Hope Creek: SRV Problems Worst Than Exspected and New Phenomena Showing up

Inadequate SRV Performance Monitoring and Analysis Cornerstone Significance Cross-Cutting Coverup Aspect

Report Section
Initiating Events

Green FIN 05000354/2019003-01  Open/Closed

[P.5] - Operating Experience  

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The inspectors identified a Green finding (FIN) because PSEG did not adequately monitor and analyze safety relief valve (SRV) performance data, in accordance with ER-AA-2003, “System Performance Monitoring and Analysis,” Revision 11.  Specifically, PSEG’s main steam system performance monitoring plan did not identify appropriate SRV tailpipe temperature (TPT) values to detect critical leakage degradation and establish an adequate action plan in anticipation of exceeding action levels.  As a result, the ‘H’ SRV operated for extended periods of elevated TPT, with mischaracterized leakage rates and an inadequate action plan to address the degraded conditions. Description:  Hope Creek has 14 safety-related main steam SRVs that provide reactor pressure vessel overpressure protection.  The ‘H’ SRV consists of two stages: a pilot stage that senses main steam system pressure, and a main stage that actuated by the pilot stage to relieve elevated main steam system pressure.  Each SRV discharges through a tailpipe that directs the steam through a downcomer into a suppression pool.  Internal SRV leakage has been known in the industry to occur through the pilot and/or main stages, even under normal main steam system operating pressures.  Industry operating experience (OE) indicates the consequences of SRV leakage can include relief setpoint drift, failure of the pilot stage to reseat, delayed actuation, spurious opening, suppression pool cooling margin reduction, cycling of the SRV tailpipe vacuum breakers, and condensate-induced void collapse stresses on the tailpipe t-quencher.

Allowing prolonged leakage on Pilgrim's  SRVs causeed two failures, which led to the NRC to jack up their inspection activities leading to the permanent shutdown. I led the outside activities which questioned the reliability of these valves. The NRC was terribly embarrassed as I predicted one or more valves would eventually fail. And it happened. I spent a lot of my time a few years ago on confronting the SRV issue at Hope Creak. I had them admit the valve reliability problem crossed their quality assurance standards.

Basically this is a series of facilative assumption fraud or corruption situation. They make a continuing series of engineering assumption that favor corporate profits or minimizes losses. Fundimentally management says we only operate with conservative facts and within the well warn path conservative safety, but it is all a lie. They operate under a set of assumptions not backed up by science. They get increasing comfortable operating on assumption. It is the boiling frog situation. They get comfortable making assumptions calling it facts leading to a meltdown or a lost of credibility leading to shutdown.

The inspectors reviewed the main steam system performance monitoring plan, and noted that it required weekly monitoring of SRV TPTs by system engineering.  The inspectors also noted that PSEG identified elevated ‘H’ SRV TPT, beginning in November 2016 at the beginning of cycle 21, and monitored elevated TPT through start-up for cycle 22 operation in the spring of 2018. PSEG replaced the ‘H’ pilot stage during the refueling outage at the end of cycle 21, but did not replace the main stage.  A highlight of elevated ‘H’ SRV TPT in cycle 21 and 22 is included below: 

 On November 21, 2016, approximately one week after start-up for cycle 21, notification (NOTF) 20748846 identified the ‘H’ SRV TPT rose from 125 degrees to 210 degrees F.  The inspectors noted that the main steam performance monitoring plan specified a normal SRV TPT temperature range of 90-190 degrees F.  On April 12, 2018, NOTF 20789878 identified the ‘H’ SRV TPT rose above 220 degrees during the planned shutdown at the end of cycle 21, and documented that a TPT of 225 degrees correlated with a leak rate of approximately 5 pound-mass per hour (lbm/hr), in accordance with calculation AB-0076, Tailpipe Temperature versus Leak Rate for the ‘H’ SRV, Revision 0.  On October 1, 2018, NOTF 20806034 captured a rising SRV leak rate trend from 155 lbm/hr in June of 2018, to a current value 325 lbm/hr at 223 degrees.  The NOTF did not discuss the large increase in correlated leakage for approximately the same TPT reported on April 12, 2018.  On December 20, 2018, NOTF 20814836 identified a periodic loud banging noise in the torus area, which was a recurrence of a similar banging noise in 2014 due to ‘H’ SRV leakage and condensate-induced water hammer in the discharge line to the torus (see NCV 2014-005-01).  

 During cycle 22, PSEG engineering was performing informal weekly monitoring of SRV leak rates, and the inspectors periodically requested to review the data as part of routine inspection.  During review of leak rate data in late December of 2018, the inspectors identified data from October and November reflected significant changes from data previously reported for the same time period.  Specifically, as reported in late November of 2018, the weekly leak rate data from October and November of 2018 was reported to range between 155 lbm/hr and 245 lbm/hr.  However, on January 2, 2019, the data from the October and November of 2018 was reported to range between 613 lbm/hr and 755 lbm/hr.  The inspectors questioned PSEG as to the reason for the change in the data, and the station ultimately determined the leak rate trend data was incorrectly monitored from August of 2018 through December of 2018, and initiated NOTF 20816775.  The inspectors also noted that equipment apparent cause evaluation (EQACE) 70168630, performed in response to 2014 ‘H’ SRV leakage that resulted in torus noise and a maintenance outage, determined that calculation AB-0076 was not accurate, and assigned an action to address it, but the action was subsequently cancelled.

 
On December 27, 2018, in response to NOTF 20814836, documenting 2018 torus noise as mentioned above, PSEG initiated action to develop adverse condition monitoring plan (ACM) 19-001.  On February 4, 2019, PSEG determined the ‘H’ SRV leak rate was approximately 961 lbm/hr, utilizing ACM 19-001, which established enhanced monitoring and analysis methods similar to ACM 14-0014 following the onset of torus noise in 2014.    

On February 12, 2019, PSEG determined that a planned maintenance outage would be scheduled in the Spring of 2019, in response to ‘H’ SRV leakage that was projected to exceed the ACM limit for torus heat-up rate prior to the summer period.  The limit was established under Technical Evaluation 80124191-0020, to support compliance with the Technical Specification 3.6.2.1.a.2 suppression pool temperature limit of 95 degrees. 

 On March 28, 2019, Hope Creek entered a planned maintenance outage to replace the ‘H’ SRV pilot and main stages. As-found bench testing of the ‘H’ SRV determined that the ‘H’ SRV lifted within the Technical Specification limits of +/- 3 percent, identified pilot stage seat leakage to be minimal, and identified main seat leakage was very high at approximately 900 lbm/hr. Hope Creek operations procedures state that spurious opening may occur with leakage as low as 200 lbm/hr.  The inspectors also noted that industry owner’s group reports state that industry data shows plants may be effected at approximately 2000 lbm/hr, either spurious opening or relief setpoint drift, though the data can vary from plant to plant.  As such, industry owner’s group reports also state that some plants use 1000 lbm/hr as an administrative limit for defining operator actions (e.g., plant shutdown). 

 The inspectors review PSEG procedure ER-AA-2003.  Step 4.2.3 required the system engineer to identify the data required to effectively detect critical degradation that can effect performance, and step 4.4.3 required establishing action plans to address conditions in anticipation of exceeding action levels.  An action level is defined as the parameter which, when reached, indicates that preventive or corrective maintenance is required.  Within the main steam system performance monitoring plan, there was an action plan established at a specific TPT, which required notification of the shift manager to consider plant shutdown in accordance with the limits established in operations procedure HC.OP-SO.SN-0001, Nuclear Pressure Relief and Automatic Depressurization System Operation (controlled copy), Attachment 2.  The inspectors reviewed Attachment 2, and noted that it established unique SRV TPT shutdown limits for each 2-stage SRV.  However, the TPT limits were based on calculations that PSEG had previously identified to be inaccurate, as described in 2005 evaluation 70049218 and 2014 EQACE 70168360.  The inspectors questioned the adequacy of an action plan and procedure limits based on calculations with known inaccuracies.  In response, PSEG wrote NOTF 20836010 to evaluate any necessary changes to the monitoring plan and operations procedure.  Establishing proper SRV action plans is important, because industry operating experience (OE) indicates that excessive SRV leakage can potentially result in a plant transient or challenge critical safety functions.   Therefore, the inspectors determined that PSEG was not in compliance with ER-AA-2003, steps 4.2.2 and 4.4.3, because PSEG’s SRV performance monitoring plans did not identify appropriate SRV TPT values to detect critical leakage degradation and establish an adequate action plan in anticipation of exceeding action levels.   Corrective Actions:  PSEG’s corrective actions included performing a maintenance outage on March 28, 2019, to replace the ‘H’ SRV pilot and main valves, performing a root cause evaluation (RCE) 70206428 to evaluate repeat elevated main seat leakage on the ‘H” SRV.
 Corrective Action References:  20748846, 20789878, 20806034, 20814836, 20806034, 20818407*, 20819899*, 20823472*, 70206428, 70205765 and 70205995 Performance Assessment:   Performance Deficiency:  The inspectors determined that PSEG’s SRV performance monitoring plans did not identify appropriate SRV TPTs to detect critical leakage degradation, and did not establish an adequate action plan in anticipation of exceeding action levels, in accordance with ER-AA-2003, steps 4.2.2 and 4.4.3.  

 Screening:  The inspectors determined the performance deficiency was more than minor, because it was associated with the Human Performance attribute of the Initiating Events cornerstone and adversely affected 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, the inspectors determined that not adequately monitoring and analyzing SRV performance during conditions of elevated TPT and leakage affected PSEG’s ability to limit likelihood of an events such as spurious SRV opening; and PSEG’s ability to limit the likelihood of challenging critical safety functions such as suppression pool cooling and SRV pressure relief at the Technical Specification setpoint.  

 Significance:  The inspectors assessed the significance of the finding using Appendix A, “The Significance Determination Process (SDP) for Findings At-Power.”  

 Cross-Cutting Aspect:  P.5 - Operating Experience:  The organization systematically and effectively collects, evaluates, and implements relevant internal and external operating experience in a timely manner. P.5 - OE: The organization systematically and effectively collects, evaluates, and implements relevant internal and external OE in a timely manner.  This finding, in accordance with IMC 0310, has a cross-cutting aspect in the Problem Identification and Resolution area associated with Operating Experience, in that PSEG did not systematically and effectively collect, evaluate, and implement relevant internal operating experience in a timely manner.  Specifically, PSEG’s main steam performance monitoring plan did not implement relevant internal operating experience to effectively monitor and analyze critical leakage degradation prior to operation with elevated ‘H’ SRV TPT in 2018 and 2019.  For example, and PSEG identified in 2005 and 2014 that SRV TPT and leak rate calculations were not accurate, and used an ACM to calculate leak rates in 2014, but did not incorporate these learnings into the system monitoring plan. (P.5) Enforcement:  Inspectors did not identify a violation of regulatory requirements associated with this finding.

Observation:  Missed opportunities associated with the ‘H’ safety relief valve (SRV) and its discharge line vacuum breaker (VB)  

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The inspectors identified the following missed opportunities associated with the ‘H’ safety relief valve (SRV) and its discharge line vacuum breaker (VB):  ‘H’ SRV monitoring and CAP evaluation missed opportunities: o PSEG did not download and graph SRV TPT data from operating Cycle 21 (November 2016 through April 2018), which was needed to properly trend the recorder data during periods of elevated 'H' SRV tailpipe temperature (20819899). o 2019 RCE 70206428, and 2014 Equipment Apparent Cause Evaluation (EQACE) 70168360, stated that 2014 was the first occurrence of ‘H’ SRV main seat leakage, but missed an opportunity to include ‘H’ SRV leakage evaluated in 2011 RCE 70119769. o 2019 RCE 70206428 confirmed a previous NRC observation that 2014 EQACE 70168360 cause determination, performed in response to ‘H’ SRV leakage, was not supported with adequate technical rigor (20803213).
 

‘H’ SRV vacuum breaker missed evaluation opportunities: o PSEG did not consider the ‘H’ SRV vacuum breaker as a potential source of elevated drywell leakage during periods of ‘H’ SRV leakage and condensate induced water hammer in operating cycle 22, after the vacuum breaker was found by to be failed open during preventive maintenance in the spring of 2018 refueling and maintenance outage (20818407 and 20821310). o PSEG did not update the ‘H’ SRV failed-open vacuum breaker CAP evaluation in a timely manner once results from the failure analysis were obtained (20823472). 

The inspectors did not identify that any of the above observations would be considered more than minor performance issues.