IR 05000275/1984022
| ML20098G472 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 09/24/1984 |
| From: | Crews J, Johnson P, Mendonca M, Padovan M, Polich T, Ross T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML20098G473 | List: |
| References | |
| 50-275-84-22, 50-323-84-12, NUDOCS 8410050031 | |
| Download: ML20098G472 (21) | |
Text
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UNITED STATES g
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NUCLEAR REGULATORY COMMISSION
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REGION V
$
,4 1450 MARIA LANE, SUITE 210
,o WALNUT CREEK, CALIFORNIA 94596
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SEP BG Y M Docket Nos. 50-275 and 50-323
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Pacific Gas and Electric Company 77 Beale Street, Room 1435 San Francisco, California 94106
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Attention:
Mr. J. O. Schuyler, Vice President Nuclear Power Generation Centlemen:
Subject: NRC Inspection of Diablo Canyon Units 1 and 2 This refers to a routine inspection, conducted by Messrs. M. M. Mendonca, M. L. Padovan, T. M. Ross, T. J. Polich, and J. L. Crews of this office during the period of July 1 through August 4, 1984. This inspection examined your activities as authorized by NRC License No. DPR-76, and Construction Permit No. CPPR-69. Discussions of our findings were held with Mr. R. C. Thornberry and other members of your staff at the conclusion of the inspection.
Areas examined during this inspection are described in the enclosed inspection report. Within these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observations by the inspectors.
No violations of NRC requirements were identified within the scope of this inspection.
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Pacific Gas and Electric Company-2-b i
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r Should you have any questions concerning this inspection, we will be glad to discuss them with you.
Sincerely,
/r T. W. Bishop, Director Division of Reactor Safety
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and Projects l
Enclosure:
Inspection Report
Nos. 50-275/84-22 and 50-323/84-12
REGION V==
Report Nos:
50-275/84-22 and 50-323/84-12
Docket Nos:
50-275 and 50-323
License No:
Construction Permit No:
CPPR-69
Lisensee:
Pacific Gas and Electric Company
77 Beale Street, Room 1435
San Francisco, California 94106
Facility Name:
Diablo Canyon Units 1 and 2
Inspection at:
Diablo Canyon Site, San Luis Obispo County, California
Inspectors:
[* I/~#[
M. M.gendonca, Sr.(Xesident Inspector
Date Signed
f~ $ HEY
M. M Padovan, Rer/ dent Inspector
Date Signed
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T. M.'Ross,'I{esident Inspector
'date tig'ned
DEIdwklu
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.T. J. Polich, Resident Inspector
Date Signed
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fechnicalAssistantto
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e Re
nal Administrator
Approved by:
["IY~M
P. H. Johnson / Chief
//
Date Signed
Reactor Projects Section 3
8410050031 840926
DR ADOCK 05000275
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. Summary:
Inspection from July 1 through August 4, 1984 (Report Nos. 50-275/84-22
and 50-323/84-12)
Areas Inspected: Routine inspection of plant operations, conditions..and
events; maintenance; surveillance; independent inspection; -and ~ follow-up of
open items, LERs, and enforcement actions. 'This inspection effort involved
447 inspector-hours for Unit I and 57 inspector hours for' Unit 2 by four
resident inspectors and one region-based staff member.
. Results: No violations or deviations were identified,
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DETAILS
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' Persons Contacted
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- *R'. C. Thornberry, Plant Manager
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R. Patterson, Assistant = Plant. Manager / Superintendent
J. M.1Gisclon, Assistant Plant Manager for Technical Services
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~*W. B. -Ka'efer, Assistant; Plant Manager ^ for Support Services
C. L. Eldridge, Quality Control Manager
- R. G. Todaro, Security Supervisor
. *E. M. Conway, Personnel and General Services
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D. B. Miklush, Supervisor of Maintenance
- J..A. Sexton, Supervisor of Operations
lJ. V. Boots, Supervisor of Chemistry and Radiation Protection
W. B. McLane, Material and Project. Coordination Manager
L. F. Womack, Engineering Manager
- B. W. Giffin,' Acting Instrumentation:and Control Manager
-E. T. Murphy, Regulatory Compliance Supervisor
C. M. Seward, Supervisor of Quality Assurance
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The inspectors interviewed several-other licensee employees including
shift supervisors, reactor and auxiliary operators, maintenance.
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personnel, plant technicians and engineers, quality assurance personnel
and; general construction personnel.
- Denotes those attending the exit interview on August 3, 1984.
2.
Operating Safety Verification
-a.
cDuring 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,
con a daily basis, the inspectors'observedi control room activities to
verify compliance with selected limiting conditions for operation as
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prescribed in the facility. Technical. Specifications (TS). ' Logs,
instrumentation, recorder traces, and other operational records were
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' examined to obtain information on plant conditions, trends, and
compliance with regulations. Shift turnovers were observed on a
. sample basis to verify that all pertinent information on plant
status was relayed. During each week, the inspectors toured the
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accessible areas of the facility. to observe the following:
-(l) General plant =and equipment' conditions.
(2). Surveillance and maintenance ' activities.
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-(3) Fire hazards and fire' fighting equipment.
(4) Ignition sources ~and flammable material control.
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(5) ' Conduct.of selected activities for compliance.with the
licensee's administrative controls and approved procedures.
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(6) Interiors of electrical and control panels.
(7)- Implementation of selected portions of the licensee's physical
security plan.
(8) Plant housekeeping and cleanliness.
(9) Operability of selected Engineered Safety Features (ESF)
systems by performing comprehensive walkdowns of the system's
components.
'The inspectors talked with control room operators 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.
No violations or deviations were identified.
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b.
Technical Review Group (TRG)
A_TRG meeting is convened by appropriate plant personnel to review
problems or incidents which occur onsite and appear to represent
a
potential nonconformance. Participating personnel are intended to
be knowledgeable of and responsible for the subjects involved. The
prime purpose of this meeting is to determine root causes, propose
corrective actions to preclude recurrence, and to evaluate the
event's reportability as a Nonconformance Report (NCR) and/or
Licensee Event Report (LER). TRG proceedings are required and
administered in accordance with Nuclear Plant Administrative
Procedure (NPAP) C-12, " Identification and Resolution of Problems
and Nonconformances."
The inspectors attended a number of TRG meetings. These meetings,
in general, appeared to provide timely and accurate resolution of
plant problems. However, in one instance, an independent
examination by an inspector revealed that a TRG did not correctly
establish the sequence of events for a particular potential
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nonconformance. As a result, some of the conclusions documented in
NCR #DCl-84-TN-N096 were inappropriate. This NCR was subsequently
evaluated and appropriate conclusions were drawn.
It should be
noted that the first conclusions were excessibly conservative in
nature in that the licensee had determined the condition to be
reportable when, in fact, it was not reportable.
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Plant management was informed of the discrepancy, and then made
aware of those primary contributing causes considered by the
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fnspectors to have created this situation. These can be paraphrased
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.as follows: (1) key involved personnel were not present at the TRG
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meeting nor were they required to be, (2) the TRG chairmen was not
specifically trained on responsibilities as a chairman, and (3) TRG
personnel did not come prepared to address the problem.
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Plant management has instituted a training program to assure that
these findings are resolved. The inspectors have reviewed this
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program and will continue to follow this under normal inspection.
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- activities.
No violations or deviations were identified.
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c.
Initiation of Control Room Ventilation Pressurization Mode
On July 15,-1984, in preparation for response time testing on the
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Unit' 2 Solid State Protection System (SSPS), jumpers were being
' installed on selected SSPS. contacts. These jumpers were being.
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~ installed so-that equipment common to both units would not actuate
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as'a result of' testing. To effect this deactivation, an SSPS
contact drawing was consulted to determine whether jumpers were to
be installed for normally closed contacts, or whether normally open
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. contacts were to be lifted. This drawing incorrectly indicated that
the contacts for initiation of the control room ventilation
pressurization mode were normally closed. When a jumper was placed
around these normally open contacts, a contact was subsequently
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= closed causing control room ventilation pressurization to actuate.
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The licensee reported this ESF actuation to the NRC's headquarters
' duty officer. The inspector's followup corroborated the licensee's
findings that the event;was'due to an incorrect designation of
contact position on Westinghouse prepared electrical drawing'
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No. 458828. A program to review related drawings and verify SSPS
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contact positions was conducted by the licensee. Except for one-
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other-incorrect contact designation on a plant electrical schematic,
all SSPS contacts were verified to be correctly designated. Based
on this review, the applicable drawings acceptably reflect'SSPS
contact position.
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Additionally, the inspector has reviewed operator response to the
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, event. The operators determined the cause of the event and
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' terminated the control room' pressurization mode in an acceptable
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No violations or deviations were identified.
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Inadvertent-Safety Injection-(SI)
The July 28, 1984, SI was initiated by a high steam flow signal
coincident with a low-low T
(setpoint is 543'F) in the reactor-
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coolant system (RCS). The $Ygh steam flow signal resulted from
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surveillance testing in progress. Although RCS temperature was
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. greater than 543*F when surveillance testing began, a temperature
decrease of several degrees subsequently occurred when steam-
generator water levels were increased using the ausiliary feed
system. This provided the coincident signals necessary for an SI
' initiation. The inspectors discussed the event with the individuals
involved. From these discussions, several key points were raised.
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The primary cause of the event can be attributed to operator
Linattentiveness. The operators did not recognize the potential for
an inadvertent SI with the steam flow bistables tripped for
instrumentation'and control (I&C) work and the Reactor Coolant
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System (RCS) temperature approaching the low low setpoint due to the
addition of water to the steam generators. Based on hindsight, the
operators recognize that this point should have been understood.
Several contributory causes have also been identified. First, work
activities in the control room were heavy when the SI occurred.
Second, on-shift management involvement was not effective in
assuring that plant activities were conducted in a sufficiently
controlled manner. Finally, surveillance activities are designed
for stable plant conditions, rather than varying conditions (e.g.,
changing RCS temperature).
In this case with the plant in a
transient condition, communications and control of activities are
very important.
Plant management reemphasized to operators the importance of proper
communications and control of operating activities. These items
have been identified as being particularly important when preparing
for or conducting shift turnover. Additionally, plant management
stressed the desirability of minimizing the number of plant
evolutions being performed concurrently.
Additionally, plant management is reevaluating the scheduling of
on-shift management coverage. Previously, the on-shift management
was on shift for a number of consecutive days. The existing
schedule rotated managers through the backshifts on a nightly basis,
and the Senior Operations Supervisor acted as the on-shift manager
during day shifts. This scheduling did not allow time for managers
t., get acclimated to the shift activity, and it resulted in the
Senior Operations Supervisor performing his normal work activities
in lieu of looking at operating activities from an independent
overview. The resolution of this on-shift management concern will
be followed diring future inspection activities.
No violations or deviations were identified.
e.
Sealed Valve Control Program
Seals are used to verify ad centrol the position of manual valves
in the flow paths of plan; safety systems required by TS.
NPAPs C-9
and C-9S1 prescribe methods used to control and document the sealed
valve program.
An undocumented sealed valve was observed to be out of position and
unsealed by the inspector during performance of an ESF system
(containment spray) walkdown. This situation was brought to the
Shift Foreman's (SFM's) attention to resolve.
Subsequent action to
restore the sealed valve's original condition prompted the inspector
to perform a detailed review of the licensee's sealed valve control
program and its implementation.
The following problem areas were identified by the inspector:
(1) Operator actions necessary to resolve sealed valves discovered
to be unsealed and/or out of position were not prescribed.
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(2) Operating Procedure (0P) K-10, " Systems Requiring Sealed Valve
Checklist", does not list all sealed valves specified in
Surveillance Test Procedures (STP's) or valve identification
drawings.
(3) The appropriateness of using " valve seal change forms" in
conjunction with an STP which specifically addresses the
repositioning of sealed valves was not clearly prescribed.
(4) Appropriate implementation of sealed valve checklists and
control of safety system lineups when not required for a
particular mode was not addressed.
All of the above concerns were discussed in detail with the
licensee's operations department.
Subsequently, a SFM memo dated
July 24, 1984, was issued by the Senior Operations Supervisor to
re-emphasize the requirements of sealed valve checklist procedures
and to clarify the Operations Department's policy. This policy
statement included a diremoive to insure control of vital valves by
maintaining the sealed valve checklists in all operational modes.
This memo and proposed administrative procedure revisions are
considered to acceptably resolve each concern.
Implementation of
procedure revisions will be followed up during normal inspection
activities. The effective response of the operations department to
address identified program deficiencies indicated active and
concerned management participation.
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No violations or devia ians were identified.
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f.
" Thermal Non-Repeatability" of Barton Pressure Transmitters
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This item was addressed in an earlier inspection reporting ieriod.
The subject Barton pressure transmitters, as outlined in a July 15,
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1984 Westinghouse letter from E. P. Rahe to
R. C. DeYoung of the
NRC, may not have met accuracy requirements for above ambient
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temperatures. The inspector verified that the subject transmitters
have been verified to be removed from service at Diablo Canyon.
This acceptably addresses the accuracy questions related to the
subject transmitters.
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No violations or deviations were identified.
3.
Maintenance
a.
Diesel Generator Starting Air Compressor
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Selected portions of the corrective maintenance activities on a
starting air compressor for diesel generator 1-3 were observed by an
inspector.
Procurement documentation and adherence to
administrative work controls were verified to be acceptable.
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No violations or deviations were identified.
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Air Compressor Maintenance Test
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Selected portions of preventive maintenance test 1Al-46M, on diesel
generator starting' air compressor 1-2B, were observed. The initial
post maintenance test run was observed by the inspector,'during
.which the licensee identified four: air. leaks in an instrument line.
Three of these leaks were repaired ~and subsequently tested
satisfactorily. The remaining leak was documented on a Nuclear
' Plant Problem Report and later repaired and retested. The cardox
system for diesel generator-room 1-2 was disabled while personnel
performed maintenance and testing on starting air compressor 1-2B,
No violations or deviations were identified.
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c.
. Boric Acid Transfer Pump
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The inspector observed the replacement of mechanical seals on boric
acid transfer pump 1-1.
Maintenance Procedure M-52.2 " Mechanical
Seal Removal and' Installation (Crane)," was used in conjunction with
Shop Work Follower MM-1-84-450 to perform the work. The appropriate
administrative approvals and clearances were obtained before the
work was initiated, and the maintenance activities conformed to
applicable technical specifications. Subsequent to completion of
the work,Ethe~ inspector independently verified that the equipment
was properly returned to service.
No violations or deviations were identified.
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Surveillance-
a.
.An inspector observed the following STPs, which are used to assess
operational performance of valves in the safety injection system:
(1)1 V-3L1, " Exercising valves 8802A and 8802B, Safety Injection
Pump Discharge Isolation to RCS~ Hot Legs"
.(2)- V-3L6, " Exercising valve 8835, ' Safety Injection Cold Leg
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Isol~ation"'
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~ (3)^ V-3L13, " Exercising valve 8976, RWST to Safety Injection Pump"
The inspector observed that all precautions and. limitations required
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by the STPs were followed, and that the electronic clock used to
measure the valve stroke times was in calibration. Upon reviewing
the observed valve stroke times, the inspector found that all valve
stroke times met the acceptance criteria specified in the associated
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- STPs.
No violations or deviations were identified.
b.
STP I-1B, " Routine. Daily Check Required by Licenses," is used to
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. meet'certain TS requirements. Normally performed once per 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
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. period, STP I-1B encompasses two basic types of examination by
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operations personnel, channel checks and verificati~n of plant
conditions. 'The licensee has chosen to conduct this STP twice a
day, to ensure the daily checks are completed at least once within
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any 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period and to more closely monitor essential parameters
- indicative of overall plant status. Reactor Shutdown Margin (SDM)
sis also' required to be calculated in accordance with STP R-19, and
the result is recorded as.a step in the routine daily. checklist of
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.STP.I-1B.
During mode 5 plant conditions, an inspector observed an assistant
control operator (ACO) perform STP I-1B and STP R-10
Conduct of
these STPs, and' appropriate responses to inquiries if the inspector,
demonstrated the ACO's in-depth-knowledge and familiarity with~ plant
equipment and system operations.
Information recorded on the mode.5
daily checklist.and the data sheet for SDM calculations was
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determined'by the inspector to be accurate and complete.
No' violations or deviations were identified.
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An1 inspector observed calibration of the steam generator water level
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. channel for transmitter LI-538. This protection and safeguards
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channel was acceptably, removed from service by a valid in-plant
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clearance, and subsequently calibrated in accordance with STP
I-11B2..The test used. simulated level input signals in lieu of the
normal, transmitter output, to calibrate the channel over its-
required indication range. Personnel who performed the testing were
qualified and understood the procedure. The instrument was
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acceptably returned to service.
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No violations or deviations were identified.
d.
As a prerequisite for Natural-Circulation (NC) tests, low range
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overpower trip setpoints of the Nuclear Instrumentation System (NIS)
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Power Range (PR) channels were reduced from 25% to 6%. ' Upon
. completion of NC testing operations, all-of the NIS PR channels were
scheduled.for reinstatement of normal low range trip setpoints.
Implementation of STP I-2B, " Nuclear PR Channel Functional Test,"
-was. monitored by.the inspector for NIS channel 42.
STP I-2B
provides the necessary detailed instructions to remove a PR channel
from service, to readjust the overpower. trip high and/or low range
setpoints, and to verify proper PR channel operation wit.h a
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functional test.
Readjustment of NIS PR 42 low range overpower trip setpoint to 25%
cand a subsequent channel functional test.were performed by qualified
Nuclear Plant Operations (NPO) I&C personnel in accordance with STP
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I-2B.
The ' inspector observed that test procedure step and
associated clearance. controls were correctly applied throughout the
surveillance evolution, including NIS channel removal from service
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. and restoration.
No violations or deviations were identified.
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An inspector observed selected portions of the calibration of the
steam generator blowdown sample liquid radiation monitor. This-
calibration was -conducted in accordance with STP I-18 J2.
The
calibration used radioactive source standards and electronic input
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signals t'o develop characteristic curves for the monitor. The
insp' ctor observedithat proper cleanliness and controls were
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' observed by licensee I&C. personnel, and calibration of the test
equipment wasfcurrent. I&C personnel understood the test procedure
and performed the test acceptably.
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No vio'lations or deviations.were identified.
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'Startup Test Proce' dure Review
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Shutdown-'from Outside-the. Control' Room-Test
-Ithis the regulatory position'that licensees will develop and.
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. conduct a test program to demonstrate _ remote shutdown capability
mandated by General Design Criterion (GDC) 19.
The test program.
?should be able to verify that the nuclear power plant, from.outside'
the main control' room (MCR), can be: 1) safely shutdown, 2)
maintained in a hotfstandby condition, and 3) shown to have the
potential for being~ safely cooled.from hot standby to cold shutdown.
.Startup Test Procedure (S/U TP) No. 41.1, " Plant shutdown from
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Outside the Main Control Room,".was issued to demonstrate that
- stable hot standby conditions can be established and maintained from
outside the MCR following a reactor' trip. Testing requirements for
this evolution were compared by the inspector against applicable
provisions of Regulatory Guides (RG) 1.68 and 1.68.2, and the test
program prescribed by Chapter 14 of the licensee's Final Safety
Analysis Report (FSAR).
During the Hot Functional Test (HFT) program, preoperational testing
of plant instrumentation, controls, and systems used at the Hot
Shutdown Panel (HSDP) was completed and documented in S/U TP 37.20,
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" Control Room Inaccessibility." Subsequently, the potential
capability for cold shutdown, by partially cooling down the plant'
from hot standby, was demonstrated by S/U TP 37.28,'" Plant Cooldown
.from'Outside the MCR."
RG 1.68.2 specifically allows the
demonstration of cold shutdown capability at a time not immediately
following the demonstration of achieving and maintaining a safe hot
standby condition from a moderate reactor power level. The
- inspector considered the performance of S/U TP 37.28 during HFT to
. meet the test program objective 3) identified above.
Objectives 1) and 2) from above, should be met by an acceptable
performance of S/U TP 41.1.
The licensee's test program for
verifying remote shutdown capability was determined by the inspector
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to be consistent with commitments in the FSAR, and with regulatory
requirements and guidance, except for the following:
(1) ~ RG 1.68.2 states that shutdown of the reactor plant should "be -
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initiated from a location outside.the control room...at a
moderate power level." The S/U Program Master Document TP 40.0
has' scheduled a rod group drop test, of the most difficult to
detect rods, which will cause a negative rate signal input into
the Reactor Protection System (RPS) to initiate the necessary
reactor trip. Should the plant fail to trip from this test,
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- the procedure instructs control room operators to manually trip
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'the reactor:from inside the-MCR. These specific instructions
are not consistent with regulatory guidance.
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(2) -In_the preoperational test program, RG 1.68.2 recommends that
" verification should have been made that control of transferred
components.from the MCR is not possible after control'of these
. components from the" HSDP "has.been established." A
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prerequisite for S/U TP 41.1 was verification of HSDP
- operability by S/U TP 37.20, which did not address this
.important " transfer of control" criterion.
(3) S/U TP 41.1 does not require recording important primary and
secondary system parameters while hot shutdown conditions are
being established and maintained. These data are considered
e:sential for evaluating plant performance to determine if the
test objectives have been met.
(4) RCS temperature is identified in S/U TP.41.1 as an essential
parameter to be controlled, and yet it is_not required'to be
monitored, recorded, or evaluated during the test. The
inspector stated that an acceptable demonstration of hot
shutdown capability should establish RCS temperature as a part
of the acceptance criteria and monitor it accordingly.
.The above findings'were discussed in detail with the licensee's S/U
engineering staff. Each concern appears to have been acceptably
addressed in the form of, proposed procedure. revisions. The
inspector will. follow-up licensee activities to ascertain
satisfactory implementation of these proposed resolutions.
(275/84-22-01):
No violations or deviations were identified.
b.
. Net Load Rejection Test
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A demonstration'of the reactor plant's dynamic' response following a
full load rejection is necessary to verify performance capabilities
'of systems;important to safety delineated by Appendix A to-
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10 CFR;50. S/U TP!43.2, " Net Load Trip from 100% Power," intends
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'"to demonstrate the ability 'of the primary plant, - secondary plant
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and the automatic reactor. control systems to sustain a net load. loss
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from 100% load rejection capability." -Testing requirements of this
power ascension test procedure were compared by the inspector with
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applicable provisions of RG 1.68 and with the test program
prescribed in Chapter 14 of the FSAR.
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With'the plant at 100% rated thermal power, a full load rejection is
initiated by: opening the main transformer high side breakers.
It is
an objective of S/U TP 43.2 to evaluate the performance of automatic
control' systems as evidenced by variations of plant parameters
' during the transient, with minimal operational intervention, until
the plant is stabilized. The plant design and Emergency Operation
. Procedures (EOPs) are such that this transient should not cause a
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turbine 'or' reactor trip, _ safety injection actuation, or lif t any
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safety valves.
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.The" inspector concluded that an acceptable performance of S/U
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TPl43'.2.will address the: criteria established in RG-1.68.
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. addition, -this test of' the plant's full load rejection capability is
consistent with commitments'made in the FSAR and objectives stated
in S/U TP 43.2, exc'ept for the following:
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- A test. objective; identified in S/U TP 43.2, states " verify
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plant EOP."
But no evaluation of E0P-34, " Generator Trip -
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' Full Load Rejection," is required by the procedure.
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-(2) The FSAR establishes two test objectives for the net load trip:
(1) to-verify plant response to generator trip, and _ (2) to
verify control system performance by observed variation of
plant parameters-within-acceptable limits.
It is the intent of
S/U.TP 43.2 to initiate a transient.that will not result in a
' trip of the_ main generator. Full load rejection is, in this
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case,~a. total. loss _of'.off-site demand; the main generator
should. remain'on-line during the entire evolution and continue
to supply on-site household loads. However, the effects of
actual-test procedure implementation are not consistent with
the'FSAR. description. Furthermore, the procedure'does not-
appear to adequately provide for detailed evaluation-and review
.of-the plant's control systems performance or interactions,
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.during and subsequent to the transient.
These findings were discussed with the licensee's on-site S/U
engineering l staff. Follow-up 'of proposed procedure and FSAR
- revisions will be performed by the inspector.
(275/84-22-02)
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No violations or deviations were identified.
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Startup Program Master Document
Startup TP:No.-40.0 "Startup Program Master Document" is the overall
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etartup master document which defines the startup test program from
pre-core loading-through 100% power operation. The. inspector
reviewed the power ascension program portion -(initial entry into
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1 Mode'I to~100% rated thermal power testing)'of this document.
-TP 40.0' specifies that power ascension testing will be conducted at
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15%,-30%, 50%, 75% and 100%. rated thermal: power (RTP) testing
plateaus. During power ascension ~ testing, TP 40.0 requires that the
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NIS power range ~ high trip-point be reset to a value of the next
higher plateau power level plus 20% rated thermal power, prior to
' ascending to that power plateau (e.g., for the 50% power plateau,
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the. trip point would be' set at 70% RTP). The inspector observed
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that. regulatory guidance suggests more conservative power range high
trip-point settings for each plateau. Accordingly, this observation
was discussed with the licensee; and the licensee agreed to revise-
-TP'40.0 t'o follow NRC guidance.
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No. violations or deviations were identified.
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Static-Rod Drop and Rod Control _ Cluster Assembly-(RCCA) Below Bank
Position RequirementsLTest
.StartupTPNo.h2.3,'"StatieRodDropandRCCABelow.BankPosition
. Measurements,". specifies tlat ' core -thermocouple ' and flux maps 'are to
=beztaken'to-determine the.following:
(1), Excoreidetector response with an RCCA below bank. position.
(2) Excore detector response for the' dropped control rod
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configuration.
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'(3) Differential and integral worth of the most reactive below-bank
RCCA.-
.'(4)' Hot channel factors for.the dropped rod case.
' The inspector reviewed this procedure, and determined that S/U
TP 42.3 meets applicable NRC guidance regarding the preparation,
review and content of startup TPs.
No violations or deviations were identified.
Thermal Power Measurement and Statepoint Data Collection
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.Startup_TP'No. 42.5, " Thermal Power Measurement and Statepoint Data
Collection," specifies _that during isothermal conditions at each of
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the previously mentioned power plateaus, high accuracy plant heat
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balance measurements and corresponding flux maps are to be taken.
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- These data will be used for alignment of RCS-temperature and nuclear
' instrumentation; calibration of steam and feedwater flow
instrumentation; and adjustment of the reactor control system.
The inspector reviewed this procedure and determined that TP 42.5
meets' applicable NRC guidance regarding the preparation, review and
content of startup TPs. However, regulatory guidance suggests that
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preliminary evaluations be performed at each power-plateau (such as
extrapolating minimum DNBR and maximum. linear heat rate values to
.the high~ flux trip setpoint for the next power level) before
ascending to the next power. level. Provisions to perform these
preliminary. evaluations were not contained within TP'42.5.
The
licensee stated that the need for the preliminary evaluations would
be evaluated.
(275/84-22-03)
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No violations or deviations were identified.
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'6.
QA Program Reviews - Unit 2
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a.
Test and Measurement Equipment Control
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-The licensee's Quality Assurance Manual (QAM) Procedure 8.1,
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" Control of Measuring and Test Equipment," establishes the
programmatic' requirements "to assure that tools, gauges,
instruments, and other' measuring and testing equipment used in
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' activities affecting quality are properly controlled, calibrated,
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and adjusted to maintain precision and accuracy within specified
limits." Each responsible department (i.e., NPO, General
Construction (GC), and Engineering Research) is-required to develop
and maintain a specific program for control of measuring and test
. equipment which conforms to the-provisions of Procedure 8.1.
-The inspector reviewed QAM Procedure 8.1 for compliance with
Criterion XII of' Appendix B to 10 CFR 50, RG 1.33, Chapter 17 of the
FSAR, and ANSI Standards.N18.7 and N45.2 (including applicable
daughter standards). With two exceptions, this program procedure
was determined to acceptably prescribe all the requirements in the
aforementioned documents. ANSI N18.7-1976, section 5.2.16,
specifically addresses the need for prescribing celection of testing
equipment and measuring devices "of the proper range and type" for
use in " measurements, tests, and calibrating." Furthermore,
section 5.2.16 calls out that "special calibration shall be
performed when accuracy of... equipment is questionable." QAM
Procedure 8.1 does not address either of these areas. The onsite QA
supervisor was briefed on the program deficiencies, and responded by
assuring the inspector that responsible corporate office personnel,
involved with an imminent QAM revision, would be appropriately
informed.
It should be noted, however, that these issues had been
incorporated into the NPO Department Procedures even without benefit
of-QAM compliance.
Subsequent review of test and measurement equipment control
procedures and implementation was limited in scope to an inspection
'of the NPO Department's program. To effectively evaluate this
program, the inspector examined applicable administrative
procedures, interviewed responsible personnel involved directly in
program implementation or use of equipment, reviewed documented
calibration records and usage logs, observed check-out procedure
implementation and test equipment storage locations, and verified
calibration status of over sixty individually identified pieces of
equipment..In'the NPO Department, administration and implementation
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of test and measurement equipment control is primarily the
responsibility of the I&C organization and the Electrical and
Mechanical Maintenance groups.- Secondary responsibilities are
assigned to the Chemistry and Radiation Protection (C&RP)
organization. All of these groups were examined for conformance
with provisions of the' QAM, regulatory requirements, and industry
standards.
With a few exceptions, the inspector determined that control of test
and measurement equipment was acceptably developed in written
procedures and was being acceptably implemented. Each specific
comment generated during the inspection process was discussed in
detail with the appropriate organization supervisor. Concerns of
significance were discussed wit'. plant management, as follows:
(1) Althoup
alibrations were being performed as required, a need
for improvement in master calioration schedules was a generic
problem with all organization,
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(2) - Calibrations were ' generally performed by qualified journeymen.
A program for qualifying and identifying personnel performing
calibrations was not clearly established.
(3) Administrative procedures did not clearly prescribe the I&C
interface with C&RP department.
(4) Although calibrated equipment was available as needed for
maintenance activities, Mechanical Maintenance appeared well
behind in applying onsite resources to effectively control test
and measurement equipment inventory, usage and recall. Present
methodology is marginal. Calibration records for mechanical
maintenance were also deficient in necessary data and
' identification of acceptable standards.
(5) Timely attention was not being given to QA/QC audit items
describing areas of weakness.
Resolution of these concerns will be followed up as open item
323/84-12-01. Present senior supervisory and upper management
involvement has been markedly improved in this QA program area, even
prior to the inspection activity.
No violations or deviations were identified.
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Independent Inspection
a.
Non-licensed Operator Training
The inspector reviewed the licensee's program for non-licensed
operator training which includes systems, theory and administrative
control classes. Class content and objectives were examined.
Additionally, the inspector observed several class sessions. From
this review and observations, it was determined the program
acceptably addressed training of non-licensed operators.
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No violations or deviations were identified.
b.
Pipe Gouges Identified by an Anonymous Source
The inspectors were informed by anonymous construction personnel of
gouges in line #2-K-106-18 near hang'r number 47-55A. 'this item was
turned over to PG&E's Quality Hotliae. The Quality Hotline assigned
Quality Control Summary Report (QCSR) #70 to this concern. The
Quality Hotline investigation found that these gouges were addressed
'in Pullman Power Products Discrepancy Report (DR) No.~87-10 dated
July 14, 1984. The inspector verified selected portions of the DR.
No violations or deviations were identified.
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Open Item Follow-up
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a.
Unit 1
(1) Rad Waste Minimization (Open Item 83-19-02, Closed)
.The licensee's program for rad waste minimization was reviewed
by the inspector. This program consists of general employee
training, as well as specific training for Chem and Rad-
Protection (C&RP) personnel.
In addition, a controlling
administrative procedure (No. C-254) prescribes the objectives,
responsibilities and authority necessary to implement an
acceptable program of waste minimization. This open item is
closed.
-(2) Borg Warner Check Valve Repair (Open Item 83-22-01, Closed)
An inspector examined welding documentation concerning check
valve weld repair. The disc and nut were welded to the stud in
the subject valves. This was done to prevent disassembly of
the valve'during operation. Work was performed in accordance
with manufacturer' recommendations. This open item is closed.
(3) Fire Protection and Medical Section Staffing (Open
Item 83-39-01, Closed)
An inspector reviewed the licensee's staffing level and
program. The inspector concluded that it acceptably closes
this open item.
(4) Fire Protection Exemption on Auxiliary Feedwater Room
Ventilation Damper (0 pen Item 83-39-09, Closed)
NRR has accepted the specific subject exemption. This action
in.SSER No. 23, KUREG-0675, closes open item 83-39-09.
No violations or deviations were identified.
b.
Unit 2
. Containment Fan Cooler Unit (CFCU) Bearing Vibrations (Open
Item 82-13-01, Closed)
The licensee's program to reduce CFCU bearing vibrations has been
re' viewed by the inspector. Associated testing and design
evaluations were considered acceptable to address this problem.
This open' item is closed.
No violations or deviations were identified.
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9.
Follow-up of Previous Notices of Violation
Inoperable Emergency Core Cooling System (ECCS) Flowpath (Unit 1 Open
Item 84-06-01, closed)
Inspection Report'84-06 cited a violation concerning inoperability of the
ECCS flowpath through the Boron Injection Tank (BIT), and identified
several open' items requiring follow-up inspection. The licensee's
response to the notice of violation (letter dated June 15, 1984 from
'G. A. Maneatis, PG&E, to R. C. DeYoung, NRC), and the documentation and
programs affected by corrective action, have been reviewed by the
inspectors. The following open items associated with this violation have
been closed:
Open item 84-06-02: Operating Procedure B-1C, "12 Percent Boric
Acid System," was revised to emphasize that isolation of the BIT
necessitates close evaluation of all applicable technical
specifications.
10 pen item-84-06-03: The licensee completed a review of operating
procedures to assure appropriate TS were referenced.
Open item 84-06-04: The licensee developed and issued Procedure TP
TA 8401, " Cross Reference of Plant Equipment with Technical
Specification Requirements," which is considered to acceptably
address this item.
-Open item 84-06-05: The licensee has revised the procedure review
program to require an independent technical review for procedure
changes which affect technical content.
In addition, packages
containing substantial procedure changes will be submitted to the
Plant Staff Review Committee (PSRC) for detailed discussions.
Open item 84-06-06: The licensee's programs to (1) place management
on-shift, (2) review other licensees' operational control methods,
and (3) walkdown systems for added verification of correct alignment
and technical specification compliance have been reviewed.
Implementation of these programs was determined to meet the
licensee's commitments.
No violations or deviations ware identified.
10.
LER Follow-up (Unit 1)
Circumstances and corrective actions described in LERs, as listed below,
were examined by the inspectors. The inspectors found that these LERs
had been reviewed by the licensee, and were reported to the NRC within
acceptable reporting intervals. The inspectors also verified that
-appropriate corrective actions were taken. Accordingly, these LERs are
considered closed.
LER No. 82-03: The plant vent radiation monitors were inadvertently
deenergized without this condition being indicated in the control room.
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An annunciator was installed to ensure that control room personnel are
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aware of any loss of power to the plant vent radiation monitors.
LER No. 83-01: The steam generator blowdown flow recorder head was
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repaired to complete action on this LER related to equipment failure.
LER No. 83-02: Maintenance on the liquid radwaste flow recorder repaired
this equipment failure.
LER No. 83-05: Repair of the earthquake force monitor reset switch and
local cabling resolved this LER related to equipment failure.
LER No. 83-08: Electrical maintenance personnel incorrectly terminated a
wire connection which removed power to the radiation monitors. The
importance of proper circuit identification was discussed with all
workers involved in similar activities.
LER No. 83-09: The power switch to the plant vent iodine sampler was
inadvertently opened during construction activities. Construction
personnel were counseled on the need for caution in their work
activities.
LER No. 83-10: A construction electrician inadvertently grounded the
power to the main annunciator system (corrective action coincides with
that on 83-09).
LER No. 83-13: Plant vent air sample pumps were deenergized without
recognition by operators. An equipment power supply cross-reference list
has been prepared.
LER No. 83-15: A design change, which affected the annunciator
indication for the plant vent iodine sampler, was not identified in
related surveillance test procedures. The impact of design changes on
procedures was reemphasized with the licensee's operations and
engineering personnel to address this event report.
LER No. 83-17: The failed power supply breaker to the oily water
separator flow monitor was replaced.
LER No. 83-18: On return to service from clearance, a valve on the fire
water system was mispositioned. This was caused by the use of an
incorrect valve checklist. Discussions with personnel reinforced the
need for the use of proper clearance forms and valve lineup sheets for
return to service.
LER No. 83-20: A gaseous radwaste monitor tube failed due to end-of-life
and was subsequently replaced.
LER No. 83-24: An inadvertent ground of electrical connections caused
the loss of main control room annunciators. Training was conducted for
the General Construction Electricians involved.
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LER No. 83-27: The diesel-generator starting air compressor relief valve
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- was repaired and the definition of an operable diesel generator was
clarified tol resolve this LER related to equipment failure.
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LER No. 83-30: ' Completion of surveillance on the seismic monitoring
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system' resolved this LER which was apparently caused by NPO personnel
. error.
LER No.-83-31:. Surveillance frequency requirements were clarified
concerning auxiliary. hoist load testing.
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LER No. 83-34: RHR pump control circuit inconsistencies were discovered
between approved schematics and the as-installed configuration. The
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_ licensee determined that modifications to the control circuitry were
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incorrectly implemented. To ensure.that. modification controls were
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acceptable, the licensee examined all modifications to similar control
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' circuits. Additionally, administrative requirements were provided,
-requiring the. design intent to be included within the appropriate test
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. procedure.
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' LER No. 83-35:. Firewater system re-alignment was not completed due to
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. lack of procedure comprehension by personnel. Operations personnel were
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instructed to review procedures prior to use.
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LER No. 83-36: The control room ventilation supply fan motor was
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repaired, subsequent to its reported failure.
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~ LER No. 84-01: Fuse replacement in the SSPS corrected the cause of this
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inadvertent SI.
LER No.=84-03:
The licensee has continued to monitor instrument AC power
which ' caused an. inadvertent SI reported in this LER.
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LLER No. 84-05: Operations personnel error caused a diesel generator to
.. start. -Involved personnel were briefed and a protective guard was
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instal) ' over the incorrectly moved breaker.
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LER No.~84-07:
Operations personnel incorrectly tried to reset a 125 V
AC instrument power supply breaker which caused a mode transfer of the
control room ventilation system. The function of.this breaker was
clarified by adding a descriptive-label.
LER'No. 84-09: An inadvertent start of a diesel generator was caused by
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personnel' error in the alignment of the. auto / manual selection switch.
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. Corrective action included personnel counseling.
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LER No.-84-12:
Personnel error resulted in an inadvertent loss of main
- control room annunciators.. Operations personnel were counseled and
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retrained.
LER No. 84-13:
Inoperable emergency core cooling system flow path. This
' issue was followed-up and closed as item 84-06-01.
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LER No. 84-14: Temperature instrumentation was replaced in the over-
temperature Delta-T protection circuity which caused a reactor trip.
LER No. 84-15: A failed control module in the steam dump system caused
an SI actuation to occur.'
The defective module was replaced.
LER No.84-16i Construction personnel. inadvertently opened a power
supply breaker to several plant radiation monitors. These work
activities have been placed under tighter administrative controls.
No violations or deviations were identified.
11.
Follow-up on Items Identified During Special Team Inspection
At the conclusion of the Region V Special Team Inspection, on June 12,
1984, licensee management provided information and/or made commitments
regarding specific findings and concerns identified during the
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= inspection.
(See-paragraph 8 of NRC Inspection Report No. 50-275/84-07).
Subsequent to theLinspection, facility' records and procedures were
. examined and discussions were held with licensee representatives
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regarding the status of the following items.
Independent Verification of Operational Activities
a.-
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Review of plant procedures revealed that an on-the-spot procedure
change was made to NPAP C-104, " Independent Verification of
. Operating Activities," on June 6, 1984. Revisions were also made to
the Diablo Canyon Administrative Procedure, Supplement I to NPAP
C-104.
These changes clarify instructions for independent
verification of operational activities to require that, except for
unusual circumstances, the independent verifier will not accompany
the person. performing the activity to be verified. Exceptions to
this requirement, which require supervisor approval, are those
circumstances where a substantial. reduction in personnel radiation
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exposure will result, or where the presence of the independent
verifier is important to ensure against an inadvertent unit trip or
. engineered safety features actuation. An example of the latter is
the conduct of surveillance testing of the solid state protection
system.
In such a case the independent verification would be
conducted on a step-by-step basis as the testing proceeds. The
procedure (NPAP C-104, Supplement 1) includes a special notation for
such circumstances that the independent reviewer, "...shall make
every effort to act -in an independent manner during the performance
of his duties."
No violations or deviations were identified,
b.
Work Planning
As of July 9,1984, two additional persons had been hired and were
on board to fill vacant positions in the I&C Work Planning group.
Six' additional contract employees were on board - two in I&C Work
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Planning, and four in Mechanical and Electrical Maintenance Work
Planning.
No violations or deviations were identified.
c.
Post-Trip Information System Reliability
A' review of facility records. revealed that extensive
trouble-shooting had identified several defective components in the
power supply- (inverter and oscillator board) of the
sequence-of-events (P-250) computer. Replacement of the defective
components.and subsequent testing demonstrated that previous
problems with reliability have been successfully corrected. The
records also-indicate that an investigation revealed a loose wire on
an output buffer driver of the main annunciator recorder
(typewriter) unit. Previously reported ma1 performance of the
recorder / typewriter appears to have been corrected by reconnection
of this loose wire.
No violations or deviations were identified.
12.
Exit Meeting
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On August 3, 1984, an exit meeting was conducted with the licensee's
representatives identified in paragraph 1.
The inspectors summarized the
inspection scope and findings, as described in this report.
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