IR 05000382/1999013

Insp Rept 50-382/99-13 on 990523-0703.Noncited Violations Noted.Major Areas Inspected:Aspects of Operations,Maint, Engineering & Plant Support Activities

ML20210B177
Person / Time
Site:	Waterford
Issue date:	07/15/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20210B157	List: IR 05000382/1999013 ML20210B152
References
50-382-99-13, NUDOCS 9907230073
Download: ML20210B177 (19)

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, ENCLOSURE U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

. Docket No.: 50-382 License No.: NPF-39 Report No.: Sr;-382 /99-13 Licensee: Enterg.' Operations, Inc.

Facility: Waterford Steam Electric Station, Unit 3 Location: Hwy.18 Killona, Louisiana Dates: May 23 through July 3,1999 Inspectors: T. R. Farnholtz, Senior Resident inspector J. M. Keeton, Resident inspector Approved By: P. H. Harrell, Chief, Project Branch D ATTACHMENT: SupplementalInformation 9907230073 990715 PDR ADOCK 05000392 G PDR m.

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EXECUTIVE SUMMARY Waterford Steam Electric Station, Unit 3 NRC lospection Report 50-382/99-13 This routine, announced inspection included aspects of operations, maintenance, engineering, and plant support activities. The report covers a 6-week period of resident inspection.

Operations

• Licensed reactor operators had not taken timely action to control reactor coolant system cool down following an automatic reactor trip caused by a loss of two reactor coolant pumps. The pumps were lost as a result of an electrical bus being automatically deenergized for a reason that could not be identified (Section 01.2).

= Operators took conservative actions when the estimated critical configuration appeared to be incorrect. The station log entries were incomplete in explaining the reason the first startup was aborted (Section 01.3).

I Maintenance (

• The actions of mechanical maintenance technicians were inappropriate when a lube oil i strainer in Charging Pump A was removed, inspected, and replaced without cleaning it. f The procedural step specifically directed the technicians to clean the strainer. The {

interpretation of this step to clean as required could result in unintended consequences j and assumes aspects of the step as written, which were not evident. Also, the condition ;

of strainers is not always possible to ascertain accurately by visual inspection. No I operability concerns with Charging Pump A were identified (Section M4.1). l l

Enaineerina

= A violation was identified for the failure to provide correct instructions in a design change written to perform a modification to install local ammeters on the safety-related essential j chillers. The incorrect instructions resulted in the both Trains A and B essential chillers i being in a degraded condition for a period of 54 days. This Severity Level IV violation of Criterion 111 of Appendix B to 10 CFR Part 50 is being treated as a noncited violation consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as Condition Report 98-0476 (Section E2.1).

• The licensee's initial actions concerning the low flow conditions in Trains A and B safety-related roem coolers were inadequate in that all relevant information was not considered when determining the past operability of these components. A more complete and detailed operability evaluation was performed when the inspectors questioned the effect of a degraded condition of the essential chillers, which were identified to have occurred at the same time as the degradation of the room coolers.

This evaluation concluded that the room coolers were capable of performing their safety-related functions (Section E2.2).

• A violation was identified for omission of 39 containment isolation valves from a list in the Updated Final Safety Analysis Report that resulted in the failure to ensure that the

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-2-valve indications had been tested in accordance with Technical Specification -

survei!!ance requirements. ;This Severity Level IV violation is be,ng treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. The corrective actions have been completed per Licensee Event Report 50-382/97-019 recommendations (Section E8.1).

Plant Support

• A violation was identified for the failure to control all points of access into the protected area and to adequately verify the identity and access authorization of an individual entering the protected area. This Severity Level IV violation is being treated as a noncited violation consistent with Appendix C of the NRC Enforcement policy. This violation is in the licensee's corrective action program as Condition Report 99-0716 (Section S1.1).

• Central Alarm Station security officer knowledge and equipment fami.v .y were good.

Radio communication between security officers was not consistently conducted using the three-way method (Section S4.1).

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Report Details Summarv of Plant Status At the beginning of this inspection period, the plant was operating at 100 percent power. On June 14,1993, the plant automatically tripped when power was lost to a nonsafety-related electrical bus and caused a loss of power to two reactor coolant pumps. Electrical power was restored to the bus and a plant startup was conducted on. June 16. The plant reached full power on June 17 and remained at that level for the remainder of this inspection period.

l. Operations 01 Conduct of Operations (71707)

O1.1 General Comments (71707)

The inspectors performed frequent reviews arid observations of ongoing plant operations, control panel walkdowns, and plant tours. Observed activities were performed in a manner consistent with safe operation of the facility. The inspectors observed that operators utilized good self-checking and peer-checking techniques when manipulating plant equipment. Operators consistently used three-way communication techniques, both in the control room and in external communications with auxiliary operators and maintenance personnel.

01.2 Reactor Trio Upon Loss of Electrical Bus A1 a. Insoection Scoce (93702)

The inspectors responded to the reactor trip, observed licensed operator actions in the control room, observed plant conditions following the trip, observed posttrip plant stabilization, and reviewed procedures and data related to the reactor trip.

b. Observations and Findings On June 14,1999, at 1:07 p.m., an automatic reactor trip occurred. The inspectors responded to the control room to observe operator trip response and verify plant conditions. The trip was caused by a loss of the 7-kV Electrical Bus A1. This caused a loss of Reactor Coolant Pumps (RCP) 1 A and 18, all three running circulating water pumps, and two condensate pumps. The decreasing speed of the RCPs was sensed by j the core protection calculators and the reactor trip was initiated by two of four departure-from-nucleate-boiling ratio trips. All safety systems and components performed as expected.

The inspectors observed the licensed operators perform the standard posttrip actions and follow the appropriate emergency operating procedures. Because of the low power history, decay heat was very low and the tripped RCPs reduced the amount of heat being added to the reactor coolant system (RCS). Additionally, the main steam drains ]

were open, both turbine-driven steam generator feedwater pumps continued to run, and 1 the turbine-driven emergency feedwater pump had started and continued to run. I

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While the operators attt opted to stabilize the plant, the inspectors noted that the third charging pump had started and RCS temperature had decreased to about 520*F (25'F less than no-load RCS temperature) and was continuing to decrease. The inspectors asked the shift superintendent if he should be securing steam loads to control cool down of the RCS. The shift superintendent consulted with the control room supervisor who directed the licensed operators to secure steam loads to control the cool down. The temperature of the RCS was increased to 545*F, where it was automatically controlled by the steam bypass system. Plant conditions were stabilized in Mode 3 and a root cause investigation was commenced.

The inspectors reviewed Operating Procedure OP-100-012," Post Trip Review,"

Attachment 6.1, Revision 5, and the Preliminary Root Cause Analysis Report produced by the Significant Events Review Team (SERT). The only fault indications on Electrical Bus A1 were that the feeder breaker from the unit auxiliary transformer (UAT) had tripped open and the 74/HR relay had actuated, which indicated an overcurrent condition had existed. Actuation of the 74/HR relay had prevented a fast bus transfer from the UAT to the startup transformer. An exhaustive troubleshooting plan was developed and performed. The plan included evaluation of all relays that could have caused or been affected by an overcurrent trip. Allloads supplied from Electrical Bus A, including RCPs 1 A and 18, Circulating Water Pumps A and C, and Condensate Pumps A and C, were checked for grounds and shorts and point-to-point wiring checks were conducted. All breakers, including the UAT supply breaker, were inspected and tested. The UAT oil was sampled for abnormalindications. No unusualindications were identified.

The SERT cpocluded that the most probable cause of the trip was a spurious trip of an RCP 2 rela : 'Terred u as a sneak circuit). The SERT cited other industry experience with similar indications tnat had been related to actuations caused by the RCP 2 relays.

Based on this assumption, the two relays for the RCPs on that bus were inspected and replaced. No abnormal indications were identified.

c. Conclusions Licensed reactor operators had not taken timely action to control reactor coolant system cool down following an automatic reactor trip caused by a loss of two reactor coolant pumps. The pumps were lost as a result of an electrical bus being automatically deenergized for a reason that could not be identified.

01.3 Reactor Startuo a. Inspection Scope (71707)

The inspectors observed licensed operators in the control room during portions of the reactor startup. The inspectors also reviewed the appropriate startup procedures, estimated critical configuration (ECC) calculations, station log entries, and poststartup activities.

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<n b.' Observations and Findinos On June 16,1999, at 1:22 a.m., all prerequisites had been completed for approach to

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criticality, Mode 2 was entered and control element assembly (CEA) regulating group ,

withdrawal was commenced. At 3:09 a.m., the reactor engineer questioned whether the j reactor could achieve criticality based on observation of the CEA positions when the count rate doubled.' In discussions with the licensed operators, a concern was raised that the reactivity bias factor used in the estimated critical calculations was in error. A conservative decision was made to insert the CEA regulating groups that had been withdrawn and recalculate the ECC. Mode 3 was entered at 5:02 a.m. Condition Report (CR) 99-0690 was written.

A review of the ECC and historical data from the previous reactor startup at the

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beginning of this cycle indicated that the reactivity bias factor was correct. Also, the count rate had doubled at approximately the same point in the previous startup

- indicating that criticality would have occurred as predicted in the ECC.

At 9:47 a.m., Mode 2 was reentered as CEA withdrawal commenced for reactor startup.

Criticality was achieved at 12:43 p.m. A review of the critical data indicated that the reactor had achieved criticality as was originally predicted by the ECC. The power increase was uneventful, and the main generator was tied to the grid at 6:08 p.m. The plant achieved 100 percent power on June.17 at 11:11 a.m. l The inspectors reviewed the station log narrative of the reactor startup and found that entries had been made that indicated a problem was identified that had caused the first startup to be aborted. However, there was no entry to indicate how the issue was resolved to permit the second startup. The lack of information in the station log was discussed with the operations superintendent. He agreed that the information should have been included and stated that he would discuss the importance of accurate log keeping with the licensed operators.

The inspectors noted that following the reactor power increase the 7-kV Electrical Bus 1 A had not been transferred from the startup transformer to the UAT, as was normal practice. In a review of the Updated Final Safety Analysis Report (UFSAR),

Section 8.1.2, the inspectors found in a general statement that the plant receives power under normal operating conditions from the main generator through the UATs.

- Procedure OP-010-004, " Power Operations," Revision 0, step 9.1.44, states "if desired,"

then transfer plant auxiliaries from the startup transformer to the UAT. The inspectors asked the. operations superintendent if this allowed continuous operation in this electrical alignment. The response was that operations management had decided that the plant would be run on the startup transformers in case there was an intermittent problem with the UAT. The startup transformers are capable of continuously carrying the loads on Electrical Bus 1 A. The inspectors considered this decision to be satisfactory.

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c. Conclusions Operators took conservative actions when the ECC appeared to be incorrect. The station log entries were incomplete in explaining the reason the first startup was aborted.

08 Miscellaneous Operations issues (92901)

08.1 (Closed) LER 50-382/97-020-01: Potential Safety-Related Static Uninterruptible Power Supply (SUPS) Common Mode Failure LER 97-020, Revision 01, was issued on March 16,1999. This revision described corrective actlons taken in Refueling Outage 9. The actions replaced one of the SUPS units, rerouted some of the cables, and revised procedures to require operators to trip l1 nonessential loads that received power from SUPS 3B-S during a control room / cable l vault fire scenario. The inspectors considered the corrective actions taken by the j licensee were appropriate. '

08.2 (Closed) LERs 50-382/97-021-00 and -01: Inside and Outside Containment Isolation Valves Failed Leakage Criteria On June 11,1997, while the reactor was shut down in Mode 5, the inside containment isolation valve for the fire protection system failed the leak rate test. The outside containment isolation valve had also failed the leak rate test during the previous week.

The outside valve had been reworked, reinstalled, and retested. The retest was ,

satisfactory. The inside isolatica valve was replaced and retested. Both valves had been retested satisfactorily and were returned to compliance with 10 CFR Part 50, Appendix J.

On December 16,1997, Revision 01 described the results of a detailed evaluation of the valve failures. The corrective measures were updated to include results of this investigation. They included procedure revisions to verify repetitive tasks as a result of a design change to the system, and the operating procedure was revised to require that the operators drain the system if the deluge valve actuated. The inspectors concluded that the corrective actions were appropriate.

08.3 (Closed) LER 50-382/97-023: Missed Emergency Diesel Generator (EDG) Fuel System Surveillances On July 8,1997, both EDG A and B were declared inoperable because Technical Specification (TS) Surveillance 4.8.1.1.2.h.2 had not been completed within its 10-year plus 25 percent surveillance interval. The licensee had previously determined that this TS surveillance was not necessary according to the inservice inspection program. A requested deletion from TS had been submitted to NRC with Change Request NPF-38-172 in 1995. In preparation for Refueling Outage 8, the licensee had removed this TS change request to allow focus on more immediate TS issues related to L_

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the outage.' They then discovered that they had miscalculated the grace period, thus requiring both EDGs to be declared inoperable. Emergency TS Change Request NPF-38-200 was submitted on July 10,1997, to eliminate TS 4.8.1.1.2.h.2.

The change was_ approved by NRC on July 11,1997, and both EDGs were declared operable.

11. Maintenance M1 Conduct of Maintenance (61726,62707)

The inspectors observed all or portions of the following maintenance and surveillance activities, as specified by the referenced procedure numbers and maintenance action item (mal) numbers:

• OP-903-068 Emergency Diesel Generator B surveillance run

= 004849 Charging Pump A oil and filter change

• 401862 Calibration of fuel handling building ventilation system emergency exhaust high range noble gas radiation monitor

• OP 903-090 Shutdown margin determination

• OP-004-019 Estimated critical configuration in general, the inspectors considered the observed work activities to have been performed in an acceptable and effective manner. The technicians were knowledgeable and conducted the work as required. Appropriate support personnel, including health

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j physics, quality control, supervisory, and system engineering personnel were at the work site when required.

M2 Ealntenance and Material Condition of Facilities and Equipment in general, material condition throughout the plant continues to be good. Very few leaks have been noted on valves and components. One exception was noted on June 22 during a routine tour of the turbine generator building. The inspectors identified a

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q packing leak on a moisture-separator reheater temperature-control valve Isolation i Valve MS 3251B and an MAI had not yet been initiated. The leak was in excess of 60 drops per minute. The inspectors informed the shift superintendent who took appropriate actions to correct the problem. The packing leak was repaired prior to the

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'M4 ' Maintenance Staff Knowledge and Performance M4.1 Charaina Pumo A Maintenance a. Inspection Scoce (62707) -

The inspectors observed maintenance technicians performing planned work activities on Charging Pump A. The work included draining the oil from the pump crankcase, replacing the oil filter, cleaning the' oil sump strainer, and refilling the sump with oil.

b. Observations and Findinas ]

On June 8,1999, Charging Pump A was tagged out to perform planned maintenance.

The work primarily involved the pump lubricating oil system and was performed under '

MAI 004849. ' Step 1 of the associated procedure stated to drain the oil from pump, remove the base cover, and clean the pump primary strainer at the bottom of the oil ,

sump. The inspectors observed the technicians performing this step. The strainer was l removed and inspected using a flashlight positioned behind the holes in the strainer to detect a clogged condition. The technicians considered the strainer to be clean, and it was reinstalled without cleaning it. The inspectors observed this and were concerned that the step was not performed as specified in the procedure. The step directed the !

technicians to clean the strainer, but instead the strainer was inspected and reinstalled j with no cleaning performed.

The inspectors considered the actions of the technicians to be inappropriate in this case i since the step was specific and did not provide for alternative methods to be employed. l Interpreting a step to mean something other than as written could result in unintended consequences and presumes to know the reason why the step was written in the way it i was.' In addition, it is not always possible to determine the condition of streiners in general by merely performing a visual inspection. -

in this case however, the' inspectors were able to observe the charging pump strainer as it was being inspected and determined that it did appear to be in satisfactory condition.

The size of the holes in the strainer were relatively large, and foreign material did not appear to be present. In addition, postmaintenance testing of the pump was satisfactory. As a result, even though the technicians did not clean the strainer, the inspectors did not consider the operability of the charging pump to be in question.

The inspectors informed the licensee of this observation and CR 99-0675 was written to address any corrective actions to be taken. The inspectors considered this action to be

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c. Conclusions The actions of mechanical maintenance technicians were inappropriate when a lube oil strainer in Charging Pump A was removed, inspected, and replaced without cleaning it.

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-7-The procedural step specifically directed the technicians to clean the strainer. The interpretation of this step to clean as required could result in unintended consequences and assumes aspects of the step as written, which were not evident. Also, the condition of strainers is not always possible to ascertain accurately by visualinspection. No operability concerns with Charging Pump A were identified.

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E2 Engineering Suppott of Facilities and Equipment E2.1 Dearaded Essential Chillers a. Inspection Scoce (37551)

The inspectors reviewed a condition in which all three safety-related essential chillers were degraded for an extended period of time such that they were not capable of operating at full capacity.

b. Observations and Findinos in 1992, the licensee performed a modification to all three safety-related essential chillers to add a local ammeter to the control panels. The modifications were done under Design Change (DC)-3192.. This DC included instructions on the electrical installation of the ammeter between a control circuit shunt resistor and Terminal 24 in the chiller control panel. This required installing a jumper wire between the new ammeter and Terminal 24 and relocating one end of a lead supplying the capacity control module from Terminal 24 to the resistor side of the ammeter. This had the effect of introducing an additional lead and the local ammeter postlug in the voltage drop sensing circuit.

The voltage drop sensing circuit is extremely sensitive to resistence. The licensee stated that an increase in resistance of as littis as 0.1 ohms would cause the controller i to sense a compressor motor electrical overload condition and send a close signal to the inlet guide vanes, thereby reducing the load on the chiller. With the guide vanes fully 1 closed, the chiller capacity would be reduced to approximately 130 tons. This would be l approximately 50 percent of the required post loss-of-coolant accident heat load of j'

257 tons on each chilled water loop.

Any maintenance activity on the ammeter, such as calibration or replacement, required disconnecting and then reconnecting the leads in the voltage drop sensing circuit at the ammeter. If the leads were reconnected such that the resistance across the ammeter terminal increased even slightly, the voltage drop sensing circuit would not function as )

designed.

The ammeter for Essential Chiller A was calibrated on February 27,1997. The Essential Chiller B ammeter was calibrated on February 7,1998. These activities had j

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-8-the effect of introducing the failure mechanism described above. This condition was identified and corrected un Essential Chiller A on April 2,1998. The same condition was identified and corrected on Essential Chiller B on April 7,1998. While not norma!!y operated, the same failure mechanism was introduced into Essential Chiller A/B following ammeter calibration activities on September 3,1997, and corrected on April 15,1998. The voltage drop sensing circuit wiring was changed such that the temperature controller portion of the circuit was made independent of the ammeter.

For a 13-month period between February 27,1997, and April 2,1998, it was determined that Essential Chiller A was degraded such that it was unable to operate at full capacity.

Similarly, for the 2-month period between February 7 and April 7,1998, it was determined that Essential Chiller B was degraded. For the 54-day period from February 7 through April 2,1998, both Essential Chillers A and B were degraded at the same time. This degradation was observed as slowly rising chiller outlet temperatures on several occasions on both essential chillers.

Licensee engineering personnel performed Engineering Evaluation ER-W3-98-0950-00-00 to determine the significance of this degradation. The design basis chill water outlet temperature was 42 F. The evaluation determined that a worst case chill water outlet temperature of 75 F could be expected with the chillers in the degraded condition. This was used to determine maximum room temperatures. The control room was identified as having the greatest deviation from the design basis temperature as well as the most electrical equipment. A chill water outlet temperature of 75'F would translate to a control room temperature of 101 F. The licensee determined that this was most limiting room and that all evaluated equipment in this room was 1 capable of withstanding the temperature rise to 101 *F. The inspectors, having no I evidence to the contrary, considered this evaluation to be adequate.

10 CFR Part 50, Appendix B, Criterion Ill, " Design Control," states th' at measures shall be established to assure that applicable regulatory requirements and the design-basis '

are correctly translated into specifications, drawings, procedures, and instructions. The l failure to provide correct instructions to install the local ammeters in DC-3192 is identified as a violation. This Severity Level IV violation is being treated as a noncited ,

violation consistent with Appendix C of the NRC Enforcement Policy. This violation is in l the licensee's corrective action program as CR 98-0476 (50-383/9913-01).

c. Conclusions A violation was identified for the failure to provide correct instructions in a design change written to perform a modification to install local ammeters on the safety-related essential chillers. The incorrect instructions resulted in both Trains A and B essential chillers being in a degraded condition for a period of 54 days. This Severity Level IV violation of Criterion lit of Appendix B to 10 CFR Part 50 is being treated as a noncited violation consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CR 98-0476.

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E2.2 Dearaded Room Coolers a. jn_sp_ection Scoce (37551)

The inspectors reviewed the licensee's efforts concerning two conditions identified during Refueling Outage 9. Testing of chill water system flow through safety-related room coolers was conducted, and multiple low flow conditions were identified in both Trains A and B.

b. Observations and Findinas On February 28,1999, the licensee identified that 7 of 13 Train A safety-related room coolers had as-found chill water flow values below the specified design capacity flow.

On March 9, the licensee identified that 4 of 14 Train B safety-related room coolers had chill water flow values below the specified design capacity flow. In each of these two cases, a CR was written, CR 99-0240 for Train A and CR 99-0319 for Train B.

Following identification, the flows in each train of the safety-related chill water system were adjusted to established flows greater than design capacity through all room coolers. The as-left condition of Trains A and B safety-related chill water systems was adequate to perform its design function.

Past operability and reportability requirements of the room coolers were initially I 1 addressed in CR 99-0240. The most limiting component was identified as Charging Pump AB Room Cooler AH-22. Corrective Action 3 to CR 99-0240 requested that I I

engineering personnel perform an analysis to evaluate the past operability of Room Cooler AH-22. The initial response to this request was in the form of an extension request waich stated that an operability evaluation was not able to be performed at that time due to the outage workload and that the condition described in the CR had been corrected. Therefore, no startup restraint was associated with this condition. This j response did not address past operability, which was the subject of the original request. !

However, an evaluation was later performed, which concluded that the steady state {

temperature of the Charging Pump AB cubicle would be a maximum of 127*F and that j the equipment located in this room could continue to function under these conditions.

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The inspe ctors considered the initial response and the original engineering evaluation to j be inadecuate since it did not consider all relevant information.

Subsequent to this operability reportability determination, the inspectors questioned the ,

effect of the degraded safety-related essential chillers discussed in Section E2.1 of this report. The essential chillers were degraded during Operating Cycle 9. Also during Operating Cycle 9, the degradation of the safety-relMed room coolers was experienced.

Initially, the licensee did not consider these two related events when the original operability evaluation was performed. When this was brought to their attention, the licensee performed Engineering Evaluation ER-W3-99-0491-00-00 to reevaluate the past operability of the room coolers.

The inspectors reviewed this evaluation and interviewed the engineering personnel involved in its development. The basis for this evaluation was Engineering

r-10-Evaluation ER-W3-98-0950-00-00, which was performed to evaluate the degraded essential chiller condition and determined that the chill water temperature would be 75'F under accident conditions. The past operability evaluation for the room coolers was detailed and well organized. The assumptions were clearly stated and reasonable. The engineering personnel involved in this issue were knowledgeable. The evaluation concluded that the room coolers would be capable of pedorming their safety-related function even though many room temperatures would be significantly higher than the design-basis temperatures. The inspectors concluded that the conclusions in this evaluation were sufficiently supported and were adequate.

c. Conclusions The licensee's initial actions concerning the low flow conditions in Trains A and B safety-related room coolers were inadequate in that all relevant information was not considered when determining the past operability of these components. A more complete and detailed operability evaluation was performed when the inspectors questioned the effect of a degraded condition of the essential chillers, which were identified to have occurred at the same time as the degradation of the room coolers.

This evaluation concluded that the room coolers were capable of performing their safety-related functions.

E8 Miscellaneous Engineering issues (92901)

E8.1 (Closed) Licensee Event Report (LER) 50-382/97-019: Noncompliance with TS 3.3.3.6 for Containment Isolation Valve Position Indication On May 29,1997, with prompting by the NRC, the licensee determined a previous reportability determination had been incorrect. This LER was written to describe the corrective actions required to return the plant to compliance with TS 3.3.3.6. The licensee found a total of 39 nonautomatic containment isolation valves that had been incorrectly excluded from the valve list in Table 7.5-3 in the UFSAR. These valves had been incorrectly scoped during implementation of Regulatory Guide 1.97.

In accordance with the corrective actions recommended in the LER, the valves have been added to the surveillance list required by TS 4.3.3.6. Also, the valves have been added to the list in Operating Procedure OP-903-013, " Monthly Channel Checks," to implement the requirements of Regulatory Guide 1.97. Corrective actions have been completed.

Omission of these valves from the list in the UFSAR resulted in failure to ensure that the valve indications had been tested in accordance with TS surveillance requirements.

This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. The corrective actions have been completed per LER recommendations (50-382/9913-02).

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t-11-IV. Plant Support L

R1 Radiological Protection and Chemistry Controls (

During routine tours, the inspectors observed posted radiation survey measurements, which were required by licensee procedures and NRC regulations. A sample of doors was found locked as required for the purpose of radiation protection. Licensee ,

personnel working la radiologically controlled areas were observed following applicable J procedures for radiation protection.

S1 Conduct of Security and Safeguards Activities  !

S1.1 Failure to Control Personnel Access into the Protected Area a. Insoection Scope (71750)

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The inspectors reviewed the licensee's actions concerning a security event, which l resulted in an individual gaining access to the protected area through a primary access

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l portal turnstile without being logged into the security computer. I b. Observations and Findinas I

10 CFR 73.55(d)(1) states that the licensee shall control all points of personnel and l vehicle access into the protected area. Further, identification and search of all i individuals must be made and authorization must be checked at these points. l Paragraph 5.6.1.4 of the licensee's Physical Security Plan, Revision 18, states that personnel access is granted into the protected area only after all access processing, including appropriate searches for firearms, explosives, and incendiary devices, and verification of identity and access authorization (by security personnel or biometric hand readers) is accomplished.

Paragraph 5.16.1.5 of the licensee's Security Procedure PS-011102, Revision 15, requires that each card reader or hand reader discrepancy is satisfactorily resolved prior to allowing access to the protected area.

Contrary to the above, on June 28,1999, an individual accessed the protected area without being . logged into the security computer. One authorized employee carded in without entering the turnstile. He then moved to another turnstile, carded in again and entered the protected area through the second turnstile. Another employee, approached the first turnstile and while he carded in, since the turnstile was still open awaiting the first employee to enter, the second employee entered the turnstile under the identification and authorization of the first employee. This vulnerability would have allowed an unauthorized entry into the protected area. Following this event, the licensee

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-12-placed a compensatory officer at the turnstiles to ensure that unauthorized access could not occur under the above scenario. The licensee entered the issue into their corrective '

action program as CR 99-0716.

The failure to control all points of personnel access into the protected area and to adequately verify the identity and access authorization of an individual entering the -

protected area is identified as a violation. This Severity Level IV violation is being treated as a noncited violation consistent with Appendix C of the NRC Enforcement !

Policy. This violation is in the licensee's corrective action program as CR 99-0716

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(50-382/9913-03).

c. Conclusions A violation was identified for the failure to control all points of access into the protected )

area and to adequately verify the identity and access authorization of an individual j entering the protected area. This Severity Level IV violation is being treated as a l noncited violation consistent with Appendix C of the NRC Enforcement policy. This I violation is in the licensee's corrective action program as CR 99-0716.

S4 Security and Safeguards Staff Knowledge and Performance S4.1 ~ Conduct of Operations in the Central Alarm Station (CAS)

a. Inspection Scope (71750)

The inspectors made several routine tours of the plant to observe security personnel in the performance of their duties during this inspection period. Interviews were conducted >

with several security officers.

i b. Observations and Findinas During this inspection period, the inspectors conducted several tours of the plant, which j included security facilities. Two of these tours included extended observations of operations in the CAS. During these observations, the inspectors interviewed the security officers on duty to gain an understanding of their level of knowledge. The inspectors concluded that the officers had a good understanding of their duties and f were familiar with the use of the available equipment. However, the inspectors noted that radio communications between the CAS operators and security officers in other ]

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parts of the plant viere not consistently conducted using the three-way method. The CAS operator transmitted information to another officer who acknowledged the message, but the information was not repeated back to ensure proper understanding. i Also, the CAS operators did not request a repeat back if one was not made. The l

licensee stated that it was managements expectation that security communication be l conducted in the same three-way manner that plant operators use.

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-13-In addition, the inspectors' observed the quality of the closed circuit television images in the CAS. Picture quality and field of vision were considered good during both the daytime and nighttime hours. No concerns were identified.

c. Conclusions Central Alarm Station security officer knowledge and equipment familiarity were good.

Radio communication between security officers was not consistently conducted using the three-way method.

V. Manaaement Meetinas X1. Exit Meeting Summary The inspectors presented the inspection results to members of licensee management on July 7,1999. The licensee acknowledged the findings presented.

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

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ATTACHMENT SUPPLEMENTAL INFORMATION PARTIAL LIST OF PERSONS CONTACTED Licensee R. F. Burski, Director Site Support C. M. Dugger, Vice-President, Operations E. C. Ewing, Director, Nuclear Safety & Regulatory Affairs.

C. Fugate, Operations Superintendent J. G. Hoffpauir, Manager, Operations T. R. Leonard, General Manager, Plant Operations D. C. Matheny, Refuel 10 Coordinator E. Perkins, Jr., Manager, Licensing G. D. Pierce, Director of Ot'ality L. Rushing, Manager, Pedormance and System Engineering B. Thigpen, Director, Planning and Scheduling A. J. Wrape, Director, Design Engineering INSPECTION PROCEDURES USED 37551 Onsite Engineering 61726 Surveillance Observations .

62707- Maintenance Observations 71707 Plant Operations 71750 Plant Support Activities -

92700 - Onsite LER Review 92902 Followup-Maintenance 92903 Followup-Engineering 93702 Prompt Onsite Response to Events

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-2-ITEMS OPENED. CLOSED. AND DISCUSSED Opened 50-382/9913-01 NCV' Failure to provide correct instructions to install the local ammeters in DC-3192 (Section E2.1).

50-382/9913-02 NCV Failure to ensure valve indications had been tested in accordance with TS surveillance requirements (Section E8.1).

50-382/9913-03 NCV Failure to control all points of personnel access into the protected area and to adequately verify the identity and access authorization of an individual entering the protected area (Section S1.1).

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50-382/97-019 LER Noncompliance with TS 3.3.3.6 for Containment Isolation Valve Position Indication (Section 08.1)

50-382/97-020-01 LER Potential Safety-Related SUPS Common Mode Failure j (Section 08.1)

50-382/97-021-00 LER Inside and Outside Containment Isolation Valves Failed

. and -01 Leakage Criteria (Section 08.2)

50-382/97-023 LER Missed EDG Fuel System Surveillances (Section 08.3)

50-382/9913-02 NCV Failure to provide correct instructions to install the local ammeters in DC-3192 (Section E2.1).

50-382/9913-01 NCV Failure to ensure valve indications had been tested in l accordance with TS surveillance requirements (Section E8.1).

50-382/9913-03 NCV Failure to control all points of personnel access into the ,

protected area and to adequately verify the identity and j access authorization of an individual entering the protected .

area (Section S1.1). l i

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l Discussect None

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3-LIST OF ACRONYMS USED CAS control alarm station CEA control element assembly CFR. Code of Federal Regulations CR condition report DC design change ECC estimated critical configuration EDG emergency diesel generator LER licensee event report MAI maintenance action item NCV noncited violation NRC Nuclear Regulatory Commission PDR Public Document Room RCP reactor coolant pump RCS reactor coolant system SERT Significant Events Review Team SUPS static uninterruptible power supply TS Technical Specification UAT unit auxiliary transformer UFSAR Updated Final Safety Analysis Report

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