Pilgrim Blizzard LOOP And Plant Trip...Worst Accident in Plant's History.

Jan 30:

Reactor Core Isolation Cooling (RCIC) System 

The RCIC is used in BWR-3 through BWR-6 boiling water reactor designs. The RCIC system is a single train standby system for safe shut down of the plant. The system is not considered part of the emergency core cooling system (ECCS), and does not have a loss of coolant accident (LOCA) function. The RCIC system is designed to ensure that sufficient reactor water inventory is maintained in the vessel to permit adequate core cooling. This prevents the reactor fuel from overheating in the event that the reactor is isolated from the secondary plant. 

Following a normal reactor shut down, core fission product decay heat causes steam generation to continue, albeit at a reduced rate. During this time, the turbine bypass system diverts the steam to the main condenser if the reactor is not isolated from the secondary plant, or to the suppression pool through operation of safety/relief valves (SRVs) if the reactor is isolated. 

The RCIC system supplies the makeup water required to maintain reactor vessel inventory. The turbine-driven pump supplies makeup water from the condensate storage tank (CST) to the reactor vessel. An alternate source of water is available from the suppression pool. The turbine is driven by a portion of the steam generated by the decay heat and exhausts to the suppression pool. This operation continues until the vessel pressure and temperature is reduced to the point that the residual heat removal (RHR) system can be placed into operation. 

First, I documented I predicted a LOOP...think I am the first person who ever predicted a extremely rare Loss Of Offsite Power accident and then it occurred. 

I believe so far the important inop component are.

1) HPCI

2) LOOP 

3) Four ADS/SRV since 2011

I think the plant is going to get a special inspection and maybe a Augment inspection. It might get raised to a red level finding...national implications. 

Should have shutdown 4 hours before the blizzard struck.

I believe the smaller shutdown off site line, it wasn't safety qualified, bet you they were afraid to test it with a load it was so fragile. 

So it scrammed at 52% power.

PRELIMINARY NOTIFICATION OF EVENT OR UNUSUAL OCCURRENCE - PNO-I-15-001
This preliminary notification constitutes EARLY notice of events of POSSIBLE safety or public
interest significance. Some of the information may not yet be fully verified or evaluated by the
Region I staff.
Facility Licensee Emergency Classification
Entergy Nuclear Operations, Inc. __ Notification of Unusual Event
Pilgrim Nuclear Power Station ___ Alert
Plymouth, MA ___ Site Area Emergency
Docket No. 50-293 ___ General Emergency
License No. DPR-35 X Not Applicable 

SUBJECT: PILGRIM NUCLEAR POWER STATION: SHUTDOWN GREATER THAN 72 HOURS DUE TO REACTOR SCRAM FOLLOWING A PARTIAL LOSS OF OFFSITE POWER

On January 27, 2015, Pilgrim Nuclear Power Station experienced an automatic scram following a turbine trip due to a partial loss of offsite power. The station was experiencing high winds and heavy snowfall during a severe winter storm when the station began experiencing degrading switchyard conditions. The station had already transferred the emergency busses onto their respective emergency diesel generators and was downpowering to 20% power to take the turbine offline. At 4:02 a.m. with the reactor at 52% power, the second offsite line was lost and the station experienced a load reject.

The station experienced equipment issues while cooling down after the scram including: the station diesel air compressor failed to start, one of four safety relief valves could not be operated manually from the control room, and high pressure coolant injection had to be secured due to failure of the gland seal motor.

The station is currently in cold shutdown, the safety buses are being powered by their respective emergency diesel generators, and all safety-related equipment required for safe plant shutdown are available. The licensee is working on restoring their 345kV lines.
Resident inspectors and region-based inspectors are providing oversight and performing
follow-up inspections.

This preliminary notification is issued for information only. The information presented herein has been discussed with the licensee and is current as of 1:00 p.m. on January 29, 2015. Commonwealth of Massachusetts officials have been kept informed.

Nobody considers the 23 kilo-volt a legitimate safety line. You get it, they use it and it trips, that is proof it is a pure LOOP. As I said, they are preserving the operability of the 23 kilo-volt line just to mitigate the violation coming out of this. Or to conn the public that the grid was still connected to the plant.    

One of two 345-kilovolt offsite lines was deenergized due to weather concerns. At about 52 percent power, the second 345-kilovolt line that provides off-site power to the plant tripped, resulting in a reactor shutdown, or scram, at about 4 a.m. (Nuclear power plants not only generate power and send it to the grid, they also receive a certain amount of power from the grid for operational purposes.)

A third off-site power line, a 23-kilovolt line, remains available. However, the emergency diesel generators for now remain the primary source of power for safety systems. The reactor was safely shut down, with plant safety systems performing as expected. The exact cause of the loss of the 345-KV power lines is still being investigated.

The moderator has indicated they moved my article ..they have taken notice of my title of "From the Hands of God." The blizzard has stuck overnight and we are getting indications of the plant trip and LOOP. This God thing is me indicating I think this is a big deal and I got people talking to me.  This NRC at the below is indication they added the next blog article about the new NRC inspection just for me.

Moderator January 28, 2015 at 9:53 am

"From the hands of God"

How many individuals in the USA ever predicted a LOOP at a specific plant at a particular timeframe and had the prediction openly documented on the internet two days before it happened? I think I am the first?

“Historic Blizzard Juno Warning Going Over Pilgrim Nuclear Plant”

1. The NRC documents 20 LOOPs at Pilgrim since 1980 (42 years of operation). I estimate the per one hundred year rate for Pilgrim is 55 LOOPs. Pilgrims relicensing documents say it is about 6.5 LOOPs per one hundred years. What is the bounding LOOP rate…pilgrim had three LOOPs in about three days during blizzard Nemo? That is an astronomical rate. I request the NRC use the worst case LOOP rate of about 55 LOOPs in all Pilgrim’s violation risk calculations and any other risk calculation used in Pilgrim. It gets you wondering what generic LOOP rate would bound all loops rate uncertainties?
   “This got to be an act of god: A blizzard that knocks Pilgrim off the grid on Jan 27 and this below inspection report is dated on Jan 26. It explains why Pilgrim has so many LOOPS and why the NRC remains inconsequential with controlling bad actor licensees. I yet can’t get a copiable document…have to wait till it gets on Adams.
   ‘Pilgrim Nuclear Power Station – NRC 95002 Supplemental Inspection Report 05000293/2014008 and Assignment of Two Parallel White Performance Indicator Inspection Findings’
   Did the agency see the blizzard coming in anticipation of the LOOP and decided it has to be released the IR yesterday! This is proof the agency seen the LOOP coming and didn’t force Pilgrim to shutdown prior to the storm. They should have ordered Pilgrim to shutdown 4 hours before the blizzard hit. This would have more caused them incentive to repair their fleet wide nuclear endeavors. It would have been invaluable for all the rest of the utilities to see.
   If you were god, would your release Pilgrim’s inspection report before the LOOP or after the LOOP?
   This is my proof that an intelligent god exist!!! I never needed any proof.
   Bill, why haven’t you put your hat in ring to be a NRC commissioner?
   I have to give “great” credit to the NRC for publishing my items! Thank you Victor.
   steamshovel2002@yahoo.com
   Note: Moved by the moderator

   Reply
• ModeratorJanuary 28, 2015 at 9:54 am
  

  Please see our post today for more information on Pilgrim.

Just for me: 

Additional Scrutiny at Pilgrim Nuclear Power Plant Set to Continue

9 Comments Posted by Moderator on January 28, 2015

Neil Sheehan
Public Affairs Officer
Region I
Last fall, a team of NRC inspectors was tasked with evaluating whether issues at the Pilgrim nuclear power plant that triggered increased agency oversight had been satisfactorily addressed. That team has now returned its findings in the form of a newly issued inspection report.
And the answer – at least at this point in time – is that Entergy, the Plymouth, Mass., plant’s owner, still has some more work to do.

The implications of the LOOP, plant trip and components degradation are hitting me...there has been no public discussions about the failed SRV valve as of yet. I know the  SRV valve didn't work and I am hinting to the NRC pretty heavy I am  into the details with the history of the SRVs.  

1. Mike MulliganJanuary 28, 2015 at 11:18 am
   

   Does Scrutiny ever lead to a behavior change with a licensee? Why didn’t it work from this new inspection report preventing the plant trip and newest in storm Juno LOOP. Ring that up you cash register risk perspectives with a broken HPCI and 55 LOOPs per one hundred years.
   Makes me laugh…have to wait until pilgrim is ready to receive the inspection?
   Maybe if the inspection was more timelier to the 2013 events…Pilgrim wouldn't have had the yesterday’s LOOP. How come the NRC didn’t force Pilgrim to shut down prior to storm Juno as identified in the new inspection report, as their switchyard and the outside transmission system was so fragile for the expected climate and especially winter storms.
   We knew Pilgrim was going down the tubes being in 2011 when they accepted poor quality brand new SRVs (all four of them)…the pathetic host of leaks, down powers and shutdowns over this new equipment. We were shocked the agency would treat these important last ditch core cooling components so cavalierly. You know how I feel, read my 2.206s. I contend if the agency would have slapped Entergy hard in the head with a big fine or prolonged shutdown then… you would have woke Entergy up from their nap. Then Pilgrim would have sailed through storm Juno uneventful at 100% power.
   I call the NRC a “paper cut” regulator….the only power they got over these giant companies as incentive to get their heads on straight is to give them one insignificant paper cut after another to no results.
   Why is the NRC allowing our NE grid to become so fragile? Why is the two plant Millstone (Dominion) unit and Pilgrim (Entergy) going down the tubes together…why can’t the agency control these plants? I think it extremely dangerous to allow a plant to be operating in “organizational dysfunction” and impaired “safety culture” mode knowingly for prolong periods of time: repetitively spewing out of the plants safety component breakdown, unseen component degradation and showing contempt towards the agency with knowingly violating tech specs, licensing conditions and the USFARs. It is like operating your car carelessly with the low oil pressure red warning light for days and weeks. I think it is in the greater interest of the United State of American to drive a plant early and quickly out of disorder and chaotic organizational conditions?

The NRC talking to me again. The USFAR don't cover ever aspect of a plant condition. The current state of the organization, the condition of the equipment and how the plant in the past responded to to similar problems...the conditions expressed by the NRC itself in the new inspection. The NRC recently has stated they take it very seriously when a plant keeps challenging and testing needlessly it safety systems. It is a very dangerous practice and it wears out the gear. You just can't keep testing your plant safety components...putting or turning a safety response into the normal operating regime of a plant. Because switchyard and transmission component are't reliable and causing plant trips and deep safety challenge...you can't explain this as the normal and expected operational events. 

Nuclear Power Plants Ready For Major Winter Storm

15 Comments Posted by Moderator on January 26, 2015

• ModeratorJanuary 27, 2015 at 11:32 am
  

  Thank you for the comment
  We should have stated that the limits on wind speed are defined in the plants’ Emergency Action Levels (EALs) and Updated Final Safety Analysis Report (UFSAR). While plants’ Technical Specifications do not contain explicit limits with respect to wind speed, the operability of the associated systems can be impacted by external events which may require a plant shutdown. For most plants, the Abnormal Operating Procedures (AOPs) and EALs will direct plant shutdown based upon actual and forecasted wind velocities to ensure the associated safety-related systems remain operable.
  Neil Sheehan

Then this: 

Additional Scrutiny at Pilgrim Nuclear Power Plant Set to Continue

9 Comments Posted by Moderator on January 28, 2015

Neil Sheehan

Public Affairs Officer

Region I

Here I am laying out why this needs a Special or Augmented inspection...the failed components and I am giving the NRC deep details with the operational problems documented in the docket. I giving them the short story documented in the docket with why I think all ADS and SRV valves are not operable based on the cumulative recent operating experiences and agency documents. They  all know this story is tracking with all the documents.   

1. Mike MulliganJanuary 29, 2015 at 7:10 pmYour comment is awaiting moderation.
2. 
   
3. So when you sending the special inspection team? An augment inspection?
   Sound like I had a little birdy whispering in my ears?
   Just when you could think the repetitive TDAFWP couldn’t get any worst at Millstone…now we got the poor quality SRVs failing over and over again at Pilgrim for 4 years just like the TDAFW pumps did. Is this going to take three special inspection to fix just like Millstone? Wait, this is like the TDAFWP and both half capabilities electric aux feed water pumps being simultaneously inop for 4 years. You should conservatively call “all” the SRVs/ADS valves inop and not according to tech specs since 2011.
   I bet you the SRV was leaking for a prolonged period of time and the agency hid it on us. The hide the leak philosophy first, before fix it quickly philosophy.This caused the valve to fail.The ADS/ SRV valves were inop since 2011 when first installed. Before they even got warmed they were inop. You get it, after “new” installation of the “new” three stage SRVs (4 of them), the first leak impairing the operation of one of these valve occurred within one or two months. Maybe within weeks of first start-up. This situation is unprecedented in the nuclear industry. I’ll bet you we are heading to a cover-up of a red finding. This is not about one valve…the whole group of them have a design defect and uncontrollable poor quality components from day one. A common mode failure of the automatic depressurization system and safety relief valve for four years. These nuclear safety valves weren’t fit to be in nuclear power plant.
   (Yesterday) “We knew Pilgrim was going down the tubes beginning in 2011 when they accepted poor quality brand new SRVs (all four of them)…the pathetic host of leaks, down powers and shutdowns over this new equipment. We were shocked the agency would treat these important last ditch core cooling components so cavalierly.”
   We have had a dangerous meltdown of the effectiveness of the NRC. i am writing up a 2.206 requesting the Pilgrim plant remain shutdown. All plants in Region I should be shutdown because there was such a severe breakdown in the NRC.
   What level of risk would that get you to: HPIC inop, SRV/ads inop, in a LOOP and the risk of 55 loops per 100 years (52 more LOOPs than assumed in calculations)? I think this is the most severe accident we have had in a long time.
   “The station experienced equipment issues while cooling down after the scram including: the
   station diesel air compressor failed to start, one of four safety relief valves could not be operated
   manually from the control room, and high pressure coolant injection had to be secured due to
   failure of the gland seal motor.”

I think the small transmission line is just a shame...going to be used as risk mitigation strategy for the violation. It is going to have great worth in calculating the violation level, but absolutely no worth for the operators in house. It just doesn't have the redundancy or the proper safety quality to be use as a source of power in nuclear plant.
The mysteriously discovered third line leading to a partial LOOP is nothing but regulator and licencee fraud...they ginned it up just to reduce the violation level. The 23 kilo-volt line is never mention in any of the new inspection report LOOPs...whether it was energized or not. The recent inspection report treats the plant as only having two viable lines into the plant. I find it highly suspicious now they are talking about partial LOOPs. 

Complicated Reactor Scram due to Loss of Offsite Power on October 14, 2013 Entergy assembled a multi-discipline team to perform the RCE for this issue. In addition to the direct cause of the failure of a defective pole at an offsite substation, which was determined to be outside the control of Entergy, the RCE documented one root and one contributing cause:

 Entergy failed to ensure that station procedures contained adequate pre-defined, risk-based criteria for planned maintenance on offsite transmission equipment which places Pilgrim in an SPV to an automatic scram (Root Cause); and

 The design for generation at Pilgrim is less than robust, with only two paths for generation output and offsite power supply (Contributing Cause).

Proposed Director's Decision on My Palisades PCP Impeller Blades!

It will be significant if I catch them all on this.

It will be so sweet if they really need a 50.59 and the staff didn't catch them on it??? 

Jan 26 at 12:32 PM 

Dear Michele G. Evans, 

https://adamswebsearch2.nrc.gov/webSearch2/main.jsp?AccessionNumber=ML14338A435 

Thank you for the NRC's response. The report was pretty detailed. I am sure people will look at me admiring if a worst PCP blade problem occurs or Palisades and the facility continues to develop bad plant problems. Got to love that new CDBI inspection results at this old plant. 

Information Notice No. 85-03: Separation of Primary Reactor Coolant Pump Shaft and Impeller

The scenario not explained yet by the NRC yet is: A set of blades getting flung off and creating a bad vibration issues with the pump. The staff then doesn’t think it is that bad and continues to run the pump. The vibration level build up to where it damages “all” the pump seals and this creates a LOCA. On the above IN, they almost separated the impeller from the shaft. 

Remember a nuclear plant doesn't need a severe core melt to get a license yanked...all they need is for the public to lose trust in the plant.
Thank you for answering me.
Sincerely,

Michele G. Evans(NRR): Mulligan’s Palisades 2.206

Mrs. Rankin, 

Additional Concerns: 

I think an accident coming out of broken PCP impeller blades is basically too complex to understand. I honestly don’t think anyone really understands completely how or why these blades fail. What can happen in the future not contrary to licensing. The normal way they handle this is they make a quality requirement over the global uncertainties. Why isn't there a quality requirement where these impellers are supposed to be replaced before cracks and broken blades shows up? 

Why isn't this an adverse to quality” violation? I am not certain how the USFAR and licensing treats quality for the PCP components “Why isn't this related to a 10 CFR 50.59 or licensing amendment request? I considered the PCP impeller problem contrary to plant licensing and the USFAR. Why didn't “not operating to plant licensing”, the NPSH issue…not cycle through a 50.59 or licensed amendment request change? I request the Palisades Plant immediately comply with all NRC regulations and UFSAR requirements. 

As far as the Salem plant primary coolant pump problem and Palisades plant PCP problems being dissimilar…I disagree. Basically defects have shown up in prior outage and inspections at both plants. The licensees and the NRC failed to immediately correct the problem. I fear this attitude would carry over to a much larger problem…where the licensee and the NRC would detect an incipient early problem and decide not to repair it. Then it leads to a much larger problem later on or it becomes a runaway repetitive problem. It is noticed the NRC doesn't do a comprehensive inspection write up about the early problems. You wait until to you are hunting around inside the core and coolant piping for broken off blades and missing screws to comprehensively report on it. I could make a case these inspection reports are still rather skimpy. 

Does the NRC have any actually testing with these 4000 hp pumps…proof…that the loose ductile blades won’t shatter the impeller? 

I have issues with the transparency of the OIG. Your staff reports these issues to the OIG. But there is no paperwork trail (like on the docket) that I can see showing you sent documents to the OIG and OIG never contacts me indicating they'd seen my concern and it is taken into consideration one way or another? 

I wish I had an industry wide perspective on PCP impeller blade problem? The blade problem seems only related to Palisades. I request the LERs and inspection reports on PCP problem be more comprehensively. This is an early indicator with licensee and safety culture problem. The public should see this.

Sincerely,Mike MulliganHinsdale, NH16033368320

ACTION: Proposed director's decision under 10 CFR 2.206;issuance. [7590-01-P]

SUMMARY: The U.S. Nuclear Regulatory Commission (NRC) is issuing a proposed director's decision with regard to a petition dated March 5, 2014, as supplemented on April 8, May 21, and September 3, 2014, filed by Mr. Michael Mulligan (the petitioner), requesting that the NRC take action with regard to Entergy Nuclear Operations, Inc. (ENO or the licensee) at Palisades
Nuclear Plant (PNP). The petitioner's requests and the proposed director's decision are included in the SUPPLEMENTARY INFORMATION section of this document.

Historic Blizzard Juno Warning Going Over Pilgrim Nuclear Plant

Jan 28, 2015

Is anyone asking the question why is Millstone and Pilgrim both going down the tubes together? 

Equipment breakdowns are nothing but a distraction from keeping the reactor safe in a historic blizzard and LOOP. 

***I don't buy the first part of this below...Entergy could have raised the roof through all federal and state authorities asking that (I believe) National Grid up grade these transmission lines. I doubt these lines meet FERC and FERC quality and reliability standards with the wood poles falling over or the lines shorting in a storm. They also could sue them?

We talking about a destructive fiduciary conflict or competition thing going on between National Grid and Entergy? Hell, if I was National Grid, I'd be thinking Pilgrim not might not be around in a short time, so why waste money on investing in their transmission system? 

I'd wonder if National grid is intentionally sabotaging Entergy, as they figured out away to make a few extra pennies in financial markets by speculating...creating stress on the electric grid or natural gas lines?

The coincident loss of transmission lines from faults external to Pilgrim resulted in a LOOP, main generator load reject, and reactor scram. This cause was determined to be outside the control of Entergy (Root Cause); 

 Entergy failed to ensure that procedures established adequate pre-defined, riskbased criteria to guide operators confronted with deteriorating switchyard conditions during and following a blizzard (Root Cause); 

 Entergy failed to ensure that procedure 2.1.42, “Operation During Severe Weather,” provided guidance for operators to determine which severe snow storms were most likely to challenge Pilgrim switchyard reliability (Contributing Cause); 

 Entergy did not ensure that CAPRs from previous severe weather events prevented recurrence (Contributing Cause); and 

 Previously identified internal OE was not successfully utilized by Entergy to direct removal of snow and ice from transformer insulators prior reenergizing (Contributing Cause).

The risk profile with 55 LOOPs per 100 years, in another LOOP and HPCI broke was pretty pathetic. Must have had annunciation alarms going up the ying hang all during the storm.

Entergy identified that individuals did not always understand the importance of adhering to nuclear standards and that station leaders have not consistently exhibited behaviors that set the appropriate standards

The cornerstone safety program at a nuclear plant..Corrective Action Program (CAP). You think the breakdown of the CAP program is just limited with their scram record?  

(new inspection report 201408) 

"In particular, Entergy identified that implementation of the station’s CAP has not been effective in ensuring adequate corrective actions are taken to address issues in a timely manner."

So it is more than equipment problem...the safety components of the whole organization is misfiring. Notice the NRC doesn't disclose what safety culture aspects were impaired?  

(new inspection report 201408) 

"With respect to the safety culture review, inspectors determined that Entergy’s evaluations appropriately identified the safety culture aspects that caused or significantly contributed to the performance issues."

It sounds like they had a inspector in the control room during this and that is the reason for the down power.

AUTOMATIC REACTOR SCRAM ON TURBINE TRIP DUE TO LOSS OF OFFSITE POWER

"On Tuesday January 27, 2015 at 0402 hours, with the Pilgrim Nuclear Power Station (PNPS) Reactor Mode Select Switch (RMSS) in Run and reactor power approximately 52% an automatic reactor scram signal was received due to the automatic trip of the main turbine that was initiated by the opening of the main generator breaker, ACB-104. The event occurred during winter storm 'Juno.' Prior to the event off-site transmission Line 355 was de-energized due [to] weather conditions and its associated PNPS switchyard breakers (ACB-105, a main generator breaker and ACB-102), were open. Per station procedures, reactor power was being lowered, a reactor protection system bus had been placed onto a back-up power supply, the Emergency Diesel Generators had been started and were powering the associated safety related 4 KV buses. The second off-site transmission Line 342 de-energized and the associated PNPS switchyard breakers (ACB-104 main generator breaker and ACB-103) opened. The Shutdown Transformer off-site power supply has remained available throughout this event. All control rods were verified to be fully inserted. Per plant design, Primary Containment Isolation System (PCIS) Group lI sampling systems, Group VI Reactor Water Clean-up (RWCU) system and Reactor Building Isolation System (RBIS) isolations occurred. Currently, the EDG's are powering the safety related 4KV buses, reactor water level is being maintained by the Reactor Core Isolation Cooling (RCIC) system and reactor pressure is being maintained by High Pressure Coolant Injection (HPCI) system. The station is conducting a plant cool down at this time. All systems responded as designed with the exception of a non-safety-related diesel air compressor, K-117 that failed to start."

Diesel Air compressor...you know what hell looks like, it shutting down a power plant without the air compressors. It is another example where they don't make these backup safety gear measure up to the necessary quality and testing. This gear is just a figurehead. 

In reminds me with ANO and Entergy killing a employee. Don't they care about the safety of their Pilgrim employees. You don't want your employees running inside and outside the plant sitting on the ocean's edge in a historic and terrible blizzard. You want them hunkered down in a stable mode to ride out the storm. In other words, at 100% or shutdown. These plants should be designed for the climate...it is not that hard to do. I don't hear about Millstone shutting down.  It is terrible unsafe to force their employees in a panic, in blizzard after blizzard to run around the plant inside and out like chickens with the heads cut off. 

The licensee will notify the State and local governments and plans on issuing a press release. The NRC Resident Inspector has been informed.

LOSS OF HIGH PRESSURE COOLANT INJECTION

"On Tuesday, January 27, 2015, at 0948 EST, with the Reactor Mode Select Switch (RMSS) in the Shutdown position and Pilgrim Nuclear Power Station (PNPS) at 0% core thermal power, the High Pressure Coolant Injection (HPCI) system was isolated by the main control room operating crew and declared INOPERABLE. HPCI had been in service for reactor pressure control following the automatic reactor scram experienced during winter storm 'Juno' reported in EN# 50769. It appears there was a malfunction of the HPCI turbine gland seal condenser blower or associated condensate pump. Reactor pressure control was transitioned to the safety relief valves and the reactor cooldown was continued. The plant is stable. The Emergency Diesel Generators are powering the safety related 4KV buses and reactor water level is being maintained by the Reactor Core Isolation Cooling (RCIC) system. HPCI is required to be OPERABLE in accordance with Technical Specification 3.5.C.1. Since HPCI is a single train system, the INOPERABILITY is reportable in accordance with 10CFR50.72(b)(3)(v)(D). The cause of the HPCI malfunction is not known at this time and troubleshooting continues.

"This event had no impact on the health and/or safety of the public.

"The USNRC Senior Resident Inspector has been notified."

Jan 26 from the NRC

PILGRIM NUCLEAR POWER STATION- NRC 95002 SUPPLEMENTAL INSPECTION REPORT 05000293/2014008 AND ASSIGNMENT OF TWO PARALLEL WHITE PERFORMANCE INDICATOR INSPECTION FINDINGS

• The current loss of offsite power frequency used in the agency’s risk models is slightly less than 3 events per 100 years. (Victor Dricks)

****Prediction below on Jan 25****

Jan 25, 2015: What do you say, I think the plant will trip and they will get some kind of LOOP in storm Juno. Bet you they got a 50% chance. 

It might be historic in nature....

With 20 "Lost Of offsite Power (LOOPS)accidents since 1980 according to the NRC...one of the highest rates in nation.

The NRC estimates a nuclear plant will get 2,3 or 5 LOOPs per one hundred years.I believe the Pilgrim estimated prorated rate is 55 LOOPs per one hundred years. Pilgrim is really susceptible to LOOPs and especially in the winter...

Pilgrim had 2 LOOPs last Nemo blizzard...

Jan 27: Basically the NRC and Entergy think the quality of the grid is out of the control of Entergy...

The progress here was they were powering down and at 50%...

Pilgrim nuclear plant offline because of storm outage 

JAN 27 2015: The Pilgrim Nuclear Power Station in Plymouth could be offline for days after a storm-related outage shut down two of the major lines carrying electricity from the generating facility.Officials said the problem is similar to one that hit during a 2013 blizzard, and poses no safety threat. The lines failed about 4 a.m., at a time when Pilgrim’s output had already been reduced to 20 percent because of storm-related conditions on the electrical grid.Continue reading below

“All safety systems worked as designed and plant conditions are currently stable,” said plant spokeswoman Lauren Burm. “There’s no threat to the safety of plant workers or the public.”She said it could be days before Pilgrim resumes normal operations, but that the plant would be able to stay offline for much longer than that without safety concerns.

Speaking at a morning news conference, state energy secretary Matthew A. Beaton said he had received no reports of the storm causing broader problems with the electrical grid.

About 7:45 a.m. Tuesday, there were 21,881 reported outages in the state, concentrated largely on the South Shore, Cape Cod and Nantucket. 

Brown Ferry

December 23, 2014: Licensee Event Report 50-259/2014-005-00

On October 29, 2014, during performance of the Browns Ferry Nuclear Plant (BFN) Unit 1 Main Steam Relief Valve (MSRV) Manual Cycle Test, MSRV 1-19 failed to open. Investigation of the failure revealed a misconfiguration of the control air lines to both the MSRV 1-19 and MSRV 1-18 which occurred during installation of the flex hoses in 2006. MSRV 1-19 has an Automatic Depressurization System (ADS) function which was defeated by the air line misconfiguration. The ADS function for MSRV 1-19 has been inoperable since May 2007. This condition would have prevented MSRV 1-19 from performing its specified ADS safety function for longer than allowed by Technical Specifications. The cause of this event was a latent organizational and programmatic gap associated with the BFN Unit 1 Restart Organization. Specifically, the management and organizational infrastructure in place during the BFN Unit 1 restart was inadequate to preclude numerous human performance errors during the 2005-2007 time period, including the multiple human performance errors associated with this event.

It is a incomplete corrective action program...how do they tell the operability of containment air? By detecting pressure and displaying it in the control room. Containment air connects up to the accumulators...drain the air from containment air because of the check valves in the dischage of  the accumulator would remain operable and pressurized. The accumulator would open and shut the SRV/ADS valve. You don't remotely display accumulator air pressure, even if you did...it wouldn't fully detect operability. This is a rather cheap and worthless fix coming out of the lessens of TMI. I hate add on components. Lets say a clump of rust from the interior falls off and collects at the bottom. Rust might weld the check valve shut. So the accumulator might still be filled with air and ADS might not work if the normal air fails.

The only way of verification of the permeability of the accumulator I can think of is a remote isolation valve up stream of the check valves. Have a vent path between the isolation valve and check valve, and another remotely operated valve in the vent like. You would need to display accumulation outside contain. Then shut the main line isolation valve, open the vent path valve...if the accumulator pressure goes down then the accumulator would work. By operation the SRV valve or ADS valve, even if these component opened, it still wouldn't detect the operability of the occumulation/

The big problem is not the mixed up lines...is they couldn't detect it not working it in all these testing and leak rate test over all these years. The non operability is very difficult to detect...you can't detect the non operability.

The corrective action is to revise the MSRV pilot valve installation procedures for all three units to include a step to validate the ADS-MSRVs are connected to the appropriate ADS accumulator.

Plant Operating Conditions Before the Event

Browns Ferry Nuclear Plant (BFN) Unit 1 was in Mode 1 at approximately 20 percent power.

So they were

II. Description of Event

A. Event:

On October 29, 2014, at 2225 hours Central Daylight Time (CDT), during performance of the BFN Unit 1 Main Steam Relief Valve (MSRV) Manual Cycle Test, MSRV [RV] 1-19 failed to open. Investigation of the failure on October 30, 2014, revealed the failure of MSRV 1-19 to stroke was due to the control air root valve, 1-SHV-032-2519, being

It is much worst than you can imagine. They found the mix up by accident. Here is the first error, the air root valve was found shut. Then they found the mixed up. So one ADS valve didn't work and a regulate SRV didn't. This raise two questions...were they decking prior testing of these valves.

inappropriately isolated by a separate, and unrelated, human performance error that occurred during the fall 2014 BFN Unit 1 Refueling Outage (RFO). Control air root valve 1-SHV-032-2519 is the control air header shutoff for MSRV 1-18. Further investigation revealed a misconfiguration of the control air lines to both MSRV 1-19 and MSRV 1-18. MSRV 1-19 has an Automatic Depressurization System (ADS) [SB] function.

BFN Unit 1 has 13 MSRVs. All 13 MSRVs can be opened manually from the main control room or are self-actuated to limit reactor pressure. The ADS consists of 6 of the 13 MSRVs and is designed to provide depressurization of the reactor during a small break loss of coolant accident if the High Pressure Coolant Injection System (HPCI) [BJ] fails or is unable to maintain required water level in the reactor. Each of the MSRVs used for ADS is equipped with an air accumulator [ACC]. The accumulator provides the pneumatic power to actuate the valves. These accumulators are provided to assure that the valves can be held open following failure of normal air supply.

The misconfiguration would have prevented MSRV 1-19 from performing its specified ADS safety function for longer than allowed by Technical Specifications (TS) Limiting Condition for Operation (LCO) 3.5.1 ECCS - Operating, actions due to a loss of backup control air supply from an accumulator.

The misconfiguration event occurred on December 7, 2006, during preparation for BFN Unit 1 restart from an extended outage, when the air hoses were installed incorrectly on MSRV 1-19 and MSRV 1-18 in a swapped configuration. Review of the work order determined the instructions were adequate to achieve successful installation of the hoses.

The misconfiguration was subsequently discovered by Operations on April 29, 2007, as part of the System Preoperability Checklist walkdown. A work order was initiated to correctly align the MSRV air lines. However, the lines were not swapped and remained misconfigured. A review of the work steps revealed a substitution error that essentially directed the workers to remove the lines and reinstall them in the same orientation.

On May 22, 2007, BFN Unit 1 was brought on-line with the misconfiguration still in place. This date represents the beginning of MSRV 1-19 inoperability.

On November 7, 2014, a temporary modification was implemented to restore operability of the ADS safety function. The ADS control air accumulator intended for MSRV 1-19 remains connected to MSRV 1-18. The controls and logic for the two valves were swapped to ensure the ADS circuitry from MSRV 1-19 opens MSRV 1-18. This temporary modification will remain in place until the condition can be corrected during the next refueling outage.

B. Status of structures, components, or systems that were inoperable at the start of the event and that contributed to the event:

The control air root valve 1-SHV-032-2519 was inappropriately isolated by a separate, and unrelated, human performance error, that occurred during the fall 2014 BFN Unit 1 RFO, resulting in the discovery of the ADS control air accumulator misconfiguration between MSRV 1-19 and MSRV 1-18.

C. Dates and approximate times of occurrences:

Dates & Approximate Times

December 7, 2006 Air hoses to MSRV 1-19 and 1-18 were installed in a swapped configuration during BFN Unit 1 restart.

April 29, 2007 Operations identified MSRV misconfiguration. Work that same day failed to correct the condition. Unit 1 restart.

May 22, 2007: BFN Unit 1 was brought on-line with the misconfiguration still in place. Start of MSRV 1-19 inoperability.

October 29, 2014, at 2225 hours CDT: MSRV 1-19 failed to open during the MSRV Manual Cycle Test. BFN Unit 1 entered TS LCO 3.5.1.E.

October 30, 2014 Central Standard Time (CST): Troubleshooting activities identified the misconfiguration of the control air lines to both the MSRV 1-19 and MSRV 1-18.

November 7, 2014, at 1746 hours: Implemented temporary modification to restore ADS function. Operations declared MSRV 1-19 Operable and exited TS LCO 3.5.1.E.

D. Manufacturer and model number (or other identification) of each component that failed during the event:

There were no failed components associated with this event.

E. Other systems or secondary functions affected:

There were no other system or secondary functions affected.

F. Method of discovery of each component or system failure or procedure error:

During performance of the BFN Unit 1 MSRV Manual Cycle Test, MSRV 1-19 failed to open. Investigation of the failure on October 30, 2014, revealed the failure of MSRV 1-19 to stroke was due to the control air root valve, 1-SHV-032-2519, being inappropriately isolated by a separate human performance error. Further investigation revealed a misconfiguration of the control air lines to both MSRV 1-19 and MSRV 1-18.

G. The failure mode, mechanism, and effect of each failed component, if known:

There were no failed components associated with this event.

H. Operator actions:

MSRV 1-19 failed to open during the MSRV Manual Cycle Test when Operations took the handswitch to the open position. Operations declared MSRV 1-19 inoperable and entered TS LCO 3.5.1.E.

Ill. Cause of the Event / Problem Statement

A. The cause of each component or system failure or personnel error, if known:

The direct cause of this condition was MSRVs 1-18 and 1-19 were initially installed with swapped control air supplied due to a latent human performance error made during BFN Unit 1 restart in 2006.

Contributing to this event was that there are no requirements to verify the ADS-MSRVs are connected to ADS accumulators.

B. The cause(s) and circumstances for each human performance related root cause:

The cause of this event was a latent organizational and programmatic gap associated with the BFN Unit 1 Restart Organization. Specifically, the management and organizational infrastructure in place during the BFN Unit 1 restart was inadequate to preclude numerous human performance errors during the 2005-2007 time period, including the multiple human performance errors associated with this event.

IV. Analysis of the event:

The Tennessee Valley Authority is submitting this report in accordance with Title 10 of the Code of Federal Regulations (10 CFR) 50.73(a)(2)(i)(B), as any operation or condition which was prohibited by the plant's Technical Specifications.

The BFN Unit 1 TS LCO 3.5.1, ECCS - Operating, requires the ADS function of 6 MSRVs to be Operable, during Mode 1, and Modes 2 and 3, when the steam dome pressure is greater than or equal to 150 pounds per square inch gauge (psig). With one BFN Unit 1 ADS valve inoperable, TS 3.5.1 Required Action E.1 requires the ADS valve to be returned to Operable status in 14 days. If the ADS valve cannot be restored to Operable status in the required time period, TS 3.5.1 Required Actions G.A and G.2 require the unit to be in Mode 3 in 12 hours and to reduce reactor steam dome pressure to less than or equal to 150 psig in 36 hours.

Inoperability of MSRV 1-19 began on May 22, 2007, when BFN Unit 1 was brought on-line after an extended shutdown and ended on November 7, 2014, at 1746 hours CST, when the ADS function was declared operable following a temporary modification to MSRVs 1-19 and 1-18. Therefore, BFN Unit 1 operated with one inoperable ADS valve for longer than allowed by TS 3.5.1 Actions.

BFN Unit 1 LCO 3.0.4 prohibits Mode changes when an LCO is not met except under certain conditions that were not applicable to this event. Since it was not recognized that one BFN Unit 1 ADS valve was inoperable from May 22, 2007, until November 7, 2014, BFN changed Modes in violation of LCO 3.0.4 on multiple occasions. This event was the result of multiple, and latent, human performance errors at all levels of the organization during BFN Unit I restart. Specifically, human performance errors were introduced when flex hoses were initially installed incorrectly in 2006, when preparing the flawed corrective maintenance work order after the condition was identified in 2007, when the work order was approved with the flaw, when the work order was performed without identifying the error, and when the organization failed to verify the identified misconfiguration had been corrected.

Human performance issues during the BFN Unit 1 Restart were previously identified and evaluated by Problem Evaluation Report (PER)137614 in 2008 to investigate the five BFN Unit 1 scrams following BFN Unit 1 restart. The investigation identified three common root causes including an inadequate BFN Unit 1 management and organizational infrastructure, less than adequate risk management, and a lack of first line supervision and management oversight. Consistent with these findings, the cause of this event was a latent organizational and programmatic gap associated with the BFN Unit I Restart Organization.

Contributing to this event was that there are no requirements to verify the ADS-MSRVs are connected to ADS accumulators. During each outage, testing is performed as part of pre-startup activities to verify the ADS valves can be cycled from the control room. The MSRV solenoid pilot valves are removed and replaced with lab verified, refurbished pilot valves that have certified set points, and the ADS accumulators are checked for soundness. However, the connection of the ADS-MSRVs to the correct ADS accumulators is not verified. This missing requirement, in part, allowed this misconfiguration condition to exist undetected for approximately seven years.

 The likelihood of the MSRV control air lines being swapped in the future is unlikely because the flex hoses connecting control air to the MSRVs cannot be physically manipulated to interface with an adjacent MSRV because the interface is welded and this union is not broken during normal valve maintenance. To ensure this condition does not exist for the other BFN units, walkdowns will be performed on the BFN Units 2 and 3 MSRV control air lines during each units upcoming refueling outage. To preclude this condition from recurring, the MSRV pilot valve installation procedures will be revised to verify ADS-MSRVs are connected to the correct accumulator.

Assessment of Safety Consequences

ADS serves as a backup to the HPCI System under certain loss of coolant accident conditions. During the last three years, one ADS valve has been inoperable, and the HPCI and low pressure ECCS have been out service for maintenance along with the inoperable ADS valve. Evaluations provided by General Electric and AREVA have shown that the bounding scenario plus the loss of the ADS valve does not result in failure to meet 10 CFR 50.46 and Primary Containment acceptance criteria.

A Probabilistic Risk Analysis (PRA) of this condition concluded that the unavailability of the MSRV 1-19 to perform an ADS function or to be backed by an accumulator would have an insignificant impact on overall plant risk. The PRA concluded that there was no plant configuration which would present a significant increase in risk over normal test and maintenance due to the unavailability of a single ADS valve.

Based on the discussion above, the safety significance of this condition is minimal and did not pose a threat to the health and safety of the public or plant personnel.

A. Availability of systems or components that could have performed the same function as the components and systems that failed during the event:

Five of the six ADS valves remained available. Although the ADS function for MSRV 1-19 was unavailable, the valve would have performed within the tolerance of the mechanical setpoint of 1135 psig during an overpressurization event.

B. For events that occurred when the reactor was shut down, availability of systems or components needed to shutdown the reactor and maintain safe shutdown conditions, remove residual heat, control the release of radioactive material, or mitigate the consequences of an accident:

The ADS is not required to perform its safety function when the reactor is shut down.

C. For failure that rendered a train of a safety system inoperable, an estimate of the elapsed time from discovery of the failure until the train was returned to service:

Inoperability of MSRV 1-19 began on May 22, 2007, when BFN Unit 1 was brought on-line after an extended shutdown and ended on November 7, 2014, at 1746 hours CST, when the ADS function was declared operable following a temporary modification to MSRVs 1-19 and 1-18.

VI. Corrective Actions

Corrective Actions are being managed by TVA's corrective action program under Problem Evaluation Report (PER) 952082.

Immediate Corrective Actions

A temporary modification was implemented to restore operability of the ADS safety function. This temporary modification will remain in place until the configuration can be corrected during the next refueling outage.

Corrective Actions that Reduce Probability of Similar Events Occurrinq in the Future "

* BFN will perform walkdowns of the BFN Units 2 and 3 MSRV control air lines during each units upcoming refueling outage to ensure proper configuration.

* BFN will revise the MSRV pilot valve installation procedures for all three units to include a step to validate the ADS-MSRVs are connected to the appropriate ADS accumulator.

VII. Additional Information:

A. Previous similar events at the same plant:

A search of the Corrective Action Program and BFN Licensee Event Reports for Units 1, 2, and 3, for approximately the past three years did not identify any similar events.

B. Additional Information:

There is no additional information.

C. Safety System Functional Failure Consideration:

In accordance with the Nuclear Energy Institute (NEI) 99-02, "Regulatory Assessment Performance Indicator Guideline," this event is not considered a system functional failure because the minimum number of ADS valves remained available to perform their safety function in the event of an accident.

D. Scram with Complications Consideration:

This event did not result in a reactor scram.

VIII. Commitments

There are no commitments.

ANO Stator Drop Accident: The NRC Stove Piping Risk?

Update

So basically ANO and Entergy got three yellow findings. 

January 22, 2015 SUBJECT: ARKANSAS NUCLEAR ONE, UNITS 1 AND 2 - FINAL SIGNIFICANCE DETERMINATION OF YELLOW FINDING AND NOTICE OF VIOLATION; NRC INSPECTION REPORT 05000313/2014010 AND 05000368/2014010

Above all else, these flooding problems weren't discovered by an effective process of Entergy and the NRC. I bet you effectively Entergy is paying the dead and injured employees mere pennies in compensation and punishment. After all, it Arkansas you know. It took Entergy not following procedures and then dropping a 550 ton stator killing a employee to uncover the flooding flaws. The punishment levels get derived through a grossly politically assumption system...perceived through a process and calculation system nobody understands. Nobody gets a penalty or punishment including the NRC for not having a effective organization before the stator dropped. Nobody got fired here or gone to jail. They are just paper whipping the violation. Both these plants should have paid the price of the plants being prohibited from starting up for a year or two.    

It got to be noted, as you go down the emergency operating procedures the complexity massively increases and they increasingly depend on less quality components and procedures. Complexity and uncertainty levels just skyrockets as you increasingly depend on not fully designed and engineered systems and procedures. At some level of complexity and stress, an outcome can never be assured. As the accident strips massively the redundant safety systems away from the plant, the consequence of a error drastically increase the risk of damaging the core. I hate add on systems or component because usually they aren't fully tested and all the uncertainties aren't fully washed out. I like a holistically designed plant...all these components in on plant first design.   

The NRC take on these cooling paths to be valid should be, you have to demonstrate flow up to the first containment isolation valve. If you depend on service water flow or temporally diesel generator, then you have to demonstrate flow up to the first containment isolation valve and you measure flow and pressure. Make believe flow paths are not approved. You really need periodic, yearly or every two years...the troops getting on the ground and pressurizing the alignment up to the first isolation valve to be even considered as a safety system. 

Basically in this day and age, a double fail safe, push a button and the system aligns and fills up and SG level is controlled...

This is basically the Fukushima dilemma...not having a diesel generator 100 feet up the ocean bluff and hard wired to the plant. The philosophy with the Japanese in a Tsunami, of having to fight the battle to save the plant in the flood waters within the plant. 

So how about a big tank way outside the flood zone. It hard piped into the plant right up to the steam generators. Starting the diesel generator, push a button and open up and valve or two...everyone safe. An access road to the tank...with the fire department cycling their trucks in a out to fill the tank. You could have constructed a sturdy cement cauldron out in the river and hard piped to near this tank. Then a fire truck could continuously fill the tank from the river.

Then the other Japanese dilemma...would you damage the steam generator in order to cool the core.

I didn't hear about the flex system coming in to save Entergy's butts.                 

A not recognized risk, if the staff and licensed operators think the mitigating strategies or flow paths are too star treky(not believable)...it is going to impact the safety culture. I'd like to see if the licensed operators accept the cooling paths.

Basically risk perspectives is a Abracadabra campaign monied system where the NRC and Entergy go into dark smoke filled rooms to negotiate a paper cut punishment and violation.   

You get it, the community has no say in it. 

So why isn’t the NRC recalculating the so call electrical yellow finding violation. It seems the flooding yellow finding was active just prior to the  first yellow finding. Two cases: 

1) ANO stator electrical yellow finding with the flooding barriers all according to regulations. 

2) ANO stator electrical yellow finding with the flooding barriers according to an inadequate flooding barrier in this second ANO yellow finding. 

Once can legitimately surmise the second example contains a lot more risk than the first example, and justified a lot bigger violation. 

This would be my contention that the disposition of risk perspective is riddled with fraud and corruption.   

The flooding issue is another example with inspector activities and the ROP is severely inadequate to know the true conditions at a power plant…the NRC selectively enforces tech specs and the licensing conditions at these power Plants. Why isn’t it a slam dunk that ANO employees are going to jail? Why isn’t there some serious soul searching going on in the NRC with why their inspection  and inspector activities didn’t undercover these violation at the first opportunity many years and decades ago?   

*I am looking for this answer: What is the generic  “Loss of offsite power” accident rate used in all NRC risk calculation and within coming up with a plant violation level?  I am told it is 2, 3 or 5 LOOPs per 100 years. Could the answer be in the once per hundred year terms?  

Mike Mulligan

Hinsdale, NH

NRC Finalizes Violations for Arkansas Nuclear One

     Posted by on January 23, 2015

The Arkansas Nuclear One power plant, in Russellville, Ark., is coming under increased NRC focus as a result of flood protection problems.


Beginning in 2013, Entergy Operations officials and the NRC began extensive inspections of the flood protection program at ANO. Many problems were discovered and are described in a Sept. 9, 2014, NRC inspection report.

All told, more than 100 previously unknown flood barrier deficiencies creating flooding pathways into the site’s two auxiliary buildings were found. These included defective floor seals, flooding barriers that were designed, but never installed, and seals that had deteriorated over time. In one case, a special hatch that was supposed to be close a ventilation duct in the Unit 1 auxiliary building in the event of flooding had never been installed.

In the unlikely event of extreme flooding – a kind not seen since weather records have been kept for the area – significant amounts of water could have entered the auxiliary buildings. This could have submerged vital plant equipment, as well as the emergency diesel generator fuel vaults. The licensee has replaced degraded seals, installed new flood barriers and adopted new measures to better protect the site from flooding.
NRC held a regulatory conference with Entergy officials on Oct. 28, 2014. After considering information provided by the company, NRC determined violations related to flood protection have substantial safety significance, or are “yellow.” (The NRC evaluates regulatory performance at nuclear plants with a color coded process that classifies inspection findings as green, white, yellow or red, in order of increasing safety significance.)

The NRC divides plants into five performance categories, or columns on its Action Matrix. ANO Units 1 and 2 received yellow violations in June 2014 because electrical equipment damaged during an industrial incident increased risk to the plant. Workers were moving a 525-ton component out of the plant’s turbine building when a temporary lifting rig collapsed on March 13, 2013, damaging plant equipment. Those violations moved both units from Column 1 to Column 3 of the NRC’s Action Matrix. The agency increases its oversight of plants as performance declines.

The new violations will lead NRC to reassess whether even more inspection resources need to be focused on ANO. The NRC will determine the appropriate level of agency oversight and notify Entergy officials of that decision in a separate letter.