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{{Adams
#REDIRECT [[IR 05000219/2014005]]
| number = ML15042A072
| issue date = 02/11/2015
| title = Oyster Creek Nuclear Generating Station - NRC Integrated Inspection Report 05000219/2014005 and Preliminary White Finding
| author name = Nieh H K
| author affiliation = NRC/RGN-I/DRP
| addressee name = Hanson B
| addressee affiliation = Exelon Nuclear Generation Corp
| docket = 05000219
| license number = DPR-016
| contact person = KENNEDY, SR
| case reference number = EA-14-186
| document report number = 05000219/2014005, IR 2014005
| document type = Inspection Report, Letter
| page count = 66
}}
See also: [[followed by::IR 05000219/2014005]]
 
=Text=
{{#Wiki_filter:
[[Issue date::February 11, 2015]]
 
EA-14-186 Mr. Bryan Hanson Senior Vice President, Exelon Generation President and Chief Nuclear Officer, Exelon Nuclear 4300 Winfield Road Warrenville, IL 60555
 
SUBJECT: OYSTER CREEK NUCLEAR GENERATING STATION NRC INTEGRATED INSPECTION REPORT 05000219/2014005 AND PRELIMINARY WHITE FINDING
 
==Dear Mr. Hanson:==
On December 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Oyster Creek Nuclear Generating Station. The enclosed report documents the inspection results, which were discussed on January 29, 2015, with Mr. G. Stathes, Site Vice President, and other members of your staff. The inspection examined activities conducted under your license as they relate to safety and compliance with the rules and regulations and with the conditions of your license. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel. The enclosed inspection report discusses a finding associated with the failure of Emergency Diesel Generator (EDG) No. 2, which has preliminarily been determined to be White, a finding with low to moderate safety significance. As described in Section 4OA2 of the enclosed report, the finding is associated with an apparent violation of Title 10 of the Code of Federal Regulations the suitability of a different maintenance process for tensioning the cooling fan belt on the EDGs. As a result, the new method imposed a stress above the fatigue endurance limit of the shaft material, making the EDG cooling fan shaft susceptible to fatigue and subsequent failure on July 28, 2014. As a consequence, Exelon also violated Technical Specification (TS) 3.7.C, since the EDG No. 2 was determined to be inoperable for greater than the technical specification allowed outage time. The finding was assessed based on the best available information, using Inspection Manual -y significance determination is described in the enclosed report. Because the finding is also an apparent violation of NRC requirements, it is being considered for escalated enforcement action in accordance with the Enforcement Policy, which appears on thttp://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html. The NRC will inform you, in writing, when the final significance has been determined. We intend to complete and issue our final safety significance determination within 90 days from the date of this letter. encourage an open dialogue between your staff and the NRC; however, the dialogue should not affect the timeliness of our final determination. We believe that we have sufficient information to make a final significance determination. However, before we make a final decision, we are providing you an opportunity to provide your perspective on this matter, including the significance, causes, and corrective actions, as well as any other information that you believe the NRC should take into consideration. Accordingly, you may notify us of your decision within 10 days to: (1) request a regulatory conference to meet with the NRC and provide your views in person; (2) submit your position on the finding in writing; or, (3) accept the finding as characterized in the enclosed inspection report. If you choose to request a regulatory conference, the meeting should be held in the NRC Region I office within 30 days of the date of this letter, and will be open for public observation. The NRC will issue a public meeting notice and a press release to announce the date and time of the conference. We encourage you to submit supporting documentation at least 1 week prior to the conference in an effort to make the conference more efficient and effective. If you choose to provide a written response, it should be sent to the NRC within 30 days of the date of this letter. Inspection Report No. 05000219/2014005; EA-14-Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, Region I, and a copy to the NRC Senior Resident Inspector at the Oyster Creek Nuclear Generating Station. You may also elect to accept the finding as characterized in this letter and the inspection report, in which case the NRC will proceed with its regulatory decision. However, if you choose not to request a regulatory conference or to submit a written response, you will not be allowed to Please contact Silas Kennedy at (610) 337-5046 within 10 days from the issue date of this letter to notify the NRC of your intentions. If we have not heard from you within 10 days, we will continue with our significance determination and enforcement decision. Because the NRC has not made a final determination in this matter, no notice of violation is being issued for this inspection finding at this time. In addition, please be advised that the number and characterization of the apparent violation may change based on further NRC review. The final resolution of this matter will be conveyed in separate correspondence. In addition, the enclosed inspection report documents three violations of NRC requirements which were of very low safety significance (Green). However, because of the very low safety significance and because they are entered into your corrective action program, the NRC is treating these findings as non-cited violations, consistent with Section 2.3.2.a of the NRC Enforcement Policy. If you contest the non-cited violations 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 U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Oyster Creek Nuclear Generating Station. In addition, if you disagree with the cross-cutting aspect assigned to any finding, 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 the Oyster Creek Nuclear Generating Station. In accordance with 10 CFR 2.390 of the NRCs Rules of a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records component of the Agencywide Documents Access and 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/ Ho K. Nieh, Director Division of Reactor Projects Docket No.: 50-219 License No.: DPR-16
 
===Enclosure:===
Inspection Report 05000219/2014005 Attachment 1: Detailed Risk Significance Evaluation Attachment 2: Supplementary Information cc w/encl: Distribution via ListServ
 
=SUMMARY=
IR 05000219/2014005; 10/01/2014  12/31/2014; Exelon Energy Company, LLC, Oyster Creek Nuclear Generating Station; Inservice Inspection Activities; Problem Identification and Resolution. This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. Inspectors identified one apparent violation of with preliminary low to moderate safety significance (White) and three findings of very low safety significance (Green), which were also non-cited violations. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) , dated June 2, 2011. The cross-cutting -Cutting overseeing the safe operation of commercial nuclear power reactors is described in NUREG- 
 
===Cornerstone: Mitigating Systems===
Preliminary
: '''White.'''
The inspectors identified a preliminary White finding and an associated staff did not review the suitability of the application of a different maintenance process at Oyster Creek that was essential to a safety-related function of the emergency diesel generators (EDG). Specifically, in May 2005, Exelon staff changed the method for tensioning the cooling fan belt on the EDG from measuring belt deflection to belt frequency and did not verify the adequacy of the acceptance criteria stated for the new method. As a result, Exelon staff did not identify that the specified belt frequency imposed a stress above the fatigue endurance limit of the shaft material, making the EDG cooling fan shaft susceptible to fatigue and subsequent failure on July 28, 2014. As a consequence, Exelon also violated Technical Specification 3.7.C, because the EDG No. 2 was determined to be inoperable for greater than the technical specification allowed outage time. immediate corrective actions included entering the issue into their corrective action program as issue report (IR) 1686101, replacing the EDG No. 2 fan shaft, examining the EDG No.1 fan shaft for extent of condition, and performing a failure analysis to determine the causes  of the broken shaft. This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and 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). In accordance with IMC 0609.04, Significance Determination Process for Findings At-inspectors screened the finding for safety significance and determined that a detailed risk evaluation was required because the finding represented an actual loss of function of a single train for greater than its technical specification allowed outage time. The detailed risk evaluation concluded that the increase in core damage frequency was 5.1E-6, or White (low to moderate safety significance). This finding does not have an associated cross-cutting aspect because the performance deficiency occurred in 2005 and is not reflective of present performance. (Section 4OA2.4)
: '''Green.'''
The inspectors identified a non-cited violation (NCV) of Technical Specification maintain the plant shutdown procedure. Specifically, the procedure was not adequate in that it did not contain precautions concerning rod insertion when reactor power is below the point of adding heat; operational limitations on plant cooldown when power is below the point of adding heat; and contingency actions for re-criticality during shutdown. Exelon entered this issue into their corrective action program as IR 2412093 and conducted a root cause analysis. This finding is more than minor because it affected the procedure quality attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the reliability and capability of systems that respond to initiating events. Specifically, the plant shutdown procedure did not contain precautions to continuously insert control rods when reactor power is less than the point of adding heat, did not define operational considerations for limiting reactor cooldown, and did not contain contingency actions for return to criticality  Determination Process for Findings At-very low safety significance (Green). This finding has a cross-cutting aspect in the area of Human Performance, Documentation, because Exelon did not ensure that the shutdown procedure contained adequate controls for soft shutdown. [H.7] (Section 4OA2.5)  Green and when performing a plant shutdown. Specifically, the operators did not ensure that all personnel on shift had received Just-in-Time-Training for their role in the shutdown; operators did not perform a reactivity Heightened Level Awareness brief for the shutdown, and did not insert source range monitors (SRMs) in accordance with procedure. These performance deficiencies contributed to two unanticipated criticalities during the shutdown. Exelon entered this issue into their corrective action program as IR 2412093 and conducted a root cause analysis. This finding is more than minor because it affected the procedure quality attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the reliability and capability of systems that respond to initiating events. Specifically, Exelon did not implement procedures during the plant shutdown which contributed to two unanticipated returns to criticality which required operator action to mitigate. The inspectors screened this  0609, -609 determined this finding was of very low safety significance (Green). This finding has a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because licensed operators did not implement processes, procedures and work instructions during the plant shutdown. [H.8] (Section 4OA2.5) 
 
===Cornerstone: Initiating Events===
: '''Green.'''
The inspectors identified an NCV of 10 CFR Part 50, Appendix B, Criterion XVI, associated with the reactor head cooling (RHC) spray line 2-inch upper flange which was installed in a configuration that exceeded the allowable acceptance criteria. Specifically, Exelon staff identified a misaligned flange condition in IR 845395 but did not correct the deficiency by evaluation, repair or replacement during the 1R22 refueling outage in 2008  or subsequently during the 1R23 and 1R24 refueling outages. Exelon staff completed corrective actions to replace the flange during the 1R25 refueling outage after the NRC inspector questioned the acceptability of this condition. Exelon staff entered this issue into their corrective action program as IR 2385501. The finding is more than minor because it is associated with the equipment performance attribute of the Initiating Events cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, misalignment of the RHC spray line flange was greater than that provided in Oyster Creek pipe specifications and resulted in additional stresses in the flange weld. This condition was identified by Exelon staff as a possible contributor to the occurrence of a through wall crack and leak in the N7B upper flange socket weld joint that was identified and repaired in November 2012, but the misalignment was not corrected at that time. The inspectors screened this issue using IMC  Exhibit 1 of -and determined this finding was of very low safety significance (Green). The inspectors determined that this finding had a Problem Identification and Resolution cross-cutting aspect because Exelon did not evaluate and take timely corrective actions to address the long-standing repetitive flange alignment issue of the reactor head cooling spray piping flange connection to reactor pressure vessel head N7B nozzle [P.2].  (Section 1R08)
 
=REPORT DETAILS=
Summary of Plant Status  Oyster Creek began the inspection period with the reactor shut down for the 1R25 refueling outage. Operators commenced a startup of the reactor on October 11, 2014. On October 12, 2014, an automatic scram occurred at approximately 1 percent power due to a human performance error which occurred during troubleshooting of the main generator automatic voltage regulator. Following repairs, Oyster Creek operators commenced startup on  October 13, 2014, and the unit achieved 100 percent power on October 17, 2014. Operators briefly lowered power to 90 percent to perform rod pattern adjustments on October 18, 2014, October 24, 2014 and November 10, 2014. Operators lowered power to 95 percent on November 21, 2014 to perform turbine surveillances and returned to full power later the same day. The unit remained at or near 100 percent power for the remainder of the inspection period.
 
==REACTOR SAFETY==
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
{{a|1R01}}
==1R01 Adverse Weather Protection==
{{IP sample|IP=IP 71111.01|count=3}}
 
===.1 Readiness for Seasonal Extreme Weather Conditions===
 
====a. Inspection Scope====
temperatures. The review focused on the intake structure and the EDGs. The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR), technical specifications, control room logs, and the corrective action program to determine what temperatures or other seasonal weather could challenge these systems, and to ensure Exelon personnel had adequately prepared for these challenges. The inspectors procedure and applicable operating procedures. The inspectors performed walkdowns of the selected systems to ensure station personnel identified issues that could challenge the operability of the systems during cold weather conditions.
 
====b. Findings====
No findings were identified.
 
===.2 Readiness for Impending Adverse Weather Conditions===
 
====a. Inspection Scope====
National Weather Service on November 8, 2014. The inspectors verified that Exelon implemented their adverse weather procedures and that operators monitored plant equipment that could have been affected by the adverse weather conditions. The inspectors performed walkdowns to verify that equipment in areas around the plant were maintained within procedural limits, and when necessary, compensatory actions were properly implemented in accordance with procedures. The inspectors also verified that Exelon properly implemented its adverse weather procedures and that operators reviewed applicable emergency procedure. The inspectors performed independent walkdowns of the site to verify the site was ready for the onset of adverse weather.
 
====a. Findings====
No findings were identified.
 
===.3 External Flooding
 
====a. Inspection Scope====
During the week of October 22, 2014, the inspectors performed an inspection of the external flood protection measures for Oyster Creek Nuclear Generating Station. The inspectors reviewed the UFSAR, Chapter 2.4.2, which depicted the design flood levels and protection areas containing safety-related equipment to identify areas that may be affected by external flooding. The inspectors conducted a general site walkdown of the EDG building to ensure that Exelon erected flood protection measures in accordance with design specifications. The inspectors also reviewed operating procedures for mitigating external flooding during severe weather to determine if Exelon planned or established adequate measures to protect against external flooding events.
 
====b. Findings====
No findings were identified.
{{a|1R04}}
==1R04 Equipment Alignment==
 
===.1 Partial System Walkdowns===
===
{{IP sample|IP=IP 71111.04Q|count=4}}
 
====a. Inspection Scope====
The inspectors performed partial walkdowns of the following systems:  Core spray system II during planned maintenance for core spray system I on November 12, 2014  Containment spray system I during planned maintenance for containment spray system II on November 19, 2014    1-2 service water pump and both trains of emergency service water during planned maintenance on the 1-1 service water pump on December 8, 2014  1-2 and 1-3 turbine building closed cooling water pumps and both EDGs during planned maintenance on the 1-1 turbine building closed cooling water pump on December 9, 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 Exelon 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.
{{a|1R05}}
==1R05 Fire Protection==
 
===.1 Resident Inspector Quarterly Walkdowns===
{{IP sample|IP=IP 71111.05Q|count=3}}
 
====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 Exelon 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.
 
Condenser bay (TB-FZ-11E) on October 9, 2014  Drywell & Torus (RB-FA-2) on October 10, 2014  Northeast corner room (RB-FZ-1F4) on October 28, 2014
 
====b. Findings====
No findings were identified.
{{a|1R06}}
==1R06 Flood Protection Measures==
{{IP sample|IP=IP 71111.06|count=1}}
 
===.1 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 Exelon identified and corrected flooding problems and whether operator actions for coping with flooding were adequate. The inspectors also focused on the containment spray system areas to verify the adequacy of equipment seals located below the flood line, floor and water penetration seals, watertight door seals, common drain lines and sumps, sump pumps, level alarms, control circuits, and temporary or removable flood barriers.
 
====b. Findings====
No findings were identified.
{{a|1R08}}
==1R08 In-Service Inspection Activities==
{{IP sample|IP=IP 71111.08|count=1}}
 
====a. Inspection Scope====
The inspectors conducted a review of -service inspection (ISI) program activities for monitoring degradation of the reactor coolant system pressure boundary, risk significant piping and components, and containment systems for the Oyster Greek Nuclear Generating Station. The sample selection was based on the inspection procedure objectives and risk priority of those pressure retaining components in these systems where degradation would result in a significant increase in risk. The inspectors observed in-process non-destructive examinations (NDE), reviewed documentation, and interviewed inspection personnel to verify that the NDE activities performed as part of the Oyster Creek ISI during the 1R25 outage were conducted in accordance with the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI, 2007 Edition, 2008 Addenda. NDE and Welding Activities (IMC Section 02.01)  The inspectors observed portions of NDE activities in process and reviewed the nondestructive examinations data records listed below:  ASME Code Required Examinations  Activities inspected included direct field observations of manual and automated ultrasonic testing (UT), visual testing (VT), and dye penetrant (PT) testing. The inspectors reviewed the applicable NDE procedures, qualification certification for the personnel and procedures, and confirmed that relevant indications were properly documented and dispositioned. The inspectors reviewed a sample of certifications of the NDE technicians performing the examinations and verified that the inspections were performed in accordance with approved procedures and that the results were reviewed and evaluated by certified Level III NDE personnel. The inspectors observed portions of the following in-process NDE activities, including review of the examination documentation data records:    weld NG-E-0007 (UT examination report UT-14-052);  PT testing of the RHC vent pipe-slip on flange weld RHC-2-60 (PT examination reports BOP-PT-2014-013 and BOP-PT-2014-14);  Automated encoded phased array UT of reactor vessel top closure head spray flange to nozzle N7A dissimilar metal weld NR02/02-576 (phased array examination report 1-B5-10.0010);  Automated encoded phased array UT of reactor vessel top closure head spray flange to nozzle N7B dissimilar metal weld NR02/4-576 (phased array examination report 1-B5-10.0020);
Automated encoded phased array UT of reactor vessel top closure head vent flange to nozzle N8 dissimilar metal weld NR02/6-576 (phased array examination report  1-B5-10.0024); and,  VT examination of drywell sand bed bay 9 for epoxy coating anomalies and for corrosion. The inspectors reviewed the following NDE data records:  Automated encoded phased array UT data of isolation condenser nozzles N5A  and N5B safe-end dissimilar metal welds;  Automated encoded phased array UT data of reactor recirculation system reactor vessel outlet safe-end-to-nozzle dissimilar metal welds N1A, N1C, and N1D;  VT examination reports of sand bed bays 1, 3, 5, 7, 13 ,17, and 19 and UT thickness measurements taken in these sand bed bays; and,  PT examination data records of reactor vessel top closure head flange to nozzle N7B upper pipe/flange replacement during 1R25 outage. (See Repair/Replacement Activities below)  Other Augmented or Industry Initiative Examinations  The inspectors reviewed inspection records of visual inspections conducted of the reactor vessel internal components. The inspectors verified that the activities were performed in accordance with applicable examination procedures and industry guidance. The inspections were performed in accordance with the Boiling Water Reactor Vessel and Internals Project, In-Vessel Visual Inspection Program. The inspectors reviewed the VT examination data records and the disposition of identified indications.
 
The inspections during the 1R25 outage monitored and recorded the condition of the following reactor vessel internal components: reactor pressure vessel attachment welds; steam dryer; feedwater spargers; core shroud; shroud tie rod; core spray piping and spargers; top guide; and, fuel support casting.
 
Review of Originally Rejectable Indications Accepted by Evaluation  One sample was reviewed during this inspection that involved examinations with recordable indications that was accepted for continued service from the current 1R25 outage. The indication documented in IR 2386495 was on the reactor recirculation nation port piping identified during a PT examination and was considered outside diameter stress corrosion cracking which was removed by surface buffing and the results were evaluated and determined to be acceptable for continued service. Modification/Repair/Replacements Consisting of Welding on Pressure Boundary Risk Significant Systems  Exelon staff planned to replace the RHC spray line 2-inch upper flange per work order C20300107 during the 1R25 refueling outage but it was de-scoped from the planned list of outage activities. However, during a follow-up confirmation PT examination of the previously repaired 2-inch upper flange to pipe socket weld the NRC inspectors observed the 2-inch upper flange was noticeably out of level and requested the NDE technician at the worksite to photograph the condition. The inspectors informed appropriate Exelon NDE staff who initiated IR 2385501 on September 24, 2014.  -inch upper flange replacement back into the 1R25 outage scope and the flange was replaced on September 30, 2014. The inspectors reviewed the documentation associated with the replacement of RHC spray line 2-inch 1500 pound stainless steel upper flange connection to the reactor pressure vessel closure head N7B nozzle. The inspectors reviewed the replacement work order, welding documentation, and the PT data records to verify that the welding activities and applicable NDE activities were performed in accordance with ASME Code requirements. Identification and Resolution of Problems (02.05)  The inspectors reviewed a sample of action requests, which identified NDE indications, deficiencies and other nonconforming conditions since the previous 1R24 outage and during the present 1R25 outage. The inspectors verified that nonconforming conditions were properly identified, characterized, evaluated, corrective actions identified and dispositioned, and appropriately entered into the Oyster Creek corrective action program.
 
====b. Findings====
Reactor Head Cooling Spray Line Flange
 
=====Introduction:=====
The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI, "Corrective Action," because Exelon did not promptly correct a condition adverse to quality associated with the RHC spray line 2-inch upper flange which was installed in a configuration that exceeded the allowable acceptance criteria.
 
=====Description:=====
On September 23, 2014, the NRC inspectors observed the upper pipe flange on the 2-inch RHC spray line connection to the reactor pressure vessel closure head was visibly out of parallel. This flange is attached to piping via a socket weld. As part of reactor reassembly after a refueling outage, this flange is bolted to an adjacent flange of a short pipe spool piece that is then bolted to the reactor pressure vessel at nozzle N7B. The inspectors noted the observed flange misalignment could increase stresses in the flange socket weld and adjacent components and questioned the estions, Exelon staff entered the issue into their corrective action program in IR 2385501 for further evaluation. In IR 2385501, Exelon staff indicated the out-of-alignment condition could have resulted from a weld repair of the flange socket weld on November 26, 2012, during the previous refueling outage (1R24). Additionally further misalignment could have been introduced by welding recently completed during the current refueling outage (1R25) to replace an adjacent check valve (V-31-5).
 
The inspectors reviewed the maintenance history of the flange and determined the  RHC spray line was bent on October 27, 2008, during the 1R22 refueling outage while removing the RPV closure head mirror insulation with the Reactor Building overhead documented in IR 836642 which included a cold spring stress evaluation as a contingency if the damaged piping was not replaced. Exelon staff provided the cold spring evaluation to the inspector and indicated this evaluation was not utilized because the visibly bent/damaged portion of piping was replaced during the 1R22 refueling outage up to the reactor pressure vessel head N7B nozzle, with the exception of the  2-inch upper flange on the RHC spray line and a short pipe and tee connection. The inspectors noted the evaluation, if utilized, would have only supported a single operating cycle. Exelon staff performed PT examinations of the 2-inch piping welds and flange socket weld that were not replaced and determined there were no indications of surface cracks. flange remained misaligned after pipe replacement in the 1R22 refueling outage. In review of IR 845395, the inspectors determined that on November 14, 2008, Exelon  procedure CC-AA-flange misalignment was a condition adverse to quality in accordance with Exelon procedure PI-AA- to quality as an all-inclusive term used in reference to any of the following: failures, malfunctions, deficiencies, defective items, and non-conformances. An action to replace the flange during the next refuel outage was tracked as an action in the work order system. The inspectors observed this condition was not entered into the corrective action program for evaluation of acceptability to defer this repair. The work order to replace the flange was subsequently removed by Exelon staff from the next three refueling outage work scopes (1R23, 1R24 and 1R25) without evaluation as to whether the misalignment was acceptable. The inspectors noted this misalignment likely contributed to a leak at the flange socket weld joint. During the nuclear steam supply system leak test on November 26, 2012, Exelon staff observed a through-wall leak in the N7B upper flange socket weld. Exelon staff completed a localized weld repair of the socket weld with the flange remaining bolted in accordance with the ASME Boiler and Pressure Vessel Code, Section XI. Exelon staff completed an apparent cause evaluation under IR 1444414 and concluded the socket weld through-wall crack resulted from the RHC spray piping being bent on October 27, 2008. This condition induced mechanical stresses resulting in a defect in the socket weld base metal interface of the RHC spray line 2-inch upper flange. ause involving may have contributed to the flaw propagation. However, the inspectors noted the apparent cause evaluation did not reference IR 845395, which identified an actual misaligned condition of approximately
 
===.25 inches.===
 
The apparent cause evaluation also noted that during flange disassembly in 1R24 the bolts had to be cut. Upon further discussions with Oyster Creek station personnel the inspectors determined it was common practice to cut the RHC spray line flange bolts during reactor pressure vessel closure head piping disassembly activities because the bolts were seized. The inspectors confirmed this problem in review of IR 845395, IR 1135047, IR 1441461, IR 1441468, and IR 1430492. These IRs ensured the bolts were replaced as a corrective action but did not result in a corrective action to evaluate the misaligned flange as acceptable. Exelon staff revised procedure MA-OC-205-001, cutting.
 
Exelon staff completed corrective actions to replace the 2-inch RHC spray line upper flange on September 30, 2014 during the 1R25 refuel outage. The inspectors reviewed the associated documentation including the replacement work order, welding documentation, and the PT data records and verified that the welding activities and applicable non-destructive examination activities were performed in accordance with applicable ASME Boiler and Pressure Vessel Code requirements.
 
=====Analysis:=====
The inspectors determined that Exelon did not take prompt corrective actions, in accordance with 10 CFR 50, Appendix B, Criterion XVI, to address misalignment of the reactor head cooling spray piping flange, which was a performance deficiency that because it is associated with the equipment performance attribute (a misaligned flange) of the Initiating Events cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, misalignment of the RHC spray line flange was greater than that provided in Oyster Creek pipe specifications and resulted in additional stresses in the flange weld. This condition was described by Exelon staff as a possible contributor to the occurrence of a through wall crack and leak in the N7B upper flange socket weld joint that was identified and repaired in November 2012, but the misalignment was not corrected at that time. This issue is also similar to observed flange misalignment could increase stresses in the flange socket weld and adjacent components, and likely contributed to a leak at the flange socket weld joint.
 
Initial Screening and d the finding as very low safety significance (Green). Using Exhibit 1 of Question 1 because the worst-case degradation would be a small leak from a fatigue crack caused by operating thermal and/or mechanical loads combined with cold spring only result in a small leak in the Schedule 80 socket weld of RHC spray line 2-inch upper flange connection and would not have affected other systems used to mitigate a loss of coolant accident. Based on the leakage observed from the pinhole location in the 2-inch socket weld during the 1R24 outage reactor leak test (conducted at 1030 psig, 206 degrees F) the reactor coolant leak rate would likely be much less than the technical specification limit of 5 gallons per minute (gpm) unidentified leakage and leakage would not be expected to increase greater than the make-up capacity of a control rod drive pump (110 gpm). Additionally, operations personnel could have manually depressurized the reactor pressure vessel if needed and all other mitigating systems equipment was available. The inspectors determined that this finding had a Problem Identification and Resolution cross-cutting aspect because Exelon did not thoroughly evaluate and take timely corrective actions to address the long-standing repetitive flange alignment issue of the reactor head cooling spray piping flange connection to the reactor pressure vessel head N7B nozzle (P.2).
 
=====Enforcement:=====
part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected. Contrary to the above, since identification in IR 845395, dated November 14, 2008, Exelon staff did not correct a condition adverse to quality regarding the non-conforming, 2-inch RHC spray line upper flange connection to the reactor pressure vessel head N7B nozzle that corrective action to restore compliance consisted of replacing the 2-inch RHC spray line upper flange on September 30, 2014. Because this issue is of very low safety significance (Green) and Exelon entered this issue into their corrective action program as IR 2385501, this finding is being treated as an NCV consistent with Section 2.3.2 of the Enforcement Policy.  (NCV 05000219/2014005-01, Reactor Head Cooling Spray Piping Flange Misalignment)
{{a|1R11}}
==1R11 Licensed Operator Requalification Program==
{{IP sample|IP=IP 71111.11Q|count=3}}
 
===.1 Quarterly Review of Licensed Operator Requalification Testing and Training===
 
====a. Inspection Scope====
The inspectors observed licensed operator simulator training on October 21, 2014, which included a loss of B1 bus coincident with a large break loss of coolant accident and the failure of the No. 2 EDG. The inspectors also observed licensed operator simulator training on November 5, 2014, which included a loss of core spray system I coincident with a large break loss of coolant accident and the failure of the No. 1 EDG. The inspectors evaluated operator performance during the simulated event and verified completion of 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 and the technical specification action statements entered by the shift technical advisor. Additionally, the inspectors assessed the ability of the crew and 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 licensed operator performance during plant startup activities following refueling outage 1R25 on October 13, 2014. The inspectors observed infrequently performed test or evolution briefings, pre-shift briefings, and reactivity contOperations Section Expectations Handbook and Exelon Administrative Procedure  OP-AA-Additionally, the inspectors observed test performance 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.
{{a|1R12}}
==1R12 Maintenance Effectiveness==
{{IP sample|IP=IP 71111.12|count=1}}
 
====a. Inspection Scope====
The inspectors reviewed the sample listed below to assess the effectiveness of maintenance activities on structures, systems or components performance and reliability. The inspectors reviewed system health reports, corrective action program documents, maintenance work orders, and maintenance rule basis documents to ensure that Exelon was identifying and properly evaluating performance problems within the scope of the maintenance rule. For each sample selected, the inspectors verified that the structure, system or component was properly scoped into the maintenance rule in accordance with 10 CFR 50.65 and verified that the (a)(2) performance criteria established by Exelon staff was reasonable. As applicable, for a structure, system or component classified as (a)(1), the inspectors assessed the adequacy of goals and corrective actions to return the structure, system or component to (a)(2). Additionally, the inspectors ensured that Exelon staff was identifying and addressing common cause failures that occurred within and across maintenance rule system boundaries.
 
Turbine building closed cooling water system on December 24, 2014
 
====b. Findings====
No findings were identified.
{{a|1R13}}
==1R13 Maintenance Risk Assessments and Emergent Work Control==
{{IP sample|IP=IP 71111.13|count=3}}
 
====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 Exelon 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 Exelon personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the assessments were accurate and complete. When Exelon performed emergent work, the inspectors verified that operations personnel promptly assessed and managed plant risk. The inspectors reviewed the scope of maintenance work and discussed the results of the 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.
 
Core spray system 1 maintenance window on November 12, 2014 Standby liquid control system inservice and surveillance testing on December 1, 2014  operating switch on December 16, 2014
 
====b. Findings====
No findings were identified.
{{a|1R15}}
==1R15 Operability Determinations and Functionality Assessments==
{{IP sample|IP=IP 71111.15|count=1}}
 
====a. Inspection Scope====
The inspectors reviewed operability determinations for the following degraded or non-conforming conditions:  Isolation condenser makeup capabilities with the normal fire system isolated for leak repair on November 28, 2014  The inspectors selected this sample based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the operability determination 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 Exelon. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations.
 
====b. Findings====
No findings were identified.
{{a|1R18}}
==1R18 Plant Modifications==
{{IP sample|IP=IP 71111.18|count=2}}
 
===.1 Temporary Modifications===
 
====a. Inspection Scope====
The inspectors reviewed the temporary modifications listed below to determine whether the modifications affected the safety functions of systems that are important to safety. The inspectors reviewed 10 CFR 50.59 documentation and post-modification testing results, and conducted field walkdowns of the modifications to verify that the temporary modifications did not degrade the design bases, licensing bases, and performance capability of the affected systems.
 
lation during cold temperatures  Temporary change to the condensate storage tank level instrumentation
 
====b. Findings====
No findings were identified.
{{a|1R19}}
==1R19 Post-Maintenance Testing==
{{IP sample|IP=IP 71111.19|count=4}}
 
====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.
 
Refurbishment of main steam isolation valve (V-1-8) on October 8, 2014  Containment spray motor 1-1 after oil change and general inspection on October 27, 2014  Replace A core spray booster pump (P-20-2A) undervoltage time delay relay on November 11, 2014  Troubleshoot and repair of C1 battery charger on December 11, 2014
 
====b. Findings====
No findings were identified.
{{a|1R20}}
==1R20 Refueling and Other Outage Activities==
{{IP sample|IP=IP 71111.20|count=1}}
 
====a. Inspection Scope====
Oyster Creek began the inspection period shutdown for the 1R25 Refueling outage, which begaschedule and outage risk plan for the refueling outage, which was conducted  development and implementation of outage plans and schedules to verify that risk, industry experience, previous site-specific problems, and defense-in-depth were activities following the refueling outage on October 11-12, 2014. The reactor automatically scrammed, at approximately 1 percent power, due to a human performance error during troubleshooting of the main generator automatic voltage regulator. Following repairs,  during plant startup on October 13, 2014. Exelon placed the generator on the grid on October 15, 2014. During the outage, the inspectors monitored controls associated with the following outage activities:
Configuration management, including maintenance of defense-in-depth, commensurate with the outage plan for the key safety functions and compliance with the applicable technical specifications when taking equipment out of service  Implementation of clearance activities and confirmation that tags were properly hung and that equipment was appropriately configured to safely support the associated work or testing  Status and configuration of electrical systems and switchyard activities to ensure that technical specifications were met  Monitoring of decay heat removal operations  Impact of outage work on the ability of the operators to operate the spent fuel pool cooling system  Reactor water inventory controls, including flow paths, configurations, alternative means for inventory additions, and controls to prevent inventory loss  Activities that could affect reactivity  Maintenance of secondary containment as required by technical specifications  Identification and resolution of problems related to refueling outage activities
 
====b. Findings====
No findings were identified.
{{a|1R22}}
==1R22 Surveillance Testing==
{{IP sample|IP=IP 71111.22|count=5}}
 
====a. Inspection Scope====
The inspectors observed performance of surveillance tests and/or reviewed test data  of selected risk-significant structures, systems or components to assess whether test results satisfied technical specifications, the UFSAR, and Exelon 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:  Automatic depressurization system actuation circuit test and calibration on October 8, 2014  Main steam isolation valve leak rate test (South Header) (V-1-8/NS-03B & V-1-10/NS-04B) on October 24, 2014  Containment spray and emergency service water system 1 pump operability and quarterly inservice test on October 27, 2014  Safety relief valve inservice test on October 29, 2014  Loss of offsite power and loss of coolant accident actuation test for the No. 2 EDG on November 6, 2014
 
====b. Findings====
No findings were identified.
 
===Cornerstone:===
Emergency Preparedness  1EP4 Emergency Action Level and Emergency Plan Changes (IP 71114.04  1 sample)
 
====a. Inspection Scope====
Exelon implemented various changes to the Oyster Creek Emergency Action Levels (EALs), Emergency Plan, and Implementing Procedures. Exelon had determined that, in accordance with 10 CFR 50.54(q)(3), any change made to the EALs, Emergency Plan, and its lower-tier implementing procedures, had not resulted in any reduction in effectiveness of the Plan, and that the revised Plan continued to meet the standards in 50.47(b) and the requirements of 10 CFR 50 Appendix E.
 
The inspectors performed an in-office review of all EAL and Emergency Plan changes submitted by Exelon as required by 10 CFR 50.54(q)(5), including the changes to lower-tier emergency plan implementing procedures, to evaluate for any potential reductions in effectiveness of the Emergency Plan. This review by the inspectors was not documented in an NRC Safety Evaluation Report and does not constitute formal NRC approval of the changes. Therefore, these changes remain subject to future NRC inspection in their entirety. The requirements in 10 CFR 50.54(q) were used as reference criteria.
 
====b. Findings====
No findings were identified.
{{a|1EP6}}
==1EP6 Drill Evaluation==
{{IP sample|IP=IP 71114.06|count=1}}
 
===.1 Training Observations===
 
====a. Inspection Scope====
The inspectors observed a simulator training evolution for Oyster Creek Nuclear Generating Station licensed operators on October 21, 2014, which required emergency plan implementation by an operations crew. Exelon planned for this evolution to be evaluated and included in performance indicator data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the crew. The inspectors also attended the post-evolution critique for the scenarsame issues and entered them into the corrective action program.
 
====b. Findings====
No findings were identified.
 
===2. ===
===Cornerstone:===
Public Radiation Safety and Occupational Radiation Safety  (71124.01  1 sample)  a.
 
b.
 
  (71124.02  1 sample)  a.
 
    ----
b. No findings were identified.
 
(71124.05)  a.
 
        -        -     
-  -      -
b.
 
a.
 
b.
 
==OTHER ACTIVITIES==
{{a|4OA1}}
==4OA1 Performance Indicator Verification==
{{IP sample|IP=IP 71151}}
===.1 Mitigating Systems Performance Index (5 samples)===
 
====a. Inspection Scope====
Index for the following systems for the period of October 1, 2013 through September 30, 2014:  Emergency Alternating Current (AC) Power System  High Pressure Injection System  Heat Removal  Isolation Condensers Residual Heat Removal (RHR)  Containment Spray  Cooling Water System  To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in Nuclear Energy Institute (NEI) Document 99-condition reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports to validate the accuracy of the submittals.
 
====b. Findings====
No findings were identified.
 
a.  -    b. No findings were identified.
 
a.  -
b.
 
{{a|4OA2}}
==4OA2 Problem Identification and Resolution==
{{IP sample|IP=IP 71152|count=5}}
 
===.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 Exelon 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 indicate the existence of more significant safety issues. The inspectors performed a focused review on issue reports that potentially could be screened as Maintenance Rule Functional Failures to determine if there were trends or precursors that could be identified and to review the effectiveness of corrective actions. The inspectors reviewed issue reports generated during the second and third quarter of 2014 to determine if the issue reports were screened and investigated in accordance with Exelon procedures. The inspectors also reviewed issue reports for the third and fourth quarters of 2013 to assess if trends exist in various subject areas (equipment problems, human performance issues, etc.), as well as individual issues identified during the NRC daily condition report review.
 
====b. Findings and Observations====
No findings were identified. The inspectors noted that Oyster Creek is generating issue reports at an appropriate rate and threshold. No discernable new trends were identified.
 
The inspectors noted that issues were generally screened appropriately and investigations were assigned in accordance with Exelon corrective action program procedures and in most instances the issue reports were appropriately and timely screened for Maintenance Rule Functional Failures.
 
The inspectors noted that issue reports pertaining to the acoustic and thermocouple monitoring systems for the electromatic relief valves were not properly screened and evaluated in some cases in accordance with their condition based monitoring program. This resulted in the Post Accident Monitoring system requiring an (a)(1) evaluation in accordance with the Maintenance Rule Program. The inspectors independently screened this issue as minor in accordance with IMC 0612 because the system never lost its ability to perform its function. The inspectors also noted that there were a higher number of issue reports that were identified by oversight organizations. The issues identified by the oversight organizations tended to be more insightful than those that were self-identified. They also had the tendency to identify issues at a lower threshold. The inspectors discussed with plant management that more issue reports could be generated and they could be more self-critical when reviewing their performance at the worker and first line levels.
 
===.3 Annual Sample: Review of the Operator Workaround Program===
 
====a. Inspection Scope====
The inspectors reviewed the cumulative effects of the existing operator workarounds, operator burdens, existing operator aids and disabled alarms, and open main control room deficiencies to identify any effect on emergency operating procedure operator actions, and any impact on possible initiating events and mitigating systems. The inspectors evaluated whether station personnel had identified, assessed, and reviewed operator workarounds as specified in Exelon procedure OP-AA-102-Work-  room distractions to minimize operator burdens. The inspectors reviewed the system used to track these operator workarounds and recent Exelon self-assessments of the program. The inspectors also toured the control room and discussed the current operator workarounds with the operators to ensure the items were being addressed on  a schedule consistent with their relative safety significance.
 
====b. Findings and Observations====
No findings were identified.
 
The inspectors determined that the issues reviewed did not adversely affect the capability of the operators to implement abnormal or emergency operating procedures. The inspectors also verified that Exelon entered operator workarounds and burdens into the corrective action program at an appropriate threshold and planned or implemented corrective actions commensurate with their safety significance.
 
===.4 Annual Sample: EDG Cooling Fan Shaft Failure===
 
====a. Inspection Scope====
The inspectors performed an in-cooling fan upper shaft sheared into two pieces during a bi-weekly surveillance test, which resulted in a loss of cooling and subsequent inoperability of EDG No. 2. entification threshold, cause analyses, extent of condition reviews, compensatory actions, and the prioritization and timeliness characterizing, and correcting problems associated with this issue and whether the planned or completed corrective actions were appropriate. The inspectors compared the Appendix B. In addition, the inspectors performed field walkdowns and interviewed engineering personnel to assess the effectiveness of the implemented corrective actions. b. Observations  The inspectors concluded that Exelon staff conducted an appropriate technical review in sufficient detail to identify the likely causes of the fan shaft failure. Their review included a metallurgical examination performed by a laboratory (Exelon Power Labs) and a fatigue analysis performed by a third party contractor. The inspectors also concluded that Exelon staff identified the extent of condition which was limited to the one redundant EDG unit. Corrective actions included replacement of the failed EDG No. 2 fan shaft, ultrasonic testing of the EDG No. 1 fan shaft for potential degradation, and reducing the level of fan belt tension on both EDG units.
 
Exelon staff documented in their apparent cause evaluation that the shaft failure occurred via rotational bending fatigue. Based on observations of the fracture surface, Exelon staff determined that cracking initiated at a grooved location in the shaft, which acted as a stress concentration, and cracking propagated by a high-cycle, low-stress fatigue mechanism. Exelon staff further documented that no material defects were observed on the shaft outer surface that would have contributed to the failure initiation. Exelon staff concluded that the apparent cause of the shaft failure was a higher than average stress concentration factor due to a manufacturing deficiency at the grooved location and that the contributing cause was the EDG belt tension setting did not provide adequate margin necessary to address stress risers at the notch in the shaft. These conclusions were reported to the NRC in License Event Report (LER) 2014-003, dated November 11, 2014 (ADAMS accession number ML14325A598). with the safety significance, was timely, and included appropriate compensatory actions. The inspectors concluded that actions completed to re-evaluate the fan belt tension, revise maintenance procedures to decrease belt tension acceptance criteria, and take action to lower the belt tension on both EDG No. 1 and EDG No. 2 were reasonable to correct the problem and prevent reoccurrence. Action completed to examine the EDG No. 1 shaft by ultrasonic testing was appropriate to determine a crack had not initiated in the shaft at the grooved location (i.e. highest stress area). Exelon staff also initiated a planned corrective action to replace the EDG No. 1 shaft. Notwithstanding, the inspectors determined that in their review of the EDG maintenance records, Exelon staff missed an opportunity to identify their maintenance staff did not use calibrated measurement and test equipment for the field measurement of EDG cooling fan belt tensions. Specifically, the belt tension meter used to measure fan belt and test equipment by Exelon and was not certified or calibrated. In response to 2015, and it was found to be within calibration tolerances. Exelon staff entered this issue into their corrective action program (IR 2434265). While this issue represented a violation involving 10 CFR 50, Appendix B, Criterion XII regarding control of measurement and test equipment for safety-related activities, inspectors determined that this issue was minor because no equipment operability or functionality was adversely impacted. In accordance with IMC 0612, "Power Reactor Inspection Reports," the above issue constituted a violation of minor significance that is not subject to enforcement action in accordance with the Enforcement Policy.
 
====c. Findings====
 
=====Introduction.=====
The inspectors identified a preliminary White finding and associated Exelon did not review the suitability of the application of a different maintenance process at Oyster Creek Nuclear Generating Station that was essential to a safety-related function of the EDGs.
 
=====Description.=====
On July 28, 2014, EDG No. 2 was operated for its bi-weekly load received. Following shutdown of the EDG unit, the fan duct access was opened and Exelon staff discovered that the cooling fan upper shaft had sheared into two pieces at placing the fan shaft, performing ultrasonic testing on the EDG No. 1 fan shaft for extent of condition, and initiating an apparent cause evaluation to investigate and identify the causes of the shaft failure.
 
Oyster Creek is equipped with two identical EDG units. The function of the EDGs is to provide AC power to the safety-related class 1E busses upon a loss of off-site power. The EDG units are installed in self-contained enclosures inside the EDG vaults and are cooled via radiators in duct compartments configured atop the engine. Cooling air to each engine is drawn into this duct by a large fan. The fan is supported and rotated by a belt-driven shaft (upper shaft) that is, in turn, rotated by a power-takeoff shaft (lower shaft) connected to the engine. As part of their investigation, Exelon staff sent parts of the shaft section and bearing to Exelon Power Labs for failure analysis and also utilized a vendor to perform a stress analysis on fatigue crack initiation and growth. Exelon Power Labs concluded that the fracture was caused by rotational bending fatigue, and the cracking initiated at the shaft groove diameter transition, which would act as a high stress concentrator. Exelon Power Labs also concluded that no material defects were observed on the shaft outer diameter surface that would have contributed to the initiation of the fatigue failure. Based on the laboratory failure results, Exelon staff analyzed the mechanical loads placed on the fan shaft and determined the crack growth time period. Exelon staff concluded that the potential causes of rotational bending fatigue were:  1) the shaft hub loading exceeded the material properties, or 2) a defect produced a stress riser at the groove location in the shaft. Exelon staff further concluded that the EDG No. 2 could have met its mission time (24 hours) approximately four test cycles (or 42 days) prior to surface and supporting crack growth calculations.
 
Exelon staff reported the results of their apparent cause evaluation in LER 2014-003, dated November 11, 2014. Exelon staff concluded that the EDG No. 2 fan shaft likely failed due a higher than average stress concentration factor caused by a manufacturing deficiency in the grooved location on the shaft. Exelon staff further reported that limited detail was available from the shaft manufacturer regarding shaft groove profile, surface finish, and material properties. Exelon staff reported that the increased belt tension was a contributing cause because the increased belt tension did not provide adequate margin to address stress risers at the groove. As part of the corrective actions, Exelon staff performed a technical evaluation to determine the correct belt tension, reduced the fan belt tensions on both EDGs, and revised the acceptance criterion stated in the EDG belt maintenance procedure from 60 Hz to 47.4 Hz. Exelon staff also recommended that fan shaft vibration performance monitoring be implemented in the EDG 24-month inspection. The inspectors reviewed the apparent cause analysis and supporting failure analysis reports, and performed independent reviews of the shaft stresses and fatigue life based on those stresses. The inspectors determined and shaft dimensions, the belt tension acceptance criterion of 60 (+/- 2) Hz specified in reported fatigue endurance limit of the shaft material (i.e. the fan shaft would no longer operate indefinitely). The inspectors also determined that EDG No. 2 likely operated for a sufficient time at this stress level such that a crack could be initiated in the shaft. Specifically, the fan belt tension corresponding to the acceptance criteria likely caused the fan shaft to accumulate fatigue usage periodically every two years when the fan belt was re-tensioned at a value above its endurance limit. The inspectors noted that the EDG No. 2 fan belt was tensioned between 59 to 61 Hz as recorded in previous work orders. analyses identified that Exelon staff used a nominal shaft diameter of 3.0 inches in their stress calculations and not the measured shaft diameter of 2.939 inches. The inspectors observed the measured diameter was identified as an input to their analysis, but the nominal shaft diameter was used. The inspectors discussed this observation with Exelon staff and determined that the stress concentration factor utilized in the analysis served as a bounding stress concentration factor for the shaft groove area. Exelon staff further stated that this bounding stress concentration factor would account for small differences in the shaft dimensions. The inspectors determined utilizing the measured diameter in their stress calculations was appropriate for failure analysis of this specific shaft. Using the measured shaft diameter increased the calculated shaft stresses at the analyzed belt tension loads. Considering the stress concentration from the groove (a diameter, the inspectors determined the belt tension acceptance criteria at 60 Hz (i.e. hub load) resulted in a calculated stress greater than the reported endurance limit of the shaft material. The inspectors noted this conclusion differed from information in LER 2014-003 that indicated the hub load at 60 Hz produced stresses in the shaft groove transition of 19.15 kips/inch2 performance. Prior to May 2005, Exelon staff followed the instructions in the diesel generator vendor manual for performing maintenance on the diesel cooling system, which included the cooling fan belt. The vendor manual directed tensioning of the belt until it deflected approximately 7/16 inch with an applied force of 10 to 13 pounds. As part of corrective actions from a loose belt issue on EDG No. 1 in 2004, Exelon staff created a new procedure, MA-OC-86103-hanged the method for tensioning the belt from a standard belt deflection technique to measuring the frequency at which the belt vibrates after being struck with an object. The frequency of the belt corresponds to belt tension. Exelon established an acceptance criterion of 60.6 (+/- 1) Hz; however, there was not a documented or referenced evaluation that described how the frequency acceptance criterion in the new procedure was calculated or whether this frequency was equivalent to the deflection criterion in the vendor manual. The inspectors noted that the belt tension acceptance criteria in procedure MA-OC-86103-100 was subsequently revised to 60 (+/- 2) Hz on April 9, 2008 in Revision 2.  -AA-essing of procedure was a new task or significantly altered the methodology previously used. Procedure validation would have verified the procedure could be performed and that the acceptance criteria were adequate. The inspectors identified that this validation step was not performed during the processing of maintenance procedure MA-OC-86103-100 when it was issued in 2005. The inspectors determined procedure AD-AA-101 also required the station qualified reviewer to determine if a cross-disciplinary review was necessary; however, the inspectors identified that a cross-discipline review was not performed by engineering staff during the processing of MA-OC-86103-100, although there was a significant increase in shaft loading from the increased belt tension. The procedure was processed by maintenance department staff only. The inspectors determined that these are two examples where Exelon staff did not implement procedural requirements and are therefore performance deficiencies. Analysisthe acceptance criteria of a new EDG belt maintenance process, essential to a safety-related function of the EDGs, in accordance with 10 CFR 50, Appendix B, Criterion III, foresee and correct and should have been prevented. Specifically, an evaluation would have reasonably considered the stress placed on the fan shaft due to increasing the belt tension and evaluated the margin in the shaft design considering the controls placed on shaft dimensions, material and surface finish. An evaluation, if conducted, would also have likely involved EDG vendor consultation regarding this change. This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and 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). In accordance with Appendix ance Determination Process for Findings At-June 19, 2012, the inspectors screened the finding for safety significance and determined that a detailed risk evaluation was required because EDG No. 2 was inoperable for greater than the technical specification allowed outage time. Based upon the detailed risk evaluation, the calculated change in core damage frequency for this issue was 5.1E-6, or low to moderate safety significance (White). The dominant internal core damage sequences involved various losses of offsite power initiating events followed by failure of the remaining 4160 Volt AC emergency bus. The dominant external event core damage sequences involved switchyard fires that contributed to loss of offsite power. The time that the EDG was available before failure was credited in the analysis and afforded operators more time to recover offsite power, which lowered the risk of this issue. Also, diverse make-up sources to the isolation condenser and availability of the Forked River Combustion Turbine Generators helped mitigate the risk. An exposure time of 44 days (42 days plus two days for corrective maintenance) was used for the time the EDG could have met its 24 hour mission time. A detailed analysis is contained in Attachment 1 of this report. This finding does not have an associated cross-cutting aspect because the performance deficiency occurred in 2005 and is not reflective of present performance. Enforcementrt, that of materials, parts, equipment, and processes that are essential to the safety-related res shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the m May 13, 2005, to September 9, 2014, Exelon did not review the suitability of the application of a different maintenance process at Oyster Creek that was essential to a safety-related function of the EDGs. Specifically, Exelon changed the method for tensioning the cooling fan belt on the EDG from measuring belt deflection to belt frequency and did not verify the adequacy of the acceptance criteria stated for the new method. As a result, Exelon did not identify that the specified belt frequency imposed a stress above the fatigue endurance limit of the shaft material, making the EDG cooling fan shaft susceptible to fatigue and failure on July 28, 2014. As a consequence of this design control issue, Exelon also violated Technical Specification 3.7.C, because EDG No. 2 was determined to be inoperable for greater than the technical specification allowed corrective action program (IR 1686101), replacement of the EDG No. 2 fan shaft, examining the EDG No. 1 fan shaft for extent of condition, and initiating a failure analysis to determine the causes of the broken shaft. This issue is being characterized as an AV  significance will be dispositioned in separate future correspondence. (AV 05000219/2014005-02, Inadequate Review of Change in Maintenance Process Results in Inoperable Emergency Diesel Generator)
 
===.5 Annual Sample: Reactivity Management Event===
 
====a. Inspection Scope====
The inspectors conducted a Problem Identification and Resolution sample for evaluation of corrective actions associated with a reactor re-criticality during plant shutdown activities on July 8, 2014.
 
The inspectors reviewed and assessed crew operator performance and crew decision making, including adherence to expected roles and responsibilities, the use of command and control elements associated with reactivity manipulations, the use of procedures, the use of diverse instrumentation to assess plant conditions and overall implementation of operations department and station standards; determined the appropriateness and safety significance of up-ranging on intermediate range monitors (IRM) during this event; determined the appropriateness and safety significance of inserting each SRM individually rather than fully inserting all SRMs over one continuous stroke; reviewed  taken to date, including overall organizational response, evaluation of the apparent cause, and adequacy of corrective actions; reviewed the adequacy of the preparation by the operations staff for the reactor shutdown including training prior to the evolution and briefings by the operations staff; reviewed the adequacy of operator requalification training as it related to this event; assessed the decision making and actions taken by the operators during the reactor shutdown to determine if there are any implications related to safety culture; reviewed the adequacy of the simulator to model the behavior of the current reactor core during shutdown activities and the current adequacy of the industry operating experience and assessed the effectiveness of any actions taken in response to the operating experience.
 
====b. Findings and Observations====
===.1 Inadequate Plant Shutdown Procedure===
 
=====Introduction.=====
The inspectors identified a Green NCV of Technical Specification 6.8.1(a), adequately established and maintained. Specifically, the procedure was not adequate in that it did not contain precautions concerning rod insertion when reactor power is below the point of adding heat; operational limitations on plant cooldown when power is below the point of adding heat and contingency actions for re-criticality during shutdown.
 
=====Description.=====
On July 8, 2014, while performing a technical specification required plant shutdown to address electromatic relief valve operability concerns, licensed operators allowed the reactor to regain criticality twice when power was below the point of adding heat. reactor scram. As compared to a normal shutdown with a reactor scram inserted from approximately 10 percent power, a soft shutdown requires additional time for complete manual insertion of all control rods. Due to delays experienced during shutdown and the additional time for rod insertion, positive reactivity effects from xenon (xenon was decaying vice rising), and reactor cooldown associated with existing steam loads, become more significant when reactor power is reduced below the point of adding heat.
 
The positive reactivity effects of xenon and cooldown must be countered by the negative reactivity contributed by control rod insertion. The inspectors noted that Procedure 203 did not contain any precautionary guidance to alert the operators concerning the need to prioritize control rod insertion during soft shutdown. Additionally, the inspectors noted that Procedure 203 did not contain any amplifying guidance as to the necessity to limit reactor cooldown during soft shutdown.
 
Operators had proceeded with rod insertion and the reactor shutdown sufficiently such that power was below the point of adding heat and the reactor was subsequently subcritical. When the operators stopped control rod insertion during the shutdown  to partially insert individual SRMs, the reactor regained criticality due to the positive reactivity being added by the xenon decay and reactor cooldown. The operators ranged IRMs up to keep power visible on range and recommenced rod insertion, which turned power downward and made the reactor subcritical. Operators again stopped control rod insertion to further insert SRMs, and again the reactor regained criticality due to positive reactivity effects. Operators were directed to continuously insert control rods by the unit supervisor, the reactor was made subcritical and the shutdown proceeded until all control rods were fully inserted. The inspectors noted that Procedure 203 did not contain any contingency actions for situations where the reactor regains criticality during shutdown.
 
=====Analysis.=====
The inspectors determined that not maintaining an adequate plant shutdown procedure in accordance with Technical Specification 6.8.1 is a performance deficiency ined this finding was more than minor because the finding affected the procedure quality attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the reliability and capability of systems that respond to initiating events. Specifically, the plant shutdown procedure did not contain precautions to continuously insert control rods when reactor power is less than the point of adding heat, did not define operational considerations for limiting reactor cooldown and did not contain contingency actions for return to criticality during shutdown.
 
Process for Findings At-because the finding resulted in a mismanagement of reactivity by operators in that they demonstrated an inability to anticipate and control changes in reactivity during plant operations. As such, inspectors assessed this finding using IMC 0609 Appendix M, performed the bounding analysis required by Appendix M. In this analysis, the senior reactor analyst made conservative assumptions that a transient had occurred in which the operators would have always failed to manually scram the reactor, and the reactor protective system had electrical failures which made it less reliable. This conservative analysis yielded a change in core damage frequency of 8.0E-7 and the finding was determined to be of very low safety significance (Green). This finding has a cross-cutting aspect in the area of Human Performance, Documentation, because Exelon did not ensure that the shutdown procedure contained adequate controls for soft shutdown. [H.7]  Enforcementpart, that written procedures shall be established, implemented, and maintained as recommended in Appendix A of Regulatory Guide 1.33, February 1978. Regulatory Guide 1.33, Appendix A discusses general plant operating procedures including Plant Shutdown to Hot Standby. Contrary to the above, prior to July 8, 2014, Exelon did not properly maintain procedure 203, Plant Shutdown to include precautions, clarifications, and contingency action for recriticality during soft shutdown. Because this violation was as IR 2412093, this violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000219/201405-03, Plant Shutdown Procedure Was Inadequate For Soft Shutdown)
 
===.2 Procedure Use and Adherence===
 
=====Introduction.=====
The inspectors identified a Green NCV of Technical Specification 6.8.1(a), implement procedures when performing a plant shutdown. Specifically, the operators did not ensure that all personnel on shift had received Just in Time Training for their role in the shutdown, operators did not perform a reactivity Heightened Level Awareness brief for the shutdown, and did not insert SRMs in accordance with procedure. These issues contributed to two unanticipated criticalities during the shutdown.
 
=====Description.=====
On July 8, 2014, prior to, and during the course of a technical specification required reactor shutdown, Oyster Creek licensed reactor operators did not implement written procedures. accordance with Attachment 203--Level A-Criticality due to Reactor Cooldown, Including Instrumentation to Monitor, and the Indications of Impending Re-not perform a reactivity Heightened Level Awareness brief covering the topics of Attachment 203-13, as indicated during personnel interviews. turnover occurs during the shutdown, then all relieving personnel have had Just-in- Time-Training for their rol-at-the-controls during the unanticipated criticalities did not attend the provided Just-in-Time-Training on July 7, 2014, prior to relieving the watch on July 8, 2014, as indicated by the training attendance sheet. Proc3 -SRM DRIVE CONTROL switincrementally inserted the SRM detectors into the reactor causing a delay in rod insertion when operating at low power levels.
 
=====Analysis.=====
The inspectors determined that the failure of personnel to implement procedures during the plant shutdown, in accordance with Technical Specification 6.8.1, prevent. The finding is more than minor because it was associated with the Human Performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the operator failure to implement procedures during the plant shutdown contributed to two unanticipated returns to criticality which required operator action to mitigate.
 
aracterization of  Process for Findings At-because the finding resulted in a mismanagement of reactivity by operators in that they demonstrated an inability to anticipate and control changes in reactivity during plant operations. As such, inspectors assessed this finding using IMC 0609 Appendix M, eactor analyst performed the bounding analysis required by Appendix M. In this analysis, the senior reactor analyst made conservative assumptions that a transient had occurred in which the operators would have always failed to manually scram the reactor, and the reactor protective system had electrical failures which made it less reliable. This conservative analysis yielded a change in core damage frequency of 8.0E-7 and the finding was determined to be of very low safety significance (Green). This finding has a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because licensed operators did not implement processes, procedures and work instructions during the plant shutdown. [H.8] 
 
=====Enforcement.=====
Technical Specification 6.8.1(a), part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Regulatory Guide 1.33, Appendix A requires that safety-related activities listed therein be covered by written procedures. Contrary to the above, on July 8, 2014, the licensee failed to properly implement safety-related procedures related to Regulatory Guide 1.33, Appendix A, -Because this violation was of very low safety significance and it was entered into NCV, consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000219/201405-04, Procedures Not Implemented During Plant Shutdown)
{{a|4OA3}}
==4OA3 Follow-Up of Events and Notices of Enforcement Discretion==
{{IP sample|IP=IP 71153|count=4}}
 
===.1 Plant Events===
 
====a. Inspection Scope====
For the plant events listed below, the inspectors reviewed and/or observed plant parameters, reviewed personnel performance, and evaluated performance of mitigating systems. The inspectors communicated the plant events to appropriate regional tential reactive inspection activities. As applicable, the inspectors verified that Exelon made appropriate emergency classification assessments and properly reported the event in accordance with 10 CFR Parts 50.72 and 50.73. The inspectors reviewed Exel-up actions related to the events to assure that Exelon implemented appropriate corrective actions commensurate with their safety significance.
 
Reactor scram during automatic voltage regulator troubleshooting on October 12, 2014
 
====b. Findings====
No findings were identified.
 
===.2 (Closed) Exelon Event Report (LER) 05000219/2013-005-01: Reactor Protection System Actuation with the Reactor in Hot Shutdown===
On December 17, 2013, while the plant was shut down, the plant experienced a reactor scram when taking the mode switch from refuel position to shutdown position. The jumpers required to prevent a full scram for the mode switch change were not installed as required by procedure. The reactor protection system actuation was a result of the reactor mode switch being placed from the refuel position to the shutdown position without the scram bypass jumpers installed.
 
The root cause determined that an invalidated assumption by the supervisors resulted in a reactor scram while shut down. The reactor was subcritical with all rods inserted at the time of the reactor protection system actuation, therefore this is considered minor per IMC 0612. Inspectors completed a problem identification and resolution sample to review the details of the event in NRC inspection report 05000219/2014003, Section review. The inspectors did not identify any violations or new issues during the review of the LER. This LER is closed.
 
===.3 (Closed) Exelon Event Report (LER) 05000219/2014-003-00: Technical Specification Prohibited Condition Caused by EDG Inoperable for Greater than Allowed Outage Time===
The inspectors reviewed Exelon's actions and reportability criteria associated with LER 05000219/2014-003-00, which was submitted to the NRC on November 11, 2014 (ML14325A598). On July 28, 2014, EDG No. 2 failed during its bi-weekly load surveillance test. The cause of the failure was determined to be rotational bending performing ultrasonic testing on the EDG No. 1 fan shaft for extent of condition, and performing an apparent cause evaluation. The apparent cause evaluation concluded that the EDG was inoperable for approximately 43 days. The inspectors determined that Exelon violated Technical Specification 3.7.C, because EDG No. 2 was determined to  be inoperable for greater than the technical specification allowed outage time of 7 days. However, this violation constitutes an additional example of violation AV 05000219/2014005-02, which is described section 4OA2.4.c of this report, and is not being cited individually. The inspectors did not identify any additional findings or violations of NRC requirements during the review of the LER. This LER is closed.
 
===.4 (Closed) Exelon Event Report (LER) 05000219/2014-004-00: Local Leak Rate Test Results in Excess of Technical Specifications===
 
On September 18, 2014, during the 1R25 refueling outage with the reactor in cold shutdown, Exelon discovered the as-found local leak rate test on main steam isolation valve V-1-8, did not meet the acceptance criteria of technical specification 4.5.D.2, -found leak rate for V-1-8 was  16 standard cubic feet per hour (SCFH) which exceed the technical specification acceptance criteria of 11.9 SCFH at a test pressure of 20 psid. The safety significance of the issue is considered minimal due to V-1-8 being installed in series with a second main steam isolation valve (V-1-10) in the affected steam header, which did meet the technical specification acceptance criteria and provides adequate margin between the projected offsite dose and 10 CFR 100 guidelines.
 
Exelon determined the cause of the failure to be material wear on the poppet and valve seat. The valve was repaired during 1R25 and successfully passed the local leak rate test.
 
The inspectors determined that the reported technical specification violation was minor, as it was not a precursor to a significant event, did not have the potential to lead to a more significant safety concern, did not relate to a performance indicator that would have exceeded a threshold, and did not adversely affect any of the cornerstone objectives. The inspectors did not identify any new issues during the review of the  LER. This LER is closed.
{{a|4OA6}}
==4OA6 Meetings, Including Exit==
On January 29, 2015, the inspectors presented the inspection results to Mr. G. Stathes, Site Vice President, and other members of the Oyster Creek Nuclear Generating Station staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.
 
ATTACHMENT 1: Detailed Risk Evaluation: Failure of EDG No. 2 Fan Shaft ATTACHMENT 2: Supplementary Information 1-ATTACHMENT 1: DETAILED RISK SIGNIFICANCE EVALUATION Oyster Creek Nuclear Generating Station Failure of Emergency Diesel Generator (EDG) 2 Fan Shaft  Conclusion:  The overall change in core damage frequency for the performance deficiency was 5.1E-6/year (White). Assumptions:  1. The fan shaft on EDG No. 2 failed due to rotational bending fatigue on July 28, 2014. The analyst assumed that the crack in the fan shaft initiated and propagated only during times that the diesel generator was running during its last 3 surveillance runs. This assumption was based on the fact that rotational bending fatigue would only propagate when the engine is started and run. Prior to that, the analyst assumed the shaft would have met its 24 hour mission time. There was no assumption of accelerated degradation associated with diesel starts or any degradation while the unit was in standby. The analyst assumed that the failure was a deterministic outcome set to occur after the specific number of operating hours which followed the completion of surveillance testing on June 16, 2014.
 
treated this idle time as 7.5 minutes of full speed run time to properly correlate this time to the appropriate number of cycles. This assumption was made because by running the EDG at half speed the number of fatigue cycles is cut in half. The table below lists the run history of EDG No. 2, with idle times included, to develop an adjusted full speed run time equivalent undergoing fatigue.
 
- - -                      For example, based on the data provided in the above table , on June 30, 2014, the EDG was run for 1.467 hours at full speed and then idled at half speed for 0.25 hours. Therefore the shaft accrued 1.592 hours of equivalent full speed run time to contribute to failure of the shaft. Adding in the times after June 30, the EDG would have started on a postulated demand and would have been able to run for 4.38 hours before shaft failure.
 
Additionally, the analyst assumed the EDG could not operate without the fan. The analyst assumed that EDG No. 2 would have run for a short period of time as engine temperatures rose to the point of actuating high temperature annunciators. The analyst assumed that operators would then secure the EDG or the EDG would fail soon thereafter. This time  was assumed to be 15 minutes and was added to the time the EDG fan shaft would fail for determining the total time the EDG would be available. The analyst grouped, or binned, 1-short runs within one day of each other to simplify the binning process. The bins of the run availability times and with the added 15 minutes are presented in the table below:  Bin Number Time period Number of days in bin EDG run time available 1 July 16  28 12 1.6 hours 2 June 30  July 16 16 3.0 hours 3 June 16  30 14 4.6 hours  For example, the analyst assumed that EDG No. 2 would have run for 1.6 hours if demanded, during the 12 day period from July 16 to July 28, 2014. Next, EDG No. 2 would have run for 3.0 hours, if demanded, during the 16 day period from June 30 to July 16, 2014. Before June 16, 2013, the analyst assumed that the fan shaft for EDG No. 2 would have met its 24 hour mission time assumed in the Standardized Plant Analysis Risk (SPAR) model. Therefore, prior to this date no additional risk impact was assumed. 2. The shaft took 41.75 hours (from 5:10 a.m. on July 28 to 11:00 p.m. on July 29) to replace and return to service. The EDG was assumed to have been unavailable during this repair time. Also from this, the EDG No. 2 was assumed to be non-recoverable within the mission time used for the EDG in the SPAR model. This made the total exposure time was from June 16, 2014, to July 29, 2014, or 44 days. 3. Common cause vulnerabilities for EDG No. 1 existed. The belt for the fan shaft for EDG No. 1 was covered by the same procedural tightening specifications. The fan shaft was of similar design, construction, and manufacture. Therefore, the analyst modeled the failure by setting Basic Event EPS-DGN-FR-the SPAR model. 4. The station began shutting down on July 7 due to electromagnetic relief valve concerns and experienced a reactor scram due to lowering condenser vacuum on July 11, 2014. During these shutdown periods, the plant was placed on shutdown cooling. The analyst assumed this time was not significant and assumed all of the risk was at-power  The Oyster Creek SPAR model, Revision 8.22, dated May 20, 2014, was used in the analysis. A cutset truncation of 1.0E-13 was used. Average test and maintenance was assumed. Internal Events
 
=====Analysis:=====
A. Risk Estimate for the 42-hour Repair Time period on July 28 through July 29, 2014:  During this 42-hour period, the analyst assumed that EDG No. 2 was completely unavailable as it was being repaired. The result was a conditional core damage probability of 1.52E-7 for the 61-hour period and an annualized core damage frequency (CDF) of 1.52E-7/year. B. Risk Estimate for the 12-day period between July 16 and July 28, 2014:  During this exposure period, EDG No. 2 was assumed to have been capable of running for 1.6 hours. The loss of offsite power (LOOP) frequencies used in the analysis were 1-would result in a risk increase attributable to the fan shaft failure. The analyst used the 1.5 hour values from the SPAR model to approximate 1.6 hours. The base LOOP frequencies from the SPAR model are listed in the second column of the table below. The analyst adjusted these base values by multiplying them by the respective 1.5-hour non-recovery probabilities of offsite power (in the third column) to obtain the frequency of each type of LOOP that was not recovered in 1.5 hours (in the fourth column). LOOP Type Base Frequency Offsite power non-recovery probability for 1.5 hours Adjusted LOOP non-recovery frequency Grid Centered (GC) 1.22E-02/year 0.5034 6.14E-03/year Switchyard Centered (SC) 1.04E-02/year 0.2920 3.04E-03/year Plant Centered (PC) 1.93E-03/year 0.2341 4.52E-04/year Weather Related (WR) 3.91E-03/year 0.6136 2.40E-03/year  In this bin, time of t=0 needed to be reset to 1.5 hours following the LOOP event for the recovery factors for offsite power. In the SPAR model, recovery times for offsite power are set at the intervals of 30 minutes, 1 hour, 4 hours, and 10 hours. For instance, in 1-hour sequences for recovery of offsite power in SPAR, the basic event for non-recovery of offsite power should be adjusted to the non-recovery at 2.5 hours, given that, recovery has failed at 1.5 hours after the LOOP began.
 
Also, an adjustment to account for the diminishment of decay heat must be considered. This is because the magnitude of decay heat following shutdown is less than in the early moments following a reactor trip, and the timing of core damage sequences is affected by this fact. The analyst determined that the average decay heat level in the first 30 minutes is approximately two times the average level that exists 3 to 4 hours following shutdown. Therefore, baseline 30-minute SPAR model sequences, which essentially, account for boil-off to fuel un-covering, were further adjusted to 1-hour sequences.
 
The 1-hour sequences were further changed to 1.5-hour sequences. The analyst determined that decay heat rates leveled out quickly following shutdown and could find no basis for adjusting the times associated with the 4 and 10-hour sequences. These decay heat adjustments were used for this bin and all following bins. The following table presents the adjusted offsite power non-recovery factors for the event times that are relevant in the SPAR core damage cutsets:
1-SPAR recovery time for specific LOOP Adjustment for decay heat diminishing Time adjustment for 1.5  hours of run time available  Adjusted LOOP non-recovery frequency for  1.5 hours (/year) SPAR base offsite power non-recovery at 1.5 hours adjusted to Column 3 times Modified SPAR non-recovery 30 minute Grid Centered 1 hour 2.5 hour 6.14E-03 0.320 0.636 30 minute Switchyard Centered 1 hour 2.5 hour 3.04E-03 0.182 0.623 30 minute Plant Centered 1 hour 2.5 hour 4.52E-04 0.144 0.615 30 minute Weather Related 1 hour 2.5 hour 2.40E-03 0.520 0.848 1 hour Grid Centered 1.5 hours 3 hour 6.14E-03 0.250 0.496 1 hour Switchyard Centered 1.5 hours 3 hour 3.04E-03 0.145 0.498 1 hour Plant Centered 1.5 hours 3 hour 4.52E-04 0.112 0.477 1 hour Weather Related 1.5 hours 3 hour 2.40E-03 0.480 0.782 4 hour Grid Centered 4 hour 5.5 hours 6.14E-03 0.087 0.173 4 hour Switchyard Centered 4 hour 5.5 hours 3.04E-03 0.059 0.201 4 hour Plant Centered 4 hour 5.5 hours 4.52E-04 0.044 0.187 4 hour Weather Related 4 hour 5.5 hours 2.40E-03 0.349 0.568 10 hour Grid Centered 10 hour 11.5 hours 6.14E-03 0.020 0.041 10 hour Switchyard Centered 10 hour 11.5 hours 3.04E-03 0.019 0.065 10 hour Plant Centered 10 hour 11.5 hours 4.52E-04 0.014 0.059 10 hour Weather Related 10 hour 11.5 hours 2.40E-03 0.233 0.380  The results of this bin of the analysis yielded a CDF of 3.49E-5/year for this bin. When the base case risk (1.25E-5/year) was subtracted from the bin CDF value and applied to a 12 day time period, the core damage probability of 7.36E-7 results. This was annualized to obtain a bin CDF of 7.36E-7/year.
 
1-C. Risk Estimate for the 16-day period between June 30 and July 16, 2014:  During this exposure period, EDG No. 2 was assumed to have been capable of running for 3.0 hours. The LOOP frequencies were adjusted to reflect the situation that only LOOPs with durations greater than 3 hours would result in a risk increase attributable to the fan shaft failure.
 
LOOP Type Base Frequency Offsite power non-recovery probability for 1.5 hours Adjusted LOOP non-recovery frequency Grid Centered (GC) 1.22E-02/year 0.250 3.05E-03/year Switchyard Centered (SC) 1.04E-02/year 0.145 1.51E-03/year Plant Centered (PC) 1.93E-03/year 0.112 2.16E-04/year Weather Related (WR) 3.91E-03/year 0.480 1.88E-03/year  The methodology was repeated from the 1.5 hour bin. Time of t=0 needed to be reset to 3.0 hours following the LOOP event for the recovery factors for offsite power. Also, the same adjustments to account for the diminishment of decay heat were applied.
 
The following table presents the adjusted offsite power non-recovery factors for the event times that are relevant in the SPAR core damage cutsets:
1-SPAR recovery time for specific LOOP Adjustment for decay heat diminishing Time adjustment for 3.0  hours of run time available  Adjusted LOOP non-recovery frequency for  1.5 hours (/year) SPAR base offsite power non-recovery at 1.5 hours adjusted to Column 3 times Modified SPAR non-recovery 30 minute Grid Centered 1 hour 4 hour 3.05E-03 0.169 0.675 30 minute Switchyard Centered 1 hour 4 hour 1.51E-03 0.102 0.705 30 minute Plant Centered 1 hour 4 hour 2.16E-04 0.078 0.694 30 minute Weather Related 1 hour 4 hour 1.88E-03 0.4244 0.884 1 hour Grid Centered 1.5 hours 4.5 hour 3.05E-03 0.144 0.577 1 hour Switchyard Centered 1.5 hours 4.5 hour 1.51E-03 0.089 0.613 1 hour Plant Centered 1.5 hours 4.5 hour 2.16E-04 0.067 0.600 1 hour Weather Related 1.5 hours 4.5 hour 1.88E-03 0.403 0.840 4 hour Grid Centered 4 hour 7 hours 3.05E-03 0.065 0.261 4 hour Switchyard Centered 4 hour 7 hours 1.51E-03 0.047 0.320 4 hour Plant Centered 4 hour 7 hours 2.16E-04 0.034 0.308 4 hour Weather Related 4 hour 7 hours 1.88E-03 0.321 0.670 10 hour Grid Centered 10 hour 13 hours 3.05E-03 0.017 0.067 10 hour Switchyard Centered 10 hour 13 hours 1.51E-03 0.016 0.113 10 hour Plant Centered 10 hour 13 hours 2.16E-04 0.012 0.107 10 hour Weather Related 10 hour 13 hours 1.88E-03 0.222 0.462  The results of this bin of the analysis yielded a core damage frequency (CDF) of 3.21E-5/year for this bin. When the base case risk (1.25E-5/year) was subtracted from the bin CDF value and applied to a 16 day time period, the core damage probability of 8.59E-7 results. This was annualized to obtain a bin CDF of 8.59E-7/year.
 
1-D. Risk Estimate for the 14-day period between June 16 and June 30, 2014:  During this exposure period, EDG No. 2 was assumed to have been capable of running for 4.6 hours. The LOOP frequencies were adjusted to reflect the situation that only LOOPs with durations greater than 4.5 hours would result in a risk increase attributable to the fan shaft failure. The methodology was repeated from the previous bins. Time of t=0 needed to be reset to 4.5 hours following the LOOP event for the recovery factors for offsite power. Also, the same adjustments to account for the diminishment of decay heat were applied.
 
The results of this bin of the analysis yielded a CDF of 2.97E-5/year for this bin. When the base case risk (1.25E-5/year) was subtracted from the bin CDF value and applied to a 14 day time period, the core damage probability of 6.59E-7 results. This was annualized to obtain a bin CDF of 6.59E-7/year. E. Combined Risk Estimate for Internal Events:  The following table presents the aggregate internal events result:  TIME PERIOD DAYS OF EXPOSURE DELTA CDF July 28 - 29 1.8 1.52E-7 July 16 - 28 12 7.36E-7 June 30 - July 16 16 8.59E-7 June 16 - 30 14 6.59E-7 Total Internal Events Delta-CDF 2.41E-6  External Events
 
=====Analysis:=====
scenarios, which would become more risk significant without the availability of EDG NO. 2.
 
Fire in Switchyard. One fire area, Fire Area MT-FA-12, included the startup transformers. For postulated fires in this area, offsite power was assumed to be lost. The analyst substituted the -3/year) and applied it to the internal events scenario for switchyard centered LOOPs. The analyst assumed that the fire removes offsite power. This was modeled by setting the startup transformers (described in the SPAR model as SB1 and SC1) to TRUE. The annualized CDF for this case of a switchyard centered LOOP was 8.59E-7. The conditional case sets the EDG No. 2 failing to run to TRUE. This results in a conditional CDF of 1.86E-5/year. Assuming the 44 day exposure period, the -6/year. The analyst noted this scenario was the dominant scenario. Fire in Switchgear 1C. The analyst noted that one of the initiators for internal events which contributed significant risk to internal risk was a Loss of Switchgear 1C. This plant state would represent degradation of power to both redundant trains of power for the redundant trains of safety equipment. The analyst assumed a fire in Switchgear 1C would produce a similar scenario. An estimate was derived by applying the value for fire initiating event likelihood (of 6.19E-4/year) from the Oyster Creek Fire PRA. This value accounted for the fire ignition frequency, severity factor, and non-suppression factor, and was substituted for the Loss of 1C 1-internal events initiating frequency. The analyst applied a 44 day exposure time to the results and obtained a change in CDF of 1.8E-7/year.
 
Fire in Switchgear 1A. Power to Switchgear 1C from offsite is fed by Switchgear 1A. Therefore, a loss of Switchgear 1A, would affect Switchgear 1C and have an impact on plant safety without EDG No. 2. The analyst performed a similar analysis as done with Switchgear 1C. The analyst applied a 44 day exposure time to the results and obtained a change in CDF of 2.7E-8/year. Fire in 1A2. This fire scenario represented a fire in the control room cabinet which would give operators control of the equipment on Switchgears 1A and 1C. The analyst applied a 44 day exposure time to the results and obtained a change in CDF of 1.8E-7/year. Many other fire scenarios were analyzed, but were determined to not be risk significant. The analyst combined the risk estimate of these fire scenarios to obtain a fire risk estimate of 2.64E-6/year. Exelon shared their preliminary fire risk assessment of this condition with the analyst. Their result yielded an estimate of 5.5E-6 based on a 43 day exposure period. Of note, Exelon informed the analyst that their fire PRA was conservative and that the licensee removed some of the conservatisms from their model to obtain a more realistic risk estimate. Exelon had not shared this revised analysis with the analyst, but stated the value was above, but close to 1E-6/year based on a 43 day exposure period. The analyst considered this value to be comparable to the results obtained from the NRC analysis (2.66E-6/year based on a 44 day exposure period). The analyst reviewed the risk due to EDG being unavailable during seismic events. The  analyst used the seismic hazard vectors of Oyster Creek contained in Table 4A-1 of Volume 2  External Events of the Risk Assessment of Operational Events Handbook. These vectors were applied to the switchyard insulators to verify any additional risk from a seismically induced LOOP. The analysis yielded an increase in risk of 2.1E-8, which the analyst considered negligible when compared to the internal events risk value.
 
did not consider flooding to be a significant risk contributor for this particular performance deficiency.
 
Based on the above, the analyst determined that only fire-related external events added significantly to the risk of the finding and it was estimated to be 2.64E-6/year.
 
Large Early Release Frequency (LERF)  The LERF assessment utilized NRC Inspection Manual Chapter 0609, Appendix H, EDG No. 2 was considered a Type A finding. The analyst screened out bins where EDG No. 2 was able to run for at least 12 hours, assuming that an early release was not possible with the diminishment of decay heat.
 
assumes 1.0 for high-pressure sequences with a dry drywell, and 0.6 for high-pressure sequences with a flooded drywell. The dry drywell value is bounding, but not necessarily conservative, in that liner melt-through is expected to occur shortly after vessel failure if the 1-drywell is dry. The flooded drywell value is affected by the mode of reactor coolant system rupture, operator actions following the onset of core damage, and phenomenological issues related to direct containment heating and fuel-coolant interactions.  -pressure vessel breach phenomena (namely, fuel-coolant interaction, liner-melt-through, and direct containment heating). The multiplier for converting CDF to LERF according to the licensee was approximately 8E-2. LERF FACTOR  Licensee PRA Factor (8E-2) 5.1E-6 4.1E-7 Appendix H, Flooded drywell (0.6) 5.1E-6 3.1E-6 Appendix H, Dry drywell (1.0) 5.1E-6 5.1E-6  the EDG would have run for at least 1.6 hours in the most conservative scenario, giving the operators time to commence plant depressurization. Recent evaluations (e.g., SOARCA Peach Bottom) have indicated that the likelihood of severe accident-induced main steam line creep rupture or a stuck-open relief valve prior to vessel breach is potentially higher than typically The Probability of High-Pressure Melt Ejection-Induced Direct Containment Heating Failure in  These failure modes would lead to a more benign containment response at the time of vessel breach, in terms of direct containment heating and fuel-coolant interaction-induced containment failure.
 
Exelon performed their preliminary analysis using a 43-day exposure period. The analyst noted but instead the licensee used only one day of repair time.
 
Exelon used similar assumptions in their analysis derived from a report from their contracted party. It included 42 days of crack propagation and one day of repair to conclude that the t repair -6 when common cause was applied for EDG No. 1 for internal events only and 1.6E-6 when common cause was not applied. This was compared to 2.41E-6 for the NRC internal analysis. review and noted that the results did not differ significantly. F result with a value of 1.6E-7/year. The analyst concluded that this LERF value was accurate enough to demonstrate that LERF results would not drive a different conclusion than the CDF results. Overall Risk Significance  The total change in core damage frequency for the period between June 16, 2014, and July 29, 2014 (44 days), was estimated as the sum of internal risk (2.41E-6) and external risk (2.64E-6) to obtain an aggregate risk of 5.1E-6/year.
 
1-Sensitivities  Use of a 211 day exposure period. The analyst considered use of a 211 day exposure period in the SPAR with common cause applied and crack development was considered. Internal events were estimated at 8.45E-6. Risk from external events (fire) was estimated at 1.26E-5/year. This yielded a combined change in CDF of 2.1E-5/year.
 
Use of a 100 day exposure period. The analyst considered use of a 100 day exposure period in the SPAR with common cause applied and failure to be only possible after crack initiation at 98 days prior to failure. This analysis was to estimate if crack growth had commenced earlier than the licensee postulated. Internal events were estimated at 4.61E-6. Risk from external events (fire) was estimated at 6.06E-6/year. This yielded a combined change in CDF of 1.1E-5/year. Of note, this result was near the White-Yellow threshold and demonstrates that including four would be April 21  July 29, 2014. Common cause potential. The analyst performed a bounding internal events analysis using a 44 day exposure period with EDG No. 2 failed with the potential for common cause on EDG No. 1 (set EDG NO. 2 to TRUE in Systems Analysis Programs for Hands-On Evaluation (SAPHIRE)). This result did not credit any recovery of EDG No. 1 had it failed and assumed that EDG No. 2 was unavailable for any run time during the 44 day period. This analysis yielded a delta CDF of 4.0E-6/year for internal events only. No common cause potential. The analyst performed an internal events analysis using a 44 day exposure period with EDG No. 2 failed without the potential for common cause on EDG No. 1 (set EDG No. 2 to 1.0 in SAPHIRE). This result did not credit any recovery of EDG No. 1 had it failed and assumed that EDG No. 2 was unavailable for any run time during the 44 day period. This analysis yielded a delta CDF of 3.1E-6/year for internal events only. This analysis was performed to judge the sensitivity to common cause. Uncertainties  The bin between the June 30 and July 16 surveillance runs was examined for uncertainties because it was the most risk significant. The results of the analysis yielded a point estimate 3.37E-5. The median value was slightly lower at 2.70E-5 and the mean was higher at 6.64E-5. The confidence interval was 1.15E-5  7.14E-5. After sampling, the analyst considered these values to be representative of all bins which were analyzed. The analyst concluded that the uncertainty analysis gave confidence in the results of the point estimates of the 44 day and 211 day exposure periods.
 
2-ATTACHMENT 2:
 
=SUPPLEMENTARY INFORMATION=
 
==KEY POINTS OF CONTACT==
Exelon Personnel 
: [[contact::G. Stathes]], Site Vice-President
: [[contact::J. Dostal]], Plant Manager
: [[contact::M. Ford]], Director, Operations 
: [[contact::G. Malone]], Director, Engineering
: [[contact::C. Symonds]], Director, Training
: [[contact::D. DiCello]], Director, Work Management
: [[contact::M. McKenna]], Manager, Regulatory Assurance
: [[contact::T. Farenga]], Radiation Protection Manager
: [[contact::J. Renda]], Manager, Environmental/Chemistry
: [[contact::T. Keenan]], Manager, Site Security
: [[contact::H. Ray]], Senior Manager, Design Engineering
: [[contact::E. Swain]], Shift Operations Superintendent
: [[contact::T. Cappuccino]], Regulatory Assurance Specialist
: [[contact::K. Paez]], Regulatory Assurance Specialist 
==LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED==
 
===Opened===
: 05000219/2014005-02 AV Inadequate Review of Change in Maintenance Process Results in Inoperable Emergency Diesel Generator (Section 4OA2.4) 
===Opened/Closed===
: 05000219/2014005-01  NCV  Reactor Head Cooling Spray Piping Flange Misalignment (Section 1R08) 
: 05000219/2014005-03 NCV Plant Shutdown Procedure was Inadequate for Soft Shutdown (Section 4OA2.5)   
: 05000219/2014005-04 NCV Procedures Not Implemented During Plant Shutdown (Section 4OA2.5)   
===Closed===
: [[Closes LER::05000219/LER-2013-005]]-01 LER Reactor Protection System Actuation with Reactor in Hot Shutdown (Section 4OA3.2)
: [[Closes LER::05000219/LER-2014-003]]-00 LER Technical Specification Prohibited Condition Caused by Emergency Diesel Generator Inoperable for Greater than Allowed Outage Time  (Section 4OA3.3) 
: 2-2  Attachment 2
: [[Closes LER::05000219/LER-2014-004]]-00 LER Local Leak Rate Test Results in Excess of Technical Specifications (Section 4OA3.4) 
==LIST OF DOCUMENTS REVIEWED==
==Section 1R01: Adverse Weather Protection==
 
===Procedures===
: 322, Service Water System, Revision 84
: 341, Emergency Diesel Generator Operation, Revision 108
: ABN-31, High Winds, Revision 19
: ABN-32, Abnormal Intake Level, Revision 24
: OP-OC-108-109-1002, Cold Weather Freeze Inspection, Revision 4
: WC-AA-107, Seasonal Readiness, Revision 14
===Condition Reports===
(IRs)
: 2419178
: 2403104
: Maintenance Orders/Work Orders A2342119 A2347123 A2347412 A2347216
===Miscellaneous===
: Oyster Creek Certification of 2014-2015 Winter Readiness, dated November 15, 2014
 
==Section 1R04: Equipment Alignment==
 
===Procedures===
: 308, Emergency Core Cooling System Operation, Revision 94 309.1, Turbine Building Closed Cooling Water System, Revision 57 310, Containment Spray System Operation, Revision 109 341, Emergency Diesel Generator Operation, Revision 108
: ABN-32, Abnormal Intake Level, Revision 24
: OP-AA-108-112, Plant Status and Configuration, Revision 8
: OP-AA-108-117, Protected Equipment Program, Revision 4
===Drawings===
: 3E-862-21-1000, Emergency Diesel Generator Diesel Fuel Oil Storage & Transfer System, Revision 24
: BR 2005 Sh. 2, Reactor & Turbine Building Service Water System, Revision 107
: BR 2005 Sh. 4, Emergency Service Water System, Revision 86
: BR 2006 Sh. 4, Turbine Building Closed Cooling Water System, Revision 65
===Condition Reports===
(IRs)
: 2418411
: 2422230
===Miscellaneous===
: Tagging Clearance #
: 14501238   
: 2-3
: Attachment 2
 
==Section 1R05: Fire Protection==
 
===Procedures===
: RB-FA-2, Reactor Building (Drywell and Torus), Revision 1
: RB-FZ-1F4, Reactor Building (- TB-FZ--
 
==Section 1R06: Flood Protection Measures==
 
===Procedures===
: RAP-N1a, Fire Pump 1 Trouble, Revision 3
: RAP-N2a, Fire Pump 2 Trouble, Revision 2
: RAP-RB1C(1-7), 1-7 Sump Reactor Bldg Flr Drain Sump High Level, Revision 1
===Condition Reports===
(IRs)
: 1692258
: 1698798
: Maintenance Orders/Work Orders R2143772 R2145964 R0802432 R2145964 R0803021
===Miscellaneous===
: Component History Work Order Closure Remarks for Level Switch
: LS-572-4, dated
: November 24, 2014 Component History Work Order Closure Remarks for Valve V-24-35, dated November 26, 2014 Component History Work Order Closure Remarks for Valve V-24-38, dated November 26, 2014 Internal Flood Evaluation Summary and Notebook, Oyster Creek Nuclear Generating Station, dated April 17, 2008
: OC-2010-S-0099, 50.59 Screening,
: RAP-N2a and
: RAP-N2b Procedure Changes, Revision 0
: OP-OC-201-008-1018, Oyster Creek Generating Station Pre-Fire Plan, Control Room (OB-FZ-5), Revision 1
: OP-OC-201-008-1019, Oyster Creek Generating Station Pre-Fire Plan, New Cable Spreading Room (OB-FZ-22A), Revision 1 Oyster Creek Nuclear Generating Station UFSAR, Section 9.3.3, Equipment and Floor Drainage Systems, Revision 16 Oyster Creek Nuclear Generating Station UFSAR, Table 9.3-4, Equipment and Floor Drainage System Components, Revision 16
 
==Section 1R08: In-service Inspection==
 
===Procedures===
: 2400-GMM-3900.52, Inspection and Torquing of Bolted Connections, Revision 7
: CC-AA-407, Maintenance Specification: Evaluation and Repair of Piping and Equipment Flanges, Revision 2
: ER-AA-330, Conduct of Inservice Inspection Activities, Revision 10
: ER-AA-330-002, Inservice Inspection of Section XI Welds and Components, Revision 11
: ER-AA-330-009, ASME Section XI Repair/Replacement-Program, Revision 8
: ER-AA-335-002, Liquid Penetrant Examination, Revision 7
: ER-AA-335-004, Ultrasonic Measurement of Material Thickness and Interfering Conditions, Revision 16
: ER-AA-335-014,
: VT-1 Visual Examination, Revision 8
: ER-AA-335-016,
: VT-3 Visual Examination of Component Supports, Attachments and Interiors of Reactor Vessels, Revision 9
: ER-AA-335-018, Visual Examination of ASME IWE Class MC and Metallic Liners of IWL Class 
: 2-4
: Attachment 2 CC Components, Revision 8
: ER-OC-330-5001, ISI Program Plan, Fifth Ten-Year Inspection Interval, Revision 0
: ER-OC-330-5002, ISI Classification Basis Document, Fifth Ten-Year Inspection Interval, Revision 0
: GEH-PDI-UT-2, PDI Generic Procedure for the Ultrasonic Examination of Austenitic Pipes, Revision 6
: GEH-UT-247, Procedure for Phased Array Ultrasonic Examination of Dissimilar Metal Welds, Revision 3
: MA-OC-2015-001, Reactor Pressure Vessel Disassembly, Revision 11
: MA-OC-205-004, Reactor Pressure Vessel Reassembly Preparation, Revision 4
: PI-AA-120, Issue Identification and Screening Process, Revision 1
: PI-AA-125, Corrective Action Program (CAP) Procedure, Revision 0
===Condition Reports===
(IRs)
: 0836642
: 0842517
: 0845395
: 1135047
: 1430492
: 1435389
: 1437583
: 1441263
: 1441461
: 1441468
: 1444414
: 2363923
: 2386495
: 2381516
: 2385501
: 2386495
: 2392567
: Maintenance Orders/Work Orders
: C2028889, ASME Section XI Repair/Replacement Plan N7B Flange Repair, dated
: November 27, 2012
: C20300107, Replace Flange For NR02 Nozzle, dated September 30, 2014
: C2032913, Replace Existing 2-inch V-31-5 Check Valve With New, dated September 23, 2014
: NDE Inspection Reports & Data Sheets Automated Encoded Phased Array UT Examination data of isolation condenser nozzle N5Asafe-end dissimilar metal weld NR02/1-566A, dated September 24, 2014 Automated Encoded Phased Array UT Examination data of isolation condenser nozzle N5B safe-end dissimilar metal weld NR02/1-566B, dated September 24, 2014 Automated Encoded Phased Array UT Examination data of reactor vessel reactor recirculation system outlet N1A safe-end-to-nozzle dissimilar metal weld NR02/4-565A, dated September 21, 2014 Automated Encoded Phased Array UT Examination data of reactor vessel reactor recirculation system outlet N1C safe-end-to-nozzle dissimilar metal weld NR02/4-565C, dated September 24, 2014 Automated Encoded Phased Array UT Examination data of reactor vessel reactor recirculation system outlet N1D safe-end-to-nozzle dissimilar metal weld NR02/4-565D, dated September 22, 2014 Liquid Penetrant Examination Data Sheet Report, 1R22-057, PT Head Cooling Spray Nozzle, dated October 31, 2008 Liquid Penetrant Examination Data Sheet Report, 1R22-061, PT Head Cooling Spray Nozzle, dated November 7, 2008 Liquid Penetrant Examination Reports No.
: BOP-PT-2014-013 and
: BOP-PT-2014-14, 9/25/14 UT Examination Report No.
: UT-14-052, dated September 25, 2014 Sand Bed Bay 1, Report 1R25-LRA-009, ASME IWE (CLASS MC) Containment and IWL (CLASS CC) Metallic Liners Visual Exam and NDE Report, dated September 21, 2014 and UT Thickness Measurement Report No. 1R25-LRA-010, dated September 21, 2014 Sand Bed Bay 11, Report 1R25-LRA-001, ASME IWE (CLASS MC) Containment and IWL (CLASS CC) Metallic Liners Visual Exam and NDE Report, dated September 19, 2014 and UT Thickness Measurement Report No. 1R25-LRA-002, dated September 19, 2014   
: 2-5
: Attachment 2 Sand Bed Bay 17, Report 1R25-LRA-013, ASME IWE (CLASS MC) Containment and IWL (CLASS CC) Metallic Liners Visual Exam and NDE Report, dated September 22, 2014 and UT Thickness Measurement Report No. 1R25-LRA-020, dated September 22, 2014 Sand Bed Bay 19, Report 1R25-LRA-011, ASME IWE (CLASS MC) Containment and IWL (CLASS CC) Metallic Liners Visual Exam and NDE Report, dated September 22, 2014 and UT Thickness Measurement Report No. 1R25-LRA-012, dated September 22, 2014 Sand Bed Bay 3, Report 1R25-LRA-003, ASME IWE (CLASS MC) Containment and IWL (CLASS CC) Metallic Liners Visual Exam and NDE Report, dated September 19, 2014 and UT Thickness Measurement Report No. 1R25-LRA-005, dated September 19, 2014 Sand Bed Bay 5, Report 1R25-LRA-004, ASME IWE (CLASS MC) Containment and IWL (CLASS CC) Metallic Liners Visual Exam and NDE Report, dated September 19, 2014 and UT Thickness Measurement Report No. 1R25-LRA-006, dated September 19, 2014 Sand Bed Bay 7, Report 1R25-LRA-007, ASME IWE (CLASS MC) Containment and IWL (CLASS CC) Metallic Liners Visual Exam and NDE Report, dated September 20, 2014 and UT Thickness Measurement Report No. 1R25-LRA-008, dated September 20, 2014
: VT-1 Visual Examination NDE Report, 1R22-058, Spray Nozzle Penetration, dated November 5, 2008
: VT-1 Visual Examination NDE Report, 1R22-062, Head Cooling Spray Nozzle, dated November 7, 2008
: VT-2 Visual Examination NDE Sheet, Report No. R2143786, N7B flange, Post Repair Test during Plant Operational Pressure Test, dated December 4, 2012
: Engineering Calculations & Evaluations Engineering Evaluation for AR A2318125, Repair of N7B Flange, dated November 26, 2012 Structural Integrity Associates, Inc. CALCULATION PACKAGE, File No.: 0801436.301; Title: RPV Head Spray Line Cold-Spring Stress Evaluation, Revision 0 and Revision 1
: Program Health Reports Inservice Inspection (ISI) Program Health Reports 2nd, 3rd, 4th Quarter 2013 Inservice Inspection (ISI) Program Health Report 1st Quarter 2014
 
==Section 1R11: Licensed Operator Requalification Program==
 
===Procedures===
: 1001.22, Core Monitoring and Operation, Revision 51 201, Plant Startup, Revision 93 302.1, Control Rod Drive System, Revision 114 312.9, Primary Containment Control, Revision 58 315.1, Turbine Generator Startup, Revision 92
: ABN-12, Turbine Generator Startup, Revision 92
: OP-OC-101-111-1001, Strategies for Successful Transient Mitigation, Revision 8
: OP-OC-101-111-1002, SOS Expectations, Revision 13
: OP-OC-108-1001, Craft Capability, Revision 1
: OP-OC-108-104-1001, Guidance for Limiting and Administrative Conditions for Operations, Revision 5 RAP, Generator Excitation Equipment Malfunction, Revision 4
===Condition Reports===
(IRs)
: 02394977
: 02395136
: 02395202
: 02395293
: 02395452
: 02395730   
: 2-6
: Attachment 2 Miscellaneous
: OBE 14-6.1, Loss of B1 Bus/LBLOCA/Failure of No. 2 EDG, Revision 1 OCNGS
: EP 2014 Off Year Exercise, November 5, 2014
 
==Section 1R12: Maintenance Effectiveness==
 
===Procedures===
: 309.1, Turbine Building Closed Cooling Water System, Revision 57
: ER-AA-310-1001, Maintenance Rule Scoping, Revision 4
: ER-AA-310-1004, Maintenance Rule
: Performance Monitoring, Revision 12
: PI-AA-120, Issue Identification and Screening Process, Revision 1
: PI-AA-125, Corrective Action Program (CAP) Procedure, Revision 0
===Condition Reports===
(IRs)
: 1614197
: 1616472
: 1625920
: 1625923
: 1618476
: 2383814
: 2396328
: 2388149
: 2390832 1674492
 
==Section 1R13: Maintenance Risk Assessments and Emergent Work Control==
 
===Procedures===
: 612.4.001, Standby Liquid Control Pump and Valve Operability and In-Service Test, Revision 49
: WC-AA-101, On-Line Work Control Process, Revision 24
===Condition Reports===
(IRs)
: 2425636
===Miscellaneous===
: Oyster Creek Morning Report for November 14, 2014 Oyster Creek Morning Report for December 15, 2014
: SC 14-19, 10 CFR Part 21 Communication: Failure of SBM Switch Q16SBMC3G31S1A2P1, dated December 11, 2014
 
==Section 1R15: Operability Determinations and Functionality Assessments==
 
===Procedures===
: OP-AA-108-115, Operability Determinations, Revision 15
: OP-AA-108-115-1002, Supplemental Consideration for On-Shift Immediate Operability Determinations, Revision 3
===Condition Reports===
(IRs)
: 2417768
: 2418265
: 1694765
===Miscellaneous===
: Oyster Creek Nuclear Generating Station Technical Specification 3.8, Isolation Condenser, Amendment 241 dated November 28, 2014 Oyster November 28, 2014   
: 2-7
: Attachment 2
 
==Section 1R18: Plant Modifications==
 
===Procedures===
: 331, Office Building Heating, Ventilation and Air Conditioning System, Revision 69 2400-SMM-3219.02, Liquid Poison System Explosive Valve Maintenance, Revision 8
: WC-AA-107, Seasonal Readiness, Revision 14
===Condition Reports===
(IRs)
: 2429266
: 2419244
: 2415894
: 2415830
: 2415601
: 2415358
: 2414554
: 2414252
: 2414267
: 2414270
: 2414264
: 2414257 2414321
 
==Section 1R19: Post-Maintenance Testing==
 
===Procedures===
: 624.4.001, Main Steam Valve Position Indication and IST Test, Revision 17 634.2.012, C1 Battery Charger Load Test, Revision 8 665.5.103, Main Steam Isolation Valve Leak Rate Test (South Header) (V-1-8/NS-03B & V-1-10/NS-04B), Revision 1
: ER-OC-380, Oyster Creek Primary Containment Leakage Rate Testing Program, Revision 6
: MA-AA-716-012, Post Maintenance Testing, Revision 19
: OP-AA-108-106, Equipment Return to Service, Revision 4
: OP-AA-108-115, Operability Determinations, Revision 15
: WC-AA-101, On-Line Work Control Process, Revision 24
===Condition Reports===
(IRs)
: 2383817
: 2383831
: 2383832
: 2383265
: 2392538
: 2405181
: 2428600
: Maintenance Orders/Work Orders
: C2032911 R2215315 R2210392 R2161384
: C2031083 A2366845
: C2033274
===Miscellaneous===
: ECR 01-00628, 480V Circuit Breaker UV Device Replacement, dated March 18, 2003 NRC Inspection Manual Part 9900, Technical Guidance, dated April 16, 2008 Oyster Creek Nuclear Generating Station Technical Specification 4.5, Containment System, Amendment 262 Plant Process Computer Data for C Battery Voltage, dated October 22, 2014 through November 3, 2014
: VM-OC-0526, Battery Charger C-1 & C-2 (Model 3S-130-500CD), Revision 7
: VM-OC-0584, Agastat 7000 & 2400 Series Timing Relay Installation and Operation Manual, Revision 6
: VM-OC-5016, GE Industrial Motors Including Custom 8000 Horizontal Motor (GEH-3160), Revision 7
 
==Section 1R20: Refueling and Other Outage Activities==
 
===Procedures===
: 201, Plant Startup, Revision 93
: OP-AA-108-108, Unit Restart Review, Revision 15   
: 2-8
: Attachment 2 Drawings 3E-153-02-009, General Arrangement, Reactor Building, Sections C-C, D-D & E-E, Revision 4
===Condition Reports===
(IRs)
: 2395478
: 2395581
: 2390253
: 2390254
: 2394370
: 2394363
: 2394362
: 2394360
: 2394358
: 2394009
: 2393974
: 2393846
: 2393656
: 2394341
: 2394244
: 2394170
: 2391291
: 2390252
: 2390335
: 2391148
: 2391164
: 2387152
: 2390111
: 2390690
: 2390688
: 2390683
: 2390678
: 2390676
: 2390674
: 2390667
: 2390662
: 2391757
: 2391731
: 2391655
: 2391528
: 2391500
: 2391403
: 2387811
: 2391274
: 2391078
: 2390701
: 2390691
: 2390513
: 2392790
: 2392892
: 2392631
: 2392567
: 2392557
: 2392545
: 2392538
: 2392515
: 2392495
: 2392451
: 2392344
: 2392347
: 2392290
: 2392288
: 2392287
: 2392201
: 2391990
: 2391936
: 2391901
: 2391889
: 2391875
: 2391816
: 2391782
: 2388952
: 2388959
: 2383148
: 2381853
: 2183020
: 1691343
: 2381887
: 2383836
: 2385903
: 2345243
: 2382943
: 2386495
: Maintenance Orders/Work Orders R2212089
: C2030852
===Miscellaneous===
: ASME, Boiler and Pressure Vessel Code, Section XI: Inservice Inspection of Nuclear Power Plant Components, Section
: IWB-2420, Successive Inspections, 2007 Code with 2009 Addenda OC1C25SU, Rod Control Sequence Review and Approval Sheet, dated October 1, 2014 Plant Oversight Review Committee Agenda Package, dated October 3, 2014 Plant Oversight Review Committee Agenda Package, dated October 7, 2014 Plant Oversight Review Committee Agenda Package, dated October 8, 2014 Plant Oversight Review Committee Agenda Package, dated October 9, 2014 Work Clearance No. 145011
 
==Section 1R22: Surveillance Testing==
 
===Procedures===
: 602.3.005, Automatic Depressurization System Actuation Circuit Test and Calibration,
: Revision 34 606.4.016, Containment Spray and Emergency Service Water System 1 Pump Operability and Quarterly Inservice Test. Revision 38 610.4.003, Core Spray Valve Operability and In-Service Test, Revision 44 636.4.002, Diesel Generator No. 2 Automatic Actuation Test, Revision 15 665.5.103, Main Steam Isolation Valve Leak Rate Test (South Header) (V-1-8/NS-03B &
: V-1-10/NS-04B), Revision 1
: ER-OC-380, Oyster Creek Primary Containment Leakage Rate Testing Program, Revision 6
: SP-1302-12-155, Oyster Creek Specification for Reactor Safety Valve Testing Nuclear Safety
===Condition Reports===
(IRs)
: 2383817
: 2383831
: 2383832
: 2383265
: 2391679
: 2391702
: 2400720
: 2391033
: 2391017
: 2391020
: 2391021
: 2391028
: 2391024
: 2391009
: 2390808
: 2391161
: 2391159
: 2391158
: 2391157
: 2391156 
: 2-9
: Attachment 2 Maintenance Orders/Work Orders R2214615 R2247418 R2211655
===Miscellaneous===
: ASME OM Code (2004 with 2006 Addenda) Mandatory Appendix I, Inservice Testing of Pressure Relief Devices in Light-Water Reactor Nuclear Power Plants Oyster Creek Nuclear Generating Station Technical Specification 2.2, Safety Limit - Reactor Coolant System Pressure, Amendment 233 Oyster Creek Nuclear Generating Station Technical Specification 4.5, Containment System, Amendment 262 Oyster Creek Nuclear Generating Station Technical Specification 4.3, Reactor Coolant, Amendment 276 Oyster Creek Nuclear Generating Station Technical Specification 4.4.B, Automatic Depressurization, Amendment 276 Oyster Creek Nuclear Generating Station Updated Final Safety Analysis Report Table 6.2-3, Containment Spray Pumps, Revision 14 Oyster Creek Nuclear Generating Station Updated Final Safety Analysis Report Table 6.2-5, Containment Spray System Suction Valves, Revision 14 Oyster Creek Nuclear Generating Station Updated Final Safety Analysis Report Table 6.2-6, Emergency Service Water Pumps, Revision 16 Oyster Creek Nuclear Generating Station Updated Final Safety Analysis Report Table 6.2-9, Containment Spray System Valves, Revision 14 Safety Valve Test Data for Valve BW05084, dated September 25, 2014 Safety Valve Test Data for Valve BY08715, dated September 25, 2014
: Relief From the Requirements of the ASME Code, Relief Request No.
: VR-01 for Fifth Inservice
 
==Section 1EP4: Emergency Action Level and Emergency Plan Changes==
 
===Procedures===
: EP-AA-114, Notifications, Revision 13
 
==Section 1EP6: Drill Evaluation==
 
===Procedures===
: EP-AA-112-1 00-F-01, Shift Emergency Director Check List, Revision U
: EP-AA-114-F-02, BWR Release in Progress Determination Guidance, Revision A
: EP-AA-114-100-F-03, State/Local Notification Form, Revision H
: EP-AA-122, Drills and Exercise Program, Revision 16
 
==Section 2RS5: Radiation Monitoring Instrumentation==
 
===Procedures===
  --  -- -- --- ------ 
: 2-10
: Attachment 2 ------- --- --- ---- ---- ---- ---- ---- ---- --- ---- ---- ----- --- ---- ----- ------ ---- ---- ---- ---- --- --- ---- ----              - -----  -----  ---   
: 2-11
: Attachment 2  - - - -        -  -- -- -- --- -- ---  ---- ----- ----
 
==Section 4OA1: Performance Indicator Verification==
 
===Procedures===
: EP-AA-125-1001, EP Performance Indicator Guidance, Revision 8
: EP-AA-125-1002, ERO Performance
: Performance Indicators Guidance, Revision 10
: LS-AA-2001, Collecting and Reporting of NRC Performance Indicator Data, Revision 14
: LS-AA-2110, Monthly Data Elements for NRC Emergency Response Organization (ERO) Drill Participation, Revision 6
: LS-AA-2130, Monthly Data Elements for NRC Alert and Notification System (ANS) Reliability, Revision 5
: LS-AA-2140, Monthly Data Elements for NRC Occupational Exposure Control Effectiveness, Revision 5
: LS-AA-2150, Monthly Data Elements for RETS/ODCM Radiological Effluent Occurrences, Revision 5
: LS-AA-2200, Mitigating System Performance Index Data Acquisition and Reporting, Revision 5 
: 2-12
: Attachment 2  -
 
==Section 4OA2: Problem Identification and Resolution==
 
===Procedures===
: 307, Isolation Condenser System, Revision 124 308, Emergency Core Cooling System Operation, Revision 94 341, Emergency Diesel Generator Operation, Revision 108
: ABN-30, Control Room Evacuation, Revision 25
: ABN-31, High Winds, Revision 19
: ABN-60, Grid Emergency, Revision 15
: AD-AA-101, Processing of Procedures and T&RMs, Revision 15
: AD-AA-101-1000, Management Model Terminology and Direction, Revision 1
: AD-AA-101-1002, Writer's Guide and Process Guide for Processing and T&RM, Revision 7
: AD-AA-102, Station Qualified Review, Revision 5
: CC-AA-102, Design Input and Configuration Change Impact Screening, Revision 6
: CC-AA-103, Configuration Change Control, Revision 7
: CC-AA-104, Document Change Request, Revision 14
: CC-AA-11, Nonconforming Materials, Parts, or Components, Revision 5
: CC-AA-309-101, Engineering Technical Evaluations, Revision 7 and 14
: ER-AA-310-1004, Maintenance Rule
: Performance Monitoring, Revision 11
: LS-AA-104, Exelon 50.59 Review Process, Revision 4
: LS-AA-104-1000, Exelon 50.59 Resource Manual, Revision 1
: LS-AA-104-1001, 50.59 Review Coversheet, Revision 2
: LS-AA-104-1002, 50.59 Applicability Review Form, Revision 2
: LS-AA-106, Plant Operations Review Committee, Revision 1
: LS-AA-120, Issue Identification and Screening Process, Revision 1
: LS-AA-120, Issue Identification and Screening Process, Revision 4
: LS-AA-125, Corrective Action Program, Revision 0
: LS-OC-125, Corrective Action Program (CAP) Procedure, Revision 6
: MA-OC-86103-100, Diesel Generator Fan Belt Replacement, Revision 0
: MA-OC-861-101, Diesel Generator Inspection (24 Month) - Mechanical, Revision 17
: OP-AA-101-111, Roles and Responsibilities of On-Shift Personnel, Rev 6
: OP-AA-102-103, Operator Work-Around Program, Revision 4
: OP-AA-102-103-1001, Operator Burden and Plant Significant Decisions Impact Assessment Program, Revision 6
: OP-AA-106-101, Significant Event Reporting, Rev 16
: OP-AA-108-105-1001, MCR and RWCR Equipment Deficiency Management and Performance Indicator Screening, Revision 5
: OP-AA-115-101, Operator Aid Postings, Revision 2
: OP-AA-3, Reactivity Management, Rev 1
: OP-AA-300, Reactivity Management, Rev 6
: OP-AA-300-1540, Reactivity Management Administration, Rev 10
: OP-AB-300-1005, BWR Reactivity Management
: Shutdown Activities, Rev 4
: OP-OC-300-1001, Oyster Creek Reactivity SRO Guidelines, Rev 1
: PI-AA-120, Issue Identification and Screening Process, Revision 1
: PI-AA-125, Corrective Action Program (CAP) Procedure, Revision 0 Procedure 203, Plant Shutdown, Rev 75 
: 2-13
: Attachment 2 Procedure 403.1, Operation of NI SRM Channel During and After Shutdown, Rev 11
: WC-AA-106, Work Screening and Processing, Revision 15
===Condition Reports===
(IRs)
: 2413117
: 1062005
: 1067996
: 1067996
: 1128036
: 1135900
: 1137564
: 1138066
: 1138066
: 1138066
: 1138809
: 1140050
: 1140312
: 1140821
: 1141413
: 1141981
: 1148348
: 1164020
: 1166208
: 1166848
: 1166848
: 1166848
: 1181950
: 1181958
: 1181999
: 1183062
: 1183064
: 1183066
: 1183067
: 1183069
: 1183070
: 1183075
: 1183080
: 1183081
: 1183084
: 1183086
: 1183087
: 1183088
: 1417235
: 1418769
: 1424714
: 1437014
: 1437317
: 1438253
: 1438256
: 1438256
: 1443312
: 1444861
: 1444862
: 1457722
: 1473767
: 1481670
: 1481670
: 1486185
: 1495758
: 1506509
: 1506509
: 1511787
: 1511787
: 1511787
: 1538843
: 1551624
: 1560524
: 1562515
: 1568796
: 1584827
: 1586565
: 1589077
: 1596563
: 1597136
: 1600245
: 1605092
: 1605095
: 1614019
: 1614019
: 1614019
: 1622182
: 1628481
: 1629184
: 1633161
: 1645010
: 1645010
: 1645010
: 1645572
: 1674814
: 1682905
: 1695263
: 1183076
: 1183078
: 2383948
: 2384908
: 2384931
: 2386534
: 2407283
: 2408095
: 2410105
: 2411800
: 1443312
: 1443313
: 2422565
: 2422586
: 2422705
: 2422885
: 2423821
: 1500241
: 1473767
: 1629184
: 1584827
: 1610014
: 1637438
: 2344845
: 2394011
: 2396328
: 2397633
: 2415358
: 2415697
: 2415894
: 2415898
: 2415936
: 2415939
: 2415947
: 2415998
: 2416045
: 2416791
: 2417635
: 2418002
: 2418011
: 2418265
: 2418411
: 2421785
: 2422319
: 2422497
: 1679865
: 1680667
: 1688410
: 1744563
: 2412093
: 2419138
: 1575377
: 1686101
: 1686767
: 1688727
: 1688756
: 1699147
: 2396154
: 2396163
: 2434265
: Maintenance Orders/Work Orders
: C2032634 R2065452 R2151853 R2190622 R2202606 R2242349
===Miscellaneous===
: OP-AA-102-103-1001 Attachment 1, Operator Burden/Degraded Equipment Aggregate Assessment, dated January 6, 2014, April 15, 2014 and July 18, 2014 Adverse Condition Monitoring Plan Log, dated December 10, 2014 Disabled Alarms Database, dated December 9, 2014 Control Room Narrative Log, dated December 5-12, 2014 Operational Decision Making Process Log, dated December 10, 2014 Operations Department Concerns List, dated December 9, 2014 Operator Challenge Database, dated December 9, 2014 Operator Work Arounds Database, dated December 9, 2014
: Oyster Creek Forced Outage Scope, dated December 9, 2014 Oyster Creek Nuclear Generating Station Plan of the Day, dated December 9, 2014 Oyster Creek Online Priority Work List, dated December 9, 2014 Plant Air Leaks Database, dated December 9, 2014 Plant Oil Leaks Database, dated December 9, 2014 Plant Water Leaks Database, dated December 9, 2014 Temporary and Interim Procedure Changes Log, dated December 10, 2014 Apparent Cause Investigation Report, 1F34 Shutdown Reactivity Management Performance Root Cause Investigation Report, Reactor Re-criticality During Soft Shutdown 
: 2-14
: Attachment 2 ACIT
: 01686101-06, Technical Evaluation:
: Determine the Correct Installation Tension to be placed on the
: EDG-2 Cooling Fan Belt, dated September 9, 2014 ACIT
: 01686101-33, Technical Evaluation:
: Perform Owners Acceptance for Structural Integrity Report 1401386.401, dated January 6, 2015 Apparent Cause Evaluation (ACE) for
: AR 01686101, Emergency Diesel Generator Upper Fan Shaft Failure, dated September 28, 2014 Engineering Change Request (ECR) 13-00474, Fan Hitting Shroud, Revision 0 Exelon Position Paper to Address NRC Concerns Regarding Emergency Diesel Generator 2 Upper Fan Shaft Failure, dated November 21, 2014 Exelon Power Labs Project Number
: OYS-35189, Failure Analysis of Cooling Fan Shaft Section, dated August 13, 2014 Licensee Event Report (LER) 2004-001, #1 EDG Inoperable Caused by Cooling Fan Bearing Bolts Not Torqued Properly Following Preventative Maintenance Activities, Revision 00
: LER 2014-003, Technical Specification Prohibited Condition Caused by Emergency Diesel Generator Inoperable for Greater than Allowed Outage Time, Revision 00 NRC Inspection Report Number 50-219/93-09, dated July 18, 1993 Operator Logs, Night Shift, dated July 28, 2014 Oyster Creek Generating Station Technical Specifications, Amendment 278 Oyster Creek Generating Station Updated Final Safety Analysis Report, Revision 18 Structural Integrity Associates Report Number 1400935.402.R0, Fracture Mechanics Evaluation of Failed Cooling Fan Shaft, dated August 8, 2014 Structural Integrity Associates Report Number 1401386.401.R0, Evaluation of Failed Cooling Fan Shaft, dated December 30, 2014 Technical Data Report 1120, Failure Analysis of a Fractured Emergency Diesel Shaft, dated September 13, 1993
: VM-OC-0097, Maintenance Instruction M.I. 1200, MP45 Cooling Fan and Related Drive Train Assembly, Revision A
 
==Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion==
 
===Procedures===
: 315.1, Turbine Generator Startup, Revision 92
: ABN-1, Reactor Scram, Revision 13
===Condition Reports===
(IRs)
: 2394374
: 2394357
: Maintenance Orders/Work Orders R2211902 A0700966 R0800966
===Miscellaneous===
: Event Notification 50476 Event Notification 50524 Human Performance Issue Verbal Report, dated October 14, 2014 Oyster Creek Nuclear Generating Station Operations Narrative Logs for October 12, 2014 Oyster Creek Nuclear Generating Station Outage Control Center Narrative Logs for September 18-19, 2014 Plant Process Computer data for October 12, 2014   
: 2-15
: Attachment 2
==LIST OF ACRONYMS==
: [[AC]] [[Alternating Current]]
: [[ADAMS]] [[Agencywide Documents Access and Management System]]
: [[ALARA]] [[As-Low as Reasonably Achievable]]
: [[ASME]] [[American Society of Mechanical Engineers]]
: [[AV]] [[Apparent Violation]]
: [[CDF]] [[Core Damage Frequency]]
: [[CFR]] [[Code of Federal Regulations]]
: [[CPS]] [[Counts per Second]]
: [[EDG]] [[Emergency Diesel Generator Exelon  Exelon Nuclear]]
: [[GPM]] [[Gallons per Minute]]
: [[IMC]] [[Inspection Manual Chapter]]
: [[IPEEE]] [[Individual Plant Examination External Events]]
: [[IR]] [[Issue Report]]
: [[IRM]] [[Intermediate Range Monitor]]
: [[ISI]] [[In-Service Inspection]]
: [[KSI]] [[Kips per Square Inch]]
: [[LER]] [[Licensee event report]]
: [[LERF]] [[Large Early Release Frequency]]
: [[LOOP]] [[Loss of Offsite Power]]
: [[NCV]] [[Non-Cited Violation]]
: [[NDE]] [[Non-Destructive Examination]]
: [[NEI]] [[Nuclear Energy Institute]]
: [[NUREG]] [[]]
: [[NRC]] [[technical report designation (Nuclear Regulatory Commission)]]
: [[NRC]] [[Nuclear Regulatory Commission]]
: [[SAPHIR]] [[E  Systems Analysis Programs for Hands-On Evaluation]]
: [[SCFH]] [[Standard Cubic Feet per Hour]]
: [[SDP]] [[Significance Determination Process]]
: [[SPAR]] [[Standardized Plant Analysis Risk]]
: [[SRM]] [[Source Range Monitor]]
: [[SSC]] [[Structure, System, or Component]]
: [[UFSAR]] [[Updated Final Safety Analysis Report]]
: [[UT]] [[Ultrasonic Testing]]
: [[VT]] [[Visual Examination]]
}}

Revision as of 01:32, 23 February 2018

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