IR 05000219/2002003
| ML022030003 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 07/18/2002 |
| From: | David Lew NRC/RGN-I/DRS/PEB |
| To: | Skolds J AmerGen Energy Co, Exelon Generation Co, Exelon Nuclear |
| References | |
| IR-02-003 | |
| Download: ML022030003 (20) | |
Text
uly 18, 2002
SUBJECT:
OYSTER CREEK GENERATING STATION - NRC PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 50-219/02-03
Dear Mr. Skolds:
On June 7, 2002, the NRC completed a team inspection at the Oyster Creek Generating Station. The enclosed report presents the results of that inspection. The results of this inspection were discussed on June 7, 2002, with Mr. E. Harkness and other members of your staff.
This inspection was an examination of activities conducted under your license as they relate to the identification and resolution of problems, and compliance with the Commissions rules and regulations, and with the conditions of your license. Within these areas, the inspection involved examination of selected procedures and representative records, observation of activities, and interviews with personnel.
On the basis of the sample selected for review, the team concluded that in general, problems were properly identified, evaluated to an appropriate detail, and corrected. Notwithstanding, the team identified some instances where your staff was not adequately evaluating equipment performance trends to ensure problems are identified as early as reasonably possible.
There was one green finding identified during this inspection regarding inadequate trending and evaluation of lower than expected control room ventilation system air flow. This finding was also determined to be a violation of NRC requirements. However, because of its very low safety significance and because it has been entered into your corrective action program, the NRC is treating this finding as a non-cited violation, in accordance with Section VI.A.1 of the NRCs Enforcement Policy. If you deny this non-cited violation, you should provide a response with the basis for your denial, within 30 days of the date of this inspection report, 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 Senior Resident Inspector at the Oyster Creek Generating Station.
Mr. Jack Skolds -2-In accordance with 10 CFR 2.790 of the NRCs "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
David C. Lew, Chief Performance Evaluation Branch Division of Reactor Safety Docket No. 50-219 License No. DPR-16
Enclosure:
Inspection Report 50-219/02-03 Attachments: (1) Supplemental Information
REGION I==
Docket No: 50-219 License No: DPR-16 Report No: 50-219/02-03 Licensee: AmerGen Energy Company, LLC (AmerGen)
Facility: Oyster Creek Generating Station Location: Forked River, New Jersey Dates: May 20 - 24, 2002 June 3 - 7, 2002 Inspectors: Mel Gray, Reactor Inspector (Team Leader)
Steve Pindale, Reactor Inspector Galen Smith, Resident Inspector, DRP Steve Shaffer, Project Engineer (In-Training)
Approved By: David C. Lew, Chief Performance Evaluation Branch Division of Reactor Safety
SUMMARY OF ISSUES IR 05000219-02-03; on May 20-24, 2002, and June 3-7, 2002; Oyster Creek Generating Station; biennial baseline inspection of the identification and resolution of problems. A violation was identified in the area of evaluation of equipment performance trend data.
This inspection was conducted by two regional inspectors and a resident inspector. One green finding of very low safety significance was identified during the inspection and was classified as a noncited violation. The significance of most findings is indicated by their color (green, white, yellow, red) using IMC 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.
Identification and Resolution of Problems Based on the sample items selected for review, the team concluded the implementation of the corrective action program at Oyster Creek Generating Station was adequate. The licensee was identifying problems and entering them into the corrective action program at an appropriate threshold. The licensee generally prioritized and evaluated issues appropriately and in a timely fashion. Notwithstanding, the team identified some examples where the licensee had not evaluated equipment performance trends in adequate detail to address degrading conditions or anomalous indications. One example regarding decreasing control room ventilation air flow measurements was determined to be a finding of very low safety significance (Green).
The team concluded the licensee identified and implemented corrective actions that addressed the causes of problems and were implemented in a timely fashion. However, one exception was noted regarding equipment tagging problems. In this area, the team determined that while the licensee identified and evaluated a continuing trend in equipment clearance and tagging errors, their corrective actions to date have not been effective in improving performance.
Furthermore, the team noted the licensees March 2002 effectiveness review of corrective actions in this area incorrectly concluded their actions were effective in precluding further tagging problems.
Cornerstone: Mitigating Systems
Green. A violation of 10CFR Part 50 Appendix B Criteria XVI, dispositioned as a noncited violation, was identified for failure to promptly identify and correct a condition adverse to quality regarding a low air flow condition in Train A of the control room ventilation system. The licensee had not, since at least 1996, adequately monitored and evaluated surveillance test trend data to identify decreasing air flow measurements in the Train A control room ventilation system. Consequently, the condition had not been evaluated in the licensees corrective action process, and corrective action have been not yet been taken to increase flows consistent with values referenced in the safety analysis report, or alternatively, determined the lower flows are acceptable.
ii
This issue is more than minor since less than adequate monitoring of degrading air flow conditions could impact the capability of the control room ventilation system to maintain temperatures required for reliable equipment and operator performance. However, this issue was evaluated using Phase I of NRC SDP and determined to have very low safety significance (Green), since the equipment has remained operable. There was no loss of safety function, and technical specification requirements were met. The lower air flows have remained adequate to maintain the temperatures below that required for reliable operator and equipment performance when Train A has been in service. Also, more recent air flow measurements, while still below the expected flow, indicate some improvement. Additionally, Train B has remained unaffected by this condition. (Section 4OA2.b)
iii
Report Details 4. OTHER ACTIVITIES (OA)
4OA2 Identification and Resolution of Problems a. Effectiveness of Problem Identification (1) Inspection Scope The team reviewed the procedures describing the licensees corrective action process and determined that the licensee identified problems primarily through the initiation of Corrective Action Program Reports (CAP). The team determined that the licensee considered the work control process to be a part of the corrective action process, and generally addressed minor equipment problems directly with an action request (AR).
Team members attended daily management meetings, where CAPs were reviewed for initial screening and assignment, to better understand the licensees threshold for identifying and entering problems into their corrective action process.
The team selected a sample of CAPs for review to determine whether the licensee was identifying, accurately characterizing, and entering problems into the corrective action process at an appropriate threshold to help ensure reliable equipment and safe plant operation. The CAPs selected covered the period from the last NRC problem identification inspection in March 2001 to the present. The CAPs were selected to cover the seven cornerstones of safety identified in the NRC Reactor Oversight Process (ROP). In addition, the team considered risk insights from the licensees Individual Plant Examination (IPE) Report to help focus the CAP sample on risk significant plant equipment. The Attachment lists the CAPs selected by the team for review.
The team supplemented its review of CAPs with items selected from the licensees maintenance, operations, engineering and oversight processes to verify that the licensee appropriately considered problems identified in these processes for entry into their corrective action program. Specifically, the team reviewed a sample of maintenance ARs, work orders, operator log entries, control room deficiency and work around lists, surveillance test results, engineering system health reports, installed temporary modification packages, design change request lists, monthly CAP reports and quarterly nuclear oversight reports. Issues identified in these documents were reviewed to ensure underlying problems associated with each issue were appropriately considered for identification and resolution via the corrective action process.
The team also reviewed licensee procedures and interviewed personnel to understand whether other processes were used to address problems. Additionally, the team walked down selected portions of the plant to independently assess whether visible problems were being adequately addressed.
(2) Findings Based on the CAPs reviewed, the team concluded the licensee set an acceptable threshold for identifying problems and entering them into the corrective action process.
The CAPs reviewed adequately described and characterized problems, and generally identified prior similar occurrences.
The team also determined that, as the licensee recognized problems in operations, maintenance and engineering activities, they generally initiated a CAP or AR in accordance with station procedures. However, the team did identify some minor equipment problems during plant walkdowns that were not entered into the licensees corrective action process or work control process. These problems involved oil leaks, missing bolting hardware, and degraded material conditions on emergency diesel generators, emergency service water pump motors, and the operating control rod drive pump. The team concluded these observations did not render any equipment inoperable. The licensee appropriately initiated CAPs and actions requests in response to the teams observations.
The team concluded the licensees nuclear oversight and CAP trend reports were functioning as intended to help ensure licensee management was cognizant, and addressing, problem trends within the corrective action process. Furthermore, the team confirmed through discussions with plant personnel that the corrective action process was considered and utilized as the primary problem resolution process.
b. Prioritization and Evaluation of Issues (1) Inspection Scope The team reviewed the CAPs and action requests listed in the Attachment to determine whether the licensee adequately evaluated and prioritized problems. The CAPs reviewed encompassed the full range of licensee evaluations, including root and apparent cause evaluations, CAPs closed to identified or directed actions, and CAPs closed to trending. The team selected CAPs considering risk insights from the Oyster Creek IPE. Additionally, the team selected a sample of CAPs associated with previous NRC noncited violations (NCV) to determine whether the licensee was evaluating and resolving problems associated with compliance to applicable regulatory requirements.
The team also reviewed the licensees evaluation of industry operating experience information for applicability to their facility.
For each CAP selected, the team considered the licensees prioritization for completing the evaluation and identifying corrective actions. The team assessed whether the licensee evaluated the problems in sufficient detail to determine the likely causes and identify corrective actions to prevent recurrence. The team reviewed the licensees consideration of the extent of the problems to determine whether the licensee adequately bounded the issues. The team also reviewed the licensees assessment of equipment operability and regulatory reporting requirements. The team further reviewed equipment performance results and assessments recorded in completed surveillance test procedures, operator log entries, and operator tour sheets to determine whether the
licensees evaluation of equipment performance was technically adequate to identify degrading or non-conforming equipment.
(2) Findings The team concluded the licensee generally prioritized and completed evaluations in a timely fashion. The licensees evaluation of problems were determined to be of sufficient detail to identify the likely causes and the corrective actions to prevent problem recurrence. The licensee completed detailed root and apparent cause evaluations for more risk significant problems. For the sample reviewed, the team concluded the evaluations adequately identified the causal factors and addressed the potential extent of the circumstances contributing to the problems. Additionally, the licensees proposed corrective actions reasonably addressed the causal factors. The team observed the licensees management review committee and concluded they appropriately provided additional oversight of evaluations for more significant problems. The licensees evaluations of less significant problems were evaluated in adequate detail, generally by evaluation under a directed action with closure to an AR.
Notwithstanding, the team identified several instances where the licensee had not evaluated equipment performance trends in adequate detail to address degrading conditions or anomalous indications. One instance regarding decreasing control room ventilation air flow measurements was determined to be a finding of very low safety significance (Green).
Additionally, with regard to prioritization, the team identified two evaluations of safety related battery charger alarm problems where the licensee inappropriately categorized equipment troubleshooting activities needed to confirm the problem as elective maintenance. Consequently, the activities had not yet been completed, and the initial evaluation results regarding operability and the extent of the problems had not been finalized.
Control Room Ventilation Air Flow Trending and Evaluation Green. A noncited violation of 10 CFR 50 Appendix B, Criteria XVI (Corrective Action),
for failure to promptly identify and correct a condition adverse to quality regarding a low air flow condition in Train A of the control room ventilation system.
The team reviewed CAP 2001-1435, initiated in September 2001, concerning higher than normal control room temperature and humidity conditions when Train A of the control room heating, ventilation, and air conditioning (HVAC) system was in service.
The licensee closed the CAP to a directed action for maintenance to check the freon charge in the Train A compressors. Through verbal discussions with the licensee, the team determined the freon charge was likely adequate. The problem had apparently not recurred since September 2001 during the limited occasions when Train A was in service.
The team determined that system surveillance tests were completed every two years that verified each HVAC train (A and B) was capable of maintaining the control room at a positive pressure during the partial recirculation mode of operation as required in the technical specifications. Additionally, the surveillance test procedures required that system air flows be calculated from pitot tube pressure measurements and trended to assess the general system condition. The team determined that the Train A system air flows measured in 1996 and 1998 were about 10,400 cfm, which was less than the 13,500 cfm value referenced in the licensees safety analysis report (SAR). The team further determined that the air flow rate calculation associated with the most recent surveillance test (July 2000) had not been completed to trend Train A air flow. When it was subsequently completed during this inspection, the system air flow from that July 2000 test yielded a lower value, about 9,150 cfm. The team concluded the control room HVAC air flow measurements were significantly less than the expected flow and were decreasing.
In discussing the results with the responsible system engineer, the team learned that the fan sheave for the single fan in Train A was suspected to be undersized. The system engineer recently had fan and motor speed measurements taken to help confirm this condition. Additionally, the team determined more recent informal flow measurements described in action request AR#A2018138 determined the flow to be about 11,000 cfm.
The work order indicated that the air flow was adequate to maintain the control room at a positive pressure as required for system operability.
The team concluded that the licensee had not, since at least 1996, adequately monitored and evaluated surveillance trend test data to identify decreasing air flow measurements in the Train A control room HVAC. Consequently, the condition had not been evaluated in the licensees corrective action process, and corrective actions have been not yet been taken to increase flows consistent with values referenced in the SAR.
The team also concluded the licensees operability statement in the work order was incomplete in that operator temperature and humidity habitability requirements and equipment environmental requirements had not been evaluated. In response to the teams observations, the licensee initiated CAP 2002-0850 and concluded Train A remained operable based on meeting surveillance test acceptance criteria and procedural controls that maintained temperature within normal limits.
This issue is more than minor since less than adequate monitoring of degrading air flow conditions could impact the capacity of the control room ventilation system to maintain temperatures required for reliable equipment and operator performance. The mitigating system cornerstone is applicable to this issue since the control room HVAC system is required to support mitigating equipment operation and operator actions. This issue affects the mitigating system cornerstone objective regarding the capability of the control room ventilation system. However, this issue was evaluated using Phase I of NRC SDP and determined to have very low safety significance (Green), since the equipment has remained operable. There was no loss of safety function, and technical specification requirements were met. The air flows have been adequate to maintain the temperatures below that required for reliable operator and equipment performance when Train A has been in service, and more recent air flow measurements, while remaining below the expected flow, indicate some improvement. Additionally, Train B has remained unaffected by this condition.
10 CFR Part 50 Appendix B, Criterion XVI requires, in part, that measures be established to ensure that conditions adverse to quality be promptly identified and corrected. Contrary to this requirement, the licensee failed to identify a degrading air flow trend and correct the low air flow condition in Train A of the control room HVAC, or alternatively, evaluate it as acceptable. However, because of the very low safety significance, and because the issue was entered into the licensees corrective action program as CAP 2002-0850, it is being treated as a non-cited violation, consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 50-219/02-03-01)
Main Steam Isolation Valve (MSIV) Stroke Time Trending and Evaluation The team noted that a control room log entry dated August 18, 2001, identified that the partial (10% closed) slow stroke time for an MSIV located in the drywell was approximately 23 seconds while the partial slow stroke time was over a minute for the MSIV located outside the drywell on the same steam line. The team reviewed MSIV partial stroke times recorded in surveillance test procedures and observed similar stroke time differences between the two MSIVs on the other steam line as well. The licensees surveillance test procedure indicates this information was to be used for equipment trending purposes and was not a technical specification requirement.
In discussing the information with the responsible system engineer, the team determined he was not aware the trend information was compiled and had not evaluated the trend. The system engineer indicated the partial stroke test is accomplished by venting air from the MSIV operator via a path different than that used for the fast closure MSIV function required by technical specifications, and that he considered the partial stroke time data to have no correlation to the MSIV fast closure performance. The team confirmed that the slow stroke vent path is different, verified there were no vendor manual recommendations regarding partial stroke time acceptance criteria, confirmed MSIV fast stroke time requirements were being met, and confirmed there appeared not to be a correlation between MSIV slow stroke times and fast stroke time performance.
Notwithstanding, the team concluded the licensee was not evaluating trend information recorded in accordance with their surveillance test procedures for equipment performance, or alternatively, revising their procedure to record trend information they considered meaningful.
Control Rod Drive (CRD) Pump Oil Consumption Trending and Evaluation During a plant walkdown, the team identified an oil leak on the operating CRD B pump gearbox. This pump is required to be operable per technical specifications. The team observed the oil had leaked onto the pump skid and through the floor grating such that it collected between the core spray pumps on the floor below and created a personnel safety hazard.
The team determined the oil leak was not identified in the licensee work control program or noted in recent operator log tour sheets. The team questioned the oil consumption trend and the pumps ability to perform its function for the required time during a postulated accident. In response, the licensee cleaned the oil from the floor, reinspected the pump, found a relatively slow oil leak, and concluded that the oil leak does not affect pump operability. The licensee also initiated an AR to correct the condition. In reviewing the licensees conclusions, the team determined that operator log sheets do not require specific inspection of the CRD gearbox oil sight glass level and that the sight glass has no markings indicating an acceptable level. Consequently, the specifics of oil level checks were left to the skill of the craft, and consistent oil consumption trending information was not being identified and evaluated for theB CRD pump gearbox leak.
Battery Charger Alarm Evaluation Prioritization The team identified two instances regarding the safety related 125 VDC system where the priorities assigned to equipment troubleshooting (to confirm problem evaluation conclusions and to assess the extent of the problem) were low and were inconsistent with the risk significance of the degraded equipment. In both instances, the licensee classified troubleshooting activities in a manner inconsistent with their procedures as elective rather than corrective maintenance.
The team determined the licensees work screening and process procedure classifies tasks broadly as either elective and corrective maintenance. The licensees procedure defines corrective maintenance as the restoration of equipment or components affecting nuclear safety, personnel safety, or plant reliability that have failed, are degraded, or do not conform to their original design, configuration, or performance criteria. The licensees procedure defines elective maintenance, in part, as potential equipment problems not meeting the criteria listed for corrective maintenance, such as minor equipment leaks.
The licensee initiated CAPs 2001-1027 and -1059 in June 2001 to address momentary undervoltage alarms for the 125 VDC bus when equipment was started. The licensee concluded the bus and equipment were operable, and initiated AR#A2014366 to complete further troubleshooting to confirm their conclusions and identify the extent of the problem. The licensee classified the AR as elective maintenance, deferred the work several times, and had not yet performed the troubleshooting at the time of the inspection. The team concluded that while the licensees initial evaluation conclusions were supported, the elective maintenance category and priority assigned to completing troubleshooting to confirm their conclusions and identify the extent of the problem was inconsistent with the 125 VDC bus safety function.
Similarly, the team identified that the licensee initiated CAP 2001-1302 in August 2001 to address resistors on alarm cards associated with the C-1 battery charger that had visual signs of overheating. The licensee concluded the battery charger was operable and initiated AR#A2014229, which was classified as elective maintenance, to repair the alarm cards. The AR had been rescheduled at least once, and at the time of the inspection, had not yet been performed. The team determined the affected charger alarm cards were either not used (low current alarm) or that surveillance tests confirmed
the alarm remained functional (ground circuit alarm). Additionally, surveillance tests indicated the C-1 battery charger output was normal. Notwithstanding, the team concluded the elective maintenance category and priority assigned to completing troubleshooting to identify the cause of the resistor degradation and confirm the extent of the problem was inconsistent with the battery charger safety function.
c. Effectiveness of Corrective Actions (1) Inspection Scope The team reviewed the licensees corrective actions associated with selected CAPs to determine whether the actions addressed the identified causes of the problems. The team also reviewed the licensees timeliness in implementing corrective actions and their effectiveness in preventing recurrence of significant conditions adverse to quality.
Furthermore, the team reviewed the backlog of CAP corrective actions, maintenance ARs, and planned work orders to determine whether there were corrective actions in the backlog that either individually or collectively were of risk significance to plant safety.
(2) Findings The team determined that actions identified within the licensees corrective action process addressed the causes of the problems and were generally tracked to timely completion. The team noted that licensee management reviewed internal performance indicators of open evaluations and corrective actions required to prevent problem recurrence (CAPRs) at weekly meetings to determine whether evaluations and CAPRs were being completed in a timely manner. Based on the sample reviewed and the licensees internal performance indicators, the team concluded the licensee controlled corrective action due dates commensurate with the risk significance of the problems.
The team did identify an instance where a non-CAPR corrective action to revise a drawing to reflect the plant was closed out to an AR; however, the AR had not yet been assigned to a department for completion. The licensee reviewed their AR database, identified fourteen additional ARs associated with CAPs that were not assigned, and initiated CAP 2002-0804 to address this process issue. The team reviewed the open, unassigned ARs and concluded none were safety significant or impacted equipment operability.
Based on a review of selected CAPs and observing management meetings during the inspection, the team concluded that licensee management adequately considered the potential safety significance of problems in determining the pace of corrective actions.
The team further determined that the licensees corrective actions were generally effective. For more significant problems, the licensee performed effectiveness reviews some time after the corrective actions were completed to confirm the effectiveness of their corrective actions.
Notwithstanding, the team observed that in the area of equipment tagging, the licensees corrective actions have not been effective to date. The team determined that since July 2001, the licensee evaluated seventeen problems in their corrective action process regarding preparing and maintaining clearance tags for equipment removed
from service. The errors included inadequately written clearance orders, working on equipment under no clearance or a suspended clearance, failure to sign onto active clearances, improper execution of clearance orders, and removal of clearance tags prior to completion of maintenance. An additional tagging problem occurred during the inspection where the incorrect core spray pump was removed from service for a short period (less than fifteen minutes). The licensee initiated CAP 2002-0802 for this self-identified problem.
Based on the continuing problem trend, the team concluded the licensees corrective actions to correct tagging problems have not been effective in improving performance.
The team further noted that an opportunity to identify this was missed in July 2001, when the licensee initiated a root cause evaluation via CAP 2001-1086 to address continuing equipment tagging problems. The licensees follow-up effectiveness review was completed in March 2002, and concluded that the corrective actions were effective since no sufficiently similar events had recurred since the initial event. However, the team noted that ten clearance and tagging error-related CAPs had been generated between initiating CAP 2001-1086 and the follow-up effectiveness review. The team determined the licensees effectiveness review incorrectly concluded their actions were effective in precluding further tagging problems.
d. Assessment of Safety Conscious Work Environment (1) Inspection Scope During the course of the inspection, team members interviewed plant staff to determine if conditions existed that would result in personnel being hesitant to raise safety concerns to their management and/or the NRC.
(2) Findings No findings were identified.
4OA6 Management Meetings Exit Meeting Summary The team presented the inspection results to Mr. E. Harkness and other members of licensee management on June 7, 2002. The licensee acknowledged the results presented. No proprietary information was identified during the inspection.
ATTACHMENT SUPPLEMENTAL INFORMATION KEY POINTS OF CONTACT Licensee (in alphabetical order)
R. Baran Regulatory Assurance J. Booty System Manager M. Bradley Manager, Instrument and Controls Maintenance J. Franks System Manager B. Guzejko Operations Support E. Harkness Plant Manager M. Heck System Manager E.Johnson System Manager A. Krukowski Manager, Maintenance Optimization G. Mulholland Work Week Manager W. Mussel System Manager J. Rogers Regulatory Assurance S. Schwartz System Manager R. Skelskey System Manager D. Slear Regulatory Assurance C. Wilson Senior Manager, Operations J. Yuen System Manager Other R. Pinney State of New Jersey Department of Environmental Protection, Bureau of Nuclear Engineering ITEMS OPENED, CLOSED, AND DISCUSSED Items Opened and Closed 50-219/02-03-01 NCV Violation of 10 CFR Appendix B, Criterion XVI for the failure to promptly identify and correct a condition adverse to quality regarding a low air flow condition in Train A of the control room ventilation system. (Section 4OA2.b)
LIST OF ACRONYMS USED AmerGen AmerGen Energy Company, LLC AR Action Request CAP Corrective Action Program Report CAPR Corrective Action to Prevent Recurrence CRD Control Rod Drive HVAC Heating, Ventilation, and Air Conditioning IMC Inspection Manual Chapter IPE Individual Plant Examination MSIV Main Steam Isolation Valve NCV Noncited Violation NRC Nuclear Regulatory Commission ROP Reactor Oversight Process SAR Safety Analysis Report SDP Significance Determination Process LIST OF DOCUMENTS REVIEWED Procedures SP-1302-12-237, Erosion/Corrosion Program SP-1302-12-261, Pipe Integrity Inspection Program 610-3.3.006, Rev. 43, Core Spray Isolation Valve Actuation and Calibration Test OU-AA-102, Rev. 2, Forced Outage Management OP-AA-102-102, General Area Checks and Operator Field Rounds WC-AA-101-1001, Rev. 1, Work Screening and Processing 351.1 Rev 83, Chemical Waste/Floor Drain System Operating Procedure 2000-ADM-7216.01, Corrective Action Process, Revision 9 2000-RAP-3024.02, Alarm Response Procedure - Electrical, Revision 70 2400-ADM-1220.18, Preventive Maintenance Program, Revision 4 LS-AA-126, Self-Assessment Program, Revision 2 LS-AA-126-1001, Focused Area Self-Assessments, Revision 0 108P,Clearance and Tagging, Revision 4 681.4.002, Quarterly Active Clearance Audit, Revision 0 Operational Experience Reviews 2001-11 (10CRF21)
OE 13394 OE 13279 OE 13270 OE 12439 OE 12809
Non-Cited Violations NCV 2001-003-01 (CAP 2001-0389)
NCV 2001-003-03 (CAP-2001-0306)
NCV 2001-006-01 (CAP-2001-1024)
NCV 2001-007-01 (CAP-2001-1214)
NCV 2001-009-01 (CAP-2001-1589)
NCV 2001-010-01 (CAP 2001-1865)
NCV 2001-007-02 (CAPs 2001-0307 and 2001-1155)
Calculations C-1302-104-E310-081 C-1302-211-E540-124 C-1302-211-5300-046 Temporary Modifications 1999-046 2001-034 2001-044 CAPS 1998-0021 2001-0092 2001-0931 2001-1430 2001-1838 1998-0218 2001-0259 2001-0962 2001-1435 2001-1881 1998-0321 2001-0307 2001-0974 2001-1474 2001-2061 1998-0562 2001-0344 2001-1025 2001-1494 2002-0006 1998-1198 2001-0344 2001-1027 2001-1524 2002-0028 1999-0243 2001-0389 2001-1041 2001-1552 2002-0056 1999-0348 2001-0487 2001-1059 2001-1611 2002-0065 1999-0903 2001-0496 2001-1078 2001-1612 2002-0087 1999-0924 2001-0501 2001-1086 2001-1616 2002-0089 1999-1516 2001-0503 2001-1121 2001-1662 2002-0108 2000-0115 2001-0578 2001-1129 2001-1666 2002-0161 2000-0290 2001-0688 2001-1191 2001-1682 2002-0185 2000-0301 2001-0690 2001-1212 2001-1735 2002-0194 2000-0305 2001-0711 2001-1229 2001-1742 2002-0202 2000-0407 2001-0715 2001-1285 2001-1749 2002-0214 2000-0852 2001-0715 2001-1307 2001-1750 2002-0220 2000-1269 2001-0720 2001-1358 2001-1753 2002-0222 2000-1513 2001-0811 2001-1359 2001-1758 2002-0223 2000-1589 2001-0824 2001-1360 2001-1759 2002-0231 2000-1609 2001-0851 2001-1366 2001-1761 2002-0300 2000-1788 2001-0853 2001-1373 2001-1768 2002-0305 2000-2041 2001-0866 2001-1374 2001-1770 2000-2061 2001-0890 2001-1377 2001-1781 2002-0315 2000-2061 2001-0919 2001-1378 2001-1782 2002-0334 2000-2124 2001-0922 2001-1390 2001-1784 2002-0338 2000-2151 2001-0927 2001-1428 2001-1785 2002-0345
2002-0355 2002-0499 2002-0591 2002-0681 2002-0778 2002-0364 2002-0506 2002-0592 2002-0686 2002-0785 2002-0369 2002-0512 2002-0593 2002-0688 2002-0787 2002-0388 2002-0513 2002-0594 2002-0697 2002-0802 2002-0389 2002-0542 2002-0598 2002-0698 2002-0804 2002-0393 2002-0545 2002-0612 2002-0710 2002-0806 2002-0459 2002-0552 2002-0615 2002-0711 2002-0818 2002-0461 2002-0565 2002-0645 2002-0719 2002-0825 2002-0472 2002-0583 2002-0654 2002-0762 2002-0850 2002-0484 2002-0589 2002-0679 2002-0764 2002-0496 ACTION REQUESTS (ARs)
A0701332 A0786454 A2017051 A2024360 A2032505 A0703414 A0786576 A2017277 A2026423 A2032636 A0706930 A0786787 A2018138 A2027357 A2032992 A0776781 A0786936 A2018872 A2027455 A2033300 A0777394 A2009427 A2018910 A2028361 A2033421 A0783089 A2010520 A2019672 A2028659 A2034409 A0783289 A2013122 A2019805 A2029686 A2034562 A0783648 A2013284 A2019942 A2030328 A2034625 A0785501 A2014229 A2020271 A2030576 A2034626 A0785898 A2014366 A2022609 A2031319 A2034627 A0786051 A2014585 A2023526 A2031327 A2035562 A0786115 A2014626 A2023908 A2031421 WORK ORDERS 00550972 R0805350 R0805761 R2007178 R2014223 C2001275 R0805444 R0807085 R2010803 R2014870 C2001279 R0805450 R0807645 R2011181 R2016807 C2001782 R0805453 R0808681 R2013869 R2017986 R0805304 R0805455 R0809338 R2013935 R2018561 Clearance Orders 01001440 01001498 01001445 01001528 01001476 01001647 01001496 02501002
Miscellaneous Monthly System Report (System 731 - 4160VAC Distribution System), March 2002 Monthly System Report (System 735 - 125VDC Station DC System), May 2002 System Health Overview Report, 125VDC System, 4th Quarter, 2001 Oyster Creek Nuclear Generating Station Letter - TS Amendment 221, July 17, 2001 Engineering Change Request (ECR) 01-00387, Replace PS-RE0023 Switches, Rev. 0 Oyster Creek Safety Review Board Meeting Minutes (Memoranda dated 2/14/01 and 5/18/01)
NOSA-OC-02-1Q, Continuous Assessment Report, January - March 2002 Defeated Alarm/Bypassed Recorder Input/Removed Recorder Summary Log, January 1, 2001 -
June 1, 2001 Operator Concerns Log, January 1, 2001 - June 1, 2001 Control Room Operating Logs; Entries, January 1, 2001 - June 1, 2001 Clearance and Tagging Risk Assessment, 108/108P Transition, December 1, 2001 Completed Surveillance Test Procedures 654.3.004 on 9/3/96, 9/12/98 and 7/20/00 Nuclear Plant Operator Initial Training Module for Main Steam System, Module 2611-PGD-2621 Focused Assessment of the Oyster Creek Maintenance Rule, SA-2-1-5125, September 2001