IR 05000354/1987001

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Insp Rept 50-354/87-01 on 870101-0209.Violation Noted: Failure to Obtain & Analyze Grab Samples Per Drywell Leak Detection Action Statement
ML20212M149
Person / Time
Site: Hope Creek PSEG icon.png
Issue date: 03/04/1987
From: Norrholm L
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20212M143 List:
References
50-354-87-01, 50-354-87-1, IEIN-86-109, NUDOCS 8703110169
Download: ML20212M149 (14)
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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

050354-860924-050354-861023 Report N /87-01 050354-861030 050354-861101 Docket 50-354 050354-861128 050354-861205 License NP F-57 050354-861206 050354-861209 Licensee: .Public Service Electric and Gas Company 050354-861210 Facility: Hope Creek Generating Station Conducted: January 1, 1987 - February 9, 1987

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Inspectors: R. W. Borchardt, Senior Resident Inspector D. K. Allsopp, Resident Inspector Approved: k ft 3 /4[i? /

L. l lorrholm, Chief, Projects Section 2B / Dite Inspection Summary:

Inspection on January 1,1987 - February 9,1987 (Inspection Report Number 50-354/87-01)

Areas Inspected: Routine onsite resident inspection of the following areas: followup on outstanding inspection items, operational safety verification, surveillance testing, maintenance activities, engineered safety feature system walkdown, RHR pump failure, security, licensee event report followup, and regional temporary instruction followup. This inspection involved 162 hours0.00188 days <br />0.045 hours <br />2.678571e-4 weeks <br />6.1641e-5 months <br /> by the inspector Results: One apparent violation of Technical Specifications was identified during the inspection (paragraph 3.2) pertaining to the failure to obtain and analyze grab samples as required by the drywell leak detection action statemen Increased management attention is needed to prevent additional Technical Specification action statement violations, especially in the radiation protection and chemistry areas. The number of control room overhead annunciators in alarm during power operation continues to be of concern to the NRC. (Paragraph 3.3)

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DETAILS Persons Contacted Within this report period, interviews and discussions were conducted with Mr. R. Salvesen and members of the licensee management and staff-and various contractor personnel as necessary to support inspection activit . Followup on Outstanding Inspection Items 2.1 Violaticns (Closed) Violation (86-30-04); Timely corrective action. The inspecto reviewed the licensee's response to this violation dated August 27, 1986, and reviewed the current status of open quality assurance action request This review indicates that responses are now being submitted in accordance with the station's program. The inspector has no further questions at this time and this item is close (Closed) Violation (86-48-02); Core Spray pressure transmitter isolate The inspector reviewed the licensee's response to this violation dated January 7,1987 and verified through independent inspection that adequate corrective actions have been completed. Safety related system lineups will continue to be performed by the inspector on a routine basis. This item is close .2 Unresolved Item (Closed) Unresolved Item (86-27-03); RHR valves HVF-011A and HVF-0118 require Technical Specification change. The inspector verified that RHR suppression pool return valves HV-F-011A and HV-F0118 are now correctly listed in Technical Specification table 3.6.3-1 under "Other Containment Valves". This item is close .3 Inspector Follow Items (Closed) Inspector Follow Item (86-20-04); Licensee to add additional information to ADS logic functional test. The licensee revised procedure OP-ST.SN-002, ADS Logic Functional Test - 18 months, to include detailed instructions for simulating RHR pump "B" discharge pressure at E11-N655 These instructions include prescriptive steps for RHR system restoration and independent verification of system lineup after completion of the tes The inspector reviewed the revised procedure, reviewed ADS logic prints, and had no further questions. This item is close _

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. (Closed) Inspector Follow Item'(86-20-05); Inadequate testing of ADS solenoid and ADS manual inhibit switch. The licensee revised OP-ST.SN-001, ADS and Safety Relief Valve Operability Test - 18 months. This procedure adequately tests both ADS trip channels simultaneously and the ADS solenoid. The licensee revised OP-ST.SN-002, ADS Logic Functional Test - 18 months. This procedure adequately tests the ADS actuation timer inhibit switch. The inspector reviewed both revised procedures, reviewed ADS logic prints, and had no further questions. This item is close (Closed)' Inspector Follow Item (86-30-03); Licensee's actions to prevent inadvertent ESF actuations. The inspector verified that the corrective actions detailed in Inspection Report 50-354/86-30 have been completed satisfactorily. Although these actions have apparently been effective, the inspector will continue to closely monitor the performance of ESF system instrumentatio (Closed) Inspector Follow Item (86-30-05); Identification tags at remote shutdown station readout devices. The inspector verified that the instrument readout devices identified during the NRR Electrical Instrumen-tation and Control Systems Branch visit have been properly labeled. The applicable readout devices were reactor pressure (690 A, E, J, N), reactor vessel level (B21-691 AA), and suppression pool level and temperature indicators located in the auxiliary equipment room and the remote shutdown-pane .4 Information Notices Information Notice 86-109; Diaphragm Failure in Scram Outlet Valve Causing Rod Insertio During routine full power operations, the Nine Mile Point Unit 1 Nuclear Power Plant experienced a single control rod scram when the diapneaqm in the air operator of the scram outlet valve faile Investigation revealed that the diaphragm failed because of an aging process that resulted in a radial crack in the rubber (buna-n and nylon material). The licer.see initiated a review of its spare parts inventory and past operating experience and contacted the General Electric Company to determine the need for a diaphragm replacement program and to discuss the generic implications of this even The inspector conducted a review of this issue at Hope Creek and determined that no shelf life recommendation is made by the supplie However, the licensee has established a qualified service life of 10 years and an uncompressed shelf life of 5 years based upon their own analysis. An inspection and replacement schedule has been established such that one-sixth of the hydraulic control units will be inspected each refueling outage in accordance with environmental qualification mainte-nance and surveillance procedure M001-HCU-011. The diaphragms currently installed at Hope Creek are approximately three years old. A General Electric (GE) representative onsite informed the inspector that GE is

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currently evaluating the information from Nine Mile Point I and expects the review to be completed in 2 months. The inspector will review the GE finding and any licensee actions in a future inspectio . Operational _ Safety Verification 3.1 Inspection Activities On a daily basis throughout the report period, inspections were conducted to verify that the facility was operated safely and in conformance with regulatory requirements. The licensee's management control system was evaluated by direct observation of activities, tours of the facility, interviews and discussions with licensee personnel, independent verification of safety system status and limiting conditions for operation, and review of facility record These inspection activities were conducted in accordance with NRC inspection procedure 7170 .2 Inspection Findings and Significant Plant Events The unit entered this report period at 100% power and, except for short duration power reductions to perform surveillance testing and maintenance, remained at full power throughout the perio From January 1 to January 5,1987, the drywell leak detection gaseous radioactivity monitor system was inoperable. The licensee entered the appropriate action statement and correctly obtained and analyzed containment atmosphere grab samples on January 1 and 2, 1987. However, on January 3 and 4,1987, no grab samples were obtained. The licensee identified this oversight; however, due to the recurrent nature of this type of problem, the inspector informed the licensee that the failure to take the appli-cable action statement samples was e. violation of Technical Specification 3.4.3.1. (87-01-01)

l Once the violation was identified, the proper grab sample was i obtained and analyzed, and on January 5,1987 the gaseous radioactivity monitor was returned to service. Because of the subsystem redundancy built into the drywell leak detection-l system, this violation is of minor safety significance, but it does further illustrate the need for effective corrective action to prevent future sampling violations. Numerous licensee event reports document similar Technical Specification violation At 9:03 p.m. on January 8,1987, the "A" control room ventilation train isolated and the "A" control room emergency filtration system actuated while an I&C technician was troubleshooting a noble gas radiation monitor. The technician had installed a portable monitor into the installed circuitry causing a momentary downscale spike which initiated the ESF actuations. The isolation signal cleared immediately after removal of the portable device and ventilation systems were returned to norma _ _ _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ - _ - - _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _

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s fat 4:32 p.m..on' January - 12,'1987, the reactor water cleanup-

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l system isolated during performance of-a surveillance test. The:

Lisolation resulted when a fuse blew while connecting test

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. equipment. The. isolation was reset and the system returned to operatio .At 11:25 p.m.lon January 13, 1987, the reactor water cleanup .

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system isolated _on high temperature when an I&C technician took

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a routine temperature reading. The isolation was reset and the system restored to operation. 'Although modifications were made

.to the Riley temperature modules in 1984 to correct this problem, additional design changes are being. evaluated. The inspectors will continue to followup on the licensee's action On January 23, 1987, an I&C technician error while performing a surveillance test resulted in the . filtration, recirculation and -

ventilation system (FRVS) automatically starting. The I&C technician satisfied the 2 out'of 3 actuation logic when he turned off the wrong channel (A) while performing a functional test on channel "C". The actuation signal was reset and the system returned to the normal standby mod At 10:54 a.m. on January 23, 1987, numerous systems started in

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response to a reactor building ventilation (RBV) group 19 isolation signal. The group 19 isolation' actuation logic was satisfied after RBV channel "C" was placed in the tripped condition due to being inoperable. This was coupled with a

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second inoperable signal which resulted from a momentary loss of communication between one radiation monitor _and its processo The isolation was reset and the system restored to norma At 9:05 p.m. on January 23, 1987, the high pressure coolant injection outboard steam supply valve isolated on high differential temperature between ambient room temperature and i room supply temperature due to unusually cold weather. The isolation was reset and the room supply thermostat was increased from 40 degrees F to 65 degrees F to preclude recurrenc At 10:50 p.m. on January 26, 1987, the "B" core spray pump automati- 1 cally started and ran on minimum flow after receiving an unexplained start signal. An I&C technician was performing a core spray surveillance test at the time, but repeating the surveillance test did not cause another pump start. Although an investigation was conducted,~no conclusive root cause could be determined. The licensee believes the technician inadvertently energized the start

!. circuit with a test meter. The core spray system was returned to its normal condition after successfully completing the surveillance test.

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At 2:00 p.m. on January 30, 1987, the licensee received an "A" Channel Nuclear Steam Supply Shutoff System (NSSSS) isolation signal during a surveillance test on the reactor water cleanup (RWCU) system. The NSSSS isolation occurred when the I&C technician's probe slipped off a test point and caused a short which resulted in a blown fuse. -The NSSSS isolation shut a main steam line drain valve and reactor recirculation sample valv All systems responded as expected. The NSSSS isolation signal was reset and all systems returned to norma At 10:06 a.m. on February 5, 1987, the normal infeed power supply to the "B" reactor protection system (RPS) motor generator (MG) set was lost, resulting in a half scram and a reactor water cleanup ' solation. The operators attempted to shift loads to the alternate RPS power supply, but on 2 separate occasions the electrical protection assemblies (EPA) tripped open. The-original loss of power to the RPS MG set was caused by a ground on a welding receptacle powered from 480V bus 108482. 10B482 also provides power to the RPS MG set. The ground was isolated, power restored to the RPS bus and all trip conditions reset allowing RWCU to be returned to servic Subsequent investigation into the EPA trips has not determined a cause. All Technical Specification trip valves were verified by performance of surveillance test .3 Control Room Annunciators During steady state power operation approximately 50 of the 450 annunciators are in alarm. While the operators have been found to be knowledgeable of plant conditions, the large number of

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annunciators makes it more difficult for them to focus their attention on important plant parameters. In addition to overhead annunciators being illuminated, every time an alarm condition is received an operator must acknowledge the new alarm by pushing an acknowledge button on the control room pane This again has the potential of diverting the operator's attention from more important matters. On an average day the j annunciators in alarm can be broken down into four groups.

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Alarms from local panel trouble alarms: There are normally l about 20 overhead annunciators illuminated because a trouble alarm is up at a local panel somewhere in the plant. As currently designed, the overhead annunciator

, will remain illuminated even after the local alarm has been l acknowledged and until the alarm condition is cleare Design change request DCR-4-HC-019 has been submitted to l change the annunciator logic so that when a local alarm is l

acknowledged, the control room annunciator will reset.

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Nuisance Alarms: Approximately 17 annunciators are in alarm for invalid reasons. These are under review by the applicable system engineer Vibration Alarms: Six vibration related alarms are under investigation to determine if alarm setpoints should be changed based upon recent motor vibration dat Valid Alarms: The remaining annunciators in alarm are due to cenditions caused by surveillance testings, maintenance, or valid alarm condition The inspector will continue to monitor the status of control room alarms on a routine basis. No violations were identifie . Surveillance Testing 4.1 Inspection Activity During this inspection period the inspector performed detailed technical procedure reviews, witnessed in progress surveillance

, testing, and reviewed completed surveillance packages. The inspector verified that the surveillance tests were performed in accordance with Technical Specifications, licensee approved procedures, and NRC regulations. These inspection activities were conducted in accordance with NRC inspection procedure 6172 The following surveillance tests were reviewed, with portions witnessed by the inspector:

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MD-ST.PJ-005(Q) 250 VDC Battery Charger Capacity Test

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IC-FT. AB-017 MSIV Closure Logic A1

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MD-ST.FC-001 RCIC Turbine Low 011 Pressure Switch 18 Month Calibration

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IC-FT.SE-014 Functional Test of Average Power Range Monitor

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IC. FT.BB-013 Functional Test - Core Spray Low Reactor Pressure Permissive No violations were identifie . . _ . . - - . _ . - - _

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5. Maintenance Activities 5.1 Inspection Activity During this inspection period the inspector observed selected main-tenance_ activities on safety related equipment to ascertain that these activities were conducted in accordance with approved proce-dures, Technical Specifications, and appropriate industrial codes and standards. These inspections were conducted in accordance with NRC inspection procedure 6270 .2 Inspection Findings t

Portions of the following activity was observed by the inspector:

Work Order Procedure Description 87-01-05-051-6 MD-ST.SB-001 Inspection and testing

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of reactor protection syste Electrical protection assembl No violations were identifie . Engineered Safety Feature (ESF) System Walkdown 6.1 Inspection Activity The inspectors independently verified the operability of selected ESF systems by performing a walkdown of accessible portions of the system to confirm that system lineup procedures match plant drawings and the as-built configuration. This ESF system walkdown was also conducted to identify equipment conditions that might degrade performance, to determine that instrumentation is calibrated and functioning, and to verify that valves are properly positioned and locked as appropriat This inspection was conducted in accordance with NRC inspection procedure 7171 .2 Inspection Findings The safety and turbine auxiliaries cooling system was inspected, and although no violations were identified the inspector has the following operational concern The safety and turbine auxiliaries cooling system (STACS) is a closed loop cooling water system composed of the safety related safety auxiliaries cooling system (SACS) and the non-safety related turbine auxiliaries cooling system (TACS). SACS supplies cooling water to ESF equipment such as residual heat removal heat exchangers, diesel generators, emergency core

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cooling system room coolers, and the filtration recirculation and ventilation systems during both normal and emergency operation. SACS is made up of 2 redundant loops with two 50%

pumps and two 50% heat exchangers per loop. The TACS utilizes the SACS pumps and heat exchangers during routine operation, but is automatically isolated upon an accident conditio A review of recent operational experience indicates that improvements in system design and operation are needed on the SACS. As can be seen from the following events, the root cause of the system problems is the unwanted accumulation of nitrogen in system components and instrumentation sensing lines. The nitrogen originates from the STACS accumulator On December 1, 1986, both pumps in the "B" loop of SACS tripped and TACS isolated on low supply pressure after the "D" diesel generator (DG) was started for surveillance testing. Because cooling water had been lost to the diesel, the control room operator secured the diese It should be noted that a loaded DG will seize up after running approximately 5 minutes without SACS cooling. Subsequent investigation revealed that both the

"B" and "0" SACS pumps were air bound and that a significant amount of air / nitrogen had accumulated in the top of the SACS heat exchangers. The nitrogen that bound the pumps most probably came from the DG heat exchangers after flow had been e initiate On December 5, 1986, an automatic TACS loop swap was initiated based upon an invalid low flow signal on the operating TACS loop. Troubleshooting by I&C found excessive air / nitrogen in the transmitter sensing line On December 12, 1986, both pumps in the "B" loop tripped on low flow after the "B" loop SACS heat exchanger bypass valve was shut. Upon closing the bypass valve, an increased flow was forced through the heat exchangers sweeping nitrogen to the pumps. Nitrogen was vented from the pump casings as well as the heat exchangers, and FRV Nitrogen induced problems, especially those causing automatic pump and valve operation have forced the control room operators to operate STACS in a lineup different from the design inten Instead of running 2 pumps in the operating loop, and having the other loop in automatic standby, one pump was maintained in manual-run in the " standby" loop. This in turn has caused valve operation problems during swaps of TACS loop _ . . _

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. 10 The. operations department has initiated a program of venting SACS heat exchangers and system vents in an effort to minimize the adverse effects of nitrogen accumulation. This has apparently_

been effective, based upon the reduced nitrogen _ accumulatio Although this is an adequate short term fix, a permanent design modification is necessary to ensure long term system operabilit Design modifications currently under evaluation include:

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DCR-4-HC-0014; improve supply and return accumulator design to reduce nitrogen uptake into-STACS water

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DCP-4-HMJ-86-836; relocate TACS low flow transmitters FT-2522A through D to an area less susceptible to nitrogen accumulatio Based upon the safety related function of SACS and the adverse impact on the operability of the system caused by accumulated nitrogen, the inspector will follow the licensee's long term actions. (87-01-03)

During this review, the inspector verified that the licensee's surveillance tests satisfy requirements of Technical Specification No violations were identifie . RHR Pump Failure On November 16, 1986, the "B" Residual Heat Removal (RHR) pump was placed in service from the control room in the shutdown cooling mode following a shutdown cooling demonstration from the remote shutdown panel. After approximately 10 minutes of operation, the pump was removed from service due to excessive motor amps and high vibratio The "B" RHR pump was filled, vented and restarted. An electrician then verified that at an 8000 GPM flowrate, motor amp readings were approximately 200 amps and increasing as compared to normal readings of 150 amps at 10,000 GPM. The pump was again stopped and locally observed to stop abruptly without the normal coastdown. The pump and motor were decoupled and motor related problems were ruled ou However, a bearing failure appeared likely since the pump could not be rotated by hand. The pump was removed from the system for disassembly and inspection. The inspection showed that the bearing to sleeve clearances were three to four times the allowable tolerance of 0.005 - 0.012 inches and that there was excessive wear of the wear rings. The second stage casing ring had spot welded itself to the impelle A review of equipment history records identified the following significant events:

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On August 3, 1986, the discharge head flange developed a leak and was retorque _ _ - . _ , _ . - - - _ .

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On September 20, 1986, the "B" RHR pump was secured after an operator observed abnormally high vibration. An ISI test performed later that same day was successfully completed, including vibration measure-ments.

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On November 11, 1986, a snubber on the "B" RHR loop was found broken and subsequently replace The licensee has determined the root cause of the pump failure to be a series of " minor" water hammer / cavitation events over a period of time. The steam condensing valves of the "B" RHR loop, BC-HV-F052B and BC-PV-F0518, were known to be ' leaking from the HPCI steam supply line into the RHR system. As these valves leaked by, a steam bubble was formed in a portion of the "B" RHR loop and the RHR temperature would increase. During the period that these valves were leaking, the Operations Department lowered the RHR temperature by placing the

"B" RHR system into the suppression pool cooling mode. Each time the

"B" pump was started, a water hammer event took place since the ECCS jockey pump was unable to collapse the steam bubble formed in the RHR piping. The licensee also attributes the broken snubber on November 11, 1986, to such an even The licensee repaired the leaking isolation valves, which, based upon RHR water temperature, has stopped the steam leakage. The "B" RHR pump was replaced with a spare, and a design change has been initiated to blank off the steam condensing line No violations were identifie . Security - Access Control of Packages The inspector conducted an inspection to verify that the licensee controls the entry and exit of all packages and materials to the protected area in accordance with the approved physical security plan and regulatory requirements. The inspector also verified through observation and discussion with security personnel that all material and packages are adequately searched by hand or equipment prior to entry into the protected are No violations were identifie . Licensee Event Report Followup The licensee submitted the following event reports during the inspection period. All of the reports were reviewed for accuracy and timely sub-mission. The asterisked reports received additional followup by the inspector for corrective action implementation. The (#) ftems identify reports which involve licensee identified Technical Specification viola-tions which .tre not being cited based upon meeting the criteria of 10 CFR 2 Appendix C regarding licensee identified violation ,. . _ _ _ _ _ - _

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    • LER 86-084-00 North and South Plant Vent Radiation Monitors Inoperable
    • LER 86-090-00 Minimum Required Radiation Monitors Not in Service When Operational Condition Changed LER 86-091-00 Inadvertent Opening of "P" Safety Relief Valve

LER 86-093-00 Shutdown Cooling Isolation During Instrument Backfilling LER 86-094-00 Inadvertent Isolation of Reactor Water Cleanup System LER 86-069 describes the events which resulted in a full reactor scram while the plant was shut down in operational condition 4. The scram occurred when a spurious trip of the "G" Intermediate Range Monitor (IRM) produced an "A2" channel trip was coupled with a "81" and "B2" channel trip caused by surveillance testing on the "A" Rod Block Monitor (RBM). The "G" IRM trip cause is unknown, however it is believed to have resulted from a conservative "high voltage inoperable" trip setting. The surveillance test induced trip could have been prevented if the procedure included a precaution that the associated average power range monitor could be affected by the local power range monitor testin LER 86-084 details the inoperability of the north plant vent (NPV)

and south plant vent (SPV) radiation monitors due to the incorrect installation of the iodine cartridge securing device on each of the monitoring skids. The cartridges were found not to be sealed properly in their mountings ar.d resulted in both monitors being inoperable for one week without the required action statement samples being taken. Correc-tive actions consisted of reinstruction of technicians, revision of pro-cedures, and an evaluation of the installed 0-ring sea LER 86-090 describes a miscommunication between radiation protection and the control room, and a work order tracking system input error that resulted in an insufficient number of operable refuel floor exhaust monitoring channels (RFEMC). This event occurred when an operable RFEMC was erroneously placed in the tripped condition while the redundant channel, which was inoperable, remained in service. To prevent future recurrence, the Station General Manager will review applicable procedural requirements with his staff and their respon-sibility to fully inform the control room of the status of equipment and work order .s a-

.13 LER 86-092 describes an unexpected actuation of HPCI, RCIC, and channel

"D" of the primary containment isolation system during the full power generator load reject test. These actuations occurred as a result of instrumentation errors coupled with actual vessel water level oscillations, which together were sufficient to make up the protection logic. Details of this event are discussed in paragraph 3.3 of NRC Inspection Report 50-354/86-56. No unacceptable conditions were identifie . Regional Temporary Instructions 10.1 Inspection of Standby Gas Treatment System (TI-RI-86-01)

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A review of the filtration, recirculation and ventilation system (FRVS) was performea to verify single failure criteria and to complete Region I Temporary Inspection RI-86-01. The licensee utilizes a more comprehensive version of standby gas treatment system, called FRVS, due to Hope Creek's originally proposed site location in a high population area. FRVS is composed of separate recirculation and ventilation subsystems. The recirculation system uses 6 mechanically and electrically (Class 1E) independent 25% filter trains. The ventilation system uses 2 mechanically and electrically (Class IE) independent 100%

filter trains. There is no automatic deluge operation for the FRVS charcoal filter beds. The inspector could not identify any single failure mechanisms which would render FRVS incapable of fulfilling its design functio No violations were identifie .2 Control Room Environment (RI-TI-87-01)

In addition to the normal routine observation of control room activities, a special assessment of the control room environment was conducted in accordance with Region I temporary instruction RI-87-0 The control room licensed operators have been found to display a professional attitude and appearance, and are always aware of plant status. While the high number of overhead annunciators detracts from the operator's ability to monitor plant status, the operators have been found to know the up-to-date status of each alarm. The licensee is not satisfied with the annunciator situation and is investigating possible design changes as discussed in paragraph of this report. The control room staff has done an acceptable job in the areas of noise control and control room access. The use of the work control center, located outside of the control room, prevents excessive numbers of people from entering the control room and reduces the amount of time that the operators spend processing paperwor Control room access is adequately controlled through the practice of entering the control room via the shift supervisor's office and the use of floor boundary markings. The inspector notes however, that noise and access control while still acceptable, has degraded since completion of power ascension testing. The control

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room appearance is generally neat and well organized with an occasional accumulation of test equipment at the back panel Radios are not used in the control room, nor personal reading material allowed. No violations were identifie .10.3 Steam, Feed and Condensate System Survey (RI-TI-87-02)

The licensee's response to I&E Information Notice 86-106,

"Feedwater Line Break", was reviewed in accordance with Region I Temporary Instruction 87-02. The Itcensee had not received Information Notice 86-106, and therefore has not formally responded to i The licensee does not consider wall thinning of secondary piping (steam, feedwater, condensate, and connected systems) an immediate problem at Hope Creek due to the plant's limited operational histor There is currently no inspection program in place to monitor or detect pipe thinning on secondary systems. The licensee is reviewing the subject to determine if such a program should be implemente During plant construction, the licensee. identified " critical" piping locations considered susceptible to erosion (based on fluid velocity and moisture content). These " critical" piping locations were upgraded to a copper bearing steel material to improve erosion resistance. The licensee's formal response to Information Notice 86-106 will be reviewed at a later date. No violations were identifie . Exit Interview The inspectors met with Mr. J. Nichols and other licensee personnel periodically and at the end of the inspection report to summarize the scope and findings of their inspection activitie In addition, the inspector stated his opinion that lack of progress in the areas of housekeeping and overhead alarms may be related to recently decreased management presence on site and a perceived change in worker attitude once the goal of completing power ascension testing had been achieve The licensee acknowledged awareness of these factors. The Regional Project Section Chief attended an exit interview on February 20, 1987 with the Vice President-Nuclear to discuss the above concern Based on Region I review and discussions with the licensee, it was determined that this report does not contain information subject to 10 CFR 2 restrictions.

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