IR 05000395/1997001

Insp Rept 50-395/97-01 on 970209-0322.No Violations Noted. Major Areas Inspected:Operations,Maintenance,Engineering & Plant Support

ML20138J673
Person / Time
Site:	Summer
Issue date:	04/17/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20138J643	List: IR 05000395/1997001 ML20138J639
References
50-395-97-01, 50-395-97-1, NUDOCS 9705080290
Download: ML20138J673 (37)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION II

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Docket No.: 50 395 License No.: NPF 12 Report No.: 50 395/97 01 Licensee: South Carolina Electric & Gas (SCE&G)

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Facility: V. C. Sumrc,ar Nuclear Station

i Location: P. O. Box 88 Jenkinsville, SC 29065

Dates: February 9 - March 22, 1997

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Inspectors

T. Farnholtz, Acting Senior Resident Inspector l R. McWhorter. Senior Resident Inspector, North Anna (Section 07.2)

P. Byron, Resident Inspector, Surry (Sections 08.1, 08.2, 08.3, and 08.4)

D. Jones, Reactor Inspector, RII (Sections R1.1, R1.2, and R1.3)

E. Girard, Reactor Inspector, RII (Sections E1.3 and E8.1)

G. Salyers, Reactor Inspector. RII (Sections P2.1, P2.2, P3.1, P5.1, P5.2, P6.1, P7.1, and P7.2)

Approved by: G. Belisle, Chief, Reactor Projects Branch 5 Division of Reactor Projects ENCLOSURE 9705080290 970417 PDR ADOCK 05000395 O PDR

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I EXEClfTIVE SUMMARY l l

V. C. Summer Nuclear Station j NRC Inspection Report 50 395/97-01 i i

This integrated inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a 6 week period of resident insaection: in addition, it includes the results of announced inspections )y regional ins)ectors including: D. Jones, E. Girard, and G. Salyers. G. Belisle, Branch C11ef, visited with the resident

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inspectors and plant personnel.

Operations

. A Non cited Violation (NCV) was identified concerning the failure to properly perform a surveillance test on a turbine driven emergency feedwater pump. The pump was required to be started twice in order to obtain the required test data. The post test review process was effective in identifying the error (Section 01.2).

. Self assessment activities were conducted in a thorough and professional manner. Appropriate personnel were available and actively participated ,

in a Quality Assurance exit meeting and a Plant Safety Review Committee (PSRC) meeting. No concerns were identified (Section 07.1).

. The Independent Safety Engineering Group (ISEG) team met Technical ;

5 meification (TS) requirements and provided useful reviews and ;

recommendations to plant management. The visibility of ISEG personnel !

and their involvement in diverse plant activities were considered a strength (Section 07.2).

Maintenance

. All observed maintenance activities were conducted in an appropr%te i manner and in accordance with established procedures. Good cooi : :1ation and planning were noted with regards to some safety-related chiller ;

work. Corrective maintenance activities on spent fuel cooling '

components were effective (Section M1.1). i

. Surveillance testing was conducted in a professional and safety conscious manner. Testing was performed by qualified personnel using approved procedures (Section M2.1).

. The human red tag program was adequate to ensure personnel protection when the use of a danger tag is not practical. Configuration controls and personnel qualifications were maintained as required (Section M3.1).

Enaineerina

. The engineering evaluation performed in response to Westinghouse Nuclear Safety Advisory Letter 96 004 was adequate. The V. C. Summer plant is not susceptible to the concerns outlined in this letter and the reactor is still protected under the postulated instrument failures (Section E1.1).

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. The licensee's program to identify possible problems in the safety related logic circuits, as described in NRC Generic Letter 96 01, was effective. Several questions were raised concerning the adequacy of current testing procedures for the reactor trip and bypass breaker P-4 circuits. Design engineering personnel adequately addressed all of these concerns in a logical and reasonable manner. Testing procedure -

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and program enhancements were identified to improve the verification of these circuits (Section E1.2).

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. The licensee met the intent of Generic Letter 8910 in verifying the design basis capabilities of their motor operated valves. However, the inspectors identified a few weaknesses in valve factor, load sensitive behavior, and stem friction coefficient values used in the licensee's calculations. The weaknesses were generally considered minor and the licensee initiated satisfactory actions to address the more significant l weaknesse Inspection followup item 50 395/97001 02 was identified to track the completion of these actions (Section E1.3).

. Strengths in the Generic Letter 89-10 program were identified which included: very accurate stem measurements of motor operated valve torque and thrust on gate and globe valves, extensive butterfly valve torque measurements, valve factor determinations that were very well-justified (except for the weaknesses referred to above), and ,

particularly well described bases for the capabilities of gate and globe '

valves provided in Technical Report TR01520-001 (Section E1.3).  :

. Issues were raised regarding the licensee's evaluations of seven valves for pressure locking and thermal binding. The licensee stated that they would provide a supplemental response to Generic Letter 95 07 to address :

these issues. The NRC staff will address these issues in their safety )

evaluation of the licensee's response to Generic Letter 95 07 (Section E1.3).

. A weakness was identified concerning the adequacy of the limiting ,

parameters which are listed on the diesel generator operating log Diesel engine exhaust temperatures had exceeded the established normal band as stated on the operating logs during periods of high ambient temperatures. The licensee was not aware of the basis of some of the limiting values as contained in the operating logs (Section E2.1).

. An NCV was identified concerning the failure to adequately control the design of the Charging / Safety Injection pump recirculation minimum flow line valve swer lockout feature modification. The licensee failed to revise the TSs to include this valve in the appropriate surveillance requirements section (Section E2.2).

Plant Support i

. The licensee had implemented an effective program for maintaining !

radioactive effluent monitoring instrumentation in an operable condition

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and for performing the required surveillances to demonstrate their operability (Section R1.1).

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. The surveillance requirements for demonstrating operability of the !

meteorological monitoring instrumentation were met (Section R1.2).

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. The licensee had implemented an effective program for maintaining the Control Room Emergency Ventilation System in an operable condition and l for performing the required surveillances to demonstrate operability of '

the system (Section R1.3).

. The licensee maintained the emergency response facilities and equipment at a satisfactory level of operational readiness (Section P2.1).

. Emergency Response Organization (ER0) equipment and facility audits were properly completed and inventories had been satisfactorily maintained !

(Section P2.1).

. The licensee's newly developed electronic information system for the emergency response facilities has the potential to enhance the licensee's capabilities in an emergency situation (Section P2.1).

. Public Alerting System siren availability was high, maintenance of the siren system was good, and the sirens had been tested at the required ;

frequencies (Section P2.2).

. The licensee's reviews of Emergency Plan and Emergency Plan Procedure changes were satisfactory and met the requirements of 10 CFR 50.54(q)

(Section P3).

. The licensee maintained a good initial training and annual retraining program for Emergency Preparednes ERO lesson plans and exams were well organized and contained good detail (Section P5.1).

. The inspectors identified four examples of a lack of a detailed review in the ERO lesson plans and exams (Section P5.1).

. The licensee satisfied the drill commitments in their Emergency Plan and EPP 105, Conduct of Drills and Exercises, Revision 2 (Section P5.2).

. The changing from first responders to a four rotating team approach had improved teamwork and performance by the ERO (Section P6)

. An Emergency Preparedness program audit was organized, thorough, and objective. The audit satisfied the requirements of 10 CFR 50.54(t)

(Section P7.1).

. Overall, the licensee adecuctely tracked Emergency Preparedness drill findings to completion anc resolved the drill findings. Documentation was not always available to demonstrate adequate closure had been achieved (Section P7.2).

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. Lighting in the protected area was adequate to illuminate the are Established ins)ection procedures contained sufficient requirements to ensure that lig1 ting levels are maintained at or above minimum levels (Section 52.1).

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Report Details

Summary of Plant Status Unit 1 began this inspection period at 100 percent power and remained at that a level during the entire inspection perio l l Doerations 01 Conduct of Operations 01.1 General Comments (71707)

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

01.2 Turbine Driven Emeraency Feedwater Pumo (TDEFW) Testina Insoection Scoce (71707) i The inspectors reviewed the licensee's actions regarding the incorrect conduct of testing on the TDEFW pum b. Observations and Findinas

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On February 18 and 19, 1997, t"e Operations Control Room Supervisor authorized the 3erformanca of surveillance Test Procedure (STP) 220.002, 4 Turbine Driven Emergencv F% dwater Pump Test, Revision 1. Three i different Surveillance Test Task Sheets (STTS) were generated to conduct this one test. The first STTS (0064954) was for the performance of the monthly test. A second STTS (0064860) was for the quarterly test which included all of the requirements of the monthly test plus some additional data such as bearing vibrations and oil temperatures. The third STTS (0064859) was to specify where the pump was to be started fro For this run, a quarterly test with a start from the A train emergency feedwater actuation relay K-634A was required. However, the pump was incorrectly started from the B train emergency feedwater actuation relay K 634B. During the post test reviews, the responsible supervisor noticed the inconsistency, declared the test unsatisfactory, and a test deficiency was written. Later on February 19, the test was performed again from the correct relay and declared satisfactor The inspectors reviewed the circumstances of this event and determined that the primary contributing factor was the complexity of the pre test administrative paperwork. The controlling STP includes eight different tests which are to be performed at different times to meet TS and inservice testing requirements. In this case, test number five (Section 6.7 of STP 220.002) was to be 3erformed and was specified on STTS 0064859. However, a note in tie "Last Comments" section of STTS 0064860 (quarterly test) indicated that the pump had been started per step A Train Slave Relay. The Control Room Supervisor assumed this to mean

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that the pump was started from the A train last quarter and should be started from the B train this quarte In addition, the operators are trained that testing or maintenance is to be performed in the associated A or B train maintenance weeks except in very rare or unusual circumstances. This was an A train test scheduled to be performed in a B train week. The note on STTS 0064860 and the timing of the test in the B train maintenance week was enough to convince the Control Room Supervisor that the pump should be started from the B train slave relay. This was incorrect and resulted in the necessity to start the TDEFW pump twice in order to satisfactorily perform the required tes The licensee initiated corrective actions to simplify STP 220.00 '

S)ecifically, the monthly test was eliminated and the requirements of .

l t1e quarterly test will be performed on a monthly basis. The revised procedure will require only one STTS for each test and will specify the starting point on that sheet. The inspectors considered these actions to be adequate to prevent a similar occurrence in the futur Station Administrative Procedure (SAP) 134 Control of Station Surveillance Activities, Revision 8. Section 5.4.1, states, that, "Each responsible supervisor is responsible to his manager for effective I conduct of the surveillance program within their subgroup which includes assuring that all surveillance activities are performed in accordance with applicable procedures (s) and schedules (s)". The failure to perform the specified surveillance test on the TDEFW pump is identified as a violation. This licensee identified violation is being treated as an NCV consistent with Section VII.B.1 of the NRC Enforcement Policy. This is identified as NCV 50 395/97001 0 The inspectors noted that this error was identified as a result of a post test review. This indicated that the post test review process was effective in identifying and correcting test deficiencies before the test was signed off as satisfactor Conclusions An NCV was identified concerning the failure to properly perform a surveillance test on a TDEFW pump. The pump was required to be started twice in order to obtain the required test data. The post test review process was effective in identifying the error.

02 - Operational Status of Facilities and Equipment 02.1 Enaineered Safety Features System Walkdown (71707)

The inspectors performed a walkdown of accessible portions of the A train and B train Service Water (SW) systems. No discrepancies or concerns were identifie . .

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07 Quality Assurance in Operations 07.1 Licensee Self Assessment Activities Insoection Scope (71707. 40500)

The inspectors evaluated licensee self assessment activities by attending a Quality Assurance (QA) exit meeting and a PSRC meeting, Observations and Findinas The inspectors attended a QA exit meeting on February 25 to discuss the results of a QA audit of fire protection. The audit identified several issues and the findings were discussed with the appropriate manager The inspectors considered the exit meeting to be effective in disseminating important information concerning the fire protection audi The inspectors attended a meeting of the PSRC on February 25. The purpose of the meeting was to review procedure revisions and safety 1 evaluations. Specifically, a change to Fire Protection Procedure j (FPP)-025. Fire Containment, Revision 1, was reviewed which reflected the requirements for risk significant area doors. Also, two safety evaluations were reviewed concerning a Modification Request Form (MRF)

to upgrade the existing primary water treatment instrumentation panel !

and a commercial change notice to add a strainer and appropriate valving !

to the Turbine Closed Cycle Cooling System. The PSRC Secretary established that a quorum was present and each subject was fully l discussed. Questions and concerns were addressed with attention being given to the 10 CFR 50.59 safety evaluations that were performed for each change. Each change was approved following a vote of the committee member i Conclusions  !

Self assessment activities were conducted in a thorough and professional manner. Appropriate personnel were available and actively participated in a QA exit meeting and a PSRC meeting. No concerns were identifie .

07.2 Indeoendent Safety Enaineerina Group (ISEG) Review Insoection Scope (40500)

On March 19 and 20. the inspectors reviewed ISEG activities at the sit The ISEG was required to be established by and conducted activities in accordance with TSs 6.2.3 and 6.3. The inspectors reviewed ISEG manning, duties activities, and recommendations to ascertain if TS requirements were me _ - - - - . . . - . . _ _ - - - .- . . - . . - -

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The inspectors found that ISEG activities at the site were delineated in

QSP 600, Inde)endent Safety Engineering Group, Revision QSP 600 assigned to t1e ISEG all duties and activities required by T Additionally, QSP 600 provided guidance for the disposition of ISEG

. reviews and provided an organizational structure that was appropriately l independent of station managemen On March 20, the inspectors met with the ISEG team leader and discussed i

ISEG activities. The inspectors reviewed the scope of ISEG reviews and the qualifications of personnel assigned to the ISEG and found that TS recuirements for review areas and personnel qualifications were me I Adcitionally, the inspectors found that the ISEG team was providing I monthly safety briefings to station management and observed one of these '

briefings. The briefing observed by the inspectors presented highlights of industry loss of offsite power events during shutdown operation The briefing was informative and well received by managemen Reports provided by the ISEG to plant management were also reviewed and discussed. ISEG reports were found to include monthly progress reports, technical work records on individual issues, and outage safety review The inspectors reviewed in detail copies of a routine monthly progress report and a technical work record from the ISEG review of a core thermal power deficit problem. The inspectors found that the reports were sufficiently detailed, tracked priority issues and open items, and provided detailed recommendations for performance improvemen '

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c. Conclusions The ISEG team met TS requirements and provided useful reviews and recommendations to plant management. The visibility of ISEG personnel and their involvement in diverse plant activities were consic': ed a strengt Miscellaneous Operations Issues (92901)

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08.1 (Closed) Licensee Event Report (LER) 50 395/95003: volume in the sodium hydroxide tank above Technical Specification limits. On May 6, 1995, while performing a six month TS verification of the volume in the containment spray additive tank, the licensee discovered that level was above the maximum TS requirement when measured with the sightglas )erations personnel drained a) proximately 60 gallons from the tank to t1e reactor building sump whic1 brought the volume to the mid range of the TS requirements (3140 to 3230 gallons). Investigation revealed that on April 21, an operator added 30 gallons of Sodium Hydroxide (NaOH) to the tank but did not drain a corresponding amount of licuid from the tank. The licensee determined that the operators reliec on remote indication in the control room. The Na0H tank level instrumentation (LI-7356 and LI 7358) in the control room is not sufficiently accurate to show small changes in tank leve .

The licensee determined that inadequate procedural guidance was the cause of the event. Procedural controls were not in place to ensure that equal volumes were drained and added. . System Operating Procedure (S0P) 116. Reactor Building Spray System. Revision 12, added Step B.2.18 which requires the performance of STP 112.009 when all additions have been completed. STP 112 009, Spray Additive Tank Sodium Hydroxide Contained Solution Volume Test, Revision 1. Step 6.3 requires that the level in the Sodium Hydroxide Store Tank Sightglass be recorded. The inspectors verified that the two procedures contained the LER corrective actions.

08.2 (Closed) Violation 50 395/95009 01: failure to control the volume in the containment spray additive tank. This violation was written against the event described in LER 50-395/95003. The closure of Item 08.1 also closes this item.

08.3 (Closed) Violation 50-395/95013-01: failure to follow procedures. This violation contains three examples and each will be addressed separately. i i On July 16, 1995, while swapping from train A to train B single train chilled water operation, the licensee failed to alace emergency feedwater pump cooling fan XFN-83B in manual. t11s resulted in higher than expected temperatures in the turbine driven emergency pump roo The licensee determined that SOP 501, HVAC Chilled Water System, was adequate and the event was caused by the o>erator's inattention to detail. The shift on duty was counselled ay Operations managemen i They were also directed to produce and present a human performance l program video on the event for review by other de)artment personne l The inspectors reviewed the training attendance sleet ' On July 24,'1995, after declaring a portion of the Fire Detection System inoperable, the licensee failed to adequately establish an hourly fire watch to inspect all affected zones. As a result, both emergency diesel rooms were not inspected by the hourly roving fire watch for approximately 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br />. The licensee determined that the Fire Protection Officer (FPO) was involved in an incident where he evaluated conditions for two separate fire protection panels and erroneously selected the wrong zone for the fire watch. This was considered to be another example of inattention to detail. The FP0 was counselled and the Root Cause Analysis (RCA) of the event was reviewed by all the FP0 The insaectors reviewed the training attendance record and the root cause, RCA 106 ,

i On July 24, 1995, the licensee established an hourly roving fire watch !

to inspect rooms in the lower two levels of the emergency diesel ;

generator building. The fire watch failed to patrol the rooms in the i lower level for approximately eight hours. The licensee concluded that !

FPP 004, Duties of a Fire Watch, was inadequate. It did not provide j adequate instructions to address those situations where a Roving Fire

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Watch (RFW) was established for zones containing either confined or radiological entry controlled spaces. The licensee issued FPP 020, Program Administration Revision 0, and Section 3.5.2 provides instructions for the RFW to perform their assigned watch duties. The inspectors reviewed FPP 020. Revision 0, and verified that it contains adequate instructions for the RF The licensee completed their corrective actions and the inspectors verified that they have been complete .4 (Closed) Insoection Followup Item (IFI) 50 395/95020 01: air in SW piping to suction of TDEFW pump. On December 11, 1995, the licensee performed maintenance on the TDEFW pump and following maintenance the suction header was filled and vented. When the TDEFW pump was started for aost maintenance testing low suction pressure alarms were received in t1e control room. In addition, local suction and discharge pressure indicators fluctuated abnormally. The licensee determined that the cause of the )ressure fluctuation was air in the TDEFW pump suction header from t1e backup B SW supply piping. Investigation revealed that this section of piaing had been drained on December 11 and the procedure to fill and vent tie piping was inadequate. Station Operating Procedure (S0P) 117 Service Water System, Revision 17, Change A and S0P 211, Emergency Feedwater System Revision 9 Change K, added steps for venting the piping from SW to the EFW pump suctions. The inspectors verified that the changes provided adequate guidanc The licensee's investigation determined that the inadequate filling and venting was the source of the air in the SW piping. The inspectors .

reviewed the root cause evaluation (RC No. 1075) and considered that it adequately addressed the issues. The licensee has demonstrated the pump's operability by the successful performance of STP 220.002 Turbine Driven Emergency Feedwater Pump Test, Revision 1. The licensee inspected the pump during Refueling Outage 9 and found no damage. The inspectors reviewed the inspection report. The licensee completed all 1 the corrective action )

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II. Maintenance l M1 Conduct of Maintenance M1.1 General Comments Insoection Scope (62707) i The inspectors observed or reviewed all or portions of the following work activities: ,

• Maintenance Work Request (MWR) 90102007, Modify Indicator IPI00494 '

Operating Bands Per MRF 90I02G l l

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. Preventive Maintenance Task Sheet (PMTS) P0207426, Replace Purge Unit Oil Return Dehydrator on C Chille . PMTS P0208294, Replace XVX16401C-VU, C Chiller Oil Return Solenoid Valv * PMTS P0205659, Calibrate IFS 09035A, Chill Water Chiller C Outlet Flow Switc . MWR 9604109. Determine and Correct Cause of Increased Noise from Motor Outboard Bearing on B Spent Fuel Cooling Pum . MWR 9603369. Repair XVC06653-SF, B Spent Fuel Cooling Pump Discharge Check Valv . MWR 9703130. Clean / Repair Flanged Connection on Discharge of B Spent Fuel Cooling Pum b. Observations and Findinas l

The licensee's maintenance personnel performed a major areventive maintenance package on the C safety related chiller. T1e inspectors observed several aspects of this work and concluded that it was well I planned and coordinated between the various maintenance group No l concerns were identifie I Corrective maintenance was performed on the B spent fuel cooling pump including replacing the motor, repair of a bolted connection leak, and repair of the discharge check valve. The motor was exhibiting an increased noise level from the outboard bearing. The discharge check valve was showing signs of excessive seat leakage when the pump was scured after filling the refueling cavity from the Refueling Water Storage Tank. Upon disassembly, it was discovered that the valve disk was hung up such that the valve did not close. Part of the disk near the hinge pin did not have sufficient clearance with the valve body to allow the valve to close by its own weight. This condition was documented on a non conformance notice and the disk was machined to i provide the necessary clearance. The valve was reassembled and tested I to verify full disk travel. The inspectors considered the licensees actions concerning this work to be appropriat c. Conclusions All observed maintenance activities were conducted in an appropriate manner and in accordance with established procedures. Good coordination and planning were noted with regards to some safety-related chiller work. Corrective maintenance activities on spent fuel cooling components were effective.

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l l M2 Maintenance and Material Condition of Facilities and Equipment

M2.1 Surveillance Observation

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a. Inspection Scope (61726)

i i The inspectors observed or reviewed all or portions of the following

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{ . STP-170.002, Diesel Fire Pump Monthly Test, Revision 2 ;

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. STP 501.001, Battery Weekly Test, Revision 9

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b, Observations and Findinas i

The inspetors observed the activities associated with the test of the diesel driven fire pump which is conducted monthly by operations

personnel. The pump was operated for a minimum of 30 minutes and monitored for proper operation of both the pump and the engin Following the test, the operators verified proper levels in the fuel tank and the engine oil sump. The inspectors did not identify any )

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J The licensee conducted weekly surveillance testing on the safety-related i batteries. Data was taken on one pilot cell on each battery (cell #35 5 for the A battery and cell #2 for the B battery). Parameters measured

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for each pilot cell included electrolyte level, cell voltage, cell temperature, and specific gravity. A corrected specific gravity was then calculated and verified to be greater than 1.200. No concerns were identifie c. Conclusions j Surveillance testing was conducted in a professional and safety

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conscious manner. Testing was performed by qualified personnel using

{; approved procedure M3 Maintenance Procedures and Documentation j M3.1 Human Red Tao Proaram J

1 a. Inspection Scope (62707)

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The inspectors reviewed the licensees program for using human red tags

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to ensure personnel safety during the conduct of maintenanc b. Observations and Findinas The licensee's human red tag program is outlined in SAP-201, Danger Tagging, Revision 5, Section 6.6. The human red tag is used by

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7 electrical personnel when the use of a danger tag is not practical. A note in Section 6.6 states:

' "Some electrical activities require intermittent operation of circuits which preclude installation of a Danger Tag. To ensure personnel protection, an Electrical Maintenance

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! person may be stationed at the electrical component in lieu of a Danger Tag."

Shift Supervisor approval is required prior to the use of a human red tag. A list of personnel currently qualified to act as a human red tag

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is maintained in the tagout log book in the control room. Attachment VI

of SAP 201 is used to record the as found position of the component and the date and time that the component is repositioned. The human red tag is required to remain at the component the entire time the component is used for isolation. The com)onent is restored to its as found position and independently verified w1en it is no longer required for isolatio c. Conclusions

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The licensee's human red tag program was adequate to ensure personnel I protection when the use of a danger tag is not practical. Configuration

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controls and personnel qualifications were maintained as required.

M8 Miscellaneous Maintenance Issues (92902)

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M8.1 (Closed) LER 50-395/96005: engineered safety features actuation signal steam line isolation. NCV 50 395/96007 06 was issued to close this even III. Enaineerino El Conduct of Engineering l E1.1 Licensee Review of Westinahouse Nuclear Safety Advisory Letter 96-004 a. Insoection Scooe (37551)

The inspectors reviewed the licensee's response to Westinghouse Nuclear Safety Advisory Letter 96 004 Control And Protection Interactio b. Observations and Findinos >

Westinghouse issued Nuclear Safety Advisory Letter 96 004 to address the interactions between the control and protection functions of the steam generator level control system which could prevent Reactor Protection System (RPS) actuation on low low steam generator level at some plant Specifically, a concern was identified with designs that share a common steam generator tap for steam generator level instruments and main steam flow instruments. A postulated failure at the common tap, along with an additional postulated failure of a second level instrument could prevent

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the RPS from initiating a reactor trip and an emergency feedwater automatic star t Licensee engineering personnel evaluated this concern and determined

, that this was not a problem. The evaluation indicated that a failure of the common tap would drive the level signal high and the steam flow

signal low. Both of these signals would drive the feed flow signal lo In the event of a failure of a second level instrument, the reactor would still trip on low feed flow. The inspectors agreed with this

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l Conclusions

. The engineering evaluation performed in response to Westinghouse Nuclear j Safety Advisory Letter 96 004 was adequate. Licensee engineering

. personnel determined that the plant is not susceptible to the concerns outlined in this letter and the reactor is still protected under the

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postulated instrument failure E1.2 Reactor Trio Breaker Circuitry Review ,

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i Insoection Scope (37551)

During a review performed under NRC Generic Letter (GL) 96 01, Testing )

of Safety Related Logic Circuits, several questions were raised

concerning the adequacy of the 3 resent surveillance testing requirements ;

of the P 4 permissive logic. T1e inspectors reviewed the licensee *s !

response to these question i

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Observations and Findinos )

1 1 The reactor trip breakers and the reactor trip bypass breakers both !

contain a 33 contact and a 52 contact which is part of the RPS P 4 circuitr But under current surveillance testing requirements, only the reactor trip breaker 52 contacts and the reactor trip bypass breaker 33 contacts are verified. In the normal )lant configuration, the reactor trip breakers are racked in and t1e bypass breakers are racked out. In this condition, the trip breaker 52 contacts are open and the bypass breaker 33 contacts are closed. In the event of a reactor trip, i the trip breakers oyen and the trip breaker 52 contacts close. This i

provides input to tie solid state protection system. Current l surveillance testing adequately tests the circuit in the normal

. configuration. During testing, the trip bypass breaker is racked in which changes the P 4 circuitry to a configuration which is not fully

, tested. The action statement in TS allows 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> to restore the P 4 :

circui During testing, the licensee enters a TS action statement which allows either two hours or four hours for testing (depending on the reason for racking in the bypass breaker) and six hours for repairs.

These times are much more restrictive than the P-4 action statement. In 1

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response to this concern, the licensee will declare P 4 inoperable on

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the associated train when the bypass breaker is racked in. In addition, the testing procedures are being enhanced to verify all contacts in the

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P 4 circuit. The inspectors considered these actions adequate to address this 33 and 52 contact testing issue.

A second question concerned the P-4 logic that feeds into the high steam flow program circuitry to lock the program into the minimum region (less than 40 percent) following a reactor trip. This feature is not tested under the current surveillance testing program. This feature is not described in the Final Safety Analysis Report (FSAR) and is not taken credit for in any accident analysis. The licensee has determined that adding the P 4 input to the high steam flow setpoint program loop calibration would be an enhancement. The inspectors agreed that the high steam flow function would remain operable even if the P-4 input failed.

The adequacy of the function and logic testing of the P 4 input to the turbine trip circuitry was also questioned. This function provides a turbine trip signal in the event of a reactor trip. Specifically, the concern was that the circuitry is not tested as a whole or verified to ;

actuate independently from other sources of a turbine trip signal. In ;

response, design engineering personnel noted that the P 4 logic that feeds the turbine trip circuitry is verified to actuate on both trains by performance of two separate surveillance tests. These are STP-345.039. Reactor Trip P 4 Actuating Device Operational Test, Revision 4 and STP-172.001, AMSAC Output Relay Test, Revision The P 4 input is independently tested by utilizing voltage readings across the trip breaker contacts to ensure continuity. The inspectors concluded that these concerns were adequately addressed in a logical and thorough manner.

The reactor trip breakers and bypass breakers are periodically changed out on line as a preventive maintenance item. A question was raised concerning the 33 and 52 contact verification following breaker replacement. Currently, no independent verification is performed for the 52 contacts after completion of the breaker replacement. These contacts are internal to the breaker and are disconnected when the i breaker is removed with the contact block. The 33 contacts are '

physically located in the breaker cubicle and are not disconnected when the breakers are replaced. Verification of these contacts is performed every refueling outage as required by TS but are not required to be i verified after breaker replacement. The 33 and 52 contacts actually '

consists of multiple individual contacts in a single assembly, each performing different functions. The change in state of the contact assemblies is verified by the proper reactor trip and bypass breaker status light indications on the main control board which are generated by some of the individual 52 contacts. Although this does not verify all of the 52 contacts, it is reasonable to assume that the assembly is functioning properly based on main control board indications until an enhanced procedure is developed. The inspectors agreed that current testing requirements are adequate but that improvements in testing these contacts would. provide added confidence of the integrity of the circuit following breaker replacemen .

12 Conclusions 1 The licensee's program to identify possible problems in the

-

safety-related logic circuits, as described in NRC GL 96-01, was effective. Several questions were raised concerning the adequacy of current testing procedures for the reactor trip and bypass breaker P 4 ;

circuit Design engineering personnel adequately addressed all of '

these concerns in a logical and reasonable manner. Testing procedure and program enhancements were identified to improve the verification of these circuit E1.3 Generic Letter 89-10 Procram Imolementation  !

. Insoection Scope (Temocrary Instruction 2515/109)

This inspection provided an assessment of the licensee's implementation i of GL 8910, Safety Related Motor 0perated Valve Testing and '

Surveillance. The licensee notified the NRC that they had completed implementation of GL 89-10 in a letter dated December 20, 199 The assessment conducted during this inspection included evaluations of:

the scope of Motor-0perated Valves (MOVs) included, the calculations of the design basis differential 3ressure, the determinations of MOV settings and verifications of iOV capabilities, the periodic verification of MOV capabilities, the MOV post maintenance and post modification testing, and pressure locking and thermal binding. The inspectors conducted the assessment through a review of the licensee's GL 8910 implementing documentation and through interviews with licensee personnel. The documents reviewed included: TR01520 001, Generic Letter 89 10 Motor 0perated Valve Setup. Test, and Performance Validation Summary Report, Revision 1, dated June 1, 1996: RC-95 0201. Submittal For Closure of Generic Letter 8910, Safety Related Motor-0perated Valve '

Testing and Surveillance, dated July 27, 1995: and the procedures, calculations, test records, etc., referred to in the following paragraph In addition, the inspectors reviewed summary tabulations of MOV information and calculation results prepared by the license Prominent among the tabulations was a list of "available valve factors" (AVFs) for the licensee's GL 89-10 gate and globe valves. The licensee prepared this list at the inspectors' request to aid them in assessing the capabilities of the licensee's M0Vs. The inspectors compared the AVFs of the licensee's valves to valve factor requirements established through industry testing to determine if the AVFs were conservatively higher. The AVFs were calculated for each MOV using the formulas given belo AVF (Close) = (Th * [1 - (LSB + U)]) PL SR/ (Disc Area * DBDP)

AVF (0 pen) = (Th * [1 - (LSB + V)]) - PL + SR/ (Disc Area * DBDP)

wher Th = thrust available for limit switch control, thrust at

. . _ _ - . - . . - - . -- .. . = - . . . .. _ -

.

torque switch trip for torque switch control LSB = load sensitive behavior  !

l U = uncertainty (instrument and other uncertainties combined J by square root sum of squares method)  ;

,

= packing load

'

PL SR = stem rejection load DBDP = design basis differential pressure Observations and Findinas Scope of MOVs Included in the Proaram

,

The scope of valves in the licensee's GL 89 10 program was l reviewed previously by the NRC and was determined acceptable !

during Inspection 50 395/92 02. In the current ins)ection, the !

inspectors reviewed the list of MOVs contained in t1e licensee's program and found that the scope had been reduced by 17 valve The bases for excluding each of these valves was documented in calculation DC01520, Revision 5. The inspectors reviewed the ;

bases and found that they were satisfactory. The current program '

i sco>e included 83 gate valves,12 globe and sto 21 autterfly valves for a total of 116 valves. p check valves, and Determinations of Settinas and Verifications of Capabilities for Gate. Globe. and Stop Check Valves The inspectors selected and reviewed calculations, test data, and evaluations for the following sample of valves in order to assess the licensee's validation of calculation assumptions and their determinations of MOV settings and capabilities:

XVG03111B B Reactor Building Cooling Unit Return Isolation XVG08000A Pressurizer Power Operated Relief Valve (PORV) Block XVG08107 Charging Line Isolation XVG02802B Main Steam Header B Emergency Feedwater Pump Turbine Supply XVG03001A A Train Refueling Water Storage Tank Suction Shutoff XVG06797 Reactor Building Sprinkler System Supply Header Isolation The inspector's findings were as follows:

M0V Sizina and Switch Settinas The licensee's gate valve thrust calculations utilized the standard industry equations. The initial gate valve set up thrust

_ _ _ .. _ . . _ . _ _ _ _ . _ _ ._ __ . _

. .

,

'

calculations used a valve factor of 0.60 in the open and close direction for Westinghouse valves 0.50 in the open and close direction for Anchor Darling valves, and 0.60 in the open and close direction for Borg Warner valves. In calculations relating i thrust to torque, the licensee initially assumed a stem friction coefficient of 0.15. The valve factors and stem friction coefficients were subsequently modified, where appropriate, based on in plant test results or (for valve factors only) confirmatory

data from other industry sources. Gate valves had their minimum i required thrust adjusted for load sensitive behavior, torque j

switch repeatability, and diagnostic equipment uncertainties. The

maximum allowable thrust was adjusted for torque switch i repeatability and diagnostic equipment uncertainties. The values

for torque switch repeatability and diagnostic equipment

uncertainties were adjusted by procedure during the field set u Globe and stop-check valve thrust requirements were calculated using standard industry equations with a 1.1 valve factor. As for gate valves, the licensee assumed a 0.15 stem friction coefficient in relating thrust to torque. The globe valves were installed in a flow under the seat configuration. All globe and stop-check valves had their minimum required thrust adjusted to account for load sensitive behavior. Similar to the gate valves, the minimum and maximum calculated thrust requirements for these valves were adjusted to account for diagnostic equipment uncertainties and  !

torque switch repeatabilit Valve Factor I i

The licensee determined a dynamic test based valve factor for each valve that was satisfactorily dynamically tested and used that valve factor to calculate the valve's thrust requirement Additionally, the licensee determined dynamic test based valve factors for identified groups of similar valves and used the group valve factors in determining thrust requirements for the MOVs in each group that had not been satisfactorily dynamically teste From their review of the bases for the valve factors used by the licensee, the inspectors identified weaknesses in the valve factors used for several groups. These weaknesses and the actions which the licensee initiated to address each are described below:

,

. The justification for the valve factor used in calculating the closing thrust requirements for MOV group 13 was considered weak. The value (0.5) was based on bounding the results of only two industry tests (not licensee tests) and the inspectors were aware of additional industry data which indicated that a higher valve factor value might be appropriat Because these MOVs had a relatively high available valve factor (0.6), the insaectors did not have any immediate concern for their opera)ilit However, the long term ca) abilities of these MOVs were considered marginal. T1e licensee established item LIC MSP970008 in

.. .- _ - - - . - - , _ - . . .. -..

. .

15 l their regulatory tracking system to bypass the close torque switch of these valves (increasing the available valve factor) and to further review industry data to verify their valve factor. These actions were scheduled to be complete l in November 199 . The justifications for the valve factors used calculating thrust recuirements for MOV groups 10, 11, 12 and 22 were considerec weak because they were based on a limited amount of test data and bounding values. There was no immediate concern for the operability of these valves, as they had l very high available valve factors (0.8 and greater). !

However, the long term capabilities of these valves could be of concern if there were significant changes in their setups or operating conditions. The licensee established item LIC-MSP970009 in their regulatory tracking system to review industry data to verify their valve factors. This action I was scheduled to be complete in November 199 The regulatory tracking system items which the licensee initiated to address the above weaknesses were considered satisfactor Load Sensitive Behavior j i

The licensee determined a dynamic test based load sensitive behavior for each valve that was satisfactorily dynamically tested and used that value in calculating the valve's thrust l requirements. Additionally, the licensee analyzed the results from the tested valves and determined values to be applied in calculating thrust requirements for MOVs that did not have reliable test measurements. The licensee based their load sensitive behavior analysis on 38 measurements: 29 from torque closed MOVs and 9 from limit closed MOVs. To minimize the measurement error associated with torque switch trip, the licensee used a different method to determine load sensitive behavior than is typically used in the industr In their method, the licensee determined load sensitive behavior thrust as the difference between the dynamic test thrust at control switch trip and the static thrust at the same torque that produced the dynamic control switch trip. For this approach to be valid, the stem factor must be stable during the seating portion of the dynamic test. The inspectors reviewed examples of the licensee's dynamic test diagnostic traces and verified that the stem factor remained stable in this region of the valve strok The licensee's Engineers Technical Work Record 13157, GL 89 10 LSB in the Close Direction, dated February 28, 1997, and Technical Report TR01520 001, Generic Letter 89 10 Motor 0perated Valve Set- ,

up Test, and Performance Validation Summary Report, dated June 1, '

1996, specified a load sensitive behavior margin of 4 percent to be added to the dynamic component of the minimum required thrust i for limit closed MOVs and 11 percent margin to be added for MOVs '

l l

- - . . -. .- . . .

l

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that were torque closed. Based on a statistical analysis of the licensee's load sensitive behavior data, the inspectors considered these values marginal. However, the inspectors found that margins which the licensee added to account for other uncertainties were sufficient to relieve any concern as to the final calculated thrust requirement Stem Friction Coefficient l

!

As mentioned previously above, the licensee's original calculations assumed a stem friction coefficient value of 0.15 in i determining an actuator's output thrust capability. The licensee l monitored stem friction coefficient during static and dynamic '

tests. The originally assumed stem friction coefficient of 0.15 was compared to the stem friction coefficient obtained in testing to ensure that the assumed value was conservativ If the test I value for a valve exceeded 0.15, a stem friction coefficient of 0.20 was applied to the tested MOV and all other non tested MOVs in its group. Further, if the associated test was used to justify the valve factor used for another valve group, the 0.20 stem friction coefficient value was also ap) lied to that group. The ;

licensee prepared a data information sleet and alots of open and closed dynamic stem friction coefficients for t1e inspectors. The data and plots indicated that the use of a 0.15 stem friction coefficient in the close direction was adecuate to account for variations in stem friction coefficien Fowever, the open direction data indicated that a value of approximately 0.165 would be more appropriate. Because of a 10 percent margin which the licensee added to the o>en direction minimum required thrust the inspectors found that tie licensee's calculated minimum thrust requirement was adequat Re evaluation of Actuator Capabilities Based on Industry Information The licensee recently re reviewed the design basis ca) abilities of their MOV actuators using information made available ay Commonwealth Edison and documented in Commonwealth Edison White Paper 125, Installed Motor Capability Evaluation Revision Based on this information the licensee determined that, at worst-

.

l case conditions, five of their MOVs had insufficient capabilities to open their torque switches at the present torque switch settings. This could result in motor damage and loss of capability. The licensee documented this condition for resolution in Nonconformance Notice (NCN) 97-0180. The inspectors found that the licensee satisfactorily evaluated and demonstrated that these valves could perform their safety functions and that appropriate corrective actions had been recommended (resetting the torque switches during the upcoming Fall 1997 outage).

_ __

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17 l l

.

Desian Basis Capability The inspectors found that the licensee's tests provided accurate l results and were well documented. Tiie test results, supplemented !

in a few cases with industry results, supported the design basis capabilities of the licensee's MOVs. The inspectors did not entirely agree with the valve factors (based on bounding values),

stem friction coefficients, and load sensitive behavior determined by the licensee from their testing. However, as discussed above, i based on conservative margins which the licensee applied in their l calculations and actions which the licensee instituted to j strengthen the valve factors selected for five valve groups (10, i 11, 12, 13, and 22), the inspectors considered the licensee's verifications of design basis capabilities satisfactory. Determinations of Toraue Recuirements and Verifications of the Caoabilities of Butterfly Valves The licensee summarized their validation of the torque i requirements and capabilities of their butterfly valves in Technical Report TR01520 001, Revision The report documented that the butterfly valves were all limit controlled and that the torque requirements for each butterfly valve had been specified by the manufacturer, Henry Pratt. The report provided evaluations of dynamic tests which the licensee conducted to demonstrate that the valves were capable of performing their design basis function Each valve was dynamically tested and the torque recorde (Examples of torque traces from the tests were reviewed by the inspectors.) Based on a review of the test parameters and results documented in TR01520 001, the inspectors found that the licensee had adequately demonstrated the design basis capabilities of their l butterfly valves. Periodic Verificatior!

The inspectors found that the licensee's requirements for periodically testing MOVs in accordance with GL 8910 were s)ecified in Engineering Services procedure ES 513. Revision T1is procedure specified that the testing would be performed at least every 5 years or 3 refueling outages, unless a longer period could be justified by the MOV com)onent engineer ES 513 further indicated that the testing would )e static but that additional testing would be performed in accordance with submittal RC 95 0201 to the NRC (dated July 27, 1995). RC-95 0201 stated that two dynamic tests would be performed on six of the licensee's GL 8910 valves during the next 10 years. Additionally, the submittal indicated that the static testing of less risk significant valves would be performed less frequently than specified in ES 513. The inspectors reviewed printouts from the licensee's work planning databases and verified that the periodic testing was include *

l l

The licensee's periodic verification actions were considered adequate for closure of GL 89-10. The NRC may re-assess the licensee's long term aeriodic verification program as part of its ;

review for GL 96 05, )eriodie Verification of Design-Basis !

Capability of Safety Related Motor-0perated Valves, dated September 18, 199 !

l 5. Post Maintenance and Post Modification Testina The inspectors reviewed the licensee's post maintenance test requirements and guidance, which were specified in General Test Procedure GTP 214. Post Maintenance Testing Guideline. Revision I Additionally, the inspectors reviewed the post maintenance testing I recorded for Work Orders 94M3237 (replace stem nut), 93T0020 1 (repair valve), 94N3109 (repair / replace valve), 9404290 (replace I thermal overloads), 9503577 (repair declutch handle) and 9603426 I (troubleshoot and repair position indication). The inspectors j found that the licensee had implemented acceptable post :

maintenance testin l The licensee's post modification test requirements were determined by engineers using post maintenance testing requirements as guidance. To assess the adequacy of the post modification testing implemented by the licensee, the inspectors selected and reviewed I the testing recorded for modifications 217450143 (modify actuator logic to limit open/ shut), 227650007 (drill Sole in disk), l 223620026 (replace worm gear), 217450136 (ocuator wiring )

modification), and 217450164 (regear actuator). The inspectors found that the testing specified was appropriate and concluded i that the licensee had implemented acceptable post modification l testin l 6. Pressure Lockina and Thermal Bindina l The licensee's GL 95 07 Pressure Locking and Thermal Binding of i Safety Related Power 0perated Gate Valves, submittals dated February 13 and August 2,1996 stated that an analytical method was utilized to demonstrate that the actuators on valves XVG08000A B.C RC (PORV blocks), XVG08801A,B SI (high head injection to Reactor Coolant System (RCS) cold legs), XVG08884 SI (high head injection to RCS hot legs), XVG08885 SI (alternate high head injection to RCS cold legs), XVG08886 SI (high head injection to RCS hot legs), and XVG08889 SI (low head injection to RCS hot i legs) could develo) adequate thrust to overcome pressure lockin l Pressure locking t1 rust requirements for these valves were i determined by the Westinghouse Owners Group (WOG)/ Commonwealth Edison method. The inspectors used the WOG/ Commonwealth Edison methodology with the appropriate GL 8910 parameters to I independently calculate the thrust required to overcome pressure l lockin l l

i

.

The inspectors found that the actuators for valves XVG08000A,B,C-RC, and XVG08801A,B SI were able to develop the thrust required to overcome pressure locking. The actuator capability for valve XVG08885 SI was satisfactory for the short term but was marginal and should not be considered as long term corrective action to preclude pressure locking. A low disk coefficient of friction was used in its pressure locking calculation and the margin between actuator capability and valve pressure locking thrust requirements were minima The licensee's pressure locking calculations for valves XVG08884-

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SI, XVG08886-SI and XVG08889 SI assumed that bonnet leakage over an eight hour period would reduce the amount of thrust required to overcome pressure locking and concluded that the valves could overcome potential pressure locking. The licensee used a Westinghouse analysis of bonnet depressurization rates for gate valves tested by Commonwealth Edison to determine bonnet depressurization rates for these valves. The inspectors reviewed

the results of the Westinghouse analysis and noted that the bonnet depressurization rates might not have bounded the bonnet depressurization rate of a low pressure coolant injection valve pressure locking event at another plant reported in Licensee Event Report 50 333/91014-00, Bonnet Pressure Locking of Low Pressure ECCS Injection Valves, dated August 5,1991. The inspectors concluded that the licensee could not demonstrate that the Westinghouse analysis bonnet depressurization rates were applicable to their flexible wedge gate valves. Therefore, the capabilities of valves XVG08884-SI, XVG08886 SI and XVG08889 SI to overcome pressure locking were in question. For valve XVG08889-SI, this issue was resolved for the short term by the availability of a safety evaluation prepared for the licensee by Westinghouse in 1988. The safety evaluation stated that sufficient hot leg recirculation flow could be provided by one of the redundant charging system hot leg injection flow paths; therefore XVG08889-SI would not be required to open. This safety evaluation was consistent with plant procedures. For valves XVG08884 SI and XVG08886 SI, the inspectors independently calculated the thrust recuired to overcome pressure locking assuming no bonnet leakage anc found that the actuators were able to develop the thrust required to overcome the pressure locking. However, the margin between the required thrust to overcome pressure locking and the actuator capability was marginal and should not be considered as long term corrective action to preclude pressure lockin The licensee's GL 95-07 subettals stated that valves XVG08000A,B,C-RC were not susceptible to thermal binding because the valves had been closed numerous times and reopened at a lower temperature without experiencing any problems. However, when the inspectors reviewed the history of these valves, they found the licensee did not have adequate historical data on the valves'

wedging and unwedging forces to support this conclusion. The historical wedging and unwedging forces may have been

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f l o

i 20 I

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significantly altered due to modifications undertaken in 1994. No )

measurements of the wedging and unwedging forces were available J for the period prior to the 1994 modifications. Therefore, the inspectors were unable to determine if these valves were susceptible to thermal binding under the current actuator setup condition The adequacy of the licensee's actions to address aressure locking and thermal binding remain under NRC evaluation. luring the current inspection, the inspectors raised issues regarding acceptable pressure locking analytical margins, bonnet depressurization assumptions, and possible thermal binding of the PORV block valves. The inspectors informed the licensee that their evaluations of valves XVG08884 SI, XVG08885-SI, XVG08886 SI and XVG08889 SI for pressure locking: and their evaluations of valves XVG08000A,B,C RC for thermal binding were currently insufficient to meet the intent of GL 95-07. The licensee stated that they would provide a supplemental response to GL 95 07 to address these issues. In the future, the NRC staff will address i these issues in their safety evaluation of the licensee's response to GL 95 0 . Strenaths The inspectors observed the following strengths in the licensee's implementation of GL 8910:

. The overall application of very accurate stem measurements of MOV torque and thrust in design-basis tests of gate and j globe valve '

. The extent of direct stem dynamic and static test torque i measurements performed on butterfly valve j e Except as noted above, valve factor determinations that were l very well-justifie . The particularly well described bases for the capabilities of gate and globe valves provided in technical report TR01520 00 ,

c. Conclusions The NRC inspectors concluded that the licensee had met the intent of GL 8910 in verifying the design basis capabilities of their MOVs. The inspectors identified a few weaknesses in valve factor, load sensitive behavior, and stem friction coefficient values used in the licensee *s calculations. However, as discussed above, based on conservative margins which the licensee applied in their calculations and actions which the licensee instituted to strengthen the valve factors selected for five valve groups (10,11,12,13, and 22), the inspectors considered the licensee's verifications of design basis capabilities

_ _ _ . _ __ _ _ _ _ ._ ._ _ _ __. ._

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f

4 l 21

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satisfactory. The ins >ectors identified the licensee's completion of

'

the actions to strengtlen the valve factors as IFI 50 395/97001 02. The

'

actions were specified in the licensee's regulatory tracking system as items LIC MSP970008 and LIC MSP97000 The inspectors also observed a number of licensee strengths, which were

described in E1.1. !

The adequacy of the licensee's actions to address pressure locking and I i thermal binding remain under NRC evaluation. Issues were raised

regarding the licensee's evaluations of four valves for pressure locking and three valves for thermal binding. Previously addressed by the NRC l through GL 8910, the NRC staff will now address these issues in their ;

i safety evaluation of the licensee's response to GL 95 07. The licensee agreed to provide a supplemental response to GL 95 07 to address these issue Based on the NRC's review of the Summer GL 89 10 program and its implementation, and the actions which the licensee established to address weaknesses in valve factors, the NRC is closing its review of the GL 89 10 program at Summer.

E2 Engineering Support of Facilities and Equipment

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E2.1 Diesel Generator Hiah Exhaust Temoeratures l a. Inspection Scope (37551)

'

The inspectors reviewed the circumstances of a cylinder exhaust temperature that was observed to be high out of the normal band during a surveillance test of the B diesel generato b. Observations and Findinos

On March 11, during the performance of STP 125.002, Diesel Ge6.erator

, 0)erability Test, Revision 17, on the B diesel generator, it was noted

tlat the exhaust temperature for the number 12 cylinder was high out of the normal band as stated on the operating logs. At full load, the exhaust temperature for this cylinder was indicating 909 F. The normal

'

'

temperature band stated on the operating logs is 600 to 900 F. The maximum temperature limit on the logs is 1000*F.

A review of the operating logs for each month from January 1996, revealed that during tests conducted in the summer months (May through 1

July) the number 12 cylinder exhaust temperature routinely exceeded the !

maximum normal band of 900 The logs indicate that the highest I temperature for this cylinder was 932 F and occurred in July 199 l 4 During that same July 1996 test, exhaust temperatures for cylinders 3.

'

4, 5, and 6 also exceeded the maximum normal band. At no time did any exhaust temperatures exceed the maximum temperature limit of 1000 Based on this review, the inspectors concluded that the high cylinder

.

exhaust temperatures were due to the elevated ambient temperatures  !

. .

during the summer months and did not effect the operability of the diesel generato The operating logs provide a minimum, a maximum, and a normal range for each data point for which they are applicable. When the diesel generator is in operation, the o)erator monitors the im)ortant parameters and records them on t1e appropriate logs. T1e parameter limits stated on the logs are the o)erator's guide to any required actions. During periods of high amaient temperatures, it is normal for some of the cylinder exhaust tem)eratures to exceed the normal band stated on the operating logs. T1e inspectors concluded that the stated normal band was not adequate in that it did not encompass the normal expected temperatures during year round operation. Also, the licensee was not able to determine the basis of some of the limiting values that are in the logs. The inspectors considered the lack of an adequate normal band on the operating logs for the diesel engine exhaust temperatures to be a weaknes Conclusions A weakness was identified concerning the adequacy of the limiting parameters which are listed on the diesel generator operating log Diesel engine exhaust temperatures had exceeded the established normal band, as stated on the operating logs, during aeriods of high ambient temperatures. The licensee was not aware of t1e basis for some of the limiting values contained in the operating logs.

E2.2 Charaina/ Safety In.iection (SI) Pumo Recirculation Minimum Flow Valve Inspection Scooe (37551)

The inspectors reviewed the licensee's actions regarding the power lockout modification on the charging /SI pump recirculation minimum flow line valve, Observations and Findinas By letter from SCE&G to the NRC dated November 7,1986, the licensee committed to installing a power lockout feature on the charging /SI pump recirculation minimum flow line valve (XVG 8106). This is a motor operated valve in the common recirculation header which acceats flow from each of the three charging /SI pumps and returns it to t1e volume control tank to ensure a minimum flow of water through a running pump to prevent damag It was identified that this normally open valve was vulnerable to a single failure which could cause spurious operation in the closed direction and subsequent damage to a running pump. To prevent this, the control system for this valve was modified in 1988 to provide a power lockout feature to remove power from the motor operator during normal plant operation. This modification removed the single failure concer . -_ .. _--

. .

23 A 10 CFR 50.59 evaluation was performed for this modification in April

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1988. The evaluation indicated that this bodification did not require a change to the plant TS. During some recent work on a separate modification, the licensee noted that valve XVG 8106 should have been included in TS surveillance requirement 4.5.2.a when the modification was done in 1988. Surveillance requirement 4.5.2.a is a list of valves that are to be verified in the correct position with power removed once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Prior to discovery, the licensee had verified power was removed from this valve every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> but valve position was verified only every 31 days,

'

The licensee submitted a TS change request to the NRC to add valve XVG 8106 to surveillance requirement 4.5.2.a. Also, the operating logs were revised to aad the valve position verification every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The

licensee reviewed other valves which have been equipped with similar I

<

power lockout features to determine if the problem was more widesprea ;

No additional problems were identified. The inspectors concluded that these actions were adequate to correct the discrepancy. The failure to

.'

adequately control the design of the XVG 8106 power lockout feature modification is identified as a violation. This licensee identified and

, corrected violation is being treated as an NCV consistent with Section VII.B.1 of the NRC Enforcement Policy. This is identified as NCV 50-

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395/97001 0 c. Conclusions An NCV was identified concerning the failure to adequately control the design of the Charging /SI pump recirculation minimum flow line valve l i gwer lockout feature modification. The licensee failed to revise the '

l TS to include this valve in the appropriate surveillance requirements section.

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E7 Quality Assurance in Engineering Activities (37551)

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E7.1 Review of Updated Final Safety Analysis Report (UFSAR) Commitments A recent discovery of a licensee o>erating their facility in a manner ,

i contrary to the UFSAR description lighlighted the need for a special !

focused review that compared plant practices, procedures and/or parameters to the UFSAR description. While performing the inspections ;

discussed in this report, the inspectors reviewed the applicable

~

portions of the FSAR that related to the areas inspected. No discrepancies were identifie E8 Miscellaneous Engineering Issues (92903)

E8.1 (00en) URI 50 395/96011 08: evaluation of motor operated valves for meeting requirements of Appendix R Section III.L.7. This item was initiated to follow up on the licensee's completion of a reanalysis of Information Notice 9218 due to recent industry problems related to " hot

shorts" for Appendix R related motor operated valves. During the current inspection, the inspectors examined the status of the licensee's

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!

, 24 reanalysis and found that it had been completed. The results were l documented in Technical Work Record 16714, dated January 7, 1997. The

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I reanalysis concluded that the licensee's MOVs were not susceptible to '

damage which would preclude them from being placed in the required fire emergency positions 65 a result of fire induced hot shorts in the main ;

, control room or 448 cable spreading area. The inspectors did not assess the licensee's basis for this conclusion. The item will be subject to j further NRC review in a subsequent inspection.

IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 Radioactive Effluent Monitorina Instrumentation i Inspection Scope (84750)

The inspectors reviewed licensee's procedures and records pertaining to i surveillances and alarm setpoints for selected radicactive effluent

monitors. The surveillance procedures and established alarm setpoints were evaluated for consistency with the operational and surveillance requirements specified in sections 1.1.1 and 1.2.1 of the Offsite Dose

. Calculation Manual (0DCM) for demonstrating the operability of the monitors.

4 Observations and Findinas j The inspectors toured the Control Room and relevant areas of the

Auxiliary and Turbine Buildings with a licensee representative to i determine the operational status for the following effluent monitors: i

! RM L9 Liquid Radwaste Effluent Line t

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RM-L8 Turbine Building Sump Effluent Line {

RM A3 Main Plant Vent Exhaust System i

,

The above monitors were found to be well maintained and operable at the l time of the tour )

1 The inspectors reviewed the procedures listed below which related to channel checks, source checks, channel calibrations, channel operational i tests, and alarm setpoints for the above listed monitors:

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OAP 10 Operating Logs HPP 710 Sampling and Release of Radioactive Liquid Effluents STP 137.002 Radiation Monitor Monthly Source Check STP 360.069 Liquid Radiation Monitor (RML0009) Calibration STP 360.070 Liquid Radiation Monitor RM L9 OP Test STP 360.067 Turbine Building Sump Liquid Radiation Monitor (RML0008) Calibration STP 360.068 Turbine Building Sump Liquid Radiation Monitor RM L8 OP Test

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STP 360.035 Main Plant Exhaust Atmospheric Radiation Monitor )

(RMA0003) Calibration STP-360.036 Main Plant Vent Exhaust Atmospheric Radiation Monitor {

RM A3 Gaseous Channel Operational Test l The inspectors determined that the above procedures included provisions for performing the required surveillances in accordance with the relevant sections of the ODCM and at the specified frequencies. The inspectors also reviewed selected licensee records of performance of channel checks, source checks, channel calibrations, and channel operational tests for each the above listed monitors. The records selected for review were generally the most recently completed  ;

surveillances for each of the required check / test. Records for the )

first 3 batches of liquid radwaste released during January 1997 were also reviewed. Those records indicated that the surveillances had been performed in accordance with their applicable procedures. The inspectors noted that the licensee used National Institute of Standards and Technology (NIST) standards for routine monitor calibrations. The ,

ODCH specified that NIST standards be used for initial instrument

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calibration and sources related to the initial calibration be used for subsequent calibration. Use of NIST standards met ODCM requirement !

The inspectors considered the use of NIST standards for routine calibrations as a program enhancement. The inspectors also verified that the alarm setpoints for the above listed monitors were set more conservatively than required by the ODCM. Data compiled by the licensee from the Removal and Restoration Log, which was used to note when instruments were removed from and returned to service, indicated that each of the above listed monitors were operable more than 99 percent of the time during 199 Conclusions Based on the above reviews and observations, it was concluded that the licensee had implemented an effective program for maintaining  :

radioactive effluent monitoring instrumentation in an operable condition and for performing the required surveillances to demonstrate their operabilit '

R1.2 Meteoroloaical Monitorina Proaram Inspection Scope (84750)

The inspectors reviewed the licensee's procedures and records for the surveillances performed to demonstrate operability of the meteorological monitoring instrumentation as required by TS 3/4.3. Observations and Findinos The inspectors reviewed procedures Operations Administrative Procedure (0AP) 106.1, Operating Logs, Revision 6, and STP 393.004, Heteorological Tower Calibration Revision 4. and determined that they included provisions for performing daily channel checks and semiannual channel l

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calibrations as prescribed by the TSs. The inspectors also reviewed the records for the most recent instrument calibrations for wind speed, wind direction, and air temperature which were performed during December 1996. Those records indicated that the calibrations were current and had been performed in accordance with the applicable procedure. During a tour of the control room, licensee personnel displayed on a monitor the computerized log of the daily channel checks aerformed for the previous three days. The inspectors determined t1at the daily channel checks had been performed as required and noted that the meteorological monitoring instrumentation was operable at the time of the tour, Conclusions Based on the above reviews and observations, the inspectors concluded that the surveillance requirements for demonstrating operability of the meteorological monitoring instrumentation were me R1.3 Control Room Emeraency Ventilation System Insoection Scope (84750)

The inspectors reviewed the licensee's procedures and records for the surveillances required to demonstrate operability of the Control Room Emergency Ventilation System (CREVS) and the Control Room Isolation Radiation Monitor (RM A1). Those procedures and records were evaluated for consistency with the operational and surveillance requirements delineated in TSs 3/4.7.6 and 3/4. Observations and Findinos The inspectors toured the mechanical equiament room in which the control room ventilation systems were located. T1e licensee's cognizant system engineer located and identified, for the inspectors, the major components of the systems. The emergency ventilation system included two independent trains consisting of fans, dampers, pre filters, High Efficiency Particulate Air (HEPA) filters, and charcoal absorber filter beds. The inspectors verified that the air flow paths and arrangement of the system components within those paths were consistent with the system diagram (Figure 9.4 1) referenced in Section 9.4.1.2 of the FSA The inspectors observed that the components and associated duct work were well maintained structurally and that there was no physical deterioration of the equipment or duct work sealant The inspectors reviewed the procedures listed below and determined the they included provisions for performing functional tests, filter leak testing, air flow measurements, differential pressure measurements, and ;

charcoal adsorption efficiency testing. The procedures also included !

provisions for performing channel checks, channel calibrations, and channel operational tests for the RM Al radiation monitor. The surveillance frequency and acceptance criteria for the test results !

specified in those procedures were consistent with the TS requirement Review of selected records of those tests, generally the most recently

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completed, indicated that they had been performed in accordance with the testing procedures and that the acceptance criteria had been me AP 10 Operating Logs STP 124.001 Control Room Emergency Air Cleanup .

STP 454.002 Control Room Emergency Air Cleanup System Performance Test STP 454.001 Control Room Emergency Air Cleanup System Canister Test STP 125.010 Integrated Safeguards Test Train A STP 125.011 Integrated Safeguards Test Train B STP 360.031 Control Room Supply Air Atmospheric Radiation Monitor :*

RMA0001 Calibration STP-360.032 Control Room Supply Air Atmospheric Radiation '

Monitor, RM A1, Channel Operational Test 0AP 11 Guidelines for Operations Department Special i Instructions c. Conclusions  :

Based on the above reviews and observations, the inspectors concluded that the licensee had implemented an effective program for maintaining l the CREVS in an operable condition and for performing the required ,

surveillances to demonstrate operability of the system.

P2 Status of EP Facilities, Equipment, and Resources P2.1 Emeraency Response Facilities and Eauioment Inspection Scope (82701)

This area was inspected to determine whether the licensee's Emergency Response Facilities (ERFs) and equipment, were adequately maintained in i accordance with the Emergency Plan. Recuirements a3plicable to this area are found in 10 CFR 50.47(b)(8) anc (9),10 CFR 50.54(q),

Sections IV.E and VI of Appendix E to 10 CFR Part 50, and the licensee's Emergency Pla b. Observations and Findinas The inspectors toured the Technical Support Center (TSC), Operational l Support Center (0SC), and the Emergency Operations Facility (E0F). The !

inspectors tested telephones, fax machines, Emergency Response Facility l Information System monitor, Dose Computer, and an Early Warning Siren System computer. The inspectors inventoried three emergency cabinets, two field monitoring kits, and two controlled content drawer Several i controlled volumes of the Emergency Plan Procedures (EPPs) were audited !

in the ERFs for completeness and being maintained up to dat The inspectors reviewed documentation for EPP 103, Emergency Equipment Checklist, Revision 4, and EPP 104, Verification of Communications Capability, Revision 4, from January 1996 through February 1997, and

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l observed that required tests and audits were completed at the required j frequencies, j The licensee installed a new Electronic Information System (EIS) in the ERFs. The EIS system automated the transfer of information among the ERFs and to government agencies. The system was used as an electronic status board, log book, and information transfer. Any station could review another stations log or status board. A line printer immediately l printed out all entered data so as to provide a hard copy to facilitate l reconstruction of an event should the system fai i This EIS system was developed by the licensee. The EIS computer system )

consisted of two main central processing units (CPUs) and numerous terminals along with support hardware. The main CPU was connected by the network and had telephone / modem backup should the network become inoperable. All hardware in the )lant was powered by diesel backed circuits. The hardware at the E07 was equipped with uninteruptable power supplies. Other hardware included fax modems to allow automatic faxing of the Emergency Notification forms to State and local government Other than the EIS system, no significant changes had been made to the facilitie Conclusion The inspectors concluded that the licensee maintained the emergency response facilities and equipment at a satisfactory level of operational readiness. Equi) ment and facility audits were pro >erly completed and inventories had 3een satisfactorily maintained. T1e licensee's newly developed EIS for the ERFs has the potential to enhance the licensee's capabilities in an emergency situatio P2.2 Public Alertina System 1 Inspection Scope (82701)

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This area was inspected to review the licensee's method of notifying the i public in the event of an emergency, and to review the Public Alerting l System test frequency and test data. Requirements applicable to this l area are found in 10 CFR 50.47(b)(5),Section IV.D of Appendix E to 10 CFR Part 50, and the licensee's Emergency Pla Observations and Findinos The licensee maintained 106 sirens within the Emergency Preparedness Zone for their public alert and notification system. The inspectors reviewed documentation from January 1996 through February 1997 of weekly silent tests, monthly growl tests, and an annual sounding of the sirens.

< The 1996 V.C. Summer Nuclear Plant siren availability report summary indicated a siren availability of 98.1 percent compared to a required availability of 90 percen _ _ _ _ _ _ _ _ . _ . . _ . _ . _ _ . _ _ . . . . _ _ . _ _ . . _ _ _ _ _ _ . _ _ _

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Documentation reviewed by the inspectors indicated the licensee '

performed annual preventative maintenance on the sirens during the i months of June through August 1996, and semi annual preventative

maintenance on the siren control units during April and December 199 The inspectors' review of V.C. Summer's siren testing documentation 1 determined that the sirens had been tested at the required frequencies.

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, The inspectors concluded that siren availability was high, maintenance

of the siren system was good, and that the sirens had been tested at the

required frequencies.

l P3 EP Procedures and Docu E tation l P3.1 Chanaes to the Emeraency Plan and Procedures I Insoection Scope (82701)

The inspectors reviewed the licensee's process for making changes to the Emergency Plan and EPPs. The inspectors reviewed changes to the

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Emergency Plan and EPPs to evaluate whether changes to the EPPs were in >

agreement with and implemented the Emergency Plan. Requirements j applicable to this area are found in 10 CFR 50.47(b)(16),10 CFR

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50.54(q), Appendix E to 10 CFR Part 50, and the licensee's Emergency i Plan, Observations and Findinas

! Revision 38 of the Emergency Plan was in effect at the time of the

! inspection. Revision 38 had an effective date of December 17, 199 The revision was a complete reprint because of the licensee changing

their_ w ed processing program and incorporated comments from NRC's

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i review of Revision 36. The licensee used procedure SAP-139, Procedure Development Review Approval and Control Revision 16 Attachment XIII, 1 Determination Of Decrease In The Effectiveness, when making changes to i the Emergency Plan and EPPs. The inspector reviewed SAP 139 1 documentation associated with Revision 38 of the Emergency Plaa and the

! fifteen revisions to the EPPs. In the revision documentation packages,

changes incorporated in the revision were identified in Section 7.0,

Revision Summary, of the procedure The inspectors observed that some

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of the change " summaries" did not provide sufficient information about i the change for the reviewer to fully understand the changes. Some

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examples in EPP 102, Emergency Plan Training, were:

. Changed to wording of Section 4.2 to clarify the inten . Changed 5.3.1B to include documentation requirements

(QA-QSR 95158).

. Changed 5.3.2 to 5.4 and included documentation requirements

(QA-QSR 95158).

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The inspectors observed that copies of the revisions were submitted to the NRC within 30 days of the revisions implementation dat c. Conclusion The inspectors concluded that the licensee's reviews of Emergency Plan and Emergency Plan Procedure changes were satisfactory and met the requirements of 10 CFR 50.54(q).

P5 Staff Training and Qualification in EP PS.1 Trainina of Emeraency Response Personnel a. Inspection Scope (82701)

The inspectors reviewed the Emergency Response Training Program to evaluate whether emergency response personnel were initially trained and retrained annually to maintain their training current. Requirements applicable to this area are contained in 10 CFR 50.47(b)(2) and (15),

Section IV.F of Appendix E to 10 CFR Part 50, and the licensee's Emergency Plan, b. Observations and Findinas The inspectors observed that ERO members wee current in their annual retraining. The inspectors randomly selected approximately twenty individual ERO members and performed an independent verification that they had received their required initial training and annual retrainin The inspectors reviewed Emergency Preparedness group's quarterly training audits and verified that the licensee was conducting the audits as required in EPP 102, Emergency Plan Training Revision 3, effective date of June 20, 1996. In addition to the quarterly audits, the inspectors observed that the licensee performed a weekly training verification on each weekly duty roster prior to the roster being issue The inspectors reviewed Attachment 1 of EPP 102 which listed the required training courses (Lesson Plans) for the corresponding ERO positions. The inspectors reviewed two of the Emergency Preparedness lesson plans. The two lesson plans reviewed were well organized, and contained sufficient detail to provide the necessary information. The inspectors noted that the lesson plans had received the required annual review in February 1997. While reviewing the lesson plans, the inspectors identified two instances in which the lesson plans had not been updated to agree with the Revision 38 of the Emergency Plan. Both instances involved the December 1996, Revision 38 to the Emergency Plan in which the augmentation start time requirement was changed from "after notification" to "after emergency declaration." The inspector observed that the licensee also taught Emergency Plan and EPP revisions as part of the annual retraining. The change to Revision 38 of the Emergency Plan that pcrtaining to augmentation start time was discussed in the procedure change portion of the annual retraining. The exams associated

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with the lesson plans were challenging and the questions well writte The inspectors noted additional examples of lack of detail in reviewing the exams. One of the exams had two identical questions, the other exam 1 asked the same question two different ways, and a third question gave the answer to the other two questions. The inspectors' review comments concerning the lesson plans and exams were discussed with the license l The licensee acknowledged the inspectors' review comments. The licensee promptly corrected the inspectors' comment of the lesson plan, and stated that they planned to review and revise the exam The Emergency Preparedness staff participate in one training session for each shift operating crew during each cycle of licensed operator re-qualification simulator training. The inspectors observed one of these session The Emergency Preparedness staff observed crew's performance to ensure that emergencies were properly classified in a timely manner and that notifications were properly completed. The inspectors noted that the training was most beneficial to the control room communicators as they went through the pager activation process and notifications to ,

proxy State and local government I Conclusion l

The licensee maintained a good initial training and annual retraining I progra ERO lesson plans and exams were well organized and contained i good detail. The inspectors identified four examples of a lack of a ,

detailed review in the lesson plans and exam j P5.2 Emeraency Plannina Drills Inspection Scope (82701) '

The inspectors reviewed the licensee's drill documentation to evaluate whether they were conducting the types and number of drill identified in EPP 105, Conduct of Drills and Exercises, Revision 2. Requirements ;

applicable to this area are contained in 10 CFR 50.47(b)(14), '

Section IV.F(1) of Appendix E to 10 CFR Part 50, and the licensee's Emergency Pla Observations and Findinas The inspectors reviewed documentation for licensee conducted table top drills, training drills, evacuation drills, and an augmentation drill since the last inspection. The inspectors observed that drill and exercise objectives required by EPP-105 were being completed at the required frequencie The quality of drill documentation had improved since the last inspection in March 199 Report formats were more consistent and documentation for a particular drill was contained in one fil .-.-- -. - - - _ - - - . - . . _ . _ - - .

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c. Conclusion The licensee satisfied the drill commitments in their Emergency Plan and s EPP-105, Conduct of Drills and Exercise l

P EP Organization and A &inistration '

P6.1 Emeraency Preparedness Oraanization a. Inspection Scope (82701)

i This area was inspected to determine if any changes in the licensee's management or personnel had occurred which would effect the efficiency or performance of the Emergency Preparedness Organization. Requirements applicable to this area are found in 10 CFR 50.47(b)(1) and (16),

Section IV.A of Appendix E to 10 CFR Part 50, and the licensee's Emergency Pla b. Observation and Findinas  !

The inspectors observed that the licensee had changed the ERO response from a first responder type to a rotating four (4) team approac !

During an emergency, even though there was a designated ERO duty l section, all ERO members were called in. After all ERO members had reported to the ERF, the duty section would assume the ERO positions, continuing staffing plans would be made, and the off duty sections would be dismissed. Discussions with the licensees' staff indicated that this approach had fostered team work and better performance by the ERO. The inspectors reviewed documentation that the site successfully conuucted an off-hour unannounced ERO staffing drill on December 3, 1996, c. Conclusion The changing from first responders to a four rotating team approach had improved teamwork and performance by the ER P7 Quality Assurance in EP Activities P7.1 Reauired 10 CFR 50.54(t) Audit of Emeraencv Preparedness Program (82701)

a. The inspectors reviewed this area to assess the quality of the required audit and evaluate whether the audit met the requirements of 10 CFR 50.54(t) and the licensee's Emergency Pla b. Observations and Findinas The licensee's most recent independent audit 0A AUD 97001 0. was a two person audit performed between January 14 and February 11, 1997. The

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, 33 i inspectors reviewed the audit's documentation. The audit was performed using both performance and compliance based techniques from selected criteri The audit questions supported the audit objectives and were developed prior to commencing the audit. The audit identified both strengths and weakness in the Emergency Preparedness program. The audit identified three findings, three quality action items, one enhancement, and three quality system review procedure comment sheets. No adverse impact was noted in the audit regarding the performance of the Emergency Plan activities.

, Conclusion The inspectors' review of the Emergency Preparedness program audit determined the audit to be organized, thorough, and objective. The audit satisfied the requirements of 10 CFR 50.54(t).

P7.2 Licensee's Corrective Action Proaram For Drill Comments and Issues Inspection Scope (82701)

This area was reviewed to evaluate the licensee's corrective actions to t

comments and issues identified in their drills. Requirements applicable to this area are contained in 10 CFR 50.47(b)(14). Observations and Findinqs The inspectors selected three or four drill comments from each of the five drill packages and reviewed the licensee's documentation to determine if the comments were tracked and resolved. The licensee could

not provide any documentation that some comments were addressed and i resolved. Examples of drill comments not being tracked to resolution or not being documented were:

* The condition of vehicles used for field monitoring.

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. The TSC signout boards could not be immediately located.

I Some of the resolutions of drill comments that were tracked contained

insufficient detail to clearly convey what was done.

. After discussions with the licensee, the inspectors determined that all

! drill comments were being resolved, but this conclusion could not be clearly determined from the available documentatio Conclusion The licensee adequately tracked findings to completion and resolved the

drill finding Documentation was not always available to demonstrate J adequate closure had been achieve i i

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51.1 General Comments (71750)

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The inspectors observed routine security and safeguards activities during the conduct of plant tours throughout the inspection period. No concerns were identified. During the week of March 3. the NRC conducted

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an Operational Safeguards Readiness Evaluation (0SRE). The ins)ectors observed portions of these activities. A separate report will 3e issued to assess the results of this evaluatio S2 Status of Security Facilities and Equipment S2.1 Protected Area Liahtina Insoection Scope (71750)

The inspectors reviewed the licensees actions regarding lighting in the protected are Observations and Findinas General area lighting in the protected area is accomplished by the use of seven high mast lighting units consisting of either six or eight lamp Lighting in areas which are obscured or shadowed are illuminated using portable lights in sufficient numbers and output to obtain a minimum of 0.2 footcandles of illuminatio Security personnel are responsible for performing Security Procedure (SPP) 230 Security Lighting System Inspection, Revision 1. This procedure requires that the lighting system be insSected every seven days during the hours of darkness. It specifies t1e minimum lighting requirements and the actions necessary to correct or com)ensate for inadequate lighting levels. The inspectors considered t1e protected area lighting system and the associated inspections to be adequate to ensure that sufficient lighting is available between the hours of sunset and sunris Conclusions Lighting in the protected area was adequate to illuminate the are Established ins)ection procedures contained sufficient requirements to ensure that lig1 ting levels are maintained at or above minimum level .. . - - . - .. - . - - . - . . - . - . . . - - - . - - - - - - -

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35 Manaoement Meetinas X1 Exit Meeting Sumary The inspectors ) resented the inspection results to members of licensee 4 management at t1e conclusion of the inspection on February 28, March March 21, March 31, and April 17, 1997. The licensee acknowledged the

, findings presented.

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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 l

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PARTIAL LIST OF PERSONS CONTACTED i

Licensee F. Bacon, Manager, Chemistry Services i

L. Blue, Manager Health Physics S. Byrne, General Manager, Nuclear Plant Operations R. Clary, Manager, Quality Systems M. Fowlkes, Manager, Operations

S. Furstenberg, Manager, Maintenance Services i S. Hunt, Manager, Quality Systems

. D. Lavigne, General Manager, Nuclear Support Services

G. Moffatt, Manager, Design Engineering

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K. Nettles, General Manager, Strategic Planning and Development I

! H. O'Quinn, Manager, Nuclear Protection Services i A. Rice, Manager, Nuclear Licensing and Operating Experience

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G. Taylor, Vice President, Nuclear Operations

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T. Taylor, General Manager, Engineering Services

R. Waselus, Manager, Systems and Component Engineering

~: R. White, Nuclear Coordinator, South Carolina Public Service Authority B. Williams, General Manager, Engineering Services t

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G. Williams, Associate Manager, Operations

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INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems IP 61726: Surveillance Observations IP 62707: Maintenance Observations IP 71707: Plant Operations IP 71750: Plant Support Activities IP 82701: Operational Status of the Emergency Preparedness Program IP 84750: Radioactive Waste Treatment Effluent and Environmental Monitoring IP 92901: Followup Plant Operations IP 92902: Followup - Man tenance IP 92903: Followup EnL seering TI 2515/109: Inspection'Re.:uirements to Generic Letter 89-10, Safety Related Motor 0peratec Valve Testing and Surveillance l

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ITEMS OPENED, CLOSED, AND DISCUSSED Opened

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! 50-395/97001-01 NCV failure to perform the specified surveillance test on the turbine driven emergency feedwater pump (Section .

01.2).

50 395/97001 02 IFI actions to address weaknesses in valve factors .

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(Section E1.3.c).

50 395/97001 03 NCV failure to control the design of the charging / safety l injection pump recirculation minimum flow valve power lockout feature (Section E2.2).

Closed 50 395/97001 01 NCV failure to perform the specified surveillance test on  !

the turbine driven emergency feedwater pump (Section 01.2).

50 395/95003 LER volume in the sodium hydroxide tank above Technical i Specification limits (Section 08.1).

50 395/95009-01 VIO failure to control the volume in the containment l spray additive tank (Section 08.2).

50 395/95013 01 VIO failure to follow procedures (Section 08.3).

50 395/95020 01 IFI air in service water piping to suction of turbine 4 driven emergency feedwater pump (Section 08.4). l 50 395/96005 LER engineered safety features actuation signal - steam line isolation (Section M8.1).

50 395/97001 03 NCV failure to control the design of the charging / safety injection pump recirculation minimum flow valve power lockout feature (Section E2.2).

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Discussed 50 395/96011 08 URI evaluation of motor operated valves for meeting requirements of Appendix R Section III.L.7 (Section ,

E8.1).