I was in a phone meeting with at least two NRC region III officials yesterday, the inspectors boss and a regional equipment specialist.
My pitch is the cosby SRVs have worked flawlessly for at least a decade. I actually might have added pressure in and around 2003, that the current SRVs was defective in 2003 and that is why they got the Crosby in them today. They had a host of leaking and valves with operational problems. See the docket on my comments in and around 2003. I believe this is when they went to the cosby valves.
Pressure setpoint drift problems: Technical Specification violations
Unit 1
LER-2018-003-01 (2 vlvs failed test)
Unit 2
LER-2017-002-02 (2 vlvs failed test
LER-2017-004-02 (2 vlvs failed test)
So they have been working perfectly till 2015. This isn't a one plant facility...its a two plant facility. Then unit 1 had two SRV's setpoint drift problem out of 13 SRVs. Plant 2 began having problem in about 2017 with two valves failing teck specs and then again in 2018 with two failing again on setpoint drift. My take is all of a sudden in 2015 setpoint drift failures showed up ending with 6 failed test, albeit it failed by just a few psi. All found failing for unknown reasons. The NRC's take is the laSalle discovered defected and corrected the problem like in 2015. I came back with, "well, it seems the corrective actions didn't work in 2015, as we had a another failure 2017. And the corrective actions in 2017 didn't work also as we had another failures of two in 2018. So out of three LERs, with got 6 valves that failed for unknown reason. The NRC could throw at LaSalle a expensive route cause analysis on the failed SRVs, but they don't have a good enough reason for as yet. I thought that would be a good idea as it would send a message to LaSalle and the rest of the industry. I told them I thought we had reason to suspect we got vendor testing paperwork falsification issues going on. Out of three testing cycles, we got three LERs describing two failed test each. Finding exactly two failed test over three cycles seems like wining the $800 million dollar lottery to me. I reminded the NRC I think the testing vendors can make the testing result sing to any tune of the licensees.
NRC officials poorly trained on SRV operations and maintenance issues throughout the industry precipitated by the NRC's poor documentation of historical operation and maintenance. This poor historically documentation, like some kind of repetitive 2 year industry notification, leads to the effect of inadequate training on reactor safety equipment to inspectors and within the senior leadership of the NRC. I believe this effects more than safety relief valve issues.
Update May 12
I got a call yesterday afternoon from Allegations Sara that new information has just come in and the agency wants me to hear it. I got a tele conference with a few NRC officials and the licensee this morning at 9:30 am. That is why I am looking over this article this morning. Bells are ringing when the NRC says they got new information they want me hear and maybe the license will be in the meeting. Is this coming from the new US House election?
***reposted from 2/20
***Reposted from 2/19
NRC search for safety relief valve LERS for the last ten years
Unit 1 Cosby LERs
Licensee Event Report 2018-003-01, Two Main Steam Safety Relief Valves Failed lnservice Lift Inspection Pressure Test
These Below LER are not into the system.
During the February 2015 Unit 2 refueling outage L2R15, two main steam safety relief valves (SRV) did not pass TS Surveillance Requirement 3.4.4.1 and lnservice Testing Program lift pressure requirements. Both SRVs lifted below their expected lift pressures and were replaced during the outage. A failure analysis was conducted by a vendor testing laboratory, but the cause for the valves lifting below their set-point was indeterminate.
LER Unit 2 374-2017-004-01 : During the February 2017 Unit 2 refueling outage, two main steam safety relief valves (SRV) did not pass TS Surveillance Requirement 3.4.4.1 and lnservice Testing Program lift pressure requirements. Both SRVs lifted below their expected lift pressures and were replaced during the outage. A failure analysis was conducted by a vendor testing laboratory, but the cause for the valves lifting below their set-point was indeterminate.
LER Unit 2
SRV 1 B21-F013U
1 B21-F013U
Unit 2 LERs
Licensee Event Report 2017-004-02, Two Main Steam Safety Relief Valves Failed lnservice Lift Inspection Pressure Test
SRVs 2B21 ·F013C
2B21·F013L
Licensee Event Report 2015-002-00, Two Main Steam Safety Relief Valves Failed Inservice Inspection Pressure Test
SRV 2B21-F013S
2821-F013M
***I talked to Sara of Allegations and then to two inspectors at the plant. These two inspectors couldn't believe a utility would routinely enters LCOs over SRV lift setpoint drift inaccuracies, a required shutdown over disc and seat corrosion bonding if known, are required to fix the problem or submit a license amendment request to change TS. I told these guys plants like Hope Creek and Pilgrim routinely with SRVs, either refurnish the valves on site or replace the refurbished valves from a vender. These is utterly no necessity of fixing the latent problems like corrosion bonding. The NRC decided these setpoint drift repeated problems violated tech specs and are defined as safe on a whim. I found these inspectors light on training surrounding SRVs, Tech Specs and problems with SRVs.
Mike, the utilities only has two choices here with this problem. These guys are so naïve and poorly trained on TS and SRV problems in the industry. I said, these plants regularly go into a LCOs over the SRVs.
***Everything is deregulation. Granted they failed Tech Specs by a small amount. These are Crosby valves which have a good reputation as far as I can see. But if they were up at power and discovered a LCO, they would have had to shutdown. This penalty is supposed to get them to fix or replace the valves. They seem to not have the same problem with Target Rock valves seat and disc sticking together...corrosion bonding.
You notice, they have no idea why the valves failed?
The valves pressure set point test probably started out at plus or minus 1% many years ago. After troubles, they relaxed the testing requirements to plus or minus 3% that needed a LAR. Now in the future, its going to be plus or minus 5%. They are going to plus or minus 5% on the target rock relief valves. I think this is dangerous behavior, just repetitive relaxing requirements because of component failures
LER 2018-003-01
During the February 2018 Unit 1 refueling outage, two main steam safety relief valves (SRV) did not pass Technical Specification (TS) Surveillance Requirement 3.4.4.1 and lnservice Testing (IST) Program lift pressure requirements. Both SRVs lifted below their expected lift pressures. On February 27, 2018, SRV 1B21-F013R was required to lift within plus or minus three percent of 1205 psi (i.e., 1205 psi plus or minus 36.1 psi), but lifted at 1167 psi. On February 27, 2018, SRV 1 B21-F013U was required to lift within plus or minus three percent of 1150 psi (i.e., 1150 psi plus or minus 34.5 psi), but lifted at 1109 psi.
Multiple test failures are reportable under 1 O CFR 50. 73(a)(2)(i)(B) as an operation or condition prohibited by the plant's TS. Both SRVs lifted prior to their expected lift pressures, which is conservative regarding maintaining reactor pressure vessel over-pressure limits. Both SRVs were replaced during the outage. A failure analysis was conducted; however, it did not identify a cause for the valves lifting below their expected lift set-points.
LaSalle County Station (LSCS) Unit 1 is a General Electric Boiling Water Reactor with 3546 Megawatts Thermal Rated Core Power.
The main steam safety relief valves (SRVs) are designed to prevent over-pressurization of the reactor pressure vessel (RPV) during transients and abnormal conditions, which protects against a failure of the reactor coolant pressure boundary (RCPB). There are thirteen SRVs installed on the four main steam lines, which discharge near the bottom of the suppression pool to condense the steam through SRV tailpipes that exhaust beneath the suppression pool surface.
CONDITION PRIOR TO EVENT
Unit(s): 1 Date: Reactor Mode(s): 5 Mode(s) Name:
DESCRIPTION OF EVENT
February 27, 2018 Refueling
Time: Power Level:
1520 CST O percent
01
During the February 2018 Unit 1 refueling outage, two main steam safety relief valves (SRV) did not pass Technical Specification (TS) Surveillance Requirement (SR) 3.4.4.1 and lnservice Testing (IST) Program lift pressure requirements. Both SRVs lifted below their expected lift pressures. On February 27, 2018, SRV 1 B21-F013R was required to lift within plus or minus three percent of 1205 psi (i.e., 1205 psi plus or minus 36.1 psi), but lifted at 1167 psi. On February 27, 2018, SRV 1 B21-F013U was required to lift within plus or minus three percent of 1150 psi (i.e., 1150 psi plus or minus 34.5 psi}, but lifted at 1109 psi.
CAUSE OF EVENT
A failure analysis was conducted; however, it did not identify a cause for the valves lifting below their expected lift set-points.
Station operating experience has shown a tendency for a portion of LSCS SRVs to experience minor setpoint drift sufficient to exceed the acceptance criteria of minus three percent over time. A license amendment request (LAA) was submitted to the NRC on February 27, 2018 to revise TS SR 3.4.4.1 to lower the setpoint tolerances for Unit 1 and Unit 2 SRVs. This proposed change would revise the SRV as-found lower tolerances from minus three percent to minus five percent to account for minor SRV setpoint drift in the conservative direction. This proposed change will reduce the unnecessarily restrictive surveillance requirement and will not impact the reliability of the SRVs or adversely impact their ability to perform their safety function. The change will reduce the number of TS SRV surveillance test failures for early lift pressure and preclude the submittal of previously reportable licensee event reports to the NRC due to setpoint drift in the low (conservative) direction...
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