IR 05000354/2020001
| ML20127H813 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 05/06/2020 |
| From: | Brice Bickett Reactor Projects Branch 3 |
| To: | Carr E Public Service Enterprise Group |
| References | |
| IR 2020001 | |
| Download: ML20127H813 (16) | |
Text
May 6, 2020
SUBJECT:
HOPE CREEK GENERATING STATION - INTEGRATED INSPECTION REPORT 05000354/2020001
Dear Mr. Carr:
On March 31, 2020, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Hope Creek Generating Station. On April 15, 2020, the NRC inspectors discussed the results of this inspection with Mr. Ed Casulli, Site Vice President and other members of your staff. The results of this inspection are documented in the enclosed report.
One finding of very low safety significance (Green) is documented in this report. This finding involved a violation of NRC requirements. One Severity Level IV violation without an associated finding is documented in this report. We are treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.
If you contest the violations or the significance or severity of the violations documented in this inspection report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN:
Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement; and the NRC Resident Inspector at Hope Creek Generating Station.
If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; and the NRC Resident Inspector at Hope Creek Generating Station. This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document Room in accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding.
Sincerely, X /RA/
Signed by: NRC-PIV
Brice A. Bickett, Chief Reactor Projects Branch 3 Division of Reactor Projects
Docket No. 05000354 License No. NPF-57
Enclosure:
Inspection Report 05000354/2020001
Inspection Report
Docket Number:
05000354
License Number:
Report Number:
Enterprise Identifier: I-2020-001-0026
Licensee:
Facility:
Hope Creek Generating Station
Location:
Hancock's Bridge, NJ 08038
Inspection Dates:
January 01, 2020 to March 31, 2020
Inspectors:
A. Ziedonis, Senior Resident Inspector
J. Patel, Resident Inspector
D. Beacon, Resident Inspector
S. Pindale, Senior Reactor Inspector
Approved By:
Brice A. Bickett, Chief
Reactor Projects Branch 3
Division of Reactor Projects
SUMMARY
The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees
performance by conducting an integrated inspection at Hope Creek Generating Station, in
accordance with the Reactor Oversight Process. The Reactor Oversight Process is the NRCs
program for overseeing the safe operation of commercial nuclear power reactors. Refer to
https://www.nrc.gov/reactors/operating/oversight.html for more information.
List of Findings and Violations
Inadequate Test Control of Emergency Load Sequencers Redundant Solid-State Logic Timer
Module
Cornerstone
Significance
Cross-Cutting
Aspect
Report
Section
Mitigating
Systems
Green
Open/Closed
[P.2] -
Evaluation
The inspectors identified a Green finding and associated non-cited violation (NCV) of Title 10
of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion XI, Test
Control, when PSEG did not ensure that testing was identified and performed to demonstrate
the emergency load sequencer (ELS) systems backup logic timer modules would perform
satisfactorily sequencing of required electrical loads. Specifically, the ELS is designed with
backup logic timer modules that are automatically relied upon when a failure of the primary
logic timer module occurs, such as the 'D' ELS primary module on four separate occurrences
between May 14, 2019 through September 26, 2019.
SRV Lift Setpoints Exceed Technical Specification Limits
Cornerstone
Significance
Cross-Cutting
Aspect
Report
Section
Not Applicable
Open/Closed
Not Applicable
A self-revealing Severity Level IV Non-Citied Violation of Technical Specification (TS) 3.4.2.1
(three examples) was identified after PSEG was notified that the as-found lift setpoint of main
steam safety relief valve (SRV) pilot stage assemblies had exceeded the lift setting allowable
tolerance.
Additional Tracking Items
Type
Issue Number
Title
Report Section
Status
LER 2019-002-00 for Hope
Creek Generating Station,
As-found Set-point Failures
Closed
LER 2019-001-00 for Hope
Creek Generating Station,
Manual Scram and Manual
Actuation of Reactor Core
Isolation Cooling
Closed
Concern Regarding As-
Found Values for Safety
Relief Valve Lift Setpoints
Exceed Technical
Specification Allowable Limit
Closed
PLANT STATUS
The Hope Creek Generating Station (Hope Creek) began the inspection period at approximately
100 percent rated thermal power (RTP). On February 20, power was reduced to approximately
65 percent RTP, following a loss of power to the 'C' feedwater heating control panel, trip of the
'C' reactor feed pump, and intermediate recirclation pump runback. Power was restored to
approximately 100 percent RTP on February 21. On March 14, a planned load reduction to
approximately 65 percent RTP was conducted, to perform main turbine valve testing and a
control rod pattern exchange. Power was restored to approximately 100 percent RTP on
March 15. The station remained at or near 100 percent RTP for the remainder of the inspection
period.
INSPECTION SCOPES
Inspections were conducted using the appropriate portions of the inspection procedures (IPs) in
effect at the beginning of the inspection unless otherwise noted. Currently approved IPs with
their attached revision histories are located on the public website at
http://www.nrc.gov/readingrm/doc-collections/insp-manual/inspection-procedure/index.html.
Samples were declared complete when the IP requirements most appropriate to the inspection
activity were met consistent with Inspection Manual Chapter (IMC) 2515, Light-Water Reactor
Inspection Program - Operations Phase. From January 1 - March 19, 2020, the inspectors
performed plant status activities described in IMC 2515, Appendix D, Plant Status, and
conducted routine reviews using IP 71152, Problem Identification and Resolution. The
inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel to assess licensee performance and compliance with Commission rules and
regulations, license conditions, site procedures, and standards.
Starting on March 20, 2020, in response to the National Emergency declared by the President
of the United States on the public health risks of the coronavirus (COVID-19), resident
inspectors were directed to begin telework and to remotely access licensee information using
available technology. During this time the resident inspectors performed periodic site visits
each week and during that time conducted plant status activities as described in IMC 2515,
Appendix DProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 2515,</br></br>Appendix D" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process.; and observed risk significant activities when warranted. In addition, resident and
regional baseline inspections were evaluated to determine if all or portion of the objectives and
requirements stated in the IP could be performed remotely. If the inspections could be
performed remotely, they were conducted per the applicable IP. In the cases where it was
determined the objectives and requirements could not be performed remotely, management
elected to postpone and reschedule the inspection to a later date.
REACTOR SAFETY
71111.01 - Adverse Weather Protection
Impending Severe Weather Sample (IP Section 03.02) (1 Sample)
The inspectors evaluated readiness for impending adverse weather conditions for
(1)
Elevated river grassing conditions on February 27
71111.04 - Equipment Alignment
Partial Walkdown Sample (IP Section 03.01) (3 Samples)
The inspectors evaluated system configurations during partial walkdowns of the following
systems/trains:
(1)
'A' safety auxiliaries cooling system following restoration from planned maintenance
on January 3
(2)
'D' service water train following traveling water screen failure on February 11
(3)
'B' residual heat removal system on February 18
71111.05 - Fire Protection
Fire Area Walkdown and Inspection Sample (IP Section 03.01) (5 Samples)
The inspectors evaluated the implementation of the fire protection program by conducting a
walkdown and performing a review to verify program compliance, equipment functionality,
material condition, and operational readiness of the following fire areas:
(1)
Control equipment division I and II cables room 5403 on January 31
(2)
Class 1E inverter room 5448 on January 31
(3)
Class 1E division II switchgear room 5413 on January 31
(4)
'A' and 'B' safety and turbine auxiliary cooling system (SACS) heat exchanger and
pump rooms on March 6
(5)
Service water intake structure with incipient fire detector panel out of service on
March 9
71111.06 - Flood Protection Measures
Inspection Activities - Internal Flooding (IP Section 03.01) (1 Sample)
The inspectors evaluated internal flooding mitigation protections in the:
(1)
'A' and 'B' safety and auxiliaries cooling system and heat exchanger rooms on
March 24
71111.07A - Heat Sink Performance
Annual Review (IP Section 03.01) (1 Sample)
The inspectors evaluated readiness and performance of:
(1)
B1 safety and auxiliaries cooling system heat exchanger on March 31
71111.11Q - Licensed Operator Requalification Program and Licensed Operator Performance
Licensed Operator Performance in the Actual Plant/Main Control Room (IP Section 03.01) (1 Sample)
(1)
The inspectors observed and evaluated licensed operator performance in the Control
Room during a planned load reduction to perform turbine valve testing and a rod
pattern exchange on March 14.
Licensed Operator Requalification Training/Examinations (IP Section 03.02) (1 Sample)
(1)
The inspectors observed and evaluated a crew of licensed operators in the plant's
simulator during a licensed operator requalification exam on February 11.
71111.12 - Maintenance Effectiveness
Maintenance Effectiveness (IP Section 03.01) (2 Samples)
The inspectors evaluated the effectiveness of maintenance to ensure the following
structures, systems, and components (SSCs) remain capable of performing their intended
function:
(1)
Control rod 42-59 elevated friction on February 12
(2)
Cooling tower bypass valve failure and degraded main condenser vacuum on
February 19
Quality Control (IP Section 03.02) (1 Sample)
The inspectors evaluated the effectiveness of maintenance and quality control activities to
ensure the following SSC remains capable of performing its intended function:
(1)
Startup level control valve component failure due to an expired shelf life on March 18
71111.13 - Maintenance Risk Assessments and Emergent Work Control
Risk Assessment and Management Sample (IP Section 03.01) (5 Samples)
The inspectors evaluated the accuracy and completeness of risk assessments for the
following planned and emergent work activities to ensure configuration changes and
appropriate work controls were addressed;
(1)
Emergent repairs to the 'A' emergency diesel generator (EDG) fuel oil injector line
and the replacement of fuel oil suction strainers on January 2
(2)
Emergent repairs to the 'D' station service water traveling water screens on January 3
(3)
Emergent repairs to the 'C' EDG cooling valve on January 7
(4)
Emergent repairs to the 'C' feedwater heater control panel uninterruptible power
supply on February 20
(5)
Emergent repairs to the 'B' control room emergency filtration train on February 26
71111.15 - Operability Determinations and Functionality Assessments
Operability Determination or Functionality Assessment (IP Section 03.01) (4 Samples)
The inspectors evaluated the licensee's justifications and actions associated with the
following operability determinations and functionality assessments:
(1)
'A' EDG following a controlled engine shutdown during the 24-hour endurance test on
January 2
(2)
'C' EDG with a degraded voltage regulator on January 6
(3)
'L' safety relief valve following a decrease in second stage temperature on January 21
(4)
Safety relief valve vacuum breaker testing non-conformance on February 5
71111.18 - Plant Modifications
Temporary Modifications and/or Permanent Modifications (IP Section 03.01 and/or 03.02) (1 Sample)
The inspectors evaluated the following temporary or permanent modification:
(1)
Portable diesel generators installed for technical specification changes under license
amendment 216 (ML19073A073) on March 27
71111.19 - Post-Maintenance Testing
Post-Maintenance Test Sample (IP Section 03.01) (7 Samples)
The inspectors evaluated the following post maintenance test activities to verify system
operability and functionality:
(1)
'A' station auxiliaries cooling system supply valve to the EDGs following corrective
maintenance on January 2
(2)
'D' station service water traveling water screens following planned maintenance on
January 8
(3)
'A' EDG following planned relay maintenance on January 31
(4)
'B' EDG following planned maintenance on February 18
(5)
'B' primary contained instrument gas inboard isolation valve following corrective
maintenance on March 11
(6)
'B' standby liquid control following planned maintenance on March 12
(7)
'D' station service water pump following planned maintenance on March 20
71111.22 - Surveillance Testing
The inspectors evaluated the following surveillance tests:
Surveillance Tests (other) (IP Section 03.01) (4 Samples)
(1)
HC.IC-FT.PE-0004, emergency load sequencer functional test on January 16
(2)
HC.OP-ST.SV-0002, remote shutdown control panel test of residual heat removal
system loop B low pressure coolant injection valve F017B on January 22
(3)
HC.OP-ST.BF-0001, monthly control rod drive exercise on February 25
(4)
HC.OP-ST.KJ-0001, monthly EDG operability test on
February 24
Inservice Testing (IP Section 03.01) (1 Sample)
(1)
HC.OP-IS.BJ-0001, HPCI main and booster pump inservice test on March 4
71114.06 - Drill Evaluation
Select Emergency Preparedness Drills and/or Training for Observation (IP Section 03.01) (1 Sample)
(1)
The inspector evaluated the conduct of a routine PSEG emergency planning drill on
February 26
OTHER ACTIVITIES - BASELINE
71151 - Performance Indicator Verification
The inspectors verified licensee performance indicators submittals listed below from
April 1 2019, through March 31, 2020:
IE01: Unplanned Scrams per 7000 Critical Hours Sample (IP Section 02.01) (1 Sample)
(1)
Unplanned Scrams
IE03: Unplanned Power Changes per 7000 Critical Hours Sample (IP Section 02.02) (1 Sample)
(1)
Unplanned Power Changes
IE04: Unplanned Scrams with Complications (USwC) Sample (IP Section 02.03) (1 Sample)
(1)
Unplanned Scrams with Complications
71152 - Problem Identification and Resolution
Annual Follow-up of Selected Issues (IP Section 02.03) (1 Sample)
The inspectors reviewed the licensees implementation of its corrective action program
related to the following issues:
(1)
Corrective actions to address repetitive safety relief valve setpoint test results found
outside of tolerance
71153 - Followup of Events and Notices of Enforcement Discretion
Event Report (IP Section 03.02) (2 Samples)
The inspectors evaluated the following LERs which can be accessed at
https://lersearch.inl.gov/LERSearchCriteria.aspx:
(1)
LER 05000354/2019-001-00, Manual Scram and Manual Actuation of Reactor Core
Isolation Cooling on March 25 (ADAMS Accession No. ML19274D127). The
inspectors determined that it was not reasonable to foresee or correct the cause
discussed in the LER therefore no performance deficiency was identified. The
inspectors did not identify a violation of NRC requirements.
(2)
LER 05000354/2019-02, Safety Relief Valve Setpoint Failures on January 29
(ADAMS Accession No. ML20006E541). The inspection conclusions associated with
this LER are documented in this report under Inspection Results Section 71152.
INSPECTION RESULTS
Inadequate Test Control of Emergency Load Sequencers Redundant Solid-State Logic Timer
Module
Cornerstone
Significance
Cross-Cutting
Aspect
Report
Section
Mitigating
Systems
Green
Open/Closed
[P.2] -
Evaluation
The inspectors identified a Green finding and associated non-cited violation (NCV) of Title 10
of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion XI, Test
Control, when PSEG did not ensure that testing was identified and performed to demonstrate
the emergency load sequencer (ELS) systems backup logic timer modules would perform
satisfactorily sequencing of required electrical loads. Specifically, the ELS is designed with
backup logic timer modules that are automatically relied upon when a failure of the primary
logic timer module occurs, such as the 'D' ELS primary module on four separate occurrences
between May 14, 2019, through September 26, 2019.
Description: Hope Creek Generating Station (HCGS) has four Class 1E ELSs, one for each
of the four Class 1E power divisions. Each channelized ELS consists of two individual solid-
state sequencers, one for the loss of power (LOP) sequence and one for the loss of coolant
accident (LOCA) sequence. The LOP and LOCA sequencers each have two redundant solid-
state logic timers, a primary and a backup, powered from redundant internal power
supplies. The ELS generates sequential start signals for required electrical loads following
LOP or LOCA events, upon closure of the EDG output breaker. The LOP and LOCA logic
timers are Programmable Logic Universal Modules (PLUM) of identical design, with
differences in the timing configuration depending on the LOP or LOCA application. The
primary and backup PLUMs receive simultaneous input signals; however, a watchdog timer
holds the output of the backup module to an off state if the primary module is functional. If
the primary module fails, the watchdog timer automatically releases the backup module
output signal. The backup PLUM is not required to satisfy single failure general design
criteria but rather is a design feature to increase EDG reliability. The ELS is described in the
Updated Final Safety Analysis Report (UFSAR) Section 8.3.1.1.2.7, and Hope Creek
complies with Regulatory Guide 1.108, as described in UFSAR Section 1.8.1.108.
From May 2019 to September 2019, PSEG documented four occurrences of a failed primary
LOP module associated with the D ELS. Each module has a light emitting diode (LED) to
indicate availability of the module to perform its design function. For three of the four
occasions, May 14 (20826088), May 28 (20826980), and September 25, 2019 (20833746), a
nuclear equipment operator reported to the main control room that the LED was extinguished
on LOP module card A3-7 on the D ELS panel. On September 26, 2019, the inspectors
identified the same failure on module A3-7 (20834826).
The inspectors reviewed the notifications (i.e., condition reports) for each occurrence, and
reviewed the immediate operability screenings against TS 3.8.1.1, AC Sources -
Operating. The inspectors noted that for each of the failures, PSEG concluded the D
EDGs ELS was operable but degraded. This conclusion was supported by operability
evaluations documented in 70207240-0010, 70207462-0010, and 70209337-0010. PSEG
documented the ELS system is completely redundant, and therefore the D LOP backup
module can perform all required design functions. The inspectors questioned PSEG as to
whether the backup module had ever been functionally tested to demonstrate its design
function. PSEG reviewed historical documents and receipt records and determined that the
backup LOP and LOCA modules had not been tested since initial installation, and PSEG
could not find any record of initial installation testing for any of the LOP modules.
Corrective Actions: PSEG documented the lack of testing the LOP and LOCA backup
PLUMs in CAP under the corrective action references below. Additionally, following each of
the four D EDG PLUM failures, PSEG corrected the condition and restored the primary
PLUM to a functional status in less time than the Technical Specification limiting condition for
operation (LCO) action statement would allow had the D EDG been declared inoperable.
Corrective Action References: 20844381, 20844617, 20844618, and 20844619
Performance Assessment:
Performance Deficiency: The inspectors determined that because PSEG did not
demonstrate the emergency load sequencer (ELS) backup PLUMs would perform
satisfactorily when in service, this issue was a performance deficiency that was within
PSEGs ability to foresee and correct and should have been prevented.
Screening: The inspectors determined the performance deficiency was 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. Specifically, the inspectors determined that crediting the ELS
backup PLUM for D EDG operability following a failure of the primary PLUM, without
appropriate test control measures for the backup PLUM, constituted an adverse impact to the
cornerstone objective.
Significance: The inspectors assessed the significance of the finding using Appendix A, The
Significance Determination Process (SDP) for Findings At-Power. The inspectors assessed
the significance of the finding using IMC 0609.04, Initial Characterization of Findings, and
IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The inspectors
determined this finding was of very low safety significance (Green) because the Exhibit 2
screening questions were answered No.
Cross-Cutting Aspect: P.2 - Evaluation: The organization thoroughly evaluates issues to
ensure that resolutions address causes and extent of conditions commensurate with their
safety significance. The inspectors determined that PSEG did not perform a thorough
operability evaluation of the D EDG, to ensure that the resolution (reasonable assurance)
sufficiently addressed the cause (degraded condition with failed primary PLUM). Specifically,
PSEGs operability evaluation did not identify that the ELS backup PLUMs were never tested,
and did not address reasonable assurance of the ELS safety function in the absence of any
testing.
Enforcement:
Violation: Title 10 CFR Part 50, Appendix B, Criterion XI, Test Control, states in part, that a
test program shall be established to assure that all testing required to demonstrate that
structures, systems, and components will perform satisfactorily in service is identified and
performed in accordance with written test procedures which incorporate the requirements and
acceptance limits contained in applicable design documents. The test program shall include,
as appropriate, proof tests prior to installation, preoperational tests, and operational tests
during nuclear power plants.
Contrary to the above, existing prior to the close of the inspection period, PSEGs test
program did not assure that testing required to demonstrate that the ELS will perform
satisfactorily in service was identified and performed. Specifically, PSEG did not perform
testing of the safety-related ELS system backup time modules, which have been
automatically relied upon when a failure of the primary logic timer module occurs.
Enforcement Action: This violation is being treated as a non-cited violation, consistent with
Section 2.3.2 of the Enforcement Policy.
SRV Lift Setpoints Exceed Technical Specification Limits
Cornerstone
Severity
Cross-Cutting
Aspect
Report
Section
Not
Applicable
Open/Closed
Not
Applicable
A self-revealing Severity Level IV Non-Citied Violation of Technical Specification (TS) 3.4.2.1
(three examples) was identified after PSEG was notified that the as-found lift setpoint of main
steam safety relief valve (SRV) pilot stage assemblies had exceeded the lift setting allowable
tolerance.
Description: The inspectors performed a problem identification and resolution sample to
review corrective actions associated with three issues where as-found setpoint tests for main
steam SRV pilot stage assemblies exceeded Hope Creeks allowable setpoint tolerance of
+/- 3 percent, as permitted by TS 3.4.2.1:
LER 2016-003-01, As-Found Values for Safety Relief Valve Lift Set Points Exceed
Technical Specification Allowable Limit, reviewed, documented and closed in NRC
Inspection 05000354/2018001;
LER 2018-002-01, Safety Relief Valve As-Found Setpoint Failure, reviewed,
documented and closed in NRC Inspection 05000354/2018003; and
LER 2019-002-00, Safety Relief Valve As-Found Setpoint Failures.
In response to LER 2013-003-01, the NRC opened Unresolved Item (URI)05000354/2018001-02 to determine the appropriateness of PSEGs corrective actions and
the enforcement aspects of the issue. PSEG staff concluded that the cause of the setpoint
drift was attributed to corrosion bonding between the pilot disc and seating surfaces.
The SRV corrosion bonding issue has been reported to the NRC by a number of
licensees. NRC staff in the Office of Nuclear Reactor Regulation have met with the Boiling
Water Reactor Owners Group (BWROG) and other stakeholders to gain a better
understanding of the industry initiatives to address this issue (reference ADAMS Accession
No. ML18267A016, ML19239A280, ML19323E051).
PSEG has worked with the BWROG in evaluating 2-stage SRV setpoint drift issues, and has
taken a number of actions, including a change to the platinum coating application process for
the pilot valve disc for the 2-stage SRVs. In addition, PSEG staff commenced a phased
implementation plan to replace the 2-stage SRVs with a modified 3-stage SRV design, which
was re-designed by the vendor to eliminate operational challenges associated with earlier
3-stage designs. The phased approach began during the Spring 2018 refueling outage,
when one modified 3-stage SRV was installed. Subsequently, this 3-stage SRV was removed
during the Fall 2019 refueling outage, tested with satisfactory performance, disassembled,
inspected, refurbished, re-certified, and reinstalled for the current operating cycle. The
inspectors noted PSEG staff continued implementing appropriate corrective actions during
their Fall 2019 refueling outage by installing an additional six modified 3-stage SRVs. The
inspectors further noted that additional modified 3-stage SRVs are planned to be installed in
the future.
In all the three LERs, PSEG staff concluded the safety significance was very low because the
safety function of the SRVs was not compromised. In particular, all SRVs lifted will below the
established safety limit. Additionally, technical evaluations performed by PSEG determined
the as-found condition of the SRVs would have satisfactorily performed the intended safety
function under postulated accident conditions, including dynamic loading to connected
piping. The inspectors reviewed the technical analyses and determined they supported
PSEGs conclusions.
The inspectors also reviewed the test failure history associated with 10 of 14 SRVs in 2016;
8 of 14 in 2018; and 6 of 14 in 2019. Hope Creek is designed with 14 SRVs, and TS 3.4.2.1
requires 13 of 14 to be OPERABLE within +/- 3 of setpoint in OPERATIONAL CONDITIONS
1, 2 and 3. The inspectors noted that 23 of the 24 test failures were high out of specification,
and those test failures were typical of the corrosion bonding phenomenon. However, one of
the 2019 failures lifted low out of specification. PSEG staff and the offsite vendor conducted
evaluations to determine the cause of that test failure. Both the vendor and PSEG staff
concluded that, although no relevant material deficiencies were observed upon pilot valve
disassembly, the likely cause for the failure was uneven loading between the spherical collar
and retainer section of the pilot valve, allowing for the pilot disc to open unevenly. At the time
of inspection, PSEG staff was in continued discussion with the offsite test facility to determine
if additional actions were warranted. The inspectors determined there was not any
performance deficiency or adverse safety impact for the low out of specification failure.
Corrective Actions: PSEG commenced an SRV phased replacement plan, installing seven
(of 14 total) modified 3-stage SRVs to date. PSEG has taken a number of actions in
collaboration with the industry, including a change to the platinum coating application process
for the pilot valve disc for the 2-stage SRVs. PSEG conducted technical evaluations of the
as-found out of specification test results, and concluded the SRVs lifted below the safety limit,
and would have performed the intended safety function under postulated accident conditions,
including dynamic loading to connected piping.
Corrective Action References: 20839122, 70190219, and 70210209
Performance Assessment: The NRC determined this violation was not reasonably
foreseeable and preventable by the licensee and therefore is not a performance deficiency.
Enforcement:
Severity: This issue is assigned a Severity Level IV violation based on its similarity to
example 6.1.d.1 in the Enforcement Policy, a failure to comply with a technical specification
action requirement demonstrates misapplication of the conventions in technical specifications Section 1.0, Use and Application, or the allowances for LCO and surveillance requirement
applicabilities in TS Section 3.0. The inspectors also reviewed the NRC Enforcement Policy,
Section 2.2.1, Factors Affecting Assessment of Violations, which states, in part, that in
determining the appropriate enforcement response to a violation, the NRC considers,
whenever possible, risk information in assessing the safety or security significance of
violations and assigning severity levels. The inspectors determined the issue to be of very
low safety significance because the safety function of the SRVs was not compromised. As a
result, the inspectors determined that the violation is appropriately characterized at Severity
Level IV.
Violation: TS 3.4.2.1 requires the safety valve function of at least 13 of the 14 SRVs to be
operable with specified lift setting tolerances of +/- 3 percent. Contrary to this requirement,
on three occasions (October 2016, April 2018, and November 2019), SRV lift setpoint testing
revealed that two or more of the 14 SRVs had as-found set points in excess of the TS
allowable tolerance; and those SRVs were assumed to have been inoperable at some point
during the respective operating cycles.
Enforcement Action: This violation is being treated as a non-cited violation, consistent with
Section 2.3.2 of the Enforcement Policy.
Unresolved Item
(Closed)
Concern Regarding As-Found Values for Safety Relief
Valve Lift Setpoints Exceed Technical Specification
Allowable Limit
Description: This URI is closed. The basis for the URI closure is discussed in this report
under NCV 05000354/2020001-02 in the above Inspections Results associated with Report
Section 71152.
EXIT MEETINGS AND DEBRIEFS
The inspectors verified no proprietary information was retained or documented in this report.
- On January 30, 2020, the inspectors presented the safety relief valve problem
identification and resolution inspection results to Mr. Gary Stith, Mechanical Engineering
Branch Manager and other members of the licensee staff.
On April 15, 2020, the inspectors presented the integrated inspection results to
Mr. Ed Casulli, Site Vice President and other members of the licensee staff.