ML20236K739
| ML20236K739 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 07/24/1987 |
| From: | Gallo R, Linville J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20236K676 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-2.K.3.18, TASK-TM 50-277-87-17, 50-278-87-17, IEB-85-003, IEB-85-3, NUDOCS 8708070237 | |
| Download: ML20236K739 (39) | |
See also: IR 05000277/1987017
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
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Report No. 50-277/87-17 & 50-278/87-17
Docket No. 50-277 & 50-278
License No. OPR-44 & DPR-56
Licensee: Philadelphia Electric Company
c.T 2301 Market-Street
,
_ Philadelphia, Pennsylvania 19101
Facility Name: Peach Bottom Atomic Power Station Units.2 and 3
, Inspection At: Delta, Pennsylvania
Inspection'Conducte'd: June 1, 1987 to July 17, 1987
Inspectors: T. P. Johnson, Senior Resident Inspector
R. J. Urban, Resident Inspector
L. L. Scholl, Reactor Engineer
L. E. Myers, Resident' Inspector
S. D. Kucharski, Resident Inspector, Limerick
Revlewed By: OM1
.. / LT7iviile, Chief /
7/2347
'/ ' gat 6
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e 6 tor Projects Se on 2A,
vision of Reacto Projects
Approved By: Qfd5 [w '1 >4 1
R. W./ Gall , Chief, y date
Reactor Pr ts Branch 2,
Division of Reactor Projects
Inspection Summary: Routine, on site regular and backshift resident
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inspection'(210 hours0.00243 days <br />0.0583 hours <br />3.472222e-4 weeks <br />7.9905e-5 months <br /> Unit 2; 174 hours0.00201 days <br />0.0483 hours <br />2.876984e-4 weeks <br />6.6207e-5 months <br /> Unit 3) of accessible portions of
Unit 2 and 3, operational safety, shutdown Order commitments, radiation i
protection, physical security, control room activities, licensee events, j
surveillance testing, refueling and outage activities, Unit 2 core reload
and outage activities, maintenance, and outstanding items. In addition, a )
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review'of the apparently inoperable Control Room Ventilation Radiation
Monitoring System was conducted.
Results: One violation (section 4.4.5) for failing to perform a Technical
Specification surveillance test on the Unit 2 A loop of drywell spray. The ,
Control Room Ventilation Radiation Monitoring System has been incorrectly j
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configured and apparently out of service since initial plant startup (see
section 6.2.3). Annunciator auto / manual reset switches are neither
controlled nor documented. Several ESF actuations occurred on Unit 2 (see
section 4.2). An error by a licensed reactor operator resulted in a
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shutdown scram on Unit 2 (see.section 4.2.2). A partial loss of off site
power occurred on July 10, 1987 (see section 4.2.6). L'censee actions were
observed from the Control Room and were effective. The conduct of the Unit 2
core reload activities was also effective.
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I_ DETAILS
1.0 Persons Conta$ced
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,e?~ B. L. Clark, Administration Engineer
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.G. F. Dawson, Maintenance Engineer
A.'A, Fulvio, Technical Engineer
J..A. Jordan, Performance Engineer
J. C. Oddo, Nuclear Security Specialist
D. L. Oltmans, Senior Chemist
F. W. Polaski, Operations Engineer
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D. P. Potocik, Senior Health Physicist
G. R. Rainey, Superintendent Plant Services
M. B.,Ryan, Outage Engineer
D. C. Smith, Superintendent Operations
- D. M. Smith, Manager, Peach Bottom Atomic Power Station
J. E. Winzenried, Staf f Engineer
Other licensee employees were also contacted.
l- *Present at exit interview on site and for summation of preliminary
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findings.
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2.0 plant Status
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2.1 Unit 2-
The unit began the inspection period with activities to return the
exchanged control rod drives to service to support core reload.
Other outage modi,fication, testing, and maintenance work was being
performed during to period. A reactor scram occurred on June 19,
1987, with the unit in a cold. shutdown condition (see section
4.2.2). Core reload began on June 22, 1987, and reload was
complete on July 1, 1987. The core was verified on July 2, 1937.
At the end of the report period, preparations for vessel
reassembly were in progress. Unit 2 remained in a cold shutdown
condition as required by NRC Order dated Manh 31, 1987.
M.2 Unit'3
The unit was maintained in a cold shutdown, with the reactor mode
switch in " shutdown" position, during the inspection period. This
was as required by NRC Order dated March 31, 1987.
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3.0 Previous Inspection Item Update
3.1 (0 pen) IE Bulletin 85-03. See section 4.4.3 of this report.
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4.0 Plant Operations Review
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4.1 Station Tours
The inspector observed plant operations during daily facility
tours. Most accessible plant areas were inspected.
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4.1.1 Control Room and facility shift staffing are frequently
checked for compliance with 10 CFR 50.54 and Technical
Specifications. The presence of a senior licensed operator { !
and the fluclear Operations Monitoring Team (f40MT) member
in the control room was verified frequently.
4.1.2 The inspector frequently observed that selected control
room instrumentation confirmed that instruments were '
operable and indicated values were within Technical
Specification requirements and normal operating limits. !
ECCS switch positioning and valve lineups were verified
baseo on control 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.
On June 23, 1987, the inspector observed the once per
shift FPanalarm" annunciator alarm test conducted by the ;
Unit 2 and 3 reactor operators. The inspector noted '
that for similar alarms on similar panels, some alarms
reset automatically (i.e., immediately when the alarm
was acknowledged) and some alarms had to be manually
reset (i.e., by depressing the reset push button). The
inspector checked Unit 2 alarm panel 20C205R versus Unit
3 alarm panel 30C205R. These alarm panels provide
annunciation for the reactor protection, neutron
monitoring, rod control and standby liquid control
systems. The 2(3)C205R panels have 45 alarm windows of
which 12 alarms were set up differently between Unit' 2 and
Unit 3 (i.e., manual vs. auto reset). The determination
as to whether an alarm will automatically or manually reset
depends on the position of an internal annunciator cam slide
switch. The inspector discussed the manual / auto reset
switch for alarms with operators and licensee management.
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The, inspector expressed a concern that the operators have
control and could reposition the auto / manual reset switch;
and, that 1,he required position of the switch was ne'ither
L ' I, documentecJon electrical prints nor on the alarm cards.
L The licensee- acknowledged this concern and on June 26, 1987,
-y issued a memo that directed the repositioning of auto / manual l
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, reset switches to the auto position to ensure consistency.
>} In addition, the licensee committed to performing an
s ? evaluation to determine the permanent status of these auto /
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manual reset switches. The inspector will follow the status
of these annunciator auto / manual reset switches in a future
insprtion.
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 periodic backshift observations, to
ensure compliance with administrative procedures and
1 regulatory guidance. No inadequacies were identified.
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m 4.1.6 The inspector observed the m31n stack and both reactor
building ventilation stack radiation monitors and
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- recorders, and periodically reviewed-traces from
backshift periods to verify that radioactive gas release
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rates were within limits and that unplanned releases had
not occurred. No inadequacies were identified.
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3 4.1.7 The inspector observed control room indications of fire
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'% detectiof instrumentation and fire suppression systems,
., monitored use of fire watches and ignition source
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," i controls, checked a sampling of fire barriers for
integrity, and observed fire-fighting equipment
,' ' stations. No inadequacies were identified.
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4.1.8 The inspecto" observed overall facility housekeeping
conditions, including control of combustibles, loose
trash and debris. Cleanup was spot-checked during and
after maintenance. Plant housekeeping was generally
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acceptable.
4.1.S The inspector observed the shutdown nuclear instrumentation
subsystems (source rege and intermediate range monitors)
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and the reactor protection system to verify that the required
channels were operable.
)h l On June 5,1987, during a routine control room tour, the
si inspector noted that there were differences in the Unit
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s 2 and Unit 3 RPS one line operater aid diagrams. The
, ( 'Jnit 2 diagrams (operator aid Nos. 84-21 and 38) and the j
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Unit 3 diagrams (operator aid Nos. 84-47 and 48) did not
accurately reflect the correct location of the RPS trip
breakers that were installed by modifications during
last refueling outage for each unit. In addition, a Unit
2 modification (MOD #1916) added a static inverter
supply to the alternate feed. The inspector discussed
these minor deficiencies with the on shift licensed
operators and STA. Pen and ink changes were made on the
affected RPS diagrams to reflect the correct alignment.
The inspector will continue to review this area on a
continuing basis.
4.1.10 The inspector frequently verified that the required
off site electrical power startup sources and emergency
on site diesel generators were operable. A loss of the
- 3 startup source during a lightning storm occurred on
July 10,'1987 (see section 4.2.6).
4.1.11 The inspector monitored the frequency of in plant and
control room tours by plant and corporate managenient.
The. tours were generally adequate.
4.1.12 The inspector verified operability of selected safety
related equipment and systems by in plant checks of
valve positioning, control of locked valves, power
supply availability, operating procedures, plant
drawings, instrumentation 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 procedures. Systems checked
included the Unit 3 shutdown cooling (RHR) system, and
the Unit 2 and 3 High Pressure Service Water (HPSW)
systems.
On June 12, 1987, the inspector noted that the 3B HPSW
pump was supplying the 3C RHR heat exchanger via the A
to B loop cross connect line, i.e. , key lock MOV 3344
was open. The 3A HPSW was out of service for
maintenance and the 3C HPSW pump was noted as running ;
hot. Thus, the 3B and 3D HPSW pumps were the only two l
available for Unit 3. The inspector noted that the Unit '
2 and Unit 3 HPSW systems can be cross connected by
opening norn, ally locked closed valves HV-516A and B.
However, no currently approved operating procedure
exists for this operation. The licensee stated that
special procedures (SP) had been written in the past for
cross connecting the Unit 2 and 3 HPSW systems. SP-162,
164, 184 and 186 were written for specific uses during ,
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years 1977 and 1983. The licensee stated that the !
procedure for cross connecting HPSW would be addressed 1
in a system (5) procedure (S.3.2). The inspector will
review this new "S" procedure in a future inspection.
4.1.13 The inspector performed backshift and week-end tours of
the facility on the following days:
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June 21, 1987; 8:00 a.m. - 12:00 noon.
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June 28, 1987; 6:00 p.m. - 10:00 p.m.
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July 13, 1987; 5:20 a.m. - 7:00 a.m.
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July 16, 1987; 12:00 midnight - 1:45 a.m.
4.2 Followup On Events Occurring During the Inspection
4.2.1 Unit 2 ESF Actuation on June 2,1987
A half group III outside containment ventilation j
isolation and half scram occurred on Unit 2 at 4:40 p.m. '
on June 2, 1987. Unit 2 was in a refueling outage with
the entire core offloaded. The cause of the isolation
was loss of power to the 2B Reactor Protection System
(RPS) bus. The 2B RPS bus was being powered from the
alternate feed when circuit breaker #23 from the 20Y50
panel tripped. In addition, the 20Y50 panel feeder breaker
(#52-3691) at motor control center E124-R-C was noted as
being. tripped. Modifications to the 2B RPS MG set required
the bus to be supplied from the alternate feed. The
licensee reset the isolation and half scram after re-
energizing the 2B RPS. An ENS call was made at 5:45 p.m.
and the senior resident was notified. The cause of the
breaker trip was determined to be an inadequately designed
SOLA voltage regulating tr ansformer (20X40) causing higher
than normal primary current. The licensee intends to
replace the transformer prior to startup.
The inspector reviewed the licensee's Suspected Licensee
Event Report (SLER), upset report, LER (see section 6.2.3),
and discussed the event with licensed operators and engineers.
L No violations were noted.
4.2.2 Unit 2 Scram with Core Offloaded on June 19, 1987
At 3:49 a.m. on June 19, 1937, a reactor scram occurred
on Unit 2. At the time of the scram, surveillance
testing was in progress on the IRMs. The core was
offloaded and no rod motion occurred as all rods were
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fully inserted. IRM surveillance test (ST) 3.2.3 was
being performed in preparation for core reload. The
cause of the scram was an apparent personnel error by
the reactor operator performing the surveillance and was "
compounded by equipment malfunction. The operator
failed to reset a channel "B" half scram signal before
testing the "A" channel scram circuitry. The licensee
reset the scram signal and made an ENS call at 5:05 a.m.
The inspector reviewed the SLER, the upset report, ST
3.2.3, and control room logs. The inspector also
discussed'the event with the operator performing the ST
and with licensee management. The inspector concluded
that the event was caused by a licensed operator error,
compounded by several equipment malfunctions during the
ST.
4.2.3 Unit 2 ESF Actuation on June 30, 1987
An outboard Group II containment isolation occurred on
Unit 2 at 8:41 a.m. on June 30, 1987. Unit 2 was in a
refueling outage with most of the fuel bundles reloaded
into the core. A Reactor Water Cleanup (RWCU) outside
containment isolation relay, 16A-K27, was being replaud
because it had reached the end of its Environmentally
Qualified (EQ) lifespan. The work was being accomplished
under maintenance request form (MRF) #2-61F-8407725, and
the relay was blocked using maintenance work permit
- 3-61 F-84-07723.
When the electrician lifted lead AY-10 from coil terminal
- 10, several relays were heard actuating. The following
outside containment isolation valves auto closed: drywell
instrument N2; drywell equipment alarm sump; and drywell
floor drain sump. Associated alarms were also received in
the control room. The vertical lead (AY-10) that was lifted
from relay 16A-K27 was connected with several other relays.
Upon lifting lead AY-10, power was lost to relay 16A-K98
which caused the outboard Group II isolation. All-contain-
n.ent isolation valves closed as designed.
The resident inspector was in the control room when the
isolation occurred. An ENS call was made at 9:55 a.m.
The isolation was reset at 10:50 a.m., when the electricians
completed the replacement of 16A-K27. The inspector reviewed
the licensee's SLER and upset report, and discussed the
event with the STAS and licensed operators. The cause of
the isolation was use of an inadequate blocking permit, in
that panel internal wiring diagrams should have been con-
sulted when writing the permit. These diagrams depict how
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relays are in'erconnected. The licensee intends to submit
an LER, which will be reviewed in a future report. .No
additional deficiencies were identified and the inspector
had no further questions at this time.
4.2.4 011 Spills
At 2:15 a.m. on June 22, 1987, an oil spill from the
temporary diesel driven air compressor occurred on site.
The oil (approximately 25 gallons) flowed into the storm
sewer and was contained by inner and outer oil booms in
the discharge pond. The licensee had the oil cleaned up
and repaired the air compressor.
Subsequently, at 10:57 a.m. on July 1, 1987, the
licensee discovered that approximately 30 to 50 gallons
of oil had spilled into the Susquehanna River from a
different storm sewer. An additional 30 to 50 gallons
of oil were contained by an oil boom. Low river level '
in combination with the boom lodging on a rock allowed the
oil to flow into the rivet. the licensee determined that
the spill was #6 fuel oil. The spill was terminated'and a
contractor consultant, Underwater Technology (UT), came on
site and removed the oil from the river. The resident
inspector was notified by the licensee at 12:30 p.m. and an
ENS call was made at 4:15 p.m.
The inspector reviewed licensee actions as required by
procedure SE-6, Pollution Incident Prevention Plan, Rev.
5. SE-6 refers to notifications as required by
Environmental Technical Specifications (ETS). The ETS
were replaced by the Radiological ETS in 1984. Also,
SE-6 states that VIP International is the cleanup
consultant; however, UT is the current consultant for
oil cleanup. The inspector discussed these minor
deficiencies with licensee personnel who also had
identified the minor SE-6 errors. The licensee stated
that procedure SE-6 would be revised. The inspector
will review ~*a revised procedure in a future
inspectinn.
No violations were noted. l
4.2.5 Unit 2 ESF Actuatior. on July 10, 1987
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At 9:05 a.m. on July 10, 1987, the Unit 2 shutdown
cooling system isolated when a fuse blew. A loss of
power to the system II logic resulted in the closure of
MO-17 and 18 valves and tripping of the 2A RHR pump.
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The cause of the blown fuse is under investigation. The l
licensee replaced the fuse, reset the isolations, f
restored shutdown cooling and made a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> ENS call at
10:50 a.m. Unit 2 was in the refueling mode with
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coolant temperature at about 105 F.
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The inspector reviewed the SLER and control room logs,
and discussed the event with licensed operators. The
licensee intends to submit a LER for the event. The
inspector will review the LER in a future inspection.
No violations were noted.
4.2.6 Partial Loss of Off Site Power on July 10, 1987
At 3:28 p.m. on July 10,- 1987, a lightning strike during
a storm caused a partial lass of off site power. The
3435 breaker tripped resulting in a loss of power to the #3
startup source for both units. This resulted in a loss
of the #2 and #3 13 KV non vital auxiliary buses, and a
fast transfer of the Unit 2 E-2Z and E-42, and Unit 3
E-13 and E-33 4KV emergency buses to the #2 startup
emergency source. The fast transfers actuated as
designed and no diesel generator starts occurred. Group
II and III containment isolations occurred on both
units, including a loss of shutdown cooling. Unit 2 was
in the refuel mode with the reactor cavity flooded and
cross-connected to the spent fuel and equipment pools.
Coolant temperature was approximately 105 F. Unit 3 was
in the shutdown mode with coolant temperature at about
150 F. The licensee transferred loads to the #2 startup
source per proceaure S.8.3.D.3 and restored shutdown
cooling at 4:12 p.m. on Unit 2 and at 4:40 p.m. on Unit
3. The licensee made a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> ENS call at 5:15 p.m. for
the ESF actuation. The #3 startup source was restored
and the licensee normalized the electrical lineup at
6:55 p.m.
The senior resident inspector was in the control room
prior to and during the event observing licensee
actions. The inspector verified that actions were in
accordance with procedure S.8.3.D.3, " Unscheduled
Tripping of #3 Off Site Power Source, Rev. 7, 10/24/86.
Licensee management reported to the control room within
minutes of the event. The inspector noted that the
control room shif t supervisors (engineers) took command
and controlled the recovery actions.
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The inspector observed the restoration of shutdown
cooling on both units in accordance with S.3.2.C.I. No
unacceptable conditions were noted. Overall response by
the licensee was effective.
4.2.7 Unit 2 Reactor Mode Switch Positioning July 11, 1987
At 5:30 p.m. on July 11, 1987, the licensee made a 4
hour ENS call reporting an event that occurred at 1:05
p.m. The event was the repositioning of the reactor
mode switch from the shutdown to the refuel position
wi th all IRM detector cables disconnected. At 1:19 p.m.
the reactor mode switch was returned to the shutdown
position. The licensee initially determined that this
was reportable as a 30 day LER. However, after further
review the licensee determined that it was reportable under
the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> requirement of 50.72.B.2.111.
The inspector reviewed control room logs and Technical
Specification (TS) 3.1/4.1 and its associated basis. I
The i spector alse discussed the event with licensed
opera;. ors and licensee management. TS 3.1.A, Table
3.1.1 (note 7) requires the IRM high flux scram function
to be operable when the reactor mode switch is in the
refuel position. All control rods were already fully
inserted, and the CRD system was previously blocked by
shift permit #3-87-567. This block prevents any control
rod movement. Thus, the inspector determined that the
licensee had adhered to TS 3.1.A, Table 3.1.1 (note 1)
actions which requires all rods to be inserted within
four hours if a RPS trip function is unavailable. In
additicn, t'. ~: t;J a fcc t!,e refvel moot RPS trip
functions is that it ensures that shifting to the refuel
mode while at power does not diminish the protection
provided by the RPS.
The inspector concluded that repositioning the reactor
mode switch was acceptable for existing plant conditions.
4.3 Logs and Records
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The inspector reviewed logs and records for accuracy,
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completeness, abnormal conditions, significant operating changes
and trends, required entries, operating and night order propriety,
correct equipment and lock-out status, jumper log validity,
conformance with Limiting Conditions for Operations, and proper
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reporting. The following logs and records were reviewed: Nuclear
Operations Monitoring Team Log, Shift Supervision Log, Reactor ) '
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Engineering' Logs, 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, Temporary Circuit Modification Log, and Ignition
Source Control Checklists. Control Room logs were compartJ l
with Administrative Procedure A-7, Shift Operations. Frequent
initialing of entries by licensed operators, shift supervision,
e and licensee on-site management constituted evidence of licensee
review. No unacceptable conditions were identified.
4.4 Refueling Outage Activities
4.4.1 Unit 2 Core Reload
The inspector reviewed Special Procedure (SP)-1021,
" Plant Conditions Necemary to Reload Fuel Unit 2," for
Technical Specification requirevnents associated with
loading fuel into the reactor vessel. SP-1021 was
reviewed in the control room while it was being
implemented and after it had been completed. All steps
had been completed and signed off satisfactorily. All
changes to SP-1021 were handled properly and in
accordance with procedures. The inspector questioned
the operators concerning SP-1021 and found them
knowledgeable of the procedure. The SP was also
discussed with licensee engineers, and the inspector
independently verified that specific steps were
adequately performed. The inspector also reviewed
selected "Shif t Training Bulletins" to verify the
informatier was accurate and complete.
Unit 2 core reload began on June 22, 1987. A review of
the following documentation was performed:
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FH-6C " Fuel Movement and Core Alteration Procedure !
During a Fuel Handling Outage," Revision 19, March
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FH-6C, Appendix 1, " Core Component Transfer i
Authorization Sheet."
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S-14.1-2, " Operation of the Unit 2 Refueling
Platform Controls and Interlocks," Revision 0, May
8, 1984.
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5-14.2, " Moving Fuel from the Fuel Pool to the
Reactor," Revision 5, May 8, 1984. >
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S-14.3, " Moving Fuel from the Reactor to the Fuel
I- Pool." Revision 7, May 8, 1984.
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S-14.4, " Moving Fuel Within the Reactor," Revision
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7, May 8, 1984.
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ST-12.1-3, " Refueling Interlock Functional Test,"
Revision 1, October 31, 1984.
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ST-3.1.2, "SRM Core Monitoring Test," Revision 9,
Janua ry 11, 1985.
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ST-3.1.3, "SRM Functional and Calibration Check,"
Revision 5, October 29, 1983.
The inspector monitored the following items associated
with core reload through direct observation of fuel
handling and Control Room activities:
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The operability of refueling interlocks
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The operability of source ronge monitoring (SRM)
instrumentation
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Availability of direct communication between the
control room and the refueling bridge
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The presence of a senior licensed operator
supervising fuel handling activities
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The operability of the standbv gas treatment system
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The radiological precautions for fuel handling
including adherence to the RWP
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The presence of an HP technician in the fuel floor
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The precautionary measures for preventing the {
intrusion of foreign objects into the reactor I
cavity )
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The operation of the refueling bridge and
associated fuel handling equipment
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Reactor vessel and fuel pool water level and
clarity requirements
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Fuel and component accountability in the spent fuel
pool and in the reactor core
- - _ _ _ _ _ _ _ _ _ _- __
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Reactor mode switch locked in " refueling" position
--
The operability and required full insertion of all
--
Unit 2 reactor operator cognizance of refueling
activities and direct monitoring of SRM levels and
changes (count rates and period changes).
Fuel loading was completed at 11:53 p.m. on July 1,1987.
The core was verified complete at 10:35 a.m. on July 2,
1987. Overall, coordination and conduct of the refueling
activity was considered to be effective. Within the scope
of this review of fuel loading activities, no unacceptable
conditions were identified.
4.4.2 Unit 2 Stuck Fuel Bundle No. 49-40
The inspector attended the Nuclear Review Board (NRB)
meeting that was held to review the cause of Unit 2
stuck fuel bundle 49-40 which was encountered during the
fuel offload on Unit 2. The meeting was held at PECo
headquarters on June 2, 1987. The fuel bundle problem
was initially reviewed in NRC Inspections 277/86-10 and
277/86-09.
The NRB was briefed by members of the Peach Bottom
technical staff on the findings of their investigation
to determine the cause for fuel bundle 49-40 sticking in
its fuel support piece. The binding was caused by a
piece of foreign material in the coolant flow stream
which impacted on and deformed the fuel assembly lower
tie plate. The foreign material was a sphere approximately
7/8 inches in diameter, brown in color, non-magnetic and
with a dose rate of 15 R/hr at one foot. It was recovered
during the investigation. The fuel bundle remains stuck in .
its fuel support piece in the spent fuel pool. .
The licensee concluded that the spherical object most
probably entered the vessel during the 1984-85 pipe 1
replacement outage. The fuel bundle lower tie plate was I
apparently deformed by repeated impact by the object. The I
object is probably stainless steel with an activity of 7-8 I
curies. )
Future actions to be performed by the licensee include:
1
--
Possible inspection of additional fuel locations I
for foreign objects.
\ . . _ _ _ _ _ _ _ _ _ _ _ _
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--
Attempt to separate the fuel bundle from its fuel'
support piece for additional examination.
--
Incorporate tool handling equipment visual
I inspection for missing parts at completion of each
l job.
l
--
Send object to GE for analysis.
The NRB discussion was probing and thoroughly explored
the safety implications of the problem. The NRB l
concluded that actions taken were adequate to support i
reloading of the Unit 2 core.
The inspector verified that a quorum of NRB members and
alternates was present per Technical Specification 6.5.2
and NRB administrative procedures.
No violations were identified.
,
4.4.3 Motor Operated Valves (MOVs) Testing
In response to IE Bulletin 85-03, the licensee is
performing MOVATS testing on Unit 2 High Pressure Coolant
Injection (HPCI) and Reactor Core Isolation Cooling (RCIC)
MOVs. Testing has determined that four valves do not meet
the engineering calculated motor thrust requirements. The
valves include the following: RCIC minimum flow (13-27),
RCIC Condensate Storage Tank (CST) test return (2.3-30),
RCIC torus suction (13-41), and HPCI inside containment
steam supply (23-15). Based on this information, the
licensee made an ENS call at 5:22 p.m., on June 8, 1987,
and informed the senior resident inspector. The apparent
cause of the low motor thrust is associated with the spring
packs and belleville washers. The licensee is repairing
the defective spring packs and performing retests. In
addition, differential pressure testing is scheduled during
restart.
The inspector reviewed the licensee's test results and
SLER; discussed the testing with licensee engineers, ;
maintenance and vendor personnel; and monitored test i
implementation with licensee and vendor personnel. The !
licensee intends to submit an LER for these MOV test
failures. In addition, Unit 3 testing will be performed
as well as possible additional testing for other Unit 2
and 3 MOVs IE Bulletin 85-03 remains open pending the
completion of licensee testing, submittal to the NRC of ,
test results, and NRC reviews.
r
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4.4.4 Unit 2 Standby Liquid Control System (SLCS)
Modifications
The licensee performed modifications (MOD 867) on the
Unit 2 SLCS to meet the requirements of 10 CFR
50.62(c)(4) for anticipated transients without scram
(ATWS) risk reduction. The SLCS must have an equivalent
capacity of 86 gpm injection at 1394 weight natural
sodium pentaborate. In order to achieve this, the
licensee selected an enriched baron solution of
approximately 60?; Boron-10 isotope. Thus a lower SLCS
capacity (flow rate) and a lower concentration may be
acceptable. MOD 867 changed the boron enrichment, and
minimum tank level and temperature requirements for the
SLCS.
Since the MOD required a Technical Specification (TS)
change, prior NRC approval was required. NRR approved
the TS change (Amendment Nos. 122 and 126) on June 2,
1987. The inspector reviewed the following: the MOD
package (including the safety evaluation, PORC approval,
MRFs, and other documentation); the revised system
operating, surveillance test and annunciator procedures;
and TS Amendment Nos. 122 and 126. The inspector also
reviewed the "Shif t Training Bulletin" and interviewed
selected licensed operators with respect to their
knowledge of the SLCS and related modifications. The
operators interviewed demonstrated adequate knowledqe of
the SLCS modifications. The inspector verified tht. the
SLCS was operable prior to Unit 2 core reload by
performing an ESF walkdown (see detail 4.5) and that
SP-1021 procedural signoffs for SLCS operability were
appropriate (see detail 4.4.1).
During the review of ST 7.1.1-2, " Unit 2 Standby Liquid
Control T;nk Baron Solution Analysis," the inspector
noted that the licensee used an average SLCS pump flow
rate rather than the lowest flow rat 9. TS 3.4.3 requires
that multiplication of boron concentr:s'. ion (weight percent),
pump flow rate and boron enrichment m: .t be greater than
1.0. The inspector stated that using an average SLCS pump
flow rate is less conservative than using the lowest value.
The difference for ST 7.1.1-2 performed on June 2, 1987,
was as follows:
--
SLCS pump A - 52.25 gpm
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9
--
SLCS pump B - 55.55 gpm I
--
Average -
53.90 gpm
--
result using average SLCS flow = 1.32 )
--
result using lowest SLCS flow = 1.28 l
The TS 3.4.3 requirement was met in both cases. After
discussions with licensee personnel, a representative
stated that the procedure (ST 7.1.1-2) would be revised !
to incorporate using the lowest SLCS pump flow rate.
The inspector will review the revised ST 7.1.1-2 in a
future inspection.
No violations were noted.
4.4.5 Containment Spray Systems ;
l
On June 10, 1987, during implementation- t a planned
system modification, another boiling water reactor
(BWR/3) discovered the presence of corrosion products in
the primary containment spray headers and nozzles in the
drywell. A significant amount of rust flakes were found
in the header and nozzles such that blockage may have
occurred during system initiation.
1
The purpose of the containment spray system is to scrub
radionuclides and to reduce pressure in primary
containment for structural considerations by condensing
steam in the drywell or torus during accident conditions
by spraying these areas with torus water. In response
to this BWR containment spray deficiency, the inspectors
conducted a review of the containment spray systems at ,
Peach Bottom 2 and 3. As part of this review, the i
documents listed in Attachment 2 were reviewed. The ]
inspectors also had discussions with licensee system, d
technical, performance, and In Service Inspection (ISI)
engineers.
Primary containment spray in the drywell consists of two
independent twelve inch ring headers mounted on the
drywell wall at elevations 161' and 172'. The pipe is
manufactured from carbon steel in accordance with ASTM
specification A106 Grade B. Each ring header has 160
equally spaced brass 1 1/2" Fogjet nozzles (1 1/2-7G40).
The upper header (loop A) nozzles point downward at a 53
l angle from horizontal, and the lower header (loop B)
nozzles point downward at a 28 angle from horizontal. !
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J
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Primary containment spray in the torus consists of one
four inch ring header suspended from the center of the
torus ceiling at elevation 122'. The header completely
circles the torus and is concentric with the torus, )j
There are sixteen equally spaced (one per torus bay) '
brass 1 1/2" Fulljet nozzles. All of these nozzles point
,. vertically downward. Either RHR loop A or B can supply
l- the torus ring header.
l
The licensee wrote two maintenance request forms (MRFs ',
8704666, 8704668) to inspect the drywell and torus spray
headers in Unit 2. On June 18, 1987, test engineers and
ISI engineers performed a visual (direct and
fiberoptic) examination of the three headers and
several nozzles. The licensee findings were:
--
For the A drywell spray loop, three nozzles were
removed (#88, #122, #159). All three nozzles and
several inches of header pipe on each side of the ,
removed nozzles showed minimum surface rust. The '
same nozzles were removed from the B loop and
indications were similar. 1
--
For the torus spray loop, four nozzles were removed
(#3,#6,#10,#14). Nozzle #3 was clean, the
piping on each side of the nozzle had minimum
surface ast and a piece of glass (3/4") from a
light bulb was found in the pipe. Nozzle #6 had a
slight buildup of loose powder rust that would not
interfere with the nozzle flow path. The piping on
each side of the nozzle had minimum surface rust.
Both nozzle #30 and #14 were clean and minimum
surface rust was seen in the pipe on each side of
the nozzles.
The inspectors reviewed the licensee's inspection and
findings. The licensee stated that they would inspect
the Unit 3 primary containment spray headers by the end
of July. The inspectors will follow up on the Unit 3
inspection in a future report.
In addition to this review, the inspector also looked at
what type of surveillance tests or inspections are
conducted on the primary containment spray system. The
only activity performed on the primary containment spray
system is an air test on the drywell and torus headers
and nozzles once every five years as required by
Technical Specification (TS) 4.5.8.1d. This requirement
is satisfied by the performance of Surveillance Test
(ST) 12.2, " Containment and Torus Sparger Air Test."
. - _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ -
_ _ _ _ _ __
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I
The inspector reviewed past performances of ST 12.2 to
determine if any blockages or abnormalities were
encountered. For Unit 3, ST 12.2 was performed in its
entirety on January 1, 1979, and again on August 17,
1983. A partial of ST 12.2'(torus spray sparger) was
performed on October 23, 1985, another partial of ST
12.2 ( A loop of the drywell sparger) was performed on
'
October 27, 1985, and ST 12.2 was entirely complete on
November 20, 1985 when the B loop of the drywell sparger
was air tested. The inspector found no discrepancies with i
the performance of these tests and had no further questions
on the Unit 3 STs. .'
The inspector also ieviewed completed ST 12.2 for Unit
2. The following partial ST 12.2 were performed: July '
19, 1980, partial of torus; July 24, 1980, partial of A
and B loop drywell (ST complete); June 19, 1985, partial
of torus. Thus, ST 12.2 was last completed in its entirety
on July 24, 1980. Therefore, ST 12.2 was required to be
fully completed again by October 24, 1986 (including the
25'J grace period), to fulfill the five year requirement of
an. air test on the drywell and torus headers and nozzles
as' stated in TS 4.5.B.1d. As of July 17,.1967, the partial
A and B loop drywell header air tests had not yet been
performed to entirely complete ST 12.2 by October 24, 1986.
This is an apparent violation of TS 4.5.B.1d (277/87-17-01).
The inspector further investigated the method in which
partially performed surveillance tests ere tracked. See
section 7.3.
i
4.5 Engineered Safeguards Features (ESF) System Walkdown
The inspector performed a detailed walkdown of portions of the
Standby Liquid Control System (SLCS) in order to independently
verify the operability of the Unit 2 and 3 systems. The SLCS
walkdown included verification of the following items:
--
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, breakers, and switches are !
properly aligned. !
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Verification that instrumentation is properly valved in and i
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Verification that valves required to be locked have {
appropriate locking devices.
--
Verification that control room switches, indications and
controls are satisfactory.
--
Verification that surveillance test procedures properly
implement the Technical Specifications surveillance
requirements.
No violations were identified.
5.0 TMI Action Plan (TAP) Items Review
5.1 TAP Item II.K.3.18.C, Modification of ADS Logic (Closed - Unit 2)
The Unit 2 Automatic Depressurization System (ADS) has been
modified in accordance with TAP Item II.K.3.18 to automatically
initiate in the absence of a high drywell . pressure initiation
signal. The ADS functions as a backup to the High Pressure
Coolant Injection System (HPCI) by depressurizing the reactor
vessel so that low pressure systems may inject water for core
cooling. The ADS was previously actuated upon coincident signals
of reactor vessel low water level, hiah drywell pressure, a low
pressure Emergency Core Cooling System (ECCS) pump running, and a
105 second time delay which allows ADS to be bypassed if the
operator believes the actuation signal is erroneous or if vessel
water level can be restored. However, for transient and accident
events ei ? f: ~ r ~ "u: 'i ? d g.: F:::u e, e 4 r-e fure :r
j
degraded by a loss of HPCI, manual actuation of the ADS would be 4
required to ensure adequate core cooling.
To reduce the dependence for manual actuation to ensure adequate
core cooling, the licensee installed bypass timers which wil'1
automatically by pass the drywell high pressure condition required
for ADS actuation if recctvP vessel water level remains below the
ADS initiatich setpoint (level 1) for a sustained period. After a
set time delay of nine minutes (plus or minus one minute) and the
103 second time delay, ADS will automatically actuate in the
absence of a drywell high pressure signal if a reactor vessel low
water level condition still exists and a low pressure ECCS pump is
running.
Four, nine minute time delays have been added, one for each ADS
drywell high pressure initiation channel. There are two ADS
actuation channels (Division 1 and Division 2), either of which
can perform the required ADS function. There are two bypass .
timers associated with each ADS division. The low reactor water I
. _ _ _ _ _ _ _ _ _
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.
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. 20
level signal is sealed in so that the bypass time (nine minutes)
will not automatically reset upon recovery of low reactor water
level. The 105 second actuation timer will reset if reactor water
level recovers above the trip setpoint (-106") before it times
out.
Another modification made to the Unit 2 ADS consists of the
addition of two ADS manual inhibit switches (one per ADS division)
that permit the operator to override the ADS automatic blowdown
logic if necessary. These manual inhibit switches are located on ~
control room panel C03 near the controls for the safety relief
valves. A key-locked switch is used for the manual inhibit -
function to provide a means of limiting the potential for
inadvertent actuation cf the manual inhibit. Alarms alert the
operator of time-out of the bypass timer and activation of the ==
manual inhibit switches.
'{
The above ADS logic modification was approved by NRR in Technical
Specification (TS) Amendments Nos. 106 and 110, datad March 5, 1985.
The modification was completed on Unit 3 during the 1985-1986
refueling outage and on Unit 2 during the 1987 refueling outage. ,
The inspector reviewed completed modification package No. 633 and
associated documentation including: safety evaluation,
construction job memo, electrical schemat cs (MI-S52), PORC
approval sheets, modification acceptance test results, maintenance
request forms and related checklists. The inspector reviewed TS
Amendment Nos. 106 and 110, BWR Owners Group Evaluation of the ADS ,
Logic Modification; and related NRC/PECo correspondence on the '
subject. The inspector also reviewed the revised plant procedures
which implemented this ADS logic change including surveillance
test procedures, system operating procedures, alarm cards, and
emergency operating (TRIP) procedures. The inspector discussed
the modification with licensee engineers and plant licensed
operators.
I Within the scope of the review of actions taken by the licensee in
response to TAP Item II.K.3.18.C for Unit 2, no unacceptable
conditions were noted. TAP Item II.K.3.18.C is closed for Unit 2.
TAP Item II.K.3.18.C was reviewed and closed for Unit 3 in NRC
Inspection 278/86-07.
6.0 Review of Licensee Event Reports (LERs)
6.1 LER Review
The inspector reviewed LERs submitted to the NRC to verify that
the details were clearly reported, including the accuracy of the ',
description and corrective action adequ;cy. The inspector
.
_ - _ _ _ _ _ . _ . _ _ . . _ - _ _ . - -
- _ _ _ _ _ _ _ _ _ -
c. .
,
21
determined whether further information was required, whether
generic-implications were indicated, and whether the event
.
,
warranted on-site followup. The following LERs were reviewed: j
LER No.
LER Date
Event Date Subject
2-87-06 Primary Containment Isolation System (PCIS) Group II
May 22, 1987 due to RPS "B" Motor Generator (MG) set trip
April 23, 1987
- 2-87-08 Control Room Ventilation Radiation Monitor
July 1, 1987 Inoperability i
May 29, 1987
July 9, 1987
June 2, 1987
- 3-87-06 PCIS Group III during bus transfer
June 12, 1987
May 14, 1987
6.2 LER On-Site Followu2 i
For LERs selected for en-site followup and review (denoted by
asterisks above), the inspector verified that appropriate
corrective action was taken or responsibility was assigned and
that continued operation 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 3-87-06 concerns a PCIS Group III isolation and half
scram that occurred on Unit 3 on May 14, 1987. The
cause of the isolation was a trip of the "B" RPS bus on
overvoltage during diesel generator paralleling
evolutions. The event was reviewed in NRC Inspection
277/87-15 and 278/87-15. The licensee concluded that i
the root cause of event was operator error compounded by
procedural inadequacies. The inspector concurred with
this determination. However, the inspector also
concluded that another contributing factor to the event
was inadequate training as discussed in NRC Inspection
277/87-15 and 278/87-15.
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6.2.2 LER 2-87-09 concerns a PCIS half Group III containment
l ventilation isolation that occurred on Unit 2 on June 2,
1987. The event is discussed in section 4,2.1 of this
r: port. No inadequacies were noted relative to this
LER.
I
6.2.3 Control Room Ventilation Radiation Monitor !
'
i
l
Background-
The licensee informed the NRC on July 2, 1987, and
reported in.LER #2-87-08 that incorrect piping
configurations existed in the control room ventilation
radiation monitoring (CRVRM) system. The inlet ports of
three of the four solenoid valves had the piping !
reversed. As a result, the CRVRM system would.not have j
been able to detect abnormal radiation conditions as '
designed. The licensee discovered the incorrect 1
configuration on May 29, 1987, during troubleshooting of !
low sample system flow. The CRVRM system provides for
control room emergency filter actuation on high
radiation and for control room isolation on high-high
radiation. The solenoid valves provide for switching of
sample points from the normal air supply to the
emergency air supply on a high radiation signal. As a
result of these piping configuration errors, the CRVRM
systen may rot have been able to perform its safety
function during accident conditions and control room
exposures may have exceeded design values.
.
The peach Bottom control room is common to Units 2 and
3. The CRVRM system functions to sample the air
entering the control room under normal operating
conditions to analyze the air for noble gases, iodine,
and particulate. Normal control room ventilation is
swapped over to emergency filtration during high noble
gas radiation conditions, and isolated (both normal and
emergency modes) during high-high noble gas radiation
conditions or equipment failure. The system also l
monitors the air entering the control room via the j
emergency ventilation duct after a high radiation
swapover. The sampling is accomplished via solenoid ] ,
valves SV-0760A thru D. Each solenoid valve has two l
inlet ports (one piped to the normal ventilation duct j
and the other to the emergency duct) and one exhaust '
port. Only one of the two inlet ports is open at any
given time. During normal operation the four solenoids
are de-energized, and, if piped correctly, the normal
ventilation duct is being sampled. Should high radiation
conditions occur in the normal ventilation duct, the four
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23 l
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solenoids energize, thereby closing the port from the normal l
ventilation duct and opening the port from the emergency duct. '
Licensee Review and Conclusion
With Unit 2 in the refuel mode and Unit 3 in cold
shutdown, on May 29, 1987, at approximately 10:00 a.m.,
the licensee discovered that incorrect piping
configurations ex.isted in the CRVRM system.
Specifically, the sample lines from the normal
ventilation duct and the emergency ventilation duct to
solenoid valve SV-0760B were reversed. Similar
discrepancies existed for SV-0760A and SV-07600. The
sample lines to SV-0760C were piped correctly. The
discovery occurred during investigation of suspected low
flow through the "B" channel of the CRVRM system.
Technical Specification 3.11.A.5 states that "at least l
one of two main control room intake air radiation l
mor.itors shall be operable with the inoperable chanr.el I
failed safe whenever the control room emergency /
ventilation air supply fans and filter trains are
required to be operable by 3.11.A.1 or filtration of the
control room ventilation intake air must be initiated."
As a result of the piping configuration errors, the
licensee determined that the CRVRM system would not have
been able to detect abnormal radiation conditions as
designed. The system has been in this condition for an
undetermined amount of time. Since the channels were
not failed safe during this time period, nor was
filtration+t-of the control room ventilation intake air in
of te '4~~-+ determined that a failure to comply
with the requirements of Technical Specification 3.11.A.5 occurred. The licensee determined that this
was reportable under the requirements of 10 CFR
50.73(a)(2)(1)(B) involving a condition prohibited by
technical specifications.
As reported in the LER,the licensee determined that as a
result of the piping configuration errors, the control
room emergency ventilation system, which is designed to
provide control room habitability during accident
conditions, would not have been able to perform its j
function as designed. '
The licensee performed a preliminary analysis using
methodology consistent with the " Design Review of Plant !
Shielding" submitted in response to NUREG-0737, Item (
II.B.2.2. The results of this preliminary analysis show
that although the normal ventilation was not being
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24
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sampled from the correct duct, automatic swapover of the
control room ventilation system from the normal mode to
the emergency mode would have occurred during accident
conditions consistent with those assumed in the
NUREG-0737 submittal, but the swapover would have been
delayed by 72 minutes. This delay translates to a less
than 1% increase in control room operator exposures (180
day total integrated dose) for the postulated accident
duration and these exposures would have been maintained
at a small fraction (less than 10%) of the GDC-19 dose
limits of 30 rem thyroid, 5 rem whole body, and 30 rem
skin. The swapover would have been delayed because,
prior to entering the control room, the ductwork
branches off to a portion of the emergency duct. It was
from this portion of the emergency duct that the
misaligned radiation monitoring system was obtaining its
samples rather than from the normal ventilation duct.
Therefore, the system ductwork configuration would have
allowed contaminated air to reach the ventilation
radiation monitors (although delayed) thereby effecting
an automatic swapover to emergency filtration.
In addition, the licensee determined that the
consequences of the piping configuration errors would be
minimized due to (1) a Continuous Air Monitoring (CAM)
device which is installed in the control room as a
backup to the ventilation radiation monitoring system,
and (2) the actions specified in the station emergency
procedure for control room air supply high radiation
which require immediate radiation and air surveys in the
control room and at the control room ventilation intake.
In the event of contaminated air in the control room the
CAM would have alerted the control rocm operators who
would then have responded to the abnormal radiation
condition in accordance with the emergency procedure,
including manual swapover or isolation of the control
room if necessary.
The licensee determined that the root cause of the event
was unknown. Plant engineering staff conducted an
investigation to determine the cause. Maintenance
Request Forms and Plant Modifications documentation were
reviewed in an effort to pinpoint the cause of the
discrepancy. It is believed that the condition has
existed since initial installation of the system (prior
to 1974 commercial operation). Upon discovery of the i
sampling point discrepancies, the licensee realigned the )
sample lines to SV-0760 A, B and D to the correct con- l
figuration.
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1
). Additionally, the licensee checked all other ventilation
l radiation monitoring systems for proper piping
configurations. No discrepancies were found. Also, the
'
. licensee stated that a study would be initiated of other
safety systems that depend on sensing process parameters
,
to gain confidence that this deficiency an isolated
1
event. Many process parameters have be- properly
sensed in the past because they have ini..ated Reactor
Protection System actuations, Emergency Core Cooling
System actuations and Primary Containment Isolation
System actuations. The licensee plans to examine those
portions of safety systems that sense process parameters
that have never initiated an emergency safeguard feature !
and determine if the surveillance tests on that portion
of the system would uncover any installation errors, or
even subsequent process line blockages. If any portiotis
of safety systen are identified as having the potential
to have installation deficiencies or subsequent line
blockages the licensee will develop plans to ensure these
portions can function properly. The results of this study
will be reported in a revision to the LER.
NRC Review and Conclusion
The inspector reviewed the LER #2-87-08, and related
documentation (Attachment 3) and discussed it with
licensee engineers and operators. The inspector
verified that the CRVRM system is safety related as
stated in the FSAR, 0-List, and Technical Specifications 3.11.A/4.11.A and their Bases.
A walkdown of the CRVRM system was conducted by the
inspector with the licensee system engineer on July 9,
1987. During the walkdown the inspector questioned the
engineer with regard to the system operation, trouble-
shooting and repair activities. The engineer stated that
the incorrect piping configuration was discovered during
troubleshooting of apparent low sample flow conditions in
the "B" channel of the CRVRM system. The condition had
apparently been determined by cleaner than nor. mal filter
changes and a small difference in two sataple pump (A and B)
vacuum gauges. The licensee disconnected the sample lines
and performed flow tests with nitrogen. Based on these
tests, the licensee concluded that three of four lines were
piped incorrectly. The inspector confirmed this by dis-
cussions with the licensee system engineer.
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The inspector reviewed construction and preoperational
test records for the control room ventilation system and
for the CRVRM system. These records indicate that the
L system was turned over in October 1973. The startup
test for the CRVRM system (#73-4) was performed in May
1973; however, valves SV-760A,B,C&D were not' proper Q
material. This test exception was approved. The valves
were replaced, field inspected, and accepted in September
1973 (reference MRF #2-73-1167). The inspector concluded
that the cause of the incorrect piping configuration was
inadequate construction installation and QC verification of
the CRVRM system.
The inspector reviewed CRVRM system TS 3.11.A. TS 3.11.A.5 requires at least one of the two radiation
monitors to be operable with the failed channel in a
tripped condition. This is required when the CRVRM
system is required to be operable per TS 3.11. A.1 (e.g. ,
either unit is required to have secondary containment).
If TS 3.11.A.5 cannot be met, the filtration of the
control room air intake is required to be initiated with
the emergency filter and fan. Thus, the licensee has
been in apparent violation of 15 3.11.A.5 for both units
since the date of the Operating License, e.g., October
25, 1973 (Unit 2) and July 2, 1974 (Unit 3). (277/87-17-02).
The control room emergency ventilation system is designed
such that the control room is habitable under accident
conditions. The CRVRM system provides system actuation on
high radiation and system isolation on high high radiation.
Thus, a safety related system may not have been able to
perform its functi;n as designed.
The inspector reviewed the licensee's control room
continuous air monitoring (CAM) system and procedure j
E-7, " Control Room Air Supply High Radiation, Rev. 5. 1
The CAM system provides for radiation monitoring (beta f
and alpha) of the control room air. The CAM system is j
not required by Technical Specifict.tions, however the J'
licensee maintains the CAM in service. The inspector
reviewed the CAM system operation, testing, and
maintenance. In addition, the inspector questioned
control room operators and technicians with regard to
CAM operation, testing and use during implementation of
E-7 (actual high radiation in the control room). The
inspector determined that operators and technicians were
knowledgeable of the CAM system in the control room.
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The licensee analyzed the ability of the control room
emergency ventilation to swapover even though the piping
configuration was in error. The inspector reviewed this
preliminary analysis as stated in the LER. The review
of the final analysis will be performed in a future
inspection.
The inspector reviewed surveillance testing (ST) for the
CRVRM system. TS 4.11.A.4 requires operability testing
of the CRVRM system every three months. ST 9.8 tests
the CRVRM system by performing a functional test on the
initiation and control logic. The inspector discussed
ST 9.8 with licensee engineering and test personnel.
The licensee stated that a new procedure (ST 4.7.3) is
being written to calibrate the CRVRM detectors
(RIS-0760A and B). The licensee had identified a
deficiency with respect to their ST program apparently
caused by the fact that TS 4.11.A doesn't directly
require a calibration test for the CRVRM system. The
inspector will review this ST procedure in a future
inspection.
The CRVRM system high and high-high trip setpoints could
not be verified by the preoperational and startup test
data nor instrument data sheets. The inspector
questioned the licensee with respect to these setpoints.
A licensee representative stated that engineering is
determining the correct setpoints. The current high
trip setpoint is 400 CPM for each detector; however, the
high-high setpoint could not be determined. ST 9.8
records these setpoints which are 400 CPM for high le el
and a dial setting for hign-high level. The inspector
reviewed standard TS (STS) for the CRVRM system.
STS specify requirements for CRVRM system alarm / trip
setpoints and surveillance requirements for channel
calibration. These CRVRM trip setpoints and calibration
requirements are unresolved pending licensee
determination and subsequent NRC review. (UNR
277/87-17-03)
Summary
As a result of apparent inadequate construction, QC, and
preoperational test verifications; the CRVRM system has
been incorrectly configured since Unit 2 and 3 startup
(1973,1974). Thus, the plant has been in apparent
violation of TS 3.11.A.5 and a safety system may not have
been able to perform as designed. The licensee identified
this non-conforming condition during system troubleshooting.
Otherwise, this condition may have gone undetected for a
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1
L longer period of time. A review of similar systems has not
, determined any other deficiencies. Mitigating factors for
! the inoperability of the CRVRM system include a functional
control room CAM and emergency procedure E-7. In addition,
the licensee has preliminarily determined that the incorrect 1
i
CRVRM system configuration would have allowed a delayed
swapover to the emergency ventilation system.
7.0 Surveillance Testing
The inspector reviewed surveillance tests (STs) 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
calibrated, work was performed by qualified personnel, and test
acceptance criteria were met.
7.1 Surveillance Tests Reviewed :
The inspector reviewed the following corrpleted STs:
--' ST 7.1.1-2, " Unit 2 Standby Liquid Control Tank Boron ,
Solutinn Analysis," Rev. O, 4/29/87, performed on Unit 2 on
'6/1/87.
--
ST 13 8-2, " Unit 2 Standby Liquid Control Injection Test,"
Rev. 0, 5/18/87, performed on Unit 2 on 6/2/87.
--
ST 6.1.2, " Standby Liquid Control Pump Functional Test for
ISI," Rev. 2, 12/19/86 performed on Unit 2 on 2/4/87.
--
ST 12.2, " Containment and Torus Sparger Air Test," various
revisions, performed on Unit 2 on 1/1/79, 8/17/83, 10/23/85,
10/27/85 and on Unit 3 on 6/19/80, 6/24/80, 6/19/85, and
11/20/85.
With the exception of ST 7.1.1-2 (see detail 4.4.4) and ST 12.2
(see detail 4.4.5 and 7.3), no unacceptable conditions were
identified.
7.2 Partial Surveillance Tests
Ir. Combined Inspection Report 50-277/85-29; 50-278/85-33, a violation
was issued concerning a failure to test three Unit 3 relief valves
after the other eight valves were tested under partial surveillance
tests. The violation was noted by the inspector in October 1985.
The licensee's response to the violation stated that the cause of
the remaining missed partial surveillance test was a failure to
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29
follow administrative procedure A-3, " Procedure for Temporary
Changes to Approved Procedures." After a review of corrective t
action, this violation was closed in Combined Inspection Report
50-277/86-19; 50-278/86-20.
Based on a similar apparent violation detailed in this inspection
report (detail 4.4.5), the inspector reviewed the method in which gg
the licensee tracks partial surveillar:e tests. For the review,
the inspector had discussions with the performance engineer,
system engineer and surveillance test coordinator, and reviewed
administrative procedures A-3, " Procedure for Temporary Changes to
Approved Procedures," Rev. 8 and A-43, " Surveillance Testing System,"
Rev. 18.
The inspector determined that the licensee's computer software
program for surveillance tests (STARS) cannot completely
differentiate between partially completed STs and completed STs.
A partially completed ST can be entered into STARS, but it will
not appear on the " Grace Period Surveillance Test Report" or
" Overdue Test Report." Once the partial ST is reviewed and is
removed from the " Tests Awaiting Official Verification Report,"
the ST will not reappear until its next surveillance period.
Therefore, required portions of the ST may not be completed unless
the cognizant supervising engineer manually tracks the partial ST
until it is totally complete.
The performance engineer stated that plans for obtainir.g an
updated STARS program that could track partial STs was being
discussed. The resident inspector will foliow this item as part
of the apparent violation in detail 4.4.5.
8.0 Maintenance
For the following maintenance activities the inspector spot-checked
administrative controls, reviewed documentation, and observed portions
of the actual maintenance: l
Maintenance
Procedure /
Document Eouipment Date Observed
S.4.2.J Control Rod Operation Functional June 2, 1987
Test
MRF MS7-4771 2C HPSW Pump June 22, 1987
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Administrative controls checked included maintenance request forms
(MRFs), blocking permits, fire watches and ignition source controls,
item, handling reports, QC involvement, plant conditions, TS LCOs,
equipment turnover information, and post maintenance testing.
Documents reviewed included maintenance procedures, material
certifications, RWPs,.MRFs, and receipt inspections.
_
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No inadequacies were identified.
1
9.0 M diation Protection
l
CQring the report period, the inspector examined work in progress in
hoth units, including health physics (HP) procedures and controls, ,
dosimetry and badging, protective clothing use, adherence to radiation
work permit (RWP) requirements, radiation surveys, radiation protection
instruments use, and handling of potentially contaminated equipment and
materials.
The inspector observed individuals frisking in accordance with HP
procedures. A sampling of high radiation doors was verified to be
i 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 information and 'pecple working in
RWP areas were observed to be meeting the applicable requirements. No
unacceptable conditions were identified.
10.0 Phy_sical Security
10.1 Routine Observations
The inspector monitored security activities for compliance with
the accepted Security Plan and associated implementing procedures,
including: operations of the CAS cnd SAS, checks of vehicles
on-site 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 inadequacies were id.entified.
10.2 Watchman Asleep on June 21, 1987
The Plant Manager found a security watchman asleep at the Unit 2
drywell access at about 4:00 p.m., on June 21, 1987. The watchman
s
was escorted off site by the sergeant of the guards, and the
watchman subsequently quit. No work was in progress in the
drywell and an HP control point was not established. The licensee
informed the senior resident inspector of this occurrence at 7:00
a.m., on June 22, 1987. The licensee investigated the incident
and the NRC reviewed 1^. in Inspection 277/87-20; 278/87-20.
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10.3 Drug Allegation (RI-87-A-0070)
!
On June 18, 1987, the inspector received a call from an anonymous
source alleging that a contractor worker was a habitual drug user.
The inspector notified the licensee of this information. The
licensee's security organization and the contractor's management
performed an investigation. The licensee informed the inspector
that the individual admitted drug use in the past.
The contractor worker's employer requested that he submit to a drug
test; he refused and his employment was. going to be terminated.
,
However, the employee was advised by a lawyer to take the drug test.
l' A drug test was administered on June 29, 1987, and the results were
'
negative.
The individual does not currently have access to the peach Bottom
l protected area. Readmittance to the protected area will be
l determined pending f urther licensee investigation. Tne inspectors
L will follow this issue.
1
10.4 Controlled Substance Found During Search
At 1:09 p.m. on July 8,1987, a contractor employee was found to
be carrying a controlled substance in a cigarette pack while
trying to enter the orotected area. During the required routine
search, a security guard noticed a piece of tape covering the
opening of the cigarette pack. Upon examination, a small bag of
white powder was discovered.
The contractor employee is a janitor employed by International
Systems Services (ISS) and has been working at peach Bottom since
October 1985. He stated that the substance was methamphetamine
and he has never brought in .or used drugs in the protected area.
However, he did admit to storing drugs in his car on licensee
property. The individual had access only to administrative
..< buildings within the protected area and did not have vital area ]
,
. access.
The contractor worker's employment was terminated by ISS, his
security badge was pulled and he was escorted off site. The
substance was sent to the state lab for analysis. The Nuclear
Employee Data System (NEDS) and the Pennsylvania State Police in
York were notified.
The inspectors had no further questions.
11.0 In-Office Review of public and Special Reports
The inspector reviewed the following:
--
Monthly Operating Report for May 1987, dated June 15, 1987.
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Special Report for,the Motor Driven Fire Pump Out-of-Service,
dated June'5, 1987.
h
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No unacceptable conditions were noted. \
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< 12.'0 Unresolved Items
]
, Unresolved items are items about which more information is required to
- ascertain whether they are acceptable violations or deviations. Two
unresolved items'are discussed in section 6.2.3.
13.0 Management Meetings '
. 13.1 Preliminary Igyection Findings
A verbal summary of preliminary findings was provided to the
'
Manager, Peach Bottom Stacion at the conclusion of the inspection.
During the inspection, licensee management was periodically
notified verbally of the preliminary findings by the resident
.irrpectors. No written inspection material was provided to the )
' licensee during the inspection. No pr0 pietary information is
,
1.1cluded in this report.
)3.2AttendanceatManagementMeetingsConductedbyRegionBased
Inspectors
Inspection Reporting
S Date \ Subject Report No. Inspector
6/15-19/87 IE Bulletin 87-16/16 Varela
80-11 (Masonry
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6/15-17/87 EQ 87-18/18 Paolino
4 ;
6/1-5/p?x Containment 87-19'19 Chung
Integrity
,6/28-7/2/87 Security 87-20/20 Bailey
7/13-17/87 Radiological 87-21/21 Oragoun'
Controls
13.3NRCRecionI/100 Management Meeting on June 17, 1987
\
- g;'i On June 17, 1987, a management meeting was held at Peach Bottom
Station. At this meeting, PECo discussed the status of actions in
response to the NRC Order c'ated March 31, 1987. The licensee
o.fiscussed the status of the MAC investigation and their security
investigation; updated the status of the NOMT; discussed future
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plans for training, shift organization, and procedures update;
ana, discussed the PECo " Commitment to Excellent Program". A list
of meeting attendees is included in Attachment 1. The inspector
will continue to follow this area. l
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13.4 NRC/Harford County, Maryland Meetina on June 23, 1987 I
On June 23, 1987, NRC representatives attended the Harford County i
(MD) Council Meeting in Bel Air, MD. The meeting purpose was to l
brief the Council regarding the status of the Shutdown Order,
investigations, and followup. The inspector attended the meeting.
13.5 NRC/PECo Meeting at Bethesda, Maryland on July 15, 1987
On July 15, 1987, a ranagement meeting was held at NRC
headquarters in Bethesda, MD. At this meeting, PECo discussed the
status of their actions in response to the NRC Order, including
their recovery plan (" Commitment to Excellence"). The inspector !
attended the meeting. A meeting summary will be provided by NRR.
The inspector will continue to follow this area.
1
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ATTACHMENT 1
PECo/NRC Meeting i
June 17, 1987
NRC Attendees
R. M. Gallo, Branch Chief Project Branch 2, Region I
W. F. Kane, Director, Division of Reactor Projects, Region I
W. V. Johnston, Acting Director, Division of Reactor Safety, Region I
J. C. Linville, Section Chief, PB2, DRP, Region I
R. E. Martin, NRC Pr oject Manager, USNRC/NRR
R. J. Urban, Resident Inspector, PBAPS
B. Clayton, Regional Coordinator, NRC
S. F. Shankman, Region I Operator Licensing
M. T. Miller, State Liaison Officer Region I
J. H. Williams, Project Engineer, Region I
D. S. Morisseau, Training and Assessment Specialist, NRR
State of Maryland Attendees
W. Bonta, Engineer, State Department of Health
P. Perzynski, Staff, State Department of Health
T. Magette, Administrator, Nuclear Evaluations, MD Power Plant Research
Program
State of Pennsylvania Attendees
W. Dornsife, Chief, Division of Nuclear Safety, PA Department of
Environmental Resources
S. Maingi, Nuclear Engineer, PA Department of Environmental Resources
PECo Attendees
G. F. Daebeler, Assistant to Plant Manager for Commitment to Excellence
Program
E. P. Fogarty, Project Manager, Commitment to Excellence Program
Dr. W. F. Hushion, Medical Director ,
G. M. Leitch, Manager, Nuclear Generation Department
E. J. Bradley, Associate General Counsel
J. W.. Gallagher, Vice President, Nuclear Operations
D. M. Smith, Manager, Peach Bottom Atomic Pcwer Station
A. B. Donell, Nuclear Operations QA Division, Site Supervisor
C. J. McDermott, Manager, Public Information
R. H. Logue, Assistant to Manager, Nuclear Support Department
J. W. Jones, Assistant Manager, Public Information
P. E. Webster, Senior Public Information Representative
P. J. Duca,. Procedures Coordinator
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Others
H. R. Abendroth, Senior Engineer, Atlantic Electric l
M. A. Phillips, Senior Engineer, Public Service Electric & Gas
C. D. Schaefer, Electrical Operations, Delmarva Power .
, C. W. Thayer, Management Analysis Company $
! J. R. Coughlin, Lead Scheduler
W. L. Fauth, Consultant
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ATTACHMENT 2
Documents Reviewed for Containment Spray System
1. Peach Bottom Atomic Power Station, Units 2 & 3, Updated Final Safety
Analysis Report
2. Peach Bottom Atomic Power Station, Units 2 & 3, Technical
Specifications
3. Surveillance Test ST 12.2, " Containment and Torus Spray Sparger Air
Test", Rev. 3, 5/28/85
4. Administrative Procedure A-3, " Procedure for Temporary Changes To
Approved Procedures," Rev. 8, 10/20/86
5. Bechtel Design Drawings 6280-C2-362 " Field Assembly for Drywell Spray
Headers", and 6280-C2-321, " Suppression Chamber Internal Spray Header
Assembly"
6. Vendor Technical Manuals for Fulljet Spray Nozzles (6280-C2-85-1) and
Fogjet Nozzles (6280-C2-84-1)
7. Field Inspection Report #1087-2439, "RHR Drywell and Torus Containment
Spray Header", June 18, 1987
8. P&ID M-361, " Residual Heat Removal System"
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ATTACHMENT 3
Control Room Ventilation Radiation Monitoring System Documentation Reviewed
--
UFSAR' sections 10.13 and 7.12.5
!
--
Peach Bottom Q-List section 17.0, Rev. 22
--
TS 3.11.A/4.11.A and Bases
--
E-7, Control Room Air Supply High Radiation, Rev. 5, 7/1/80
--
ST-9.8, Control Room Emergency Ventilation and Radiation Monitor
Functional Test, Revision 11, 10/28/85
--
RT 7.6.2, Periodic Operational Check and Inspection of CAMS, Rev. O,
11/8/82
--
RT 7.6.1, Periodic Calibration and Maintenance of CAMS, Rev. 2, 6/29/87
--
RT 7.6.3, Periodic Filter Change and Check of CAMS, Rev. 1, 4/15/87
--
Alarm Cards 00C214 #2 and #3 (Control Room Vent Supply Rad A, B)
--
P&ID M-393, Control Room Ventilation Flow Diagram, Revision 10, 2/26/85
--
E-255. Rev. 17, ESD Control Room Annunciators
--
P&ID M-384, Control Room Temperature Control Diagram, Revision 19,
6/16/80
--
LFE Instruction Book #6280-M236-37-1, Vent Rad Monitoring System
--
P&ID M-328, Cooling & Heating Piping Systems, Revision 14, 11/30/76
--
Spec M-236, Radiation Monitoring Systems
--
P&ID M-334, Ventilation Radiation Monitoring System, Revision 15,
10/31/83
--
QAD M-834, Ventilation Radiation Monitoring System, Revision 4
--
S.12.6.2.A, Normal Operation of the Control Room Ventilation, Revision
1, 03/19/87
--
S.12.6.2.A, COL, Control Room Radiation Monitor Sample Station Check
List, Revision 0, 08/30/82
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S.12.6.2.B, Setup of Contral Room Emergency Vent System for Automatic
Operation, Revision 2, 05/18/87
--
S.12.6.2.C, Control Room Purge Air System, Revision 0, 01/18/73
1
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S.12.6.2.0, Routine Inspection of Control Room Ventilation System,
l Revision 2, 05/18/87
--
S.12.6.1.A, Aligning the Control Room Chilled Water System Valving in
Preparation for Control Room Chi'ler Startup, Revision 0, 11/16/72
--
S.12.6.1A, COL, Control Room Chilled Water Startup, Revision 3,
06/18/b0
--
S.12.6.1.B, Starting Up the Control Room Chilled Water System Normal
Cveration, Revision 0, 11/16/72
--
S.12.6.1.0, Loss of the Control Room Chiller Units and/or the Control
Room Chilled Water Pumps, Revision 1, 06/24/80
--
S.12.6.1.E, Chemical Addition to the Control Room Chilled Water System,
Revision 1, 06/17/80 !
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S.12.6.1.F, Routine Inspection - Control Room Chiller Operating,
Revision 0, 10/29/80 i'
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E-1674, ESD Ventilation Radiation Monitoring System, Revision 5
--
Peach Bottom Startup Tests No. 73-4 and 74 and Construction Turnover
Information for Control Room Radiation and Ventilation Systems (1973)
--
MRFs 2-73-1167, 2-63-M-86-8740, 2-63M-87-4198
f
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