I wonder how long would a rapidly cycling SRV could go on? Could it crack the tailpiece pipe. That would bypass primary containment.
These guy have switched back and forth from the 3rd stage to the 2rd I can't tell what they are doing now. They are shifting to the 3 stage I think. The 3 stage SRVs got Pilgrim in so much trouble.The part 21 thing is Pilgrim's SRVs failure. At 400 psia they can't get the RHR pumps on. I don't understand.One only can imagine if a SRV is cycling anytime -reactor level shrink and swell- how would they know what vessel level is? How long do you think the downstream piping would last with the cycling.I think this all is a analyzed condition or accident... I talked to project manager overseeing this upgrade for about an hour. He says A new IN is coming out on the SRVs. The project engineer says these valves are very troublesome and the NRC is watching anything SRV very closely. I said watching things doesn't do shit, fixing things is the gold standard.The project manager agrees with me the real issue is the licenses can't get any other manufacturer to supply their version of a SRV based in getting sued to the big accident shows up and their SRV was involved...
NRC RAI
In the course of the [May 1, 2018] discussion, SNC described how it developed and performed the MVB low pressure (400 psi), full flow test in response to the prior testing problems addressed in the Part 21 notification. SNC stated the reason that 400 psig was selected for the modified test pressure was that Target Rock had informed them that 400 psig is the lowest pressure at which the valves can be stroked. The NRC staff requests SNC to supplement its April 17, 2018 RAI response to provide that additional information on the docket.
SNC Response to NRC RAI
The low pressure safety relief valve (SRV) main valve body (MVB) test was developed in conjunction with NWS Technologies. The 400 psig actuation requirement was developed through full flow (ungagged) tests at various incremental pressures starting at 50 psig and increasing up to 400 psig. During each test at incremental pressures, MVB disc stroke/travel was measured using the test stand linear variable differential transformer (LVDT). With pressure removed, the MVB was also stroked by hand to validate travel. The goal was to validate full stroke of the MVB disc (2.78-inch or greater) at the lowest pressure while eliminating rapid cycling of the disc. This goal was achieved consistently at 400 psig. At pressures lower than 400 psig, the MVB disc would open, but would either not consistently achieve full stroke or have rapid cycling following the initial stroke. These results have been replicated during 400 psig MVB testing in 2018.
But of course, they have no way to detect the when the setpoint accuracy crosses the tech spec limit. I make the case it could happen early in the cycle, not towards the end.
You know why this came out at this time. The outage is coming up and they expect bad testing news with the SRVs.
You know why this came out at this time. The outage is coming up and they expect bad testing news with the SRVs.
Think about it, they loosened the setpoint from +/- 1 to + - 3 in 1999?May 9, 2018HOPE CREEK GENERATING STATION UNIT 1 – INTEGRATED INSPECTION REPORT 05000354/2018001Observation 71152 Annual Follow-up of Selected issues Review of PSEG’s corrective actions, and whether there was an associated violation of NRC requirements for repetitive lift setpoint test failures for main steam safety relief valves.:The inspectors performed an in-depth review of PSEG's evaluation and corrective actions associated with main steam safety relief valve (SRV) setpoint drift issues at Hope Creek. Specifically, since the Hope Creek technical specifications were revised in
Think about it, in 10 of 11 cycles they failed to shutdown when required.1999 to increase the SRV as-found lift setpoint to +/- 3 percent, SRV testing at Hope Creek has resulted in one or more SRVs exceeding the technical specification allowable
Other plants have implied the corrosion bonding occurs on new metal surfacing, meaning, if it was aged, it wouldn't occur.as-found lift setpoint acceptance criteria in ten of 11 post-operating cycles. The setpoint drift has been attributed to “corrosion bonding,” and this phenomenon
Did the change fix the problem or facilitate the unreliability problems?typically affects the initial SRV actuation. The inspectors also reviewed PSEG’s actions since the most recent test results were reported (Cycle 20), where ten of 14 SRVs exceeded their technical specification allowable lift setpoints. This inspection was conducted onsite in July 2017, and continued from the NRC Region I office until its conclusion in the first quarter of 2018.The inspectors assessed PSEG's problem identification threshold, problem analysis, extent of condition reviews, operating experience, compensatory actions, and the prioritization and timeliness of their corrective actions to determine whether PSEG staff were appropriately identifying, characterizing, and correcting problems associated with this issue, and whether the planned or completed corrective actions were appropriate. The inspectors compared the actions taken to the requirements of PSEG’s CAP, 10 CFR Part 50, Appendix B, and technical specifications. The inspectors reviewed associated documents and interviewed engineering personnel to assess the adequacy of PSEG’s actions. The inspectors also reviewed PSEG’s classification and certification of SRV sub-components to determine whether the components were of the proper safety classification. Finally, the inspectors reviewed PSEG’s technical evaluations related to the overpressure protection capability and the structural integrity of associated pipe and supports considering the as-found SRV test results.History and Operating Experience:Hope Creek has 14 safety-related main steam SRVs that provide reactor pressure vessel overpressure protection and an automatic/manual depressurization function. Hope Creek technical specification 3.4.2.1, “Safety/Relief Valves,” requires that 13 of the 14 SRVs be operable with the specified code safety valve function lift setting (+/- 3 percent).The inspectors noted these 2-stage SRVs, manufactured by Target Rock, have been subject to setpoint drift, typically in the increased setpoint direction at a number of boiling water reactor nuclear power plants. The NRC approved a change to the Hope Creek technical specifications in 1999 to increase the SRV as-found lift test setpoint
It is 18 years later, these are very problematic valves, just ask Pilgrim, and they haven't updated B55. Who says it is solve too?tolerance from +/-1 percent to +/-3 percent as a result of insights (circa late 1970’s) from NRC Generic Safety Issue B-55, “Improved Reliability of Target Rock Safety Relief Valves” and from the Boiling Water Reactor Owners Group. The specific issue associated with the 2-stage SRV was a corrosion bonding problem, which occurs due to bridging oxides created between the pilot disc surface and the pilot valve body disc seating surface during service. The corrosion bonding phenomenon has resulted in the valve lifting at a higher pressure, failing to meet its setpoint criteria during the first lift attempt, but typically, lifting satisfactorily at its nominal setpoint during consecutive tests (after the corrosion bond is broken during the initial lift).In August 2000, the NRC notified the industry via NRC Regulatory Issue Summary 2000-
And now we got a new problem per pilgrim: Test stand damage. Meaning, they have no way to test for test stand damage until after the accident or only after the cycle. They got no way to test for this kind of damage at the beginning of the cycle.12, that the NRC considered Generic Safety Issue B-55 to be resolved. Specifically, for the 2-stage SRVs, the primary cause of the upward setpoint drift problem was determined to be corrosion bonding of the pilot valve disc to its seat. The Regulatory Issue Summary identified three modifications that were found to improve performance:• installation of ion beam implanted platinum pilot valve disks;• installation of Stellite 21 pilot valve disks; and• installation of additional pressure actuation switches.The Regulatory Issue Summary further indicated that there had been significant improvements in the performance of both the 3- and 2-stage SRVs, and that plant owners and the Boiling Water Reactor Owners Group were continuing to evaluate further enhancements. Subsequently, the NRC issued Information Notice 2006-24 to communicate additional operating experience insights associated with SRVs that continued to exceed the TS lift setpoint tolerance. The Information Notice documented
Yea, because of the vast majority of the reliefs show damage during the testing.that, while the individual events were within the American Society of Mechanical Engineers (ASME) tolerance limit or within accident analyses, there remained a number of reported events of valve setpoint issue at various plants.While technical specification 4.4.2.2 requires that at least half of the SRV pilot stage assemblies be removed and set pressure tested, the inspectors determined PSEG staff
But none of them worked. It is only gotten worst with a recent step increase in failures?typically performed as-found lift tests on all 14 SRV pilot valves each refueling outage due to the past test results. The inspectors noted the setpoint tests were conducted at a remote, certified testing facility after the SRV pilot valves were removed during refueling outages. During the last six operating cycles, the number of test failures were as follows (all 14 SRV pilot valve assemblies tested each time):Operating Cycle No. of SRVs beyond +/- 3 percent test acceptance criteria 15 6 16 6 17 6 18 5 19 10 20 10Corrective Actions:The inspectors determined PSEG staff considered and implemented several corrective
Who even says some of these activities were designed to fix the valves. I say it was just a half ass fix to by time. Much of this was just experimentation within a nuclear plant. Say the first exotic coating, they are required to prove the fix worked. They are supposed to put these in a test stand that mimics the condition in the reactors before plant installation. No suppresses. The whole process of putting exotic coatings on the pilot valves is been one failure after another one. Why hasn't the process that put these valve coatings the SRVs as faulty.actions and mitigation strategies intended to improve SRV performance. Some of these activities included applying a platinum coating to the pilot valve discs (in 1997), increasing the TS as-found setpoint tolerance acceptance criteria (in 1999), and
But only led to a step spike in failures.replacing the platinum coated pilot valve discs with a solid Stellite 21 material (in 2006) believed to be less susceptible to corrosion bonding. PSEG staff also conducted several investigations to determine whether other factors contributed to the problem (evaluated critical pilot disc and seat dimensions, evaluated SRV insulation installation and placement, and evaluated SRV vibration after an extended power uprate was implemented).PSEG had previously planned to install 3-stage Target Rock SRVs as an action to eliminate the corrosion bonding issue with the 2-stage SRVs. Specifically, they had planned on installing several 3-stage Target Rock SRVs in May 2015, however, several months prior to the start of Hope Creek’s refueling outage, there was significant operating experience with the replacement 3-stage SRVs (at the Pilgrim Nuclear Power Plant). A 10 CFR Part 21 Report documented this substantial safety hazard was submitted to the NRC by Target Rock on May 1, 2015, describing this issue. Subsequently, Target Rock initiated efforts to re-design the 3-stage SRV to eliminate this problem.In addition to the above corrective actions intended to reduce the likelihood of
By why does it take decades for the owners group to get their work done.corrosion bonding, PSEG conducted several evaluations to determine whether plant specific configuration or design issues contributed to setpoint drift or amplification of the corrosion bonding phenomenon, and continued to work with the Boiling Water
How can you think of these valves as reliable after all the failed redesigns spanning decades?Reactor Owners Group to further investigate the 2-stage SRV performance issues. During this inspection, the inspectors noted that PSEG staff planned additional corrective actions, to be implemented at the next refueling outage (Spring 2018). Specifically, PSEG staff planned to 1) re-evaluate the platinum coating process of the pilot valve disc for the existing 2-stage SRVs, and 2) to procure and install the recently
They are already exceeding safety limits...re-designed 3-stage Target Rock SRV in a phased approach. PSEG was engaged in discussions with Target Rock regarding the re-designed 3-stage SRV, and how the re-design is expected to resolve the substantial safety hazard identified in Target Rock’s May 1, 2015, letter to the NRC.Evaluation of As-Found Condition and Current Operability:Relative to the ten of 14 SRVs that did not meet test acceptance criteria at the end of Cycle 20, PSEG staff performed two separate technical evaluations. The first evaluation assessed the reactor pressure vessel over-pressure function of the SRVs, the impact to associated safety-related systems (e.g., HPCI), and reactor fuel impact. The second technical evaluation considered the increased stress impact on the SRV downcomer piping (SRV discharge to torus), supports, spargers and torus loads to determine whether the SRVs and connected pipe remained capable of performing their intended function to direct steam to the torus for “quenching.” In particular, the second evaluation assessed two specific SRVs (A and F), which exhibited as-found lift setpoints that exceeded the maximum allowable percent increase (MAPI) value. The inspectors determined the MAPI value is the upper limit associated with each SRV based on the SRV discharge line design allowable stresses; and each MAPI is unique to specific SRV discharge lines (based on configuration, supports, etc.). Because two SRVs exceeded
Basically the ASME is a private code company and most of the limits are paid by the utilities.the MAPI in the most recent operating cycle (Cycle 20) and one exceeded the MAPI in each of the two prior cycles, PSEG staff evaluated prior operability/functionality of the SRVs (in the aggregate) using Level D Service Limits to show that the SRVs could have fulfilled their safety function. PSEG staff’s evaluations concluded that the SRVs remained capable of performing their intended functions.The inspectors, with the assistance from NRC technical staff in the Office of Nuclear Reactor Regulation, reviewed both technical evaluations and concluded there was reasonable assurance the SRVs remained capable of performing their intended functions. However, with respect to the second technical evaluation related to downcomer pipe and supports, design margin was reduced by the application of Level D Service Limits. Specifically, consistent with guidance to NRC inspectors in NRC IMC 0326, “Operability Determinations and Functionality Assessments for Conditions Adverse to Quality or Safety,” PSEG staff evaluated the main steam and SRV piping and supports using the criteria in Appendix F of Section III (Division 1) of the ASME Code.
Based on all the failed correctives action taken to date, you can predict the new corrective actions fail again.This Appendix uses Level D Service Limits to demonstrate equipment pressure retaining capability. The inspectors noted that while these limits are intended to demonstrate the pressure retaining capability of SRV downcomer pipes and components, Level D Service Limits allow for the possibility of deformation and the potential that component repair may be required. The inspectors concluded that PSEG’s post trip reviews and the CAP provided processes to ensure downcomer pipe, components, and supports would be evaluated if SRVs initially lifted higher than the specified setpoint bands.The guidance provided in IMC 0326 indicated that licensees “may use these criteria until compliance with current licensing basis criteria can be satisfied (normally the next refueling outage).” The inspectors observed PSEG staff applied Level D Service Limits in technical evaluations over several operating cycles. While repetitive application of Level D Service Limits is not typical, the inspectors concluded that, in this instance, PSEG’s completed corrective actions and planned actions involving replacement of all
What evidence does the NRC have that this is not going on at the other applicable licensees. They are all do the exact same thing. But the NRC pays a little coy, not implicating the other bad actors.SRVs over the next few operating cycles with an improved design were reasonable and appropriate, considering SRVs remained capable of performing their intended safety functions.Relative to current operability of the installed SRVs, PSEG staff stated that they consider the installed SRVs to be operable because the SRVs were tested to within the required +/- 1 percent (as-left) tolerance prior to installation. They further stated that there was no method available to assess the setpoint of the valves during the operating cycle (that the valves are removed from the plant prior to testing). And, if the valves do not meet the setpoint criteria during post-operating cycle testing, the impact on plant safety is assessed. Finally, PSEG staff stated that, in all cases, the as-found set-point of the valves were found to support the specific safety function to protect the reactor pressure vessel from over-pressurization. The inspectors acknowledged PSEG’s position
The trouble is this is a private group with no transparency. These kinds of groups were designed to restrict transparency.that direct evidence is not available to indicate which, how many, and to what degree, SRVs may have drifted during an operating cycle. However, the inspectors noted that PSEG staff did not document their rationale as to which steps in their operability procedure applied to justify not entering the operability process.Summary:There have been repeated SRV lift setpoint test failures at Hope Creek, attributed to a generic issue with Target Rock 2-stage SRVs resulting in corrosion bonding between the pilot disc and seating surfaces. PSEG staff has been active with the Boiling Water Reactor Owners Group in evaluating SRV setpoint drift issues, and has an auditable
The licensees have been calling setpoint drift inaccuracy in the LERs for years, as you can't prove we even crossed the tech spec violation because it is not seeable. These guys are so crooked.history of their implementation of corrective actions, specifically intended to address their chronic SRV setpoint drift issue. Notwithstanding their efforts, PSEG staff has been unsuccessful in resolving this issue. They are planning to implement additional actions during the next refueling outage, including the application of a platinum coating of the pilot valve disc and a phased approach to install a recently redesigned 3-stage Target Rock SRV. Additional discussion on this issue is documented in Inspection Results, 71153, Unresolved Item, in this report.Unresolved Item (Open)Concern Regarding As-Found Values for Safety Relief Valve Lift Setpoints Exceed Technical Specification Allowable Limit URI 05000354/2018001-0271153 Follow-up of Events and Notices of Enforcement DiscretionDescription:On October 22, 2016, PSEG staff received results that the as-found setpoint tests for the main steam SRV pilot stage assemblies had exceeded the lift setting tolerance prescribed in technical specification 3.4.2.1. Specifically, ten of the 14 pilot stage assemblies tested experienced drift beyond the +/- 3 percent tolerance permitted by technical specification 3.4.2.1. PSEG staff concluded that the cause of the setpoint drift was attributed to corrosion bonding between the pilot disc and seating surfaces, and that is consistent with industry experience. This condition was reportable under 10 CFR 50.73(a)(2)(i)(B) as any operation or condition which was prohibited by the plant’s technical specifications.Based on a review of the Cycle 20 test results of the main steam SRV pilot stage assembly setpoint tests, and the nature of the predominant failure mechanism
This paragraph is all absolutely BS(corrosion bonding), the inspectors concluded that an unacceptable number (greater than one) of SRVs likely and reasonably became inoperable at some indeterminate time during the operating cycle. As documented in Inspection Results, 71152, Observations in this report, there is a history of SRV lift setpoint test failures due to a long-standing, generic issue with Target Rock 2-stage SRVs. In particular, PSEG staff has been active with the Boiling Water Reactor Owners Group in evaluating SRV setpoint drift issues, and has an auditable history of their implementation of corrective actions, specifically intended to address their chronic SRV setpoint drift issue. Notwithstanding their efforts, PSEG staff has been unsuccessful in realizing an improvement in SRV performance in this area. PSEG staff has elected to implement additional corrective actions beginning the spring 2018 refueling outage.Specifically, they plan to reinstitute platinum coating of the pilot valve disc, and they plan to install the recently redesigned 3-stage Target Rock SRV in a phased approach.While this issue has not been effectively resolved, PSEG’s post-test evaluations have demonstrated that, in their as-found condition, the SRVs would have satisfactorily performed their intended safety function (i.e., mitigating the consequences of a postulated accident); and therefore, was of low safety significance.Additional NRC review is necessary to determine the appropriateness of PSEG’s corrective actions to date, given the corrective action options available, and whether there was an associated violation of NRC requirements in addition to the consequential violation of technical specification 3.4.2.1.Planned Closure Actions: The NRC is continuing a review of the generic issue with the 2-stage Target Rock SRVs and the associated safety significance. The results of this review will be considered in determining the appropriateness of PSEG’s corrective
actions to date and whether an associated violation of NRC requirements existed, as well as the characterization of the consequential violation of technical specification 3.4.2.1.PSEG Actions: Specific to the fall 2016 SRV lift setpoint test results, all 14 of the SRVs were refurbished and adjusted as necessary; and were all tested and demonstrated to meet the required +/- 1 percent as-left tolerance prior to installation. PSEG also planned additional corrective actions, to be implemented during the spring 2018 refueling outage, including: 1) to re-evaluate the platinum coating process of the pilot valve disc for the existing 2-stage SRVs, and 2) to procure and install the recently re-designed 3-stage Target Rock SRV in a phased approach. Finally, PSEG communicated with the SRV vendor concerning the re-design of the 3-stage SRV following a prior identification (May 2015) of a substantial safety hazard to ensure that the re-design addressed the identified problems.Corrective Action References: Notification/Order 20747318, 20772038, and 80110848This review closes LER 05000354/2016-003 and Supplemental LER 05000354/2016-003-01
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