ML20138Q164
| ML20138Q164 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 12/18/1985 |
| From: | Beall J, Gallo R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20138Q147 | List: |
| References | |
| 50-277-85-29, 50-278-85-33, NUDOCS 8512270076 | |
| Download: ML20138Q164 (31) | |
See also: IR 05000277/1985029
Text
i:.
.
V. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No. 50-277/85-E9 & 50-278/85-33
Docket No. 50-277 & 50-278
Licensee: Philadelphia Electric Company
2301 Market Street
Philadelphia, Pennsylvania 19101
Facility Name: Peach Bottom Atomic Power Station Units 2 and 3
Inspection at: Delta, Pennsylvania
Inspection conducted: September 14 - October 25, 1985
Inspectors: T. P. Johnson, Senior Resident Inspector
J. H. Williams, Resident Inspector
J. P. Rogers, Reactor Engineer
Reviewed by: /hF #5~
J. Beall, Project Engineer date
Approved by: b
Robert M. Gallo, Chief
I
_date
(8 87
Reactor Projection Section 2A
Inspection Summary: Routine, on-site regular and backshift resident inspection
(157 hours0.00182 days <br />0.0436 hours <br />2.595899e-4 weeks <br />5.97385e-5 months <br /> Unit 2; 140 hours0.00162 days <br />0.0389 hours <br />2.314815e-4 weeks <br />5.327e-5 months <br /> Unit 3) of accessible portions of Unit 2 and 3,
operational safety, radiation protec+. ion, physical security, control room
activities, li ensee events, surveillance testing, refueling and outage
activities, mai..tenance, and outstanding items.
Results: Licensee management continued their involvement in Unit 2 and 3 opera-
tions. Personnel generally implemented station procedures except for the
following areas: administrative procedures for blocking and procedural revi-
sions (4.2.2); RHR system operating procedures (4.2.2); and, a surveillance
procedure for the portal monitor (4.1). Three of the 11 main steam safety
relief valves on Unit 3 apparently were not tested during the last operating
cycle.(7.2). During the period August 29 through October 10, 1985 eight RPS
actuations occurred in Unit 3 and no reports were made to tha NRC in accordance
with 10 CFR 50.72. The actuations were not reported due to a misinterpretation
of the requirements of 10 CFR 50.72 and 50.73 (4.3). Control Room operator
response during a feedwater transient and scram on Unit 2 was good.
8512270076 851220
PDR ADOCK 05000277
G PDR
.
.
DETAILS
1. Persons Contacted
J. F. Mitman, Maintenance Engineer
- R. S. Fleischmann, Manager Peach Bottom Atomic Power Station
A. Fulvio, Technical Engineer
A. E. Hilsmeier, Senior Health Physicist
D. L. Oltmans, Senior Chemist
F. W. Polaski, Outage Planning Engineer
S. R. Roberts, Operations Engineer
D. C. Smith, Superintendent Operations
S. A. Spitko, Administration Engineer
J. E. Winzenried, Superintendent Plant Services
Other licensee employees were also contacted.
- Present at exit interview on site and for summation of preliminary findings .
2. Plant Status
2.1 Common
NRC Commissioner Zech toured the Peach Bottom facility on September
19, 1985. He met with the licensee management, the NRC Resident
Inspectors and Region I management personnel including the Regional
Administrator. The Commissioner also held discussions with licensee
Control Room licensed operators.
On September 23, 1985, a PECo chemistry technician drowned while
obtaining a sample in the discharge canal. His body was recovered on
September 25, 1985, by Pennsylvania State Police divers.
The annual Peach Bottom Emergency Exercise was held October 17, 1985.
NRC Inspection 277/85-36 and 278/85-34 evaluates this exercise.
2.2 Unit 2
The unit began the report period at 100% power. On September 19,
1985, the unit was shutdown due to simultaneous inoperability of the
E-2 diesel generator and the 2A RHR pump (see detail 4.2.1).
The unit remained shutdown until October 4, 1985, when unit startup
was effected. The unit achieved 100% power on October 6, 1985.
The unit remained at 100% power until October 17, 1985, when Unit 2
scrammed on low reactor water level due to loss of feedwater (see
detail 4.2.3). The unit was restarted on October 18, 1985, and
achieved 100% power on October 19, 1985. The unit remained at 100%
power the remainder of the report period.
m
, . - -_ _ -._ . . _ _ _.
.
.
3
2.3 Unit 3
Unit 3 remained in a refueling / outage status during the entire report
period.
Major items completed during the inspection period were LPRM exchange,
SRM and IRM dry tube replacement, fuel reconstitution, diesel generator
annual inspections, core spray sparger' repair, IGSCC inspections and
recirculation suction pipe N-1 safe end plug sample removal.
Major items remaining are completion of recirculation and RHR piping
overlays, completion of system work and return to service, fuel
reload, vessel assembly and hydro, ILRT and unit startup (see detail
4.4).
Startup is scheduled for January 1986.
3. Previous Inspection Item Update
3.1 (Closed) Violation (277/84-17-02). Failure to take prompt corrective
action in response to identified failures to comply with maintenance
department administrative (MA) procedures. The licensee responded to
the violation in a letter dated August 8, 1984. The inspector
reviewed the licensee response and determined it to be adequate.
"
Five MA procedures had been identified as overdue for their required
two year review. The inspector verified that the five MA procedures
(MA-4, MA-8, MA-11, MA-15 and MA-17) were reviewed and revised in
1984. In addition, a check was made of all other MA procedures to
ensure they were reviewed within two years. All MA procedures were
reviewed in calendar year 1984 or 1985. The licensee instituted a
tracking system for ensuring MA procedures are reviewed and revised
as required. This item is closed.
3.2 (Closed) Uqresolved Item (277/83-37-01). Secondary Containment Door
Alarms. The inspector had noted many malfunctioning secondary con-
tainment door indicators (blue lights and position switches) and
numerous instances of personnel disregarding the blue light interlock.
In order to meet secondary containment integrity, Technical Specifi-
t
cation 3.7.C/4.7.C, at least one door in each access opening in the
reactor building must be closed. The blue light system reminds personnel
of this requirement. If a blue light is lit above a secondary con-
tainment door, the door is not to be opened as another door is already
opened. Opening both of these doors would thus breach secondary
4
containment integrity. The secondary containment access system is
tested every 2 months by performance of routine test, RT-1.8.1,
" Secondary Containment Access Control System Alarm Test," Revision 4,
September 20, 1983. This test verifies operability of the blue light
!
!
4
_
j
<
, - - - , , - - a ,,,.m e , - , _ , , , , - - - , , - - , ----,-.-e ,, - . - - -,.w.--- , , - -
.
.-
4
system, the local audible alarms, and the remote control room annun-
ciator alarms. The inspector verified that this test is being per-
formed as r: quired with satisfactory results. Also, the inspector
observed the satisfactory operation of the secondary containment
access control system on both Unit 2 and Unit 3. Based on licensee
satisfactory performance of RT-1.8.1 and inspector observations, this
item is closed.
3.3 (Closed) Violation (277/84-07-01; 278/84-07-01). Failure to follow
Standby Gas Treatment System (SGTS) Procedure. The licensee responded
to the violation in a letter dated June 7, 1984. The response was
reviewed by the inspector and found to be acceptable. The licensee
revised the SGTS operating procedure of concern. The inspector reviewed
the revised procedure, S.10.5.G, Manual Swap Over of Reactor Building
Equipment Cell Exhaust to Standby Gas, Revision 2, October 22, 1984.
The revised procedure S.10.5.G deletes two steps that were done
-locally in the SGTS room. These deleted steps are addressed adequately
in another procedure, SGTS Setup for Automatic Operation, S.10.5.A,
Revision 2, May 18, 1979. This item is closed.
3.4 (Closed) Inspector Follow Item (277/84-15-02). Standby Gas Treatment
System (SGTS) fan logic problem. A failure of the SGTS fan A inlet
and outlet dampers occurred on a system start on Unit 2 on April 27,
1984. This damper failure concurrent with a SGTS automatic initiation
caused by a group III isolation, would have made the SGTS inoperable.
This was due to the design of the B SGTS standby fan start circuit
differential pressure switch (OPS). This DPS senses SGTS differential
pressure (DP) and automatically starts the B SGTS fan on a no flow
condition. In this case, a no flow condition would have occurred;
however, the DPS would have sensed adequate DP, and the B SGTS fan
would not have been given a start signal. The licensee issued LER
2-84-08, May 29, 1984, and LER 2-84-08, Revision 1, dated July '
,
1985. The inspector reviewed both these LERs. The revised LER
referenced a system modification that would replace the DPS with
pitot tube flow elements and flow switches (FE/FS). These FE/FS
numbered 70004 and 70005 would ensure that the B SGTS fan would auto
start on no flow conditions for the A SGTS fan (Unit 2) or for the C
SGTS fan (Unit 3). Modification 1505 (plant MOD 84-088) was completed
on both Unit 2 and 3 on January 10, 1985. The inspector reviewed the
completed MOD package including the following documentation: Modiff-
cation correspondence, PORC approval sheet, safety evaluation, main-
tenance request forms, construction job memo, field engineer check-
out, modification acceptance test, vendor information: and revised
electrical drawings (E-206 Rev. 24). The inspector discussed the
modification with the licensee. The inspector noted that the current
Q-list, Revision 20, August 21, 1984, did not include the modified
FE/FS 70004 and 70005. The inspector contacted the licensee's
Mechanical Engineering Department to ensure that the FE/FS 70004 and
70005 were to be included in the next revision to the Q-list. The
inspector had no further questions. This item is closed.
L_
.
.
5
3.5 (Closed) Violation (277/84-17-02). Inadequate acceptance criteria in
surveillance procedures. The licensee responded to the violation in
a letter dated August 8, 1984. The inspector reviewed the response
and determined it to be acceptable. The licensee revised the 3
affected procedures, ST12.15.1-3, ST 12.15.3-3, and ST 12.15.4-3, to
include more definitive acceptance criteria. The inspector reviewed
the 3 revised STs and determined that they were adequate. This item
is closed. i
l
3.6 (Closed) Violation (277/84-15-05). Failure to post a_ radioactive
contamination area. The licensee responded to the violation in a
letter dated August 10, 1984. The inspector reviewed the licensee's
response and found it acceptable. The licensee has instructed all HP
personnel to include fire barrier seals in the swipe surveys as they
are potentially contaminated areas. The inspector verified this
through discussions with HP personnel. This item is closed.
3.7 (Closed) Unresolved Item (50-278/80-21-02). Withdrawing a control
rod with badly damaged seals. The licensee developed a proccdure to
provide instructions for withdrawing a control rod with badly damaged
seals. The inspector reviewed procedure S.4.3.Q, " Withdrawal of a
Control Rod With Badly Damaged CRD Seals", Revision 0, August 25,
1980. The inspector noted that the procedure requires implementation
under the direction of a reactor engineer and that precautions are
included to provide actions if a control rod block alarm occurs. If
a controi rod block alarm occurs from the Rod Block Monitor system,
the procedure requires immediate removal of the jumper that was
applied in order to cause the rod withdrawal motion. The inspector
discussed the use of this procedure with the licensee and verified
that operators were knowledgeable. Based on the licensee's procedure
S.4.3.Q, the inspector's review of the procedure and discussions with
licensee personnel, this item is closed.
3.8 (Closed) Unresolved Item (277/79-09-01; 278/79-10-01). Administrative
Procedure A-42, Revision 7, Jumper Log Procedure, did not require
PORC review and approval for jumper installation on safety related
equipment. Procedure A-42 was revised and the current A-42, Revision
9, dated April 25, 1985, requires that "all jumpers shall be installed
via specific PORC approved procedures or the PECo blocking permit if
required as part of the permit". The inspector reviewed several
recent safety related jumpers and the implementing procedures listed
in the jumper log. The inspector verified that the use of the
jumpers had been PORC approved prior to jumper installation. This
item is closed.
. I
6
3.9 (Closed) Unresolved Item (277/79-09-07; 278/79-10-07). Complet,ed
surveillance tests were filed in standard file cabinets with no fire
rating pending shipment to permanent storage and microfilming. Some
completed tests had been stored for an extended period of time. A
system for the collection and storage of records was discussed in the
letter from S. L. Daltroff to T. T. Martin (NRC) dated October 19,
1981. The letter stated that the licensee would be in full compliance
with the requirements of ANSI N45.2.9 by June 1983. In November,
1983,.the NRC found a backlog of completed maintenance request forms
(MRFs) stored in several cardboard boxes under desks and along aisles
and radiation work permits stored ir, stacks on desks. Violations
277/83-32-01 and 278/83-30-01 were subsequently issued. The licensee
actions to comply with ANSI N45.2.9 will be inspected as part of the
inspection of the corrective action to the violations. This unre-
solved item is closed.
3.10 (Closed) Unresolved Item (277/79-09-09; 278/79-10-09). Administrative
Procedure A-26, Procedure for Corrective Maintenance, did not require
the licensee to document the cause of the failure, malfunction, or
defect, and corrective action taken to preclude repetition. Equipment
failures are documented on the Maintenance Request Form (MRF), which
includes documentation of corrective actions. Administrative Proce-
dure A-26 covers the use of the MRF. The Computerized History and
Maintenance Planning System (CHAMPS) maintains a history file on all
equipment. A-26 also states that the preparation of the Licensee
Event Report (LER) provides a mechanism for evaluating malfunctions
of items specified in the Technical Specifications. The LERs include
cause, corrective action, and action to prevent recurrence. In addi-
tion, the I&C Engineer and Maintenance Engineer are responsible for
the review of failure of "Q" listed equipment and equipment essential
to electric power generation. Based on the above, this item is closed.
3.11 (Closed) Unresolved Item (277/79-09-04; 278/79-10-04). No written
program or documentation to demonstrate that the Plant Operation
Review Committee (PORC) and Off Site Review Committee (OSRC) performed
review, evaluation, and corrective action relative to failure to
follow procedures as required by Technical Specification 6.5.1.6.e.
The inspector reviewed Technical Specification 6.5.1.6.e, Administra-
tive Procedure A-4, Plant Operations Revew Committee Procedure, and
recent PORC meeting minutes. When a violation or suspected violation
of Technical Specifications, internal rules, procedures, or regulations
is identified, the PORC investigates the cause and recommendations to
prevent recurrence as documented in the PORC minutes. The PORC minutes
are then sent to the Nuclear Review Board (NRB) which replaced the
OSRC. The NRB reviews the PORC minutes and documents this in the NRB
minutes. The inspector reviewed selected NRB meeting minutes to
verify this. Based on the above, this item is closed.
".
.
1
3.12 (Closed) Unresolved Item (277/79-09-05; 278/79-10-05). Only those
nonconformance reports (NCRs) deemed significant by the QA Division
Superintendent were sent to the OSRC (currently called the Nuclear
Review Board) for their review. All NCRs are listed and discussed in
the PORC minutes. All PORC minutes are reviewed by the NRB. Also, a
log of all QA NCR's is distributed to the NRB members. Based upon
this information being available to NRB members for further review as
desired,.this item is closed.
3.13 (Closed) Inspector Follow Item (278/85-27-01). Unit 3 core spray
sparger cracks. This item is closed based on detail 4.4.1.
4. Plant Operations Review
4.1 Station Tours
The inspector observed plant operations during daily facility tours.
The following areas were inspected:
--
Control Room
--
Cable Spreading Room
--
Reactor Buildings
--
Turbine Buildings
--
Radwaste Building
--
Pump House
--
Diesel Generator Building
--
Protected and Vital Areas
--
Security Facilities (CAS, SAS, Access Control, Aux SAS)
--
High Radiation and Contamination Control Areas
--
Shift Turnover
--
Unit 3 Drywell
During a daily plant tour on September 25, 1985, the inspector noted
that the portal monitor on the 165 foot level of the administrative
building bridge was due for its 6 month calibration on July 7, 1985,
as indicated on the calibration sticker attached to the monitor. This
portal monitor, Eberline model PMC-48 serial number 332, checks for
potential personnel contamination when exiting the power block at the
165 foot level of the turbine building and proceeding to the adminis-
trative building. The inspector immediately notified the licensee of
the potential out of calibration portal monitor. The licensee began
an investigation to determine the calibration status of the portal
monitor.
There are two types of portal monitors in use at the station;
Eberline model PMC-4B and Instrumentation Research Technology (IRT)
model PRM-110. At the 165 foot administrative building bridge there
is one Eberline portal monitor. At the 116 foot turbine
building / power block exit there are two IRT portal monitors with a
backup Eberline monitor which is not normally in use. At the securi-
.
.
8
ty building exit concourse there are two IRT portal monitors with two
backup Eberline monitors which are not normally in use.
The inspector checked the calibration status of the IRT portal moni-
tors. Procedure RT-7.32, Portal Radiation Monitor Model PRM-110 Sen-
sitivity and Source Check, Revision 1, January 27, 1983, was
reviewed. The inspector verified that all four IRT portal monitors
currently in use were in calibration by reviewing the completed
monthly RT 7.32 procedures performed during the period April to Sep-
tember 1985.
Technical Specification 6.8.1 requires implementation of procedures
for Surveillance Testing. Surveillance Test Procedure ST 4.9.B, Por-
tal Monitor Calibration and Source Check, Revision 3, June 21, 1983
and HPA-53, Calibration of Portal Monitors, Revision 1, August 8,
1978, detail the calibration frequency and calibration procedures for
the Eberline Model PMC-48 portal monitors. The inspector checked the
most recently completed ST 4.9.B test results. Quarterly source
checks were performed on August 10, 1984, October 1,1984, January 7,
1985 and April 2, 1985. Semi-annual calibrations were performed on
August 10, 1984 and on January 7, 1985. The source check and cali-
bration were due again on July 7,1985; however no records of the
completion of this surveillance were available. On September 26,
1985, the licensee informed the inspector that the ST 4.9.8 procedure
performance was missed for the Eberline portal monitors on July 7,
1985, due to an oversight. All Eberline portal monitors were cali-
brated on September 25, 1285; and verified by the inspector. Failure
to perform a required surveillance test procedure is an apparent vio-
lation of Technical Specification 6.8.1. (277/85-29-02).
4.~ 1.1 Control Room and facility shift staffing was frequently
checked for compliance with 10 CFR 50.54 and Technical
Specifications. Presence of a senior licensed operator in
the control room was verified frequently.
4.1.2 The inspector frequently observed that selected control
room instrumentation confirmed that instruments were opera-
ble and indicated values we*e within Technical Specifica-
tion requirements and normal operating limits. ECCS switch
positioning and valve lineups were verified based on con-
trol room indicators and plant observations. Observations
included flow setpoints, breaker positioning, PCIS status,
and radiation monitoring instruments.
4.1.3 Selected control room off-normal alarms (annunciators) were
discussed with control room operators and shift supervision
to assure they were knowledgeable of alarm status, plant
conditions, and that corrective action, if required, was
being taken. In addition, the applicable alarm cards were
checked for accuracy. The operators were knowledgeable of
alarm status and plant conditions.
.
,
.
.
9
4.1.4 The inspector checked for fluid leaks by observing sump _
status, alarms, and pump out rates; and discussed reactor
coolant system leakage with licensee personnel.
4.1.5 Shift relief and turnover activities were monitored daily,
including backshift observations, to ensure compliance with
administrative procedures and regulatory guidance. No in-
adequacies were identified.
4.1.6 The inspector observed main stack and ventilation stack
radiation monitors and recorders, and periodically reviewed
traces from backshift periods to verify that radioactive
gaseous release rates were within limits and that unplanned
releases had not occurred. No inadequacies were
identified.
4.1.7 The inspector observed control room indications of fire
detection instrumentation and fire suppression systems,
monitored use of fire watches and ignition source controls,
checked a sampling of fire barriers for integrity, and ob-
served fire-fighting equipment stations. No inadequacies
were identified.
4.1.8 The inspector observed overall~ facility housekeeping condi-
tions, including control of combustibles, loose trash and
debris. Cleanup was spot-checked during and after mainte-
nance. Plant housekeeping was generally acceptable.
4.1.9 The inspector verified operability of selected safety re-
. lated equipment and systems by in plant checks of valve
positioning, control of locked valves, power supply avail-
ability, operating procedures, plant drawings, instrumenta-
tion and breaker positioning. Selected major components
were visually inspected for leakage, proper lubrication,
cooling water supply, operating air supply, and general
conditions. No significant piping vibration was detected.
The inspector reviewed selected blocking permits (tagouts)
for conformance to licensee procedure,. No inadequacies
were identified. >
4.1.10 The inspector observed portions of the Unit 2 plant startup
on October 4, 1985, including the following:
--
Rod Sequence Control System and Rod Worth Minimizer
System operations.
--
Control Rod Withdrawal.
--
Main turbine startup and generator synchronization.
.
l
l
r
. - .__ . - --
_
.
10
--
Implementation of procedure GP-2, Normal Plant
Startup, Revision 39, March 20, 1985.
--
Additional licensed operator present for startup.
--
Shift Supervisor and Shift Superintendent frequent
supervision of licensed reactor operators involved in
startup activities.
The startup was being performed in accordance with plant
startup and system operating procedures. No unacceptable
conditions were . identified.
4.2 Followup On Events Occurring During the Inspection
4.2.1 Unit 2 2A RHR Pump Abnormalities
At 7:15 p.m. on September 19, 1985, the licensee declared
an Unusual Event and began to shutdown Unit 2 because the
2A RHR pump was declared inoperable due to low flow (Tech-
nical Specification 4.5.A), concurrent with the E-2 diesel
generator out of service for annual maintenance. Technical
Specification 3.5.F.1 requires the reactor to be in cold
shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> with one low pressure emergency
core cooling system and a diesel generator out of service.
The reactor was manually scrammed at 9:51 p.m. from 30%
power. Group II and III primary containment isolations
occurred because of the low water level transient resulting
from the scram. The E-2 diesel generator was returned to
service at 2:55 a.m. on September 20, 1985, and the Unusual
Event was terminatec. The licersee tested the pump in ac-
cordance with ST 6.8, RHR A Pump, Valve, Flow and Cooler
Test, Revision 27, August 24, 1985, and based upon these
tests decided to disassemble the pump and inspect the pump
internals. The licensee proceeded to cold shutdown to in-
vestigate the 2A RHR pump problem. During the period Sep-
tember 20-23, 1985, the 2A RHR pump was disassembled, the
pump internals and suction strainer were inspected, and the
pump was reassembled. No problems nor abnormalities were
noted. Subsequently, on September 23, 1985, pump testing
in accordance with ST 6.8, led to unsatisfactory results.
The unit remained shut down during the period September 23
- October 3, 1985, as the licensee continued to investigate
the 2A RHR pump flow and pressure abnormalities. The 2A RHR
pump exhibited lower than expected discharge pressure at
pump flows greater than 11,200 gpm. The licensee plotted
the 2A RHR pump curve data, pump developed head versus
flow. The licensee additionally examined the pump inter-
nals, piping, suction valve and torus strainer for obstruc-
tions and found none. The pump was run with the suction
.
..
11
strainer removed and then with the strainer installed.
There was no difference in the flow characteristics as the
ST 6.8 data was unable to meet the test acceptance
criteria.
The inspector reviewed the ST 6.8 data-taken during the
period September 19 through October 4, 1985. The inspector
also reviewed selected test data (pump head and flow) when
plotted on the Bingham pump curve M-1-V-284-1. Normal pump
discharge pressure was 200 psig at flows of 11,500 gpm;
however, the pump was exhibiting discharge pressures of the
range 140 to 170 psig at pump flows of 11,500 gpm.
Technical Specification 4.5.A requires that each RHR pump
deliver 10,900 gpm against a system head corresponding to a
vessel pressure of 20 psig based on individual pump tests.
ST 6.8 acceptance criteria for RHR pump flow is 11,500 gpm.
Previous tests for the 2A RHR pump met the acceptance cri-
teria of 11,500 gpm. The inspector reviewed selected ccm-
pleted ST 6.8 for the period 1977 - 1985. No abnormalities
were observed. On October 2, 1985, the licensee submitted
an emergency Technical Specification change request to al-
low a lower 2A RHR pump flow. On October 3, 1985, the
licensee informed the inspector that PECo engineering had
evaluated the 2A RHR pump flow problem and had determined
that the pump could currently meet the Technical Specifi- g
cation requirement of 10,900 gpm. The licensee stated that
the ST 6.8 acceptance criteria.of 11,500 gpm was based on
pump runout criteria and not Technical Specification re-
quirements. The 2A RHR pump data shows that at a flow of
10,900 gpm, the pump operates on the pump curve. The in-
spector verified this by irdependently plotting pump head
and flow data. Based on this PECo engineering evaluation, ,
the licensee declared the 2A RHR pump operable after satis-
factory completion of ST 6.8 on October 3, 1985. Unit 2
was then prepared for restart. The inspector reviewed the
ST 6.8 test results and the temporary procedure change
(TPC) to ensure compliance with Technical Specification 6.8.3 and Administrative Procedure A-3, Procedure for Tem- *
'
,
porary Changes tv Approved Procedures, Revision 7, January e
/!
7, 1985. The TPC was approved by two people, one SR0 and
one member of PORC. The inspector also verified that the
"
PORC approved this TPC by attending the PORC meeting on
October 4, 1985. (See detail 4.6.)
The inspector reviewed the licensee's formal engineering
evaluations of the 2A RHR pump test data, dated October 4,
1985 and October 9, 1985. The evaluations state that the
Technical Specification requirement of 10,900 gpm at 20
psig reactor pressure can be met if the 2A RHR pump oper-
ates "on the pump curve" at 10,900 gpm and at a minimum of
=
, _ , _ _ - . ,, __. - - - - . - _ - . -
.
.
12
" '
- s.4
.
> '
'l 205 psig discharge pressure. The evaluations also state
the original ST 6.8 acceptance criteria of 11,500 gpm ras
based on pump runout criteria in a broken loop. An accep-
tance criteria of 10,900 gpm was considered satisfactory to
meet the Technical Specification 4.5.A required flow.
The inspector discussed the status of the 2A RHR pump with
,c the Station Manager. Based on these discussions, the
N. licensee intended to declare the 2A RHR pump operable, per-
form plant startup, and perform the following:
(1) Weekly testing of the 2A RHR pump per ST 6.8.
(2) Trending test data for the 2A RHR pump to monitor po-
N. s- tential further degradation.
'E
(3) ' Pursuing 2A RHR pump repairs during a Unit 2 outage
currently scheduled for late November, 1985.
The inspector reviewed 2A RHR pump ST data performed on
October 3, 10, 11, 16 and 25, 1985. This test data met
the 2A RHR pump acceptance criteria of greater than 205
psig discharge pressure at a flow af 10,900 gpm.
The inspector will continue to follow these activities.
(IFI 277/85-29-03.)
4.2.2 Unit 2 Engineered Safeguards Features (ESF) Actuation
s
At 6:07 p.m. on September 24, 1985, an ESF actuation oc-
curred on Unit 2 while in cold shutdown. The ESF actuation
was due to low reactor water level and caused a reactor
T
scram signal and Group II/III primary containment isola-
tion. The low reactor water level condition was caused by
the draining of the reactor vessel via the shutdown cooling
suction lines for the 2C RHR pump and through the RHR full
flow test line to the torus. The licensee initially esti-
mated that reactor water level decreased from a level of an
initial value of +25" to about -20". The reactor was shut-
down prior to the event and no control rod motion occurred.
. The Group II/III isolations operated correctly. Reactor
level was restored to normal, and the scram signal and the
Group II/III isolations were reset. The licensee made an
s
ENS call per 10 CFR 50.72.
The inspector reviewed the control room logs, recorder
traces and discussed the event with the operators. Further
discussions were conducted with licensee operations
supervision.
. .- .- - .
_
.
13
.
The Unit 2-licensed reactor operator was completing RHR
system operating procedure S.3.2.C.1, Shutdown Cooling
Mode, Revision -13, July 26,1984, in order to remove the 2C
RHR pump from shutdown cooling. The operator did not close
valve MO-2-10-15C, 2C RHR pump shutdown cooling suction
valve as required by S.3.2.C.1. The operator then began
implementing RHR system operating procedure S.3.2.C.3,
Placing Torus Cooling In Service, Revision 9, March 28,
1985, for the 2A RHR pump. Procedure S.3.2.C.1 opened RHR
torus return valves MO-2-10-39A and 34A. This_ valve align-
ment allowed the reactor vessel to gravity drain from the
shutdown cooling lines through the 2C RHR pump to the torus
via the torus cooling return line. Once the vessel level
reached zero inches reference, a Group II/III primary con-
tainment isolation occurred, closing the RHR shutdown cool-
ing valves M0-2-17 and 18. This isolated the drain path.
Reactor water level was recovered by the condensate pumps
that were operating in automatic startup level control on
long path recirc. The licensee estimated that level
dropped about 35 inches.
Inspector review of control room reactor water level re-
corders indicated the following:
(1) The reactor water level recorder LR-96 trace which is
fed from level indicator LI-94, went from +25 inches
to zero inches. The scale is from zero inches to +60
inches and the instrument is calibrated at 1000 psig
<
and is automatically density compensated; and the lev-
el trace indicates true level.
(2) The reactor water level recorder LR-110 trace, which
is fed from level transmitter LT-110A, went from
greater than +50 inches to +15 inches. The scale is
-.
+50 inches to -165 inches and the instrument is cali-
.broted at 1000 psig. Since the plant was in cold
shutdown, the +15 inches indicated level has to be
adjusted to obtain true level. The licensee deter-
mined that the actual level was -7 inches based on
instrument calibration data.
The inspector discussed this event with the licensee. Dis- ,
ciplinary action was taken against the licensed operator. '
The licensee indicated that RHR procedure S.3.2.C.1 would a
be revised to ensure procedure completion prior to entry l
into another RHR procedure. The inspector reviewed the i
licensee's upset report regarding the event, including the
analysis for actual level based on instrument calibration
data. The inspector independently calculated the level
decrease, and this calculation concurs with the licensee
l
l
'
. ,
{
.
14
determined value. The licensee issued a LER for this
event. (See detail 6.2.5.)
The cause of this event was a violation of the RHR system
operating procedure S.3.2.C.1, however because the NRC
wants to encourage and support licensee initiative for
self-identification and torrection of problems no notice of
violation is issued-since (1) the licensee identified the
problem, (2) it fits Severity Level IV or V, (3) the viola-
tion will be reported as an LER, (4) measures were taken to
correct the problem and additional measures were taken to
prevent recurrence, and (5) it is not a-violation that
could reasonably be expected to have been prevented by cor-
rection of a previous violation. The inspector had no fur-
ther questions at this time.
4.2.3 Unit 2 Scram On Loss of Feedwater
At 9:21 a.m. on October 17, 1985, Unit 2 scrammed on low
reactor level (0 inches) from 100% power due to a total
.. loss of reactor feedwater. All three operating turbine-
driven reactor feedwater pumps tripped on overspeed due to
a malfunction of the automatic feedwater control system.
Reactor wa:er level decreased to -95 inches indicated-(-178
inches is the top of the active fuel). Primary containment
isolations occurred for Groups I, II, III and the reactor
T
recirculation pumps tripped on low-low level. RCIC and HPCI
auto initiated and injected into the reactor vessel to re-
cover level to +50 inches by 9:25 a.m. The licensee de-
clared an Unusual Event, made an ENS call, and issued a
S- press release.
s The cause of the feedwater control system malfunction was
determined by the licensee to be a loose connection in the
feedwater flow summer unit, General Electric supplied de-
vice FSUM-2-6-103. ~The flc summer unit is connected by
-
use of a retractable ribbon cable. This cable has 18 male
connections which slip fit into the flow summer unit and
lock with-the use of two tabs. The flow summer unit then
may slide-in and out of the control cabinet. The licensee
discovered that the connector was loose causing a loss of
flow summer unit output signal. lhis loss of output signal
was sensed by the steam flow / feed flow comparator unit as a
false loss of feed signal. This then resulted in a signal
being sent to all three reactor feed pump turbines to in-
crease feed flow, resulting in a transient which caused all
3 reactor feed pumps to trip on overspeed. The licensee
replaced the flow summer unit with an identical device from
. Unit 3, which was shutdown for refueling. The inspector
reviewed electrical schematic drawing (ESD) on the
feedwater control system, 6280-MI-5-25, Revision 40, dated
.
~.
15
June 17, 1985. This ESD shows that a zero output from the
- total feedwater flow summer unit (FSUM-2-6-103) would be
sensed by the feed flow / steam comparator unit, causing a
command signal to be sent to all operating reactor
feedwater pumps to increase speed. The inspector also re-
viewed the preliminary licensee upset report for the event
and the completed GP-18, Scram Review Procedure.
The Senior Resident Inspector and 3 other NRC Region I in-
spectors were in the control room.at the time of the tran-
sient and scram observing the annual emergency exercise.
The licensee recovery actions were good. Once reactor lev-
el was stabilized, the licensee secured HPCI and RCIC, re-
opened the MSIVs and placed the C reactor feed pump in
service. Unit 2 restarted on October 18, 1985, and the
reactor was critical at.6:35 a.m. The unit achieved 100%
power on October 20, 1985. The feedwater control system
responded normally in automatic 3-element control during
power escalation.
, Within the scope of this review, no violations were
identified.
4.3 Logs and Records
The inspector reviewed logs and records for accuracy, completeness,
abnormal conditions, significant operating changes and trends, re-
quired entries, operating and night order propriety, correct equip-
ment and lock-out. status, jumper log validity, conformance to
Limiting Conditions for Operations, and proper reporting. The fol-
lowing logs and records were reviewed: Shift Supervision Log, Reac-
tor Engineering Log Unit 2, Unit 2 Reactor Operator's Log, Unit 3
' Reactor Operator's Log, Control Operator Log Book and STA Log Book,
Night Orders, Radiation Work Permits, Locked Valve Log, Maintenance
Request Forms and Ignition Source Control Checklists. Control Room
logs were compared against Administrative Procedure A-7, $Sitt
Operations. Frequent initialing of entries by licensed operators,
shift supervision, and licensee on-site management constituted evi-
dence of licensee review.
On October 11, 1985, while reviewing the Unit 3 Operator's Log in the
Control Room, the inspector noted that on October 10, 1985, at 1:52
p.m., Unit 3 experienced a scram from the IRM monitoring system. At
the time of the scram no fuel was in the reactor vessel and a special
procedure was in effect to prevent automatic starting of the ECCS.
The control rods were withdrawn to reduce radiation exposures for
l work planned on repairing the core spray "T" box. The control rods
i
were blocked and there was no position indication on any of the 185
[ control rods. Neither control rod drive pump was operating nor were
there accumulator pressure and the reactor was at atmospheric pres-
sure. The licensee was questioned about making an ENS call to the
. . .
- ~ . .
.
.
l
16 !
NRC to report the reactor protection system actuation in accordance !
with 10 CFR 50.72(b)(2)(ii). The inspector determined that on August
29, 1985, the licensee issued written guidance on reporting scrams
during the Unit 3 refueling outage when there was no fuel in the re-
actor. The licensee determined that'with no fuel in the reactor ves-
'
sel there was no longer a reactor and therefore no need for a reactor
-
protection system. Based upon this logic the licensee reasoned that
actuations of the reactor protection system were not reportable.
This. interpretation was limited to scram signals with no fuel in the
f vessel. All other actuations of engineered safety features were to
be reported as required by, Administrative Procedure A-31. The
licensee was informed that 10 CFR 50.72 requires notification of the
, - NRC within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of any event or condition that results in manual
or automatic actuation of any engineered safety feature, including
the reactor protection system, and that this requirement applied to
i
each nuclear power reactor licensed under 10 CFR 50. In addition, 10
CFR 50.73 requires that a Licensee Event Report be prepared for such
events. When informed on October 11, 1985, the licensee immediately
rescinded the August 29, 1985 guidance memorandum. Upon further re-
view of the Unit 3 Operator Log by the inspector it was determined
that while the August 29, 1985 guidance was in effect there.were sev-
en additional reactor protection system actuations, as follows:
Date Time Scram
8/29/85 5:30 p.m. "D" IRM spike with A channe7 tripped
for relay work .
9/11/85 ' 1:55 a.m. Scram Discharge Volume High Level
9/11/85 7:43 p.m. "A" IRM spike
9/12/85 11:57 p.m. "C" IRM spike and B RPS channel
,
tripped
9/13/85 12:10 a.m. "C" IRM spike
! 9/13/85 9:33 a.m. "A" IRM spike
a
9/14/85' 1:49 a.m. "C" IRM spike
None of the above actuations were reported to the NRC via the ENS
telephone nor was a Licensee Event Report submitted to the NRC.
- Failure to make reports to the NRC as required by 10 CFR 50.72 and
50.73 is an apparent violation (278/85-33-03).
?
_
h - _ -
.
. .
17
4.4 Refueling / Outage Activities
4.4.1- -Unit 3 Core Spray Sparger Cracks
, During in-vessel remote visual inspection of the B loop of
core spray piping, per IE: Bulletin 80-13, crack indications
were observed in the annulus area on Unit 3. The licensee
'
proposed repair of the core spray piping by welding two
brackets to the T-box junction core spray and pipes. The
inspector attended a meeting on September 17, 1985, among
the NRC (NRR), the licensee and General Electric, to dis-
cuss the status of the core spray pipe inspections, crack
indications and repair dispositions. The inspector re-
viewed the Licensee Event Report #3-85-14 dated September
25, 1985, regarding the core spray cracks. The licensee
performed repairs on the core spray piping during the peri-
od October 4-9, 1985. The inspector reviewed the core
spray sparger repair work including the following: mockup
,
training, ALARA review, modification package, safety evalu-
, ation, repair activities, HP_ controls and QC. The inspec-
tor observed some of the welding of the brackets in the
reactor vessel from the fuel floor. NRC Inspections
278/85-36 and 278/85-37 further review HP controls and
maintenance activities for the core spray sparger crack
repairs. Within the scope of this review, no unacceptable
conditions were identified.
4.4.2 Control of Unit 3 Equipment During Refueling / Outage
,
On October.10, 1985, the inspector reviewed the licensee's
procedures and requirements for writing permits and block-
ing sequences for tagging and control of safety related
equipment. In early September 1985, the licensee institut-
ed a practice of allowing three non-licensed Plant
Operators-Nuclear (PON) to write permits on equipment not
covered by Technical Specifications in order to increase
permit production during the Unit 3 outage. Each of these
PONS have about five years plant experience in their cur-
, rent position. In addition, they were given special train-
ing in the rules for permits and blocking, and in writing
permits. The licensee revised the scope of permits written
by the PONS in early October 1985 to include safety related
systems for which an approved blocking sequence existed or
, for which a menber of shift supervision had defined how tc
block the system. The inspector reviewed the following
Administrative Procedures for requirements on writing
permits:
--
A-40, Working Hour Restrictions, Rev. 2, 2/15/84
'
--
A-41, Procedure for Control of Safety Related Equip-
ment, Rev. 2, 8/31/82
-
.. . . - . -
-- -. . . . . . . - -.
.
.
18
--
A-26, Procedure for Corrective Maintenance, Rev. 24,
1/4/85
--
A-26A, Procedure for Corrective and Preventive Mainte-
nance Using Champs, Rev. 2, 2/21/85
Administrative Procedures A-26 and A-26A require that a
Control Operator prepare permits for tagging and control-
ling safety-related equipment.
The Control Operator is defined in procedure A-26A as the
posted Control Operator (a licensed reactor operator).
Procedure A-26A further states that the Control Operator
is responsible for preparing, applying and issuing blocking
permits, equipment turnover, and for removal of blocking
permits. The inspector noted that PONS had written the
following permits:
--
Unit 3 Control Rod Drives on September 16, 1985
--
Unit 3 HPSW Crossover Valve on September 25, 1985
--
Unit 3 HPCI Turbine Exhaust on October 4, 1985
The preparation of these permits was not in agreement with
the revised guidance the licensee provided to expedite per-
mit preparation. The inspector brought the discrepancy
between A-26 and A-26A and the revised practice to the
licensee's attention on October 11, 1985. Procedures A-25
and A-26A were revised, reviewed and approved by PORC
(Meeting 85-148) and subsequently reviewed and approved
by the QA Division on October 11, 1985. Both A-26 and
A-26A were revised, on an expedited basis, to state that as
necessary shift supervision shall direct preparation of a
permit.
Procedure A-2, Rev. 27, dated January 7, 1985, Administra-
tive Procedure for Control and L'se of Documents states that
revised "A" Procedures must be reviewed against QA Program -
Requirements and must contain equivalent, more conservative
or additional requirements to be issued on an expedited
basis.
The inspector reviewed the training given to operators as-
sociated with permits and blocking, plant systems, safety
systems, and Technical Specifications. The inspector de-
termined that Control Operators get more training than PONS
in plant systems, safety systems. Technical Specifications,
and permit writing. In addition to this extra training,
I
-
,
.
19
.
the Qualification Manual (August, 1983) for Control Opera-
tors' requires the trainee to show competence in the re-
quirements for writing: (a) blocking permits, (b) radiation
work permits, (c) temporary clearance forms, and (d) safety
permits.
The inspector stated that the October 11, 1985 expedited
change to A-26 and A-26A was in a less conservative direc-
tion because of the additional training and demonstrated
knowledge of Control Ogerators in the areas of safety sys-
tems, plant systems, Technical Specifications and permits
and blocking over and above that demonstrated by PONS. In
addition, the change did not contain equivalent or addi- .
tional requirements. Therefore, it appears that the
licensee did not follow procedure A-2 in making the change
'
to procedures A-26 and A-26A.
Technical Specification section 6.8.1 states that written
procedures and administrative policies shall be estab-
lished, implemented and maintained that meet the require-
ments of Regulatory Guide 1.33, November 1972. Failure to
follow procedures A-26, A-26A and A-2 is an apparent viola-
tion of Technical Specification 6.8.1. (277/85-29-01;
278/85-33-01)
4.5 Engineered Safeguards Features (ESF) System Walkdown
The inspector performed a detailed walkdown of portions of the Stand-
by Gas Treatment System (SGTS) in order to independently verify the
operability of the Unit 2 and Unit 3 common system. The SGTS
walkdown included verifications of the following items:
--
Review of 3GTS documentation listed in the Attachment to this ,
report.
--
Inspection of system equipment conditions.
--
Confirmation that the system check-off-list (COL) and operating
.
procedures are consistent with plant drawings.
--
Verification that system valves, dampers, breakers, and switches
are properly aligned.
--
Verification that instrumentation is properly valved in and
,
--
Verification that valves required to be locked have appropriate
ic:: king devices.
--
Verification that control room switches, indications and con-
trols are satisfactory.
[
- , ,
_.
.
20
1
--
Verification that surveillance test procedures properly imple-
ment the Technical Specifications surveillance requirements.
No unacceptable conditions'were identified.
4.6 Plant Operations Review Committee (PORC)
- The inspector attended the PORC meeting #85-142 on October 4, 1985.
The inspector reviewed the requirements of the administrative proce-
dure A-4, Plant Operations Review Committee Procedure, Revision 20,
July 30,'1985, and Technical Specifications (TS) section 6.5.1. The
PORC meeting was conducted in accordance with A-4 and TS 6.5.1 as
verified by checking the following items:
--
A quorum of the PORC was present.
--
The meeting composition was adequate.
--
Written minutes were generated.
--
Procedure changes and plant modifications were reviewed.
~
Within the scope of the PORC meeting review, no unacceptable condi-
tions were identified.
.
4.7 General Employee Training (GET)
The inspector attended the Peach Bottom GET requalification training
-on October 9, 1985. The inspector monitored GET course content to
ensure it met the requirements of FSAR Section 13.3.4 and A-50,
Training Procedure, Revision 10, September 6, 1984. The GET course
included the following areas: radiation protection, security, emer-
gency and evacuation procedures, quality assurance and industrial-
safety. Within the scope of the review of this GET course, no unac-
ceptable conditions were identified.
5. TMI Action Plan (TAP) Item Status
5.1 TAP Item II.F.1.4, Containment Pressure Monitor and II.F.1.5,
Containment Water Level Monitor (Closed)
Instrumentation required for these TAP items was addressed under
plant modification 80-31. This modification work was reviewed
during Inspections 277/82-07; 278/82-07, and 277/83-34; 278/83-32.
The inspector reviewed the completed modification package including
the safety evaluation, maintenance request forms, and acceptance
testing. The recorders and indicators installed in the control room
were examined to verify that they were installed as described. The ,
inspecter reviewed relevant drawings and FSAR.section 7.20 to ensure
appropriate changes had been made. The licensee submitted a Techni-
cal Specification change request by letter dated February 11, 1982,
,
21
to incorporate the instrumentation into the Technical Specifications.
This change has not been issued by NRC as of this time. No unaccept-
able conditions were noted. TAP items II.F.1.4 and 5 are considered
complete and are closed.
5.2 TAP Item II.K.3.57, Manual Activation of ADS (Closed)
TAP item II.K.3.57 requires that the emergency procedures include
verification that a source of cooling water is available prior to
actuation of the automatic depressurization system (ADS). Alternate
water sources should be identified and referenced in the procedures.
The inspector reviewed the licensee's Transient Response Implementa-
tion Plan (TRIP) procedures T-101, RPV Control and T-111, Level Res-
toration. Based on these procedures, the alternate water source
requirements prior to ADS manual actuation of TAP item II.K.3.57 have
been incorporated into the emergency procedures. This item is
closed.
5.3 TAP Item II.K.3.16.B Reduction of Challenges and Failures of Relief
Valves (0 pen)
NRR letter dated April 23, 1984, endorsed the following four modifi-
cations for implementing TAP item II.K.3.16.B. These modifications
are based on the BWR Owner's Group Evaluation BWR OG-8134 dated March
31, 1981.
5.3.1 Low-Low Set (LLS) Relief Logic System or Equivalent
Manual Action (Closed)
The LLS relief logic system will open a selected relief
valve on concurrent signals of reactor high pressure scram
and any safety relief valve (SRV) opening. The BWR Emer-
gency Procedure Guidelines, Revision 1, January 31, 1981,
call for equivalent manual action. An SRV is manually held
open beyond the reclosure setpoint.
The inspector reviewed Peach Bottom TRIP procedure T-101.
This procedure directs the operator to manually open one or
more relief valves if the relief valves are cycling to
maintain reactor pressure below 1090 psig and to reclose
the relief valve at 950 psig.
NRR letter dated October 23, 1984, concurred with this ac-
tion. This item is closed.
5.3.2 Increase Relief Valve Simmer Margin (Closed)
Increasing the difference between the SRV set pressure and
the reactor pressure vessel operating pressure is intended
to minimize leakage and reduce potential spurious cpenings.
-, . -.- -_ - - - - _ _ - - - - _ -
.
.
22
The inspector reviewed Technical Specification 2.2, Reactor
Coolant System Integrity. The relief valve settings listed
in the Technical Specification conform to the set point
increases specified in License Amendment Nos. 36 and 41 for
Units 2 and 3, respectively. The NRC's safety evaluation
supporting Amendment 36 dated August 18, 1977 concluded
that the higher SRV setpoints reduce the probability of
excessive leakage and spurious valve openings. NRR letter
dated October 23, 1984, concurred with these cctions. This
item is closed.
5.3.3 Preventive Maintenance Program (Closed)
Each licensee should have a preventive maintenance program
to enhance the performance of SRVs. During each refueling
outage, 50% of the target rock SRVs " top works" containing
the pilot stage should be steam / nitrogen tested for
recalibration of setpoints, pilot leakage determination,
and refurbishment.
Peach Bottom Technical Specification 4.6.D requires the
following actions be performed at least once per operating
cycle:
(1) The removal of at least five of eleven target-rock
relief valves for checking or replacement so that all
valves are tested every two cycles.
(2) At least one relief valve shall be disassembled and
inspected.
(3) All piping, switches, and accumulators for continuous
valve bellows monitoring shall be inspected.
(4) Each relief valve shall be manually opened once at
reactor pressure greater than or equal to 100 psig.
(See detail 7.2.)
NRR letter dated October 23, 1984, concurred with the above
actions.
A review of procedure M-1.6 Relief Valve Replacement, con-
firms that before a relief valve is installed its setpoint
must be determined and indicated.
The inspector reviewed all surveillance test ST-13.32,
Safety and Relief Valve Replacement, forms for the last six
years. From these ST's all relief and safety valves have
been removed, tested, and inspected as per Technical Spect-
fication 4.6,0. This item is closed.
.
.
23
5.3.4 Lower the reactor vessel water level isolation setpoint
for main steam isolation valve (MSIV) closure level 2 to
level 1 (Open).
As stated in licensee letter dated June 19, 1984, this mod-
ification will be implemented r- later than the first
refueling outage after issuance of a licensee amendment.
The licensee amendment application was transmitted to the
NRC by letter dated April 19, 1984. NRR issued Amendments
Nos.~111 and 115 on October 2, 1985. This item is open
pending licensee implementation of the Amendment and in-
spector review.
5.4 Status of Closed TMI Acticn Plan Items
The inspector evaluated the TMI Action Plan Items that were closed to
determine whether problems have been experienced subsequent to
the item being closed. The inspector noted that with regards to Item
I.A.1.3, the licensee uses overtime for operators on a routine basis.
Overtime data through September, 1985, for licensed reactor opera-
tors indicates a low of 574 hours0.00664 days <br />0.159 hours <br />9.490741e-4 weeks <br />2.18407e-4 months <br /> and a high of 1258 hours0.0146 days <br />0.349 hours <br />0.00208 weeks <br />4.78669e-4 months <br /> of over-
time. The licensee's letter to Region I dated August 16, 1985,
in association with an enforcement conference held on June 21, 1985,
acknowledged a problem in this area and indicates that they are pur-
suing a solution. The inspector also noted in reviewing Item I.A.1.1
that while the STA is effectively used at Peach Bottom, the position
is a three year assignment and therefore the STA is not likely to
have many years of experience in the job. Currently, the most expe-
rienced STA has two years on shift. In an emergency situation the
on-shift STA could be rather inexperienced.
TMI Items II.F.1 and II.F.2 required installation of wide range in-
struments as describad below:
Instrument Range
Torus level, LR 8123 l' to 21'
Torus Temperature, TR 8123 30 degreer to 230 degrees F
Drywell Pressure, PR-8102 5-25 psia
0-225 psig
Reactor Level, LR 110 -165" to +50"
0" to -325"
Reactor Pressure, PR 404 0 to 1500 psig
The accuracy and range of the instruments is such that slight drifts
in the electronics can cause readings which prompt the operators to
request corrective maintenance. The apparent instrument drift has
resulted in a high rate of unavailability of the instruments and op-
erators to have less confidence in the instruments. The inspector
-
.
.
24
has noted that these instruments are tagged out of service more fre-
quently than other instruments. This instrumentation which is infre-
quently used requires a considerable amount of licensee attention.
The inspector will continue to review the performance of these in-
struments and operator attitudes about t!iem.
6. Review of Licensee Event Reports (LERs)
6.1 The inspector reviewed LERs submitted to NRC:RI to verify that the
details were clearly reported, including the accur.tcy of the descrip- ,
tion and corrective action adequacy. The inspector determined wheth- '
er further information was required, whether generic implications
were indicated, and whether the event warranted on-site followup.
The following LERs were reviewed:
LER No.
LER Date
Event Date Subject
September 6, 1985
August 7, 1985 d
i
2-85-14 Scram and Group II/III Isolations On Reactor '
September 24, 1985 Low Level
August 20, 1985
2-85-15 RPS and PCIS Actuation
September 20, 1985
August 22, 1985
,
September 20, 1985
August 26, 1985
LER No.
LER Date
Event Date Subject
2-85-17 Torus Low Level During Startup
September 4, 1985
August 23, 1985
- 2-85-18 Reactor Water Cleanup System Isolation
October 11, 1985
September 12, 1985
- 2-85-19 2A RHR Pump Inoperable
October 18, 1985
September 19, 1985
n .
.
25
October 21, 1985 Isolation in Cold Shutdown
September 24, 2985
3-85-11 Degraded Fire Barriers
October 1, 1985
June 21, 1985
3-85-13 Crack Indications in RHR Pipe Welds
August 22, 1985
July 26, 1985
3-85-14 Core Spray Sparger Junction Box Cracks
September 25, 1985
August 26, 1985
6.2 On-Site-Followup
For LERs selected for on-site followup and review (denoted by aster-
isks above), the inspector verified that appropriate corrective ac-
tion was taken or responsibility assigned and that continued
operations of the facility was conducted in accordance with Technical
Specifications and did not constitute an unreviewed safety question
as defined in 10 CFR 50.59. Report accuracy, compliance with current
reporting requirements and applicability to other site systems and
components were also reviewed.
6.2.1 LER 2-85-12 concerns a reactor scram on Unit 2 during
startup due to high IRM flux. This event was reviewed in
detail 4.2.2 of NRC Inspection 277/85-30. No discrepancies
were identified relative to this LER.
6.2.2 LER 2-85-16 concerns a reactor scram on Unit 2 during
startup due to a spurious low level signal while returning
a pressure transmitter to service. This event was reviewed
in detail 4.2.4 of NRC Inspection 277/85-30. No inadequa-
cies were identified relative to this LER. ,
6.2.3 LER 2-85-18 concerns an isolation of the Reactor Water
Cleanup (RWCU) system due to personnel error. The Unit 2
RWCU system isolated on high flow at 10:30 a.m. on Septem-
ber 12, 1985. This group IIA primary containment isolation
system (PCIS) actuation occurred while operators were re-
turning the 2A RWCU filter demineralizer to service upon
completion of backwash and precoat operations. The appar-
ent cause of the high flow and isolation was a momentary
excessive RWCU system flow as the filter demineralizer was
valved too quickly into service. The PCIS actuated cor-
rectly and the licensee made a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> report on the ENS per
~
,
,
26
10 CFR 50.72. The licensee reset the PCIS signal and re-
turned the RWCU to service. The inspector reviewed the
event, checked operator logs and discussed the isolation
with the shift operators and licensee management. The
-non-licensed operator involved in valving in the filter
demineralizer was counselled on the correct procedure for
return to service. No inadequacies were identified
relative to this LER.
6.2.4 LER 2-85-19 concerns the 2A RHR pump inoperability and
the event is reviewed in detail 4.2.1 of this report. No
inadequacies were identified relative to this LER.
6.2.5 LER 2-85-20 concerns a reactor low level scram signal
and PCIS Group II/III isolation while in cold shutdown due
to vessel draining through the RHR system to the torus.
This event is revieved in detail 4.2.2 of this report. No
inadequacies were identified relative to this LER.
7. Surveillance Testing
7.1 The inspector observed surveillance tests to verify that testing had
been properly scheduled, approved by shift supervision, control room
operators were knowledgeable regarding testing in progress, approved
procedures were being used, redundant systems or components were
available for service as required, test instrumentation was calibrat-
ed, work was performed by qualified personnel, and test acceptance
criteria were met. Parts of the following tests were observed:
--
ST 6.8, RHR A Pump, Valve, Flow and Cooler Test, Revision 27,
August 24, 1985, performed on October 3, 10, 11, and 16, 1985. ;
--
ST 6.8.1, Daily RHR A System and Unit Cooler Operability, Revi-
sion~16, October 25, 1985, performed on October 25, 1985.
In addition, a review of the following completed surveillance tests
was performed:
--
ST 4.9.B, Portal Monitor Calibration and Source Check, Revision
3, June 21, 1983, performed on April 2, 1985, January 7, 1985,
August 9, 1984, and October 1, 1984.
--
RT 7.32, Portal Radiation Monitor Model PRM-110 Sensitivity and
Source Checks, Revision 1, January 27, 1983, performed on April
17, 1985, May 26, 1985, and on June 13, 1985.
No inadequacies were identified.
.- _. --
.
27
7.2 The inspector reviewed ST 10.4, Rev. 10, Relief Valve Manual Actua-
tion, performed on Unit 3 on September 3, 1983. The inspector noted
that four relief valves (71 B, G, K and L) were not-tested during the
-September 1983 performance of ST 10.4. ST 10.4 was also performed on
November 21, 1983 and February 28, 1985, and tested Unit 3 valves 71E
and 71L respectively. No other copies of ST 10.4 for Unit 3 could be
found, therefore it appears that relief valves 71 B, G, and K were
not tested for Unit 3 during operating cycle 6 (September 1983
- through July 1985). Technical Specification paragraph 4.6,0.4
requires that each relief valve be manually opened once per operating
cycle with the reactor pressure equal to or greater than 100 psig to
demonstrate its ability to pass steam. Surveillance Test 10.4 imple-
ments this requirement.
The inspector discussed the missing test data with the licensee who
indicated a data search was being made to determine if these relief
valves had been tested. No additional surveillance records were
found during this report period. The inspector checked the similar
test for Unit 2, recorded on ST 10.4, Rev. 14, performed July 9,
1985. All eleven relief valves were tested. Failure to manually test
relief valves 71 B, G, and K is an apparent violation of Technical
Specification 4.6.D.4 surveillance requirements (278/85-33-02).
7.3 The inspector reviewed the core spray sparger line break differential
pressure (d/p) instrument Technical Specification (TS) surveillance
requirements. This instrument senses d/p between the core spray in-
jection line and above the core plate. The instrument alarms in the
control room on high d/p, indicative of a break in the core spray
sparger line within the vessel annulus region.
The inspector noted a discrepancy with respect to the TS surveillance
requirements. TS Table 4.2.B item (8) references the " core spray
sparger d/p" instrument with a reouired calibration frequency of once
per six months. TS 4.5.A item (e) references the " core spray header
delta-P instrumentation" with a required calibration frequency of
once per three months. The inspector informed the licensee of this
discrepancy. The licensee calibrates the core spray d/p instrument
using surveillance test procedures ST 2.2.01 A and 8 for Unit 2 and
ST.2.7,01 A and B for Unit 3. The core spray d/p instrument, DPIS-
2(3)-14-43A and B, calibration is performed every three months. The
inspector reviewed completed ST records to verify that the abeve sur-
veillance test is performed every three months. The licensee intends
to submit a TS change request to clarify this discrepancy. The in-
spector will review this item in a future inspection (IFI
277/85-29-04).
8. Maintenance
For the following maintenance activities the inspector spot-checked admin-
istrative controls, reviewed documentation, and observed portions of the
actual maintenance:
_ . _ . . _ _ - .. - _ _ _ _ _ _ _ _ . _ _ -__- , __ - - _ . _ _
_,
.
-
28
Maintenance
Procedure /
Document Equipment Date Observed
SP-863 Unit 3 Core Spray October 8, 1985
"T-Box" Repair
Administrative controls checked included maintenance requests, blocking
permits, fire watches and ignition source controls, item handling reports,
and shift turnover information. Documents reviewed included procedures,
material certifications and receipt inspections, welder qualifications and
weld information data sheets.
No inadequacies were identified.
9. Radiation Protection
During this report period, the inspector examined work in progress in both
units, including the following:
--
Health Physics (HP) controls
--
Badging
--
Protective clothing use
--
Adherence to Radiation Work Permit (RWP) requirements
--
Surveys
--
Handling of potentially contaminated equipment and materials
'
The inspector observed individuals frisking in accordance with Health
Physics procedures. A sampling of high radiation doors was verified to be <
locked as required. Compliance with RWP requirements was verified during
each tour. RWP line entries were. reviewed to verify that personnel had
provided the required ;nformation and people working in RWP areas were
observed to be meeting the applicable requirements. No unacceptable con-
ditions were identified.
10. Physical Security
The inspector monitored security activities for compliance with the ac-
cepted Security Plan and associated implementing procedures, including:
operations of the CAS and SAS, checks of vehicles on-site to verify proper
control, observation of protected area access control and badging proce-
dures on each shift, inspection of physical barriers, checks on control of
vital area access and escort procedures. No inadequacies were identified.
,
s
..
_ 29
11. In-Office Review of Public and Special Reports
The inspector reviewed the following documents:
--
Unit 2 Inservice Inspection Program Final Report, dated July 13,
1985.
--
Peach Bottom Monthly Operating Report for September, 1985.
--
Unit 2 Containment Integrated Leak Rate Test Report, dated June 11,
1985.
--
Semi-Annual Effluent Release Report No. 19, Revision 1, dated October
8, 1985.
Within the scope of the resias of these documents, no unacceptable condi-
tions were identified.
12. Inspector Follow Items
Inspector follow items are items for which the current inspection findings
are acceptable, but due to on going licensee work or special inspector
interest in an area, are specifically noted for future follow-up. Follow-
up is at the discretion of the inspector and regional management. Inspec-
tor follow items are discussed in Detail 4.2.1 and 7.3.
13. Management Meetings
13.1 Preliminary Inspection Findings
A verbal summary of preliminary findings was provided to the Station
Superintendent at the conclusion of the inspection. During the in-
spection, licensee management was periodically notified verbally of
the preliminary findings by the resident inspectors. No written in-
spection material was provided to the licensee during the inspection.
No proprietary information is included in this report.
13.2 Attendance at Management Meetings Conducted by Region-Based
Inspectors
The resident inspectors attended entrance and exit interviews by ,
region-based inspectors as follows:
Inspection Reporting
Date Subject Report No. Inspector
10/15/85 (Ent) Emergency Preparedness 277/85-36 Hawxhurst
- 10/18/85 (Exit) Annual Exercise 278/85-34
- ,
9/30/85 (Ent) Local Leak Rate Testing 278/85-35 Kucharski
- 10/4/85 (Exit)
. .
_
_ _ _ _ _ - . _ _ _ _ _ . _ _ _ _ . _ _ , _ . _ _ _ _____
_
. _ - .
'O .
!
L
.
30
e ,
[
Inspection Reporting
Date Subject Report No. Inspector
10/8/85 (Ent) Unit 3 Core Spray 278/85-36 Bicehouse
10/11/85(Exit) Sparger Repair
10/15/85 (Ent) SNM Accountability 2'7/85-37 Della Ratta
10/18/85 (Exit) and Control 278/85-38
10/21/85 (Ent) Unit 3 Pipe Rupairs 277/85-38 Reynolds
10/25/85 (Exit) 278/85-37
.
L
.. .
.
ATTACHMENT
S.10.5.A, Setup of The Standby Gas Treatment System for Auto Operation, Revi-
sion 2, 05/18/79
S.10.5.A C.0.L., Standby Gas Treatment Auto Operation, Revision 6, 09/28/81
S.10.5.8, Manual Start of Standby Gas Treatment System, Revision 4, 10/01/84
S.10.5.C, Shutdown of Standby Gas Treatment System Following " Auto" Initiation
Caused by Group 3 Isolation, Revision 4, 05/18/79
S.10.5.C.1 C.0.L., Unit 2 S.G.T.S. Return To Normal, Revision 3, 12/21/83
S.10.5.C.2 C.0.L., Unit 3 S.G.T.S. Return To Normal, Revision 3, 12/22/83
S.10.5.D, Shutdown of the Standby Gas Treatment System Following Manual Start,
Revision 1, 04/15/73
S.'10.5.E, Routine Inspection of S.G.T.S., Revision 5, 08/02/84
S.10.5.F, Manual Operation of the S.G.T.S. for DOP and Halogenated Hydrocarbon
Testing, Revision 2, 07/11/84
S.10.5.G, Manual Swap Over of Reactor Building Equipment Cell Exhaust to Stand-
by Gas, Revision 2, 10/22/84
FSAR Section 5.3, Secondary Containment System
Technical Specifications 3.7.8/4.7.B, Standby Gas Treatment System
Technical Specifications 3.7.C/4.7.C, Secondary Containment
P&ID M-388, Reactor Building Ventilation Flow Diagram, Revision 19, 3/13/85
P&ID M-391, Containment Isolation Control Diagram, Revision 17, 3/21/79
P&ID M-397, Standby Gas Treatment Control Diagram, Revision 27, 10/29/82
E-206 Sheet 1 of 1, ESD Standby Gas Treatment System, Revision 24, 7/19/84
E-206 Sheet 2 of 2, ESD Standby Gas Treatment System, Revision 24, 7/19/84
-
E-208 ESD Standby Gas Treatment System Isolation Valves, Revision 13, 11/4/75
M-I-S-23 Sheet 18, ESD Primary Containment Isolation System, Revision 68,
9/17/84
M-I-S-23 Sheet 16, ESD Primary Containment Isolation, Revision 60, 1/15/82
ST-13.9, Secondary Containment Capability Test, Revision 7, 5/16/83
ST-13.7A, SGTS Differential and Heater Capacity, Revision 3, 7/11/84