Hope/Salem Is A Mess: Their's And The Nation's Flex Stratigy

May 9, 2018 theres

SUBJECT: HOPE CREEK GENERATING STATION UNIT 1 – INTEGRATED INSPECTION REPORT 05000354/2018001

Implementing Procedures for Beyond Design Basis FLEX Mitigating Strategies Not Followed Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems  

 Green  FIN 05000354/2018001-01 Closed H.5 – Human Performance – Work

Each violation should be treated separately. Then fine or worst the hell out of them for each violation. Honestly, in this bundle all violations into one generic single violation system, you have no idea how many violation are in the industry. It is just not disciplining away from a chaotic and erratic site. It sends no messages to the other plants to keep these plants orderly.

The big inexpensive and flaw in the system the flex system should have been included into a licensing bases system.

These components are  

Management 71152 A Green finding (FIN) was identified by the inspectors for multiple examples of PSEG not following the station specific procedures that implement the Salem and HCGS Final Integrated Plans for Beyond Design Basis FLEX Mitigating Strategies, EM-SA-100-1000 and EM-HC-100-1000, respectively.  Specifically, since compliance with the FLEX order was met on November 10, 2016, PSEG did not follow the common PSEG fleet PM Process and diesel fuel oil testing program procedures, MA-AA-716-210, CY-AB-140-410, and SC.OP-LB.DF-0001 for the annual fuel oil sampling of FLEX equipment.  In addition to this, between December 6, 2017, and March 8, 2018, PSEG did not follow site specific procedures for FLEX equipment unavailability and mitigation capability protection in accordance with these procedures, OP-HC-108-115-1001 and OP-SA-108-115-1001, Operability Assessment and Equipment Control Program. Description:  PSEG is committed to comply with NEI 12-06, Diverse and Flexible Coping Strategies (FLEX) Implementation Guide, and NRC Order on Mitigation Strategies, EA-12-049.  

FLEX Equipment Preventive Maintenance

Section 11.5.2 of NEI 12-06 states, in part, that portable equipment that directly performs a FLEX mitigation strategy for the core, containment, or spent fuel pool (SFP) should be subject to maintenance and testing guidance provided in Institute of Nuclear Power Operations (INPO) AP 913, Equipment Reliability Process, to verify proper function.  The maintenance program should ensure that the FLEX equipment reliability is being achieved.  Standard industry templates (e.g., EPRI) and associated bases will be developed to define specific maintenance and testing.

In complying with NRC Order EA-12-049, PSEG implemented EM-HC-100-1000 and EM-SA-100-1000.  In Sections 2.18.7 of these procedures it states that FLEX mitigation equipment is subject to initial acceptance testing and subsequent periodic maintenance and testing to verify proper function.  FLEX diesel generators and pumps are in PSEG’s fleet common PM process, MA-AA-716-210, which defines periodic testing and maintenance and follows the PM template requirements in EPRI’s Preventive Maintenance Basis for FLEX Equipment – Project Overview Report (EPRI Report 3002000623), dated September 2013.  

The inspectors reviewed a number of recent equipment and PM issues at PSEG associated with the HCGS, Salem, and fleet common FLEX diesel generators and pumps.  During the review, the inspectors found that this equipment is scheduled per PSEG’s PM program and, in accordance with EPRI guidance, should be tested every 6 months and the fuel oil should be sampled every 12 months.  Based on the inspector’s requests and questions related to the FLEX fuel oil cloud point and sample results, PSEG found that the initial fuel oil samples for all of the FLEX diesel generators and pumps were either never taken (at Salem) or not analyzed (at HCGS).  Because of this, the inspectors determined that since compliance with the FLEX order was met on November 10, 2016, PSEG has not followed the common PSEG fleet PM Process and diesel fuel oil testing program procedures, MA-AA-716-210, CY-AB-140-410, and SC.OP-LB.DF-0001, for the annual fuel oil sampling of FLEX equipment.

FLEX Equipment Unavailability and Protection

Section 11.5.3 of NEI 12-06 states, in part, that the unavailability of equipment and applicable connections that directly performs a FLEX mitigation strategy for the core, containment, and SFP should be managed such that risk to mitigating strategy capability is minimized.  The unavailability of installed plant equipment is controlled by existing plant processes such as the technical specifications. 

PSEG’s FLEX equipment allowable outage times and required actions for equipment unavailability are maintained in site specific operations procedures OP-HC-108-115-1001 and OP-SA-108-115-1001 in order to meet the requirements in NEI 12-06.

For the three site FLEX diesel pumps (H1FLX-10-P-500 (HCGS)); SCFLX-1FLXE18 (Salem); C1FLX-1FLXE42 (back-up common to Salem and HCGS), a loss of two of three represents a loss of a FLEX mitigation capability.  OP-HC-108-115-1001 and OP-SA-108-115-1001 state, in part, that when installed equipment which supports FLEX strategies becomes unavailable, then the FLEX strategy affected by this unavailability does not need to be maintained during the unavailability.  The required beyond design basis (BDB)/FLEX equipment may be unavailable for 90 days provided that the site BDB/FLEX capability (N) is met. If the site BDB/FLEX capability is met but not protected for all of the sites’ applicable hazards (flood, earthquake, high winds from hurricane or tornado, or local intense precipitation), then the allowed unavailability is reduced to 45 days.

On February 19, 2018, PSEG documented NOTF 20787557 for the FLEX diesel back-up pump common to Salem and HCGS (C1FLX-1FLXE42) failure to start that was not returned to an available condition until March 8.  A NOTF (20783115) dated December 6, 2017, 75 days earlier, documented a failure to start with the same common FLEX diesel pump.  The inspectors noted that no actions were taken to resolve the December issue other than attempting to start the pump multiple times over 12 days until the pump started on December 18, 2017.  At this point, PSEG declared the pump available without performing any corrective maintenance or documenting any basis for the pump being available.  The inspectors questioned PSEG about the time period mentioned above and how PSEG’s BDB/FLEX capability was protected during that time for all of the applicable site hazards as all three pumps are located in outside FLEX storage areas at ground level.  Because of this, the inspectors determined that PSEG did not follow site specific procedures for FLEX equipment unavailability and mitigation capability protection for this common diesel pump between December 6, 2017, and March 8, 2018 (92 days).

Based on all of the information above, the inspectors determined that there were multiple examples of PSEG not following the station specific procedures for FLEX Mitigating Strategies.  Specifically, PSEG did not follow the common PSEG fleet PM Process and diesel fuel oil testing program procedures for the annual fuel oil sampling of FLEX equipment, or site specific procedures for FLEX equipment unavailability so that equipment issues were appropriately tracked and adequately protected to allow it to be unavailable for greater than 90 days when availability should have been limited to less than 45 days.
11

Corrective Actions:  PSEG’s corrective actions for the above issues included obtaining fuel oil samples from all the Salem, HCGS, and common FLEX equipment onsite and analyzing the samples to ensure the fuel oil quality remained adequate.  PSEG also replaced the starting solenoid on the common FLEX diesel pump that failed to start and returned the pump to an available status on March 8, 2018, 92 days after it first became unavailable.

Corrective Action References:  20787557, 20783115, 60138024, 20787861, 20787862, 20787863, 20787879, 20787880, 20787881, 20787882, 20787883, 20787884, 20791977, 20791974, and 80122006. Performance Assessment:

Performance Deficiency:  PSEG’s station specific procedures EM-SA-100-1000 and EM-HC-100-1000 implement the Salem and HCGS FLEX Mitigating Strategies, which includes FLEX equipment PM and unavailability.  The inspectors determined that since January 2017, there were multiple examples of PSEG not implementing these procedures utilizing existing procedures for the PM process, diesel fuel oil testing or operability assessment and equipment control, and that this represented a performance deficiency.

Screening:  The performance deficiency is more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).  The inspectors also reviewed IMC 0612, Appendix E, “Examples of Minor Issues,” and found it was sufficiently similar to Example 3.k, in that significant programmatic deficiencies were identified that could have led to worse outcomes.

Significance:  Issues identified concerning FLEX are evaluated through a cross-regional panel using IMC 0609, Appendix M, “Significance Determination Process Using Qualitative Criteria,” as informed by Appendix O, “Post Fukushima Mitigation Strategies Significance Determination Process (Orders EA-12-049 and EA-12-051)” (ML16055A351).  The finding was determined to be of very low safety significance (Green) because the inspector answered “no” to the five questions in the draft Appendix O.  Specifically, this condition was not associated with SFP level instrumentation required by NRC Order EA-12-051 and did not result in a complete loss of function to maintain or restore core cooling, containment pressure control/heat removal and/or SFP cooling capabilities.

Cross-Cutting Aspect:  This finding has a cross-cutting aspect in the area of Human Performance, Work Management, because PSEG did not implement a process of planning, controlling, and executing work activities such that nuclear safety was the overriding priority and did not identify and manage the coordination of different Salem, HCGS and PSEG common work groups or job activities.  Specifically, PSEG did not execute work activities associated with the FLEX fuel oil sampling or corrective maintenance activities on FLEX equipment that would ensure that equipment’s reliability and availability. (H.5) Enforcement:  This finding does not involve enforcement action because no violation of regulatory requirements was identified.  Because the finding does not involve a violation of regulatory requirements and has very low safety significance, it is identified as a finding.

Observation 71152  Annual Follow-up of Selected issues Review of Recent FLEX Equipment and Preventive Maintenance Issues

The inspectors noted the following observations during the review:

1. PSEG is inconsistent when conducting CAP screening for NOTFs involving FLEX equipment failures in accordance with procedure LS-AA-120, Issue Identification and Screening Process.  NOTFs 20775917 and 20766130 for FLEX diesel generator (H1FLX-10-G-2026) and pump (H1FLX-10-P-500) failures to start were screened as significance level (SL) 4, a non-corrective action program condition (N-CAP), when similar failures to start of a FLEX diesel pump (C1FLX-1FLXE42) in NOTFs 20783115 and 20787557 were screened as SL3, a condition affecting regulatory compliance (CARC).  NOTF 20788124 for the spare FLEX diesel generator (SCFLX-1FLXE10) low engine coolant temperature and determined it to be non-functional, but the NOTF was screened as SL4 instead of SL3.

2. PSEG did not have a process or procedure in place to ensure that the fuel oil used for outdoor FLEX equipment has the required fuel additives to ensure proper operation during cold weather operations.  PSEG documented the inspector’s concern in NOTF 20786860.

3. PSEG did not quarantine and send out for failure analysis a failed FLEX component, the engine control module from a FLEX diesel generator (H1FLX-10-G-2026), identified in NOTF 20775917.  PSEG has initiated NOTFs 20774397 and 20783803 to document delays and a lack of oversight in the failure analysis tracking process.  PSEG has created corrective actions under orders 70196257 and 70197907 to revise ER-AA-230-1004, Failure Analysis Tracking and Reporting by April 2018.

Junk Plant Hope Creek's SRVs: Newest -Same- Explanation as 2016

Update May 18

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... 

The reactor water level is highly susceptible to boiling-not boiling with the SRV in operation(reactor level shrink and swell). Nobody takes into consideration if the valve is in any other position than open or shut. It would be disconcerting if all the water level indication were jumping around without knowing what the real water level was in reactor caused by the cycling SRV.      

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. 

***This is a brand new inspection report on their defective safety relieves. Talky, Talky talky...but never do nothing. Personally I think this is a continuation of the my 2016 complaint surrounding the poor reliability. The issue I got is the per tech  when they got more than one than one SRVs crossing the setpoint band they are required to be shutdown and repair the valves. 13 of 14 reliefs needing to be operable implies there is not much extra relieving capacity.  

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.    

May 9, 2018

HOPE CREEK GENERATING STATION UNIT 1 – INTEGRATED INSPECTION REPORT 05000354/2018001

Observation 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, they loosened the setpoint from  +/- 1 to + - 3 in 1999?  

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

Think about it, in 10 of 11 cycles they failed to shutdown when required.

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

Other plants have implied the corrosion bonding occurs on new metal surfacing, meaning, if it was aged, it wouldn't occur.  

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

Did the change fix the problem or facilitate the unreliability problems?

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-

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?

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

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.

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

Yea, because of the vast majority of the reliefs show damage during the testing.

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 10

Corrective Actions:

The inspectors determined PSEG staff considered and implemented several corrective

But none of them worked. It is only gotten worst with a recent step increase in failures?

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

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.    

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

But only led to a step spike in failures.

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

By why does it take decades for the owners group to get their work done.

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

How can you think of these valves as reliable after all the failed redesigns spanning decades?

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

They are already exceeding safety limits...

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. 

Basically the ASME is a private code company and most of the limits are paid by the utilities.

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

Based on all the failed correctives action taken to date, you can predict the new corrective actions fail again.  

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

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.

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 trouble is this is a private group with no transparency. These kinds of groups were designed to restrict transparency.

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 05000354/2018001-02

71153  Follow-up of Events and Notices of Enforcement Discretion

Description:

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

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. 

(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

This paragraph is all absolutely BS  

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 80110848

This review closes LER 05000354/2016-003 and Supplemental LER 05000354/2016-003-01

2016001: Hope Creek's 1st SRV Inspection Responce To Me

Reposted from 9/30/2017

The questions I posed to the NRC to drive this article is on the NRC's docket.

May 10, 2016

SUBJECT: HOPE CREEK GENERATING STATION UNIT 1 – INTEGRATED INSPECTION REPORT 05000354/2016001

Annual Sample:  Safety Relief Valve Set Point Drift

a. Inspection Scope

The inspectors reviewed PSEG's identification, evaluation, and corrective actions associated with longstanding main steam safety relief valve (SRV) set point drift issues at HCGS.  Specifically, at HCGS, one or more SRVs have exceeded the TS allowable as-found lift set point acceptance criteria in 17 of the 19 operating cycles over the life  of the plant (See Section 4OA3.1 for a review of Licensee Event Report (LER) 05000354/2015-004-01 related to as-found test results from refueling outage 19 (RF19)).  PSEG contracted with NWS Technologies to perform SRV as-found testing, SRV pilot valve assembly inspection and repair, and SRV as-left testing at their offsite facility.

The inspectors assessed PSEG’s problem identification threshold, technical and cause analyses, operating experience (OE) and trend reviews, vendor oversight, and the prioritization and timeliness of corrective actions to evaluate whether PSEG was appropriately identifying, characterizing, and correcting problems associated with these issues and whether the planned and/or completed corrective actions were appropriate.  The inspectors compared the actions taken in accordance with the requirements of PSEG’s and NWS’ maintenance procedures, PSEG’s CAP, 10 CFR 50 Appendix B,  Hope Creek’s TSs, and the Maintenance Rule.  The inspectors interviewed Nuclear Oversight (NOS) and engineering personnel to gain an understanding of potential operational challenges, overpressure protection capability and margin management, NWS performance, planned and completed corrective actions, and SRV performance.  The inspectors also reviewed NWS pilot assembly test and inspection documentation, including quality assurance (QA) acceptance and independent verifications, to ensure that NWS performed activities in accordance with prescribed procedures and industry standards.  In addition, the inspectors performed several walkdowns of SRV related instrumentation (including the control room, the remote shutdown panel, and the alternate shutdown automatic depressurization system panel instrumentation and alarm panels) to independently assess the material condition, operating environment, SRV performance, and configuration control.  [See also NRC Inspection Report 05000354/2012004, Section 4OA2.2, NRC Inspection Report 05000354/2013005, Section 4OA2.6, and NRC Inspection Report 05000354/2015003, Section 4OA2.4 for additional NRC assessment of the Hope Creek SRV issues.]

a. Findings and Observations

No NRC or self-revealing findings were identified.  A licensee-identified violation associated with as-found set point test failures in RF19 is documented in Section 4OA7.  

The Hope Creek main steam SRVs are 6" x 10" Target Rock Model 7567F, 2-stage SRVs consisting of a pilot stage, a main stage, and an air operator for remote operation.  Hope Creek has 14 safety-related main steam SRVs that provide reactor pressure vessel overpressure protection and an automatic/manual depressurization function.  Hope Creek TS 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).  Hope Creek TS surveillance requirement 4.4.2.2 requires that at least half of the SRV pilot stage assemblies be removed and set pressure tested in accordance with the Surveillance Frequency Control Program (currently at the refueling outage (RFO) frequency of every 18 months).  Since RF15 in April 2009, PSEG has performed as found lift tests on all 14 SRV pilot valves every outage.  PSEG conducts this surveillance testing during RFOs when the SRVs are accessible during reactor shutdown conditions.  Historically, Hope Creek has experienced numerous as-found lift pressure failures during SRV testing.  Most recently, in June 2015, PSEG identified that 10 of 14 SRVs lifted above the TS specified pressure band (see Section 4OA3.1).

The Target Rock 2-stage SRV has an industry-wide history of set point drift.  Early documentation from General Electric (GE) identified that the Target Rock 2-stage SRV design was susceptible to corrosion bonding resulting in set point drift.  The corrosion bonding failure mode occurs due to bridging oxides created between the pilot disc surface and the pilot valve body disc seating surface during service.  The corrosion bonding trend results in the valve lifting at a higher pressure, failing to meet its set point criteria during the first lift attempt, but successfully lifting during consecutive tests (after the corrosion bond is broken during the first lift).  Over the years, PSEG

May 11 2018: The multiple failures of the coatings and new valve designs indicate massive experimentation going on in the reactor. They are suppose put these changes into a comprehensive testing regime guaranteeing there will no surprises and the changes worked as advertised before they to go into the reactor. I think all these changes are engineered to buy time for the utility, not really solve the problem. It is really fraud and corruption!!!    

personnel reviewed failure mechanisms and implemented maintenance recommendations from industry OE, GE Service Information Letters (SILs), and Boiling Water Reactor Owners Group recommendations in an unsuccessful attempt to address Target Rock pilot set point drift failures.  For example, the industry and PSEG have identified and implemented numerous mitigating strategies including: different pilot disc materials/coatings, addressing critical pilot disc and seat dimensions, correcting methods of insulation installation, and increased TS as-found set point margin (from +/- 1 percent to +/- 3 percent) in an attempt to improve Target Rock 2-stage SRV reliability.  The inspectors noted that PSEG implemented a mitigation strategy to install new pilot discs in all 14 SRV pilot valves every RFO; however, based on the continued set point drift failures, this aggressive practice has not proven effective at mitigating the corrosion bonding failure mechanism. 

During the review of Hope Creek LER 05000354/2010-002-01 in September 2011, NRC inspectors questioned whether multiple SRVs exceeding the TS allowable as-found lift set point acceptance criteria represented a significant CAQ (SCAQ).  In response, on September 13, 2011, PSEG initiated corrective action NOTF 20525076 to address the inspectors’ concern.  PSEG reviewed their CAP procedure guidance and determined that the condition was not a SCAQ; however, it warranted a root cause evaluation (RCE).  In February 2012, PSEG completed the RCE, “SRV Setpoint Drift Root Cause Evaluation” (70128407-010), to evaluate the longstanding SRV set point drift issues.  PSEG’s root cause analysis reviewed station preventative maintenance practices (rigging, storage, transportation, etc.), maintenance procedures, internal maintenance history, vendor maintenance history (including testing and inspection reports, replacement parts, and practices), industry OE, and the application of this OE at Hope Creek.  The root cause team evaluated the Target Rock SRV pilot valve design, manufacturing, and application.  The root cause team also reviewed effects of Extended Power Uprate, steam line vibration, and performance of each SRV by serial number.  In February 2012, the multi-disciplined PSEG root cause team determined that the Target Rock 2-stage SRV pilot valve design was incapable of satisfying the set point drift design requirements on a consistent basis.  PSEG’s corrective actions to prevent recurrence of the above root cause included plans to replace the currently installed Target Rock 2stage SRVs with a design that eliminates set point drift events exceeding +/-3 percent and improves SRV reliability.  Based on several engineering studies (including industry OE), PSEG’s Main Steam SRV Replacement Project (H-11-0009) recommended replacing the existing 2-stage Target Rock pilot valves with a SEBIM pilot operated design or with an upgraded Target Rock 3-stage pilot.  During the first quarter of 2014, PSEG made the decision to no longer pursue the SEBIM model replacement valve due to difficulties meeting Hope Creek specifications.  PSEG developed design change package (DCP) 80107006, “Safety Relief Valve (SRV) Replacement,” and had planned to install seven Target Rock 3-stage pilots in May 2015 (RF19).  However, in the early months of 2015 (just prior to RF19), PSEG decided to defer installing the new 3-stage Target Rock valves due to significant OE at Pilgrim Nuclear Power Station (including a Target Rock Part 21 report).  At the time of this inspection, PSEG tentatively planned to install one new 3-stage Target Rock pilot valve in the Fall 2016 RFO (RF20), contingent on the satisfactory acceptance testing results.  The inspectors noted that PSEG’s decisions that resulted in delays in replacing the existing 2-stage Target Rock pilot valves were appropriate, conservative, and aligned with the principle of not moving forward in the face of uncertainty.  From a historic perspective, leading up to RF19 in May 2015, the inspectors noted that PSEG’s aggregate actions to address SRV pilot valve set point drift issues were aligned with industry initiatives, appropriate, and commensurate with the safety significance.

On June 3, 2015, based on initial post-RF19 test reports, PSEG initiated corrective action NOTF 20692390 documenting that four SRVs failed their as-found set point tests.  Upon completion of the as-found testing on June 10, 2015, PSEG updated the NOTF documenting that 10 of 14 SRVs had failed their as-found set point tests.  On July 30, PSEG submitted a LER (LER 2015-004-00) for the SRVs set point failures. 

On  August 13, engineering completed two technical evaluations assessing the safety significance of the set point failures and determined that the set point drift did 

Maybe it bounded reactor vessel overpressure and other engineering design limits...but nobody talks about the reduction in that margin for the last decade. Remember an overpressure accident leading to cracking the vessel or bursting a large pipe would be a accident like no other meltdown in the western world.

not impact or challenge the ability of the SRVs to perform their function of relieving reactor vessel overpressure (see Section 4OA3.1).  On August 26, 2015, PSEG submitted a revision to the LER (LER 2015-004-01) to include the associated technical evaluations and impact on SRV operability.  Based on a review of the LERs, technical evaluations, and associated corrective action NOTF, the NRC resident inspectors identified that PSEG did not identify and/or evaluate an apparent adverse trend in as-found set point testing results (see table below).  Specifically, the resident inspectors noted that both the number and

Update May 11 2018: On the step increase of problem, the NRC says they brought it to the attention of Hope Creek. I brought it to the NRC before they knew it.    

magnitude of the RF19 failures represented a step increase compared to the previous four operating cycles (RF15 – RF18).  The resident inspectors discussed this observation with PSEG staff on several occasions and subsequently engaged PSEG senior managers and the PSEG engineering staff on a conference call on September 16, 2015.  This conference call included NRC Region I Division of Reactor Projects and Division of Reactor Safety managers and technical staff.  On November 5, 2015, following the resident inspectors’ additional engagement on the potential adverse trend, PSEG initiated two corrective action NOTFs to: (1) evaluate a possible trend in SRV set point drift magnitude and/or number of valves affected (NOTF 20709653), and (2) evaluate a potential correlation between the number of as-found set point failures and the time interval between SRV removal and SRV testing (NOTF 20709757).  Based on a review of corrective action NOTFs and NOS reports, the inspectors found no evidence that PSEG had identified and evaluated this potential trend prior to NRC engagement. 

RF15 04/09

RF16 10/10

RF17 04/12

RF18 10/13

RF19 05/15

SRV set point failures

6 6 6 5 10

Average set point drift (average of all 14 valves)

3.77% 3.64% 3.30% 2.34% 5.34%

Highest set point  pressure (psig)

1212 1199 1202 1192 1240

Number of valves above 1200 psig

2 0 1 0 5

Approximate average delay in days between SRV removal & SRV test

N/A N/A 20 25 50

Causal analysis Note: significance level  (SL)2 RCE completed in 02/12

SL3 ACE (70096933)

SL3 ACE (70115711)

SL2 WGE (70138789)

SL2 WGE (70161353)

SL4 no evaluation

On February 17, 2016, engineering completed two evaluations (70181904-010 and 70181906-010).  Engineering concluded that no definitive trend could be established based on a review of the as-found set point failures by cycle, SRV location, and set pressure group (i.e., valves set to lift at 1108 psig, 1120 psig, or 1130 psig), with one exception.  Engineering noted that the data showed that the 1108 psig set pressure group had an increasing trend in failures after cycle 14.  Engineering initiated an action item to perform a more detailed trend analysis of the 1108 psig group by specific pilot valve serial number and critical as-found dimensions (70181904-060).  In the evaluation, engineering concluded, that although the H1R19 test results show a significant increase in failures compared to H1R18, the failure rate does not represent an adverse trend and the single H1R19 data set is not sufficient to declare a trend.  The inspectors noted that engineering’s evaluation did not fully evaluate the possible trend in SRV set point drift magnitude (note from the table above that the average set point drift more than doubled when compared to the RF18 data).

Engineering reviewed the test data for RF17 through RF19 from the table above and concluded that an extended time interval between SRV removal from the plant until as found set point testing can adversely impact the results (number of set point failures).  Engineering initiated an action item to expedite SRV as-found testing in RF20 to further evaluate and assess the potential adverse trend in the RF19 failure rate (70181904-050).  The inspectors noted that the data supported engineering’s  conclusion regarding the impact of a time delay before testing.  Based on an OE review, the inspectors also noted that a Pilgrim Nuclear Power Station LER (LER 2004-001-00) attributed three 2-stage SRV pilot valve failures due to a significant delay in performing as-found testing.  The inspectors noted that the data suggests that significant delays prior to testing may result in more failures and a higher average set pressure.  However, the data also showed that the corrosion bonding phenomenon adversely impacted SRV pilot valve set pressures during the operating cycle as some valves failed even when tested within a few days of removal.  Thus, expediting the as-found testing would not eliminate corrosion bonding induced test failures; however, it may reduce the number and magnitude of the overall failures and result in as-found test results that more accurately reflect SRV pilot valve performance during the operating cycle.

The inspectors noted that engineering’s evaluation did not assess a potential correlation between time delays on the front end of the cycle and the failure rate (including magnitude).  Specifically, potential significant time delays between completing the required as-left +/- 1 percent testing and installing the pilot valves back into the plant and the potential impact on as-found failure rate at the end of the operating cycle.  The inspectors reviewed the data for RF18 and RF19, and concluded that there was no correlation on the front end.  

The inspectors noted that the significant step-change in SRV pilot valve as-found test results from the RF19 testing represented a CAQ.  Based on interviews and document reviews, the inspectors determined that PSEG had not identified the condition until prompted by the resident inspectors.  The inspectors determined that PSEG’s not identifying and evaluating the CAQ was a performance deficiency that was reasonably within PSEG’s ability to foresee and correct.  The inspectors evaluated this PSEG performance deficiency in accordance with IMC 0612, Appendix B, “Issue Screening,” and determined that the issue was minor.  This issue was minor because the inspectors did not identify any PSEG and/or NWS deficiency that may have contributed to an increased failure rate, nor any actions that PSEG should take to preclude recurrence prior to RF20.  

Based on a historical review of PSEG’s causal evaluations initiated to evaluate SRV set point drift failures (see table above), the inspectors concluded that PSEG had high confidence in their 2012 RCE, which may have led to not questioning the RF19 as-found test results.  Specifically, the inspectors noted that, following the RCE (completed in February 2012), PSEG initiated a significance level (SL) 2 work group evaluations (WGEs) after RF17 and after RF18, but initiated no causal evaluation after RF19.  In addition, the inspectors noted that on June 5, 2015, PSEG personnel did not provide adequate documentation supporting the CAP Management Review Committee (MRC) decision to screen NOTF 20692390 as SL4 with no associated evaluation, especially considering the number and magnitude of the as-found test failures.  The inspectors noted MRC’s decision, barring any documented justification, was not aligned with PSEG procedure LS-AA-120, “Issue Identification and Screening Process,” Attachment 2 (“Significance Level Guidance”) and Attachment 3 (“Guidance for Determining Evaluation Type”).  The inspectors determined that PSEG’s not following their CAP administrative procedure was a performance deficiency that was reasonably within PSEG’s ability to foresee and correct.  The inspectors evaluated this PSEG performance deficiency in accordance with IMC 0612, Appendix B, “Issue Screening,” and determined that the issue was minor.  Notwithstanding, the inspectors viewed the issue as another missed opportunity for PSEG to self-identify this trend.

Based on the RF19 as-found test results (all second lift tests were within 3 percent of the specified set point, with the average of 1.39 percent), engineering concluded that all ten SRV test failures were also due to the corrosion bonding phenomenon.  The inspectors noted that, based on PSEG and industry OE and RF19 test results, engineering’s conclusion was reasonable.  However, at the time of this inspection,PSEG had not performed internal inspections of any of the SRV pilots removed during RF19 to confirm their theory.  PSEG plans to perform inspections (including subsequent as-left set point testing) of all 14 SRV pilot valves commencing in June 2016 to support Hope Creek’s next RFO (RF20).  

Based on a review of as-left test documentation for all 14 SRVs pilot valves installed in RF17 and RF18 and a sample of SRV pilot assembly inspection records, the inspectors noted that NWS personnel maintained high-quality records that clearly documented the as-found condition, repairs and/or replaced components, the as-left condition, QA acceptance, and procedure compliance.

 2. The station is planning the replacement of the currently installed Target Rock two-stage SRVs with three-stage SRVs that are expected to eliminate setpoint drift events exceeding +/-3% and improve SRV reliability. The replacement is expected to begin in the next planned refueling outage, H1 R21, in the spring of 2018, pending resolution of open technical items with the valve manufacturer. The replacement will take place over several outages in order to replace all fourteen SRVs.

Junk Plant River Bend's Secret Fuel Meltdown

Is this the new Trump NRC, the licensees don't have to publically discuss how they damaged fuel.

Honestly, damaged assemblies. Not a damaged assemble. More than 1000 pins in a assembly...

SUBJECT: RIVER BEND STATION – NRC INTEGRATED INSPECTION REPORT 05000458/2018001

Pg 7

1) The inspectors evaluated a planned maintenance outage implemented to remove damaged fuel assemblies.  Inspection activities occurred from January 8, 2018, to January 31, 2018

Junk Plant Callaway Safety Analysis and Procedures

This could have turned a terrible accident into meltdown. One has no assurance there is no similar issues throughout the industry.  

This is my version of the engineers screwing the control room people. Can you believe this went unaddressed since initial startup? If the licensee can't do their jobs then it is up to the NRC to catch these flaws. Why didn't the CDBI or other special engineering inspection catch them on this years ago? Give them a big fine for not catching it.

Believe me, if you have the big one up in the control room, you are going to all be alone up in the control room. And you know it!!! The NRC and licensees set you up for failure.  

Power Reactor	Event Number: 53388
Facility: CALLAWAY Region: 4 State: MO Unit: [1] [ ] [ ] RX Type: [1] W-4-LP NRC Notified By: JEREMY MORTON HQ OPS Officer: DAN LIVERMORE	Notification Date: 05/07/2018 Notification Time: 16:31 [ET] Event Date: 05/07/2018 Event Time: 13:35 [CDT] Last Update Date: 05/07/2018
Emergency Class: NON EMERGENCY 10 CFR Section: 50.72(b)(3)(v)(A) - POT UNABLE TO SAFE SD 50.72(b)(3)(v)(B) - POT RHR INOP 50.72(b)(3)(v)(D) - ACCIDENT MITIGATION	Person (Organization): MARK HAIRE (R4DO)

Unit	SCRAM Code	RX CRIT	Initial PWR	Initial RX Mode	Current PWR	Current RX Mode
1	N	Y	100	Power Operation	100	Power Operation

Event Text

DISCOVERY OF A CONDITION THAT COULD HAVE PREVENTED FULFILLMENT OF A SAFETY FUNCTION "On May 7, 2018, during an engineering review of mission time requirements for Technical Specification related equipment, a deficiency was discovered regarding the Emergency Operating Procedure (EOP) guidance for natural circulation cooldown with a stagnant loop. This condition could be the result of a postulated Main Steam Line Break with a loss of offsite power. "During a natural circulation cooldown with a faulted steam generator, flow in the stagnant reactor coolant system (RCS) loop associated with the isolated faulted steam generator (SG) could stagnate and result in elevated temperatures in that loop. This becomes an issue when RCS depressurization to residual heat removal system (RHR) entry conditions is attempted. The liquid in the stagnant loop will flash to steam and prevent RCS depressurization. In this condition, the time required to complete the cooldown would be sufficiently long that the nitrogen accumulators associated with Callaway's atmospheric steam dumps and turbine driven auxiliary feedwater pump flow control valves would be exhausted. The atmospheric steam dumps and turbine driven auxiliary feedwater pump would not be capable of performing their specified safety functions of cooling the plant to entry conditions for RHR operation. This issue has been analyzed by Westinghouse in WCAP-16632-P. This WCAP determined that to prevent loop stagnation, the RCS cooldown rate in these conditions should be limited to a rate dependent on the temperature differential present in the active loops. "The WCAP analysis was used to support a revision to the generic Emergency Response Guideline (ERG) for ES-0.2 "Natural Circulation Cooldown." Figure 1 in ES-0.2 provides a curve of the maximum allowable cooldown rate as a function of active loop temperature differential which is directly proportional to the level of core decay heat. At the time of discovery of this condition, Callaway's EOP structure did not ensure that the ES-0.2 guidance would be implemented for a natural circulation cooldown with a stagnant loop. "Callaway has issued interim guidance to the on-shift personnel regarding this concern and is in the process of revising the applicable EOPs. "This condition is reportable per 10 CFR 50.72(b)(3)(v) for any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to (A) Shutdown the reactor and maintain it in a safe shutdown condition, (B) Remove residual heat, or (D) mitigate the consequences of an accident." The licensee notified the NRC Resident Inspector of this condition.