IR 05000272/1997015

Insp Repts 50-272/97-15 & 50-311/97-15 on 970727-0907.No Violations Noted.Major Areas Inspected:Operations, Engineering,Maint & Plant Support

ML18102B590
Person / Time
Site:	Salem
Issue date:	09/24/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML18102B589	List: IR 05000272/1997015 ML18102B588
References
50-272-97-15, NUDOCS 9710010432
Download: ML18102B590 (16)

Text

Docket Nos:

License Nos:

Report N Licensee:

Facility:

Location:

Dates:

Inspectors:

U. S. NUCLEAR REGULATORY COMMISSION 50-272, 50-311 DPR-70, DPR-75

REGION I

50-272/97-15, 50-311 /97-15 Public Service Electric and Gas Company Salem Nuclear Generating Station, Units 1 & 2 P.O. Box 236 Hancocks Bridge, New Jersey 08038 July 27, 1997 - September 7, 1997 M.* G. Evans, Senior Resident Inspector R. K. Lorson, Resident Inspector F. J. Laughlin, Resident Inspector H. K. Nieh, Resident Inspector L. M. Harrison, Reactor Engineer J. D. Noggle, Senior Radiation Specialist Approved by:

James C. Linville, Chief, Projects Branch 3 Division of Reactor Projects 9710010432 970924 PDR ADOCK 05000272 G

PDR

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EXECUTIVE SUMMARY Salem Nuclear Generating Station NRC Inspection Report 50-272/97-15, 50-311 /97-15 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 6-week period of resident inspectio Operations Overall, personnel and plant management controlled the reactor start-up evolutions wel The operating crews were attentive, used excellent communication skills and appropriately addressed all issues and challenges. The pre-evolution briefs were thorough and management support was evident. The Management Review Committee performed a critical assessment of the station performance prior to start-up and prior to exceeding the 25% holdpoint. However, a minor weakness involving communications with the test group and the control of test activities was noted as evidenced by missed data and a last minute question regarding how to obtain the test dat Maintenance Maintenance planning weaknesses were identified during troubleshooting of the pressurizer *

level channel Ill indication problem. These weaknesses included a poor decision to enter the Unit 2 biological shield when acceptable alternatives were available for isolating the transmitter that would have significantly reduced the workers' exposure, poor preparation for a pre-job brief, and lack of a sufficiently detailed plan for troubleshooting the indication problem. The operators demonstrated a good questioning attitude by identifying the pre-job brief weaknesses, and the maintenance manager indicated that operations feedback would be incorporated to enhance future maintenance plannin Engineering The inspector concluded that the licensee conducted the leak tests and associated troubleshooting for the safety injection valves in a controlled manner and adequately demonstrated that the leak rate was within the allowed limi Operators identified and initiated proper actions to resolve analog rod position indication (ARPI) to group rod position indication differences. Salem implemented effective corrective actions to address the historical problems associated *with the ARPI system. There was good engineering, maintenance, and plant management oversight for resolving this issu However, the ARPI calibration *deficiencies and readout scale indicators installed in July 1997, were indicative of a weakness in modification design and testin Plant Support The inspector concluded that all control room fire suppression equipment required by licensee procedures was availabl ii

• TABLE OF CONTENTS EXECUTIVE SUMMARY ii TABLE OF CONTENTS.......... '.................................... iii I. Operations

04 OS

Conduct of Operations*....................................

01. 1 General Comments.................................

. Operator Knowledge and Performance................. :.......

0 Reactor Startup and Low Power Testing..................

Miscellaneous Operations Issue

.............................

O (Closed) Licensee Event Report (LER) 50-272/97-007-00, failure to perform an independent verification of a discharge valve lineup

......................................

OS.2 (Closed) LER 50-311/97-003-00, excessive debris in Unit 2 containment......................................

OS.3 (Closed) LER 311 /97-00S-OO, failure to enter an action statement for having both radiation monitors in the same control room air intake duct inoperable.......... ~........ 4 II. Maintenance................................................... 4 M 1 Conduct of Maintenance.................................. 4 M 1. 1 General Comments................................. 4 M1.2 Pressurizer Level Instrument Troubleshooting

..............

MS.

Miscellaneous Maintenance Issues...........................

MS.1 (Closed) LER 50-311 /97-007-00, inadequate in-service testing of component cooling system check valves, 2CC195 and 2CC210.........................................

Ill. Engineering

...................................................

E1 Conduct of Engineering................................... 7 E1.1 Leak Test of Boron Injection Tank Isolation Valves...........

E1.2 Salem Analog Rod Position Indication System Problems.......

S ES Miscellaneous Engineering Issues............................

ES. 1 (Closed) LER 50-311 /97-006-00, seismic adequacy of the 21 service water (SW) heade........................... 9 IV. Plant Support............. *.............. ~......................

RS Miscellaneous Radiological Protection and Chemistry Issues......... 9 R (Closed) Violation 50-272&311 /97-07-02, failure of RP services to provide periodic RP program and ALARA program assessments...................................... 9 F2 Status of Fire Protection Facilities and Equipment................

V. Management Meetings............................................

X 1 Exit Meeting Summary...................................

X2 NRC Confirmatory Action Letter (CAL) 1-95-009 Modification.......

iii

Report Details Summary of Plant Status Unit 1 remained defueled for the duration of the inspection perio Unit 2 began the inspection period in Mode 5, Cold Shutdown. On July 30, operators increased average coolant temperature above 200°F and entered Mode 4, Hot Shutdow On August 2, operators increased average coolant temperature above 350°F and entered Mode 3, Hot Standby. On August 6, the NRC issued a letter modifying Confirmatory Action Letter (CAL) 1-95-009, allowing the restart of the unit. On August 17, Mode 2, Startup, was entered and criticality was achieved at 1 : 14 p The unit was shutdown on August 19 because of a mismatch in rod position indication. The unit entered Mode 2 again on August *22 and reactor criticality was achieved at 6:34 pm. On August 26, the unit entered Mode 1, Power Operations, and exceeded 5% power. On September 2, the unit reached 47% power and remained at that power level through the end of the report perio I. Operations

Conduct of Operations 01. 1 General Comments (71707)

Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. In general, the conduct of operations was professional and safety-conscious; specific events and noteworthy observations are detailed in the sections belo Operator Knowledge and Performance 0 Reactor Startup and Low Power Testing Inspection Scope (71707)

The NRC performed augmented inspection coverage of the Unit 2 reactor start-up and low power test program. The test program was interrupted twice to correct a rod position indication mismatch between the group position indication (GPI)

system, and the analog rod position indication (ARPI) system. The inspectors observed reactor start-up activities on August 7, 17, and 22. Selected portions of the following procedures were observed:

• S2.0P-IO.ZZ-0003, Hot Standby to Minimum Load

• S2.0P-IO.ZZ-0004, Power Operation

• SC.TE-Tl.ZZ-0001, Start-Up And Power Ascension Program

• S2.RE-IO.ZZ-0001, Refueling Test Sequence

• S2.RE-ST.ZZ-0010, Isothermal Temperature Coefficient Determination

• S2.RE-RA.ZZ-0003, Post Refueling Initial Criticality

• S2.RE-RA.ZZ-0005, Boron Endpoint Determination

• S2.RE-RA.ZZ-0008, Rod Swap Reactivity Measurements

2 Observations and Findings Salem personnel and plant management controlled the reactor start-up evolutions well. The pre-startup briefings were thorough and included good participation by key individuals, and contained a good discussion of past operating problems and contingency action The reactor operators were attentive, practiced self and peer checking and displayed excellent communications skills. Reactor engineering provided good oversight of the start-up evolutions and interfaced well with the operators during the reactor physics testing. The shift supervisor and shift technical adviser provided good oversight of the reactivity manipulations and test activitie The Management Review Committee (MRC) performed a critical assessment of the station performance prior to start-up and to exceeding. the 25% reactor power holdpoin The operators demonstrated a good questioning attitude during the start-up test period by identifying several emergent equipment problems including: a mismatch between the ARPI and GPI rod position indications, an inoperable source range channel 328 indicator, 22 feedwater pump vibration problems, and an increasing trend on the channel Ill pressurizer level indication. The operators declared the equipment inoperable as required and initiated the necessary repair activitie The reactor engineers demonstrated a good understanding of the physics test requirements and procedures. The inspectors noted that the testing was performed in accordance with the applicable procedures and the test data reviewed was acceptable. During the rod testing and power ascension to two percent, operators remained focused. The nature of the rod testing procedure was a long repetitive process which challenged operators to avoid complacency. Anomalies encountered during testing, such as the unanticipated automatic insertion of one group of control bank "D" rods as the selector switch was moved through auto, was appropriately discussed and resolved by the crew prior to proceeding. Station resources such as instrumentation and control technicians were appropriately utilized to resolve question A few minor problems were identified during the August 22 start-up including: the gamma metrics shutdown radiation monitor produced a number of control. room alarms which demanded continued attention by the control room operators. During the start-up, the device would alarm frequently due to the increasing radiation

• levels, then reset with a higher setpoint and repeat the process. Operators attempted to compensate for this by manually resetting the alarm setpoint at frequent intervals during the start-up. The inspector was concerned that this could distract the operators and discussed this observation with the operations manager who stated that he would review the use of the gamma metrics during start-ups.

. During the main feed pump testing, communication weaknesses with the test group were noted. Specifically, a main feed pump had to be shutdown and restarted because the test group was not informed to take data. In another instance, the test group was still working out the logistics of how to obtain some data as operations was in the process of putting a main feed pump in service. The test personnel had

not pre-planned how to obtain the data and provisions for a person in the field to monitor a valve position were not made prior to starting the evolutio During main feed pump testing, an auxiliary operator was observed using a radio in the radio exclusion zone at the main feed pump control panel. The area was painted red with a sign stating the exclusion requirements. The operator stated that the area was new and he had not noticed the requirement. The radio did not cause any problems and there was little risk at the time because the pump had not yet been placed on line. In researching the problem, operators discovered that the area had not been added to the operations procedure that describes radio exclusion zones. The shift entered a discrepancy report on the issue and the oncoming shift was briefed during the shift turnove Conclusions Overall, personnel and plant management controlled the reactor start-up evolutions well. The operating crews were attentive, used excellent communication skills and appropriately addressed aH issues and challenges. The pre-evolution briefs were thorough and management support was evident. However, a weakness involving communication*s with the test group and the control of test activities was noted as evidenced by missed data and a last minute question regarding how to obtain the test dat Miscellaneous Operations Issue 0 (Closed) Licensee Event Report (LER) 50-272/97-007-00, failure to perform an independent verification of a discharge valve lineup. This issue was discussed in NRC Inspection Report 97-14 Section 07.1 and involved an event where the operators did not perform an independent valve lineup verification prior to conducting a liquid effluent release. The event had no actual consequences since the restoration lineup confirmed that the release flowpath was correct. The licensee attributed this event to operator error and committed to several corrective actions including operator training on the event and to evaluate the procedure for human factors enhancements. The inspector concluded that the corrective actions were acceptabl.2 (Closed) LER 50-311/97-003-00, excessive debris in Unit 2 containment. In March

• 1 997, during the cleanup of the Salem Unit 2 containment, the licensee found many examples of poor housekeeping. For example, an estimated 300 to 400 pounds of excess debris were found and removed. As documented in NRC Inspection Report 97-12, section 02.2, the resident inspectors toured the Unit 2 containment prior to the plant mode change to Mode 4 in June 1997. The inspectors concluded that containment was in very good condition and ready to support plant heat u Additional corrective actions taken by the licensee included station management reinforcement of the necessary housekeeping requirements through many means as described in Performance Improvement Request No. 970318238, including enhanced field observation worksheets completed by supervisors touring assigned areas, and inclusion of expectations in the Work Standards Handbook. In addition,

the inspector verified that the licensee also initiated corrective action to ensure the cleanup of Unit 1 containment prior to the plant heating u Based on the inspectors' previous tour of Unit 2 containment and the corrective actions taken by the licensee to ensure cleanup of, Unit 1 prior to entry into Mode 4, this LER is close.3 (Closed) LER 311 /97-008-00, failure to enter an action statement for having both radiation monitors in the same control room air intake duct inoperable. This issue was discussed in NRC Inspection Report 97-14, Section 01.2. The licensee attributed the event to misjudgment by the control room supervisor caused by a failure to validate and verify the impact of the troubleshooting work packag Corrective actions included operator tra.ining emphasizing proper work planning methods and the use of the Technical Specification Action Statement Log and planned human factor improvements to the nomenclature of the radiation monitor channels. The inspector concluded that the corrective actions were acceptabl II. Maintenance M 1 Conduct of Maintenance M1.1 General Comments Inspection Scope (62707)

The inspectors observed all or portions of the following work activities:

• 970824119:

• 970801145:

• 970821331:

• 970829075:

• 950602111:

Troubleshoot 4 kV Breaker Troubleshoot.Inability To Start Traveling Screen on High Differential Pressure Troubleshoot 2Nl32 Source Range Nuclear Instrument System Channel II Troubleshoot Inoperable Pressurizer Level Instrument Channel Ill Adjust Analog Rod Position Indication System The inspectors observed that the plant staff performed the maintenance effectively within the requirements of the station maintenance program except as noted in section M 1. 2 belo Inspection Scope (61726)

The inspectors observed all or portions of the following surveillances:

• S2.IC-ST.NIS-0004:

• S2.0P-ST.SW-0010:

2N44 Power Range

/nservice Testing Containment Fan Cooler Unit Service Water And Control Air Valves

• S2.IC-CC.RCS-0002:

• SC.MD-CM.DG-0006:

• S2.IC-SC.RCP-0022:

Rod Position Indication System Signal Conditioning Module Calibration Hot Full Flow Diesel Generator Speed/load Control System Alignment 2l T461 Pressurizer level Protection Channel Ill The inspectors observed that plant staff did the surveillances safely, effectively proving operability of the associated syste M1.2 Pressurizer Level Instrument Troubleshooting Inspection Scope (62707)

The inspector reviewed the troubleshooting activities to repair the channel Ill pressurizer water level instrument. The control room operators observed an increasing trend on the indication, and on August 29 the operators declared the channel inoperable when the deviation between channel Ill and channels I and II exceeded 3%. The operators place*: channel Ill in the trip condition as required by Technical Specification 3.3.1.1 which established the pressurizer level input to the reactor trip circuitry in a 1 out of 2 instead of the normal 2 out of 3 configuratio Observations and Findings PSE&G performed several activities to correct the level deviation problem including:

backfill of level transmitter (l T)-461 sensing lines using a high pressure positive displacement pump, replacement of the LT-461 equalizing valve, and inspection and refill of the L T-461 bellows. The repair activities did not correct the problem, and troubleshooting activities continued through the end of the inspection perio On September 2 plant operators went inside the Unit 2 biological shield to shut the high side root isolation valve (PS-9) for LT-461, however, the operators inadvertently isolated the root valve (PS-11 l for the channel I transmitter. This resulted in only one pressurizer level channel remaining operable and placed the unit into Technical Specification (TS) 3.0.3 which required the unit to be placed in hot standby within 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> The control room operator immediately recognized this condition and directed that PS-11 be opened. The plant equipment operato~s reentered the biological shield and promptly restored channel I. The initial root cause for this event appears to be that the PS-11 valve was mislabelled, however, the licensee is continuing to investigate this event and plans to issue a LER. The inspector will review the LER when it is issue The inspector questioned whether the licensee's decision to enter the area behind the biological shield to isolate L T-461 was necessary and consistent with minimizing occupational exposure. The dose rate is significantly higher inside the biological shield and three valves were available outside the biological shield to isolate LT-461. The inspector noted that maintenance procedure 52.IC-SC.RCP-0022, 2l T-461 Pressurizer level Protection Channel Ill, uses the isolation valves outside the

biological shield to isolate the level transmitter. The licensee was able to subsequently isolate LT-461 by using the valves outside the biological shield. The combined exposure for the three workers who entered the biological shield was 217 millirem which is well below NRC limits. The inspector concluded that the licensee's decision to enter the biological shield was a poor maintenance planning decision because acceptable alternatives were available. for isolating L T-461 that would have significantly reduced the workers' exposur The inspector observed a pre-job briefing conducted in preparation for using a high pressure positive displacement pump to backfill the L T-461 instrument lines. The briefing was conducted using a written troubleshooting guideline (troubleshooter)

and a 1OCFR50.59 applicability revie The operators identified several deficiencies with each of these documents and the brief was terminated to correct the deficiencies. The operators demonstrated a good questioning attitude, however, the deficiencies reflected poor maintenance planning. The station issued action request (AR) 970905278 which identified weaknesses in the channel Ill troubleshooting plan. The maintenance manager indicated that operations input had not been obtained prior to conducting the brief and indicated that it would be obtained for future complex maintenance evolutions.* Conclusions Maintenance planning weaknesses were identified during troubleshooting of the pressurizer level channel Ill indication problem. These weaknesses included a poor decision to enter the Unit 2 biological shield when acceptable alternatives were available for isolating L T-461 that would have significantly reduced worker exposure, poor preparation for a pre-job brief and troubleshooting planning weaknesses. The operators demonstrated a good questioning attitude by identifying the pre-job brief weaknesses, and the maintenance manager indicated that operations feedback would be incorporated into the planning of future complex maintenance evolution MS Miscellaneous Maintenance Issues M8.1 (Closed) LER 50-311197-007-00, inadequate in-service testing of component cooling system check valves, 2CC195 and 2CC210. Technical Specifications and in-service testing requirements of the American Society of Mechanical Engineers (ASME) necessitate testing of these valves in both directions on a 92 day frequency. Upon identification by the licensee in February 1997, that these valves had not been tested in the reverse direction to verify that they were fully closed, the licensee radiographed the valves on February 21, 1997. The past reportability for failure to perform proper surveillance testing prior to February 1 997, will be addressed in a supplemental report to LER 50-272/97-01-01. However, due to personnel error, the routine task for performing the next 92 day surveillance that was due on June 15, 1997, was not generated prior to the expiration of the surveillance interval. Subsequently, the valves were radiographed satisfactorily on June 23, 199 The inspector reviewed the corrective actions taken by the licensee, as detailed in the LER, and concluded that such actions were thorough and appropriate. These actions included a review of the administrative controls for creation and revision of routine tasks to determine if further enhancements were needed. Based on the inspector's review of the licensee's corrective actions and failure to identify any other overdue routine tasks associated with Technical Specification surveillance requirements, this LER is close Ill. Engineering E1 Conduct of Engineering E1.1 Leak Test of Boron Injection Tank Isolation Valves Inspection Scope (61726)

The licensee identified that, on July 19, safety injection valves 2SJ12 and 2SJ13, the boron injection tank isolation valves failed a quarterly leak test conducted in accordance with procedure S2.0P-PT.SJ-0001 (0), Revision 0, 2SJ12 and 2SJ13 leakage Test. The inspector reviewed licensee troubleshooting and retest activities in response to this deficienc b; Observations and Findings In response to NRC Bulletin 88-08, "Thermal Stresses in Piping Connected to Reactor Coolant Systems" (the bulletin), the licensee committed to performing a quarterly leak test on valves 2SJ12 and 2SJ13. The leak test on July 19 revealed a

.34 gallon per minute (gpm) leak rate, while the licensee committed to a leak rate of less than or equal to.05 gpm in its response to the bulletin. This leak rate was determined to be small enough to preclude the potential for thermal fatigue in the

• downstream piping. The instrumentation used to measure the leak rate consists of two in-line flow meters in series, one with a range of 0-1 gpm, and the other with a range of 0-10 gpm, capable of measuring flow rates as low as the.05 gpm maximu After the test failure, the licensee performed troubleshooting on the valves to determine which ones were leaking and adjusted the closing torque of both valve The licensee also changed the troubleshooting procedure to more accurately establish the conditions at which the test is run when the plant is at power. After troubleshooting the valves, a subsequent leak test was within the allowed limi One initiative the licensee employed to verify the flow rate through the flow meter was to collect the leakage in a poly bottle for a speCified time interval. This action demonstrated that the flow meter was accurate for flow rates greater than about

.05 gpm, and that it usually indicated zero flow for flow rates less than.05 gp Conclusions The inspector concluded that the licensee conducted the leak tests and associated troubleshooting for the safety injection valves in a controlled manner and adequately demonstrated that the leak rate was within the allowed limi E1.2 Salem Analog Rod Position Indication System Problems Inspection Scope (37551 l The inspector reviewed PSE&G's response to a mismatch of greater than twelve steps between the analog rod position indication (ARPI) for several control rods and the corresponding group position indication (GPI). Because of the mismatch in position indication, the operators terminated the reactor start-up on August 8, and low power test activities on August 19, to place the unit in hot standby within six hours as required by Technical Specification (TS) 3.1.3. Observations and Findings In July 1997, PSE&G installed a modification to the ARPI system that provided a unique ARPI scale and specific calibration data for each control rod. The intent of.

the modification was to improve the ARPI accuracy to eliminate past problems with system performance. Following the August 8 shutdown, the licensee identified two calibration errors that occurred in July 1 997 that involved the ARPI readout display gain adjustment and also the correction factor used to adjust for temperature differences between the calibration and operating condition The licensee performed several corrective actions following the August 8 shutdown including: replacing the ARPI scale with a more readable scale, correcting the calibration deficiencies, justifying use of the plant computer system (P-250) for improved ARPI readability and also development of an improved algorithm that enhanced the accuracy of the P-250 at rod positions other than the calibration endpoints. The licensee also submitted an exigent change to TS 3.1.3.1 that expanded the allowed difference between the ARPI and the GPI to + /- eighteen steps-at power levels. below 85%.

Maintenance technicians replaced the signal conditioning modules for the two control rods that exceeded the twelve step ARPl-GP.1 limit on August 19 and successfully retested the indicators. The inspectors have not observed any subsequent problems with the ARPI system and concluded that the repairs were successful. The inspectors noted good engineering, maintenance, and plant management oversight for resolving this issu Conclusions Operators responded appropriately to the ARPl-GPI indication differences. PSE&G implemented effective corrective actions to address the historical problems associated with the ARPI system. There was good engineering, maintenance, and

plant management oversight for resolving this issue. However, the ARPI calibration deficiencies and readout scale indicators installed in July 1997, were indicative of a modification design weaknes ES Miscellaneous Engineering Issues E (Closed) LER 50-311197-006-00, seismic adequacy of the 21 service water (SW)

header. This issue was discussed in NRC Inspection Report 97-07 Section E2.1 and involved modification activities that connected new piping to the 21 SW header before the required pipe hangers were installed. The root cause was attributed to unclear work instructions for connecting the system piping. The corrective actions included revision of the work instructions, proper installation of the piping, and training of appropriate personnel on the event. The inspector concluded that the corrective actions were acceptabl IV. Plant Support RS Miscellaneous Radiological Protection and Chemistry Issues R (Closed) Violation 50-272&311/97-07-02. failure of RP services to provide periodic RP program and ALARA program assessments Inspection Scope (83750)

Within Section 1 2.4 entitled, 11 ALARA Program, 11 the Updated Final Safety Analysis Report (UFSAR) lists the functions to be provided by the Principal Health Physicist-Radiological Safety, which include: Ensuring periodic reviews of the As Low As Is Reasonably Achievable (ALARA) Program are conducted and providing periodic assessments of the station Radiation Protection (RP) progra The UFSAR commitment discussed above, was captured in licensee procedure NC.NA-AP.ZZ-0024(0), Rev. 7, which states in Section 3.6 that, the Principal Health Physicist-Radiological Safety is responsible for ensuring periodic reviews of the ALARA Program are conducted and is responsible for periodic, scheduled assessments of the station RP Program with a frequency such that all functional activities are assessed at least every four year Contrary to these license commitments, the inspector reviewed documented results of the RP Services group efforts over the last several years* and did not find significant evidence of periodic reviews of the ALARA Program scheduled by RP Services that were conducted nor any evidence of periodic assessments of the Salem Station RP program provided by RP Services. This resulted in a severity level IV violation (VIO 50-272/97-07-02; 50-311/97-07-02). Observations and Findings PSE&G response letter, dated June 13, 1997, concurred with the violation and attributed the violation to inadequate management oversight of the assessment

..

..

10.

program caused by management personnel changes and the elimination of the radiological assessor position. Also no departmental procedure existed that established organizational responsibilitie Corrective actions specified in the letter included: reestablishment of an RP Services assessm~nt program and scheduling and conducting RP assessments; establishing and staffing the radiological assessor position; and development of a procedure or directive to define organizational responsibilitie During this inspection period, the inspector reviewed the licensees* actions and verified that an active RP Services assessment program had been established and staffed with a dedicated radiological assessor. Both Hope Creek and Salem stations were scheduled for 8 functiona: RP assessments to be conducted every two year The first functional area assessment of the Radiation. Dose Control program at both facilities had been completed at the time of this inspection. These two assessments appeared to exhibit good techniCal depth identifying many areas for improvemen Organizational responsibilities for the radiological assessment activities were documented in Departmental Directive RS.DD-ZZ-000 Conclusions After reviewing the corrective actions associated with the violation, the inspector determined ttiat the corrective actions adequately addressed the violation and are sufficient to prevent recurrence of the violation. Therefore, this violation is close F2 Status of Fire Protection Facilities and Equipment Inspection Scope (71750)

The inspector reviewed the licensee's control room fire suppression capability in response to an inadvertent actuation of this equipment at another licensed facilit Observations and Findings The Salem Unit 1 &2 common control room does not have an automatic fire suppression system. The licensee received an exemption to 10 CFR 50, Appendix R to get relief from this requirement, which is documented in the Updated Final Safety Analysis Report. The fire suppression equipment available in the control room consists of one fire hose and multiple fire extinguishers which utilize water, halon and carbon dioxide as extinguishing agent The inspector observed that ten self-contained breathing apparatuses (SCBAs) were

.stored in a ready room immediately outside the control room vital door. These are surveilled and maintained by radiation protection personnel and are of sufficient number for the eight required control room operators when both units are in power operations. The SCBAs are required by licensee procedure SC.OP-AB.CR-0003, Revision 3, "Control Room Habitability," for operator use in the event of toxic gas

• '

intrusion into the control room. Procedures require evacuation for a fire in the control roo Conclusions The inspector concluded that all control room fire suppression equipment required by licensee procedures was availabl V. Management Meetings X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on September 12, 1997. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie X2 NRC Confirmatory Action Letter (CAL) 1-95-009 Modification On August 6, 1997, the NRC Region I, Regional Administrator gave approval for the restart of Salem Unit 2 by modifying CAL 1-95-009. In the August 6 letter, hold points were established at three discrete power levels to allow a planned NRC assessment of Salem Unit 2 performance. The holdpoints are consistent with activities in the Integrated Test Program and are: following flux mapping at 25% power; after the 10% load swing test at 50% power, and following the 25% load swing test at 90% power. At each holdpoint, PSE&G plans to assess plant and organizational performance and agreed to review the results of each of these assessments with the NRC and obtain concurrence prior to increasing powe On August 29, the licensee conducted a Management Review Committee (MRC) meeting to assess performance at the 25% power holdpoint. Following the MRC meeting, the licensee presented the assessment to the NRC Salem Assessment Panel (SAP). The SAP then met to independently assess licensee performance. The SAP concluded that if no further events occurred between the close of the meeting and the plant's readiness to proceed past 25% power, that the licensee was ready to proceed in power ascension to 50% power. On August 31, the licensee formally requested and gained NRC concurrence to raise reactor power above 25%.

INSPECTION PROCEDURES USED IP 37551:

IP 61726:

IP 62707:

IP 71707:

Onsite Engineering Surveillance Observations Maintenance Observations Plant Operations IP 71750:

IP 83750:

Plant Support Activities Occupational Radiation Exposure Opened None Closed 50-272&311/97-07-02 50-272/97-007-00 50-311/97-003-00 50-311 /97-006-00 50-311 /97-007-00 50-311 /97-008-00 ITEMS OPENED, CLOSED, AND DISCUSSED VIO failure of RP services to provide periodic RP program and ALARA program assessments LER failure to perform an independent verification of a discharge valve lineup LER excessive debris in Unit 2 containment LER seismic adequacy of the 21 SW header was invalidated LER inadequate in-service testing of component cooling system check valves, 2CC195 and 2CC210 LER failure to enter an action statement for having both radiation monitors in the same control room air intake duct inoperable

ALARA ARPI ASME CAL GPI gpm LER LT MRC NRC PDR PSE&G RP SAP SCBAs SW TS UFSAR

LIST OF ACRONYMS USED As Low As Reasonably Achievable Analog Rod Position Indication American Society of Mechanical Engineers Confirmatory Action Letter Group Position Indication Gallon Per Minute Licensee Event Report Level Transmitter Management Review Committee Nuclear Regulatory Commission Public Document Room.

Public Service Electric and Gas Radiation Protection Salem Assessment Panel Self-Contained Breathing Apparatuses Service Water Technical Specification Updated Final Safety Analysis Report