IR 05000456/2006002
| ML061360416 | |
| Person / Time | |
|---|---|
| Site: | Braidwood  |
| Issue date: | 05/15/2006 |
| From: | Skokowski R A NRC/RGN-III/DRP/RPB3 |
| To: | Crane C M Exelon Generation Co |
| References | |
| FOIA/PA-2010-0209 IR-06-002 | |
| Download: ML061360416 (29) | |
Text
May 15, 2006
Mr. Christopher M. CranePresident and Chief Nuclear Officer Exelon Nuclear Exelon Generation Company, LLC 4300 Winfield Road Warrenville, IL 60555
SUBJECT: BRAIDWOOD STATION, UNITS 1 AND 2 NRC INTEGRATEDINSPECTION REPORT 05000456/2006002; 05000457/2006002
Dear Mr. Crane:
On March 31, 2006, the U. S. Nuclear Regulatory Commission (NRC) completed an integratedinspection at your Braidwood Station, Units 1 and 2. The enclosed report documents the inspection results, which were discussed on April 3, 2006, with Mr. K. Polson and other members of your staff. Additionally, on May 12, 2006, a followup telephone discussion was held with Mr. Ambler of you staff to reclassify one issue provided during the April 3, 2006, meetings.The inspection examined activities conducted under your license as they relate to safety and tocompliance with the Commission's rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.Based on the results of this inspection, one self-revealed finding of very low safety significance(Green) is documented in this report. This finding was determined to involve a violation of NRC requirements. Because this violation was of very low safety significance and because the issue was 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 NRC's Enforcement policy.If you contest the subject or severity of the Non-Cited Violation, you should provide a responsewithin 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, D.C.
20555-001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission -
Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office ofEnforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-001; and the Resident Inspector office at the Byron facility.
C. Crane-2-In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letterand its enclosure will be made available electronically for public inspection in the NRCPublic Document Room or from the Publicly Available Records (PARS) component of NRC's 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/Richard A. Skokowski, ChiefBranch 3 Division of Reactor ProjectsDocket Nos. 50-456; 50-457License Nos. NPF-72; NPF-77
Enclosure:
Inspection Report 05000456/2006002; 05000457/2006002
w/Attachment:
Supplemental Informationcc w/encl:Site Vice President - Braidwood StationPlant Manager - Braidwood Station Regulatory Assurance Manager - Braidwood Station Chief Operating Officer Senior Vice President - Nuclear Services Vice President - Operations Support Vice President - Licensing and Regulatory Affairs Director Licensing Manager Licensing - Braidwood and Byron Senior Counsel, Nuclear, Mid-West Regional Operating Group Document Control Desk - Licensing Assistant Attorney General Illinois Emergency Management Agency State Liaison Officer Chairman, Illinois Commerce Commission
SUMMARY OF FINDINGS
IR 05000456/2006002, 05000457/2006002; 01/01/2006 - 03/31/2006; Braidwood Station,Units 1 & 2; Event Followup.This report covers a 3-month period of baseline resident inspection and an inspection inaccordance with Temporary Instruction 2515/165, "Operational Readiness of Offsite Power and
Impact on Plant Risk." The inspections were conducted by resident and inspectors based in the NRC Region III office. One Green finding which was a violation of NRC requirements wasidentified. The significance of most findings is indicated by their color (Green, White, Yellow,
Red) using Inspection Manual Chapter (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 NRC's program for overseeing the safe operation ofcommercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process,"Revision 3, dated July 2000.A.Inspector-Identified and Self-Revealed FindingsGreen. A finding of very low safety significance and associated Non-Cited Violation ofLicensee Condition 2.C(1) "Maximum Power Level," was self-revealed during the November 18, 2004, feedwater heater transient, which resulted in an increase of reactor power as high as 103.3 percent. Power was returned below the maximum licensed power by an automatic control rod stop and a turbine runback.This finding was considered more than minor because it had a credible impact onsafety, in that exceeding the maximum allowed power level potentially challenged the integrity of the reactor coolant and fuel integrity barriers. This finding affected the Barrier Integrity Cornerstone and was considered to have a very low safety significance (Green). Specifically, using the SDP Phase 1 screening worksheet (IMC 0609,
Appendix A, Attachment 1), the inspectors determined that the actual increase in reactorpower did not significantly challenge either the reactor coolant or fuel integrity barriers. (Section 40A3.2)
B.Licensee-Identified Violations
None.
2
REPORT DETAILS
Summary of Plant StatusBoth units operated at or near full power throughout the inspection period except for brief powerreductions for turbine valve testing, control rod adjustments, or feedwater systemmanipulations.1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity1R01Adverse Weather Protection (71111.01)
a. Inspection Scope
The inspectors performed several walkdowns of the temporary liquid radwaste storagetank areas in response to actual high winds, tornado watches, rainfall events, and freezing conditions. The purpose of the inspections was to monitor the licensee's response to damage to the berm around the tanks and determine if additional concerns or vulnerabilities existed. Minor issues identified during the walkdowns were brought tothe attention of plant management and the inspectors verified that they were enteredinto the licensee's corrective action program.The inspectors also reviewed Issue Reports (IRs) generated since the tanks wereinstalled to verify that problems with t he tanks and transfer system identified by thelicensee staff were being adequately addressed. Documents reviewed as part of this inspection are listed in the Attachment. This review constituted one sample of this inspection requirement for the onset of a site specific weather related condition.
b. Findings
No findings of significance were identified.
1R04 Equipment Alignment (71111.04)
.1 Partial Walkdowns
a. Inspection Scope
The inspectors performed partial walkdowns of the accessible portions of risk-significantsystem trains during periods when the train was of increased importance due toredundant trains or other equipment being unavailable. The inspectors utilized the valveand electric breaker checklists listed to determine whether the components were properly positioned and that support systems were aligned as needed. The inspectorsalso examined the material condition of the components and observed operating parameters of equipment to determine whether there were any obvious deficiencies.
3The inspectors reviewed IRs associated with the train to determine whether thosedocuments identified issues affecting train function. The inspectors used the information in the appropriate sections of the Technical Specifications (TS) and the Updated Final Safety Analysis Report (UFSAR) to determine the functional requirements of the system. The inspectors also reviewed the licensee's identification of and thecontrols over the redundant risk-related equipment required to remain in service. The inspectors verified that minor issues identified during this inspection were entered into the licensee's corrective action program. Documents reviewed during this inspection are listed in the Attachment.The inspectors completed three samples of this requirement by walkdowns of thefollowing trains:*1A residual heat removal (RH) train;*1A safety injection (SI) train; and
- 2B containment spray train.
b. Findings
No findings of significance were identified.
.2 Complete Walkdowns
a. Inspection Scope
The inspectors performed a complete system walkdowns of the following systems:
- nonessential service water (WS)system; and*Unit 1 diesel generator (DG) fuel oil transfer system.The WS system was selected because it is considered risk-significant from an initiatingevent standpoint, and the Unit 1 DG fuel oil system walkdown was performed after thelicensee discovered an out of positioned drain valve on the 1B DG fuel oil day tank. In addition to the walkdowns, the inspectors reviewed the following:
- selected operating procedures regarding system configuration;*the UFSAR, system drawings, and other selected design bases documentationregarding t he system; and*IRs for the system initiated within the last year.The inspectors verified that minor issues identified during this inspection were enteredinto the licensee's corrective action program. Documents reviewed as part of this inspection are listed in the Attachment. These walkdowns represented two inspection samples.
b. Findings
No findings of significance were identified.
41R05Fire Protection (71111.05)
.1 Quarterly Inspection
a. Inspection Scope
The inspectors conducted fire protection walkdowns which were focused on availability,accessibility, and the condition of fire fighting equipment, the control of transientcombustibles and ignition sources, and on the condition and operating status of installed fire barriers. The inspectors selected fire areas for inspection based on their overall contribution to internal fire risk, as documented in the Individual Plant Examination of External Events with additional insights or their potential to impact equipment which could initiate a plant transient or be required for safe shutdown. The inspectors used the Fire Protection Report, Revision 21, to determine: whether fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and that fire doors, dampers, and penetration seals appeared to be in satisfactory condition.The inspectors completed nine samples of this inspection requirement during thefollowing walkdowns:*halon fire suppression system;*0FP10S fire hydrant out of service and compensatory measure review;
- 1B DG room;
- Unit 1 upper cable spreading room;
- Unit 1 lower cable spreading room;
- Unit 1 essential switchgear room - Division 11;
- Unit 2 essential switchgear room - Division 21;
- turbine building 451 foot elevation general area pre-outage review of transientcombustibles; and *auxiliary building 383 foot elevation.The inspectors verified that minor issues identified during the inspection were enteredinto the licensee's corrective action program. Documents reviewed during this inspection are listed in the Attachment.
b. Findings
No findings of significance were identified.
.2 Annual Inspection (Fire Dr
ill)
a. Inspection Scope
The inspectors observed licensee fire brigade response to a simulated fire in theDivision 22 essential switchgear room. The inspector's evaluation included the following criteria:
5*proper number of fire brigade members, including a brigade leader, responded;*protective equipment, including self-contained breathing apparatus, was donnedproperly;*adequate fire fighting equipment was brought to the scene;
- command and control, communications, and procedure usage was appropriate;
- checks for victims and fire propagation were conducted;*attacks on the fire were conducted in accordance with training and procedures;*smoke removal was simulated;
- drill objectives were met;
- emergency action level conditions were discussed; and
- a critique was conducted in which any deficiencies identified by the inspectorswere also identified and discussed by the licensee evaluators or participants.This inspection constituted one sample of the annual requirement.
b. Findings
No findings of significance were identified.
1R06 Flood Protection Measures (71111.06)Internal Flooding Review
a. Inspection Scope
The inspectors evaluated the internal flooding controls for the following area:
- turbine building general area proximate to the 2C circulating water box withsystem drained and manhole covers removed during maintenance.This area constituted one sample of this inspection requirement. This turbine buildinggeneral area was selected because of the use of a temporary pumping systemestablished to prevent water intrusion into the water box and subsequently into the turbine building lower levels while the manhole covers were removed on the system.The inspectors reviewed the licensee's procedures for the pump rig set-up andperformed walkdowns to assess the validity of the line-up to ensure both mechanical adequacy and electrical power supply diversity was achieved.
b. Findings
No findings of significance were identified.
61R11Licensed Operator Requalification Program (71111.11)Quarterly Review of Testing/Training Activity
a. Inspection Scope
The inspectors observed operating crew performance during an evaluated simulator out-of-the-box scenario involving a steam generator tube rupture and failure of the reactor containment fan coolers to switch to slow speed.The inspectors evaluated crew performance in the following areas:
- clarity and formality of communications;*ability to take timely actions in the safe direction;
- prioritization, interpretation, and verification of alarms;
- procedure use;
- control board manipulations;
- oversight and direction from supervisors; and
- group dynamics.Crew performance in these areas was compared to licensee management expectationsand guidelines.The inspectors verified that the crew completed the critical tasks listed in the simulatorguide. The inspectors also compared simulator configurations with actual control board configurations. For any weaknesses identified, the inspectors observed the licensee evaluators to determine whether they also noted the issues and discussed them in thecritique at the end of the session. This review constituted one sample of this inspection requirement.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness (71111.12)Routine Inspection
a. Inspection Scope
The inspectors reviewed the licensee's overall maintenance effectiveness for selectedplant systems. This evaluation consisted of the following specific activities:*observing the conduct of planned and emergent maintenance activities wherepossible;*reviewing selected IRs, open Work Orders (WOs), and control room log entriesin order to identify system deficiencies;*reviewing licensee system monitoring and trend reports; 7*attending various meetings throughout the inspection period where the status ofmaintenance rule activities was discussed;*a partial walkdown of the selected system; and
- interviews with the appropriate system engineer.The inspectors also reviewed whether the licensee properly implemented MaintenanceRule, 10 CFR 50.65, for the chosen systems. Specifically, the inspectors determined whether:*the system was scoped in accordance with 10 CFR 50.65;*performance problems constituted maintenance rule functional failures;
- the system had been assigned the proper safety significance classification;*the system was properly classified as (a)(1) or (a)(2); and*the goals and corrective actions for the system were appropriate.The above aspects were evaluated using the maintenance rule program and otherdocuments listed in the Attachment. The inspectors also verified that the licensee was appropriately tracking reliability and/or unavailability for the systems.The inspectors completed two samples in this inspection requirement by reviewing thefollowing systems:*WS system subsequent to an increasing trend of temperature control valvecircuit issues and pump packing leaks; and*auxiliary feedwater (AF) system.
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
a. Inspection Scope
The inspectors reviewed the licensee's management of plant risk during emergentmaintenance activities or during activities where more than one signific ant system ortrain was unavailable. The activities were chosen based on their potential impact on increasing the probability of an initiating event or impacting the operation ofsafety-significant equipment. The inspections were conducted to determine whether evaluation, planning, control, and performance of the work were done in a manner to reduce the risk and minimize the duration where practical, and that contingency planswere in place where appropriate.The licensee's daily configuration risk assessment records, observations of operatorturnover and plan-of-the-day meetings, and observations of work in progress, were used by the inspectors to verify; that the equipment configurations were properly listed; thatprotected equipment were identified and were being controlled where appropriate; thatwork was being conducted properly; and that significant aspects of plant risk were being communicated to the necessary personnel.
8In addition, the inspectors reviewed selected issues, listed in the Attachment, that thelicensee encountered during the activities, to determine whether problems were being entered into the corrective action program with the appropriate characterization and significance.The inspectors completed six samples by reviewing the following activities:
- troubleshooting and repair of feedwater isolation valve 1FW009D;*1B RH pump maintenance;
- 2SX016A unplanned extension of TS allowed outage time;
- 1C reactor coolant pump (RCP) undervoltage trip circuit troubleshooting andrepair;*1A RH pump maintenance; and
- Unit Common component cooling water heat exchanger maintenance.
b. Findings
No findings of significance were identified.
1R14 Operator Performance During Non-Routine Evolutions and Events (71111.14)
a. Inspection Scope
The inspectors completed three samples by observing and/or reviewing operatorperformance during the following events:*Unit 1 power ascension with two moisture separator reheater drain tanksoperating on their emergency level control valves;*Unit 1 unplanned rod motion during routine surveillance testing; and*failure of the Group C shutdown bank indication.The inspectors observed the control room response, interviewed plant operators andreviewed plant records including control room logs, operator turnovers, and IRs. The inspectors verified that the control room response was consistent with stationprocedures and that identified discrepancies were captured in the corrective action program. Documents reviewed as part of this inspection are listed in the Attachment.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations (71111.15)
a. Inspection Scope
The inspectors evaluated plant conditions and selected IRs for risk-significantcomponents and systems in which operability issues were questioned. Theseconditions were evaluated to determine whether the operability of components wasjustified. The inspectors compared the operability and design criteria in the appropriate 9section of the UFSAR to the licensee's evaluations presented in the IRs and documentslisted in the Attachment to verify that the components or systems were operable. Theinspectors also conducted interviews with the appropriate licensee system engineersand conducted plant walkdowns, as necessary, to obtain further information regarding operability questions. Documents reviewed as part of this inspection are listed in theAttachment.The inspectors completed six samples by reviewing the following operability evaluationsand conditions:*review of Braidwood's evaluation of a Byron DG voltage regulator circuit failure;*review of procedure modification and re-performance of Unit 1 K640A slave relaysurveillance following surveillance failure;*Westinghouse fuel manufacturing issue;
- intermittent failure of 1C RCP undervoltage relay;
- review of DG operability with flame-hardened pushrods; and*power range nuclear instrument positive high flux rate reactor trip testingmethodology.
b. Findings
No findings of significance were identified.
1R19 Post-Maintenance Testing (71111.19)
a. Inspection Scope
The inspectors reviewed post-maintenance testing activities associated with importantmitigating systems, barrier integrity, and support systems to ensure that the testingadequately demonstrat ed system operability and functional capability. The inspectorsused the appropriate sections of the TS and UFSAR, as well as the WOs for the work performed, to evaluate the scope of the maintenance and to determine whether thepost-maintenance testing was performed adequately, demonstrated that the maintenance was successful, and that operability was restored. The inspectorsdetermined whether the tests were conducted in accordance with the procedures, including establishing the proper plant conditions and prerequisites; that the testacceptance criteria were met; and that the results of the tests were properly reviewed and recorded. The activities were selected based on their importance in demonstrating mitigating systems capability and barrier integrity. The inspectors verified that minorissues identified during the inspection were entered into the licensee's corrective action program by reviewing the documents in the Attachment.Six samples were completed by observing post-maintenance testing of the followingcomponents:*1B RH pump;*1B AF pump;
- Unit 2 fuel pool cooling pump;
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing (71111.22)
a. Inspection Scope
The inspectors reviewed surveillance testing activities associated with importantmitigating systems, barrier integrity, and support systems to ensure that the testingadequately demonstrat ed system operability and functional capability. The inspectorsused the appropriate sections of the TS and UFSAR to determine whether the surveillance testing was performed adequately and that operability was restored. Theinspectors determined whether the testing met the frequency requirements; that thetests were conducted in accordance with the procedures, including establishing the proper plant conditions and prerequisites; that the test acceptance criteria were met; and that the results of the tests were properly reviewed and recorded. The activities were selected based on their importance in demonstrating mitigati ng systems capability,barrier integrity and the initiating events cornerstone. Documents reviewed as part of this inspection are listed in the Attachment.Five samples were completed by observing and evaluating the following surveillancetests:*1A AF pump American Society of Mechanical Engineers (ASME) test; *2B DG bypass of automatic trips;
- 1B DG monthly slow start and turbo charger spindown tests;
- Unit 1 containment miniflow purge supply and exhaust isolation valve local leakrate test; and*2B DG oil transfer pump train ASME test.
b. Findings
No findings of significance were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
Cornerstones: Initiating Events Reactor Safety Strategic Area
a. Inspection Scope
The inspectors reviewed the documents listed in the Attachment to verify that thelicensee had correctly reported Performance Indicator data, in accordance with the criteria in Nuclear Energy Institute 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 2. The data reported by the licensee was compared to a sampling of control room logs, IRs, and other sources of data generated since the last verification. The inspectors verified that minor issues identified during the inspection were entered into the licensee's corrective action program. The inspectors completed six samples by reviewing the following Performance Indicators for the time frame covering January 1, 2004 through December 31, 2005:*Unit 1 unplanned scrams per 7000 critical hours;*Unit 1 unplanned scrams with loss of normal heat removal;
- Unit 1 unplanned transients per 7000 critical hours;
- Unit 2 unplanned scrams per 7000 critical hours;
- Unit 2 unplanned scrams with loss of normal heat removal; and
- Unit 2 unplanned transients per 7000 critical hours.
b. Findings
No findings of significance were identified.4OA2Identification and Resolution of Problems (71152)
.1 Routine Review of Identification and Resolution of Problems
a. Inspection Scope
As discussed in previous sections of this report, the inspectors routinely reviewed issuesduring baseline inspection activities and plant status reviews to determine whether they were being entered into the licensee's corrective action program at an appropriate threshold, that adequate attention was being given to timely corrective actions, and thatadverse trends were identified and addressed. Minor issues entered into the licensee's corrective action program as a result of the inspectors' observations are generally denoted in the Attachment. These activities were part of normal inspection activities and were not considered separate samples.
b. Findings
No findings of significance were identified.
The inspectors reviewed the observations of multiple FASAs to determine if the licensee's program was effective at identifying potential issues and developing associated corrective actions. Documents reviewed during this inspection are listed in the Attachment. This activity completed one sample of the annual requirement. a.Prioritization and Evaluation of Issues (1)Inspection ScopeThe inspectors assessed the licensee's evaluation and disposition of FASAs in 2005concerning the following areas: FASA report for Problem Identification & Resolution of August 2005, Common Cause Analysis for NRC Findings/Non-Cited Violations ofSeptember 2005, FASA report for Essential Service Water (SX) of July 2005, and the FASA report for Emergency Preparedness (EP) of July 2005.
(2)IssuesThe inspectors noted that each finding of the Safety System Design and Performance(SSDPC) inspection that the FASA did not identify was captured in an IR and was assigned a priority consistent with its significance. The inspectors also noted that two of the findings were outside the scope of the FASA charter. The three remaining findings were within the scope of the charter, but were not identified by the FASA team. Specifically, the FASA team looked into operator actions and procedures related to the SX system, but were unable to identify the deficiency for the recovery of plugged SXstrainers and adequate DG SX cross-connect flow. The last finding concerned the ASME in-service inspection of the SX intake header piping, but the FASA did not evaluate for ASME in-service inspection adequacy. The licensee was planning to perform a root cause evaluation to determine the reason(s) for these five discrepancies and the plan was being tracked by IR 370513. The inspectors determined that the August 2005 FASA for Problem Identification &Resolution had appropriately reviewed for common causes and resolutions of past findings and violations. However, the inspectors noted that the licensee failed to assess current unresolved items (URIs) for disposition. The licensee had disputed the validity of a URI concerning molded case circuit breakers and thus did not assess corrective actions for it.
13The inspectors noted that the July 2005 FASA on EP had appropriately reviewed the EPprogram with the exception of the review of Emergency Action Level (EAL) changes.
The licensee conducted a direct review of EAL changes 13 through 15 for 50.54(q)adequacy. A subsequent NRC inspection determined that an EAL change, which waspart of the FASA review for unplanned radiological release in excess of limits, was not adequate and resulted in a Severity Level IV violation. Although these issues indicated shortcomings within the licensee's self-assessments, the issue with the self-assessments did not constitute violations of NRC requirements.4OA3Event Followup (71153)The inspectors completed two inspection samples in this area.
.1 Offsite Tritium Contamination From Prior Circulating Water Vacuum Breaker Leaks
a. Inspection Scope
This event was previously discussed in Inspection Report 05000456/2005010;05000457/2005010; Section 4OA3.1. The inspectors continued activities following up this event to monitor the licensee's characterization of the leaks and contamination, plans for mitigation, root cause evaluations, and other actions.Activities completed by the inspectors included:
- monitoring the licensee's efforts to identify historic spills/leaks from theblowdown line and other events that could have caused tritium releases;*monitoring the licensee's efforts to identify the extent of contamination aroundthe blowdown vacuum breaker valves;*participating in a public information night on February 28, 2006, at the licensee'straining facility;*monitoring the licensee's response to a spill on March 13, 2006, from the bermaround the outside temporary storage tanks;*conducting several walkdowns of the outside temporary storage tanks andpumping system;*monitoring the licensee's response to tritium found in Center Street ditches froma nearby overflowing cistern;*observing licensee maintenance on blowdown vacuum breaker valves; and
- holding several discussions with licensee personnel regarding its plans to pumpthe water from Exelon pond, just north of Smiley Road.The inspectors verified that minor issues identified during this inspection were enteredinto the licensee's corrective action program. Documents reviewed during this inspection are listed in the Attachment.
b. Findings
The NRC conducted a separate inspection regarding this event as documented inInspection Report 05000456/2006008; 05000457/2006008. Violations and findings 14were identified in that inspection. No additional findings of significance were identifiedduring this inspection.
.2 (Closed) Licensee Event Report (LER) 05000456/2005003-00:
Licensed MaximumPower Level Exceeded Due to Feedwater Heater TransientIntroduction: On November 18, 2004, a feedwater heater transient resulted in anincrease of reactor power as high as 103.3 percent. The overpower event was self-revealing and determined to be a Non-Cited Violation of License Condition 2.C.(1)
"Maximum Power Level." This finding was determined to be of very low safety significance.
Description:
On December 2, 2005, the licensee identified that Unit 1 reactor power hadexceeded its maximum licensed power level during a feedwater heater transient occurring on November 18, 2004. Initially, the licensee had concluded that the licensedpower level was not exceeded based on the nuclear instrumentation readings during the event. However, during a subsequent evaluation, the licensee concluded that the Unit 1peak power during this event was 103.3 percent, which was a violation of License Condition 2.C.(1) "Maximum Power Level."On November 18, 2004, Braidwood Unit 1 experienced an isolation of extraction steamto the 15A and 15B low pressure feedwater heaters. The isolation occurred after the 15A level controller was inadvertently bumped due to nearby maintenance. The isolation caused a heater control system transient cascading through the 16A/B and17A/B low pressure feedwater heaters, respectively. The loss of feedwater preheat allowed colder water to enter the steam generator, causing an increase in reactor power due to the positive reactivity feedback. Reactor power increased above the overpower delta-temperature set point on 2 of 4 channels, resulting in an automatic control rod stop and a turbine runback.The licensee's initial evaluation was that event did not exceed the licensed power limitbased on nuclear instrumentation readings and a 10 minute average computer calorimetric taken during the event. Although licensee operating staff noted that the reactor coolant loop temperature indications had exceeded 102 percent power during the event, these indications were considered less credible, as the delta temperature channels were less accurate during an event than during steady state operation.
However, during a subsequent peer review of this event, it was questioned whether the Unit 1 power increase was accurately determined. As a result, the licensee asked Westinghouse Corporation to perform an independent evaluation of the Unit 1 power increase. This evaluation was completed on December 1, 2005, and concluded that Unit 1 reactor power was likely as high as 103.3 percent during this event. This new value was based on an evaluation of the affect of the reactor coolant temperature changes observed during the event on the nuclear instrumentation readings. On December 3, 2005, the licensee notified the NRC of the possible violation of thelicensed power level.The licensee's corrective actions, as described in the LER, included developing astandard work package for working on the level control assemblies for the low pressure feedwater heaters. This package included guidance on avoiding inadvertent isolation of 15the heaters during maintenance on the level controllers. Additionally, the licensee wasdeveloping guidance for determining the appropriate corrections to nuclear power instrumentation readings, after a potential overpower transient. This event and the corrective actions were being tracked by licensee IR 280594, dated November 18, 2004.Analysis: The inspectors determined that the inadvertent bumping of the feedwaterheater level controller during nearby maintenance was a performance deficiency warranting a significance evaluation. This finding was considered more than minor because it had a credible impact on safety, in that exceeding the maximum allowed power level potentially challenged the integrity of the reactor coolant and fuel integritybarriers. This finding affected the Barrier Integrity Cornerstone and was considered to have very low safety significance (Green). Specifically, using the SDP Phase 1 screening worksheet (IMC 0609, Appendix A, Attachment 1), the inspectors determined that the actual increase in reactor power did not significantly challenge either the reactorcoolant or fuel integrity barriers.Enforcement: Licensee Condition 2.C.(1) "Maximum Power Level," required thatBraidwood, Unit 1, reactor core power levels not exceed 3586.6 megawatts thermal (100 percent rated power). Contrary to this, on November 18, 2004, Braidwood Unit 1 power was 103.3 percent following a feedwater heater transient, caused by the inadvertent isolation of feedwater heaters during routine maintenance. This event andthe corrective actions were being tracked by licensee IR 280594, dated November 18, 2004. Because the violation was of very low safety significance and the issue was captured in the licensee's corrective action program, this violation is being treated as a Non-Cited Violation consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000456/2006002-01). 4OA5OtherImplementation of Temporary Instruction (TI) 2515/165 - Operational Readiness ofOffsite Power and Impact on Plant Risk
a. Inspection Scope
The objective of TI 2515/165, "Operational Readiness of Offsite Power and Impact onPlant Risk," was to confirm, through inspections and interviews, the operational readiness of offsite power systems in accordance with NRC requirements. On March 13through 15, 2006, the inspectors reviewed licensee procedures and discussed the attributes identified in TI 2515/165 with licensee personnel. In accordance with the requirements of TI 2515/165, the inspectors evaluated the licensee's operatingprocedures used to assure the functionality/operability of the offsite power system, aswell as, the risk assessment, emergent work, and/or grid reliability procedures used toassess the operability and readiness of the offsite power system.The information gathered while completing this TI was forwarded to the Office ofNuclear Reactor Regulation for further review and evaluation. The TI is closed.
b. Findings
No findings of significance were identified.4OA6MeetingsExit MeetingThe inspectors presented the inspection results to Mr. K. Polson and other members oflicensee management at the conclusion of the inspection on April 3, 2006. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.On May 12, 2006, an additional followup telephone discussion was held with Mr. Amblerof the licensee management to reclassify one issue described during the April 3, 2006, meeting.ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- K. Polson, Site Vice PresidentG. Boerschig Plant Manager
- D. Ambler, Regulatory Assurance Manager
- S. Butler, Licensing Engineer
- T. D'Antonio, Project Manager
- G. Dudek, Operations Director
- J. Kuczynski, Chemistry Manager
- J. Moser, Radiation Protection Manager
- M. Smith, Engineering Director
- E. Wrigley, Maintenance DirectorNuclear Regulatory Commission
- R. Skokowski, Chief, Reactor Projects Branch 3
LIST OF ITEMS
OPENED, CLOSED AND DISCUSSED
Opened
05000456/2006002-01NCVLicensed Maximum Power Level Exceeded Due toFeedwater Heater TransientClosed05000456/2005003-00LERLicensed Maximum Power Level Exceeded Due toFeedwater Heater Transient05000456/2006002-01NCVLicensed Maximum Power Level Exceeded Due toFeedwater Heater TransientDiscussedNone.
2
LIST OF DOCUMENTS REVIEWED
The following is a list of documents reviewed during the inspection.
- Inclusion on this list doesnot imply that the NRC inspectors reviewed the documents in their entirety but rather that selected sections of portions of the documents were evaluated as part of the overall inspection effort.
- Inclusion of a document on this list does not imply NRC acceptance of the document orany part of it, unless this is stated in the body of the inspection report.1R01Adverse Weather ProtectionIR
- 465083; Enter 0/1/2BwOA
- ENV-1, Due to Tornado Watch for the Area; March 11, 2006IR
- 465367; Enter 0/1/2BwOA
- ENV-1, Due to Tornado Watch for the Area; March 12, 2006IR
- 465719; FRAC Tank Berm Pushed Flat due to High Wind Condition; March 13, 2006
- IR 466356; FRAC Farm #2 Berm/Water Issues; March 14, 2006 [NRC-Identified]1R04Equipment AlignmentBwAR 1PL07J-1-E6; Day Tank Level Low; Revision 5E2BwOP
- RH-E1; Electrical Lineup - Unit 1 Operating; Revision 6
- BwOP
- RH-M1; Operating Mechanical Lineup Unit 1 1A RH Train; Revision 12
- BwOP
- SI-E1; Electrical Lineup - Unit 1 Operating; Revision 9
- BwOP
- SI-M1; Operating Mechanical Lineup Unit 1; Revision 16
- BwOP
- CS-M2; Operating Mechanical Lineup Unit 2; Revision 6
- BwOP
- CS-E2; Electrical Lineup - Unit 2; Revision 0E2
- BwOP
- DO-M11; Operating Mechanical Lineup Unit 1 DG 1A Fuel Oil; Revision 3
- BwOP
- DO-M13; Operating Mechanical Lineup Unit 1 DG 1B Fuel Oil; Revision 3
- 1BwOSR 3.8.1.2-2; 1B DG Operability Surveillance; Revision 15
-50; Diagram of Diesel Fuel Oil Unit 1; Sheet 1A
-50; Diagram of Diesel Fuel Oil Unit 1; Sheet 1D
-129; Diagram of Containment Spray -Sheet 1A
- IR 443238; NRC Noted Rust on 2CS01T (Unit 2 Containment Spray Additive Tank);January 18, 2006 [NRC-Identified]IR
- 468586; 1DO2006B Found Out of Normal Position; March 20, 20061R05Fire ProtectionBwAP 1110-1; Fire Protection Program System Requirements; Revision 24IR
- 436464; UCSR Halon Bottle Weight PM Issues; December 20, 2005
- IR 440315; Excess Storage of Transient Combustibles in Unit 1 Turbine Building; January 9,
- 2006 [NRC-Identified]IR
- 443407; Need to Add Steps to BwHS 4009-118 Concerning Low Halon Pressure;
- January 18, 2006 [NRC-Identified]IR
- 443982; Potential Trend in Oversight/Involvement in Fire Protection; January 19, 2006
[NRC-Identified]IR
- 455181; Appendix R Light "Ready" LED is not Lit; February 17, 2006 [NRC-Identified]IR
- 462935; Unit 1 Upper Cable Spreading Room Needs General Housekeeping Cleanup;
- March 7, 2006 [NRC-Identified]IR
- 467316; Fire Extinguisher T-8-19, Missing Quarterly Inspection Initials; March 16, 2006
[NRC-Identified]IR
- 467659; Fire Extinguisher A-4-5, Missing Quarterly Inspection Initials; March 17, 2006
[NRC-Identified]
- 3Braidwood Station Pre-fire Plans; Fire Zone 3.3; February 1, 2006Braidwood Station Pre-fire Plans; Zone 3.2; February 1, 2006
- Fire Protection Report; Figure 2.3-7, Upper Cable Spreading Area; Amendment 18
- Fire Protection Report; Figure 2.3-9, Lower Cable Spreading Area; Amendment 18
- Braidwood Station Pre-fire Plans; Fire Zone 5.2-1; February 1, 2006
- Braidwood Station Pre-fire Plans; Fire Zone 5.2-2; February 1, 2006
- Fire Protection Report; Figure 2.3.8.10; Turbine Building Main Floor (Fire Zone 8.6-0);
- Amendment 21
- Fire Protection Report; Figure 2.3-10, Mezzanine Floor Plan EL. 426'; Amendment 17
- Fire Protection Report; Figures 2.3-13, Floor Plan EL. 383'-0"; Amendment 18
- Fire Protection Report; Figure 2.4.2.54; Turbine Building Operating Floor (Fire Zone 8.6-0);Amendment 21
- Figure 2.3-8; Main Floor at Elevation 451"-0"; Sheets 1 and 2 of 4
- Fire Drill Scenario No. 20.01.21.06; Transformer 232X Fire; March 29, 20061R12Maintenance Effectiveness (71111.12Q)IR
- 291725; 0WS362B Leaks By and Will Not Isolate (Duplicate of
- WO 668623); January 18, 2005
- IR 302144; Pipe Leaking Upstream of Valve; February 16, 2005
- IR 303561; 2WS023A Leaks By (Winter Time Problem); February 20, 2005
- IR 305944; 1A Electro Hydraulic Cooler WS Inlet Flex Hose Bulged; February 27, 2005
- IR 305945; 2B Electro Hydraulic Cooler WS Outlet Flex Hose is Heavily Corroded; February 27,
- 2005
- IR 310779; 1WS021A Leaks By and Allowing Steady Stream of Water to Flow; March 10, 2005
- IR 311137; Raw Water Systems Corrosion Rates Higher than Exelon Target; March 10, 2005
- IR 313289; Numerous WS Valves Leak By; March 16, 2005
- IR 324061; 0C WS Pump Bowl Full of Water; April 13, 2005
- IR 326104; 2WS060A Had Solid Stream of Leak by When Used for Isolation; April 19, 2005
- IR 326428; Excessive Leakage from Packing Gland on 0WS01PC; April 19, 2005
- IR 330772; 2FW01A WS Lines to Motor Bearing Oil Coolers Plugged - Piping Replaced; May 1,
- 2005
- IR 334600; Unit 2 Generator Cold Gas Temperature Indication Erratic; May 12, 2005
- IR 335914; WS Piping Inlet Flange to Air Side Seal Oil Cooler Degraded; May 17, 2005
- IR 336098; WS Outlet Flange to H2 Side Seal Oil Cooler Needs Replacing; May 17, 2005
- IR 337347; Valve 0WS381A is Continuously Leaking By; May 21, 2005
- IR OC WS Pump Has Spraying Packing Leak; May 28, 2005
- IR 339919; Drain Assembly for WS on 2PS11MB Broke Off; May 31, 2005
- IR 346321; WS Flow at 900 Gallons Per Minute with Chiller Shutdown; J
une 22, 2005IR
- 351262; 2WS395B Leaks By Seat; July 8, 2005
- IR 351380; WS Supply and Return Lines are Clogged to 2AS02PA and 2AS02PB; July 8, 2005
- IR 355192; No Change in Unit 1 Exciter Temp When Fully Opening Bypass Valve; July 20,
- 2005
- IR 363643; 2WS113 Air Gauges not Functioning; August 16, 2005
- IR 368551; Excessive Packing Leak on 0WS01PA; August 31, 2005
- IR 368553; Excessive Packing Leak on 0WS01PB; August 31, 2005
- IR 373783; 1B Feedwater Pump WS Temperature Control Valve is Leaking By with Full Closed Demand; September 15, 2005
- IR 394127; Line 1WS15AA-1.5" Found to be Below Minimum Wall Thickness; November 3,
- 2005
- 4IR
- 396107; 0FI-WS070 Indicator Reading 0 Gallons Per Minute with Flow Present in Line;November 8, 2005
- IR 399239; 2WS143 Exciter Cooling Temperature Control Valve Failure; November 16, 2005
- IR 428436; Observed Wall Thinning on Line 1WS17BD-2" (Pre-Freeze Non Destructive Examination); November 29, 2005
- IR 436245; WS Temperature Control Valves (2WS054) Swinging; December 22, 2005
- IR 443267; 0WS112 Needs to Changed from Bronze to Carbon Steel; January 18, 2006
- IR 455777; 2B Heater Drain Pump Motor Cooler WS Return Line Leak; February 19, 2006
- IR 457303; Bryozoa Suspected in Valve 1CW096C; February 22, 2006
- High Safety Significant Status of In-Scope Functions
- NEX-MS-03.1; Piping Minimum Wall Thickness Calculation; Revision 3
- Maintenance Rule - Performance Criteria; Cooling Water for Non Safety Loads Maintenance Rule Expert Panel Scoping Determination; WS System; Braidwood Station Maintenance Rule -Evaluation History; WS System; February 21; 2006
- IR 00225998; Unplanned Limiting Condition for Operation Entry for 2AF01PA Failure to Start;
- June 4, 2004
- IR 00227302; 2A AF Pump Failed to Start from Main Control Room - Unplanned Technical Requirements Manual Entry; June 6, 2004
- IR 00204230; Pump Oil Reservoir Goes Empty When Oil Auxiliary Oil Pump Starts;February 26, 2004
- IR 00205604; No Post Maintenance Test Specified for 5 Year AF Battery Test; February 24,
- 2006
- Maintenance Rule - Performance Criteria; AF System; Braidwood Station Maintenance Rule Expert Panel Scoping Determination; AF System; Braidwood Station Maintenance Rule - Evaluation History; AF System; March 13, 20061R13Maintenance Risk Assessments and Emergent Work Control1BwOA; Attachment P RCP [Reactor Coolant Pump] Bus Undervoltage; Revision 101IR
- 455048; Received Unexpected Annunciator 1-13-A2 RCP Bus Undervoltage; February 17,
- 2006
- Drawing 20E-1-4017C; Relaying and Metering Diagram 6900 Volts Switchgear Bus 158;
- Sheet E03
- Drawing 20E-1-4030AP21; 6.9 Kilovolts Switchgear Bus 158 Undervoltage and Underfrequency Relays Sheet E07
- Drawing 20E-1-4030F28; Reactor Protection - RCP Underfrequency and Undervoltage and Overpower and Over Temperature Trips; Sheet 07
- Drawing 20E-1-4030EF72; Reactor Protection - RCP Underfrequency and Undervoltage and Overpower and Over Temperature Trips; Sheet 07
- Issue Resolution Documentation Form; Bus 158 Undervoltage Engineered Safety Feature Actuation System Input; February 17, 2006
- Technical Bulletin
- TB-04-17, Revision 1; Replacement Relays in Solid State Protection System;
- November 18, 2005
- List of Protected Equipment; March 6, 2006
- Risk Assessment Sheet; Work Week of March 6, 2006
- Unit 0 Component Cooling Heat Exchanger Protected Equipment Log
- 51R14Operator Performance During Non-Routine Evolutions and EventsIR
- 447364; Shutdown Bank C Group Step Counter Declared Inoperable; January 30, 2006IR
- 447696; Lessons Learned from U2 Step Counter Replacement; January 30, 2006
- IR 446848; Unexpected Rod Movement During Instrument Maintenance Calibration;
- January 27, 2006
- MA-AA-7176-004; Troubleshooting Log; January 30, 20061R15Operability EvaluationsBwISR 3.3.1.8-005; Channel Operational Tet of Nuclear Instrumentation System PowerRange N41; Revision 12
- BwISR 3.3.1.11-205; Channel Verification/Calibration of Nuclear Instrumentation System PowerRange N41; Revision 12
- IR 436037; 1A DG Large Swings in Volts Amps Reactive (VARS) During Monthly Surveillance;December 21, 2005
- IR 436037 Assign#2; Equipment Apparent Cause Evaluation to Investigate 1A DG VAR Swings;January 24, 2006
- IR 436037 Assign#4; 1A DG Large Swings in VARS During Monthly Surveillance; January 31, 2006
- IR 440621; 1BwOSR 3.3.2.8-640A Unexpected Results; January 10, 2006IR
- 456689; Diesel Generator Operation and Operability with Flame-Hardened Pushrods;February 27, 2006
- IR 466771; Potential Missed Surveillance Requirement for Power Range Positive Flux RateTrip; March 15, 2006
- Regulatory Guide 1.118 - Periodic Testing of Electric Power and Protection Systems;
- Revision 3
- 20E-1-4030DG54; DG 1B Starting Sequence Cont. (Description of Operation 1DG01KB Part 4);
- Sheet 11R19Post-Maintenance Testing1BwOSR 5.5.8
- SI-1B; Train B Safety Injection System Valve Stroke Surveillance; Revision 41BwOSR 5.5.8
- SI-2; ASME Surveillance Requirements for the 1B Safety Injection Pump;
- Revision 4
- 1BwOSR 5.5.8
- SI-2B; Indication Test of 1SI8807B, SI and CV (Chemical and Volume Control)
- Pumps Suction Header X-Tie Valve; Revision 4
- EC [Engineering change]
- 352609; Design Change Package 1B Auxiliary FeedwaterPerformance Monitoring System; Revision 0
- IR 445952; Lessons Learned from Performance of 2BwOSR 3.8.2.23-2
- IR 458106; Pipe Wrench Staged on the Grating Near 1SI161; February 24, 2006[NRC-Identified]IR
- 459084; Door to 2AF01PB Not Fixed Since November 2, 2004; February 27, 2006
[NRC-Identified]WO
- 863648 01; ASME Surveillance Requirements for Residual Heat Removal Pump;January 23, 2006
- WO 871148 01; September ASME Surveillance Requirements for 1B Safety Injection Pump;February 24, 2006
- 1BwOSR 5.5.8.CC-2A; Train A Component Cooling Water Isolation Valve Indication 18 MonthSurveillance; Revision 0
- 1BwOSR 5.5.8.RH-2A; Train A Residual Heat Removal Valves Indication Test Surveillance;Revision 1
- 61BwOSR 5.5.8.SI-2A; Train A Safety Injection System Isolation Valve Indication TestSurveillance; Revision 3
- 1BwOSR 5.5.8.RH-3A; Residual Heat Removal Train A Valves Stroke Surveillance; Revision 31BwOSR 5.5.8.CC-1A; Train A Component Cooling Isolation Valves Stroke QuarterlySurveillance; Revision 1
- 0BwOS
- Revision 51R22Surveillance Testing2BwOSR 3.8.1.13-2; 2B DG Bypass of Automatic Trips Surveillance; Revision 2IR
- 445967; High Strainer P; January 25, 20062BwVSR 5.5.8.DO.2; ASME Requirement for Testing the Diesel Fuel Oil Transfer System (B-
- Train); Revision 2
- WO 859409 01; Unit One Motor Driven Auxiliary Feedwater Pump ASME QuarterlySurveillance; January 6, 2006
- WO 872919; Mechanical Maintenance-Fuel Oil Transfer Pump Suction Strainer; March 24,
- 2006
- BwOP
- DG-1; Diesel Generator Alignment to Standby Condition; Revision 26
- BwOP
- DG-11; Diesel Generator Startup; Revision 30
- BwOP
- DG-12; Diesel Generator Shutdown; Revision 23
- BwVS 900-8; Diesel Generator Engine Analysis; Revision 7
- 1BwOSR 3.8.1.2-2; 1B Diesel Generator Operability Surveillance; Revision 151BwOSR 3.6.3.6; Primary Containment Type C Local Leakage Rate Tests of ContainmentMiniflow Purge Isolation Valves (VQ); Revision 4
-130; Diesel Oil and Fuel Oil Supply Unit 2; Sheet 1B1R23Temporary Plant ModificationsBwOP
- WX-501T4; Liquid Release Tank 0WX01T Transfer to Temporary Storage Tank;Revision 3
- EC 358522 (Temporary Configuration; Addition of Temporary Storage Capacity for the Liquid Radwaste System; Revision 0
- EC 358798; Provide Guidance for Installation of Electrical Power for the Outdoor Tritium Tank Farm; January 6, 2006
- IR 465817; Evaluate Whether TCC
- EC 358498 Hoses are Satisfactory; March 13, 2006
[NRC-Identified]
4OA1 Performance Indicator VerificationLS-AA-2010; Monthly Data Elements for
- NRC/WANO [World Association of Nuclear Operators]Unit/Reactor Shutdown Occurrences; Revision 3
4OA2 Identification and Resolution of ProblemsAT 265884;
- EP Program Assessment Report; July 7, 2005IR
- 370513; Review for Missed Opportunities from NRC SSDPC Inspection; September 6, 2005IR
- 367473; Potential Enhancements to Strainer Backwash Response ; August 27, 2005IR
- 364793; SSDPC Inspection - Pressure Test of SX piping; August 18, 2005
- AT 287798-02; SSDPC FASA Report; July 8, 2005
- 7CCA related to
- 358058; NRC Findings/Non-Cited Violations and Licensee Identified Violations;September 29, 2005
- IR 358058; NRC Findings/Non-Cited Violations and Licensee Identified Violations; July 29, 2005
- AT 265881; Problem Identification and Resolution; August 5, 2005
4OA3 Event FollowupLS-AA-125-001; Root Cause Investigation Charter; Tritium Release from Braidwood Stationwith Potential to Affect Public; Revision 5
- IR 274721;
- HI-2 Isolation of 15-17 Heaters Causing OPDT Runback; November 18, 2004
- IR 274718; Main Turbine Governor Valve Indication; November 18, 2004
- IR 281594; Evaluation of Reactor Power During Recent OPDT Runback Event; November 18,
- 2004
- IR 442540; Leak at Circulating Water Blowdown Vacuum Breaker; January 16, 2006
- IR 448107; Tritium Found in Groundwater Northeast of Vacuum Breaker 4; January 30, 2006
- IR 472315; Concerns with FRAC Tank System Identified by NRC Resident; March 29, 2006[NRC-Identified]IR
- 472351; NRC Questions Temporary Tritium storage Inside Steam Generator ReplacementProject Building; March 29, 2006 [NRC-Identified]
- 8
LIST OF ACRONYMS
USEDAFAuxiliary FeedwaterADAMSAgencywide Documents Access and Management System
ASMEAmerican Society of Mechanical Engineers
BwAPBraidwood Administrative Procedure
BwARBraidwood Annunciator Response Procedure
BwISRBraidwood Instrument Surveillance Requirement ProcedureBwOABraidwood Abnormal Operations Procedure
BwOPBraidwood Operating Procedure
BwOSRBraidwood Operating Surveillance Requirement ProcedureBwVSBraidwood Engineering Surveillance ProcedureBwVSRBraidwood Engineering Surveillance Requirement ProcedureCFRCode of Federal Regulations
CVChemical and Volume Control System
DGDiesel Generator
EALEmergency Action Level
ECEngineering Change
FASAFocus Area Self-Assessments
EPEmergency Preparedness
IRIssue Reports
LERLicensee Event Report
NRCNuclear Regulatory Commission
PARSPublicly Available Records
PI&RProblem Identification and Resolution
RCPReactor Coolant Pump
RHResidual Heat Removal
SDPSignificance Determination Process
SISafety Injection
SSDPCSafety System Design and Performance
SXEssential Service Water
TITemporary Instruction
TSTechnical Specification
UFSARUpdated Final Safety Analysis Report
URIUnresolved Item
VARVolts Amps Reactive
WANOWorld Association of Nuclear Operators
WOWork Order