IR 05000275/1985026
| ML17083B641 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 08/29/1985 |
| From: | Dodds R, Mendonca, Mendonca M, Padovan M, Plich T, Polich T, Ross T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17083B640 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-1.C.1, TASK-1.C.8, TASK-2.B.4, TASK-2.F.1, TASK-3.D.1.1, TASK-TM 50-275-85-26, 50-323-85-23, IEB-79-02, IEB-79-2, NUDOCS 8509130227 | |
| Download: ML17083B641 (50) | |
Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos:
Docket Nos:
License Nos:
50-275/85-26 and 50-323/85-23 50-275 and 50-323 DPR-80 and DPR-81 Licensee:
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 tuis Obispo County, California Inspection Conducted:
June 30, 1985 through August 17, 1985 Inspectors:
o s, Chief, Reactor Projects Section l at signed M. M.
M ndonca, Sr. Resident Inspector 2-ate igned M. L. Pado an, eside Inspector ate igned sident ns ec or F ~$
'e igned T. J. Poli
, Resident I *spe'ctor r
ate igned Approved by:
R.
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D s,
ief, Reactor Projects Section
ate igned S509i3Oia7 s60829 PDR ADOCK 05000275
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~ 1-2-Summary:
Ins ection from June 30 throu h-Au ust
1985 (Re ort Nos. 50-275/85-26 and 50-323 85-23 I
Areas Ins ected:
Routine inspection of plant operations, maintenance and surveillance activities, followup of onsite 'events, open items, and IERs, as well as selected independent inspection activities.
During'this inspection Inspection Procedures 71707, 71710, 61726, 62703, 30703, 93702, 92705, 92700, 72616,'2302, 72608, 72566, 72400, 72564, 72596, 72521 and 61709'were used for guidance.
I This inspection effort required-196 inspector-hours 'for Vnit 1,'nd 271 inspector-hours for Vnit 2 by four resident inspectors and one regional-based inspecto I ~
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Persons Contacted R.
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C. Thornberry, Plant Manager Patterson, Assistant Plant Manager, Plant Superintendent M. Gisclon, Assistant Plant Manager for Technical Services B. Kaefer, Assistant Plant Manager for Support Services A. Wogsland, Technical Assistant to Nuclear Power Operations Manager G. Todaro, Security Supervisor B. Miklush, Maintenance Manager A. Sexton, Operations Manager G. Crockett, Instrumentation and Control Maintenance Manager W. Rapp, Onsite Safety Review Group Chairman L ~ 'Fisher, Senior Power Production Engineer U. Boots, Chemistry and Radiation Protection Manager B. McLane, Material and Project Coordination Manager F.
Womack, Engineering Manager L. Peterson, Instrumentation and Control General Foreman, Vnit 1 L. Grebel, Regulatory Compliance Supervisor S. Weinberg, News Service Representative R. Fridley, Senior Operations Supervisor J.
Angus, Senior Power Production Engineer P. Powers, Senior Chemistry and Radiation Protection Engineer G. Banton, Senior Power Production Engineer The inspectors interviewed several other licensee employees including shift supervisors, reactor and auxiliary operators, maintenance personnel, plant technicians and engineers, quality assurance personnel and general construction personnel.
"-Denotes those attending the exit interview.
Note:
Acronyms are used throughout this report; refer to the Index of Acronyms attached to the report.
2.
0 erational Safet Uerifiction General During the inspection period, the inspectors observed and examined activities to verify the operational safety 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:
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(1)
General plant and equipment conditions.
(2)
Surveillance and maintenance activities.
(3)
Fire hazards and fire fighting equipment.
(4)
Radiation protection controls.
(5)
Conduct of selected activities for compliance with the licensee's administrative controls and approved procedures.
(6)
Interiors of electrical and control panels.
(7)
Implementation of selected portions of the licensee's physical security plan.
(8)
Plant housekeeping and cleanliness.
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.
Com onent Coolin Mater S stem Malkdown 1'uring a walkdown of the CCM systems on Units 1 and 2, the inspector noted several sealed valves with broken or missing seals.
.No sealed valve change sheet existed for-. these valves that would indicate a
reason for the broken or missing-'seals.<
When notified by the inspector that sealed valves were not sealed,.the licensee promptly
replaced the seals.
None of the valves were 'found<out of position.
Also during this walkdown,.two sealed valves were"found to be properly sealed but incorrectly labele'd.
Additionally, a valve was found incorrectly labeled on the Un'it 2 CCP system operating valve identification diagram.
Since these disc'repancies are, typical of recent system walkdowns, this item will be'ollowed as* open item number 85-23-01.
C Intake Structure Partial Floodin In order to make weld repairs on the Unit 2 circulating water pump 2-2 scroll cage, clearance
)$17-13129-85 was issued on May 9, 1985 to permit dewatering of the 2-2 pump suction bay.
A submersible dewatering pump was used to transfer the water from the suction bay to the ocean.
Subsequently, on June 29, 1985, clearance jjl7-14066-85 was issued on the Unit 2 circulating water pump 2-1 suction bay to dewater that bay to prevent corrosion of the pump impeller and casing.
Since a dewatering pump was already installed in the 2-2 pump suction bay, maintenance personnel determined that water in the 2-1 bay could be drained to the 2-2 bay (utilizing ASM demusseling supply valves 2-FCV-604 and 2-FCV-605 and the interconnected piping
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as a cross tie between the bays),
to use the existing de-watering pump.
This was believed to be a time saving action.
Maintenance personnel assumed the eight inch line and de-watering pump had
'sufficient capacity to accommodate the flow of water from the cross tie.
Accordingly, an auxiliary operator remotely opened pneumatically operated valves FCV-604 and FCV-605 and left the intake structure.
However, the cross tie was actually a
thirty-eight inch line and the water flow from the 2-1 bay to the previously de-watering 2-2 bay far exceeded the capacity of the de-watering pump.
Mater flowed into the circulating water pump 2-2 scroll cage and passed through an open'manway hatch in the scroll cage.
During a 15 to 20 minute period, it was estimated that more than 100,000 gallons of water, poured through the open manway, flooding a confined portion of the intake structure common to both Units to a depth of about 4 feet.
All four motor operators on the circulating water pump discharge isolation valves (two 'per unit)
were submerged, as well as ciiculating water temperature instrumentation (rendering the equipment inoperable).
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The inspector's review of this event identified several contributing factors.
First, poor communications existed, between maintenance personnel and the clearance,coordinators.
Maintenance personnel did not indicate,to the coordinators that themanway 'hatch was open.
Conversely, the clearance coordinators failed to question the maintenance individuals about the status of', the circulating water pump 2-2 work prior to issuing. the. clearance'to de-water the 2-1 suction bay.
Additionally, the auxiliary operator opening the cross tie valves failed to completely assess the consequences of that action by "double-checking"-the flow,of water into the 2-2 suction bay.
Had the operator observed the flow,'of water into the 2-2 bay, as good practice would suggest, the observed flow might have been diagnosed as excessive and corrective actions could have been immediately initiated.
In discussion with licensee personnel, the inspector concluded that.
schedular pressures to complete Unit 2 work items impacted on the performance of plant personnel, and reduced the licensee's capability to effectively control Unit 2 plant systems.
This finding was discussed with the licensee's plant and corporate management, the licensee has agreed to evaluate the effect of schedular constraints on plant operation.
b.
Containment Ventilation S stem Isolations On July 2, 1985, while Unit 1 was in Hode 1, a containment ventilation isolation signal was generated at the Unit 1 facility as a result of a spurious spike on containment air particulate radiation monitor RE-11.
The spike was determined to be caused by random induced noise, and the signal was reset within five to ten minutes.
Mith the exception of the RE-11 isolation valves, no containment ventilation isolation valves actuated, since they were in their normally closed position.
However, due to the minor significance of this event, plant operators failed to realize that under strict interpretation of 10 CFR Part 50.72, the NRC should
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have been notified of this ESF actuation within four hours.
During a subsequent review of the plant logs, the licensee identified this reporting failure and notified the NRC about ten and one-half hours after the ESF actuation.
As corrective action, the Senior Operations Supervisor issued a
memo to the shift. foremen which 1)
contained excerpts from the TS and FSAR defining ESF systems, and 2) instructed the SFM to be conservative in reviewing plant incidents for reportability.
In accordance with 10 CFR Part 2, a
notice of violation will not be issued by the NRC, as this event was 1) identified and reported by the licensee, 2) of low severity, 3)
corrected, including measures to prevent reoccurrence and 4) it gas not the subject of a previous violation.
On July 5, 1985, while Unit 2 was in Mode 5, a second containment ventilation system isolation occurred on Unit 2, which required a
4-hour Significant Event Report to the NRC.
In this case, containment isolation was caused by a spurious spike in the plant vent gaseous radiation monitor RM 14A.
Only the vent monitor isolation valves changed position (similar to the previously described RE-11 event).
The spike was believed to be caused by noise which resulted from the operation of electrical disconnects in the 500 KV switchyard.
NRC notification was made in accordance with applicable regulation.
On August 5, 1985, a third automatic containment ventilation isolation occurred while Unit 1 was in Mode 1, as a result of personnel and procedural errors.
This event occurred after containment air radioactive gas monitor RM-12 was removed from service for maintenance.
RM-12 was taken out of service, and the containment ventilation isolation signal leads to the SSPS were lifted in accordance with STP I-100Bl "...RM-12 Removal From Service."
Detector cable tests, and repairs were conducted under one section of STP I-100B3.
This procedure required deenergizing the RM-12 monitor by removing the moni:tor's control power fuses.
After cable repairs were completed, the monitor was being returned to service in accordance with STP I-100B4 "Reinstatement to Service:...RM-12."
This procedure required re-supplying control power to RM-12, and stipulated reconnecting the containment ventilation isolation signal leads previo'usly lifted in STP-100B1.
The technicians re-supplied power',
'warm'ed ug RM-12 for a period of 30 minutes (as required by STP X.-,lOOB4), and..reconnected:
the signal leads to the fSPS.
Howev'er,, the techni'cians't this point realized the repaired detector cable had not'. been connected.
This oversight.
occurred since STP I-100B3 d'id not have a step in the "Cable Integrity Tests" section to reconnect the cable.
This step was included in a different section of the STP which'was not used on this occasion.
Having realized thi's detector cable was not connected, the technicians de-powered,'RM-12 in order to safely reconnect the cable.
However, they failed to realize that a
containment ventilation isolation signal would be generated on a loss of power to RM-12, since the leads to the SSPS had been reconnected.
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As corrective action, the licensee intends to revise the cable integrity tests section of STP I-100B3 to indicate that the cable should be reconnected.
The inspectors will provide followup of corrective actions taken.
'n August 9, 1985 a fourth containment ventilation j.solation occurred on Unit 2, while trouble shooting the cause of a high radiation annunciator.
Since none of the radiation'monitors indicated a high.radiation alarm, the individual monitors were being reset sequentially.
When RM-14A was reset, a containment ventilation isolation resulted.
The licensee has formed a task force to analyze the cau's'es of the frequent containment ventilation; isolations; the results of their findings will be monitored as part of the routine followup inspection.
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Accumulator Outlet Isolation Valve Breakers During a monthly surveillance, with Unit 1 in Mode 3, the licensee identified that all four accumulators were technically inoperable since the assumulator outlet isolation valve operator breakers had not been sealed in the open position, as required by TS Surveillance Requirement 4.5.1.l.c.
The isolation val'ves were in the open position, and the operator breakers were also opened.
However, the breakers were caution tagged open, rather than sealed open as required by the TS.
After discovery of this event the breakers were sealed open in accordance with the TS.
This event was caused by a conflict in procedures and a misunderstanding by plant. operators regarding the requirements for the use of seals.
Plant operators believed that caution tagging the open breakers fulfilled the TS requirement of "sealing the breaker in the open position."
In discussion with operations management, the inspector clarified that sealing must be accomplished by installing a physical barrier to prevent inadvertent change of the breaker position, so that two separate actions must be taken to change breaker position (remove the seal and then actuate the breaker).
A plastic seal would satisfy this requirement.
To prevent recurrence of this event, the licensee issued an
"On-the-Spot Change" to OP 1,-1 "Plant Heatup from Cold Shutdown to Hot Standby" to specify installation of seals on the breakers.
A memo to the SFM was also written to advise the operating crews that caution tags are not a suitable replacement for the installation of plastic seals.
The licensee further installed labels on the Unit 1 and Unit 2 breaker panels specifying the accumulator isolation valve operator breakers to be racked out and sealed when the'nit is in Modes 1 and 2, and when RCS pressure is above 1000 psig in Mode 3.
In accordance with 10 CFR Part 2, Appendix C, no notice of violation will be issued foz this violation of the TS, since the licensee has met the test conditions of Appendix C, Items V.A. (1) through (5).
No violations or deviations were identifie p'
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4.
Maintenance p4 M
The inspectors observed portions of, and reviewed records on, maintenance activities to assure compliance to approved pro'cedures, technical specifications, and appropriate 'industry codes and standards.
a.
Auxilia Buildin Ventilation Charcoal Filter Maintenance The seal interface on the subject filter bank for Unit 1 were tightened.
The work was in accordance with approved maintenance shop work follower and the system was tested'and returned to service.
b.
Di ital Rod Position Indication Maintenance Trouble shooting of the subject, Unit 2 maintenance activity was observed by the inspector.
Administrative controls were established and followed, i.e., information and caution tags, as well as, clearance.
This work did not resolved the deviations that have been observed in the digital rod position indication system on rod C-9.
Work will continue to resolve the problem that is similar to a
problem that was resolved in Unit 1 after startup testing on the system.
c.
Char in Pum 2-3 The initial disassembly of the 2-3 reciprocating charging pump was observed by the inspector.
The charging pump pinion gear was broken and extensive damage of crank shaft bull gear had occurred.
The inspector observed lifting and rigging techniques and verified that proper clearances were in effect.
No violations or deviations were identified.
5.
Surveillance By direct observation and record review of licensee surveillance testing, the inspectors verified compliance with TS requirements and implementating plant procedures for the following item:
Ion Chromato ra h Calibration The inspector observed portions of the daily calibration of the ion chromatograph.
A standard sample was analyzed with the ion chromatograph to verify calibration.
The technician understood the procedure and conducted the calibration in accordance with Chemical Analysis Procedures B-21 and C-60.
The results were documented and reviewed in accordance with plant procedures.
b.
Auxiliar Buildin Safe uards Filter Ieaka e Test This test was conducted in accordance with STP M-3A.
The test includes measurement of freon concentrations as a function of time to establish the amount of leakage around the subject filters.
The
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data evaluation by the licensee's Plant Engineering staff did not include the affects of a residual concentration of freon from a previous test two days earlier, nor did it it correctly establish the point of "break-through," i.e., the point at which freon passes through the filter bank.
This data required analysis by "industry experts" to establish the correct leakage evaluation.
The test demonstrated compliance with TSs allowable leakage rate.
The licensee's engineering department has performed additional tests to identify the cause of the incorrect data evaluations.
Chemical cleaners used in the auxiliary=building were determined to affect the licensee's monitoring equipment.
Also, the licensee performed methol iodide tests to verify charcoal filter effectiveness and has sent charcoal samples offsite for analysis of potential contaminants.
The licensee believes they have an understanding of the data discrepancies and are pursuing long-term resolutions and, test changes.
Calibration of Steam Generator Slow and Pressure Channels The inspector observed selected portions of the calibration of the protection and alarm functions for the steam generator flow and pressure channels on protection set II, in accordance'pith STP I-12B6.
This calibration was,performed in conformance with TS requirements and was reviewed and 'approved by the licensee.
Equipment used for the calibration gas itself calibrated. 'imiting Conditions for Operation were satisfied as acquired by action statements on removal from'sexvice'nd',r'einstatement to service of the subject instrument channels.
'The t'echnicians, understood and performed the calibration in accordance".with the STP,.
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li Routine Shift Check Re uired b.I;icenses The inspector observed portions 'of the routine 'shift check on Unit, 1.
This test was co'nducted iq,.accordance with STP I'-lA.
The test included two basic types of checks:
(1) Channel checks, and (2)
verification that a condition parameter meets TS requirements.
The ACO understood the procedure,and conduct'ed<,the surveillance in accordance with the procedure.
The results'ere documented and signed by the ACO.
Diesel Generator l-l A surveillance test of DG l-l was conducted, in accordance with STP M-9A.
The required starting time of less than 10 seconds was not obtained using one set of starting air motors.
A second set of starting air motors was subsequently used to obtain the required starting time.
As required by STP M-9A an AR was written to report that, two sets of air motors were used to obtain a less than
second start.
Also as required by STP M-9A a second AR was written to report a low lubricating oil temperature.
The steps of the STP were properly followed and the SFM declared the l-l DG operable upon successfully completing the one hour load ru P
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No violations or deviations were identified.
6.
Routine Ins ection a
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Master Com letion List Resolution of all mode-specific items in the MCL is required as a
condition of the Unit 2 license.
In this inspection period, the MCL has been reviewed and tracked by the inspectors in order to verify completion of those items required prior to entering Hodes 2, 3, and 4 of reactor operation.
The licensee has addressed all Mode 2, 3, and 4 requirements identified within the HCL and has scheduled or completed all subsequent items.
b.
Power Ievel Plateau Data Review - Unit 1 The inspectors evaluated test 'results for the following startup tests:
Power Coefficient Measurement, Plant Shutdown from Outside the Hain Control'oom Net Load Rejection f'rom 100/ Power Natural Circulati'on Tests, These tests were verified to be complete with all identified anomolies appropriately dispositioned.
Additionally, at each power plateau (i.e., 15/, 30/, 50/, 75/,
and 100@ the inspectors determined that applicable t:est'esults were 'reviewed by the PSRC to confirm existing and predicted plant performance.
PSRC authorization, prior to proceeding with each sequential power plateau, assured plant operation continued in an expected safe and controlled manner in full compliance with all applicable TS.
The inspectors also verified that selected test results were reviewed and accepted by the licensee, e.g.,
pseudo dropped rod test procedure 42.3, vibration monitoring test procedure 7.7, and load swings test procedure 43.1.
Furthermore, the inspectors confirmed by direct observations or review of selected procedures that the licensee conducted and evaluated required core performance tests (e.g., reactor heat balance, RCS flow measurement, flux distribution, RCS leakage, etc.)
and plant radiological surveys at each power plateau.
Finally, the inspectors reviewed the licensee startup test report supplement 2 dated July 26, 1985.
This report complied with TS requirements and accurately described Unit 1 test program.
c>>
Pre-Critical Test Mitnessin
- Unit 2 Pre-critical tests observed included RCS leakage, source range monitor calibration/response, control rod drop times, reactor protective system response, and pressurizer pressure and level control tests.
During the performance of Unit 2 pre-critical tests two instances of failure to follow startup test procedures or cautions were observed by the inspector.
Startup Test Procedure
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36.1
"Rod Drive Timing Test" required rod banks to be left at five steps after each rod in the bank had been timed; also, a precaution in the test instruction section stated rods should not be driven below five steps.
Contrary to this procedure the inspector observed one shutdown bank to be driven to zero steps.
A second instance occurred during the performance of Test Procedure 36.3,
"Rod Drop Time Measurements" which included a caution to drop rod H-8 first while timing control bank D rods.
Contrary to this caution the inspector observed H-8 to be the last rod to be dropped during the hot standby position of this procedure.
While these two instances posed no safety concern they do indicate a
lack of attention to detail while performing startup testing and are typical of other test procedures observed during the pre-critical test witnessing.
The licensee's lead startup engineer has issued a
memorandum reemphasizing the need for strict procedural compliance; and, the Operations Manager has discussed this need with his personnel.
Recent observations by the inspectors show improvement in this area; however, procedure compliance will continue to be followed closely during future startup activities by the inspectors.
d.
Pre-Critical Data Review - Unit 2 Test results were examined for RCS leakage, source range monitor calibration/response, control rod drop times, reactor protective system response, and pressurizer pressure and level control tests.
Additionally, the inspector verified that the licensee reviewed and evaluated test results for incore neutron monitors, RCS flow and coastdown characteristics, pressurizer pressure control, loose parts vibration monitors, and control rod drive and position indication systems'o violations or deviations were identified.
7.
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endent Ins ection Seismic Induced S stems Interaction Pr'o ram II The inspector observed selected modifications for, the subject program.
Specifically, modifications tp the income flux monitor seal table and path selector support struc'tures were examined on Unit 2 (these modifications are also the'topic of Information Notice 85-45).
The change was configured as requ'ired by the design change documentation.
Appropriate procedure changes for the modifications were completed.
System Inter'action Program other modifications on the incore flux monitoring "system were also observed.
This closes open item 85-05-02 and IN 85-45.
b.
ualit Hotline The inspector reviewed twelve Quality Concern Summary Reports that were recently completed by the Quality Hotline in this inspection period, in addition to continuous sampling of such items throughout
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the year.
These reports showed that the investigations of identified concerns were performed in accordance with Quality Hotline procedures.
For example, individuals that raised concerns were contacted, when their identity was known, and the resolution of their concern was discussed.
Also, the inspector's review found that the Quality Hotline investigations identified regulatory requirements, where applicable, and,assured compliance to the requirements.
Finally,,the inspector di,scussed the procedures with Quality Hotline personnel, to assure that'they.,w'ere understood and implemented.
Mana ement Assessment"'of Technical Review Grou, Effectiveness f
t The Plant Manager issued a memorandum,'on 'July 8, 1985 to the Assistant Plant Managers and Department.Mana'gers that reemphasized guidance on the conduct of the TRG. 'This memorandum specifically addressed the concern of open, item 85-25-01.
The memorandum restated that "the person most closely involved" in an issue be present at the TRG whenever possible,and ithat the chairman of the TRG should assure that input from that person be considered.
The inspectors will continue to observe TRG meetings as part of the routine inspection program.
Of particular note was the TRG on a containment ventilation isolation that follow'ed the precepts of the plant managers memorandum.
This closes'he open item 85-25-01.
Boron Dilution Events Generic Letter 85-05 requested that the licensee
"assure itself that adequate protection against boron dilution events exists in its plants."
The licensee's general office technical staff's evaluation of the generic letter was reviewed.
This evaluation addressed three specific concerns from the generic letter:
1)
RHR over pressurization for a boron dilution event is mitigated by a combination of RCS low pressure overpressure protection system and RHR relief valve, as well as, a backup of interlocks to assure that the RHR system is isolated from the RCS on high pressure conditions, 2)
distinct positive alarms and indications (e.g.,
high flux at shutdown alarm and source range count rate)
are provided for operator action as outlined in the FSAR, and 3)
the lack of redundancy of alarms and TS for boron dilution events is considered to be adequately addressed by emergency procedures and operator training.
The inspector's review found that the licensee addressed the generic letter concerns.
This review closes open item GL-85-05.
Postin of NRC Form 3 The inspector examined the licensee's posting of Form 3 'for compliance with 10 CFR 50.70(e).
The inspector observed 16 postings of NRC Form 3.
Discussions with several employees during the inspectors tour showed that these employees were aware of at least one posting location.
These postings were observable with little effort to or from any work location onsite.
The licensee controls and updates the postings on the bulletin boards in the NPO
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administration building and at'he main elevator to the turbine and auxiliary buildings'.
Further, the inspector confirmed that site training for protected area escorted access includes a handout of NRC Form 3 and a
discussion posting locations.'or'.restricted area unescorted access, a handout with a signature sheet promises compliance to the provisions of the handout.
This handout includes NRC Form 3.
For escorted access to the protected area, an NRC Form, 3 has been included in the handout offered to,the< individual.
This training proceduralizes (NPAP B-252) and encompasses all individuals subject to
CFR 50.7(e).
Therefore, the actual postings combined with required training program assure that employees not only have NRC Form 3s available, but that they have opportunity to be appraised of the contents of NRC Form 3 by training.
No violations or deviations were identified.
8.
Three Mile Island Task Action Plan Followu I.C.1 Short-Term Accident and Procedure Review (closed)
This item consists of procedure reviews and revised emergency operating procedures verification.
The procedure reviews were done generally for both units and can be closed for Unit 2 based upon the Unit 1 review (IR Number 50-275/81-24).
The full implementation and training of the revised emergency operating procedures were documented in a PG&E letter dated March 26, 1985.
The conditions of this letter have been verified, i.e., the licensee's procedures are consistent with the Westinghouse Owner's Group requirements and training has been completed.
I.C.8 II.F.1.1 Monitor Selected Emer enc Procedures (closed)
and Accident Monitorin Procedures closed These procedure reviews have been completed for Unit 1 and are applicable to Unit 2.
Therefore, these items are closed based on IR Numbers50-275/80-21 for I.C.8; and 50-275/83-32 for II.F.1.1.
II.B.4 Trainin to Miti ate Core Dama e (closed)
This item is also applicable to both units, since this training is generic for Diablo Canyon.
Therefore, it can be closed based on IR number 50-275/81-19.
III.D.l.lPrimar Coolant Outside Containment (closed)
Unit 1 close-out of this item verified the program and implementation (IR Number 50-275/82-29 and 50-275/84-10).
The
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k LI ation Followu Task:
Alle ation or Concern No.
1720 and 1721 ATS No.:
RV-85-A-046 a
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Characterization I
An alleger asserts that PG&E never thought about seeing if Hilti Kwik Bolts were installed properly and stated that he found bolts welded to the backside of base plates.'he alleger goes on to describe a situation on hanger 50-123R wherein hanger 50-123R had anchor bolts that were not properly installed, i.e.,
a stud *with a bolt on either end of the base plate was installed with concrete chipped out to allow for the bolt and stud on the bottom.
The alleger also asserts that he found sabotage issues in this situation which PG&E never addressed.
b.
Im lied Si nificance to Desi n Construction and 0 erations c ~
The allegation implies that improper installation techniques of anchor bolts for base plates could result in hanger configurations that do not satisfy design requirements for safety related functions.
Assessment, of Safet Si nificance The licensee had previously identified, in Harch of 1976, hanger anchor bolt discrepancies.
Region V was aware of the situation and followed the licensee's resolution of the anchor bolting issue.
The Region's involvement was documented in NRC Inspection Report Nos. 50-275/76-14, 77-03, 77-11 and 50-323/76-05, 77-01, 77-03, 77-06, 77-08 and 77-11.
In addition, NRC Inspection Repoit No. 50-075/77-17 documents NRC findings related to a situation wherein an alleger asserted that anchor bolts had been cut short or omitted to avoid drilling rebar or resetting the hangers or racks.
Further, the NRC closely followed the licensees actions to address the issues of IE Bulletin 79-02 and documented the findings in NRC Inspection Report No. 50-275/80-18.
The inspector reviewed the documentation on the hanger 50-123R construction in addition to observing non-destructive examination of the bolt length to verify embedment depth.
Initial construction of hanger 50-123R was accepted on August 6, 1976.
The first modification documented in the work package on the subject hanger showed that a reinspection program on shell type anchors resulted in the installation of an additional two stud type anchors in accordance with Pullman Power Products equality Assurance Instruction Number 98 Revision II.
This work was,completed and accepted on July 19, 1977..
The next modificator.on "was accepted, on August 17, 1979 and removed clamps for rupgu're restraint work,
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however it did not involve work on the anchors or studs.
The next.
work, that was completed on January 7,
1981, consisted of rupture restraint work and installation of leveling shims rather than nuts to respond to NRC Inspection and Enforcement Bulletin 79-02.
The last work package included chipping of grout to inspect the stud type anchor.
This inspection damaged the studs and required replacement that was completed and accepted on April 14, 1983.
This review of construction documentation on this hanger showed that quality related controls and verifications were performed as required.
The review did not disclose any evidence to indicate that any anchors or studs were ever found improperly installed.
d.
To provide added assurance that the studs were properly installed, the inspector requested the licensee to perform ultrasonic (UT)
measurements of the stud lengths.
The inspector observed these measurements on July 31, 1985.
The UT device was calibrated using a
standard block and was also verified with bolts similar to those installed in the hanger.
The measurements showed that the bolts were full length as specified by'he installation requirements.
The UT device was then verified to still be calibrated with 'both the standard block and the bolts'tha't were similar to those installed on the hanger.
ld Conclusion and Staff Position-The staff concludes that the licensee had c'onsidere'd whether anchor bolts were installed properly and had "conducted significant
.
verifications to provide such assurance.
1'he work documentation for hanger 50-123R showed that all steps were complied with in accordance wiCh quality control and assurance procedures.
While the UT test did not verify that the anchor bolts were installed with an anchor 'or shell, it did verify that the bolt lengths were as specified.
Based on the visual inspection and MT tests, the staff believe that the bolts were properly installed in anchors or shell.
The staff concludes that there was no indication of sabotage.
The allegations were not 'substantiated.
e.
Action Re uired No further action is required.
Task:
Alle ation or Concern No.
(none)
ATS NO:
RV-84-A-114 a
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Characterization Pullman Power Products (PPP) deficient condition notifications (DCNs) initiated by gC inspectors were allegedly "voided" by PPP QC supervision and then not properly retained in the PPP DCN files.
(This was a general concern identified during discussions with allegers.)
IS Jl sS
Im lied Si nificance to Plant Desi n Construction or 0 eration DCNs are used to document nonconformities in the installation and inspection of piping, piping supports, rupture restraints and other miscellaneous installations.
The nonconformities include incorrect documentation as well as deviations from prescribed procedures, codes, specifications or work processes.
Voiding DCNs, which identify valid nonconformities, could result in plant structures which might not be capable of performing their intended safety functions.
Failure to properly retain voided DCNs eliminates 1) the record of the reported deficient condition and 2) the evaluation of why the nonconforming condition does not exist.
This suggests that actual nonconformities could be overlooked for corrective action, and subsequent QA evaluations of program effectiveness may result in inappropriate conclusions.
Assessment of Safet Si nificance The staff, in response to this concern, examined the PPP DCN filing system.
The files were observed to be organized such that DCN's written by a particular inspector were filed together in numerical order.
PPP recently completed an audit of the DCN files in preparation for quality document turnover to the licensee.
The inspectors reviewed DCN logs for seven PPP QC inspectors, and selected over 300 DCNs from PPP files for review.
Of the more than 300 DCNs selected for review, none were found to be improperly voided.
For those DCNs that were issued and were not in the files, the file contained an explanation for the missing DCNs.
A discussion of each DCN file reviewed is provided below.
(1)
QC Ins ector A
The QC Inspector A DCN log (QC inspector's log) was compared to the DCN log maintained by the PPP QC office (QC 'specialist's log).
The QC inspector's log indicated "that, he had issued DCNs. 001 through 021.
The QC specialist's log listed DCNs 001 through 023.
This discrepancy was apparently the result 'of 'the QC '3.nspector's failure to enter the DCNs in his log.
'He also did not enter DCN,012 into his logs.
All twenty-three DGNs, reviewed by the NRC iinspector, were found to be originals, with tlie exception'of DCN,O'18.
DCN 018 was not in the DCN file, and no information referring '-to DCN 018 was entered on the QC specialist's DCN log. The,QC inspector's DCN log identified DCN-18 as having to do with an arc strike,and weld spatter on civil steel.
In discussing this situation with PPP QC personnel, the NRC inspector'.determined that the QC inspector identified discrepancies (arc strike and weld spatter)
were corrected "in process" during subsequent modifications.
Apparently, the QC inspector was aware of the corrective actions in process, and accordingly chose to not send the DCN to the QC specialist.
Voiding rationale for all voided DCNs were reviewed by the NRC inspector and found to be acceptable.
No voided,'unfiled DCNs were identified during this revie /
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C Ins ector 8 The numbers of DCN entries, in,the QC inspector 8's log agreed with the gC specialist's log; both indicating sixty-one.DCNs.
All sixty-one log entries identified by the gC inspector, were reviewed by the NRC inspector.
The (}A specialist's log identified that nine of the inspectors DCNs had not been received fog filing.
These 'situatio'ns'.were addressed individually by a Memorandum to File, dated May 9, 1985.
The inspector examined the PPP rationale for dispositioning each identified missing DCN and found the, dispositions to be reasonable and appropriate.
Further, the reasons,.associated with the voiding of voided DCNs were examined and found to be appropriate.
The inspector considers that a more tim'ely analysis of the DCN files would have been appropriate; however, the inspectoi also considers that the findings and dispositions of the analysis'do not suggest a
flaw in the DCN identification and.correction process employed by ppp.
The PPP (}A manager indicated that this DCN file had been stored in a fire proof cabinet for approximately ten months after the gC inspector terminated employment.
This storage was to assure control of this DCN file.
The gA Manager pointed out that the file was used frequently and its location was known to five individuals in the gA department.
The storage location was consistent with the procedural requirements (ESD-240, Section 11.4) for storage of DCN files.
Permanent storage of the completed DCN files was accomplished by the licensee who conservatively stored them in their vault.
This type of storage was not required by ESD-212 which provides for permanent vault storage of DRs and specifically excludes DCNs.
This method of DCN storage and the distinction between DRs and DCNs (discussed later in this text) is consistent with the definition of quality assurance records in ANSI N45.2.9-1974.
(3)
C lns ector C
(}C inspector C's file was examined in a manner so as to protect the individual's identity, at the individual's request.
The result of the NRC's examination of his DCN records indicated that PPP did not void the individua'l's DCNs, as alleged, and then prohibit the filing of the DCNs.
Several DCNs, logged on the gC inspector's log, appeared to be missing from the file.
However, upon closer examination, the logged DCNs were found to pertain to arc strikes.
PPP procedure ESD-240 "Field Procedure for Non-Conformance Reporting" established the DCN system, and required the keeping of DCN logs.
Section 1.0 "Scope" of this procedure required arc strikes to be reported in accordance with ESD-271.
ESD-271 Sections 5.0 and 6.0, specified that arc strikes are to be reported on arc strike forms, logged on arc strike logs, and forwarded 'to PG&E.
Thus, the gC 'inspector entered the arc strike forms in his DCN log in error.
The NRC inspector verified that the arc strike forms had been received by PGSE and were retained in the PGSZ records syste E I gl I.
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The few remaining voided and missing DCNs were voided and lost.
The gC inspector, by a filed memo, implicitly appeared to agree that no further action was needed on the lost DCNs.
This explanation addressed the absence of DCNs from the file.
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In reviewing this DCN file, the inspector identified that no (}C inspector's log was available in the file.
PPP management reviewed the QC inspector's daily inspection log, ahd the daily inspection logs of individuals who worked with the inspector, for any evidence of the existence of a gC inspector's log.
Additionally, PPP management reviewed the DCN files of the individuals who worked with the inspector, and questioned the inspector's QC leadman in a attempt to locate the missing log.
No recollection or evidence that the gC inspector kept a
DCN log was obtained.
However, a log of the inspector's DCNs was kept by the (}C specialist.
This log indicated seventeen DCNs.
DCN 003 was voided, but the log indicated it was dispositioned in DCN 209 which was written by another QC inspector (this was verified by the NRC inspector).
DCN 004 was not in the file, and the (}C specialist's log contained no entry for this DCN.
The NRC was unable to ascertain whether DCN 004 ever existed; however, in view of the completeness of the (}C Specialist's log, and the status of other DCN files, the inspector does not feel that the missing DCN cause to be a critical void so as to invalidate the total PPP DCN retention process.
The remainder of the DCNs were observed to be originals, correctly logged and in the file.
The DCN files of three additional inspectors were also reviewed by the NRC inspectors.
Of the 158 additional DCNs reviewed, no instance of voided DCNs not being retained in the DCN file were observed.
Procedure ESD-240 specified that identified discrepancies in documentation and/or hardware, which require PGSE approval, be reported on Discrepancy Reports (DRs).
Discrepancies of this nature include identification of violations of PGK specifications, or violations of PPP ESD procedures which can not be resolved within PPP.
No corresponding need for any DRs were identified by the NRC inspectors in the review of DCN subject matter.
Procedure ESD-240 also required retention of original DCNs in the DCN files.
In the few identified instances when the entire DCN in the file was not original, a duplicate copy was provided.
Section
"Requirements for Collection, Storage, and Haintenance of equality Assurance Records for Nuclear Power Plants" specifies
"records may be originals or reproduced copies'
"
In questioning PPP why ESD-240 required retaining originals, PPP indicated that retention of originals was specified only for clarity during reproduction.
Accordingly, the NRC inspectors deemed retention of a few duplicate DCNs, in lieu of original DCNs, was permissible.
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The NRC inspectors determined that. additional discussions with concerned individuals about alleged missing and voided DCNs was not warranted.
This determination was based on the lack of substantive findings from the above review, and the fact that ESD-240, Section 7.3.2 provides a method where the originator of a voided DCN can disagree with the determination and forward his disagreement to the PPP field QA/QC manager.
No indication of this type of action by QC inspectors was identified by the inspectors during this review.
d.
Staff Position Based upon the staff's inspections, the following conclusions were reached:
(1)
There was no evidence to substantiate the allegation that PPP wrongly, and with a desire to cover up identified discrepancies, voided or failed to file DCNs which were written by QC inspectors and; (2)
Considerable evidence exists indicating that PPP took extraordinary measures to locate missing DCNs; and, failing to locate the DCNs, documented in the file, their assessment of each such situation in the file.
f Thus, the staff concludes that the;:PPP DCN files comply with the intent of ANSI standards and PPP procedures, recognizing that perfection was not always obtain'ed in 'the case of some'n issuing DCNs.
I f
No further action is required.
ll.
Technical Assistance Contract - Contractor A,'Cbrrectxve Action Eollowu for Construction t
pl A contract has been awarded by NRC Region V to pi;ovide assistance in the inspection of allegations.
An independentiinspectio'n item, that was identified by contract personnel and followed by contract personnel and the inspectors, is addressed below.
During the review of allegation 0833, it was observed, that PPP internal field QA audits apparently did not follow-up on previous audit findings to verify whether corrective action taken was effective.
PPP internal audit 885 and gll8 (from the review of allegation 0833) were re-reviewed with PPP QA/QC personnel.
Audit action request f/1-4 of audit report f/85 was used as an example of no corrective action verification evidence.
The PPP internal auditing procedure contradicted PPP corporate QA audit requirements.
In the limited sample of audits reviewed, there was no apparent evidence of verification actions taken in the audit record files reviewed.
Therefore, the methods by which PPP verifies that the corrective actions were effective as required by ANSI N-45.2.12 was examine I r
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First, the PPP procedures were reviewed for internal field QA audit requirements.
It was'equired in paragraph 10.2 (audit follow-up) of ESD-263 to "... assure that corrective action was implemented as scheduled...,"
but it did not mention verification of corrective action effectiveness.
In the same procedure, footnote jjl8 to the instructions for filling in the Audit Action Request form states that the follow-up shall consist, of a "...Report by Auditor of effectiveness of implemented corrective action...."
Additionally in PPP procedure KFP-18, "Audits,"
paragraph 18.9.4 states that "A follow-up audit will be conducted to assure that corrective action has been taken."
PPP personnel acknowledged that field internal audits never re-audited previous audit findings during current audits; and that PPP relied solely upon the footnote jjl8 block signature as complete evidence that corrective action effectiveness was verified.
Further, PPP felt this was adequate, because the PPP internal QA auditors were trained in the contents of the QA procedures and therefore understood 'the intent of procedural requirements.
f Three PPP internal auditors training records were.reviewed.
In all cases, the training records contained 'the'>>required reading list (ANSI N 45.2 and daughter documents.,
NCA-3800 etc.,), auditor qualifications per ANSI N 45.2.23, training courses complet'ed, and copies of tests taken.
All records reviewed appeared to be acceptable.'
The last area inspected was the function of the PPP,'corporate auditors on the Diablo Canyon site and their relationship to the functions performed by the internal field QA auditors.,
The requirements for performing internal audits of field QA programs by the PPP corporate quality engineering group was defined in ESD-274.
This procedure for Diablo Canyon consists of a cover sheet which incorporates PPP corporate procedure jjXVIII-1in its entirety.
Of specific interest in the procedure were paragraph 6.1.5, 6.1.6, and 11.3 which clearly require verification of corrective action in the annual announced audits and also in the periodic unannounced audits.
"Corporate 'Audit 87177-1-85 was checked to assure that the corporate auditors were complying with ESD-274.
It was deteimined that all audit action requests from previous audit 87177-1-84 were assigned for re-audit; and that specific audit action requests (jj3, 8, and 9) from this previous audit were re-audited.
For each of these audit action requests the corporate auditors verified that the corrective action was effective.
lt was concluded by the inspector that PPP corporate audits meet the requirements of criteria XVIIIin Appendix B of 10CFR50.
The field internal auditor actions provide more of a surveillance function than providing a programmatic assessment of the field QA program.
This was based upon the description of the responsibilities of a field auditor provided by the PPP QA manager.
The PPP corporate audit requirements were reviewed and specifically met the requirements of ANSI N 45.2.12.
The PPP field audit group had procedures similar in content to the corporate, but requirements for re-auditing appeared to be inconsistent.
Specifically, the allowance of a single signature in block j/18 of the audit action request form to acceptance of two distinctly different re-audit responsibilities; i.e., assure implementation of corrective
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actions, and verify effectiveness of corrective actions.
This concern is considered to be closed.
No violations or deviations were identified.
'2.
Licensee Event Re ort Follow-u (Units 1 and 2)
Circumstances and corrective actions described in the following LERs, listed below, were examined.
Review of the IERs, and reporting to NRC within required time intervals by the licensee, was verified by the inspectors.
The inspectors also ensured corrective actions were established and applicable events were accurately described.
Accordingly, the following IERs are considered closed:
Unit 1:
85-19 Missed surveillance on incore thermocouples due to administrative oversights 85-20 Start of wrong Unit diesel generator (discussed in report NRC inspection 85-25)
85-21 Power and axial flux difference xenon transient (discussed in NRC inspection report 85-25)
85-22 Accumulator outlet isolation valve operator breakers seals not in place (discussed in the Event Followup section of this report)
85-23 Spurious containment ventilatio'n isolation from gaseous radiation monitor RE-ll (discussed in the Event Followup section of this report)
Unit 2:
85-01 Containment ventilation isolation on noise in the plant vent gaseous radiation monitor R1 14A due to switching of power transmiss'io'n 3:ines (discussed in,the Event Followup section of this report)
85-02 Safety injection signal 'on,'miscommunication between operator and IRC techn'ician,,
13.
Mana ement Information S stems and Techni'cal Review Methods the licensee employs within the plant.for the coordination of work planning and technical review 'of problems was examined by discussion with plant management, engineers, schedulers, shift foremen and control operators, by review of implementing procedures for the identification and processing of Action Requests and quality evaluations, and by attending several meetings, including a shift turnover, startup meeting and Plant Manager's morning meetin I V
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lt, Principal methods utilized to coordinate work activities include an 8:00 a.m. Startup meeting to coordinate activities for Unit 2 (includes management, engineers, coordinators, craft supervisors, operations, etc.), Plant Managers morning meeting at 8:30 a.m. to appraise the plant manager of plant status and forth coming events,,(includes presentation by the three Assistant Plant Managers),
oncoming shift briefing where the Shift Foreman review past events with the entire shift, Shift Orders, and significant turnover items (also,, each member of the crew discusses items of interest in his area of responsibility)-',
a Wednesday morning NPG Managers/Directors meeting where topics of general -interest are discussed with the staff by key managers from the. "City" or the I'plant, and on friday morning a plant staff meeting is held 'that includes NRC exit meeting, discussion of individual problems',,long'ange goal's, etc.
I Discussions with the Assistant Plant Managers disclosed that they kept themselves informed in a variety, of ways including the following:
Receipt of a copy of the summary logs from the Shift Zoreman/Control Operator.
Attendance at coordinators'eetings.
Visit Control Rooms on a daily basis.
Plant walkdowns approximately weekly.
Once a month spend full eight hours in requalification training.
Review of operating experience reports.
Review of reportable events.
Attendance at PSRC meetings.
Plant scheduling is coordinated through the Work Planning Center by
'tilizing of a computerized system for tracking all action items, including surveillance requirements.
Each department has a Senior Planner Scheduler and.a number of Planners who are assigned to the craft foreman.
The Operations Coordinator assigns priority to Action Requests, but these can be upgraded as plant needs dictate.
The program for full utilization of the planning center was still being developed, but in the meantime, the Action Request procedures appear to provide the necessary guidance for this activity.
No violations or deviations were identified.
14.
Exit On August 16, 1985, 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 II lE l
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American Nuclear Society
'merican National Standards Institute Action Request American Society of Mechanical Engineers Auxiliary Saltwater System, Auxiliary Feedwater Boric Acid Chemistry and Radiation Protection Containment Fan Cooler Unit Code of Federal Regulations Control Operator Control Room Ventilation System Chemical and Volume Control System Design Change Notice Digital Electro-Hydraulic Department of Engineering Research Diesel Generator Discrepancy Report Estimated Critical Position Emergency Offsite Facility Engineered Safety Features Federal Emergency Management Agency Fuel Handling Building Flow Control Valve Final Safety Analysis Report Government Accountability Project General Construction Gas Decay Tank General Office Nuclear Plant Review and Audit Committee Hot Functional Test Instrumentation and Control Inspection and Enforcement Institute of Nuclear Power Operations
Inspection Report
Inservice Inspection
Licensee
Event Report
Limiting Conditions for Operation
Level Control Valve
Liquid Holdup Tank
Lawrence Livermore National Laboratory
Ievel Transmitter
Master Completion List
Moveable Incore Detector
System
Mechanical Maintenance
Maintenance
Procedure
Magentic Particle Test
Minor Variation Report
Nondistructive Examination
Nuclear Engineering Department
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NPPR
NRC
OIR
OP
OPEG
OSRG
PN
PGGE
PPP
PSRC
PSI.
QAM
QCSR
QCl
RCCA
RBP
RVI,IS
SCO
SFM
SSER
SSPS
S/U
SUER
SWP
SWF
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Nuclear Plant Administrative Procedure
Nuclear Power Operations
Nuclear Plant Problem Report
Nuclear Regulatory Commission
Nuclear Reactor Regulation
Nuclear
Steam Supply System
Open Item Report
Operating Procedure
Onsite Plant Engineering
Group
Onsite Review Group
Pressure
Control Valve
Preliminary Notification
Post Accident Sampling System
Pacific
Gas
and Electric
Power Operated Relief Valve
Pullman Power Products
Pressurizer Relief Tank
Plant Staff Review Committee
Preservice
Inspection
Pressurized
Water Reactor
Quality Assurance
Quality Assurance
Manual
Quality Assurance
Procednrd
Quality Control
Quality Concern
Summary Report
Quality Control Instruction ',,
Radiological Controlled Ar'ea
Rod Control Cluster Assembly
Radiation Base Point:
Pump
Residual Heat Remov'al
Radiation Monitor
Reactor Operators
Reactor Vessel Ievel Indications, System-
Routine Work Permit
Senior Control Operator
Shift Foreman
Safety Injection
Safety Parameter
Display System
Senior Reactor Operators
Supplemental
Safety Evaluation Report
Solid State Protection
System
Surveillance Test Procedure
Start-up
Significant Operating Experience
Report
Special
Work Permit
Shopwork Follower
Temporary Instruction
Three Mile Island
Technical Review Group
Technical Specification
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