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!!!

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.

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???

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.  

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.

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.

LER 2015-002-00: Main Steam Safety Relief Valves Determined to be Inoperable Following Evaluation

I called up the Pilgrim inspectors over this LER today. The NRC seems to be very disappointed with this LER and have a lot of questions over it. It is still under investigation, so I got very little comment about.

The inspector said the special inspection is coming out tomorrow. He said it is going to be big and make big news, whatever this means. My comment to him was, you should have had the big inspection right after the 2013 blizzard, plant trip and LOOP and when the first problems in the SRVs showed up in 2011. I told him I am disappointing with the NRC over this...he said the higher up make the decision not him. He was very polite and a good guy. I tried not to give him any grief, told him I don't hold you personally responsible. Said, I hold you inspector guys as heroes and you are in the front lines against or preventing chaotic condition at your plants.

Bottom line in this LER, the three stage safety relief  valves were found to be unsafe for plant operation, they yanked the three stage out and replaced it with the troublesome 2 stage relief valve.

Is the plant really licensed now for the 2 stage reliefs...did they need a licensed amendment request?    

I asked him to discuss my conversation to him with his boss, the inspector said he would. I requested a discussion with his boss, the project manager. We will see. They will probably let me digest the special inspection report...

• Also the Pilgrim inspector yesterday said NRC inspectors were on site at the safety valve manufacturer Target Rock. It was similar to a special inspection as Pilgrim.  

I said to the inspector, basically no matter what happens with the violation on the Juno LOOP and SRVs special inspection...all it is going to be is a paperwork violation. You went out of you way to let them start-up post Juno and all though these SRV inops, these guys never pay a big price for poor performance. It is all though the Entergy Nuke Plants. 

You don't have the power to make these big guys tremble at the sound of your soft whisper!!! 

Here is my commentary on the LER:   

May 12, 2015 

Licensee Event Report 2015-002-00, Main Steam Safety Relief Valves Determined to be Inoperable Following Evaluation EVENT DATE    03 12 2015   

LER NUMBER2015 002 00 

REPORT DATE05 12 2015 

On March 12, 2015, after further evaluation of system

You get it, basically this report is required to come out in 60 days. The licencee get a period to decide if it is going to be a LER and evaluating. These guys are really smart about the timing of the LERs.  They are looking ahead in the future...

Basically because they started up without a complete evaluation, they didn't understand the problem...they started up with two inop SRV valves. They illegally started up. Really, these new valves before they ever were put into the plant were inop. 

It looks like Pilgrim knew prior to the Juno start up these valves were unsafe. But they didn't have a replacement. They would have waited for weeks and maybe a month before the new two stage SRVs could have been tested and brought to the plant. The whole documentation trail post Juno was engineered to allow Pilgrim to knowingly and illegally operate with defective and unsafe 3 stage SRV valves till replacement at the outage with 2 stage.

I talked a length about when I thought Pilgrim should have call the SRVs inop. Then they would have entered into Tech Specs. If one SRV was called inop, it would have been a required shutdown within 14 day. If two or more were inop, it would have been something like an immediate or within 6 hours shutdown. I asked the inspector why didn't the NRC enforce tech specs and force the shutdown, he said that was the decision of the gods much higher than me. I get the decision of the gods are not challengable by him.       

I think the NRC are gods. They got a really a lot of policies and rules...it looks like the NRC makes decision solely based on rules, engineering and science. I think this is not the case. I think they secretly go behind closes doors, make the decisions on self interest...then wrap the policies and rules around the godly objective they choose. It just looks like the NRC is making decision on rules, engineering and science!!!  

performance of SRV-3A and SRV-3C, along with results of valve internal conditions identified during physical inspection, the valves were determined to have been inoperable for an indeterminate period during the last operating cycle. Specifically, SRV-3C was determined to

Isn't that convenient they declare it in the outage with no price to pay. You get the system, they are incompetent at diagnosing the problems of the set of valve or keeping it properly maintained...but this stated incompetence gets them to the outage where they never pay a price. This is corruption and lying on a federal document..the so called incompetence just gives them a free ticket into the next outage. These guys are extremely smart and cagey.     

be inoperable based on its on-demand performance at low reactor pressures, as well as the visual conditions that were identified during the inspection process. SRV-3A was

The NRC said the valves would have still have provided their licencing function. So what study are you using to support this? I asked him, what about in a prolonged station blackout. These valves would have needed to be cycled in this event between 200 to 400 times. It sounds like all these valves would have failed in a event like this. Doesn't this matter to the NRC?  

considered inoperable based on it having similar internal indications as SRV-C when it was disassembled and inspected. SRV-3A was installed in May 2011 and SRV-3C was installed in October 2013. 

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.

At the time the valves were declared inoperable the reactor was at 100% power. The valves had been replaced

I had issues with getting the Pilgrim inspector to tell me what the above sentence means. When did they declare the valves inoperable at 100% power and did they enter into tech specs. It would have been a quick shutdown because it was more than one valve. The NRC inspector deftly shifted the conversation to LER 2015-001-00 and he would anwser my question.

in February 2015 during the forced outage relating to winter storm Juno. This event posed no threat to public health and safety. 

BACKGROUND 

On January 27, 2015, during winter storm Juno, Pilgrim Nuclear Power Station (PNPS) experienced a generator load reject and automatic reactor scram. During the pressure vessel cool-down period, a Main Steam Safety Relief Valve (SRV) appeared to have not fully opened when manually operated to control reactor pressure. Reactor vessel pressure did not lower as expected, reactor water level did not increase (swell) as expected, and there was minimal change in tailpipe temperature, which was not consistent with changes observed when other SRVs were opened. Operations maintained control of reactor pressure by alternate openings of other SRVs during plant cool-down. 

Specifically, at 1015 hours, the first opening of SRV-3C was initiated when reactor pressure was 220 psig. When

God intervened here.  What condition would that valve be in if we didn't have the Juno plant trip and then the next voluntary plant blizzard shutdown. What condition would this be in just prior to the outage shutdown on April 19? 

There is absolutely no evidence and testing on how this damaged valve in other situation(at operating pressure).   

the operator placed the hand switch in the Open position there was no significant change in plant operating parameters. The operator initiated the second opening of SRV-3C at 1032 hours when reactor pressure was 262 psig, and again, there was no significant change in plant operating parameters, but a small torus water temperature increase was observed near the SRV-3C tailpipe outlet in the containment suppression pool. After the second attempt, Operations declared the valve SRV-3C, Serial Number (SN) 9, inoperable.

This is important, Entergy later says the valve could have preformed it function at full pressure. The operators don't have that knowledge in their heads as the engineers who studied it in their heads for hours. There was a anomaly in the operation of the valve that the operators seen, the operator is too busy and information of the condition inside the valve was unavailable to them...so the operator determined the valve was too dangerous to operate based on what they know. It only matters what the operator thinks in his head at the time, not the full picture of the components operability days and months after the engineers study the conditions of the valve.  

The SRVs are dual function Target Rock Corporation Model 0867F valves that are designed to operate in both safety

Basically the engineers at Pilgrim are stove piping the operability of the SRVs in the automatic modes. The third mode of of these valves is the licensed operators manual mode. Thet open and close these valve for pressure control of the reactor. It unprofessional to allow a automatic function at a nuclear...humans are suppose to be operating these plants not automatic component. Maybe in the opening moments of a plant scram and isolation...it is ok to allowed the SRVs to cycle on their own. Then the people take control of the SRVs, watching very closely what the valves do to the rest of the plant. 

Probably the most critical use of  the SRVs valves is in a prolonged station blackout. These valves are use as the means to guild the plant through cold down. The cool-down might have stopped and restarted depending on component availability. The weak link in the emergency evolution with  high probability of a core damage is a stuck open relief and a failure for a valve to open is very problematic. The quality of these valve need to be that  the manual operations should be bullet proof with opening and shutting in a accident. 

mode and relief mode. The safety mode is automatically actuated at 1155 psig and involves successive opening of a first stage pilot valve, second stage pilot valve, and the main stage. The relief mode can be automatically actuated by the Alternate Depressurization System (ADS) which opens all four valves. Relief mode can also be initiated manually by the operator using any of the four SRVs individually or together. The relief mode of operation requires Direct Current power to energize a solenoid valve mounted locally on each valve. When the solenoid is energized, locally stored nitrogen is admitted to an air operator mounted on the valve. Nitrogen provides the motive force to open the second stage pilot valve and cause the SRV main stage to open. 

PNPS has four, three-stage SRVs installed on the Main Steam lines. Each three-stage SRV contains a pilot (also called the first stage), a second stage, a main stage, and an air-operator. The pilot has main steam constantly applied to a bellows spring via a pressure sensing tube extending through the valve body. As the set pressure is reached, the bellows expands, opening the pilot disc and allowing steam to pass to the second stage. Steam pressure behind the second stage piston pushes the second stage disc open allowing steam to vent from behind the main stage piston to the containment suppression pool. Main steam pressure is present in front of the main stage piston, therefore, venting behind the piston creates a large differential pressure across the main piston causing it to stroke; pulling open the main stage disc to discharge steam and relieve system pressure. The air-operator is used to manually operate (open) the SRV below its setpoint pressure. When the air operator is pressurized, the operator plunger pushes directly against the second stage piston, opening the disc. 

Subsequent to the plant reaching cold shutdown, SRV-3C, and another valve, SRV-3A, SN 4, were removed from the Main Steam system for testiness, disassemble, inspection,

This description is almost complete. In the recent Oyster Creek yellow finding with the Electromagnetic Relief Valves( their SRVs valves) they basically yank the valves out of the plant and then let them sit on a bench for 1.5 years. It is at this point they do the as found testing and inspecting, then certify testing for insertion into the plant. So it is important the dates of all of the testing, which they don't have here. Again, you see the possibilities of "engineering" the discovery of defects in a safety valve with a agenda in mind. This is fraud and corruption. In Oyster Creek with valves taken out of the plant, it took them 1.5 years to discovered serious problems and defects in the valve. How hard is it to know, you yank a safety valve out of reactor...it is you duty to immediately do as found testing and inspections. You want to immediately discovered design defects in the valve. 

and refurbishment. The valves met the Technical Specification required lift set-point acceptance criterion during testing. Based on the testing having demonstrated acceptable results within the Technical Specification acceptance criterion for valve opening and initial inspection results, an operability evaluation for each valve determined that the valves were operable and

This is like preparing you car for  long trip. You go out and start your car, it starts up. Then you begin your trip with no oil in the engine, depending on the oil pressure warning light to work.  How about dates on the pressure testing and then the disassembly inspection.

able to fulfill their intended safety function. However, after disassembly, during the inspection process, internal damage in the main stage piston section was observed that required further investigation. 

EVENT DESCRIPTION

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 attempt at 220 psig; second attempt at 262 psig;), as well as the visual conditions that were identified during the inspection process. SRV-3A was considered inoperable based on it having similar internal indications as SRV-3C when it was disassembled and inspected. SRV-3A was installed in May 2011 and SRV-3C was installed in October 2013. 

Additionally, during an extent of condition review of

These expensive employees are note for their attention to-detail...it is dangerous to operate a nuclear plant with employees who can't detect subtle defects. it just looks like like these employee are actively turning their heads away with problems with SRVS. It is not plausible these employee are so stupid.

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.

The condition of the SRVs did not cause adverse results during the plant cool-downs, since the other installed

Yea, but Entergy didn't know the internals of these valves were massively damaged...could detect it.  

SRVs operated as expected to control reactor pressure. In both cases, the reactor was placed safely in a cold shutdown condition. 

Also, all the SRV's responded properly when called upon to function at higher reactor pressures (approximately

So massive internal damage and future operatability problems doesn't matter.  

1000 psig or pressures close to that). In addition, following high pressure operation, the SRV's functioned over their entire range of operations. 

CAUSE OF THE EVENT 

The degradation mechanism is believed to be fretting wear (repeated cyclical rubbing) between the main stage piston and liner, increasing the friction in the stroke of the valve. Fretting is a time-dependent wear mechanism which

Got any legitimate engineering studies and testing predicting the wear mechanism or is it all guess work. Can reliable predict the wear mechanism through the cycle.     

develops while the valves are in-service in the plant.The fretting occurs because the piston-to-disk threaded connection loosens and the main steam line flow vibration drives the piston rings against the guide liner.

It is believed valve certification testing on a limited

I don't believe the limited steam flow test stand is the problem. Can you even imagine the noise of these valves popping open and shut on the test stand creating such loading and damage? Can you even imagine a professional nuclear safety service provider hearing this severe flow perturbation noise...how can you think he would not request to inspect the valve right after the test. These guys are probably testing as assortment SRV valves from different plants. How could such severe test stand flow noise not stand out from other plants' normal valves testing.    

steam-flow test stand creates the conditions internal to the main body which allows the valve to develop a fretting wear condition while in-service. The gagged-

How come there is not not other plants with test stand damage to their SRVs  and then vibration damage to the spring and components similar to Pilgrim?  Now how loud in that "high impact loading"?

Honestly, "Main Spring relaxation was caused by "extreme dynamics encountered during limited flow testing""...the test stand technician could hear the "extreme dynamics" and wonder if something was broken in the valve. They didn't record the loud noise in a document. 

Can Entergy artificially create...reenact... the same test stand damage and then create the same kind of vibrations on their steam line seen by the SRVs in a laboratory..can Entergy artificially create the same kind of damage on the SRVs seen in normal operation?

valve test stand operations on a limited steam capacity test stand subjects the valve main stage to high opening force and high impact load. The high impact load increases potential loosening of the threaded joint between the main stage piston and the main disc stem (as-manufactured condition). When the valve is installed in the plant, normal system operation (steam flow) can cause

I think Pilgrim has a big problem with excessive steam line vibration and it could lead to catastrophic break of a main steam line. Wonder if the special inspection will say anything about steam line vibration.   

the loosened piston to move (continuous, long-term, low amplitude vibration) relative to its liner. This movement may cause the piston rings to rub (fret) against the liner. Continued fretting may cause the rings to wear a groove into the liner; increasing potential binding friction against the piston when the valve strokes open. If sufficient binding friction has developed then the SRV opening stroke may not exhibit the typical rapid popping action when the valve opens at low reactor pressure where less opening force is available.

Target Rock Corporation issued an interim 10 Code of Federal Regulations (CFR) Part 21 report to the U.S. Nuclear Regulatory Commission concerning a potential test induced defect in the SRVs on March 16, 2015 (NRC Event # 50900) to provide notification that a multi-faceted investigation is ongoing to identify the cause of internal damage that could go undetected during production of new valves and refurbishment of valves that have been in-service. Although a root cause has not been determined at this time, sufficient facts have been established to warrant investigation of changes to current testing practices. This 10 CFR Part 21 notification was issued as a result of the PNPS SRV failures. 

ADDITIONAL CONDITIONS

The SRVs also exhibit a spring "shortening" (or relaxation) phenomenon. GE SIL-196, Supplement 17 determined that Main Spring relaxation was caused by "extreme dynamics encountered during limited flow testing.... Valve dynamics under full flow conditions (i.e., discharge not gagged) are much less severe than those under limited flow conditions.

The shortened spring is directly related to the overload

What did you say, the test stand noise made me hard of hearing? 

condition created on the test stand that is potentially contributing to the loosened main stage piston connections. It is not unusual for a valve on the test stand to not fully close after a test stroke. Based on

A problem though the years in the industry, once you use a SRV, it has the high probability of leaking in the near future. Are we really talking about the SRVs are not sturdy and durable enough for the duty of plant operation.   

evaluations to date, a shortened main stage spring does

Can I see than engineering and scientific report?  

not impact the valve over-pressure set-point, automatic actuation, or manual operation. Thus, this phenomenon does not directly impact the functionality of the valves. 

CORRECTIVE ACTIONS 

Prior to restart from the forced outage related to winter

This is the point when Entergy realized these valves were not safe.

storm Juno, SRV-3A and 3C were replaced with certified spare valves.

All SRV body/bases were removed from the system during the current refueling outage. In place of the four SRV's

You got to give Entergy the credit to expertly engineer the replacement of the SRV valve at their convenience.  Man, they know how to read the NRC to get away with this. 

removed from the plant during the current refueling outage, PNPS has installed 2-stage SRV's. These will be used for Cycle 21.

Corrective actions will be captured in the PNPS corrective action program in Condition Report CR-PNP- 2015-0561 and appropriate engineering documents.  

SAFETY CONSEQUENCES 

The function of the safety relief valves is to limit peak vessel pressure during overpressure transients to satisfy the American Society of Mechanical Engineers Boiler and Pressure Vessel Code requirements for overpressure protection.

The Automatic Depressurization System (ADS) provides a means to rapidly depressurize the primary system to a pressure where low-pressure systems can provide makeup for core cooling. In the event of a small or medium break Loss of Coolant Accident, the ADS function would be required if the High Pressure Coolant Injection (HPCI) system is unable to maintain reactor water level. The postulated transients that require SRV actuation are described in Chapter 14 and Appendices R and Q of the Final Safety Analysis Report (FSAR). In accordance with plant Technical Specification 3.5.E.1 Limiting Condition for Operation, the ADS is required to be operable whenever there is irradiated fuel in the reactor vessel and the reactor pressure is greater than 104 psig and prior to a startup from a cold condition. In accordance with FSAR Section 4.4 Nuclear System Pressure Relief System sub-section 4.4.5 Description, "For depressurization operation, each relief valve is provided with a power actuated device capable of opening the valve at any steam pressure above 100 psig, and capable of holding the valve open until the steam pressure decreases to about 50 psig." Additionally, FSAR Table 6.3-1 Core Standby Cooling Systems Equipment Design Data Summary lists ADS valves as having a pressure range of 1,120 to 50 psig which spans from above normal operating pressure at rated core thermal power to below the pressure interlock for entry into Residual Heat Removal Shutdown Cooling. 

During both cool-downs when SRV-A (February 2013) and SRV-C (January 2015) did not perform as expected, other SRVs were available to perform the necessary function of pressure control. During the event, both HPCI and the

You notice how Entergy failed to mention HPCI was inoped near the end of the cooled.  They aren't scrupulously honestly in this document. The pattern of them selectively releasing information that reflect well on the plant. .

Reactor Core Isolation Cooling systems were used when needed to provide the functions of supplying makeup water to the vessel, providing adequate core cooling, and heat removal. Therefore, there was no adverse impact on the public health or safety. 

REPORTABILITY 

This report is submitted in accordance with:  

* 10 CFR 50.73(a)(2)(v)(B) and 10 CFR 50.73(a)(2)(v)(D) - Event or Condition that Could Have Prevented Fulfillment of a Safety Function. 

 * 10 CFR 50.73(a)(2)(i)(B) - Operation or Condition Prohibited by Technical Specifications