IR 05000400/1991013
| ML18009A974 | |
| Person / Time | |
|---|---|
| Site: | Harris  |
| Issue date: | 06/27/1991 |
| From: | Christensen H, Shannon M, Tedrow J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18009A972 | List: |
| References | |
| 50-400-91-13, NUDOCS 9107160115 | |
| Download: ML18009A974 (19) | |
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ONITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 Report No.:
50-400/91-13 Licensee:
Carolina Power and Light Company P. 0.
Box 1551 Raleigh, NC 27602 Docket No.:
50-400 Faci1 ity Name:
Har ris
Inspection Cond ted:
May 18 - June 14, 1991 Inspectors:
J.
drow, Sensor Ress ent nspector License No.:
NPF-63 Date cygne
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M.
ann as>dent nspectnn c wage ate sgne Approved b
H.
r>stensen, ection ie Division of Reactor Projects ate S>gne SUMMARY Scope:
This routine inspection was conducted by two resident inspectors in the areas of plant operations, radiological controls, security, fire protection, surveillance observation, maintenance observation, design changes and modifications, licensee event reports, evaluation of licensee self assessment, followup of onsite events, plant startup from refueling, and licensee action on previous inspection items.
Numerous facility tours were conducted and facility operations observed.
Some of these tours and observations were conducted on backshifts.
Results:
One violation was identified:
Failure to have two operable AFW system flow paths (paragraph 2.b. 1).
The licensee's efforts to identify repetitive failures was considered to be a
strength of the licensee's maintenance program (paragraph 4).
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07lboliS ~50op400 ~ Op+7 pDR POOCH 0 POP G P h, REPORT DETAILS Persons Contacted Licensee Employees P. Beane, Manager, guality Control
- J. Collins, Manager, Operations C. Gibson, Manager, Programs and Procedures
- C. Hinnant, General Manager, Harris Plant D. McCarthy, Manager, Site Engineering B. Meyer, Manager, Environmental and Radiation Monitoring T. Morton, Manager, Maintenance J. Nevill, Manager, Technical Support
- C. Olexik, Manager, Regulatory Compliance A. Powell, Manager, Harris Training Unit R. Richey, Vice President, Harris Nuclear Project H. Smith, Manager, Radwaste Operation E. Willett, Manager, Outages and Modifications W. Wilson, Manager - Spent Nuclear Fuel Other licensee employees contacted included office, operations, engineering, maintenance, chemistry/radiation and corporate personnel.
"Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragraph. Review of Plant Operations (71707) The plant began this inspection period in the cold shutdown (Mode 5) condition. Following repair of a packing leak on a block valve for a pressurizer power operated relief valve, a plant heatup was performed and the hot standby (Mode 3) condition reached at 1:27 a.m. on May 19. A reactor startup was commenced at 8:20 a.m., on May 20, and the RCS boron concentration was diluted to achieve reactor criticality at 4:50 p.m. At 12:36 p.m. on May 22, the plant began power operation (Mode 1). After a brief turbine overspeed trip test which necessitated placing the plant back in the startup condition, plant power operation resumed at 7:34 a.m. on May 25. On June 3 a reactor trip from 100 percent power occurred (see paragraph 8 for details on the reactor trip). Following performance of a post-trip review of this event, a plant startup was performed and the reactor was taken critical at 3:05 a.m. on June 4 followed by the resumption of power operation at ll:04 a.m. At 2:30 a.m. on June 7 the plant was shut down to hot standby to perform additional post-maintenance testing on a manual reactor trip switch. Following this testing the reactor was again taken critical at 12:27 p.m. on June 9 followed by the resumption of power operation at 2:49 p.m. The plant remained in power operation for the duration of this inspection perio a. Shift Logs and Facility Records The inspector reviewed records and discussed various entries with operations personnel to verify compliance with the Technical Specifications (TS) and the licensee's administrative procedures. The following records were reviewed: Shift Supervisor 's Log; Control Operator's Log; Night Order Book; Equipment Inoperable Record; Active Clearance Log; Jumper and Wire Removal Log; Temporary Modification Log; Chemistry Daily Reports; Shift Turnover Checklist; and selected Radwaste Logs. In addition, the inspector independently verified clearance order tagouts. No violations or deviations were identified. b. Facility Tours and Observations Throughout the inspection period, facility tours were conducted to observe operations, surveillance, and maintenance activities in progress. Some of these observations were conducted during backshifts. Also, during this inspection period, licensee meetings were attended by the inspectors to observe planning and management activities. The facility tours and observations encompassed the following areas: security perimeter fence; control room; emergency diesel generator building; reactor auxiliary building; waste processing building; turbine building; fuel handling building; emergency servic'e water building; battery rooms; electrical switchgear rooms; and the technical support center. During these tours, the following observations were made: (1) Monitoring Instrumentation - Equipment operating status, area atmospheric and liquid radiation monitors, electrical system lin'eup, reactor operating parameters, and auxiliary equipment operating parameters were observed to verify that indicated parameters were in accordance with the TS for the current operational mode. While observing startup activities on May 20, 1991, the inspector noticed that the Auxiliary Feedwater (AFW) system was not aligned for automatic standby operation. Specifically, motor operated isolation valves 1AF-55, 1AF-93, and 1AF-74 were closed. These valves isolate feedwater flow from the motor driven AFW pumps to the A, B and C steam generators, respectively. Further, the manually operated flow control valves in these feed lines, 1AF-49, lAF-51, and lAF-50, were also closed. These six valves are normally open when the system is aligned for automatic standby operation. The AFW system was being used to supply feedwater to the steam generators due to operational problems with the main feedwater system. To feed the steam generators, an operator would close the flow control and isolation valves, start an AFW pump and then open the appropriate valves to sequentially fill the steam generators. When finished, the AFW pump was secured and valves reopened for the standby lineup. The flow control valves and isolation valves were closed.to eliminate leakage past the flow control valves into the steam generators which was believed to have contributed to AFW system check valve damage. The AFW system had been used in this manner since approximately ll:18 a.m. on Nay 19, when the "A" main feedwater pump had tripped. From a review of the control operator's log the inspector determined that twice the AFW system flow path had been manually blocked by closing flow control and isolation valves while the plant was in Mode 3, for greater than six hours. Further, the plant entered Mode 2 from Node 3 at 8:20 a.m. on Nay 20 with the AFW system again not aligned for automatic standby operation. The inspector discussed the operability of the AFW system in this configuration with licensee personnel. The inspector was informed that this valve lineup was in accordance with operating procedure OP-137, Auxiliary Feedwater System, and in accordance with the plant general procedure for heatup. A review of procedure OP-137 revealed that although the procedure directed the flow control valves be repositioned for feeding the steam generators, the required position for the isolation valves was open. The inspector was also informed that all valves in the flowpath did not receive an automatic signal to reopen on an auxiliary feedwater actuation signal, and that operator action was necessary to open the valves. When this matter was discussed with operations management, the inspector was informed that the system was considered to be operable even though operator action was required. Operating personnel had previously identified this concern to management through an Operations Feedback Report (OFR-901) as early as August 1988. Licensee management's response to the OFR stated that no action was required. Technical Specification (TS) 3.7.2.1 requires three AFW pumps and their associated flow paths to be operable in Modes 1, 2, and 3. Action b of this Limiting Condition for Operation (LCO) specifies that with two AFW pumps inoperable the plant must proceed from Mode 3 to Mode 4 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. With the motor driven AFW pump flow path not in the automatic standby lineup, this system was not capable of performing its automatic function and was inoperable. Exceeding the allotted time for inoperable AFW system flow paths is contrary to the requirements of TS and is considered to be a violatio (2) (3) (4) Violation (400/91-13-01): Failure to have two operable AFW system flow paths. After being informed of this matter, licensee personnel changed procedure OP-137 to declare the AFW system inoperable when shutting these valves and issued a night order alerting operators to this change. Shift Staffing - The inspectors verified that operating shift staffing was in accordance with TS requirements and that control room operations were being conducted in an orderly and professional manner. In addition, the inspector observed shift turnovers on various occasions to verify the continuity of plant status, operational problems, and other pertinent plant information during these turnovers. Plant Housekeeping Conditions - Storage of material and components, and cleanliness conditions of various areas throughout the facility were observed to determine whether safety and/or fire hazards existed. Radiological Protection Program - Radiation protection control activities were observed routinely to verify that these activities were in conformance with the facility policies and procedures, and in compliance with regulatory requirements. The inspectors also reviewed selected radiation work permits to verify that controls were adequate. Security Control - In the course of monthly activities, the inspector included a review of the licensee's physical security program. The performance of various shifts of the security force was observed in the conduct of daily activities which included: protected and vital area access controls; searching of personnel, packages, and vehicles; badge issuance and retrieval; escorting of visitors; patrols; and compensatory posts. In addition, the inspector observed the operational status of Closed Circuit Television (CCTV) monitors, the Intrusion Detection system in the central and secondary alarm stations, protected area lighting, protected and vital area barrier integrity, and the security organization interface with operations and maintenance. Fire Protection - Fire protection activities, staffing and equipment were observed to verify that fire brigade staffing was appropriate and that fire alarms, extinguishing equipment, actuating controls, fire fighting equipment, emergency equipment, and fire barriers were operable. No violations or deviations were identifie c. Review of Nonconformance Reports Adverse Condition Reports (ACRs) were reviewed to verify the following: TS were complied with, corrective actions as identified in the reports were accomplished or being pursued for completion, generic items were identified and reported, and items were reported as required by the TS. No violations or deviations were identified. 3. Surveillance Observation (61726) Surveillance tests were observed to verify that approved procedures were being used; qualified personnel were conducting the tests; tests were adequate to verify equipment operability; calibrated equipment was utilized; and TS requirements were followed. The following tests were observed and/or data reviewed: MST-I0001 Train "A" Solid State Protection System Actuation Logic and Master Relay Test MST-I0055 Reactor Coolant Loop 1 Flow Instrument (F-0414) Calibration t MST-I0056 Reactor Coolant Loop 1 Flow Instrument (F-0415) Calibration MST-I0058 Reactor Coolant Loop 2 Flow Instrument (F-0424) Calibration MST-I0072 Train "A" 18 Month Manual Reactor Trip Solid State Protection System Actuation Logic and Master Relay Test MST-I0246 Loop Calibration of Auxiliary Feedwater Turbine Differential Pressure (PD-2180) OST-1026 Reactor Coolant System Leakage Evaluation OST-1111 Auxiliary Feedwater Pump 1X-SAB Operability Test OST-1214 Emergency Service Water System Operability Train A OST-1215 Emergency Service Water System Operability Train B EST-703 Moderator Temperature Coefficient Measurement Beginning of Life After Each Refueling No violations or deviations were identifie. Maintenance Observation (62703) The inspector observed/reviewed maintenance activities to verify that correct equipment clearances were in effect; work requests and fire prevention work permits, as required, were issued and being followed; quality control personnel were available for inspection activities as required; and, TS requirements were being followed. Maintenance was observed and work packages were reviewed for the following maintenance (WR/JO) activities: Preventive maintenance on reactor trip breakers in accordance with procedure MPT-E0005, Reactor Trip Breaker, Westinghouse Model DS-416. Replacement of the jack shaft on the "B" reactor trip bypass breaker. Troubleshooting of the "A" reactor trip breaker failure to open and replacement of a defective closing coil. Repair of a chipped brush on the "A" emergency diesel generator. Replacement of the reactor trip/closing switch on the main control board. Replacement of a failed SSPS undervoltage output card. Inspection and test of safety injection alternate mini-flow recirculation valves 1CS-744 and 1CS-755 in accordance with procedure EST-211, Auxiliary Relief Valve Testing. The licensee utilizes the AMMS system to provide trend reports of equipment failures. These reports allow the identification of repetitive failures attributed to either specific equipment problems or applications. Predictions of future failures are then calculated and prioritized. Maintenance planners also identify repetitive failures based upon their experience and review of work history. When abnormalities in component operation are identified, the appropriate system or component engineer is notified. These efforts were effective in identifying repetitive weld failures on the equalizing line of the "B" charging/safety injection pump, multiple failures on reactor makeup total flow transmitters, and failures to steam generator blowdown flash tank pressure switches. Plant change requests were initiated to analyze and repair these problems. These repairs have been effective in reducing the repetitive failures. The identification of repetitive failures is considered to be a strength of the licensee's maintenance program. As a backup to the reviews performed above, an industry component failure analysis report data base is also accessed to compare Harris plant equipment to the rest of the nuclear industry's. No violations or deviations were identifie Design Changes and Modifications (37828) Installation of new or modified systems were reviewed to verify that the changes were reviewed and approved in accordance with 10 CFR 50.59, that the changes were performed in accordance with technically adequate and approved procedures, that subsequent testing,and test results met acceptance criteria or deviations were resolved in an acceptable manner, and that appropriate drawings and facility procedures were revised as necessary. This review included selected observations of modifications and/or testing in progress. The following modifications/design changes were reviewed: PCR-5216 Change of Differential Pressure Transmitter for PDK-2180-1SB PCR-5933 Turbine Driven Auxiliary Feedwater Setpoint Determination Post-modification testing in accordance with procedure EPT-148T, Determination of Turbine Driven Auxiliary Feedwater Pump Differential Pressure Controller Setpoint, was observed in conjunction with the review of modification PCR-5216. Modification PCR-5216 was implemented to install a more accurate differential pressure transmitter for pump control. The test procedure was performed to establish a new setpoint for the pump controller to provide the design minimum of 430 gpm to two steam generators, with the turbine driven AFW pump running, and a maximum of 514 gpm to each steam generator with all three AFW pumps running. This test was performed on May 25, 1991, at approximately 30 percent power to facilitate better feedwater control. During plant startup and power increase to 30 percent, the previous setpoint of 32 percent was utilized for the pump controller. This setpoint had been verified to provide adequate feedwater flow during startup from the previous refueling outage. The data obtained from the performance of the test on May 25 indicated that the turbine driven AFW pump, with a controller setpoint of 32 percent was incapable of supplying the design 430 gpm flow to two steam generators and instead could only deliver approximately 340 gpm. The licensee declared the pump inoperable and established a new controller setpoint of 36 percent. The new setpoint of 36 percent was determined from the analysis of test data and represented approximately 445 gpm as a minimum flow and 524 gpm as a maximum flow. Licensee personnel established a corresponding error analysis of 11 gpm based on the accuracy of components and instrumentation involved. When the error analysis is subtracted from the estimated flow of 445 gpm, the pump is just capable of providing the design minimum flow rate. The maximum flow rate was determined to be acceptable upon reanalyzing the steam generator overfill analysis. The inspector discussed the narrow margin which existed between the present pump controller setpoint and the minimum design flow rate with licensee personnel. The licensee is presently considering several long-term plant modifications to increase the margin and is performing additional analyses as wel Inspector Followup Item (400/90-13-02): Follow the licensee's activities regarding the narrow margin for minimum flow from the turbine driven AFW pump. t 6. Review of Licensee Event Reports (92700) The following LERs were reviewed for potential generic impact, to detect trends, and to determine whether corrective actions appeared appropriate. Events that were reported immediately were reviewed as they occurred to determine if the TS were satisfied. LERs were reviewed in accordance with the current NRC Enforcement Policy. a ~ (Closed) LER 91-03: This LER reported that following receipt of a fuel oil shipment, licensee personnel failed to determine its kinematic viscosity. This event was previously discussed in NRC Inspection Report 50-400/91-04 and was the subject of a non-cited violation (NCV 400/91-04-02). The licensee has completed training chemistry personnel to enhance their awareness of fuel oil sampling and analysis requirements and has revised the sampling procedure to require comparison between gravity values. 7; b. (Closed) LER 91-06: This LER reported that a shutdown margin calculation was not performed while testing the source range nuclear instruments. This event was previously discussed in NRC Inspection Report 50-400/91-06. The licensee has revised the testing procedures to include a caution note alerting operators of shutdown margin verification requirements and has discussed this event with operations personnel. Evaluation of Licensee Self Assessment (40500) a ~ In January 1991, the licensee made organizational changes to provide three levels of self assessment. The first level of assessment consisted of individual self checks, supervision and management monitoring of work performance and review of performance indicators. A second level assessment is performed by the Nuclear Services Department (NSD) which provides a centralized review of plant performance in various functional areas. The third assessment is performed by the Nuclear Assessment Department (NAD) which was formed from the Corporate Nuclear Safety and guality Assurance organizations. This group performs the independent review function. The licensee has relied upon the craft to perform a significant amount of the first level assessment. The craft is expected to perform an individual self check of work performed followed by independent verification by another craft person. Due to problems which were noted during previous inspections (report number 50-400/91-09) and at other licensee nuclear plants, an increase in craft training or management/supervisor involvement may be required to achieve 'the desired results of this first level of assessmen The inspector reviewed the NSD mission and description provided in an interoffice memorandum dated November 15, 1990. This group will primarily assess performance of the licensee's nuclear plants in programs which are common to all the plants. Critical success factors have been created in the functional areas of plant operations, maintenance, health physics, chemistry, technical support, emergency preparedness, outage and modifications, and security, to assist in this assessment. The first quarter 1991 Functional Performance Review Report was reviewed. This report consisted of information on trends, problems, and good practices in the functional areas as well as a comparison with the critical success factors for each plant. Due to various comments from the nuclear plants about the criteria used, the critical success factors are presently being reviewed to incorporate comments and achieve consistency between the nuclear plants. Also corporate functional area managers performed on site reviews. Executive summaries of these reviews were reviewed by the inspector. Areas reviewed included emergency planning scenario development on the simulator, security force training, health physics outage work practices, locked high radiation area control, compliance with chemistry procedures, and technical support work management. Strengths and recommendations for improvement were noted. Recommenda-tions were discussed with the appropriate plant functional area manager for resolution. However, no formal process existed if disagreement existed between the managers on the recommendations provided. The lack of formal methods for resolving the recommenda-tions and for stating the mission and organizational responsibilities for assessment, were considered by the inspector to be areas which needed improvement. The inspector considered that when this group is fully functional and responsibilities refined, it should help achieve consistency between the licensee's nuclear plants. The employment of appropriate critical success factors should also have a beneficial effect on plant safety. The Nuclear Assessment Department is divided into site groups and a corporate group. The corporate group provides coordination, planning and leadership for audits of functional areas, evaluations of site and corporate programs, trending and analysis support, a peer evaluation program of management, and document reviews which are required by the TS. Activities of the corporate NAD group were reviewed in NRC Inspection Report 50-324,325/91-10 and were not reinspected in this report. For additional information of this group's function/activities refer to that report. The onsite NAD group perform surveillance and field observations of plant activities, system walkdowns, oversight of PNSC activities, and participate in team audits/evaluations. The inspector attended selected meetings of the onsite NAD group, reviewed the NAD Mission and Procedures Manual, and reviewed a cross reference list which was created to ensure current TS requirements were being complied with by the new organization. The meetings included a brief of plant activities/problems observed and status of various observations currently underway. Direction was provided on how to proceed with assessments in progress. The inspector was impressed with the usage of casual factor charting/flow charting of plant events and processes during these meetings. The NAD Manual contained technical procedures and guidelines. Administrative procedures were still under development. The inspector reviewed procedures NAD'100-02, Conduct of Operations, and NAD 100-03, Assessment Process. In summary, the NAD organization was presently still in the initial stages for developing practices/processes for performing meaningful assessments. The cross reference list was reviewed by the inspector and compared to the requirements contained in the TS for the Corporate Nuclear Safety and Onsite Nuclear Safety groups. This review indicated that TS requirements had been appropriately reassigned and were being accomplished. Twenty one of approximately 170 observations, performed by the onsite NAD group since January 1991, were reviewed. The inspector found these observations to be relatively consistent with observations performed by the NRC. Although three functional area evaluations had been performed by the corporate NAD group in the maintenance, health physics and chemistry, and modification areas, the reports for these evaluations were not yet available. b. The licensee's quality control group is composed of two gC receipt inspectors, five mechanical/civil/electrical inspectors and two managers/supervisors. This group is primarily involved with the verification of modification work and they also perform all the specialized non-destructive examination inspections. During the current outage the licensee has acquired eleven additional contract gC personnel to cover the modification activities. The regular staffing was considered to be minimal. c. The inspectors attended selected Plant Nuclear Safety Committee meetings to observe committee activities and verify TS requirements with respect to committee composition, duties, and responsibilities. Minutes from these meetings were also reviewed to verify accurate documentation. No violations of deviations were identified. 8. Onsite Followup of Events (93702) On June 3, 1991, at 3:33 p.m., the plant experienced a reactor trip while operating at 100 percent power. The cause of the trip was attributed to a technician placing a reactor coolant flow detector back in service following calibration. This action caused a pressure pulse on the common leg of three flow detectors which resulted in a low flow signal on all three transmitters and associated low flow reactor trip. The transmitters had recently been changed during the refueling outage to more sensitive instrumentation. The licensee subsequently found that other plants had experienced similar problems due to the increased sensi tivity of the transmitters. However, thi s informati on was not identified during the transmitter modification process. The resident inspector was onsite during the reactor trip and observed post-trip activities. The inspector noted that the secondary plant, which has had a previous history of pump trips during rapid transients, was very stable and the main feed pumps did not trip. The improved performance of the secondary plant was attributed to modifications to the main feed pump recirculation valves during the refueling outage which allowed more rapid opening, and prevented the low flow trip of the main feedwater pumps. It was also noted that the operators maintained good control of the plant and limited the plant cooldown. Discussions with operators revealed that the "A" reactor trip breaker had not opened following the automatic reactor trip signal and the breaker had to be manually opened by the operator 22 seconds into the event. This event is discussed in more detail in NRC Inspection Report 50-400/91-15. The inspectors reviewed the post-trip/safeguards review, OMM-004, and the troubleshooting/testing activities associated with the reactor trip breaker. The plant was subsequently restarted on June 4, 1991 at 2:24 a.m. Plant Startup From Refueling (71711) The inspector observed plant activities during unit startup following refueling to verify that plant systems were properly returned to service and that the startup was conducted in accordance with approved procedures and in compliance with the TS. The plant began deboration to criticality on May 20 and entered the startup mode (Mode 2) at 8:20 a.m. Criticality was achieved at 4:50 p.m. on May 20. The inspectors observed the approach to criticality and verified that criticality occurred within the limits calculated by the licensee. Implementation of the following procedures was verified: GP-004 Reactor Startup GP-005 Power Operation EPT-069 Initial Criticality EST-703 Moderator Temperature Coefficient Measurement Beginning of Life After Each Refueling PLP.-626 Power Ascension Testing Program After a Refueling Outage Due to problems experienced during a previous startup from a refueling outage (reference NRC Inspection Report 50-400/90-01), the licensee implemented a new power ascension test program. This program was delineated in procedure PLP-626 and specified the sequence of testing necessary to ascend to full power. This program was effective in controlling the power escalation to full power following the refueling outage without misha No violations or deviations were identified. 10. Licensee Action on Previously Identified Inspection Findings (92702, 92701) a. (Closed) IFI 400/91-01-01: Review licensee's progress to repair flanges and valves and minimize system leakage. Prior to the refueling outage the licensee had reduced the number of drip bags to 53. During the outage repairs were completed on approximately 36 of these. This action has been effective in minimizing system leakage. b. (Closed) P2189-13: This CFR Part 21 report notified the licensee of a problem with specific control devices in the diesel generator air control system. As a result of field failures, the manufacturer redesigned the valve seating arrangement. During refueling outage 3, plant modifications per PCR-5245 were implemented to replace the air start valves on both diesels. 11. Exit Interview (30703) The inspectors met with licensee representatives (denoted in paragraph 1) at the conclusion of the inspection on June 14, 1991. During this meeting, the inspectors summarized the scope and findings of the inspection as they are detailed in this report, with particular emphasis on the Violation, and Inspector Follow-up item addressed below. The licensee representatives acknowledged the inspector's comments and did not identify as proprietary any of the materials provided to or reviewed by the inspectors durin'g this inspection. During this meeting licensee personnel took exception to the violation and considered manual operator action sufficient to consider the AFW system flowpath operable. Item Number 400/91-13-01 400/91-13-02 12. Acronyms and Initialisms Descri tion and Reference VIO: Failure to have two operable AFW system flow paths. (Paragraph 2.b.l.) IFI: Follow the licensee's activities regarding the narrow margin for minimum flow from the turbine driven AFW pump. (Paragraph 5) ACR - Adverse Condition Report AFW - Auxiliary Feedwater AMMS - Automated Maintenance Management System CCTV CFR CNS EPT EST GP GPM IFI LCO LER MPT MST NAD NCV NRC NSD OFR OMM ONS OP OST PCR PLP PNSC QA/QC RCS/RC SSPS TS VIO WR/JO Closed Circuit Television Code of Federal Regulations Corporate Nuclear Safety Engineering Performance Test Engineering Surveillance Test General Procedure Gallons Per Minute Inspector Follow-up Item Limiting Condition for Operation Licensee Event Report Maintenance Performance Test Maintenance Surveillance Test Nuclear Assessment Department Non-Cited Violation Nuclear Regulatory Commission Nuclear Services Department Operation Feedback Report Operations Monitoring Program Onsite Nuclear Safety Operation Procedure Operations Surveillance Test Plant Change Request Plant Procedure Plant Nuclear Safety Committee Quality Assurance/Quality Control Reactor Coolant System Solid State Protection System Technical Specification Violation Work Request/Job Order