IR 05000247/2018004
| ML19038A398 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 02/07/2019 |
| From: | Daniel Schroeder Reactor Projects Branch 2 |
| To: | Vitale A Entergy Nuclear Operations |
| Schroeder D | |
| References | |
| EA-16-193 IR 2018004 | |
| Download: ML19038A398 (35) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION ary 7, 2019
SUBJECT:
INDIAN POINT NUCLEAR GENERATING - INTEGRATED INSPECTION REPORT 05000247/2018004 AND 05000286/2018004
Dear Mr. Vitale:
On December 31, 2018, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Indian Point Nuclear Generating (Indian Point), Units 2 and 3. On January 10, 2019, the NRC inspectors discussed the results of this inspection with you and other members of your staff. The results of this inspection are documented in the enclosed report.
The NRC inspectors documented two findings of very low safety significance (Green) in this report. One finding involved a violation of NRC requirements; one finding did not involve a violation of NRC requirements. The NRC is treating the violation as a non-cited violation (NCV)
consistent with Section 2.3.2.a of the Enforcement Policy.
If you contest the violation or significance of the NCV, 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 Indian Point. In addition, if you disagree with the cross-cutting aspect assignment or the finding not associated with a regulatory requirement 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 Indian Point. 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 the NRC Public Document Room in accordance with Title 10 of the Code of Federal Regulations (10 CFR), Part 2.390, Public Inspections, Exemptions, Requests for Withholding.
Sincerely,
/RA/
Daniel L. Schroeder, Chief Reactor Projects Branch 2 Division of Reactor Projects Docket Numbers: 50-247 and 50-286 License Numbers: DPR-26 and DPR-64
Enclosure:
Inspection Report 05000247/2018004 and 05000286/2018004
Inspection Report
Docket Numbers: 50-247 and 50-286 License Numbers: DPR-26 and DPR-64 Report Numbers: 05000247/2018004 and 05000286/2018004 Enterprise Identifier: I-2018-004-0078 Licensee: Entergy Nuclear Northeast (Entergy)
Facility: Indian Point Nuclear Generating, Units 2 and 3 Location: 450 Broadway, Generation Support Building Buchanan, NY 10511-0249 Inspection Dates: October 1, 2018, to December 31, 2018 Inspectors: B. Haagensen, Senior Resident Inspector A. Siwy, Resident Inspector J. Vazquez, Resident Inspector J. DeBoer, Emergency Preparedness Inspector T. Setzer, Senior Project Engineer D. Silk, Senior Operations Engineer S. Wilson, Health Physicist Approved By: Daniel L. Schroeder, Chief Reactor Projects Branch 2 Division of Reactor Projects Enclosure
SUMMARY
The U.S. Nuclear Regulatory Commission (NRC) continued monitoring Entergys performance at Indian Point Nuclear Generating, Units 2 and 3, by conducting the baseline inspections described in this report 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. NRC-identified and self-revealed findings, violations, and additional items are summarized in the table below.
List of Findings and Violations Inadequate Control of Transient Combustibles in the 480 Volt Electrical Switchgear Room Cornerstone Significance Cross-Cutting Inspection Aspect Results Section Mitigating Green H.5 - Work 71111.05Q Systems Non-Cited Violation (NCV) Management 05000286/2018004-01 Closed The inspectors identified a Green NCV of Unit 3 Technical Specification (TS) 5.4.1 when Entergy did not take adequate measures to control transient combustibles in accordance with established procedures and thereby did not maintain in effect all provisions of the approved fire protection program, as described in the Unit 3 final safety analysis report. Specifically, on two separate occasions, Entergy did not ensure that transient combustibles were evaluated in accordance with established procedures and, as a result, they allowed combustible loading in the 480 volt emergency switchgear room to exceed limits established in the fire hazards analysis (FHA) of record.
Failure to Adequately Manage Flow Accelerated Corrosion on a Reheat Steam Line Caused a Steam Leak and a Reactor Trip Cornerstone Significance Cross-Cutting Inspection Aspect Results Section Initiating Events Green None 71153 Finding (FIN)05000286/2018004-02 Closed A self-revealed Green FIN was identified when Entergy did not adequately manage the degradation of the 36C feedwater heater (FWH) reheat steam lines, as required by EN-DC-315, Flow Accelerated Corrosion Program. The failure resulted in a large steam leak in the Unit 3 turbine building, from the 36C FWH reheat steam line, which required tripping the reactor and shutting the main steam isolation valve (MSIVs) to isolate the leak for plant and personnel safety.
Additional Tracking Items Type Issue number Title Report Status Section LER 05000286/2018-002-00 Manual Reactor Shutdown 71153 Closed Due to Weld Leak on Safety Injection System Tank LER 05000286/2018-003-00 Manual Reactor Trip Due to a 71153 Closed Steam Leak on a High Pressure Feedwater Heater VIO 05000247/2016-003-07 Inadequate Control of Floor 71152 Closed Drains to Minimize Groundwater Contamination (Enforcement Action (EA)-16-193)
TABLE OF CONTENTS
PLANT STATUS
INSPECTION SCOPES
................................................................................................................
REACTOR SAFETY
..................................................................................................................
OTHER ACTIVITIES - BASELINE
..........................................................................................
INSPECTION RESULTS
............................................................................................................
EXIT MEETINGS AND DEBRIEFS
............................................................................................ 25
DOCUMENTS REVIEWED
......................................................................................................... 26
PLANT STATUS
Unit 2 began the inspection period at rated thermal power. On October 29, 2018, operators
reduced reactor power to 80 percent for turbine valve testing, followed by repairs to the
condensate pump. Operators returned the unit to rated thermal power on November 1,
2018, and it remained at or near rated thermal power for the remainder of the inspection period.
Unit 3 operated at or near rated thermal power for the entire 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/reading-
rm/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. 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 Entergys performance and
compliance with Commission rules and regulations, license conditions, site procedures, and
standards.
REACTOR SAFETY
71111.01 - Adverse Weather Protection
Seasonal Extreme Weather (1 Sample)
The inspectors evaluated winter readiness of the Unit 2 service water system and the Unit 3
refueling water storage tank on December 20, 2018.
External Flooding (1 Sample)
The inspectors evaluated readiness to cope with external flooding at Units 2 and 3 on
December 11, 2018.
71111.04 - Equipment Alignment
Partial Walkdowns (4 Samples)
The inspectors evaluated system configurations during partial walkdowns of the following
systems/trains:
Unit 2
(1) Control room control panels with temporary scaffolding in place on October 22, 2018
(2) FWH and moisture separator reheat systems on October 26, 2018
(3) Service water following repair of valve SWN-6 on October 28, 2018
Unit 3
(4) 31 service water system on December 11, 2018
Complete Walkdowns (2 Samples)
(1) The inspectors evaluated system configurations during a complete walkdown of the
Unit 3 480 volt analog current distribution system on November 10, 2018.
(2) The inspectors evaluated system configurations during a complete walkdown of the
Unit 3 safety injection system on December 14 and 17, 2018.
71111.05A/Q - Fire Protection Annual/Quarterly
Quarterly Inspection (4 Samples)
The inspectors evaluated fire protection program implementation in the following selected
areas:
Unit 2
(1) Transformer yard (pre-fire plan (PFP)-263) on December 13, 2018
Unit 3
(2) 480 volt switchgear room (PFP-351) on October 1, 2018
(3) Cable spreading room (PFP-352) on October 25, 2018
(4) Turbine building, 15-foot elevation (PFP-362), on November 12, 2018
71111.06 - Flood Protection Measures
Internal Flooding (1 Sample)
The inspectors evaluated internal flooding mitigation protections in:
(1) Emergency diesel generator (EDG) room at Unit 2 on December 19, 2018
71111.11 - Licensed Operator Requalification Program and Licensed Operator Performance
Operator Requalification (3 Samples)
Unit 2
(1) The inspectors observed and evaluated an operator requalification exam on October 2,
2018.
(2) The inspectors observed and evaluated a crew of licensed operators in the plants
simulator during licensed operator requalification training on November 27, 2018.
Unit 3
(3) The inspectors observed and evaluated a crew of licensed operators in the plants
simulator during an emergency planning training drill on December 12, 2018.
Operator Performance (1 Sample)
Unit 3
(1) The inspectors observed and evaluated an operator support of surveillance testing on
October 3, 2018.
71111.11A - Licensed Operator Requalification Program and Licensed Operator Performance
(Annual)
Operator Requalification Exam Results (Annual) (2 Samples)
(1) The inspectors reviewed and evaluated requalification examination results for Unit 2
(operating test only) on November 21, 2018.
(2) The inspectors reviewed and evaluated requalification examination results for Unit 3
(written and operating test) on November 21, 2018.
71111.11B - Licensed Operator Requalification Program and Licensed Operator Performance
(Biennial)
Operator Requalification Program and Operator Performance (Biennial) (1 Sample)
The inspectors reviewed and evaluated operator performance, evaluator performance, and
simulator performance during the Unit 2 requalification examinations completed on
October 18, 2018.
71111.12 - Maintenance Effectiveness
Routine Maintenance Effectiveness (1 Sample)
The inspectors evaluated the effectiveness of routine maintenance activities associated
with the following equipment and/or safety significant functions:
(1) 6.9 kV system at Units 2 and 3 on December 10, 2018
Quality Control (1 Sample)
The inspectors evaluated the following maintenance and quality control activities:
(1) Quality control program for commercial dedication of repair parts at Units 2 and 3 on
December 20, 2018
71111.13 - Maintenance Risk Assessments and Emergent Work Control (4 Samples)
The inspectors evaluated the risk assessments for the following planned and emergent
work activities:
Unit 2
(1) Planned Yellow risk during 21 motor-driven auxiliary feedwater pump maintenance
activities on October 15, 2018
(2) Planned Yellow risk for restoration of offsite electrical power feeder 13W93 on
December 17, 2018
Unit 3
(3) Elevated risk during 32 EDG maintenance window on October 29, 2018
(4) Planned Yellow risk for the 33 EDG 12-year overhaul on December 5, 2018
71111.15 - Operability Determinations and Functionality Assessments (3 Samples)
The inspectors evaluated the following operability determinations and functionality
assessments:
Unit 2
(1) 23 fuel oil transfer pump failed motor condition assessment testing resulting in 23 EDG
being declared inoperable (CR-IP2-2018-05597) on October 10, 2018
Unit 3
(2) Through-wall leak on service water discharge line SWN-49-1 to the 31 component
cooling water heat exchanger (CR-IP3-2018-03011) on October 5, 2018
(3) Through-wall leak on service water temperature indicating line TI-1237 downstream of
SWN-35-2 from the 32 component cooling water heat exchanger (CR-IP3-2018-03023)
on October 8, 2018
71111.18 - Plant Modifications (2 Samples)
The inspectors evaluated the following temporary or permanent modifications:
(1) Engineering Change (EC) Package 79544 - Flow accelerated corrosion extent of
condition and reheat steam system line repairs (permanent modification) at Unit 3 on
September 23, 2018
(2) EC Package 79929 - Bypass nitrogen supply valve 891C to allow manual pressurization
of the 33 accumulator (temporary modification) at Unit 3 on October 25, 2018
71111.19 - Post Maintenance Testing (3 Samples)
The inspectors evaluated post maintenance testing for the following maintenance/repair
activities:
Unit 2
(1) 22 EDG after repairs on December 12, 2018
Unit 3
(2) 31 EDG post maintenance testing following 4-year engine maintenance and inspection
on October 2, 2018
(3) Service water post maintenance testing following repair of leak on valve SWN-77-4 on
October 31, 2018
71111.22 - Surveillance Testing
The inspectors evaluated the following surveillance tests:
Routine (2 Samples)
(1) 2-PT-M048, 480 volt undervoltage alarm at Unit 2 on December 13, 2018
(2) 3-PC-OL27H, Electrical bus 6A 480 volt undervoltage relays inspection and calibration at
Unit 3 on December 18, 2018
71114.04 - Emergency Action Level and Emergency Plan Changes (1 Sample)
The inspectors verified that the changes made to the emergency plan were done in
accordance with Title 10 of the Code of Federal Regulations (10 CFR) Part 50.54(q)(3), and
any change made to the Emergency Action Levels, Emergency Plan, and its lower-tier
implementing procedures had not resulted in any reduction in effectiveness of the Plan.
This evaluation does not constitute NRC approval.
71114.06 - Drill Evaluation
Emergency Planning Drill (1 Sample)
The inspectors evaluated the conduct of a routine Entergy emergency drill, including a
hazardous environment in the cable spreading room (Alert declaration), the closure of an
MSIV at 100 percent power with failure of the reactor protective system (Site Area
Emergency declaration), and a loss of coolant accident into containment with fuel failure
and potential failure of containment (General Emergency declaration) at Unit 3 on
December 12, 2018. This drill also involved the activation of the alternate Emergency
Operations Facility in Fishkill, New York.
OTHER ACTIVITIES - BASELINE
71151 - Performance Indicator Verification
Mitigating Systems Performance Index (2 Samples)
The inspectors verified Entergys performance indicators submittals listed below for the
period from October 1, 2017, through September 30, 2018:
Unit 2
(1) Safety System Functional Failures (MS05)
Unit 3
(2) Safety System Functional Failures (MS05)
Operational Exposure Control Effectiveness (1 Sample)
The inspectors reviewed Entergys submittals for the occupational radiological occurrences
performance indicator for the period from October 1, 2017, through September 30, 2018.
Radiological Effluent TS/Offsite Dose Calculation Manual Radiological Effluent Occurrences
(1 Sample)
The inspectors reviewed Entergys submittals for the radiological effluent TS/Offsite Dose
Calculation Manual radiological effluent occurrence performance indicator for the period
from October 1, 2017, through September 30, 2018.
71152 - Problem Identification and Resolution
Semiannual Trend Review (1 Sample)
The inspectors reviewed Entergys corrective action program for trends that might be
indicative of a more significant safety issue.
Annual Follow-Up of Selected Issues (4 Samples)
The inspectors reviewed Entergys implementation of its corrective action program related to
the following issues:
(1) Service water integrity corrective actions for leaks in American Society of Mechanical
Engineers (ASME) Class III systems at Units 2 and 3
(2) Corrective action effectiveness for pressurizer level channel L-461 at Unit 2
(3) Follow-up of cyber security Technical Instruction 2201/004 at Units 2 and 3 (Official Use
Only - Security Related Information, Indian Point Nuclear Generating Units 2 and 3 -
Temporary Instruction 2201/004, Inspection of Implementation of Interim Cyber Security
Milestones 1-7, Reports 05000247/2015405 and 05000286/2015405 (Agencywide
Documents Access and Management System (ADAMS) Accession No. ML15295A050))
is documented in Official Use Only - Security Related Information, Indian Point Energy
Center, Units 2 and 3 - Security Inspection Report 05000247/2018410 and
05000286/2018410 (ADAMS Accession No. ML18341A038).
(4) Corrective actions for groundwater contamination at Unit 2
71153 - Follow-Up of Events and Notices of Enforcement Discretion
Events (2 Samples)
The inspectors evaluated response to the following events:
Unit 2
(1) Unplanned TS 3.0.3 entry and preparations for reactor downpower following failure of
service water header cross-tie valve SWN-6 on October 28, 2018
Unit 3
(2) Fire and loss of qualified source of offsite power GT/2F breaker and bus on October 12,
2018.
Licensee Event Reports (LERs) (2 Samples)
The inspectors evaluated the following LERs, which can be accessed at
https://lersearch.inl.gov/LERSearchCriteria.aspx:
(1) LER 05000286/2018-002-00, Manual Reactor Shutdown Due to Weld Leak on Safety
Injection System Tank (ADAMS Accession No. ML18313A129)
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 also concluded that no violation of NRC requirements occurred.
(2) LER 05000286/2018-003-00, Manual Reactor Trip Due to a Steam Leak on a High
Pressure Feedwater Heater (ADAMS Accession No. ML18341A122)
The circumstances surrounding this LER are documented in the Inspection Results
section, FIN 05000286/2018004-02.
INSPECTION RESULTS
Inadequate Control of Transient Combustibles in the 480 Volt Electrical Switchgear
Room
Cornerstone Significance Cross-Cutting Report
Aspect Section
Mitigating Green H.5 - Work 71111.05Q
Systems NCV 05000286/2018004-01 Management
Closed
Introduction: The inspectors identified a Green NCV of Unit 3 TS 5.4.1 when Entergy did not
take adequate measures to control transient combustibles in accordance with established
procedures and thereby did not maintain in effect all provisions of the approved fire protection
program, as described in the Unit 3 final safety analysis report. Specifically, on two separate
occasions, Entergy did not ensure that transient combustibles were evaluated in accordance
with established procedures; and as a result, they allowed combustible loading in the 480 volt
emergency switchgear room to exceed limits established in the FHA of record.
Description: On August 28, 2018, the inspectors questioned the presence of scaffolding
containing fire-retardant wooden planks, located in the 480 volt emergency switchgear room,
and whether or not Entergy had developed an associated transient combustibles evaluation
(TCE) in accordance with fleet procedure EN-DC-161, Control of Combustibles. The
switchgear room is classified by EN-DC-161 as a Level-2 plant area, and EN-DC-161 thereby
requires that a TCE be processed when a job involves the introduction of more than
100 pounds of fire-retardant treated lumber. Entergy determined that the amount of lumber
included in the scaffolding materials (an estimated 260 pounds) exceeded this 100-pound
threshold, and they documented the issue in CR-IP3-2018-02527. Entergy then developed
TCE 18-054, which concluded that the transient combustibles did not present a significant fire
protection concern and that no special fire protection measures were required while materials
were present. The scaffolding was left in place, as it was still to be used for ongoing work.
On October 1, 2018, while observing maintenance activities in the 31 EDG cell (located
adjacent to the 480 volt switchgear room), the inspectors identified three 55-gallon drums
(total of 165 gallons) of diesel generator lubrication oil (lube oil) being stored in the switchgear
room, unattended. The inspectors questioned whether or not Entergy had developed an
associated TC
- E. EN-DC-161 requires, for Level-2 plant areas, that a TCE be processed
when a job involves the introduction of more than 5 gallons of combustible liquids in approved
containers. Additionally, EN-DC-161 states that when lube oil is collected in drums outside of
a designated storage area, the drums should be removed from the building or placed in an
approved storage area either upon completion of shift following filling of the drum, or at the
completion of the job, whichever comes first. The oil drums, however, had been filled and
staged in the switchgear room during the previous shift. Entergy determined that TCE 18-061
had been developed for the work in the EDG cell, but that this TCE did not apply to the
switchgear room, which was a separate fire zone. This issue was documented in
CR-IP3-2018-02958, and Entergy then developed TCE 18-061, Revision 2, to address the
staging of combustibles in the switchgear room. The evaluation concluded that the
introduction of these combustibles would not adversely impact the fire protection program, nor
would it challenge the conclusions of the FHA or the Appendix R safe-shutdown analysis
because the oil contained in steel drums did not have a high potential for ignition, and the
work being performed did not entail the introduction of additional ignition sources into the
area. It was therefore concluded that no special fire protection or compensatory measures
were required. The drums were removed during the following shift, after the associated
maintenance activities were completed.
From TCE 18-061, the inspectors determined that the three 55-gallon drums of lube oil
staged in the switchgear room introduced an estimated heat load of 6,744 BTU/ft2.
TCE 18-054 estimated that the wood scaffolding materials introduced a heat load of
1,581 BTU/ft2. The Unit 3 FHA, as revised by EC-76353, established a maximum permissible
combustible loading (loading limit) of 80,000 BTU/ft2. The revised FHA also listed a fixed
loading in the switchgear room (from permanently-staged permanently equipment) of
79,545 BTU/ft2. The inspectors thereby concluded that, in the case of the wood scaffolding
being present in the switchgear room, the total heat load (fixed plus transient) was estimated
to be 1,126 BTU/ft2 in excess of the FHA loading limit. In the case of the wood scaffolding
plus the oil drums, the total heat load was estimated to be 7,870 BTU/ft2 in excess of the FHA
loading limit.
The oil drums were immediately removed from the switchgear room. The wood scaffolding
planks, however, remained in the switchgear room, as they were to be used for ongoing work.
The continued presence of a combustible loading in excess of the established loading limit for
the room was documented in CR-IP3-2018-03633. To resolve the outstanding discrepancy,
Entergy reviewed associated analyses and concluded that an excessive degree of
conservatism was built into the 80,000-BTU/ft2 limit. Prior to the development of EC-76353,
the loading limit had been established to be 120,000 BTU/ft2, based on the assumption that
all fire barriers enclosing the room could withstand a fire lasting up to 11/2 hours. However,
this assumption had been brought into question during a 2017 NRC inspection, which
identified that the dimensions of a damper assembly in the room slightly exceeded the
acceptable dimensions for credited 11/2-hour fire barrier. The loading limit for the room was
thereafter reduced to 80,000 BTU/ft2 to account for a more conservative assumption that the
fire barriers could withstand a fire of at least one hour, as documented in IP3-ANAL-FP-0132,
Fire Damper Assembly Analysis. In reviewing the case of wood scaffolding staged in the
room, Entergy concluded that, based on the conservatism built into the reduced limit, the
introduction of an excess loading of 1,126 BTU/ft2 (which would equate to approximately 0.8
minutes of additional potential fire severity) would not pose a significant concern. On
November 19, 2018, TCE 18-054, Revision 1, was developed documenting this conclusion
and providing justification for the continued staging of the scaffolding in the room.
Subsequently, on November 29, 2018, Entergy implemented EC 80670, which established a
new loading limit of 100,000 BTU/ft2. This increased limit reflected the engineering judgment
that the dampers were of a structural configuration that could contain a fire lasting nearly 11/2
hours and that a limit of 100,000 BTU/ft2 would provide an adequate degree of conservatism,
while allowing for the conduct of activities in the room that introduce an acceptable amount of
transient combustibles. The NRC inspectors reviewed the associated assessment and
agreed that this conclusion was reasonable.
Corrective Actions: Regarding the wood scaffolding stored in the switchgear room without an
associated TCE in place, Entergy generated CR-IP3-2018-02527, developed TCE 18-054,
and thereafter revised TCE 18-054 to justify the continued presence of the scaffolding despite
the fact that it constituted a combustible loading in excess of the loading limit listed in the FHA
of record. Regarding the case of the lube oil drums, Entergy generated CR-IP3-2018-02958,
revised TCE 18-061 to incorporate the switchgear room into the evaluation, and removed the
oil drums after the associated maintenance activities were completed.
Corrective Action References: CR-IP3-2018-02527, CR-IP3-2018-02958, and
Performance Assessment:
Performance Deficiency: The inspectors determined that not completing a TCE, as required
by EN-DC-161, Control of Combustibles, Revision 18, was a performance deficiency, given
that it was reasonably within Entergys ability to foresee and correct and should have been
prevented. Specifically, on August 28, 2018, wood in excess of 100 pounds was identified in
the switchgear room; however, an associated TCE had not been developed. Additionally, on
October 1, 2018, three 55-gallon drums of EDG lube oil were stored in the switchgear room
without an associated TCE having been developed to authorize storage in this room, as
required for a volume of lube oil in excess of 5 gallons.
Screening: The inspectors determined the performance deficiency was more than minor
because it was associated with protection against external factors attribute of the Mitigating
Systems cornerstone, and it adversely affected the cornerstone goal of ensuring the
availability, reliability, and capability of systems that respond to initiating events to prevent
undesirable consequences. Specifically, storage of combustibles in excess of the maximum
permissible combustibles loading could have the potential to challenge the capability of fire
barriers to prevent a fire from affecting multiple fire zones and further degrading plant
equipment. Additionally, this issue was similar to an example listed in IMC 0612, Appendix E,
"Examples of Minor lssues," Example 4.k., because the fire loading was not within the FHA
limits established at the time. Entergy required the issuance of a revised evaluation to
provide reasonable assurance that the presence of combustibles of a quantity in excess of
the loading limit of record would not challenge the capacity of fire barriers, and further
evaluation and the issuance of an EC was necessary to raise the established loading limit to
a less-conservative value.
Significance: The inspectors assessed the significance of the finding using IMC 0609,
Appendix F, Fire Protection Significance Determination Process, and determined that this
finding screened to Green (very low safety significance) because it had a low degradation
rating in accordance with Attachment 2 of the appendix.
Cross-Cutting Aspect: The inspectors determined that this finding had a cross-cutting aspect
in the area of Human Performance, Work Management, because Entergy did not adequately
plan, control, and execute work activities such that nuclear safety was the overriding priority,
nor did they adequately identify risk associated with work being performed or coordinate
across working groups to anticipate and manage this risk. Specifically, in the case of wood
scaffolding being stored in the switchgear room, while planning work to be performed,
Entergy did not adequately consider the fire risk that would be introduced by the presence of
additional combustible materials. In the case of lube oil being stored in the room, Entergy did
not take adequate action to ensure that activities were executed in a manner that would
prevent work taking place in one area (the adjacent EDG cell) from introducing additional fire
risk into a space for which it had not been evaluated (the switchgear room). In both cases,
Entergy did not take sufficient action to ensure that workers were aware of the fire protection
requirements associated with activities being conducted and to ensure that they coordinated
as needed across working groups to adequately assess and mitigate the associated fire risk.
Enforcement:
Violation: Unit 3 TS 5.4.1 states, in part, that written procedures shall be established and
implemented covering fire protection program implementation. Entergy procedure EN-DC-
161, Control of Combustibles, is the controlling document for the control of transient
combustible materials within the fire protection program. EN-DC-161, Revision 18, requires,
in part, that a TCE be processed if non-exempt combustible materials associated with a job in
a Level 2 area include an excess of either 100 pounds of fire retardant treated lumber or 5
gallons of combustible liquids in approved containers.
Contrary to the above, on August 28, 2018, and October 1, 2018, Entergy did not process a
TCE associated with storage of non-exempt combustible materials in excess of the limits
listed in EN-DC-161 for a Level 2 area. Specifically, Entergy stored greater than 100 pounds
of fire-retardant treated lumber and greater than 5 gallons of diesel generator lube oil in the
480 volt essential switchgear room without processing an associated TC
- E. Furthermore, from
August 28, 2018, to November 29, 2018, Entergy allowed the total combustibles loading in
the room to exceed the limit established in the FHA, as modified by EC 76353.
Disposition: This violation is being treated as an NCV, consistent with Section 2.3.2 of the
Failure to Adequately Manage Flow Accelerated Corrosion on a Reheat Steam Line
Caused a Steam Leak and a Reactor Trip
Cornerstone Significance Cross-Cutting Report
Aspect Section
Initiating Events Green None 71153
Closed
Introduction: A self-revealed Green finding (FIN) was identified when Entergy did not
adequately manage the degradation of the 36C FWH reheat steam lines, as required by
EN-DC-315, Flow Accelerated Corrosion Program. The failure resulted in a large steam
leak in the Unit 3 turbine building from the 36C FWH reheat steam line, which required
tripping the reactor and shutting the MSIVs to isolate the leak for plant and personnel safety.
Description: On September 18, 2018, Entergy identified a small steam leak on the 36C FWH
reheat steam line. Over the period of approximately one hour, this steam leak increased in
size until a decision was made to evacuate the turbine building, trip the reactor, and shut the
MSIVs to stop the steam leak. Attempts to isolate the leak locally were unsuccessful. The
event was promptly reported to the NRC (Manual Reactor Trip Due to a Steam Leak on a
High Pressure Feedwater Heater, Event Number 53611) under 10 CFR 50.72(b)(2)(iv)(B),
Valid Reactor Protective System Actuation, 10 CFR 50.72(b)(3)(iv)(A), Valid Safety System
Actuation, and LER 05000286/2018-003-00, Manual Reactor Trip Due to Steam Leak on High
Pressure Feedwater Heater (ADAMS Accession No. ML18341A122).
Entergy had adopted the industry standard software program, CHECWORKs', to monitor
and predict the effects of flow-accelerated corrosion (FAC) in susceptible piping systems,
including the high pressure FWH reheat steam system. Entergy follows the requirements
specified in EN-DC-315 by invoking the guidelines contained in reference 9 of the procedure
(Electric Power Research Institute (EPRI), Nuclear Safety Analysis Center 202L,
Recommendations for an Effective Flow Accelerated Corrosion Program) and in
reference 18 (EPRI, Technical Report 1019176, CHECWORKS' Steam Feedwater
Application, Guidelines for Plant Modeling, and Evaluation of Components, dated
November 2009), along with other industry guidelines. The objective of the FAC program is
to predict, detect, monitor, and minimize degradation of single and two-phase flow piping
(safety- and non-safety-related systems) to prevent failures while enhancing plant safety and
reliability.
FAC occurs when a normally protective oxide layer on a metal surface dissolves in fast
flowing water or wet steam. The underlying metal corrodes to recreate the oxide, and the
metal loss continues. The rate of FAC degradation depends on the flow velocity, fluid
temperature, chemistry, and other system-related parameters. FAC only affects carbon steel
piping carrying ultra-pure, deoxygenated water, or wet steam. CHECWORKs' is used by
the industry to determine which system components are most susceptible to FAC, predict the
wear rate of these components, and identify when the components need to be repaired or
replaced prior to experiencing component failure. However, the components must be
properly modeled in CHECWORKs', and the program must be calibrated by measuring
various representative wear rates on the components and inputting the inspection data into
the CHECWORKs' program. Wear rate modeling in CHECWORKs' is based on realistic
models, not conservative models. The program predicts a median wear rate, which implies
that 50 percent of the components modeled will have higher wear rates than the model
predicts. As a result, the assessment of component susceptibility depends heavily on the
accuracy of the modeling, the calibration of the model by inputting actual inspection data, and
the conservative selection of criteria for monitoring susceptible components.
Previously, in 2007, the 36C FWH reheat steam line experienced erosion failure at a different
component location/line section, and this failure was also not predicted by the
CHECWORKS' model. The size of this failure was small, and the steam leak was isolated
without impacting plant performance. Entergy did not reassess the predictive validity of the
model for this line following the 2007 failure. The inspectors concluded that this event
represented an opportunity to revise the model to reflect the new information that the 36C
FWH reheat steam line was experiencing greater FAC wear rates than either the 36A and
36B lines and to adjust the model to better predict the actual FAC wear rates in the 36C FWH
reheat steam line. Had this change been made in accordance with program direction, the
subsequent failure could have been predicted and thereby prevented. However, the failed
line was repaired, extent of condition assessment was limited, and no further action was
taken to modify the CHECWORKS' model. The high pressure FWH reheat steam lines
were modeled in CHECWORKS' by a single reheat steam line that was supposed to be
representative of all three reheat steam lines into the 36A, 36B, and 36C FWHs. This model
is appropriate only if the wear rates on the three lines are the same. However, it was clear
from the 2007 failure that the wear rate on the 36C FWH reheat steam line was more
aggressive than the other lines, and the FAC wear rates could not be accurately represented
by a single line in the CHECWORKS' model. The inspectors concluded that this steam line
failure should have resulted in Entergy expanding the scope for FAC inspections during the
2009 refueling outage, but the opportunity to do so was missed.
Entergy subsequently completed a root cause evaluation for the 2018 reheat steam line
failure in November of 2018. The root cause evaluation concluded that the cause of the
failure was that the FAC engineers did not use the system operating experience and
replacement history to identify that reheat steam line piping to the 36C FWH was more
susceptible to FAC than the same reheat steam piping to the 36A and 36B FWHs. Entergy
identified that failures had occurred in 2007 on the 36C FWH reheat steam line branch. As a
result, additional inspections should have been performed on the 36C FWH reheat steam line
compared to the 36A and 36B lines because the 36C FWH reheat steam line was more
susceptible to FAC. Entergy concluded that this action should have identified the wall
thinning prior to failure. Also contributing to the failure was a weakness in the setup of the
CHECWORKs' model whereby the three parallel lines to the 36A, 36B, and 33C FWHs
were modeled as a single representative line when the reality was that the actual FAC wear
rates were different on each line. Another contributing cause was that the extent of condition
guidance for scope expansion in EN-DC-315 was limited to components within two
diameters downstream which did not include the elbow in the line that subsequently failed.
The inspectors independently reviewed the root cause evaluation and concluded that Entergy
had adequately identified the proximate cause of the failure.
The reheat steam lines to the high pressure FWHs are not classified as safety-related
components and are therefore not subject to the requirements of the quality assurance
program. However, they are subject to the requirements of Entergys internal procedures
including EN-DC-315 and referenced documents. In addition, the renewed license for Unit 3
commits Entergy to managing age-related degradation of the 36C FWH reheat steam lines
under the FAC program described in EN-DC-315.
Corrective Actions: Entergy replaced the failed section of the 36C FWH reheat steam line
and completed an extent of condition assessment on all the reheat steam lines going into the
36C FWH. Entergy inspected approximately 43 additional component locations on the 36
FWH reheat steam lines and replaced several additional affected sections that had
experienced substantial FAC erosion; greater than predicted by CHECWORKs'.
Corrective Action References: CR-IP3-2018-02773 and CR-HQN-2018-02056
Performance Assessment:
Performance Deficiency: The inspectors determined that failure to follow the requirements of
EN-DC-315 and industry guidelines incorporated by reference was a performance deficiency
that was within Entergys ability to foresee and correct. Specifically, the 36C FWH reheat
steam line was not conservatively modeled in the CHECWORKs' software application
program because Entergy did not follow the guidelines contained in reference 9 of the
procedure (EPRI, Nuclear Safety Analysis Center 202L, Recommendations for an Effective
Flow Accelerated Corrosion Program) and reference 18 of the procedure (EPRI, Technical
Report 1019176, CHECWORKS' Steam Feedwater Application, Guidelines for Plant
Modeling and Evaluation of Components, dated November 2009). Specifically, Entergy did
not update the FAC modeling of the high pressure FWH reheat steam lines in 2007 when a
prior component failure occurred. In addition, Entergy modeled six parallel high pressure
FWH reheat steam lines as a single representative line, contrary to the guidance in the
program documents. This guidance states, It is recommended that parallel trains be divided
into separate lines. This allows improved evaluation during model calibration. The
procedure further states, It is strongly recommended that all parallel trains of susceptible
systems be fully modeled. This is because parallel trains are rarely identical. Entergy did
not recognize that the single-line model in CHECWORKs' was not representative of the
actual FAC wear rate in the 36C FWH reheat steam line, because the unique operating
parameters in this line were more adverse than those parameters in the 36A and 36B FWH
reheat steam lines. The inspectors therefore determined that while the performance
deficiency was within Entergys ability to foresee and prevent, it did not occur within the three-
year period of current performance assessment.
Screening: Using IMC 0612, Appendix B, Issue Screening, the inspectors determined the
performance deficiency was more than minor because it was associated with the equipment
performance attribute of the Initiating Events cornerstone and adversely affected the
cornerstone objective to limit the likelihood of events that upset plant stability and challenge
critical safety functions during shutdown as well as power operations. Specifically, the failure
of the 36C FWH reheat steam line caused hazardous conditions in the turbine building, which
required the operators to manually trip the reactor and shut the MSIVs.
Significance: The inspectors assessed the significance of the finding using IMC 0609,
4, Initial Characterization of Findings, and determined that performance
deficiency affected the Initiating Events cornerstone as a transient initiation contributor.
Specifically, the failure of the reheat steam piping led to a reactor trip. Using IMC 0609,
Appendix A, Exhibit 1, Initiating Events Screening Questions, the inspectors determined that
the finding screened to Green. Specifically, the reheat steam line break caused the operators
to manually trip the reactor, but it did not also cause the loss of mitigation equipment relied
upon to transition the plant from the onset of the trip to a stable shutdown condition.
Specifically, the auxiliary feedwater system started and responded as designed during a
Cross-Cutting Aspect: The inspectors did not assign a cross-cutting aspect for this issue
because it was not indicative of current Entergy performance. The performance deficiency
occurred in 2007, when a prior failure occurred in the 36C FWH reheat steam line which
should have caused Entergy to assess the predicative validity of the susceptibility modeling
for this line in CHECWORKs'.
Enforcement: The inspectors did not identify a violation of regulatory requirements
associated with this finding.
Observations 71152
Annual Follow-Up of
Selected Issues
Service Water Integrity Corrective Actions for Leaks in ASME Class III Systems
The inspectors reviewed the effectiveness of the corrective actions associated with the
resolution of the high incidence of through-wall leaks in ASME Class III service water system
piping observed in 2015 and 2016. The ASME code does not permit plants to continue to
operate indefinitely with through-wall leaks in ASME Class III piping. If a leak occurs, further
analysis is required under the code to demonstrate structural integrity of the leaking pipe or
component and system operability.
In 2015 and 2016, there was an increase in the frequency of through-wall leaks in service
water pipes in both units which resulted in the generation of several LERs. This trend was
assessed during a problem identification and resolution inspection sample at the end of 2016
by a specialized engineering inspector from the Division of Reactor Safety (Indian Point
Integrated Inspection Report 05000247/2016004 and 05000286/2016004 (ADAMS Accession
No. ML17037C541)). The inspectors determined that, in general, Entergys overall response
to the service water system piping leaks was commensurate with the safety significance and
included appropriate compensatory actions. The inspectors concluded that completed and
planned actions were reasonable to correct the service water system piping weld flaw leakage
problems.
In 2018, the inspectors revisited this issue of concern to verify that the planned actions from
2016 had been completed and to assess their effectiveness. The inspectors concluded that
the service water integrity improvement program had reduced the number of through-wall
leaks from previous years. The service water leak database showed a substantial reduction
in ASME Class III piping system through-wall leaks in 2017 and 2018. In 2015, there were
nine through-wall leaks and in 2016 there were five through-wall leaks. The inspectors
concluded that this reduction was primarily due to the effectiveness of corrective actions from
Entergys service water integrity improvement program including the replacement of degraded
carbon steel radiation monitor piping with corrosion resistant stainless alloy (AL6xn) piping.
The inspectors also noted one of Entergys service water leak mitigation plans included the
installation of mechanical seals over the unprotected weld joints on the inside diameter of the
cement-lined carbon steel piping on service water header lines on Unit 2 to address the
crevice corrosion initiated leaks. The inspectors reviewed Indian Points Generic Letter 89-13
program and the service water pre-outage non-destructive examination inspection database
to verify that Entergy was adequately tracking and prioritizing vulnerable service water piping
locations and scheduling inspections on required pipe weld locations.
The inspectors noted that insulation kits had not been consistently installed between the new
stainless steel AL6xn service water lines (primarily serving the radiation monitors) and the old
carbon steel service water lines. This condition causes the establishment of a galvanic
corrosion cell at the interface between the dissimilar metals and may result in accelerated
corrosion if the difference in the electrode potentials between carbon steel and stainless steel
is high. However, to date, there has been no substantial degradation identified in these
dissimilar metal joints. A license renewal commitment requires monitoring of dissimilar metal
joints for potential future degradation.
In the late 1990s, Unit 3 completed a project to update the safety classifications for
safety-related systems, structures, and components and conservatively reclassified all piping
systems that were originally built under ASME Code B31.1 and seismic Class I requirements
to ASME Code Class II
- I. Subsequently, the inspectors also noted that service water lines that
were formerly classified as ASME Code Class III and subject to comprehensive
code-mandated inspections had been reclassified to ASME Code B31.1 because the original
classification was later determined to be overly conservative.
Component cooling water heat exchanger line 405 was reclassified under EC 61654 primarily
on the bases that a failure of the heat exchanger discharge line would not impede the safety
function of the service water system and component cooling water heat exchangers because
failure of line 405 would not restrict or reduce service water flow to the safety-related
components (CR-HQN-2017-00416). The Unit 3 common service water discharge line from
the outlet of the component cooling water heat exchangers had experienced corrosion that
reduced the wall thickness of the piping below the required minimum wall thickness. The
corrective action to restore structural integrity was to install a carbon fiber wrap around the
pipe to restore structural integrity under EC 61654. However, the installation of carbon fiber
wrap is not a code-approved repair and could not be used on ASME Class III pipe. Entergy
subsequently declassified the corroded pipe from ASME Class III to ASME Class B31.1,
seismic Class I, in order to meet the code requirements to install carbon fiber wrap on line
405. This issue of concern resulted in opening an unresolved item (URI) in Indian Point
Integrated Inspection Report 05000247/2017004 and 05000286/2017004 (ADAMS Accession
No. ML18045A497). The inspectors subsequently closed the URI after completing a
comprehensive inspection, as documented in Indian Point Integrated Inspection Report 05000247/2018001 and 05000286/2018001 (ADAMS Accession No. ML18131A024) by a
Division of Reactor Safety Engineering inspector.
In another case, on October 2, 2017, a through-wall leak was identified at FCV-1176A on the
10-inch common service water discharge line from all three Unit 2 EDGs
(CR-IP2-2017-03616). The section of piping had been declassified from ASME Class III to
ASME B31.1. The through-wall leak was located on a socket welded fitting for a drain line
and could not be repaired under an approved ASME code case. The service water pipe
component was classified under ASME B31.1, which then allowed the installation of a
temporary housekeeping patch for a six-month period until the component could be
weld-repaired during a 2018 outage.
In each case, the inspectors determined that the reclassification from ASME Code Class III to
ASME Code B31.1 met the requirements under 10 CFR 50.59, Changes, Tests, and
Experiments, and 10 CFR 50.55a, Codes and Standards, at the time of the reclassification.
However, the inspectors noted that the inspection requirements for ASME B31.1 (seismic
Class I) piping to maintain piping integrity are not well-specified as they were under the ASME
Class III Code. The catastrophic failure of the component cooling water heat exchanger
discharge pipe could potentially result in the flooding of portions at the Unit 3 auxiliary building
and failure of associated safety significant equipment in the nearby area. The failure of the
common service water discharge line from the Unit 2 EDGs could flood the common EDG
sump, which could compromise the operability of all three EDGs.
Observations 71152
Annual Follow-Up of
Selected Issues
Corrective Action Effectiveness for Pressurizer Level Channel L-461
The inspectors reviewed the effectiveness of the corrective actions associated with the
resolution of an out-of-tolerance condition in pressurizer level channel III, L-461, and
pressurizer level indicator (LI)-461. On February 3, 2017, L-461 had drifted out of the upper
end of the acceptable tolerance band as previously documented in CR-IP2-2017-00477.
Entergy had completed an operability determination and concluded that L-461 was operable
because it would still perform its safety function. The as-left channel calibration for LI-461
was realigned under a temporary modification to bias the indicated 100 percent operating
point downward by approximately 8 percent (CR-IP2-2017-00481) to offset the instrument drift
in the high direction by adjusting LI-461 and LM-461 (signal conditioner). However, on
January 22, 2018, L-461 drifted further out of tolerance in the high direction at the upper
calibration point in the band. The as-left indication at 100 percent level for LI-461 was reading
96.0 percent with the surveillance test acceptance criteria from 97.2 percent to 102.8 percent
which resulted in L-461 failing the surveillance test and not meeting the previously established
revised operability criteria. If instrumentation and control had realigned the upper instrument
calibration point upwards to restore tolerance at the high end of the instrument band, then LI-
461 would subsequently fail the channel check criteria for comparison with the other
pressurizer level instruments (LI-459 and LI-460) while at power (60 percent pressurizer
programed level at 100 percent power).
Unit 2 has three safety-related channels for measuring pressurizer level L-459, L-460, and
L-461. Biasing the 100 percent operating point for the level indicator, LI-461, realigns the
indicated level, LI-461, in the control room but does not change the actual setpoint of the
pressurizer level signal from the level transmitter, (LT)-461, to the reactor trip bistables.
Biasing LI-461 downward by 8 percent to more accurately indicate pressurizer level implies
that the actual level trip signal input to the bistables is higher (by 8 percent) than the indicated
pressurizer level on LI-461 in the control room. If the level transmitters LT-459 and LT-460 for
channels L-459 and L-460 were reading pressurizer level accurately, and LI-461 was not
biased downward, LI-461 and LT-461 would be indicating 8 percent higher than the other
channels and 8 percent higher than actual pressurizer level. This implies that on an
increasing pressurizer level transient event, L-461 will trip the associated reactor protective
system bistable sooner (at a lower actual pressurizer level) than the other channels.
Entergy determined that the most likely cause of the alignment error was the introduction of a
gas bubble into the reference leg of the pressurizer level transmitter LT-461. LT-461 was
subsequently replaced during the Unit 2 refueling outage in March/April of 2018 and the new
pressure transmitter was calibrated satisfactorily for cold conditions in the pressurizer.
Following the restart from the refueling outage in April 2018, LI-461 still was indicating higher
than the other pressurizer level channels, but remained within acceptable tolerance for
surveillance testing and channel checks. On June 3, 2018, LI-461 was noted to be drifting
higher than that other level instruments at the 100 percent power programed level (60 percent
pressurizer level) during channel checks (CR-IP2-2018-03560). As a result, LI-461 was again
modified (biased low) to realign the upper point of the instrument band such that L-461
passed the surveillance test at 100 percent pressurizer level and LI-461 passed the channel
checks at 60 percent level. On September 6, 2018, L-461 finally diverged at the high end of
the instrument band and could not be further adjusted without challenging the channel check
acceptance criteria for LI-461 in the mid-range. The as-left LI-461 pressurizer level was
indicating 97 percent when the acceptance criteria was 98 percent to 102 percent (CR-IP2-
2018-05070). Entergy referred to the operability determination in CR-IP2-2017-00481 and
determined, as before, that channel L-461 remained operable because it could still perform its
safety function to trip the reactor on an increasing pressurizer level transient prior to
exceeding the high level setpoint at 89 percent pressurizer level. As before, the operability
evaluation concluded that L-461 would send a trip signal early to the bistables (at a lower than
required trip setpoint while pressurizer level was increasing) but that L-459 and L-460
bistables would not reach their trip setpoints until the required pressurizer level of 89 percent
from the accident analysis. A reactor trip signal on high pressurizer level requires a
coincidence of 2 of 3 channels to trip the reactor and would not occur until one of the other
accurate channels reached 89 percent.
On December 21, 2018, at the 100 percent power programmed pressurizer level, LI-459 was
indicating 54.3 percent, LI-460 was indicating 54.6 percent, and LI-461 was indicating high
61.7 percent. This meets the criteria for an acceptable channel check at 100 percent power
(within 8 percent). However, LI-461 was still out of the acceptance band (low) for the high
level reactor trip setpoint at this high end (100 percent pressurizer level) of the instrument
band.
The inspectors concluded that channel L-461 is in an operable but degraded condition
because the channel will trip at a higher trip setpoint than allowable in the accident analysis.
L-461 is operable because L-461 will still perform its safety function (trip the reactor prior to 89
percent pressurizer level) but it will trip sooner (lower) on an increasing level transient than the
other two channels. It is degraded because LT-461 is not calibrated within the acceptance
conditions required under the setpoint control program which is part of the plants design
basis. Entergy considers L-461 to be operable but not degraded as stated in CR-IP2-2018-
05070 in accordance with EN-OP-104, Operability. The corrective actions taken during the
last refueling outage in 2018 were considered to be reasonable but were ineffective in
restoring L-461 within the acceptance criteria in TS 3.3.1. This degraded condition is not
considered a significant condition adverse to quality and, as such, recurrence of the degraded
condition is not required to be prevented, only corrected. If operation of Unit 2 continues
beyond the scheduled final defueling outage in 2020, this condition will have to be corrected
to restore compliance with 10 CFR Part 50, Appendix B, Criteria XVI, Corrective Actions,
prior to restart.
Observations 71152
Annual Follow-Up of
Selected Issues
Corrective Actions for Groundwater Contamination
The inspectors reviewed and assessed Entergys corrective actions associated with a Notice
of Violation (NOV) regarding 10 CFR 20.1406(c) for Entergys failure to conduct operations to
minimize the introduction of residual radioactivity into the subsurface of the site
(VIO 05000247/2016003-07, Inadequate Control of Floor Drains to Minimize Groundwater
Contamination, documented in Indian Point Integrated Inspection Report 05000247/2016003
and 05000286/2016003; EA-16-193 (ADAMS Accession No. ML17013A233)).
Observations: (Closed) VIO 05000247/2016003-07, January 2016 Groundwater
Contamination. The inspectors interviewed personnel knowledgeable of the groundwater
contamination events, interviewed members of Entergys groundwater monitoring team and
its contract hydrogeologists, reviewed documentation and building drawings, and conducted
site walk down observations of the areas hardened (sealed) to prevent unmonitored releases
of radioactive materials.
Description: In February 2016, Entergy notified the NRC of a significant increase in
groundwater tritium levels measured at three monitoring wells (MW-30, MW-31, and MW-32)
located near the Unit 2 fuel storage building (FSB). In August 2016, Entergy notified the
NRC of the detection of Cobalt-58 measured in MW-32 located near the Unit 2 FSB.
The inspectors identified a Green NOV of 10 CFR 20.1406(c) for Entergys failure to
conduct operations to minimize the introduction of residual radioactivity into the subsurface
of the site (groundwater). Specifically, on January 2016, a spill caused by multiple floor
drain obstructions resulted in the backup of contaminated water onto the floor of the 35-foot
elevation of the primary auxiliary building and the subfloor of the Unit 2 FSB with
subsequent leakage to onsite groundwater. In June/July 2016, another event occurred due
to an obstructed flow path through a floor drain in the FSB, which spilled to the subfloor and
contaminated the onsite groundwater.
Entergy completed a root cause analysis and determined that a contributing cause was that
the floor drain systems were not maintained clear of obstructions and interferences and that
Entergy had not verified the ability of the floor drains to handle the volume and flowrates for
draining activities being conducted. As a result, repeated spills of contaminated water
within the radiological controlled area leaked to onsite groundwater.
Entergys Response to NOV: In an NOV response letter to the NRC (Reply to a Notice of
Violation; EA-16-193, Indian Point Nuclear Generating Unit No. 2, dated February 16, 2017
(ADAMS Accession No. ML17054C823)), Entergy stated the reason for the violation and
corrective steps taken and results achieved as well as enhancements to prevent future
occurrences. The corrective actions included:
1) Repairs were made to the floor drain system and the FSB sump pump 28.
2) Floor drain systems in the radiologically controlled areas at both Units 2 and 3 have
been cleaned and inspected.
3) Preventative maintenance work orders were created to ensure periodic cleaning and
inspection of the floor drain systems.
4) Plugging of the north sole plate drain line and installation of a backwater valve in the
subfloor drain line were made.
5) Harden site structures to minimize potential releases of radiologically-contaminated
fluids to groundwater.
6) Seal and coat FSB truck bay subfloor.
7) Seal and or replace designated building/structural joints with potential path to
groundwater.
8) Site procedures associated with work activity risk analysis, EN-WM-104, On Line Risk
Assessment, and groundwater protection, IP-SMM-CY-110, Radiological Ground
Water Monitoring Program, have been revised to improve the identification of activities
that if performed incorrectly, can cause an unmonitored release or discharge of
radioactive material to the environment.
9) Site procedures 2-SOP-4.3.1, Support Procedure-Spent Fuel Pit Cooling, and
3-SOP-SFP-003, Operation of the Backup Spent Fuel Pool Cooling System, have
been revised to include additional guidance requiring operators to confirm with
Engineering that drain pathways are verified adequate for component draining prior to
use, and to monitor the drain down to prevent leaks or spills.
10) A groundwater protection steering committee has been formed and includes senior
representatives of those site departments having the greatest influence on groundwater
protection. The committee meets at a frequency specified in site procedures to evaluate
the groundwater protection program.
11) Entergy completed an internal self-assessment of the site groundwater protection
program to identify and compliance gaps. Subject matter experts from Electric Power
Research Institute also conducted an assessment of the site implementation of the
objectives in Nuclear Energy Institute 07-07, Industry Ground Water Protection
Initiative - Final Guidance Document, dated August 2007.
2) Equipment identification numbers have been established for the floor drains in the
radiologically controlled areas at the site and entered into the site equipment database.
13) Building drawings have been updated with the location and equipment number for each
floor drain in the radiologically-controlled area.
14) Entergy created and provided Indian Point Groundwater Tritium Awareness Training to
provide employees an understanding of key issues surrounding groundwater tritium, the
event at Indian Point in January of 2016, and prevention of uncontrolled releases of any
contamination to the environment.
Results: The inspectors reviewed Entergys response to VIO 05000247/2016003-07 and
determined that the causal analysis was appropriate. The inspectors reviewed Entergys
corrective actions and determined that Entergy had completed the corrective actions provided
in Reply to a Notice of Violation; EA-16-193, dated January 16, 2017, and full compliance
was achieved. This violation is closed.
Observations 71152
Semiannual Trend
Review
Inadequate Control of Fire Hazards and Seismic Hazards
During in-plant inspection tours over the past six months, the inspectors had noted an
increased adverse trend associated with the control of materials, tools, and/or equipment that
could pose a potential fire or seismic hazards concern. In November 2018, the inspectors
subsequently reviewed items entered into the corrective action program and noted a
considerable number of relevant condition reports that were associated with this adverse
trend.
Inadequate Control of Fire Hazards
Fire hazards identified included improperly stored combustible or flammable materials,
materials/equipment placed in locations blocking emergency egress pathways, and fire doors
that had been propped open. The inspectors had identified a number of instances where the
improper storage of combustible materials had challenged the transient combustible limits for
the fire area. A review of condition reports then showed additional instances where
combustible/flammable materials were found to be improperly stored - including aerosol
canisters containing flammable material (CR-IP2-2018-02010 and CR-IP2-2018-06300), cans
of flammable paint (CR-IP2-2018-01651 and CR-IP2-2018-06432), uncovered waste canisters
(CR-IP2-2018-06432), removed insulation (CR-IP2-2018-00526), wood planks or pallets
(CR-IP2-2018-06612 and CR-IP3-2018-02527), diesel generator lubrication oil
(CR-IP3-2018-02958), and other materials (e.g., CR-IP2-2018-01093, CR-IP2-2018-03029,
CR-IP2-2018-03664, CR-IP2-2018-05766, and CR-IP3-2018-03580).
In certain instances, workers responsible for the handling of combustible materials were
unaware of associated requirements. In one such instance (CR-IP3-2018-02958), a TCE had
been developed to address the removal and storage of diesel generator lubrication oil.
Workers handling the lubrication oil subsequently moved the stored oil to a separate room,
without realizing that the TCE did not allow for storage in this room. This separate room
constituted a separate fire zone with different combustibles loading requirements.
The inspectors noted that Entergy addressed instances of inadequate storage of combustibles
by correcting the issue and coaching responsible individuals. One instance was found to
have led to a clock reset for the group involved (CR-IP3-2018-02527). At the time when the
NRC inspectors first began to observe and track this trend, however, they did not note any
corrective actions reflecting a more substantial organizational response, such as the
reinforcement of standards across departments.
In late November 2018, a number of additional instances of combustible control issues were
identified during a third-party (non-NRC) inspection performed at the site. Entergy captured
the issues from this third-party inspection in CR-IP2-2018-06471 and conducted an
organizational and programmatic screening in accordance with EN-LI-118, Cause Evaluation
Process. Entergy also issued an operations learning clock reset to all site personnel, with the
intent of communicating the issues and reinforcing requirements associated with the control of
fire hazards.
In most instances, the NRC inspectors determined that the issues identified were individually
minor performance deficiencies, in accordance with IMC 0612, "Power Reactor Inspection
Reports," because they were not likely to affect equipment important to safety, did not result in
the station exceeding any licensing basis requirements, and were promptly corrected.
Therefore, those issues are not subject to enforcement action, in accordance with the NRC
Enforcement Policy. However, the inspectors determined that two of the issues identified
(CR-IP3-2018-02527 and CR-IP3-2018-02958) did result in the station exceeding
combustibles loading limits listed in the Unit 3 FHA of record. A Green NCV of regulatory
requirements associated with these two more-than-minor instances is discussed separately in
this report.
Inadequate Control of Seismic Hazards
Instances of potential seismic hazards included the use of seismic restraints with an expired
rigging inspection (CR-IP2-2018-01553), scaffolding found to be in contact with the Unit 2
containment liner during refueling outage activities (CR-IP2-2018-02205), unattended ladders
that were not properly restrained or that were left free-standing (CR-IP2-2018-03700,
CR-IP2-2018-05688, CR-IP3-2018-02283, and CR-IP3-2018-02388), an unsecured bucket of
chains positioned above protected equipment (CR-IP3-2018-01448), and other inadequately
stored/restrained equipment (e.g., CR-IP3-2018-01864 and CR-IP3-2018-02889).
In one instance (CR-IP2-2018-05822), free-standing scaffolding had been erected near
control equipment, and this scaffolding exceeded dimensional limits established by station
procedures. Entergy had implemented an engineering evaluation to justify the exceeded
dimensions, in accordance with procedural requirements; however, this justification included
relying on operator/worker intervention to prevent the interaction of the scaffolding with
equipment during a seismic event. Reliance on prompt individual operator action to mitigate
such a hazard could have the potential to pose both an industrial safety concern (i.e., if the
responsible individual were to be injured by the scaffolding) and/or a nuclear safety concern
(i.e., if attempts to prevent tipping/falling of the scaffolding were not sufficient to prevent
interaction with equipment).
In some cases, attempts had been made to store materials in a manner that mitigated the
likelihood of seismic interaction. However, the restraints put in place were either degraded
(e.g., CR-IP2-2018-01553) or positioned in a manner that would not be effective in preventing
interaction with sensitive equipment (e.g., CR-IP3-2018-01717).
Many of the instances of inadequate control of seismic hazards reviewed were found to have
been initially identified by the NRC inspectors, rather than plant personnel. This reflected an
apparent lack of sufficient sensitivity/understanding among personnel regarding the potential
seismic hazards introduced by inadequately stored tools and equipment.
The NRC inspectors discussed the observed trend in seismic hazards issues with Entergy
management. Following this discussion, Entergy captured the potential trend in
CR-IP2-2019-00107 and developed corrective action to conduct a performance analysis, in
accordance with procedure EN-LI-118, Case Evaluation Process. Through this assessment,
Entergy intends to identify and address factors contributing to this trend.
The NRC inspectors determined that those issues, which entailed a failure to meet procedural
requirements, were minor performance deficiencies, in accordance with IMC 0612, "Power
Reactor Inspection Reports," because of the low likelihood of actual impact on safety-related
equipment. Therefore, these issues are not subject to enforcement action in accordance with
EXIT MEETINGS AND DEBRIEFS
The inspectors confirmed that proprietary information was controlled to protect from public
disclosure.
On January 10, 2019, the inspectors presented the quarterly resident inspector inspection
results to Mr. Anthony Vitale, Site Vice President, and other members of the Entergy staff.
DOCUMENTS REVIEWED
Common Documents Used
Indian Point Units 2 and 3, Control Room Narrative Logs
Indian Point Units 2 and 3, Individual Plant Examination
Indian Point Units 2 and 3, Individual Plant Examination of External Events
Indian Point Units 2 and 3, Plan of the Day
Indian Point Units 2 and 3, Technical Requirements Manual
Indian Point Units 2 and 3, Technical Specifications and Bases
Indian Point Units 2 and 3, Updated Final Safety Analysis Report
Procedures
0-MET-002-GEN, Location of Sandbags in Flood Warning Conditions, Revision 2
0-MET-402-GEN, Location of Sandbags in Flood Warning Conditions, Revision 5
0-SOP-WEATHER-001, Seasonal Weather Preparation, Revision 5
0-SOP-WEATHER-002, Severe Weather Preparations, Revision 0
2-AOP-FLOOD1, Plant Flooding - Conventional Side, Revision 11
2-COL-30.1, Electric Heat Tracing, Revision 34
2-SOP-30.1, Electric Heat Tracing, Revision 31
3-AOP-FLOOD1, Flooding, Revision 10
3-IC-PC-N-T-1116S, Refueling Water Storage Tank Temperature Control, Revision 8
Condition Reports (CR-IP2-) (*initiated in response to inspection)
2000-08786 2018-06841* 2018-06842*
Maintenance Orders/Work Orders
Miscellaneous
License Amendment Request LAR-2017-000095, CA4, NRC Flood Hazard Mitigation Strategy
NRC Near Term Task Force Recommendation 2.1, Flooding Hazard Reevaluation Report -
Entergy Required Response
Tagout 3C20-1-AS-031
Procedures
3-COL-EL-001, 6900 and 480 Volt AC Distribution, Revision 58
3-COL-RW-002, Service Water System, Revision 51
EN-MA-133, Control of Scaffolding, Revision 19
Condition Reports (CR-IP2-) (*initiated in response to inspection)
2018-05689* 2018-05822* 2018-05875 2018-06010
Condition Reports (CR-IP3-)
2010-00091 2015-03976 2017-04522
Maintenance Orders/Work Orders
WO 00221902 WO 00485536 WO 00512106 WO 52843857
Drawings
A209847, Moisture Separator Reheaters Vent Chamber Discharge, Revision 14
A235304, Heater Drains and Vents, Revision 25
Miscellaneous
Scaffolding Engineering Evaluation, Scaffold Log #4297, dated October 22, 2018
UT Erosion/Corrosion Examination Report IP2-UT-18-054, dated November 8, 2018
71111.05A/Q
Procedures
EN-DC-161, Control of Combustibles, Revision 18
Condition Reports (CR-IP3-) (*initiated in response to inspection)
2017-05105 2018-02427 2018-02958*
Analyses/Calculations
IP3-ANAL-FP-01264, Fire Barrier Analysis, Revision 0
IP3-ANAL-FP-01325, Fire Damper Assembly Analysis, Revision 0
IP3-ANAL-FP-02143, Fire Hazards Analysis, Revision 5
IP3-CALC-FP-02795, Combustible Loading Calculation for IP3 Fire Hazards Analysis,
Revision 2
Engineering Change Packages
EC-76353, Revise Combustible Loading Calculation IP-Calc-FP-02795 and Ancillary Fire
Protection Engineering Evaluations to Address Issues Identified by CR-IP3-2017-05105,
Revision 0
EC-80670, Revise Maximum Permissible Combustible Loading for IP3 480V SWGR Room to
Recover Available Margin in Support of Future Transient Combustible Loading,
Revision 0
Miscellaneous
PFP-263, Transformer Yard, Exterior Buildings, Revision 0
PFP-351, 480V Switchgear Room, Control Building, Revision 15
PFP-352, Cable Spread Rooms/Battery Rooms, Control Building, Revision 10
PFP-362, General Floor Plan, Turbine Building, 15-0, Revision 14
PFP-362A, 6.9KV Switchgear Area, Turbine Building, Revision 12
PFP-362B, H2 Seal Oil Unit, Turbine Building, Revision 12
PFP-362E, Heater Drain Pumps, Revision 14
PFP-362F, Turbine Lube Oil Storage/Reservoir, Turbine Building, Revision 5
PFP-362G, Main Condenser Water Box, Revision 11
Transient Combustible Evaluation 18-054, Revision 0
Transient Combustible Evaluation 18-054, Revision 1
Transient Combustible Evaluation 18-061, Revision 1
Transient Combustible Evaluation 18-061, Revision 2
Transient Combustible Evaluation 18-065, Revision 0
Procedures
2-AOP-FLOOD-1, Flooding, Revision 11
Miscellaneous
NRC Information Notice 2005-30: Safe Shutdown Potentially Challenged by Unanalyzed
Internal Flooding Events and Inadequate Design
NUREG-0933, ITEM A-17 System Interactions in Nuclear Power Plants, Revision 2
NUREG-1174, Resolution of Generic Safety Issues (formerly entitled "A Prioritization of Generic
Safety Issues")
Unit 2 Independent Plant Examination, Revision 0
Procedures
3-AOP-NI-1, Nuclear Instrument Failure, Revision 4
E-0, Reactor Trip or Safety Injection, Revision 6
FR-C.1, Response to Inadequate Core Cooling, Revision 1
FR-C.2, Response to Degraded Core Cooling, Revision 3
FR-S.1, Response to Nuclear Power Generation - ATWS, Revision 2
IP-EP-120, EPIP, Classification, Revision 12
IP-EP-210, Emergency Plan Implementing Procedures, Central Control Room, Revision 23
IP-EP-AD13, IPEC Emergency Action Level Technical Bases, Revision 19
SACRG-1, Severe Accident Control Room Guideline, Revision 3
SACRG-2, Severe Accident Control Room Guideline after the TSC Is Functional, Revision 4
Condition Reports (CR-IP2-) (*initiated in response to inspection)
2018-06740*
Condition Reports (CR-IP3-)
2018-03762 2018-03776 2018-03777
Miscellaneous
EAL Tables
Procedures
EN-MP-100, Critical Procurements, Revision 13
EN-MP-138, Commercial Grade Dedication Lab Conduct of Operation, Revision 3
Miscellaneous
Requisition No. 02664445
Requisition No. 02673533
Requisition No. 02685499
Requisition No. 02706210
Procedures
EN-OP-119, Protected Equipment Postings, Revision 9
EN-WM-104, On Line Risk Assessment, Revision 18
Condition Reports (CR-IP2-) (*initiated in response to inspection)
2018-03268* 2018-05688*
Condition Reports (CR-IP3-)
2018-03693 2018-03744
Miscellaneous
EOOS Operators Risk Report for December 12, 2018
IP3-12-00001, Indian Point Unit 3 Equipment Out of Service Model Update, Revision 1
IP3-RPT-16-00035, Indian Point Unit 3 Probabilistic Safety Assessment Interim Update,
Revision 0
Unit 2 Equipment Out of Service on Line Risk Assessment for October 15, 2018
Procedures
EN-LI-102, Corrective Action Program, Revision 35
EN-OP-104, Operability Determination Process, Revision 16
IP-SMM-LI-108, Event Notification and Reporting, Revision 23
Condition Reports (CR-IP2-)
2018-05444 2018-05597 2018-05624
Condition Reports (CR-IP3-)
2018-03011 2018-03023
Maintenance Orders/Work Orders
WO 00510272-1 WO 00510514-1 WO 52830384-1
Engineering Evaluations
CR-IP3-2018-03011, Prompt Operability Determination
Drawings
ISI-27223, Flow Diagram of the Service Water System Nuclear Steam Supply Plant,
Revision 23
Miscellaneous
SEP-SW-IPC-001, NRC Generic Letter 89-13 Service Water Program, Revision 2
Procedures
3-SOP-SI-001, Safety Injection System Operation, Revision 51
EN-DC-315, Flow Accelerated Corrosion Program, Revision 13
EN-LI-100, Process Applicability Determination, Revision 25
Condition Reports (CR-IP3-)
2018-02773 2018-03091
Engineering Change Packages
EC-79929, Bypass Nitrogen Supply Valve 891C to Allow Manual Pressurization of the
Accumulator, Revision 0
EC-79544, IP3 Reheater Drain Elbow Failure - Plant Restart, Revision R-000, Sequence 1
Drawings
21-F-27233, Flow Diagram, Nitrogen to Nuclear Equipment, Revision 40
21-F-27353, Flow Diagram, Safety Injection System, Sheet 1, Revision 44
EC-H-50010, Erosion Corrosion Inspection Turbine Building and Heater Bay Reheater Drain
Piping Isometric from LCV-1105, 1105A, and 1105B to Feedwater Heaters 36A, B,
and C, Revision 2
EC-H-50015, Erosion Corrosion Inspection Turbine Building and Heater Bay Reheater Drain
Piping Isometric from LCV-1104, 1104A, and 1104B to Feedwater Heaters 36A, B,
and C, Revision 2
Miscellaneous
EPRI, Technical Report 1019176, CHECWORKs' Steam/Feedwater Application Guidelines for
Plant Modeling and Evaluation of Component Inspection Data
LER Unit 3 286/2018-003-00, Manual Reactor Trip Due to a Steam Leak on a High Pressure
Feedwater Heater, dated November 19, 2018
NUREG-1930, Volume 2, USNRC Safety Evaluation Report, Related to the License Renewal of
Indian Point Nuclear Generating Unit Nos. 2 and 3
System Description 19.0, Extraction Steam Vents and Drains, Revision 6
Tagout 3C20-1-SI-015
Procedures
0-GNR-405-ELC, Emergency Diesel Generator 4-Year Inspection, Revision 6
Condition Reports (CR-IP3-)
2018-02963 2018-03261
Maintenance Orders/Work Orders
Drawings
21-F-27223, Flow Diagram, Service Water System Nuclear Steam Supply Plant, Revision 52
Procedures
3-AOP-NI-1, Nuclear Instrument Failure, Revision 4
E-0, Reactor Trip or Safety Injection, Revision 6
EN-EP-801, Emergency Response Organization, Revision 15
FR-C.1, Response to Inadequate Core Cooling, Revision 1
FR-C.2, Response to Degraded Core Cooling, Revision 3
FR-S.1, Response to Nuclear Power Generation - ATWS, Revision 2
IP-EP-120, EPIP, Classification, Revision 12
IP-EP-210, Emergency Plan Implementing Procedures, Central Control Room, Revision 23
IP-EP-251, Alternate Emergency Operations Center, Revision 6
IP-EP-AD13, IPEC Emergency Action Level Technical Bases, Revision 19
SACRG-1, Severe Accident Control Room Guideline, Revision 3
SACRG-2, Severe Accident Control Room Guideline after the TSC Is Functional, Revision 4
Condition Reports (CR-IP2-) (*initiated in response to inspection)
2018-06740*
Condition Reports (CR-IP3-)
2018-03762 2018-03776 2018-03777
Miscellaneous
Indian Point Emergency Action Level Matrix, Revision 18-1
Indian Point Energy Center Emergency Plan 17-02, Revision 21
Indian Point Energy Center Emergency Planning Training Drill Guide on December 12, 2018
71152
Procedures
2-SOP-4.3.1, Spent Fuel Pit Cooling, Revision 33
3-SOP-SFP-003, Operation of the Backup Spent Fuel Pool Cooling System, Revision 24
EN-DC-161, Control of Combustibles, Revision 18
EN-LI-118, Cause Evaluation Process, Revision 28
EN-LI-121, Trending and Performance Review Process, Revision 25
EN-WM-104, On Line Risk Assessment, Revision 18
IP-SMM-CY-110, Radiological Ground Water Monitoring Program, Revision 9
IP-SMM-DC-910, Temporary Equipment, Revision 3
Condition Reports (CR-IP2-) (*initiated in response to inspection)
2018-00526 2018-01093 2018-01552 2018-01553 2018-01651 2018-01974
2018-02010 2018-02076 2018-02205 2018-03029 2018-03664 2018-03700
2018-04305 2018-05688 2018-05766 2018-05822 2018-06300 2018-06432
2018-06432 2018-06593 2018-06612 2018-06741 2019-00107*
Condition Reports (CR-IP3-)
2018-01448 2018-01673 2018-01717 2018-01864 2018-01896 2018-02283
2018-02527 2018-02388 2018-02889 2018-02899 2018-02958 2018-03580
2018-03618
Miscellaneous
2016 Groundwater Project Unit 2 and Unit 3 Floor Drains Flow Verification and Current
Condition, Revision 2
Job Aid JA-PI-121-01, Trend Codes, Revision 6
Operations Learning Clock Reset IP2-2018-6742, Blocked Egress ad Fire Equipment,
Housekeeping, and Flammable Storage, dated November 30, 2018
Root Cause Evaluation, IP2 Groundwater Event, Revision 1, dated April 1, 2016
71153
Condition Reports (CR-IP2-)
2018-05922
Drawings
21-F-2722, Flow Diagram Nuclear Steam Supply Plant, Sheet 1, Revision 130