ML20033A599
| ML20033A599 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 09/16/1981 |
| From: | Blough A, Cowgill C, Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20033A590 | List: |
| References | |
| TASK-2.E.4.1, TASK-2.E.4.2, TASK-2.K.3.13, TASK-2.K.3.15, TASK-TM 50-277-81-19, 50-278-81-20, NUDOCS 8111250610 | |
| Download: ML20033A599 (18) | |
See also: IR 05000277/1981019
Text
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50-278/810813
50-278/810830
50-277/810808
50-277/810812
50-277/810827
U.S. NUCLEAR REGULATORY COMMISSION
OFFICE OF INSPECTION AND ENFORCEMENT ~
Region I
50-277/81-19
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Report No.
50-278/81-20
50-277
Docket No.
50-278
C
License No. DPR-56
Priority
Category
C
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Licensee: Philadelphia Electric Company
2301 Market Street
Philadelphia, Pennsylvania
Facility Name: Peach Bottom Atomic Power Station, Units 2 and 3
Inspection at: Delta, Pennsylvania
Inspection conducted: August 4 - September 3, 1981
Inspectors:
C0 kU h , h
iIf6f&l
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C. J. Cowgill, III, Senior Resident-
date signed
Inspector
e,c. L % %., k
sluft!
A. R. Blough, Resident Inspector
date signed
Approved by:
& . O. A % b
ill6/88
E. C. McCabe, Jr., Chief, Reactor
date signed
Projects Section No. 28, DRPI
Inspection Summary:
Inspection on August 4 - September 3, 1981
(Combined Inspection Report Nos. 50-277/81-19 and 50-278/81-20)
Areas Inspected:
Routine, onsite regular and backshift inspections by the
resident inspectors (53 hours6.134259e-4 days <br />0.0147 hours <br />8.763227e-5 weeks <br />2.01665e-5 months <br /> Unit 2; 42 hours4.861111e-4 days <br />0.0117 hours <br />6.944444e-5 weeks <br />1.5981e-5 months <br /> Unit 3). Areas inspected
included accessible portions of the Unit 2 and Unit 3 facilities, radiation
protection, physical security, operational safety, control room activities,.
LERs, periodic reports, TMI action plan items, surveillance testing, and open
items.
4
8111250610 811105
PDR ADOCK 05000277
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Results: Noncompliances: None in seven areas, four in three areas (failure
- to take re' quired Technical Specification actions for inoper tive Primary
' Containment Isolation Valves, Detail 4; failure to take required. Technical
Specification actions for inoperative APRM, Detail 4; inadequate drawing
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control, Detail 8; failure to log temperatures dur.ing primary system cooldown,
Detail 7).
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DETAILS
1.
Persons Contacted
W. H. Alden, Engineer-in-Charge, Nuclear Section
M. J. Cooney, Superintendent, Generation Division (Nuclear)
J. K. Davenport, Maintenance Engineer
G. F. Dawson, I&C Engineer
- R. S. Fleishmann, Assistant Station Superintendent
A. Fulvio, Results Engineer
N. Gazda, Health Physics, Radiation Protection Manager
F. W. Polaski, Reactor Engineer
S. R. Roberts, Operations Engineer
D. C. Smith, Outage Coordinator
S. A. Spitko, Site Q.A. Engineer
S. Q. Tharpe, Security Supervisor
W. E. Tilton, Refuel Floor Supervisor
- W.
T. Ullrich, Station Superintendent
A. J. Wasong, Test Engineer
H. L. Watson, Chemistry Supervisor
J. E. Winzenried, Technical Engineer
R. H. Wright, Test Engineer
Other licensee employees were also contacted during the inspection.
- Present at exit interviews on site and for summation of preliminary
inspection findings.
2.
Previous Inspection Item Update
(Closed) Unresolved Item (79-07-01, 79-06-01), review OSR committee audit
transmittal dates for 1978. Timeliness of audit report issuance was the
subject of a noncompliance in combined reports 79-13 and 79-15.
Corrective actions were found adequate in combined reports 80-31 and
80-23. This item is closed.
3.
Plant Operations Review
a.
Logs and Records
A sampling review of logs and records was made to:
identify
significant changes and trends; assure that required entries were
being made; to verify that operating orders and night orders conform
to Technical Specification requirements; check correctness of
communications concerning equipment and lock-out status; verify
jumper log conformance to procedural requirements; and to verify
conformance to limiting conditions for operations.
Logs and records
e
reviewed were:
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(1) Shift Supervision Log - August 4 - September 2, 1981
(2) Unit 2 Jumper Log - Current Entries
_(3) Unit 3 Jumper Log - Current Entries
(4) Reactor Engineering Log - Unit 2 - August, 1981
(5) Reactor Operators Log - Unit 3 - August 4 - September 2,
1981
(6) Reactor Operators-Log - Unit 3 - August s - September 2,
1981
(7) CO Log Book - August 4 - September 2, 1981
(8) STA Log Book - August, 1981 (Sampling)
(9) Night Orders - Current Entries
(10) Radiation Work Permits (RWP's) - Various in both Units 2 and
3'- August, 1981
(11) Maintenance Request Forms (MRF's) - Units- 2 and 3, (Sampling) -
August, 1981
(12) Ignition Source Control Checklists (Sampling) - August,1981
(13) Operation Work & Information Data - August, 1981
Control room logs were reviewed pursuant to requirements of
Administrative Procedure A-7, " Shift Operations."' Frequent
initialing of entries by licensed operators, shift supervision, and
licensee on-site management constituted evidence of licensee review.
Logs were also reviewed to assure that plant conditions, including
abnormalities and significant operations, were accurately and
completely recorded.
Logs were also assessed to determine that
matters requiring reports to the NRC were being processed as
suspected reportable occurrences. This' area is discussed further'in
Detail 4.
b.
Facility Tours
During the course of this inspection, which also included shift-
turnover, the inspector conducted daily tours and made observations
of:
Control Room (daily)
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-- ' Turbine Building-(all levels)
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-Reactor Building - (accessible areas)
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Diesel Generator Building;
-Yard _ area and perimeter exterior to the power block,-including
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-Emergency Cooling Tower and torus dewatering. tank
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Security Building, including CAS, Aux.SAS, and control point
monitoring
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Vehicular Control
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The SAS and power block control points
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Security Fencing
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Portal Monitoring
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Personnel and Badging
Control of Radiation and High Radiation areas, including locked
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door checks
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TV monitoring capabilities
Off-Shift Inspections during this inspection period and the areas
examined were as follows:
DATE
AREAS EXAMINED-
August 11
Control Room observations, Unit 3
refuel floor observations and
Reactor Building tour.
August 12
Control Room observations,
tour of cable spreading room
and radwaste building (165-
foot elevation)
August 21
Control Room observations,
tour of protected area
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September 2
Control Room observations
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Off-Normal Alarms. Selected annunciators were discussed with
control room operators and supervision to assure they were
knowledgeable of plant conditions and that corrective action,
if required, was being taken.
Examples of specific : alarms
discussed during the report period were: -Refueling Water
Storage Tank, High/ Low Level; Computer and Cable Spreading Room
Fire Suppression System Deactivated; " Accumulator" and " Drift"
alarms for individual control rods; and Standby Liquid Tank or
Pipe Temperature, High/ Low. The operators were knowledgeable
of alarm status and plant conditions.
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Control Room Manning. On frequent occasions during this
inspection,-the inspector confirmed that requirements of 10 CFR 50.54(k), the Technical Specifications and commitments to the
NRR letter of July 31, 1980 for minimum staffing were
satisfied. The inspector frequently confirmed that a senior
licensed operator was in the control room complex. No
unacceptable conditions were identified.
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Fluid Leaks. The inspector observed sump status, alarms,
pump-out rates', and discussed leakage with licensee personnel.
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The inspector noted that the licensee was closely monitoring
Unit 2 drywell unidentified leakage as the maximum allowable
was approached.
Some leaks were found and repaired in an
outage from August 17-25. No unacceptable fluid leak
conditions were identified.
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Piping Vibration. No significant piping vibration or unusual
conditions were identified.
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Monitoring Instrumentation. The inspector frequently confirmed
that selected instruments were. operating and that indicated
values were within Technical Specification requirements. On a
daily basis when the inspector was on site, ECCS switch
positioning and valve lineups (based on control room indicators
and plant observations) were verified.
Examples of
instrumentation observed included flow setpoints, breaker
positioning, PCIS status, radiation monitoring instruments, and
Standby Liquid Control system parameters.
This area is
discussed further in Detail 4.
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Fire Protection. On frequent occasions the inspector verified
the licensee's measures for_ fire protection. The inspector
observed control room indications of fire detection and fire
suppression systems, spot-checked for proper use of fire
watches and ignition source controls, checked a sampling of
fire barriers for integrity, and observed fire-fighting
equipment stations. On August 12, the inspector informed shift
supervision of a small accumulation of combustibles (white
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coveralls) near the Unit 2 remote shutdown panel -- this
condition was promptly corrected. No. items of noncompliance
were identified.
c.
Follow-up Events Occurring During the Inspection
The inspector followed-up on events that occurred during the
inspection in order to ascertain.the nature and significance of-the
event, verify safe plant conditions, verify licensee conformance to
license conditions and NRC reporting requirements, and evaluate the
need for. additional NRC involvement.
(1) Fire in Rod Position System (RPIS) Circuitry
At 10:15 a.m. August 13, 1981, with Unit 3 in cold shutdown
(for a refueling and .aodification outage), a- small fire
occurred in the rod position indication system (RPIS) fuse box
located in a cabinet in the cable spreading-room. The fire was
quickly _ extinguished, using dry chemical fire extinguishers,
but some sparking continued for about 15 minutes until'the RPIS
was de-energized. All control rods were blocked fully inserted
for Scram Discharge System modifications. The fire was caused
by shorting of an untaped, energized 120 volt-AC lead in an
adjacent cabinet as the power supply drawer was-being removed-
for modification. Workers had taped leads they believed, based
on review of electrical diagrams, to be energized. 'The
inspector toured the control room and cable. spreading room -
shortly after the fire, observed that it was out and that there
was no loss of, or continuing hazard to, additional equipment.
The inspector noted that the fire was not in the vicinity of
any equipment addressed in LER 2-82-38/IP (reference Detail 4).
The inspector reviewed logs and procedures, and discussed the
event with operations personnel. An Unusual Event had been
declared, and emergency plan procedures had been followed.
In
reviewing emergency plan implementing procedures, the inspector
noted that, for all levels of emergencies, notification of the
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NRC via the Regional Office is specified.
Per 10 CFR 50.72,
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and licensee administrative procedure, notification of
emergencies should be made to the NRC Headquarters Duty Officer
using the Emergency Notification System (ENS). The licensee
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stated that procedures would be changed; the inspector will
review the revised nrocedures.
The licensee was not able to
quickly determine why a fire, rather than merely blown fuses,
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had occurred.
Components involved were sent off-site for
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detailed analysis. This item will receive further NRC review.
(277/81-19-01; 278/81-20-02).
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(2) Unplanned Release of Radioactive Water to Storm Drains
About 8 10 a.m., August 30, the licensee discovered that water
had leaked through the Unit 3 Reactor Building railroad access
door. The water backup was caused by a clogged reactor-
building floor drain system and Reactor Water Cleanup pump seal
failure. The licensee immediately dammed the water at the
railroad door. Samples at the drain the Reactor Building
showed IE-3 microcuries per milliliter activity.
It was
estimated that between 10 and 100 gallons of water entered the
storm drain system. The storm drain in the front of the Unit 3-
Reactor Building showed SE-6 microcuries per milliliter
activity, with Zinc-65 the principle isotope.
Samples at the
culvert at the discharge to the Conowingo Pond showed no
detectable activity.
The area outside the Reactor Building
railroad access door was immediately decontaminated. No
personnel contamination resulted. The licensee notified the
NRC Duty Officer of this occurrence via the Emergency
Notification System.
The inspector reviewed sample results from August 30, observed
~ that the railroad door had been dan.med, and held discussions
with licensee personnel regarding long-term corrective actions.
Licensee management stated that modifications to prevent
recurrence were being reviewed in conjunction with corrective
action described in PECO response to NRC Immediate Action
Letter 81-18 (Reference Combined In.pection Report 277/81-07
and 278/81-09).
4.
Review of Licensee Event Reports (LERs)
a.
The inspector reviewed LERs submitted to the NRC:RI office to verify
that the details of the event were clearly reported, including the
accuracy of the description of cause and adequacy of corrective
action. The inspector determined whether further information was
required from the licensee, whether generic implications were
indicated, and whether continued operation of the facility was
conducted in accordance with Technical Specifications.
Report
accuracy, compliance with current reporting requirements and
applicability to other site systems and components were also
reviewed.
The following LERs were reviewed:
LER No.
LER Date
Event Date
Subject
2-81-37/IP
August 10, 1981 August 8, 1981
Failure to initiate
August 12,
281 (clarification)
shutdown when PCIS
August 13, 1981 (correction)
limiting conditions
for operation were
not satisfied
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2-81-38/IP. August 13, 1981 August 12, 1981
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2-81-38/1T
August 26, 1981
safe shutdown analysis
indicated that cables-
associated with 4KV
emergency bus breaker
control were not
adequately separated
2-81-39/IP
August 27, 1981 August 27, 1981
Operation with inadequate
LPRM inputs from one level
(core height) to an
3-81-13/IP
August 31,_1981 August 30, 1981
Unplanned release of
radioactive water into
the storm drain system
(see Detail 3)
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LER No. 2-81-37/IP
About 7:30 a.m. on August 8, operators found a HPCI turbine
exhaust drain line-isolation valve, A0-4248, failed closed due
to a failed solenoid coil. The HPCI turbine exhaust drain line
is a one-inch line.
In order to ensure HPCI system
operability, shift personnel ~ mechanically blocked the valve
open at about 11:30 a.m., and.left the redundant, in-line-air
operated isolation valve open. Shift personnel verified
operability of the in-line valve prior to mechanically blocking
A0-4248. These valves are Primary Containment Isolation System
(PCIS) valves; and Technical Specifications require that PCIS
valves be operable or closed, or that an associated in-line
valve be closed and logged once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
If this
condition cannot be met, then a plant shutdown is to be
initiated and cold shutdown reached within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
In this
case, less than the required containment integrity existed for
about 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />.
The inspector reviewed logs, surveillance tests, maintenance
documents, and held discussions with various licensee staff
personnel to determine the causal factors for this event.
Sequence of events.
(All times approximate)
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TIME
EVENT
7:30 a.m., August 8
A0-4248 found closed. Cause
determined to be failed solenoid
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11:30 a.m., August 8
A0-4248 mechanically blocked
open
2:05 p.m., August 8
Blocking permit applied for
repair of AO-4248
Time Unknown (prior to
Shift supervision log entry
3:00 p.m., August 8)
identifying problem with
A0-4248
3:00 p.m., August 8
Shift' turnover
6:30 p.m., August-8
. Maintenance request-2-23-M-1-35
completed and associated blocking,
permit cleared
Time unknown (prior to
Log entry in shift supervision
11:00 p.m. August 8)
log, "U/2 HPCI A0-4248 (23-138)
Repair, Tested 0.K.:and Returned
to Service."
11:00 p.m., August 8
Shift turnover
7:00 a.m., August 9
Shift turnover
7:20 a.m., August 9
Shift discovered A0-4248 still
blocked in_the open position.
Valve returned to service
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Log Review
In reviewing logs, the inspector noted that no log entries-
regarding the status of A0-4248 were made in the Unit 2 reactor
operators log book. Additionally, no mention of the abnormal
condition of A0-4248 was made on the shift turnover sheet for-
the Unit 2 reactor operator or shift supervisor.
The inspector noted that a surveillance test for checks on
inoperable isolation valves had not been used. Also,
information tags, an optional method available to convey
information which may be useful to other personnel, were not
,
used.
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Discussions with Station Personnel
The inspector discussed the event with various operators,
senior operators and station' management personnel involved.
These discussions identified that confusion' existed on
information transfer regarding the event.
The Unit 2
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afternoon Shift Supervisor and Reactor.0perator were not
provided with complete information regarding the status of
A0-4248. Both operators indicated that they.were informed that
the solenoid was being repaired but not that the valve was
mechanically blocked open. The inspector concluded that
communications inadequacies lengthened the period of valve
inoperability.
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Maintenance and Testing Activities
Maintenance, testing,'and return to service of valve A0-4248
was logged in the shift supervision log as complete before
11:30 p.m. on August 8, but the valve'was determined still-to
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be blocked open (i.e., inoperable for containment isolation
functions) during the operator's routine panel check at 7:20.
a.m., August 9.
Maintenance Request Form No. 2-23-M-1-35, for
repair of valve A0-4248, specified in Section 7, " Operation
Verification," a test for:
"No air leaks". The documented
test result (performed August 8) was: "None heard".
Station procedures require that post-maintenance testing assure
-valve operability. The specified test did not meet these
requirements, in that the containment isolation function of the =
valve in question was not tested. The inspector concluded that
the failure to adequately test after repair lengthened the
period of valve inoperability.
Findings
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A0-4248 was mechanically t, locked open for about 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />. The
redundant PCIS isolation valve was not closed.
No reactor
shutdown was initiated. The failure to comply with the
Technical Specification Limiting Condition for Operation is a
violation (277/81-19-02).
Station administrative procedures require that significant
equipment abnormalities be logged in the operator's logs.
Additionally, post maintenance testing is required to show that
equipment is operable.
The failure to log the abnormalities
associated with A0-4248 and to adequately test the valve after
repair is considered part of the above violation.
The inspector noted that Group I, II, and III PCIS valves are
provided with color-coded switch handles on control' room
panels.
No similar memery aid has been provided for Groups IV
and V (HPCI and RCIC) PCIS valves. HPCI and RCIC turbine
exhaust drain isolation valves shut on any turbine trip, as
well as in Primary Containment Isolation, to provide turbine
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isolation. Although.no' contribution to this event was
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substantiated, the inspector recommended that station
-management consider visual aids for these and similar valves.
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LER No'. 2-81-38/1P and l
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For the eight, 4KV bus breakers (per unit) which feed the 4KV
emergency buses from the two'off-site power supplies, control
cables for all breakers for a unit are run through the 'same
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cable trays from the cable spreading room to the remote
shutdown panels. A single fire could disable cortrol of all
the breakers. Diesel generators would still be available, and
I would start automatically on a LOCA signal,.but might have to
be manually closed in on the buses.
Licensee immediate
corrective actions during Unit 2 operations included marking of
the affected trays, stationing of a continously-roving fire -
watch, restricting use of ignition sources in the areas, and
increasing the emphasis on good housekeeping in the area.
PORC-reviewed instructions ware issued to operating personnel
that, in event of a fire that could affect the cables, the 4KV-
buses were to be supplied by the diesels and a Unit 2 shutdown
initiated. The inspector spot-checked implementation of these
actions and discussed provisions with licensed operators. No
inadequacies were noted.
Permanent corrective modifications
are being designed. On August 28 the inspector discussed this'
issue with the licensee and was informed that the problem
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applies also to Unit 3.
The licensee is endeavoring to
complete permanent modifications at Unit 3 during the current
outage. Additionally, the licensee identified an inadequacy.in
protective relays for the breakers--certain protective features
(related to offsite power supply transformer conditions) for
all associated 4KV breakers are fed from a single relay'in the
control room.
Individual, separated relays are needed. The-
inspector verified that the latest information was included in
revised instructions ta the operators and in the followup LER.
The inspector will review the licensee's permanent resolution
of this design problem (81-19-05 and 81-20-02).
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LER No. 2-81-39/IP
With the Unit shutdown on August 18,LPRM 32-49C failed upscale
and was by passed. This left only one operable LPRM input to
the 'C' level of APRM 'C'.
Technical Specifications require
two LPRM inputs per level for'an APRM to be considered
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operable. The unit was started up on August 24. At times
during operation, the 'A' Logic Trip System was receiving input
.C
from only one fully operable APRM because either APRM 'A'
or
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'E' was periodically by passed. When the problem was
discovered at 00:05 a.m. on August 27, APRM 'C' was promptly
by passed and subsequently returned to operability. The
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licensee was not able to determine for what period of time
either the 'A'
or the 'E' APRM had been by passed.
Technical
Specifications require two operable APRMs per trip system;
otherwise, either the trip system shall be tripped or all
,
operable control rods shall be inserted within four hours.
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Failure to meet the Technical' Specification Limiting Condition
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for Operation from startup on August 24 until 00:05 a.m.,
August 27, is s noncompliance (277/81-19-04).
During the time when less than the required number of inputs
were available, APRM 'C' apparently responded properly to power
changes from both rod movement and flow adjustments. All LPRM
inputs from the
'A', 'B'
and 'D' levels were operable.
Improper APRM response would have been detected by the
operators through routine checks of the instruments du' ring
power changes and during steady-state operations.
Additionally, process computer printouts used by the reactor
engineer during power ascension would have indicated an
abnormal " gain adjustment factor", and excessive gain
adjustments during APRM calibrations would have been required.
No such inconsistencies were identified by the licensee. The
inspector reviewed process computer printouts of core
y~
performance parameters and identified no abnormalities.
The inspector discussed this occurrence with licensee
representatives and reviewed licensee procedures.
There are no
formal checks to verify two LPRM inputs per level for APRMs.
The licensee is examining this inadequacy and stated that tha
subject would be addressed in the followup report.
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The inspector also expressed concern that other reactor
f
engineering requirements may receive no formal checks (e.g.,
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MFLPD not routinely compared to fraction of rated power; see IE
Report 277/81-03).
The inspector observed that an APRM may be
left by passed unnecessarily, which does not appear to be good
engineering practice.
For example, the inspector observed on
August 28 that, at Unit 2, one APRM in each logic trip system
was by passed, possibly from testing the previous day. No
notation regarding APRMs being by passed had been made in
reactor operator turnover sheets since startup four days
earlier.
The turnover sheet includes a section for
instrumentation by passed or out of service. These
observations were provided to station management.
5.
Radiation Protection
During this report period, the inspector examined work in progress in
accessible areas of the Unit 2 and Unit 3 facilities. Areas examined
included:
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a.
Health Physics (HP) controls
b.
Badging
c.
Usage of protective clothing
d.
Personnel adherence to RWP requirements
-e.
Surveys
f.
Handling of potentially contaminated equipment and materials
Add *+.ionally, inspections were conducted of usage of friskers and portal
monitors by personnel exiting various RWP areas, the power block, and the
licensee's final exit point. More than 50 people were observed to meet
frisking requirements of Health Physics procedures during the month. A
samplina of high radiation doors were ve.rified to be locked as required.
No unacceptable conditions were identified.
6.
physical Security
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The inspector spot-checked compliance with the Accepted Security Plan and
implementing procedures, . including operations of the CAS and SAS, over 20
spot-checks of vehicles onsite to verify proper control, observation of
protected area access control and badging procedures on each shift,
inspection of physical barriers, checks on control of vital area access
and escort procedures. No unacceptable conditions were identified.
7.
Surveillance Testing
,
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Du-ir.; facility and control room tours the inspector observed portions of
surveillance tests in progress and spot-checked recorded data.
Following
a normal shutdown and cooldown of Unit 2 on August 17-18, the inspector
reviewed the completed test ST 9.12, " Reactor Vessel Temperatures," used
to record temperatures.during heatups and cooldowns. The test had been
properly initiated. Data was properly recorded. Calculations were
t
correct. At about 220 degrees, cooldown temperature logging was stopped
at 5:00 a.m.
Temperaturas had changed 42-47 degrees in the preceding
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45 minutes. ST 9.12 requires continued temperature logging at least
,
every 15 minutes until less than five degrees di ference occurs between
any two readings taken 1.n a 45 minute period. This .is a violation.
1
(277/81-19-06). The inspector noted that cooldown had progressed in a
deliberate, controlled manner, well within Technical Specification limits
for'cooldown rate.
Recorder traces m ntaining'all required temperatures
were reviewed for the period during which required logging was not done.
The inspector reviewed ST 9.12 as performed for a previous cooldown of
~
each unit.
Logging of temperatures in each case had continued until
completion of the cooldown (about 150 to 160 degrees Farenheit).
In
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reviewing these tests, the inspector also noted that the " Test Frequency"
statement, as written, was potentially susceptible to being misread.
This comment was provided to licensee management.
8.
Review of TMI Action-Plan (TAP) Requirements
The inspector reviewed the status of licensee action on the following TAP
requirements to verify that the licensee is meeting his NRC commitments,
a.
TAP Item II.E.4.1--Dedicated Hydrogen Penetrations
Plants using external recombiners or purge systems for post-accident
combustible gas control of the containment atmosphere should provide
containment penetratit.n systems for external recombiner or purge
systems that are dedicated to that service only, that meet the
redundancy and single-failure requirements of General Design
Criteria 54 and 56 of Appendix A to 10 CFR 50, and that are sized to
satisfy the flow requirements of the recombiner or purge system.
The licensee reviewed this item and responded that the criteria
would be met with addition of two isolation valves: one outboard of
the radioactive gas sampler valves, and one on the nitrogen
compressor suction line.
NRC:NRR letters dated October 29, 1980 and
August 18, 1981 concluded that the design changes met the General
Design Criteria and satisfied.this TAP item. The inspector reviewed
modification packages, interviewed licensee personnel and observed
in plant indicators to verify that the modifications had been
adequately implemented.
PORC review was verified, and selected
procedures and drawings were checked. The inspector noted that, for
Unit 2, one controlled copy of drawing M-372, "P&ID, Containment
Atomsphere Dilution System" had m t been updated to include the
radioactive gas sampler isolation valve, installed October, 1980.
When notified, a licensee representative promptly corrected this
oversight. The inspector also verified that Technical
Specifications had been amended to include the new valves. The
inspector had no further questions regarding this TAP item.
Based on the above-noted inadequacy in a controlled drawing, the
inspector reviewed a larger sample of drawings and procedures to
verify that modifications had been properly incorporated. A
sampling of ten procedures was reviewed and no inadequacies noted.
The shift supervision and the control room copies of seven selected
drawings were reviewed. The inspector noted that a new revision of
drawing M-372 had been issued. On the new revision, the radioactive
gas sampler valve was not clearly depicted on either copy reviewed.
The in-line valve denotion was unclear, and the valve number and
operator were not discernible. Two of three licensed operators
questioned believed the print shcwed a section of pipe with no
valve.
Failure to update and maintain controlled drawings following
piant modifications violates requirements for appropriate (up-to-date)
drawings in 10CFR50 Appendix B Criterion V, Peach Bottom QA Plan Section
2, and Peach Bottom Precedure A-6. (217/81-19-03)
,
.
..
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b.
TAP Item II.E.4.2.5--Containment Isolation Dependability
Pressure Setpoint
The containment setpoint pressure that initiates containment
isolation for non-essential penetrations must be the minimum
compctible with normal operating conditions (within one PSI of
maximum pressure normally expected). The licensee's response, dated
January 8, 1981, justifies the current setpoint of 2.0 PSIG using
-rationale outlined in NUREG-0737. NRC:NRR accepted this submittal
in a letter dated July 14, 1981. This item is closed.
c.
TAP Item II.E.'4.2.7--Containment Isolation Dependability
--High Radiation Trip
Containment purge and vent isolation valves must close on a high
radiation signal. The licensee's December 22, 1980 submittal
indicated that discussions with the licensing staff were in progress
and that a schedule for implementation would follow. The inspector
contacted the NRC Licensing Project Manager, who stated that the
item is still under discussion, and further correspondence will
result. This item remains open.
d.
TAP Item II.K.3.13--HPCI and RCIC Initiation Levels-
The initiation levels of the HPCI and RCIC system should be
separated so that the RCIC system initiates at a higher water level
than the HPCI system.
Further, the initiation logic of the RCIC
system should be modified so that the RCIC system will restart on
low water level. These changes have the potential to reduce the
number of challenges to the HPCI system and could result in less
stress on the vessel from cold water injection. Analyses should be
performed to evaluate these changes, and submitted to the NRC staff.
Modifications shall be implemented if justified by the analyses.
The licensee participated in a Boiling Water Reactor Owners' Group
program to study this issue. The owners group conclusion, endorsed
by the licensee, was that separation of the initiation levels would
yield only minimal reduction in the thermal cycle history.
-_ Automatic restart of the RCIC was considered beneficial, however. A
representative of NRR stated that the owners group report is under
review.
-The licensee committed to implementation of the automatic restart
feature by July 1, 1981. The inspector reviewed the modification
package, verified PORC review of the modification, and interviewed
licensee personnel. The modification makes the high reactor water
level trip effective on the steam' supply valve rather than the
. _ _ _ -_ - . - _ - _ _ _ _ _ _ _ . - _ - _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ - _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _
.
.
17
turbine trip and throttle valve, so that no manual. reset is-
required. The modification was completed at Unit 2 on June 18,
1981, and is being completed during the current Unit 3 outage. This
item remains open (Unit 3 only).
e.
TAP Item II.K.3.15--HPCI and RCIC Break-Detection Logic
The HPCI and RCIC steam line break detection circuitry should be
modified so that pressure spikes resulting from. system initiation
will not cause inadvertent system isolation.
The licensee participated in a BWR Owners' Group evaluation of this
issue and concluded that a time delay in the break detection
circuitry should eliminate any spurious isolations from flow peaks
during a normal system start. Further, the time delay preserves the
4
break detection. capabilities and does not impact on the design basis
accident analysis of HPCI and RCIC steam line breaks. An NRC:NRR
representative stated that the owners group position is under staff
review.
,
i
The licensee committed to installation of a three-second time delay
,
feature by July 1, 1981.
The inspector reviewed the modification
package, verified PORC review of the modification,-and interviewed
licensee personnel. PORC minutes indicated that no Technical
Specification change was needed, whereas the Safety Evaluation
.
recommended additions to the Technical Specifications but concluded
' .
that prior approval was not needed. 14 licensee representative
stated that the inconsistency was an oversight in PORC minutes and
that revision would be submitted for PORC review.
(The actual
Technical Specifications change request had been received by PORC in
-
,
!
a separate action).
Further, the licensee reviewed other
modifications in progress during the current Unit 3 outage and
determined that clarification of PORC minutes was warranted in one
additional case. The modification was completed at Unit 2 on May
26, 1981 and is being completed during the current Unit 3 outage.
.
This item remains open (Unit 3 only),
9.
In-Office Review of Monthly and Special Reports
j
The following licensee reports have been reviewed in-office onsite.
3
a.
Peach Bottom Atomic Power Station Monthly Operating Report for:
July, 1981 dated August 14, 1981
This report was reviewed pursuant to Technical-Specifications and
verified to determine that operating statistics had been accurately
reported and that narrative summaries of the month's operating
'
experience were contained therein. No unacceptable conditions were
identified.
7
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_-__._-____._.___.,___.__.------.___.____._-_a
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b.
Thermal Mapping Reports:
No. 81-2 for July 22, 1981, transmitted August 17,.1981
.,
No. 81-3 for July 28, 1981, transmitted August 17, 1981
These reports were reviewed pursuant to Environmental Technical
Specifications to verify that the required data had been. submitted to
NRC:NRR. No unacceptable conditions were identified.
'
10. Management Meetings--Preliminary Inspection Findings
A summary of preliminary findings was provided to the Station
Superintendent at the conclusion of the inspection. During the period of
this inspection, licensee management was periodically notified of the
preliminary findings by the resident inspectors.
The dates involved, t!-
senior licensee representative contacted, and subjects discussed were as
follows.
Date
Subject
Senior Licensee Representative Present
,
August 7
Routine discussions
Station Superintendent
August 12
LER 2-81-37/IP (Detail 4)
Assistant Station Superintendent
August 14
Routine Discussions
Station Superintendent
,
August 19
Maintenance procedural
Maintenance Engineer
adherence
August 20
Shift Operations Procedural
Operations Engineer
Adherence
,
August 21
LCO and procedural adherence Station Superintendent
4
(Detail 4), Surveillance
Testing (Detail 7), and
Routine Discussions
August 28
Routine Discussions
Station Superintendent
September 3
Summary of Preliminary
Station Superintendent
Findings
!
2
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