IR 05000269/1996013

Insp Repts 50-269/96-13,50-270/96-13,50-287/96-13 & 70-0004/96-13 on 960825-1005.Violations Noted.Major Areas Inspected:Operations,Engineering,Maintenance & Plant Support

ML15118A147
Person / Time
Site:	Oconee
Issue date:	10/05/1996
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML15118A145	List: IR 05000269/1996013 ML15118A144 ML15118A146
References
50-269-96-13, 50-270-96-13, 50-287-96-13, 72-0004-96-13, 72-4-96-13, NUDOCS 9611150237
Download: ML15118A147 (42)

Text

U.S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket Nos:

50-269,50-270,50-287,72-04 License Nos:

DPR-38, DPR-47, DPR-55. SNM-2503 Report No:

50-269/96-13. 50-270/96-13, 50-287/96-13 Licensee:

Duke Power Company Facility:

Oconee Nuclear Station, Units 1, 2 & 3 Location:

7812B Rochester Highway Seneca, SC 29672 Dates:

August 25 - October 5. 1996 Inspectors:

M. Scott, Senior Resident Inspector G. Humphrey, Resident Inspector N. Salgado, Resident Inspector G. Walton, Reactor Inspector P. Kellogg, Reactor Inspector Approved by:

L. D. Wert, Acting Chief, Reactor Projects Branch 1 Division of Reactor Projects

ENCLOSURE 2 9611150237 961104 PDR ADOCK 05000269 Q

PDR

EXECUTIVE SUMMARY Oconee Nuclear Station, Units 1, 2 & 3 NRC Inspection Report 50-269/96-1 /96-13, 50-287/96-13 This integrated inspection included aspects of licensee operation engineering, maintenance, and plant support. The report covers a six-week period of resident inspection; in addition, it includes the results of announced inspections by two regional reactor safety inspector Operations

Operations were generally performed in a professional and safety conscious manner. A non licensed operator identified a main transformer oil leak and actions were promptly taken to minimize transformer damage (Section 01.3). Actions in response to a reactor coolant system leak were prompt and appropriate (Section 01.4). Controlled shutdowns of Units 1 and 3 were completed professionally (Sections 01.7 and 01.8).

• The initial licensee response to the Unit 2 heater drain tank line rupture on September 24, 1996. was good. An NRC Augmented Inspection Team was dispatched to the site to evaluate this line break event. The Team findings are addressed in Inspection Report 50-269,270.287/96-15 (Section 01.6).

• A Non-Cited Violation (NCV) was identified involving the manipulation of a wrong unit valve (Section 01.5).

• An inspector followup item was identified involving a Unit 2 broken feedwater pump suction pipe hanger. The deficiency was evaluated by engineering personnel, but not promptly reported to Operations (Section 02.1)

MAINTENANCE

Maintenance work was carried out in a careful and methodical manner (Section M1.1 and M1.4).

• The licensee's initial corrective actions on the 2B High Pressure Injection (HPI) pump motor and 2T transformer problems were appropriat An inspector followup item was identified concerning the motor failure analysis (Section M1.2).

An unresolved item was identified involving maintenance deficiencies associated with high voltage lug connections (Section M1.3).

• Long-term validation testing of the Standby Shutdown Facility (SSF) was satisfactorily completed during this inspection period (Section M1.1).

ENCLOSURE 2

Engineering

Two violations were identified in the engineering area: A modification test procedure did not contain required specific criteria (Section E1.3): and the 10 CFR 50.59 evaluation for a modification of high pressure injection piping was inadequate (Section E1.4). An unresolved item was identified associated with a leaking socket weld on a line connected to high pressure injection piping (Section E1.4).

• NRC review of existing open items associated with the Service Water System Operational Performance Inspection (SWSOPI) concluded that the licensee adequately addressed the technical issues identified and planned modifications should ensure the appropriate system upgrades (Section E1.5). An inspector followup item was identified to address the implementation of the planned service water system modifications. A violation involving several service water related design control inadequacies was also identified (Sections E8.1, E8.2 and E8.18).

• Engineering adequately supported SSF testing (Section M1.1).

• Engineering performed adequate review and closure of a past operability issue regarding injection line check valves (Section E8.19).

• A licensee identified NCV was identified concerning missed surveillance testing on thirteen relief valves. The inservice testing interval had not been started on the correct date (Section E1.1).

Plant Support

On September 19. the licensee held an emergency dril The residents observed that licensee activity coordination, deportment and professionalism, and initial scenario response were excellent (Section R1).

Observation of the drill by emergency preparedness inspectors are addressed in Inspection Report 50-269,279,287/96-1 ENCLOSURE 2

Report Details Summary of Plant Status Unit 1 operated at full power until September 19. 1996, when power was reduced due to a problem with the 1A main feedwater pump (MFP) (Section 01.2).

Full power was resumed on September 23. Shutdown of Unit 1 began on October with power being held at approximately 15 percent until the end of the inspection period to support the shutdown of Unit 3 (Section 01.7). The Unit 1 shutdown was initiated due to possible secondary piping problems found as a result of the Unit 2 drain line rupture even Unit 2 operated at power until September 21, 1996, when it was shutdown due to a failure of the 2B High Pressure Injection (HPI) pump motor (Section 01.3).

During unit power ascension on September 24, 1996, after the HPI motor was replaced, a second stage moisture separator reheater (MSR) drain line rupture occurred. The unit was manually tripped. The unit remained shutdown throughout the end of the reporting period (Section 01.6).

Unit 3 returned to full power on August 30, 1996. after the 3B MFP was returned to service following a repair of its lube oil drive gears. The unit operated at or near full power from August 30, 1996, until October 4, 199 when it was shutdown to evaluate the need for modifications on secondary piping as a result of the Unit 2 drain line rupture even Review of UFSAR Commitments A recent discovery of a licensee operating their facility in a manner contrary to the Updated Final Safety Analysis Report (UFSAR) description signified the need for a special focus review that compares plant practices, procedures, and/or parameters to the UFSAR descriptions. While performing inspections discussed in this report, the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected. The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures, and/or parameters. No deficiencies were identifie I. Operations

Conduct of Operations 01.1 General Comments (71707)

Using Inspection Procedure 71707. the inspectors conducted frequent reviews of ongoing plant operations. In general, the conduct of operations was professional and safety-conscious: specific events and noteworthy observations are detailed in the sections belo ENCLOSURE 2

01.2 1A MFP Evaluation a. Inspection Scope On September 19, Unit 1 power was reduced due to an indicated vibrational problem with the 1A MFP. The licensee promptly informed the resident inspector who responded to the plant and observed the related activitie b. Inspection Findings During day shift on September 18. the licensed operators had responded to three vibration alarms on the inboard bearing for the 1A MF Initially, the alarms were attributed to an instrument or alarm proble In the early morning hours of September 19, the frequency of alarms increased and the pump was shutdown for investigation. Audible hydraulic-related noise was also noted at the pump. Alternate portable vibration instrumentation corroborated the frequencies seen with the installed pump vibration probe The inspector arrived at the control room about 2:20 p.m. and observed that power was being reduced at a controlled rate. The operators maintained good control of the evolution and all parameters checked were within normal limits. The licensee had appropriate procedures (i.e.,

OP/1/A/1103/04, Soluble Poison Concentration Control: OP/1/A/1102/04, Power Reduction; and 1/A/1106/02. Condensate and Feedwater System Isolation and Return to Service of MFP) in use and tags had been prepared to remove the pump from service. Power was held at approximately 60 percent during the pump inspectio The pump was disassembled to the point necessary to assure that there was no damage. The inspector observed the disassembly and examined the pump parts. No physical problems were detected with the pump. A vibration probe on the pump inboard bearing position was found to be reading approximately 50 percent higher than the calibration referenc The probe was recalibrated and returned to service. The licensee documented the findings in Problem Investigation Process (PIP) report 1 96-1756. The hydraulic noise heard earlier was noted to be present on a Unit 3 MFP. The licensee attributed the noise to expected localized condition The pump was returned to service and operated properly. The unit was returned to full power on September 23. 199 c. Conclusions The licensee took conservative and effective actions to resolve the 1A MFP vibration proble ENCLOSURE 2

01.3 Unit 2 HPI Pump Motor Failure and Subsequent 2T Transformer Problems a. Inspection Scope The inspector reviewed the operability and reportability issues concerning the failure of the Unit 2 HPI pump motor and the subsequent electrical system problem b. Observations and Findings On September 18, 1996. at 1:32 a.m., the 2B HPI pump motor failed while in service. The 2A HPI Pump started automatically on a signal generated from a low reactor coolant pump seal injection flow condition. The operators responded to the pump loss and entered the appropriate TS action statement At 3:25 a.m., a non-licensed operator performing rounds identified an oil leak on the 2T Auxiliary Transformer. The Unit 2 power loads were transferred to the Startup Transformer (CT2) and the 2T transformer was removed from servic The 2B HPI pump was isolated, tagged, and an investigation was initiated. Preliminary results of that investigation revealed: (1)

one of the pump motor electrical leads was burned and had separated from the lug connector, and (2)

the motor phase associated with the burned lead had an open circuit. The inspectors observed portions of the trouble shooting, repair and testing. (See Section M1.2 for more details on the 2B HPI motor failure.)

An inspection of the 2T transformer revealed that a copper line (approximately 1/2 inch diameter) associated with the gas pressure indication within the transformer oil system had been electrically burned and approximately 2 inches of the tubing had been destroye This had resulted in an oil leak from the transformer's top mounted reservoir that was estimated to be 200-250 gallons in volume. The damaged transformer and the initiation of several alarms that occurred at the time that the HPI pump motor failed were determined to have resulted from an electrical power surge originating from the motor failure. The burned tubing was located close to the transformer isophase duct and the licensee concluded that the power surge had caused an arc from the.duct to the grounded tubing. The inspectors discussed the details of the mode of failure with the licensee, observed the 2T transformer damage, and monitored some of the repair activities. The tubing was repaired and the transformer was returned to servic Repairs and testing of the 2B HPI pump were not completed within the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Limiting Condition for Operation (LCO) period and Unit 2 was shutdown on September 21, 1996. to satisfy TS requirement ENCLOSURE 2

c. Conclusions The licensee's operational focus was appropriate and the investigation of the transformer oil leak was thoroug.4 Unit 2 Injection Piping Reactor Coolant System (RCS) Leakage a. Inspection Scope On September 21, 1996, at 5:30 p.m., the licensee discovered apparent pin hole leaks in a socket weld joint at valve 2HP-491. The licensee informed the residents of the problem. At the time, the plant was in hot shutdown due to the problems with the 2B HPI pump discussed in Section 01.3 of this repor b. Observations and Findings During a reactor building (RB) entry to perform other work, two Instrument and Electrical (I&E) personnel noted a fine mist coming from a weld near valve 2HP-491. This valve is located on a test line connected to the body of valve 2HP-487. 2HP-487 is a stop check valve located in the 2A1 high pressure injection path. Access to a manual valve which would isolate the leaking weld from the RCS was blocked by the leak spray. The licensee initially made a 10 CFR 50.72 report for an unisoluble RCS leak per TS 3.1.6.3. The licensee took appropriate TS required steps. RCS conditions were reduced to 800 psig and 340 degrees F. At that point, workers were able to isolate the injection line from the RCS and subsequently the TS requirement for plant shutdown to cold conditions was exited. Additionally, by decreasing the RCS temperature to less than 350 degrees F, the TS 3.3.1 requirement for two functional HPI trains was no longer applicable. PIP 2-96-1802 was initiated and engineering developed a minor modification to repair the problem (see Sections M1.4 and E1.3 of this report).

c. Conclusions The Operations personnel involved with this problem acted conservatively and effectively to address the leak. TS and reporting requirements were me.5 Wrong Unit Valve Operated a. Inspection Scope On September 22, 1996, a low seal flow condition was indicated on the 1A2 RCP. During the subsequent corrective actions, a Unit 2 valve was incorrectly operated. The inspectors reviewed the licensee's actions related to this deficienc ENCLOSURE 2

b. Observations and Findings The Unit 1 Supervisor and Control Room (CR) Senior Reactor Operator (SRO) discussed the problem and decided to increase seal flow. A pre job brief was held between the SRO. Unit 1 Reactor Operator (RO), and a Non-Licensed Operator (NLO) who was serving as primary side (auxiliary building) NLO for both Unit 1 and Unit 2. A Unit 2 drawing was used during the discussion and valve 2HP-67 (versus 1HP-67) was addressed as the valve to adjust. The NLO repeated the valve number several times and wrote down valve 2HP-67 in his notebook and headed into the plan After radio communications were established, the Unit 1 RO directed that the NLO throttle 2HP-67 and the NLO repeated this back prior to adjusting the valv At 11:49 p.m., the Unit 2 alarm (2SAS-6/D-5) was received on a low 2B2 RCP inlet seal flow. A Unit 2 RO verified the condition on his unit and notified the NLO who had performed the recent action. The NLO that had been sent to adjust 2HP-67 then repositioned the valve to its previous throttled position and proper seal flow was immediately re-established to the 2B2 RCP. No additional operational problems were induced by the error. The resident inspectors were informed of the problem and were kept apprised of the corrective actions. PIP 5-96-1803 was initiate Operations management indicated concern regarding the performance of the operators. Management expectations for communications were not me The involved personnel were counseled and the details of the incident were promulgated as a training issue. Additional communications training is being scheduled. Management expectations and the noted deficiencies were discussed in detail with the inspectors. Due to the minor nature of this problem and the prompt management attention placed on it, this licensee-identified and corrected violation is being treated as a Non-Cited Violation consistent with Section VII.B.1 of the NRC Enforcement Policy. This issue is identified as Non-Cited Violation 50 269,270/96-13-01. Wrong Unit Valve Operation During RCP Seal Flow Adjustmen c. Conclusions The licensee took prompt and thorough actions in response to the mispositioned component occurrence. The corrective actions were appropriate to reduce the potential of recurrenc.6 Unit 2 B Heater Drain Line Rupture Event a. Inspection Scope (93702)

On September 24. the 2B heater drain tank line ruptured between the tank and the feedwater heaters. The inspectors were immediately notified of the problem and responded to the plant to monitor the licensee's activitie ENCLOSURE 2

b. Observations and Findings Unit 2 was returning to power after a short outage to repair a failed HPI pump motor (See Section 01.3). At approximately 55 percent power, non-licensed operators were valving in the heater drain tanks to the feedwater heaters. A rupture of an eighteen inch line between the heater drain tank and the feedwater heaters occurred at 4:42 p.m. that resulted in severe injuries to seven plant personne The control room operations personnel manually tripped the plant in the next several minutes. The event was reviewed by an NRC Augmented Inspection Team (AIT). (See Inspection Report 50-270/96-15.)

The manual trip of the unit was normal with all systems responding as expected. The inspectors reviewed logs, discussed the incident and plant conditions with Operations personnel, and verified actions taken during the shutdown. The plant was stabilized in the hot shutdown condition with no known radiological problem Shortly after the line rupture, the licensee assembled all plant workers for accountability and manned the TSC. Shortly after the unit was tripped, the licensee contacted the senior resident inspector who responded to the site. The licensee also promptly informed the NRC Operations Center of the even The resident inspectors established communications in the TSC with the licensee and appropriate NRC groups. The licensee had also manned the OSC and evaluated courses of action. Survey personnel assessed the secondary plant condition. The resident inspectors also reviewed the extent of the damage at the location of the leak and reported that information to NRC management. Additional inspectors were detailed from the NRC Regional office and arrived on site by 8:20 p. c. Conclusion The inspectors concluded that the licensee's immediate response to the event was good, and appropriate safety conscious measures were take Inspection Report 50-270/96-15 contains additional details of the inciden.7 Unit 1 Power Reduction a. Inspection Scope After the above Unit 2 event, the licensee determined that Units 1 and 3 should be shutdown for evaluation, inspection, and repairs of the secondary piping systems. The inspectors observed the Unit 1 power reduction to 15 percent powe ENCLOSURE 2

b. Observations and Findings The inspectors reviewed the licensee's activities in progress during the Unit 1 power reduction from 100 percent to 15 percent power. The activity was performed in accordance with operational procedure OP/1/A/1102/10, Controlling Procedure For Unit Shutdown. The reactor power reduction began on the evening of October 3 and the turbine generator was offline at 12:33 a.m., on October 4, 1996. This power reduction was in response to the licensee's identification of potential anomalies in the Unit 1 MSR drain line piping after the Unit 2 pipe failure event on September 24, 199 During the power reduction, the inspector observed proper operator actions and conformance to the requirements of the above procedure. The operators were alert and attentive to plant parameters. During the reduction, the inspector toured the secondary plant and observed no problems or possible water hamme Unit 1 power reduction was suspended at the 15 percent level to insure that steam would be available for the Auxiliary Steam System. This system provides sealing steam for the secondary plant turbines (i.e.,

Unit 3 steam seals) and also allowed using the main condenser as a heat sink. This power level was necessary because the reliability of the auxiliary boiler was questionable at that time and the shutdown of Unit 3 would eliminoemhat unit as an auxiliary steam sourc c. Conclusions The shutdown was accomplished in accordance with the shutdown procedure and the unit responded as expected. The operators performed the evolution in a controlled and professional manne.8 Unit 3 Power Reduction a. Inspection Scope The inspectors observed the Unit 3 power reduction and shutdow b. Observations and Findings The inspectors observed the Unit 3 power reduction from 100 percent to hot shutdown which was performed IAW OP/3/A/1106/10, Enclosure 4.1, Shut Down to Hot Shutdown. During the shutdown, the inspector observed proper plant operation and proper plant response to controls. The only problem that occurred during the shutdown was a small water hammer occurrence when the 3D heaters were taken out of service. The dump valve to the condenser did not control slowly to allow a gradual increase in flow. As the valve failed open, relatively low energy steam/water was released to the condenser that caused no visible damage to components, but made an audible noise. PIP 3-96-1918 was initiated to address the water hammer occurrenc ENCLOSURE 2

The inspectors toured the turbine building inspecting for anomalous conditions. Several header and branch lines off the suction of the condensate booster pumps had indications of previous pipe movemen These observations were reported to Operations personnel along with other minor items observed during the tour A satisfactory control rod drop test (discussed further in Section M1.1)

was observed at the end of the power reduction. The licensee decided to begin the Unit 3 refueling outage that had been previously scheduled to begin in early Novembe c. Conclusions The shutdown was accomplished in accordance with the shutdown procedure and the unit responded as expected. The operators performed the evolution in a controlled and professional manne Operational Status of Facilities and Equipment 02.1 Discovery of Failed Feedwater Hanger a. Inspection Scope The resident inspectors reviewed the licensee's actions associated with failed feedwater hanger that was found resting on several electrical cable b. Observations and Findings On September 1. the inspectors examined a feedwater pump suction pipe hanger 2-07B-0-14-A-H6 which had a broken rod support. The licensee had identified the problem and initiated PIP 2-96-1672. The lagged pipe and trapeze had sagged toward the electrical cable tray directly beneat The support trapeze and the end of the broken rod were partially resting on the tray, yet still moving with the suction pipe normal motion. It could not be determined when the hanger rod had broken. Judging from the rod hanger appearance, it most likely had been in that position for a long period. The hanger was difficult to inspect because it was 12 feet above the basement floor elevation, close to the turbine building wall, and in the proximity to several cable trays. The inspectors reviewed the hanger condition and discussed plans and operability concerns with the licensee. The engineering group had learned of the problem on August 29, 1996, and initiated an internal discussion. The inspectors noted that Operations was not informed of the issue until August 31. 199 The licensee performed an evaluation of the approximate 262 cables in that tray and only one cable was determined to have minor damage. With ENCLOSURE 2

the pipe in the tray, it was difficult to see all the damage and the licensee also relied on poor quality readings from data collecting instruments attached to the cables to locate problems. All the cables in the tray were non-safety related and the licensee concluded that operation of the plant was not affected by the situation. The problem was scheduled to be worked during the current Unit 2 shutdow c. Conclusions The licensee evaluated the identified problem and made plans to fully resolve the condition. The inspectors noted that the issue was not promptly reported to Operations. The hanger issue, including assessment and repairs to cables, is addressed as Inspector Followup Item 270/96 13-02, Failed Hanger Repai I Maintenance M1 Conduct of Maintenance (61726,62703,62707)

M1.1 General Comments a. Inspection Scope The inspectors observed all or portions of the following maintenance activities:

• TT/0/A/0400/26 SSF DG-24 Hour Run and Service Water Flow Model Validation

• WO 96018027 PM U3 Auxiliary Instrument Air Sullair Compressor

• IP/O/A/0305/008 Disable/Enable RPS Trip or To Maintain a Channel In Manual Bypass

• WO 96073014 Repair Unit 2 Tubing Air Leaks On 2HD-LT-0027B

• WO 96054547 Repair Depressing Air Compressor #2 At Keowee

• IP/O/B/0261/004 CCW Pump Rotameter Sight Glass Cleaning And Alarm Setpoint Adjustment

• WO 96069992 Unit 3 RPS Channel B Tripped For Unknown Reason

• WO 96031699 Inspection And Maintenance On ACB-1

• WO 96017851 Replace Safety Relief Valve On ACB-1

• PT/0/A/0620/09 Keowee Hydro Operation

ENCLOSURE 2

• WO 93082154 Doble Testing SL1 Potential Transformers

• WO 96644970 Keowee Unit 2 Voltage Regulator Calibration

• PT/0/A/0300/01 Unit 3 Rod Drop Test b. Observations and Findings The inspectors found the work performed under these activities to be professional and thorough. All work observed was performed with the work package present and in active use. Tests and weld fitups were performed correctly. Technicians were experienced and knowledgeable of their assigned tasks. When required. test procedures were changed when unexpected conditions were encountered. Quality Control personnel were present when required by procedure. When applicable, appropriate radiation control measures were in plac Long-term validation testing of the SSF was satisfactorily completed this inspection period. The inspectors observed portions of the testing, specifically the operation of major SSF components such as the RCP seal makeup pumps. SSF diesel generator, and auxiliary service water pumps. The tested equipment operated well, requiring little maintenance attentio The Unit 3 control rod test results were acceptable. The maximum rod drop time was 1.270 seconds which was within the administrative limits of 1.40 seconds. and the TS allowable 1.6 second c. Conclusion The observed maintenance and surveillance activities were completed thoroughly and professionall M1.2 2B HPI Pump and Motor Work (WO 96038747)

a. Inspection Scope (62703)

Section 01.3 discussed the operational aspects of the failure of the 2B HPI motor. The inspectors monitored the investigative and recovery actions, including testing of the moto b. Observations and Findings Electrical testing indicated that the pump motor had failed. The motor internal winding was initially thought to be the problem. The motor was transported to the refurbishment facility which had overhauled the motor 1.5 years ago. When the motor was disassembled and inspected, initial indications from a team sent with the motor to the vendor was that it failed due to an internal grounding problem on one phase. The root cause for its failure will be documented in PIP 2-96-1777. The proposed ENCLOSURE 2

resolutions of the October 7, 1996 version of the PIP were as follows:

Have vendor rewind the failed motor and return [it] to [site]

store *

Review predictive maintenance program for motor. Add proven technologies that could predict failures and are economically justifie *.

Review past operating and maintenance history of HPI motors. Look for trends that have pointed to failur *

Review the existing motor refurbishment schedule. Make any necessary changes that may help prevent failure *

Review the motor lead lugging process for needed changes to ensure proper lug installatio *

Investigate the possibility of purchasing an additional spare

[motor] to cover long lead times for rewind Additional NRC review of the motor failure analysis will be performe This issue is addressed as Inspector Followup Item 50-270/96-13-05, 2B HPI Motor Failur When the motor leads were inspected in the plant during the time of the investigative/repair disassembly, a motor pigtail lead had pulled loose from the electrical lug that attached to the main power cables without significant force being applied. The resident inspector observed the electrician pull the pigtail free of the lug without significant effor The lug to pigtail interface showed no ohmic heatin It was concluded that this lug connection most likely did not play a significant role in the motor failure. It was noted that the lug may not have caused problems due to the silicone taping around the joint. Good practice was to perform a pull test after the lug crimp was made. Work records indicated that Quality Control personnel were present for joint make u The licensee's normal practice in this area (large motor lugging) was on-the-job training to provide guidance with more experienced personnel providing trainin At the close of the inspection period, NRC review of the lug connection issues was not complete. This issue will be followed up under URI 50 270/96-13-06, Lug Connections for High Voltage Terminations. This issue is unresolved pending additional NRC review of the maintenance activities associated with the apparently poor connectio c. Conclusions The repair work at the pump was well controlled and methodically performed. Management specifically directed that craft personnel take ENCLOSURE 2

the time to do the work correctly. The repairs exceeded the 72-hour LCO period and a plant shutdown was initiated. Additional NRC review of the motor failure and lug connection issues will be conducte M1.3 ST Transformer Issues a. Inspection Scope During this period, the 5T transformer, which is one of two electrical sources for the primary instrument air compressor, was identified as having a differential current problem. The inspectors observed testing and held discussions with the licensee regarding the proble b. Observations and Findings On September 9, 1996, the 87Z relay for the ST Transformer annunciated a local alarm for a possible current differential problem. Several electrical crews checked the problem and the inspector observed a recheck under WO 96072390. Because there was a potential for an internal winding problem. the transformer was shipped to an offsite shop for possible rewind. The shop performed additional testing of the transformer and identified no electrical problems. Subsequently, electricians checked the bus terminals that had been removed from the transformer and found an insulator problem. This problem was subsequently corrected and the transformer was to be returned to service at the end of the inspection perio M1.4 RCS Injection Line Repairs a. Inspection Scope Section 01.4 discussed a socket weld leak on a small line connected to valve 2HPI-491 which is on a RCS injection line pipe. Through direct observations, review of the modification package, and discussions with the licensee, the inspector followed up on the corrective action b. Observations and Findings Minor Modification ONOE-9496 removed the majority of the test line piping under WO 96075990 from the HPI injection lines (see Section 01.4). The inspectors observed satisfactory portions of the test line removal, the cap weld fitup, and weld tacking of the caps to the remnant test line stubs. The observed work was in accordance with instruction requirements. A fire watch was posted and a RP technician was at the work site to assist and provide ALARA direction. (See Section E1.3 for a discussion of post installation testing.)

• ENCLOSURE 2

c Conclusions Observed work was performed in difficult conditions in the Reactor Building with good control of the FME and weld processe III. Engineering El Conduct of Engineering E1.1 Missed Surveillances on Thirteen Relief Valves a. Inspection Scope (37551. 40500)

On August 29, 1996. while developing the relief valve IST engineering support program, and revising calculation OSC-5561, Safety Related Relief Valves and Vacuum Breaker For IST Program, the licensee discovered that they had missed thirteen relief valves that were required to be tested by the TS/IST program. The inspector reviewed the licensee's PIP 0-96-1666, 10 CFR 50.72 notification, work orders, and other documentation as necessar b. Observations and Findings While working on the relief valve engineering support program and reviewing the Oconee Nuclear Station ASME Inservice Testing Program, the licensee identified an error involving the ten year testing interval The third ten-year IST interval began on July 1. 1992. The licensee had previously thought that the start date was July 1, 1993. TS 4. requires performance of valve testing in accordance with the ASME Section XI IST program. ASME/ANSI OM-1 1987, Operation and Maintenance of Nuclear Power Plants, is the governing document for the required relief valve testing. The OM-1 code documents the scope of the valves and the required testing frequency. The code requires that all the Class 2 and 3 valves in the program shall be tested within each ten year period, with a minimum of twenty percent of the valves tested within any forty-eight months. As a result of the incorrect test interval start date, surveillance testing of thirteen valves had been misse According to the evaluation attached to PIP 0-96-1666, only two of the thirteen valves were required for accident mitigation. After further evaluation, the licensee declared the two valves (1LP-61 and 3LP-61)

inoperable on September 3, 1996. The licensee made a 10 CFR Part 50.72 notification because declaring 1LP-61 and 3LP-61 inoperable rendered the Borated Water Storage Tank (BWST) inoperable. Valves 1LP-61 and 3LP-61 are the vent valves for the BWST. These valves are required to be capable of opening and admitting sufficient air to maintain the pressure in the BWST above its design vacuum when liquid is removed from the tank. The BWST provides a source of borated water for the emergency core cooling systems during certain design basis accidents. TS 3. ENCLOSURE 2

required restoration of the BWST operability within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, or be in hot shutdown within six hours. Upon discovery of their administrative error, the licensee immediately entered the appropriate LCO and made preparations to work the valves. The inspectors observed the removal of the valves from the BWST vent piping to clearly establish the present operability of the BWST. The valves were tested "as found" per OM-1, found to provide an air flow path, were refurbished, and were reinstalled on the BWST. With the proof of the open air flow path found during testing, the valves were determined to be past operable. As part of the licensee's corrective actions, a justification for deferral for the remaining valves to be tested was completed. This licensee identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy. This issue is identified as NCV 50-269,270,287/96-13-07, Missed TS/IST Surveillance On Thirteen Relief Valve c. Conclusion The inspector concluded that the licensee missed surveillance testing on thirteen relief valves because they mistakenly thought the third ten year interval started in July 1993 when in fact the start date was July 1992. This licensee identified violation was of minor safety significance and addressed as a NC E1.2 Hydraulic Snubbers a. Inspection Scope An Oconee snubber vendor identified that their supplied equipment did not meet the Duke ordering criteria. The inspectors reviewed the operability and reportability issues concerning the qualification of hydraulic snubbers used in the containments at Ocone b. Observations and Findings On August 26. 1996. Grinnell Corporation reported to the licensee that their hydraulic snubbers were not fully capable of withstanding all accident conditions that may exist in containments following a Loss of Coolant Accident or a Steam Line Break (LOCA or SLB). The licensee documented this information in PIP 0-96-1636. which identified that Grinnell Company had not met the procurement specifications regarding environmental conditions (radiation and temperature) associated with their Model PH76N and PH74R snubber Through their PIP process, the licensee evaluated the environmental conditions for which these snubbers would be subjected during their design basis accident conditions. Initially, the licensee's operability conclusion relied upon a position that the licensing basis for Oconee does not require assumption of a seismic event during a LOCA or SL Additional analysis was performed that concluded that the snubbers would ENCLOSURE 2

• perform their design safety function of restraining piping or component movement under accident condition c. Conclusion The inspectors reviewed the licensee's evaluation of the snubbers. It was noted that based on the design basis accident. Oconee is not required to assume a seismic event during a LOCA or SLB. The inspectors concluded that the licensee had performed a adequate evaluation which supported the conclusion that the snubbers were operabl E1.3 Minor Modification ONOE-9496 Test Problem a. Scope The inspector reviewed the completed Minor Modification package ONOE 9496. Cut and Cap 1" HPI Lines (4 Places). A leak in the one inch test line was discussed in Section 01.4 of this report. The leaking test line and the other three test lines similarly modified were remove The lines were installed as a part of a larger modification NSM-22975 which replaced Unit 2 injection line lift check valves with new check valves and up-stream isolation valve b. Observations and Inspection Findings During the inspector's review of the modification package, it was determined that the associated inservice testing did contain detailed testing requirements. The modification package indicated that the newly installed welded pipe caps were Class A stainless steel under American Society of Mechanical Engineers (ASME) XI Boiler and Pressure Vessel Code requirements. TS 4.3 and FSAR Section 5.0 (and others) were based on the ASME Code requirement In the minor modifications package (ONOE-9496). paragraph 4. described the inservice testing as follows:

Have Maintenance perform inservice leak inspection. Document when NO LEAKS foun Verified By __Date In the same package. Enclosure 9.3, Modification Test Plan, under verification retests stated:

Type of Test:

Documentation:

Performed By:

Inservice Pressure Test MP/O/A/1720/016 Mech. Maintenance There was an asterisk by the test type with an asterisk note in the lower margin that indicated... " Per telephone conversation with [.....]

this procedure not required. However, per [the minor modification ENCLOSURE 2

package] a visual leak test will be performed once system is placed in service."

The inspector concluded that the minor modification test and inspection instructions did not have several requirements indicated in paragraphs 17.3.2.8. Tests, and 17.3.2.12, Inspection, of the Topical Report (Chapter 17 of the FSAR, Duke 1-A) such as test acceptance criteria (test pressure), clear method of inspection such as VT-2 (a close visual inspection of the entire weld joint), and prerequisites such as a hold time and temperature requirements), et Per the Topical Report, these requirements shall be applied as necessary for any test that the licensee shall decide to perform. The operational pressure was not specifically listed and an allowable range for the test was not listed. The operational temperature, the degree of visual observation (proximity to the weld, the amount of leakage, available lighting), and any other prerequisite such as length of hold time at pressure prior to inspection or the qualification of the inspecting individual were not addressed. An inservice test was not specified in the ASME code (1989 version) for one inch and under pipe in size (an explanation of the asterisk note). But the licensee had dictated a test in the packag On September 25, 1996. when the inspector initially reviewed the minor modification package, the unit had returned to power. At that time, the inspector asked engineering if the welded caps had an inservice test in accordance with the Topical Report at a known operating pressure. Based on a signature in the package, Engineering believed that this had occurred, but could not state for sure if that had occurred at normal operating pressure or any fixed pressure due to the lack of specified criteria. Operations was contacted by the inspector for input on the plant conditions at the time of the test and weld inspection Independently, on September 23, 1996. Operations had the same concerns about the instructions of the package in that they felt that it did not provide clear guidance. On-shift Engineering and Operations had ensured that the testing had been carried out at the normal and known operating pressure and temperature (Operations had performed PT/O/A/200/46 that required proper maintenance of normal operating pressure within a specified range) and that this had been maintained stable for a number of hours prior to the inspection. The inspector concluded that based on a good review of plant work, Operations and shift engineering had ensured test continuity. Their actions were commendable. The inspector concluded that verbal actions should not be depended upon to meet test requirement The WO task sheets (3 and 5 for WO 96075990) for the work completed by inspection/test performers indicated that the Operations personnel wrote down the RCS pressure and temperature for two of the welds, but they ENCLOSURE 2

were not the procedure indicated performers. For the other two welds, designated performers (maintenance personnel) did not write down pressure and temperature, but the plant had been at normal operating pressure and temperature for inspection performance. In summary, proper inspections of the welds did occur and practical criteria were applied, but this was not in accordance with any clear written procedural step The inspector reviewed NSD-301 (Nuclear Station Modifications). NSD-408 (Testing), and Site Directive 2.2.1 (Minor Modification Program), which was the applicable procedure for the implementation of the Topical Report. These documents, which were to be used by site engineers in the generation of modifications, did not contain the Topical Report list of requirements for test and inspections. The Topical report programmatic requirements should be available for the end user who was intended to provide safety function under the QA program requirement Appendix B of 10 CFR 50 (Criteria V) and TS 6.4.1 require after a modification has been performed that testing and inspection be performed in accordance with written procedures. Although testing had been performed with some prerequisites, the procedure did not list the required criteria to provide assurance that the test was adequat Based on the above, the written procedure for the inservice test was inadequate. This is a violation of the Appendix B requirements and attendant Topical Report paragraphs. The violation is identified as Vio 50-270/96-13-08, Failure to Provide Adequate Test and Inspection Requirement c. Conclusions Although good efforts were noted on the part of the Operations and shift personnel for this particular modification testing, required programmatic elements of modification tests and inspection were not contained in site procedure E1.4 Modification ONS-22975 Package Problem a. Inspection Scope Modification ONS-22975, Replace HPI Check Valves 2HP-126, 2HP-127. 2HP 152, and 2HP-153, originally installed the replacement HPI check valves, piping, isolation valves, and test piping discussed in Sections E. and 01.4 of this report. The inspector reviewed portions of the modification packag b. Observations and Findings The package was generally comprehensive except as noted below. The package did not contain a fatigue analysis. FSAR section 5.2. discusses fatigue analysis requirements for the sections of pipe addressed in the modification (Class 1).

Operation of the RCPs can ENCLOSURE 2

cause vibration of RCS piping and may require additional fabrication to ensure piping survivabilit The test piping had failed on the 2HP-491 downstream socket wel This weld was removed (with the test piping) and transferred offsite for evaluation. Until a written evaluation of this test piping weld failure has been formulated and details of the welding can be reviewed, this will be identified as URI 50-270/96-13-09. RCS Piping Socket Weld Failur The inspector also reviewed the 10 CFR 50.59 evaluation for ONS-2297 The evaluation performed for the above modification concluded that the modification did not represent an Unreviewed Safety Question. The evaluation indicated that no fatigue evaluation would be required due to previous NRC written communication Previously, the NRC had identified that the licensee did not have a complete fatigue analysis for some RCS piping as required by their FSA A deviation was issued in Inspection Report 50-269,270,287/95-0 Additional information is contained in the following correspondence:

US NRC Project Manager Letters to the Oconee Site Vice President (dated 4-27-95 and 7-10-95)

Duke Power Letter To US NRC, From Site Vice President (dated 10-3 94.6-26-95, 2-22-96)

The letters addressed existing RCS piping from the large diameter RCS loops to the first existing isolation valves. Existing piping was to be analyzed by the August 31, 1999. New modifications to RCS piping were not addressed in the above letters. The 10 CFR 50.59 evaluation did not adequately address potential cyclic load fatigue issues associated with the piping to be attached to the RCS piping. The inspector concluded that the NSM-22975 modification did not contain fatigue analysis to support the Unit 2 RCS piping chang The licensee's failure to provide an adequate 10 CFR 50.59 evaluation for the NSM 22975 modification is identified as Violation 50-270/96-13 10, Failure to Perform Adequate 10 CFR 50.59 Evaluatio c. Conclusions Regarding the subject modification and 10 CFR 50.59 requirements, the licensee failed to perform an adequate evaluation of the modificatio ENCLOSURE 2

E1.5 Service Water System a. Inspection Scope (TI 2515/118)

This portion of the inspection was conducted to review the licensee's actions to resolve concerns previously identified by NRC SWSOPI initially conducted in 1993. Also, the inspectors performed reviews of the licensee's response to Generic Letter (GL) 89-13. "Service Water System Problems Affecting Safety-Related Equipment." The actions were evaluated against TI 2515/118. Field inspections were also performed of portions of the service water system. The inspectors reviewed the

"Oconee Nuclear Performance Measures Report" for the "ERCW Suction Supply to LPSW". Eighteen open items were reviewed, as listed in Section E8 of this report, to determine if these activities were conducted in accordance with TS, the FSAR, approved procedures, Generic Letter 89-13, and appropriate industry codes and standard b. Observations and Findings The inspectors reviewed outstanding LERs. violations, unresolved items, and inspector follow-up items associated with the Service Water Syste The corrective actions described by the licensee were evaluated for adequacy and completeness. The licensee is presently implementing modifications to correct deficiencies identified as a result of the service water inspections. The modifications work has started, but work completion as currently planned will not be finished until late 199 The inspectors reviewed the licensee's actions relative to resolving the issues. Subsequent modification work and follow-on testing will be tracked as IFI 50-269,270.287/96-13-03, Service Water System Modifications and Testing, in order to assure complete corrective actions are implemented for the items being closed that require modifications. Inspection findings are discussed in paragraph 0 c. Conclusions The inspections concluded that the planned modifications to certain portions of the service water system discussed in this report would allow the various service water systems to perform their required safety functions. The inspectors also found that the requirements of Generic Letter 89-13 had been implemented. The inspectors noted the licensee's

"Oconee Nuclear Performance Report" for the "ECCW Suction Supply to LPSW" identified the service water project as status "RED" indicating that several service water modification projects are not on track to meet the various implementation schedules. The inspectors concluded that this schedule slippage could potentially delay implementation completion of the modifications committed to be completed by late 199 *

ENCLOSURE 2

E8 Miscellaneous Engineering (92903, 92901)

E8.1 (Closed) URI 50-269.270.287/93-13-03: ECCW System Design and Testing This item concerned several design and testing deficiencies associated with the ECCW system. These deficiencies included apparent failure to meet single failure criteria for several valves, associated power supplies and logic circuits, the amount of water needed in the hotwells and upper surge tanks to provide for decay heat removal, the lack of seismic qualification of portions of the CCW/ECCW and support systems, the acceptability of restarting a CCW for accident mitigation, and the adequacy of testing performed on the ECCW system. The licensee responded on December 28, 1995, with proposed corrective actions that would correct these issues. The NRC accepted the licensee's proposal on July 2. 1996. This inspection determined the licensee had taken adequate corrective actions to resolve these issues. These corrective actions included modifications that will upgrade those portions of the CCW system which supplies LPSW. installing a QA1 water supply from LPSW to the CCW pumps, and installing QA1 control circuitry to auto restart selected CCW pumps. These modifications are NSM ON-X2932, -X3000, X3001. and -X3003. NRC review of the completion and testing of these modifications will be identified as IFI 50-269,270.287/96-13-03, Service Water Modifications and Testin CFR 50. Appendix B. Criterion III, "Design Control," requires that adequate measures be established for the selection of equipment and processes. Failure to adequately control design is identified as the first example of violation 50-269,270.287/96-13-04. Inadequate Design Contro E (Closed) URI 50-269,270,287/93-13-04:

LPSW/ECCW Operability This URI identified that all four CCW pump discharge valves could go closed on a loss of the CCW pumps if one of several single failures occurred in the CCW system control logic. The licensee acknowledged this potential failure mode and for immediate corrective actions proposed that the LPSW suction cross connect valves between units be opened to supply a common suction to the LPSW pumps from all three units CCW system Inspection Report 50-269,270.287/94-39 discussed this URI and determined that with the unit CCW cross-connect valves open, two additional siphon paths, not affected by the single failure, were available to provide water to the LPSW suction source and eliminated the single failure vulnerabilit The licensee has implemented a modification that ensures that at least one CCW pump discharge valve will remain open when all CCW pumps trip, even with a single failure in the control circuitry. The inspectors determined the licensee had taken adequate corrective actions to resolve this issu ENCLOSURE 2

10 CFR 50. Appendix B, Criterion III, "Design Control," requires that adequate measures be established for the selection of equipment and processes. Failure to adequately control design is identified as the second example of Violation 50-269,270,287/96-13-04, Inadequate Design Contro E8.3 (Closed) DEV 50-269.270.287/93-25-01: (Deviation A in NRC Inspection Report 93-25), Failure to Adequately Perform SWS GL Action The licensee's original response to GL 89-13 was not inclusive of some of the systems utilizing service water. In response, a revised GL response was submitted September 1. 1994. However, there were omissions and inadequacies associated with this response. The omissions and inadequacies outstanding are:

(1) Action I - No date was provided as to when the CCW system hydraulic model would be benchmarked. No date was provided as to when the HPSW system hydraulic model would be benchmarked. The frequency of simultaneous SSF SWS pump testing was not specifie (2) Action III - No administrative controls existed to ensure the committed inspection program for the SSF, ASW. and Keowee SWSs would be accomplished. System engineers interviewed who were to do the inspection program were unaware of their inspection responsibilities. There were no criteria by which to judge piping condition acceptability. Also, no technical bases for the adequacy of the piping inspection program in terms of scope, frequency, or corrective action could be ascertaine (3) Action IV - No date was provided as to when the Keowee single failure analysis would be complete (4) Action V - The GL response referenced a Duke Power Company letter to the NRC dated April 20, 1994, as providing the discussion on procedures and training. However, this letter was not applicable to Action V. Also, the presently docketed correspondence on this matter indicated that SWS procedures were receiving a two-year review. This was not correct. The licensee had revised their procedure review cycle to as long as every six years following a change to their QA pla The inspectors reviewed the licensee's response submitted to the NRC on April 4, 1995, that addressed the four issues above. The issues were verified by the inspector as being adequately addressed in the subject response. The inspectors also verified that action items with stated implementation dates were implemented, as stated. One of the corrective action items involved a commitment by the licensee to evaluate the design basis documentation to verify the ability of the Keowee service water systems to perform their required functions following a single ENCLOSURE 2

active failure. This action was verified as being completed by the licensee (ref. OSC-5409), but technical review of the evaluation by the inspectors was not done at this time. The inspectors determined the licensee had adequately addressed the open issue E8.4 (Closed) VIO 50-269.270.287/93-25-03: (Violation B in NRC Inspection Report 93-25). Failure to Perform Adequate Calculations and Evaluations to Support Facility Desig There were seven parts associated with this violation. Items 2 and 7 were reviewed and documented in IR 50-269,270.287/94-31 as acceptabl In Item 1, the NPSH of the LPSW pumps was not adequately considered as a design input in that calculation OSC-5019 was accepted by the licensee's engineering department with inadequate NPSH and inadequate technical justification. Modification X-3001 LPSW is being installed to isolate non-essential loads from the LPSW system. This will reduce the required LPSW flow and NPSH. The modification was scheduled to be completed during the next refueling outage of each unit with the final work being completed in 1997. The modification installation and testing will be followed under IFI 50-269,270.287/96-13-0 In Item 3. the commercial grade evaluation for Belzona as a suitable material for application in the Unit 2 RBCU tubes was inadequate. The licensee indicated that an effort was in progress to analyze Belzona for cyclic and LOCA loadings. PIP 0-094-1154 contained the results of laboratory testing in dynamic and LOCA conditions. The results indicated that Belzona would perform in the RBCU application including LOCA conditions. Additionally, the RBCUs were replaced during a subsequent refueling outag In Item 4, the design basis of the ECCW system was not adequately translated into design documents it that the calculations supporting ECCW decay heat removal capability did not include numerous aspects of the design that would reduce decay heat removal capability. These aspects included outgassing, reduced pressure effect. incorrect vertical dimensions, heat transfer area, even flow split between condensers, first syphon acceptance criteria, and adequate first syphon testin The inspector reviewed calculation OSC-2346. The calculation had been revised to incorporate the teams comments concerning outgassing, reduced pressure effect, incorrect vertical dimensions, heat transfer area, and even flow split between condensers. The results of the calculations indicated that sufficient decay heat removal capability existed with these new conditions considered. The first syphon acceptance criteria and testing were included in VIO 50-269,270,287/94-31-04 and are addressed in subsequent paragraph In Item 5, the design basis of the CCW's system capability to withstand the loss of Lake Keowee was not translated into any design documen ENCLOSURE 2

• The inspector reviewed calculations OSC-5739, 5993, 5974, 5973. 5951, and 5975. These calculations bounded the heatup of the intake following the loss of Lake Keowee. The calculations concluded that the heatup up of the intake following the loss of Lake Keowee would not exceed the design basis of the CCW or LPSW systems during a 30 day even In Item 6, the design basis for the LPSW's system capability to function as described in Case B of Abnormal Procedure AP/1/A/177/133, " Loss of Condenser Circulation Water Intake Canal/Dam failure." Step 5.5.1, was not translated into any design document. As noted above. design Calculation OSC-5993 concluded that the LPSW system's capability to function, in the event of dam failure would not be los E8.5 (Closed) VIO 50-269.270,287/93-25-04: (Violation A in Inspection Report 93-25), Inadequate Evaluation of Conditions Adverse to Quality by Engineerin There were two parts associated with this violation. Item 2 was reviewed and documented in IR 50-269.270,287/94-31 as acceptabl In Item 1. the evaluation of PIP 92-454 for a postulated water hammer within the LPSW piping downstream of the RBCUs did not include the consequences on the structural integrity of the piping. In response to the violation, PIP 93-1031 was written and OSC-6020 performed indicating turbine building flood was the bounding event. To eliminate the water hammer, the licensee committed in the response that a flow orifice would be installed downstream of the potential cavitatio Subsequent to this response, the licensee's corporate engineering completed additional computer analysis to determine if the water hammer would occur on the discharge of the RBCUs. Based on corporate engineering results, the discharge from the RBCUs was determined to always be in a condition of two-phase flow. Any water hammer would be dampened by the two-phase state. Therefore, installation of a flow orifice to increase downstream pressure would have the detrimental effect of eliminating the dampening effect of the two-phase state. The evaluation concluded that installation of flow orifices that would ensure single phase conditions would actually increase the potential for water hammer. Therefore, the installation of orifices was not require The inspectors reviewed the licensee position on this matter and concluded that installation of orifices was not require E8.6 (Closed) IFI 50-269,270,287/93-25-05:

Additional Validation of RBCU Evaluation Input This IFI was reviewed by the NRC team inspection and documented in NRC IR 50-269,270,287/94-31. The team observed licensee attempting to take air flow measurements during the current refueling outage but the attempt was poorly coordinated and not accomplished. The licensee stated air flow measurements would be obtained during the next refueling ENCLOSURE 2

outag At that time, the inspector follow-up item remained open pending the licensee acquiring the air flow data. During this inspection the inspector reviewed the results of the air flow testing and calculations. PIP 3-095-810 documented the results as acceptable based upon a measured flow rate of 40,000 cfm. This measured flow rate was compared to the design flow rate of 54,000 cfm and was determined to be acceptable as it represented less than one percent reduction in heat removal capability. The PIP was closed on January 4, 199 E8.7 (Closed) IFI 50-269.270.287/93-25-06: Actions to Improve Operator Responses to Abnormal Event There were three parts associated with this ite (1) In Part A, the prerequisite for the total loss of LPSW was no LPSW pump operating; not inadequate LPSW flow. The licensee revised the prerequisite of the procedure. No additional problems identified. Part A was closed in IR 50-269,50-270,50-287/94-3 (2) In Part B. Abnormal Procedure AP/1/A/1700/13, "Loss of Condenser Circulating Water Intake Canal/Dam Failure," had several weaknesses. The licensee generated PIP 0-094-0514 to revise the procedure and improve operator training to address these concern Operator training had been revised and taught to the 1994-95 licensed reactor operator and senior reactor operator clas Also, other licensed operators would be taught during the 1994-95 PTRQ classroom training. The procedure revision was scheduled to be completed by November 30, 1994. The PIP 3-094-0514 was closed on 1/4/96. The procedure reviewed by the inspector, change dated 5/30/95 contained the steps necessary to alert the operators to shut CCW 8 within one hour of dam failure or prior to submersio (3) In Part C, potential weaknesses in the operator guidance for response to a severe tornado were identified. The licensee indicated that a tornado would be considered as part of an upcoming exercise to ascertain whether further operator guidance was warranted. The PIP 0-95-1192 was issued to track this ite A drill containing a tornado on-site was conducted on 9/19/9 This drill was unsuccessful in assuring ASW flow to the SGs within 40 minutes. Following enhancements to the procedures and additional training, the licensee conducted another drill on 10/25/95. The results of this drill were satisfactor E8.8 (Closed) VIO 50-269.270.287/93-25-08: (Violation D in NRC Inspection Report 93-25). Inadequate SSF and ECCW Testin There were three parts associated with this violatio In Item 1, ECCW flow test procedure PT/1/A/0261/07 did not account for ENCLOSURE 2

the potential + 2,000 gpm error which could result from the method used to measure flow - observation of the impact point of the ECCW discharge flum In response the licensee committed to produce an analysis by July 1, 1994, and incorporate its results in the test procedure by August 1, 199 A revision to the analysis, OSC-5629, "ECCW Test Acceptance Criteria Inputs," was issued on July 13. 1994. There were no technical discrepancies associated with the new analysis. However, the results were not incorporated into the test procedure at the time of the follow up inspection. The licensee stated that they had intentionally delayed incorporation until just before the next required procedure performance at the next refueling outage so that all other ensuing changes can be incorporated at the same time in one overall revision. PIP 0-094-1175 was issued to track this item. The PIP was closed on 12/18/95. The inspector reviewed PT/1.2,3/A/0261/07. The procedure had been revised to incorporate a more conservative acceptance criteria than that contained in OSC-5629. Additionally, OSC-5629 had been revised to remove 1 foot from the observed plume length to account for the inaccuracy of the measurement and correlated weir flow with the observed leve In Item 2, the preoperational test program for the SSF's SWS and the post-construction flushing procedure for the SSF's discharge lines to all the SGs were inadequate. In response the licensee committed to performing reverse flow testing of each unit's SSF ASW supply pipin Adequate flush velocities would be achieved during the testing along with water samples to verify the flush was adequat Procedures were revised and the first test (Unit 1) had been complete The preliminary results appeared to address the initial concerns. There was provision for assuring the velocities would be adequate and that condensate would be used to flush the lines. The procedure also had steps to ensure that the condensate flow out of sample lines were clea Also, the licensee had replaced the SSF feedwater control valves and added bypass valves to assist in the control of the SSF feedwater flow to the steam generators. The modifications appeared adequat TT/1,2.3/A/0600/13 was completed on June 9, 1994. Test results were acceptabl Item 3 was closed in IR 50-269,270,287/94-3 E8.9 (Closed) DEV 50-269,270.287/93-25-10:

(Deviation B in NRC Inspection Report 93-25), Inadequate HPSW SBO Tes The test did not properly establish initial testing conditions and provided weak guidance when problems were identified. In response the licensee committed to revise the test procedure. The test procedure had ENCLOSURE 2

been revised, and all but one initial issue had been addressed. For the condition of a severely leaking HPSW pump discharge check valve, the updated procedure still directed the operator to isolate the faulty valve and allowed the test to proceed and the results to be accepted, when the test would not have passed with the valve un-isolated. The PIP contained a statement that "The test can continue with the leaking check valve isolated", and a note still existed in the procedure to make an entry in the turnover sheets to inform the operators to shut the affected pump's discharge valve upon loss of power to prevent excessive losses of the EWST. implying that a leaking check valve was acceptable with regard to the test results. As noted in the original inspection report, this is not acceptable since it is not reasonable to expect that an operator would isolate the valve before excessive losses from the EWST could have occurred in an actual SBO event. Numerous, complex operator actions are necessary to respond to an SBO event. The guidance for performing the isolation is not contained in an emergency procedure but on a rounds checklis This deviation remained open in IR 50 269.270,287/94-31 pending appropriate resolution to a leaking HPSW pump discharge check valve when performing the test. PT/0/A/250/38 was revised to account for a leaking check valve. If the test fails due to a leaking check valve, a Priority 1 work request is issued to repair the valve and the test will be rerun after the valve is repaire E8.10 (Closed) VIO 50-269,270.287/93-25-12: (Violation C in NRC Inspection Report 93-25), SWS Procedure/Drawing Content or Procedure Implementation

Inadequacie There were five parts associated with this violation. Items 2, 3. 4, and 5 are closed in other report In Item 1. engineering administrative procedures did not establish a definitive length of time for revising calculations following design changes. In the licensee's original response to the violation the licensee stated that Procedure EDM-101, Engineering Calculations/Analysis, would be revised to provide the necessary guidance by September 1, 1994. However, in a letter dated September 1, the licensee stated that the plant modification process would be revised by November 1, 1994, to provide the necessary guidance. The inspectors verified that the modification process had been modified to contain the necessary guidanc The original inspection finding dealt with calculations associated with the SSF SWSs. With regard to these, many of the older calculations have been deleted. Some calculation revisions are on hold while the DBD is being completed. This was scheduled for mid-199 The definition of design documents to be updated with a facility change had been modified to include affected design calculations. However, the infrastructure to implement the requirement did not exi's This violation was reviewed and remained open in IR 50-269.270.287/94-31 ENCLOSURE 2

pending corrective action. An electronic data base of engineering calculations that will allow searching of calculations to enable a more accurate determination of the cascading effect of a calculation file change had been developed. The schedule and scope of this project was issued on June 1. 199 E8.11 (Closed) IFI 50-269,270,287/93-25-15: Administrative Controls for Lake Keowee Calculation OSC-3528, Keowee Lake Level Minimum Administrative Limits, had numerous technical weaknesses. The calculation was an attempt to establish a minimum lake level necessary to ensue operability of Oconee and Keowee for design basis events. Calculation OSC-3528 was revise The administrative controls for Lake Keowee level have been incorporated into SLC 16.9.7. SLC 16.9.7 addresses the lake levels and required actions for a range of lake levels. These actions address both Oconee and Keowee operabilitie E8.12 (Closed) VIO 50-269,270.287/94-31-01:

Inadequate Corrective Action Controls This violation contained four parts. Example, Part A identified that the corrective actions to Deviation 50-269,270,287/93-25-01 operating procedures were inadequate in that numerous valves in the Keowee service water system, including all of the generator thrust bearing cooler inlet valves and drain valves WL-1, 2. 5. and 6 for both units were omitte The licensee's corrective actions were to revise the applicable operating procedures and include the omitted valves. The inspector reviewed six procedures, identified in the licensees response letter, and verified the operating procedures for both units now properly include the appropriate valve Example, Part B identified that drawings at Keowee did not reflect correct as-built conditions in that a spigot was installed on unit 2 downstream of valve 2WWL-3. The licensee removed the spigot using a minor modification. The inspector performed field inspections and verified the spigot had been remove Example, Part C identified technical errors associated with actual available source inventory in calculation OSC-0864. known by engineering but not identified on a condition adverse to quality through the PIP process. The licensee's corrective actions included issuing PIP 94-1500 which is now closed. The licensee identified that technically the condition did not meet the PIP criteria, but identified the condition on a PIP for tracking purposes. The inspector reviewed the corrected calculation and noted the errors had no adverse affect on system reliabilit ENCLOSURE 2

Example, Part D identified that corrective actions for a condition adverse to quality. PIP-0-94-313 were inadequate in that 10 rotameters contained slime contamination and 11 were pegged high which is the same condition the PIP had identified and was subsequently closed with corrective actions take The corrective actions included revision to Procedure OIP/2/A/1102/20, Enclosure 5.11. The inspector reviewed the procedure revision and noted it provides explicit instructions for inspection and acceptance of the rotameters. The inspector evaluated 3 operator round sheets, performed daily, of the inspection of the rotameters to the above revised procedure. Additionally, the inspector inspected all service water pump rotameters. Some problems were noted with the rotameters in that one contained clams and several were pegged high. As part of the licensee's service water modification discussed in this report, the licensee has identified the need to replace the rotameters with flow orifices. This activity will be followed as part of IFI 50-269,270,287/96-13-0 Service Water System Modifications and Testing The inspectors evaluation determined the licensee had taken adequate corrective actions on the four example E8.13 (Closed) IFI 50-269.270.287/94-31-02: Hydraulic Model Controls Transition No administrative control existed to assure the LPSW pump flows used as hydraulic computer model input for the LPSW system remained valid during quarterly testing of the LPSW pumps. System engineers are now being provided with the quarterly pump testing data. They then compare the results against the computer models and other calculations to ensure the validity of the design basis analyse E8.14 (Closed) IFI 50-269,270,287/94-31-03: Re-performance of Calculation OSC 2346 This item was first identified as item 4 of 50-269,270,287/93-25-0 The calculation OSC-2346 was revised to correct inaccuracies and omissions. The revised calculation indicated that sufficient ECCW decay heat removal capability existe E8.15 (Closed) NCV 50-269,270.287/94-31-04: Inadequate LPSW Suction Source Testing Via the ECCW System This item was originally responded to by the licensee on March 15, 199 In that response the licensee acknowledged the violation. However, the licensee requested that the violation be considered for reclassification as an NCV. This request was based upon the licensee's identification of the problem and having taken corrective action to adequately test the first siphon on Unit 3. The tests on Units 1 and 2 were awaiting the next refueling for performance. Subsequent to the inspection, the ENCLOSURE 2

licensee completed the tests with acceptable results. The NRC by letter dated July 12, 1995, agreed with the re-characterization of this item as an NC E8.16 (Closed) IFI 50-269.270,287/94-31-07: Quality Programs Review This item was initially addressed to the licensee as 7 weaknesses in the cover letter of IR 50-269.270,287/93-2 The 7 items were addressed and their status updated in IR 50-269,270.287/94-31. Three of the items were closed in that report. Items 1-4 were incorporated into IFI 94-31 07 as the program reviews had not been completed. The 4 items covered programmatic weaknesses in design control, engineering evaluations, testing, and in the QA classification of components which perform a safety-related functions. The inspector reviewed the corrective actions and PIPs associated with these 4 items. The licensee completed the programmatic reviews and revisions as contained in their response dated April 20. 1994, on January 1. 1996. This item is closed as well as Items 1-4 of the cover letter to IR 50-269,270.287/93-2 E8.17 (Closed) VIO 50-269,270,287/94-31-08: ASME Section XI Test Program Omissions This violation identified that atmospheric relief valves, check valves from the auxiliary service water pump to the high pressure injection motor cooler, and the turbine oil cooling bypass valves were not tested to ASME Section XI requirements. This violation was denied by the licensee based on the position that certain valves are not required in the ASME Section XI (IST) program but are in an Appendix B program the NRC approved. In a letter dated October 4, 1996. the NRC concurred that valves, in lieu of being included in an IST program, may be included in the Oconee Appendix B program if the valves are not required to achieve a safe shutdown condition of hot standby or hot shutdown, but only required to achieve cold shutdown following a design basis acciden However, the review identified one valve, LPSW-53 that was not included in the IST program or Appendix B program. but according to the resolution of the corrective action program, was required to be included in the IST program because it could be required to perform a safety function of mitigating an accident. Therefore, one example of the violation remained as writte The inspector determined, based on the licensee's response to the violation, review of the PIP, review of the design basis, and review of all applicable correspondence associated with this issue, that adequate corrective actions were take E8.18 (Closed) LER 50-269/94-04 (and Supplement 1):

Post Accident Core Cooling Technically Inoperable Due to a Design Deficiency and URI 50 269.270,287/94-39-02. HPSW Out-of-Service Rendering LPSW Inoperabl The LER identified that a support system to LPSW operation had been ENCLOSURE 2

taken out of service on two occasions when the support system was necessary for LPSW system operability. The support system in question was the HPSW system. A critical component of the HPSW system, the elevated water storage tank, was taken out of service to support maintenance activities in 1985 (August to November) and in 1990 (July to September). Following a postulated LOCA/LOOP the necessary sealing flow preventing air intrusion into the CCW intake piping would not have been provided without the EWST inventory available. Consequently, the siphon would fail and the suction source for the LPSW system would be lost rendering the LPSW system inoperable. If operators attempted to restart the CCW pumps, cooling flow to the CCW pumps would be lost, eventually rendering the CCW pumps incapable of performing their safety functio A pivotal factor in needing the HPSW system to support the LPSW suction source was Keowee lake leve Gravity flow can provide the necessary water to the LPSW system when lake level was above 798.1'. Therefore, siphon flow or forced CCW pump flow is needed below 798.1'. which is when the HPSW system is needed to support the LPSW suction sourc Beyond what was discussed in the LER, there were numerous other times that critical HPSW system components necessary to support the LPSW suction source were out of service, and the LPSW TS 3.3.7 LCO action statement or the motherhood TS 3.0 was not entered. However, in most of those cases either Keowee lake level would have supported gravity flow, or the component was returned to service before the action statement expired. Other examples when the HPSW system was degraded and/or not able to perform its support system function were:

-

From 1982 to November 1986 when the jockey pump's discharge check valve was installed backward From November 1986 to January 1987 when the jockey pump's discharge check valve had been removed from the syste September 1987 when the each section of the Unit 1 main feeder bus was taken out of service for maintenance and inspectio Once the licensee recognized in 1994 that the LPSW support system functions of HPSW must be maintained to keep the LPSW system operable, engineering personnel immediately verified the lake level was such that the HPSW system was not necessary to support LPSW operability. Other corrective actions included taking actions to revise the HPSW and CCW system DBDs and other engineering documents and performing a single failure analysis of the HPSW system. However, engineering personnel classified the altitude valve as a passive device even though it performed an active function. The HPSW check valves and the altitude valve were to be placed in the ASME Section XI test progra Also, the licensee implemented a SLC to cover the HPSW system as a support system to LPSW. There were deficiencies within the SLC such as ENCLOSURE 2

there was no applicable "LCO Action Statement" when either half of Unit 1's main feeder bus is taken out of service (the power source for the HPSW pumps).

The licensee indicated that a modification was being planned that would enhance the existing siphon by installing the Siphon Seal Water Syste This modification is scheduled to be completed for all units by late 1997. Completion and testing of this modification is identified as IFI 50-269,270,287/96-13-03 Service Water System Modification and Testin This inspection determined the licensee has taken adequate corrective actions to resolve this issu CFR 50, Appendix B, Criterion III, "Design Control," requires that adequate measures be established for the selection of equipment and processes. Failure to adequately control design is identified as the third Example of Violation 50-269,270,287/96-13-04, Inadequate Design Contro E8.19 LER 269/96-08:

1HP-153. Emergency Core Cooling Check Valve Inoperable Due to Wear On August 29. 1996, the licensee submitted LER 269/96-08 and the inspectors have followed up on the occurrence. On November 6, 1995, Unit 1 was in cold shutdown for a refueling outage. Flow testing of cold leg injection lines indicated that valve 1-HP-153 failed to pass its required flow rate of greater than 375 gpm. At that time, the valve was inspected and repaired under WO 95084912. Additionally, an upstream orifice in the injection line was inspected under WO 95034816 to verify no blockage. Subsequently, the flow test was satisfactorily re-

.

performed. The inspector reviewed the historical WO and test performed on 1HP-153 after the repair of this period and found the test results acceptable (WO 95084912 of November 23, 1995, and TT/1/A/0251/54 of November 5, 1995).

ENCLOSURE 2

Prior to the above occurrence, the licensee had earlier problems with the 1HP-153 valve. The valve had failed a lower differential pressure flow test on May 6, 1995, while the unit was in cold shutdown. At that time, the valve was re-tested with the lower differential pressure test without repair and met the flow criteria. PIP 95-487 at that time provided justification for the observed condition Based on the second failure (November 6, 1995), the licensee made a past operability evaluation for the period May 6 to November 6, 1995. The evaluation was generated in part by the A/E which took considerable time. Utilizing the A/E flow model computational methods, the condition was analyzed at given flow rates with respect to a limiting SBLOC The completed evaluation was issued September 23. 1996, (PIP 1-95-1392, OSC-6071). The evaluation concluded that the licensing-basis safety function of the Oconee high pressure injection system was ensured, even with the flow deficiency caused by the malfunctioning check valv Based on acceptance of the above evaluation, the licensee retracted the subject LER on September 26. 1996. The reasoning and evaluation were reviewed by the inspectors and found acceptabl As an adjunct to above, the licensee was actively pursuing installation of replacement valves for the existing design lift checks on the injection lines for all units. This was being done to replace obsolescent equipment and remove valves from those positions that have seen potential erosion problems. NSM 22975 had installed new check valves and additional isolation valves on Unit 2 to date. The test line on one of these valves is discussed in Section 01.4 of this repor IV.Plant.Support Areas:

R1 Radiological Protection and Chemistry (RP&C) Controls R Emergency Plan Drill (71750)

a. Inspection Scope On September 17, 1996. the licensee held an emergency drill with full FEMA, local county, and state participation. Although the NRC did not participate, the residents and visiting Emergency Preparedness inspectors observed the dril See IR 50-269.270.287/96-14 for further details. The residents observed portions of the drill at the site operator training simulator, TSC. and OS b. Observation and Findings The training simulator was used as the plant with the drill event. The inspectors observed close coordination of the Operations crew on the simulator with the drill activities occurring at the actual plant. The Operations crew followed site procedures, and the drill scenario ENCLOSURE 2

provided good trainin In approximately 20 minutes from the announcement to man the TSC, the OSC was appropriately manned by licensee personne At the end of that 20 minutes, the managers in charge of the OSC had a current understanding of simulated plant conditions and had accounted for all personnel under their control. Additionally, they appropriately informed the TSC of their readiness (21 minutes post announcement) which was within minutes of the TSC call to the OSC. All equipment in the OSC was functional. Maintenance crews with support equipment were in adjacent waiting areas quietly awaiting further instructions. The residents checked the NRC communication devices in the TSC and found them functiona c. Conclusions The observations by the resident inspectors indicated that the licensee had demonstrated good emergency response capabilities during the dril V. Management Meetings X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on October 9, 1996. The licensee acknowledged the findings presente The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie *

ENCLOSURE 2

Partial List of Persons Contacted Licensee B. Peele, Station Manager D. Coyle, Systems Engineering Manager J. Davis, Engineering Manager T. Coutu, Operations Support Manager W. Foster, Safety Assurance Manager J. Hampton, Vice President, Oconee Site D. Hubbard, Maintenance Superintendent E. Burchfield, Regulatory Compliance C. Little, Electrical Systems/Equipment Manager J. Smith, Regulatory Compliance G. Ridgeway, Acting Operations Superintendent

ENCLOSURE 2

Inspection Procedures Used IP 71750:

Plant Support Activities IP 71707:

Plant Operations IP 61726: Surveillance Observations IP 62703: Maintenance Observations IP 71750:

Plant Support Activities IP 37551: Onsite Engineering IP 92901:

Followup - Plant Operations IP 92902:

Followup - Maintenance IP 92903:

Followup - Engineering IP 92904:

Followup - Plant Support IP 90712:

LER Followup IP 93702:

Prompt Onsite Response to Events IP 62707: Maintenance Observations IP 40500:

Effectiveness of Licensee's Problem Resolution and Prevention TI 2515/118: SWSOPI Items Opened, Closed, and Discussed Opened 269/96-13-01 NCV:

Wrong Unit Valve Operation During Reactor Coolant Pump Seal Flow Adjustment (Section 01.5)

270/96-13-02 IFI:

Failed Hanger Repair (Section 02.1)

269.270,287/96-13-03 IFI: Service Water System Modifications and Testing (Sections E8.1. E8.4, E8.12, and E8.18 269,270.287/96-13-04 VIO:

Inadequate Design Control-Three Examples (Sections E8.1, E8.2. and E8.18)

270/96-13-05 IFI:

2B HPI Motor Failure (Section M1.2)

270/96-13-06 URI:

Lug Connections for High Voltage Terminations (Section M1.2)

269.270.287/96-13-07 NCV:

Missed TS/IST Surveillance on Thirteen Relief Valves (Section E1.1)

270/96-13-08 VIO:

Failure to Provide Adequate Test and Inspection Requirements (Section E1.3)

270/96-13-09 URI:

RCS Piping Socket Weld Failure (Section E1.4)

270/96-13-10 VIO: Failure to Perform Adequate 10 CFR 50.59 Evaluation (Section E1.4)

ENCLOSURE 2

Closed 269,270,287/93-13-03 URI:

ECCW System Design and Testing (Section E8. 1)

269,270,287/93-13-04 URI:

LPSW/ECCW Operability (Section E8.2)

269,270,287/93-25-01 DEV:

Failure to Adequately Perform SWS GL Actions (Section E8.3)

269,270,287/93-25-03 VIO:

Failure to Perform Adequate Calculations and Evaluations to Support Facility Design (Section E,270,287/93-25-04 VIG:

Inadequate Evaluation of Conditions Adverse to Quality by Engineering (Section E,270,287/93-25-05 IFI:

Additional Validation of RBCU Evaluation Inputs (Section E8.6)

269,270.287/93-25-06 IFI:

Actions to Improve Operator Responses to Abnormal Events (Section E8.7)

269,270,287/93-25-08 VIO:

Inadequate SSF and ECCW Testing (Section E8.8)

269,270,287/93-25-10 DEV:

Inadequate HPSW SBO Test (Section E8.9)

269,270,287/93-25-12 VIO:

SWS Procedure/Drawing Content or Procedure Implementation Inadequacies (Section E8. 10)

269,270,287/93-25-15 IFI:

Administrative Controls for Lake Keowee (Section E8.11)

269.270,287/94-31-01 VIO:

Inadequate Corrective Action Controls (Section E8.12)

269,270,287/94-31-02 IFI:

Hydraulic Model Controls Transition (Section E8.13)

269,270,287/94-31-03 IFI:

Re-performance of Calculation OSC-2346 (Section E8.14)

269,270,287/94-31-04 NCV:

Inadequate LPSW Suction Source Testing Via the ECCW System (Section E8.15)

269.270,287/94-31-07 IFI:

Quality Programs Review (Section E.16)

269,270,287/94-31-08 VIO:

ASME Section X a

Test Program Omissions (Section E8.17)

ENCLOSURE 2

269,270,287/94-04 LER:

Post Accident Core Cooling Technically Inoperable Due to a Design Deficiency (Section E8.18)

269.270,287/94-39-02 URI:

HPSW Out-of-Service Rendering LPSW Inoperable (Section E8.18)

ENCLOSURE 2

List of Acronyms AIT Augmented Inspection Team ASME American Society of Mechanical Engineers ASW Auxiliary Service Water ATWS Anticipated Transient Without Scram CFR Code of Federal Regulations CCW Condenser Circulating Water CFM Cubic Feet Minute CPM Counts Per Minute CR Control Room DBD Design Basis Document DEV Deviation DG Diesel Generator ECCW Emergency Condenser Cooling Water ERCW Emergency Raw Cooling Water EWST Elevated Water Storage Tank FA Fuel Assembly FDWP MFP FEMA Federal Emergency Management Agency FME Foreign Material Exclusion FSAR Final Safety Analysis Report GL Generic Letter GPM Gallons Per Minute HPI High Pressure Injection HPSW High Pressure Service Water

.HVAC Heating Ventilation and Air Conditioning I&E Instrument & Electrical IAW In Accordance With ICS Integrated Control System IFI Inspector Followup Item INPO Institute of Nuclear Power Operations IR

Inspection Report

ISFSI

Independent Fuel Storage Installation

IST

Inservice Test

KHU

Keowee Hydro Unit

LDST

Letdown Storage Tank

LER

Licensee Event Report

LCO

Limiting Condition for Operation

LOCA

Loss of Coolant Accident

LOOP

Loss of Offsite Power

LPI

Low Pressure Injection

LPSW

Low Pressure Service Water

MCC

Motor Control Center

MFP

Main Feedwater Pump

MP

Maintenance Procedure

MSR

Moisture Separator Reheater

MSSR

Main Steam Safety Relief Valve

MSL

Main Steam Line

MW

Megawatt

NCV

Non-Cited Violation

NLO

Non-Licensed Operator

NPSH

Net Positive Suction Head

NRC

Nuclear Regulatory Commission

NSM

Nuclear Station Modification

ENCLOSURE 2

NSD

Nuclear System Directive

ONS

Oconee Nuclear Station

'0OSC

Operational Support Center

PIP

Problem Investigation Process

PM

Preventive Maintenance

PSIG

Pounds Per Square Inch Gauge

PTRQ

Personnel Training Requirement Qualification

QA

Quality Assurance

QA1

Safety Related Material Level

QC

Quality Control

QSM

Quality Standard Manual

RBCU

Reactor Building Cooling Unit

RCA

Radiation Controlled Area

RCP

Reactor Coolant Pump

RCS

Reactor Coolant System

RIA

Radiation Monitor

RO

Reactor Operator

RP

Radiological Protection

RP&C

Radiological Protection and Chemistry

SBLOCA

Small Break LOCA

SBO

Station Blackout

SRO

Senior Reactor Operator

SSF

Safe Shutdown Facility

SFP

Spent Fuel Pool

SG

Steam Generator

SLB

Steam Line Break

SLC

Selected License Commitment

.SOER

Significant Operating Event Report

SSF

Standby Safety Facility

STAR

Stop Think Act React

SWS

Service Water System

SWSOPI

Service Water System Operational Performance Inspection

TI

Temporary Instruction

TS

Technical Specification

TSC

Technical Support Center

UFSAR

Updated Final Safety Analysis Report

URI

Unresolved Item

USQ

Unreviewed Safety Question

VIO

Violation

WO

Work Order

WR

Work Request

WTA

Main Generator Exciter Control

ENCLOSURE 2