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