Thursday, June 04, 2015

Employee Sabotage: Knocking Off Line The Waterford Nuclear Plant?

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Wednesday, June 03, 2015

LER 2014-006-00: The River Bend Christmas Scram Causing the First Special Inspection

So here is the 2014 Christmas scram that got the first inspection. An event like this happens with the mixture of poor plant maintenance and general incompetence of the employees...poor training across the board.  

Doesn't it raise the hairs in the back of your neck with all degradation of components showing up in one event? 

This is a dangerous plant in many ways...

I believe the first half scram with the turbine control scam over instrumentation problem was basically a  turbine grounding problem throwing electrical spikes at the instrumentation...creating a set of scrams.

I see the problem as in many cases as  intermittent equipment and electrical problems...they really don't have a means to record the event. They are uncertain what caused it...they guess what did it or on a quick and expensive fix...then quickly startup into the next scram.   

Licensee Event Report 50-458 /2014-006-00:Automatic Reactor Scram and Primary Containment Isolation Due to Loss of Power on the Division 2 Reactor Protection System With a Concurrent Division 1 Half-scram On December 25, 2014. at 0836 CST, a reactor scram occurred while the plant was operating at approximately 85 percent power. This event resulted from the loss of power on the Division 2 reactor protection system (RPS) (**JD**) bus, in conjunction with a preexisting half-scram on Division I. The loss of Division 2 RPS power also resulted in a Division 2 containment isolation signal. Approximately four minutes after the scram, reactor water level increased to the Level 8 setpoint, causing the running main feedwater pump (**SJ**) to trip. As reactor water level decreased back through the normal operating range, operators attempted to re-start main feedwater pump "C," but its supply breaker failed to close. Main feedwater pump "A" was subsequently returned to service. As reactor water level decreased to the point at which the startup feedwater regulating valve (FRV) should have opened to establish automatic control, the valve failed to open. Attempts to open it with a manual input signal were unsuccessful, and the "C" main FRVwas put back into service. By that time, reactor water level had decreased slightly below the Level 3 RPS actuation setpoint, resulting in a second scram signal. INVESTIGATION and IMMEDIATE ACTIONS 
The Division I half-scram had been inserted two days prior to the event, in compliance with Technical Specifications, following the failure of an instrumentation channel on the no. 2 main turbine control valve. Teams were formed to investigate the separate significant aspects of the event, as follows: Loss of Division 2 RPS Bus 
Power was lost when the output breaker on the RPS motor-generator (MG) in the Division 2 subsystem tripped. The mostly likely cause of the output breaker trip was an intermittent failure of the MG field flash card due to a degraded capacitor. The capacitor was replaced, and the MG was tested and returned to a standby condition as a backup power supply. The alternate power supply will remain in service carrying the bus until completion of a modification to eliminate the field flash card as a potential source of recurrence of this problem. Misoperation of the Startup FRV The operation of the startup FRV was investigated to determine why it was unresponsive to either the automatic controller or the operator's manual input. Maintenance technicians discovered a failed circuit card in the "manual" side of the valve controller. The ".automatic" function of the controller had operated correctly in the post-scram environment once reactor water level had returned to normal, and this was confirmed again during the troubleshooting. Additionally, Engineering personnel determined that the performance of the valve was consistent with its design criteria. The valve and its control logic are designed for flow control, and not simply for isolation. When the valve receives a gradual "open" signal from the closed position, there is no specific time response requirement. This design feature can allow a delayed response that, in the scram recovery scenario, may be too slow to arrest a significant downward trend in reactor water level. Malfunction of Main Feedwater Pump "C" The failure of main feedwater pump "C" was found to have been was caused by an "over-racked" condition of its supply breaker (that is, the breaker racking mechanism had slightly over-travelled the last time the breaker was returned to service). This caused the limit switches that detect the position of the breaker mechanism within the cabinet to give the control logic circuit a false indication that the breaker was not connected to the bus. Interim instructions have been implemented to have electricians verify the condition of all similar breakers each time they are racked in.
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Tuesday, June 02, 2015

I Now Know What Is Wrong With The NRC. It's a Alien Invasion Coming.


Posted by Chris Beveridge
June 2, 2015 at 11:25 AM


The central idea of the series is one that’s certainly an interesting one, an approach you don’t see often when it comes to alien invasion shows. At least not ones that are treated seriously when you get down to it. As we see with the prologue here, these aliens are looking for a way to take care of business by working through the children. Not just any children though, but carefully selected ones that will give them the access they need. Seeing the way a young girl is enthralled by an imaginary friend she calls Drill is certainly eerie with how it unfolds, since Harper just views it all as a game and her mother finds it cute. But when it leads to the mother’s death in a creative way, that sets things into motion since the child’s father is the head of the Nuclear Regulatory Commission. That elevates things up several notches to be sure among those that investigate such things.
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Sunday, May 31, 2015

March 7, 2013: Mike Mulligan's Request For Special Inspection on Pilgrims SRVs Problems

Additionally, during an extent of condition review of historical SRV performance, the review identified on March 13, 2015 that SRV-3A had failed to open in response to three manual actuation demands on February 9, 2013 with reactor pressures of 114, 101, and 98 psig.


I supposed I could have danced around in a sting bikini at the font door of the NRC's main office trying to get them to take action. Maybe that could made them act.

The media is about worthless!!! 
From: Michael Mulligan [mailto:steamshovel2002@yahoo.com] 
Sent: Thursday, March 07, 2013 12:33 PMTo: newstip~globe.com; NRC Allegation
Subject: 2.206: Pilgrim Nuclear Plant SRVRequest for Emergency Shutdown  
Dear Sir, 
I called this into your hotline by telephone and left a message to a reporter an hour or so ago. This is just a follow-up. I'd like to get Gov Patrick to demand an immediate Pilgrim shutdown and demand a special investigation of these events.  
Mike 
So the below is my 2.206 request to the NRC. You'd do me a favor if the BG calls our region I public relation people...Neil Shaheen. 

March 7, 2013

Bill Borchardt
Executive Director for Operations
U.S. Nuclear Regulatory Commission
Washington, DC 20555-0001

Dear Mr. Bochardt,
Request an emergency and for a exigent bases, that the Pilgrim Nuclear plant be immediately shut down. 
Don't tell me just before Nor'easter Nimo struck the Pilgrim plant with a leaking safety relief valve and down at 80%, Entergy was intending to operate that plant with a defective leaking safety relief valve till the next refuel outage? Tell me it ain't so. It certainly looks like with the current leak today they are intending to operate till next month. 
Is the game plan today to incrementally increase reactor power from 94% by 1% to see if a new SRV leak is getting worse? 
Timeline: 
1) New three stage safety relief valves installed in the plant around May 2011. 
2) First leak and shut down on Dec, 26. 2011 (SRV RV-203-3D). 
3) Second leak and shut down on Jan 20, 2013 (SRV RV-203-3B).  
4) Third leak occurred a few weeks later and the Nemo blizzard tripped the plant.. .the NRC promised these valves would be fixed. (SRV RV-203-3B). 
5) Basically they operated for 20 days at 100% power operation post shutdown, then reported on Feb 27 the plant is operating at 94% power with no explained reason until today. The reason for the down power was kept secret from the public.
(NRC added: EDO -- G20130174)  
Don't forget the repetitive nature of the recently broken scram discharge volume vent and drain valves...implies Entergy is incapable of maintaining safety components in a nuclear plant.  
The repeated nature of the failure of the safety relief valves means Entergy doesn't know the mechanism of the failure.. .it is a common mode failure. The design and manufacture of these valves
They changed out the not safe 3 stage SRV valves  for new 2 stage SRVs after Juno...the NE+RC forced their hands  
are defective and it is extremely unsafe to operate in a nuclear plant with all safety relief valves being INOP. A condition adverse to quality...  
The NRC should have made a public comment about the new leaking safety relief when they first became aware of the leak. The implication is the agency was going to allow the plant to operate with unsafe SRVs until the refueling outage next month. The NRC is involved in a serious cover-up of an extremely unsafe operation in a nuclear power.  
1) Request an immediate shutdown the Pilgrim Plant.  
2) The is the second time I requested a special NRC inspection concerning the defective SRV valves.  
3) Not allowing the plant to restart Pilgrim until they fully understand the past failure mechanisms of the four bad new three stage safety relief valves.  
4) Request the OIG investigate this cover-up to keep an unsafe nuclear plant at power. 
References:
The Popperville Town Hall (my blog) 

"Pilgrim's Safety Relief Valve Leaking Boondoggle"

Sincerely,
Michael Mulligan
PO Box 161
Hinsdale, NH 0345116033368320
steamshovel2002@vahoo.com
This is the agency's take directly in the lead up to the Juno's trip. There is a lot more evidence. These guys are picking and choosing what information they think is important to push  out for a organizational agenda.  
May 27, 2015: PILGRIM NUCLEAR POWER STATION – NRC SPECIAL INSPECTION REPORT 05000293/2015007; AND PRELIMINARY WHITE FINDING
  • The ‘A’ SRV was not planned to be used due to previously identified pilot valve leakage, but was considered by Entergy to be available for use if needed.
The problem with the above in a past LER with pilot valve leakage, they all should know this...the leak can make the relief lift inaccurate without being detectable. It could be so inaccurate if they knew about it, they would have to intermediately shut down to fix it. It illegal to be up at power with a inaccurate SRV valve.  
  • While the ‘C’ SRV satisfactorily stroked during both the setpoint test and additional low pressure (100 psig) actuation test at the testing facility, the inspection revealed notable damage to some internal valve main stage parts. Specifically, the main valve piston had indications of some scoring and the lower piston ring (two rings in total) was seized within the piston ring. The most noteworthy damage was wear (grooves) in the main operating cylinder liner where the operating piston rings rest while the valve is in its closed position.

  • During Entergy’s investigation of the January 27, 2015 partial LOOP event, Entergy staff reviewed plant parameter data associated with historical SRV actuations. During the review, Entergy staff determined that the ‘A’ SRV similarly did not open during manual actuations on February 9, 2013, during a plant cooldown following a LOOP event. This determination was based on Entergy’s review of the response of reactor pressure, level, local suppression pool temperature, and SRV tailpipe temperature.
I think Entergy was actively not looking for problems with the SRV valves in 2013. They knew the mis-operation and choose not to report it. 

  • Entergy identified that, during the February 9, 2013, event, operators attempted to utilize the ‘A’ SRV to reduce reactor pressure on three occasions (at 114 psig, 101 psig, and at 98 psig). The operators observed that the ‘A’ SRV did not yield the appropriate tailpipe acoustic monitor response, although tailpipe temperature did show an increase. Following the third opening without observing the appropriate acoustic monitor response, operators only utilized the ‘C’ and ‘D’ SRVs for plant cooldown [note that the operators considered that the ‘B’ SRV was less desirable to use due to previously-observed pilot valve leakage]. 

  • The only action that resulted from CR-PNP-2013-00825 was the replacement of components associated with the ‘A’ SRV’s acoustic monitor. Maintenance workers identified an electrical ground on the system. Analysis. Entergy’s failure to identify, evaluate, and correct the condition of the ‘A’ SRV’s failure to open upon manual actuation during a plant cooldown on February 9, 2013, was a performance deficiency. In addition, the failure to take actions to preclude repetition resulted in the ‘C’ SRV failing to open due to a similar cause following the January 27, 2015 LOOP event.
2015-002-00: On March 12, 2015, after further engineering evaluation of performance of the valves and internal conditions identified during inspection, SRV-3A and SRV-3C were determined to have been inoperable for an indeterminate period during the last operating cycle. SRV-3C was determined to be inoperable based on its on-demand performance at low reactor pressures (first

Licensee Event Report (LER).2013-002-00, "SRV-3B Safety Relief Valve Declared Inoperable Due to Leakage and Setpoint Drift" was submitted on March 31, 2013 (Reference 1), with a target schedule of September 30, 2013 to submit a Supplement to the LER, after completing
the root cause analysis. Since then the vendor (Target Rock) has issued a 10 CFR Part 21 Notification, (Reference 2)confirming defects in safety relief valve bellows.

2013 - 002 - 01 On February 3, 2013, RV-203-3B first stage pilot valve leakage was identified while at full power. Reactor power was lowered to 80% and at 1000 psig pressure, the pilot was reseated. An Operability Determination with a compensatory measure was implemented to maintain the reactor power at 80% and reactor pressure at 1000 psig. An Operations Decision Making Issue (ODMI) was implemented to monitor and take corrective actions. During the forced outage on February 8, 2013, caused by a loss of offsite power due to a major winter storm, RV-203-3B first stage pilot valve was replaced with a new pilot valve and the plant was returned to power operation. The cause of the pilot leakage was determined to be a combination of the natural frequency issue and weakening of the pilot bellows spring. This bellows spring had a through wall failure during testing at an offsite test facility in March 2013. This failure was the subject of a Target Rock 10 CFR, Part 21 (Reference 1).The removed RV-203-3B pilot valve was sent to Wyle Laboratory for testing. 
As-found test results for the SRV, RV 203-3B pilot valve were: 
Pilot S/N SRV Position As-Found Deviation 23 RV-203-3B 1112 psig (-)3.8% Technical Specification 3.6.D.1 requires the as-found setpoint to be within 1155±34.6 psig (1120.4 psig to 1189.6 psig). The as-found setpoint was less than the minimum pressure specification required by TS 3.6.D.1. This test result was entered into the corrective action program as a separate event, and is included in this LER since the condition was discovered within 60 days from the initial discovery of pilot leakage. Accordingly, this as-found value being out of Technical Specification setpoint is reported in this LER pursuant to 10 CFR 50.73(a)(2)(i)(B).
Licensee Event Report 2013-002-01, SRV-3B SafetyRelief Valve Declared Inoperable Due to Leakage and Setpoint Drift
1/20/2013
  • This condition potentially applies to all four three
The design is defective creating the damaged components. There was no way to reliability to observe or predict the degradation mechanism. They were unfit for reactor operation...they were inop from new installation and onto the Juno plant trip.

The 3 stage SRVs defective and unsafe...post last outage they were all removed. 

Lets say the main spring was so severely damaged it would fail in three cycles. It would get through all the testing, then have two cycles before failing. It would pass all test, but sitting right on the precipice of failure. Is that fully operational or inoperationl? Does getting past all the pre-operational testing mean it is operational despite the actual materiel condition of the components inside the valve. 

I am certain there would be many other problems documented in secret plant documents than this.    
stage SRVs that were installed in RFO 18. During Cycle 19 operation, Pilgrim has observed leakage from RV-203-3B, 3C, and 3D.
  • On May 18, 2011 and November 25, 2011, SRV RV 203-3C second stage pilot valve minor leakage was observed. This condition did not cause inoperability of the valve. SRV RV-203-3C was replaced during the December 26, 2011 shutdown.
  • On December 26, 2011, SRV, RV-203-3D first stage pilot valve experienced leakage that exceeded the operability criteria while operating at full power. The plant was shut down as required by TS 3.6.D.2, RV 203-3C and 3D were repaired and the plant returned to full power operation. The cause of the pilot leakage was later determined to be a combination of the natural frequency issue and weakening of the pilot bellows spring. This bellows spring had a through wall failure during testing at an offsite test facility in March 2013. This failure was the subject of a Target Rock 10 CFR, Part 21 (Reference 1).
  • On January 20, 2013, Pilgrim experienced the event described in this Licensee Event Report, first stage pilot valve leakage of SRV, RV-203-3B. The plant was shutdown as required by TS 3.6.D.2. The pilot valve was replaced with a refurbished pilot and the plant was returned to full power operation.
  • On February 3, 2013, RV-203-3B first stage pilot valve leakage was identified while at full power. Reactor power was lowered to 80% and at 1000 psig pressure, the pilot was reseated. An Operability Determination with a compensatory measure was implemented to maintain the reactor power at 80% and reactor pressure at 1000 psig. An Operations Decision Making Issue (ODMI) was implemented to monitor and take corrective actions. During the forced outage on February 8, 2013, caused by a loss of offsite power due to a major winter storm, RV-203-3B first stage pilot valve was replaced with a new pilot valve and the plant was returned to power operation. The cause of the pilot leakage was determined to be a combination of the natural frequency issue and weakening of the pilot bellows spring. This bellows spring had a through wall failure during testing at an offsite test facility in March 2013. This failure was the subject of a Target Rock 10 CFR, Part 21 (Reference 1).
The removed RV-203-3B pilot valve was sent to Wyle Laboratory for testing.
As-found test results for the SRV, RV 203-3B pilot valve were: 
Pilot S/N SRV Position As-Found Deviation23 RV-203-3B 1112 psig (-)3.8%
Technical Specification 3.6.D.1 requires the as-found setpoint to be within 1155±34.6 psig (1120.4 psig to 1189.6 psig). The as-found setpoint was less than the minimum pressure specification required by TS 3.6.D.1. This test result was entered into the corrective action program as a separate event, and is included in this LER since the condition was discovered within 60 days from the initial discovery of pilot leakage. Accordingly, this as-found value being out of Technical Specification setpoint is reported in this
  • The third pilot on RV-203-3B began leaking on February 26, 2013. Leakage was controlled by reducing power and pressure per the ODMI. This pilot was replaced during the Spring 2013 RFO. The cause of the pilot leakage was that the pilot assembly had a natural frequency that was close to a resonant frequency of the valve assembly when installed on the PNPS main steam line.
























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Friday, May 29, 2015

What the Death Rattles in Quad Cities Nuclear Plant Looks Like???

We are watching The death spiral of Quad Cities...its death throes. So the death sentence is coming in Sept. Imagine how fearful and insecure the employees are? Exelon has been torturing these employees for years with this threatening. 
Exelon to decide fate of Quad Cities nuclear power plant in September: CEO 
Louisville, Kentucky (Platts)--29 May 2015/526 pm EDT/2126 GMT 
Exelon CEO Christopher Crane said the nation's largest nuclear generator will decide in September whether to close its money-losing, 1,824-MW Quad Cities merchant nuclear plant in Illinois.

Time is running out for Exelon to craft an economic solution for three Illinois nuclear plants -- Byron and Clinton are the others, totaling about 5,000 MW of generation -- Crane said in comments webcast Thursday from the Sanford Bernstein Strategic Decisions Conference in New York.

The Chicago-based company had hoped the Illinois General Assembly would pass Exelon-backed legislation creating a low-carbon portfolio standard to provide the nuclear plants with an estimated $300 million/year in economic support before its 2015 regular session adjourns late next week.

That appears unlikely, although lawmakers still could consider the legislation during a two-week fall veto session in November...
It is obvious Exelon knew this plant was coming to the end of their rope...why waste money on this plant when we are going to shut it down. So this is the amount of money you got to spend on the outage...prioritized the plant with maintenance thinking the it is only going to run a few more years.

So this steam leak, the shorting cable, the fires and plant electrical transient....it all started by not having enough money to fix gland seal valve packing leak. The work around from this leak. 

Look at what was needed to create this, not enough money for the maintenance budget, not following procedures, cable error in construction...the moisture took advantage of an electric cable issue creating all these fires.

What I worry about, will the financial problems broadly degrade  the components throughout a plant...setting up the plant to be in a condition outside the license.
August 12, 2014: QUAD CITIES NUCLEAR POWER STATION, UNITS 1 AND 2NRC INTEGRATED INSPECTION REPORT 05000254/2014003; 05000265/2014003 
Green. A finding of very low safety significance (Green) and associated non-cited violation of Technical Specification (TS) Section 5.4.1 was self-revealed on April 2, 2014 for the licensee’s failure to establish a procedure in accordance with the requirements of Regulatory Guide 1.33. Specifically, the licensee established procedure QOP 5600-01, “Gland Seal System Operation,” for use during startup of the Main Steam and Turbine Generator systems. However, the procedure failed to include provisions to ensure that the steam seal regulator bypass valve, 2-3099-S2 (S2) was closed prior to lifting the steam seal bypass relief valve and exceeding the bypass line design pressure. That resulted in a failure of the piping and a significant steam leak in the ‘D’ heater bay. Immediate corrective actions taken by the licensee included revising their procedures for operation of the Gland Seal system and conducting just-in-time training on Gland Seal system operation for operators prior to the subsequent startup on Unit 2. In addition, the licensee planned to review and revise their operator training program for the Gland Seal system. The licensee documented this issue in CAP as IR 1642409. In June 2013, the licensee identified packing leakage from the steam seal feed valve, 2-3099-S1 (S1). In September 2013, the S1 packing leakage increased, and the licensee made a decision to close the valve. The S1 is required during startup of the Main Steam and Turbine Systems and normally kept open while operating, though the gland seal system can continue to function with the S1 closed, once at normal steam pressures. The licensee had a plan to fix this leak during the refueling outage. However, they did not include this work into a forced outage scope. The licensee was forced to shut down Unit 2 due to an unrelated issue on March 31, 2014, and attempted to startup on April 2, 2014, prior to repairing the S1 valve. The packing leak on S1 caused the operators to have trouble while starting up the Gland Seal system, as described below.
It just looks like we are setting up the conditions of a big scalding event(feed system or steam) at plant with multiple deaths and injuries...maybe electrocution. Generally a big steam or boiling hot water leak...it is a nasty accident with short all over the plant. Would a high pressure and temperature feedwater pipe break be easier on a new plant or a old plant with degraded cables... 

An insider would know in the of the SJAE and the heater bay room...it is very elevated temperature area. It is just the run-to-failure option. At some point before relicense, they should proactively replace all the cables in the high temperature area. It doesn't take many brains to figure electrical cabling in a high temperature room need to be replace often. 

This is what the death throes look like with prolong grossly insufficient maintenance budget...it is the death rattle.

 The titles in the list of recent LERs looks like a junk yard!!!

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Pilgrim (Juno) Indicts the "For-Show" Fuhushima Nationwide Nuclear Industry Flex System!!!

Like to know a little bit more with what was going on with K-111 air compressor.

 Basically there was no simulator training over loss of instrument air, simulator fidelity issues across the board...Blizzard Juno indicts plant training and the NRC oversight of same.

 It horrendously indicts the NRC for allowing the competence of the Pilgrim staff to decay away to such low levels. It was chaotic and extremely unprofessional on the set up for Juno and with the staff during the plant accidents. 

 It took 8 hours of no service air to hook up the flex air compressor. Like to understand the reason for that. 

 Then the flex diesel compressors was undersized for the job. What poor engineering... 

 Within about 6 months two nuclear sites got into terrible troubles in NE with a loss of instrument air system.(Pilgrim and Millstone)
1/27/15 04:02 Line 342 faulted. Automatic reactor scram on load reject at 52% reactor thermal power. 

1/27/15 04:08 Operations entered Procedure 5.3.8, “Loss of Instrument Air.” Electric-driven air compressor K-111 was out-of-service for motor replacement, electric-driven air compressor K-110 lost its power source due to the loss the 345 kV power lines, and diesel-driven air compressor K-117 attempted to start but failed to run. 
1/27/15 13:59 FLEX diesel air compressor installed to supply station compressed air. Instrument air pressure increased, however, the capacity of the compressor was not sufficient to increase system pressure to normal. 
1/28/15 10:47 Temporary offsite air compressor is placed into service. Loss of Instrument Air Procedure is exited
So the K-117 diesel generator air compressor failed consecutively in two separate LOOP accidents on two different problems.

Once by bad fuel and the other with batteries.

I thought they test these guys with a approach of threat???

Junk plant...

2013: Final Precursor AnalysisAccident Sequence Precursor Program – Office of Nuclear Regulatory ResearchPilgrim Nuclear PowerStationTwo Losses of Offsite Power Due to Winter StormNemoEvent Date: 02/08/2013 LER: 293/13-003IR: 50-293/13-02 CCDP = 8×10-5Plant Type: Boiling-Water Reactor (BWR); General Electric-3 with a Mark I ContainmentPlant Operating Mode (Reactor Power Level): Mode 1 (81% Reactor PowerAdditional Event Information.

On February 11th, operators responded to a failure of the diesel-driven instrument air system compressor (K-117) during a time when no other air compressors were available to supply the instrument air system due to the loss of offsite power. The inspectors responded to the control room to assess the impact of the loss of the K-117 air compressor and operator response to the event. Entergy implemented the loss of instrument air procedure, evaluated the impact of the loss of instrument air on plant components (e.g., spent fuel pool cooling was lost), and made preparations to install a portable compressor located onsite as part of the response to the Fukushima orders. The K-117 air compressor fuel was found contaminated; the fuel tank was emptied, cleaned, and refilled. The K-117 air compressor was restored on February 12th. The unavailability of the air compressor is expected to have a negligible impact on the CCDP of the 2nd LOOP event.

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Thursday, May 28, 2015

Juno's Peak Torus Temperature?

The integrity of the containment wholly depends on average torus water temperature....Public Protection.

Controlling torus temperature depends on the manual startup of the torus cooling systems.

Why no graph on average torus temperature versus time in the special inspection...no mention of torus temperature.

How the staff controls torus temperature is a direct indicator of the their competence and indicates if the staff is in a panicky mode...overwhelmed!!!

Controlling reactor water level by the Core Spray system in this indicates the staffs actions was chaotic...it is not the normal way they control water level?

They dumped and abandoned RCIC for hours???

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NRC Pulling their Punches: "Pilgrim nuclear plant may need more oversight, regulators says"?

This is a very good article!

Pilgrim nuclear plant may need more oversight, regulators says 

“Before that storm, Pilgrim did poorly in a supplemental inspection conducted by NRC investigators in December. Inspectors returned earlier this month and repeated that inspection. Results will be released in June.”

I wonder how many inspectors did this inspection(May)...was it similar to the first? They characterized the 23kV line in the 2013 Nemo Plant trip in this inspection.

Special Inspection: 4) The 23kV line remained operable and vital buses were powered by the EDGs, but there were intermittent alarms associated with the 23kV line.

They are basically obscuring the magnitude of the problems at Pilgrim last winter...the NRC should have had enough manpower to include the switch yard inspection in the special inspection.

I think the violation level keys on the operability of the 23kv line...that is why it is extremely important to document all the conditions and alarms on the 23kV line. The NRC needs to make an independent determination on the operability of this line because the violation level keys off of this. They NRC is well aware of this. I bet you in this months inspection they will spend some time explaining the operability of this line.

The idea the special inspection treated the 23kV line “intermittent alarms” so skimpily indicates the NRC was engineering the violation level...pulling their punches to protect their own image and Pilgrim.
It is like NRC upper management told the special inspectors...we want this inspection to go no higher than a "white" level. Remember the House Republicans are watching us closely. The violation will key off the 23kV line, we need the 23 kV line to be was operable. Only cover the 23kV lightly in the special inspection so we can say the line is operable.  






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Pilgrim Special Inspection: Professional Reactor Operator Society

PILGRIM NUCLEAR POWER STATION – NRC SPECIAL INSPECTION REPORT - REPORT DATED May 27,2015

Submitted by NUCBIZ on May 28, 2015 - 08:57

By Bob Meyer

Last year the Quad Cities fire and steam leak event took to top prize for plant issues that complicated events and challanged operations. This year in 2015 so far, Entergy's Pilgrim Plant is in the lead based on performance and equipment issues associated with the plants response to a winter storm.

Here are a few things Entergy failed on: Batteries with inadequate margins; not appropriately evaluate unexpected and unsatisfactory performce of a SRV; did not ensure that personnel, equipment, procedures, and other resources were available and adequate to support nuclear safety; licensed personnel did not implement procedures to ensure adequate valve line-ups; personnel did not implement a CAP with a low threshold; Entergy did not maintain complete and accurate documentation for compensatory measures; and failed to make an event notification within the appropriate time.

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Wednesday, May 27, 2015

Blizzard Juno Pilgrim Plant Trip Fiasco NRC Special Inspection

(Work in progress) 
They could have basically gave them the same level of violation in the 2013 blizzard plant trip LOOP.

 The magnitude of chaotic condition isn't cover in the violation amount or level...
May 27, 2015: PILGRIM NRC SPECIAL INSPECTION REPORT 05000293/2015007; AND PRELIMINARY WHITE FINDING
In addition, this report documents one Severity Level IV non-cited violation (NCV) and six findings of very low safety significance (Green). Five of the Green findings were determined to involve violations of NRC requirements.
Green. A self-revealing Green finding was identified for Entergy’s failure to verify that the diesel-driven air compressor (K-117) was available for service prior to the January 27, 2015 winter storm. Specifically, although K-117 was tested prior to the winter storm, the test methodology did not reveal that the capacity of the starting battery was inadequate. The failure to verify that the diesel-driven air compressor (K-117) was available for service prior to the January 27, 2015 winter storm is a performance deficiency that was within Entergy’s ability to foresee and correct. This resulted in a loss of instrument air during the plant trip which complicated the event response. Entergy entered the issue into the corrective action program (CAP) as condition report (CR)-PNP-2015-00559 and initiated actions to supply instrument air with a temporary air compressor. Entergy also revised the operability test for K-117 air compressor to remove the alternating current (AC) power source prior to starting the air compressor.
This self-revealing issue was more than minor because it is associated with the procedure quality and design control attributes of the Initiating Events cornerstone and adversely impacted the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, failure of K-117 resulted in loss of instrument air, which adversely impacted the plant response during the January 27, 2015 winter storm. Additionally, this issue is also associated with the procedure quality and design control attributes of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating event to prevent undesirable consequences... 
Green. The team identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion V, “Instructions, Procedures, and Drawings,” when Entergy staff performed an inadequate past operability determination that assessed performance of the ‘C’ safety/relief valve (SRV), which did not open as expected when called upon to function. Specifically, following the January 27, 2015 reactor scram, operators placed an open demand for the ‘C’ SRV twice during post-scram recovery operations, but the valve did not respond as expected and did not perform its pressure reduction function on both occasions. Entergy’s subsequent past operability assessment for the valve’s operation incorrectly concluded that the valve was fully capable of performing its required functions during its installed service. In response to the team’s past operability concerns, Entergy subsequently re-evaluated the past operability of ‘C’ SRV and concluded that it was inoperable and placed the issue into the corrective action program (CAP) as CR-PNP-2015- 02051...
Apparent Violation. A self-revealing preliminary White finding and AV of 10 CFR 50, Appendix B, Criterion XVI, “Corrective Action,” and Technical Specification (TS) 3.5.E, “Automatic Depressurization System,” was identified for the failure to identify, evaluate, and correct a significant condition adverse to quality associated with the ‘A’ SRV. Specifically, Entergy failed to identify, evaluate, and correct the ‘A’ SRV’s failure to open upon manual actuation during a plant cooldown on February 9, 2013. In addition, the failure to take actions to preclude repetition resulted in the ‘C’ SRV failing to open due to a similar cause following the January 27, 2015, LOOP event. Entergy entered this issue in to the CAP as CR-PNP-2015-01983, CR-PNP-2015-00561, and CR-PNP-2015-01520. Immediate corrective actions included replacing the ‘A’ and ‘C’ SRVs and completing a detailed operability analysis of the installed SRVs which concluded that a reasonable assurance of operability existed. Entergy’s failure to identify, evaluate, and correct the condition of the ‘A’ SRV’s failure to open upon manual actuation during a plant cooldown on February 9, 2013, was a performance deficiency. In addition, the failure to take actions to preclude repetition resulted in the ‘C’ SRV failing to open due to a similar cause following the January 27, 2015 LOOP event... 
Green. A self-revealing Green NCV of TS 5.4.1, “Procedures,” was identified because Entergy failed to include appropriate operator actions to both recognize the effects of and recover systems and components important to safety within Procedure 5.3.8, “Loss of Instrument Air,” abnormal operating procedure. Entergy entered this issue into the CAP as PNP-CR-2015 0888 and issued a revision to Procedure 5.3.8 to provide additional guidance to operators during a loss of instrument air. The inspectors determined that the level of detail in Procedure 5.3.8, “Loss of Instrument Air,” Revision 39, was inadequate to provide appropriate operator guidance to identify and mitigate key events of January 27, 2015. This self-revealing performance deficiency was reasonably... 
Green. A self-revealing Green NCV of TS 5.4.1, “Procedures,” was identified because the operating crew failed to implement a procedure step to open the reactor core isolation cooling (RCIC) system cooling water supply valve during a manual startup of the system. As a result, the RCIC system was operated for over 2 ½ hours with no cooling water being supplied to the lubricating oil cooler or to the barometric condenser. Entergy entered the issue into the CAP as CR-PNP-2015-0566, CR-PNP-2015-0570, and CR-PNP-2015-0952 and conducted a human performance review of the Control Room operators involved with the issue. The inspectors determined that the failure to implement Procedure 5.3.35.1, Attachment 29, “RCIC Injection – Manual Alignment Checklist,” and the Vacuum Tank Pressure Hi Alarm, C904L-F3, alarm response procedure was a performance deficiency and was reasonably within the ability of Entergy personnel to foresee and prevent.... Green. The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI, “Corrective Action,” because PNPS staff failed to identify and correct conditions adverse to quality associated with the partial voiding of the ‘A’ core spray (CS) discharge header on January 27, 2015, following the loss of the keepfill system due to a LOOP. PNPS entered the issue into the CAP as CR-PNP-2015-01406 and planned procedural changes that would provide guidance to operate the affected pumps in order to prevent pump discharge piping from voiding if keepfill pressure is lost...  
Green. The inspectors identified a Green NCV of 10 CFR 50.54(q)(2) for failing to follow and maintain an emergency plan that meets the requirements of planning standards 10 CFR 50.47(b) and Appendix E. Specifically, on January 27, 2015, following a loss of instrument air, the indications in the Control Room for Sea Water Bay level were lost, and Entergy did not implement compensatory measures, as directed by an Emergency Plan Implementing Procedure, to determine whether a Sea Water Bay level emergency action level (EAL) threshold had been exceeded. Entergy entered this issue into the CAP as CR-PNP-2015- 00948 and initiated corrective actions to identify alternative means for assessing this EAL in the event of a loss of Sea Water Bay level instruments...
Severity Level IV. An NRC-identified SL IV NCV of 10 CFR Part 50.72(b)(3)(xiii) was identified when Entergy failed to make a required event notification within eight hours for a major loss of assessment capability. Specifically, an unplanned loss occurred of all EAL instrumentation associated with Sea Water Bay level that resulted in an inability to evaluate all EALs for an abnormal water level condition. Entergy entered the issue into the CAP as CR-PNP-2015-00949. Compliance was restored on February 5, 2015, when Entergy reported the major loss of assessment capability under Event Notification (EN) 50790...
Date/Time Event
1/24 PNPS commenced storm preparations.
1/26 High winds and snow impact the site.
1/27 01:33 Control Room receives numerous grid disturbance alarms on 345 kilovolt (kV) Line 355, operators reported flashing in the switchyard. Control Room operators commenced power reduction per Procedure 2.1.42, “Operation during Severe Weather,” and placed the safety-related Buses A5 and A6 on the emergency diesel generators (EDGs) ‘A’ and ‘B’, respectively.
01:33-02:32 Line 355 power interrupted three times.
02:35 Line 355 is lost.
04:02 Reactor trip from 52 percent power due to generator load reject upon loss of 345 kV Line 342. Per Emergency Operating Procedure (EOP)-1, “Reactor Pressure Vessel Control,” operators closed the main steam isolation valves and placed the RCIC system in level control and the high pressure coolant injection (HPCI) system in pressure control mode.
04:12 Operators commenced a plant cooldown. Diesel-driven air compressor K-117 attempted to start and failed to run on low instrument air header pressure (sustained loss of instrument air).
09:48 Operators secured the HPCI system at approximately 120 psig reactor vessel pressure, commencing reactor pressure control using SRVs and the RCIC system. Operators commence periodic operation of the ‘B’ CS pump for level control.
09:53 HPCI system declared inoperable following receipt of Gland Seal Condenser Blower Overload Alarm. Condensate discovered backing-up through the blower due to the shutdown condensate flow path being isolated to the Radioactive Waste Building (caused by loss of instrument air).
10:56 Following challenges in controlling reactor pressure (pressure increased from approximately 120 psig to 350 psig) and level, operators manually start the RCIC system in the pressure control mode and begin to open SRVs for longer periods of time to reestablish cooldown.
16:26 ‘B’ residual heat removal (RHR) system placed in shutdown cooling.
16:46 EOP-1 exited.
16:57 Reactor temperature <212 font="">
1/28 10:47 Instrument air system fully restored using a temporary diesel-driven air compressor.
1/30 18:45 Offsite power restored via Lines 355 and 342 following de-icing and inspection of the switchyard with the assistance of the grid operator, NSTAR.
1/31 01:30 Safety-related Buses A5 and A6 were restored to their normal offsite power sources.
Wink, wink, wink: they called the 2013 Nemo plant trip and LOOP a full LOOP when it occurred. In the 2015 Juno special inspection the NRC are retroactively calling the 2013 LOOP a partial LOOP based on absolutely no evidence. The difference between between a full LOOP and a partial LOOP is can the 23kv line power up the shutdown transformer. This whole thing about the partial LOOP, they are improperly crafting the Pilgrim 2015 Juno violation level to the public. 
  • (Special Inspection)Pilgrim had a similar event during a severe winter storm in February 2013, which resulted in a partial loss of offsite power. Therefore, this event tripped the deterministic criterion for repetitive failures in the switchyard, which impacted safety-related systems.
This is big, do you understand how few people in the USA could do this. So the 2013 Nemo LOOP LER according to the Licensee, this was a "full blown LOOP" because they loss the 23kv electric line supplying the shutdown transformer. I give you clue, they are gaming the violation level. If the station gets into a blackout, they are taking credit that the 23KV line would power up the shutdown transformer and then power up the plant without the diesel generators. In both cases, in the 2015 blizzard Juno and the 2013 Blizzard Nemo, the secondary line was unavailable to power up the plant. It was in improper, basically a fraud and corruption for the NRC to assume the 23 KV line was available to the plant for the risk calculation and thus sets the inaccurate resultant violation level. The violation level is too low. We just don't know how much higher the violation would be.
 That Pilgrim project manager, the boss of the inspectors on site better not give me a call. I fill is ears with problems on this inspection report. This is going to allegations and the OIG...wrong doing by the NRC employees. They are all too smart to do something stupid like this.    

 Why did the NRC improperly characterize in the 2015 Juno LOOP special inspection that the 2013 Nemo LOOP was a partial LOOP??? It is clearly not accurate. Is the rest of this special inspection that sloppy and intentionally inaccurate? Here is a direct quote from the licencee in their own LER, they define it a LOOP not a partial LOOP:      
April 8, 2013: Licensee Event Report 2013-003-00, Loss of Off-Site Power Events Due to Winter Storm Nemo 

 "On Friday, February 8, 2013, at 2018 hours, the shutdown transformer (SDT) was declared inoperable due to repeated off-site 23KV Trouble/Trip Bypass alarms and reports from NSTAR regarding the power loss and restoration events on the Line via the Manomet Substation.  
On February 8th, two line faults occurred on both 345KV transmission lines connected to the PNPS ring bus. At 2102 hours a major fault occurred on off-site Line 342 which remained de-energized for the remainder of the storm. At 2117 hours a fault on Line 355 occurred resulting in a full load reject of the PNPS generator, a subsequent reactor scram, and loss of the SUT. Emergency diesel generators (EDGs) automatically started and provided power to safety buses A5 and A6." 

 4) The 23kV line remained operable and vital buses were powered by the EDGs, but there were intermittent alarms associated with the 23kV line.(The senior manager in the control room would call the 23kV line inop and dangerous for use in blizzard Juno) Unavailable in blackout.
Key Modeling Assumptions. The following modeling assumptions were determined to
be significant to the modeling of this event analysis:

·         This analysis models the January 27, 2015 reactor trip at PNPS as a switchyard related
             LOOP initiating event.

       o The probability of switchyard-related LOOP (IE-LOOPSC) was set to 1.0; all
          other initiating event probabilities were set to zero.

·         SDT Availability. The 23kV power source via the SDT was available throughout the event. Given a postulated failure of a diesel generator, the SDT will automatically align to power safety buses A5 and/or A6.

        o To allow credit for the SDT availability, the house events HE-LOOP (House
           Event - Loss of Offsite Power IE Has Occurred) and HE-LOOPSC (House Event             Switchyard- Related Loss of Offsite Power IE Has Occurred) must be removed from             the ACP-23KV (Shutdown Transformer Offsite Power Supply) fault tree.

·         Offsite Power Recovery. The key offsite power recovery times for PNPS that are modeled within the plant SPAR model are:

        0 30 Minutes - LOOP and subsequent Station Blackout (SBO) combined with
                 failures/unavailabilities to RCIC, HPCI, and reactor depressurization.

        o 1 Hour - LOOP and subsequent SBO with two or more stuck open SRVs (given
               successful RCIC or HPCI operation).

         o 3 Hours - LOOP and subsequent SBO with operators failing to recover offsite
                power prior to the depletion of the switchyard batteries.

 ‘B’ SRV was cycled 52 times and ‘D’ SRV was cycled 53 times.
Additionally, offsite power remained available to Buses A5 and A6 via the shutdown transformer (SDT) powered from the station’s 23Kv line.

 The team determined that the SRVs were manually cycled 105 times (52 for the ‘B’ SRV and 53 for the ‘D’ SRV) while attempting to stabilize pressure and control RPV level with the CS pump.





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