Pilgrim Diesel Generator; Example of "Are minds drifting at Pilgrim"?

This is my example of the NRC is managing the decline of Pilgrim. This should have been a lot bigger violation.

Personally I think this comes from all the hard starts these DGs have undergone in recent years in "Loss of Offsite Power" accidents. They are wearing them out. I predicted next LOOP, both DGs started up needing to supply the plant, one would fail on premature wear.  

***Any little corrupt trick to get onto the other side of the surveillance-"Entergy staff determined that the X-107B EDG had been and remained operable because the volume of fluid that had been discharged would not have produced a hydraulic lock on cylinder 9L and therefore would not have prevented the engine from starting. Entergy staff exited TS 3.5.F at 2:30 AM.

General incompetence-"In discussions with the inspectors, Entergy staff stated that the condition did not render the EDG inoperable, but that they were entering voluntary LCOs for the purpose of investigation and troubleshooting only."

***Bet you for months they have been adding water to the expansion tank. Have they been getting low level alarms when operating. They log filling the expansion tank...this is first thing the inspectors should have done is get the long term trend on filling the expansion and fill tanks.   

***From identification of the issue through correction of the problem by replacement of the 9L cylinder head, Pilgrim staff maintained that the condition had not caused the X-107B EDG to be inoperable.

***"Entergy staff stated that their EDGs were capable of operating with one cylinder removed from service; however, were unable to provide the inspectors with any design documents or engineering calculations showing that the EDGs would be capable of supplying design basis loads under such conditions."

***"Entergy procedure EN-OP-104, “Operability Determination Process,” Revision 9, states that, for an immediate operability determination, “if a piece of information material to the determination is missing or unconfirmed, and cannot reasonably be expected to support a determination that the SSC [structure, system, or component] is OPERABLE, the SM (shift manager) should declare the SSC INOPERABLE.”


I still think Entergy massaged this into a non cited violation from a required shutdown...

August 11, 2015

SUBJECT: PILGRIM NUCLEAR POWER STATION - INTEGRATED 

INSPECTION REPORT 05000293/2015002

Pg 17

1R15 Operability Determinations and Functionality Assessments (71111.15 – 6 samples)

Description. On March 18, 2015, at 2:15 AM, operators entered TS 3.5.F, “Minimum Low Pressure Cooling and Diesel Generator Availability,” to perform pre-startup checks of the X-107B EDG in accordance with procedure 8.9.1, “Emergency Diesel Generator and Associated Emergency Bus Surveillance,” Revision 129. TS 3.5.F provides a 72 hour limiting condition for operation (LCO) that can be extended to 14 days provided that all low pressure core and containment cooling systems, and the SBO diesel generator are determined to be operable. When the engine was rolled over with air to verify that no fluid was present in any of the cylinders, engine coolant was instead observed to spray out of the open cylinder test cock on cylinder 9L. Entergy staff estimated that approximately six ounces of fluid was discharged. This issue was entered into the CAP as CR-2015-02109. Entergy staff determined that the X-107B EDG had been and remained operable because the volume of fluid that had been discharged would not have produced a hydraulic lock on cylinder 9L and therefore would not have prevented the engine from starting. Entergy staff exited TS 3.5.F at 2:30 AM. 

On March 18, 2015, at 9:16 AM, Entergy staff determined that an inspection of cylinder 9L should be performed, and entered TS 3.5.F. Initial troubleshooting was inconclusive as to where the leak was coming from, leading Entergy staff to exit TS 3.5.F and prepare additional troubleshooting plans. At 4:00 PM, Entergy staff entered TS 3.5.F to continue troubleshooting and perform additional inspections of the cylinder head. The scope of this activity subsequently expanded to include replacement of the associated cylinder head. In discussions with the inspectors, Entergy staff stated that the condition did not render the EDG inoperable, but that they were entering voluntary LCOs for the purpose of investigation and troubleshooting only. Entergy staff performed surveillance procedure 8.9.16.1, “Manually Start and Load Blackout Diesel via the Shutdown Transformer,” Revision 48, at 5:40 PM, to extend the TS 3.5.F allowed outage time to 14 days. Testing of the replaced head showed the source of the leakage to have been from the area of the cylinder exhaust valves. Entergy’s immediate corrective actions included replacement of the X-107B EDG 9L cylinder head and sending out the damaged cylinder head for analysis by a vendor. The completion of the analysis by the vendor is being tracked by CR-2015-2109. Entergy staff exited TS 3.5.F following successful post maintenance testing at 6:11 AM on March 21, 2015. From identification of the issue through correction of the problem by replacement of the 9L cylinder head, Pilgrim staff maintained that the condition had not caused the X-107B EDG to be inoperable. Entergy staff stated that their EDGs were capable of operating with one cylinder removed from service; however, were unable to provide the inspectors with any design documents or engineering calculations showing that the EDGs would be capable of supplying design basis loads under such conditions.

The inspectors reviewed CR-2015-02109 and the associated apparent cause evaluation (ACE). While the inspectors agreed that the as-found condition would not have prevented the X-107B EDG from starting, they did not conclude that the EDG remained operable. Although the source of the engine coolant leak was unknown at the time of discovery, it could reasonably have been due to a crack in the cylinder head. Such a leak would have the possibility of worsening during engine operation. Although hydraulic locking of the cylinder would not be a realistic concern during engine operation, increased engine coolant leakage into the cylinder would result in water intrusion into the crankcase and lubricating oil sump, which would eventually cause the engine to fail to operable after engine coolant had been identified in cylinder 9L.

Entergy procedure EN-OP-104, “Operability Determination Process,” Revision 9, states that, for an immediate operability determination, “if a piece of information material to the determination is missing or unconfirmed, and cannot reasonably be expected to support a determination that the SSC [structure, system, or component] is OPERABLE, the SM (shift manager) should declare the SSC INOPERABLE.” In this case, at the time of discovery, although the cause of the leak had not been established, it could reasonably have been due to a crack in the cylinder head. For the reasons discussed above, it could be concluded that this condition would not support a determination that the X-107B EDG remained operable. Additionally, an operability determination example presented in Attachment 9.1, “Operability Classification Guide,” of this procedure indicates that an EDG that cannot run for the duration assumed in the current licensing basis should be considered inoperable. SDBD-61, “Design Basis Document for Emergency Diesel Generator (EDG),” states, “The ‘mission time’ for the design basis Loss-of-Coolant- Accident (LOCA) is 30 days for the long term containment cooling analysis, as described in TDBD100 “Design Basis Document for Design Basis Accidents, Transients and

Special Events (DBATS).” Therefore, the inspectors further concluded that Pilgrim staff also should reasonably have concluded that the X-107B EDG should have been declared inoperable after engine coolant had been identified in cylinder 9L.

TS 3.5.F, “Minimum Low Pressure Cooling and Diesel Generator Availability,” provides a 72 hour allowed outage time for one EDG, provided the remaining EDG is demonstrated to be operable per TS SR 4.5.F.1. TS SR 4.5.F.1 requires that, within 24 hours, a determination be made that the operable EDG is not inoperable due to a common cause failure, or that the monthly TS-required surveillance test be performed for the operable EDG, and that, within 1 hour and every 8 hours thereafter, correct breaker alignment and indicated power availability for each offsite circuit be verified. If these requirements cannot be met, TS 3.5.F further requires that the reactor be placed in cold shutdown within 24 hours. Since Entergy staff did not declare the X-107B EDG inoperable as a result of the engine coolant leakage issue, but instead entered what Entergy staff considered to be voluntary LCOs for the purpose of investigation, only the portion of TS SR 4.5.F.1 for offsite breaker verification was performed. Therefore, the inspectors additionally concluded that Entergy staff’s failure to perform the required determination that the operable EDG was not inoperable due to common cause failure constituted a violation of TS 3.5.F.

The TS-required monthly surveillance test was satisfactorily completed on the X-107A EDG on April 2, 2015, approximately two weeks after the X-107B EDG 9L cylinder head coolant leakage event. While this did not eliminate the TS violation discussed above, it did demonstrate that, from a risk perspective, the X-107A EDG had been capable of performing its design safety function during that period.

Analysis. The inspectors determined that Entergy’s inadequate operability determination of the X-107B EDG after engine coolant was found in one of the cylinders, and resultant failure to determine that the X-107A EDG was not inoperable due to a common cause failure, or to perform the complete TS-specified EDG monthly surveillance test, within 24 hours in accordance with TS SR 4.5.F.1, was a performance deficiency that was within Entergy’s ability to foresee and correct, and should have been prevented. The finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, Entergy staff inadequately determined that the X-107B EDG was operable, which resulted in the operability of the X-107A EDG not being verified, either through determination that it was not inoperable due to a common cause failure or performing TS SR 4.5.F.1 in its entirety. 

In accordance with IMC 0609.04, “Initial Characterization of Findings,” and Exhibit 2 of IMC 0609, Appendix A, “The Significance Determination Process for Findings At-Power,” the inspectors determined that this finding was of very low safety significance (Green) because the performance deficiency was not a design or qualification deficiency, did not involve an actual loss of safety function, did not represent actual loss of a safety function of a single train for greater than its TS allowed outage time, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event.

This finding had a cross-cutting aspect in the area of Human Performance, Conservative Bias, because Entergy staff did not use decision making practices that emphasized prudent choices over those that are simply allowed. Specifically, Entergy staff’s operability determination for the X-107B EDG was based on the conclusion that the as found condition would not have caused the engine to be inoperable because it would not have created a hydraulic lock; they did not consider that the condition would likely worsen during EDG operation, nor did their operability determination consider EDG mission time [H.14]. 

Enforcement. 10 CFR 50, Appendix B, Criterion V, “Instructions, Procedures, and Drawings,” states, in part, that “activities affecting quality shall be prescribed by documented instructions, procedures, or drawings… and shall be accomplished in accordance with these instructions, procedures, or drawings.” Procedure EN-OP-104, “Operability Determination Process,” Revision 9, states, in part, that “if a piece of information material to the determination is missing or unconfirmed, and cannot reasonably be expected to support a determination that the SSC [structure, system, or component] is OPERABLE, the SM (shift manager) should declare the SSC INOPERABLE.” Also, during any period when one EDG is inoperable, TS 3.5.F allows continued reactor operation during the succeeding 72 hours, provided that the remaining EDG is demonstrated to be operable in accordance with TS SR 4.5.F.1. TS SR 4.5.F.1 requires that, within 24 hours, a determination be made that the operable EDG is not inoperable due to a common cause failure, or that the monthly surveillance test be performed on the operable EDG in accordance with TS SR 4.9.A.1.a, and that, within 1 hour and once every 8 hours thereafter, correct breaker alignment and indicated power availability for each offsite circuit be verified. If this requirement cannot be met, then the reactor shall be placed in the cold shutdown condition within 24 hours.

Contrary to the above, on March 18, 2015, Entergy staff performed an inadequate operability determination of the X-107B EDG following indications of engine coolant leakage in cylinder 9L, the X-107A EDG was not demonstrated to be operable in accordance with TS SR 4.5.F.1, in that a determination that the X-107A EDG was not inoperable due to a common cause failure was not made, nor was the monthly surveillance test performed on the X-107A EDG in accordance with TS SR 4.9.A.1.a. Because this violation was of very low safety significance (Green) and Entergy staff entered this issue into their CAP as CR-2015-2109, this violation is being treated as a NCV, consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000293/2015002-02, Inadequate Operability Determination for the X-107B EDG Results in TS Violation)

Pilgrim: I Am Startled In A Good Way With The Honesty Today

Well, the NRC is going to report it all in a inspection report anyways.

"Plant Struggles To Maintain Its Aging Plant"

Pilgrim plant workers aim for a safe shutdown

By David Abel Globe Staff  October 31, 2015

PLYMOUTH — Behind the barbed-wire fences and heavily armed guards protecting the Pilgrim Nuclear Power Station, Steve Verrochi and his department heads huddled around a long table to review the daily report of potential safety concerns at one of the nation’s most troubled nuclear plants. 

A component of the security system had been declared “unreliable” and an “unexpected alarm” had gone off in the plant’s control room. Some fans at the huge plant had failed, and a radiation monitor required repairs after being struck by lightning. There were leaky seals, malfunctioning gauges, corroding pipes, and a computer that ceased providing real-time data about reactor power.

***And the maintenance workers were falling behind on their repairs. 

“We need to get back on track,” Verrochi, the plant’s general manager, told his staff at that recent morning meeting, as a Globe reporter looked on. “The last couple of weeks we’ve been off the mark.”  

This month, Entergy Corp. announced that it will shutter the money-losing plant no later than June 2019. Plant officials, as well as federal regulators, insist that Pilgrim remains safe, even as company officials say the plant is losing about $40 million a year, and that they expect to pay tens of millions of dollars to comply with new federal inspections. But antinuclear activists argue that the plant is unsafe and fear that Entergy will now scrimp on safety to save cash.

 

Maintenance at the 43-year-old plant has received increased scrutiny since the US Nuclear Regulatory Commission downgraded Pilgrim’s safety ranking in September, designating the plant as having one of the nation’s three least-safe reactors.

The meeting in a white-walled conference room of the operations building reflected the risks of continuing to run a 43-year-old plant, which will start the decades-long task of decommissioning after it closes.

‘There’s a lot of obsolete stuff out there. We do a lot of repairs.’ 

John Ohrenberger, who oversees maintenance staff at plant 

During the visit, the plant’s attention to safety and security concerns was evident nearly everywhere throughout the sprawling facility along Cape Cod Bay. 

Guards in black fatigues, who carry assault rifles and handguns, patrol the property and keep a close watch from scores of cameras and bulletproof towers. They regularly train for terrorist attacks and store weapons in gun lockers and armored vehicles, while local and federal law enforcement officials patrol the waters beyond the rocky sea wall off the coast. 

Visitors must pass through a gantlet of security before nearing sensitive areas, including massive concrete barriers to protect against truck bombs, steel turnstile doors that require handprints to open, and X-ray machines that examine the contents of bags and others that check for explosive residue.  

Inside, posters exhort employees to mind their ALARA, the ubiquitous acronym reminding them to reduce their radiation exposure to “as low as reasonably achievable.” 

Others remind them that “every millirem counts” and “we are all responsible for radiation protection.”

Craig F. Walker/Globe Staff 

A spent fuel pool contains thousands of fuel assemblies.

The average US resident is exposed to about 620 millirem of radiation a year, according to the regulatory commission; Pilgrim allows its employees near radiation until they absorb 1,200 millirem. If there’s a major emergency, plant officials allow them to be exposed to as much as 20,000 millirem. 

 

High doses of radiation can cause cancer, but the regulatory commission says on its website that “there are no data to establish a firm link between cancer and doses below about 10,000 millirem.” 

Employees who work in the containment area at Pilgrim are required to wear devices that track their radiation

John Ohrenberger, who oversees 95 employees who do maintenance at the plant, said he used to get about 1,200 millirem of radiation a year as a nuclear mechanic. He wasn’t concerned about the routine radiation exposure, even as his staff’s workload has risen to address the plant’s aging systems. 

***“There’s a lot of obsolete stuff out there,” he said. “We do a lot of repairs.” 

Those jobs include working inside the drywell that houses the reactor, where hundreds of highly radioactive fuel rods generate steam that turns the plant’s turbines to create electricity. 

Plant officials use equipment to suck nitrogen out of the air before the workers open the steel hatch to enter the steamy drywell, which is where Tom Wonsey found himself last January when one of four critical safety valves failed. 

***The nuclear mechanic was part of a team that spent about 30 hours wearing special anticontamination suits, using wrenches to replace the bulky valve, which weighs more than 1,000 pounds and helps cool the reactor when it powers down. That failure, following previous safety valve problems, led the regulatory commission to downgrade the plant’s safety rating. 

Yet the prolonged proximity to the reactor didn’t faze Wonsey, who estimates he has been exposed to about 1,000 millirem of radiation this year. “I’ve never seen anything to be concerned about the plant’s safety,” he said between jobs at the plant.

Craig F. Walker/Globe Staff 

David Noyes of Entergy walked past dry cask storage units last week during a tour of the Pilgrim nuclear plant.

Plant officials showed the redundant systems they would use to prevent a calamity, including water pumps and diesel generators stored in multiple locations, well above sea level. They would be used in the event the plant lost power to cool the reactor, as occurred in Japan after a tsunami in 2011 ravaged the Fukushima nuclear plant. 

While Entergy has invested millions of dollars in safety upgrades to comply with new federal regulations triggered by Fukushima, some longtime employees acknowledge they can only prepare for what they can foresee. 

“When Fukushima happened, it took everyone aback,” said Paul Smith, a staff engineer who has worked at Pilgrim

***

since 1968. “It taught us we don’t know everything. It also taught us modesty.” 

In the coming years, as the plant enters the decommissioning process, its employees will still have dangerous work to do. They’ll have to transfer 3,162 highly radioactive fuel assemblies from the spent fuel pool to massive casks, a delicate, expensive task that will leave them indefinitely on a large concrete pad beside the reactor building. 

Helping ensure that the plant complies with federal safety regulations is Erin Carfang, the Nuclear Regulatory Commission’s senior resident inspector at Pilgrim. 

She said she goes wherever she wants at the plant and has issued multiple violations to Pilgrim, including the one earlier this year that led the regulatory commission to downgrade its safety rating. 

***If the plant becomes unsafe, Carfang said, she wouldn’t hesitate to recommend it be closed before 2019. She has young children and lives near the plant, she added.
“We believe there is an adequate safety margin for the plant to continue operating,” she said in her office. “We have a vested interest in keeping it safe.” 

So why didn't the NRC listen to me in my 2013 petition on the SRVs? I had everything in my 2013 petition the NRC later discovered in their 2015 SRV inspection report and violation finding.  

At the recent morning meeting, the 27-page report the group reviewed showed that the plant’s staff had already been exposed to nearly 97 percent of the radiation that Pilgrim officials had set as a goal for the year. 

Verrochi also heard reports from maintenance, engineering, security, and other departments about concerns both big and small. 

***Verrochi worried that “mental distractions” could lead to “severe consequences.” 

“It’s all about being deliberate,” he reminded the staff. “If you find yourself in a situation where your mind drifts, it’s time to readjust.” 

Verrochi discussed how to “finish strong in 2019” and gently reprimanded the staff for being three minutes late to the meeting, which prompted the department heads to flash a thumbs-down sign in unison. 

Then he praised the staff for their alertness and “excellent job” responding to a leak in the control room, prompting a thumbs-up from the staff. 

“Be deliberate and act with integrity,” he told them before adjourning the meeting.

Fifteen Years of Data on Hope Creek's 2 Stage SRVs

Ok, put together these recent events. Put the puzzle together. What picture do you see. The dual recirc pump trip. The out of alignment srv and it piping. The come-along who broke the SRV before operation. The dinged SRV piping...many pipe...with a pipe wrench gouge weakening it. The prolong operation with the leaking SRV on strong indications. The whole deal with the SRV set point inaccuracy. Leaking SRV and using safety equipment (torus cooling) to accommodate poor maintenance. Hope Creek has painted a picture with these events…what commonalities do you see in it all. What picture do you see in the puzzle?   

I called two Hope Creek telephone numbers this morning explaining the SRV problem...gave them a opportunity to talk to me. Nothing yet

Right, in 2000 Hope Creek said all is fixed with the SRVs. I see a trends from 2000 to today of a drastic increase in the magnitude of inaccuracies going higher than required tech spec limits and a drastic increase in testing valve failures per operating period. The reliability the Hope Creeks SRVs has drastically declined in 15 years. Over and over again Hope Creek has opined after each poor operational period, we now are positive we got a handle on the SRV maintenance and reliability issues. But each operational period only gets worst. In 2000 Hope Creek had a SRV failure of 14%. In the most recent period in their NRC reporting it is at a 71% failure rate. The current failure rate is 5 times worst than 2000.

Hmm, Hope Creek had their first power up rate in 2001. It was 1.4%? Had another uprate in 2008 @ 15%. Is the SRV inaccuracy deal uprate related? 

Just saying, a 16.4% increase in power and no comparable increase in safety relief valve capacity?

How is the insulation situation around the SRVs with all this movement and power increase?   

There is clear and convincing evidence a majority of the SRVs aren't reliable enough to stay within tech specs limits for the operating period and the majority of the operational time Hope Creek really is prohibited from being at power according to plant licencing. I bet you at the 6 month operational period, if the plant was required to be shutdown and test their SRVs for lift pressure accuracy...five SRVs would be inop. According to tech specs, Hope Creek is required to have thirteen of fourteen fully functional.   

It is beyond shocking Hope Creek and NRC hasn't made a operability determination and why there was so many failures this past operating period. It is mind boggling! Why did we have 10 failures out of fourteenth...why have the rates changed so drastically in recent years. Isn't anyone inquisitive?

Why do I feel like the corrective actions on the distance past failures have led to a rash of new failures? 

Fifteen years of SRV LERs: 

Licensee Event Report 2015-004-01

10 of 14 failed tech specs testing 

Licensee Event Report 2013-007-00

5 failed 

Licensee Event Report 2013-005-00

SRV P solenoid failed to operate-they didn’t know at what point in the cycle. Manufacturer defect. Why didn’t testing pick this up before installation and during cycle?

  

(If this is a LER, how come the cold spring H SRV isn’t a LER?)

The SRV-P SOV (S/N 481) was a new valve purchased from Target Rock for installation in refueling outage H1R17.

A new SRV…it this why the Target Rock new SRV replacement deal fell through? What crap quality new valves.

Licensee Event Report 2012-004-01

6 failed

Outside tech specs by a huge margin  

Licensee Event Report 2010-002-01

6 failed

5 failed by corrosion bonding.

1 failed through a spring failure.

Taking about the change from plus or minus 1% t0 3%.

Outside Tech Specs by a huge margin.

Licensee Event Report 2009-002-001

6 failed with another with a question

Outside tech specs by a huge margin.

Was  the H SRV this period, was the bellows assemble noticeably distorted. What cause this distortion in 2009...

“For the sixth SRV, the bellows assembly was noticeably distorted.”

15% Power Uprate

LER 354/2006-003-00

3 failed tech specs accuracy.

All failed by 3.2%. It is highly implausible they all at the exact rate. It is an indicator of fraud.

LER 354/2004-009-00

“PSEG determined that the setpoint value for several safety relief valves” :)

5 failed set point accuracy

3 failed oxidation bonding

Unknown reason for the other two. The LER update on the two unknown failures are missing? 

LER 354/2003-003-00

8 failed tech spec setpoint testing

6 on setpoint testing

2 by leaking. A leaking SRV has a high probability of failing to operate on demand and the valve just opening on its own. A leaking SRV has a high probability of failing on setpoint inaccuracy. 

Implies these valves were leaking from the beginning: The offsite test procedure was revised to require the performance of an additional seat leakage test at 10 psig higher than the seat leakage certification test. This additional test provides added assurance of the valve's ability to be leak tight. The certification seat leakage test pressure is currently performed at the maximum operating pressure of 1010 psig.

LER 354/2001-007-00

3 failed tech spec testing

LICENSEE EVENT REPORT NO. 2000-003-00

2 failed tech spec testing;

If only the next 15 years Hope Creek had two failures per refueling outage. Look at with the future record I provided.  In the next fifteen years, the magnitude of  inaccuracies have drastically worsened and the number of valves failures per operating period have drastically increased. Remember the most recent period had ten of fourteen SRVs being inop.

•  Prior to Cycle 9, pilot discs for thirteen of the fourteen SRVs were modified with platinum ion implantation to address problems with setpoint drift caused by corrosion bonding of the pilot disc to the pilot seat.

I think the below is basically a public con job and coning the public about fixing the SRVs is just going to continue in the future. Hope Creek and the NRC are just addicted to being deceptive. 

“On May 4, 2000, the results of the Safety Relief Valve (SRV) setpoint testing were received. The testing revealed that, following Cycle 9, 2 of the 14 SRVs experienced setpoint drift outside of the Technical Specification limit of +/ 3%. One of the failures was of a valve with a pilot disc that was modified with platinum ion implantation. The drift for this valve appears to have been caused by friction on the sliding surfaces resulting from poorly controlled maintenance performed by the valve vendor. These practices have been addressed via a NUPIC audit. Corrective actions have been proposed and their effectiveness is being monitored. The cause of the drift for the other valve is corrosion bonding of the pilot disc to the pilot seat. The SRVs were inspected, refurbished and satisfactorily re-tested at a test facility. SRV drift in two-stage Target Rock valves is being addressed generically by the Boiling Water Reactor Owners Group. Platinum ion implantation has now been implemented on all 14 SRVs. The ion implantation process has resulted in a marked reduction of setpoint drift and will continue to be the primary solution for pilot disc to seat corrosion bonding.”

PREVIOUS OCCURRENCES 

LER 95-004, LER 95-036, LER 354/97-024, and LER 354/99-003, reported events where SRV setpoint drift exceeded the Technical Specification allowable limits during previous operating cycles. The corrective actions taken to address setpoint drift have not been fully implemented; therefore, they were not entirely effective at eliminating this phenomena. However, the ion implantation process has reduced the magnitude of the setpoint drift and is expected to further reduce it after the corrective actions are fully implemented. As described in the following Corrective Actions section, PSE&G continues to work with the BWROG to resolve this issue.

2011 Edition: Hope Creeks SRV Tech Specs

The 10 violation average 6.5%. Bet you the average of the 14 reliefs is higher than 3.0%?

update 10/30

Why isn't LER 2015-004-01 a violation? Why did the NRC intentionally walk pass this violation last Sept 2014.

Enforcement. 10 CFR 50, Appendix B, Criterion XVI, "Corrective Action," requires in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected.

I don't have any conclusive proof at all the SRV weren't replaced with clean spares last sept 2014. Maybe they all only been in the plant for seven months.

2015-004-01

test results for the ten SRVs not meeting the TS requirements are as follows:

Valve ID As Found TS Lift Setting Acceptable Band % Difference

(psig) (psig) (psig)               Actual

F013C 1216 1130 1096.1 -1163.9     7.61%

F013F 1240 1108 1074.8 -1141.2     11.90%

F013G 1208 1120 1086.4 - 1153.6    7.86%

F013H 1148 1108 1074.8-1141.2      3.60% (in about 7 months)

F013J 1161 1120 1086.4 -1153.6     3.66%

F013K 1161 1108 107 4.8 -1141.2    4.80%

F013 L 1165 1120 1086.4 -1153.6    4.00%

F013 M 1207 1108 1074.8 -1141.2    8.90%

F013P 1221 1120 1086.4 -1153.6     9.00%

F013R 1169 1120 1086.4 -1153.6     4.38

Obviously these guys are in trouble. Going to have to look at the safety evaluation with why they need 13 of 14 SRVs. The NRC implies it is a reactor over power level and vessel pressure thing. 

This is what I mean by stove piping or siloing. Nobody considered a SRV pressure lift setpoint over limit could be discovered when the plant is operational. Nobody ever figured somebody would discover evidence of a inop could occur early in a operating cycle. Then the outside contender would discover a 72% failure rate in last cycle and Hope Creek has been whining about wanting to replace the poor reliability 2 stage SRV. There is very credible proof Hope Creek in recent years spent the majority of its operational time in a condition when they shouldn't have been allowed to operate. This is a perfect SRV storm and the industry will be studying or training on these events for many years.     

REACTOR COOLANT SYSTEM
3/4.4.2 SAFETY/RELIEF VALVES
SAFETY/RELIEF VALVES
LIMITING CONDITION FOR OPERATION

3.4.2.1 The safety valve function of at least 13 of the following reactor coolant system safety/relief valves shall be OPERABLE*# with the specified code safety valve function lift settings:**

4 safety-relief valves @ 1108 psig ±3%

5 safety-relief valves @ 1120 psig ±3%

5 safety-relief valves 0 1130 psig ±3%

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.

ACTION:

a. With the safety valve function of two or more of the above listed fourteen safety/relief valves inoperable, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours.

b. With one or more safety/relief valves stuck open, provided that suppression pool average water temperature is less than 110F, close the stuck open safety relief valve(s); if unable to close the stuck open valve(s) within 2 minutes or if suppression pool average water
temperature is 110F or greater, place the reactor mode switch in the Shutdown position.

c. With one or more of the above required safety/relief valve acoustic monitors inoperable, restore the inoperable monitors to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours and in COLD SHUTDOWN within the following 24 hours.

*SRVs which perform as ADS function must also satisfy the OPERABILITY requirements of Specification 3.5.1, ECCS-Operating.

**The lift setting pressure shall correspond to ambient conditions of the valves at nominal operating temperatures and pressures.

#SRVs which perform a low-low set function must also satisfy the OPERABILITY requirements of Specification 3.4.2.2, Safety/Relief Valves Low-Low Set Function.
HOPE

TABLE 1.2
OPERATIONAL CONDITIONS
MODE SWITCH
POSITION
AVERAGE REACTOR
CONDITION COOLANT TEMPERATURE

1. POWER OPERATION

2. STARTUP

3. HOT SHUTDOWN

4. COLD SHUTDOWN

5. REFUELING

The Value Of Backing The Highest Cost Electricity.

See, the powerful Canadian cabal Entergy warn us about. They control both political parties...

Long term overpriced contracts are not in the public interest. 

Remember the natural gas fracking miracle...it is going to drive down electric prices for the next two decades. 

All the teabagger electricity interest always favors the highest price electricity that sets the price for the rest of energy sources. Baker and Dean's political interest always backs the highest energy source price. It is a policy that backs the collusion of all the electric energy sources. And high electricity prices always favors the profits of the electric utilities. Now you know the magic why all the politicians favors the highest cost electricity.     

Former Vt. Gov. Howard Dean backs Gov. Charlie Baker's hydropower bill 

By Shira Schoenberg | sschoenberg@repub.com masslive.com
on October 28, 2015 at 1:36 PM

BOSTON - Former Vermont governor Howard Dean met with Massachusetts Gov. Charlie Baker for an hour at his Statehouse office on Wednesday, as Dean threw his weight behind Baker's proposal to increase the use of hydropower in Massachusetts. 

The event was a unique bipartisan moment, with Dean, the former 2004 Democratic presidential candidate and chairman of the Democratic National Committee, supporting a proposal by Baker, a Republican governor.

"Isn't it nice to do something bipartisan in an election year?" Dean quipped. 

Baker's bill would require utilities to solicit long-term contracts for hydroelectric power. So rather than buying electricity daily, the utility could sign a contract with a supplier for several months. The legislation would authorize utilities in Massachusetts to work with utilities in Connecticut and Rhode Island to buy power together. The goal would be to allow Massachusetts utilities to get better rates on hydroelectric power by buying in bulk. 

Baker's legislation, which is being considered by the Democratic-controlled Legislature, has taken on increased urgency with the news that the Pilgrim Nuclear Power Station plans to close by 2019, which will require the state to come up with a way to replace the lost power.

Vermont faced a similar situation with the 2014 closure of the Vermont Yankee nuclear power plant. Dean, who was governor from 1991 to 2003, and the governors before and after him, have all signed contracts to import Canadian hydropower. Vermont also has its own…. hydroelectric generation facilities. According to a Vermont-based renewable energy group, in 2013, 20 percent of Vermont's electricity generation was produced from hydroelectric power…

 

Nukes: We Can Only Survive In Markets Controlled By Our Buddies?

I translate this into commom language. Fertel means teabagger government hating plants (nukes and other) can't compete in the free market and deregulated markets. They can only survive in the political market where the Republican government haters dominate the scene. Like in the Republican breakaway regions of our south. It is only in the regulated markets dominated by the Republicans, where these politicians can control the excessive electricity prices...they hose the ratepayers on expensive insider games that benefits the rich.  

More US nuclear power units will shut permanently, NEI's Fertel says 

Washington (Platts)--26 Oct 2015 604 pm EDT/2204 GMTUS Nuclear plant operators are likely to announce the permanent closure of additional reactors in the coming months for economic reasons, Nuclear Energy Institute President and CEO Marvin Fertel said Monday.
"I'm hoping very few" will be shut, but some are expected to, he said on the sidelines of a news conference Monday.
Entergy announced earlier this month it will permanently close its 728-MW Pilgrim station in Massachusetts sometime between 2017 and 2019, citing low power prices. The company has said a decision on whether to shut its 849-MW FitzPatrick plant in New York, also for economic reasons, will be announced by the end of the month.
Exelon has said five of its reactors in Illinois are struggling economically and a decision will be made next year about their future.We're closing very safe, well-operated plants because of market dysfunctionalities," Fertel said during the news conference, which was called to discuss the awarding of an operating license on October 22 by the US Nuclear Regulatory Commission to the Tennessee Valley Authority for its 1,150-MW Watts Bar-2 reactor in Spring City, Tennessee.
While TVA sets prices for its nuclear units, reactors in deregulated electricity markets are struggling, Fertel said.
Electricity regulators have made adjustments to capacity markets in the PJM Interconnection region that have increased revenue and helped recognize the value of baseload generating units, helping nuclear operators there, Fertel said. However, the nuclear plant operators still need increases in the prices of power they receive, including through a more level playing field for nuclear-generated power and other fuel sources, he said.
"Even so, we don't think some of this will happen fast enough to potentially save some plants," Fertel said.
TVA does not expect any impact from low power prices to the viability of its nuclear units because it operates the wholesale system and has a public power model in the parts of seven states in which it operates, TVA CEO Bill Johnson said during the news conference. However, he said retiring merchant reactors is a mistake.
"It's a mistake for us to close these plants because of the way the markets are designed," he said.
"It threatens transmission stability; it is the only mass source of low-cost carbon-free power," Johnson said.
TVA's Watts Bar-2 will load nuclear fuel starting in several weeks and then will start producing power at low levels before reaching full-power commercial operations sometime in the first quarter of next year, Johnson said. He declined to estimate how much power the new unit would generate in the coming months.

Hope Creek's SRVs, pipe pinning and cold spring?

update 10/28

(new)-Hope creek and Salem 1& 2 is the second largest nuclear facility in the USA. They own Peach Bottom, Salem 1& 2 and Hope Creek. They have a high plant number for such a small company. I'll bet you per stockholder to nuclear plant ratio, PSEG has the highest rate in the nation. They have a very high nuclear plant exposure. Man, abutting the cheap Marcellus shale gas field and Pennsylvania...cheap electricity??? Maybe the cheap natural gas plants can bail out their nukes...  

(New)Forgot- asked why there never was a licence event report (LER) on the H SRV. The failure of the H SRV last Sept 2014 was a "special interest" to the nuclear industry directly after shutdown according to the NRC inspection report...but why no LER? He verified no H SRV LER on the docket. He thought it surprising it wasn't on the docket. He thought NRC regulations don't required federal reporting on this kind of problem. I am telling you, it is a cover-up and the rules for NRC LER reporting is part of the problem. They corrupted public transparency...    

"So a special or stand in Hope Creek NRC resident called me up.

• Basically Hope Creek were in negotiation with a European firm on replacement SRVs (identical to Pilgrim’s now in plant)…the Europeans backed out because they couldn’t meet our quality standards. 

• Then Hope Creek approached Target Rock for a SRV contract for the 2 stage replacement. They pulled out of the discussion without a reason.

I gave him the SRVs setpoint admin scenario. He gave me all the nuclear analysis saying they were safe. I said safe for me is following all the plant licensing and tech specs without question first. If the written rules aren’t right, you do a written evaluation, then change the rules. But you have to follow tech spec. What if in the control room you came upon information one SRV setpoint was at 5%, is the valve inop? On the second one going out, are they required to shut down? What does the actual tech specs required the plant to do? Then I told him the situation with H SRV testing. Said it went to 3.6% at 7 months. When does the valves go out of tech specs, at the one month or six months? HC last testing has a 71% failure rate. At the 8 month time frame will HC with two inop SRVs and have to shutdown. Hope Creek for about a decade has been whining about the need to replace the 2 stage.   

This so called stand in NRC resident is siloing information in his head just to career wise survive.  This information goes into this cubby hole and that information goes into another cubby hole…but never shall all the information in my special cubby holes meet.  

Does the uncertainty of not knowing the actually set point lift point require an immediate plant shutdown?

That is when he explained to me these are complicated matters, he will have to get back to me in a few days.

I am thinking this is a huge cover-up. At least the Pilgrim style model, there is no new replacement to be had on the market. It probably all over the BWRs, I see similar issues with the PWRs with the pressure operated relief valves (PORV).

Everything is always an information gather campaign?  

I’ll bet you the liability for making these kinds valves is too large for any manufacturer to consider supply the nukes. What if one of our valves caused a trillion dollar plant meltdown?"

Another update:

We are in that SRV setpoint lift pressure inaccuracy admin error I talked about the other day. Them idiots. That leaking Hope Creek H SRV last sept 5 2014…they replaced it with a refurbished one. Started up and seven months later they entered the normal outage. Massive SRV setpoint lift inaccuracies in the refueling outage forced them to test all 14 SRVs. They tested the Sept 2014 installed H SRV who was only in the plant for seven months. It failed the lift pressure test accuracy with a 3.6% (while in the plant for only seven months). On two SRVs being declared inop they are required to be shutdown within 24 hours. Hope Creek SRVs had a 71% lift accuracy failure rate this period. Some huge numbers too. How can Hope Creek demonstrate they are within Tech Specs say at the 8 month point …prove they are safe and fully within tech specs? These guys are the same model SRVs as Pilgrim. They have been operating for 5.5 months now…how many inop SRVs are in the plant now?

The admin scenario I was talking about in Pilgrim. The SRV testing facility calls Pilgrim saying the SRVs you sent us have all been tested, inspected...they are good for plant operation and well within tech specs. Pilgrim installs these and restarts. The testing facility calls six months later saying we made a terrible admin mistake. The A SRV was mistakenly set to lift at 5%. Plus or minus 3% pressure is the tech spec limit. It is outside your tech specs and you need to call the valve inop.

What would Pilgrim be required to do per tech specs?

Tech Specs says all SRVs need to be operable at power and be within 3% lift pressure testing limits. Upon one two SRV being inop, the plant is required to be shutdown within 24 hours. They would have need NRC permission to stay up in power after 24 hours.

Tech Spec SRV lift pressure valve actuation point isn't discoverable at power or fixable. 

Works in progress

Update@1pm

You get it with the H SRV valve. In a little over six months of operation, this valve exceeded its tech spec plus or minus 3% limits of 3.6%. It was required to be called inop. The second inop SRV would require the plant to be shutdown per Tech Specs

How many SRVs were lift setpoint inaccurate on Aug 2014? Why didn't they yanking out all the reliefs on the Sept maintenance outage and reset them.  How many right now are inop and Hope Creek should be required to be shutdown.  

• April 2012: startup from refueling

• Sept 5, 2014: leaking SRV  ‘H’ shutdown

• April 11, 2015-May 13: normal refueling. 32 day outage

***Hope Creek from the Sept 2014 end of maintenance outage till beginning of April 2015 normal refueling outage. The amount of time it takes for a SRV setpoint lift pressure accuracy to be within tech specs and then get to 3.6% over tech spec lift limits.

Result: 218 days 

It is 218 days from the start date to the end date, but not including the end date 

Or 7 months, 6 days excluding the end date 

***Hope Creek from end May 2015 normal refueling till today 

Result: 167 days 

It is 167 days from the start date to the end date, but not including the end date 

Or 5 months, 14 days excluding the end date

***Pilgrim from end of normal May 2015 refueling till today

Result: 154 days

It is 154 days from the start date to the end date, but not including the end date

Or 5 months, 1 day excluding the end dat

LER 2015-004-01 

F013H 1148 1108 1074.8-1141.2 3.60%

"As-Found Values for Safety Relief Valve Lift Set Points Exceed Technical Specification Allowable Limit." 

Technical Specification (TS) 3.4.2.1 requires that the safety function of at least 13 of 14 SRVs be operable with a specified code safety valve function lift setting, within a tolerance of+/- 3%. Action (a) of TS 3.4.2.1 specifies "With the safety valve function of two or more of the above listed fourteen safety/relief valves inoperable, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours." Therefore, this is a condition reportable under 10 CFR 50.73(a)(2)(i)(B) as an Operation or Condition Prohibited by TS.

CORRECTIVE ACTION

1. All 14 SRV pilot stage assemblies were removed and replaced with pre-tested, certified spare pilot valves(H1R19).

2. Evaluate options for the replacement of the currently installed Target Rock two-stage SRVs with a design that eliminates setpoint drift events exceeding +/-3% and improve SRV reliability. The replacement schedule will be developed after a suitable valve is identified.

I am still working on this...

So how would say five SRVs discharge piping severing effect all the accidents. A stuck open SRV and a severed SRV discharge line?

This is a much worst accident than the NRC portrays and it should have gotten a much bigger inspection...

Remember LaSalles torus temperature stratification incident...

They had to use torus cooling to compensate for the leaking SRV throughout the cycle and they were surprised with hearing steam bubble collapse booms in the torus. 

Bet you those steam bubble vacuum booms sound very similar to the normal operation of HPIC and RCIC. 

I am shocked they had to use safety systems(torus cooling)excessively just because they were too cheap to fix the SRV right and then failed to immediately shutdown on the fist indication the H SRV was leaking.      

Hope Creek

February 5, 2015 

SUBJECT: HOPE CREEK GENERATING STATION UNIT 1 – NRC INTEGRATED INSPECTION REPORT 05000354/2014005

Pg11

 (NCV 05000354/2014005-01, Failure to Identify and Correct a Condition Adverse to Quality Associated with Safety Relief Valve Discharge Piping Misalignment)

***and the August 2014 power reduction due to a safety relief valve indicating open.

***The SRVs are Target Rock Model 7567F two-stage SRVs

 1R15 Operability Determinations and Functionality Assessments (71111.15 – 3 samples)

a. Inspection Scope

Findings 

Introduction. A self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, “Corrective Action,” because PSEG did not promptly identify and correct a condition adverse to quality. Specifically, PSEG did not initiate a NOTF or perform an evaluation of a cold spring condition

The SRV and its discharge piping were not line up on installation of the tested valve in 2012... the relief and it discharge piping was out of alignment by some two inches. Hope Creek used the tremendous force of a "come-along" chain to jack the valve and piping together for attachment. One doesn't know the misalignment before the the "come-along". This damaged the 2 stage SRV.  This is what happens when you have gorilla maintenance employees and a initially poorly designed valve. Then you had incompetent control room people who never could make the right safety call from 2012 to Sept 2014. This is very similar to the bungling of the Pilgrim SRVs since new installation in 2011 with the length of time the licencee and NRC took to come to terms with their SRV problems. 

Check out the SRV set point lift pressure inaccuracy inops in Licensee Event Report 2015-004-01. Ten out fourteen failed their tech spec acquirement. They needed to be declared broken at greater plus or minus three percent inaccuracy. Severity one percent failed tech spec testing. Upon discovering more than one SRV was outside tech spec they were required to shutdown and fix them. A large number of SRVs being outside Tech Specs were substantially outside plus or minus 3%.   

I consider the "identification occurrence" as being corrupt and a document falsification. The "event date" was sometimes during "plant operation".   Because they have no means to know or proof when the tens valve went broken, they would have to make a conservative guess they went broken one day after startup from outage after in 2012.  

IDENTIFICATION OF OCCURRENCE
Event Date: June 2, 2015
Discovery Date: June 2; 2015

So in this operating period (18 month) with Hope Creek's model 7567F (Pilgrim too)they has extremely dangerous leaking H SRV and other 9 failed testing valves. 

***Where the hell is the Licence Event report(LER)on the leaking 'H' SRV valve??? 

Just saying, 'H' SRV valve was inop before they even started up.

found in the ‘H’ SRV discharge piping during the valve’s replacement in 2012. This condition that occurred during installation was determined to be the cause of a leak on the main seat of the newly installed SRV. The leak proceeded to degrade during the operating cycle and ultimately caused Hope Creek to shut down and replace the SRV on September 5, 2014.

Description. The target rock model 7567F two-stage, pilot-operated SRV consists of two assemblies: a pilot stage assembly and a main stage assembly. These two assemblies are directly coupled to provide a unitized, dual function SRV. The pilot stage assembly is a pressure sensing and control element, and the main stage assembly is a system fluid-actuated reverse seated angle globe valve which provides for the pressure relief function or system depressurization at full rated flow. This model SRV has a set pressure range of 1025 to 1190 psig and weighs approximately 1100 pounds. The  main stage disc is tightly seated by the combined forces exerted by the preload spring and the system internal pressure acting over the area of the valve disc.

_________________________________________________________________________________


***2014005 February 5, 2015-The inspectors reviewed PSEG’s ACE, SRV work history, procedures and previous CAP evaluations and determined that PSEG’s conduct of maintenance in WO 60097071 should have generated a NOTF to document and evaluate the discharge piping misalignment found when removing the ‘H’ SRV in RF17. The inspectors also identified a note in Section 5.2.3 of MA-AA-734-458, Pressure Relief Device Removal and Installation, which states that “discharge piping should not cause any bending or apply any cold spring to the relief valve. Any cold spring or pipe distortion should be brought to the attention of supervision.” The inspectors determined that PSEG should have evaluated the misaligned SRV discharge piping as a potential condition adverse to quality.

***05000354/2015002-On April 15, 2015, PSEG NDE personnel were attempting to perform an ASME Code required ultrasonic examination of a weld on the ‘A’ SRV inlet piping, just below the bolted flange, when NDE personnel discovered tooling marks in the area of the weld preventing them from performing the weld examination.

 

In addition, the inspectors identified that PSEG procedure, HC.MD-CM.0006, Sections 5.4 Valve Body Removal, 5.5 Valve and Piping Inspections and 5.6 Valve Body Installation contained supervisory hold points for maintenance supervision to verify work task completion. Specifically, the inspectors identified that Sections 5.5 and 5.6 required visual inspection of the SRV inlet and outlet piping as well as notes that any nicks, pits and grooves that are greater than 0.062 inches in depth are to be evaluated by the engineering staff.

The inspectors observed that each use of the torque tool on the RCS piping likely caused unquantified degradation to the affected RCS piping. The inspectors’ review of PSEG’s technical evaluation, SRV work history, and procedures determined that these tooling marks should have been identified and evaluated as a condition adverse to quality by PSEG prior to April 2015, and as early as the first usage of the torque tool for SRV maintenance applications which started per HC.MD-CM.AB-0006 Revision 17 in October 2004. In addition, the inspectors identified that PSEG procedure, HC.MD-CM.0006, Sections 5.4 Valve Body Removal, 5.5 Valve and Piping Inspections and 5.6 Valve Body Installation contained supervisory hold points for maintenance supervision to verify work task completion. Specifically, the inspectors identified that Sections 5.5 and 5.6 required visual inspection of the SRV inlet and outlet piping as well as notes that any nicks, pits and grooves that are greater than 0.062 inches in depth are to be evaluated by the engineering staff.

_____________________________________________________________________________________

On August 12, 2014, an equipment operator on reactor building rounds noted a loud banging noise emanating from the torus room area between the 54’ and 77’ elevations. Further investigation by operations within the torus room revealed the noise to be loudest around azimuth 340 degrees, with a pattern of a loud bang followed by several softer, quieter bangs. The loud bangs occurred at a frequency of every 5 seconds. PSEG conducted a review of plant parameters and correlated the noise with an increased frequency in the need to run suppression pool cooling and torus letdown  due to increases in torus heat input and level since February 2014.

PSEG initiated an investigation to determine the potential causes of the noise. As part of this investigation, PSEG developed a failure mode causal team (FMCT) with input from subject matter experts throughout the industry to identify potential causes of the noise. Industry operating experience (OE) was also reviewed, indicating similar events at Hatch and Millstone. The FMCT determined that the two most likely causes of the noise were either cycling of the ‘H’ SRV tailpipe vacuum breakers (VBs) inside primary containment (elevation 112’) or ‘H’ SRV leak by resulting in a water chugging event within the SRV discharge pipe T-quencher located inside the torus. OE from Hatch and Millstone indicated that if the VBs were cycling, failure of the VBs could occur within 30 days of the appearance of the noise, causing a potential direct pathway of any steam flow through ‘H’ SRV to the drywell instead of being dissipated by the water volume of the torus. Due to this potential failure mode, PSEG made the decision on August 25, 2014, to conduct a planned maintenance outage on September 5, 2014, to further troubleshoot and repair the source of the noise.

After shutting down the plant on September 5, 2014, PSEG refuted the cycling SRV VB potential cause by conducting walk downs at rated pressure inside the drywell and performing inspections of the ‘H’ SRV VBs to verify they had not been cycling. After completing detailed visual inspections inside the drywell and torus, PSEG concluded that the most probable cause of the torus noise was excessive leakage past the ‘H’ SRV main seat inducing a water chugging event within the T-quencher. This water chugging event occurred when significant quantities of steam reached the water in the T-quencher initiating a repeating condensate induced water hammer inside the T-quencher. PSEG removed and replaced the ‘H’ SRV main and pilot valve assemblies, and had both assemblies tested offsite. The results of the testing yielded 0.05 gpm and 2.35 gpm leakage past the pilot and main seats, respectively, totaling approximately 2.4 gpm or 1200 lbm/hr at 1000 psig.

PSEG’s investigation of the ‘H’ SRV main seat leakage identified the main disc as being severely steam cut. The apparent cause evaluation determined the most likely cause of the steam cutting to be the existence of cold spring in the tailpipe of the ‘H’ SRV during the last replacement of the valve in RF17 (April 2012) under WO 60097071. This WO documented that the ‘H’ SRV tailpipe was misaligned and discussion with maintenance found that a “come-along” was used to adjust for piping misalignment following removal of the valve. PSEG determined that a large moment force was applied to the SRV main during installation, causing the initial leak on the SRV main seat, which then degraded during the operating cycle. During the removal of the ‘H’ SRV main assembly in September 2014, the misalignment of the discharge piping was documented in NOTF 20661387 as off by 1.5” horizontally and 1.25” vertically. PSEG found that the ‘H’ SRV discharge piping spring can was not pinned during the removal process in 2012, and if it had been pinned prior to removal, it could have prevented any cold spring or piping misalignment during reinstallation of the new SRV. PSEG’s apparent cause evaluation (ACE) determined that the SRV installation and removal procedure does not include steps to pin the spring can prior to SRV piping disassembly.

The inspectors reviewed PSEG’s ACE, SRV work history, procedures and previous CAP evaluations and determined that PSEG’s conduct of maintenance in WO 60097071 should have generated a NOTF to document and evaluate the discharge piping misalignment found when removing the ‘H’ SRV in RF17. The inspectors also identified a note in Section 5.2.3 of MA-AA-734-458, Pressure Relief Device Removal and Installation, which states that “discharge piping should not cause any bending or apply any cold spring to the relief valve. Any cold spring or pipe distortion should be brought to the attention of supervision.” The inspectors determined that PSEG should have evaluated the misaligned SRV discharge piping as a potential condition adverse to quality.

Analysis. The inspectors determined that the inadequate identification and evaluation of the conditions adverse to quality associated with ‘H’ SRV discharge piping misalignment found during valve replacement in 2012, was a performance deficiency that was within PSEG’s ability to foresee and correct. The finding was more than minor because it was associated with the procedure quality attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of an event that upsets plant stability. Also, if left uncorrected, the finding had the potential to lead to a more significant safety concern. The inspectors determined that this finding was of very low safety significance (Green) using Exhibit 1 of IMC 0609, Appendix A, “The Significance Determination Process (SDP) for Findings At-Power,” dated June 19, 2012, because the finding did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. Specifically, the ‘H’ SRV safety-related function, relied upon for accident mitigation and pressure relief, remained operable.

This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Identification, because PSEG did not identify this issue completely, accurately and in a timely manner in accordance with the CAP. [P.1]

Enforcement. 10 CFR 50, Appendix B, Criterion XVI, “Corrective Action,” requires in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected. Contrary to the above, PSEG failed to promptly identify and correct a condition adverse to quality. Specifically, PSEG did not initiate a NOTF or perform an evaluation of a cold spring condition found in the ‘H’ SRV discharge piping during the valve’s replacement in 2012. This condition was determined to be the cause of an initial leak on the main seat of the new SRV during installation, which then proceeded to degrade during the operating cycle and ultimately caused PSEG to shut down and replace the SRV on September 5, 2014. PSEG’s corrective actions included replacing the ‘H’ SRV, providing training to all maintenance crews responsible for SRV work, and adding steps to the SRV removal and installation procedure to: 1) generate a notification for the identification of any piping misalignment; and 2) pin the discharge piping spring can prior to SRV removal. Because this finding was of very low safety significance and because it was entered into PSEG’s CAP as NOTF 20661387, this violation is being treated as an NCV, consistent with the NRC Enforcement Policy. (NCV 05000354/2014005-01, Failure to Identify and Correct a Condition Adverse to Quality Associated with Safety Relief Valve Discharge Piping Misalignment)