ML14209A132

IR 05000354-14-003, April 1, 2014 - June 30, 2014, Hope Creek Generating Station, Unit 1

ML14209A132
Person / Time
Site:	Hope Creek
Issue date:	07/28/2014
From:	Dentel G T Reactor Projects Branch 3
To:	Joyce T P Public Service Enterprise Group
DENTEL, GT
References
IR-14-003
Download: ML14209A132 (50)

See also: IR 05000354/2014003

Text

July 28, 2014

Mr. Thomas 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. 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 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 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 2 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 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 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. 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, 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)

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.

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.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.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-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

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.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Resident Inspector Quarterly Walkdowns

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

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 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

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.

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 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, 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

.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 communications, and coordination of activities between work groups similarly met established expectations and standards.

b. Findings

No findings were identified

1R12 Maintenance Effectiveness

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.

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 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

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-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 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. -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 (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 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. 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

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.

1R18 Plant Modifications

.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

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 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

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

b. Findings

No findings were identified. Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation

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.

4OA1 Performance Indicator (PI) Verification

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.

4OA2 Problem Identification and Resolution

.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.

-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

.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

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.

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.

.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-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.

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 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.

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)

---

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 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-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

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

05000354/2014003-05 NCV Inadequate Evaluation of a Main Control Room Chiller Design Change (Section 4OA3)

Closed

05000354/LER-2013-007-00 LER As-Found Values for Safety Relief Valve Lift Set Points Exceed Technical Specification Allowable Limit (Section 4OA3)

05000354/LER-2013-008-01 LER Automatic Actuation of the Reactor Protection System Due to a Main Turbine Trip (Section 4OA3)

05000354/LER-2013-009-01 LER Automatic Actuation of the Reactor Protection System Due to a Main Turbine Trip (Section 4OA3)

05000354/LER-2013-010-00 LER Loss of Both Main Control Room Chillers (Section 4OA3)

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

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

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

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

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 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

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

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

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

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

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

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

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

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

-- --- -- - - --- - -- - - -- ---- ---- --- ---

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

Attachment

TCCP temporary configuration control package

UFSAR Updated Final Safety Analysis Report