IR 05000293/1998010
| ML20198L796 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 12/22/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20198L780 | List: |
| References | |
| 50-293-98-10, NUDOCS 9901050119 | |
| Download: ML20198L796 (30) | |
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.. , s Enclosure U.S. NUCLEAR REGULATORY COMMISSION
REGION I
License No.: DPR 35 Report No.: 98 10 Docket No.: 50-293 Licensee: BEC Energy
' 800 Boylston Street Boston, Massachusetts 02199 ,
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Facility: Pilgrim Nuclear Power Station Inspection Period: October 20,1998 - December 8,1998 Inspectors: R. Laura, Senior Resident inspector R. Arrighi, Resident inspector D. Silk, Sr. Emergency Preparedness Specialist R. FuhrmeL'+er, Sr. Reactor Engineer L. Cheung, b . Reactor Engineer Approved by: C. Cowgill, Chief Reactor Projects Branch No. 5 Division of Reactor Projects
4 c-9901050119 981222 PDR ADOCK 05000293 0 pm
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. ,i l EXECUTIVE SUMMARY Pilgrim Nuclear Power Station NRC Inspection Report 50-293/98-10 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers resident inspection for the period of October 20,1998, through December 8,1998;in addition, it includes the results of announced inspections by a regional senior emergency preparedness specialist and a senior fire protection reactor engineer. Further, a senior Region i electrical engineer performed an l in-office review of LER 97-13.
Operations
- The conduct of routine operations was professional and safety-conscious. An initiative to require newly licensed operators to serve under instruction watches prior to assuming full licensed duties was positive. (Section 01.1)
- Reactor engineers prepared a thorough power maneuver plan to support a planned
!- down power to 70% reactor power. Reactor fuel vendor recommendations were followed to minimize the chance to develop a reactor fuel leak. (Section 04.1)
- Operators maneuvered the plant and performed individual control rod scram time testing in a competent manner. Test anomalies were promptly evaluated prior to proceeding. (Section 04.1)
- Operators were slow to declare the "B" SBGT train inoperable. Operators troubleshot the cause of the "B" SBGT fan trip for one hour prior to entering the applicable technical specification action statement. (Section 04.2)
Maintenance i
- . A good questioning attitudo was displayed by the electrical maintenance mechanics l during work on motor operated valve actuators when they observed that the wiring was not in accordance with the internal wiring diagram. (Section M1.1)
- A procedure weakness was identified during the performance of the standby gas treatment surveillance involving the adequacy of the system retest. The licensee
! initiated a problem report to resolve this issue. (Section M1.1)
- Operators used remote cameras to closely roonitor valve leaks inside the condenser bay. Efforts to stop packing leakage from the "B" feed water regulating valve
'during a down power were not completed. Interim actions were taken to mitigate the eifects of the steam leak. (Section M2.1)
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- Overall, the inspector observed that the licensee maintained continued attention to
. material condition deficiencies. The NRC did note some minor deficiencies that were not captured in the licensee's corrective action system (Section M2.1)
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Enaineerina
- The licensee's corrective actions taken and planned for degraded and non-conforming equipment conditions (residual heat removal single failure vulnerability, heat exchanger supports) was determined to be good. (Section E8.1 and E8.3)
- The inspector concluded that the licensee's extensive engineering review for resolving a previous load shed issue resulted in the identification of the load-shed-circuit cable separation problem. This problem was properly evaluated, reported to !
the NRC with corrective actions taken and planned. (Section E8.2)
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j * Two radiation dose rate signs in the "B" residual heat removal (RHR) quadrant were '
l not updated after chemical decontamination of the RHR system. (Section 01.1)
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l .* The implementation of the fire protection program was found to be acceptable, as i evidenced by: the installed detection and suppression systems are in good repair, ;
the smoke detectors and sprinkler heads were not obstructed, control of
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l combustible material was generally good, the new "B" switchgear room raceway <
l fire barrier enclosures met the requirements for 3-hour rated barriers for safe shutdown systems, the design of the main transformer fire detection, fire
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suppression, and oil drainage systems documented in the field revision notices !
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(FRN), and the fire brigade was well trained, knowledgeable, and enthusiastic.
(Sections F2.1, F2.3, F2.4, and F4.1)
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Based on the issues documented in the fire prctection program self assessment report,.the fire protection program audits, and the associated prs, the inspector l determined that the self-assessment and audits had been successful in identifying l. program strengths and areas for impmvement. The Fire Protection improvement l Program is an excellent initiative, and appears to have the proper focus to resolve l fire protection program deficiencies. (Section F7.1 and F7.2)
'e Emergency equipment surveillances and communication tests were performed as l
l required and the facilities were determined to be in a good state of operational
! readiness. (Section P2)
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-* A review of the licensee's procedure change review process, and a sampling of recent procedure changes, indicated that a good procedure control program was being implemented. (Section P3)
- - Overall ERO member training was assessed as good because Plan requirements were being met and no adverse drill performances were observed. The licensee maintains the ERO at least three deep in key k ,tions. (Section P5 and P6)
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- . Based upon generally good licensee performance during drills, the absence of repeat
- audit findings, and no adverse trends in the EP program, the licensee's problem l identification and corrective action processes were determined to be effective. The
EP program audits were thorough and the reports were useful for licensee
~ management to assess the effectiveness of the EP program. (Section P7)
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i TABLE OF CONTENTS EX EC UTI VE S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . il Summary of Plant Status ............................................1 1. O PE R AT I O N S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 01.1 G eneral Comme nts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 04 Operational Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . 2 04.1 Reactivity Controls During Down power . . . . . . . . . . . . . . . . . . . 2 04.2 Techn: cal Specification Implementation ................... 3 08 Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 08.1 (Closed) LER 5 0-2 9 3 /9 7-2 8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 11. M A I N T E N A N C E . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 M1 - Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 M1.1 (Open URI 50-2 9 3/9 8-10-02) . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 M2.1 Degraded Equipment Problem Identification . . . . . . . . . . . . . . . . . 6 M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 M8.1 (Closed) LER 5 0-2 9 3 /9 8- 10 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 M8.2 (Closed) LER 5 0-2 9 3 /9 8 - 1 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 111. ENGINEERING . . . . . . . . . . . . ...................................8 E8 Miscellaneous Engine onng issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 E8.1 (Closed) LER 5 0-2 9 3 /9 8 -07 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 E8.2 (Closed) LER 5 0-2 9 3 /9 7- 13 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 E8.3 (Closed) LER 50-2 9 3/9 8-0 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1 E8.4 (Closed) LERs 50-293/97-27,98-02, and 98-04 . . . . . . . . . . . . 11 E8.5 (Closed) eel 97-482-03023, salt service water (SSW) Single Failure, eel 97-482-05014,50.73 Reportability, URI 97-05-06, SSW Single Failure, and LER 97-1 1 -00, -01 and -02. . . . . . . . . . . . . . . . . . . 1 1 I V. PLA NT S U PPO RT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 F2 Status of Fire Protection Facilities and Equipment ................ 12 F2.1 Material Condition of Fire Protection Equipment . . . . . . . . . . . . . 12 F2.2 Fire Barrier Penetration Seals . . . . . . . . . . . . . . . . . . . . . . . . . . 13 F2.3 Raceway Fire 8arrier Enclosures .......................14 F2.4 Main Transformer Replacement Fire Protection Modifications . . . 15 F4 Fire Protection Staff Knowledge and Performance . . . . . . . . . . . . . . . . 16 F4.1 Fire Drill Observation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 F7 Quality Assurance in Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . 17 F7.1 Firt orotection Program Self-Assessment . . . . . . . . . . . . . . . . . 17 F7.2 Quanty Assurance Audits of the Fire Protection Program . . . . . . 18 P2- Status of EP Facilities, Equipment, instrumentation and Supplies . . . . . . 19 P3 EP Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 P5 Staff Training and Qualification in EP . . . . . . . . . . . . . . . . . . . . . . . . . 20 P6 EP Organization and Administration . . . . . . . . . . . . . . . . . . . . . . . . . . 21 P7 Quality Assurance (QA) in EP Activities . . . . . . . . . . . . . . . . . . . . . . . 21 iv f
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V. M AN AG EM ENT M EETINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 2 i
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'X1 Exit Meeting Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 2 X3 Management Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 )
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PARTIAL LIST OF PERSONS CONTACTED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 ^
l INSPECTION PROCEDURES USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 l
ITEMS OPENED, CLOSED, AND UPDATED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 !
LIST O F AC RO NYMS U SED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 5 <
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REPORT DETAILS Summarv of Plant Status Pilgrim Nuclear Power Station (PNPS) began the period at approximately 100 percent power. On December 3,1998, power was reduced to approximately 70 percent to perform a rod pattern adjustment and turbine valve testing. At the completion of there i activities, operators returned the unit to full power, where it remained through the end of the period.
On December 3,1998, operators declared the high pressure coolant injection (HPCI)
system inoperable due to a failed power supply inverter. A formal NRC notification (ENS l- 35103) was made to the NRC pursuant to 50.72 requirements. Later that night, the failed
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inverter was replaced, operators declared the HPCI syt. tem operable and exited the 14 day shutdown LCO.
! 1. OPERATIONS l
l 01 Conduct of Operations 1 l
l 01.1 General Comments (71707)
L Using Inspection Procedure 71707, the inspector conducted frequent reviews of
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ongoing plant operations. The inspector observed that proper control room staffing was maintained, continued use of self-checking, and plant behavior was commensurate with the plant configuration and plant activities in progress. Shift briefings and turnovers were well conducted with good discussion on compensatory measures and degraded equipment. Licensed reactor operators actively participated l in the turnover meetings. The latest nuclear industry operating experience l continued to be reviewed during the plant manager's morning meeting. Newly
[ licensed operators' stood under instruction watches prior to fully assuming their i licensed duties. This was viewed as a positive initiative by operations management.
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During tours of reactor plant spaces, the inspector noted some improvement in the cleanliness of the plant. Anomalies identified during tours were discussed with the nuclear watch engineer. The lighting in the residual heat removal (RHR) quadrants was improved and selected plant spaces were cleaned and painted. The inspector identified and informed radiation protection management that two radiation dose signs in the "B" RHR quadrant did not reflect actual conditions. These signs had not been removed / updated after the chemical decontamination of the RHR system.
The signs were removed and a problem report generated.
' Topical headings such as 01, M8, etc., are used in accordance with the NRC
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standardized reactor inspection report outline. Individual reports are not expected to
- address all outline topics.
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04 Operational Knowledge and Performance 04.1 Reactivity Controls Durina Down power a. jngnection Scope (71707)
Durhg deep back shift inspection, the inspector monitored operator performance during a planned power reduction to approximately 70% power to facilitate a rod pattern exchange and also to conduct various maintenance and surveillance
' activities.
b. Observations and Findinas Prior to the down power, reactor engineering personnel prepared a detailed power maneuver plan with guidance on recirculation flow changes and control rod l patterns. Reactor fuel vendor soft start-up recommendations were used to minimize l the potential to develop reactor fuel pin leakage. Reactor engineers were scheduled to supplement shift coverage to support power changes and the conduct of individual control rod scram time testing. Operations management had operators I attend "just in time" training on the simulator to pepare for the down power activities. Additionally, senior reactor operators held a pre-evolutionary briefing to review the planned activities. The inspector determined that good planning for the down power activities was evident.
The inspector observed operators lower reactor power to approximately 70% by slowly lowering core flow to 40 mlb/hr and then inserting control rods in group 16 to position 06. Operators followed procedure 2.1.4, " Station Power Changes." No abnormalities or equipment problems were noted during this power reduction. The !
inspector observed portions of individual control rod scram time testing. Good communication and command-and-control was evident between operators at the 905 control room panel, the control rod testing panel and locally at the hydraulic control unit station in the reactor building. Use of the prescribed self-checking I technique was also evident. After each individual rod scram, reactor engineers used the 3-D monicore to verify thermallimit data.
Operators carefully documented a test anomaly when some of the individual control rod bottom lights did not illuminate. Crew members thoroughly discussed this problem prior to proceeding. Operators initiated a problem report to document, evaluate and correct this condition. After control rod testing was completed, operators returned the unit to full power operations with no problems.
c. Conclusions Reactor engineers prepared a thorough power maneuver plan to support a planned down power to 70% reactor power. Reactor fuel vendor recommendations were followed to minimize the chance to develop a reactor fuel leak.
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Operators maneuvered the plant and performed individual control rod scram time testing in a competent manner. Test anomalies were promptly evaluated prior to proceeding.
O4.2 Technical Soecification Imolementation a. Insoection Scoce (71707)
The inspector monitored the performance of selected maintenance and surveillance activities to verify proper implementation of technical specification (TS) action statements.
b. Observations and Findinas On October 22,1998, during the performance of surveillance procedure 8.M.2-1.5.8.4, " Logic System Functional Test of the "B" Standby Gas Treatment System," the "B" standby gas treatment (SBGT) fan tripped unexpectedly.
Operators stopped the test, restored the reactor building ventilation to its normal lineup, and began investigating the cause of the f ailure. After approximately one hour of troubleshooting the SBGT system to identify the cause of the fan trip, operators declared the "B" SBGT system inoperable. The "A" SBGT train was started and verified operational approximately two hours after the system was declared inoperable. The inspector noted that this was three hours efter the "B" SBGT f an tripped. A problem report was issued to document the fan trip.
Subsequent licensee investigation determined that a procedure error caused the fan trip. The inspector determined that the procedure error was a minor vialation not subject to formal NRC enforcement.
The inspector questioned the nuclear watch engineer and the Operations Department Manager for the reason on the delay in declaring the "B" SBGT train inoperable and entering the applicable technical specification (TS). Although troubleshooting was initiated to identify the cause of the fan trip, the inspector determined that the system was inoperable at the time of the equipment f ailure.
Technical specification 3.7.B.1.c, requires that after one SBGT train is made or found to be inoperable for any reason, the other SBGT train shall be verified operable within the following two hours. However, the other train was not verified operable until three hours after the fan tripped which was in violation of TS. The inspector discussed his concern with licensee representatives. The operations manager acknowledged the concern and operations management initiated a problem report. The failure to complete the surveillance in the specified time is considered a minor violation and not subject to formal NRC enforcement. The inspector notes that of the other activities observed, the licensee properly implemented the technical specification requirements.
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c. Conclusions Operators were slow to declare the "B" SBGT train inoperable. Operators troubleshot the cause of the "B" SBGT fan trip for one hour prior to entering the applicable technical specification action statement.
08 Miscellaneous Operations issues 08.1 (Closed) LER 50-293/97-28: Intake Structure in a Confiauration inconsis.!pnt with Tornado Deoressurization Analysis Assumptions This LER documented that the configuration of the screen house was outside the i design basis of the plant. The door between the hypo-chlorination pump room and the traveling screen area was included as part of the tornado depressurization l model, but the door had been removed; and the station tornado procedure required that the operators secure open all intake structure doors, thereby creating large openings not considered in the tornado depressurization analysis. An engineering evaluation was performed that concluded that the intake structure remained operable.
The inspector conducted an on-site review of the LER and reviewed the corresponding engineering evaluation and proposed corrective actions and found l them to be appropriate. The inspector verified that the licensee resolved the
! discrepancy between the tornado depressurization analysis and the station tornado procedure; and developed a program to maintain sub-compartment barriers within l their design configuration. This licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-293/98 10-01). This LER is closed.
i l II. MAINTENANCE M1 Conduct of Maintenance M 1.1 (Ocen URI 50-293/98-10-02) General Maintenance and Surveillance
a. Inspection Scope (61726)
l The inspector observed portions of selected surveillance and maintenance activities to verify use of approved procedures, correct system restoration, and proper post work testing. The following activities were observed:
l P9500707 Re-terminate actuator of MO-1301-60 l
P97004i3 Replace spring pack on MO-1400-4B l 8.M 2-1.5.8.3 Logic System Functional Test of the "A" Standby Gas Treatment System 8.9.1.1 Diesel Oil Transfer System and Valve Quarterly Operability 8.5.4.4 HPCI System Valve Operability Test 8.5.4.1 HPCI System Pump and Valve Test 9.9 Control Rod Scram Time Testing
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l 5 b. Observations and Findinas ,
l During rnaintenance on motor operated valve MO-130160, electricians noted that the length of one of the actuator wires was short and that the actuator wires were
! not in accordance with the internal wiring diagram. The electricians stopped the work activity, notified supervision, and reviewed the applicable electrical prints.
Engineering verified that the actuator was correctly wired and generated a drawing change notice to reflect actual wire configuration. Thus, the circuit was electrically I
equivalent to the design. The issue of electrically equivalent circuits was previously ;
evaluated in Section E8.3 of NRC Inspection Report No. 50-293/97-04. The '
corrective actions were reviewed and found to be appropriste. The inspector determined that the maintenance staf f demonstrated good attention-to-detail and a questioning attit'ude by placing the work on hold and verifying proper wire configuration.
During performance of the surveillance on the "A" standby gas treatment (SBGT)
system, a temperature sensor was disconnected by unplugging the electrical connector (grey boot connector). Unplugging the connector causes a trip of the heater circuit and SBGT fan Upon completion of the surveillance, the procedure required double verification that the connector was restored and then the SBGT train returned to its normal standby lineup. The inspector noted that the SBGT fan is not restarted to verify proper electrical connection. The inspector questioned the adequacy of the surveillance procedure since only a visual verification of the electrical connection was performed rather than a functional test. The licensee acknowledged the inspectors question and issued a problem report to review the issue.
Discussion with several members of the licensee's staff revealed that actual system response is performed for other temperature elements that are disconnected and reconnected. The licensee indicated that the surveillance procedure would be revised to verify proper electrical connection. Also, a review of licensee procedure 1.13.1," Post Work Test Matrices and Guidelines," suggests that system functional testing is required for this situation. The adequacy of system retest is considered an unresolved item (URI 50 293/9810-02)pending further NRC review.
c. Conclusion A good questioning attitude was displayed by the electrical maintenance mechanics during work on motor operated valve actuators when they observed that the wiring was not in accordance with the internal wiring diagram.
A procedure weakness was identified during the performance of the SBGT j surveillance involving the adequacy of the system retest. The licensee initiated a I problem report to resolve this issue.
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M2.1 Dearaded Eauipment Problem Identificati >n l a. Insoection Scooe (62707)
During plant tours, the inspector verified that plant equipment deficiencies were being identified and entered into the licensee's corrective action program. Some areas toured by the inspector included the reactor building, EDG rooms, torus room
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and the HPCI and RCIC turbine rooms.
l l b. Observations and Findinas A number of plant equipment deficiencies are being identified by the plant staff as indicated by the presence of work request tags. Active leaks in the condenser bay
- were monitored with the use of remote cameras and were routinely checked.
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. Licensee efforts this period during a down power were not successful in correcting l packing leakage from the "B" feed water regulating valve which is located in the condenser bay. The licensee attempted to tighten the packing stud nuts but found
th9 nuts torqued to a higher than expected value. A decision was made to stop the work to aliow further evaluation prior to adjusting the packing nuts. As a precautionary measure, the licensee installed a deflector shield to ensure that steam l leakage from the packing gland did not adversely impact any adjacent controls or l equipment. The feedwater system engineer indicated that additional work was planned to correct the packing leakage during the next down power. 1-Three plant equipment deficiencies were missed by the plant staff during operator and management tours. in the high pressure coolant injection (HPCI) turbine room,
' the inspector noted that an instrument air line was improperly secured due to a i missing pipe restraint. The air line supplied air to several HPCI system air-operated valves. The air line was not supported for approximately 25 feet allowing excess line movement. The inspector informed systems engineering personnel who j initiated a problem report to document, evaluate and correct the problem. The inspector determined that the air line was by design not required to be seismically l l qualified. The air-operated HPCI system valves are designed to fail in the safe j l position on a loss of instrument air. i
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The second deficiency observed during plant tours involved two normally lit logic l status lights on the division i anticipated transient without scram (ATWS) panel.
Two lights, DS7A and DS7C, were nnt lit. The inspector informed the nuclear watch engineer and the light bulbs were replaced. The inspector interviewed the i system engineer and also the ATWS system maintenance history. No other
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- concerns were noted with the ATWS system panels. The third deficiency involved a loose inspection port on the T-13O lnstrument air receiver. The port was designed with one fastener. The inspector notified operators vibo initie.ted a problem report
, to document, evaluate and correct the prodem. The inspector noted that with few i exceptions, plant equipment deficiencies were identified by the plant staff and
- entered into the work contrvl process for correction.
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c. Conclusions Overall, the inspector observed that the licensee maintained continued attention to material condition deficiencies. The NRC did note sorne minor deficiencies that were not captured in the licensee's corrective action system.
Overall, the inspector noted continued attention to material condition deficiencies.
The NRC did note some minor deficiencies that were not captured in the licensee's corrective action system.
M8 Miscellaneous Maintenance issues (92902)
M8.1 (Closed) LER 50-293/98-10: Inadeauate Surveillance Performed for Containment Coolina Flow Rates This LER documented that a licensee calculation specified a containment cooling flow rate of 5100 gpm using one residual heat removal (RHR) pump, whereas the pump discharge check valve had been forward flow exercised to only 4800 gpm.
The inspector conducted an on-site review of the LER and verified that the RHR system has been tested to the required flow, and that the applicable surveillance procedures have been revised to require testing at 5100 gpm. Other potentially similar testing discrepancies will be evaluated as part of the licensee's design basis information recovery process. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50 293/98-10-03). This LER is closed.
M8.2 (Closed) LER 50-293/98-11: Reactor Floor Pluas Removed Durina Operation This LER documented that on November 26,1996, two concrete shield plugs were removed from directly over the torus compartment creating an opening between the torus compartment and the reactor building. This opening is not considered in the high energy line break (HELB), tornado, and floodino calculations. The licensee performed an analysis that showed the projected temperature, pressure, and flooding values were bounded by the existing analyses. The delay in issuance of this LER was attributed to an incorrect initial reportability evaluation in 1996 which focused on system operability. Such incorrect reportability evaluations were previously cited as a violation in NRC Inspection Report 50-293/97-05. The licensee has provided corrective actions in response to that violation that addresses the cause of this event.
The inspector conducted an on-site review of the LER and reviewed the corresponding engineering evaluation and proposed corrective actions and found them to be appropriate. The inspector verified that the licensee developed a program to maintain sub-compartment barriers within their design configuration.
This licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-293/98-10-04). This LER is closed.
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Violation, consistent with Section Vll B.1 of the NRC Enforcement Policy. (NCV 50- l 293/98-10-04). This LER is closed. )
111. ENGINEERING E8- Miscellaneous Engineering issues (92903) _
l E8.1 (Closed) LER 50-293/98-07: Sinale Failure Vulnerability of the Residual Heat Removal (RHR) System when in Suporession Pool Coolina a. Inspection Scope (37551)
The inspector reviewed a licensee identified design deficiency involving a single failure vulnerability of the RHR system.
b. Observations and Findinas The RHR single failure vulnerability could potentially result in the suppression pool ,
cooling (SPC) valves not automatically closing when called upon to perform their intended safety function. The required initiating events for this scenario include
- operation of the RHR system in the suppression pool cooling mode, a LOOP coincident with a LOCA, and the failure of the respective EDG. The SPC valves would have no power available and not automatically close, resulting in the low pressure coolant injection (LPCI) flow being diverted, in put, from the core back to the suppression pool with the valves open. During this period, LPCl flow to the reactor vessel would be less than that previously considered in the LOCA analysis, which presumes two LPCl pumps with one core spray pump in the event of an emergency diesel generator failure. 'The licensee indicated that notwithstanding this failure, the reduced flow from LPCI and the flow from the core spray pump should be sufficient to prevent peak central temperature from exceeding 2200*F and therefore was bounded by the assumptions in the LOCA analysis.
' Upon discovery of the vulnerability, a standirig order was issued that required operators to declare the LPCI system inoperable whenever the RHR system is in the SPC mode of operation. The licensee reviewed operating logs and did not identify any instance where the LPCI technical specification (TS) action statement was exceeded while in the SPC lineup. Plant procedure 2.2.19, " Residual Heat Removal," was subsequently revised to require entering the TS when in the SPC lineup, The licensee indicated that based on the low probability of occurrence, a TS amendment and UFSAR change was being considered to resolve this issue.
[ The inspector conducted an on-site review of the LER and verified that operators L declare the LPCI system inoperable and enter the corresponding TS whenever the l RHR system is in the SPC mode. The inadequate design of the RHR system, while j in suppression pool cooling, is a violation of design control requirements contained in 10CFR 50, Appendix B, Criterion lil, Design Controls. The inspector noted that several different initiating factors (i.e., LOCA, LOOP, EDG Failure, operation in SFP i
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cooling mode) are all simultaneously required for this condition to occur. Also, the inspector noted that operators could take manual actions to mitigate the problem if it did occur. Based on the low safety consequence and low probability of this scenario from occurring, this non-repetitive, licensee-identified and corrective violation is being treated as a Non-Cited Violation (NCV 50-293/98-10-05),
consistent with Section Vll.B.1 of the NRC Enforcement Policy. LER 98-07 is closed.
E8.2 (Closed) LER 50-293/97-13, Cable Separation for Load Shed Circuits On August 14,1997, the licensee identified that the control cables for the nonsafety-related loads of the load-shed circuitry were not classified as safety-related and, theref ore, were routed in nonsafety-related raceways with nonsafety-related cables. The load-shedding is considered a safety function to avoid l overloading of the emergency diesel generators (EDG). This condition was '
discovered when the licensee was reviewing the load shed circuits for resolving another issue. The licensee believed that this condition had existed since original plant construction. On September 16,1997, the licensee submitted Licensee Event Report (LER) 97-13 to the NRC to report this deficient condition.
The licensee initiated extensive corrective actions for this issue, including conducting a walkdown of the affected cables, performing an operability determination and a load shed f ailure analysis. The operability determination was documented in Engineering Evaluation 97-012 (dated August 14,1997) to determine the operability of the emergency diesel generators (EDG). This evaluation documented all cables external to the motor control centers and associated with the load-shed circuitry for both EDGs, including the cable function and routing. The licensee analyzed the effect of potential overload;ng of the EDGs if the load-shed circuitry did not shed the operating loads as ranuired when the EDG output breakers were closed. This evaluation of the load shec . cuits identified that the cables classified as nonsafety-related had the same quality (purchased to the same specification) as the safety-related cables and that the nonsafety-related raceway supports used the same seismic design as that for the safety-related raceways.
The licensee also updated EDG Loading Calculation PS-79-21, dated July 13,1998, to include a load shed f ailure analysis, which demonstrated the acceptability of the current condition. The analysis was based on an assumed cable failure condition that an over-(.urrent cable could overheat all other cables in the same raceway and j cause the load shed circuits associated with those cables to fail. The analysis indicated that for the worst cable tray failure, concurrent with a design basis '
accident (DBA) and a loss of offsite power (LOOP), only one EDG could be overloaded (inoperable). Although the analysis did not include the loading (64 kW)
of the 250 Vdc backup battery charger, this backup charger had been administratively prohibited from being connected to the swing bus during plant power operations at the time the analysis was performed. If a DBA concurrent with ,
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a LOOP occurs when the backup charger was connected to the swing bus, both EDGs could be affected, because of the automatic transfer function of the swing bus. The licensee had determined to continue to administratively prohibit the i
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backup battery charger to be connected to the swing bus until this cable-separation issue is resolved. The inspector conducted an in-office review of LER 97-13, Engineering Evaluation 97 012 and Calculation PS-79-21 and determined the operability determination and its supporting calculation acceptable.
The licensee had completed a design change package (PDC 97-26, dated April 23, l 1998) as a long term resolution to the load-shed-circuit, cable-separation' problem.
During the design s'. age, the licensee also i'fentified other cases where nonsafety-related cables were routed in rafety-related raceway for shedding safety-related loads. Discussion with the licensee indicated that the EDG overloading effect for these circuits was bounded by Engineering Evaluation 97-012. This design change involved 39 nonsafety-related load-shedding circuits which require physical modification and two nonsafety-related loads which require upgrade by analysis of their load-shed circuits to safety-related. The licensee completed Safety Evaluation No. 3149 for this design change. The licensee stated that implementation of PDC 97-26 was scheduled for the next refueling outage (starting April 1999). The inspector reviewed PDC 97 26 and the associated safety evaluation and found them of good quality. LER 97-013 is closed.
The licensee's failure to originally classify the load shed circuits for nonsafety-related loads as safety-related is a violation of 10 CFR 50, Appendix B, Criterion lil, Design Controls. The inspector considered the safety consequence of this deficient condition to be low because the EDGs would only be impacted if, during the DBA concurrent with a LOOP, the backup battery charger is connected to the swing bus and the worse case cable tray failure is postulated. Normally, the backup battery I charger is disconnected except during the maintenance of the primary battery chargers. Prior to the mid-1990's, this maintenance occurred only during plant l outages; and, af ter identification in 1997, the backup charger was administratively prohibited from being connected to the swing bus during operation. During a postulated LOOP, when load-shedding is required, all nonsafety-related ac power cables are expected to be deenergized, reducing the likelihood of a total failure of the cables in the worst case cable tray. Therefore, the inspector determined the above non-repetitive, licensee-identified violation to be a Non-Cited Violation (NCV 50-293/9810-06), consistent with Section Vll.B.1 of the NRC Enforcement Policy.
The inepector concluded that the licensee's extensive engineering review for resolving a previous load shed issue resulted in the identification of the load-shed-circuit cable separation problem. This problem $nas properly evaluated, reported to the NRC with corrective actions taken and planned.
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E8.3 (Closed) LER 50-293/98-03: RBCCW and TBCCW Heat Exchanaer Supports Outside Desianj3 asis Seismic Reauirements This LER documented problems with the seismic adequacy of the RBCCW and ,
TBCCW heat exchanger supports in connection with the USl A-46 Program. The l saddle support base plates did not conform to design drawings. I The inspector conducted an on-site review of the LER and reviewed the i corresponding engineering evaluation and proposed corrective actions and found )
them to be appropriate Calculations were performed that demonstrated that the I reinforced concrete piers and anchor bolts have adequate capacity for the design seismic demand; however, the design margins are less than those for full ,
qualification. The inspector verified that maintenance requests have been generated
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to restore full qualification of the support plates. This work is scheduled to be performed prior to restart from the cycle 12 refueling outage scheduled for April 1999. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50 293/98-10-07). This LER is closed.
E8.4 (Closed) LERs 50-293/97-27,98-02, and 98-04: Emeraency Diesel Generator LEDG) Air Temoerature Below D9_sian Limits j l
These LERs documented three different occasions when the EDG room temperature l went below the design temperature of 60*F. These events were influenced by
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wind direction and speed.
The inspector conducted an on-site review of the LERs and reviewed the corresponding engineering evaluation and proposed corrective actions. A vendor analysis was performed that concluded the diesels remain operable with a room ambient temperature above 40* F if the diesel jacket water and lube oil temperatures remain within established design limits. A review of surveillance test data demonstrated that the EDGs have started and come up to rated speed within the required 10 seconds with outside air temperatures of 50*F or less. The inspector verified that procedure 2.1.12.1," Emergency Diesel Generator Daily Surveillance," l was changed to require that the outside ambient and EDG room temperatures be I recorded daily. The procedure also requires that EDG jacket water temperature, and l lube oil temperature and pressure be recorded daily. Long term corrective actions are being evaluated as part of the licensee's problem reporting process. The inspector determined that the corrective actions taken and planned were appropriate. No violations were identified. These LERs are closed.
E8.5 (Closed) eel 97-482-03023, salt service water (SSW) Sinale Failure, eel 97-482-05014,50.73 Reoortability, URI 97-05-06, SSW Sinale Failure, and LER 97-11-00, !
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Section E1.3 of NRC Inspection Report No. 50-293/97-05, dated October 21,1997, documented a design deficiency that rendered the SSW system vulnerable to a single failure. Under certain conditions, only one SSW pump would remain j i
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l operating with the SSW headers cross connected with the potential for insufficient .
net positive suction head (NPSH). This concern was initially documented as URI 97-05-06. Later, this was cited as a corrective action violation as part of the related Notice of Violation, dated April 27,1998. l l
The inspector reviewed the corrective actions taken and planned. The licensee subsequently performed hydraulic analyses that supported one SSW pump serving
- both SSW trains. Additionally, pump testing at the vendor facility was performed to
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establish performance data and NPSH requirements for the SSW pumps. Lastly, the licensee submitted a license amo dment dated February 11,1998, to clarify single failures which may place the SSW system in a configuration of one SSW pump supplying both trains. At the end of this inspection period, this license amendment !'
was under final review by the NRR staff. Based on the Notice of Violation, the l licensee's response and the aforementioned corrective actions, eel 97-482-03023 and URI 97-05-06 are closed.
Section E1.3 of NRC Inspection Report No 50-293/97-05 also documented the licensee's failure to report the SSW system design deficiency pursuant to the requirements of 10CFR 50.73. The NRC issued a Notice of Violation on April 27, 1998. Subsequently, the licensee issued LER 97-11 and two supplements to report the SSW design deficiency. The licenseo also completed an extent of condition review and took corrective actions, as necessary. The inspector conducted an onsite review of the LER and its two supplements. No deficiencies were identified.
eel 97-482-05014and LER 97-11, and its two supplements, are closed.
IV. PLANT SUPPORT F2 Status of Fire Protection Facilities and Equipment F2.1 Material Condition of Fire Protection Eauioment a. Insr;ection Scoce (64704)
The inspector toured the accessible portions of the turbine building, reactor building, j screen house, and diesel generator building with the site fire protection engineer and l
the fire protection team leader to evaluate the material condition of the installed l suppression systems, detection systems, and portable fire extinguishers. The inspector also evaluated combustible material storage and control during the tours.
b. Observations and Findinas During the 1998 qual:ty assurance audit of the fire protection program, the auditors questioned the sprinkler and detection system compliance with the applicable National Fire Protection Association (NFPA) Codes. In response to the questions, BEC Energy instituted a program to reconstitute the design and licensing bases of
- the detection and suppression systems, and to review the as-built systems for I
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l l compliance with the codes of record. This effort was in-progress at the time of the i inspection.
The fixed suppression systems in the plant were in good repair, and a deluge valve had been recently replaced due to identification of a damaged valve seat.
i Scaffolding which was left in place near the seal oil equipment skid had its decking l removed, in order to leave the sprinkler system discharge heads unobstructed. The inspector performed a detailed inspection of the pre-action sprinkler system which protects the oil auxiliaries for the recirculation motor generator sets. No deficiencies were found.
Portable fire extinguishers were located as required throughout the plant. The l inspector found several portable extinguishers which had missing tamper seals. ;
These extinguishers were replaced with spares to correct the deficiency.
The only accumulation of combustible material the inspector noted was in the health physics cage on the 74' elevation of the reactor building. The materialin the cage was covered by permit 98-97, and the fire protection group was working with health physics to reduce the amount of material stored there.
c. Conclusions Based on visual observations during plant tours, the inspector determined that the installed detection and suppression systems are in good repair, and the smoke detectors and sprinkler heads were not obstructed. Control of combustible material was generally good.
F2.2 Fire Barrier Penetration Seals a. Insoection Scoce (64704)
During the plant tours, the inspector selected penetrations 62.502E-001-9 and -13, I l between the reactor building and the "B" diesel generator room to evaluate installed
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condition and review of qualification test data.
b. Observations and Findinas Penetrations 62.502E-001-9and -13 are 4" conduit passing through the east wall of the 23' elevation of the reactor building to the "B" diesel generator room. The penetration seals are Typ3 lil-C, consisting of a 2" depth of Kaowool8 covered with a 1" layer of Flamemastic 778.-
The penetration seals installed in the plant were in good condition, and did not exhibit any separation of the material at the surface of either the conduit or the j penetrating cables.
! This seal design was subjected to a fire endurance test meeting the requirements of
- the Institute of Electrical and Electronic Engineers (IEEE) Specification 634-1978,
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l' " Standard Cable Penetration Fire Stop Qualification Test." The test included a three !
L . hour fire exposure, using the American Society for Testing and Materials (ASTM) !
E-119 furnace temperature profile, and a subsequent hose stream test. The fire exposure was conducted for 183 minutes on September 3,1987, at the Southwest Certification Services, Inc. facility in San Antonio, Texas. The final test report, l "CTP-1147,IEEE 634-1978 Three Hour Fire Qualification Test," issued October 16, '
!- 1987, indicated that the seal design successfully passed both the fire exposure and 1 l hose stream tests. ,
l c. Conclusions Based on the observed condition of the seals in the plant, and the information
- contained in the fire test final report, the inspector determined that fire barrier l penetration seals 62.502E-OO1-9 and -13 met the requirements for a 3-hour
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penetration seal.
L F2.3 Hageway Fire Barrier Enclosures
[ a. Insoection Scope (647Q4)
The inspector reviewed Plant Design Change (PDC) 98 22, " Replacement of Appendix R Enclosures in the 'B' Switchgear Room," and observed the condition of l the new enclosures in the plant. I b. Observations and Findinas ;
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! The original raceway fire barrier enclosures installed at Pilgrim were constructed l using Pyrocrete*, a cement based material which, in some of its formulations, also L contained asbestos. Problems with the enclosures are documented in integrated Inspection Report 50-293/98-05,and were the subject of a notice violation issued with integrated Inspection Report 50-293/98-06. The problems included the lack of a test of the specific configuration of the enclosures used at Pilgrim. The formulations used in constructing the raceway enclosures at Pilgrim are no longer available, which precluded constructing a replica for subjecting to fire tests.
BEC Energy chose to remove the two enclosures in the "B" switchgear room and
, replace them with a qualified material. The work was performed under PDC 98-22, l using a 3-hour rated barrier which meets the acceptance criteria specified in NRC Generic Letter (GL) 86-10. The barrier is constructed of material manufactured by Mecatiss, of Morestel, France. The inspector verified that the installed configuration l matched the design drawings.
BEC Energy provided fire test results that support the 3-hour rating of the barrier.
The test was conducted by Underwriters Laboratories, Inc. (UL) on November 30,
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1995, and is documented in File NC 1973, Project 95NK17030," Report on i: Raceway Fire Barriers for Aluminum Cable Tray and Aluminum Conduit Systems, i Florida Power Corporation, Crystal River, Floriaa," issued February 6,1996. The new barrier installed at Pilgrim corresponds' to the MTS-3 System, which exhibited f
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an average tcmperature rise on the unexposed side of approximately 150 degrees Fahrenheit during the three hour fire exposure.
c. Conclusions Based on the review of modification package PDC 98-22, field verification of the installed configuration, and the data in the UL fire test report, the inspector determined that the new "B" Switchgear Room raceway fire barrier enclosures met the requirements for 3-hour rated b.striers for safe si utdown systems.
F2.4 Main Transformer Replacement Fire Protection Modifications a. Insoection Scope (64704)
The inspector reviewed the fire protection modifications associated with the replacement of the main transformer, and observed the condition of the equipment in the field.
b. Observations and Findinos Pilgrim station experienced a failure of the main generator step-up transformer in March 1997. The failed transformer was replaced with a new transformer which has a slightly different physical configuration than the old transformer. This difference required modification of the deluge system which protects the transformer. In addition, BEC Energy took the opportunity to replace old detection system equipment with up-to-date detection, and to enhance the switchgear room protection.
The transformer failure in March 1997 involved a failure of a bushing where the segregated bus connects to the low voltage side of the transformer. Since the transformer oil level normally is above the level of the bushing, oil leaked out of the transformer into the segregated bus ducts. From the segregated bus ducts, which are not liquid tight, the oil leaked onto the floor of the generator auxiliaries area of the turbine building spreading on the floor, and under the door of the lower switchgear room. in order to prevent a future occurrence of oil spreading under the door of the switchgear room, Field Revision Notice (FRN) 97-09-10 was issued April 4,1997. This FRN added oil drain lines to the segregated bus ducts to direct any oil leakage to the collection basin under the transformer, and dams in the turbine auxiliaries area of the turbine building to prevent liquids on the floor running under doors. This modification is expected to preclude a repetition of oil intrusion into the switchgear room.
The new transformer includes an external oil reservoir located above the top of the transformer casing. The deluge system was modified under FRN 97-09-13 to provide additional protection, from the effects of an exposure fire, for the oil tank and the structural steel which supports it. The design of the new piping and nozzles conforms to the requirements of NFPA Standard 15, " Water Spray Fixed Systems for Fire Protection." One exception, to the requirements for hydrostatic
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, testing of new piping, was documented. In lieu of a hydrostatic test, the system l l was to be activated with both fire pumps running. This would provide a functional test at the highest pressure the system would be likely to experience, and would i not require removal or plugging of the discharge heads. The inspector considered I this exception reasonable. l The original fire detection system for the transformer used a rate of rise pneumatic system to activate the deluge system. Since replacement parts for this system were difficult to obtain, BEC Energy took this opportunity to update the system with more modern equipment. The new detection system, installed under FRN 97-09-19, uses a thermistor wire detector, with a fixed set point of 190 degrees Fahrenheit.
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j The electronic control panel for the new detection system is a UL listed releasing 1 panel, and was connected to activate the modified deluge system, and the remote alarms for control room trouble indication.
c. Conclusions Based on the design of the main transformer fire detection, fire suppression, and oil drainage systems documented in the FRNs, and observations of the condition of the installed equipment, the inspector determined that BEC Er'ergy had taken appropriate actions to protect safety related and safe shutdown equipment from the potential effects of a transformer failure.
F4 Fire Protection Staff Knowledge and Performance F4.1 Fire Drill Observation a. Inspection Scope (64704)
The inspector observed an unscheduled fire drill, conducted during the day shift.
b. Observations and Findinas An unscheduled fire drill was conducted during the day shift, staged in the "A" battery room. The scenario involved a fire, an injured worker, and an acid spill.
The "A" battery room is within the confines of the radiologically controlled area, so the potential for contamination was also an issue to be considered.
The fire brigade leader reported to the scene approximately one minute after the drill was announced in the plant. He evaluated the conditions at the scene, and called the control room on cellular phone (one of three available means of communication between the scene and the control room) to notify the operators of the conditions
- and assistance needed. The fire brigade leader then used the plant page to direct l
the fire brigade to the assembly point for attacking the simulated fire.
The fire brigade leader showed excellent judgement in not allowing personnel to enter the room with the simulated fire until two personnel in protective clothing (turnout gear and self-contained breathing apparatus) were available to make the l
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entry and search for victims. The victim was extracted from the room and turned over to emergency medical technicians within ten minutes of the drill being l announced.
! The fira brigade leader coordinated with plant operators to ensure that the exhaust l
ventilation system was operating to remove smoko and fumes, and to ensure that nobody entered the room with the simulated fire unaccompanied. All the fire brigade members and support personnel (chemistry, health physics, security)
demonstrated good enthusiasm, and utilized all appropriate protective equipment.
During discussions with the training specialist supervising the drill, the fire brigade members demonstrated good knowledge of their duties and responsibilities.
c. Conclusions i Based on observations of the search and rescue actions and extinguishment plan j demonstrated during the fire drill, the inspector determined that the fire brigade was well trained, knowledgeable, and enthusiastic.
F7 Quality Assurance in Fire Protection F7.1 Fire Protection Proaram Self-Assessment a. Inspection Scooe (64704)
The inspector reviewed the report of the self-assessment of the fire protection program which was conducted in 1998.
b. Observations and Findinas The self-assessment performed in 1998 was the first of a series of planned annual self-assessments. They are being performed as a long-term action to resolve issues identified in Quality Assurance (QA) Audit 97-05 (discussed in Section F7.2 of this report). The 1998 self-assessment used several contractor personnel and a peer evaluator (fire protection engineer) from another New England nuclear power plant.
The self-assessment identified several program strengths, including the technical competence of the personnel assigned to the program and control of combustible materials and hot work. Opportunities for improvement were identified in the areas of procedure clarity, training, fire barriers in the screen house, program document updating, and resource allocation for the program. Nineteen problem reports (prs)
were issued during the assessment. The inspector reviewed the PR descriptions in the report, and concurred with the report's conclusion that none of the prs identified issues affecting the operability of the fire protection systems or
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equipment.
l l Several program aspects were specifically excluded from the self-assessment scope l because they had been previously identified as requiring additional review, and ( programs had already been initiated by BEC Energy to perform those reviews.
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Based on the issues documented in the self assessment report and the associated
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l prs, the inspector determined that the self-assessment was an excellent initiative, i and had been successfulin identifying strengths and areas for improvement in the I fire protection program.
F7.2 Quality Assurance Audits of the Fire Protection Proaram )
- a. Insoection Scope (64704)
The inspector reviewed QA audi? reports for the 1996,1997, and 1998 audits of the fire protection program to evaluate audit content, significance of the audit findings, and recommendations for program enhancements made in the audit reports. l i
b. Observations and Findinas.
I The 1996 audit found the program sound, with a need to improve performance in the area of timeliness of response to identified issues. The 1997 audit identified
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- that the program was in need of additional resources due to the need for program improvements and concurrent updating of procedures and governing documents.
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The scope of the.1998 audit was expanded beyond that described in GL 82-21,
" Technical Specifications for Fire Protection Audits," to include safe shutdown analysis, safe shutdown equipment list, and Appendix R issues, based on the Fire Protection Functional Inspection (FPFI) pilot program violations and unresolved items regarding QA audit scope. The 1998 audit issued 17 prs in the areas of combustible material control, safe shutdown equipment list completeness, emergency lighting adequacy, procedure adequacy, and NFPA code compliance.
In response to the issues identified in the 1997 and 1998 audits, BEC Energy has instituted a Fire Protection Program improvement Program. As part of the improvement program, BEC Energy has assigned additional personnel, including contract engineers, to resolve fire protection procedure issues; brought in contract j fire inspectors to provide oversight of day-to-day program activities; is developing a
! computerized process for combustible material control and permit issuance; -
conducting a review of the detection and suppression system design and licensing
- bases (including NFPA code compliance); updating the Fire Hazards Analysis; i replaced raceway fire barrier enclosures in the "B" switchgear room; and performing i a reverification of the Appendix R safe shutdown analysis and equipment list.
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19 c. Conclusions Based on the issues raised in the fire protection program audits, and the BEC Energy Fire Protection Program improvement Program which was instituted in response to audit findings, the inspector determined that the audits have been effective in identifying program deficiencies and initiating corrective actions.
P2 Status of EP Facilities, Equipment, instrumentation and Supplies a. Inspection Scope (82701)
The inspector conducted an audit of emergency equipment in the control room, the j operations support center (OSC), the technical support center (TSC), and the i emergency operations facility (EOF). The inspector reviewed documentation of emergency equipment surveillances and communications tests conducted during the past year for completeness and accuracy.
b. Observations and Findinas l i
An audit of equipment and supplies in the control room, the OSC, the TSC, and the EOF indicated that specifieo equipment was present. Current revisions of the
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emergency plan and implementing procedures were present in the facilities.
Selected radiological monitoring instrumentation was checked and operability was
, verified. The f acilities were well kept and orderly, thus ready for immediate j activation. A review of completed surveillances for the facilities and communications tests for 1998 indicated that they were performed as required.
Discrepancies identified in the surveillances and communications tests were resolved.
c. Conclusions 1 Emergency equipment surveillances and communication tests were i performed as required and the facilities were in a good state of operational readiness.
P3 EP Procedures and Documentation a. Inspection Scooe (82701)
The inspector assessed the process used by the licensee to review and change the emergency plan (Plan) and implementing procedures (IPs), and reviewed recent changes to assess the impact on the effectiveness of the Plan. The inspector also reviewed emergency response information distributed to the public.
b. Observations and Findinos Prior to this inspection, the inspector conducted an in-office review of recent IP changes. Based upon the licensee's determination that the changes did not decrease the overall effectiveness of the Plan and after review of the changes, no NRC approvalis required in accordance with 10 CFR 50.54(q). During this
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inspection, it was determined that the licensee's 10 CFR 50.54(q) review (effectiveness review) process was well controlled. Review criteria for the effectiveness checks included a 10CFR 50.59 safety review. Regular Plan and IP
- reviews were performed by the licensee. The inspector reviewed the bases for I
several Plan and IP changes and determined that the changes were acceptable.
Telephone book inserts and information calendars distributed throughout the l emergency planning zone contained sufficient information about responding to a
' radiological emergency. Media training and site familiarization was made available to the local media to ensure that they were knowledgeable of licensee emergency response activities.
c. Conclusions A review of the licensee's procedure change review process, and a sampling of recent procedure changes, indicated that a good procedure control program was being implemented. The licensee's public information program was implemented as required.
P5 Staff Training and Qualification in EP a. Inspection Scope (82701)
The inspector reviewed records and training requirements to evaluate the licensee's emergency response training program.
i b. Observations and Findinos Requalification training records for several emergency response organization (ERO) i members were checked to verify that they had received annual classroom training. )
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Likewise, records for newly qualified ERO members indicated they had received the required training. Selected training modules were reviewed for content and were assessed as appropriate. Required drills were conducted as required. However, it ;
was determined that there are no drill participation requirements in the Plan for either initial or requalification training for ERO members. Although, drill participation is not tracked, most ERO members will participate (either as observers or players)
since the ERO teams rotate through the drill schedule. The inspector also determined that chemistry technician training for post accident sampling system (PASS) is not completely formalized. For example, in addition to the specified training, instructors would use a supplemental PASS training module as they deemed necessary. Also, there was no formal method of determining which technicians would draw a PASS sample from which sample points. However, no adverse performances have been observed of the ERO in general or related to PASS l drills. The licensee agreed to assess its policy of drill requirements for ERO training and its handling of PASS training. The inspector had no further questions in this I area.
Offsite drills and training, including the annual emergency action level training for state and local officials, was conducted in accordance with the Plan.
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c. Conclusion Overall ERO member training was assessed as good because Plan requirements were being met and no adverse drill performances were observed.
P6 EP Organization and Administration The EP department has remained at a constant staffing level although there has been a change in personnel within the department. The inspector observed no adverse imp:% on the EP program as a result of these changes. The licensee i utilizes a master surveillance schedule which tracks all EP-related activities, such as, I facilities surveillances, communication tests, and drills, to ensure that the program was being properly implemented. The inspector considered this to be a useful management toolin maintaining the EP program. The EP staff continues to receive strong management support as evidenced by cooperation from supporting departments to implement the EP program and by management participation in the ERO.
The EP department maintains an emergency telephone directory that contains ERO mernbers (listed alphabetically or by position), their associated telephone numbers (pager number if appropriate), and qualification expiration dates. The inspector considered this to be a useful tool to help quickly notify ERO members as a supplemental method of notification. The licensee successfully monitors and maintains the ERO at least three deep in key positions. The licensee continues to monitor the impact on the ERO of the pending sale of the Pilgrim station.
P7 Quality Assurance (QA)in EP Activities a. Insoection Scope (82701)
The inspector reviewed the licensee's processes for identifying and tracking EP-related issues and assessed the effectiveness of problem resolution. The inspector interviewed the QA manager, reviewed the 1997 and 1998 QA audit and surveillance reports and the 1998 audit checklist to assess the effectiveness of the audits of the EP program.
b. Observations and Findinas The licensee has numerous programs for problem identification which include audits, self-assessments, and drill or exercise evaluations. The EP-related issues were reviewed (those that had been closed in the past six months as well as those that are currently open) and it was determined that the licensee has an appropriate threshold for problem identification and the issues in the tracking system were properly prioritized. No repeat items were identified.
The EP audit and surveillance teams for the 1997 and 1998 audits consisted of several persons, at least one of whom possessed technical expertise or experience in EP. The 1997 audit was conducted over approximately a two week period whereas in 1998 surveillances were performed throughout the year. The checklist used for the 1998 surveillances were determined to be sufficiently detailed to i
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assess the program. The 1997 and 1998 audit and surveillance reports were thorough and the observations supported the conclusions. The subjects specified l by 10CFR 50.54(t) were addressed and the reports contained recommendations for l program enhancement. There were no repeat recommendations from 1997 to 1 1998. The reports were distributed to the appropriate levels of licensee management and the portions of the reports addres;ing the offsite interface were made available to offsite officials, j
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c. Conclusions l Based upon generally good licensee performance :uring drills, the absence of repeat audit or self-assessment findings, and no adver. . trends in the EP program, the licensee's problem identification and correctiv* ' tion processes were determined to be effective. The EP program audits were thorot ,.i and the reports were useful for licensee management to assess the effectiveness of the EP program.
V MANAGEMENT MEETINGS X1- Exit Meeting Summary
- The results of the inspection were discussed with BEC Energy management on December 17,1998, during an exit meeting conducted at the site.
During the inspection, several documents reviewed by the inspector were i
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determined to contain proprietary information. All documents containing proprietary information were returned to BEC Energy.
X3 Management Meeting Summary On November 19,1998, Mr. Curtis Cowgill, NRC Region 1 Projects Branch Chief,
! visited the site for a facility tour, interviewed licensee managers, and discussed l current inspection issues with the NRC resident inspector staff.
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i PARTIAL LIST OF PERSONS CONTACTED Boston Edison Comoeny H. Oheim, General Manager Technical Section P. Smalley, Manager Chemistry K. Sullivan, Emergency Preparedness Plan Coordinator J. Spangler, Emergency Preparedness Manager G. Vazquez, Emergency Preparedness Readiness Coordinator INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 40500: Effectiveness of Licensee Controls in !dentifying, Resolving, and Preventing
Problems IP 61726: Surveillance Observation IP 62707: Maintenance Observation IP 71707: Plant Operations IP 71750: Plant Support Activities IP 82301: Evaluation of Exercises for Power Reactors IP 82701: Operational Status of the Emergency Preparedness Program IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor l Facilities l lP 92901: Followup - Operations IP 92902: Followup - Maintenance j IP 92903: Followup - Engineering ;
IP 92904: Followup - Plant Support i IP 93702: Prompt Onsite Response to Events at Operating Power Reactors l
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ITEMS OPENED, CLOSED, AND UPDATED j
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Pilgrim Nuclear Power Station l Docket No. 50-293 i l
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URI 98-10-02 Adequacy of Post Maintenance Testing of SGIS fan-heater circuit Closed l
eel 97-482-03023 SSW Single Failure !
eel 97-482-05014 50.73 Reportability I LER 97-11 (01/02) SSW System Single Fail Vulnerability
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LER 97-13 Cable Separation for Load Shed Circuits)
LER 97-27 EDG Air Temperature Below Design Limits LER 97-28 Intake Structure in a Configuration inconsistent with Tornado Deprc::surization Analysis Assumptions j LER 98-02 EDG Room Air Temperature Below Design Basis ;
LER 98-03 RBCCW and TBCCW Heat Exchanger Supports Outside Design Basis l Seismic Requirements !
LER 98-04 Emergency Diesel Generator (EDG) Air Temperature Below Design i Limits !
LER 98-07 Single Failure Vulnerability of the Residual Heat Removal (RHR)
System when in Suppression Pool Cooling i LER 98-10 Inadequate Surveillance Performed for Containment Cooling Flow l
Rates l LER 98-11 Reactor Floor Plugs Removed During Operation l URI 97-05-06 SSW Single Failure Opened and Closed
NCV 98-10-01 Intake Structure in a Configuration inconsistent with Tornado l Depressurization Analysis Assumptions NCV 9810-03 Inadequate Surveillance Performed for Containment Cooling Flow Rates NCV 98-10-04 Reactor Floor Plugs Removed During Operation NCV 98-10-05 Single Failure Vulnerability of the Residual Heat Removal (RHR)
System when in Suppression Pool Cooling i NCV 98-10-06 Cable Separation for Load Shed Circuits i
NCV 98-10-07 RBCCW and TBCCW Heat Exchanger Supports Outside Design Basis Seismic Requirements l
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LIST OF ACRONYMS USED ALARA As Low As is Reasonably Achievable ASTM American Society for Testing and Materials CFR Code of Federal Regulations l DRP Division of Reactor Projects j EOF Emergency Operations Facility l EP Emergency Preparedness ERO Emergency Response Organization FPFI Fire Protection Functional inspection l
' FRN Field Revision Notice l
GL NRC Generic Letter !
HCU . Hydraulic Control Unit l I&C Instrumentation and Controls IEEE Institute of Electrical and Electronic Engineers
- IFl Inspection Follow-Up Item IP Implementing Procedure IR Inspection Report LCO Limiting Condition of Operation LER Licensee Event Report MOV Motor-operated Valve MR Maintenance Request NCV Non-Cited Violation NFPA National Fire Protection Association i NOV Notice of Violation l NRC- Nuclear Regulatory Commission
.NRR Office of Nuclear Reactor Regulation OSC Operations Support Center PDC Plant Design Change Pian Emergency Plan PNPS Pilgrim Nuclear Power Station PR Problem Report ;
l- PRA Probabilistic Risk Assessment l QA Quality Assurance RFO Refueling Outage RHR Residual Heat Removal RP Radiological Protection
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TBCCW Turbine Building Closed Cooling Water
!. TSC Technical Support Center L
UFSAR Updated Final Safety Analysis Report
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UL Underwriter's Laboratories, incorporated
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