ML14209A132: Difference between revisions

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| issue date = 07/28/2014
| issue date = 07/28/2014
| title = IR 05000354-14-003, April 1, 2014 - June 30, 2014, Hope Creek Generating Station, Unit 1
| title = IR 05000354-14-003, April 1, 2014 - June 30, 2014, Hope Creek Generating Station, Unit 1
| author name = Dentel G T
| author name = Dentel G
| author affiliation = NRC/RGN-I/DRP/PB3
| author affiliation = NRC/RGN-I/DRP/PB3
| addressee name = Joyce T P
| addressee name = Joyce T
| addressee affiliation = PSEG Nuclear, LLC
| addressee affiliation = PSEG Nuclear, LLC
| docket = 05000354
| docket = 05000354
Line 14: Line 14:
| page count = 50
| page count = 50
}}
}}
See also: [[followed by::IR 05000354/2014003]]
See also: [[see also::IR 05000354/2014003]]


=Text=
=Text=
{{#Wiki_filter: UNITED STATES NUCLEAR REGULATORY COMMISSION REGION I 2100 RENAISSANCE BLVD., SUITE 100 KING OF PRUSSIA, PA 19406-2713   July 28, 2014 Mr. Thomas P. Joyce President and Chief Nuclear Officer PSEG Nuclear LLC N09 P.O. Box 236 Hancocks Bridge, NJ 08038 SUBJECT: HOPE CREEK GENERATING STATION UNIT 1 NRC INTEGRATED INSPECTION REPORT 05000354/2014003 Dear Mr. Joyce: On June 30, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Hope Creek Generating Station (HCGS). The enclosed inspection report documents the inspection results, which were discussed on July 10, 2014 with Mr. P. Davison, Site Vice President of Hope Creek, and other members of your staff. The inspection examined activities conducted under your license as they relate to safety and The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel. This report documents one NRC-identified and four self-revealing findings of very low safety significance (Green). Three of these findings were determined to involve a violation of NRC requirements. Additionally, a licensee-identified violation, which was determined to be of very low safety significance, is listed in this report. However, because of the very low safety significance, and because they are entered into your corrective action program (CAP), the NRC is treating the findings as non-cited violations (NCVs) consistent with Section 2.3.2.a of the NRC Enforcement Policy. If you contest any NCVs in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at HCGS. In addition, if you disagree with the cross-cutting aspect assigned to any finding, or a 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 Regional Administrator, Region I, and the NRC Resident Inspector at HCGS.      
{{#Wiki_filter:UNITED STATES
T. Joyce 2  In accordance with Title 10 of the Code of Federal Regulations ( Available Records component of the NSystem (ADAMS).  ADAMS is accessible from the NRC website at http://www.nrc.gov/reading-rm/adams.html  (the Public Electronic Reading Room).  Sincerely,    /RA/  Glenn T. Dentel, Chief Reactor Projects Branch 3 Division of Reactor Projects  Docket Nos.:  50-354  License Nos.: NPF-57  Enclosure: Inspection Report 05000354/2014003    w/Attachment: Supplementary Information  cc w/encl: Distribution via ListServ 
                        NUCLEAR REGULATORY COMMISSION
1    In accordance with Title 10 of the Code of Federal Regulations  ss Management System (ADAMS).  ADAMS is accessible from the NRC website at http://www.nrc.gov/reading-rm/adams.html  (the Public Electronic Reading Room).  Sincerely,    /RA/  Glenn T. Dentel, Chief Reactor Projects Branch 3 Division of Reactor Projects  Docket Nos.:  50-354 License Nos.: NPF-57  Enclosure: Inspection Report 05000354/2014003    w/Attachment: Supplementary Information  cc w/encl: Distribution via ListServ      Distribution: (via email)    M. Draxton, DRP W. Dean, RA    B. Reyes, DRP D. Lew, DRA    J. Hawkins, DRP J. Trapp, DRS    S. Ibarrola, DRP P. Krohn, DRS    C. Ott, DRP, AA H. Nieh, DRP    A. Bowers, RI OEDO M. Scott, DRP    RidsNrrPHHope Creek Resource G. Dentel, DRP    RidsNrrDorLpl1-2 Resource R. Barkley, DRP    ROPreports Resource  DOCUMENT NAME: G:\DRP\BRANCH3\INSPECTION\REPORTS\ISSUED\2014 (ROP 15)\HC IR2014003 FINAL.DOCX ADAMS Accession No.:  ML14209A132    SUNSI Review  Non-Sensitive  Sensitive  Publicly Available  Non-Publicly Available  OFFICE RI/DRP RI/DRP RI/DRP  NAME JHawkins/ RSB for RBarkley/ RSB  GDentel/ GTD    DATE 07/22 /14 07 /22/14 07 / 28 /14  OFFICIAL RECORD COPY 
                                            REGION I
1  Enclosure          U.S. NUCLEAR REGULATORY COMMISSION  REGION I      Docket Nos.:  50-354  License Nos.:  NPF-57  Report No.:  05000354/2014003    Licensee:  Public Service Enterprise Group (PSEG) Nuclear LLC    Facility:  Hope Creek Generating Station (HCGS)  Location:  P.O. Box 236    Hancocks Bridge, NJ  08038  Dates:  April 1, 2014 through June 30, 2014  Inspectors:  J. Hawkins, Senior Resident Inspector    S. Ibarrola, Resident Inspector H. Gray, Senior Reactor Inspector  Approved By:  Glenn T. Dentel, Chief    Reactor Projects Branch 3    Division of Reactor Projects     
                                2100 RENAISSANCE BLVD., SUITE 100
2  Enclosure  TABLE OF CONTENTS  SUMMARY ................................................................................................................................ 3 REPORT DETAILS .................................................................................................................... 7 1. REACTOR SAFETY ........................................................................................................... 7 1R01 Adverse Weather Protection  .................................................................................... 7 1R04 Equipment Alignment ............................................................................................... 8 1R05 Fire Protection .......................................................................................................... 9 1R06 Flood Protection Measures  .....................................................................................10 1R11 Licensed Operator Requalification Program  ...........................................................13 1R12 Maintenance Effectiveness  .....................................................................................14 1R13 Maintenance Risk Assessments and Emergent Work Control  ................................16 1R15 Operability Determinations and Functionality Assessments  ....................................19 1R18 Plant Modifications  .................................................................................................20 1R19 Post-Maintenance Testing  ......................................................................................20 1R22 Surveillance Testing  ...............................................................................................21 1EP6 Drill Evaluation  .......................................................................................................22 4. OTHER ACTIVITIES ..........................................................................................................22 4OA1 Performance Indicator (PI) Verification ....................................................................22 4OA2 Problem Identification and Resolution  ....................................................................23 4OA3 Follow-Up of Events and Notices of Enforcement Discretion  ..................................24 4OA5 Other Activities ........................................................................................................30 4OA6 Meetings, Including Exit ...........................................................................................31 4OA7  Licensee-Identified Violations ..................................................................................31 ATTACHMENT: SUPPLEMENTARY INFORMATION ...............................................................31 SUPPLEMENTARY INFORMATION ....................................................................................... A-1 KEY POINTS OF CONTACT .................................................................................................. A-1 LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED .................................... A-1 LIST OF DOCUMENTS REVIEWED ....................................................................................... A-2 LIST OF ACRONYMS ........................................................................................................... A-15   
                                  KING OF PRUSSIA, PA 19406-2713
3  Enclosure  SUMMARY  IR 05000354/2014003; 4/01/2014  6/30/2014; Hope Creek Generating Station; Flood Protection Measures, Maintenance Effectiveness, Maintenance Risk Assessments and Emergent Work Control, Follow-up of Events and Notices of Enforcement Discretion.  This report covered a three-month period of inspection by the resident inspectors and announced inspections performed by regional inspectors.  Five findings of very low safety significance (Green) were identified.  Three of the findings were determined to be violations of NRC requirements.  The significance of most findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter -cutting  - December 19, 2013.  All violations of NRC requirements are dispositioned in accordance with operation of commercial nuclear power reactors is described in NUREG-  Cornerstone: Initiating Events  Green.  A self-revealing finding of very low safety significance (Green) was identified for  LS-AA-  Specifically, PSEG failed to take self-drain valve troubleshooting on January 11, 2010.  As a result, PSEG did not identify and correct a potential design flaw associated with thermal binding of the MS dump valves, December 1, 2013, leading to a reactor scram from 100 percent power.  actions include a design change to the MS emergency level control system that eliminates dump valve cycling on high MS level.  The performance deficiency was determined to be 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.  The inspectors determined that this finding was of very low safety significance Process (SDP) for Findings At-cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (e.g. loss of condenser, loss of feed water).  The inspectors determined that there was no cross-cutting aspect associated with this finding because the cause of the performance deficiency occurred more than three years ago, and was not representative of present plant performance. (Section 1R12)  Green.  A self-revealing Green NCV of Technical Specification -AA-1000, , during the spring 2009 
                                              July 28, 2014
4  Enclosure  refueling outage (1R15), PSEG failed to follow a work order (WO) requiring the replacement of all Bailey logic modules listed in WO 60061175 with new logic modules.  As a result, a logic module (H1PB-1PBXIS- vital bus was not replaced during 1R15, and failed due to age on December 19, 2013, causing a loss of the vital bus and an entry into the associated 8 hour Technical Specification Action Statement (TSAS) 3.8.3.1 for Onsite Power Distribution Systems.  PSEthe failed logic module, performance of an extent of condition inspection to ensure other similar logic modules and relays were replaced, and reinforcement of proper maintenance practices with the individuals involved in the completion of WO 60061175.    The performance deficiency was determined to be more than minor because it was associated with the human 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, not following the work order instructions resulted in an extended service duration and failbus on December 19, 2013.  Similarly, this performance deficiency was also similar to examples 2.g and 4.b of NRC IMC 0612, Appendix E, in that PSEG is required to follow their procedures per TS 6.8.1, and ultimately led to a safety impact given the failure of the logic module causing a loss of power to the 10A404 vital bus.  The inspectors determined the finding to be of very low safety significance (Green) in accordance with Exhibit 1 of NRC -Power, contributes to the likelihood of an initiating event (Loss of an AC Bus), but did not affect mitigation equipment.  The inspectors determined that there was no cross-cutting aspect associated with this finding because the cause of the performance deficiency occurred more than three years ago, and was not representative of present plant performance. (Section 1R13)  Green.  A self-revealing finding of very low safety significance (Green) was identified when PSEG failed to ensure that appropriate contingency actions were in place prior to the r tuning as required by WC-AA-105,  Specifically, the decision to tune the emergency level controller subsequent reactor scram on Decconducting performance management with the individuals involved with the tuning evolution and revising the moisture separator drain tank level tuning procedure to require an individual at the normal and emergency controllers when performing emergency level controller tuning.  This finding was more than minor because it was associated with the human 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.  The inspectors determined that this finding was of very low safety significance (Green) using Exhibit 1 of NRC IMC 0609, -June 19, 2012, because the finding did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (e.g. loss of condenser, loss of feed water).  The inspectors determined that the finding had a cross cutting aspect in the Human Performance area associated with Work Management, because PSEG personnel did not implement a process of planning, 
Mr. Thomas P. Joyce
5  Enclosure    controlling, and executing work activities such that nuclear safety is the overriding priority.  Specifically, technicians were only stationed at the emergency level controller during the tuning, when having technicians at both controllers would have provided more time to and subsequent reactor scram on December 5, 2013.  [H.5] (Section 4OA3)  Cornerstone: Mitigating Systems  Green.  Tprocedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 could potentially complicate an Specifically, the procedures did not ensure operator response would not communicate the high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) watertight rooms and potentially render two safety-significant single train systems inoperable.  In addition to entering the issue into the corrective action program (CAP) as NOTFs revision of the annunciator response procedures and issuance of a standing order to the Operations department staff.    The performance deficiency is more than minor because it was associated with the procedure quality attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).  Specifically, PSEG procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 could potentially complicate an internal flooding event and adversely affect assumptions in Hope ensure operator response would not communicate the HPCI and RCIC watertight rooms and potentially render multiple trains of safety-related SSCs inoperable.  This performance deficiency was also similar to examples 3.j and 3.k of NRC IMC 0612, Appendix E, in that communicating the two watertight rooms created a reasonable doubt of operability of the HPCI and RCIC systems.  PSEG plans to perform a detailed technical evaluation to evaluate the impact of internal flood propagation in the HPCI and RCIC rooms.  The finding was evaluated in accordance with Exhibits 2 and -Since opening the watertight door during an internal flooding event could bypass the flood protection feature and potentially degrade two or more trains of a multi-train system or function, a detailed risk assessment was performed.  The finding was determined to be of very low safety significance (Green).  Since the change in core damage frequency was sufficiently low, no further evaluation for large early release was required.  The inspectors determined that the finding had a cross cutting aspect in the Human Performance area associated with Training, in that PSEG did not provide adequate training and ensure knowledge transfer to maintain a knowledgeable, technically competent workforce and instill nuclear safety values. Specifically, operator training did not ensure operator response to internal flooding would not result in communicating two watertight rooms containing safety significant single-train systems.  [H.9] (Section 1R06)   
President and Chief Nuclear Officer
6  Enclosure  Cornerstone:  Barrier Integrity  Green.  The inspectors reviewed a Green self-revealing NCV of Title 10 of the Code of Federal Regulations for design change package (DCP) 4EC-3662 failed to reclassify the purchase classification (PC) of the main control room (MCR) chiller pressure control valve (PCV) positioner from non-safety related (PC4) to safety related (PC1).  Because of the incorrectly assigned PC, PSEG did not track the shelf life of replacement positioner diaphragms, which led to the replacement of the failed positioner and changing the purchase classification for the chiller PCV positioners to safety-related (PC1).  Since the implementation of DCP 4EC-3662 in 1997, the DCP procedures have been enhanced to ensure the completion of a purchase class evaluation of procured materials that are implemented in the design change process.  The inspectors determined that the performance deficiency was more than minor because  it is associated with the design control attribute of the Barrier Integrity cornerstone, and adversely affected the cornerstone objective of maintaining the radiological barrier functionality of the control room.  In accordance with Exhibit 3 of NRC IMC 0609, Appendix 2012, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency represents a degradation of only the radiological barrier function provided for the control room.  The inspectors determined that there was no cross-cutting aspect associated with this finding because the cause of the performance deficiency occurred more than three years ago, and was not representative of present plant performance.  (Section 4OA3)  Other Findings  A violation of very low safety significance that was identified by PSEG was reviewed by the inspectors.  Corrective actions taken or plancorrective action program.  This violation and corrective action tracking number are listed in Section 4OA7 of this report.   
PSEG Nuclear LLC - N09
7  Enclosure  REPORT DETAILS  Summary of Plant Status  Hope Creek Generating Station began the inspection period at full rated thermal power (RTP).  On April 1, 2014, Hope Creek conducted a planned down power to 50 percent of RTP to support power suppression testing (PST), main turbine valve testing and main condenser water box cleaning.  The unit was retureactor recirculation pump (RRP) speed unexpectedly rose to its maximum value.  Operators took manual control of the pump and reduced the pump speed to less than reactor recirculation flow TS reqRRP speed control circuit corrective maintenance.  Operators returned the unit to full power on the same day.  On May 28, 2014, Hope Creek conducted a planned down power to 50 percent of RTP to support main turbine valve testing and main condenser water box cleaning.  The unit was returned to full RTP on May 31, 2014, and remained at or near full RTP for the remainder of the inspection period.  1. REACTOR SAFETY  Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity  1R01 Adverse Weather Protection (71111.01  2 samples)  .1 Readiness for Seasonal Extreme Weather Conditions  a. Inspection Scope  temperatures.  The review focused on the safety auxiliaries cooling system (SACS) and station service water (SSW) system.  The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and TS to determine what temperatures or other seasonal weather could challenge these systems and to ensure PSEG personnel had adequately prepared for these challenges.  The inspectors reviewed station procedures, including seasonal weather preparation procedure and applicable operating procedures.  The inspectors performed walkdowns of the selected systems to verify that no unidentified issues existed that could challenge the operability of the systems during hot weather conditions.  Documents reviewed for each section of this inspection report are listed in the Attachment.  b. Findings  No findings were identified.  .2 External Flooding  a. Inspection Scope  During the week of May 24, 2014, the inspectors performed an inspection of the external flood protection measures for Hope Creek.  The inspectors reviewed procedures, design ntaining safety-
P.O. Box 236
8  Enclosure  related equipment to identify areas that may be affected by flooding.  The inspectors also reviewed the limiting conditions for operations and the surveillance requirements in  the Hope Creek Unit 1 areas, which protect Unit 1 equipment, that are susceptible to external flooding.  Specifically, the inspectors walked down the south, east and west walls of the reactor ed the condition of the walls and ensured that any outside penetrations susceptible to external flooding were flood protected.  The inspectors also inspected the flood doors present in that area, which are listed in TS Table 3.7.3-that the doors were in conformance with plant maintenance procedures and drawings.  The inspectors reviewed the preventive maintenance activities performed on these doors with the responsible system engineer.  The inspectors also conducted a walkdown of these doors to verify that the doors were in conformance with the design basis requirements in the UFSAR, the TS, and plant procedures and drawings.  Additionally, the inspectors reviewed the abnormal operating procedure, HC.OP-AB.MISC-0001, PSEG had planned or established adequate measures to protect against external flooding events.  b. Findings  No findings were identified.  1R04 Equipment Alignment    Partial System Walkdowns (71111.04  3 samples)  a. Inspection Scope  The inspectors performed partial walkdowns of the following systems:  RCIC during HPCI booster pump planned maintenance on May 2, 2014  mergency diesel generator (EDG) area ventilation system tornado dampers  2014  The inspectors selected these systems based on their risk-significance relative to the reactor safety cornerstones at the time they were inspected.  The inspectors reviewed applicable operating procedures, system diagrams, the UFSAR, technical specifications, work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have impacted system performance of their intended safety functions.  The inspectors also performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable.  The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies.  The inspectors also reviewed whether PSEG staff had properly identified equipment issues and entered them into the corrective action program for resolution with the appropriate significance characterization. 
Hancocks Bridge, NJ 08038
9  Enclosure  b. Findings  No findings were identified.  1R05 Fire Protection  .1 Resident Inspector Quarterly Walkdowns (71111.05Q  5 samples)  a. Inspection Scope  The inspectors conducted tours of the areas listed below to assess the material condition and operational status of fire protection features.  The inspectors verified that PSEG controlled combustible materials and ignition sources in accordance with administrative procedures.  The inspectors verified that fire protection and suppression equipment was available for use as specified in the area pre-fire plan, and passive fire barriers were maintained in good material condition.  The inspectors also verified that station personnel implemented compensatory measures for out of service, degraded, or inoperable fire protection equipment, as applicable, in accordance with procedures.    Review of compensatory measure fire watch for 10C467 fire protection panel power supply failure on April 17, 2014  FRH-II-415, Revision 4, Hope Creek Pre-Fire Plan, drywell pad torus area on April 21, 2014  FRH-II-412, Revision 3, Hope Creek Pre-Fire Plan, RCIC pump and turbine room and electrical equipment room, on May 20, 2014  FRH-II-532, Revision 6, Hope Creek Pre-Fire Plan, lower control equipment room, on May 23, 2014  FRH-II-542, Revision 9, Hope Creek Pre-Fire Plan, control equipment mezzanine, on May 23, 2014  b. Findings  No findings were identified.  .2 Fire Protection  Drill Observation (71111.05A  1 sample)  a. Inspection Scope  The inspectors observed an unannounced fire brigade drill scenario conducted on  April 7, 2014, that involved a fire in the Hope Creek radwaste area, room 3351.  The inspectors evaluated the readiness of the plant fire brigade to fight fires.  The inspectors verified that PSEG personnel identified deficiencies; openly discussed them in a self-critical manner at the post-drill debrief; and took appropriate corrective actions as required.  The inspectors evaluated specific attributes as follows:  Proper wearing of turnout gear and self-contained breathing apparatus  Proper use and layout of fire hoses  Employment of appropriate fire-fighting techniques  Sufficient fire-fighting equipment brought to the scene  Effectiveness of command and control 
SUBJECT:         HOPE CREEK GENERATING STATION UNIT 1 - NRC INTEGRATED
10  Enclosure    Search for victims and propagation of the fire into other plant areas  Smoke removal operations  Utilization of pre-planned strategies  Adherence to the pre-planned drill scenario  Drill objectives met  r these -fighting strategies.    b. Findings  No findings were identified.  1R06 Flood Protection Measures (71111.06  1 sample)  Internal Flooding Review  a. Inspection Scope  The inspectors reviewed the UFSAR, the site flooding analysis, and plant procedures to assess susceptibilities involving internal flooding.  The inspectors also reviewed the corrective action program to determine if PSEG identified and corrected flooding problems and whether operator actions for coping with flooding were adequate.  The  residual heat removal (RHR) pump room (4113), the  RHR pump room (4114), the HPCI pump and turbine room (4111), and the RCIC pump and turbine room (4110) to verify the adequacy of penetration seals located below the flood line, watertight door seals, common drain lines and sumps, and room level alarms.    b. Findings  Introduction.  The inspectors identified a Grbecause PSEG procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 could potentially complicate an internal flooding event and adversely affect assumptions in Specifically, the procedures did not ensure operator response would not communicate the HPCI and RCIC watertight rooms and potentially render two safety-significant single train systems inoperable.    Description.  During a review of flood protection measures for the 54 foot elevation of the reactor building, inspectors questioned whether execution of flooding procedures could RHR pump rooms, the HPCI pump and turbine room, and the RCIC pump and turbine room are protected.  Specifically, inspectors determined that in response to a room flooding alarm, the procedures directed operators to enter the rooms to investigate the flooding and assess the extent of flooding, an action which could allow communication between two watertight rooms.   
                INSPECTION REPORT 05000354/2014003
11  Enclosure  moderate energy line can at most affect only the operations of one train of a redundant safety- Inspectors reviewed procedural actions that would be taken in response to flood alarms for the HPCI pump and turbine room (Room 4111) and the RCIC pump and turbine room (Room 4110).  The alarm response procedures for the HPCI and RCIC room flood alarms direct operators to dispatch an equipment operator to the applicable room to investigate and confirm the floor level alarm and enter HC.OP-EO.ZZ--EO.ZZ-0103/4 provides an entry condition of any reactor building room floor level above 1 inch, which is also the setpoint of the level alarm.  The procedure directs operators to use all available sump pumps and isolate all systems discharging into the room.    Since the procedures direct operators to investigate and confirm flooding, the inspectors assessed the ability of operators to enter the room without affecting equipment in an adjacent room.  Each of the ECCS/RCIC rooms are separated by large watertight doors with no window or portal to monitor conditions on the other side of the door without opening the door.  The inspectors noted that the alarm response procedures for a high an equipment operator to enter the RHR pump rooms at their upper levels (77 foot elevation) to determine the cause of the alarm.  This procedural direction would prevent flood propagation to the adjacent HPCI and RCIC electrical rooms.  The HPCI and RCIC rooms are located next to one another and are connected by a watertight door.  For a flood in the HPCI room, since both doors to the room open into the adjacent rooms (i.e., water pressure would aid in opening the door), once the door was unlatched, the water would force the door open and flood the adjacent room.  The inspectors noted that the alarm response procedures for potential flooding in the HPCI and RCIC rooms do not provide direction on where to access the HPCI and RCIC rooms when investigating for a potential flood condition.  Therefore, when executing the procedure to respond to flooding in the HPCI room, operators could propagate an internal flood to two watertight rooms if they were to access the HPCI room through the door connecting HPCI and RCIC.  The inspectors interviewed the Hope Creek emergency operating procedure (EOP) coordinator regarding operator actions in response to indications of a flood in the HPCI and RCIC rooms and the HC.OP-EO.ZZ-0103/4 procedure.  Interviews with the EOP coordinator indicated that operator knowledge would ensure proper access to the HPCI and RCIC rooms when investigating a potential flood.  However, no operator training could be found that specified that operators should not access the HPCI and RCIC rooms using the connecting watertight door when responding to a potential flood condition.  The inspectors interviewed a senior reactor operator and two equipment operators about their response to alarms for a potential flood in the HPCI room.  The senior reactor operator did not indicate that he would direct which door to access the HPCI room.  The equipment operators indicated that they would access the HPCI room from the door to the RCIC room because the floor drains in the RCIC room would better drain any flood water.    In the absence of further engineering evaluation, there was reasonable doubt of the operability of the HPCI and RCIC systems.  Specifically, internal flood propagation from 
Dear Mr. Joyce:
12  Enclosure  the design internal flood in the HPCI room could result in a water level that calls the operability of RCIC into question.  PSEG plans to perform a detailed technical evaluation to evaluate the impact of internal flood propagation in the HPCI and RCIC rooms in PSEG entered the issue into the CAP as NOTFs 206include a planned revision of the annunciator response procedures and issuance of a standing order to the Operations department staff.  Analysisrovide adequate procedural guidance to respond to a HPCI/RCIC room flood alarm was a performance deficiency The performance deficiency is more than minor because it was associated with the procedure quality attribute of the Mitigating Systems cornerstone, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).  Specifically, PSEG procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 could potentially complicate an internal flooding event and adversely affect assumptions ensure operator response would not communicate the HPCI and RCIC watertight rooms and potentially render multiple trains of safety-related SSCs inoperable.  This performance deficiency was also similar to examples 3.j and 3.k of NRC IMC 0612, Appendix E, in that communicating the two watertight rooms created a reasonable doubt of operability of the RCIC system.  PSEG plans to perform a detailed technical evaluation to evaluate the impact of internal flood propagation in the HPCI and RCIC rooms.  The finding was evaluated in At-flooding event could bypass the flood protection feature and potentially degrade two or more trains of a multi-train system or function, a detailed risk assessment was performed.    The condition was modeled using the Hope Creek SPAR model version 8.18 along with SAPHIRE version 8.09.  As a bounding analysis, the condition was assumed to exist for greater than one year and the flooding was assumed to require a reactor shutdown, which results in a plant transient with failure of HPCI and RCIC due to flood impacts.  The flooding initiating event frequency was derived from the Hope Creek Internal Flood Report, HC-PRA-012, Revision 2.  The resulting change in core damage frequency was substantially less than 1E-7.  The dominant sequences included a transient with a failure to depressurize along with RCIC and HPCI failures.  Since the change in core damage frequency was sufficiently low, no further evaluation for large early release was required.  The inspectors determined that the finding had a cross-cutting aspect in the Human Performance area associated with Training, in that PSEG did not provide adequate training and ensure knowledge transfer to maintain a knowledgeable, technically competent workforce and instill nuclear safety values.  Specifically, operator training did not ensure operator response to internal flooding would not communicate the HPCI and RCIC watertight rooms and potentially render multiple trains of safety-related SSCs inoperable.  [H.9].    Enforcement.  procedures recommended in Appendix A of Regulatory Guide (RG) 1.33, Revision 2, shall be established, implemented, and maintained.  RG 1.33, Revision 2, Appendix A, 
On June 30, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at
13  Enclosure  Section 5, requires that each safety-related annunciator should have its own written procedure, which should normally contain the immediate operation action.  PSEG procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 provide direction for operator response to indications of high level in the HPCI and RCIC rooms.  Contrary to the above, until implementation of Operations Department Standing Order 2014-26 on  May 24, 2014, PSEG procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 were inadequate in that actions directed in the procedures could complicate an internal design.  In addition to entering the issue into the CAP as NOTFs 20646334, 20646335, corrective actions include a planned revision of the annunciator response procedures and issuance of a standing order to the Operations department staff.  Because this violation was of very low safety significance (Green), and PSEG entered this issue into their CAP, this violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy.  (NCV 05000354/2014003-01, Inadequate Procedural Guidance for Responding to an Internal Flooding Event in the HPCI and RCIC Rooms)  1R11 Licensed Operator Requalification Program (71111.11Q  2 samples)  .1 Quarterly Review of Licensed Operator Requalification Testing and Training  a. Inspection Scope  The inspectors observed licensed operator simulator training on April 28, 2014, that condenser vacuum, and an anticipated transient without scram.  The inspectors evaluated operator performance during the simulated event and verified completion  of critical tasks, risk significant operator actions, including the use of abnormal and emergency operating procedures.  The inspectors assessed the clarity and effectiveness of communications, implementation of actions in response to alarms and degrading plant conditions, and the oversight and direction provided by the control room supervisor.  The inspectors verified the accuracy and timeliness of the emergency classification made by the shift manager.  Additionally, the inspectors assessed the ability of the training staff to identify and document crew performance problems.    b. Findings  No findings were identified  .2 Quarterly Review of Licensed Operator Performance in the Main Control Room  a. Inspection Scope  The inspectors observed a planned down power to support PST to locate a potential fuel defect and the conduct main turbine valve testing on April 1, 2014.  The inspectors observed reactivity manipulations to verify that procedure use and crew communications met established expectations and standards.  The inspectors observed pre-job briefings to verify that the briefings met the criteria specified in OP-AA-101-111--AA--Job Br  Additionally, the inspectors observed the performance of turbine valve testing surveillance test, HC.OP-ST.AC-0002, on April 1, 2014,  to verify that procedure use, crew 
your Hope Creek Generating Station (HCGS). The enclosed inspection report documents the
14  Enclosure  communications, and coordination of activities between work groups similarly met established expectations and standards.  b. Findings  No findings were identified  1R12 Maintenance Effectiveness (71111.12Q  3 samples)  a. Inspection Scope  The inspectors reviewed the samples listed below to assess the effectiveness of maintenance activities on structure, system, or component (SSC) performance and reliability.  The inspectors reviewed corrective action program documents (notifications), maintenance work orders (orders), and maintenance rule basis documents to ensure that PSEG was identifying and properly evaluating performance problems within the scope of the maintenance rule.  As applicable, the inspectors verified that the SSC was properly scoped into the maintenance rule in accordance with 10 CFR 50.65 and verified that the (a)(2) performance criteria established by PSEG staff was reasonable; for SSCs classified as (a)(1), the inspectors assessed the adequacy of goals and corrective actions to return these SSCs to (a)(2); and, the inspectors independently verified that appropriate work practices were followed for the SSCs reviewed.  Additionally, the inspectors ensured that PSEG staff was identifying and addressing common cause failures that occurred within and across maintenance rule system boundaries.    2013, scrams (Order 70161698)  Salem Unit 3 (gas turbine generator) scoping in Hope Creek maintenance rule program (NOTF 20502118)  RCIC nuclear management and control leak detection system card failure and replacement on May 23, 2014 (Order 60113250)  b. Findings  Introduction.  A self-revealing finding of very low safety significance (Green) was PSEG procedure LS-AA-  Specifically, PSEG failed to take self-recom-shooting on January 11, 2010.  As a result, PSEG did not identify and correct a potential design flaw associated with thermal binding of the MS dump valves, which was  December 1, 2013, causing a reactor scram from 100 percent power.  Description.  Hope Creek utilizes two horizontal non-reheat MS vessels that remove moisture in the steam from the high pressure turbine exhaust before it enters the low pressure turbine which prevents damage to the low pressure turbines.  The condensate that is collected in the MS is drained to the 5A, 5B, and 5C feed water heaters where it eventually drains to the condenser.  If the water level in the MS becomes too high and the normal MS level control drain valves are not able to drain it, then the dump valve opens draining the water in the MS directly to the condenser. 
inspection results, which were discussed on July 10, 2014 with Mr. P. Davison, Site Vice
15  Enclosure    normal drain level reached a maximum allowed value of 70 percent allowing the MS dump valve to cycle to control level.  After six minutes (~15 cycles of the going open and shut) of successfully controlling MS level in the dump valve range, the -and a reactor scram.  On December 5, 2013, a second reactor scraemergency level controller tuning.  when expected causing high MS level.  PSEG conducted a root cause evaluation (Order 70161698) to determine the cause of 2013, scrams.  binding because both PSEG and the valve manufacturer did not recognize the potential for these valves to experience thermal binding.  differential expansion, resulting in the valve plug sticking in the valve cage.  -rol issues.  The dump valve had cycled multiple times during drain valve control troubleshooting and the dump valve did not open for 12 S dump valve not operating as expected was documented under NOTF 20447050.  valve had cycled several times prior to the failure to open and recommended that the  ent corrective actions as necessary.  This NOTF was not properly allocated to the equipment apparent cause valve control troubleshooting and therefore was never evaluated.  PSEG created NOTF performance and identify the thermal binding issue when the valve is cycled at normal reactor power and pressure.  LS-AA-125, Corrective Action Program, Revision 12, Section 3.5.6 (effective on  agreed upon by the assignees and that the corrective actions are appropriately entered the inspectors concluded that PSEG failed to ensure that EQACE 70105948 addressed the identified issue in NOTF be evaluated and corrected.  PSEG has entered the above concerns into the CAP as 20640526.  level control system that eliminates dump valve cycling on high MS level.  Analysis.  accordance with PSEG procedure LS-AA-correct and should have been prevented.  The performance deficiency was determined 
President of Hope Creek, and other members of your staff.
16  Enclosure  to be 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.  The inspectors determined that this finding was of very low safety significance using Exhibit 1 of NRC -9, 2012, because the finding did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (e.g. loss of condenser, loss of feed water).  The inspectors determined that there was no cross-cutting aspect associated with this finding because the cause of the performance deficiency occurred more than three years ago, and was not representative of present plant performance.  Enforcement.  This finding does not involve enforcement action because no violation of a regulatory requirement was identified.  Since this finding does not involve a violation and is of very low safety significance (Green), it is identified as a FIN.  (FIN 05000354/2014003-02, Failure to Evaluate an Identified Issue with the Moisture Separator Dump Valve Performance)  1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13  5 samples)  a. Inspection Scope  The inspectors reviewed station evaluation and management of plant risk for the maintenance and emergent work activities listed below to verify that PSEG performed the appropriate risk assessments prior to removing equipment for work.  The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones.  As applicable for each activity, the inspectors verified that PSEG personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the assessments were accurate and complete.  When PSEG performed emergent work, the inspectors verified that operations personnel promptly assessed and managed plant risk.  The inspectors reviewed the scope of maintenance work and discussed the results of babilistic risk analyst to verify plant conditions were consistent with the risk assessment.  The inspectors also reviewed the technical specification requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.  Unplanned de-  Planned high risk activity to perform main turbine combined intermediate valve testing on April 2, 2014  Planned high risk activity to perform power suppression testing to locate a fuel defect on April 2, 2014  -demanded speed changes on May 22, 2014  n fan planned maintenance on June 11, 2014 b. Findings  Introduction.  A Green self--AA-
The inspection examined activities conducted under your license as they relate to safety and
17  Enclosure  lacement of Bailey logic modules associated (1R15), PSEG failed to follow a WO requiring the replacement of all Bailey logic modules listed in WO 60061175 with new logic modules.  As a result, a logic module (H1PB-1PBXIS-DC652010302) for the 10A404 vital bus was not replaced during 1R15, and failed due to age on December 19, 2013, causing a loss of the 10A404 bus and an entry into the associated 8 hour TSAS 3.8.3.1 for Onsite Power Distribution Systems.  Description.  The PSEG Class 1E AC power distribution system provides a reliable source of power for all Class 1E loads and distributes power at 4.16 kilovolt (kV), 480 volt (V), and 208/120 V.  The system is divided into four independent channels and each channel supplies power to loads in its own load group.  Each of the four vital buses is provided with connections to the two offsite power sources through two in-feed breakers (40401 and 40408).  One of these breakers is designated as the normal source and the other as the alternate source for the bus.  In addition to these two connections to offsite power, each of the vital buses is connected to its dedicated EDG.  These EDGs serve as the standby electric power source for their respective channels in case both the normal and alternate power supplies to a bus are lost.  At 3:11 pm on December 19, 2013, PSEG was performing a normally planned swap of the 10A404 in-feed breakers from 40408 to 40401, when both in-feed breakers tripped open and de-energized the 10A404 bus.  PSEG stabilized the plant, entered the associated 8 hour TSAS 3.8.3.1, conducted troubleshooting, performed component replacements, and returned the 10A404 vital bus to service at 5:01 pm on December 19, 2013.  Following the restoration of the 10A404 vital bus on December 19, 2013, PSEG conducted an EQACE documented under order 70162013.  This EQACE determined that the apparent cause of the 10A404 vital bus loss was an age-related failure of a logic module (H1PB-1PBXIS-DC652010302) that was not replaced, but mistakenly documented as being replaced in 2009 per WO 60061175.  PSEG determined that the independent peer check verification performed for both the LM removal and LM installation failed to ensure that the serial number for the removed LM (H1PB-1PBXIS-DC652010302) was not reinstalled into the system.  Because this logic module was not replaced in 2009, and remained in the system for 4 years past its vendor recommended lifetime of 20 years, PSEG determined that it failed due to age and could not provide an output to allow the 10A404 bus 40408 in-feed breaker to trip normally during the planned in-feed breaker swap on December 19, 2013.  -feed breaker swaps, operations narrative logs, and the completed EQACE 70162013 for the December 19, 2013, event.  PSEG procedure MA-AA-using appropriate documentation such as work orders, notifications, or applicable (Revision 14) and the revision in use during 1R15 (Revision 7) have this language requiring all work be performed in accordance with the appropriate documentation.  The inspectors determined that PSEG failed to follow this procedure by not complying with WO 60061175 for the replacement of Bailey cards for the 10A404 in-feed breakers ogic Modules listed with new -feed breaker logic module 
compliance with the Commissions rules and regulations and with the conditions of your license.
18  Enclosure  (H1PB-1PBXIS-DC652010302 LM 4.16 KV MAIN BKR 52-40401).  Contrary to this, 0061175 showed that the original logic module was re-installed following its removal during the of all other similar logic modules found them replaced as documented.  PSEG initiated NOTF 20639519 and EQACE 70162013 in the CAP to replace the failed logic module, identify other similar logic modules and relays that may not have been replaced or may not have an associated maintenance plan, and reinforce proper maintenance practices to the individuals involved in the completion of WO 60061175.    Analysis.  -AA-1000 for Maintenance Standards and Practices during the replacement of a Bailey logic module associated with the 10A404 vital bus represented a performance deficiency that was reasonably within oresee and correct and should have been prevented.  The performance deficiency was determined to be more than minor because it was associated with the human 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, not following the work order instructions resulted in an extended service duration and failure of a component that resulted in a loss of power to similar to examples 2.g and 4.b of NRC IMC 0612 Appendix E, in that PSEG is required to follow its procedures per TS 6.8.1, and ultimately led to a safety impact given the failure of the logic module causing a loss of power to the 10A404 vital bus.  The inspectors determined the finding to be of very low safety significance (Green) in accordance with Exhibit 1 Determination Process for Findings At-involved the loss of a support system that contributes to the likelihood of an initiating event (Loss of an AC Bus), but did not affect mitigation equipment.  The inspectors determined that there was no cross-cutting aspect associated with this finding because the cause of the performance deficiency occurred more than three years ago, and was not representative of current plant performance.  Enforcementprocedures recommended in Appendix A of RG 1.33, Revision 2, shall be established, implemented, and maintained.  Section 9.a of RG 1.33, Revision 2, Appendix A, requires that maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances.  Section 3.0 of PSEG procedure MA-AA-work on plant SSCs will be performed using appropriate documentation such as work orders, notifications, or applicable troubleshooting process control forms.  Contrary to the above, on April 16, 2009, PSEG failed to follow this procedure during the replacement of a Bailey logic module associated with the 10A404 vital bus.  Specifically, PSEG failed to follow WO 60061175 which required the replacement of all Bailey logic modules listed in the WO with new logic modules.  As a result, a logic module for the 10A404 vital bus was not replaced in 2009, and failed due to age on December 19, 2013, causing a loss of the 10A404 bus and an entry into the associated 8 hour TSAS 
The inspectors reviewed selected procedures and records, observed activities, and interviewed
19  Enclosure  3.8.3.1 for Onsite Power Distribution Systems. replacement of the failed logic module, performance of an extent of condition inspection to ensure other similar logic modules and relays were replaced, and reinforcement of proper maintenance practices with the individuals involved in the completion of WO 60061175.  Because this violation was of very low safety significance (Green) and was being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.  (NCV 05000354/2014003-03, Failure to Follow Procedure Resulting in the Loss of a Vital 4kV Bus)  1R15 Operability Determinations and Functionality Assessments (71111.15  5 samples)  a. Inspection Scope  The inspectors reviewed operability determinations for the following degraded or non-conforming conditions:  80108395)  2014 (NOTF 20645519)  Standby liquid control event report #49909 retraction on April 15, 2014 (NOTFs 20647199 and 20643229)  , 2014 (NOTF 20651102)  Revision 3 of Masterpact Breaker failure analysis operability evaluation on May 28, 2014 (NOTF 20652187 and Order 70163760)  The inspectors selected these issues based on the risk significance of the associated components and systems.  The inspectors evaluated the technical adequacy of the operability determinations to assess whether technical specification operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred.  The inspectors compared the operability and design criteria in the appropriate sections of the technical specifications and UFSAR to Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled by PSEG.  The inspectors determined, where appropriate, compliance with assumptions in the evaluations.  b. Findings  No findings were identified.   
personnel.
20  Enclosure  1R18 Plant Modifications (71111.18  2 samples)  .1 Temporary Modifications  a. Inspection Scope  The inspectors reviewed the temporary modification listed below to determine whether the modification affected the safety functions of systems that are important to safety.  The inspectors reviewed 10 CFR 50.59 documentation to verify that the temporary modification did not degrade the design bases, licensing bases, and performance capability of the affected systems.    Temporary Configuration Change Package (TCCP) 4HT-14-005  Temporary Repairs to the Condensate Storage Tank Dike Drain Line  b. Findings  No findings were identified.  .2 Permanent Modifications  a. Inspection Scope  The inspectors evaluated a modification to the RWCU system implemented by DCP  existing breaker auxiliary contact in series with the internal close coil to allow the close coil to be de-energized after the breaker has closed rather than be continuously energized.  The existing configuration with the breaker close coil continuously energized is allowing an intermittent failure of these breakers where they lock up and fail to re-close when required per design.  The inspectors verified that the design bases, licensing bases, and performance capability of the affected systems were not degraded by the modification.  In addition, the inspectors reviewed modification documents associated with the upgrade and design change, including the breaker operation.  The inspectors also reviewed revisions to the control room alarm response procedure and interviewed engineering and operations personnel to ensure the procedure could be reasonably performed.    b. Findings  No findings were identified.  1R19 Post-Maintenance Testing (71111.19  7 samples)  a. Inspection Scope  The inspectors reviewed the post-maintenance tests for the maintenance activities listed below to verify that procedures and test activities ensured system operability and functional capability.  The inspectors reviewed the test procedure to verify that the procedure adequately tested the safety functions that may have been affected by the maintenance activity, that the acceptance criteria in the procedure was consistent with the information in the applicable licensing basis and/or design basis documents, and that the procedure had been properly reviewed and approved.  The inspectors also 
This report documents one NRC-identified and four self-revealing findings of very low safety
21  Enclosure  witnessed the test or reviewed test data to verify that the test results adequately demonstrated restoration of the affected safety functions.  HPCI oil supply pressure gauge replacement on October 10, 2013 (Order 60113238)  replacement on April 23, 2014 (Order 60116090)  10C467 fire protection panel power supply replacement on May 9, 2014 (Order 30269527)  60117312)  RCIC nuclear management and control leak detection system card replacement on May 23, 2014 (Order 60113250)  Service air compressor oil leak repair on June 5, 2014 (Order 60117447)  30098617)    b. Findings  No findings were identified.  1R22 Surveillance Testing (71111.22  9 samples)  a. Inspection Scope  The inspectors observed performance of surveillance tests and/or reviewed test data  of selected risk-significant SSCs to assess whether test results satisfied technical specifications, the UFSAR, and PSEG procedure requirements.  The inspectors verified that test acceptance criteria were clear, tests demonstrated operational readiness and were consistent with design documentation, test instrumentation had current calibrations and the range and accuracy for the application, tests were performed as written, and applicable test prerequisites were satisfied.  Upon test completion, the inspectors considered whether the test results supported that equipment was capable of performing the required safety functions.  The inspectors reviewed the following surveillance tests:  HC.OP-ST.AC-0002, Turbine Valve Testing quarterly surveillance on April 1, 2014  HC.OP-ST.KJ-0003, Emergency Diesel Generator 1CG400 Operability Test on  April 7, 2014  HC.OP-IS.BJ-0001, HPCI Main and Booster Pump Set  0P204 and 0P217  In-service Test on April 9, 2014 (in-service test)  HC.MD-ST.PB-0003, Class 1E 4.16 kV Feeder Degraded Voltage Monthly pril 15, 2014  HC.OP-IS.BC--Service Test on April 22, 2014  (in-service test)  HC.OP-DL.ZZ-0026, Drywell floor drain leakage monitoring on May 1, 2014 (RCS leakage)  HC.FP-ST.KC-0009, Diesel Driven Fire Pump Operability Test on May 6, 2014  HC.OP-IS.BC--Service Test on June 25, 2014  (in-service test)    HC.OP-ST.KJ-0001, Emergency Diesel Generator 1AG400 Operability Test on  June 30, 2014 
significance (Green). Three of these findings were determined to involve a violation of NRC
22  Enclosure  b. Findings  No findings were identified.  Cornerstone: Emergency Preparedness  1EP6 Drill Evaluation (71114.06  1 sample)  Emergency Preparedness Drill Observation  a. Inspection Scope  The inspectors evaluated the conduct of a routine PSEG emergency drill on June 24, 2014 to identify any weaknesses and deficiencies in the classification, notification, and protective action recommendation development activities.  The inspectors observed emergency response operations in the technical support center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures.  The inspectors also attended the drill critique to compare inspector observations with those identified by PSEG staff in order to weaknesses and entering them into the corrective action program.  b. Findings  No findings were identified.  4. OTHER ACTIVITIES  4OA1 Performance Indicator (PI) Verification (71151)    Reactor Coolant System (RCS) Specific Activity and RCS Leak Rate (2 samples)  a. Inspection Scope  nd RCS leak rate performance indicators for the period of April 1, 2013, through March 31, 2014.  To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, also reviewed RCS sample analysis and control room logs of daily measurements of RCS leakage, and compared that information to the data reported by the performance indicator.  Additionally, the inspectors observed chemistry personnel taking and analyzing an RCS sample.    b. Inspection Findings  No findings were identified.   
requirements. Additionally, a licensee-identified violation, which was determined to be of very
23  Enclosure  4OA2 Problem Identification and Resolution (71152  1 sample)  .1 Routine Review of Problem Identification and Resolution Activities  a. Inspection Scope  inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that PSEG entered issues into the corrective action program at an appropriate threshold, gave adequate attention to timely corrective actions, and identified and addressed adverse trends.  In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the corrective action program and periodically attended condition report screening meetings.    b. Findings  No findings were identified.  .2 Semi-Annual Trend Review  a. Inspection Scope  The inspectors performed a semi-annual review of site issues, as required by Inspection rends that might indicate the existence of more significant safety issues.  In this review, the inspectors included repetitive or closely-related issues that may have been documented by PSEG outside of the corrective action program, such as trend reports, performance indicators, major equipment problem lists, system health reports, maintenance rule assessments, and maintenance or corrective action program backlogs.  The inspection also reviewed uary 2014 to May 2014 daily condition report review (Section 4OA2.1).  The inspectors reviewed the Hope Creek station performance improvement integrated matrix (PIIM), conducted under procedure LS-AA-125-PSEG personnel were appropriately evaluating and trending adverse conditions in accordance with applicable procedures.  b. Findings and Observations  No findings were identified during this trend review.    The inspectors noted that PSEG personnel identified the following trends and entered them into the corrective action program:  an adverse trend in Appendix J leakage (NOTFs 20632747, 20632748, 20632749); an adverse trend in design change package quality (NOTFs 20642767 and 20644539); and an adverse trend in critical component failures (NOTF 20638889).  The inspectors also reviewed the 2013 third cycle Hope Creek PIIM and the performance improvement action plan developed to improve station performance in the areas of equipment reliability, decision making, and risk management. 
low safety significance, is listed in this report. However, because of the very low safety
24  Enclosure  -system maintenance rule screenings:    When the feedwater crosstie valve (AE-HV-4144) failed, it was screened as not a functional failure against the feedwater system.  The condition was not screened against the feedwater sealing functions of HPCI and RCIC.    The DD-411 battery room temperature was found above acceptance criteria.  A maintenance rule functional failure screening was performed for the functions of the 1E 125 volt direct current (DC) system, but not for the auxiliary building diesel area ventilation system.    As found setpoint failures of safety relief valves were screened against the automatic depressurization system functions, but not against any of the main steam system functions.    The inspectors determined this observation was not more than minor in accordance with IMC 0612, because the observations did not result in any of the systems requiring additional monitoring per 10 CFR 50.65(a)(1).  appropriately identifying and entering issues into the corrective action program, adequately evaluating the identified issues, and appropriately identifying adverse trends before they become more safety significant problems.  4OA3 Follow-Up of Events and Notices of Enforcement Discretion (71153  6 samples)  .1 Plant Events  a. Inspection Scope  For the plant event listed below, the inspectors reviewed plant parameters, reviewed personnel performance, and evaluated performance of mitigating systems.  The inspectors communicated the plant events to appropriate regional personnel, and As applicable, the inspectors verified that PSEG made appropriate emergency classification assessments and properly reported the event in accordance with 10 CFR  follow-up actions related to the events to assure that PSEG implemented appropriate corrective actions commensurate with their safety significance.  -demanded speed change due to a failure in the speed controller, causing a momentary increase in reactor power above the thermal power limit on May 15, 2014 (NOTF 20651102)        .2 Event Notification (EN) 49909 Retraction, Standby Liquid Control System (SLC) Sample Concentration Outside Technical Specification Limits 
significance, and because they are entered into your corrective action program (CAP), the NRC
25  Enclosure    At 10:27 pm on March 12, 2014, PSEG was in the process of returning the SLC system a SLC tank high level alarm (>4880 gallons).  The MCR informed the equipment operator conducting the SLC system restoration of the unexpected SLC tank high level alarm and the operator closed a valve that had just been opened, which stopped the rise in SLC storage tank level at 4926 gallons.  tank yielded a sodium pentaborate concentration outside the TS limits, rendering both subsystems inoperable.  The concentration was found to be at 13.598% by weight, below the required concentration of 13.6% by weight.  As part of the corrective actions, PSEG restored the concentration to within TS limits and conducted an apparent cause evaluation.  This condition was reported under 10 CFR 50.72(b)(3)(v)(D) on March 13, 2014, as  a condition that could have prevented the fulfillment of a safety function required to mitigate the consequences of an accident (EN 49909).  On April 14, 2014, PSEG a subsequent review of the analytical data has determined that the SLC tank sample met the TS requirement for operability (13.6 weight percent) and therefore, there was no reportable condition.reviewedocumentation including multiple NOTFs and technical evaluation (Order 70166989), station procedures, and interviewed several members of station staff and management regarding the event.  No findings were identified during this review.  .3 (Closed) Licensee Event Report (LER) 05000354/2013-007-00, As-Found Values for Safety Relief Valve Lift Set Points Exceed Technical Specification Allowable Limit  On November 22, 2013, PSEG received test results indicating that the as-found lift setpoints for 5 of 14 main steam safety relief valves (SRVs) failed to open within the required TS actuation pressure setpoint tolerance.  TS 3.4.2.1 provides an allowable pressure band of +/- 3 percent for each SRV.  All five of the SRVs opened above the surfaces of the pilot disc.  These issues were placed into the CAP as NOTF 20631351.  The pilot assembly for each of the 14 SRVs has been replaced with a fully tested spare replace the currently installed SRVs with a new design that eliminates setpoint drift events exceeding TS requirements and improves SRV reliability.  Although this LER reports the inoperability of five SRVs, this event did not result in a loss of system safety function based on engineering analyses.  These analyses showed that the SRVs would have functioned to prevent a reactor vessel over-pressurization and that postulated piping stresses would not exceed allowable limits.  The enforcement aspects of this finding are discussed in Section 4OA7.  This LER is closed.  .4 (Closed) LER 05000354/2013-008-00 and LER 05000354/2013-008-01, Automatic Actuation of the Reactor Protection System Due to a Main Turbine Trip  On December 1, 2013, Hope Creek Unit 1 automatically scrammed from 100 percent rated thermal power due to a main turbine trip.  The main turbine trip was due to high The plant was stabilized in hot shutdown, Operational Condition 3.   
is treating the findings as non-cited violations (NCVs) consistent with Section 2.3.2.a of the
26  Enclosure  This condition is reportable under 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted  in an automatic actuation of the reactor protection system.  The inspectors reviewed  LER revision, root cause evaluation report (Order 70161698), supporting documentation, station procedures, and interviewed several members of station staff and management regarding the event.  One finding was identified and is discussed in Section 1R12 of this report.  These LERs are closed.  .5 (Closed) LER 05000354/2013-009-00 and LER 05000354/2013-009-01, Automatic Actuation of the Reactor Protection System Due to a Main Turbine Trip  a. Inspection Scope  ergency level controller, the reactor automatically scrammed from 75 percent power due to a main turbine trip.  subsequent turbine trip.  The automatic reactor scram resulted in a trip of both RRPs, as designed.  During the recovery of the RRPs, the digital electro-hydraulic control system was mis-operated which caused the turbine bypass valves to cycle.  This caused reactor level to swell above Level 8 then shrink below Level 3, resulting in a second actuation of the reactor protection system.  This condition is reportable under 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in an automatic actuation of the reactor protection system.  The inspectors reviewed station procedures, and interviewed several members of station staff and management regarding the event.  Two findings were identified and are discussed below.  These LERs are closed.  b. Findings  .1  Failure to Use Approved Method of Post-Scram Reactor Pressure Control  The mis-operation of the digital electro-hydraulic control system following the reactor scram on December 5, 2013, has been previously evaluated.  A self-revealing Green NCV of TS 6.8.1.a (NCV 05000354/2014002-06) for Failure to Use Approved Method of Post-Scram Reactor Pressure Control is documented in NRC Inspection Report 05000354/2014002.    .2  Inadequate Implementation of Contingency Actions During Moisture Separator      Emergency Level Controller Tuning  Introduction. A self-revealing finding of very low safety significance (Green) was identified when PSEG failed to ensure that contingency actions were appropriate for  December 5, 2013.  Specifically, the decision to tune the emergency level controller without appropriate contingencies in place led to a turbine trip and subsequent reactor  Description. emergency level controller following its replacement in accordance with PSEG procedure HC.IC-LC.AF- 
NRC Enforcement Policy. If you contest any NCVs in this report, you should provide a
27  Enclosure  During the tuning evolution, the  The moisture separators improve the quality of the steam from the high pressure turbine exhaust, and minimize erosion of the low pressure turbines due to excessively moist through three drain valves on each MS to the #5 feedwater heaters.  The position of the drain valves is controlled by the MS normal level controller.  When the level in the MS  is above the normal drain control level, a high level emergency dump valve (one per MS) directs flow from the MS to the condenser.  The emergency level dump valve is normally closed and is controlled by the MS emergency level controller.  PSEG procedure HC.IC-LC.AF-raises MS level into the emergency dump range to tune the emergency level controller by manually closing the normal drain valves.  This evolution was evaluated and determined to be a high risk evolution in accordance with WC-AA- WC-AA-105 requires that the risk management plan be presented for approval by a risk management challenge board prior to performance of the high risk activity.  This plan was initially reviewed by a risk management challenge board and was not approved.  An action from the risk management challenge board included ensuring that during the tuning, one person is to be stationed at the normal level controller and one at the emergency level controller.  The risk management challenge board directed that both people would need to be prepared to respond in case the MS drain tank level rises during the tuning evolution.  A second risk management challenge board was held to review the risk management plan.  The contingency action for stationing maintenance technicians at each controller was not implemented.  The second challenge board failed to ensure that contingency actions were appropriate for the activity being performed as specified by PSEG procedure WC-AA-105.  A heightened level of awareness (HLA) brief was performed prior to performance of the high risk activity.  Having a maintenance technician at the normal and emergency level controllers was discussed.  Contrary to the direction of the risk management challenge board and the HLA brief, a maintenance technician was not stationed at the normal level controller during the tuning of the emergency level contrincluded conducting performance management with the individuals involved with the tuning evolution, and revising the moisture separator drain tank level tuning procedure to require an individual at the normal and emergency controllers when performing emergency level controller tuning.  Analysislevel controller tuforesee and correct, and should have been prevented.  Specifically, a contingency action specified by the risk management challenge board and the HLA brief prior to the high risk tuning activity was not performed.  As a result, the technicians were unable to caused a turbine trip and reactor scram.   
response within 30 days of the date of this inspection report, with the basis for your denial, to
28  Enclosure  This finding was more than minor because it was associated with the human 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.  The inspectors determined that this finding was of very low safety significance (Green) using (SDP) for Findings At-e finding did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (e.g. loss of condenser, loss of feed water).  The inspectors determined that the finding had a cross-cutting aspect in the Human Performance area associated with Work Management, because PSEG personnel did not implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority.  Specifically, technicians were only stationed at the emergency level controller during the tuning, when having technicians at both controllers would have provided more time to recover from a high e turbine trip and subsequent reactor scram on December 5, 2013.  (H.5)  Enforcement. This finding was not a violation of NRC requirements because no violation of regulatory requirements was identified.  Since this finding does not involve a violation and is of very low safety significance (Green), it is identified as a FIN.  (FIN 05000354/2014003-04, Inadequate Implementation of Contingency Actions During Moisture Separator Emergency Level Controller Tuning)  .6 (Closed) LER 05000354/2013-010-00, Loss of Both Main Control Room Chillers  a. Inspection Scope  fluctuations in load.  The TSAS (TS 3.7.2.2 Action a.2) for both MCR air conditioning and chiller were placed in service for post maintenance testing, returned to an operable status, and the TS action statement was exited.  This condition is reportable under 10 CFR 50.73(a)(2)(v)(D) as an event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident.  The inspectors reviewed supporting documentation, station procedures, and interviewed several members of station staff and management regarding the event.  One finding was identified and is discussed below.  These LERs are closed.  b. Findings  Introduction.  A Green self-revealing NCV of 10 CFR 50, Appendix B, Criterion III, P 4EC-3662 failed to reclassify the PC of the MCR chiller PCV positioner from non-safety related (PC4) to safety related (PC1).  Because of the incorrectly assigned PC, PSEG did not track the shelf life of replacement positioner diaphragms, which led to th
the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, DC 20555-
29  Enclosure  by the failed positioner, and led to both MCR chillers being inoperable.  Description.  The control room envelope (CRE) heating, ventilation and air conditioning (HVAC) systems are designed to ensure habitability during any design basis radiological accident.  Redundant HVAC systems are provided to control the ambient conditions for safety-related equipment to ensure operating temperature limits are not exceeded.  The the CRE for equipment performance and operator comfort.  fluctuations in load.  TS action statement 3.7.2.2.a.2 for both MCR chillers being inoperable was entered.  This condition was reportable per 10CFR50.72(b)(3)(v)(D), as an event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident, PSEG submitted an eight-hour event notification (#49671) for concurrent inoperability of MCR chiller was placed in service for post maintenance testing and returned to an operable status, allowing PSEG to exit the TS.  Throughout the time both chillers were inoperable, the MCR temperature was maintained below the TS limit of 90 degrees Fahrenheit.  PSEG conducted an equipment apparent cause evaluation (EQACE 70162284) and inoperable chiller condenser PCV.  The positioner for the PCV, which provides cooling water flow to the chiller condenser, failed due to a leak in the positioner's internal relay assembly, which is made up of a series of diaphragms.  This positioner had failed 2011.  The replaced positioner that failed on December 20, 2013, had only been allowed an internal leakage path for the air, resulting in the failure of the positioner to operate properly.  This failure was determined to be age-related caused by a legacy issue with the implementation of DCP 4EC-3662 in 1997.  The chiller PCV has an active safety function in the open position to provide cooling water flow to the MCR chiller.  On a loss of instrument air, the chiller PCV was originally designed to fail open, but this DCP installed backup air bottles to supply the chiller PCV, preventing the PCV from failing open so that the chiller would not trip on low evaporator refrigerant pressure.  This design change resulted in the PCV becoming self-modulating, changing the classification of the PCV positioner from nonsafety-related to safety-evaluation of this DCP in the EQACE concluded that the DCP failed to identify that the PC of the positioner for the PCV should have been changed from nonsafety-related to safety-related and as a result, the PC was not changed.  If the PC of the positioner had been changed to PC1, a positioner that had been on the shelf for more than 20 years would not have been installed into a safety-related system.  But because the PC was not changed, PSEG determined that the shelf life of the in-stock replacement positioners was not tracked, leading to the installation of a positioner in 2011 that had been manufactured 21 years before. 
0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement,
30  Enclosure  ed that the MCR chiller PCV positioner failed to operate because of internal relay leakage caused by damaged diaphragms.  These diaphragms failed due to entered this issue actions the site has replaced the failed positioner and changed the purchase classification for the chiller PCV positioners to safety-related (PC1).    Analysismplement the DCP process for DCP 4EC-3662 correct, and should have been prevented.  Specifically, because of the incorrectly assigned PC, PSEG did not track the shelf life of replacement positioner diaphragms, determined that the performance deficiency was more than minor because it is associated with the design control attribute of the of the barrier integrity cornerstone, and adversely affected the cornerstone objective of maintaining the radiological barrier Determination Process (SDP) for Findings at inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency represents a degradation of only the radiological barrier function provided for the control room.  Since the implementation of DCP 4EC-3662, the DCP procedures have been enhanced to ensure the completion of a purchase class evaluation of procured materials that are implemented in the DCP process.  The inspectors determined that there was no cross-cutting aspect associated with this finding because the cause of the performance deficiency occurred more than three years ago, and was not representative of current plant performance.  Enforcementn part, that measures shall be established to assure that applicable regulatory requirements and the design basis for structures, systems, and components shall be correctly translated into specifications, drawings, procedures, and instructions.  Contrary t-3662 in 1997, failed to reclassify the PC of the MCR chiller PCV positioner from nonsafety-related to safety-related.  Because of the incorrectly assigned PC, PSEG did not track the shelf life of replacement positio -related.  Because of the very low safety significance (Green) and because the issue was entered into the CAP as notification 20642546, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.  (NCV 05000354/2014003-05, Inadequate Evaluation of a Main Control Room Chiller Design Change)  4OA5 Other Activities       
United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC
31  Enclosure  a. Inspection Scope    ----------      4OA6 Meetings, Including Exit  On , the inspectors presented the inspection results to .  The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.  4OA7  Licensee-Identified Violations  The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy, for being dispositioned as a NCV:  In Modes 1, 2, and 3, Hope Creek TS 3.4.2.1, "Safety Relief Valves," requires that  13 of the 14 SRVs open within of +/- 3 percent of the specified code safety valve function lift settings or else be in Mode 3 within 12 hours and in Mode 4 within the next 24 hours.  Contrary to this requirement, on November 22, 2013, PSEG identified that five of the fourteen SRVs were determined to have their as-found setpoints in excess of the TS allowable tolerance, thus leaving nine operable SRVs.  The pilot assembly for each of the fourteen SRVs has been replaced with a fully tested spare assembly.  Additionally, LER 2013-is being considered through the plant modification process.  PSEG entered this issue into their CAP as notification 20631351.  The inoperability of the five SRVs did not result in a loss of system safety function based on engineering analyses that showed that postulated piping stresses would not exceed allowable limits.  Therefore, this finding is of very low (Green) safety significance based on an SDP issue screening, because the SRVs would have functioned to prevent a reactor vessel over-pressurization.  The closure of the LER associated with this event was documented in Section 4OA3.  ATTACHMENT: SUPPLEMENTARY INFORMATION
Resident Inspector at HCGS. In addition, if you disagree with the cross-cutting aspect assigned
A-1    Attachment  SUPPLEMENTARY INFORMATION  KEY POINTS OF CONTACT  Licensee Personnel  P. Davison, Site Vice President E. Carr, Plant Manager P. Bellard, Program Engineering S. Bier, EOP Coordinator M. Biggs, Hope Creek Maintenance Rule Coordinator M. Cardile, Fire Protection Supervisor J. Carlin, Fire Protection Superintendent S. Connelly, System Engineer A. DiEgidio, Chemistry Technician T. Headman, Emergency Preparedness Technical Specialist W. Hickey, Work Week Manager C. Johnson, Senior Program Engineer E. Martin, Senior Program Engineer J. Master, Chemistry Technician M. Meltzer, Chemistry T. Morin, Regulatory Assurance Engineer M. Reeser, System Engineer  M. Rooney, System Engineer R. Smith, System Engineer K. Timko, System Engineer A. Tramontana, Program Engineering Manager M. Tudisco, Nuclear Maintenance Supervisor K. Wichman, System Engineer  LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED  Opened/Closed  05000354/2014003-01 NCV Inadequate Procedural Guidance for Responding to an Internal Flooding Event in the HPCI and RCIC Rooms (Section 1R06)    05000354/2014003-02 FIN Failure to Evaluate an Identified Issue with the Moisture Separator Dump Valve Performance (Section 1R12)  05000354/2014003-03 NCV Failure to Follow Procedure Resulting in the Loss of a Vital 4kV Bus (Section 1R13)  05000354/2014003-04 FIN Inadequate Implementation of Contingency Actions During Moisture Separator Emergency Level Controller Tuning (Section 4OA3) 
to any finding, or a finding not associated with a regulatory requirement in this report, you
A-2    Attachment  05000354/2014003-05 NCV Inadequate Evaluation of a Main Control Room Chiller Design Change (Section 4OA3)    Closed  05000354/2013-007-00 LER As-Found Values for Safety Relief Valve Lift Set Points Exceed Technical Specification Allowable Limit (Section 4OA3)    05000354/2013-008-01 LER Automatic Actuation of the Reactor Protection System Due to a Main Turbine Trip (Section 4OA3)  05000354/2013-009-01 LER Automatic Actuation of the Reactor Protection System Due to a Main Turbine Trip (Section 4OA3)  05000354/2013-010-00 LER Loss of Both Main Control Room Chillers (Section 4OA3)  LIST OF DOCUMENTS REVIEWED  Section 1R01: Adverse Weather Protection  Procedures ER-HC-310-1009, HCGS  Maintenance Rule Scoping, Revision 10 HC.MD-GP.ZZ-0037, Plant Bulkhead Doors Overhaul, Revision 5 HC.MD-PM.ZZ-0007, Missile Resistant and Watertight Doors Preventative Maintenance,  Revision 9 HC.OP-AB.MISC-0001, Acts of Nature, Revision 23 HC.OP-DL.ZZ-0014, Monday Shift Routine Log, Revision 34 HC.OP-GP.ZZ-0003, Station Preparations for Winter Conditions, Revision 29 OP-AA-108-111-1001, Severe Weather and Natural Disaster Guidelines, Revision 9  WC-AA-107, Seasonal Readiness, Revision 13  Other Documents 2013 Summer Readiness Hope Creek Critique 2014 Hope Creek Summer Readiness Affirmation Certification Letter, dated May 1, 2014  Notifications (*NRC-identified) 20546153 20562816 20610276 20612823 20613802 20615133 20649147 20650908 20650999 20652771* 20652918* 20654490 20654491 20654493 20654495 20654496  Maintenance Orders/Work Orders 30236406 60092591 60104126 60112815 60112948 60114177 60115861 70159564 80107747 80110867   
should provide a response within 30 days of the date of this inspection report, with the basis for
A-3    Attachment  Drawings  A-0203-0, General Plant Floor Plan Level 3    Section 1R04: Equipment Alignment  Procedures HC.OP-ST.BD-0001, RCIC Piping and Flow Path Verification  Monthly, Revision 14 HC.OP-ST.EA-0001, Service Water Flow Path Verification  Monthly, Revision 11 OP-AA-108-116, Protected Equipment Program, Revision 9 OP-HC-108-115-1001, Operability Assessment and Equipment Control Program, Revision 27  Notifications (*NRC-identified) 20529358 20529359 20529360 20529362 20636088 20636089 20647011 20648223 20649406* 20649407* 20649408* 20649409*  Maintenance Orders/Work Orders 30255253 50165993 70127188 70129996  Drawings E-0485-0, Electrical Schematic Auxiliary Building  Diesel Area Switchgear Room Coolers and Air Dampers, Sht. 3, Revision 8 M-10-1, Sheet 1, Service Water, Revision 54 M-10-1, Sheet 2, Service Water, Revision 43 M-49-1, Reactor Core Isolation Cooling, Revision 30 M-50-1, RCIC Pump Turbine, Revision 29  Miscellaneous HCGS PRA Risk Evaluation Form for Work Week #1418, Revision 3, dated May 2, 2013 MP 192355 NRC IN 96-06, Design and Testing Deficiencies of Tornado Dampers at Nuclear Power Plants OE 33769 PM 30255253 Protected Equipment Log for HPCI Sight Glass Repair, dated May 2, 2014  Section 1R05: Fire Protection  Procedures FP-AA-014, Fire Protection Training Program, Revision 1 FP-AA-015, Compensatory Measure Firewatch Program, Revision 5 FP-AA-028-1001, Emergency Response Safety and Risk Management Plan, Revision 0 FP-HC-004, Actions for Inoperable Fire Protection  Hope Creek Station, Revision 1 FRH-II-- FRH-II-412, Hope Creek Pre-Fire Plan, RCIC Pump and Turbine Room, RHR Pump and Heat , Revision 3 FRH-II-415, Hope Creek Pre---Revision 4 FRH-II-522, Hope Creek Pre-Fire Plan, - FRH-II-532, Hope Creek Pre-Fire Plan, - Revision 6 
your disagreement, to the Regional Administrator, Region I, and the NRC Resident Inspector at
A-4    Attachment  FRH-II-542, Hope Creek Pre-Fire Plan, -- FRH-II-551, Hope Creek Pre-Fire Plan, - - HC.OP-IS.BD-0001, Reactor Core Isolation Cooling Pump  OP203  Inservice Test, Rev 58 SH.FP-EO.ZZ-0002, Fire Department Fire Response, Revision 3  Notifications (*NRC identified) 20632422 20633801 20639488 20642920 20644734 20644822 20646267 20646330 20646361 20647111 20647263* 20647351* 20651472  Maintenance Orders/Work Orders 0158901 50165299 70143862 70161457  Drawings M-50-1, P&ID RCIC Pump Turbine, Revision 29  Miscellaneous  Fire Protection Impairment Permit 11760, dated April 16, 2014  Section 1R06: Flood Protection Measures  Procedures EP-HC-111-130, HC EAL Wall Chart  All Conditions, Revision 1 HC.OP-AR.ZZ-0004, Overhead Annunciator Window Box A6, Revision 18 HC.OP-AR.ZZ-0006, Overhead Annunciator Window Box B1, Revision 25 HC.OP-AR.ZZ-0022, CRIDS Computer Points Book 3 D2880 Thru D3257, Revision 19 HC.OP-EO.ZZ-0103/4, Reactor Building and Radioactive Release Control, Revision 9 HC.OP-EO.ZZ-0103/4-CONV, Hope Creek Emergency Operating Procedure Conversion Document, Revision 9 HC.OP-EO.ZZ-0103/4-FC, Reactor Building and Radioactive Release Control Flow Chart, Revision 9  Notifications (*NRC identified) 20643688* 20643694* 20643696* 20643885* 20643886* 20643887* 20646334* 20646335* 20653586* 20656703*  Drawings A-4641-1, Reactor Building Unit 1 - J-25-0, Sheet 5, Logic Diagram Plant Leak Detection, Revision 6 M-25-1, Sheet 1, Plant Leak Detection, Revision 8 M-97-1, Sheet 2, Building and Equipment Drain Reactor Building, Revision 18  Other Documents Calculation Number 11-0092, Reactor Building Flooding  Calculation Number BC-0031, ECCS Pump Rooms Flood Level Alarm Set Point, Revision 1 HC-PRA-012, Internal Flood Evaluation Summary and Notebook, Revision 2 HC-PRA-017, Internal Flood Walkdown Notebook, Revision 0 
HCGS.
A-5    Attachment  Section 1R11: Licensed Operator Requalification Program  Procedures CY-AB-120-340, Offgas Chemistry, Revision 8 HC.OP-AB.IC-0001, Control Rod, Revision 16 HC.OP-FT.AC-0002, Main Turbine Functional Test Monthly, Revision 31 HC.OP-FT.AC-0005, Turbine Overspeed Protection System Operability Test  Quarterly,  Revision 13 HC.OP-ST.AC-0002, Turbine Valve Testing  Quarterly, Revision 49 HU-AA-1211, Pre-Job Briefings, Revision 11 NF-AA-400-1000, Fuel Integrity Monitoring, Revision 4 NF-AA-400-1700, BWR Fuel Reliability Indicator (FRI) Calculation and Transmittal, Revision 1 NF-AA-430, Failed Fuel Action Plan, Revision 8 OP-AA-101-111-1004, Operations Standards, Revision 4 OP-AA-108-111, Attachment 1, Adverse Condition Monitoring and Contingency Plan, Revision 7 OP-AA-300, Reactivity Management, Revision 6 OP-AB-300-1001, BWR Control Rod Movement Requirements, Revision 6 OP-AB-300-1003, BWR Reactivity Maneuver Guidance, Revision 11  Notifications 20543906 20566308 20644437  Maintenance Orders/Work Orders 50163804 70140638 80110856  Other Documents HC 14-01, OTDM for Turbine Overspeed Protection System Operability Test  Quarterly, February 11, 2014 HC 14-008, ACM for Fuel Reliability Parameters used to Monitor Fuel Defect indicate potential fuel failure, March 25, 2014, Revision 0 Hope Creek Long Term Trends  2014 for Failed Fuel Monitoring (NOTF 20644437) Hope Creek Failed Fuel Monitoring Team Meeting on March 15, 2014 REMA 2014-0022, April 2014 TVT and PST Downpower REMA, Revision 0  Miscellaneous Scenario Guide (SG)-644, Reactor Recirc Pump Trip / RWCU Leak / Loss of Main Condenser Vacuum / ATWS dated April 24, 2014  Section 1R12: Maintenance Effectiveness  Procedures ER-AA-10, Equipment Reliability Process Description, Revision 1 ER-AA-310, Implementation of the Maintenance Rule, Revision 11 ER-AA-310-1001, Maintenance Rule  Scoping, Revision 6 ER-AA-310-1004, Maintenance Rule  Performance Monitoring, Revision 10 ER-AA-310-1005, Maintenance Rule  Dispositioning Between (a)(1) and (a)(2), Revision 9 ER-HC-310-1009, Maintenance Rule System Function and Risk Significant Guide, Revision 10 ER-SA-310-1009, Salem Generating Station  Maintenance Rule Scoping, Revision 4 HC.DE-PS.ZZ-0041, Hope Creek Station Blackout Program, Revision 3 
A-6    Attachment  HC.IC-CC.SK-0002, RCIC  Division 4 Steam Leak Detection Temperature Monitor H1SK-1SKXR-11503, Revision 14 HC.IC-DC.SK-0001, NUMAC Leak Detection Setup and Trip Selection, Revision 11 HC.OP-AB.ZZ-0135, Station Blackout // Loss of Offsite Power // Diesel Generator Malfunction, Revision 39 LS-AA-125, Corrective Action Program, Revision 17 MA-AA-716-004, Conduct of Troubleshooting, Revision 12 MA-AA-716-012, Post Maintenance Testing, Revision 19 MA-AA-716-210-1005, Predefine Change Process, Revision 3 S1.OP-AB.LOOP-0001, (Salem) Loss of Off-site Power, Revision 29 WC-AA-111, Predefine Process, Revision 8  Notifications  20335737 20413574 20447050 20502118 20570839 20619184 20623712 20638460 20640526 20645207 20651951  Orders 60113250 70073704 70105948 70121525 70124871 70157974 70161698 80110856  Miscellaneous HC 10-m 72 hours to 14 days HC 13-015, OTDM for Continued Operation of the Moisture Separator without a Root Cause for the Dump Valve Failing to Control Level, dated December 6, 2013 NUMARC 93-01, Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Revision 4 NRC Correspondence, HCGS  Issuance of Amendment Re: Emergency Diesel Generators A and B Allowed Outage Time Extension, dated March 25, 2011  Section 1R13: Maintenance Risk Assessments and Emergent Work Control  Procedures HC.CH-SA.HA-0002, Sampling Offgas System from 00-C-963 Panel, Revision 8 HC.OP-AB.RPV-0001, Reactor Power, Revision 13 HC.OP-FT.AC-0005, Turbine Overspeed Protection System Operability Test  Quarterly,  Revision 13 HC.OP-IO.ZZ-0006, Power Changes During Operation, Revision 57 HC.OP-SO.BB-0002, Reactor Recirculation System Operation, Revision 98 HC.OP-SO.PB-0001, 4.16KV System Operation, Revision 29 HC.OP-ST.PB-0002, AC Power Supply Transfer Functional Test  18 Months, Revision 11 HC.OP-ST.ZZ-0001, Power Distribution Lineup  Weekly, Revision 36 MA-AA-1000, Conduct of Maintenance Manual, Section 3.0 - Maintenance Standards and Practices, Revision 7 and 14 NC.CH-RC.ZZ-2525, Gamma Spectroscopy Analysis Using CAS, Revision 4 NF-AB-431, Power Suppression Testing, Revision 6 WC-AA-101, On-Line Work Management Process, Revision 22 WC-AA-105, Work Activity Risk Management, Revision 2     
A-7    Attachment  Notifications (*NRC identified) 20465881 20521256 20585982 20593568 20600597 20627730 20632023 20634061 20637967 20638221 20639498 20639519 20644437 20645095 20645435 20645701* 20645705 20650898 20650904 20651102 20651204 20651430 20651432 20651876 20653142  Maintenance Orders/Work Orders 30098613 30098617 30243196 30265556 60061175 60114688 60117312 70046681 70072347 70097158 70110518 70142932 70155514 70162013  Miscellaneous DCP 4-HC-0170 HC-14- HCGS Operations Narrative Logs, May 14-15, 2014 HCGS PRA Risk Evaluation Form for June 8, 2014, through June 14, 2014, Revision 0 Protected Equipment Log  HRE 2014-0023, Mid-Cycle 19 Standing REMA, from May 9-30, 2014, Revision 3 NRC RIS 2007-21, Adherence to Licensed Power Limits, Revision 1 REMA 2014-0022, April 2014 TVT and PST Downpower REMA, Revision 0 Troubleshooting Data Sheet  November 15, 2013 Troubleshooting Work Sheet  NOTF 20651102 for Proper Indication and ControSpeed Control Loop, dated May 14, 2014 WC-AA-105-F3, Form 3, Risk Management Plan    Section 1R15: Operability Determinations and Functionality Assessments  CC-AA-309-101, Engineering Technical Evaluations, Revision 10 ER-AA-2006, Lost Parts Evaluation, Revision 8 HC.CH-CA.ZZ-0026, Boron by Mannitol Titration, Revision 18 HC.OP-AB.RPV-0001, Reactor Power, Revision 13 HC.OP-IO.ZZ-0006, Power Changes During Operation, Revision 57 HC.OP-IS.BH-0004, Standby Liquid Control Pump  BP208  Inservice Test, Revision 12 HC.OP-SO.BB-0002, Reactor Recirculation System Operation, Revision 98 HC.OP-SO.KJ-0001, Emergency Diesel Generators Operation, Revision 70 HC.OP-SO.PB-0001, 4.16KV System Operation, Revision 29 HC.OP-ST.KJ-0003, Emergency Diesel Generator 1CG400 Operability Test  Monthly,  Revision  76 HC.OP-ST.PB-0002, AC Power Supply Transfer Functional Test  18 Months, Revision 11 HC.OP-ST.ZZ-0001, Power Distribution Lineup  Weekly, Revision 36 HU-AA-1212, Technical Task Risk/Rigor Assessment, Pre-Job Brief, Independent Third Party Review and Post-Job Brief, Revision 8 MA-AA-1000, Conduct of Maintenance Manual, Section 3.0 - Maintenance Standards and  Practices, Revision 7 and 14 WC-AA-101, On-Line Work Management Process, Revision 22 
A-8    Attachment  Notifications (*NRC identified) 20221500 20439888 20442565 20442566 20465881 20521256 20585982 20593568 20600597 20616574 20627730 20632023 20634061 20637967 20638221 20639498 20639519 20640696 20643229 20643322* 20644637 20645519 20645994 20647199* 20650611* 20650701* 20650788* 20650831* 20650856* 20650858* 20650898 20650904 20651102 20651204 20651430 20651432 20651876 20652187 20652199 20653142 20653635*  Drawings M-52-1, Core Spray, Revision 31 M-52-1, Sheet 1, Residual Heat Removal, Revision 45 M-52-1, Sheet 2, Residual Heat Removal, Revision 40  Maintenance Orders/Work Orders 30098613 30098617 30243196 50165850 60061175 60087495 60087534 60087538 60087539 60087540 60087541 60089905 60114688 60117312 70046681 70072347 70097158 70110518 70142932 70149472 70155514 70157453 70162013 70163760 70164628 80079629 80079863 80108395 80111752 80111754  Miscellaneous 10855-D3.33, Design, Installation and Test Specification for Standby Liquid Control System for the Hope Creek Generating Station, Revision 5 22A7641, Design Specifications for SLC System, Revision 1 ASTM E29-13, Standard Practice for Using Significant Digits in Test Data to Determine Conformance with Specifications C-0001, Wall Thickness Calculation for Piping, Revision 9 Calculation 1SC-BH-0001, SLC System Tank 10T-204 Level, Revision 0 DCP 4-HC-0170 DCP 4HM-0136, Change Standby Liquid Control Tank Sodium Pentaborate Concentration from 13.4 to 14.0 Weight Percent, dated December 17, 1987 HC-14- HCGS Operations Narrative Logs, May 14-15, 2014 HRE 2014-0023, Mid-Cycle 19 Standing REMA, from May 9-30, 2014, Revision 3 LD-042-MASTERPACT-1, Masterpact Issues, Revision 1 NLR-N87131, Request for Amendment Facility Operating License NPF-57 Hope Creek Generating Station Docket No. 50-354, dated July 14, 1987 NRC RIS 2007-21, Adherence to Licensed Power Limits, Revision 1 Part 9900: Technical Guidance, Standard Technical Specifications Section 3.0 Acceptable Measurement Tolerances for Technical Specification Limits, dated October 1, 1978 PM018Q-0499, Vol. 1, Operation and Maintenance Manual for Colt Industries Diesel Generator, Revision 25 Troubleshooting Data Sheet  NOTF 15, 2013 Troubleshooting Work Sheet  Speed Control Loop, dated May 14, 2014 WC-AA-105-F3, Form 3, Risk Management Plan  solator, Revision 1   
A-9    Attachment  Section 1R18: Plant Modifications  Procedures CC-AA-102, Design Input and Configuration Change Impact Screening, Revision 23 CC-AA-103, Configuration Change Control for Permanent Physical Plant Changes, Revision 15 CC-AA-112, Temporary Configuration Changes, Revision 13 CC-AA-112-1001, Temporary Configuration Change Implementation T&RM, Revision 2 OP-AA-115-101, Operator Aid Postings, Revision 3  Notifications  20439888 20639161 20640696 20651205 20652187  Maintenance Orders/Work Orders 60115429 70163760 80107203 80111298 80111754  Drawings M-08-0, Sheet 1, Condensate & Refueling Water Storage & Transfer, Revision 34  Miscellaneous DCP 80111754, Masterpact Breaker Add Aux Contact with Close Coil, Revision 1 H-1-ZZ-EGS-0043, Hope Creek Generating Station GE AKR Circuit Breaker Replacement Project LD-042-MASTERPACT-1, Revision 1 OPEVAL 14-002, Masterpact Breaker Model NW with Locked in Close Signal, Revision 3 Temporary Configuration Change Package Tracking Log, dated June 10, 2014  Section 1R19: Post-Maintenance Testing  Procedures CC-AA-309-101, Engineering Technical Evaluations, Revision 10 HC.IC-CC.SK-0002, RCIC  Division 4 Steam Leak Detection Temperature Monitor H1SK-1SKXR-11503, Revision 14 HC.IC-DC.SK-0001, NUMAC Leak Detection Setup and Trip Selection, Revision 11 HC.IC-DC.ZZ-0011, Device/Equipment Calibration Bailey, Characterizable Pneumatic Positioner, Type AP2, Revision 5 HC.OP-AB.COMP-0001, Instrument and/or Service Air, Revision 5 HC.OP-AB.RPV-0001, Reactor Power, Revision 13 HC.OP-IO.ZZ-0006, Power Changes During Operation, Revision 57 HC.OP-IS.BJ-0001, HPCI Main and Booster Pump Set  OP204 and OP217  Inservice Test, Revision 62 HC.OP-SO.BB-0002, Reactor Recirculation System Operation, Revision 98 HC.OP-ST.BC-0005, LPCI Subsystem B ECCS Time Response Functional Test  18 Months, Revision 16 HC.OP-ST.ZZ-0001, Power Distribution Lineup  Weekly, Revision 36 HU-AA-1212, Technical Task Risk/Rigor Assessment, Pre-Job Brief, Independent Third Party Review and Post-Job Brief, Revision 8 MA-AA-716-012, Post Maintenance Testing, Revision 19 MA-AA-1000, Conduct of Maintenance Manual, Section 3.0 - Maintenance Standards and  Practices, Revision 7 and 14 SM-AA-410, Control of Purchased Material, Equipment and Services Program, Revision 6 WC-AA-101, On-Line Work Management Process, Revision 22 
A-10    Attachment  Notifications (*NRC identified) 20454035 20465881 20521256 20619184 20623712 20623802 20629385 20632023 20642546 20642950 20647111 20650904 20651102 20651430 20651872 20651951 20652010 20652012 20652232 20652238 20652321 20652339 20652702 20653142 20653572* 20653872*  Maintenance Orders/Work Orders 30098613 30098617 30240742 30269527 50163142 60113238 60113250 60116090 60117312 70125746 70155514 70157974 70163994 70166194  Drawings PN11-E11-1040-0383, Sheet 3, Residual Heat Removal System, Revision 15 PN11-E11-1040-0383, Sheet 12, Residual Heat Removal System, Revision 18 PN11-E11-1040-0383, Sheet 13, Residual Heat Removal System, Revision 10 PN11-E11-1040-0383, Sheet 22, Residual Heat Removal System, Revision 17  Miscellaneous HC-14- HCGS Operations Narrative Logs, May 14-15, 2014 HCGS PRA Risk Evaluation Form for April 20, 2014 through April 26, 2014 HRE 2014-0023, Mid-Cycle 19 Standing REMA, from May 9-30, 2014, Revision 3 NRC RIS 2007-21, Adherence to Licensed Power Limits, Revision 1 Troubleshooting Data Sheet  emand, dated  November 15, 2013 Troubleshooting Work Sheet  Speed Control Loop, dated May 14, 2014 WC-AA-105-F3, Form 3, Risk Management Plan    Section 1R22: Surveillance Testing  Procedures CC-AA-309-101, Engineering Technical Evaluations, Revision 10 ER-AA-2006, Lost Parts Evaluation, Revision 8 FP-HC-004, Actions for Inoperable Fire Protection  Hope Creek Station, Revision 1 HC.FP-ST.KC-0009, Diesel Driven Fire Pump Operability Test, Revision 20 HC.IC-CC.SK-0016, Radiation Monitoring  Channel D Monitor H1SK-1SKLY-4930 Drywell Leak Detection Sump Monitoring System (DLD-SMS), Revision 22 HC.IC-GP.ZZ-0004, Thermocouples (T/C) and Resistance Temperature Detectors (RTD), Revision 8 HC.MD-ST.PB-0003, Class 1E 4.16 kV Feeder Degraded Voltage Monthly Instrumentation Channel Functional Test, Revision 26  HC.OP-DL.ZZ-0026, Surveillance Log, Revision 139 HC.OP-FT.AC-0002, Main Turbine Functional Test Monthly, Revision 31 HC.OP-FT.AC-0005, Turbine Overspeed Protection System Operability Test  Quarterly, Revision 13 HC.OP-IS.BC-0002, CP202, C Residual Heat Removal Pump In-Service Test, Revision 43 HC.OP-IS.BJ-0001, HPCI Main and Booster Pump Set  0P204 and 0P217  Inservice Test, Revision 62 
A-11    Attachment  HC.OP-SO.KJ-0001, Emergency Diesel Generators Operation, Revision 70 HC.OP-ST.AC-0002, Turbine Valve Testing  Quarterly, Revision 49 HC.OP-ST.KJ-0001, Emergency Diesel Generator 1AG400 Operability Test  Monthly,  Revision 76 HC.OP-ST.KJ-0003, Emergency Diesel Generator 1CG400 Operability Test  Monthly,  Revision 78 HC.OP-ST.SK-0001, Alternate RCS Leakage Determination, Revision 9 HU-AA-1211, Pre-Job Briefings, Revision 11 HU-AA-1212, Technical Task Risk/Rigor Assessment, Pre-Job Brief, Independent Third Party Review and Post-Job Brief, Revision 8 OP-AA-101-111-1004, Operations Standards, Revision 4 OP-AA-108-101, Control of Equipment and System Status, Revision 7 OP-AA-300, Reactivity Management, Revision 6  Notifications  20504658 20629522 20630428 20630429 20640032 20645519 20645994 20646319 20648114 20648751 20649201 20649292 20649425 20649905 20649906 20654936  Maintenance Orders/Work Orders 30199753 50163804 50164408 50164695 50165664 50165690 50165691 50165850 50166624 50167441 50169340 60026593 60058122 60097901 60107882 70008407 70023178 70097767 70122058 70127960 70139509 70145982 80111752  Calculations SC-SK-0118, Drywell Leak Detection SMS (Floor Drain Unidentified Leakage), Revision 2  Miscellaneous HC 14-01, OTDM for Turbine Overspeed Protection System Operability Test  Quarterly, dated February 11, 2014 HCGS PRA Risk Evaluation Form for April 6, 2014, through April 12, 2014 PM018Q-0499, Vol. 1, Operation and Maintenance Manual for Colt Industries Diesel Generator,  Revision 25 REMA 2014-0022, April 2014 TVT and PST Downpower REMA, Revision 0  Section 1EP6: Drill Evaluation  Procedures EP-AA-122, Drills and Exercises, Revision 3 EP-AA-122-1001, Drill and Exercise Scheduling, Development and Conduct, Revision 3 EP-AA-125-1002, NRC Drill and Exercise Performance (DEP) Indicator Guidance, Revision 3  EP-HC-111-121, Fission Product Barrier Table, Revision 1 EP-HC-111-230, Use of Fission Product Barrier Table, Revision 0 NC.EP-EP.ZZ-0102, Emergency Coordinator Response, Revision 18  NC.EP-EP.ZZ-0404, Protective Action Recommendations (PARS) Upgrades, Revision 4  Notifications  20654844 
A-12    Attachment  Miscellaneous DEP Observation Checklist for FAD-HC14-02, dated June 24, 2014  Section 4OA1: Performance Indicator Verification  Procedures HC.OP-DL.ZZ-0026, Surveillance Log, Revision 136 HC.OP-DL.ZZ-0026, Surveillance Log, Revision 137 HC.OP-DL.ZZ-0026, Surveillance Log, Revision 138 HC.OP-DL.ZZ-0026, Surveillance Log, Revision 139 HC.RA-IS.ZZ-0010, Containment Isolation Valve Type C Leak Rate Test, Revision 15 LS-AA-2090, Monthly Data Elements for NRC Reactor Coolant System Activity, Revision 5  LS-AA-2100, Monthly Data Elements for NRC Reactor Coolant System Leakage, Revision 6  LS-HC-1000-1001, Hope Creek Generating Station Surveillance Frequency Control Program List of Surveillance Frequencies, Revision 4 NC.CH-RC.ZZ-2525, Gamma Spectroscopy Analysis Using CAS, Revision 4 NC.CH-SA.RC-0002, Operation of the Reactor Building/RHR Sample Stations, Revision 18  Calculations SC-SK-0119, Drywell Leak Detection SMS  Equipment Drain Sump, Revision 1  Notifications 20650305  Maintenance Orders/Work Orders 50137021 50149686 50162608  Miscellaneous Daily Dose Equivalent Iodine-131 Sample Data Daily Surveillance Log Data Monthly Data Elements for NRC Reactor Coolant System Leakage Data Sheets  Section 4OA2: Problem Identification and Resolution  Procedures  ER-AA-2003, System Performance Monitoring and Analysis, Revision 9 ER-AA-3002, Component Cross-System Monitoring & Component Health Reporting, Revision 3 LS-AA-125, Corrective Action Program, Revision 17 LS-AA-125-1006, Performance Improvement Integrated Matrix (PIIM), Revision 5 LS-AA-1006, NRC Cross-Cutting Analysis and Trending, Revision 2  Notifications (*NRC identified) 20615843 20619913 20632801 20632802 20632361 20632641 20632746 20632747 20632748 20632749 20633058 20633338 20633339 20634028 20635871 20636138 20638889 20639772 20642767 20644539  Orders 70144876 70158815 70161953 70162269 80109029 80110809 80110866 
A-13    Attachment  Miscellaneous Hope Creek Engineering PIIM Report 1st Cycle 2013 Presentation, dated 8/31/13  Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion  Procedures CC-AA-102, Design Input and Configuration Change Impact Screening, Revision 23 CC-AA-103, Configuration Change Control for Permanent Physical Plant Changes, Revision 15 ER-HC-310-1009, Maintenance Rule System Function and Risk Significant Guide, Revision 10 HC.IC-DC.ZZ-0140, Device/Equipment Cal. Masoneilan Pressure Temperature Controller, Revision 4 HC.IC-LC.AF-0007, Moisture Separator Drain Tank Level Tuning, Revision 2 HC.OP-AB.RPV-0001, Reactor Power, Revision 13 HC.OP-AR.ZZ-0008, Overhead Annunciator Window Box C1, Revision 45 HC.OP-DL.ZZ-0026, Surveillance Log, Revision 140 HC.OP-SO.BB-0002, Reactor Recirculation System Operation, Revision 98 HC.OP-SO.GJ-0001, A(B) K400 Control Area Chilled Water System Operation, Revision 60 HU-AA-1211, Pre-Job Briefings, Revision 11 LS-AA-125-1003, Attachment 2, Equipment Apparent Cause Evaluation Guide, Revision 13DCP 4EC-3662 MA-AA-716-004, Conduct of Troubleshooting, Revision 12 SM-AA-300, Procurement Engineering Support Activities, Revision 7 WC-AA-105, Work Activity Risk Management, Revision 2  Notifications (*NRC identified) 20454035 20521256 20528822 20529153 20567269 20570629 20630857 20631351 20631820 20631940 20632542 20638799 20640526 20642546 20642767 20643301 20644017 20645207 20647829 20650346* 20650904 20651102 20651876 20652180 20652182 20652183 20652184 20652185 20652186 20652188 20653024 20653142  Maintenance Orders/Work Orders 60114285 60114286 70041898 70110518 70115711 70119769 70128407 70129670 70140751 70142556 70159686 70161353 70161698 70162284  Miscellaneous 10855-d3.33, Design, Installation and Test Specification for Standby Liquid Control System for the Hope Creek Generating Station, Revision 5 22A7641, Design Specifications for SLC System, Revision 1 ASTM E29-13, Standard Practice for Using Significant Digits in Test Data to Determine Conformance with Specifications Calculation 1SC-BH-0001, SLC System Tank 10T-204 Level, Revision 0 DCP 4-HC-0170 DCP 4HM-0136, Change Standby Liquid Control Tank Sodium Pentaborate Concentration from 13.4 to 14.0 Weight Percent, December 17, 1987 HC-14- HCGS Operations Narrative Logs, May 14-15, 2014 HRE 2014-0023, Mid-Cycle 19 Standing REMA, from May 9-30, 2014, Revision 3 
A-14    Attachment  LER 2013-009-00, Automatic Actuation of the Reactor Protection System Due to a Main Turbine Trip LER 2013-009-01, Automatic Actuation of the Reactor Protection System Due to a Main Turbine Trip NLR-N87131, Request for Amendment Facility Operating License NPF-57 Hope Creek Generating Station Docket No. 50-354, dated July 14, 1987 NRC RIS 2007-21, Adherence to Licensed Power Limits, Revision 1 Part 9900: Technical Guidance, Standard Technical Specifications Section 3.0 Acceptable Measurement Tolerances for Technical Specification Limits, October 1, 1978 PM018Q-0499, Vol. 1, Operation and Maintenance Manual for Colt Industries Diesel Generator, Revision 25 Troubleshooting Data Sheet  November 15, 2013 Troubleshooting Work Sheet  Speed Control Loop, dated May 14, 2014 WC-AA-105-F3, Form 3, Risk Management Plan  Repl  Section 4OA5: Other Activities        -- --- --    - -  ---    -  --    - -  --  ----  ----  --- ---   
A-15    Attachment  LIST OF ACRONYMS  10 CFR  Title 10 of The Code of Federal Regulations ADAMS  Agencywide Documents Access and Management System CAP  corrective action program CCE  common cause evaluation CFR  The Code of Federal Regulations CRE  control room envelope DCP  design change package EDG  emergency diesel generator EN  event notification EQACE  equipment apparent cause evaluation    HCGS  Hope Creek Generating Station    HPCI  high pressure coolant injection HVAC  heating, ventilation and air conditioning IMC  Inspection Manual Chapter kV  kilovolt LER  licensee event report LM  logic module MCR  main control room        NCV  non-cited violation    NOTF  notification NRC  Nuclear Regulatory Commission    PARS  Publicly Available Records PC  purchase classification PCV  pressure control valve PI  performance indicator PIIM  performance improvement integrated matrix        RCIC  reactor core isolation cooling RCS  reactor coolant system RG  Regulatory Guide RHR  residual heat removal RRP  reactor recirculation pump RTP  rated thermal power RWCU  reactor water cleanup SACS  safety auxiliaries cooling system SDP  Significance Determination Process SLC  standby liquid control SRV  safety relief valve SSC  structure, system, or component SSW  station service water 
A-16    Attachment  TCCP  temporary configuration control package                    UFSAR  Updated Final Safety Analysis Report               


T. Joyce                                            2
In accordance with Title 10 of the Code of Federal Regulations (CFR) 2.390 of the NRCs Rules
of Practice, a copy of this letter, its enclosure, and your response (if any) will be available
electronically for public inspection in the NRCs Public Document Room or from the Publicly
Available Records component of the NRCs Agencywide Documents Access Management
System (ADAMS). ADAMS is accessible from the NRC website at http://www.nrc.gov/reading-
rm/adams.html (the Public Electronic Reading Room).
                                                Sincerely,
                                                  /RA/
                                                Glenn T. Dentel, Chief
                                                Reactor Projects Branch 3
                                                Division of Reactor Projects
Docket Nos.: 50-354
License Nos.: NPF-57
Enclosure:      Inspection Report 05000354/2014003
                w/Attachment: Supplementary Information
cc w/encl:      Distribution via ListServ
ML14209A132
                                            Non-Sensitive                            Publicly Available
  SUNSI Review
                                            Sensitive                                Non-Publicly Available
OFFICE        RI/DRP                  RI/DRP                RI/DRP
NAME          JHawkins/ RSB for      RBarkley/ RSB        GDentel/ GTD
DATE          07/22 /14              07 /22/14            07 / 28 /14
                                         
                                        1
              U.S. NUCLEAR REGULATORY COMMISSION
                                    REGION I
Docket Nos.:  50-354
License Nos.:  NPF-57
Report No.:    05000354/2014003
Licensee:      Public Service Enterprise Group (PSEG) Nuclear LLC
Facility:      Hope Creek Generating Station (HCGS)
Location:      P.O. Box 236
              Hancocks Bridge, NJ 08038
Dates:        April 1, 2014 through June 30, 2014
Inspectors:    J. Hawkins, Senior Resident Inspector
              S. Ibarrola, Resident Inspector
              H. Gray, Senior Reactor Inspector
Approved By:  Glenn T. Dentel, Chief
              Reactor Projects Branch 3
              Division of Reactor Projects
                                                                  Enclosure
                                                              2
                                            TABLE OF CONTENTS
SUMMARY ................................................................................................................................ 3
REPORT DETAILS .................................................................................................................... 7
1.  REACTOR SAFETY ........................................................................................................... 7
  1R01  Adverse Weather Protection .................................................................................... 7
  1R04  Equipment Alignment ............................................................................................... 8
  1R05  Fire Protection .......................................................................................................... 9
  1R06  Flood Protection Measures .....................................................................................10
  1R11  Licensed Operator Requalification Program ...........................................................13
  1R12  Maintenance Effectiveness .....................................................................................14
  1R13  Maintenance Risk Assessments and Emergent Work Control ................................16
  1R15  Operability Determinations and Functionality Assessments ....................................19
  1R18  Plant Modifications .................................................................................................20
  1R19  Post-Maintenance Testing ......................................................................................20
  1R22  Surveillance Testing ...............................................................................................21
  1EP6  Drill Evaluation .......................................................................................................22
4.  OTHER ACTIVITIES ..........................................................................................................22
  4OA1  Performance Indicator (PI) Verification ....................................................................22
  4OA2  Problem Identification and Resolution ....................................................................23
  4OA3  Follow-Up of Events and Notices of Enforcement Discretion ..................................24
  4OA5  Other Activities ........................................................................................................30
  4OA6  Meetings, Including Exit ...........................................................................................31
  4OA7  Licensee-Identified Violations ..................................................................................31
ATTACHMENT: SUPPLEMENTARY INFORMATION...............................................................31
SUPPLEMENTARY INFORMATION....................................................................................... A-1
KEY POINTS OF CONTACT .................................................................................................. A-1
LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED .................................... A-1
LIST OF DOCUMENTS REVIEWED....................................................................................... A-2
LIST OF ACRONYMS ........................................................................................................... A-15
                                                                                                                          Enclosure
                                                    3
                                              SUMMARY
IR 05000354/2014003; 4/01/2014 - 6/30/2014; Hope Creek Generating Station; Flood
Protection Measures, Maintenance Effectiveness, Maintenance Risk Assessments and
Emergent Work Control, Follow-up of Events and Notices of Enforcement Discretion.
This report covered a three-month period of inspection by the resident inspectors and
announced inspections performed by regional inspectors. Five findings of very low safety
significance (Green) were identified. Three of the findings were determined to be violations of
NRC requirements. The significance of most findings is indicated by their color (i.e., greater
than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter
(IMC) 0609, Significance Determination Process (SDP), dated June 2, 2011. Cross-cutting
aspects are determined using IMC 0310, Components Within Cross-Cutting Areas, dated
December 19, 2013. All violations of NRC requirements are dispositioned in accordance with
the NRCs Enforcement Policy, dated July 9, 2013. The NRCs program for overseeing the safe
operation of commercial nuclear power reactors is described in NUREG-1649, Reactor
Oversight Process, Revision 5.
Cornerstone: Initiating Events
  Green. A self-revealing finding of very low safety significance (Green) was identified for
    PSEGs failure to evaluate an identified deficiency in accordance with PSEG procedure
    LS-AA-125, Corrective Action Program. Specifically, PSEG failed to take self-
    recommended actions in notification (NOTF) 20447050 to evaluate the B moisture
    separator (MS) dump valve performance after failing to operate as designed during B MS
    drain valve troubleshooting on January 11, 2010. As a result, PSEG did not identify and
    correct a potential design flaw associated with thermal binding of the MS dump valves,
    which was determined to be the cause of the A MS dump valve failing to stroke open on
    December 1, 2013, leading to a reactor scram from 100 percent power. PSEGs corrective
    actions include a design change to the MS emergency level control system that eliminates
    dump valve cycling on high MS level.
    The performance deficiency was determined to be 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. The inspectors determined that this finding was of very low safety significance
    (Green) using Exhibit 1 of NRC IMC 0609, Appendix A, The Significance Determination
    Process (SDP) for Findings At-Power, dated June 19, 2012, because the finding did not
    cause both a reactor trip and the loss of mitigation equipment relied upon to transition the
    plant from the onset of the trip to a stable shutdown condition (e.g. loss of condenser, loss
    of feed water). The inspectors determined that there was no cross-cutting aspect
    associated with this finding because the cause of the performance deficiency occurred
    more than three years ago, and was not representative of present plant performance.
    (Section 1R12)
  Green. A self-revealing Green NCV of Technical Specification (TS) 6.8.1.a, Procedures
    and Programs, was identified for PSEGs failure to follow procedure MA-AA-1000,
    Maintenance Standards and Practices, during the replacement of Bailey logic modules
    (LM) associated with the D vital bus (10A404). Specifically, during the spring 2009
                                                                                        Enclosure
                                                  4
  refueling outage (1R15), PSEG failed to follow a work order (WO) requiring the replacement
  of all Bailey logic modules listed in WO 60061175 with new logic modules. As a result, a
  logic module (H1PB-1PBXIS-DC652010302) for the D vital bus was not replaced during
  1R15, and failed due to age on December 19, 2013, causing a loss of the vital bus and an
  entry into the associated 8 hour Technical Specification Action Statement (TSAS) 3.8.3.1
  for Onsite Power Distribution Systems. PSEGs corrective actions included replacement of
  the failed logic module, performance of an extent of condition inspection to ensure other
  similar logic modules and relays were replaced, and reinforcement of proper maintenance
  practices with the individuals involved in the completion of WO 60061175.
  The performance deficiency was determined to be more than minor because it was
  associated with the human 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, not following the work order instructions resulted in an extended
  service duration and failure of a component that resulted in a loss of power to the D vital
  bus on December 19, 2013. Similarly, this performance deficiency was also similar to
  examples 2.g and 4.b of NRC IMC 0612, Appendix E, in that PSEG is required to follow
  their procedures per TS 6.8.1, and ultimately led to a safety impact given the failure of the
  logic module causing a loss of power to the 10A404 vital bus. The inspectors determined
  the finding to be of very low safety significance (Green) in accordance with Exhibit 1 of NRC
  IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power,
  dated June 19, 2012, because the finding involved the loss of a support system that
  contributes to the likelihood of an initiating event (Loss of an AC Bus), but did not affect
  mitigation equipment. The inspectors determined that there was no cross-cutting aspect
  associated with this finding because the cause of the performance deficiency occurred
  more than three years ago, and was not representative of present plant performance.
  (Section 1R13)
Green. A self-revealing finding of very low safety significance (Green) was identified when
  PSEG failed to ensure that appropriate contingency actions were in place prior to the
  performance of A MS emergency level controller tuning as required by WC-AA-105, Work
  Activity Risk Management. Specifically, the decision to tune the emergency level controller
  without appropriate contingencies in place led to a turbine trip on high A MS level and
  subsequent reactor scram on December 5, 2013. PSEGs corrective actions included
  conducting performance management with the individuals involved with the tuning evolution
  and revising the moisture separator drain tank level tuning procedure to require an
  individual at the normal and emergency controllers when performing emergency level
  controller tuning.
  This finding was more than minor because it was associated with the human 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. The inspectors determined that this
  finding was of very low safety significance (Green) using Exhibit 1 of NRC IMC 0609,
  Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated
  June 19, 2012, because the finding did not cause both a reactor trip and the loss of
  mitigation equipment relied upon to transition the plant from the onset of the trip to a stable
  shutdown condition (e.g. loss of condenser, loss of feed water). The inspectors determined
  that the finding had a cross cutting aspect in the Human Performance area associated with
  Work Management, because PSEG personnel did not implement a process of planning,
                                                                                          Enclosure
                                                  5
  controlling, and executing work activities such that nuclear safety is the overriding priority.
  Specifically, technicians were only stationed at the emergency level controller during the
  tuning, when having technicians at both controllers would have provided more time to
  recover from a high level condition in the A MS, and may have prevented the turbine trip
  and subsequent reactor scram on December 5, 2013. [H.5] (Section 4OA3)
Cornerstone: Mitigating Systems
  Green. The inspectors identified a Green NCV of TS 6.8.1.a, Procedures because PSEG
  procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 could potentially complicate an
  internal flooding event and adversely affect assumptions in Hope Creeks flood design.
  Specifically, the procedures did not ensure operator response would not communicate the
  high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) watertight
  rooms and potentially render two safety-significant single train systems inoperable. In
  addition to entering the issue into the corrective action program (CAP) as NOTFs
  20646334, 20646335 and 20620653586, PSEGs corrective actions include a planned
  revision of the annunciator response procedures and issuance of a standing order to the
  Operations department staff.
  The performance deficiency is more than minor because it was associated with the
  procedure quality attribute of the Mitigating Systems cornerstone and adversely affected the
  cornerstone objective to ensure the availability, reliability, and capability of systems that
  respond to initiating events to prevent undesirable consequences (i.e., core damage).
  Specifically, PSEG procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 could
  potentially complicate an internal flooding event and adversely affect assumptions in Hope
  Creeks flood design, since the procedures did not ensure operator response would not
  communicate the HPCI and RCIC watertight rooms and potentially render multiple trains of
  safety-related SSCs inoperable. This performance deficiency was also similar to examples
  3.j and 3.k of NRC IMC 0612, Appendix E, in that communicating the two watertight rooms
  created a reasonable doubt of operability of the HPCI and RCIC systems. PSEG plans to
  perform a detailed technical evaluation to evaluate the impact of internal flood propagation
  in the HPCI and RCIC rooms. The finding was evaluated in accordance with Exhibits 2 and
  4 of NRC IMC 0609, Appendix A, The SDP for Findings At-Power, dated June 19, 2012.
  Since opening the watertight door during an internal flooding event could bypass the flood
  protection feature and potentially degrade two or more trains of a multi-train system or
  function, a detailed risk assessment was performed. The finding was determined to be of
  very low safety significance (Green). Since the change in core damage frequency was
  sufficiently low, no further evaluation for large early release was required. The inspectors
  determined that the finding had a cross cutting aspect in the Human Performance area
  associated with Training, in that PSEG did not provide adequate training and ensure
  knowledge transfer to maintain a knowledgeable, technically competent workforce and instill
  nuclear safety values. Specifically, operator training did not ensure operator response to
  internal flooding would not result in communicating two watertight rooms containing safety
  significant single-train systems. [H.9] (Section 1R06)
                                                                                          Enclosure
                                                  6
Cornerstone: Barrier Integrity
  Green. The inspectors reviewed a Green self-revealing NCV of Title 10 of the Code of
    Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, Design Control, for
    PSEGs failure to effectively implement the design change process. Specifically, PSEGs
    design change package (DCP) 4EC-3662 failed to reclassify the purchase classification
    (PC) of the main control room (MCR) chiller pressure control valve (PCV) positioner from
    non-safety related (PC4) to safety related (PC1). Because of the incorrectly assigned PC,
    PSEG did not track the shelf life of replacement positioner diaphragms, which led to the
    failure of the A MCR positioner on December 20, 2013. PSEGs corrective actions included
    replacement of the failed positioner and changing the purchase classification for the chiller
    PCV positioners to safety-related (PC1). Since the implementation of DCP 4EC-3662 in
    1997, the DCP procedures have been enhanced to ensure the completion of a purchase
    class evaluation of procured materials that are implemented in the design change process.
    The inspectors determined that the performance deficiency was more than minor because
    it is associated with the design control attribute of the Barrier Integrity cornerstone, and
    adversely affected the cornerstone objective of maintaining the radiological barrier
    functionality of the control room. In accordance with Exhibit 3 of NRC IMC 0609, Appendix
    A, The Significance Determination Process (SDP) for Findings at Power, issued June 19,
    2012, the inspectors determined that this finding is of very low safety significance (Green)
    because the performance deficiency represents a degradation of only the radiological barrier
    function provided for the control room. The inspectors determined that there was no cross-
    cutting aspect associated with this finding because the cause of the performance deficiency
    occurred more than three years ago, and was not representative of present plant
    performance. (Section 4OA3)
Other Findings
A violation of very low safety significance that was identified by PSEG was reviewed by the
inspectors. Corrective actions taken or planned by PSEG have been entered into PSEGs
corrective action program. This violation and corrective action tracking number are listed in
Section 4OA7 of this report.
                                                                                            Enclosure
                                                7
                                        REPORT DETAILS
Summary of Plant Status
Hope Creek Generating Station began the inspection period at full rated thermal power (RTP).
On April 1, 2014, Hope Creek conducted a planned down power to 50 percent of RTP to
support power suppression testing (PST), main turbine valve testing and main condenser water
box cleaning. The unit was returned to full RTP on April 4, 2014. On May 14, 2014, the B
reactor recirculation pump (RRP) speed unexpectedly rose to its maximum value. Operators
took manual control of the pump and reduced the pump speed to less than reactor recirculation
flow TS requirements. On May 23, 2014, operators reduced power to 98 percent to perform B
RRP speed control circuit corrective maintenance. Operators returned the unit to full power on
the same day. On May 28, 2014, Hope Creek conducted a planned down power to 50 percent
of RTP to support main turbine valve testing and main condenser water box cleaning. The unit
was returned to full RTP on May 31, 2014, and remained at or near full RTP for the remainder of
the inspection period.
1.      REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection (71111.01 - 2 samples)
.1      Readiness for Seasonal Extreme Weather Conditions
    a. Inspection Scope
        The inspectors performed a review of PSEGs readiness for the onset of seasonal high
        temperatures. The review focused on the safety auxiliaries cooling system (SACS) and
        station service water (SSW) system. The inspectors reviewed the Updated Final Safety
        Analysis Report (UFSAR) and TS to determine what temperatures or other seasonal
        weather could challenge these systems and to ensure PSEG personnel had adequately
        prepared for these challenges. The inspectors reviewed station procedures, including
        PSEGs seasonal weather preparation procedure and applicable operating procedures.
        The inspectors performed walkdowns of the selected systems to verify that no
        unidentified issues existed that could challenge the operability of the systems during hot
        weather conditions. Documents reviewed for each section of this inspection report are
        listed in the Attachment.
    b. Findings
        No findings were identified.
.2      External Flooding
    a. Inspection Scope
        During the week of May 24, 2014, the inspectors performed an inspection of the external
        flood protection measures for Hope Creek. The inspectors reviewed procedures, design
        documents, and the UFSAR, Chapters 2.4.2, Floods, and 3.4, Water Level (Flood)
        Design, which described the design flood levels and protection areas containing safety-
                                                                                        Enclosure
                                                8
      related equipment to identify areas that may be affected by flooding. The inspectors
      also reviewed the limiting conditions for operations and the surveillance requirements in
      TS 3.7.3, Flood Protection. The inspectors review focused on the Hope Creek Unit 1
      areas, which protect Unit 1 equipment, that are susceptible to external flooding.
      Specifically, the inspectors walked down the south, east and west walls of the reactor
      building 102, 77, and 54 elevations. The inspectors inspected the condition of the
      walls and ensured that any outside penetrations susceptible to external flooding were
      flood protected. The inspectors also inspected the flood doors present in that area,
      which are listed in TS Table 3.7.3-1, Perimeter Flood Doors. The inspectors verified
      that the doors were in conformance with plant maintenance procedures and drawings.
      The inspectors reviewed the preventive maintenance activities performed on these doors
      with the responsible system engineer. The inspectors also conducted a walkdown of
      these doors to verify that the doors were in conformance with the design basis
      requirements in the UFSAR, the TS, and plant procedures and drawings. Additionally,
      the inspectors reviewed the abnormal operating procedure, HC.OP-AB.MISC-0001,
      Acts of Nature, for mitigating external flooding during severe weather to determine if
      PSEG had planned or established adequate measures to protect against external
      flooding events.
  b. Findings
      No findings were identified.
1R04 Equipment Alignment
      Partial System Walkdowns (71111.04 - 3 samples)
  a. Inspection Scope
      The inspectors performed partial walkdowns of the following systems:
        RCIC during HPCI booster pump planned maintenance on May 2, 2014
        D emergency diesel generator (EDG) area ventilation system tornado dampers
          during A EDG planned maintenance the week of May 6, 2014
        A, B, and D SSW pumps during C SSW pump planned maintenance on June 2,
          2014
      The inspectors selected these systems based on their risk-significance relative to the
      reactor safety cornerstones at the time they were inspected. The inspectors reviewed
      applicable operating procedures, system diagrams, the UFSAR, technical specifications,
      work orders, condition reports, and the impact of ongoing work activities on redundant
      trains of equipment in order to identify conditions that could have impacted system
      performance of their intended safety functions. The inspectors also performed field
      walkdowns of accessible portions of the systems to verify system components and
      support equipment were aligned correctly and were operable. The inspectors examined
      the material condition of the components and observed operating parameters of
      equipment to verify that there were no deficiencies. The inspectors also reviewed
      whether PSEG staff had properly identified equipment issues and entered them into the
      corrective action program for resolution with the appropriate significance
      characterization.
                                                                                      Enclosure
                                                  9
  b. Findings
      No findings were identified.
1R05 Fire Protection
.1    Resident Inspector Quarterly Walkdowns (71111.05Q - 5 samples)
  a. Inspection Scope
      The inspectors conducted tours of the areas listed below to assess the material
      condition and operational status of fire protection features. The inspectors verified that
      PSEG controlled combustible materials and ignition sources in accordance with
      administrative procedures. The inspectors verified that fire protection and suppression
      equipment was available for use as specified in the area pre-fire plan, and passive fire
      barriers were maintained in good material condition. The inspectors also verified that
      station personnel implemented compensatory measures for out of service, degraded, or
      inoperable fire protection equipment, as applicable, in accordance with procedures.
          Review of compensatory measure fire watch for 10C467 fire protection panel power
          supply failure on April 17, 2014
          FRH-II-415, Revision 4, Hope Creek Pre-Fire Plan, drywell pad torus area on April
          21, 2014
          FRH-II-412, Revision 3, Hope Creek Pre-Fire Plan, RCIC pump and turbine room
          and electrical equipment room, on May 20, 2014
          FRH-II-532, Revision 6, Hope Creek Pre-Fire Plan, lower control equipment room, on
          May 23, 2014
          FRH-II-542, Revision 9, Hope Creek Pre-Fire Plan, control equipment mezzanine, on
          May 23, 2014
  b. Findings
      No findings were identified.
.2    Fire Protection - Drill Observation (71111.05A - 1 sample)
  a. Inspection Scope
      The inspectors observed an unannounced fire brigade drill scenario conducted on
      April 7, 2014, that involved a fire in the Hope Creek radwaste area, room 3351. The
      inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors
      verified that PSEG personnel identified deficiencies; openly discussed them in a self-
      critical manner at the post-drill debrief; and took appropriate corrective actions as
      required. The inspectors evaluated specific attributes as follows:
          Proper wearing of turnout gear and self-contained breathing apparatus
          Proper use and layout of fire hoses
          Employment of appropriate fire-fighting techniques
          Sufficient fire-fighting equipment brought to the scene
          Effectiveness of command and control
                                                                                        Enclosure
                                                10
        Search for victims and propagation of the fire into other plant areas
        Smoke removal operations
        Utilization of pre-planned strategies
        Adherence to the pre-planned drill scenario
        Drill objectives met
      The inspectors also evaluated the fire brigades actions to determine whether these
      actions were in accordance with PSEGs fire-fighting strategies.
  b. Findings
      No findings were identified.
1R06 Flood Protection Measures (71111.06 - 1 sample)
      Internal Flooding Review
  a. Inspection Scope
      The inspectors reviewed the UFSAR, the site flooding analysis, and plant procedures to
      assess susceptibilities involving internal flooding. The inspectors also reviewed the
      corrective action program to determine if PSEG identified and corrected flooding
      problems and whether operator actions for coping with flooding were adequate. The
      inspectors also focused on the A residual heat removal (RHR) pump room (4113), the
      B RHR pump room (4109), the C RHR pump room (4114), the HPCI pump and turbine
      room (4111), and the RCIC pump and turbine room (4110) to verify the adequacy of
      penetration seals located below the flood line, watertight door seals, common drain lines
      and sumps, and room level alarms.
  b. Findings
      Introduction. The inspectors identified a Green NCV of TS 6.8.1.a, Procedures
      because PSEG procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 could
      potentially complicate an internal flooding event and adversely affect assumptions in
      Hope Creeks flood design. Specifically, the procedures did not ensure operator
      response would not communicate the HPCI and RCIC watertight rooms and potentially
      render two safety-significant single train systems inoperable.
      Description. During a review of flood protection measures for the 54 foot elevation of the
      reactor building, inspectors questioned whether execution of flooding procedures could
      impact the assumption of the flood analysis, which assumes that the A, B, and C
      RHR pump rooms, the HPCI pump and turbine room, and the RCIC pump and turbine
      room are protected. Specifically, inspectors determined that in response to a room
      flooding alarm, the procedures directed operators to enter the rooms to investigate the
      flooding and assess the extent of flooding, an action which could allow communication
      between two watertight rooms.
      Hope Creeks UFSAR section 3.6, Protection Against Dynamic Effects Associated with
      the Postulated Rupture of Piping, states in part that, The postulated failure of a
                                                                                        Enclosure
                                          11
moderate energy line can at most affect only the operations of one train of a redundant
safety-related system due to the provisions for physical separation of redundant trains.
Inspectors reviewed procedural actions that would be taken in response to flood alarms
for the HPCI pump and turbine room (Room 4111) and the RCIC pump and turbine room
(Room 4110). The alarm response procedures for the HPCI and RCIC room flood
alarms direct operators to dispatch an equipment operator to the applicable room to
investigate and confirm the floor level alarm and enter HC.OP-EO.ZZ-0103/4, Reactor
Building and Radioactive Release Control. HC.OP-EO.ZZ-0103/4 provides an entry
condition of any reactor building room floor level above 1 inch, which is also the setpoint
of the level alarm. The procedure directs operators to use all available sump pumps and
isolate all systems discharging into the room.
Since the procedures direct operators to investigate and confirm flooding, the inspectors
assessed the ability of operators to enter the room without affecting equipment in an
adjacent room. Each of the ECCS/RCIC rooms are separated by large watertight doors
with no window or portal to monitor conditions on the other side of the door without
opening the door. The inspectors noted that the alarm response procedures for a high
level alarm in the A and B RHR pump rooms direct control room operators to dispatch
an equipment operator to enter the RHR pump rooms at their upper levels (77 foot
elevation) to determine the cause of the alarm. This procedural direction would prevent
flood propagation to the adjacent HPCI and RCIC electrical rooms.
The HPCI and RCIC rooms are located next to one another and are connected by a
watertight door. For a flood in the HPCI room, since both doors to the room open into
the adjacent rooms (i.e., water pressure would aid in opening the door), once the door
was unlatched, the water would force the door open and flood the adjacent room. The
inspectors noted that the alarm response procedures for potential flooding in the HPCI
and RCIC rooms do not provide direction on where to access the HPCI and RCIC rooms
when investigating for a potential flood condition. Therefore, when executing the
procedure to respond to flooding in the HPCI room, operators could propagate an
internal flood to two watertight rooms if they were to access the HPCI room through the
door connecting HPCI and RCIC.
The inspectors interviewed the Hope Creek emergency operating procedure (EOP)
coordinator regarding operator actions in response to indications of a flood in the HPCI
and RCIC rooms and the HC.OP-EO.ZZ-0103/4 procedure. Interviews with the EOP
coordinator indicated that operator knowledge would ensure proper access to the HPCI
and RCIC rooms when investigating a potential flood. However, no operator training
could be found that specified that operators should not access the HPCI and RCIC
rooms using the connecting watertight door when responding to a potential flood
condition.
The inspectors interviewed a senior reactor operator and two equipment operators about
their response to alarms for a potential flood in the HPCI room. The senior reactor
operator did not indicate that he would direct which door to access the HPCI room. The
equipment operators indicated that they would access the HPCI room from the door to
the RCIC room because the floor drains in the RCIC room would better drain any flood
water.
In the absence of further engineering evaluation, there was reasonable doubt of the
operability of the HPCI and RCIC systems. Specifically, internal flood propagation from
                                                                                  Enclosure
                                          12
the design internal flood in the HPCI room could result in a water level that calls the
operability of RCIC into question. PSEG plans to perform a detailed technical evaluation
to evaluate the impact of internal flood propagation in the HPCI and RCIC rooms in
response to the inspectors questions (Order 70167153). PSEG entered the issue into
the CAP as NOTFs 20646334, 20646335, and 20653586. PSEGs corrective actions
include a planned revision of the annunciator response procedures and issuance of a
standing order to the Operations department staff.
Analysis. The inspectors determined that PSEGs failure to provide adequate procedural
guidance to respond to a HPCI/RCIC room flood alarm was a performance deficiency
that was within PSEGs ability to foresee and correct, and should have been prevented.
The performance deficiency is more than minor because it was associated with the
procedure quality attribute of the Mitigating Systems cornerstone, and adversely affected
the cornerstone objective to ensure the availability, reliability, and capability of systems
that respond to initiating events to prevent undesirable consequences (i.e., core
damage). Specifically, PSEG procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022
could potentially complicate an internal flooding event and adversely affect assumptions
in Hope Creeks flood design, since the procedures did not ensure operator response
would not communicate the HPCI and RCIC watertight rooms and potentially render
multiple trains of safety-related SSCs inoperable. This performance deficiency was also
similar to examples 3.j and 3.k of NRC IMC 0612, Appendix E, in that communicating the
two watertight rooms created a reasonable doubt of operability of the RCIC system.
PSEG plans to perform a detailed technical evaluation to evaluate the impact of internal
flood propagation in the HPCI and RCIC rooms. The finding was evaluated in
accordance with Exhibits 2 and 4 of NRC IMC 0609, Appendix A, The SDP for Findings
At-Power, dated June 19, 2012. Since opening the watertight door during an internal
flooding event could bypass the flood protection feature and potentially degrade two or
more trains of a multi-train system or function, a detailed risk assessment was
performed.
The condition was modeled using the Hope Creek SPAR model version 8.18 along with
SAPHIRE version 8.09. As a bounding analysis, the condition was assumed to exist for
greater than one year and the flooding was assumed to require a reactor shutdown,
which results in a plant transient with failure of HPCI and RCIC due to flood impacts.
The flooding initiating event frequency was derived from the Hope Creek Internal Flood
Report, HC-PRA-012, Revision 2. The resulting change in core damage frequency was
substantially less than 1E-7. The dominant sequences included a transient with a failure
to depressurize along with RCIC and HPCI failures. Since the change in core damage
frequency was sufficiently low, no further evaluation for large early release was required.
The inspectors determined that the finding had a cross-cutting aspect in the Human
Performance area associated with Training, in that PSEG did not provide adequate
training and ensure knowledge transfer to maintain a knowledgeable, technically
competent workforce and instill nuclear safety values. Specifically, operator training did
not ensure operator response to internal flooding would not communicate the HPCI and
RCIC watertight rooms and potentially render multiple trains of safety-related SSCs
inoperable. [H.9].
Enforcement. TS 6.8.1.a, Procedures and Programs, requires in part, that written
procedures recommended in Appendix A of Regulatory Guide (RG) 1.33, Revision 2,
shall be established, implemented, and maintained. RG 1.33, Revision 2, Appendix A,
                                                                                    Enclosure
                                                  13
      Section 5, requires that each safety-related annunciator should have its own written
      procedure, which should normally contain the immediate operation action. PSEG
      procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 provide direction for operator
      response to indications of high level in the HPCI and RCIC rooms. Contrary to the
      above, until implementation of Operations Department Standing Order 2014-26 on
      May 24, 2014, PSEG procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 were
      inadequate in that actions directed in the procedures could complicate an internal
      flooding event and potentially adversely affect assumptions in Hope Creeks flood
      design. In addition to entering the issue into the CAP as NOTFs 20646334, 20646335,
      and 20653586, PSEGs corrective actions include a planned revision of the annunciator
      response procedures and issuance of a standing order to the Operations department
      staff. Because this violation was of very low safety significance (Green), and PSEG
      entered this issue into their CAP, this violation is being treated as an NCV, consistent
      with Section 2.3.2 of the Enforcement Policy. (NCV 05000354/2014003-01, Inadequate
      Procedural Guidance for Responding to an Internal Flooding Event in the HPCI
      and RCIC Rooms)
1R11 Licensed Operator Requalification Program (71111.11Q - 2 samples)
.1    Quarterly Review of Licensed Operator Requalification Testing and Training
  a. Inspection Scope
      The inspectors observed licensed operator simulator training on April 28, 2014, that
      included an A RRP trip, reactor water cleanup (RWCU) system leak, loss of main
      condenser vacuum, and an anticipated transient without scram. The inspectors
      evaluated operator performance during the simulated event and verified completion
      of critical tasks, risk significant operator actions, including the use of abnormal and
      emergency operating procedures. The inspectors assessed the clarity and effectiveness
      of communications, implementation of actions in response to alarms and degrading plant
      conditions, and the oversight and direction provided by the control room supervisor. The
      inspectors verified the accuracy and timeliness of the emergency classification made by
      the shift manager. Additionally, the inspectors assessed the ability of the training staff to
      identify and document crew performance problems.
  b. Findings
      No findings were identified
.2    Quarterly Review of Licensed Operator Performance in the Main Control Room
  a. Inspection Scope
      The inspectors observed a planned down power to support PST to locate a potential fuel
      defect and the conduct main turbine valve testing on April 1, 2014. The inspectors
      observed reactivity manipulations to verify that procedure use and crew communications
      met established expectations and standards. The inspectors observed pre-job briefings
      to verify that the briefings met the criteria specified in OP-AA-101-111-1004 Operations
      Standards, Revision 4, and HU-AA-1211, Pre-Job Briefings, Revision 11. Additionally,
      the inspectors observed the performance of turbine valve testing surveillance test,
      HC.OP-ST.AC-0002, on April 1, 2014, to verify that procedure use, crew
                                                                                          Enclosure
                                                14
      communications, and coordination of activities between work groups similarly met
      established expectations and standards.
  b. Findings
      No findings were identified
1R12 Maintenance Effectiveness (71111.12Q - 3 samples)
  a. Inspection Scope
      The inspectors reviewed the samples listed below to assess the effectiveness of
      maintenance activities on structure, system, or component (SSC) performance and
      reliability. The inspectors reviewed corrective action program documents (notifications),
      maintenance work orders (orders), and maintenance rule basis documents to ensure
      that PSEG was identifying and properly evaluating performance problems within the
      scope of the maintenance rule. As applicable, the inspectors verified that the SSC was
      properly scoped into the maintenance rule in accordance with 10 CFR 50.65 and verified
      that the (a)(2) performance criteria established by PSEG staff was reasonable; for SSCs
      classified as (a)(1), the inspectors assessed the adequacy of goals and corrective
      actions to return these SSCs to (a)(2); and, the inspectors independently verified that
      appropriate work practices were followed for the SSCs reviewed. Additionally, the
      inspectors ensured that PSEG staff was identifying and addressing common cause
      failures that occurred within and across maintenance rule system boundaries.
          A MS drain and dump valve functional failure determinations for December 1 and 5,
          2013, scrams (Order 70161698)
          Salem Unit 3 (gas turbine generator) scoping in Hope Creek maintenance rule
          program (NOTF 20502118)
          RCIC nuclear management and control leak detection system card failure and
          replacement on May 23, 2014 (Order 60113250)
  b. Findings
      Introduction. A self-revealing finding of very low safety significance (Green) was
      identified for PSEGs failure to evaluate an identified deficiency in accordance with
      PSEG procedure LS-AA-125, Corrective Action Program. Specifically, PSEG failed to
      take self-recommended actions in NOTF 20447050 to evaluate the B MS dump valve
      performance after failing to operate as designed during B MS drain valve trouble-
      shooting on January 11, 2010. As a result, PSEG did not identify and correct a potential
      design flaw associated with thermal binding of the MS dump valves, which was
      determined to be the cause of the A MS dump valve failing to stroke open on
      December 1, 2013, causing a reactor scram from 100 percent power.
      Description. Hope Creek utilizes two horizontal non-reheat MS vessels that remove
      moisture in the steam from the high pressure turbine exhaust before it enters the low
      pressure turbine which prevents damage to the low pressure turbines. The condensate
      that is collected in the MS is drained to the 5A, 5B, and 5C feed water heaters where it
      eventually drains to the condenser. If the water level in the MS becomes too high and
      the normal MS level control drain valves are not able to drain it, then the dump valve
      opens draining the water in the MS directly to the condenser.
                                                                                      Enclosure
                                          15
At 6:07 am on December 1, 2013, while operating at 100 percent power, the A MS
normal drain level reached a maximum allowed value of 70 percent allowing the MS
dump valve to cycle to control level. After six minutes (~15 cycles of the A dump valve
going open and shut) of successfully controlling MS level in the dump valve range, the
A MS dump closed and failed to re-open causing high level in the A MS, a turbine trip
and a reactor scram.
On December 5, 2013, a second reactor scram occurred at 75 percent power during A
MS dump valve tuning with the normal A MS drain valves failed closed to support
emergency level controller tuning. The A MS dump valve again failed to stroke open
when expected causing high MS level.
PSEG conducted a root cause evaluation (Order 70161698) to determine the cause of
the A MS drain and dump valve issues leading to the December 1 and December 5,
2013, scrams. PSEG determined that the A MS dump valve experienced thermal
binding because both PSEG and the valve manufacturer did not recognize the potential
for these valves to experience thermal binding. The results from PSEGs evaluation
concluded that the A MS dump valve design is susceptible to internal binding due to
differential expansion, resulting in the valve plug sticking in the valve cage.
During the timeline review for the A MS root cause evaluation, PSEG discovered that
the B MS dump valve did not open as expected on January 11, 2010, when trouble-
shooting B MS drain valve control issues. The dump valve had cycled multiple times
prior to PSEG removing air to reopen the B MS dump valve when MS level was rising
during drain valve control troubleshooting and the dump valve did not open for 12
minutes. The condition of the B MS dump valve not operating as expected was
documented under NOTF 20447050. The NOTF documented that the B MS dump
valve had cycled several times prior to the failure to open and recommended that the
B MS dump valve performance be evaluated and implement corrective actions as
necessary. This NOTF was not properly allocated to the equipment apparent cause
evaluation (EQACE) that was created (Order 70105948) to evaluate the B MS drain
valve control troubleshooting and therefore was never evaluated. PSEG created NOTF
20640526 to document the missed opportunity to troubleshoot B MS dump valve
performance and identify the thermal binding issue when the valve is cycled at normal
reactor power and pressure.
LS-AA-125, Corrective Action Program, Revision 12, Section 3.5.6 (effective on
January 11, 2010) states to ensure that the corrective action identified have been
agreed upon by the assignees and that the corrective actions are appropriately entered
into the CR database. Based on this information, the inspectors concluded that PSEG
failed to ensure that EQACE 70105948 addressed the identified issue in NOTF
20447050 recommending that the B MS dump valve performance on January 11, 2010,
be evaluated and corrected. PSEG has entered the above concerns into the CAP as
20640526. PSEGs corrective actions include a design change to the MS emergency
level control system that eliminates dump valve cycling on high MS level.
Analysis. PSEGs failure to ensure evaluations addressed identified issues in
accordance with PSEG procedure LS-AA-125, Corrective Action Program, was a
performance deficiency which was reasonably within PSEGs ability to foresee and
correct and should have been prevented. The performance deficiency was determined
                                                                                Enclosure
                                                16
      to be 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. The inspectors
      determined that this finding was of very low safety significance using Exhibit 1 of NRC
      IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-
      Power, dated June 19, 2012, because the finding did not cause both a reactor trip and
      the loss of mitigation equipment relied upon to transition the plant from the onset of the
      trip to a stable shutdown condition (e.g. loss of condenser, loss of feed water). The
      inspectors determined that there was no cross-cutting aspect associated with this finding
      because the cause of the performance deficiency occurred more than three years ago,
      and was not representative of present plant performance.
      Enforcement. This finding does not involve enforcement action because no violation of a
      regulatory requirement was identified. Since this finding does not involve a violation and
      is of very low safety significance (Green), it is identified as a FIN. (FIN
      05000354/2014003-02, Failure to Evaluate an Identified Issue with the Moisture
      Separator Dump Valve Performance)
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13 - 5 samples)
  a. Inspection Scope
      The inspectors reviewed station evaluation and management of plant risk for the
      maintenance and emergent work activities listed below to verify that PSEG performed
      the appropriate risk assessments prior to removing equipment for work. The inspectors
      selected these activities based on potential risk significance relative to the reactor safety
      cornerstones. As applicable for each activity, the inspectors verified that PSEG
      personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the
      assessments were accurate and complete. When PSEG performed emergent work, the
      inspectors verified that operations personnel promptly assessed and managed plant risk.
      The inspectors reviewed the scope of maintenance work and discussed the results of
      the assessment with the stations probabilistic risk analyst to verify plant conditions were
      consistent with the risk assessment. The inspectors also reviewed the technical
      specification requirements and inspected portions of redundant safety systems, when
      applicable, to verify risk analysis assumptions were valid and applicable requirements
      were met.
          Unplanned de-energization and loss of the D vital bus on December 19, 2013
          Planned high risk activity to perform main turbine combined intermediate valve
          testing on April 2, 2014
      Planned high risk activity to perform power suppression testing to locate a fuel defect
          on April 2, 2014
      B RRP isolator replacement due to un-demanded speed changes on May 22, 2014
      B RHR system and F filtration, recirculation, and ventilation system recirculation
          fan planned maintenance on June 11, 2014
  b. Findings
      Introduction. A Green self-revealing NCV of TS 6.8.1.a, Procedures and Programs,
      was identified for PSEGs failure to follow procedure MA-AA-1000, Maintenance
                                                                                          Enclosure
                                          17
Standards and Practices, during the replacement of Bailey logic modules associated
with the D vital bus (10A404). Specifically, during the spring 2009 refueling outage
(1R15), PSEG failed to follow a WO requiring the replacement of all Bailey logic modules
listed in WO 60061175 with new logic modules. As a result, a logic module (H1PB-
1PBXIS-DC652010302) for the 10A404 vital bus was not replaced during 1R15, and
failed due to age on December 19, 2013, causing a loss of the 10A404 bus and an entry
into the associated 8 hour TSAS 3.8.3.1 for Onsite Power Distribution Systems.
Description. The PSEG Class 1E AC power distribution system provides a reliable
source of power for all Class 1E loads and distributes power at 4.16 kilovolt (kV), 480
volt (V), and 208/120 V. The system is divided into four independent channels and each
channel supplies power to loads in its own load group. Each of the four vital buses is
provided with connections to the two offsite power sources through two in-feed breakers
(40401 and 40408). One of these breakers is designated as the normal source and the
other as the alternate source for the bus. In addition to these two connections to offsite
power, each of the vital buses is connected to its dedicated EDG. These EDGs serve as
the standby electric power source for their respective channels in case both the normal
and alternate power supplies to a bus are lost.
At 3:11 pm on December 19, 2013, PSEG was performing a normally planned swap of
the 10A404 in-feed breakers from 40408 to 40401, when both in-feed breakers tripped
open and de-energized the 10A404 bus. PSEG stabilized the plant, entered the
associated 8 hour TSAS 3.8.3.1, conducted troubleshooting, performed component
replacements, and returned the 10A404 vital bus to service at 5:01 pm on December 19,
2013.
Following the restoration of the 10A404 vital bus on December 19, 2013, PSEG
conducted an EQACE documented under order 70162013. This EQACE determined
that the apparent cause of the 10A404 vital bus loss was an age-related failure of a logic
module (H1PB-1PBXIS-DC652010302) that was not replaced, but mistakenly
documented as being replaced in 2009 per WO 60061175. PSEG determined that the
independent peer check verification performed for both the LM removal and LM
installation failed to ensure that the serial number for the removed LM (H1PB-1PBXIS-
DC652010302) was not reinstalled into the system. Because this logic module was not
replaced in 2009, and remained in the system for 4 years past its vendor recommended
lifetime of 20 years, PSEG determined that it failed due to age and could not provide an
output to allow the 10A404 bus 40408 in-feed breaker to trip normally during the planned
in-feed breaker swap on December 19, 2013.
The inspectors reviewed PSEGs procedures for conducting the 10A404 in-feed breaker
swaps, operations narrative logs, and the completed EQACE 70162013 for the
December 19, 2013, event. PSEG procedure MA-AA-1000, Section 3.0, Maintenance
Standards and Practices, states in part, that all work on plant SSCs will be performed
using appropriate documentation such as work orders, notifications, or applicable
troubleshooting process control forms. Both the current revision of this procedure
(Revision 14) and the revision in use during 1R15 (Revision 7) have this language
requiring all work be performed in accordance with the appropriate documentation.
The inspectors determined that PSEG failed to follow this procedure by not complying
with WO 60061175 for the replacement of Bailey cards for the 10A404 in-feed breakers
during 1R15. This WO stated, in part, to Replace all Logic Modules listed with new
modules, and the list contained included the 10A404 in-feed breaker logic module
                                                                                  Enclosure
                                          18
(H1PB-1PBXIS-DC652010302 LM 4.16 KV MAIN BKR 52-40401). Contrary to this,
PSEGs review of the serial number on the failed logic module and WO 60061175
showed that the original logic module was re-installed following its removal during the
conduct of maintenance. As part of the extent of condition for PSEGs EQACE, a review
of all other similar logic modules found them replaced as documented.
PSEG initiated NOTF 20639519 and EQACE 70162013 in the CAP to replace the failed
logic module, identify other similar logic modules and relays that may not have been
replaced or may not have an associated maintenance plan, and reinforce proper
maintenance practices to the individuals involved in the completion of WO 60061175.
Analysis. PSEGs failure to follow procedure MA-AA-1000 for Maintenance Standards
and Practices during the replacement of a Bailey logic module associated with the
10A404 vital bus represented a performance deficiency that was reasonably within
PSEGs ability to foresee and correct and should have been prevented. The
performance deficiency was determined to be more than minor because it was
associated with the human 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, not following the work order instructions resulted in an
extended service duration and failure of a component that resulted in a loss of power to
the D vital bus on December 19, 2013. Similarly, this performance deficiency was also
similar to examples 2.g and 4.b of NRC IMC 0612 Appendix E, in that PSEG is required
to follow its procedures per TS 6.8.1, and ultimately led to a safety impact given the
failure of the logic module causing a loss of power to the 10A404 vital bus. The
inspectors determined the finding to be of very low safety significance (Green) in
accordance with Exhibit 1 of NRC IMC 0609, Appendix A, The Significance
Determination Process for Findings At-Power, dated June 19, 2012, because the finding
involved the loss of a support system that contributes to the likelihood of an initiating
event (Loss of an AC Bus), but did not affect mitigation equipment.
The inspectors determined that there was no cross-cutting aspect associated with this
finding because the cause of the performance deficiency occurred more than three years
ago, and was not representative of current plant performance.
Enforcement. TS 6.8.1.a, Procedures and Programs, requires in part, that written
procedures recommended in Appendix A of RG 1.33, Revision 2, shall be established,
implemented, and maintained. Section 9.a of RG 1.33, Revision 2, Appendix A, requires
that maintenance that can affect the performance of safety-related equipment should be
properly preplanned and performed in accordance with written procedures, documented
instructions, or drawings appropriate to the circumstances. Section 3.0 of PSEG
procedure MA-AA-1000, Maintenance Standards and Practices, states in part, that all
work on plant SSCs will be performed using appropriate documentation such as work
orders, notifications, or applicable troubleshooting process control forms.
Contrary to the above, on April 16, 2009, PSEG failed to follow this procedure during the
replacement of a Bailey logic module associated with the 10A404 vital bus. Specifically,
PSEG failed to follow WO 60061175 which required the replacement of all Bailey logic
modules listed in the WO with new logic modules. As a result, a logic module for the
10A404 vital bus was not replaced in 2009, and failed due to age on December 19,
2013, causing a loss of the 10A404 bus and an entry into the associated 8 hour TSAS
                                                                                  Enclosure
                                              19
      3.8.3.1 for Onsite Power Distribution Systems. PSEGs corrective actions included
      replacement of the failed logic module, performance of an extent of condition inspection
      to ensure other similar logic modules and relays were replaced, and reinforcement of
      proper maintenance practices with the individuals involved in the completion of WO
      60061175. Because this violation was of very low safety significance (Green) and was
      entered into PSEGs CAP as NOTF 20639519 and EQACE 70162013, the violation is
      being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.
      (NCV 05000354/2014003-03, Failure to Follow Procedure Resulting in the Loss of a
      Vital 4kV Bus)
1R15 Operability Determinations and Functionality Assessments (71111.15 - 5 samples)
  a. Inspection Scope
      The inspectors reviewed operability determinations for the following degraded or non-
      conforming conditions:
        Minimum Allowable Wall Thickness Evaluation of 4 D RHR Piping (Order
          80108395)
        C EDG operability with lost parts potentially in the main lube oil sump on April 7,
          2014 (NOTF 20645519)
        Standby liquid control event report #49909 retraction on April 15, 2014 (NOTFs
          20647199 and 20643229)
        B RRP undemanded speed changes on May 14, 2014 (NOTF 20651102)
        Revision 3 of Masterpact Breaker failure analysis operability evaluation on May 28,
          2014 (NOTF 20652187 and Order 70163760)
      The inspectors selected these issues based on the risk significance of the associated
      components and systems. The inspectors evaluated the technical adequacy of the
      operability determinations to assess whether technical specification operability was
      properly justified and the subject component or system remained available such that no
      unrecognized increase in risk occurred. The inspectors compared the operability and
      design criteria in the appropriate sections of the technical specifications and UFSAR to
      PSEGs evaluations to determine whether the components or systems were operable.
      Where compensatory measures were required to maintain operability, the inspectors
      determined whether the measures in place would function as intended and were
      properly controlled by PSEG. The inspectors determined, where appropriate,
      compliance with assumptions in the evaluations.
  b. Findings
      No findings were identified.
                                                                                        Enclosure
                                                20
1R18 Plant Modifications (71111.18 - 2 samples)
.1    Temporary Modifications
  a. Inspection Scope
      The inspectors reviewed the temporary modification listed below to determine whether
      the modification affected the safety functions of systems that are important to safety.
      The inspectors reviewed 10 CFR 50.59 documentation to verify that the temporary
      modification did not degrade the design bases, licensing bases, and performance
      capability of the affected systems.
        Temporary Configuration Change Package (TCCP) 4HT-14-005 - Temporary
          Repairs to the Condensate Storage Tank Dike Drain Line
  b. Findings
      No findings were identified.
.2    Permanent Modifications
  a. Inspection Scope
      The inspectors evaluated a modification to the RWCU system implemented by DCP
      80111754, Masterpact Breaker Add Aux Contact with Close Coil. This DCP wires an
      existing breaker auxiliary contact in series with the internal close coil to allow the close
      coil to be de-energized after the breaker has closed rather than be continuously
      energized. The existing configuration with the breaker close coil continuously energized
      is allowing an intermittent failure of these breakers where they lock up and fail to re-
      close when required per design. The inspectors verified that the design bases, licensing
      bases, and performance capability of the affected systems were not degraded by the
      modification. In addition, the inspectors reviewed modification documents associated
      with the upgrade and design change, including the breaker operation. The inspectors
      also reviewed revisions to the control room alarm response procedure and interviewed
      engineering and operations personnel to ensure the procedure could be reasonably
      performed.
  b. Findings
      No findings were identified.
1R19 Post-Maintenance Testing (71111.19 - 7 samples)
  a. Inspection Scope
      The inspectors reviewed the post-maintenance tests for the maintenance activities listed
      below to verify that procedures and test activities ensured system operability and
      functional capability. The inspectors reviewed the test procedure to verify that the
      procedure adequately tested the safety functions that may have been affected by the
      maintenance activity, that the acceptance criteria in the procedure was consistent with
      the information in the applicable licensing basis and/or design basis documents, and that
      the procedure had been properly reviewed and approved. The inspectors also
                                                                                          Enclosure
                                              21
      witnessed the test or reviewed test data to verify that the test results adequately
      demonstrated restoration of the affected safety functions.
        HPCI oil supply pressure gauge replacement on October 10, 2013 (Order 60113238)
        B control room chilled water pressure control valve positioner and diaphragm
          replacement on April 23, 2014 (Order 60116090)
        10C467 fire protection panel power supply replacement on May 9, 2014 (Order
          30269527)
        B RRP pump speed controller card replacements on May 22, 2014 (Order
          60117312)
        RCIC nuclear management and control leak detection system card replacement on
          May 23, 2014 (Order 60113250)
        Service air compressor oil leak repair on June 5, 2014 (Order 60117447)
        B RHR system relay replacements on June 11, 2014 (Orders 30098613 and
          30098617)
  b. Findings
      No findings were identified.
1R22 Surveillance Testing (71111.22 - 9 samples)
  a. Inspection Scope
      The inspectors observed performance of surveillance tests and/or reviewed test data
      of selected risk-significant SSCs to assess whether test results satisfied technical
      specifications, the UFSAR, and PSEG procedure requirements. The inspectors verified
      that test acceptance criteria were clear, tests demonstrated operational readiness and
      were consistent with design documentation, test instrumentation had current calibrations
      and the range and accuracy for the application, tests were performed as written, and
      applicable test prerequisites were satisfied. Upon test completion, the inspectors
      considered whether the test results supported that equipment was capable of performing
      the required safety functions. The inspectors reviewed the following surveillance tests:
        HC.OP-ST.AC-0002, Turbine Valve Testing quarterly surveillance on April 1, 2014
        HC.OP-ST.KJ-0003, Emergency Diesel Generator 1CG400 Operability Test on
          April 7, 2014
        HC.OP-IS.BJ-0001, HPCI Main and Booster Pump Set - 0P204 and 0P217 -
          In-service Test on April 9, 2014 (in-service test)
        HC.MD-ST.PB-0003, Class 1E 4.16 kV Feeder Degraded Voltage Monthly
          Instrumentation Channel Functional Testing of the B vital bus on April 15, 2014
        HC.OP-IS.BC-0004, DP202, D Residual Heat Removal Pump In-Service Test on
          April 22, 2014 (in-service test)
        HC.OP-DL.ZZ-0026, Drywell floor drain leakage monitoring on May 1, 2014 (RCS
          leakage)
        HC.FP-ST.KC-0009, Diesel Driven Fire Pump Operability Test on May 6, 2014
        HC.OP-IS.BC-0002, CP202, C Residual Heat Removal Pump In-Service Test on
          June 25, 2014 (in-service test)
        HC.OP-ST.KJ-0001, Emergency Diesel Generator 1AG400 Operability Test on
          June 30, 2014
                                                                                        Enclosure
                                                22
  b. Findings
      No findings were identified.
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation (71114.06 - 1 sample)
      Emergency Preparedness Drill Observation
  a. Inspection Scope
      The inspectors evaluated the conduct of a routine PSEG emergency drill on June 24,
      2014 to identify any weaknesses and deficiencies in the classification, notification, and
      protective action recommendation development activities. The inspectors observed
      emergency response operations in the technical support center to determine whether the
      event classification, notifications, and protective action recommendations were
      performed in accordance with procedures. The inspectors also attended the drill critique
      to compare inspector observations with those identified by PSEG staff in order to
      evaluate PSEGs critique and to verify whether the PSEG staff was properly identifying
      weaknesses and entering them into the corrective action program.
  b. Findings
      No findings were identified.
4.    OTHER ACTIVITIES
4OA1 Performance Indicator (PI) Verification (71151)
      Reactor Coolant System (RCS) Specific Activity and RCS Leak Rate (2 samples)
  a. Inspection Scope
      The inspectors reviewed PSEGs submittal for the RCS specific activity and RCS leak
      rate performance indicators for the period of April 1, 2013, through March 31, 2014. To
      determine the accuracy of the performance indicator data reported during those periods,
      the inspectors used definitions and guidance contained in NEI Document 99-02,
      Regulatory Assessment Performance Indicator Guideline, Revision 7. The inspectors
      also reviewed RCS sample analysis and control room logs of daily measurements of
      RCS leakage, and compared that information to the data reported by the performance
      indicator. Additionally, the inspectors observed chemistry personnel taking and
      analyzing an RCS sample.
  b. Inspection Findings
      No findings were identified.
                                                                                        Enclosure
                                                23
4OA2 Problem Identification and Resolution (71152 - 1 sample)
.1    Routine Review of Problem Identification and Resolution Activities
  a. Inspection Scope
      As required by Inspection Procedure 71152, Problem Identification and Resolution, the
      inspectors routinely reviewed issues during baseline inspection activities and plant
      status reviews to verify that PSEG entered issues into the corrective action program at
      an appropriate threshold, gave adequate attention to timely corrective actions, and
      identified and addressed adverse trends. In order to assist with the identification of
      repetitive equipment failures and specific human performance issues for follow-up, the
      inspectors performed a daily screening of items entered into the corrective action
      program and periodically attended condition report screening meetings.
  b. Findings
      No findings were identified.
.2    Semi-Annual Trend Review
  a. Inspection Scope
      The inspectors performed a semi-annual review of site issues, as required by Inspection
      Procedure 71152, Problem Identification and Resolution, to identify trends that might
      indicate the existence of more significant safety issues. In this review, the inspectors
      included repetitive or closely-related issues that may have been documented by PSEG
      outside of the corrective action program, such as trend reports, performance indicators,
      major equipment problem lists, system health reports, maintenance rule assessments,
      and maintenance or corrective action program backlogs. The inspection also reviewed
      PSEGs corrective action program database for the period of January 2014 to May 2014
      to assess the notifications written as well as individual issues identified during the NRCs
      daily condition report review (Section 4OA2.1). The inspectors reviewed the Hope
      Creek station performance improvement integrated matrix (PIIM), conducted under
      procedure LS-AA-125-1006, Performance Improvement Integrated Matrix, to verify that
      PSEG personnel were appropriately evaluating and trending adverse conditions in
      accordance with applicable procedures.
  b. Findings and Observations
      No findings were identified during this trend review.
      The inspectors noted that PSEG personnel identified the following trends and entered
      them into the corrective action program: an adverse trend in Appendix J leakage
      (NOTFs 20632747, 20632748, 20632749); an adverse trend in design change package
      quality (NOTFs 20642767 and 20644539); and an adverse trend in critical component
      failures (NOTF 20638889). The inspectors also reviewed the 2013 third cycle Hope
      Creek PIIM and the performance improvement action plan developed to improve station
      performance in the areas of equipment reliability, decision making, and risk
      management.
                                                                                          Enclosure
                                                24
      The inspectors noted a trend in the stations failure to perform cross-system
      maintenance rule screenings:
              When the feedwater crosstie valve (AE-HV-4144) failed, it was screened as not
              a functional failure against the feedwater system. The condition was not
              screened against the feedwater sealing functions of HPCI and RCIC.
              The DD-411 battery room temperature was found above acceptance criteria. A
              maintenance rule functional failure screening was performed for the functions of
              the 1E 125 volt direct current (DC) system, but not for the auxiliary building
              diesel area ventilation system.
              As found setpoint failures of safety relief valves were screened against the
              automatic depressurization system functions, but not against any of the main
              steam system functions.
      The inspectors determined this observation was not more than minor in accordance with
      IMC 0612, because the observations did not result in any of the systems requiring
      additional monitoring per 10 CFR 50.65(a)(1).
      Based on the review of PSEGs trending, the inspectors concluded that PSEG was
      appropriately identifying and entering issues into the corrective action program,
      adequately evaluating the identified issues, and appropriately identifying adverse trends
      before they become more safety significant problems.
4OA3 Follow-Up of Events and Notices of Enforcement Discretion (71153 - 6 samples)
.1    Plant Events
  a. Inspection Scope
      For the plant event listed below, the inspectors reviewed plant parameters, reviewed
      personnel performance, and evaluated performance of mitigating systems. The
      inspectors communicated the plant events to appropriate regional personnel, and
      compared the event details with criteria contained in IMC 0309, Reactive Inspection
      Decision Basis for Reactors, for consideration of potential reactive inspection activities.
      As applicable, the inspectors verified that PSEG made appropriate emergency
      classification assessments and properly reported the event in accordance with 10 CFR
      Parts 50.72 and 50.73. The inspectors reviewed PSEGs follow-up actions related to the
      events to assure that PSEG implemented appropriate corrective actions commensurate
      with their safety significance.
        B RRP un-demanded speed change due to a failure in the speed controller, causing
          a momentary increase in reactor power above the thermal power limit on May 15,
          2014 (NOTF 20651102)
  b. Findings
      No findings were identified.
.2    Event Notification (EN) 49909 Retraction, Standby Liquid Control System (SLC) Sample
      Concentration Outside Technical Specification Limits
                                                                                        Enclosure
                                            25
  At 10:27 pm on March 12, 2014, PSEG was in the process of returning the SLC system
  to service following planned maintenance on the B SLC pump when the MCR received
  a SLC tank high level alarm (>4880 gallons). The MCR informed the equipment
  operator conducting the SLC system restoration of the unexpected SLC tank high level
  alarm and the operator closed a valve that had just been opened, which stopped the rise
  in SLC storage tank level at 4926 gallons. PSEGs sample analysis of the SLC system
  tank yielded a sodium pentaborate concentration outside the TS limits, rendering both
  subsystems inoperable. The concentration was found to be at 13.598% by weight,
  below the required concentration of 13.6% by weight. As part of the corrective actions,
  PSEG restored the concentration to within TS limits and conducted an apparent cause
  evaluation.
  This condition was reported under 10 CFR 50.72(b)(3)(v)(D) on March 13, 2014, as
  a condition that could have prevented the fulfillment of a safety function required to
  mitigate the consequences of an accident (EN 49909). On April 14, 2014, PSEG
  retracted EN 49909 stating that a subsequent review of the analytical data has
  determined that the SLC tank sample met the TS requirement for operability (13.6
  weight percent) and therefore, there was no reportable condition. The inspectors
  reviewed PSEGs EN and EN retraction, apparent cause evaluation report, supporting
  documentation including multiple NOTFs and technical evaluation (Order 70166989),
  station procedures, and interviewed several members of station staff and management
  regarding the event. No findings were identified during this review.
.3 (Closed) Licensee Event Report (LER) 05000354/2013-007-00, As-Found Values for
  Safety Relief Valve Lift Set Points Exceed Technical Specification Allowable Limit
  On November 22, 2013, PSEG received test results indicating that the as-found lift
  setpoints for 5 of 14 main steam safety relief valves (SRVs) failed to open within the
  required TS actuation pressure setpoint tolerance. TS 3.4.2.1 provides an allowable
  pressure band of +/- 3 percent for each SRV. All five of the SRVs opened above the
  required pressure band. PSEG determined that the apparent cause for the A, D, F,
  K, and L SRV setpoint failures was corrosion bonding/sticking between the mating
  surfaces of the pilot disc. These issues were placed into the CAP as NOTF 20631351.
  The pilot assembly for each of the 14 SRVs has been replaced with a fully tested spare
  assembly. Additionally, this LER stated PSEGs corrective actions include plans to
  replace the currently installed SRVs with a new design that eliminates setpoint drift
  events exceeding TS requirements and improves SRV reliability. Although this LER
  reports the inoperability of five SRVs, this event did not result in a loss of system safety
  function based on engineering analyses. These analyses showed that the SRVs would
  have functioned to prevent a reactor vessel over-pressurization and that postulated
  piping stresses would not exceed allowable limits. The enforcement aspects of this
  finding are discussed in Section 4OA7. This LER is closed.
.4 (Closed) LER 05000354/2013-008-00 and LER 05000354/2013-008-01, Automatic
  Actuation of the Reactor Protection System Due to a Main Turbine Trip
  On December 1, 2013, Hope Creek Unit 1 automatically scrammed from 100 percent
  rated thermal power due to a main turbine trip. The main turbine trip was due to high
  level in the A MS. As a result of the scram, both RRPs tripped and three SRVs opened.
  The plant was stabilized in hot shutdown, Operational Condition 3.
                                                                                      Enclosure
                                                  26
      This condition is reportable under 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted
      in an automatic actuation of the reactor protection system. The inspectors reviewed
      PSEGs LER and LER revision, root cause evaluation report (Order 70161698),
      supporting documentation, station procedures, and interviewed several members of
      station staff and management regarding the event. One finding was identified and is
      discussed in Section 1R12 of this report. These LERs are closed.
.5    (Closed) LER 05000354/2013-009-00 and LER 05000354/2013-009-01, Automatic
      Actuation of the Reactor Protection System Due to a Main Turbine Trip
  a. Inspection Scope
      On December 5, 2013, during tuning of the A MS emergency level controller, the
      reactor automatically scrammed from 75 percent power due to a main turbine trip.
      During the tuning activities, the A MS dump valve cycled repeatedly and subsequently
      failed closed, resulting in high level in the A MS and subsequent turbine trip. The
      automatic reactor scram resulted in a trip of both RRPs, as designed. During the
      recovery of the RRPs, the digital electro-hydraulic control system was mis-operated
      which caused the turbine bypass valves to cycle. This caused reactor level to swell
      above Level 8 then shrink below Level 3, resulting in a second actuation of the reactor
      protection system.
      This condition is reportable under 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in
      an automatic actuation of the reactor protection system. The inspectors reviewed
      PSEGs LER, root cause evaluation report (Order 70161698), supporting documentation,
      station procedures, and interviewed several members of station staff and management
      regarding the event. Two findings were identified and are discussed below. These
      LERs are closed.
  b. Findings
      .1 Failure to Use Approved Method of Post-Scram Reactor Pressure Control
      The mis-operation of the digital electro-hydraulic control system following the reactor
      scram on December 5, 2013, has been previously evaluated. A self-revealing Green
      NCV of TS 6.8.1.a (NCV 05000354/2014002-06) for Failure to Use Approved Method of
      Post-Scram Reactor Pressure Control is documented in NRC Inspection Report
      05000354/2014002.
      .2 Inadequate Implementation of Contingency Actions During Moisture Separator
          Emergency Level Controller Tuning
      Introduction. A self-revealing finding of very low safety significance (Green) was
      identified when PSEG failed to ensure that contingency actions were appropriate for
      the activity being performed prior to A MS emergency level controller tuning on
      December 5, 2013. Specifically, the decision to tune the emergency level controller
      without appropriate contingencies in place led to a turbine trip and subsequent reactor
      scram on high A MS level.
      Description. On December 5, 2013, maintenance technicians were tuning the A MS
      emergency level controller following its replacement in accordance with PSEG
      procedure HC.IC-LC.AF-00007, Moisture Separator Drain Tank Level Tuning.
                                                                                        Enclosure
                                          27
During the tuning evolution, the A MS dump valve failed closed, causing a turbine trip
due to high A MS level and automatic reactor scram.
The moisture separators improve the quality of the steam from the high pressure turbine
exhaust, and minimize erosion of the low pressure turbines due to excessively moist
steam. The levels in the A and B MSs are maintained through a normal drain path
through three drain valves on each MS to the #5 feedwater heaters. The position of the
drain valves is controlled by the MS normal level controller. When the level in the MS
is above the normal drain control level, a high level emergency dump valve (one per MS)
directs flow from the MS to the condenser. The emergency level dump valve is normally
closed and is controlled by the MS emergency level controller.
PSEG procedure HC.IC-LC.AF-00007, Moisture Separator Drain Tank Level Tuning,
raises MS level into the emergency dump range to tune the emergency level controller
by manually closing the normal drain valves. This evolution was evaluated and
determined to be a high risk evolution in accordance with WC-AA-105, Work Activity
Risk Management. A risk management plan was developed for the high risk activity.
WC-AA-105 requires that the risk management plan be presented for approval by a risk
management challenge board prior to performance of the high risk activity.
This plan was initially reviewed by a risk management challenge board and was not
approved. An action from the risk management challenge board included ensuring that
during the tuning, one person is to be stationed at the normal level controller and one at
the emergency level controller. The risk management challenge board directed that both
people would need to be prepared to respond in case the MS drain tank level rises
during the tuning evolution. A second risk management challenge board was held to
review the risk management plan. The contingency action for stationing maintenance
technicians at each controller was not implemented.
The second challenge board failed to ensure that contingency actions were appropriate
for the activity being performed as specified by PSEG procedure WC-AA-105. A
heightened level of awareness (HLA) brief was performed prior to performance of the
high risk activity. Having a maintenance technician at the normal and emergency level
controllers was discussed. Contrary to the direction of the risk management challenge
board and the HLA brief, a maintenance technician was not stationed at the normal level
controller during the tuning of the emergency level controller. PSEGs corrective actions
included conducting performance management with the individuals involved with the
tuning evolution, and revising the moisture separator drain tank level tuning procedure to
require an individual at the normal and emergency controllers when performing
emergency level controller tuning.
Analysis. The inspectors determined that PSEGs failure to ensure that the contingency
actions were appropriate for the activity being performed prior to A MS emergency
level controller tuning was a performance deficiency that was within PSEGs ability to
foresee and correct, and should have been prevented. Specifically, a contingency action
specified by the risk management challenge board and the HLA brief prior to the high
risk tuning activity was not performed. As a result, the technicians were unable to
restore air to the drain valves in time to reduce the A MS level before the high level
caused a turbine trip and reactor scram.
                                                                                  Enclosure
                                                28
      This finding was more than minor because it was associated with the human
      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. The
      inspectors determined that this finding was of very low safety significance (Green) using
      Exhibit 1 of NRC IMC 0609, Appendix A, The Significance Determination Process
      (SDP) for Findings At-Power, dated June 19, 2012, because the finding did not cause
      both a reactor trip and the loss of mitigation equipment relied upon to transition the plant
      from the onset of the trip to a stable shutdown condition (e.g. loss of condenser, loss of
      feed water). The inspectors determined that the finding had a cross-cutting aspect in the
      Human Performance area associated with Work Management, because PSEG
      personnel did not implement a process of planning, controlling, and executing work
      activities such that nuclear safety is the overriding priority. Specifically, technicians were
      only stationed at the emergency level controller during the tuning, when having
      technicians at both controllers would have provided more time to recover from a high
      level condition in the A MS, and may have prevented the turbine trip and subsequent
      reactor scram on December 5, 2013. (H.5)
      Enforcement. This finding was not a violation of NRC requirements because no violation
      of regulatory requirements was identified. Since this finding does not involve a violation
      and is of very low safety significance (Green), it is identified as a FIN. (FIN
      05000354/2014003-04, Inadequate Implementation of Contingency Actions During
      Moisture Separator Emergency Level Controller Tuning)
.6    (Closed) LER 05000354/2013-010-00, Loss of Both Main Control Room Chillers
  a. Inspection Scope
      On December 20, 2013, at 1:03 pm, while the B MCR chiller was out of service in
      support of maintenance, the A MCR chiller was manually secured due to excessive
      fluctuations in load. The TSAS (TS 3.7.2.2 Action a.2) for both MCR air conditioning
      subsystems inoperable was entered. At 9:20 pm, the B control area ventilation train
      and chiller were placed in service for post maintenance testing, returned to an operable
      status, and the TS action statement was exited.
      This condition is reportable under 10 CFR 50.73(a)(2)(v)(D) as an event or condition that
      could have prevented the fulfillment of the safety function of structures or systems that
      are needed to mitigate the consequences of an accident. The inspectors reviewed
      PSEGs LER and LER revision, apparent cause evaluation (Order 70162284),
      supporting documentation, station procedures, and interviewed several members of
      station staff and management regarding the event. One finding was identified and is
      discussed below. These LERs are closed.
  b. Findings
      Introduction. A Green self-revealing NCV of 10 CFR 50, Appendix B, Criterion III,
      Design Control, was identified for PSEGs failure to effectively implement the DCP
      process. Specifically, PSEGs DCP 4EC-3662 failed to reclassify the PC of the MCR
      chiller PCV positioner from non-safety related (PC4) to safety related (PC1). Because of
      the incorrectly assigned PC, PSEG did not track the shelf life of replacement positioner
      diaphragms, which led to the failure of the A MCR positioner on December 20, 2013.
                                                                                          Enclosure
                                          29
As a result, while the B MCR chiller was inoperable following planned maintenance, the
A MCR chiller had to be manually secured due to excessive fluctuations in load caused
by the failed positioner, and led to both MCR chillers being inoperable.
Description. The control room envelope (CRE) heating, ventilation and air conditioning
(HVAC) systems are designed to ensure habitability during any design basis radiological
accident. Redundant HVAC systems are provided to control the ambient conditions for
safety-related equipment to ensure operating temperature limits are not exceeded. The
A and B MCR chillers provide the accident function of maintaining the temperature of
the CRE for equipment performance and operator comfort.
On December 20, 2013, at 1:03 pm, while the B MCR chiller was out of service in
support of maintenance, the A MCR chiller was manually secured due to excessive
fluctuations in load. TS action statement 3.7.2.2.a.2 for both MCR chillers being
inoperable was entered. This condition was reportable per 10CFR50.72(b)(3)(v)(D), as
an event or condition that could have prevented the fulfillment of the safety function of
structures or systems that are needed to mitigate the consequences of an accident,
PSEG submitted an eight-hour event notification (#49671) for concurrent inoperability of
both MCR chillers. At 9:20 pm (~8 hours into the 72 hour TS action statement), the B
MCR chiller was placed in service for post maintenance testing and returned to an
operable status, allowing PSEG to exit the TS. Throughout the time both chillers were
inoperable, the MCR temperature was maintained below the TS limit of 90 degrees
Fahrenheit.
PSEG conducted an equipment apparent cause evaluation (EQACE 70162284) and
determined the A MCR chiller excessive load fluctuations were the result of an
inoperable chiller condenser PCV. The positioner for the PCV, which provides cooling
water flow to the chiller condenser, failed due to a leak in the positioner's internal relay
assembly, which is made up of a series of diaphragms. This positioner had failed
previously due to a missing roller bearing and C clip, and was replaced at the end of
2011. The replaced positioner that failed on December 20, 2013, had only been
installed for 2 years. The damaged diaphragm in the positioners relay assembly
allowed an internal leakage path for the air, resulting in the failure of the positioner to
operate properly. This failure was determined to be age-related caused by a legacy
issue with the implementation of DCP 4EC-3662 in 1997. The chiller PCV has an active
safety function in the open position to provide cooling water flow to the MCR chiller. On
a loss of instrument air, the chiller PCV was originally designed to fail open, but this DCP
installed backup air bottles to supply the chiller PCV, preventing the PCV from failing
open so that the chiller would not trip on low evaporator refrigerant pressure. This
design change resulted in the PCV becoming self-modulating, changing the
classification of the PCV positioner from nonsafety-related to safety-related. PSEGs
evaluation of this DCP in the EQACE concluded that the DCP failed to identify that the
PC of the positioner for the PCV should have been changed from nonsafety-related to
safety-related and as a result, the PC was not changed. If the PC of the positioner had
been changed to PC1, a positioner that had been on the shelf for more than 20 years
would not have been installed into a safety-related system. But because the PC was not
changed, PSEG determined that the shelf life of the in-stock replacement positioners
was not tracked, leading to the installation of a positioner in 2011 that had been
manufactured 21 years before.
                                                                                    Enclosure
                                              30
    PSEGs determined that the MCR chiller PCV positioner failed to operate because of
    internal relay leakage caused by damaged diaphragms. These diaphragms failed due to
    the positioners age exceeding the vendor recommended lifetime of 4 years. PSEG has
    entered this issue into the CAP as NOTF 20642546. As part of PSEGs corrective
    actions the site has replaced the failed positioner and changed the purchase
    classification for the chiller PCV positioners to safety-related (PC1).
    Analysis. PSEGs failure to effectively implement the DCP process for DCP 4EC-3662
    was a performance deficiency that was within the licensees ability to foresee and
    correct, and should have been prevented. Specifically, because of the incorrectly
    assigned PC, PSEG did not track the shelf life of replacement positioner diaphragms,
    which led to the failure of the A MCR positioner on December 20, 2013. The inspectors
    determined that the performance deficiency was more than minor because it is
    associated with the design control attribute of the of the barrier integrity cornerstone, and
    adversely affected the cornerstone objective of maintaining the radiological barrier
    functionality of the control room Exhibit 3 of IMC 0609, Appendix A, The Significance
    Determination Process (SDP) for Findings at Power, issued June 19, 2012, the
    inspectors determined that this finding is of very low safety significance (Green) because
    the performance deficiency represents a degradation of only the radiological barrier
    function provided for the control room. Since the implementation of DCP 4EC-3662, the
    DCP procedures have been enhanced to ensure the completion of a purchase class
    evaluation of procured materials that are implemented in the DCP process.
    The inspectors determined that there was no cross-cutting aspect associated with this
    finding because the cause of the performance deficiency occurred more than three years
    ago, and was not representative of current plant performance.
    Enforcement. 10 CFR 50, Appendix B, Criterion III, Design Control, states, in part, that
    measures shall be established to assure that applicable regulatory requirements and the
    design basis for structures, systems, and components shall be correctly translated into
    specifications, drawings, procedures, and instructions.
    Contrary to this, PSEGs implementation of DCP 4EC-3662 in 1997, failed to reclassify
    the PC of the MCR chiller PCV positioner from nonsafety-related to safety-related.
    Because of the incorrectly assigned PC, PSEG did not track the shelf life of replacement
    positioner diaphragms, which led to the failure of the A MCR positioner on
    December 20, 2013. PSEGs corrective actions include replacement of the failed
    positioner and changing the PC for the MCR PCV positioners to safety-related.
    Because of the very low safety significance (Green) and because the issue was entered
    into the CAP as notification 20642546, this violation is being treated as an NCV,
    consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV
    05000354/2014003-05, Inadequate Evaluation of a Main Control Room Chiller
    Design Change)
4OA5 Other Activities
    Temporary Instruction (TI) 2515/182, Phase II, Underground Piping and Tank Integrity
    (1 sample)
                                                                                        Enclosure
                                                31
  a. Inspection Scope
      The licensees buried piping and underground piping and tanks program was inspected
      in accordance with paragraph 03.02.a of the TI. It was confirmed that activities which
      correspond to completion dates specified in the program, which have passed since the
      Phase 1 inspection was conducted, have been completed.
      Additionally, the licensees buried piping and underground piping and tanks program was
      inspected in accordance with paragraph 03.02.b of the TI and responses to specific
      questions found in http://www.nrc.gov/reactors/operating/ops-experience/buried-pipe-ti-
      phase-2-insp-req-2011-11-16.pdf were submitted to the NRC headquarters staff.
  b. Findings
      No findings were identified.
4OA6 Meetings, Including Exit
      On July 10, 2014, the inspectors presented the inspection results to Mr. Paul Davison,
      Hope Creek Site Vice President, and other members of the PSEG staff. The inspectors
      verified that no proprietary information was retained by the inspectors or documented in
      this report.
4OA7 Licensee-Identified Violations
      The following violation of very low safety significance (Green) was identified by the
      licensee and is a violation of NRC requirements which meets the criteria of the NRC
      Enforcement Policy, for being dispositioned as a NCV:
        In Modes 1, 2, and 3, Hope Creek TS 3.4.2.1, "Safety Relief Valves," requires that
          13 of the 14 SRVs open within of +/- 3 percent of the specified code safety valve
          function lift settings or else be in Mode 3 within 12 hours and in Mode 4 within the
          next 24 hours. Contrary to this requirement, on November 22, 2013, PSEG identified
          that five of the fourteen SRVs were determined to have their as-found setpoints in
          excess of the TS allowable tolerance, thus leaving nine operable SRVs. The pilot
          assembly for each of the fourteen SRVs has been replaced with a fully tested spare
          assembly. Additionally, LER 2013-007 stated PSEGs proposal to replace the SRVs
          is being considered through the plant modification process. PSEG entered this issue
          into their CAP as notification 20631351. The inoperability of the five SRVs did not
          result in a loss of system safety function based on engineering analyses that showed
          that postulated piping stresses would not exceed allowable limits. Therefore, this
          finding is of very low (Green) safety significance based on an SDP issue screening,
          because the SRVs would have functioned to prevent a reactor vessel over-
          pressurization. The closure of the LER associated with this event was documented
          in Section 4OA3.
ATTACHMENT: SUPPLEMENTARY INFORMATION
                                                                                      Enclosure
                                            A-1
                              SUPPLEMENTARY INFORMATION
                                  KEY POINTS OF CONTACT
Licensee Personnel
P. Davison, Site Vice President
E. Carr, Plant Manager
P. Bellard, Program Engineering
S. Bier, EOP Coordinator
M. Biggs, Hope Creek Maintenance Rule Coordinator
M. Cardile, Fire Protection Supervisor
J. Carlin, Fire Protection Superintendent
S. Connelly, System Engineer
A. DiEgidio, Chemistry Technician
T. Headman, Emergency Preparedness Technical Specialist
W. Hickey, Work Week Manager
C. Johnson, Senior Program Engineer
E. Martin, Senior Program Engineer
J. Master, Chemistry Technician
M. Meltzer, Chemistry
T. Morin, Regulatory Assurance Engineer
M. Reeser, System Engineer
M. Rooney, System Engineer
R. Smith, System Engineer
K. Timko, System Engineer
A. Tramontana, Program Engineering Manager
M. Tudisco, Nuclear Maintenance Supervisor
K. Wichman, System Engineer
              LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED
Opened/Closed
05000354/2014003-01                NCV      Inadequate Procedural Guidance for Responding
                                            to an Internal Flooding Event in the HPCI and
                                            RCIC Rooms (Section 1R06)
05000354/2014003-02                FIN    Failure to Evaluate an Identified Issue with the
                                            Moisture Separator Dump Valve Performance
                                            (Section 1R12)
05000354/2014003-03                NCV      Failure to Follow Procedure Resulting in the Loss
                                            of a Vital 4kV Bus (Section 1R13)
05000354/2014003-04                FIN    Inadequate Implementation of Contingency
                                            Actions During Moisture Separator Emergency
                                            Level Controller Tuning (Section 4OA3)
                                                                                    Attachment
                                            A-2
05000354/2014003-05              NCV      Inadequate Evaluation of a Main Control Room
                                          Chiller Design Change (Section 4OA3)
Closed
05000354/2013-007-00              LER      As-Found Values for Safety Relief Valve Lift Set
                                          Points Exceed Technical Specification Allowable
                                          Limit (Section 4OA3)
05000354/2013-008-01              LER      Automatic Actuation of the Reactor Protection
                                          System Due to a Main Turbine Trip (Section
                                          4OA3)
05000354/2013-009-01              LER      Automatic Actuation of the Reactor Protection
                                          System Due to a Main Turbine Trip (Section
                                          4OA3)
05000354/2013-010-00              LER      Loss of Both Main Control Room Chillers (Section
                                          4OA3)
                              LIST OF DOCUMENTS REVIEWED
Section 1R01: Adverse Weather Protection
Procedures
ER-HC-310-1009, HCGS - Maintenance Rule Scoping, Revision 10
HC.MD-GP.ZZ-0037, Plant Bulkhead Doors Overhaul, Revision 5
HC.MD-PM.ZZ-0007, Missile Resistant and Watertight Doors Preventative Maintenance,
        Revision 9
HC.OP-AB.MISC-0001, Acts of Nature, Revision 23
HC.OP-DL.ZZ-0014, Monday Shift Routine Log, Revision 34
HC.OP-GP.ZZ-0003, Station Preparations for Winter Conditions, Revision 29
OP-AA-108-111-1001, Severe Weather and Natural Disaster Guidelines, Revision 9
WC-AA-107, Seasonal Readiness, Revision 13
Other Documents
2013 Summer Readiness Hope Creek Critique
2014 Hope Creek Summer Readiness Affirmation Certification Letter, dated May 1, 2014
Notifications (*NRC-identified)
20546153        20562816      20610276    20612823      20613802      20615133
20649147        20650908      20650999    20652771*      20652918*    20654490
20654491        20654493      20654495    20654496
Maintenance Orders/Work Orders
30236406        60092591      60104126    60112815      60112948      60114177
60115861        70159564      80107747    80110867
                                                                                Attachment
                                              A-3
Drawings
A-0203-0, General Plant Floor Plan Level 3 - Elevation 102, Revision 19
Section 1R04: Equipment Alignment
Procedures
HC.OP-ST.BD-0001, RCIC Piping and Flow Path Verification - Monthly, Revision 14
HC.OP-ST.EA-0001, Service Water Flow Path Verification - Monthly, Revision 11
OP-AA-108-116, Protected Equipment Program, Revision 9
OP-HC-108-115-1001, Operability Assessment and Equipment Control Program, Revision 27
Notifications (*NRC-identified)
20529358        20529359      20529360      20529362      20636088    20636089
20647011        20648223      20649406*      20649407*      20649408*    20649409*
Maintenance Orders/Work Orders
30255253        50165993      70127188      70129996
Drawings
E-0485-0, Electrical Schematic Auxiliary Building - Diesel Area Switchgear Room Coolers and
        Air Dampers, Sht. 3, Revision 8
M-10-1, Sheet 1, Service Water, Revision 54
M-10-1, Sheet 2, Service Water, Revision 43
M-49-1, Reactor Core Isolation Cooling, Revision 30
M-50-1, RCIC Pump Turbine, Revision 29
Miscellaneous
HCGS PRA Risk Evaluation Form for Work Week #1418, Revision 3, dated May 2, 2013
MP 192355
NRC IN 96-06, Design and Testing Deficiencies of Tornado Dampers at Nuclear Power Plants
OE 33769
PM 30255253
Protected Equipment Log for HPCI Sight Glass Repair, dated May 2, 2014
Section 1R05: Fire Protection
Procedures
FP-AA-014, Fire Protection Training Program, Revision 1
FP-AA-015, Compensatory Measure Firewatch Program, Revision 5
FP-AA-028-1001, Emergency Response Safety and Risk Management Plan, Revision 0
FP-HC-004, Actions for Inoperable Fire Protection - Hope Creek Station, Revision 1
FRH-II-332, Service & Radwaste Area, Elevation: 102-0, Revision 4
FRH-II-412, Hope Creek Pre-Fire Plan, RCIC Pump and Turbine Room, RHR Pump and Heat
      Exchanger Rooms, and Electrical Equipment Room, Elevations 54, Revision 3
FRH-II-415, Hope Creek Pre-Fire Plan, Dry Well Pad Torus Area, Elevations: 54-0 &77-0,
      Revision 4
FRH-II-522, Hope Creek Pre-Fire Plan, Cable Spreading Room, Elevation: 77-0, Revision 6
FRH-II-532, Hope Creek Pre-Fire Plan, Lower Control Equipment Room, Elevation: 102-0,
      Revision 6
                                                                                  Attachment
                                              A-4
FRH-II-542, Hope Creek Pre-Fire Plan, Control Equipment Mezzanine, Elevations: 117-6 &
      124-0, Revision 6
FRH-II-551, Hope Creek Pre-Fire Plan, Battery Rooms & Cable Chases, Elevations: 146-0 &
      150-0, Revision 6
HC.OP-IS.BD-0001, Reactor Core Isolation Cooling Pump - OP203 - Inservice Test, Rev 58
SH.FP-EO.ZZ-0002, Fire Department Fire Response, Revision 3
Notifications (*NRC identified)
20632422        20633801      20639488    20642920        20644734  20644822
20646267        20646330      20646361    20647111        20647263*  20647351*
20651472
Maintenance Orders/Work Orders
0158901        50165299      70143862    70161457
Drawings
M-50-1, P&ID RCIC Pump Turbine, Revision 29
Miscellaneous
Fire Protection Impairment Permit 11760, dated April 16, 2014
Section 1R06: Flood Protection Measures
Procedures
EP-HC-111-130, HC EAL Wall Chart - All Conditions, Revision 1
HC.OP-AR.ZZ-0004, Overhead Annunciator Window Box A6, Revision 18
HC.OP-AR.ZZ-0006, Overhead Annunciator Window Box B1, Revision 25
HC.OP-AR.ZZ-0022, CRIDS Computer Points Book 3 D2880 Thru D3257, Revision 19
HC.OP-EO.ZZ-0103/4, Reactor Building and Radioactive Release Control, Revision 9
HC.OP-EO.ZZ-0103/4-CONV, Hope Creek Emergency Operating Procedure Conversion
        Document, Revision 9
HC.OP-EO.ZZ-0103/4-FC, Reactor Building and Radioactive Release Control Flow Chart,
        Revision 9
Notifications (*NRC identified)
20643688*      20643694*      20643696*    20643885*        20643886*  20643887*
20646334*      20646335*      20653586*    20656703*
Drawings
A-4641-1, Reactor Building Unit 1 Floor Plan at El. 54-0, Revision 6
J-25-0, Sheet 5, Logic Diagram Plant Leak Detection, Revision 6
M-25-1, Sheet 1, Plant Leak Detection, Revision 8
M-97-1, Sheet 2, Building and Equipment Drain Reactor Building, Revision 18
Other Documents
Calculation Number 11-0092, Reactor Building Flooding - Elevation 54 and 77, Revision 5
Calculation Number BC-0031, ECCS Pump Rooms Flood Level Alarm Set Point, Revision 1
HC-PRA-012, Internal Flood Evaluation Summary and Notebook, Revision 2
HC-PRA-017, Internal Flood Walkdown Notebook, Revision 0
                                                                                  Attachment
                                                A-5
Section 1R11: Licensed Operator Requalification Program
Procedures
CY-AB-120-340, Offgas Chemistry, Revision 8
HC.OP-AB.IC-0001, Control Rod, Revision 16
HC.OP-FT.AC-0002, Main Turbine Functional Test Monthly, Revision 31
HC.OP-FT.AC-0005, Turbine Overspeed Protection System Operability Test - Quarterly,
        Revision 13
HC.OP-ST.AC-0002, Turbine Valve Testing - Quarterly, Revision 49
HU-AA-1211, Pre-Job Briefings, Revision 11
NF-AA-400-1000, Fuel Integrity Monitoring, Revision 4
NF-AA-400-1700, BWR Fuel Reliability Indicator (FRI) Calculation and Transmittal, Revision 1
NF-AA-430, Failed Fuel Action Plan, Revision 8
OP-AA-101-111-1004, Operations Standards, Revision 4
OP-AA-108-111, Attachment 1, Adverse Condition Monitoring and Contingency Plan, Revision 7
OP-AA-300, Reactivity Management, Revision 6
OP-AB-300-1001, BWR Control Rod Movement Requirements, Revision 6
OP-AB-300-1003, BWR Reactivity Maneuver Guidance, Revision 11
Notifications
20543906        20566308      20644437
Maintenance Orders/Work Orders
50163804        70140638      80110856
Other Documents
HC 14-01, OTDM for Turbine Overspeed Protection System Operability Test - Quarterly,
        February 11, 2014
HC 14-008, ACM for Fuel Reliability Parameters used to Monitor Fuel Defect indicate potential
        fuel failure, March 25, 2014, Revision 0
Hope Creek Long Term Trends - 2014 for Failed Fuel Monitoring (NOTF 20644437)
Hope Creek Failed Fuel Monitoring Team Meeting on March 15, 2014
REMA 2014-0022, April 2014 TVT and PST Downpower REMA, Revision 0
Miscellaneous
Scenario Guide (SG)-644, Reactor Recirc Pump Trip / RWCU Leak / Loss of Main Condenser
        Vacuum / ATWS dated April 24, 2014
Section 1R12: Maintenance Effectiveness
Procedures
ER-AA-10, Equipment Reliability Process Description, Revision 1
ER-AA-310, Implementation of the Maintenance Rule, Revision 11
ER-AA-310-1001, Maintenance Rule - Scoping, Revision 6
ER-AA-310-1004, Maintenance Rule - Performance Monitoring, Revision 10
ER-AA-310-1005, Maintenance Rule - Dispositioning Between (a)(1) and (a)(2), Revision 9
ER-HC-310-1009, Maintenance Rule System Function and Risk Significant Guide, Revision 10
ER-SA-310-1009, Salem Generating Station - Maintenance Rule Scoping, Revision 4
HC.DE-PS.ZZ-0041, Hope Creek Station Blackout Program, Revision 3
                                                                                  Attachment
                                              A-6
HC.IC-CC.SK-0002, RCIC - Division 4 Steam Leak Detection Temperature Monitor H1SK-
        1SKXR-11503, Revision 14
HC.IC-DC.SK-0001, NUMAC Leak Detection Setup and Trip Selection, Revision 11
HC.OP-AB.ZZ-0135, Station Blackout // Loss of Offsite Power // Diesel Generator Malfunction,
        Revision 39
LS-AA-125, Corrective Action Program, Revision 17
MA-AA-716-004, Conduct of Troubleshooting, Revision 12
MA-AA-716-012, Post Maintenance Testing, Revision 19
MA-AA-716-210-1005, Predefine Change Process, Revision 3
S1.OP-AB.LOOP-0001, (Salem) Loss of Off-site Power, Revision 29
WC-AA-111, Predefine Process, Revision 8
Notifications
20335737      20413574      20447050      20502118      20570839      20619184
20623712      20638460      20640526      20645207      20651951
Orders
60113250      70073704      70105948      70121525      70124871      70157974
70161698      80110856
Miscellaneous
HC 10-03, License Amendment Request for Extending the Allowed Outage Time for the A and
        B EDGs from 72 hours to 14 days
HC 13-015, OTDM for Continued Operation of the Moisture Separator without a Root Cause for
        the Dump Valve Failing to Control Level, dated December 6, 2013
NUMARC 93-01, Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear
        Power Plants, Revision 4
NRC Correspondence, HCGS - Issuance of Amendment Re: Emergency Diesel Generators A
        and B Allowed Outage Time Extension, dated March 25, 2011
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
Procedures
HC.CH-SA.HA-0002, Sampling Offgas System from 00-C-963 Panel, Revision 8
HC.OP-AB.RPV-0001, Reactor Power, Revision 13
HC.OP-FT.AC-0005, Turbine Overspeed Protection System Operability Test - Quarterly,
        Revision 13
HC.OP-IO.ZZ-0006, Power Changes During Operation, Revision 57
HC.OP-SO.BB-0002, Reactor Recirculation System Operation, Revision 98
HC.OP-SO.PB-0001, 4.16KV System Operation, Revision 29
HC.OP-ST.PB-0002, AC Power Supply Transfer Functional Test - 18 Months, Revision 11
HC.OP-ST.ZZ-0001, Power Distribution Lineup - Weekly, Revision 36
MA-AA-1000, Conduct of Maintenance Manual, Section 3.0 - Maintenance Standards and
        Practices, Revision 7 and 14
NC.CH-RC.ZZ-2525, Gamma Spectroscopy Analysis Using CAS, Revision 4
NF-AB-431, Power Suppression Testing, Revision 6
WC-AA-101, On-Line Work Management Process, Revision 22
WC-AA-105, Work Activity Risk Management, Revision 2
                                                                                  Attachment
                                              A-7
Notifications (*NRC identified)
20465881        20521256      20585982    20593568    20600597      20627730
20632023        20634061      20637967    20638221    20639498      20639519
20644437        20645095      20645435    20645701*  20645705      20650898
20650904        20651102      20651204    20651430    20651432      20651876
20653142
Maintenance Orders/Work Orders
30098613        30098617      30243196    30265556    60061175      60114688
60117312        70046681      70072347    70097158    70110518      70142932
70155514        70162013
Miscellaneous
DCP 4-HC-0170
HC-14-006, OTDM for B Reactor Recirculation MG Set Speed Control, dated May 17, 2014
HCGS Operations Narrative Logs, May 14-15, 2014
HCGS PRA Risk Evaluation Form for June 8, 2014, through June 14, 2014, Revision 0
        Protected Equipment Log -F FRVS Recirc Fan, dated June 8, 2014
HRE 2014-0023, Mid-Cycle 19 Standing REMA, from May 9-30, 2014, Revision 3
NRC RIS 2007-21, Adherence to Licensed Power Limits, Revision 1
REMA 2014-0022, April 2014 TVT and PST Downpower REMA, Revision 0
Troubleshooting Data Sheet - NOTF 20630902 for B RRP Speed Demand, dated
        November 15, 2013
Troubleshooting Work Sheet - NOTF 20651102 for Proper Indication and Control of the B RRP
        Speed Control Loop, dated May 14, 2014
WC-AA-105-F3, Form 3, Risk Management Plan - Replacement of B Isolator, Revision 1
Section 1R15: Operability Determinations and Functionality Assessments
CC-AA-309-101, Engineering Technical Evaluations, Revision 10
ER-AA-2006, Lost Parts Evaluation, Revision 8
HC.CH-CA.ZZ-0026, Boron by Mannitol Titration, Revision 18
HC.OP-AB.RPV-0001, Reactor Power, Revision 13
HC.OP-IO.ZZ-0006, Power Changes During Operation, Revision 57
HC.OP-IS.BH-0004, Standby Liquid Control Pump - BP208 - Inservice Test, Revision 12
HC.OP-SO.BB-0002, Reactor Recirculation System Operation, Revision 98
HC.OP-SO.KJ-0001, Emergency Diesel Generators Operation, Revision 70
HC.OP-SO.PB-0001, 4.16KV System Operation, Revision 29
HC.OP-ST.KJ-0003, Emergency Diesel Generator 1CG400 Operability Test - Monthly,
        Revision 76
HC.OP-ST.PB-0002, AC Power Supply Transfer Functional Test - 18 Months, Revision 11
HC.OP-ST.ZZ-0001, Power Distribution Lineup - Weekly, Revision 36
HU-AA-1212, Technical Task Risk/Rigor Assessment, Pre-Job Brief, Independent Third Party
        Review and Post-Job Brief, Revision 8
MA-AA-1000, Conduct of Maintenance Manual, Section 3.0 - Maintenance Standards and
        Practices, Revision 7 and 14
WC-AA-101, On-Line Work Management Process, Revision 22
                                                                                Attachment
                                              A-8
Notifications (*NRC identified)
20221500        20439888      20442565    20442566      20465881      20521256
20585982        20593568      20600597    20616574      20627730      20632023
20634061        20637967      20638221    20639498      20639519      20640696
20643229        20643322*      20644637    20645519      20645994      20647199*
20650611*      20650701*      20650788*    20650831*      20650856*      20650858*
20650898        20650904      20651102    20651204      20651430      20651432
20651876        20652187      20652199    20653142      20653635*
Drawings
M-52-1, Core Spray, Revision 31
M-52-1, Sheet 1, Residual Heat Removal, Revision 45
M-52-1, Sheet 2, Residual Heat Removal, Revision 40
Maintenance Orders/Work Orders
30098613        30098617      30243196    50165850      60061175      60087495
60087534        60087538      60087539    60087540      60087541      60089905
60114688        60117312      70046681    70072347      70097158      70110518
70142932        70149472      70155514    70157453      70162013      70163760
70164628        80079629      80079863    80108395      80111752      80111754
Miscellaneous
10855-D3.33, Design, Installation and Test Specification for Standby Liquid Control System for
        the Hope Creek Generating Station, Revision 5
22A7641, Design Specifications for SLC System, Revision 1
ASTM E29-13, Standard Practice for Using Significant Digits in Test Data to Determine
        Conformance with Specifications
C-0001, Wall Thickness Calculation for Piping, Revision 9
Calculation 1SC-BH-0001, SLC System Tank 10T-204 Level, Revision 0
DCP 4-HC-0170
DCP 4HM-0136, Change Standby Liquid Control Tank Sodium Pentaborate Concentration from
        13.4 to 14.0 Weight Percent, dated December 17, 1987
HC-14-006, OTDM for B Reactor Recirculation MG Set Speed Control, May 17, 2014
HCGS Operations Narrative Logs, May 14-15, 2014
HRE 2014-0023, Mid-Cycle 19 Standing REMA, from May 9-30, 2014, Revision 3
LD-042-MASTERPACT-1, Masterpact Issues, Revision 1
NLR-N87131, Request for Amendment Facility Operating License NPF-57 Hope Creek
        Generating Station Docket No. 50-354, dated July 14, 1987
NRC RIS 2007-21, Adherence to Licensed Power Limits, Revision 1
Part 9900: Technical Guidance, Standard Technical Specifications Section 3.0 Acceptable
        Measurement Tolerances for Technical Specification Limits, dated October 1, 1978
PM018Q-0499, Vol. 1, Operation and Maintenance Manual for Colt Industries Diesel Generator,
        Revision 25
Troubleshooting Data Sheet - NOTF 20630902 for B RRP Speed Demand, dated November
        15, 2013
Troubleshooting Work Sheet - NOTF 20651102 for Proper Indication and Control of the B RRP
        Speed Control Loop, dated May 14, 2014
WC-AA-105-F3, Form 3, Risk Management Plan - Replacement of B Isolator, Revision 1
                                                                                    Attachment
                                              A-9
Section 1R18: Plant Modifications
Procedures
CC-AA-102, Design Input and Configuration Change Impact Screening, Revision 23
CC-AA-103, Configuration Change Control for Permanent Physical Plant Changes, Revision 15
CC-AA-112, Temporary Configuration Changes, Revision 13
CC-AA-112-1001, Temporary Configuration Change Implementation T&RM, Revision 2
OP-AA-115-101, Operator Aid Postings, Revision 3
Notifications
20439888        20639161      20640696      20651205    20652187
Maintenance Orders/Work Orders
60115429        70163760      80107203      80111298    80111754
Drawings
M-08-0, Sheet 1, Condensate & Refueling Water Storage & Transfer, Revision 34
Miscellaneous
DCP 80111754, Masterpact Breaker Add Aux Contact with Close Coil, Revision 1
H-1-ZZ-EGS-0043, Hope Creek Generating Station GE AKR Circuit Breaker Replacement
        Project
LD-042-MASTERPACT-1, Revision 1
OPEVAL 14-002, Masterpact Breaker Model NW with Locked in Close Signal, Revision 3
Temporary Configuration Change Package Tracking Log, dated June 10, 2014
Section 1R19: Post-Maintenance Testing
Procedures
CC-AA-309-101, Engineering Technical Evaluations, Revision 10
HC.IC-CC.SK-0002, RCIC - Division 4 Steam Leak Detection Temperature Monitor H1SK-
        1SKXR-11503, Revision 14
HC.IC-DC.SK-0001, NUMAC Leak Detection Setup and Trip Selection, Revision 11
HC.IC-DC.ZZ-0011, Device/Equipment Calibration Bailey, Characterizable Pneumatic
        Positioner, Type AP2, Revision 5
HC.OP-AB.COMP-0001, Instrument and/or Service Air, Revision 5
HC.OP-AB.RPV-0001, Reactor Power, Revision 13
HC.OP-IO.ZZ-0006, Power Changes During Operation, Revision 57
HC.OP-IS.BJ-0001, HPCI Main and Booster Pump Set - OP204 and OP217 - Inservice Test,
        Revision 62
HC.OP-SO.BB-0002, Reactor Recirculation System Operation, Revision 98
HC.OP-ST.BC-0005, LPCI Subsystem B ECCS Time Response Functional Test - 18 Months,
        Revision 16
HC.OP-ST.ZZ-0001, Power Distribution Lineup - Weekly, Revision 36
HU-AA-1212, Technical Task Risk/Rigor Assessment, Pre-Job Brief, Independent Third Party
        Review and Post-Job Brief, Revision 8
MA-AA-716-012, Post Maintenance Testing, Revision 19
MA-AA-1000, Conduct of Maintenance Manual, Section 3.0 - Maintenance Standards and
        Practices, Revision 7 and 14
SM-AA-410, Control of Purchased Material, Equipment and Services Program, Revision 6
WC-AA-101, On-Line Work Management Process, Revision 22
                                                                              Attachment
                                            A-10
Notifications (*NRC identified)
20454035        20465881      20521256    20619184    20623712      20623802
20629385        20632023      20642546    20642950    20647111      20650904
20651102        20651430      20651872    20651951    20652010      20652012
20652232        20652238      20652321    20652339    20652702      20653142
20653572*      20653872*
Maintenance Orders/Work Orders
30098613        30098617      30240742    30269527    50163142      60113238
60113250        60116090      60117312    70125746    70155514      70157974
70163994        70166194
Drawings
PN11-E11-1040-0383, Sheet 3, Residual Heat Removal System, Revision 15
PN11-E11-1040-0383, Sheet 12, Residual Heat Removal System, Revision 18
PN11-E11-1040-0383, Sheet 13, Residual Heat Removal System, Revision 10
PN11-E11-1040-0383, Sheet 22, Residual Heat Removal System, Revision 17
Miscellaneous
HC-14-006, OTDM for B Reactor Recirculation MG Set Speed Control, dated May 17, 2014
HCGS Operations Narrative Logs, May 14-15, 2014
HCGS PRA Risk Evaluation Form for April 20, 2014 through April 26, 2014
HRE 2014-0023, Mid-Cycle 19 Standing REMA, from May 9-30, 2014, Revision 3
NRC RIS 2007-21, Adherence to Licensed Power Limits, Revision 1
Troubleshooting Data Sheet - NOTF 20630902 for B RRP Speed Demand, dated
        November 15, 2013
Troubleshooting Work Sheet - NOTF 20651102 for Proper Indication and Control of the B RRP
        Speed Control Loop, dated May 14, 2014
WC-AA-105-F3, Form 3, Risk Management Plan - Replacement of B Isolator, Revision 1
Section 1R22: Surveillance Testing
Procedures
CC-AA-309-101, Engineering Technical Evaluations, Revision 10
ER-AA-2006, Lost Parts Evaluation, Revision 8
FP-HC-004, Actions for Inoperable Fire Protection - Hope Creek Station, Revision 1
HC.FP-ST.KC-0009, Diesel Driven Fire Pump Operability Test, Revision 20
HC.IC-CC.SK-0016, Radiation Monitoring - Channel D Monitor H1SK-1SKLY-4930 Drywell
        Leak Detection Sump Monitoring System (DLD-SMS), Revision 22
HC.IC-GP.ZZ-0004, Thermocouples (T/C) and Resistance Temperature Detectors (RTD),
        Revision 8
HC.MD-ST.PB-0003, Class 1E 4.16 kV Feeder Degraded Voltage Monthly Instrumentation
        Channel Functional Test, Revision 26
HC.OP-DL.ZZ-0026, Surveillance Log, Revision 139
HC.OP-FT.AC-0002, Main Turbine Functional Test Monthly, Revision 31
HC.OP-FT.AC-0005, Turbine Overspeed Protection System Operability Test - Quarterly,
        Revision 13
HC.OP-IS.BC-0002, CP202, C Residual Heat Removal Pump In-Service Test, Revision 43
HC.OP-IS.BJ-0001, HPCI Main and Booster Pump Set - 0P204 and 0P217 - Inservice Test,
        Revision 62
                                                                                  Attachment
                                            A-11
HC.OP-SO.KJ-0001, Emergency Diesel Generators Operation, Revision 70
HC.OP-ST.AC-0002, Turbine Valve Testing - Quarterly, Revision 49
HC.OP-ST.KJ-0001, Emergency Diesel Generator 1AG400 Operability Test - Monthly,
        Revision 76
HC.OP-ST.KJ-0003, Emergency Diesel Generator 1CG400 Operability Test - Monthly,
        Revision 78
HC.OP-ST.SK-0001, Alternate RCS Leakage Determination, Revision 9
HU-AA-1211, Pre-Job Briefings, Revision 11
HU-AA-1212, Technical Task Risk/Rigor Assessment, Pre-Job Brief, Independent Third Party
        Review and Post-Job Brief, Revision 8
OP-AA-101-111-1004, Operations Standards, Revision 4
OP-AA-108-101, Control of Equipment and System Status, Revision 7
OP-AA-300, Reactivity Management, Revision 6
Notifications
20504658      20629522      20630428      20630429    20640032      20645519
20645994      20646319      20648114      20648751    20649201      20649292
20649425      20649905      20649906      20654936
Maintenance Orders/Work Orders
30199753      50163804      50164408      50164695    50165664      50165690
50165691      50165850      50166624      50167441    50169340      60026593
60058122      60097901      60107882      70008407    70023178      70097767
70122058      70127960      70139509      70145982    80111752
Calculations
SC-SK-0118, Drywell Leak Detection SMS (Floor Drain Unidentified Leakage), Revision 2
Miscellaneous
HC 14-01, OTDM for Turbine Overspeed Protection System Operability Test - Quarterly, dated
        February 11, 2014
HCGS PRA Risk Evaluation Form for April 6, 2014, through April 12, 2014
PM018Q-0499, Vol. 1, Operation and Maintenance Manual for Colt Industries Diesel Generator,
        Revision 25
REMA 2014-0022, April 2014 TVT and PST Downpower REMA, Revision 0
Section 1EP6: Drill Evaluation
Procedures
EP-AA-122, Drills and Exercises, Revision 3
EP-AA-122-1001, Drill and Exercise Scheduling, Development and Conduct, Revision 3
EP-AA-125-1002, NRC Drill and Exercise Performance (DEP) Indicator Guidance, Revision 3
EP-HC-111-121, Fission Product Barrier Table, Revision 1
EP-HC-111-230, Use of Fission Product Barrier Table, Revision 0
NC.EP-EP.ZZ-0102, Emergency Coordinator Response, Revision 18
NC.EP-EP.ZZ-0404, Protective Action Recommendations (PARS) Upgrades, Revision 4
Notifications
20654844
                                                                                Attachment
                                              A-12
Miscellaneous
DEP Observation Checklist for FAD-HC14-02, dated June 24, 2014
Section 4OA1: Performance Indicator Verification
Procedures
HC.OP-DL.ZZ-0026, Surveillance Log, Revision 136
HC.OP-DL.ZZ-0026, Surveillance Log, Revision 137
HC.OP-DL.ZZ-0026, Surveillance Log, Revision 138
HC.OP-DL.ZZ-0026, Surveillance Log, Revision 139
HC.RA-IS.ZZ-0010, Containment Isolation Valve Type C Leak Rate Test, Revision 15
LS-AA-2090, Monthly Data Elements for NRC Reactor Coolant System Activity, Revision 5
LS-AA-2100, Monthly Data Elements for NRC Reactor Coolant System Leakage, Revision 6
LS-HC-1000-1001, Hope Creek Generating Station Surveillance Frequency Control Program
        List of Surveillance Frequencies, Revision 4
NC.CH-RC.ZZ-2525, Gamma Spectroscopy Analysis Using CAS, Revision 4
NC.CH-SA.RC-0002, Operation of the Reactor Building/RHR Sample Stations, Revision 18
Calculations
SC-SK-0119, Drywell Leak Detection SMS - Equipment Drain Sump, Revision 1
Notifications
20650305
Maintenance Orders/Work Orders
50137021        50149686      50162608
Miscellaneous
Daily Dose Equivalent Iodine-131 Sample Data
Daily Surveillance Log Data
Monthly Data Elements for NRC Reactor Coolant System Leakage Data Sheets
Section 4OA2: Problem Identification and Resolution
Procedures
ER-AA-2003, System Performance Monitoring and Analysis, Revision 9
ER-AA-3002, Component Cross-System Monitoring & Component Health Reporting, Revision 3
LS-AA-125, Corrective Action Program, Revision 17
LS-AA-125-1006, Performance Improvement Integrated Matrix (PIIM), Revision 5
LS-AA-1006, NRC Cross-Cutting Analysis and Trending, Revision 2
Notifications (*NRC identified)
20615843        20619913      20632801      20632802  20632361      20632641
20632746        20632747      20632748      20632749  20633058      20633338
20633339        20634028      20635871      20636138  20638889      20639772
20642767        20644539
Orders
70144876        70158815      70161953      70162269  80109029      80110809
80110866
                                                                              Attachment
                                            A-13
Miscellaneous
Hope Creek Engineering PIIM Report 1st Cycle 2013 Presentation, dated 8/31/13
Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion
Procedures
CC-AA-102, Design Input and Configuration Change Impact Screening, Revision 23
CC-AA-103, Configuration Change Control for Permanent Physical Plant Changes, Revision 15
ER-HC-310-1009, Maintenance Rule System Function and Risk Significant Guide, Revision 10
HC.IC-DC.ZZ-0140, Device/Equipment Cal. Masoneilan Pressure Temperature Controller,
        Revision 4
HC.IC-LC.AF-0007, Moisture Separator Drain Tank Level Tuning, Revision 2
HC.OP-AB.RPV-0001, Reactor Power, Revision 13
HC.OP-AR.ZZ-0008, Overhead Annunciator Window Box C1, Revision 45
HC.OP-DL.ZZ-0026, Surveillance Log, Revision 140
HC.OP-SO.BB-0002, Reactor Recirculation System Operation, Revision 98
HC.OP-SO.GJ-0001, A(B) K400 Control Area Chilled Water System Operation, Revision 60
HU-AA-1211, Pre-Job Briefings, Revision 11
LS-AA-125-1003, Attachment 2, Equipment Apparent Cause Evaluation Guide, Revision 13DCP
        4EC-3662
MA-AA-716-004, Conduct of Troubleshooting, Revision 12
SM-AA-300, Procurement Engineering Support Activities, Revision 7
WC-AA-105, Work Activity Risk Management, Revision 2
Notifications (*NRC identified)
20454035        20521256      20528822    20529153        20567269      20570629
20630857        20631351      20631820    20631940        20632542      20638799
20640526        20642546      20642767    20643301        20644017      20645207
20647829        20650346*      20650904    20651102        20651876      20652180
20652182        20652183      20652184    20652185        20652186      20652188
20653024        20653142
Maintenance Orders/Work Orders
60114285        60114286      70041898    70110518        70115711      70119769
70128407        70129670      70140751    70142556        70159686      70161353
70161698        70162284
Miscellaneous
10855-d3.33, Design, Installation and Test Specification for Standby Liquid Control System for
        the Hope Creek Generating Station, Revision 5
22A7641, Design Specifications for SLC System, Revision 1
ASTM E29-13, Standard Practice for Using Significant Digits in Test Data to Determine
        Conformance with Specifications
Calculation 1SC-BH-0001, SLC System Tank 10T-204 Level, Revision 0
DCP 4-HC-0170
DCP 4HM-0136, Change Standby Liquid Control Tank Sodium Pentaborate Concentration from
        13.4 to 14.0 Weight Percent, December 17, 1987
HC-14-006, OTDM for B Reactor Recirculation MG Set Speed Control, dated May 17, 2014
HCGS Operations Narrative Logs, May 14-15, 2014
HRE 2014-0023, Mid-Cycle 19 Standing REMA, from May 9-30, 2014, Revision 3
                                                                                    Attachment
                                            A-14
LER 2013-009-00, Automatic Actuation of the Reactor Protection System Due to a Main Turbine
      Trip
LER 2013-009-01, Automatic Actuation of the Reactor Protection System Due to a Main Turbine
      Trip
NLR-N87131, Request for Amendment Facility Operating License NPF-57 Hope Creek
      Generating Station Docket No. 50-354, dated July 14, 1987
NRC RIS 2007-21, Adherence to Licensed Power Limits, Revision 1
Part 9900: Technical Guidance, Standard Technical Specifications Section 3.0 Acceptable
      Measurement Tolerances for Technical Specification Limits, October 1, 1978
PM018Q-0499, Vol. 1, Operation and Maintenance Manual for Colt Industries Diesel Generator,
      Revision 25
Troubleshooting Data Sheet - NOTF 20630902 for B RRP Speed Demand, dated
      November 15, 2013
Troubleshooting Work Sheet - NOTF 20651102 for Proper Indication and Control of the B RRP
      Speed Control Loop, dated May 14, 2014
WC-AA-105-F3, Form 3, Risk Management Plan - Replacement of B Isolator, Revision 1
Section 4OA5: Other Activities
Condition Reports
20650822      20650823      20652896
Procedures
ER-AA-5400, Underground Piping Program Guide, Revision 4
ER-AA-5400-1002, Underground Piping Examination Guide, Revision 3
SA-AA-117, Industrial Safety, Excavating Trenching, and Shoring, Revision 13
Miscellaneous
Cathodic Protection System Health Report for Hope Creek, Q1-2014
Cathodic Protection System Health Report for Salem U1, Q2-2014
Hope Creek Underground Piping Inspection Plan, Revision 3
LR-ISG-2011-03, Aging Management Program XI.M41, "Buried and Underground Piping and
      Tanks"
NACE SP0169-2007, Control of External Corrosion on Underground or Submerged
      Metallic Piping Systems, Revision 0
NEI-09-14, Guideline for the Management of Underground Piping and Tank Integrity
      Location Sketch for Cathodic Protection of Salem U1 and U2 Structures, Revision 3
Program Health Report for the Salem Plant Underground Piping Program, P1-2014
Program Health Report for the Hope Creek Plant Underground Piping Program, P1-2014
Salem Underground Piping Inspection Plan, Revision 3
Underground Piping Inspection and Evaluation Report for Hope Creek line 0-DB-003, Liquid
      RadWaste Discharge, dated February 22,2013
Underground Piping Inspection and Evaluation Report for Salem line SC-LW-0001-12-01, liquid
      waste, Steam Generator Blowdown, dated September 11, 2012
Underground Piping Inspection and Evaluation Report for Salem lines S1-SG-1031-10 and S2-
      SG-1111-10, dated September 17-20, 2012
UT report on Hope Creek component HODB-0-DB-V013, dated June 20, 2013
                                                                                  Attachment
                                A-15
                      LIST OF ACRONYMS
10 CFR Title 10 of The Code of Federal Regulations
ADAMS  Agencywide Documents Access and Management System
CAP    corrective action program
CCE    common cause evaluation
CFR    The Code of Federal Regulations
CRE    control room envelope
DCP    design change package
EDG    emergency diesel generator
EN    event notification
EQACE  equipment apparent cause evaluation
ER    Environmental Report
HCGS  Hope Creek Generating Station
HLA    heightened level of awareness
HPCI  high pressure coolant injection
HVAC  heating, ventilation and air conditioning
IMC    Inspection Manual Chapter
kV    kilovolt
LER    licensee event report
LM    logic module
MCR    main control room
MS    moisture separator
NACE  National Association of Corrosion Engineers
NCV    non-cited violation
NEI    Nuclear Energy Institute
NOTF  notification
NRC    Nuclear Regulatory Commission
NRR    Nuclear Reactor Regulation
PARS  Publicly Available Records
PC    purchase classification
PCV    pressure control valve
PI    performance indicator
PIIM  performance improvement integrated matrix
PSEG  Public Service Enterprise Group Nuclear, LLC
PST    power suppression testing
RCIC  reactor core isolation cooling
RCS    reactor coolant system
RG    Regulatory Guide
RHR    residual heat removal
RRP    reactor recirculation pump
RTP    rated thermal power
RWCU  reactor water cleanup
SACS  safety auxiliaries cooling system
SDP    Significance Determination Process
SLC    standby liquid control
SRV    safety relief valve
SSC    structure, system, or component
SSW    station service water
                                                        Attachment
                              A-16
TCCP  temporary configuration control package
TI    Temporary Instruction
TS    technical specifications
TSAS  technical specification action statement
U1    Unit 1
U2    Unit 2
UFSAR Updated Final Safety Analysis Report
UT    ultrasonic testing
V    volt
WO    work order
                                              Attachment
}}
}}

Latest revision as of 02:06, 4 November 2019

IR 05000354-14-003, April 1, 2014 - June 30, 2014, Hope Creek Generating Station, Unit 1
ML14209A132
Person / Time
Site: Hope Creek PSEG icon.png
Issue date: 07/28/2014
From: Glenn Dentel
Reactor Projects Branch 3
To: Joyce T
Public Service Enterprise Group
DENTEL, GT
References
IR-14-003
Download: ML14209A132 (50)
v • d • e


See also: IR 05000354/2014003

Text

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION I

2100 RENAISSANCE BLVD., SUITE 100

KING OF PRUSSIA, PA 19406-2713

July 28, 2014

Mr. Thomas P. Joyce

President and Chief Nuclear Officer

PSEG Nuclear LLC - N09

P.O. Box 236

Hancocks Bridge, NJ 08038

SUBJECT: HOPE CREEK GENERATING STATION UNIT 1 - NRC INTEGRATED

INSPECTION REPORT 05000354/2014003

Dear Mr. Joyce:

On June 30, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at

your Hope Creek Generating Station (HCGS). The enclosed inspection report documents the

inspection results, which were discussed on July 10, 2014 with Mr. P. Davison, Site Vice

President of Hope Creek, and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and

compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed

personnel.

This report documents one NRC-identified and four self-revealing findings of very low safety

significance (Green). Three of these findings were determined to involve a violation of NRC

requirements. Additionally, a licensee-identified violation, which was determined to be of very

low safety significance, is listed in this report. However, because of the very low safety

significance, and because they are entered into your corrective action program (CAP), the NRC

is treating the findings as non-cited violations (NCVs) consistent with Section 2.3.2.a of the

NRC Enforcement Policy. If you contest any NCVs in this report, you should provide a

response within 30 days of the date of this inspection report, with the basis for your denial, to

the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, DC 20555-

0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement,

United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC

Resident Inspector at HCGS. In addition, if you disagree with the cross-cutting aspect assigned

to any finding, or a 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 Regional Administrator, Region I, and the NRC Resident Inspector at

HCGS.

T. Joyce 2

In accordance with Title 10 of the Code of Federal Regulations (CFR) 2.390 of the NRCs Rules

of Practice, a copy of this letter, its enclosure, and your response (if any) will be available

electronically for public inspection in the NRCs Public Document Room or from the Publicly

Available Records component of the NRCs Agencywide Documents Access Management

System (ADAMS). ADAMS is accessible from the NRC website at http://www.nrc.gov/reading-

rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Glenn T. Dentel, Chief

Reactor Projects Branch 3

Division of Reactor Projects

Docket Nos.: 50-354

License Nos.: NPF-57

Enclosure: Inspection Report 05000354/2014003

w/Attachment: Supplementary Information

cc w/encl: Distribution via ListServ

ML14209A132

Non-Sensitive Publicly Available

SUNSI Review

Sensitive Non-Publicly Available

OFFICE RI/DRP RI/DRP RI/DRP

NAME JHawkins/ RSB for RBarkley/ RSB GDentel/ GTD

DATE 07/22 /14 07 /22/14 07 / 28 /14

1

U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket Nos.: 50-354

License Nos.: NPF-57

Report No.: 05000354/2014003

Licensee: Public Service Enterprise Group (PSEG) Nuclear LLC

Facility: Hope Creek Generating Station (HCGS)

Location: P.O. Box 236

Hancocks Bridge, NJ 08038

Dates: April 1, 2014 through June 30, 2014

Inspectors: J. Hawkins, Senior Resident Inspector

S. Ibarrola, Resident Inspector

H. Gray, Senior Reactor Inspector

Approved By: Glenn T. Dentel, Chief

Reactor Projects Branch 3

Division of Reactor Projects

Enclosure

2

TABLE OF CONTENTS

SUMMARY ................................................................................................................................ 3

REPORT DETAILS .................................................................................................................... 7

1. REACTOR SAFETY ........................................................................................................... 7

1R01 Adverse Weather Protection .................................................................................... 7

1R04 Equipment Alignment ............................................................................................... 8

1R05 Fire Protection .......................................................................................................... 9

1R06 Flood Protection Measures .....................................................................................10

1R11 Licensed Operator Requalification Program ...........................................................13

1R12 Maintenance Effectiveness .....................................................................................14

1R13 Maintenance Risk Assessments and Emergent Work Control ................................16

1R15 Operability Determinations and Functionality Assessments ....................................19

1R18 Plant Modifications .................................................................................................20

1R19 Post-Maintenance Testing ......................................................................................20

1R22 Surveillance Testing ...............................................................................................21

1EP6 Drill Evaluation .......................................................................................................22

4. OTHER ACTIVITIES ..........................................................................................................22

4OA1 Performance Indicator (PI) Verification ....................................................................22

4OA2 Problem Identification and Resolution ....................................................................23

4OA3 Follow-Up of Events and Notices of Enforcement Discretion ..................................24

4OA5 Other Activities ........................................................................................................30

4OA6 Meetings, Including Exit ...........................................................................................31

4OA7 Licensee-Identified Violations ..................................................................................31

ATTACHMENT: SUPPLEMENTARY INFORMATION...............................................................31

SUPPLEMENTARY INFORMATION....................................................................................... A-1

KEY POINTS OF CONTACT .................................................................................................. A-1

LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED .................................... A-1

LIST OF DOCUMENTS REVIEWED....................................................................................... A-2

LIST OF ACRONYMS ........................................................................................................... A-15

Enclosure

3

SUMMARY

IR 05000354/2014003; 4/01/2014 - 6/30/2014; Hope Creek Generating Station; Flood

Protection Measures, Maintenance Effectiveness, Maintenance Risk Assessments and

Emergent Work Control, Follow-up of Events and Notices of Enforcement Discretion.

This report covered a three-month period of inspection by the resident inspectors and

announced inspections performed by regional inspectors. Five findings of very low safety

significance (Green) were identified. Three of the findings were determined to be violations of

NRC requirements. The significance of most findings is indicated by their color (i.e., greater

than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter

(IMC) 0609, Significance Determination Process (SDP), dated June 2, 2011. Cross-cutting

aspects are determined using IMC 0310, Components Within Cross-Cutting Areas, dated

December 19, 2013. All violations of NRC requirements are dispositioned in accordance with

the NRCs Enforcement Policy, dated July 9, 2013. The NRCs program for overseeing the safe

operation of commercial nuclear power reactors is described in NUREG-1649, Reactor

Oversight Process, Revision 5.

Cornerstone: Initiating Events

Green. A self-revealing finding of very low safety significance (Green) was identified for

PSEGs failure to evaluate an identified deficiency in accordance with PSEG procedure

LS-AA-125, Corrective Action Program. Specifically, PSEG failed to take self-

recommended actions in notification (NOTF) 20447050 to evaluate the B moisture

separator (MS) dump valve performance after failing to operate as designed during B MS

drain valve troubleshooting on January 11, 2010. As a result, PSEG did not identify and

correct a potential design flaw associated with thermal binding of the MS dump valves,

which was determined to be the cause of the A MS dump valve failing to stroke open on

December 1, 2013, leading to a reactor scram from 100 percent power. PSEGs corrective

actions include a design change to the MS emergency level control system that eliminates

dump valve cycling on high MS level.

The performance deficiency was determined to be 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. The inspectors determined that this finding was of very low safety significance

(Green) using Exhibit 1 of NRC IMC 0609, Appendix A, The Significance Determination

Process (SDP) for Findings At-Power, dated June 19, 2012, because the finding did not

cause both a reactor trip and the loss of mitigation equipment relied upon to transition the

plant from the onset of the trip to a stable shutdown condition (e.g. loss of condenser, loss

of feed water). The inspectors determined that there was no cross-cutting aspect

associated with this finding because the cause of the performance deficiency occurred

more than three years ago, and was not representative of present plant performance.

(Section 1R12)

Green. A self-revealing Green NCV of Technical Specification (TS) 6.8.1.a, Procedures

and Programs, was identified for PSEGs failure to follow procedure MA-AA-1000,

Maintenance Standards and Practices, during the replacement of Bailey logic modules

(LM) associated with the D vital bus (10A404). Specifically, during the spring 2009

Enclosure

4

refueling outage (1R15), PSEG failed to follow a work order (WO) requiring the replacement

of all Bailey logic modules listed in WO 60061175 with new logic modules. As a result, a

logic module (H1PB-1PBXIS-DC652010302) for the D vital bus was not replaced during

1R15, and failed due to age on December 19, 2013, causing a loss of the vital bus and an

entry into the associated 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Technical Specification Action Statement (TSAS) 3.8.3.1

for Onsite Power Distribution Systems. PSEGs corrective actions included replacement of

the failed logic module, performance of an extent of condition inspection to ensure other

similar logic modules and relays were replaced, and reinforcement of proper maintenance

practices with the individuals involved in the completion of WO 60061175.

The performance deficiency was determined to be more than minor because it was

associated with the human 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, not following the work order instructions resulted in an extended

service duration and failure of a component that resulted in a loss of power to the D vital

bus on December 19, 2013. Similarly, this performance deficiency was also similar to

examples 2.g and 4.b of NRC IMC 0612, Appendix E, in that PSEG is required to follow

their procedures per TS 6.8.1, and ultimately led to a safety impact given the failure of the

logic module causing a loss of power to the 10A404 vital bus. The inspectors determined

the finding to be of very low safety significance (Green) in accordance with Exhibit 1 of NRC

IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power,

dated June 19, 2012, because the finding involved the loss of a support system that

contributes to the likelihood of an initiating event (Loss of an AC Bus), but did not affect

mitigation equipment. The inspectors determined that there was no cross-cutting aspect

associated with this finding because the cause of the performance deficiency occurred

more than three years ago, and was not representative of present plant performance.

(Section 1R13)

Green. A self-revealing finding of very low safety significance (Green) was identified when

PSEG failed to ensure that appropriate contingency actions were in place prior to the

performance of A MS emergency level controller tuning as required by WC-AA-105, Work

Activity Risk Management. Specifically, the decision to tune the emergency level controller

without appropriate contingencies in place led to a turbine trip on high A MS level and

subsequent reactor scram on December 5, 2013. PSEGs corrective actions included

conducting performance management with the individuals involved with the tuning evolution

and revising the moisture separator drain tank level tuning procedure to require an

individual at the normal and emergency controllers when performing emergency level

controller tuning.

This finding was more than minor because it was associated with the human 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. The inspectors determined that this

finding was of very low safety significance (Green) using Exhibit 1 of NRC IMC 0609,

Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated

June 19, 2012, because the finding did not cause both a reactor trip and the loss of

mitigation equipment relied upon to transition the plant from the onset of the trip to a stable

shutdown condition (e.g. loss of condenser, loss of feed water). The inspectors determined

that the finding had a cross cutting aspect in the Human Performance area associated with

Work Management, because PSEG personnel did not implement a process of planning,

Enclosure

5

controlling, and executing work activities such that nuclear safety is the overriding priority.

Specifically, technicians were only stationed at the emergency level controller during the

tuning, when having technicians at both controllers would have provided more time to

recover from a high level condition in the A MS, and may have prevented the turbine trip

and subsequent reactor scram on December 5, 2013. [H.5] (Section 4OA3)

Cornerstone: Mitigating Systems

Green. The inspectors identified a Green NCV of TS 6.8.1.a, Procedures because PSEG

procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 could potentially complicate an

internal flooding event and adversely affect assumptions in Hope Creeks flood design.

Specifically, the procedures did not ensure operator response would not communicate the

high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) watertight

rooms and potentially render two safety-significant single train systems inoperable. In

addition to entering the issue into the corrective action program (CAP) as NOTFs

20646334, 20646335 and 20620653586, PSEGs corrective actions include a planned

revision of the annunciator response procedures and issuance of a standing order to the

Operations department staff.

The performance deficiency is more than minor because it was associated with the

procedure quality attribute of the Mitigating Systems cornerstone and adversely affected the

cornerstone objective to ensure the availability, reliability, and capability of systems that

respond to initiating events to prevent undesirable consequences (i.e., core damage).

Specifically, PSEG procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 could

potentially complicate an internal flooding event and adversely affect assumptions in Hope

Creeks flood design, since the procedures did not ensure operator response would not

communicate the HPCI and RCIC watertight rooms and potentially render multiple trains of

safety-related SSCs inoperable. This performance deficiency was also similar to examples

3.j and 3.k of NRC IMC 0612, Appendix E, in that communicating the two watertight rooms

created a reasonable doubt of operability of the HPCI and RCIC systems. PSEG plans to

perform a detailed technical evaluation to evaluate the impact of internal flood propagation

in the HPCI and RCIC rooms. The finding was evaluated in accordance with Exhibits 2 and

4 of NRC IMC 0609, Appendix A, The SDP for Findings At-Power, dated June 19, 2012.

Since opening the watertight door during an internal flooding event could bypass the flood

protection feature and potentially degrade two or more trains of a multi-train system or

function, a detailed risk assessment was performed. The finding was determined to be of

very low safety significance (Green). Since the change in core damage frequency was

sufficiently low, no further evaluation for large early release was required. The inspectors

determined that the finding had a cross cutting aspect in the Human Performance area

associated with Training, in that PSEG did not provide adequate training and ensure

knowledge transfer to maintain a knowledgeable, technically competent workforce and instill

nuclear safety values. Specifically, operator training did not ensure operator response to

internal flooding would not result in communicating two watertight rooms containing safety

significant single-train systems. [H.9] (Section 1R06)

Enclosure

6

Cornerstone: Barrier Integrity

Green. The inspectors reviewed a Green self-revealing NCV of Title 10 of the Code of

Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, Design Control, for

PSEGs failure to effectively implement the design change process. Specifically, PSEGs

design change package (DCP) 4EC-3662 failed to reclassify the purchase classification

(PC) of the main control room (MCR) chiller pressure control valve (PCV) positioner from

non-safety related (PC4) to safety related (PC1). Because of the incorrectly assigned PC,

PSEG did not track the shelf life of replacement positioner diaphragms, which led to the

failure of the A MCR positioner on December 20, 2013. PSEGs corrective actions included

replacement of the failed positioner and changing the purchase classification for the chiller

PCV positioners to safety-related (PC1). Since the implementation of DCP 4EC-3662 in

1997, the DCP procedures have been enhanced to ensure the completion of a purchase

class evaluation of procured materials that are implemented in the design change process.

The inspectors determined that the performance deficiency was more than minor because

it is associated with the design control attribute of the Barrier Integrity cornerstone, and

adversely affected the cornerstone objective of maintaining the radiological barrier

functionality of the control room. In accordance with Exhibit 3 of NRC IMC 0609, Appendix

A, The Significance Determination Process (SDP) for Findings at Power, issued June 19,

2012, the inspectors determined that this finding is of very low safety significance (Green)

because the performance deficiency represents a degradation of only the radiological barrier

function provided for the control room. The inspectors determined that there was no cross-

cutting aspect associated with this finding because the cause of the performance deficiency

occurred more than three years ago, and was not representative of present plant

performance. (Section 4OA3)

Other Findings

A violation of very low safety significance that was identified by PSEG was reviewed by the

inspectors. Corrective actions taken or planned by PSEG have been entered into PSEGs

corrective action program. This violation and corrective action tracking number are listed in

Section 4OA7 of this report.

Enclosure

7

REPORT DETAILS

Summary of Plant Status

Hope Creek Generating Station began the inspection period at full rated thermal power (RTP).

On April 1, 2014, Hope Creek conducted a planned down power to 50 percent of RTP to

support power suppression testing (PST), main turbine valve testing and main condenser water

box cleaning. The unit was returned to full RTP on April 4, 2014. On May 14, 2014, the B

reactor recirculation pump (RRP) speed unexpectedly rose to its maximum value. Operators

took manual control of the pump and reduced the pump speed to less than reactor recirculation

flow TS requirements. On May 23, 2014, operators reduced power to 98 percent to perform B

RRP speed control circuit corrective maintenance. Operators returned the unit to full power on

the same day. On May 28, 2014, Hope Creek conducted a planned down power to 50 percent

of RTP to support main turbine valve testing and main condenser water box cleaning. The unit

was returned to full RTP on May 31, 2014, and remained at or near full RTP for the remainder of

the inspection period.

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection (71111.01 - 2 samples)

.1 Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

The inspectors performed a review of PSEGs readiness for the onset of seasonal high

temperatures. The review focused on the safety auxiliaries cooling system (SACS) and

station service water (SSW) system. The inspectors reviewed the Updated Final Safety

Analysis Report (UFSAR) and TS to determine what temperatures or other seasonal

weather could challenge these systems and to ensure PSEG personnel had adequately

prepared for these challenges. The inspectors reviewed station procedures, including

PSEGs seasonal weather preparation procedure and applicable operating procedures.

The inspectors performed walkdowns of the selected systems to verify that no

unidentified issues existed that could challenge the operability of the systems during hot

weather conditions. Documents reviewed for each section of this inspection report are

listed in the Attachment.

b. Findings

No findings were identified.

.2 External Flooding

a. Inspection Scope

During the week of May 24, 2014, the inspectors performed an inspection of the external

flood protection measures for Hope Creek. The inspectors reviewed procedures, design

documents, and the UFSAR, Chapters 2.4.2, Floods, and 3.4, Water Level (Flood)

Design, which described the design flood levels and protection areas containing safety-

Enclosure

8

related equipment to identify areas that may be affected by flooding. The inspectors

also reviewed the limiting conditions for operations and the surveillance requirements in

TS 3.7.3, Flood Protection. The inspectors review focused on the Hope Creek Unit 1

areas, which protect Unit 1 equipment, that are susceptible to external flooding.

Specifically, the inspectors walked down the south, east and west walls of the reactor

building 102, 77, and 54 elevations. The inspectors inspected the condition of the

walls and ensured that any outside penetrations susceptible to external flooding were

flood protected. The inspectors also inspected the flood doors present in that area,

which are listed in TS Table 3.7.3-1, Perimeter Flood Doors. The inspectors verified

that the doors were in conformance with plant maintenance procedures and drawings.

The inspectors reviewed the preventive maintenance activities performed on these doors

with the responsible system engineer. The inspectors also conducted a walkdown of

these doors to verify that the doors were in conformance with the design basis

requirements in the UFSAR, the TS, and plant procedures and drawings. Additionally,

the inspectors reviewed the abnormal operating procedure, HC.OP-AB.MISC-0001,

Acts of Nature, for mitigating external flooding during severe weather to determine if

PSEG had planned or established adequate measures to protect against external

flooding events.

b. Findings

No findings were identified.

1R04 Equipment Alignment

Partial System Walkdowns (71111.04 - 3 samples)

a. Inspection Scope

The inspectors performed partial walkdowns of the following systems:

RCIC during HPCI booster pump planned maintenance on May 2, 2014

D emergency diesel generator (EDG) area ventilation system tornado dampers

during A EDG planned maintenance the week of May 6, 2014

A, B, and D SSW pumps during C SSW pump planned maintenance on June 2,

2014

The inspectors selected these systems based on their risk-significance relative to the

reactor safety cornerstones at the time they were inspected. The inspectors reviewed

applicable operating procedures, system diagrams, the UFSAR, technical specifications,

work orders, condition reports, and the impact of ongoing work activities on redundant

trains of equipment in order to identify conditions that could have impacted system

performance of their intended safety functions. The inspectors also performed field

walkdowns of accessible portions of the systems to verify system components and

support equipment were aligned correctly and were operable. The inspectors examined

the material condition of the components and observed operating parameters of

equipment to verify that there were no deficiencies. The inspectors also reviewed

whether PSEG staff had properly identified equipment issues and entered them into the

corrective action program for resolution with the appropriate significance

characterization.

Enclosure

9

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Resident Inspector Quarterly Walkdowns (71111.05Q - 5 samples)

a. Inspection Scope

The inspectors conducted tours of the areas listed below to assess the material

condition and operational status of fire protection features. The inspectors verified that

PSEG controlled combustible materials and ignition sources in accordance with

administrative procedures. The inspectors verified that fire protection and suppression

equipment was available for use as specified in the area pre-fire plan, and passive fire

barriers were maintained in good material condition. The inspectors also verified that

station personnel implemented compensatory measures for out of service, degraded, or

inoperable fire protection equipment, as applicable, in accordance with procedures.

Review of compensatory measure fire watch for 10C467 fire protection panel power

supply failure on April 17, 2014

FRH-II-415, Revision 4, Hope Creek Pre-Fire Plan, drywell pad torus area on April

21, 2014

FRH-II-412, Revision 3, Hope Creek Pre-Fire Plan, RCIC pump and turbine room

and electrical equipment room, on May 20, 2014

FRH-II-532, Revision 6, Hope Creek Pre-Fire Plan, lower control equipment room, on

May 23, 2014

FRH-II-542, Revision 9, Hope Creek Pre-Fire Plan, control equipment mezzanine, on

May 23, 2014

b. Findings

No findings were identified.

.2 Fire Protection - Drill Observation (71111.05A - 1 sample)

a. Inspection Scope

The inspectors observed an unannounced fire brigade drill scenario conducted on

April 7, 2014, that involved a fire in the Hope Creek radwaste area, room 3351. The

inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors

verified that PSEG personnel identified deficiencies; openly discussed them in a self-

critical manner at the post-drill debrief; and took appropriate corrective actions as

required. The inspectors evaluated specific attributes as follows:

Proper wearing of turnout gear and self-contained breathing apparatus

Proper use and layout of fire hoses

Employment of appropriate fire-fighting techniques

Sufficient fire-fighting equipment brought to the scene

Effectiveness of command and control

Enclosure

10

Search for victims and propagation of the fire into other plant areas

Smoke removal operations

Utilization of pre-planned strategies

Adherence to the pre-planned drill scenario

Drill objectives met

The inspectors also evaluated the fire brigades actions to determine whether these

actions were in accordance with PSEGs fire-fighting strategies.

b. Findings

No findings were identified.

1R06 Flood Protection Measures (71111.06 - 1 sample)

Internal Flooding Review

a. Inspection Scope

The inspectors reviewed the UFSAR, the site flooding analysis, and plant procedures to

assess susceptibilities involving internal flooding. The inspectors also reviewed the

corrective action program to determine if PSEG identified and corrected flooding

problems and whether operator actions for coping with flooding were adequate. The

inspectors also focused on the A residual heat removal (RHR) pump room (4113), the

B RHR pump room (4109), the C RHR pump room (4114), the HPCI pump and turbine

room (4111), and the RCIC pump and turbine room (4110) to verify the adequacy of

penetration seals located below the flood line, watertight door seals, common drain lines

and sumps, and room level alarms.

b. Findings

Introduction. The inspectors identified a Green NCV of TS 6.8.1.a, Procedures

because PSEG procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 could

potentially complicate an internal flooding event and adversely affect assumptions in

Hope Creeks flood design. Specifically, the procedures did not ensure operator

response would not communicate the HPCI and RCIC watertight rooms and potentially

render two safety-significant single train systems inoperable.

Description. During a review of flood protection measures for the 54 foot elevation of the

reactor building, inspectors questioned whether execution of flooding procedures could

impact the assumption of the flood analysis, which assumes that the A, B, and C

RHR pump rooms, the HPCI pump and turbine room, and the RCIC pump and turbine

room are protected. Specifically, inspectors determined that in response to a room

flooding alarm, the procedures directed operators to enter the rooms to investigate the

flooding and assess the extent of flooding, an action which could allow communication

between two watertight rooms.

Hope Creeks UFSAR section 3.6, Protection Against Dynamic Effects Associated with

the Postulated Rupture of Piping, states in part that, The postulated failure of a

Enclosure

11

moderate energy line can at most affect only the operations of one train of a redundant

safety-related system due to the provisions for physical separation of redundant trains.

Inspectors reviewed procedural actions that would be taken in response to flood alarms

for the HPCI pump and turbine room (Room 4111) and the RCIC pump and turbine room

(Room 4110). The alarm response procedures for the HPCI and RCIC room flood

alarms direct operators to dispatch an equipment operator to the applicable room to

investigate and confirm the floor level alarm and enter HC.OP-EO.ZZ-0103/4, Reactor

Building and Radioactive Release Control. HC.OP-EO.ZZ-0103/4 provides an entry

condition of any reactor building room floor level above 1 inch, which is also the setpoint

of the level alarm. The procedure directs operators to use all available sump pumps and

isolate all systems discharging into the room.

Since the procedures direct operators to investigate and confirm flooding, the inspectors

assessed the ability of operators to enter the room without affecting equipment in an

adjacent room. Each of the ECCS/RCIC rooms are separated by large watertight doors

with no window or portal to monitor conditions on the other side of the door without

opening the door. The inspectors noted that the alarm response procedures for a high

level alarm in the A and B RHR pump rooms direct control room operators to dispatch

an equipment operator to enter the RHR pump rooms at their upper levels (77 foot

elevation) to determine the cause of the alarm. This procedural direction would prevent

flood propagation to the adjacent HPCI and RCIC electrical rooms.

The HPCI and RCIC rooms are located next to one another and are connected by a

watertight door. For a flood in the HPCI room, since both doors to the room open into

the adjacent rooms (i.e., water pressure would aid in opening the door), once the door

was unlatched, the water would force the door open and flood the adjacent room. The

inspectors noted that the alarm response procedures for potential flooding in the HPCI

and RCIC rooms do not provide direction on where to access the HPCI and RCIC rooms

when investigating for a potential flood condition. Therefore, when executing the

procedure to respond to flooding in the HPCI room, operators could propagate an

internal flood to two watertight rooms if they were to access the HPCI room through the

door connecting HPCI and RCIC.

The inspectors interviewed the Hope Creek emergency operating procedure (EOP)

coordinator regarding operator actions in response to indications of a flood in the HPCI

and RCIC rooms and the HC.OP-EO.ZZ-0103/4 procedure. Interviews with the EOP

coordinator indicated that operator knowledge would ensure proper access to the HPCI

and RCIC rooms when investigating a potential flood. However, no operator training

could be found that specified that operators should not access the HPCI and RCIC

rooms using the connecting watertight door when responding to a potential flood

condition.

The inspectors interviewed a senior reactor operator and two equipment operators about

their response to alarms for a potential flood in the HPCI room. The senior reactor

operator did not indicate that he would direct which door to access the HPCI room. The

equipment operators indicated that they would access the HPCI room from the door to

the RCIC room because the floor drains in the RCIC room would better drain any flood

water.

In the absence of further engineering evaluation, there was reasonable doubt of the

operability of the HPCI and RCIC systems. Specifically, internal flood propagation from

Enclosure

12

the design internal flood in the HPCI room could result in a water level that calls the

operability of RCIC into question. PSEG plans to perform a detailed technical evaluation

to evaluate the impact of internal flood propagation in the HPCI and RCIC rooms in

response to the inspectors questions (Order 70167153). PSEG entered the issue into

the CAP as NOTFs 20646334, 20646335, and 20653586. PSEGs corrective actions

include a planned revision of the annunciator response procedures and issuance of a

standing order to the Operations department staff.

Analysis. The inspectors determined that PSEGs failure to provide adequate procedural

guidance to respond to a HPCI/RCIC room flood alarm was a performance deficiency

that was within PSEGs ability to foresee and correct, and should have been prevented.

The performance deficiency is more than minor because it was associated with the

procedure quality attribute of the Mitigating Systems cornerstone, and adversely affected

the cornerstone objective to ensure the availability, reliability, and capability of systems

that respond to initiating events to prevent undesirable consequences (i.e., core

damage). Specifically, PSEG procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022

could potentially complicate an internal flooding event and adversely affect assumptions

in Hope Creeks flood design, since the procedures did not ensure operator response

would not communicate the HPCI and RCIC watertight rooms and potentially render

multiple trains of safety-related SSCs inoperable. This performance deficiency was also

similar to examples 3.j and 3.k of NRC IMC 0612, Appendix E, in that communicating the

two watertight rooms created a reasonable doubt of operability of the RCIC system.

PSEG plans to perform a detailed technical evaluation to evaluate the impact of internal

flood propagation in the HPCI and RCIC rooms. The finding was evaluated in

accordance with Exhibits 2 and 4 of NRC IMC 0609, Appendix A, The SDP for Findings

At-Power, dated June 19, 2012. Since opening the watertight door during an internal

flooding event could bypass the flood protection feature and potentially degrade two or

more trains of a multi-train system or function, a detailed risk assessment was

performed.

The condition was modeled using the Hope Creek SPAR model version 8.18 along with

SAPHIRE version 8.09. As a bounding analysis, the condition was assumed to exist for

greater than one year and the flooding was assumed to require a reactor shutdown,

which results in a plant transient with failure of HPCI and RCIC due to flood impacts.

The flooding initiating event frequency was derived from the Hope Creek Internal Flood

Report, HC-PRA-012, Revision 2. The resulting change in core damage frequency was

substantially less than 1E-7. The dominant sequences included a transient with a failure

to depressurize along with RCIC and HPCI failures. Since the change in core damage

frequency was sufficiently low, no further evaluation for large early release was required.

The inspectors determined that the finding had a cross-cutting aspect in the Human

Performance area associated with Training, in that PSEG did not provide adequate

training and ensure knowledge transfer to maintain a knowledgeable, technically

competent workforce and instill nuclear safety values. Specifically, operator training did

not ensure operator response to internal flooding would not communicate the HPCI and

RCIC watertight rooms and potentially render multiple trains of safety-related SSCs

inoperable. [H.9].

Enforcement. TS 6.8.1.a, Procedures and Programs, requires in part, that written

procedures recommended in Appendix A of Regulatory Guide (RG) 1.33, Revision 2,

shall be established, implemented, and maintained. RG 1.33, Revision 2, Appendix A,

Enclosure

13

Section 5, requires that each safety-related annunciator should have its own written

procedure, which should normally contain the immediate operation action. PSEG

procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 provide direction for operator

response to indications of high level in the HPCI and RCIC rooms. Contrary to the

above, until implementation of Operations Department Standing Order 2014-26 on

May 24, 2014, PSEG procedures HC.OP-AR.ZZ-0006 and HC.OP-AR.ZZ-0022 were

inadequate in that actions directed in the procedures could complicate an internal

flooding event and potentially adversely affect assumptions in Hope Creeks flood

design. In addition to entering the issue into the CAP as NOTFs 20646334, 20646335,

and 20653586, PSEGs corrective actions include a planned revision of the annunciator

response procedures and issuance of a standing order to the Operations department

staff. Because this violation was of very low safety significance (Green), and PSEG

entered this issue into their CAP, this violation is being treated as an NCV, consistent

with Section 2.3.2 of the Enforcement Policy. (NCV 05000354/2014003-01, Inadequate

Procedural Guidance for Responding to an Internal Flooding Event in the HPCI

and RCIC Rooms)

1R11 Licensed Operator Requalification Program (71111.11Q - 2 samples)

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

a. Inspection Scope

The inspectors observed licensed operator simulator training on April 28, 2014, that

included an A RRP trip, reactor water cleanup (RWCU) system leak, loss of main

condenser vacuum, and an anticipated transient without scram. The inspectors

evaluated operator performance during the simulated event and verified completion

of critical tasks, risk significant operator actions, including the use of abnormal and

emergency operating procedures. The inspectors assessed the clarity and effectiveness

of communications, implementation of actions in response to alarms and degrading plant

conditions, and the oversight and direction provided by the control room supervisor. The

inspectors verified the accuracy and timeliness of the emergency classification made by

the shift manager. Additionally, the inspectors assessed the ability of the training staff to

identify and document crew performance problems.

b. Findings

No findings were identified

.2 Quarterly Review of Licensed Operator Performance in the Main Control Room

a. Inspection Scope

The inspectors observed a planned down power to support PST to locate a potential fuel

defect and the conduct main turbine valve testing on April 1, 2014. The inspectors

observed reactivity manipulations to verify that procedure use and crew communications

met established expectations and standards. The inspectors observed pre-job briefings

to verify that the briefings met the criteria specified in OP-AA-101-111-1004 Operations

Standards, Revision 4, and HU-AA-1211, Pre-Job Briefings, Revision 11. Additionally,

the inspectors observed the performance of turbine valve testing surveillance test,

HC.OP-ST.AC-0002, on April 1, 2014, to verify that procedure use, crew

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14

communications, and coordination of activities between work groups similarly met

established expectations and standards.

b. Findings

No findings were identified

1R12 Maintenance Effectiveness (71111.12Q - 3 samples)

a. Inspection Scope

The inspectors reviewed the samples listed below to assess the effectiveness of

maintenance activities on structure, system, or component (SSC) performance and

reliability. The inspectors reviewed corrective action program documents (notifications),

maintenance work orders (orders), and maintenance rule basis documents to ensure

that PSEG was identifying and properly evaluating performance problems within the

scope of the maintenance rule. As applicable, the inspectors verified that the SSC was

properly scoped into the maintenance rule in accordance with 10 CFR 50.65 and verified

that the (a)(2) performance criteria established by PSEG staff was reasonable; for SSCs

classified as (a)(1), the inspectors assessed the adequacy of goals and corrective

actions to return these SSCs to (a)(2); and, the inspectors independently verified that

appropriate work practices were followed for the SSCs reviewed. Additionally, the

inspectors ensured that PSEG staff was identifying and addressing common cause

failures that occurred within and across maintenance rule system boundaries.

A MS drain and dump valve functional failure determinations for December 1 and 5,

2013, scrams (Order 70161698)

Salem Unit 3 (gas turbine generator) scoping in Hope Creek maintenance rule

program (NOTF 20502118)

RCIC nuclear management and control leak detection system card failure and

replacement on May 23, 2014 (Order 60113250)

b. Findings

Introduction. A self-revealing finding of very low safety significance (Green) was

identified for PSEGs failure to evaluate an identified deficiency in accordance with

PSEG procedure LS-AA-125, Corrective Action Program. Specifically, PSEG failed to

take self-recommended actions in NOTF 20447050 to evaluate the B MS dump valve

performance after failing to operate as designed during B MS drain valve trouble-

shooting on January 11, 2010. As a result, PSEG did not identify and correct a potential

design flaw associated with thermal binding of the MS dump valves, which was

determined to be the cause of the A MS dump valve failing to stroke open on

December 1, 2013, causing a reactor scram from 100 percent power.

Description. Hope Creek utilizes two horizontal non-reheat MS vessels that remove

moisture in the steam from the high pressure turbine exhaust before it enters the low

pressure turbine which prevents damage to the low pressure turbines. The condensate

that is collected in the MS is drained to the 5A, 5B, and 5C feed water heaters where it

eventually drains to the condenser. If the water level in the MS becomes too high and

the normal MS level control drain valves are not able to drain it, then the dump valve

opens draining the water in the MS directly to the condenser.

Enclosure

15

At 6:07 am on December 1, 2013, while operating at 100 percent power, the A MS

normal drain level reached a maximum allowed value of 70 percent allowing the MS

dump valve to cycle to control level. After six minutes (~15 cycles of the A dump valve

going open and shut) of successfully controlling MS level in the dump valve range, the

A MS dump closed and failed to re-open causing high level in the A MS, a turbine trip

and a reactor scram.

On December 5, 2013, a second reactor scram occurred at 75 percent power during A

MS dump valve tuning with the normal A MS drain valves failed closed to support

emergency level controller tuning. The A MS dump valve again failed to stroke open

when expected causing high MS level.

PSEG conducted a root cause evaluation (Order 70161698) to determine the cause of

the A MS drain and dump valve issues leading to the December 1 and December 5,

2013, scrams. PSEG determined that the A MS dump valve experienced thermal

binding because both PSEG and the valve manufacturer did not recognize the potential

for these valves to experience thermal binding. The results from PSEGs evaluation

concluded that the A MS dump valve design is susceptible to internal binding due to

differential expansion, resulting in the valve plug sticking in the valve cage.

During the timeline review for the A MS root cause evaluation, PSEG discovered that

the B MS dump valve did not open as expected on January 11, 2010, when trouble-

shooting B MS drain valve control issues. The dump valve had cycled multiple times

prior to PSEG removing air to reopen the B MS dump valve when MS level was rising

during drain valve control troubleshooting and the dump valve did not open for 12

minutes. The condition of the B MS dump valve not operating as expected was

documented under NOTF 20447050. The NOTF documented that the B MS dump

valve had cycled several times prior to the failure to open and recommended that the

B MS dump valve performance be evaluated and implement corrective actions as

necessary. This NOTF was not properly allocated to the equipment apparent cause

evaluation (EQACE) that was created (Order 70105948) to evaluate the B MS drain

valve control troubleshooting and therefore was never evaluated. PSEG created NOTF

20640526 to document the missed opportunity to troubleshoot B MS dump valve

performance and identify the thermal binding issue when the valve is cycled at normal

reactor power and pressure.

LS-AA-125, Corrective Action Program, Revision 12, Section 3.5.6 (effective on

January 11, 2010) states to ensure that the corrective action identified have been

agreed upon by the assignees and that the corrective actions are appropriately entered

into the CR database. Based on this information, the inspectors concluded that PSEG

failed to ensure that EQACE 70105948 addressed the identified issue in NOTF

20447050 recommending that the B MS dump valve performance on January 11, 2010,

be evaluated and corrected. PSEG has entered the above concerns into the CAP as

20640526. PSEGs corrective actions include a design change to the MS emergency

level control system that eliminates dump valve cycling on high MS level.

Analysis. PSEGs failure to ensure evaluations addressed identified issues in

accordance with PSEG procedure LS-AA-125, Corrective Action Program, was a

performance deficiency which was reasonably within PSEGs ability to foresee and

correct and should have been prevented. The performance deficiency was determined

Enclosure

16

to be 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. The inspectors

determined that this finding was of very low safety significance using Exhibit 1 of NRC

IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-

Power, dated June 19, 2012, because the finding did not cause both a reactor trip and

the loss of mitigation equipment relied upon to transition the plant from the onset of the

trip to a stable shutdown condition (e.g. loss of condenser, loss of feed water). The

inspectors determined that there was no cross-cutting aspect associated with this finding

because the cause of the performance deficiency occurred more than three years ago,

and was not representative of present plant performance.

Enforcement. This finding does not involve enforcement action because no violation of a

regulatory requirement was identified. Since this finding does not involve a violation and

is of very low safety significance (Green), it is identified as a FIN. (FIN

05000354/2014003-02, Failure to Evaluate an Identified Issue with the Moisture

Separator Dump Valve Performance)

1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13 - 5 samples)

a. Inspection Scope

The inspectors reviewed station evaluation and management of plant risk for the

maintenance and emergent work activities listed below to verify that PSEG performed

the appropriate risk assessments prior to removing equipment for work. The inspectors

selected these activities based on potential risk significance relative to the reactor safety

cornerstones. As applicable for each activity, the inspectors verified that PSEG

personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the

assessments were accurate and complete. When PSEG performed emergent work, the

inspectors verified that operations personnel promptly assessed and managed plant risk.

The inspectors reviewed the scope of maintenance work and discussed the results of

the assessment with the stations probabilistic risk analyst to verify plant conditions were

consistent with the risk assessment. The inspectors also reviewed the technical

specification requirements and inspected portions of redundant safety systems, when

applicable, to verify risk analysis assumptions were valid and applicable requirements

were met.

Unplanned de-energization and loss of the D vital bus on December 19, 2013

Planned high risk activity to perform main turbine combined intermediate valve

testing on April 2, 2014

Planned high risk activity to perform power suppression testing to locate a fuel defect

on April 2, 2014

B RRP isolator replacement due to un-demanded speed changes on May 22, 2014

B RHR system and F filtration, recirculation, and ventilation system recirculation

fan planned maintenance on June 11, 2014

b. Findings

Introduction. A Green self-revealing NCV of TS 6.8.1.a, Procedures and Programs,

was identified for PSEGs failure to follow procedure MA-AA-1000, Maintenance

Enclosure

17

Standards and Practices, during the replacement of Bailey logic modules associated

with the D vital bus (10A404). Specifically, during the spring 2009 refueling outage

(1R15), PSEG failed to follow a WO requiring the replacement of all Bailey logic modules

listed in WO 60061175 with new logic modules. As a result, a logic module (H1PB-

1PBXIS-DC652010302) for the 10A404 vital bus was not replaced during 1R15, and

failed due to age on December 19, 2013, causing a loss of the 10A404 bus and an entry

into the associated 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> TSAS 3.8.3.1 for Onsite Power Distribution Systems.

Description. The PSEG Class 1E AC power distribution system provides a reliable

source of power for all Class 1E loads and distributes power at 4.16 kilovolt (kV), 480

volt (V), and 208/120 V. The system is divided into four independent channels and each

channel supplies power to loads in its own load group. Each of the four vital buses is

provided with connections to the two offsite power sources through two in-feed breakers

(40401 and 40408). One of these breakers is designated as the normal source and the

other as the alternate source for the bus. In addition to these two connections to offsite

power, each of the vital buses is connected to its dedicated EDG. These EDGs serve as

the standby electric power source for their respective channels in case both the normal

and alternate power supplies to a bus are lost.

At 3:11 pm on December 19, 2013, PSEG was performing a normally planned swap of

the 10A404 in-feed breakers from 40408 to 40401, when both in-feed breakers tripped

open and de-energized the 10A404 bus. PSEG stabilized the plant, entered the

associated 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> TSAS 3.8.3.1, conducted troubleshooting, performed component

replacements, and returned the 10A404 vital bus to service at 5:01 pm on December 19,

2013.

Following the restoration of the 10A404 vital bus on December 19, 2013, PSEG

conducted an EQACE documented under order 70162013. This EQACE determined

that the apparent cause of the 10A404 vital bus loss was an age-related failure of a logic

module (H1PB-1PBXIS-DC652010302) that was not replaced, but mistakenly

documented as being replaced in 2009 per WO 60061175. PSEG determined that the

independent peer check verification performed for both the LM removal and LM

installation failed to ensure that the serial number for the removed LM (H1PB-1PBXIS-

DC652010302) was not reinstalled into the system. Because this logic module was not

replaced in 2009, and remained in the system for 4 years past its vendor recommended

lifetime of 20 years, PSEG determined that it failed due to age and could not provide an

output to allow the 10A404 bus 40408 in-feed breaker to trip normally during the planned

in-feed breaker swap on December 19, 2013.

The inspectors reviewed PSEGs procedures for conducting the 10A404 in-feed breaker

swaps, operations narrative logs, and the completed EQACE 70162013 for the

December 19, 2013, event. PSEG procedure MA-AA-1000, Section 3.0, Maintenance

Standards and Practices, states in part, that all work on plant SSCs will be performed

using appropriate documentation such as work orders, notifications, or applicable

troubleshooting process control forms. Both the current revision of this procedure

(Revision 14) and the revision in use during 1R15 (Revision 7) have this language

requiring all work be performed in accordance with the appropriate documentation.

The inspectors determined that PSEG failed to follow this procedure by not complying

with WO 60061175 for the replacement of Bailey cards for the 10A404 in-feed breakers

during 1R15. This WO stated, in part, to Replace all Logic Modules listed with new

modules, and the list contained included the 10A404 in-feed breaker logic module

Enclosure

18

(H1PB-1PBXIS-DC652010302 LM 4.16 KV MAIN BKR 52-40401). Contrary to this,

PSEGs review of the serial number on the failed logic module and WO 60061175

showed that the original logic module was re-installed following its removal during the

conduct of maintenance. As part of the extent of condition for PSEGs EQACE, a review

of all other similar logic modules found them replaced as documented.

PSEG initiated NOTF 20639519 and EQACE 70162013 in the CAP to replace the failed

logic module, identify other similar logic modules and relays that may not have been

replaced or may not have an associated maintenance plan, and reinforce proper

maintenance practices to the individuals involved in the completion of WO 60061175.

Analysis. PSEGs failure to follow procedure MA-AA-1000 for Maintenance Standards

and Practices during the replacement of a Bailey logic module associated with the

10A404 vital bus represented a performance deficiency that was reasonably within

PSEGs ability to foresee and correct and should have been prevented. The

performance deficiency was determined to be more than minor because it was

associated with the human 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, not following the work order instructions resulted in an

extended service duration and failure of a component that resulted in a loss of power to

the D vital bus on December 19, 2013. Similarly, this performance deficiency was also

similar to examples 2.g and 4.b of NRC IMC 0612 Appendix E, in that PSEG is required

to follow its procedures per TS 6.8.1, and ultimately led to a safety impact given the

failure of the logic module causing a loss of power to the 10A404 vital bus. The

inspectors determined the finding to be of very low safety significance (Green) in

accordance with Exhibit 1 of NRC IMC 0609, Appendix A, The Significance

Determination Process for Findings At-Power, dated June 19, 2012, because the finding

involved the loss of a support system that contributes to the likelihood of an initiating

event (Loss of an AC Bus), but did not affect mitigation equipment.

The inspectors determined that there was no cross-cutting aspect associated with this

finding because the cause of the performance deficiency occurred more than three years

ago, and was not representative of current plant performance.

Enforcement. TS 6.8.1.a, Procedures and Programs, requires in part, that written

procedures recommended in Appendix A of RG 1.33, Revision 2, shall be established,

implemented, and maintained. Section 9.a of RG 1.33, Revision 2, Appendix A, requires

that maintenance that can affect the performance of safety-related equipment should be

properly preplanned and performed in accordance with written procedures, documented

instructions, or drawings appropriate to the circumstances. Section 3.0 of PSEG

procedure MA-AA-1000, Maintenance Standards and Practices, states in part, that all

work on plant SSCs will be performed using appropriate documentation such as work

orders, notifications, or applicable troubleshooting process control forms.

Contrary to the above, on April 16, 2009, PSEG failed to follow this procedure during the

replacement of a Bailey logic module associated with the 10A404 vital bus. Specifically,

PSEG failed to follow WO 60061175 which required the replacement of all Bailey logic

modules listed in the WO with new logic modules. As a result, a logic module for the

10A404 vital bus was not replaced in 2009, and failed due to age on December 19,

2013, causing a loss of the 10A404 bus and an entry into the associated 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> TSAS

Enclosure

19

3.8.3.1 for Onsite Power Distribution Systems. PSEGs corrective actions included

replacement of the failed logic module, performance of an extent of condition inspection

to ensure other similar logic modules and relays were replaced, and reinforcement of

proper maintenance practices with the individuals involved in the completion of WO

60061175. Because this violation was of very low safety significance (Green) and was

entered into PSEGs CAP as NOTF 20639519 and EQACE 70162013, the violation is

being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000354/2014003-03, Failure to Follow Procedure Resulting in the Loss of a

Vital 4kV Bus)

1R15 Operability Determinations and Functionality Assessments (71111.15 - 5 samples)

a. Inspection Scope

The inspectors reviewed operability determinations for the following degraded or non-

conforming conditions:

Minimum Allowable Wall Thickness Evaluation of 4 D RHR Piping (Order

80108395)

C EDG operability with lost parts potentially in the main lube oil sump on April 7,

2014 (NOTF 20645519)

Standby liquid control event report #49909 retraction on April 15, 2014 (NOTFs

20647199 and 20643229)

B RRP undemanded speed changes on May 14, 2014 (NOTF 20651102)

Revision 3 of Masterpact Breaker failure analysis operability evaluation on May 28,

2014 (NOTF 20652187 and Order 70163760)

The inspectors selected these issues based on the risk significance of the associated

components and systems. The inspectors evaluated the technical adequacy of the

operability determinations to assess whether technical specification operability was

properly justified and the subject component or system remained available such that no

unrecognized increase in risk occurred. The inspectors compared the operability and

design criteria in the appropriate sections of the technical specifications and UFSAR to

PSEGs evaluations to determine whether the components or systems were operable.

Where compensatory measures were required to maintain operability, the inspectors

determined whether the measures in place would function as intended and were

properly controlled by PSEG. The inspectors determined, where appropriate,

compliance with assumptions in the evaluations.

b. Findings

No findings were identified.

Enclosure

20

1R18 Plant Modifications (71111.18 - 2 samples)

.1 Temporary Modifications

a. Inspection Scope

The inspectors reviewed the temporary modification listed below to determine whether

the modification affected the safety functions of systems that are important to safety.

The inspectors reviewed 10 CFR 50.59 documentation to verify that the temporary

modification did not degrade the design bases, licensing bases, and performance

capability of the affected systems.

Temporary Configuration Change Package (TCCP) 4HT-14-005 - Temporary

Repairs to the Condensate Storage Tank Dike Drain Line

b. Findings

No findings were identified.

.2 Permanent Modifications

a. Inspection Scope

The inspectors evaluated a modification to the RWCU system implemented by DCP

80111754, Masterpact Breaker Add Aux Contact with Close Coil. This DCP wires an

existing breaker auxiliary contact in series with the internal close coil to allow the close

coil to be de-energized after the breaker has closed rather than be continuously

energized. The existing configuration with the breaker close coil continuously energized

is allowing an intermittent failure of these breakers where they lock up and fail to re-

close when required per design. The inspectors verified that the design bases, licensing

bases, and performance capability of the affected systems were not degraded by the

modification. In addition, the inspectors reviewed modification documents associated

with the upgrade and design change, including the breaker operation. The inspectors

also reviewed revisions to the control room alarm response procedure and interviewed

engineering and operations personnel to ensure the procedure could be reasonably

performed.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing (71111.19 - 7 samples)

a. Inspection Scope

The inspectors reviewed the post-maintenance tests for the maintenance activities listed

below to verify that procedures and test activities ensured system operability and

functional capability. The inspectors reviewed the test procedure to verify that the

procedure adequately tested the safety functions that may have been affected by the

maintenance activity, that the acceptance criteria in the procedure was consistent with

the information in the applicable licensing basis and/or design basis documents, and that

the procedure had been properly reviewed and approved. The inspectors also

Enclosure

21

witnessed the test or reviewed test data to verify that the test results adequately

demonstrated restoration of the affected safety functions.

HPCI oil supply pressure gauge replacement on October 10, 2013 (Order 60113238)

B control room chilled water pressure control valve positioner and diaphragm

replacement on April 23, 2014 (Order 60116090)

10C467 fire protection panel power supply replacement on May 9, 2014 (Order

30269527)

B RRP pump speed controller card replacements on May 22, 2014 (Order

60117312)

RCIC nuclear management and control leak detection system card replacement on

May 23, 2014 (Order 60113250)

Service air compressor oil leak repair on June 5, 2014 (Order 60117447)

B RHR system relay replacements on June 11, 2014 (Orders 30098613 and

30098617)

b. Findings

No findings were identified.

1R22 Surveillance Testing (71111.22 - 9 samples)

a. Inspection Scope

The inspectors observed performance of surveillance tests and/or reviewed test data

of selected risk-significant SSCs to assess whether test results satisfied technical

specifications, the UFSAR, and PSEG procedure requirements. The inspectors verified

that test acceptance criteria were clear, tests demonstrated operational readiness and

were consistent with design documentation, test instrumentation had current calibrations

and the range and accuracy for the application, tests were performed as written, and

applicable test prerequisites were satisfied. Upon test completion, the inspectors

considered whether the test results supported that equipment was capable of performing

the required safety functions. The inspectors reviewed the following surveillance tests:

HC.OP-ST.AC-0002, Turbine Valve Testing quarterly surveillance on April 1, 2014

HC.OP-ST.KJ-0003, Emergency Diesel Generator 1CG400 Operability Test on

April 7, 2014

HC.OP-IS.BJ-0001, HPCI Main and Booster Pump Set - 0P204 and 0P217 -

In-service Test on April 9, 2014 (in-service test)

HC.MD-ST.PB-0003, Class 1E 4.16 kV Feeder Degraded Voltage Monthly

Instrumentation Channel Functional Testing of the B vital bus on April 15, 2014

HC.OP-IS.BC-0004, DP202, D Residual Heat Removal Pump In-Service Test on

April 22, 2014 (in-service test)

HC.OP-DL.ZZ-0026, Drywell floor drain leakage monitoring on May 1, 2014 (RCS

leakage)

HC.FP-ST.KC-0009, Diesel Driven Fire Pump Operability Test on May 6, 2014

HC.OP-IS.BC-0002, CP202, C Residual Heat Removal Pump In-Service Test on

June 25, 2014 (in-service test)

HC.OP-ST.KJ-0001, Emergency Diesel Generator 1AG400 Operability Test on

June 30, 2014

Enclosure

22

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation (71114.06 - 1 sample)

Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine PSEG emergency drill on June 24,

2014 to identify any weaknesses and deficiencies in the classification, notification, and

protective action recommendation development activities. The inspectors observed

emergency response operations in the technical support center to determine whether the

event classification, notifications, and protective action recommendations were

performed in accordance with procedures. The inspectors also attended the drill critique

to compare inspector observations with those identified by PSEG staff in order to

evaluate PSEGs critique and to verify whether the PSEG staff was properly identifying

weaknesses and entering them into the corrective action program.

b. Findings

No findings were identified.

4. OTHER ACTIVITIES

4OA1 Performance Indicator (PI) Verification (71151)

Reactor Coolant System (RCS) Specific Activity and RCS Leak Rate (2 samples)

a. Inspection Scope

The inspectors reviewed PSEGs submittal for the RCS specific activity and RCS leak

rate performance indicators for the period of April 1, 2013, through March 31, 2014. To

determine the accuracy of the performance indicator data reported during those periods,

the inspectors used definitions and guidance contained in NEI Document 99-02,

Regulatory Assessment Performance Indicator Guideline, Revision 7. The inspectors

also reviewed RCS sample analysis and control room logs of daily measurements of

RCS leakage, and compared that information to the data reported by the performance

indicator. Additionally, the inspectors observed chemistry personnel taking and

analyzing an RCS sample.

b. Inspection Findings

No findings were identified.

Enclosure

23

4OA2 Problem Identification and Resolution (71152 - 1 sample)

.1 Routine Review of Problem Identification and Resolution Activities

a. Inspection Scope

As required by Inspection Procedure 71152, Problem Identification and Resolution, the

inspectors routinely reviewed issues during baseline inspection activities and plant

status reviews to verify that PSEG entered issues into the corrective action program at

an appropriate threshold, gave adequate attention to timely corrective actions, and

identified and addressed adverse trends. In order to assist with the identification of

repetitive equipment failures and specific human performance issues for follow-up, the

inspectors performed a daily screening of items entered into the corrective action

program and periodically attended condition report screening meetings.

b. Findings

No findings were identified.

.2 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a semi-annual review of site issues, as required by Inspection

Procedure 71152, Problem Identification and Resolution, to identify trends that might

indicate the existence of more significant safety issues. In this review, the inspectors

included repetitive or closely-related issues that may have been documented by PSEG

outside of the corrective action program, such as trend reports, performance indicators,

major equipment problem lists, system health reports, maintenance rule assessments,

and maintenance or corrective action program backlogs. The inspection also reviewed

PSEGs corrective action program database for the period of January 2014 to May 2014

to assess the notifications written as well as individual issues identified during the NRCs

daily condition report review (Section 4OA2.1). The inspectors reviewed the Hope

Creek station performance improvement integrated matrix (PIIM), conducted under

procedure LS-AA-125-1006, Performance Improvement Integrated Matrix, to verify that

PSEG personnel were appropriately evaluating and trending adverse conditions in

accordance with applicable procedures.

b. Findings and Observations

No findings were identified during this trend review.

The inspectors noted that PSEG personnel identified the following trends and entered

them into the corrective action program: an adverse trend in Appendix J leakage

(NOTFs 20632747, 20632748, 20632749); an adverse trend in design change package

quality (NOTFs 20642767 and 20644539); and an adverse trend in critical component

failures (NOTF 20638889). The inspectors also reviewed the 2013 third cycle Hope

Creek PIIM and the performance improvement action plan developed to improve station

performance in the areas of equipment reliability, decision making, and risk

management.

Enclosure

24

The inspectors noted a trend in the stations failure to perform cross-system

maintenance rule screenings:

When the feedwater crosstie valve (AE-HV-4144) failed, it was screened as not

a functional failure against the feedwater system. The condition was not

screened against the feedwater sealing functions of HPCI and RCIC.

The DD-411 battery room temperature was found above acceptance criteria. A

maintenance rule functional failure screening was performed for the functions of

the 1E 125 volt direct current (DC) system, but not for the auxiliary building

diesel area ventilation system.

As found setpoint failures of safety relief valves were screened against the

automatic depressurization system functions, but not against any of the main

steam system functions.

The inspectors determined this observation was not more than minor in accordance with

IMC 0612, because the observations did not result in any of the systems requiring

additional monitoring per 10 CFR 50.65(a)(1).

Based on the review of PSEGs trending, the inspectors concluded that PSEG was

appropriately identifying and entering issues into the corrective action program,

adequately evaluating the identified issues, and appropriately identifying adverse trends

before they become more safety significant problems.

4OA3 Follow-Up of Events and Notices of Enforcement Discretion (71153 - 6 samples)

.1 Plant Events

a. Inspection Scope

For the plant event listed below, the inspectors reviewed plant parameters, reviewed

personnel performance, and evaluated performance of mitigating systems. The

inspectors communicated the plant events to appropriate regional personnel, and

compared the event details with criteria contained in IMC 0309, Reactive Inspection

Decision Basis for Reactors, for consideration of potential reactive inspection activities.

As applicable, the inspectors verified that PSEG made appropriate emergency

classification assessments and properly reported the event in accordance with 10 CFR

Parts 50.72 and 50.73. The inspectors reviewed PSEGs follow-up actions related to the

events to assure that PSEG implemented appropriate corrective actions commensurate

with their safety significance.

B RRP un-demanded speed change due to a failure in the speed controller, causing

a momentary increase in reactor power above the thermal power limit on May 15,

2014 (NOTF 20651102)

b. Findings

No findings were identified.

.2 Event Notification (EN) 49909 Retraction, Standby Liquid Control System (SLC) Sample

Concentration Outside Technical Specification Limits

Enclosure

25

At 10:27 pm on March 12, 2014, PSEG was in the process of returning the SLC system

to service following planned maintenance on the B SLC pump when the MCR received

a SLC tank high level alarm (>4880 gallons). The MCR informed the equipment

operator conducting the SLC system restoration of the unexpected SLC tank high level

alarm and the operator closed a valve that had just been opened, which stopped the rise

in SLC storage tank level at 4926 gallons. PSEGs sample analysis of the SLC system

tank yielded a sodium pentaborate concentration outside the TS limits, rendering both

subsystems inoperable. The concentration was found to be at 13.598% by weight,

below the required concentration of 13.6% by weight. As part of the corrective actions,

PSEG restored the concentration to within TS limits and conducted an apparent cause

evaluation.

This condition was reported under 10 CFR 50.72(b)(3)(v)(D) on March 13, 2014, as

a condition that could have prevented the fulfillment of a safety function required to

mitigate the consequences of an accident (EN 49909). On April 14, 2014, PSEG

retracted EN 49909 stating that a subsequent review of the analytical data has

determined that the SLC tank sample met the TS requirement for operability (13.6

weight percent) and therefore, there was no reportable condition. The inspectors

reviewed PSEGs EN and EN retraction, apparent cause evaluation report, supporting

documentation including multiple NOTFs and technical evaluation (Order 70166989),

station procedures, and interviewed several members of station staff and management

regarding the event. No findings were identified during this review.

.3 (Closed) Licensee Event Report (LER) 05000354/2013-007-00, As-Found Values for

Safety Relief Valve Lift Set Points Exceed Technical Specification Allowable Limit

On November 22, 2013, PSEG received test results indicating that the as-found lift

setpoints for 5 of 14 main steam safety relief valves (SRVs) failed to open within the

required TS actuation pressure setpoint tolerance. TS 3.4.2.1 provides an allowable

pressure band of +/- 3 percent for each SRV. All five of the SRVs opened above the

required pressure band. PSEG determined that the apparent cause for the A, D, F,

K, and L SRV setpoint failures was corrosion bonding/sticking between the mating

surfaces of the pilot disc. These issues were placed into the CAP as NOTF 20631351.

The pilot assembly for each of the 14 SRVs has been replaced with a fully tested spare

assembly. Additionally, this LER stated PSEGs corrective actions include plans to

replace the currently installed SRVs with a new design that eliminates setpoint drift

events exceeding TS requirements and improves SRV reliability. Although this LER

reports the inoperability of five SRVs, this event did not result in a loss of system safety

function based on engineering analyses. These analyses showed that the SRVs would

have functioned to prevent a reactor vessel over-pressurization and that postulated

piping stresses would not exceed allowable limits. The enforcement aspects of this

finding are discussed in Section 4OA7. This LER is closed.

.4 (Closed) LER 05000354/2013-008-00 and LER 05000354/2013-008-01, Automatic

Actuation of the Reactor Protection System Due to a Main Turbine Trip

On December 1, 2013, Hope Creek Unit 1 automatically scrammed from 100 percent

rated thermal power due to a main turbine trip. The main turbine trip was due to high

level in the A MS. As a result of the scram, both RRPs tripped and three SRVs opened.

The plant was stabilized in hot shutdown, Operational Condition 3.

Enclosure

26

This condition is reportable under 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted

in an automatic actuation of the reactor protection system. The inspectors reviewed

PSEGs LER and LER revision, root cause evaluation report (Order 70161698),

supporting documentation, station procedures, and interviewed several members of

station staff and management regarding the event. One finding was identified and is

discussed in Section 1R12 of this report. These LERs are closed.

.5 (Closed) LER 05000354/2013-009-00 and LER 05000354/2013-009-01, Automatic

Actuation of the Reactor Protection System Due to a Main Turbine Trip

a. Inspection Scope

On December 5, 2013, during tuning of the A MS emergency level controller, the

reactor automatically scrammed from 75 percent power due to a main turbine trip.

During the tuning activities, the A MS dump valve cycled repeatedly and subsequently

failed closed, resulting in high level in the A MS and subsequent turbine trip. The

automatic reactor scram resulted in a trip of both RRPs, as designed. During the

recovery of the RRPs, the digital electro-hydraulic control system was mis-operated

which caused the turbine bypass valves to cycle. This caused reactor level to swell

above Level 8 then shrink below Level 3, resulting in a second actuation of the reactor

protection system.

This condition is reportable under 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in

an automatic actuation of the reactor protection system. The inspectors reviewed

PSEGs LER, root cause evaluation report (Order 70161698), supporting documentation,

station procedures, and interviewed several members of station staff and management

regarding the event. Two findings were identified and are discussed below. These

LERs are closed.

b. Findings

.1 Failure to Use Approved Method of Post-Scram Reactor Pressure Control

The mis-operation of the digital electro-hydraulic control system following the reactor

scram on December 5, 2013, has been previously evaluated. A self-revealing Green

NCV of TS 6.8.1.a (NCV 05000354/2014002-06) for Failure to Use Approved Method of

Post-Scram Reactor Pressure Control is documented in NRC Inspection Report

05000354/2014002.

.2 Inadequate Implementation of Contingency Actions During Moisture Separator

Emergency Level Controller Tuning

Introduction. A self-revealing finding of very low safety significance (Green) was

identified when PSEG failed to ensure that contingency actions were appropriate for

the activity being performed prior to A MS emergency level controller tuning on

December 5, 2013. Specifically, the decision to tune the emergency level controller

without appropriate contingencies in place led to a turbine trip and subsequent reactor

scram on high A MS level.

Description. On December 5, 2013, maintenance technicians were tuning the A MS

emergency level controller following its replacement in accordance with PSEG

procedure HC.IC-LC.AF-00007, Moisture Separator Drain Tank Level Tuning.

Enclosure

27

During the tuning evolution, the A MS dump valve failed closed, causing a turbine trip

due to high A MS level and automatic reactor scram.

The moisture separators improve the quality of the steam from the high pressure turbine

exhaust, and minimize erosion of the low pressure turbines due to excessively moist

steam. The levels in the A and B MSs are maintained through a normal drain path

through three drain valves on each MS to the #5 feedwater heaters. The position of the

drain valves is controlled by the MS normal level controller. When the level in the MS

is above the normal drain control level, a high level emergency dump valve (one per MS)

directs flow from the MS to the condenser. The emergency level dump valve is normally

closed and is controlled by the MS emergency level controller.

PSEG procedure HC.IC-LC.AF-00007, Moisture Separator Drain Tank Level Tuning,

raises MS level into the emergency dump range to tune the emergency level controller

by manually closing the normal drain valves. This evolution was evaluated and

determined to be a high risk evolution in accordance with WC-AA-105, Work Activity

Risk Management. A risk management plan was developed for the high risk activity.

WC-AA-105 requires that the risk management plan be presented for approval by a risk

management challenge board prior to performance of the high risk activity.

This plan was initially reviewed by a risk management challenge board and was not

approved. An action from the risk management challenge board included ensuring that

during the tuning, one person is to be stationed at the normal level controller and one at

the emergency level controller. The risk management challenge board directed that both

people would need to be prepared to respond in case the MS drain tank level rises

during the tuning evolution. A second risk management challenge board was held to

review the risk management plan. The contingency action for stationing maintenance

technicians at each controller was not implemented.

The second challenge board failed to ensure that contingency actions were appropriate

for the activity being performed as specified by PSEG procedure WC-AA-105. A

heightened level of awareness (HLA) brief was performed prior to performance of the

high risk activity. Having a maintenance technician at the normal and emergency level

controllers was discussed. Contrary to the direction of the risk management challenge

board and the HLA brief, a maintenance technician was not stationed at the normal level

controller during the tuning of the emergency level controller. PSEGs corrective actions

included conducting performance management with the individuals involved with the

tuning evolution, and revising the moisture separator drain tank level tuning procedure to

require an individual at the normal and emergency controllers when performing

emergency level controller tuning.

Analysis. The inspectors determined that PSEGs failure to ensure that the contingency

actions were appropriate for the activity being performed prior to A MS emergency

level controller tuning was a performance deficiency that was within PSEGs ability to

foresee and correct, and should have been prevented. Specifically, a contingency action

specified by the risk management challenge board and the HLA brief prior to the high

risk tuning activity was not performed. As a result, the technicians were unable to

restore air to the drain valves in time to reduce the A MS level before the high level

caused a turbine trip and reactor scram.

Enclosure

28

This finding was more than minor because it was associated with the human

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. The

inspectors determined that this finding was of very low safety significance (Green) using

Exhibit 1 of NRC IMC 0609, Appendix A, The Significance Determination Process

(SDP) for Findings At-Power, dated June 19, 2012, because the finding did not cause

both a reactor trip and the loss of mitigation equipment relied upon to transition the plant

from the onset of the trip to a stable shutdown condition (e.g. loss of condenser, loss of

feed water). The inspectors determined that the finding had a cross-cutting aspect in the

Human Performance area associated with Work Management, because PSEG

personnel did not implement a process of planning, controlling, and executing work

activities such that nuclear safety is the overriding priority. Specifically, technicians were

only stationed at the emergency level controller during the tuning, when having

technicians at both controllers would have provided more time to recover from a high

level condition in the A MS, and may have prevented the turbine trip and subsequent

reactor scram on December 5, 2013. (H.5)

Enforcement. This finding was not a violation of NRC requirements because no violation

of regulatory requirements was identified. Since this finding does not involve a violation

and is of very low safety significance (Green), it is identified as a FIN. (FIN

05000354/2014003-04, Inadequate Implementation of Contingency Actions During

Moisture Separator Emergency Level Controller Tuning)

.6 (Closed) LER 05000354/2013-010-00, Loss of Both Main Control Room Chillers

a. Inspection Scope

On December 20, 2013, at 1:03 pm, while the B MCR chiller was out of service in

support of maintenance, the A MCR chiller was manually secured due to excessive

fluctuations in load. The TSAS (TS 3.7.2.2 Action a.2) for both MCR air conditioning

subsystems inoperable was entered. At 9:20 pm, the B control area ventilation train

and chiller were placed in service for post maintenance testing, returned to an operable

status, and the TS action statement was exited.

This condition is reportable under 10 CFR 50.73(a)(2)(v)(D) as an event or condition that

could have prevented the fulfillment of the safety function of structures or systems that

are needed to mitigate the consequences of an accident. The inspectors reviewed

PSEGs LER and LER revision, apparent cause evaluation (Order 70162284),

supporting documentation, station procedures, and interviewed several members of

station staff and management regarding the event. One finding was identified and is

discussed below. These LERs are closed.

b. Findings

Introduction. A Green self-revealing NCV of 10 CFR 50, Appendix B, Criterion III,

Design Control, was identified for PSEGs failure to effectively implement the DCP

process. Specifically, PSEGs DCP 4EC-3662 failed to reclassify the PC of the MCR

chiller PCV positioner from non-safety related (PC4) to safety related (PC1). Because of

the incorrectly assigned PC, PSEG did not track the shelf life of replacement positioner

diaphragms, which led to the failure of the A MCR positioner on December 20, 2013.

Enclosure

29

As a result, while the B MCR chiller was inoperable following planned maintenance, the

A MCR chiller had to be manually secured due to excessive fluctuations in load caused

by the failed positioner, and led to both MCR chillers being inoperable.

Description. The control room envelope (CRE) heating, ventilation and air conditioning

(HVAC) systems are designed to ensure habitability during any design basis radiological

accident. Redundant HVAC systems are provided to control the ambient conditions for

safety-related equipment to ensure operating temperature limits are not exceeded. The

A and B MCR chillers provide the accident function of maintaining the temperature of

the CRE for equipment performance and operator comfort.

On December 20, 2013, at 1:03 pm, while the B MCR chiller was out of service in

support of maintenance, the A MCR chiller was manually secured due to excessive

fluctuations in load. TS action statement 3.7.2.2.a.2 for both MCR chillers being

inoperable was entered. This condition was reportable per 10CFR50.72(b)(3)(v)(D), as

an event or condition that could have prevented the fulfillment of the safety function of

structures or systems that are needed to mitigate the consequences of an accident,

PSEG submitted an eight-hour event notification (#49671) for concurrent inoperability of

both MCR chillers. At 9:20 pm (~8 hours into the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> TS action statement), the B

MCR chiller was placed in service for post maintenance testing and returned to an

operable status, allowing PSEG to exit the TS. Throughout the time both chillers were

inoperable, the MCR temperature was maintained below the TS limit of 90 degrees

Fahrenheit.

PSEG conducted an equipment apparent cause evaluation (EQACE 70162284) and

determined the A MCR chiller excessive load fluctuations were the result of an

inoperable chiller condenser PCV. The positioner for the PCV, which provides cooling

water flow to the chiller condenser, failed due to a leak in the positioner's internal relay

assembly, which is made up of a series of diaphragms. This positioner had failed

previously due to a missing roller bearing and C clip, and was replaced at the end of

2011. The replaced positioner that failed on December 20, 2013, had only been

installed for 2 years. The damaged diaphragm in the positioners relay assembly

allowed an internal leakage path for the air, resulting in the failure of the positioner to

operate properly. This failure was determined to be age-related caused by a legacy

issue with the implementation of DCP 4EC-3662 in 1997. The chiller PCV has an active

safety function in the open position to provide cooling water flow to the MCR chiller. On

a loss of instrument air, the chiller PCV was originally designed to fail open, but this DCP

installed backup air bottles to supply the chiller PCV, preventing the PCV from failing

open so that the chiller would not trip on low evaporator refrigerant pressure. This

design change resulted in the PCV becoming self-modulating, changing the

classification of the PCV positioner from nonsafety-related to safety-related. PSEGs

evaluation of this DCP in the EQACE concluded that the DCP failed to identify that the

PC of the positioner for the PCV should have been changed from nonsafety-related to

safety-related and as a result, the PC was not changed. If the PC of the positioner had

been changed to PC1, a positioner that had been on the shelf for more than 20 years

would not have been installed into a safety-related system. But because the PC was not

changed, PSEG determined that the shelf life of the in-stock replacement positioners

was not tracked, leading to the installation of a positioner in 2011 that had been

manufactured 21 years before.

Enclosure

30

PSEGs determined that the MCR chiller PCV positioner failed to operate because of

internal relay leakage caused by damaged diaphragms. These diaphragms failed due to

the positioners age exceeding the vendor recommended lifetime of 4 years. PSEG has

entered this issue into the CAP as NOTF 20642546. As part of PSEGs corrective

actions the site has replaced the failed positioner and changed the purchase

classification for the chiller PCV positioners to safety-related (PC1).

Analysis. PSEGs failure to effectively implement the DCP process for DCP 4EC-3662

was a performance deficiency that was within the licensees ability to foresee and

correct, and should have been prevented. Specifically, because of the incorrectly

assigned PC, PSEG did not track the shelf life of replacement positioner diaphragms,

which led to the failure of the A MCR positioner on December 20, 2013. The inspectors

determined that the performance deficiency was more than minor because it is

associated with the design control attribute of the of the barrier integrity cornerstone, and

adversely affected the cornerstone objective of maintaining the radiological barrier

functionality of the control room Exhibit 3 of IMC 0609, Appendix A, The Significance

Determination Process (SDP) for Findings at Power, issued June 19, 2012, the

inspectors determined that this finding is of very low safety significance (Green) because

the performance deficiency represents a degradation of only the radiological barrier

function provided for the control room. Since the implementation of DCP 4EC-3662, the

DCP procedures have been enhanced to ensure the completion of a purchase class

evaluation of procured materials that are implemented in the DCP process.

The inspectors determined that there was no cross-cutting aspect associated with this

finding because the cause of the performance deficiency occurred more than three years

ago, and was not representative of current plant performance.

Enforcement. 10 CFR 50, Appendix B, Criterion III, Design Control, states, in part, that

measures shall be established to assure that applicable regulatory requirements and the

design basis for structures, systems, and components shall be correctly translated into

specifications, drawings, procedures, and instructions.

Contrary to this, PSEGs implementation of DCP 4EC-3662 in 1997, failed to reclassify

the PC of the MCR chiller PCV positioner from nonsafety-related to safety-related.

Because of the incorrectly assigned PC, PSEG did not track the shelf life of replacement

positioner diaphragms, which led to the failure of the A MCR positioner on

December 20, 2013. PSEGs corrective actions include replacement of the failed

positioner and changing the PC for the MCR PCV positioners to safety-related.

Because of the very low safety significance (Green) and because the issue was entered

into the CAP as notification 20642546, this violation is being treated as an NCV,

consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV

05000354/2014003-05, Inadequate Evaluation of a Main Control Room Chiller

Design Change)

4OA5 Other Activities

Temporary Instruction (TI) 2515/182, Phase II, Underground Piping and Tank Integrity

(1 sample)

Enclosure

31

a. Inspection Scope

The licensees buried piping and underground piping and tanks program was inspected

in accordance with paragraph 03.02.a of the TI. It was confirmed that activities which

correspond to completion dates specified in the program, which have passed since the

Phase 1 inspection was conducted, have been completed.

Additionally, the licensees buried piping and underground piping and tanks program was

inspected in accordance with paragraph 03.02.b of the TI and responses to specific

questions found in http://www.nrc.gov/reactors/operating/ops-experience/buried-pipe-ti-

phase-2-insp-req-2011-11-16.pdf were submitted to the NRC headquarters staff.

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

On July 10, 2014, the inspectors presented the inspection results to Mr. Paul Davison,

Hope Creek Site Vice President, and other members of the PSEG staff. The inspectors

verified that no proprietary information was retained by the inspectors or documented in

this report.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by the

licensee and is a violation of NRC requirements which meets the criteria of the NRC

Enforcement Policy, for being dispositioned as a NCV:

In Modes 1, 2, and 3, Hope Creek TS 3.4.2.1, "Safety Relief Valves," requires that

13 of the 14 SRVs open within of +/- 3 percent of the specified code safety valve

function lift settings or else be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in Mode 4 within the

next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Contrary to this requirement, on November 22, 2013, PSEG identified

that five of the fourteen SRVs were determined to have their as-found setpoints in

excess of the TS allowable tolerance, thus leaving nine operable SRVs. The pilot

assembly for each of the fourteen SRVs has been replaced with a fully tested spare

assembly. Additionally, LER 2013-007 stated PSEGs proposal to replace the SRVs

is being considered through the plant modification process. PSEG entered this issue

into their CAP as notification 20631351. The inoperability of the five SRVs did not

result in a loss of system safety function based on engineering analyses that showed

that postulated piping stresses would not exceed allowable limits. Therefore, this

finding is of very low (Green) safety significance based on an SDP issue screening,

because the SRVs would have functioned to prevent a reactor vessel over-

pressurization. The closure of the LER associated with this event was documented

in Section 4OA3.

ATTACHMENT: SUPPLEMENTARY INFORMATION

Enclosure

A-1

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

P. Davison, Site Vice President

E. Carr, Plant Manager

P. Bellard, Program Engineering

S. Bier, EOP Coordinator

M. Biggs, Hope Creek Maintenance Rule Coordinator

M. Cardile, Fire Protection Supervisor

J. Carlin, Fire Protection Superintendent

S. Connelly, System Engineer

A. DiEgidio, Chemistry Technician

T. Headman, Emergency Preparedness Technical Specialist

W. Hickey, Work Week Manager

C. Johnson, Senior Program Engineer

E. Martin, Senior Program Engineer

J. Master, Chemistry Technician

M. Meltzer, Chemistry

T. Morin, Regulatory Assurance Engineer

M. Reeser, System Engineer

M. Rooney, System Engineer

R. Smith, System Engineer

K. Timko, System Engineer

A. Tramontana, Program Engineering Manager

M. Tudisco, Nuclear Maintenance Supervisor

K. Wichman, System Engineer

LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED

Opened/Closed

05000354/2014003-01 NCV Inadequate Procedural Guidance for Responding

to an Internal Flooding Event in the HPCI and

RCIC Rooms (Section 1R06)05000354/2014003-02 FIN Failure to Evaluate an Identified Issue with the

Moisture Separator Dump Valve Performance

(Section 1R12)05000354/2014003-03 NCV Failure to Follow Procedure Resulting in the Loss

of a Vital 4kV Bus (Section 1R13)05000354/2014003-04 FIN Inadequate Implementation of Contingency

Actions During Moisture Separator Emergency

Level Controller Tuning (Section 4OA3)

Attachment

A-2

05000354/2014003-05 NCV Inadequate Evaluation of a Main Control Room

Chiller Design Change (Section 4OA3)

Closed

05000354/2013-007-00 LER As-Found Values for Safety Relief Valve Lift Set

Points Exceed Technical Specification Allowable

Limit (Section 4OA3)

05000354/2013-008-01 LER Automatic Actuation of the Reactor Protection

System Due to a Main Turbine Trip (Section

4OA3)

05000354/2013-009-01 LER Automatic Actuation of the Reactor Protection

System Due to a Main Turbine Trip (Section

4OA3)

05000354/2013-010-00 LER Loss of Both Main Control Room Chillers (Section

4OA3)

LIST OF DOCUMENTS REVIEWED

Section 1R01: Adverse Weather Protection

Procedures

ER-HC-310-1009, HCGS - Maintenance Rule Scoping, Revision 10

HC.MD-GP.ZZ-0037, Plant Bulkhead Doors Overhaul, Revision 5

HC.MD-PM.ZZ-0007, Missile Resistant and Watertight Doors Preventative Maintenance,

Revision 9

HC.OP-AB.MISC-0001, Acts of Nature, Revision 23

HC.OP-DL.ZZ-0014, Monday Shift Routine Log, Revision 34

HC.OP-GP.ZZ-0003, Station Preparations for Winter Conditions, Revision 29

OP-AA-108-111-1001, Severe Weather and Natural Disaster Guidelines, Revision 9

WC-AA-107, Seasonal Readiness, Revision 13

Other Documents

2013 Summer Readiness Hope Creek Critique

2014 Hope Creek Summer Readiness Affirmation Certification Letter, dated May 1, 2014

Notifications (*NRC-identified)

20546153 20562816 20610276 20612823 20613802 20615133

20649147 20650908 20650999 20652771* 20652918* 20654490

20654491 20654493 20654495 20654496

Maintenance Orders/Work Orders

30236406 60092591 60104126 60112815 60112948 60114177

60115861 70159564 80107747 80110867

Attachment

A-3

Drawings

A-0203-0, General Plant Floor Plan Level 3 - Elevation 102, Revision 19

Section 1R04: Equipment Alignment

Procedures

HC.OP-ST.BD-0001, RCIC Piping and Flow Path Verification - Monthly, Revision 14

HC.OP-ST.EA-0001, Service Water Flow Path Verification - Monthly, Revision 11

OP-AA-108-116, Protected Equipment Program, Revision 9

OP-HC-108-115-1001, Operability Assessment and Equipment Control Program, Revision 27

Notifications (*NRC-identified)

20529358 20529359 20529360 20529362 20636088 20636089

20647011 20648223 20649406* 20649407* 20649408* 20649409*

Maintenance Orders/Work Orders

30255253 50165993 70127188 70129996

Drawings

E-0485-0, Electrical Schematic Auxiliary Building - Diesel Area Switchgear Room Coolers and

Air Dampers, Sht. 3, Revision 8

M-10-1, Sheet 1, Service Water, Revision 54

M-10-1, Sheet 2, Service Water, Revision 43

M-49-1, Reactor Core Isolation Cooling, Revision 30

M-50-1, RCIC Pump Turbine, Revision 29

Miscellaneous

HCGS PRA Risk Evaluation Form for Work Week #1418, Revision 3, dated May 2, 2013

MP 192355

NRC IN 96-06, Design and Testing Deficiencies of Tornado Dampers at Nuclear Power Plants

OE 33769

PM 30255253

Protected Equipment Log for HPCI Sight Glass Repair, dated May 2, 2014

Section 1R05: Fire Protection

Procedures

FP-AA-014, Fire Protection Training Program, Revision 1

FP-AA-015, Compensatory Measure Firewatch Program, Revision 5

FP-AA-028-1001, Emergency Response Safety and Risk Management Plan, Revision 0

FP-HC-004, Actions for Inoperable Fire Protection - Hope Creek Station, Revision 1

FRH-II-332, Service & Radwaste Area, Elevation: 102-0, Revision 4

FRH-II-412, Hope Creek Pre-Fire Plan, RCIC Pump and Turbine Room, RHR Pump and Heat

Exchanger Rooms, and Electrical Equipment Room, Elevations 54, Revision 3

FRH-II-415, Hope Creek Pre-Fire Plan, Dry Well Pad Torus Area, Elevations: 54-0 &77-0,

Revision 4

FRH-II-522, Hope Creek Pre-Fire Plan, Cable Spreading Room, Elevation: 77-0, Revision 6

FRH-II-532, Hope Creek Pre-Fire Plan, Lower Control Equipment Room, Elevation: 102-0,

Revision 6

Attachment

A-4

FRH-II-542, Hope Creek Pre-Fire Plan, Control Equipment Mezzanine, Elevations: 117-6 &

124-0, Revision 6

FRH-II-551, Hope Creek Pre-Fire Plan, Battery Rooms & Cable Chases, Elevations: 146-0 &

150-0, Revision 6

HC.OP-IS.BD-0001, Reactor Core Isolation Cooling Pump - OP203 - Inservice Test, Rev 58

SH.FP-EO.ZZ-0002, Fire Department Fire Response, Revision 3

Notifications (*NRC identified)

20632422 20633801 20639488 20642920 20644734 20644822

20646267 20646330 20646361 20647111 20647263* 20647351*

20651472

Maintenance Orders/Work Orders

0158901 50165299 70143862 70161457

Drawings

M-50-1, P&ID RCIC Pump Turbine, Revision 29

Miscellaneous

Fire Protection Impairment Permit 11760, dated April 16, 2014

Section 1R06: Flood Protection Measures

Procedures

EP-HC-111-130, HC EAL Wall Chart - All Conditions, Revision 1

HC.OP-AR.ZZ-0004, Overhead Annunciator Window Box A6, Revision 18

HC.OP-AR.ZZ-0006, Overhead Annunciator Window Box B1, Revision 25

HC.OP-AR.ZZ-0022, CRIDS Computer Points Book 3 D2880 Thru D3257, Revision 19

HC.OP-EO.ZZ-0103/4, Reactor Building and Radioactive Release Control, Revision 9

HC.OP-EO.ZZ-0103/4-CONV, Hope Creek Emergency Operating Procedure Conversion

Document, Revision 9

HC.OP-EO.ZZ-0103/4-FC, Reactor Building and Radioactive Release Control Flow Chart,

Revision 9

Notifications (*NRC identified)

20643688* 20643694* 20643696* 20643885* 20643886* 20643887*

20646334* 20646335* 20653586* 20656703*

Drawings

A-4641-1, Reactor Building Unit 1 Floor Plan at El. 54-0, Revision 6

J-25-0, Sheet 5, Logic Diagram Plant Leak Detection, Revision 6

M-25-1, Sheet 1, Plant Leak Detection, Revision 8

M-97-1, Sheet 2, Building and Equipment Drain Reactor Building, Revision 18

Other Documents

Calculation Number 11-0092, Reactor Building Flooding - Elevation 54 and 77, Revision 5

Calculation Number BC-0031, ECCS Pump Rooms Flood Level Alarm Set Point, Revision 1

HC-PRA-012, Internal Flood Evaluation Summary and Notebook, Revision 2

HC-PRA-017, Internal Flood Walkdown Notebook, Revision 0

Attachment

A-5

Section 1R11: Licensed Operator Requalification Program

Procedures

CY-AB-120-340, Offgas Chemistry, Revision 8

HC.OP-AB.IC-0001, Control Rod, Revision 16

HC.OP-FT.AC-0002, Main Turbine Functional Test Monthly, Revision 31

HC.OP-FT.AC-0005, Turbine Overspeed Protection System Operability Test - Quarterly,

Revision 13

HC.OP-ST.AC-0002, Turbine Valve Testing - Quarterly, Revision 49

HU-AA-1211, Pre-Job Briefings, Revision 11

NF-AA-400-1000, Fuel Integrity Monitoring, Revision 4

NF-AA-400-1700, BWR Fuel Reliability Indicator (FRI) Calculation and Transmittal, Revision 1

NF-AA-430, Failed Fuel Action Plan, Revision 8

OP-AA-101-111-1004, Operations Standards, Revision 4

OP-AA-108-111, Attachment 1, Adverse Condition Monitoring and Contingency Plan, Revision 7

OP-AA-300, Reactivity Management, Revision 6

OP-AB-300-1001, BWR Control Rod Movement Requirements, Revision 6

OP-AB-300-1003, BWR Reactivity Maneuver Guidance, Revision 11

Notifications

20543906 20566308 20644437

Maintenance Orders/Work Orders

50163804 70140638 80110856

Other Documents

HC 14-01, OTDM for Turbine Overspeed Protection System Operability Test - Quarterly,

February 11, 2014

HC 14-008, ACM for Fuel Reliability Parameters used to Monitor Fuel Defect indicate potential

fuel failure, March 25, 2014, Revision 0

Hope Creek Long Term Trends - 2014 for Failed Fuel Monitoring (NOTF 20644437)

Hope Creek Failed Fuel Monitoring Team Meeting on March 15, 2014

REMA 2014-0022, April 2014 TVT and PST Downpower REMA, Revision 0

Miscellaneous

Scenario Guide (SG)-644, Reactor Recirc Pump Trip / RWCU Leak / Loss of Main Condenser

Vacuum / ATWS dated April 24, 2014

Section 1R12: Maintenance Effectiveness

Procedures

ER-AA-10, Equipment Reliability Process Description, Revision 1

ER-AA-310, Implementation of the Maintenance Rule, Revision 11

ER-AA-310-1001, Maintenance Rule - Scoping, Revision 6

ER-AA-310-1004, Maintenance Rule - Performance Monitoring, Revision 10

ER-AA-310-1005, Maintenance Rule - Dispositioning Between (a)(1) and (a)(2), Revision 9

ER-HC-310-1009, Maintenance Rule System Function and Risk Significant Guide, Revision 10

ER-SA-310-1009, Salem Generating Station - Maintenance Rule Scoping, Revision 4

HC.DE-PS.ZZ-0041, Hope Creek Station Blackout Program, Revision 3

Attachment

A-6

HC.IC-CC.SK-0002, RCIC - Division 4 Steam Leak Detection Temperature Monitor H1SK-

1SKXR-11503, Revision 14

HC.IC-DC.SK-0001, NUMAC Leak Detection Setup and Trip Selection, Revision 11

HC.OP-AB.ZZ-0135, Station Blackout // Loss of Offsite Power // Diesel Generator Malfunction,

Revision 39

LS-AA-125, Corrective Action Program, Revision 17

MA-AA-716-004, Conduct of Troubleshooting, Revision 12

MA-AA-716-012, Post Maintenance Testing, Revision 19

MA-AA-716-210-1005, Predefine Change Process, Revision 3

S1.OP-AB.LOOP-0001, (Salem) Loss of Off-site Power, Revision 29

WC-AA-111, Predefine Process, Revision 8

Notifications

20335737 20413574 20447050 20502118 20570839 20619184

20623712 20638460 20640526 20645207 20651951

Orders

60113250 70073704 70105948 70121525 70124871 70157974

70161698 80110856

Miscellaneous

HC 10-03, License Amendment Request for Extending the Allowed Outage Time for the A and

B EDGs from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 14 days

HC 13-015, OTDM for Continued Operation of the Moisture Separator without a Root Cause for

the Dump Valve Failing to Control Level, dated December 6, 2013

NUMARC 93-01, Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear

Power Plants, Revision 4

NRC Correspondence, HCGS - Issuance of Amendment Re: Emergency Diesel Generators A

and B Allowed Outage Time Extension, dated March 25, 2011

Section 1R13: Maintenance Risk Assessments and Emergent Work Control

Procedures

HC.CH-SA.HA-0002, Sampling Offgas System from 00-C-963 Panel, Revision 8

HC.OP-AB.RPV-0001, Reactor Power, Revision 13

HC.OP-FT.AC-0005, Turbine Overspeed Protection System Operability Test - Quarterly,

Revision 13

HC.OP-IO.ZZ-0006, Power Changes During Operation, Revision 57

HC.OP-SO.BB-0002, Reactor Recirculation System Operation, Revision 98

HC.OP-SO.PB-0001, 4.16KV System Operation, Revision 29

HC.OP-ST.PB-0002, AC Power Supply Transfer Functional Test - 18 Months, Revision 11

HC.OP-ST.ZZ-0001, Power Distribution Lineup - Weekly, Revision 36

MA-AA-1000, Conduct of Maintenance Manual, Section 3.0 - Maintenance Standards and

Practices, Revision 7 and 14

NC.CH-RC.ZZ-2525, Gamma Spectroscopy Analysis Using CAS, Revision 4

NF-AB-431, Power Suppression Testing, Revision 6

WC-AA-101, On-Line Work Management Process, Revision 22

WC-AA-105, Work Activity Risk Management, Revision 2

Attachment

A-7

Notifications (*NRC identified)

20465881 20521256 20585982 20593568 20600597 20627730

20632023 20634061 20637967 20638221 20639498 20639519

20644437 20645095 20645435 20645701* 20645705 20650898

20650904 20651102 20651204 20651430 20651432 20651876

20653142

Maintenance Orders/Work Orders

30098613 30098617 30243196 30265556 60061175 60114688

60117312 70046681 70072347 70097158 70110518 70142932

70155514 70162013

Miscellaneous

DCP 4-HC-0170

HC-14-006, OTDM for B Reactor Recirculation MG Set Speed Control, dated May 17, 2014

HCGS Operations Narrative Logs, May 14-15, 2014

HCGS PRA Risk Evaluation Form for June 8, 2014, through June 14, 2014, Revision 0

Protected Equipment Log -F FRVS Recirc Fan, dated June 8, 2014

HRE 2014-0023, Mid-Cycle 19 Standing REMA, from May 9-30, 2014, Revision 3

NRC RIS 2007-21, Adherence to Licensed Power Limits, Revision 1

REMA 2014-0022, April 2014 TVT and PST Downpower REMA, Revision 0

Troubleshooting Data Sheet - NOTF 20630902 for B RRP Speed Demand, dated

November 15, 2013

Troubleshooting Work Sheet - NOTF 20651102 for Proper Indication and Control of the B RRP

Speed Control Loop, dated May 14, 2014

WC-AA-105-F3, Form 3, Risk Management Plan - Replacement of B Isolator, Revision 1

Section 1R15: Operability Determinations and Functionality Assessments

CC-AA-309-101, Engineering Technical Evaluations, Revision 10

ER-AA-2006, Lost Parts Evaluation, Revision 8

HC.CH-CA.ZZ-0026, Boron by Mannitol Titration, Revision 18

HC.OP-AB.RPV-0001, Reactor Power, Revision 13

HC.OP-IO.ZZ-0006, Power Changes During Operation, Revision 57

HC.OP-IS.BH-0004, Standby Liquid Control Pump - BP208 - Inservice Test, Revision 12

HC.OP-SO.BB-0002, Reactor Recirculation System Operation, Revision 98

HC.OP-SO.KJ-0001, Emergency Diesel Generators Operation, Revision 70

HC.OP-SO.PB-0001, 4.16KV System Operation, Revision 29

HC.OP-ST.KJ-0003, Emergency Diesel Generator 1CG400 Operability Test - Monthly,

Revision 76

HC.OP-ST.PB-0002, AC Power Supply Transfer Functional Test - 18 Months, Revision 11

HC.OP-ST.ZZ-0001, Power Distribution Lineup - Weekly, Revision 36

HU-AA-1212, Technical Task Risk/Rigor Assessment, Pre-Job Brief, Independent Third Party

Review and Post-Job Brief, Revision 8

MA-AA-1000, Conduct of Maintenance Manual, Section 3.0 - Maintenance Standards and

Practices, Revision 7 and 14

WC-AA-101, On-Line Work Management Process, Revision 22

Attachment

A-8

Notifications (*NRC identified)

20221500 20439888 20442565 20442566 20465881 20521256

20585982 20593568 20600597 20616574 20627730 20632023

20634061 20637967 20638221 20639498 20639519 20640696

20643229 20643322* 20644637 20645519 20645994 20647199*

20650611* 20650701* 20650788* 20650831* 20650856* 20650858*

20650898 20650904 20651102 20651204 20651430 20651432

20651876 20652187 20652199 20653142 20653635*

Drawings

M-52-1, Core Spray, Revision 31

M-52-1, Sheet 1, Residual Heat Removal, Revision 45

M-52-1, Sheet 2, Residual Heat Removal, Revision 40

Maintenance Orders/Work Orders

30098613 30098617 30243196 50165850 60061175 60087495

60087534 60087538 60087539 60087540 60087541 60089905

60114688 60117312 70046681 70072347 70097158 70110518

70142932 70149472 70155514 70157453 70162013 70163760

70164628 80079629 80079863 80108395 80111752 80111754

Miscellaneous

10855-D3.33, Design, Installation and Test Specification for Standby Liquid Control System for

the Hope Creek Generating Station, Revision 5

22A7641, Design Specifications for SLC System, Revision 1

ASTM E29-13, Standard Practice for Using Significant Digits in Test Data to Determine

Conformance with Specifications

C-0001, Wall Thickness Calculation for Piping, Revision 9

Calculation 1SC-BH-0001, SLC System Tank 10T-204 Level, Revision 0

DCP 4-HC-0170

DCP 4HM-0136, Change Standby Liquid Control Tank Sodium Pentaborate Concentration from

13.4 to 14.0 Weight Percent, dated December 17, 1987

HC-14-006, OTDM for B Reactor Recirculation MG Set Speed Control, May 17, 2014

HCGS Operations Narrative Logs, May 14-15, 2014

HRE 2014-0023, Mid-Cycle 19 Standing REMA, from May 9-30, 2014, Revision 3

LD-042-MASTERPACT-1, Masterpact Issues, Revision 1

NLR-N87131, Request for Amendment Facility Operating License NPF-57 Hope Creek

Generating Station Docket No. 50-354, dated July 14, 1987

NRC RIS 2007-21, Adherence to Licensed Power Limits, Revision 1

Part 9900: Technical Guidance, Standard Technical Specifications Section 3.0 Acceptable

Measurement Tolerances for Technical Specification Limits, dated October 1, 1978

PM018Q-0499, Vol. 1, Operation and Maintenance Manual for Colt Industries Diesel Generator,

Revision 25

Troubleshooting Data Sheet - NOTF 20630902 for B RRP Speed Demand, dated November

15, 2013

Troubleshooting Work Sheet - NOTF 20651102 for Proper Indication and Control of the B RRP

Speed Control Loop, dated May 14, 2014

WC-AA-105-F3, Form 3, Risk Management Plan - Replacement of B Isolator, Revision 1

Attachment

A-9

Section 1R18: Plant Modifications

Procedures

CC-AA-102, Design Input and Configuration Change Impact Screening, Revision 23

CC-AA-103, Configuration Change Control for Permanent Physical Plant Changes, Revision 15

CC-AA-112, Temporary Configuration Changes, Revision 13

CC-AA-112-1001, Temporary Configuration Change Implementation T&RM, Revision 2

OP-AA-115-101, Operator Aid Postings, Revision 3

Notifications

20439888 20639161 20640696 20651205 20652187

Maintenance Orders/Work Orders

60115429 70163760 80107203 80111298 80111754

Drawings

M-08-0, Sheet 1, Condensate & Refueling Water Storage & Transfer, Revision 34

Miscellaneous

DCP 80111754, Masterpact Breaker Add Aux Contact with Close Coil, Revision 1

H-1-ZZ-EGS-0043, Hope Creek Generating Station GE AKR Circuit Breaker Replacement

Project

LD-042-MASTERPACT-1, Revision 1

OPEVAL 14-002, Masterpact Breaker Model NW with Locked in Close Signal, Revision 3

Temporary Configuration Change Package Tracking Log, dated June 10, 2014

Section 1R19: Post-Maintenance Testing

Procedures

CC-AA-309-101, Engineering Technical Evaluations, Revision 10

HC.IC-CC.SK-0002, RCIC - Division 4 Steam Leak Detection Temperature Monitor H1SK-

1SKXR-11503, Revision 14

HC.IC-DC.SK-0001, NUMAC Leak Detection Setup and Trip Selection, Revision 11

HC.IC-DC.ZZ-0011, Device/Equipment Calibration Bailey, Characterizable Pneumatic

Positioner, Type AP2, Revision 5

HC.OP-AB.COMP-0001, Instrument and/or Service Air, Revision 5

HC.OP-AB.RPV-0001, Reactor Power, Revision 13

HC.OP-IO.ZZ-0006, Power Changes During Operation, Revision 57

HC.OP-IS.BJ-0001, HPCI Main and Booster Pump Set - OP204 and OP217 - Inservice Test,

Revision 62

HC.OP-SO.BB-0002, Reactor Recirculation System Operation, Revision 98

HC.OP-ST.BC-0005, LPCI Subsystem B ECCS Time Response Functional Test - 18 Months,

Revision 16

HC.OP-ST.ZZ-0001, Power Distribution Lineup - Weekly, Revision 36

HU-AA-1212, Technical Task Risk/Rigor Assessment, Pre-Job Brief, Independent Third Party

Review and Post-Job Brief, Revision 8

MA-AA-716-012, Post Maintenance Testing, Revision 19

MA-AA-1000, Conduct of Maintenance Manual, Section 3.0 - Maintenance Standards and

Practices, Revision 7 and 14

SM-AA-410, Control of Purchased Material, Equipment and Services Program, Revision 6

WC-AA-101, On-Line Work Management Process, Revision 22

Attachment

A-10

Notifications (*NRC identified)

20454035 20465881 20521256 20619184 20623712 20623802

20629385 20632023 20642546 20642950 20647111 20650904

20651102 20651430 20651872 20651951 20652010 20652012

20652232 20652238 20652321 20652339 20652702 20653142

20653572* 20653872*

Maintenance Orders/Work Orders

30098613 30098617 30240742 30269527 50163142 60113238

60113250 60116090 60117312 70125746 70155514 70157974

70163994 70166194

Drawings

PN11-E11-1040-0383, Sheet 3, Residual Heat Removal System, Revision 15

PN11-E11-1040-0383, Sheet 12, Residual Heat Removal System, Revision 18

PN11-E11-1040-0383, Sheet 13, Residual Heat Removal System, Revision 10

PN11-E11-1040-0383, Sheet 22, Residual Heat Removal System, Revision 17

Miscellaneous

HC-14-006, OTDM for B Reactor Recirculation MG Set Speed Control, dated May 17, 2014

HCGS Operations Narrative Logs, May 14-15, 2014

HCGS PRA Risk Evaluation Form for April 20, 2014 through April 26, 2014

HRE 2014-0023, Mid-Cycle 19 Standing REMA, from May 9-30, 2014, Revision 3

NRC RIS 2007-21, Adherence to Licensed Power Limits, Revision 1

Troubleshooting Data Sheet - NOTF 20630902 for B RRP Speed Demand, dated

November 15, 2013

Troubleshooting Work Sheet - NOTF 20651102 for Proper Indication and Control of the B RRP

Speed Control Loop, dated May 14, 2014

WC-AA-105-F3, Form 3, Risk Management Plan - Replacement of B Isolator, Revision 1

Section 1R22: Surveillance Testing

Procedures

CC-AA-309-101, Engineering Technical Evaluations, Revision 10

ER-AA-2006, Lost Parts Evaluation, Revision 8

FP-HC-004, Actions for Inoperable Fire Protection - Hope Creek Station, Revision 1

HC.FP-ST.KC-0009, Diesel Driven Fire Pump Operability Test, Revision 20

HC.IC-CC.SK-0016, Radiation Monitoring - Channel D Monitor H1SK-1SKLY-4930 Drywell

Leak Detection Sump Monitoring System (DLD-SMS), Revision 22

HC.IC-GP.ZZ-0004, Thermocouples (T/C) and Resistance Temperature Detectors (RTD),

Revision 8

HC.MD-ST.PB-0003, Class 1E 4.16 kV Feeder Degraded Voltage Monthly Instrumentation

Channel Functional Test, Revision 26

HC.OP-DL.ZZ-0026, Surveillance Log, Revision 139

HC.OP-FT.AC-0002, Main Turbine Functional Test Monthly, Revision 31

HC.OP-FT.AC-0005, Turbine Overspeed Protection System Operability Test - Quarterly,

Revision 13

HC.OP-IS.BC-0002, CP202, C Residual Heat Removal Pump In-Service Test, Revision 43

HC.OP-IS.BJ-0001, HPCI Main and Booster Pump Set - 0P204 and 0P217 - Inservice Test,

Revision 62

Attachment

A-11

HC.OP-SO.KJ-0001, Emergency Diesel Generators Operation, Revision 70

HC.OP-ST.AC-0002, Turbine Valve Testing - Quarterly, Revision 49

HC.OP-ST.KJ-0001, Emergency Diesel Generator 1AG400 Operability Test - Monthly,

Revision 76

HC.OP-ST.KJ-0003, Emergency Diesel Generator 1CG400 Operability Test - Monthly,

Revision 78

HC.OP-ST.SK-0001, Alternate RCS Leakage Determination, Revision 9

HU-AA-1211, Pre-Job Briefings, Revision 11

HU-AA-1212, Technical Task Risk/Rigor Assessment, Pre-Job Brief, Independent Third Party

Review and Post-Job Brief, Revision 8

OP-AA-101-111-1004, Operations Standards, Revision 4

OP-AA-108-101, Control of Equipment and System Status, Revision 7

OP-AA-300, Reactivity Management, Revision 6

Notifications

20504658 20629522 20630428 20630429 20640032 20645519

20645994 20646319 20648114 20648751 20649201 20649292

20649425 20649905 20649906 20654936

Maintenance Orders/Work Orders

30199753 50163804 50164408 50164695 50165664 50165690

50165691 50165850 50166624 50167441 50169340 60026593

60058122 60097901 60107882 70008407 70023178 70097767

70122058 70127960 70139509 70145982 80111752

Calculations

SC-SK-0118, Drywell Leak Detection SMS (Floor Drain Unidentified Leakage), Revision 2

Miscellaneous

HC 14-01, OTDM for Turbine Overspeed Protection System Operability Test - Quarterly, dated

February 11, 2014

HCGS PRA Risk Evaluation Form for April 6, 2014, through April 12, 2014

PM018Q-0499, Vol. 1, Operation and Maintenance Manual for Colt Industries Diesel Generator,

Revision 25

REMA 2014-0022, April 2014 TVT and PST Downpower REMA, Revision 0

Section 1EP6: Drill Evaluation

Procedures

EP-AA-122, Drills and Exercises, Revision 3

EP-AA-122-1001, Drill and Exercise Scheduling, Development and Conduct, Revision 3

EP-AA-125-1002, NRC Drill and Exercise Performance (DEP) Indicator Guidance, Revision 3

EP-HC-111-121, Fission Product Barrier Table, Revision 1

EP-HC-111-230, Use of Fission Product Barrier Table, Revision 0

NC.EP-EP.ZZ-0102, Emergency Coordinator Response, Revision 18

NC.EP-EP.ZZ-0404, Protective Action Recommendations (PARS) Upgrades, Revision 4

Notifications

20654844

Attachment

A-12

Miscellaneous

DEP Observation Checklist for FAD-HC14-02, dated June 24, 2014

Section 4OA1: Performance Indicator Verification

Procedures

HC.OP-DL.ZZ-0026, Surveillance Log, Revision 136

HC.OP-DL.ZZ-0026, Surveillance Log, Revision 137

HC.OP-DL.ZZ-0026, Surveillance Log, Revision 138

HC.OP-DL.ZZ-0026, Surveillance Log, Revision 139

HC.RA-IS.ZZ-0010, Containment Isolation Valve Type C Leak Rate Test, Revision 15

LS-AA-2090, Monthly Data Elements for NRC Reactor Coolant System Activity, Revision 5

LS-AA-2100, Monthly Data Elements for NRC Reactor Coolant System Leakage, Revision 6

LS-HC-1000-1001, Hope Creek Generating Station Surveillance Frequency Control Program

List of Surveillance Frequencies, Revision 4

NC.CH-RC.ZZ-2525, Gamma Spectroscopy Analysis Using CAS, Revision 4

NC.CH-SA.RC-0002, Operation of the Reactor Building/RHR Sample Stations, Revision 18

Calculations

SC-SK-0119, Drywell Leak Detection SMS - Equipment Drain Sump, Revision 1

Notifications

20650305

Maintenance Orders/Work Orders

50137021 50149686 50162608

Miscellaneous

Daily Dose Equivalent Iodine-131 Sample Data

Daily Surveillance Log Data

Monthly Data Elements for NRC Reactor Coolant System Leakage Data Sheets

Section 4OA2: Problem Identification and Resolution

Procedures

ER-AA-2003, System Performance Monitoring and Analysis, Revision 9

ER-AA-3002, Component Cross-System Monitoring & Component Health Reporting, Revision 3

LS-AA-125, Corrective Action Program, Revision 17

LS-AA-125-1006, Performance Improvement Integrated Matrix (PIIM), Revision 5

LS-AA-1006, NRC Cross-Cutting Analysis and Trending, Revision 2

Notifications (*NRC identified)

20615843 20619913 20632801 20632802 20632361 20632641

20632746 20632747 20632748 20632749 20633058 20633338

20633339 20634028 20635871 20636138 20638889 20639772

20642767 20644539

Orders

70144876 70158815 70161953 70162269 80109029 80110809

80110866

Attachment

A-13

Miscellaneous

Hope Creek Engineering PIIM Report 1st Cycle 2013 Presentation, dated 8/31/13

Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion

Procedures

CC-AA-102, Design Input and Configuration Change Impact Screening, Revision 23

CC-AA-103, Configuration Change Control for Permanent Physical Plant Changes, Revision 15

ER-HC-310-1009, Maintenance Rule System Function and Risk Significant Guide, Revision 10

HC.IC-DC.ZZ-0140, Device/Equipment Cal. Masoneilan Pressure Temperature Controller,

Revision 4

HC.IC-LC.AF-0007, Moisture Separator Drain Tank Level Tuning, Revision 2

HC.OP-AB.RPV-0001, Reactor Power, Revision 13

HC.OP-AR.ZZ-0008, Overhead Annunciator Window Box C1, Revision 45

HC.OP-DL.ZZ-0026, Surveillance Log, Revision 140

HC.OP-SO.BB-0002, Reactor Recirculation System Operation, Revision 98

HC.OP-SO.GJ-0001, A(B) K400 Control Area Chilled Water System Operation, Revision 60

HU-AA-1211, Pre-Job Briefings, Revision 11

LS-AA-125-1003, Attachment 2, Equipment Apparent Cause Evaluation Guide, Revision 13DCP

4EC-3662

MA-AA-716-004, Conduct of Troubleshooting, Revision 12

SM-AA-300, Procurement Engineering Support Activities, Revision 7

WC-AA-105, Work Activity Risk Management, Revision 2

Notifications (*NRC identified)

20454035 20521256 20528822 20529153 20567269 20570629

20630857 20631351 20631820 20631940 20632542 20638799

20640526 20642546 20642767 20643301 20644017 20645207

20647829 20650346* 20650904 20651102 20651876 20652180

20652182 20652183 20652184 20652185 20652186 20652188

20653024 20653142

Maintenance Orders/Work Orders

60114285 60114286 70041898 70110518 70115711 70119769

70128407 70129670 70140751 70142556 70159686 70161353

70161698 70162284

Miscellaneous

10855-d3.33, Design, Installation and Test Specification for Standby Liquid Control System for

the Hope Creek Generating Station, Revision 5

22A7641, Design Specifications for SLC System, Revision 1

ASTM E29-13, Standard Practice for Using Significant Digits in Test Data to Determine

Conformance with Specifications

Calculation 1SC-BH-0001, SLC System Tank 10T-204 Level, Revision 0

DCP 4-HC-0170

DCP 4HM-0136, Change Standby Liquid Control Tank Sodium Pentaborate Concentration from

13.4 to 14.0 Weight Percent, December 17, 1987

HC-14-006, OTDM for B Reactor Recirculation MG Set Speed Control, dated May 17, 2014

HCGS Operations Narrative Logs, May 14-15, 2014

HRE 2014-0023, Mid-Cycle 19 Standing REMA, from May 9-30, 2014, Revision 3

Attachment

A-14

LER 2013-009-00, Automatic Actuation of the Reactor Protection System Due to a Main Turbine

Trip

LER 2013-009-01, Automatic Actuation of the Reactor Protection System Due to a Main Turbine

Trip

NLR-N87131, Request for Amendment Facility Operating License NPF-57 Hope Creek

Generating Station Docket No. 50-354, dated July 14, 1987

NRC RIS 2007-21, Adherence to Licensed Power Limits, Revision 1

Part 9900: Technical Guidance, Standard Technical Specifications Section 3.0 Acceptable

Measurement Tolerances for Technical Specification Limits, October 1, 1978

PM018Q-0499, Vol. 1, Operation and Maintenance Manual for Colt Industries Diesel Generator,

Revision 25

Troubleshooting Data Sheet - NOTF 20630902 for B RRP Speed Demand, dated

November 15, 2013

Troubleshooting Work Sheet - NOTF 20651102 for Proper Indication and Control of the B RRP

Speed Control Loop, dated May 14, 2014

WC-AA-105-F3, Form 3, Risk Management Plan - Replacement of B Isolator, Revision 1

Section 4OA5: Other Activities

Condition Reports

20650822 20650823 20652896

Procedures

ER-AA-5400, Underground Piping Program Guide, Revision 4

ER-AA-5400-1002, Underground Piping Examination Guide, Revision 3

SA-AA-117, Industrial Safety, Excavating Trenching, and Shoring, Revision 13

Miscellaneous

Cathodic Protection System Health Report for Hope Creek, Q1-2014

Cathodic Protection System Health Report for Salem U1, Q2-2014

Hope Creek Underground Piping Inspection Plan, Revision 3

LR-ISG-2011-03, Aging Management Program XI.M41, "Buried and Underground Piping and

Tanks"

NACE SP0169-2007, Control of External Corrosion on Underground or Submerged

Metallic Piping Systems, Revision 0

NEI-09-14, Guideline for the Management of Underground Piping and Tank Integrity

Location Sketch for Cathodic Protection of Salem U1 and U2 Structures, Revision 3

Program Health Report for the Salem Plant Underground Piping Program, P1-2014

Program Health Report for the Hope Creek Plant Underground Piping Program, P1-2014

Salem Underground Piping Inspection Plan, Revision 3

Underground Piping Inspection and Evaluation Report for Hope Creek line 0-DB-003, Liquid

RadWaste Discharge, dated February 22,2013

Underground Piping Inspection and Evaluation Report for Salem line SC-LW-0001-12-01, liquid

waste, Steam Generator Blowdown, dated September 11, 2012

Underground Piping Inspection and Evaluation Report for Salem lines S1-SG-1031-10 and S2-

SG-1111-10, dated September 17-20, 2012

UT report on Hope Creek component HODB-0-DB-V013, dated June 20, 2013

Attachment

A-15

LIST OF ACRONYMS

10 CFR Title 10 of The Code of Federal Regulations

ADAMS Agencywide Documents Access and Management System

CAP corrective action program

CCE common cause evaluation

CFR The Code of Federal Regulations

CRE control room envelope

DCP design change package

EDG emergency diesel generator

EN event notification

EQACE equipment apparent cause evaluation

ER Environmental Report

HCGS Hope Creek Generating Station

HLA heightened level of awareness

HPCI high pressure coolant injection

HVAC heating, ventilation and air conditioning

IMC Inspection Manual Chapter

kV kilovolt

LER licensee event report

LM logic module

MCR main control room

MS moisture separator

NACE National Association of Corrosion Engineers

NCV non-cited violation

NEI Nuclear Energy Institute

NOTF notification

NRC Nuclear Regulatory Commission

NRR Nuclear Reactor Regulation

PARS Publicly Available Records

PC purchase classification

PCV pressure control valve

PI performance indicator

PIIM performance improvement integrated matrix

PSEG Public Service Enterprise Group Nuclear, LLC

PST power suppression testing

RCIC reactor core isolation cooling

RCS reactor coolant system

RG Regulatory Guide

RHR residual heat removal

RRP reactor recirculation pump

RTP rated thermal power

RWCU reactor water cleanup

SACS safety auxiliaries cooling system

SDP Significance Determination Process

SLC standby liquid control

SRV safety relief valve

SSC structure, system, or component

SSW station service water

Attachment

A-16

TCCP temporary configuration control package

TI Temporary Instruction

TS technical specifications

TSAS technical specification action statement

U1 Unit 1

U2 Unit 2

UFSAR Updated Final Safety Analysis Report

UT ultrasonic testing

V volt

WO work order

Attachment

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