IR 05000206/1985028

Insp Repts 50-206/85-28,50-361/85-27 & 50-362/85-26 on 850729-0926.Violations Noted:Failure to Perform Analysis of Changes as Described in SAR & Improper Routing of Temporary Electrical Cables

ML13323B038
Person / Time
Site:	San Onofre
Issue date:	10/16/1985
From:	Dangelo A, Huey F, Johnson P, Stewart J, Tang R, Tatum J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V)
To:
Shared Package
ML13323B032	List: IR 05000206/1985028 IR 05000729/2009026 ML13323B031
References
50-206-85-28, 50-361-85-27, 50-362-85-26, NUDOCS 8511040169
Download: ML13323B038 (20)

Text

U.S. NUCLEAR REGULATORY"COMMISSION

REGION V

Report Nos 50-206/85 28, 50-361 85 27, 50-362/85-26 Docket Nos.,

50-206, 50-361, 50-362 License. Nos DPR-13, NPF-10, NPF-15 Licensee:

Sout ern1 California Edison Company P.. 0.80&, 2244 Wahf~ut Grove Avenue Rosemead; Califortia 92770 Facility Name:

San Onofre Units I, 2 and' 3 Inspection at San Onofre, S-n Clemente, California Inspection conducted: July 29 through September 26, 1985 Inspectors

,z js F. R. HO, Senior Resident Date Signed Inspect

, Units 1, 2 and 3 J. P. S ewart, Resident Inspector Date Signed oLjrc A. D'

elo, Resident Inspector Date Signed 4 ~-.

atum, Resident Inspector Date Signed R. C. ang, Resident Inspector Date Signed Approved By:

H ohnson, Chief Date Signed Rea r Projects Section 3 8511040169 851 06 PDR AOCI" 500020 PDR

Inspection Summary Inspection on July 29 through September 26, 1985 (Report Nos. 50-206/85-28, 50-361/85-27, 50-362/85-26)

Areas Inspected: Routine resident inspection of Units 1, 2 and 3 Operations Program including the following areas:

operational safety verification, evaluation of plant trips and events, monthly surveillance activities, monthly maintenance activities, Engineered Safety Feature walkdown, independent inspection,.licensee events report review, allegation follow-up and follow-up of previously identified item This inspection involved 181 inspection hours on Unit 1, 245 inspection hours on Unit 2 and 207 inspection hours on Unit 3 for a total of 633 inspection hours by five NRC inspectors. Inspection Procedures 30703, 35751, 37700, 40700, 40702, 41700, 42700, 61726, 62703, 64704, 71707, 71710, 72701, 82301, 83726, 92700, 92705, and 93702 were covere Results:

Of the ten areas examined, two apparent violations were identified:

(1) Failure to perform analysis of changes in the facility as described in the safety analysis report, and (2) Improper routing of temporary electrical cable DETAILS 1. Persons'Contacfed Southern California Edison Company

• H. Ray, Vice President, Site Manager

• H. Morgan, Station Manage *M. Wharton, Deputy Station Manager,.

• D. Schone, Quality Assurance"Manager D. 'Stonecipher, Quality C6ntrol'-Manager

• R. Krieger, Operations Manager D.,:hull, Maintenance Manager-,

• J. Reilly, Technical Manager P. Knapp, Health Physics Manager

• B. Zintl, Complianc6 Manager J. Wambold, Training Manager

• D. Peacor, Emergency Preparedness -Manager P. Eller, Security Manager W. Marsh, Operations' Superintendent,' 'Units 2/3 J. Reeder, Operations Superintendent, Unit 1 V. Fisher, Assistant Operations Superintendent, Units 2/3 B. Joyce, Maintenance Manager:, Units '2/3 H. Merten, Maintenance Manager, Unit 1 R'. Santosuosso, Instrument 'and Control Supervisor T. Mackey, Compliance Supervisor

• G. Gibson, Compliance Supervisor

• C. Kergis, Compliance Engineer

• J. Grosshart, Quality.Assurance

• P. Wattson, Lead Compliance Enginee.*G. Hollaway, Supervisor, Startup

• P. King, Supervisor, Operations Quality Assurance

• D. Breig, Project Manager, Units.2/ *D. Nunn, Project Manager, Station San Diego Gas & Electric Company R. Erickson, San Diego Gas and Electric

• Denotes those attending the exit meeting on September 13, 1985.

The inspectors also contacted other licensee employees during the course of the inspection, including operations shift superintendents, control room supervisors, control room operators, QA and QC engineers, compliance engineers, maintenance craftsmen,.and healthphysics engineers and technician. Operational Safety Verification The inspectors performed several plant tours and verified the operability of selected emergency systems, reviewed the Tag Out log and verified proper return to service of'affected components. Particular attention was given to examination for potential fire hazards, fluid leaks, excessive vibration and verification that maintenance requests had been initiated for equipment in need of maintenanc During a routine tour of the 30 foot level of the penetration area in Unit 3, the inspector noticed that water was dripping from the component cooling water (CCW) piping in the overhead. -ased on discussions with the licensee, the inspector determined that the water was being condensed from the atmosphere by the CCW pipes. The high humidity condition in the area was caused by a leaking connection on a steam generator sample coole It appeared to the inspector that the area was not being cleaned up frequently enough to keep the water from puddling on the floo Additionally,-part of the area was posted as a contamination area, and the water was not prevented from crossing the radiological barrier Upon leaving the controlled area, the inspector discovered that the soles of his shoes had become contaminated even though the radiological barriers were not crossed. The contamination was very low level and the licensee was very responsive in decontaminating the inspector's shoe Additionally, the licensee conducted additional contamination surveys of the 30 foot penetration area to ensure that the area was not contaminated. Based on the surveys, it appeared that the contamination was restricted to a few isolated places where the contamination was picked up by the steam leaking out of the radiologically controlled area and was subsequently condensed by the CCW pipes and dripped on the floo These isolated low level contamination areas were decontaminated by the licensee, and additional-actions were taken to keep the water cleaned u No violations or deviations were identifie. Evaluation of Plant Trips.and Events Reactor Trip on August 1, 1985 (Unit 2)

On August"J, 1985, at 1532, while-at 100% power, the reactor tripped due to a momentary voltage transient on one phase of the non-lE

'Uninterruptible Power Supply (UPS) bus. This.resulted in actuation of the undervoltage relays which, under normal conditions, provide indication to.the turbine supervisory control system that the reactor has tripped ahd causes'the turbine to trip. During this voltage transient, however, the reactor.had not tripped. The subsequent turbine trip from 100% power caused the reactor to tri The licensee made a modification to the undervoltage relay logic such that a >transient on one phase of the Non-1E UPS bus would not cause a turbine trip. On August 3, 1985, the unit was returned t % powe Reactor Trip on August 20, 1985 (Unit 2)

On August 20,'1985, at 1405, while at 100% power, the reactor tripped due to spurious penalty factors being generated by Control Element Assembly Computer (CEAC) #1 causing Core Protection Calculator (CPC) #1 and #3 to trip. This condition resulted when troubleshooting CEAC #1 while it was in "Test".

When the CEAC was

energized, it generated spurious.pehalty factors while it was coming up to power and caused the reactor trip. The licensee changed procedures such that troubleshooting of this nature-is only done with the CEAC in the "INOP" mode. On August 22, 1985, the unit was returned to 100% powe Reactor Trip on September 12, 1985 (Unit 2)

On September 12, 1985, at 1015, while at 100% power, the reactor tripped due.to a turbine trip. The turbine trip was caused by a loss of generator field which was the result of.a direct short between the generator exciter bus bars. A licensee evaluation indicated that carbon build up due to accelerated brush wear was the cause of the short. The accelerated wear was the result of an out of-round condition on the exciter ring The exciter was repaired and tested before the unit resumed operatio Reactor Trip on September 19, 1985 (Unit 1)

San Onofre Unit 1 tripped at 1905 on September 19, 1985, as a result of an inadvertent protective trip of the "B" auxiliary transforme A temporary low level was experienced in one steam generator, and the turbine-driven auxiliary feed pump (AFP) started but tripped after a brief run. The AFP trip was caused by failed turbine bearings as the result of a loss of lube oil in the bearings. The circumstances of this event are currently under investigation and the results will be included in a subsequent inspection repor. Monthly Surveillance Activities Boration Flow Paths (Unit 3)

During this inspection period, the inspector observed the licensee conducting tests to demonstrate the operability of the Boric Acid Flow Paths on Unit 3 as required by the unit Technical Specifications. The surveillance was conducted in accordance with the approved operating procedures and no deficiencies were note No violations or deviations were identifie. Monthly'Maintenance Activities Charging Pump-2P191 Maintenance (Unit 2)

During this inspection peffod, the inspector observed maintenance activities associated with examination and replacement of charging pump 2P19 The licensee had discovered aileak in the discharge manifold of charging pump 2P!91, and deermined that the leak was the result of a crack which had developed in oie of the-plunger cylinders allowing water to leak past an o-ring seal assembly to'the atmosphere. This same failure had occurred approximately one year previous to this, and the

.4 licensee had determined that the crack was induced by cavitation. The licensee has changed Jthe procurement specifications associated with the discharge head.suchthat the plunger bore will not be as susceptible to cavitation crackin Auxiliary Feedwater Pymp 2P141 Maintenance (Unit 2)

The.inspector 6bserv d iainteiande activities related to correcting an oiltleak from.. oneof-the eleceric motor bearing The licensee was adherin -to th' Technical Specific'ation requirements and conducting maintenance in accordadnqe with apprbved procedure Novilations or, deviations wer idenfifie. Engineered Safety Feature Walkd6wn During thisinspection period, the inspector walked down the Emergency Boration portionof..

the Chemical and Volume Control System on Unit The systemewas found t6 e ain the tonfiguration required-by the Technical Specificationsvand the licenseesd.procedures, and the boration flow paths were found to be operable. Howeyer, during this inspection, the inspector discovered that the suction valve to charging pump 3P190 (S31208-MU062) was not locked such that the valve was secured in the open position. Instead, the locking device was installed on the valve handwheel in such a way that operation of the valve 'was not prevente Additional discussion of this locked valve issue is included in paragraph 10(g) of this report as follow-up to an open item identified during a

previous inspectio No violations or deviations were identifie. Independent Inspection Separation of Permanent Electrical Installations As discussed in paragraph 8.1.4.3.14 of the FSAR, the licensee has committed to Regulatory Guide 1.75, Revision.1, for 'separation of electrical systems. Regulatory Guide 1.75 endorses IEEE Standard 384 dated 1974. During examination of the ESF Switchgear Rooms for Units 2 and 3, the inspector discovered that the permanently installed non-1E 120 VAC lighting circuit is installed in' close proximity to Class 1E 120 VAC instrumentation and control circuit While portions of the lighting circuit are enclosed in conduit, other portions of the lighting circuit are exposed and do not appear to-satisfy the separation criteria imposed by Regulatory Guide 1.7 and IEEE 384 of-3 feet horizontal and 5 feet vertical for separation from Class 1E circuits. The non-lE lighting circuit is route through all of the ESF Switchgear Rooms for both Units 2 and 3 via wall receptacle Isolation devices which-.satisfy the-requirements of Regulatory Guide 1.75 have not been used to isolate the non-.1E lighting circuits from the Class 1Einstrumentation and control circuits.*

With regard to the above, the licensee stated in the San Onofre Units 2 and 3 FSAR, Chapter 8.1.4.3.14 A.1 that:

"Associated circuits that are treated as Class 1E circuits are limited to power circuits only."

The licensee makes a distinction between power circuits and instrumentation/control circuits in that the latter are low energy circuits. However, in FSAR Chapter 8.1.4.3.14, paragraph A.3, further explanation is given on the method used to control non-Class IE circuits as follows:

"Once the non-Class'IE circuits leave or become nonassociated with one Class IE separation group, they are not routed in such a manner as to become associated with another redundant Class IE separation group."

The procedures used involved:

(1) generation of elementary diagrams used for visual inspection, (2) conduct of design reviews by personnel knowledgeable in design and installation, and (3) computerized circuit and raceway scheduling syste The lighting circuits in question were field run and may not have been subject to the above stated review. The licensee and their Engineer of Record are reviewing the design controls which were used for the installation of the lighting circuit The issue of electrical separation requirements applicable to lighting circuits will be verified with NRR and remains an open ite (50-361/85-27-01) Control Element Assembly Calculator While operating part length rods on Unit 3, the licensee placed Control Element Assembly Calculator (CEAC) #1 in the inoperable (INOP) mode to prevent a spurious reactor trip. The control operator was manipulating part length rods for Axial Shape Index (ASI) control following a unit power reduction, and the operators had standing instructions' to "INOP" the CEAC when manipulating part length rods. Based on discussions with the licensee, the inspector determined that Control Element Assembly (CEA) 34 (a part length rod) had experienced intermittent failures on the Reed Switch Position Transmitter (RSPT) stack that provides rod position indication to CEAC #1. 'Because of the intermittent nature of the RSPT failure, the licensee felt that it was necessary to INOP CEAC

1. 1 to'prevent a spurious reactor trip from occurring. The inspector discussed this problem with the Core Performance Branch at NRR and received the following guidance:

" the licensee's actions for this particular RSPT failure appeared to be appropriate o the CEACs should not be routinely placed in'the INOP mode The inspector discussed NRR's position with the licensee, and the licensee took actions to ensure'that'.the operatin procedures provide necessary guidance to the control operators such, that the CEACs would not be routinely placed in the INOP mod No violations or deviations were identifie. Review of Licensee Event Reports'

Through.diret observations, discussions with licensee personnel, or review of the records, the following Licensee Event Reports (LERs)

were closed:

Unit Main Feedwater Pump Failure 85-012 Loss of Motor Contr61 Ce nter #1 85-013 Control.,Rod Position Indication System Unit 2 85-032

.Spurious Control Room Isolation System Train "B." Actuation 85-034 Toxic Gas Isolation System (TGIS) Hydrocarbon Analyzer Flame-out 85-035 Inoperable Waste Gas Surge Tank (WGST) Hydrogen/Oxygen Monitors85-036 Control Room Isolation System (CRIS) Train "A" Actuation Due to 2RT-7856 Failure,85-037 Control Room Isolation System (CRIS) Train "B" Actuation

.85-038 Improper Cancelation of a Continuous Fire Watch Unit 3 85-017 Inoperable Snubbers Main Steam to.Auxiliary Feedwater Pump Turbine 85-021 Fuel: Handling Isolation System Actuation 9. Follow-up of Allegation or Concern (7 Concerns)

ATS No:

RV-85-A-003 Concern Nos. 1 and 2 Characterization The alleger reported comments made by a second party (informant)

concerning personnel sleeping while on shift. In the firs instance, SCE health physics personnel were alleged to have been sleeping in a "radioactive area" in containment and in the second case contract personnel were alleged to have been sleeping in the rad waste building (24 foot elevation) during the Unit 2 refueling outag Implied Safety Significance to Operations If the allegations were true, the two individuals in question would have the potential of receiving unnecessary radiation exposure, which is against the ALARA principle. In addition, the individuals, while asleep, would not be able to.perform their normally assigned duties, which could directly or indirectly compromise plant safet A 7 Assessment of Safety Significance Inspection Report 206/85-10 discussed a previous.NRC effort to interview the alleger. Additional contact during this inspection period resulted in interviews with the alleger and an informan The informant stated that he had observed the two events and that he should have notified health physics supervisors; however, he was performing tasks which required his immediate attention..The specific allegations could not be substantiated. However, the inspectors' observations in December and-January of 1984 during the Unit 2 refueling outage (i.e., before the allegations were raised)

appear to support the observations made by the informan Specifically, the inspectors observed on December 4, 1984 an individual lying on the floor of the machine shop on the 70 foot level of the rad waste building. This observation is documented in inspection report 50-361/84-34, paragraph 4. The inspectors also observed on January 15, 1985, during a routine tour of the Unit 2 containment, a fire watch with his eyes closed. This observation is documented in inspection report 50-361/85-0 Staff Position The allegations could not be specifically substantiated by identifying the persons alleged to have been sleeping in radiation areas, although they are supported by similar findings identified in the inspectors" previous inspections. However, in both of the inspector identified instances the licensee too corrective action and briefed Health Physics Technicians on acceptable ALARA practices.' Action Require Monitor station/contract personnel,during.refueling outages in in frequntly monitored room Concern N "', Characterizati6n The eighteen month valve lineups for Units 2 and 3 had not been done on anysystem. The individual (alleger) believed these to be require Implied Safety Significance to Operations The inspector determined that the performance of system valve lineup checks referred to by the individual are not required on an 18 month basi The majority of safety related valves are required to be checked on a monthly basis (or more frequently) in accordance with the plant technical specifications. Therefore, not doing the total system valve lineups referred to by the alleger, does not appear to have major safety significanc.8 Assessment of Safety Significance

'The inspector reviewed the following completed Unit 2 system valve lineups located in the control room files on April 3-4, 198.S023-1-Chilled Water System S023-1-Containment Emergency Cooling Alignment S023-1-Containment Purge System Alignment S023-2-4 Auxiliary' Feedwater Flow Path Alignment S023-2-8 Saltwater Coolihg'System Flow -

Electrical Alignment S023-2-9 Main Steam Alignment, S023-3-1.11 Quench Tank Initial Alignment S023-3-1.12 RCDT Initial Alignment, S023-3-Chemical Volume and Control System S023-3-2.6'

Low Pressure Safety Injection S023-3-High Pressure Safety Injection S023-3-Containment Spray System S023-3-2.10 MSIV In Service The inspector determined that most of the procedures'had been initiated and completed during January through March 1985 in preparation for the Unit 2 startup following the first refuelin The inspector found several instances where previously completed procedures dated in 1984 were still located in the file Therefore, based on observations by the inspector, it appeared that the licensee was performing the system valve lineup checks as a matter of'practice,on a more frequent basis than every 18 month Furthermore, the inspector noted that many of'the safety related systems were out of servicefor an extended period for the installation of design changes from October' 1984 through January 1985 on Unit.2 and, therefore, performance of the valve lineups during this.period was not require Selected Unit. 3 valve lineup checks werealso found to have been completed on a more frequent basis then 18 month Staff Position Based on the above, the allegation was not substantiate Action Required'

Non Concern No. 4 Characterization The fourth concern raised by the individual was that a Unit 2 start up neutron detector channel was declared operable with only one of 2 detectors operable to allow Model 6 entry. The individual felt the cause was.due toischedule delay concern J/

9 Implied Significance 'to Operation If fuel loading and movement was performed with only one operable Source Range Monitor the potential -for an unplanned or local'

criticality occurring is increase Assessment of Safety Significance The Unit 2 technical specification 3.9.2 states as follows:

3.9.2 As a.minimum, two source range neutron flux monitors shall be OPERABLE and operating, each with continuous'visual indication in the control room and-one with audible.indication in the containment and control roo Applicability: Mode 6 Basis for 3/4.9.2 Instrumentation The OPERABILITY of the source range neutron flux monitors ensures that redundant. monitoring capability is available to detect changes in the reactivity condition of the cor The inspector noted that the technical specifications do not address the physical design criteria of the individual source range monitors, stating only that two monitors be operabl The inspector reviewed the following records and documentatio Unit 2 C6ntrol Room Operator's Logs January 15 -

17, 1985 o Nonconformance Reports (NCR) 2-1286 (January.15, 1985) and 2-1286 Revision 1 (February 9, 1985)

o Maintenance Orders 85011376, 85011199 o Temporary Modification Log a S023-II-5.29 Source Range Neutron Flux Monitor Calibratio o S023-II-9.222 Excore Neutron Detectors and Cable Installation and Testing

' Memo (Handwritten), Gamma-Metrics-to SCE, dated January 15, 198 Based upon the review of theabove records and interviews of cognizant engineers and technicians the inspector determined that one of the two Fission Chambers 'of excore start up detector channel 1 was. not functioning on January 1' 5,.198 On January 15, 1985, the licensee.,documentd'onNCR 2-1286 tfiat the fuel loading of Unit 2 may 'start' with one,ofthe te o Fission'

Chambers.of channel 1 not functioning. 'The basis f6r.this Jetion was the recommendation from theVendoris (Gamma-Metrics) llead engineer that the channel ould'p'erform act ri with 6ily ne Fission Chamber functioning. The-use of only one Fission Chamber required the adjustment,of the remaining Fission 'Chamber's

sensitivity, which was performed under Maintenance Order 85-011376 on January 15, 1985. Calibration of both start up channels was also completed on January 15, 1985. The inspector also reviewed the temporarymodification log and noted that the.installation of the shorting device on the inoperable fission chamber had been documented on January 15, 1985. The inspector also observed that the vendor's lead engineer commented 'in his recommendation to the licensee the following, "In my best judgement, and considering the impact on fuel loading, it seemed reasonable under circumstances to place the channel back in service with only one fission chamber." Staff Position The allegation was substantiated, however, the licensee performed the temporary modification in accordance with established requirement Therefore, based on the-above assessment, there is minimal safety significance associated with this allegatio Action Required Non Concern No. 5 Characterization The fifth concern raised by the individual was that on January 22, 1985 all operations shift personnel were to go on 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts. The, individual is concerned about fatigue and requested residents (NRC)

to observe operators for fatigue. Twelve hour shifts were to proceed for one month. The individual stated this was occurring so operations management could point out that their efforts had not held up an already lagging schedul Implied Safety Significance to Operations Working excessive overtime has the potential of increasing operators errors and reducing an operators effectiveness in responding to plant events and emergencies thereby increasing the potential for

• damaging plant equipment and increasing the threat to the public during an acciden Assessment of Safety Significance The inspector noted that, due to additional delays in the schedule of the Unit 2 Refueling outage, the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts to which the alleger referred started during the beginning of March 1985 and lasted through the second week of April 198 p11 Inspector interviews with several plant operators identified that some did complain about the forced overtime having an impact. on their abilities. The inspector interviewed the licensed operator who quit due to fatigue during the first-week in April (while working as a nuclear plant equipment operator).

The operator stated that the cumulative affect of working overtime for several weeks made him fatigued and very irritable. The inspector reviewed all overtime records for the above period and confirmed that the licensee was tracking and approving the use of overtime as described in the NRC guidelines covering the use of overtime with only minor errors noted. However, the inspector noted that the licensee procedures which implement requirements for controlling the use of overtime appeared to be weak and ineffective with regard to providing any criteria for defining proper versus excessive use of overtime. The licensee has stated that this deficiency is recognized and is in the process of being correcte Staff Position The licensee was observed to be in compliance with the existing regulatory requirements for tracking and approving the use of overtim However, the procedures. which implement the licensee program for control of the use of overtime were found to be weak with respect to providing adequate guidance for determining when overtime usage was excessive. In this regard the licensee was committed to review and revise procedures as necessary to correct the above noted weaknes Action Required The inspectors will follow up further on this item to monitor the licensee's progress in properly controlling overtim Concern No. 6 Characterization It was alleged that a flooding event (2,000 gallons estimated)

which occurred in the Unit 2 penetration (9'level) and rad waste buildings (9' level) of radioactive fluid from a containment spray system flush. This occurred due to a jumper (consisting of 8" diameter PVC piping) which ruptured. The individual's concern was that this represents poor engineering control (Health Physics decontaminated the reas; the estimated activity before cleanup was 1000 cpm/100 cm Implied Safety Significance to Operations This alleged flooding event had been previously made known to the inspector by an operator. When the flooding occurred in Unit 2, there was no fuel in the reactor vessel (the fuel was stored in the fuel handling building).

Thus, no safety systems were required to be operable in the 9' level of the flooded buildings. There is no safety significance associated with this flooding except for minor personnel contamination and/or radiation exposure incurred in, cleaning up the floodin Assessment of Safety Significance The inspector reviewed the following documents:

oIncident Report 2-001 Rev. 1 (Startup Projects)

'Procedure 2CV-299-07 Proof Flush Procedure for Shutdown Cooling Modifications Based upon the review of the above documents and interviewing the cognizant engineer the inspector determined that during flushing of the containment spray discharge piping (Step 8.9 of S02-CV-299-07)

the temporary flushing pipe failed under flow conditions and spilled approximately 5000 gallons of contaminated water into the 9'

elevation of the Unit 2 Penetration Building (water continued to flow out of the ruptured pipe for approximately 20 minutes).

The licenseets Incident Report (Revision 1) dated April 9, 1985, identified three apparent causes of the incident, which are repeated below:

"1. A gasket which was installed in.a flange of the temporary piping faile "2. Even though an elaborate headphone network was set up and in operation, when the initial gasket failure occurred there was no one on the headphones to receive the information which delayed stopping the spil "3. The watchstander at the PVC piping should not have attempted unauthorized closure of the temporary valv This action contributed to a larger spill than would otherwise have occurred."

The inspector concluded that the extent of the flooding was primarily due to the fact that the headphone network was temporarily suspended, and left the watchstander, who was a pipe fitter and not a trained member of the licensee's operations staff, in a position of making a decision which was not immediately communicated to the lead test director. The inspector also concluded that the training provided to the pipe fitter appeared to be inadequate, in that the Unit 2 control room was not notified by the watchstander of the leak by the available alternate method of communication (i.e., site telephone system) with the control room. A Health Physics technician subsequently notified the control room of the leak after the watchstander had been contaminated by the leak and had left the immediate area of the spil Staff Position The allegation was substantiated. However, the licensee was aware of and had conducted an assessment of the event. In addition to corrective actions noted in the incident report, the licensee's project startup manager committed to train all the watchstanders on alternate communication methods, when the primary communication system fails during. system testin Action Required Non Concern No. 7 Characterization It was alleged that flushing of the Low Pressure Safety Injection (LPSI) system through a mini flow bypass resulted in 1 1/2" to 2" vibration of piping.in the suction to a LPSI pump due to a pipe being supported by chainfalls rather than restraints. This occurred between January 1 to January 7, 1985, on a swing shift. Also, Bechtel procedures prohibited flow with chainfalls in us Implied Safety Significance to Operations Normally, flushing of a LPSI system using chainfalls to support portions of the piping would have the potential of overstressing the pipe and remaining pipe supports. However, since the LPSI system was not required to be operable at the time of the flushing (i.e.,

no fuel was in the reactor vessel), safety significance associated with the allegation would.at the worst case involve pipe break, flooding, et Assessment of Safety Significance The inspector interviewed the alleger's informant and reviewed the following completed documents:

o Bechtel memo, December 19, 1984 (Marsh to Cutler)

o 2CV-299-07 Proof Flush Procedure for Shutdown Cooling Modifications o 2PE-225-07 Shutdown Cooling System (DCP.2-29N)

o Unit 2 Control Operators Log December 27, 1984, through January 7, 1985 The inspector determined that the proof flush (2CV-299-07) was performed from December 26 through December 30,-1984, and that the shutdown cooling system flow test (2PE-225-07) was performed from January 1 to January 7, 198 Based upon the review of the above documents and interviews with cognizant test engineers, the inspector determined that on January 1, 1985, the.licensee tested the performance of LPSI P015 flow through the mini flow piping at 1836 (swing shift) and P016 flow at 2018 (swing shift).

The inspector also noted that LPSI piping had chainfalls being.utilized as temporary pipe supports installed per DCP 29N. The licensee also provided an engineering evaluation which stated that LPSI pump operation may be performed with the chainfalls installed as temporary.pipe supports. A test engineer -who observed portions of the LPSI pump flow testing, noted minor.,pipe vibration, but did not in his judgementfeel that it was significant, and the vibration observed appeared to be norma Staff Position The allegation-was partially substantiated in that chainfalls were, used to support piping during the LPSI system flushing. -However, the alleger's statement that Bechtel procedures prohibited flow with chainfalls in use is-not correc e. Action Required Non.

1 Follow-up of Previously Identified Items

'a. (Closed) Open Item (50-361/82-43-02), High Pressure Safety Injection (HPSI) Pump Flow. Measurement The inspector reviewed the completed Proposed Facility Changes.(PFC)

Packages modifying the HPSI recirculation piping to the Refueling Water Storage Tank (RWST) and Procedure SO 23-V-3.4.4 HPSI In service Pump test. The inspector determined that the.relocation of the flow measuring instruments and test procedure appeared to be adequate. This item is close (Closed) Violation (50-361/84-24-01), Station Housekeeping Unit 2 Safety Equipment Building Based upon several observations by the inspectors of the Unit 2 safety equipment building during the inspection period, the inspectors determined that the housekeeping was satisfactory. This item is close (Closed) Open Item (50-361/85-09-01), CPC Addressable Constant Log The licensee had made changes to procedures S02-3-2.13 and'

S03-3-2.13 to improve administrative controls associated with the CPC Addressable Constant Log, and proper log, keeping techniques have been emphasized. This item is close (Closed) Open Item (50-361/85-09-09), Battery Float Voltage The licensee.had taken action to revise procedure S023-6-15 to reflect a float voltage that is consistent with' the vendor recommendations. This item is close (Closed)"Open Item (50-361/85-09-10),

Class IE Batteries Additiona Concern The licensee had taken the following 'acti ns,

o Procedures were to be revised to ensure that the cognizaht engineer will receive surveillance and test datam

oProcedures will be revised to ensure that pilot cells are rotated annuall o Procedure S023-I-9.301 had been revised to include operation and maintenance procedures for the two cells in each battery that are jumpere o The licensee had provided documentation to demonstrate that the vendor was consulted regarding acceptance criteria for the Class IE Battery predperational test. "The vendor's acceptance

.

criteria is 90% capacity and this value is consistent with IEEE Standard 450. Additionally, subsequent surveillance testing of battery 2B007 has not indicated that the battery is degrade This item is close (Open) Open Item (50-361/85-19-01), Unit 2 Shutdown Cooling Modifications, DCP 29N The inspector examined start-up procedure S02-SPSU-806 in conjunction with the test dir'ctor "log sheet to determine if this test satisfied the requirements of paragraph 4.5.2.g.3 of. the Technical Specifications for conducting a flow balance test of, the Low Pressure Safety Injection (LPSI) system. This surveillance is required anytime a modification is made which could affect the LPSI system flow balanc (1) Procedural Concerns:

.

Procedure S02-SPSU-806 was written to verify that the design of the Shutdown Cooling (SDC) System was still in accordance with the unit FSAR description upon completion of the SDC modifications. A section was included in the procedure to adjust the full open position of the Emergency Core Cooling System (ECCS) flow control, valve, 2HV-8160, to establish the same flow conditions that existed prior to the SDC system modifications. The licensee considered that this would be sufficient to satisfy the Technical Specification surveillance requirement. However, the procedure was conducted such that prerequisites, initial-conditions and valve alignments were not clearly documented for accomplishing the ECCS flow adjustmen Additionally, the procedure did not provide for independent verification of the initial system alignment to ensure that the ECCS flow was properly adjusted. In particular, the completed test procedure did not include any valve line up sheets (e.g.,.

neither single nor independent verification of valve position)

documenting the required valve line up for the ECCS flow adjustment. This surveillance typically would not be accomplished again for the life of the plant, and several alignments were established during the test which could allow bypass flow around valve 2HV-8160 and invalidate the ECCS flow adjustmen Although the required test conditions and alignment for satisfactory performance 6f this surveillace were not adequately documented in the test procedure or test log, -based on a detailed evaluation of. available test flow data, the inspector was able to conclude that the system alignment and ECCS flow adjustment were proper. These inadequacies in procedure S02-SPSU-806 are being further evaluated in the context of the requirements of 10 CFR 50 Appendix B, Section XI and condition 19.e to Paragraph 2.C of Operating License NPF-10. This remains an open ite (2) Technical Concerns:.

The section of Procedure S02-SPSU-806 which provides for adjustment of the ECCS flow rate does not address the single leg injection flow balance. The licensee explained that since the system was not modified beyond the flow orifice (and the injection legs were therefore unaffected), establishing the same flow conditions at the flow orifice which existed before the SDC modificcationswould also establish the same injection leg flow balance which existed prior to the SDC modification The inspector reviewed the initial start-up test which originally established.ECCS flow, and it was not clear to the inspector that-S02-SPSU-806 was establishing this same ECCS flo The original ECCS flow test (as performed by procedure 2PE-225-02) had the LPSI pumps.taking a suction from the Refueling Water Storage Tank (RWST) and discharging to the refueling cavity. The data were corrected to account for the effects of the RWST level and the refueling cavity level on the suction and discharge head of the LPSI pumps. The single leg injection flows were balanced within 90 gpm only using the low flow LPSI pump, 2P015, and it is not clear that the acceptability of the single leg injection flows was evaluated for the higher flow LPSI pump, 2P016, which provided approximately 85 gpm more flo The ECCS flow test performed after completion of the SDC modifications was done with.the LPSI pumps taking a suction on the -Reactor Coolant System (RCS) hot legs and discharging to the RCS cold legs. 'The ECCS flow acceptance criteria were corrected to account for the difference in flow path, but it was not clear that the correction adequately addressed the surveillance requirement These technical aspects of the ECCS flow test remain open pending additional evaluatio.

p1 (Open) Open Item (50-361/85-01-02), LockingDevice on Locked Valves Inadequate During follow up inspection involving inadequate locking devices on locked valves, the inspector observed two valves which were not properly locked in position. The two unlocked valves, which were confirmed to be in the correct position, were S3-1208-MU062 (charging pump 3Pl90 suction) and S2-2421-MU006 (diesel generator fuel oil day tank fill valve).

This item remains open pending review and implementation of licensee corrective actio (Closed) Unresolved Item (50-362/85-21-01) Inadequate 50.59 Review, During a recent team inspection at San Onofre Units 2 and 3 (inspection report,50-362/85-21) a review was performed of design control activities. This review covered modifications made to the facility and the methods used by the licensee to document those reviews. During a plant walkdown to observe as built conditions of in process modifications, an observation was made that some scaffolding which was used to support the construction activity for the modifications was entirely supported from nuclear safety related cable tray support The scaffolding which had been erected was located in the Unit 3 switchgear room 302B. The inspector was concern that the scaffolding was supported from light weight, nonstructural members (unistrut type members) which may not have had sufficient capacity to support the scaffolding platform load Of broader concern was the method which the licensee used to control in process construction work activities such that those activities would not impact safety related plant equipmen Construction activities are controlled in a Construction Work Order package (CWO). This document is used to initiate, document and control construction or modification work within the plant. The instruction for completion of this form are contained in procedure WPP/QC1802. The procedure contains the necessary steps to be used for performing construction work activities..In addition, steps are given which include interface with the operations organization for the turn over of permanent plant equipmen The procedure contains a section which describes the use of a construction safety evaluation (CSE) document. This document is used to control construction work activities which could impact other in service safety related equipment. A CSE had been prepared for the two work activities in process within switchgear room 302 The CSE acknowledged the use of scaffolding within the room however, it did not include an evaluation for the erection of scaffolding which would be supported from nuclear safety related cable tray supports. The CWO procedure.contains specific steps for completion of the CSE and specifically addresses the use of scaffolding, hoist

and chainfalls. The procedure requires that the CSE contain precautions to ensure that scaffolding, hoist and chainfalls are not attached to nuclear safety related equipment. The procedure states that scaffolding may be erected over nuclear safety related equipment, however, steps must be taken to ensure that only one safety related train is effected at a given tim As a result of the above observations, the licensee has undertaken a review of the CSE method for controlling construction activity in the vicinity of nuclear safety related equipment. This review appears to be extensive and thorough in that it was performed not only to identify activities such as the erection of scaffolding which could have an effect on nuclear safety related equipment but also includes a review of other activities such as the routing and placement of electrical power cables and high pressure water and pneumatic air hose The licensee also performed an analysis which demonstrated 'that the cable tray supports on which the scaffolding had been erected would not have been over stressed during a design basis even During the inspection of switchgear room 302B and cable spreading rooms 315 and 315A, the inspectors also noticed that temporary power and welding cables had been routed such that these temporary cables were draped over and supported by Class IE cable tray The criteria established by Regulatory Guide 1.75 and adopted by Chapter 8.1 of the FSAR do not allow this condition to exist unless certain precautions have been taken to ensure that the redundant train remains unaffected. The licensee had prepared a CSE which permitted temporary electrical cables to be suspended no less than 3" from Class IE cable tray In this regard, the inspectors noted the following concerns involving the observed temporary welding cables:

(1) The existing procedures for performing the observed construction activity did not provide any method for controlling the use and placement of the cables such that they would not become associated with two redundant train (2) Considering the nature of temporary welding cable, and the potential of this type of high energy circuit to result in significant.damage under fault conditions, the definition of a 3" separation criterion as used.in the CSE may not be adequate.. Furthermore, in the instance of the subject welding cable, not only were the temporary electrical cables not routed in accordance with the CSE, but the CSE did not provide the bases to demonstrate that the temporary cable installation did not involve an unreviewed safety questio The inadequate 50.59 review of'scaffolding and temporary electrical cable installations is a violation:(50-362/85-26-01).

The improper routing of temporary electrical.cables'-is also a violation (50-362/85-26-02).