IR 05000338/1997004

Insp Repts 50-338/97-04 & 50-339/97-04 on 970518-0621.No Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML20149L120
Person / Time
Site:	North Anna
Issue date:	07/21/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20149L110	List: IR 05000338/1997004 ML20149L107
References
50-338-97-04, 50-338-97-4, 50-339-97-04, 50-339-97-4, NUDOCS 9707310120
Download: ML20149L120 (30)

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U.S. NUCLEAR REGULATORY COMMISSION

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REGION II

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Docket Nos: 50 338, 50 339

License Nos: NPF 4, NPF-7 i

Report Nos: 50 338/97 04, 50 339/97 04

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Licensee: Virginia Electric and Power Company (VEPCO)

Facility: North Anna Power Station, Units 1 & 2 i

Location: 1022 Haley Drive i Mineral, Virginia 23117

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Dates: May 18 through June 21, 1997

Inspectors: W. K. Poertner, Acting Senior Resident Inspector R. A. Gibbs, Resident Inspector M. J. Morgan, Senior Resident Inspector J. J. Blake, Reactor Inspector (Sections M1.5, M2.1, and M8.2)

P. J. Fillion, Reactor Inspector (Sections E1.1, E8.1, E8.2, i and E8.3)

R. D. Gibbs, Reactor Inspector (Section H8.1)

P. C. Hopkins, Project Engineer (Sections 08.1 and 08.2)

i D. W, Jones, Senior Radiation Specialist (Sections R1.2, R1.3, R8.1, R8.2, and R8.3)

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Approved by: G. Belisle, Chief Reactor Projects Branch 5 DivisionofReactorProjects ENCLOSURE 9707310120 970721 PDR ADOCK 05000338 G PDR

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EXECUTIVE SUMMARY North Anna Power Station, Units 1 & 2 NRC Inspection Report Nos. 50 338/97 04, 50 339/97 04 i

This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a five week period of resident ins)ection: in addition, it includes the results of announced inspections ay regional specialists and a regional project enginee Operations

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. Technical Specification (TS) requirements for core offload were met and

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core offload activities were carefully controlled by knowledgeable

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personnel (Section 01.2).

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. Procedures for determining alternate core cooling options to be used

upon the loss of residual heat removal were good. Operators were aware of the alternate core cooling options, the time to core boiling, and

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actions to take upon the loss of the residual heat removal system (Section 01.3).

4 * A Non cited Violation (NCV) was identified for failure to meet the requirements of TS 3.9.2 to suspend positive reactivity changes with an l inoperable source range instrument. The operating crew exhibited a lack of understanding in that they did not associate addition of water from

the refueling water storage tank at a lower boron concentration than the

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reactor coolant system boron concentration as a positive reactivity l change (Section 01.4).

. An NCV was identified concerning operation of the containment purge and l exhaust system with an inoperable radiation monitor. The technician misread the setpoint during calibration and failed to note that the step

, specifically stated that the setpoint had to be less than 3.6E3 counts per minute to meet TS requirements (Section 01.5).

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. The main turbine roll and unit synchronization were carefully controlled l and supervisory oversight was appropriate. Operating crew's

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communication practices were inconsistent. Overall, execution of the

activities resulted in a smooth transition from Mode 2 to the main

generator being placed in service (Section 01.6).

> + The Unit 1 power escalation following return to service from the Refueling Outage (RFO) was hampered by secondary side equipment problems and failures that required power reductions. The decision to operate at 96 3ercent power to reduce flow induced noise and vibration on the

. Num)er 4 main turbine governor valve was appropriate (Section 01.7).

. The safety injection accumulator system was properly aligned and in

, generally good condition. The inspectors identified several equipment deficiencies, none affecting system operability, that were corrected by the licensee prior to containment close out (Section 02.1).

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! Maintenance

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TS requirements were met ~for' the Unit 1 inside recirculation spray pump

! operability test (Section M1.1).

! e TS requirements were satisfied during the IH and 1J Emergency Diesel j Generator (EDG) 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> runs and EDG operation was carefully controlled

-(Section M1.2).

L * The licensee's decision to continue running the turbine driven auxiliary l

[i feedwater pump without attempting to establish packing gland seal water flow was not consistent with the intent of procedure 1 PT 71.1 '

O Engineering determined that, based upon packing gland temperatures, seal water flow to the packing gland was adequate.(Section M1.3).

* Repair activities associated with the failure of the 1H EDG angle drive b were accom)lished in a professional manner. Licensee actions to inspect i the other EDG angle drives and modify the configuration of the gear

-driven oil pump to. prevent slippage were appropriate and demonstrated a

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safet/ conscious approach to operation (Section M1.4).

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. The. Unit 1 Inservice Inspection (ISI) was being conducted in accordance with requirements of the TS and the ASME Section XI Code of Record. 'The i use of a self checking computer data management program to generate ISI !

, reports was positive (Section M1.5). i n  !

e Licensee programs and procedures for' dealing with findings of Steam Generator (SG) eddy current examinations were consistent with current

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industry practice. An NCV was identified for not performing baseline inspections on two SG tubes. Investigation and evaluation of missed

baseline inspections for two Steam Generator tubes was thorough i

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(Section M2.1).

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. Trending of station deviations and corrective action for identified

adverse trends were assessed as a strength (Section H8.1).  ;

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I Enaineerina

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• The inspectors concluded that the reviewed modification to the Solid l State Protection System was technically sound. Inspection observations and findings on this safety significant, relatively simple modification indicated _goed design control (Section E1.1).  !

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.- Control rod drag testing methodology. appeared to adequately test for h control rod drag forces. Test data obtained was well below the established acceptance criteria (Section E1.2).  ;

j e The Unit 1 main feedwater containment check valves were replaced during

the RF0 as scheduled. The check-valves were replaced due to seat j leakage. No discrepancies were noted during observed work practices j (Section E1.3).  !

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. Possible effects on the primary plant due to the replacement of the Unit 1 moisture separator reheaters were addressed in the safety evaluation associated with the modification (Section E1.4).

. A weakness discussed in a previous NRC inspection report related to I battery cell' inspections has been corrected by Engineering (Section-E8.1). "

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Plant Support i

e The inspectors concluded that the requirements of 10 CFR 19.11 for postings of notices to workers were properly implemented (Section R1.1).

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. The licensee'was properly monitoring and controlling personnel radiation I exposure, storing and disposing of waste, and posting area radiological conditions in accordance with 10 CFR Part 20 (Section R1.2).

. The licensee was closely monitoring collective and individual radiation

dose exposure, and was meeting established ALARA goals (Section R1.3).

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Report Details

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l 4 Summary of Plant Status  !

i Unit 1 began the inspection period shutdown for a scheduled Refueling Outage l (RF0). The unit was returned to service on June 11. Equipment problems that !

interrupted the power ascension are discussed in Section 01.7. The unit  !

achieved 100 percent power on June 17. On June 18 power was reduced to 1

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approximately 96 percent due to flow induced vibration on the Number 4 main )

turbine governor valve. The unit operated at approximately 96 percent power l for the remainder of the inspection perio !

! Unit 2 operated at or near full power for the entire inspection perio I. Operations 01 Conduct of Operations 01.1 Daily Plant Status Reviews (71707. 40500)

The inspectors conducted frequent control room tours to verify proper

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staffing, operator attentiveness, and adherence to approved procedure i The inspectors attended daily plant status meetings to maintain '

i awareness of overall facility operations and reviewed operator logs to verify operational safety and compliance with Technical Specifications (TSs). Instrumentation and safety system lineups were periodically reviewed from control room indications to assess operability. Frequent l plant tours were conducted to observe equipment status and housekeepin !

, Deviations Reports (DRs) were reviewed to assure that potential safety

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concerns were properly reported and resolved. The inspectors found that :

daily operations were generally conducted in accordance with regulatory

requirements and plant procedures.

l 01.2 Unit 1 Core Offload Activities Insoection Scope (71707)

On May 19, the inspectors observed core offload activities in the containment and in the fuel handling building.

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The inspectors verified that a Senior Reactor Operator (SRO) supervised the evolution and that direct communication between the control room, spent fuel pit, and manipulator crane station was functional. While in containment, the inspectors observed that direct communication was

. briefly lost and the SR0 immediately suspended fuel movement until

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communication was restored. The inspectors verified the source range ;

neutron flux monitor channel functional test was performed eight hours

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prior to the start of core alterations as required by TS. Additionall the audible source range indication in containment was observed to be operational. The inspectors observed that 3rocedures were properly follcwed, including effective use of self-clecking techniques at the

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manipulator crane, and that operator knowledge of core offload activities was excellent. During the inspection, foreign material exclusion practices were observed and no problems were identified. The inspectors observed that the Fuel Handling Report, which tracked the removal of fuel assemblies from the reactor core to the spent fuel pit, i was effective for controlling refueling activities, c. Conclusions I

The inspectors concluded that TS requirements for core offload were met i and that core offload activities were carefully controlled by knowledgeable personne .3 Alternate Core Coolina Assessment Review a. Inspection Scope (71707)

On May 27, the ins ctors reviewed procedures used to determine alternate core coo ng methods to be used in the event that cooling by the Residual Heat Removal (R4R) system was lost. The following procedures were reviewed: 1-G0P-13.0, " Alternate Core Cooling Method Assessment," Revision 7, and 1 G0P 13.1, " Alternate Core Cooling Method i Assessment Guidelines." R uision 7. The inspectors discussed these i procedures with the Shift Technical Advisor (STA) and interviewed i several operator ;

b. Observations and Findinas I During the inspection, Unit 1 was in Mode 6 with the reactor core fully loaded. The reactor cavity inventory was reduced (i.e, less than 23 l feet above the reactor vessel flange) in preparation for setting the reactor vessel hea The inspectors noted that there were three primary backup cooling modes l

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and one secondary backup mode identified in the alternate core cooling assessment procedures. The primary modes in order of preference included natural circulation via the Steam Generators (SGs), reflux l boiling, and forced feed and spill from either low head or high head l safety injection systems. The secondary backup mode was gravity feed and spill from the Refueling Water Storage Tank (RWST). Forced feed and

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spill using low head safety injection was the preferred backup cooling mode in effect at the time of the inspectio The inspectors discussed the backup core cooling modes with the STA, who I was responsible for assessing the preferred backup mode, and found that the STA was knowledgeable. The STA was also responsible for calculating the estimated time to core boiling. The inspectors interviewed several '

operators during the course of the Unit 1 outage to determine their l familiarity with the preferred core cooling options and found that all l the operators were aware of the preferred option in effect and the i estimated time to core boiling. The inspectors noted that operations l placed an additional visual aid in the control room that effectively I

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l informed the operators, in part, of the preferred backup cooling source I and the time to core boilin l The inspectors discussed with several operations personnel the available control room indications for determining the status of RHR and core coolant temperature and found that sufficient indications existed and that operator knowledge and sensitivity to the loss of RHR was appropriat l c. Conclusions  !

The inspectors concluded that the procedures for determining alternate core cooling options to be used upon the loss of RHR were goo Operators were aware of the alternate core cooling o)tions, the time to ,

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core boiling, and actions to take upon the loss of t1e RHR syste l 01.4 Unit 1 Reactor Cavity Fill a. Insoection Scope (71707)

The inspectors reviewed the circumstances surrounding a aositive reactivity change with a source range instrument inoperaale for testin b. Observations and Findinas On May 16, at 9:41 p.m., the Unit I reactor vessel head was removed for refueling and a reactor cavity fill was commenced using borated water from the RWST. At 9:57 p.m., source range instrument N31 was removed from service to perform a channel functional test. At 10:14 p.m., the channel was returned to service and the other source range instrument N32 was removed from service to perform a channel functional test. The instrument was returned to service at 10:28 p.m. The operator logs properly reflected that TS 3.9.2 Action Statement requires suspension of core alterations or positive reactivity changes when a source range instrument was out of servic RWST boron concentration during the cavity fill evolution was approximately 2345 pp Reactor Coolant System (RCS) boron concentration prior to commencing the reactor cavity fill was approximately 3300 pp Subsequent to returning both source range instruments to service the operating crew questioned whether the addition of the lower concentration RWST water to the RCS was a positive reactivity change. The RWST boron concentration met the requirements of TS 3.9.1, Boron Concentration, that requires a boron concentration of at least 2300 ppm with the reactor vessel head unbolted or removed. The operating crew initiated a DR report to document the potential failure to meet the TS requirement for no positive reactivity changes with a source range instrument out of service. One source range instrument was always available during the cavity fill evolution and adequate shutdown margin was maintained. At no time during the fill evolution did RCS boron concentration drop below the 2300 ppm TS requirement. The

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operating crew failed to associate the addition of a borated water

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source at a lower boron concentration as a positive reactivity change.

This non repetitive, licensee identified and corrected violation is

, being treated as an NCV consistent with Section VII.B.1 of the NRC Enforcement Policy. This item is identified as NCV 50 338/97004 0 Conclusions An NCV was identified for failure to meet the requirement of TS 3.9.2 to suspend positive reactivity changes with an ino>erable source range instrument. The operating crew exhibited a lacc of understanding in 4 that they did not associate addition of the RWST water at a lower boron concentration than the RCS boron concentration as a positive reactivity additio .5 Inocerable Containment Gaseous Radiation Monitor Inspection Scooe (71707)

The inspectors reviewed the circumstances surrounding an inoperable

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Unit 1 containment gaseous radiation monitor, Observations and Findinas On May 24, during performance of Periodic Test Procedure 1 PT 38.1.6,

" Containment Radio Gas Monitor (RMS-160) Functional Test," the high high setJoint was found out of tolerance by a factor of ten (2.7E4 cpm versus

2.7 E3 cpm) . TS requires that the setpoint be less than or equal to 3.6E3 cpm when the unit is in Mode 6. At the time of discovery Unit I was defueled. The setpoint was reset properly and a DR was initiated to document the incorrect setpoint.

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The radiation monitor had been calibrated on May 12 prior to placing the containment purga system in service. Review of the completed calibration procedure determined that the high high setpoint had been incorrectly set during the calibration. The Instrumentation and Control (I&C) technician who performed the calibration had misread the setpoint i as 27E3 cpm as op)osed to 2.7E3 cpm. From May 14 to May 20, the unit

. was in Mode 6 wit 1out the containment purge and exhaust system being secure The containment particulate radiation monitor and the manipulator crane radiation monitor were both operable during the time frame that the

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containment gas monitor was inoperable due to the incorrect setpoint.

Both of these monitors could have isolated the containment purge and exhaust system on detection of a high radiation condition as required by the TS. The high alarm setpoint was set correctly and Abnormal Procedure 0 AP 30. " Fuel Failure During Handling," required a manual isolation of containment ventilation if a high radiation alarm occur .

The licensee revised the controlling procedure to require inde>endent verification of the value transcribed into the instrument cali) ration

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procedure. This non-repetitive licensee identified and corrected j violation is being treated as an NCV consistent with Section VII.B.1 of the NRC Enforcement Policy. This item is identified as NCV 50 338/97004 02, Conclusions An NCV was identified concerning operation of the containment purge and

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exhaust system with an inoperable radiation monitor. The I&C technician misread the setpoint during calibration and failed to note that the step specifically stated that the setpoint had to be less than 3.6E3 cpm to meet TS requirements.

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01.6 Unit 1 Turbine Roll and Synchronization Insoection Scope (71707)

On June 10 cnd 11. the inspectors observed operators preparing for and rolling the main turbine and placing the main generator online after a l scheduled RF0.

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, Observations and Findinas

, The inspectors observed that a " super crew" was used in the control room

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which included, in part, four Reactor Operators and four SR0s.

i Additionally, the inspectors noted that the Operations Superintendent

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was present to provide management oversight. Although the control room was somewhat crowded at times, the inspectors concluded the use of extra operators was effectiv Communication practices during the activities were inconsistent. For

. complex evolutions such as the turbine roll and unit synchronization, the inspectors observed that communication was good. During more routine activities, such as annunciator response, communication was less formal. The inspectors noted that the turbine generator operator often addressed the operating crew as " team" prior to making an announcemen The inspectors concluded that this practice was effectiv Supervisory oversight was appropriate. The inspectors observed that a designated SR0 was assigned to the turbine generator evolutions and local plant operations in the secondary plant. Operations management was observed to provide positive input and guidance during challenging portions of the restar Operation of the plant was carefully controlled. In particular, the ins)ectors noted an effective use of self checking techniques by the turaine generator operator when rolling the main turbine and synchronizing the main generator. The reactivity control operator carefully monitored reactor powe The inspectors noted that the operators were not significantly challenged by unexpected secondary plant equipment failure .

c. Conclusions The inspectors concluded that the main turbine roll and unit synchronization were carefully controlled, supervisory oversight was appropriate, but noted crew communication practices were inconsisten Overall, execution of activities resulted in a smooth transition from Mode 2 to the main generator being placed in servic .7 Unit 1 Power Escalation a. Insoection Scope (71707)

The inspectors monitored and reviewed activities associated with the Unit 1 power escalation from 30 percent to 100 percent power following completion of a scheduled RF b. Observations and Findinas Power escalation commenced on June 11. On June 14, power had been increased to approximately 75 percent when the decision was made to reduce power to approximately 50 percent to allow the A main feedwater pump to be secured to repair the inboard bearing slinger ring. A power reduction was commenced at 1:33 a.m., and power was reduced to approximately 49 percent at 3:29 a.m., and the > ump was secured. The inboard bearing slinger ring was re service at 6:15 a.m. that same day. paired A powerand tie pump increase waswas returned to initiated following the return to service of the A main feedwater pum At 6:10 p.m., on June 14, a power reduction from 87 percent power was initiated due to a secondary steam leak from a mechanical joint in the 1A extraction steam line. Power was reduced to approximately 55 percent and the 1A feedwater heater was isolated to allow the extraction steam line mechanical joint to be inspected. The licensee determined that the gasket had failed resulting in the steam leak. The licensee installed a

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new gasket in the connection and returned the 1A feedwater heater to service. The licensee then removed the IB feedwater heater from service to inspect the similar gasket in the 1B extraction steam line. The gasket was replaced and the IB feedwater heater was returned to servic A power increase from 55 percent power was initiated at 5:00 a.m., on June 15, following gasket re)lacement activities and subsequent return to service of the feedwater 1 eater On June 17, 100 percent power was achieved at 12:44 p.m. During the power increase from approximately 96 percent power, low pitched harmonic flow noises were heard from the Number 4 main turbine governor valv The noise was attributed to the fact that the governor valve was operating at a lower position in the flow stream than in previous cycles due to the replacement of the moisture separator reheaters during the RF0. On June 18, power was reduced to approximately 96 percent to reduce the flow induced noise and vibration on the Number 4 main governor valve. The unit remained at approximately 96 percent for the

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3 remainder of the reporting period while the licensee evaluated the operation of the Number 4 main governor valv Conclusions i

Unit 1 power escalation following return to service from the RF0 was I hampered by secondary side equipment problems and failures that required power reductions. The decision to reduce power to 96 percent to reduce flow induced noise and vibration on the Number 4 main turbine governor valve was appropriat Operational Status of Facilities and Equipment l

02.1 Safety In.iection (SI) System Accumulator Walkdown Inspection Scone (71707)

On June 3 and 4, with Unit 1 in Mode 5, the inspectors performed a walkdown in the containment of accessible components associated with the

. Unit 1 SI system accumulators. The walkdown encompassed the main discharge )ath and support systems including portions of the nitrogen supply, ma(eup from primary grade water, accumulator level instrument piping and associated transmitters, accumulator sample and test lines, and miscellaneous vents and drains. The inspctors referenced the system piping and instrument diagrams and valve checkoff lists for proper system alignment and component description Observations and Findinas The inspectors checked system hangers and supports, general housekeeping of the area around the accumulators, breaker compartments for the accumulator discharge valves, and control room indications. While inspecting the breaker compartment for the B SI Accumulator Discharge Valve,1 SI M0V 1865B, the inspectors found that the A 3hase motor lead connection heat shrink was loose. The licensee issued JR N 97-1704 to document the as found condition and determined that no operability concern existe The inspectors found that all valves were in their required positions, but noted several equipment deficiencies. The following deficiencies were identified and discussed.with the license The A SI Accumulator Discharge Isolation Valve,1-SI M0V 1865A, open limit switch flexible electrical conduit was broke The B SI Accumulator Discharge Isolation Valve,1 SI H0V-1865B, was not labeled properly and the open limit switch flexible electrical conduit was broke The B SI Accumulator Makeup Isolation Solenoid Valve,1-SI-SOV-18518, flexible electrical conduit was broke . .- .- - -. .- _ _ . .. .-. .. - - -

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Drain valve 1 SI-298, associated with level transmitter 1 SI LT-1926, had minor active leakage coming from the pipe cap.

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The inspectors discussed the open limit deficiencies with operations and engineering personnel and determined that the deficiencies affected

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inputs to the Valve Monitor Light (VML). The VML receives input from all three accumulator discharge isolation valves and illuminates when all three valves are open. The light is used by operators to meet TS 4.5.1.a.2 which requires verification of valve position every 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> The individual discharge isolation valve position indicators are

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internal to the valve motor and were not affected. The inspectors

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verified that the licensee took appropriate corrective actions for the deficiencies identified prior to closing containment. The inspectors

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e also observed that the VML was functional.

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The inspectors concluded that the SI system accumulators were properly aligned and in generally good condition. The inspectors identified

several equipment deficiencies, none affecting system operability. The

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deficiencies were corrected by the licensee prior to containment close ou '

08 Miscellaneous Operations Issues (92901, 92700)

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0 (Closed) VIO 50 338/96003 03: Failure to comply with TS 3.0.4 mode

change made with inoperable BIT heat tracing circuit. The inspectors verified that the corrective actions described in the licensee's response letter, dated June 3,1996, to be reasonable and properly implemente No similar problems were identifie .2 (Closed) VIO 50 338. 339/96006 02

Failure to follow procedures for gas stripper operations on June 26, 1996. The inspectors verified that the corrective actions described in the licensee's response letter dated August 23, 1996, to be reasonable and properly implemente .3 (Closed) Licensee Event Reoort (LER) 50 338/97-04: Hi hi alarm setpoint for 1-RM-RMS 160 found out of tolerance due to personnel error. This item is discussed in Section 0 II. Maintenance M1 Conduct of Maintenance M1.1 Inside Recirculation Soray Pumos Operability Test a. Insoection Scope (61726)

On May 21, the inspectors observed portions of 1 PT 64.8, " Flow Test of the Inside Recirculation Spray Fumps," Revision 7. The purpose of the test was to ensure TS 3.6.2.2 and 4.0.5 requirements were satisfie . _ _ _ _ __

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b. Observations and Findinas The inspectors reviewed the pre job brief checklist and found that the individuals involved with the test inside containment were on the attendance list and had been briefed by the unit SRO. The inspectors observed that appropriate radiological practices were followed and that all instrumentation used during the test for pump flow, discharge pressure, amperage, temperature, and vibration was properly calibrate The inspectors reviewed past surveillances to note any adverse pump performance trends and found no problem While flow testing the B pump, the inspectors observed that the high and low pressure instrument taps for the temporarily installed flow transmitter were reversed causing unexaectedly low voltage reading The instrument technician discovered t1e problem and reported it to the operator conducting the test. The decision was made to restart the test for the B pump after correcting the transmitter tap alignment proble The inspectors observed the completion of the test and expected pump flow was obtained. The inspectors checked the A pum) test equipment, which was still connected, and found no problems. T1e licensee submitted DR N 97-1414 to address the instrument tap connection proble c. Conclusions

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The inspectors concluded that TS requirements were met for the Unit 1 inside recirculation spray pump operability tes M1.2 JJ and 1H EDG 24 Hour Run Tests a. J.D.spection Scope (61726)

On June 5 and 6. the inspectors observed operators performing portions of 1-PT 83.7H "1H EDG 24 Hour Run," Revision 3, and 1-PT-83.7J, "1J EDG 24 Hour Run," Revision 3. The inspectors observed both control room and local operation of the EDGs. The purpose of the tests was to satisfy TS 4.8.1.1.2.d.7 and 4.8.1.2 requirement b. Observations and Findinas The inspectors noted that both EDGs were run simultaneously and that a designated control room operator was assigned to each ED Additionally, the immediate area near the EDG controls was restricted to minimize operator distractions while monitoring the running EDGs. The 03erators followed procedures and carefully monitored EDG operatio T1e inspectors concluded that control room operation of the EDGs was carefully controlled and that supervisory oversight was appropriat The inspectors monitored both 1J and 1H EDG operation locally and found no unusual oil leaks, machine noises, er unexpected control respons The inspectors, however, noted that the 1H EDG turbocharger air unbalance check valve fluctuated when operating at approximately 2500 kW. The function of the check valve is to swap scavenging air from the

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engine _ blower to the turbocharger at approximately seventy five percent l load. The inspectors discussed the condition with the EDG vendor representative and with the licensee and determined that the fluctuations were normal when engine load was at the transition aoint between supplying scavenging air from the engine blower versus t1e turbocharger. In order to minimize the fluctuations, operations raised operation of the EDG to approximately 2600 kW. During the EDG run, the )

inspectors observed local o>erators performing routine engine checks in t accordance with 1 LOG 12. " Emergency Diesel Generator LOG (Operating),"

Revision 13, and found that the operators were knowledgeable of the required engine checks and that accurate data was recorde c. Conclusions l The inspectors concluded that TS requirements were satisfied during the 1H and 1J EDG 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> runs and that EDG operation was carefully controlle M1.3 Turbine Driven Auxiliary Feedwater (AFW) Pumo Test a. Insoection Scope (61726)

On June 9, the inspectors observed operators performing portions of ,

1-PT 71.10. " Turbine Driven Auxiliary Pump and Valve Test," Revision 19- i P b. Observations and Findinqs During the pump o)erability portion of the test, the inspectors observed that the pump out)oard packing gland exhibited no seal water leakoff flow once the pump was started. The inspectors noted from discussions with local operators that leakoff had been observed prior to the pump star The inspectors discussed the lack of seal water flow with engineering and maintenance who expeditiously assessed that the packing gland had not overheated and that no adjustment was needed to restore leakoff flow. The decision was made to continue with the test. Once the pump was secured the inspectors observed a steady stream of leakoff flo; Subsequent to the test, operations requested that engineering perfe w an o)erability evaluation which was documented in Engineering Transmittal (ET) No. SE 97101, " Review Seal Water Flow to the Outboard Packing Gland of 1 FW P 2," Revision 0. The conclusion of the evaluation was that no operability concern existed and that adequate seal water flow existed during the test although no leakoff was observed while the pump was runnin The inspectors had been previously informed by the licensee during previous operability tests that some leakoff was needed to ensure the packing gland does not overheat. The inspectors reviewed 1 PT-71.10, Step 6.4.18.b which stated that proper seal flow to the packing gland

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is exhibited by a " steady gentle stream (or drip) flowing from the seal packing gland."

Step 6.4.18.b was not aerformed by the operator and was not required to be performed because tie valve locking mechanism to the seal water supply was intact. If the locking mechanism is not intact, several actions are performed to restore proper seal water flow. The step assumes that if the seal water supply valve locking mechanism had not been disturbed then adequate flow would exis The inspectors discussed Step 6.4.18.b with engineering and it was determined that the packing gland should exhibit some degree of leakby as defined in the step. Engineering further stated that 1-PT 71.1Q would be revised to better clarify the requirements of proper seal water i flow to the packing glan c. Conclusions The inspectors concluded that the licensee's decision to continue running the turbine driven AFW pump without attempting to establish seal water flow was not consistent with the intent of procedure 1 PT-71.1 Engineering determined that, based upon packing gland temperatures, seal water flow to the packing gland was adequat M1.4 1H EDG Failure a. Inspection Scone (62707)

The inspectors monitored licensee actions to repair the 1H EDG following l a failure that occurred during maintenance runs following outage maintenance activities. The inspectors inspected the failed angle drive, observed maintenance activities in progress, reviewed actions associated with the effect of the failure on the remaining EDGs and reviewed the failure mechanism root cause with corporate personnel, b. Observations and Findinas On May 22, while unloading the 1H EDG from a full load maintenance run following outage maintenance activities, the radiator fan shaft sheared at the outlet of the angle drive. The 1H EDG was secured and retagged to determine the cause of the failure. Inspection of the angle drive determined that the internal gear driven oil pump to the upper angle drive bearing was not intact in that the gear driving the pump was not attached to the pump shaft. The gear was found in the bottom of the angle drive oil sump. Loss of the angle drive oil pump resulted in the failure of the upper angle drive bearing and failure of the radiator fan shaf ,

Inspection of the oil pump and gear determined that the gear was originally attached to the shaft by a single set screw and the shaft was mounted in a vertical configuration. The licensee determined that the failure resulted from the gear slipping off the pump shaft during j

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. operation of the EDG. The oil pump had not becn disturbed during the

' outage maintenance activities and the activities performed on the angle drive were in accordance with vendor recommendations. The licensee replaced the radiator fan shaft and the angle drive with a refurbished angle drive obtained from the vendor. The refurbished angle drive oil  :

'.

pump was inspected and found to have a dimple on the pump shaft to prevent slippage of the gear and double set screws were installed with  !

lock tight to arevent the setscrew attaching the gear to the shaft from 1

backing off. Following replacement of the radiator fan shaft and angle '

drive the EDG was tested and returned to service.

i

- The licensee inspected the angle drive oil pumps on the other three EDGs following repair of the 1H EDG. The oil pump gears were found securely

attached to the pump shaft on the other EDGs and the configuration was

! identical to the original 1H EDG configuration (no dimple on the shaft

and one setscrew attaching the gear to the shaft). To prevent possible future failures of the angle drive gear driven oil pumps the licensee i decided to dimple the shafts and install a second setscrew on the

remaining EDGs. At the completion of the inspection period all but one j- EDG angle drive oil pump had been configured to the new configuratio j

!

! Conclusions I

, l

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I Repair activities associated with the failure of the 1H EDG angle drive

were accom311shed in a professional manne Licensee actions to inspect i i the other EDG angle drives and modify the configuration of the gear driven oil pump to prevent slippage were appropriate and demonstrated a

safety conscious approach to operatio M1.5 Inservice Inspection (ISI) (Unit 1)

l Inspection Scope (73753)-

The inspectors observed inspection activities and reviewed arocedures

and documentation relative to the conduct of (ISI) during t1e Spring l' 1997. Unit 1 Outage.

i Observations and Findinas

! North Anna Unit 1 was in the second outage of the second period of the

, current inspection interval. The Code of Record for ISI activities during the current interval was the 1986 Edition, Section XI American Society of Mechanical Engineering (ASME) Boiler and Pressure Vessel Cod The inspectors reviewed the following ISI procedures for compliance with ASME requirements:

Procedure N Revision & Date Title NDE UT 501 Revision 1, Ultrasonic Examination of Piping January 25, 1996 Welds

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i Procedure N Revision & Date Title NDE-UT-503 Revision Ultrasonic Examination of Vessel January 25, 1996 Welds >2" in Thickness NDE UT 505 Revision 2 Ultrasonic Examination of Reactor January 25, 1996 Coolant Piping Welds NDE-UT-507 Revision Ultrasonic Examination of Nozzle September 12, 1996 Inner Radius Sections NDE PT 501 Revision 2, Liquid Penetrant Examination January 25, 1996 NDE-MT 501 Revision 2 Magnetic Particle Examination January 25, 1996 At the time of this inspection, the licensee had completed the majority of the ISI activities for this RF0. The inspectors witnessed the ultrasonic examination of the two, Class 2, stainless steel piaing welds and the magnetic 3 article examination to the two, Class 2, caraon steel welds identified yelow. The inspectors also reviewed completed examination records for the welds listed belo Line Number Weld Exam Comment

3 CH 71-1502-02 SW 1W UT , PT Elbow to Pipe Weld 3 CH-2 1502-Q2 SW 1W UT ., PT Elbow to Pipe Weld

6 SHP-37-601 02 33 MT 90 LR Elbow to Pipe 6 SHP-38-601 02 SW 63 MT 45 LR Elbow to Pipe 1 RC-E 2 7 UT Pressurizer Shell to Upper Head Weld (190" to 14")

1 RC E 2 3 UT Pressurizer Vertical Seam (8" to 12")

32 SHP 3 601-Q2 SW 1 UT, MT Piping - Wall thickness greater than 1/2 inch 4-RC-14 1502 01 SW 11 UT, PT Piping 4 inch and greater -

circumferential weld 16 WFPD 22 601 02 SW 39 UT, MT Piping - Wall thickness greater than 1/2 inch 1 RC E-2 14NIR UT Pressurizer Spray Line Nozzle, Inner Radius 29 RC-1 2501R 01 SW 8 UT 14" Nozzle to 29" Reactor Coolant Pipe 29 RC 1 2501R-Q1 SW 9 UT 6" Nozzle to 29" Reactor Coolant Pipe l

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3 14

Line Number Weld Exam Comment

a Inspectors Witnessed UT Examination

2 Inspectors Witnessed MT Examination During the observation of ISI activities, and the review of examination

, records, the inspectors noted that the licensee was using a Microsoft i

Access * program for the generation of ISI examination reports. The reports were being generated directly by the ISI examiners.

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A feature of the ISI report generation program was the fact that short-cuts and self-checking steps were built into the data entry form.

! Short cuts built into the system included such things as:

i i . Insertion of social security number, qualification level, etc.,

after examiner's name was entered.

! . Insertion of calibration data for equipment liste . Insertion of identification numbers, etc., for approved examination consumables.

The self checking steps included such things as:

. Verification that the weld identified was on the list of planned inspections. (Also will not allow re inspection of a previously

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completed examination to be overwritten without intervention by supervision.)

. Verification that examiner listed was qualified for the inspection

listed.

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] * Verification of current calibration of examination equipment, and qualification of consumable material '

,

The examination reports were still provided as a printed hard copy, i- signed by the examiner; but problems with legibility had been virtually eliminated.

c. Conclusions

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The Unit 1 ISI inspections were being conducted in accordance with requirements of the TS and the ASME Section XI Code of Record. The use of a self checking computer data management program to generate ISI reports was positiv t

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M2 Maintenance and Material Condition of Facilities and Equipment M2.1 SG Insoection (Unit 1)

i a. Insoection Scope (50002)

{

The inspectors reviewed data and results of SG eddy current inspections i that had been conducted during the current outage.

t b. Observations and Findinas North Anna Unit 1 has replacement SGs with Alloy I 690 thermally treated tubing. In that industry results have indicated good performance of

.

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Alloy I 690 tubing, the licensee established an inspection program plan focused on inspecting one SG per outage. During the current Spring 1997

, Outage, eddy current inspections were conducted in the A SG. These

inspections consisted of

l . 50 percent full length (1796 tubes) bobbin testing

3ercent (326 tubes random selection) hot leg top of

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. 9

tu>esheet focused RPC inspection

. The licensee reported that no crack-like indications were observed, and no conditions were observed which would have required supplemental RPC testing to resolve indications. Manufacturing Buff Mark (MBM) signals

,' were found that were typical of what was observed during the baseline i inspections. MBMs were resolved through comparison of signals with

baseline data per the analysis guidelines, i During the comparison of an MBM signal-in tube R21 C23, the licensee found that the baseline data did not match the current data. Further review showed that an adjacent tube showed the same signal signature as

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the baseline data for tube R21-C23. During the data review of 38 adjacent tubes, an additional tube R22-C23, was also found to not have

baseline data.

The licensee's investigation of the problem discussed the following i considerations.

,

. Since the SG replacement baseline inspections,100 percent of SG A and 50 percent of SG B and C tube have been inservice inspected.

~

i . All tubes with MBH signals in SG A have been compared with

baseline data, with only the two tubes mentioned above without

baseline data.

. During inspections of the 50 percent sample from SGs B and C, over 600 MBM indications have been compared with baseline dat . During review of baseline inspection records, the licensee noted that tubes R21-C23 and R22 C23 were recorded as having been

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inspected in sequence and were als; ine last two tubes inspected

prior to a shift chang The licensee has determined that the failure to conduct baseline i inspections of the two SG tubes constitutes a violation of the )lant TS, and is therefore preparing LER, N1 97-005 00, for submittal. T1e i

licensee has completed a review of the scope and circumstances of the violation, and completed corrective actions. This non repetitive, licensee identified and corrected violation is being treated as an NCV

',

consistent with Section VII.B.1 of the NRC Enforcement Policy. This j item is identified as NCV 50 338/97004 0 c. Conclusions

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Licensee programs and procedures for dealing with findings of Steam '

Generator eddy current examinations were consistent with current

, industry practice. An NCV was identified for not performing baseline

.

inspections on two SG tubes. Investigation and evaluation of missed

, baseline inspections for two SG tubes were thoroug >

M8 Miscellaneous Maintenance Issues (62700, 92902)

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M8.1 Corrective Action for Eauioment Problems a. Inspection ScoDe (62700)

This portion of the inspection was conducted to review the licensee's corrective actions for equipment problems. The inspection was conducted i primarily through the review of corrective actions for hardware problems

identified on station DRs. In order to complete the inspection, the licensee was requested to provide a listing of all station deviations

, written in 1997. This listing was reviewed by the inspectors in an

. effort to select a sample of hardware deviations for a more detailed ,

, review of corrective actions, and also to identify any trends in equipment performance. The inspectors selected e sample of a approximately fifteen deviations.and completed a detailed review of corrective actions. The inspectors also reviewed the Deviation Trending i Reports dated February 24, 1997 and May 5, 1997, in order to determine

"

. if the licensee was identifying and responding te, negative trends in

'

equipment performance which were observed by the inspectors. The inspectors also reviewed the licensee's procedures appliccble to this area, which included Virginia Power Administrative Procedure (VPAP)-

1601, " Corrective Action," Revision 6 and VPAP-1501, ' Deviation Reports," Revision 7. In addition, in order to understand the licensee's perspective in this area, the two most recent self assessments of the maintenance area were reviewed (Nuclear Oversight Audit 9610 and the 1996 Maintenance Program Self Assessment).

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b. Observations and Findinas The inspection identified that there were no problems noted during the

review of the correctiva actions for the sample deviations. Review of i

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the trending of deviations determined that adverse trends were being appropriately identified, and corrective actions for the identified

,

trends were being adequately implemented. Trending of deviations was assessed as a strength in the licensee's corrective action progra Corrective actions for the audit and assessment that were reviewed were determined to be appropriat l i

c. Conclusions No 3roblems were observed regarding corrective actions for equipment <

'

pro)lems. Trending of station deviations and corrective action for identified adverse' trends were assessed as a strengt M8.2 (Closed) Insoection Followu) Item (IFI) 50 338. 339/96012 08: Review functional tests that will )e conducted on new or old snubbers during Unit 1 RF0. This IFI was the result of an inspection of large-bore snubber testing during the last Unit 2 outag The North Anna Unit 1 TS states that, "At least once per 18 months 4 during shutdown, 10 >ercent of the large bore snubbers (snubbers greater

' than 50 kips) shall >e functionally tested either in place, in a full snubber bench test, or in a snubber valve block bench test. For each large bore snubber that does not meet the functional test acceptance criteria of Specification 4.7.10.d. an engineering evaluation is

'

required to determine the failure mode. If the failure is determined to be generic, an additional 10 percent of that type of snubber shall be functionally tested." In that there are six, 1000 kip and six, 1900 kip

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snubbers in each unit, the 10 percent sample consists of one snubber of each size.

i The large bore (1000 and 1900 kip) snubbers in Units 1 and 2 were installed in the late 1980's as a result of the licensee's snubber reduction program. As a result of problems identified during the Unit 2

'

large bore snubber testing, the licensee decided to functionally test i

the four large-bore snubbers in Unit 1, in lieu of the two snubbers that were required to be tested to meet the TS 10 percent sample requirements. This decision was based on the fact that these four

snubbers were the only ones that had not been tested since they were put

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into service by the design change. Gne of the snubbers that was originally not scheduled for testing this outage, failed to lock up

. during in situ testin The inspectors reviewed documentation involved with the testing of Unit

. 1 large bore snubbers. This documentation consisted of:

. An assessment of the Unit 2 failures in response to DRs 96 2135 and 96 175 * ET No. CE 97 042 Unit 1 Large Bore Snubber Evaluation, 1997 RF .

• Response to DR 97 1260.

.

.

)

t The inspectors concluded that the engineering analyses of the snubber !

failures experienced during the Unit 1 and Unit 2 RFOs were !

comprehensive, and that the licensee actions were conservative. The j inspectors also noted that DR 97-1260 corrective action evaluation by i the licensee's Maintenance Rule working grou) has determined that an (a)(1) evaluation was to be done, and that t1e results of the snubber 1 functional testing will be monitored under the Maintenance Rule for the i next two RFOs for each unit. This IFI was closed because of the i licensee increased monitoring under the Maintenance Rul I

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III. Enaineerina

]

El Conduct of Engineering E1.1 Modification to Solid State Protection System (SSPS)

a. Insoection Scooe (37550)

The inspectors reviewed a modification to the SSPS on Unit 1, including i the quality documentation and modified hardware. The modification was 1 performed under Design Change No.97-108, "SSPS Under Voltage Driver Board Modification / NAPS /1." Applicable requirements included 10 CFR 50.55a(h) Protection System b. Observations and Findinas

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The modification was to remove unused circuit elements from the undervoltage driver cards as recommended by Westinghouse Electric Corporation. The purpose was to help avoid unnecessary reactor trip j Transistors on the undervoltage driver card are directly connected to the reactor trip breaker undervoltage trip device. Two modified cards !

were installed and one was placed in stores. The modification was complete at the time of the inspection except for the final TS surveillance test. The system was not required to be operable for the current operational mode of the plan !

The inspectors found that the on-site engineering organization took care in preparing the design package, including the safety evaluation, 10 CFR 50.59 evaluation and test requirements. The ins)ectors had no comments on the documentation. The inspectors observed tlat the modified !

undervoltage card in stores had been modified with excellent skill and craftsmanship (the card was examined with the use of anti static equipment). The inspectors confirmed that diode Z1 and quad and gate CR38 were removed, and the inspectors also checked the card part numbe .

The insaectors confirmed that the removed circuit elements were in fact !

unused ay examining the drawing and the actual pin connections on card A515 in cabinet 1 EI CB 47 The inspectors reviewed completed Work Orders (W0s) 361342-03, 04, 05, and 06 in the records building, and observed that only one anomaly was noted on the W0s. The anomaly was that one card was not mcdified as ,

intended because it did not pass the visual pre inspection. This meant i

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19 i that one less spare was available. The inspectors reviewed the original 0)erational Readiness Review Package for W0s 361342 01 and 02, and

o) served that the modification was awaiting final testing before being close c. Conclusions The inspectors concluded that the reviewed modification to the SSPS was technically sound. Inspection observations and findings on this safety significant, relatively simple modification indicated good design

,

contro i

E1.2 Control Rod Draa Testina

$ a. Inspection Scope (37551)

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On May 23, the inspectors observed control rod drag testing in i accordance with 0 0P 4.29. "RCC Drag Testing In Irradiated Fuel Assemblies," Revision 2.

$ b Ob.servations and Findinas

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The inspectors discussed the testing methodology with fuel performance

analysis support personnel and observed several rod tests. The test i

procedure and associated test equipment used appeared to properly

evaluate drag forces between the control rod and the fuel assemblies.

.

The inspectors verified that test equipment used was properly calibrated i and that operators executed the test procedure properly. The inspectors

<

also reviewed the completed test results with corporate engineering i

'

personnel. Test data obtained was well below the established acceptance criteria.

} c. Conclusions

. The inspectors concluded that the control rod drag testing methodology

a)peared to adequately test for control rod drag forces. Test data

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o)tained was well below the established acceptance criteri ,

E1.3 Main Feedwater Check Valve Reolacement i

a. Insoection Scoce (37551)

The inspectors monitored activities associated with the replacement of the Unit 1 main feedwater check valves.

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b. Observations and Findinos i -

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During the RF0, the licensee replaced all three main feedwater check valves due to seat leakage during previous operating cycles. The

inspectors monitored activities in progress at the job site during the

] replacement activities and reviewed the work package documentation at

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the job location. No discreaancies were identified and the inspectors !

verified that all three chec( valves were replace l

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c. Conclusions i The Unit 1 main feedwater containment check valves were replaced during the RF0 as scheduled. The check valves were replaced due to seat leakage. No discrepancies were noted during observed work activitie .

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E1.4 Moisture Separator Reheater (MSR) Replacement Safety Evaluation, a. Insoection Scope (37551)

The inspectors reviewed the safety evaluation associated with the replacement of the Unit 1 MSRs to verify that possible effects on the primary plant were addresse b. Observations and Findinas The inspectors redewed Safety Evaluation 97 SE M00 08, " Moisture l Separator Rehe: iter Keplacement." The safety evaluation determined that the replacement 6ctivity sould not affect reactor power and that reactivity would not be cdeersely affected. The inspectors discussed the modification with engineering personnel and verified that possible effects on the primary plant were considered during the review of the modification for implementatio c. Conclusions The inspectors concluded that the possible effects on the primary plant l due to replacement of the Unit 1 MSRs were addressed in the safety I evaluation associated with the modificatio !

E8 Miscellaneous Engineering Issues (92903, 92700)

E8.1 Condition of Safety-Related Batteries: NRC Inspection Report Nos. 50-338, 339/96 12, Section E2.3, " Condition of Safety-Related Batteries," )

contains the following conclusion: j l

A detailed cell ins)ection was performed on each cell of all j the safety related aatteries. The inspectors concluded that ,

battery maintenance met requirement However, the j inspectors observed significant sedimentation in two cells, i The inspectors concluded that the sedimentation had been present on June 4 the time of the last surveillance l inspection. Therefore, the fact that the surveillance did 4 not record any problems with sedimentation was considered a weakness in the implementation of that inspection.

t During this inspection period, the Electrical Systems Manager described j the enhanced battery inspection program to the inspectors. The program !

now includes semiannual detailed inspections of all battery cells by the I

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responsible engineer, including a full report. For any problem cells identified in the semiannual inspections, the monitoring is enhance If unusual sedimentation is observed, an inspection of sedimentation is performed at least monthly. Seven cells were in this category. Also, for selected potential problem cells, weekly monitoring of individual cell voltage and specific gravity is invoked. Three cells were in this category, Cell No. 1-IV 60, which was mentioned in the 96 12 report, was replace The inspectors concluded that the weakness observed in the 96-12 inspection related to battery cell ins)ections has been addressed by the licensee. The enhanced program descriaed above was stron E8.2 (Closed) IFI 50-338. 339/96012 05: Battery service test and rating of diesel generator breaker close coil. The inspectors observed that the licensee had a voltage criterion at the 10 second point in the battery service test. The purpose of the test criterion was to demonstrate that the diesel generator breaker close coil received voltage above its rated minimum pick up voltage, which was 70 VDC. The inspectors also observed that, since the voltage measured during the battery service test at the 10 second point was slightly less than the criterion, a test was

)erformed on the breaker which demonstrated operation at about 40 VD :our items related to this situation were identified by the inspectors for follow up: three items involved details of the test procedures and one was to review any new test result The licensee evaluated the items in the inspection report, and prepared Engineering Transmittal Report ET No. CEE-97-021 Adequacy of Voltage for Diesel Generator Breaker Close Coil. The inspectors reviewed the report and found that the concerns of the IFI were resolved. The report recommends revising certain test procedures, and the inspectors observed that this was beir.g tracked in the Commitment Data Tracking System as Commitment No. 02 97 0500 006. No battery service test had been performed since inspection 96-1 E8.3 (Closed) Unresolved Item (URI) 50 338. 339/96012 07: Control of set Joints for molded-case circuit breakers. Although, a small sample of areakers were inspected, and no incorrect set points were identified, the inspectors raised the issue of whether the controls on set points for molded case circuit breakers were adequate. At that time, the licensee stated they believed their controls were adequate. A URI was established to further review the licensee's program in this area in terms of NRC requirements and site specific commitments. Since that time, Corporate Nuclear Engineering reviewed this issue and prepared a report. The inspectors did not review this report as it was in preliminary status. The Superintendent of Site Engineering told the inspectors that the report will conclude that controls on the set points for molded case circuit breakers should be enhanced, and that this recommendation will be implemente Since no incorrect set points were identified and setpoint controls will be enhanced, this issue was resolved. The details and schedule for the new controls on molded-case breaker set points is identified as IFI 50 338, 339/97004-04.

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IV. Plant Supoort~  !

l R1 Radiological Protection and Chemistry (RP&C) Cor.trols

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R1.1 Postino of Notices to Workers

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a. Inspection Scoce (71750)

On May 29, the inspectors verified the licensee's adherence to 10 CFR 19.11, " Posting of Notices to Workers."

b. Observations and Findinas

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l

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The inspectors reviewed VPAP-2802, " Notifications and Reports,"

Revision 6, to determine the posting locations of 10 CFR 19.11 l

, requirements, including NRC Form 3. The following plant areas required i j postings:

]

Main Security Access Secondary Security Access (when activated)

Site Construction Office Building - North (SCOBN)

Radiological Control Access log in area {

Training Building i The inspectors toured these areas to ensure the required postings were present and found all the required documents to be in place and not i defaced or altered. The postings were located in appropriate areas to permit workers engaged in licensed activities to observe them on the way to or from their assigned work are !

c. Conclusions

The inspectors concluded that the requirements of 10 CFR 19.11 for postings of notices to workers were properly implemente R1.2 Occupational Radiation Exposure Control Proaram a. Insoection Scope (83750)

The inspectors reviewed implementation of selected elements of the licensee's radiation protection program during a segment of the Unit 1 RF0. The review entailed observations of radiological protection activities including pre work briefings, personnel exposure monitoring, waste storage and disposal, radiological postings, and verification of msted radiation dose rates and contamination levels within the ladiologically Controlled Area (RCA). Those activities were evaluated for consistency with the requirements for program scope, occupational dose limits, surveys, personnel monitoring, access control, waste storage and disposal, and radiological posting as specified in Subparts B, C, F, G, I, J, and K of 10 CFR 2 y g-..

. .

)

23 Observations and Findinas The inspectors conducted frequent tours of the RCA to observe radiation protection activities and practices. Personnel preparing for routine entries into the RCA were observed being briefed on the radiological conditions in the areas to be entered. The briefings were given by radiation control personnel before access was granted and covered the dosimetry and the protective clothing and equipment required by the Radiation Work Permit (RWP) for the entry. The administrative limits for the allowed dose and dose rate for the entry were emphasized during the briefings. The briefings provided thorough descriptions of the existing dose rates wnich could be encountered during the entry. The inspectors determined that personnel entering the RCA were adaquately briefed on the radiological hazards which could be encountered while in the RCA and the radiological protective measures required to be taken during the entr The inspectors observed the use of personal radiation exposure monitoring devices by personnel entering and exiting the RC Thermoluminescent dosimeters were used as the prim 6ry device for monitoring personnel radiation exposure. In addition, Digital Alarming Dosimeters (DADS) were used for monitoring the accumulated dose and the encountered dose rates during each RCA entry. The DADS were set to alarm at administrative limits established for the specific RWP under which the RCA entry was being made. As the individuals exited the RCA the accumulated dose and encountered dose rate information was transferred from the DADS to the Personnel Radiation Exposure Management System (PERMS) data base in order to track individual exposures. During tours of the RCA, the inspectors noted that the required dosimetry was being properly worn by personnel when entering and while in the RC The inspectors also noted that personnel exiting the RCA routinely surveyed themselves for contamination using personal contamination monitor During tours of the RCA, the inspectors noted that general areas and individual rooms were properly posted for radiological condition Posted survey maps were used to indicate dose rates and contamination levels at saecific locations within rooms. At the inspectors * request, a licensee iealth Physics staff member performed dose rate and contamination surveys in several rooms and locations. The inspectors verified that the survey instrument readings were consistent with the dose rates and contamination levels recorded on the posted survey map The inspectors discussed with the licensee their practices for collecting and dis >osing of waste. The licensee indicated that waste generated within t1e protected area remained within the protected area until shipped offsite and that there were no waste storage areas outside of the protected area for waste generated within the protected are The licensee provided the following details regarding their waste handling practices. Contaminated waste generated within the RCA was accumulated and stored in metal boxes (B 25s) or seavans at designated locations outside of the RCA but inside the protected are The

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contaminated waste was then shipped to either an offsite licensed waste I processor or to the Low Level Radioactive Waste Disposal Facility located near Barnwell, SC. Contaminated metal was decontaminated in a building located within the 3rotected area. If the metal was ,

decontaminated below releasaale limits, then it was either transferred

to a reclamation facility or sent to the local county landfil '

.

Otherwise, it was treated in the same manner as contaminated wast !

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Non contaminated waste generated within the RCA was also accumulated and

stored in seavans located inside the protected area and then shipped to l an offsite licensed waste processor for disposal. Non contaminated

. waste generated outside of the RCA but within the protected area was

! collected and stored on a truck parked inside the protected area. When the truck was full, the waste was surveyed, to ensure that no

.

radioactive material was present, and released for disposal at the local county landfill . The inspectors toured the designated waste storage i areas and observed that waste was being stored as described above. The l inspectors also noted that containers of radioactive waste were properly labeled. At the inspectors' request, a licensee Health Physics staff

. member performed dose rate surveys of several waste containers in storage. The inspectors verified that the survey instrument readings

^ were consistent with the dose rates recorded on the labels of radioactive waste containers and that only background levels were indicated from containers of non contaminated waste. The inspectors and

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a licensee Health Physics staff member also toured and surveyed the 1 i onsite landfill which was only used during plant construction. Only

, background levels of approximately 10 microrem per hour were indicated by the survey instrument during the tour.

c. Conclusions  ;

Based on the above reviews, the inspectors concluded that the licensee was properly monitoring and controlling personnel radiation exposure,

storing and disposing of waste, and posting area radiological conditions in accordance with 10 CFR Part 2 I

,

R1.3 As low As Reasonably Achievable (ALARA)

i

, a. Insoection Scope (83750)

The inspectors reviewed licensee records of personnel radiation exposure and discussed outage related ALARA program details, implementation and goals with the licensee. The Unit 1 RF0 related collective dose was compared to licenne established ALARA goal b. Observations and Findinas The inspectors reviewed ALARA program details, implementation, and goals for the Unit 1 RF0. Based on the scheduled activities, daily and cumulative exposure projections were established for the planned 30 day outage. The calculated projection for the outage cumulative dose was 123.47 man rem but licensee management challenged the staff to attempt to limit the outage cumulative exposure to 100 man rem. Individual a

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exposures, based on data from DADS and PERMS, were summarized by RWP on a daily basis and allocated to the various organizational de Daily reports of the collective and departmental exposures, partments.along with

their respective challenge goals were issued for monitoring purpose ? lots of daily and cumulative exposure versus their respective challenge goals were also distributed daily. The inspectors noted that, as of day

'2 of the outage, the cumulative outage exposure was meeting the unagement established challenge goal.

' c. Corelusions Based en the above reviews and observations, the inspectors concluded that the licensee was closely monitoring collective and individual

,

radiation dose exposure, and was meeting established ALARA goals.

- R8 Miscellaneous RC&P Issues (92904)

R8.1 (00en) IFI 50 338. 339/96001 01: Delayed re) ort of radiological conditions following a release. During the )iennial emergency

, pre)aredness exercise conducted on August 13 15, 1996, an exercise

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wea(ness was identified regarding the licensee's failure to provide a timely-report of radiological conditions to the State and County

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governments following the declaration of a General Emergency and a radiological release. The licensee's reply to the assessed exercise weakness, dated November 13, 1996, indicated that a Dose Assessment Review Task Team would be established to address identified concerns related to the dose assessment process. During this inspection, the i task team's report, dated April 10, 1997, was discussed with the licensee's station and corporate emergency planning personnel. The report described thirteen recommendations, identified by the task team, of program enhancements for' improved performance. The licensee indicated that those recommendations were currently being assessed and that an implementation schedule had not been established. This item will remain open pending NRC review of dose assessment program

enhancements when implemented by the licensee.

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R8.2 (Closed) IFI 50 338. 339/96010 04: Documentation of technical basis for

. Health Physics conversion factors. During the inspection conducted on September 22 - November 2, 1996, the inspectors inquired about the i technical basis for the conversion factors, given in Section 6.1.5 of i procedure HP 1061.020, which were used for converting R0 2 survey

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instrument readings from units of millirem / hour (mR/hr) to units of

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disintegrations per minute (dpm). The licensee indicated that the  !

technical basis for those and other Health Physics conversion factors were being documented in Operations Support Corporate Procedures (0SCP).

During this inspection, the licensee's progress on this item was reviewed. The licensee had issued Commitment Tracking System (CTS)

Assignment No. 960506 for this item and the closure memorandum for that CTS ltem, dated February 18, 1997, indicated that the following actions had been completed. OSCP procedures which provided the technical bases for.the various aspects of the radiation protection program (2110, 2111, 2112, 2114, 2115, 2116, and 2119) had been revised to include the bases ,

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l

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for the overall program, the bases for specific instruction guidelines or criteria, and the bases or derivation of factors included in procedure instructions. The inspectors reviewed Attachment 2 to OSCP-2115 and determined that it delineated the technical bases for the conversion factors given in Section 6.1.5 of procedure HP 1061.020. The closure memorandum also indicated that the revised OSCP procedures had been transferred to the station for implementation. The licensee 1 indicated that the OSCP procedures had been reformatted into station Health Physics Administrative Procedures (HPAPs) and that the HPAPs were l

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in route for concurrence. The information providing the technical bases for the HP conversion factors had been documented and was available for use, j

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l R8.3 (Closed) Violation 50 338. 339/EA 96 322 01014: Failure to meet State i of South Carolina Radioactive Material License and 10 CFR 61.56(a)(3). !

On May 14, 1996, the licensee shiaped a package of spent resin in a High ;

Integrity Container (HIC) to the _ow-Level Radioactive Waste Disposal '

Facility located near Barnwell, SC. On May 16, 1996, the licensee was notified by the operator of the disposal facility, Chem Nuclear Systems, Inc., that the HIC was found to contain approximately 2.5 volume percent free standing liquid, which exceeded the 1 volume percent limit specified in South Carolina Radioactive Material License No. 097, Condition 32C and 10 CFR 61.56(a)(3). The licensee's reply to the Notice of Violation, dated January 2,1997, indicated that the most probable cause of the violation was a malfunction of the equipment used to de water the HIC and that, as corrective action, the de watering procedure (0 0P-20.6) had been revised. The procedural revisions were to include (1) testing the de watering leg prior to use to ensure its integrity, (2) ensuring that the final de watering of the liner will occur within seven days of shipping, and that if shipping has not occurred within seven days of de watering, the container will be de-watered again, (3) lowering the limit for the allowable liquid generated during the final de watering pass from less than five gallons to less than two gallons, and (4) requiring installation of the shipment liner lid once final de watering is completed. During this inspection, the inspectors verified that the above changes had been incorporated into Revision 3 of procedure 0 0P 2 S1 Conduct of Security and Safeguards Activities (71750)

On numerous occasions during the inspection period, the inspectors performed walkdowns of the protected area perimeter to assess security and general barrier conditions. No deficiencies were noted and the inspectors concluded that security posts were properly manned and that the perimeter's material condition was properly maintaine )

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i l l 27 i l

V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee ;

-management on June 20, 1997. The licensee acknowledged the findings l

presente I

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The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie I

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PARTIAL LIST OF PERSONS CONTACTED Licensea

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B. Foster, Superintendent Station Engineering C. Funderburk, Superintendent, Outage Planning E. Grecheck, Assistant Station Manager, Operations and Maintenance L. Hartz, Nuclear Engineering Manager J. Hayes, Superintendent, Operations D. Heacock, Assistant Station Manager, Nuclear Safety and Licensing H. Kansler, Vice President, Nuclear Operations i

P. Kemp, Supervisor, Licensing T. Maddy, Superintendent, Security W. Matthews, Station Manager M. McCarthy, Director, Nuclear-0versight H. Royal, Superintendent, Nuclear Training D. Schappell, Superintendent, Site Services R. Shears Superintendent Maintenance A. Stafford, Superintendent, Radiological Protection INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 37550: Engineering IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems IP 50002: Steam Generators IP 62700: Maintenance Im)lementation IP 61726: Surveillance 0)servations IP 62707: Maintenance Observations IP 71707: Plant Operations IP 71750: Plant Support Activities IP 73753: Inservice Insaection IP 83750: Occupational ladiation Exposure IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power i Reactor Facilities IP 92901: Followup Plant Operations IP 92902: Followup - Maintenance

! IP 92903: Followup Engineering l IP 92904: Followup Plant Support

)

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28 ITEMS OPENED, CLOSED AND DISCUSSED Opened 50 338/97004 01 NCV Failure to meet the requirements of TS 3. (Section 01.4).

50 338/97004-02 NCV Inoperable containment gaseous radiation monitor during refueling (Section 01.5).

50 338/97004-03 NCV Missed baseline inspections on SG tubes (Section M2.1).

50 338, 339/97004 04 IFI Review additional controls on molded case circuit breaker set points (Section E8.3).

Closed 50 338/97004 01 NCV Failure to meet the requirements of TS 3. (Section 01.4).

50-338/97004 02 NCV Inoperable containment gaseous radiation monitor during refueling (Section 01.5).

50 338/96003 03 VIO Failure to comply with TS 3.0.4 mode change made with inoperable BIT heat tracing circuit (Section 08.1).

50-338, 339/96006 02 VIO Failure to follow procedures for gas stripper operations on June 26, 1996 (Section 08.2).

50-338/97004 LER Hi Hi alarm setpoint for 1 RM RMS-160 found out of tolerance due to personnel error (Section 08.3).

50 338/97004 03 NCV Missed baseline inspections on SG tubes (Section M2.1).

50 338, 339/96012 08 IFI Review functional tests that will be conducted on new or old snubbers during Unit 1 RF0 (Section M8.2).

50 338, 339/96012-05 IFI Battery service test and rating of diesel generator breaker close coils (Section E8.2).

50-338, 339/96012 07 URI Control of set points for molded case circuit breakers (Section E8.3).

50 338, 339/96010 04 IFI Documentation of technical basis for Health Physics conversion factors (Section R8.2).

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50-338, 339/EA 96 322 VIO Failure to meet State of South Carolina Radioactive Material License and 10 CFR 61.56(a)(3) (Section R8.3).

Discussed 50 338, 339/96001 01 IFI Delayed report of radiological conditions following a release (Section R8.1).

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