IR 05000272/1992017

Insp Repts 50-272/92-17,50-311/92-17 & 50-354/92-18 on 921018-1128.Violation Noted But Not Cited.Major Areas Inspected:Operations,Radiological Controls,Maintenance & Surveillance Testing & Emergency Preparedness & Security

ML18096B148
Person / Time
Site:	Salem, Hope Creek
Issue date:	12/10/1992
From:	Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML18096B146	List: IR 05000272/1992017 ML18096B145
References
50-272-92-17, 50-311-92-17, 50-354-92-18, NUDOCS 9212160108
Download: ML18096B148 (29)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report No /92-17 50-311/92-17 50-354/92-18 License Nos. DPR-70 DPR-75 NPF-57 Licensee:

Facilities:

Dates:

Inspectors:

Approved:

Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, New Jersey 08038 Salem Nuclear Generating Station Hope Creek Nuclear Generating Station October 18, 1992 - November 28, 1992 Inspection Summary:

This inspection report documents routine and reactive inspections to assure public health and safety during-day and backshift hours of station activities, including: operations, radiological controls, maintenance and surveillance testing, emergency preparedness, security, engineering/technical support, and safety assessment/quality verification~ An Executive Summary follows, which summarizes the inspection findings and related conclusions.

EXECUTIVE SUMMARY Salem Inspecti~n Reports 50-272/92-17; 50-311 /92-17 Hope Creek Inspection Report 50-354/92-'18 October 18, 1992 - November 28, 1992 OPERATIONS (Modules 60710,.71707, 71710, 93702).

Salem: PSE&G operated the Salem units in a safe manne Ea~h unit was removed from service to perform secondary plant maintenance. These actions were determined to be conservative and demonstrated proactive _and safety conscious performance by the license The licensee appropriately initiated a Unit 1 load reduction due to a decreasing condenser vacuum. Three separate Technical Specification 3.0.3 entries were determined to be appropriate and conservative. The safety*injection systems on both units were appropriately aligned. The conduct of equipment operator tours remains unresolved pending further NRC review of.discrepancies identified during the licensee's audit of completed equipment operator tours.

Hope Creek: PSE&G operated the Hope Creek unit in a safe manner. The licensee performed effective event followup for two loss of shutdown cooling events that occurred while the unit was shutdown for refueling. One event was attributed to personnel error and one due to design problems. The licensee conducted unit restart from refueling in a *

professional and safety conscious manner. Strong control room command and control of all activities was evident. While the unit was operating, operators responded appropriately to a loss of the process computer which resulted in reactor water level and pressure transient However, this event is unresolved pending completion of the licensee's review. The high pressure* coolant injection system and the emergency diesel generators were appropriately aligned. The conduct of equipment operator tours remains unresolved pending further NRC review of discrepancies identified during a licensee's audit of completed equipment operator tour RADIOLOGICAL CONTROLS (Modules 71707, 93702)

Salem: Periodic inspector observation of station workers and Radiation Protection personnel noted g'ood implementation of radiological controls and protection program requirements. An unresolved item regarding the control room emergency ventilation system was closed.

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Hope Creek: Periodic inspector observation of station workers and Radiation Protection personnel noted good implementation of radiological controls and protection program requi~ements. Failure to have an operable north plant vent radiation monitor is a licensee identified non-cited violation. An inspection of the drywell determined that radiological controls were appropriate and that the material condition was goo MAINTENANCE/SURVEILLANCE (Modules 61726, 62703)

Salem: Based on specific maintenance and surveillance testing activities which were observed, the inspector concluded that the licensee implemented effective programs. The licensee appropriately responded to evidence of poor work practices performed by the fire protection group involving personnel standing on batteries during inspections in, the safety related battery rooms. No equipment operability concerns were eviden Hope Creek: Based on. specific maintenance and surveillance testing activities which were observed, the inspector concluded that th~ licensee implemented effective programs. The licensee appropriately responded to eight mis-wired local power range monitor detectors to ensure that the Technical Specifications were me EMERGENCY PREPAREDNESS (Modules 71707, 93702)

PSE&G appropriately responded to a: loss of the Delaware emergency notification sirens and a loss of the Salem emergency notification phones. The annual emergency exercise was satisfactorily conducted during the period. Reportability of loss of shutdown cooling events is unresolve SECURITY (Modules 71707, 93702)

There were no noteworthy finding ENGINEERING/TECHNICAL SUPPORT.(Modules 37828, 71707, 71711)

Salem: Engineering personnel demonstrated good involvement in plant problems, including sound assessments and evaluations. This included the following issues: damaged fire wrap, degradation of residual heat removal room concrete walls and. increased hydrogen consumption in the main generator. An open item regarding reactor coolant system w.atet level during shutdown conditions was close Hope Creek: Engineering support of unit and. reactor startup was very good. A f~lure of an emergency diesel generator fuel oil pump is unresolved.

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SAFETY ASSESSMENT/QUALITY VERIFICATION (Modules 30702, 40500, 71707,

. 90712, 92700, 92701, 94702)

Salem: The licensee demonstrated conservative decisio:n making, proper regulatory compliance and good.inter-departmental cooperation, operator performance and management support during the six plant shutdown/power reduction events undertaken during the*report perio Hope Creek: * Personp.el initiated events continued during this period. Licensee efforts to date for this issue appeared to be appropriate; however the unresolved item remains open..

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SUMMARY OF OPERATIONS Salem Units 1 and 2 Unit 1 began the period at power. On October 24, 1992, PSE&G shutdown the unit.to repair secondary plant leaks and to replace a service water, spool piece. The unit was restarted on October 30, 1992, and remained. at power the remaining portion of the inspection perio The Unit 2 reactor remained critical during the entire period.. However, PSE&G removed

• the turbine~generator from service during the period November 12-15, 1992, to repair a rriain generator stator water lea.2 Hope Creek The unit began the period shutdown for its fourth refueling outage. PSE&G restarted the unit during the period. Reactor criticality was achieved on November 6, 1992; and full power

. achieved on November 12, 1992. The unit remained at power for the remajnder of the perio.3 Common NRC Chairman Visit Dr. Ivan Selin, NRC Chairman, visited the Artificial Island on October 28, 1992. He toured the Salem facility and met with.PSE&G senior management personne. Institute of Nuclear Power Operations (JNPO) Salem.Plant Evaluation

.The annual INPO plant evaluation of Salem occurred during the period of November 2 to 13, *

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2 OPERATIONS

- _ Inspection Activities The inspectors verified that the facilities were operated safely and in conformance with regulatory requirements. Public Service Electric and Gas (PSE&G) Company management control. was evaluated by direct observation of activities, tours of the facilities, interviews and.

discussions with personnel, independent verification of safety system status and Technical Spedfication compliance, and review of facility records. The inspectors performed normal and back-shift inspections, including deep back-:shift (36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />) inspection * Inspection Findings_and Significant Plant Events

• 2.2.1 Salem Unit 1 Shutdown for Planned Maintenance; Technical Specification Required Shutdown On October 24, 1992, Unit 1 commenced a unit shutdown to repair several secondary system leaks (including the feedwater regulating valves and the heater drain pumps). The main turbine-generator unit was removed from service on October 25. The licensee intended to conduct a four to five day mfilntenance outage while maintaining the reactor critical (Mode 2).

In addition to the planned secondary system work, the licensee replaced a 20-inch service water (SW) system spool piece from the outlet of a component cooling system heat exchanger. That piece was replaced due to previously identified projected pipe wall thinnin The related Technical Specification (TS), allowing the affected SW header to be inoperable for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> while in Modes 1-4, was entered on October 25 at 3:46 On October 27, at 6: 15 p.m., the licensee determined that the repairs to the affected SW header could not be completed within the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed by TSs. Therefore, a reactor shutdown and cooldown commenced to bring the unit into Mode 5 (Cold Shutdown). That action was reported to the NRC in accordance with 10CFR50. 72 reporting requirement The licensee completed the SW repairs on October 29 at 2: 15 a.m. The licensee terminated the cooldown (TS Action Statement exited) with the reactor in Mode 3 (Hot Standby) at 360 degrees F. The reactor achieved criticality on October 30, and the unit was placed_ on-line on November 1. The licensee submitted Licensee Event Report (LER) 50-272/92-22 addressing this issue.*

The inspector reviewed the licensee's shutdown, cooldown and startup activities, maintenance work, procedure and TS compliance, and the LER. The licensee's initial determination to shutdown the unit to complete the equipment repairs was a proactive -and conservative

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decision. The inspector observect that the unit startup was very well controlled; deliberate

_ and effective. Supplemental simulator startup training was provided to the operators prior to the startup. The operations and maintenance activities observed were accomplished in a safety conscious fashio.

- Unit 2 Load Reduction for Maintenance On November 11, 1992, Unit 2 commenced a load reduction from 100% power to complete repairs for several secondary components, including the No. 21 steam generator feedwater pump (SGFP) thrust bearing trip pressure gauge (elevated reading) and minor leaks on the heater drain system. Power was reduced to 45 %. The SGFP problem was subsequently traced to a gauge indication proble While operating at 45% power, licensee personnel noted an increase of a previously identified leakage rate in the main generator stator cooling water system (from about 0. 7 liters per hour to 0~9 liters per hour). The licensee elected to remove the turbine-generator from service on November 12 to investigate and repair the leak. The reactor remained critical in Mode 2 _

(Startup) during the repair activities. After repair activities, the licensee returned the unit to service on November 1 The inspector monitored the licensee's activities associated with the load reduction and unit restoration, and portions of the maintenance work. The inspector concluded that station management's decision to reduce power, and subsequently removed the unit from service, demonstrated conservatism. The activities observed were conducted in a safe manne Unit 1 Load Reduction Due to a Decrease in Condenser Vacuum At about 6:00 a.m. on November 13, 1992, with Unit 1 operating at full power, control_

room operators noted a slight reduction of 2-3 inches Hg in condenser vacuum. During the prior night_, extreme weather conditions existed, which included a heavy rain storm with winds in excess of 30 mph. One of the six condenser circulating water subsystems (circulators) was out of service for'.preventive maintenance. Control room operators implemented abnonnal operating procedure No. Sl.OP-AB.COND-OOOl(Q), "Loss of Condenser Vacuum," which directed the operators to initiate a load reduction at 5 % per hou When 95 % power was reached, condenser vacuum stabilized and returned to norma While power was maintained at 95 %, the licensee removed several of the remaining circulators from service for water box cleaning. In addition, the licensee removed grass and debris from the circulating water trash rake '

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The inspeetor reviewed the licensee's response and followup to the condenser vacuum reduction, and concluded that those actions were appropriate. The vacuum reduction apparently resulted from reduced condenser cooling due to the flow blockage from the grass, and.debris. Full power operation resumed on November 14, 199 *

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4 Unit Shutdowns Performed in Compliance With Technical Specification 3.0.3 * *

During the report period, the licensee initiated three Salem shutdowns, two for Unit 1 and one for Unit 2, in order to comply with TS 3~0.3. This TS requires that when a Limiting Condition for Operation (LCO) is not met except as provided in the associated Action requirements, that action be initiated within one hour to place the plant in a Mode which the specification does not apply. The TS requires the effected unit to be placed in Hot Standby within the next six hours, in Hot Shutdown within the following six hours and in Cold Shutdown within the subsequent 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> On November 2, 1992, the level instrumentation for the No. 12 Boric Acid Storage Tank (BAST) failed while the No. 11 BAST was being used to support the Unit 1 startup (see paragraph A. above}. With the failed level indication on the No. 12 BAST -and with the No.. *

11 BAST level low due to usage, the LCO for TS 3.1.2.8, "Borated Water Sources-Operating," could not be met, and tp.e unit entered TS 3.0.3. The Operating Crew began a controlled shutdown within the required one hour. Within the subsequent hour, level was restored in the No. 11 BAST and the level indicator was repaired on the No. 12 BAST, TS 3.0.3. was exited, and the startup was resumed. The licensee submitted LER 50-272/92~23 addressing this even On November 14, 1992, during the Unit 2 startup (see paragraph B. above) and with plant power at 1 OE-8 amps in the intermediate range, two analog control rod position indicators for control rods in the same bank were observed to drift out of the allowable band, and both were declared inoperable. The LCO for TS 3.1.3.2.1, "Position Indication Systems-Operating," only permits one inoperable rod position indication in any one rod bank, and, therefore, the licensee.entered TS 3.0.3. Power was reduced to IOE-9 amps in order to comply with the shutdown requirements of the TS, and the position indications for the two rods were adjusted. TS 3.0.3 was exited approximately two hours after entry, and the normal plant startup was resume On November 23, 1992, the No. 11 service water nuclear header had been tagged out of service in order to perform work on the associated chill water system, and the No. 12 safety injection pump wa~ consequently rendered teehnically inoperable. Due to the higher than normal temperature and humidity weather conditions on that day, a large amount of condensation occurred on the cooling coils of the room cooler in the safety injection pump room. This condensation leaked out of the room cooler.and splashed onto the m9tor of the No. 11 safety injectiori pump, and the Operating Crew declared that pump also inoperabl With both safety injection pumps inoperable, the plant entered TS 3.0.3. A unit shutdown commenced at 5 % power per hour while operators directed condensation flow away from the No. 11 pump. Maintenance personnel meggered and tested the motor satisfactorily, and operators exited the TS. The shutdown was halted within two hours of the second safety injection pump being declared inoperable (at 92 % power), and a power escalation back to full power was conducted.

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In the case of all three shutdowns, the licensee promptly notified the NRC resident staff and the NRC Operations Center (per lOCFRSO. 72) of plant conditions and the subsequent decision to begiri a plant shutdown in order to comply with TS.3.0.3. For the November 2 and 23 events, the resident responded to the control room, discussed the situation w~th the Operating Crew and plant management, and monitored the conduct of the plant shutdow The inspector determined that, for each-event, the licensee made the proper declarations in accordance with the plant TSs, satisfied all reportability requirements, and safely conducted a pla~t shutdown while repairs or adjustments were made to the affected equipmen.2.2 Hope Creek Loss of Shutdown Cooling Events During the inspection period, Hope Creek.sustained two unplanned losses of shutdown cooling while in Operational Condition 5 (Refueling) during its fourth refueling outag At 10:05 p.m. on October 17, 1992, a loss of shutdown cooling occurred while performing a temporary release associated with design change package (DCP) 4HC-0204 No. 26 in order to obtain a chemistry sample. This caused residual heat remov3,l (RHR) valve BC-HV-F009 to close, which then tripped the B RHR pump resulting in the loss of shutdown -cooling. *

Operators reopened the RHR valve locally in the drywell and returned B RHR to its shutdown cooling lineup. This action restored shutdown cooling at 10:58 p.m. following a rise in reactor coolant temperature from 85° to 89°F. The licensee determined the event t be not reportable (see Section 5.2.D).

The licensee's investigation included a line management review, development of an incident report, an independent quality assurance (QA) review, and reviews by plant managemen The licensee determined root cause to be personnel error due to lack of awareness of the DCP work status, poor communication between work groups, and a tagging error. Corrective actions included immediate restoration of shutdown cooling and counselling of operators and *

work control personnel to ensure tagging is performed in accordance with the DCP instruction At 10: 11 a.m. on October 23, 1992, a second loss of shutdown cooling occurred. The B Reactor Protection Bus (RPS) alternate electrical protection assembly (EPA) breaker tripped on undervoltage. The B" RPS bus was being supplied by its alternate power source, bus lOA-101, and not from the RPS motor generator (MG) sets. The undervoltage condition was caused by starting the "B" turbine building ventilation system supply fan which was also being fed from bus lOA-101. Loss of power to the "B" RPS bus resulted in de-:energizing the nuclear steam supply shutoff system (NSSSS) relays. This resulted in closure of the RHR common suction isolation valve BC-HV-F008 and RHR "A" train discharge valve BC-HV-F015A and caused a loss of the "A" train shutdown cooling which was in service at the time.

In addition, reactor water cleanup (RWCU) containment suction isolation valve BG-HV-F004 also closed as expected resulting in the loss of RWCU. Operators reclosed the alternate EPA

breaker and re-energized the B" RPS bus. The NSSSS relays were reset and RHR shutdown cooling restored within approximately three minutes: RCS temperature remained unchanged at 126°F. An ENS call was made due to this being an engineered safety feature* actuatio The licensee's investigation included a line management review, development of an incident.

report, and a plant management and Station Operations Review Committee (SORC) review of Licensee Event Report 92-14. The licensee determined root cause to be the design of the alternate RPS power supply, such that it is susceptible to voltage perturbation. Corrective actiOns included increased sensitivity to vulnerability while operating on altemat~ RPS feed and longer term actions to pursue a design change to reduce susceptibilit The inspector reviewed these events and concluded that the licensee performed ~ffective event followu *

• Unit Startup Following The Fourth Refueling Outage On November 6, 1992, the licensee completed the prerequisites for restarting the unit following its fourth refueling outage. The unit entered Operational Condition 2 (Startup) and control rod withdrawal commenced at 11:09 a.m. *Control room operators achieved reactor criticality -at 3:50 p~m. that afternoon. At the conclusion of the requisite testing, operators synchronized the turbine-generator to the electrical grid at 1:34 p.m. on November 10, 1992,

.ending a 59-day outag The inspector monitored the licensee's activities in preparation for and conduct of unit restart arid return to service in accordance with NRC inspection module 71711. Significant results of these inspection activities are detailed below:

Major portions of the emergency diesel generafor and control rod drive hydraulic systems were walked down to assess readiness for restart and proper valve/contro switch alignment. A number of minor housekeeping issues were brought to licensee.

management's attention. The inspectors concluded; however, that both systems were properly aligned and operable. The licensee was prompt in initiating efforts to address the noted housekeeping deficiencie *

Applicable plant procedures, in particular integrated operating procedures OP-IO.ZZ-0002 (Preparation for Plant Startup) and OP-IO.ZZ-0003 (Startup from Cold Shutdown to Rated Power) were reviewed for completeness, appropriate signoffs and completion of required surveillance The inspectors determined that pro~edure implementation was appropriat *

Before and during the startup and power a§cension, the inspectors observed a number of surveillances required to support plant operation:

OP-ST.SE-002, Startup Range Monitor Rod Block Functional Test OP-ST.SN-0001, Automatic Depressurization System and Safety Relief Valve Functional Test - 18 Months OP-ST.AC-0001, Turbine Overspeed Protection System Operability Test The inspectors noted that licensee personnel were knowledgeable about the procedures and they performed the tests in accordance with test procedure *

Control room observations:

The senior nuclear shift supervisor (SRO licensed) exercised good command throughout the startup. Control room access was limited to necessary personnel onl *

Nuclear control operators (RO licensed) performed their duties in accordance with procedure and exhibited a good safety perspective. Reactor engineering personnel had identified a number of control rods which were calculated to have particularly high reactivity worth, where moving a rod one notch could result in a significant positive reactivity addition. Operators highlighted these control rods on the pull sheet and closely monitored their instrumentation when moving these rods. The ROs achieved criticality withouf inciden Control room personnel demonstrated good control of field activities. Repeat backs were used in almost all cases and care was taken to assure field personnel were using the applicable procedure *

Support for the operations department appeared very good. Because of the number of on-going tests, field work completion and plant/equipment status changes, the close cooperation between the various departments involved in these activities was especially noteworth The inspectors concluded that the licensee conducted unit restart in a professional and safety-conscious manner and in accordance with the applicable procedures. The close cooperation between all groups involved in the restart effort contributed significantly to the successful return to service of the uni Reactor Level and Pressure Transient On Saturday, November 21, 1992, with the unit operating normally at 100% power, the*

control room received indication/annunciation of a number of simultaneous events at 6:50 a.m.:

Reactor water level high and low alarms, 11A 11 reactor feedpump flow oscillations,

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Reactor pressure oscillations as No. 4 main turbine control valve cycled open,

"D" safety/relief valve (SRV) open, One main turbine by-pass valve cycled open, then closed,.

Loss of Nuclear Steam Supply System (NSSS) plant process computer, and Transfer of control room indication and display system (CRIDS) computer power from normal to back-u Operators immediately placed the "A" reactor feedpump in manual and restored reactor water level to normal ( + 35 inches). During the transient the other two * feedpumps compensated for the flow oscillations to maintain the reactor water level within the normal operating band (+30 to +40 inches). The "D" SRV open indicatiop was determined to be spurious as both tailpipe and suppression pool temperatures did not increase. A number of input cards relating to core performance parameters in the NSSS computer were destroyed. The electrical

distribution load dispatcher did not note any grid disturbances. At 7:37 a.m., the control room again received indication that the "D" SRV had opened and of reactor water level swings. Both these indications were determined to be spurious. No further abnormalities were noted and the "A" reactor feedpump was returned to automatic control. Reactor power was reduced to 99 % to provide a measure of operating conservatism while the NSSS computer was repaired. The licensee concluded the event to be not reportable.. The licensee returned the computer to service on November 25, 1992.

The licensee is continuing their investigation of the cause of this event. Though the potential for a Solar Magnetic Disturbance (SMD).was being monitored at the time of the transient, the licensee verified that an actual SMD did not occur and consequently was not a causal factor for the occurrence. Currently, the licensee's investigation indicates that a high level voltage spike (the source of which remains undetermined) caused failure of the watt transducers in both reactor recirculation motor-generator set control panels, which input to the plant's process computer. The process computer, which operates in the millivolt range, was subsequently damaged (i.e., two cards were severely burned). The voltage spike continued to be propagated to numerous other non-lE monitors,. recorders, and control panels which interface with the process computer. Consequently, the line noise resulted in several spurious indications of alarms and valve movements, and affected t4e feedwater control panel which caused actual oscillation of a feedwater pump and a minor reactor water level transient. -The

• cause of the high voltag*e spike continues to be investigated. This event is unresolved pending the completion of the licensee's review (URI 50-354/92-18-02).

2.2.3 Common * Engineered Safety Feature (ESF) System Walk.downs The inspectors independently verified the operability of' selected Salem aJ.ld Hope Creek *

sys~ems by performing a walkdown of the accessible portions of the system: The inspectors performed the walkdowns to confirm that system lineups and procedures matched plant

drawings and the as-built configuration, and to identify adverse equipment conditions which could degrade performance. This inspection was conducted_ in accordance with NRC inspection procedure 71710. Systems inspected included portions of the following:

Salem Unit 1 and 2 Charging System, and

_ Salem Unit 1 and 2 Safety Injection System, and

Salem Unit 1 and 2 Residual Heat Removal System, and

Hope Creek High Pressure Coolant Injection System, and

Hope Creek Emergency Diesel Generator Based on the above, the inspectors concluded that these ESF systems were operational and capable of performing their design function Open Item Followtip (Open) Unresolved Item 50-272, 311 and 354/92-12-01. Equipment Operator (EO) tours and the security card system. The inspector reviewed the issue of EO tours relative to backshift tours and EO ready room conduct. The inspector confirmed that management expectations included completion of a first tour to perform the required logs and the minimum of a second tour during each shift. EO's would then spend the remaining time on shift performing tests, tagouts, or other activities as directed by the shift supervisors. A field shift supervisor is assigned to provide in-field EO oversight. The EO's have a ready room where they can eat and spend their break periods. It is also management's expectation that no non-technical reading, no horseplay, nor any other unauthorized activities be allowed in this ready room. Hope Creek's EO ready room is adjacent to the control room. Salem's EO ready room is a new facility, also adjacent to the control room. This was recently moved from a temporary facility in the Unit 2 turbine building. During periodic day shift and backshift tours, the inspector did not identify any reading of non-technical material nor any horseplay in either the Salem or the Hope Creek EO ready rooms. This issue will remain unresolve4 pending further NRC review, including resolution of the issue of EO tour conduct

' and the effectiveness of the security card syste.

RADIOLOGICAL CONTROLS Inspection Activities PSE&G' s conformance with the radiological protection program was verified on a periodic basi.2 Inspection Findings

3.2.l Salem *Open Item* Followup (Closed) Unresolved Item 50-272/91-18-0l. Control room emergency air filtration (EAF)

Technical Specification (TS) inconsistency. During a previous radiological protection inspection, a NRC inspector identified an inconsistency in the TSs addressing the EAFs in the control room emergency air conditioning system. Specifically, the EAF units are required to be operable in all Modes at Unit 2, yet at Unit 1 the EAF units are permitted to be inoperable -in Modes 5 and 6. The two units share the same ventilation boundary, and the TS test which demonstrates the operability of the control room emergency air conditioning system relies on both plants' EAF unit being operable. The inspector identified the concern that it would be possible for the Unit 1 EAF unit to be allowed to be inoperable while the Unit 2 EAF was required to be operable, yet the Unit 2 EAF unit would not have been demonstrated to be able to maintain the required pressure in the control room boundary by itsel PSE&G acknowledged the inspector's concern and initially addressed the possible discrepancy in EAF configuration with a Technical Specification Interpretation Form in accordance with station administrative directive AD-45, "Technical Specification Interpretation Program." The inspector reviewed the completed TS Interpretation Form, which imposes the same EAF operability requirements on Unit 1 as those that exist for Unit 2, and determined that the licensee's correetive actions were appropriate and sufficient to address the inspector's concerns. The inspector verified that PSE&G was pursuing a permanent resolution to the issue in that the licensee has requested a change to the Unit 1 TSs with License Change Request 92-15 which will bring the Unit 1 TS into alignment with the Unit 2 TS. Based on the licensee's corrective actions, this item is close.2.2 Hope Creek Inoperable North Plant Vent Radiation Monitor On October 17, 1992, the north plant vent (NPV) radiation monitoring skid was declared inoperable due to low sample flow indication. Upon later review by licensee radiation protection supervision, however, it appeared that only the non-Technical Specification (TS)

indication was inoperable. The wide range noble gas sample monitor flow indication required by TS 3.3.7.11 appeared proper. The NPV radiation monitor was therefore declared operable and returned to service. On October 23, 1992, during troubleshooting of the non:..

TS flow element, the licensee discovered that the sample pump's diaphragm had failed, drawing in air which was diluting the sample monitored* by the wide range gas detector. This condition had apparently existed since at least October 17, 1992. TS 3.3.7.11 allows effluent release with the monitor inoperable as long as 12-hour grab samples are taken and analyze Such samples had not been taken. The licensee determined that the incident was caused by a

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design deficiency whereby the sample flow rate indication did not ensure a valid sample was being observed. The licensee' corrective actions included repairing the sample pump, revising alarm response procedures and evaluating a design change to detect system leakag The inspector reviewed this event and concluded that the safety significance of this event was minimal since two systems were in operation during the time when the sample pump was operating with a ruptured diaphragm.. One system exhausted first through its own filter system, and the other system was sampled locally on a routine basis (the samples showed no airborne activity). While this event constituted a violation of TS 3.3.7.11, this violation is not being cited because the inspector verified that all the criteria specified in Section VII.B of the NRC Enforcement Policy had been satisfied. The inspectpr also reviewed Licensee Event Report 92-12 which discussed this event and did not note any discrepancie Drywell Inspection The inspector performed a post-refueling outage drywell closeout inspection on November 5, 1992. PSE&G personnel had previously conducted their final closeout tour and inspectio The inspector checked for radiological conditions, equipment material condition, and overall housekeeping/cleanliness conditions. The inspector noted the drywell to be very clean with excellent housekeeping. Equipment material condition was very good. The inspector noted a large amount of equipment and debris outside the drywell airlock. The licensee was in the processing of cleaning this area. A radiation protection technician accompanied the inspector during the tour. The radiological conditions were determined to be appropriate. Overall, the inspector concluded that the drywell was ready to support power operation.

MAINTENANCE/SURVEILLANCE TESTING Maintenance Inspection Activity The inspectors observed selected 'maintenance activities on safety-telated equipment to ascertain that these activities were conducted in accordance with approved procedures, Technical Specifications, and appropriate industrial codes and standard Portions of~the following activities were observed by the inspector:

Work Order(WO) or Design Change Package (PCP)

Description Salem 1 WO 920530148 12SW387 Spool Replacement Salem 1 Various WOs 21 Steam Generator Feedwater Pump

Salem *1 WO 920923118 Salem J WO 920827107 Salem 2 WO 920901168 Hope Creek Various

Analog Rod Position Indication Adjustments Replace *rN44 *Power Range Channel IV Gain Potentiometer Turbine building revitalization Installation of VOTES test sensors and motor operated valve static and dynamic test The maintenance activities inspected were effective with respect to meeting the safety objectives of the maintenance progra * Surveillance Testing Inspection Activity The inspectors performed detailed technical procedure reviews, witnessed in-progress surveillance testing, and reviewed completed surveillance packages. The inspectors verified that* the surveillance tests were performed in accordance with Technical Specifications, approved proced~res, and NRC regulation *

The following surveillance tests were reviewed, with portions witnessed by the inspector:

Procedure N *Salem 1 S 1. OP-ST. TRB-0003(Q)

Hope Creek OP-ST.SN-001 Hope Creek OP-FT.AC-0004 Hope Creek

. OP-ST.SE-002 Hope Creek OP-ST.AC-0001 Turbine Mechanical Overspeed Test ADS and SRV Manual Operability

• Test - 18 Months Main Turbine Functional Test -

Refueling StartUp Range Monitor Rod Block Functional Test Turbine Overspeed Protection System Operability Test The surveillance testing activities inspected were effective with respect to meeting the safety *

objectives of the surveillance testing program.

13 Inspection Findings 4.3.1 Salem Poor Work Practice ill Safety-Related Battery Rooms During plant tours, the.inspector noted several instances of minor housekeeping and equipment deficiencies. The minor discrepancies were communicated to the licensee for resolution. One discrepancy, however, caused concern because it evidenced a poor work practice creating the potential to damage safety-related equipment. Speeifically, the inspector noted footprints on top of two of the six Unit 1 and 2 125 VDC safety-related batteries. *

There*appeared to be no adverse affect on the batteries, which remained in an operable condition. The licensee promptly investigated the concern and concluded that fire protection *

personnel most likely stood on the batteries while testing thermal detectors located in the overhead. The normal method utilizes a heat gun attached to a telescoping pole. A memorandum was issued to all Fire Protection Operations personnel* stressing the precautions needed when working in and around the battery rooms. The inspector concluded that the immediate actions taken by the licensee were appropriat *

4.3.2 Hope Creek Incorrect Local Power Range Monitor (LPRM) Cable Installation In October 1992, during the fourth refueling outage, licensee contractor personnel replaced a number of LPRM detector strings. Additionally, a number of LPRM detector cables in the drywell near an uninsulated portion of the reactor water cleanup (RWCU) suction piping were evaluated for accelerated thermal degradation after discovery during troubleshooting of a problem with LPRM 24-57A. The licensee *replaced six of those cables. On Noveinber 12, 1992, while holding reactor power at 23%, the licensee noted while calibrating the LPRMs that a number of detectors did not exhibit the expected responses. An investigation revealed that eight LPRM. detectors had apparently been miswired. * The licensee bypassed all eight

_

detectors and verified that the Technical Specification (TS) minimum inputs (total number and -*

core axial level) were met for each average power range monitor (APRM). The licensee requested General Electric (GE) to perform an analysis on the potential effects on plant operation/core performance and to make recommendations for interim operatio *

The inspector reviewed the licensee's activities surrounding this event and concluded that the licensee had been thorough in his evaluation t'o demonstrate the acceptability of continued reactor power operation. Short term corrective actions appeared appropriate. The licensee's long term correetive actions, including any implementation of GE's forthcoming recommendations (due in January 1993), will be assessed in a future inspection.

14 EMERGENCY *PREPAREDNESS Inspection Activity The inspector reviewed PSE&G's conformance with 10CFR50.47 regarding implementation of the emergency plan and procedures. In addition, licensee event notifications and reporting requirements per 10CFR50. 72 and 73 were reviewe.2 *

Inspection Findings Loss of Off-Site Sirens At 10: 15 a.m. on October 26, 1992, PSE&G reported that the state of Delaware emergency notification sirens were inoperable. Both the Salem and Hope Creek facilities made

emergency notification system (ENS) calls to report this event. The state of New Jersey sirens remained unaffected and operable, The failure resulted from a faulty siren causing feedback into the entire Delaware siren system.* The licensee repaired the faulty siren and declared the Delaware sirens operable at 1 :53 p.m. A followup ENS was mad.

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The inspector reviewed this event, including the Salem/Hope Creek incident reports, and discussed it with licensee personnel. The inspector concluded that licensee actions were appropriat Annual Emergency exercise The licensee conducted the annual emergency exercise at Salem on October 28, 1992. The resident inspectors participated in and monitored lfoensee performance. The details of the NRC findings a11d assessment are in NRC inspections 50-272, 311 and 354/92-1.

. Loss of Salem Emergency Notification System (ENS) Phones During the annual emergency exercise (5.2.B above), the licensee noted that the Salem ENS phones were not functioning. At 9:50 p.m. on October 28, 1992, the licensee notified the NR.C duty officer of this condition, making* the required one hour report. The ENS phone was subsequently repaired. An additional loss occurred on November 17, 1992. The licensee reported. these conditions, the NRC initiated* trouble reports wi.th the local telephone company and the ENS phone was repaire The inspector reviewed these events, including the Salem incident reports, and discussed the event with licensee personnel. Four additional ENS failures occurred during August and September 1992 (See NRC Inspection 50-272, 311 and 354/92-13). This ENS phone system is the newly installed FTS 2000 system. The inspector concluded that licensee actions were appropriate.

1 Reportability of Loss of Residual Heat Removal (RHR) Shutdown* Cooling Events The.inspector reviewed the issue for reportability of loss of shutdown cooling events at Salem and Hope Creek during shutdown condition On October 17, 1992, the Hope Creek facility experienced an unplanned loss of shutdown cooling event (See Section 2.2.2.A). PSE&G concluded that this event was due to personnel error associated with work control and a tagging/eommunication error. This caused the shutdown cooling RHR suction valves to close tripping the RHR pump. Shutdown cooling was restored in 53 minutes and reactor temperature increase about 4 °P. The unit was in Operational Condition 5 (Refuel) with the reactor cavity full. PSE&G further concluded this event to be not reportable based on the following evaluation:

The event was not an engineered safety feature (ESP) actuation, and

Hope Creek Technical Specifications (TSs) 3/4.9.11 and 3/4.4.9 allow removal of RHR shutdown cooling for up to two hours per an eight hour period, and

10CFR50.72(b)(2)(iii)(B) did not require the event to be reported because the loss was not sustained (e.g., "~my event that alone could of prevented the fulfillment of a safety function needed to remove residual heat" - did not apply), and

.

• Hope Creek emergency action levels (ECG - Emergency Classification Guide) did not require any declaration nor reportin On May 20, 1989, Salem Unit 1 lost shutdown cooling during a safety injection accumulator test. The RHR pumps tripped and they wer~ restarted within an hour. Due to the potential

• for RHR pump damage from the nitrogen injection, the licensee was cited (NRC IR 50-272/89-17-01) for failure to make a lOCFRS0.72 report per paragraphs (b)(2)(iii)(B).

The inspector reviewed the Salem relevant reporting requir~ments, and determined that only a sustained ("alone could of prevented") loss of RHR shutdown cooling, or one that involved an ESP actuation, would be required to be reported to the NRC. *

The inspector continues to review the issue of reportability of unplanned losses of RHR shutdown cooling events. Consequently, the matter remains unresolved (URI 50-272, 311/92-17-01; 50-354/92-18-01).

.

SECURITY Inspection Activity PSE&G's conformance with the security program was verified on a periodic basis; including the adequacy of staffing, entry control, alarm stations, and physical boundarie.2 Inspection Findings There were nq noteworthy findings;

. ENGINEERING/TECHNICAL SUPPORT *salem Engineering Involvement in Plant Deficiencies During a periodic plant tour with Regional management, the inspector noted the following two deficient conditions:

Damaged cable tray fire wrap located above the component cooling water (CCW)

rooms' door on the 84 foot level corridor in the auxiliary building of both units; and

Degraded concrete walls in the 45 foot level of the residual heat removal (RHR)

rooms of both unit The inspector discussed these items with system engineers, fire pr9tection engineers and *

operations personne The damaged fire wrap (JM fire barrier FS-195) was apparently caused by air interference problem between the CCW room door and the fire wrap wire supporting material. The licen.see initiated an incident report and a fire impairment, generated repair work orders (921015183 and 921015185), and confirmed that fire watches were already in place. In addition, fire protection engineers performed an evaluation and concluded that the affected fire barriers were operabl The degraded cpncrete walls in the RHR rooms were caused by ground water leakage and subsequent repair activities. The licensee.has attempted to seal the leaks, however, efforts to date have* been unsuccessful. The inspector expressed concern over the affect of the ground *

water on the 9oncrete rebar material. Licensee system engineering personnel had previously evaluated this concern by visually examining the rebar material in select locations and by *

confirming the non-existence of ferric oxide in the ground water. This would confirm that

. the rebar material is not experiencing any degradation due to rust. In addition, this issue of ground water is currently being addressed by the Salem revitalization grou **

The inspector concluded that engineering personnel demonstrated good involvement in plant problems, and their assessments and evaluations were soun B. * Main Generator Hydrogen Consumption The inspector reviewed the licensee's response to hydrogen leaks identified at both Units 1 and 2 from the main generator hydrogen system. The inspector interviewed the responsible system engineers and observed portions of the troubleshooting, repair and testing activitie Both Units 1 and 2 had experienced hydrogen leakage as evidenced by an increased hydrogen filling frequency by equipment operators. The design hydrogen leakage is 600 standard cubic feet per day (SCFD), and is based upon hydrogen permeation into the hydrogen seal oi system and the teflon hoses in the generator stator water system. No operational limitation are recommended by the generator vendors if hydrogen design leakage is exceeded, provided that an adequate volume of hydrogen is provided to cool the generato At the end of the inspection period, the Unit l hydrogen le3.kage was about 1000 SCfD, and the leakage was identified to be primarily from a leaking vent valve (to the *outside atmosphere).

Repairs to the vent valve were previo_usly addressed in NRC Inspection 92-13.

The Unit 2 leakage was at about 600-800 SCFD at the close of the inspection period, however, the hydrogen leakage had reached approximately 4000 SCFD just prior to the Unit 2 load reduction on November 11, 1992 (See Section 2.2.1.B of this report). The principle leak sources at that time were the hydrogen cooler, a vent valve (to atmosphere), and a minor hydrogen seal leak. Those leaks were effectively repaired when the turbine-generator unit was removed from service on November 1 The inspector concluded that both operations and system engineering personnel properly identified, monitored and assessed the main generator increased hydrogen consumption rate In addition, hydrogen concentration in the affected plant areas were closely monitored by the appropriate station personneL Open Item Followup (Closed) Unresolved Item 50-272 and 311/91-21-01. Reactor coolant system (RCS) water level and residual heat removal (RHR) system monitoring. During an NRC inspection of the licensee's actions taken in response to Generic Letter 89-17, "Loss of Decay Heat Removal,.

the inspector observed that all but one of the Programmed Enhancements had been adequately

• implemented. The one area of the inspection that was left unresolved concerned the installation of permanent RCS level indication and the completion of the computer displays for the RHR system performance indicators. The licensee addressed this area with the implementation of design change' packages (DCPs) lEC-3112 for Unit 1 and 2EC-3087 for Unit 2. These DCPs provided, for their respective unit, at least two independerit continuous

• RCS level indications whenever the RCS is in a reduced inventory condition and the ability to monitor RHR system parameters such as mid-loop operation core exit thermocouple setpoint and RHR pump discharge flow, discharge pressure, suction pressure and motor current. _The inspector reviewed the DCPs, including the 10CFR50.59 safety evaluations performed for them, and* inspected the control room to verify the availability of the parameter indications and the operators' ability to monitor them. The inspector determined that the licensee's actions had adequately addressed the previously unresolved issues, and this item is close For a related item pertaining to monitoring core parameters with the plant shutdown,. the inspector reviewed the licensee's actions taken in response to TMI Action Item II.F.2.2.,

"Instrumentation for Detection of Inadequate Core Cooling." PSE&G had responded to the requirements of NUREG-0737, "Clarification of TMI Action Plan Requirements," by upgrading the subcooling margin monitor (SMM) at the two Salem units via DCPs lSC-2276 and 2SC-2276. These DCPs upgraded the core exit thermocouple modules and displays to perform margin to saturation functions and display digitally the subcooling margin to control room operators. The inspector reviewed the DCPs and* discussed with licensed operators the use of the SMM control room indications and associated procedures. The inspector -

concluded that PSE&G had satisfied the regulatory requirements for this TMI Action Item, and this item is considered closed.

. 7.2 Hope Creek. Emergency Diesel Generator (EDG) Fu'el Oil Puinp Failure On November 1, 1992, the licensee completed an overhaul of the "B" EDG, manufactured by Colt-Pielstick. During post-maintenance testing, operators noted the fuel oil pressure decreased as the EDG was electrically loaded. An investigation revealed that the engine driven fuel oil pump, which had been replaced with a new unit during the overhaul, was*

rotating in the reverse directiOn from what was required.. Upon disassembly, the licensee noted that the pump internals were configured for a clockwise rotation EDG. Hope Creek's EDGs are designed with a counter-clockwise rotation of the main crank shaft. The licensee reconfigured the fuel oil pump's internals and reinstalled the pump. The EDG was then successfully tested. The licensee also determined that two spare fuel oil pumps in the warehouse were identical to the incorrect one found in the "B" EDG. The two spare pumps'

internals were reconfigured to conform to design requirements. The three other EDGs* (A, C and D) were also overhauled during the refueling outage; however, their engine driven fuel oil pumps were not replaced. The licensee is pursuing its investigation with the vendor, including an evaluation of reportability under 10CFR2.1. The engine driven fuel oil pumps, Colt-Pielstick part number P12605391 were m~ufactured by Societe d'Etudes de Machines Thermiques (SEMT) of Paris, France and delivered to Hope Creek in 198 This issue remains open pending the resolution of the licensee's Part 21 evaluation and*

'subsequent corrective actions (URI 50-354/92-18-03).

B.

Engineering Support of Unit Restart

. The inspector observed system and reactor engineering involveinent prior to and during reactor startup and power ascension activities. The inspector noted that engineers provided

• effective input to operational decisions. In a.ddition, reactor engineers provided very good *

oversight of reactivity manipulations and core physics test.

SAFETY ASSESSMENT/QUALITY VERIFICATION Salem A~

Conservative Plant *shutdowns Executed During the inspection period documented in this report, the licensee initiated six plant shutdowns/power reductions at Salem, four at Unit 1 and two atUnit 2 (See Section 2.2.1, paragraphs A-D, of this report). Technical Specification requirements compelled three of these events, and the licensee voluntarily undertook the other three to address degrading plant conditions or equipment. The resident inspector staff monitored the operating crews and other plant personnel at various times throughout each event as plant conditions were evaluated and attended to, as well as plant management's oversight of the units' operatio The inspector noted that, in each case, the licensee made a conservative decision to shut a unit down or reduce its power level; none of the voluntary shutdown events involved an exigent condition, and station personnel demonstrated proactive and conservative regulatory compliance when 11:ecessary. The inspector further concluded that the good inter-departmental cooperation, operator performance and management support exhibited during these six events characterized safe and prudent operation of the Salem nuclear power plant * Hope Creek Open Item Followup (Open) Unresolved Item 50-354/92-13-05. Several personnel initiated events were reviewed last period (NRC Inspection 50-354/92-13). Subsequently, several additional events occurred during this period (See Sections 2.2.2.A and 4.3.2.A). The inspector and members.of regional management met with Hope Creek management on October 29, 1992 to discuss each event; their _root causes, and corrective actions. Quality Assurance reviewed three of the events and issued a report (HQA-92-717) on November 4, 1992. The inspector concluded that licensee efforts to date appear to be thorough and an appropriate level of management attention has been applied. Pending completi9n of licensee followup and review activities; and subsequent NR<::: review, the unresolved item 5q-354/92-13-05 remains open.

.*

• LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS, AND OPEN ITEM FOLLOWUP 9.1 LERs and Reports PSE&G submitted the following licensee event reports, and special and periodic reports, which were reviewed for accuracy and evaluation adequacy:

Salem and Hope Creek Monthly Operating Reports for October 199 *

Salem Special Report 92-6 concerned a valid failure of the 2B emergency diesel generator (EOG) during testing on September 24, 1992. The licensee determined root cause to be equipment failure of the exhaust pipe flange bolting due to thermal cycling and fatigue. Corrective actions included repair of the 2B.EDG, inspection of the

other EDGs~ and a change to the EDG inspection program to ensure periodic checking of the EDG exhaust boltin The inspector concluded that these reports were appropriately initiate Salem LERs Unit 1

LER 92-22 (See Section 2.2.1.A).

• LER 92-13 (See Section 2.2.1.D).

Unit 2 None Hope.Creek

LER 91-10-01 discussed an automatic closure of the inboard reacfor core isolation cooling (RCIC) to torus vacuum breaker isolation valve during instrument functional testing (See NRC Inspection 50-354/91-12, Section 4.3.3.D for details). The licensee could not determine the cause of the valve closure, and stated that an LER revision would be submitted after additional testing was undertaken. As indicated in this LER (91-10-01), the licensee was unable. to duplicate the valve's closure despite extensive additional testing. The testing did verify that the valve control logic and operation were in accordance with design. While personnel error could. not be ruled out, the licensee indicated that the technician's performance of the functional test on a drywell pressure instrument had been independently verified to be accurate. The inspector concluded that the licensee had made a concerted and thorough effort to determine* the

'.

cause of this event and had demonstrated the RCIC system's operability through the

• additional testing. The inspector also noted that this supplemental LER fulfilled the licensee's commitment as* stated in LER 91-10. The inspector had no further questions at this time regarding this issu *

LER 92-10 discussed a September 24, 1992 actuation of the Primary Containment Isolation System. (See NRC Inspection 50-354/92-13, Section 4.3.2.C for details.)

The licensee's corrective actions for this event included the counseling of personnel involved and a review of the incident with all engineering department personne These actions appeared to be adequate and the LER was well writte *

LER 92..:11 discussed a September 25, 1992 actuation of the Primary Containment Isolation System. (See NRC Inspection 50-354/92-13, Section 4.3.2.C.) Corrective actions for this event included upgrading a* number of instrument calibration procedures as well as expediting the implementation of a previous corrective action (see LER 91-04 regarding instrument rack restoration procedures). No discrepancies were noted in this LE *

LER 92-12 (See Section 3.2.2.A).

• LER 92-14 (See Section 2.2.2.A).

9.2 Open Items The following previous inspection items were followed up during this inspection and are tabulated below for cross reference purpose Report Seetion 272/91-18-01 3.2. &311/92-12-01 2.2. &311/91-21-01 - 7. Hope Creek 354/92-12-01 354/92-13-05 2.2.. Closed Open Closed Open Open *

1 EXIT INTERVIEWS/MEETINGS 1 Resident Exit*Meeting The inspectors met with Mr. C. Vondra and Mr. J. Hagan and other PSE&G personnel.

periodically and at. the end of the inspection report period to summarize the scope and findings of their inspection activitie Based on NRC Region I review and discussions with PSE&G, it was determined that this report does not contain information subject to 10 CFR 2 restriction.2 Specialist Entrance and Exit Meetings Inspection Reporting Date(s)

Subject Report N *Inspector 10/20-30/92 Engineering 272&311/92-16;354/92-17 Cheung 11/4-10/92 Snubbers 354/92-19 Carrasco 11 /16-20/92 Effluents

. 272&311/92-18 Peluso 10.3 * Management Meet.ings Salem/Hope Creek Licensing Meeting The inspector attended a licensing meeting at NRR on November.3, 1992. Current *

Salem/Hope Creek licensing issues were discussed between NRR project managers and PSE&G licensing staf Security Management Meeting The inspector attended a closed management meeting held to discuss security plan*

.implementation at Salem/Hope Creek on November 23, 1992, at the Region I offic Attachment 1 is a list of attendees.

. -.

..

ATTACHMENT 1 LIST OF ATTENDEES November 23, 1992, NRC/PSE&G Management Meeting PUBLIC SERVICE ELECTRIC AND GAS COMPANY S. E. Miltenberger, Vice President & Chief Nuclear Officer L.. A. Reiter, General Manager - Quality Assurance (QA) & Nuclear Safety Review G. C. Munzenmaier, General. Manager - Nucl~ Services P. A. Moeller, Manager - Site Protection *

R. Fryling, Jr., General Solicitor M. V. Butz, General Manager, Nuclear Human Resources R. J. Mack, Nuclear Medical Director NUCLEAR REGULATORY COMMISSION W. F. Kane, Deputy Regional Administrator, Region I (RI)

C. L. Miller, Project Director, PDI-2, Office of Nuclear Reactor Regulation (NRR)

E. C. Wenzinger, Chief, Projects Branch 2, Division of Reactor Projects (DRP), RI

. J; R. White, Chief, Reactor Projects Section 2A, DRP, RI

J. H. Joyner, Chief, Facilities Radiological Safety & Safeguards Branch (FRSSB), RI R. R. Keimig, Chief, Safeguards Section, FRSSB, RI J. C. Stone, Salem Project Manager, NRR

.

T. P. Johnson, Senior Resident Inspector, Salem & Hope Creek, I?RP, R R. J. Albert, Physical Security Inspector, Division of Radiation Safety & Safeguards, RI OTHER E. Stier, Stier, Anderson & Malone H. Anderson, Stier, Anderson & Malone.

M. Wetterhahn, Winston & Strawn