

Based on continued slow but steady seal degradation, the

The transient of shutdowns cause damage to safety equipment.

licensee decided to shut down the plant on June 21, 2014, to replace the seal. The transient of shutting down the unit caused the lower stage of the seal to fail, as well as the previously declared failed middle stage. The upper and vapor stages of the seal remained fully functional. After the seal package was replaced, the unit was re-started from the maintenance outage on June 26, 2014. The licensee entered this issue into the CAP as CR–PLP–2014–03495, PCP P–50C Seal Cartridge Exceeded ODMI Minimum Pressure Drop for Two Stages,

on June 24, 2014.

A root cause evaluation was conducted to determine the cause of the seal stage failures. The removed seal was sent to the vendor for analysis after it was removed. The vendor was able to rule out many potential causes including the seal being dropped, inappropriately pressurizing the seal, increased or abnormal pump

My theory was the big impeller blade missing could damage pump bearings the bearing due to excess vibration. The C pump is the same pump with impeller missing and the seal damaged.    

vibrations, and foreign material intrusion. Interviews with maintenance personnel were also conducted. The direct cause was determined to be the stationary faces for the middle and lower stages of the seal not being sufficiently seated to allow the o-ring to seal and thus allowing leakage through the stages past the o-rings. No definitive root cause was determined. However, a probable root cause of not classifying the seal assembly as a critical maintenance activity, which would have provided additional training, oversight, and critical step identification, was identified. There was also a misunderstanding of the pre-installation testing; the licensee believed this testing would identify any assembly issues, when in fact it would only detect gross leakage or major assembly errors.

Analysis: The inspectors determined that not maintaining an adequate procedure to assemble and install the ‘C’ PCP seal was an issue of concern and evaluated the issue in accordance with IMC 0612, Appendix B. The issue of concern was not associated with any willful or traditional enforcement aspects. The inspectors determined that the issue of concern was within the licensee’s ability to foresee and correct and represented the failure to meet a standard in that the licensee did not maintain appropriate maintenance procedures as recommended in Regulatory Guide 1.33, Revision 2, Section 9.a, which the licensee was committed to in TS 5.4.1(a). Therefore the issue of concern represented a performance deficiency.

The inspectors determined that the performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

The inspectors evaluated the issue in accordance with IMC 0609, Attachment 4. The questions in Table 3 were answered "No" and the inspectors continued the significance evaluation in accordance with IMC 0609, Appendix A. The inspectors reviewed the Initiating Events questions in Exhibit 1 and answered "Yes" to the Loss of Cooling Accident (LOCA) Initiators screening question, “After a reasonable assessment of degradation, could the finding result in exceeding the reactor coolant system leak rate for a small LOCA,” because the first two seal stages ultimately failed and if the 3rd stage had failed, a PCP seal LOCA may have occurred resulting in a small break LOCA. Therefore, a detailed risk evaluation was performed by a Region III SRA.

The change in risk for this performance deficiency was best characterized by the risk associated with the manual reactor shutdown that occurred. The SRAs performed the analysis using the Palisades SPAR Model Version 8.20, SAPHIRE Version 8.1.2.0. A “Transient” initiating event analysis was run using the SPAR model. The result was an estimated conditional core damage probability (CCDP) of 4.17E–07. The CCDP result included risk due to Anticipated Transient Without Scram (ATWS) scenarios. The SRAs reviewed the results that did not contain reactor protection system failures, and obtained a revised CCDP for non-ATWS transients of 1.81E–08. Given this result, the SRAs concluded that the change in risk for the performance deficiency was less than 1E–07/year (i.e., ΔCDF < 1E–07/year). The dominant sequence involved a transient with failure of safety valves to reclose after opening, failure of shutdown cooling, and

failure of high pressure recirculation.

Based on the detailed risk evaluation, the inspectors determined that the finding was of

very low safety significance (Green).

This finding had a cross-cutting aspect in the Work Management component of the Human Performance cross-cutting area. Specifically, the licensee did not effectively screen the PCP seal assembly through the work management process to identify that it should have been classified as a critical maintenance activity. In addition, insufficient emphasis was placed on in-field vendor oversight during work execution. (H.5) Enforcement: Technical Specification 5.4.1(a), states, in part, that written procedures shall be established, implemented, and maintained as recommended in Regulatory Guide 1.33, Revision 2, dated February 1978. Section 9.a, “Procedures for Performing Maintenance,” states in part, “Maintenance that can affect the performance of safety related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances.” Procedure PCS–M–54, “N 9000 Primary Coolant Pump Shaft Seal Assembly,” Revision 6, contained instructions for assembly of safety-related PCP seals.

Contrary to the above, during RFO 1R23, maintenance personnel completed assembly of the ‘C’ PCP seal using procedure PCS–M–54, which did not include critical steps to validate that the seal was assembled correctly prior to operation. As a result, the ‘C’ PCP seal stages degraded during plant operation such that a subsequent plant outage was necessary to replace the seal. Because this issue was of very low safety significance and because it was entered into the CAP as CR–PLP–2014–03495, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000255/2015001–07, Inadequate Procedure Leads to Primary Coolant Pump Seal Degradation)