IR 05000275/1986018
| ML17083B776 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 07/14/1986 |
| From: | Mendonca M, Padovan M, Polich T, Ross T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17083B774 | List: |
| References | |
| 50-275-86-18, 50-323-86-18, NUDOCS 8608040315 | |
| Download: ML17083B776 (26) | |
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos:
50-275/86-18 and 50-323/86-18 Docket Nos:
50-275 and 50-323 License Nos:
Pacific Gas and Electric Company 77 Beale Street, Room 1451 San Francisco, California 94106 Facility Name:
Diablo Canyon Units 1 and
Inspection at:
Diablo Canyon Site, San Luis Obispo County, California Inspection Conducted:
From May 25, through July 5, 1986 Inspectors:
H. L. Padovan, Acting Senior Resident Inspector T. M. Ross, Resident Inspector T. J. 'Polich, Resident Inspector Approved by:
M. M. Mendonca, Chief, Reactor Prospects Section
~Z~r/sr Date Signed 7 /rv /P b Date Signed V/ry /J'C.
Date Signed
~/i~a'ec Date Signed Summary:
Ins ection from Ma 25, 1986 throu h Jul 5,
1986 (Re ort Nos. 50-275/86-18 and 50-323 86-18)
Areas Ins ected:
The inspection included routine inspections of plant operations, maintenance and surveillance activities, follow-up of on-site:
events, open items, and LERs, as well as selected independent inspection activities.
Additionally, during this period the Unit 2 S/U testing phase (IE manual chapter 2514) of the light water,reactor inspection program was concluded during this period.
Inspection Procedures 71707, 30703, 71710, 62703, 61726, 93702, 50095, 90712, 92702, 72616, 72301, 65051, 83301, 61700 94703, 72600, 72624, and 92700 were applied during this inspection.
Results of Ins ection:
One violation and no deviations were identified.
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DETAILS 1.
Persons Contacted
- G. A. Maneatis, President, Pacific Gas and Electric Company
+R. C. Thornberry, Plant Manager
- J. A. Sexton, Assistant Plant Manager, Plant Superintendent
- J. M. Gisclon, Assistant Plant Manager for Technical Services
- J. D. Townsend, Assistant Plant Manager for Support Services
- C. L. Eldridge, Quality Control Manager K. C. Doss, On-site Safety Review Group R.
G. Todaro, Security Supervisor D. B. Miklush, Maintenance Manager D. A. Taggert, Acting Director Quality Support T. J. Martin, Training Manager
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G. Crockett, Instrumentation and Control Maintenance Manager J. V. Boots, Chemistry and Radiation Protection Manager L. F. Womack, Engineering Manager T. L. Grebel, Regulatory Compliance Supervisor.
- S. R. Fridley, Senior Operations Supervisor R. S. Weinberg, News Service Representative The inspectors interviewed several other,lice'nsee employees including shift supervisors, reactor and auxiliary operators, maintenance personnel, plant technicians and engineers,, quality assurance personnel and general construction/startup personnel.
- Denotes those attending the exit interview.
Note:
Acronyms are used throughout this report; refer to the Index of Acronyms at the back of the report.
2.
0 erational Safet Verification a.
General During the inspection period, the inspectors observed and examined activities to verify the operational s'afety of the licensee's facility.
The observations and examinations of those activities were conducted on a daily, weekly or monthly basis.
On a.daily basis, the. inspectors observed control room activities to verify compliance with selected LCOs as prescribed in the facility TS.
Logs, instrumentation, recorder traces, and other operational records were examined to obtain information on plant conditions, and trends were reviewed for compliance with regulatory requirements.
Shift turnovers were observed on a sample basis to verify that all pertinent information of plant status was relayed.
During each week, the inspectors toured the accessible
'areas of the facility to observe the following:
l'a)
General plant and equipment condition <<
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(b)
Surveillance and maintenance activities.
(c)
Fire hazards and fire fighting equipment.
(d)
Radiation protection controls.
(e)
Conduct of selected activities for compliance with the licensee's administrative controls and approved procedures.
(f)
Interiors of electrical and control panels.
(g)
Implementation of selected portions of the licensee's physical security plan.
(h)
Plant housekeeping and cleanliness.
(i)
Essential safety feature equipment alignment and conditions.
The inspectors talked with operators in the control room, and other plant personnel.
The discussions centered on pertinent topics of general plant conditions, procedures, security, training, and other aspects of the involved work activities.
Auxiliar Saltwater Pum s During a routine ESF walkdown of Unit 1 and 2 ASW systems, the inspector observed radial surface cracking in the rubber material of several ASW pump discharge expansion joints.
Mechanical maintenance was previously aware of this problem which has also been exhibited by the non-safety related screen wash pumps.
An inspector discussed the possible adverse effects these cracks may have on ASW system operability with the maintenance manager, mechanical engineers, and OPEG.
The licensee consensus was that physical, integrity of the expansion joints was not significantly degraded by the cracks.
A design change request was issued to replace all ASW pump expansion joints with a more durable design.
This will be followed under routine inspection activities.
Unit 1 Diesel Generators During a routine ESF walkdown of DGs l-l, 1-2, and 1-3, the inspector observed several minor mechanical, electrical; and housekeeping problems.
This included mechanical flange air leaks,.
broken electrical conduits, and poor housekeeping within confined areas.
All findings were discussed in detail with the maintenance manager and were promptly resolved or scheduled for repair.
None of the inspector findings appeared to have any significant adverse impact upon DG operability, but were addressed by licensee corrective actions to assure Unit'
DGs are maintained in an optimum functional conditio F FI FFi I
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> if I v . JFP(J '"4 'F itFf b fI ~ I, d. Unit 1 Containment Penetration The existence of an unidentified spare instrument line through Un'it 1 containment penetration 82 was documented by an OPEG report (dated May 2, 1986) to DCPP on-site engineering. This'eport was issued as ., part of the corrective actions prescribed by appro'ved NCR DC2-86-TN-N022 (dated February 26) which addresse'd a similar unidentified spare line discovered, passing, through'nit 2'ontainment penetration 82. The integrity of the Unit 1'spare line was not physically established, nor incorporated into, the containment surveillance program, until May 21. NRC IR 50-323/86-05 issued a violation against Unit 2 for failing to comply with the TS surveillance requirements for verification of containment integrity. Unlike Unit 2, the spare Unit 1 line did not penetrate through the insulation covering on the auxiliary building side of penetration 82, and as such was not discernible by visual examination outside of containment. The OPEG report was based upon a review of various containment piping penetration drawings and a QC verified installation drawing. This discrepancy between previous visual walkdowns and the OPEG report was not resolved until May 21. At that time on-site engineering coordinated the removal of obstructing insulation, and found an uncapped spare instrument line through penetration 82. Further investigations revealed the line was indeed capped in containment and was proven to be leak tight by a local leak rate test. The spare line was subsequently capped and sealed on the auxiliary building side, and added to the applicable surveillance test procedure. Several opportunities were missed by the licensee to have resolved this problem in a more timely fashion: I) OPEG management did not recognize and/or promptly communicate the TS implications associated with the report; 2) low priority pursuit of this discrepancy by on-site engineering due to a predisposition that the line did not exist; or, if it did, it was probably capped; and 3) penetration was not visually examined from inside containment during a routine operations entry conducted May 14. Failure to initiate prompt corrective action upon notification of a non-conforming condition was a violation of the DCPP QA program and administrative procedures (86-18-01). One violation and no deviations were identified. 3. Event Follow-u a. Unit 2 Reactor Tri 12 KV Bus Undervolta e On June 27, 1986 a reactor trip occurred due to undervoltage on both 12KV buses for approximately 2 cycles. The undervoltage was caused by an electrical fault on CWP 2-2. The CWP tripped on indication of a'phase "B" to phase "C" differential current and instantaneous overcurren I ~ 'h li v. hl) '$ ~ . ~ ' f 'I >>,.',> VV II ! I I I CP'h g";a>> vh" u~*P. 'h ~ 4-I" II )P 3 v J ih-a' lf I ~ I '. I I Ilt II I I ')" ih ',' hv' I lh I 1,1 I' I II I Vl I Nhr ( II, hh~ I r h 'ev rggv~ <<rh I t I I" QIIh I' 4 v 0 investigation of the CWP trip subsequently revealed that some stator winding spacers had become loose and slid down such that the stator winding and the spacer came in contact and wore the insulation from the windings. The licensee plans to examine the Unit CWPs during the refueling outage in September. Twenty to thirty windings in CWP 2<<2 are currently being replaced and the spacers are being tightened. The reactor was stabilized within a half hour of the trip and the reactor was brought critical on June 28 and paralleled to the grid on June 29 with a load restriction of 50X while CWP 2-2 is being repaired. Unit 2 Reactor Tri Breakers 0 enin Intermediate Ran e Hi h Flux On June 27, 1986 at 3:07 p.m. the Unit 2 reactor trip breakers opened due to an intermediate range high flux trip signal. The trip signal was initiated by an I&C technician who failed to follow a surveillance test procedure. The reactor was in Mode 3 at the time of this event (see section 3.a). While performing STP I-3A, "Nuclear Intermediate Range Channel Analog Channel Operational Test," an I&C technician failed to place the "Level Trip" switch in the "Bypass" position before-.removing the instrument power fuses thus generating a reactor trip signal. The technician should have positioned the switch and initialed the data sheet. Also, a second technician should have verified the correct switch position and initialed the data sheet prior to the fuses being removed. The second technician was present, but due to the proximity of the fuses to the switch, he was unable to prevent the first technician from removing the fuses before turning the switch. The licensee feels the procedure is adequate and changes to the procedure could not have prevented this type of error. The technicians have been counseled on procedural compliance and verification. Reactor Tri Breaker "A" Failure to 0 en On May 28, 1986 while attempting to remove Unit 1 reactor trip breaker (RTB) 52 RTA from service for preventive maintenance, the RTB did not, open when the automatic shunt trip test button was pushed. The RTB was replaced with a backup breaker, and again the RTB would not open when the test button was depressed. This RTB was then "racked out," and I&C verified continuity through the RTB circuitry and took resistance measurements on the contacts of the automatic shunt trip block switch. These readings were found to be acceptable. The RTB was racked back into service,'and subsequently functioned properly each time the test button was pushed. STP I 33C "Time Response Testing of Reactor Trip Breakers" was then successfully completed on the breaker. The licensee's investigation determined the auto shunt trip test switch contacts were not opening when the button was depresse I 5,' Jft.5 ~ '5 1K KK I JII'y I ll ' I J RI ) rf KK K Cr Kf ), It $ l 'Kf 'Kl K I' If r I I J J ~, K ll1 I'4 II ~ I I ~ K 4K~ 11 1'pA r $ r d t g j 5 Pushing the button should have caused relay UVZA to energize the RTB shunt trip coil, opening the breaker. The operator and ISC technician, each having depressed the button, indicated the switch did not "click" until the replacement RTB was racked back into service the second time (as previously described). After exercising the switch several times, the breaker correctly functioned on all subsequent actuations of the automatic shunt trip test button. Relay UVXA and the associated circuitry were diagnosed to be performing correctly. Furthermore, the breaker would have functioned correctly upon receipt of a reactor trip signal from the SSPS. A licensee's records review indicated the same preventative maintenance activity has been previously performed five times on the Unit 1 breakers and twice on the Unit 2 breakers, without failure of the test switches, Additionally, in licensee discussions with the manufacturer of the switch, the manufacturer indicated they were unaware of any problems with that particular type of switch. To further investigate the problem, the licensee decided to monthly test the automatic shunt trip test feature on breaker RTA in an effort to duplicate the failure and positively identify the failure mechanism. The licensee, is also investigating replacement of these switches on all, Unit 1 RTBs during the upcoming refueling. Unit 2 Reactor Tri and Safet In ection On July'3, 1986 at 7:30 p.m., Unit 2 experienced a reactor trip due to. turbine trip on loss of condenser vacuum and SI due to a momentary high,steam flow coincident with low-low TAVG signal from the plant's solid state-protection system. Prior to the reactor trip, the plant was operating at approximately 9 percent power, in preparation for a semiannual'" tu'rbine overspeed trip test. When the operators opened the 500 KV generator main output breakers to separate the generator from the grid, the main condenser began losing vacuum, slowing the turbine and-causing the automatic turbine control system to open the turbine valves. This resulted in lowering of the reactor coolant temperature, causing reactor power to increase to about 10 percent. Subsequently, the turbine tripped on loss of condenser vacuum which generated a'reactor trip signal. TAVG dropped to 543 degrees F (the low-low TAVG setpoint), and the high steam flow bistables momentarily flickered as a result of a pressure pulse propagated up the steam lines from fast closure of the turbine stop valves. The pressure pulse wa's of sufficient duration (about 16 milliseconds) to initiate SI, but was too brief to cause closure of the main steam isolation valves. An Unusual Event was declared, the SI was terminated, and the plant was maintained in a hot standby condition while the licensee investigated the cause of the loss in condenser vacuum. Loss of condenser vacuum was attributed to failure of a moisture separator reheater (MSR) relief valve to reseat after lifting during the transient. Lifting of the MSR relief valve occurred since the relief valve's sealing steam had been isolated due to a previous operational proble II >> 1. >> >> I, ~
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~- I IX t >> 'I I~ '>> X I >> C. Jl >>$ 4>>X-II , ~ JI'J 1 ~ f>> I ' 'g'X ')" L JJ jk JJ I ~ >> / ~ ' F I>> 4 >> 4>>') I 'I "II>>I 4'S~ 0'fx "XJ Jl Xy >> 4,>>I $ "JI ~ JiJ ',, ll fl X XX, >> JJ I ' >>>>X I ~ P k1 II4 X I I t ~ % On July 4, the resident inspector arrived on-site and evaluated the licensee's understanding of the event prior to restart. Additionally, licensee management briefed Headquarter's personnel and the resident inspector on the event later in the day on July 4. The inspector will follow under routine inspection effort, the licensee's investigation of operational problems associated with the relief valve sealing steam. . e. Diesel Generator Starts I On June 27, 1986 two DGs were inadvertently, started by a non-licensed AO. At 1:14 p.m. DG 1-3 started when the 2F bus potential transformer fuses were, removed instead of the 2F bus auxiliary feeder breaker potential transformer fuses. The same error was made moments later on the 2G bus which resulted in DG 2-1 starting. ( Ir The error was made due to the wrong fuse location being spe'cified on the switching order which the AO was following to remove the fuses. The location of the fuses was changed by a design change, but the switching order was never updated for this design change. Also, the exact title of the fuses was not specified on the cubicle. ) The two DGs started but were prevented from sequencing the loads on to the 4 KV vital buses due to the bus potential transformer fuses being removed. The power was restored to the 4 KV buses F&G within five minutes. The switching order used has been corrected to update the potential transformer fuse locations, and new labels have been placed on all bus potential transformers. The licensee is examining all switching 'rders to ensure actual equipment locations are correct.'lso, the procedures which govern switching orders 'are under review to incorporate switching orders into individual procedures. These individual procedures will be updated and reviewed on a periodic basis. No violations or deviations were identified. r-4. Maintenance The inspectors observed portions of, and reviewed records on, a selected maintenance activity to assure compliance with approved procedures, technical specifications, and appropriate industry codes and standards. Furthermore, the inspectors verified the maintenance activity was performed by qualified personnel, in accordance with fire protection and housekeeping controls, and replacement parts were appropriately certified. a. Centrifu al Char in Pum 2-1 An inspector observed mechanical maintenance performance of various PMs, inspection of the low speed shaft key,(that drives the speed increaser lube oil pump) for proper size and fit, and repairs to ) w w,,hw(,$ WF W i ~ f ','. Ca'r'.IQ ': V (h 'F(FL ~ ('w v)A F-wwh ~ (', EJI = w 9 'l E) ,F 'l ~ ) I r h 9'1 ") I((~ l ) ' F.L(hw a) I Fh h ~'w),W F =I Fl f );,.f Vl, 'til'l (,I ... ' I,('I'h,w(~ E) gj, ~ 'F9 hr 4 f w ) ) Jwfrw I(((l ) 9(f' >> )i~w fl w c)9f ) ilw)') J '".'1 ) 1 \\44, I I "I( ~ ( w i,'h) I ( (. ) I 'F ( 'h I
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w If F I ( )19f;( VF) ) F ) I ~ 4 wl). )y w ff ) 'l w v Fl g9 ?, 'IV (P ~ iy'l (f w =F i 99$ () I w Y'>> '"" ' I I ,('* I I h) (': 'i) 'I i,(h ( If I hit Unit' CCP 2-1 to correct for excessive pump seal leakage. Job related SWFs, SWP, and clearance forms were reviewed by the inspector. Mechanical maintenance personnel activities within the defined SCA were scrutinized to verify compliance with posted radiological controls. Additionally, the inspector walked down established clearance boundaries and reviewed the TS status sheets. b. Circulatin Water Pum 2-2 The inspectors observed various portions of the CWP 2-2 stator winding repair that was being performed by contract personnel. This repair was due to the phase to phase ground that occurred on June 27, 1986 see section 3.a. The work consisted of stator coil replacement and tightening stator coil spacer to prevent slipping. No violations or deviations were identified. 5. Surveillance l By direct observation and record review of selected surveillance testing, the inspectors assured compliance with TS requirements and plant procedures. The inspectors verified that test equipment was calibrated, and acceptance criteria were met or appropriately dispositioned. Unit 1 Control Room Air Particulate Monitor The inspector observed certain aspects of 'the calibration activit'ies performed on RM-21 in accordance with STP I-108B3.'&C technicians also performed a semi-annual discriminator,,check, in'accordance with STP I-108B5, that was observed by the inspector. During this, evolution the I&C technicians appeared well versed in the procedures and very knowledgeable concerning RM-21 response characteristics; The test equipment in use were within the',calibration due date and appropriately connected. b. Fire Detection S stem Detector Functional El tl, r The inspector observed various portions of STP I"-34A. The STP was performed by qualified technicians and the results were reviewed by the I&C foreman. No violations or deviations were identified. 6. Inde endent Ins ection a ~ Control Panel Boltin In a memo to the Commission Chairman dated April 18, 1986 the NRC EDO discussed an issue concerning missing control panel anchor bolts at Dresden. An inspector reviewed the memo for any applicability to DCPP. Furthermore, in the company of a licensee's representative from GC electrical engineering, the inspector walked down the as-built structural supports of the Unit 1 and 2 control panels and SSPS cabinets. The base anchorage for all panels and cabinets were N ~ u I Pp ! P 'I l IJP l I I A NS'j=>> "w} W 'I<<) 'It)1 ) 'l
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P IL ) I A I upp 'I I Jlb 4)'L JI P' R I OI>>W I b I ~ II >> lf 4 "4 .F')4 I , ~ '>>, ~ verified against applicable DCNs and as-built, drawings with,no apparent discrepancies. It should be noted that anchor bolts have not been used at DCPP, rather all panels and cabinets, were welded to embedded base plates. Steam Generator Snubbers The inspector reviewed plant records for the subject snubbers. The-snubbers installed on the steam generators at DCPP are rated for 1300 kips. These snubbers were custom designed and manufactured for PG&E by Paul-Monroe. Approximately two and one-half years ago these snubbers were overhauled, including installation of new long-life seals, and functionally tested. There was no evidence to indicate any snubber has failed or locked-up. Change-out and maintenance of the Unit SG snubbers was witnessed by a resident inspector and documented in NRC IR 50-275/84-21. On-site maintenance engineering also indicated these Paul-Monroe snubbers were built with the modified hydraulic control valves design, recommended to minimize particulate clogging. 0 erational Mode Transition DCPP Operating Procedure L-0 "Mode Transition Checklists" provides guidance for the SFM to ensure all TS requirements are met prior to entry into an ascending operational mode. Each ascending operational mode transition checklist (e.g. Mode 6 to 5, Mode 5 to 4, etc.) also establishes a documentary record that all LCOs and associated surveillances required by TS 3.0.4 and 4.0.4 have been reviewed and verified by the SFM prior to mode entry. Throughout this year the inspector has observed various mode transitions made by Units 1 and 2 in accordance with OP L-0 and other applicable operating procedures. The inspector reviewed in-process and completed mode transition checklists as they were implemented to track 'and verify compliance with TS requirements prior to mode entry. Compliance with selected TS requirements, documented as satisfactorily complete by the SFM on mode transition check lists, were independently verified by the inspector. In all cases, applicable checklists were completed, reviewed and approved by the SFM prior to mode entry. Thermal Ex ansion Considerations in Desi n Chan es Thermal expansion has been considered in the design, initial startup and hot functional test performed on both units. No seperate procedure for thermal expansion for design changes exists at'his time; however, there are procedures which exist that govern how design change verification walkdowns (thermal expansion considerations) should be performed. The mechanism that triggers the performance of these walkdowns is somewhat subjective at this time for hot walkdowns, and more clear-cut for cold system walkdowns. The engineering manager is currently drafting a '",C, ') k kk.'< 7' tt I 'I I j,t.JI,'Ak g C"t I' ) )', k h V tt) I i I k, ~ > V) II II ICOSA I kh hI'tk ~ Ifch C ~,k V - ct ' III R k V ~ I' ~ I f k vt ' ( $ "I I 8 ,9 H procedure to coordinate all aspects of startup from mode 5 to 100X power which would include triggers for such walkdowns. I No violations or deviations were identified. 7. Startu Testin a. ualit Assurance for Unit 2 Startu Selected licensee QA surveillances for the Unit 2 S/U test program were reviewed by the inspector and all related QA findings were dispositioned in accordance with the licensee proceduxes. The inspector also independently tracked the disposition of S/U test discrepancies in the review of selected test procedures identified in section 7.b below. b. Startu Testin Unit 2 The following S/U TP results were reviewed and approved by the'ead S/U Engineer, and accepted for DCPP by the Plant Superintendent: 36.1 Rod Drive Mechanism Timing Test 38.2 Automatic Steam Generator. Level Control 38.6 Startup Adjustment of Reactor Control System 42.1 Doppler Power Reactivity Coefficient Measur'ement 42.5 Statepoint Data Collection '; 42.8 Operational Alignment of Reactor Coolant System Temperature, Instrument 42.9 Operational Alignment of Nucl'ear Instrumentation 43.1 Load Swing Tests Test results of these completed procedures were evaluated by the inspectors; including a review that all test procedure changes and test deficiencies were incorporated or dispositioned in accordance with administrative guidelines. This review completes the NRC's S/U testing phase (IE Manual Chapter 2514) of the Light Nater Reactor Inspection Program for Diablo Canyon, Unit 2. No violations or deviations were identified. 8. 0 en Item Follow-u a. Notice of Violation on Radiolo ical Controls (0 en Item 86-09-01, Closed) An inspector reviewed the licensee's response letter to the Notice of Violation (Level V) in NRC IR 50-275/86-09. PGSE letter DCL-86-151 dated May 30, 1986 describes the corrective actions taken, and planned to be taken, concerning'the failure of personnel to comply with radiological control procedures. The inspector reviewed and observed field implementation of a new plant policy encouraging greater first line supervision participation and monitoring of work inside the RCA. Furthermore, the inspector witnessed that additional emphasis on adherence to radiological, ~ I IP y X>> Ii'lt If'+i'1 I, mt g Wj.' f<< ')N<<, f) J ff 4, fh f'. ~ f f <<, f<< I g ) I (j fm,t ~, fh I ) l' >> W 1>> I ~ ~ .'gC~N, y f f f I I If, 1<<t ll
x f I I tf \\ill ~ mf >> "W W controls associated with work in-and-around SCAs has been incorporated into radiation worker requalification training. Based upon the licensee's timely response and corrective actions, this violation is considered closed (86-09-01). b. Enforcement Action on Ino erable Main Steamline Isolation Valve (0 en Item 50-323 86-04-01, Closed) and Followu of Mana ement Involvement to Address Pro ems en tern 5- , Closed) On February 12, 1986 NRC Region V issued Enforcement Action EA 86-04, comprising a Notice of Violation and Proposed Imposition of Civil Penalty for a Severity Level IIIviolation involving the inoperability of one channel of the actuation logic of one main steam isolation valve. The inspector has reviewed the licensee's response letter DCL-86-071 and finds the corrective actions to have been implemented. This was accomplished by record review, observation of maintenance performed, and attending TRGs. Thereby, open items 86-04-01 and 85-32-03 are closed. ' C ~ Auxilar Feedwater Pum Oil Slin er Rin s (0 en Item 50-275 86-15-01, closed) I NRC IR 50-275/86-15 prepared by the Performance Appraisal Section (PAS) of the Office of Inspection and Enforcement contained one unresolved item concerning operability of the AFW pumps during corrective maintenance situations. Specifically, the PAS inspectors questioned the licensee's determination of pump operability of AFW pumps 1-2 and 1-3 when contaminated oil was found in both pumps in December 1985. The resident inspector reviewed, the circumstances surrounding this issue and investigated, the action taken by the licensee in December. These actions were determined to be acceptable. Upon identifying contaminated bearing lube oil in 'AFW pump 2-2, the licensee sequentially removed AFW pumps on both units from service, inspected, flushed and replaced oil, bearing and slinger rings as deemed appropriate by the licensee. Due to the design and material of the bearings, slinger rings, and housings, it was determined the pre'sence of brass contamination in the bearing oil would not necessarily require that all AFW pumps be immediately declared inoperable. This unresolved item is closed. I 9. Licensee Event Re ort Follow-u Based on an in-office review, the following LERs were closed out by the resident inspectors: Unit 1: 84-37, 84-38, 86-05 Unit 2: 85-27, 86-15 ~I ~ i I << 1. I h ft ,>J h'I ' F I I fl t I' Ir, I gf i I I P I t rf, <<ll I j I I lt F I II << r $ << ") C'f I I p << v <<S f I I I I, ' ,I I'I, II ' F fa M I" h ~ft r f << I I I'I Il . I f The LERs were reviewed for event description, root cause, corrective actions taken, generic applicability and timeliness of reporting. The LER identified below was also closed out after in-office review and on-site follow-up inspections were performed by the inspectors to verify licensee corrective actions: Unit 2: 86-14 was closed out based upon the inspector's witnessing of selected portions of the licensee's verification of breaker cubicle terminations. No violations or deviations were identified. 10. S ent Puel Pool Re-rackin All sixteen of the Unit 1 high density spent fuel racks have been 'nstalled in the Unit 1 spent fuel pool, and leveling operations on the most recently installed rack are continuing. The inspector observed that installation instructions were followed during insertion of the racks, including installation of'earing plates under each foot of the racks. Also, QA participation was noted by the inspector. Drag testing of each individual cell, utilizing a dummy fuel assembly was performed on twelve of the sixteen racks. A total of four cells in racks 1Al, 1D1 and 1D3 did not pass drag testing and will require re-work. Pabrication of the shipping cask restraint was also observed by the inspector. The inspector also reviewe'd the licensee's receipt inspections records and evaluated the manufacturer's documentation supplied with the racks for compliance with the purchase specification. The licensee had not obtained certifications onsite for the Boraflex material used in the high density racks. Receipt of this information is expected shortly. Three Unit 2 high density spent fuel racks have been received onsite, and are in storage. No violations or'eviations were identified. 11. Exit On July 11, 1986 an exit meeting was conducted with the licensee's representatives identified in paragraph 1. The inspectors summarized the scope and findings of the inspection as described in this repor e I h il Wv? It I i, 'kvlW y .t'>> W ItCj& Vy
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? PW? I I I W"I'r>> t IV W W g<wY r . I Ill'P I? "r W? W qn = V I ~ * y l W Ill" ~ 'W j J Wi,', ?IW" iv II J ~ I I ihit. I IIII 'F g y R I W I Index of Acron s AO AFW ASW CCP CWP DG DCN DCL DCPP EDO ESF GC I&C IE IR KV LER LCO MSR NCR NRC OP OPEG PGSE PM QA QC RCA RM RTB RWP SCA SFM SG SI SSPS STP S/U - SWF 'WP TAVG TP TRG TS Auxiliary Operator Auxiliary Feedwater Auxiliary Saltwater System Centrifugal Charging Pump Circulating Water Pump Diesel Generator Design Change Notice Diablo Canyon Letter Diablo Canyon Power Plant Executive Director of Operations Engineered Safety Features General Construction Instrumentation 6 Control Inspection and Enforcement
Inspection Report
Kilo Volt
Licensee
Event Report
Limiting Conditions for Operation
'oisture'eparator
Reheater
Non-Conformance
Report
Nuclear Regulatory
Commission
Operating Procedure
Onsite, Plant Engineering
Group
Pacific Gas
and Electric
Preventative
Maintenance
Quality Assurance
Quality Control
Radiological Controlled Area
Radiation Monitor
Reactor Trip Breaker
Routine Work Permit
Surface
Contamination
Area
Shift Foreman
Safety Injection
.Solid State Protection
System
Surveillance Test'rocedure
Start-up
ShopWork Follower
Special
Work Permit
Average Temperature
Test Procedure
Technical Review Group
Technical Specification
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