ML20203E370
| ML20203E370 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 02/20/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20203E339 | List: |
| References | |
| 50-277-97-08, 50-277-97-8, 50-278-97-08, 50-278-97-8, NUDOCS 9802270033 | |
| Download: ML20203E370 (51) | |
See also: IR 05000277/1997008
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION I
Docket Nos. 50 277,50 278
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- Report Nos. 97 08
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! Licensee: PECO Energy Comp.any
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Facility: Peach Bottom Atomic Pov<er Station Units 2 and 3
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Dates: November 23,1S97 to January 17,1938
- Inspectors: A. C. McMurtray, Senior Resident inspector
M. J. Buckley, Resident inspector
B. D. Welling, Resident inspector
R. S. Barkley, Project Engineer
J. C. Jang, Senior Radiation Specialist
L. L. Eckert, Radiation Specialist
G. C. Smith, Senior Security Specialist -
P. R. Frechette, Security Specialist
J. F. Williams, NRR Project Manager >
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9802270033 990220
gDR ADOCK 05000277
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EXECUTIVE SUMMARY
Peach Bottom Atomic Power Station
NRC Inspection Report 50 277/97-08,50-278/97 08
This integrated inspection report includes aspects of licensee operations; surveillance and
maintenance; engineering and technical support; and plant support areas.
Plant Ooerat!gns:
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- Licensee management decided to shutdown Unit 3 and replace the 'E' safety relief l
valve (SRV) after observing a continuing upward trend in the tailpipe temperature.
Management also chose to shutdown Unit 2 to perform electro-hydraulic control
(EHC) pressure regulator work. These decisions showed good, conservative,
operational decision making. Operator performance during these shutdown and
startup evolutions was very good. (Sections 01.2 and 2.1)
- Station preparations for cold weather weie performed adequately. However, the l
inspectors identified a number of discrepancies associated with the documentation
and performance of the winterizing routine test procedures, which reflected lapses l
in formality and attention to detail. The failure of operations personnel to adhere !
with the requiremants in the test procedures resulted in a violation for procedural
non compliance. (Section 02.3)
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- Operator performance during two plant transients caused by circulating water
system problems was satisfactory. The second transient was initiated by the failure -
of the 2 'C' circulating water pump discharge vaive. PECO's investigations into
i both events were in progress at the end of this inspection period. The inspectors
will review the results of these investigations for maintenance performance issues.
(Section O2.4)
- On January 2,1998, the unit 2 reactor operator failed to perform the technical
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specification (TS) surveillance requirements (SRs) for verification of proper flow in
the recirculation loops. The recirculation loops were not operated outside of the TS
requirements during this period. However, it was unclear how station personnel
determined that the formal TS SRs were met and why operations personnel failed to
review the TSs when unclear information was found in the surveillance test. This
issue remains en Unresolved item (URI) pending additional discussion with
operations personnel and final review by the licensee. (Section 03.1)
- During clearance restoration for the diesel driven fire pump, the motor driven fire
pump unexpectedly started. The clearance did not contain any cautions regarding
the potential for a sudden drop in system pressure to automatically start the motor
driven pump and operations personnel performing the clearance removal were not
fully aware of this system condition. (Section O3.2)
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- On January 1,1998, the Unit 2 main turbine tripped on main oil pump low pressure
during plant start-up after the turbine rolled to a speed of 1400 RPM. Operations
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Executive Summary Cont.
personnel were unaware that the turbine had been rolling for over two hours just
prior to the trip. This issue appeared to involve a f ailure of an instrument and
control test document to restore the original EHC system alignment af ter testing and
the f ailure of operations personnel to fully fobow procedures. Concerns were also
identified with the pulling of control rods to increase reactor pressure during this
event and the failure of operations personnel to recognize the status of the main
turbine or turbine control systems. This issue remains a URI pending additional
reviews of the procedures used during this event, review of strip charts and
recorded data from this event, and further discussions with reactor engineering and
operations personnel. (Section 04.1)
- On January 7,1998, Unit 2 control room personnel entered an operational transient
procedure when a main steam line high radiation alarm was received twice during
power ascension. Concerns were identified with the operators incomplete
knowledge of the effects of the hydrogen addition system on main steam line
radiation during startups and abnormal reactor feedwater alignments. Also, the
procedure did not contain instructions to lower the hydrogen addition during this
transient. (Section 04.2)
- The inspectors found that a standby liquid control pump discharge valve was in the
correct pos' tion, but was not locked, as specified by a clearance restoration form.
Although of minimal safety impact, this and a second improperly locked valve
discovered by the licensee indicated that operators were not always rigorous in
independently verifying the condition of locked valves. Corrective actions for this
issue were good and included verification of alllocked valves in both units. This
issue resulted in a Non-Cited Violation (NCV) for procedural non-compliance.
(Section 04.3)
M.e intenance:
- Af ter the Limerick Generating Station discovered a reactor core isolation cooling
'RCIC) inboard steam velve with the wiring to the thermal overload bypass contact
lif ted, the station tested several motor operated valves looking for this condition.
This testing was proactive and showed conservative decision making. Technicians
performing the testing displayed good adherence to procedures. (Section M1.3)
- The station missed an opportunity to plan for the removal of foreign materialin the
2 'C' residual heat removal system heat exchanger. This material, which included
metal straps and an extension cord, was first identified in 1994 and had not been
tracked for removal during subsequent maintenance periods. Technicians were
surprised when they found this material during maintenance activities in January
1998. (Section M2.2)
- The station and the NRC identified instances where operations were not informed of
degraded conditions on safety related equipment in a timely manner. Although
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Executive Summary Cont.
some items were mincr, one involved an RHR system valve that was declared
inoperable af ter operations became aware of this degraded valve. (Section M3.1)
- On January 4,1998, main steam line bypass valve, BPV 1, unexpectedly opened
approximately 25% several times while the Unit 2 reactor operator was raising
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reactor power from 96% to 100%. Instrument and control technicians unknowingly
introduced a speed error bias in the speed control portion of the EHC system after
! they tightened a loose connection during replacement activities for the EHC
pressure control unit. Instrument and control personnel f ailed to understand what
effect tightening the loose connection on the speed control would have on the
speed bias signal and the EHC system. (Section M4.1)
Enaineerina: -)
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- On December 29,1997, all nine bypass valves unexpectedly opened at 155 psig
EHC pressure curing the normal depretsurization/cooldown of Unit 2. Operations
and engineering personnel failed to understand the effect on the EHC system of a
temporary plant alteration which was designed to fail the 'B' EHC pressure regulator
and allow replacement of the secondary pressure amplifier card. This lack of
system understanding contributed to all the bypass valves unexpectedly opening
which resulted in a reactor vessel level transient. (Section E2.1)
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- During scheduled maintenance, PECO maintenance personnel identified a broken
vlutch gear and found a motor brake installed to a Unit 2 residual heat removal
valve motor operator. This motor break was to have been removed per an
, engineering modification in 1988. The broken clutch gear was replaced and the
motor brake was removed. The valve was never rendered inoperable due to the
installed motor brake. The inspectors will follow-up on the inspections for motor
brakes on other valve operators and the results of the failure analyses of the clutch
gear. (Section E2.2)
Plant Support:
- Security facilities and equipment were determined to be well maintained and
reliable. Security procedures were being properly implemented. Security staff
knowledge, performance and training were determined to be acceptable. Security <
organization, administration and quality assurance programs were adequate to
ensure effective implen;3ntation of the program. A review of the vehicle barrier
system determined the system was installed and being maintained in accoro, me
with applicable regulatory guidance and requirements. (Sections S1 through S8)
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. TABLE OF CONTENTS
EXEC UTIVE S U M M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Summary of Plant Status ............................................1
1. O p e r a t i o n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
01.1 General Comments .................................1
01.2 Unit 3 Plant Shutdown to Replace 'E' Safety Relief Valve . . . . . . . 2
O2 Operational Status of Facilities and Equipment ................... 3
02.1 St.utdown of Unit 2 Due to Problems with the Electro-Hydraulic
Control (EHC) System Pressure Reg.:tator control . . . . . . . . . . . . 3
02.2 2 'B' Recirculation Pomp Speed Control Problems . . . . . . . . . . . . 4
O2.3 Cold Weather Preparations . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
O 2.4 Circulating Water System Problems (Unit 2) . . . . . . . . . . . . . . . . 7
03 OperaCons Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . 8
03.1 Missed Technical Specification (TS) Surveillance Requirement (SR)
Test for Verification of Proper Flow in the Recirculation Loops . . . 8
03.2 Unexpected Start of the Motor Driven Fire Pump During Clearance
Removal for the Diesel Driven Fire Pump .. .............. 10
04 Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . 11
04.1 Unexpected Trip of Unit 2 Main Turbirie During Start-up . . . . . . . 11
04.2 Unit 2 Main Steam Line High Radiation Alarms During Power
A s c e n si o n . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
04.3 Standby Liquid Control Pump Clearance Restoration ......... 14
07 Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
07.1 Plant Operations Review Committee (PORC) Meeting . . . . . . . . . 16
11. Maintenance and Surveillance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
M1 Conduct of Maintenance and Surveillance . . . . . . . . . . . . . . . . . . . . . . 16
M 1.1 Standby Liquid Control Pump Maintenance . . . . . . . . . . . . . . . . 16
M 2 Unit 3 Primary Containment Local Leakage Rate Testing (LLRT)
Review ........................................17
M1.3 Motor Operated Valve ThermalI'mit Bypass Operability . . . . . . . 17
M2 Maintenance and Material Condition of Facilities and Equipment . . . . . . 18
M2.1 Standby Liquid Cor' trol Pump Crankcase Oil Viscosity ........ 18
M2.2 Foreign Material in 2 'C' Residual Heat Removal System Heat
E:: c h a n g e r . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 9
M3 Mainten nce Procedures and Documentation . . . . . . . . . . . . . . . . . . . 20
M3.1 Equipment Condition Notification to Operations . . . . . . . . . . . . . 20
M4 Maintenance Staff Knowledge and Performance . . . . . . . . . . . . . . . . . 21
M4.1 Unit 2 EHC Speed Error Signal Bias Due to Repair of Speed Control
i Card Short ... ..................................21
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111. E n g in e e ri n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 3
E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
E1.1 Unit 3 Jet Pump Riser Elbow Weld Cracking . . . . . . . . . . . . . . . 23
E2 Engineering Support of Facilities and Equipment .................24
E2.1 Inadvertent Operation of Bypass Valves During Unit 2 Shutdown . 24
E2.2 2 'C' Residual Heat Removal (RHR) Pump Suction to Torus Valve
Motor Operator Deficiencies .........................25
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Tcbla of Contants (cont'd)
E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
E8.1 (Closed) URI 50 277(278)/96-04-04: Emergency Diesel Generator
(EDG) Output Breaker Response During Testing . . . . . . . . . . . . . . 26
IV. Pl a nt Su pport . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 7
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R1 Radiological Protection and Chemistry (RP&C) Controls . . . . . . . . . . . . 27 ,
R1.1 Implementation of the Radioactive Liquid and Gaseous Effluent
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ControI Programs ........................ ........27
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R2 Status of Radiological Protection and Chemistry Facilities and Equinment i
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R2.1 Calibration of Effluent / Process Radiction Monitoring Systems (RMS) l
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, R2.2 Surveillance Tests for Air Cleaning and Ventilation Systems . . . . 29
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R2 Radiological Protection er.d Chemistry Procedures and Documentation . . 30
R7 Quality Assurance (QA) in Radiological Protection and Chemistry Activities
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R8 Miscellaneous Radiological Pratection and Chemistry issues . . . . . . . . . 31
R8.1 Unreviewed Safety Question Review and Radioactive Effluents
Control (VIO 50-27 8/97-03 01 ) . . . . . . . . . . . . . . . . . . . . . . . . 31
, R8.2 Tour of Peach Bottom Unit 1 . . . . . . . . . . . . . . . . . . . . . . . . . . 32
- S1 Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . 32
! S2 Status of Security Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . 33
S3 Security and Safeguards Procedures and Documentation . . . . . . . . . . . 34
S4 Security and Safeguards Staff Knowledge and Performance . . . . . . . . . 34
S5 Security and Safeguards Staff Training and Qualifications .......... 35
S6 Security Organization and Administration . . . . . . . . . . . . . . . . . . . . . . 35
S7 Quality Assurance in Security and Safeguards Activities ......., .. 36
S8 Miscellaneous Security and Safety Issues . . . . . . . . . . . . . . . . . . . . . . 37
S8.1 Vehicle Barrier System (VBS) (Tl 2515/132) . . . . . . . . . . . . . . . 37
S8.2 Vehicle Barrier System (VBS) .........................38
l S8.3 Bom b Blast Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 8
S8A Procedural Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
S8.5 Security Force Strike Contingency Plans . . . . . . . . . . . . . . . . . . 39
F1 Control of Fire Protection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . 40
F1.1 Fire in the 2 'C' Service Air Compressor . . . . . . . . . . . . . . . . . . 40
V. Management Meetings ..........................................41
X1 Exit Meeting Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
X2 Review of Updated Final Safety Analysis Report (UFSAR) Commitments . 41
LIST O F ACRONYMS US ED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 2
IN FPECTION PROCEDURES USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . , . . . . . . . . . . . . . . . . . . . 44
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Report Details
Summarv of Plant Statgg
PECO Energy operated both units safely over the period of this report.
Unit 2 began the period operating at 100% power. On December 29,1997, the unit was
shutdown to perform repairs on the main turbine electro-hydraulic control (EHC) system.
The unit returned to power operations on January 3,1998 and on January 4 was only able
to reach 96% power due to a speed error bias s!gnalin the EHC control system. On
January 6, Unit 2 power was reduced to 90% when condenser vacuum decreased
following a trip of the 2 'C' circulating water pump. The unit returned to 100% power on
January 9 following adjustments to the speed error bias. On January 14, power was
reduced to 97% when condenser vacuum decreased after the 2 'C' circulatirig water pump
failed to start and the pump discharge valve failed open during post-maintenance testing.
Power was increased to 100% on January 16 following evaluation of the 2 'C' circulating
water pump discharge valve failure and monitoring of Unit 2 condenser vacuum.
Unit 3 began the period operating at 93% power. The unit was operating at less than full
power due to recirculation system flow rate limitations because of weld cracks on the jet
pump risers. On November 28,1997, the unit was shutdown to replace the 'E' steam
relief valve. The unit returned to power operations on December 1 and reached 93%
power on December 5 following relief valve replacement. The unit remained at about 94%
power for the remainder of the period, with the exception of load drops on December 7,
10, and 11, to troubleshoot t.ad repair a minor tube leak on the 3 'B' condenser waterbox.
1. Operations
01 Conduct of Operations'
01.1 General Comments (71707)
Ove all, operators responded well to the various load changes and shutdowns on
Units 2 and 3 throughout the period. The inspectors observed good
communications during load change evolutions and very good response to control
board alarms received. Generally, good command and control was observed during
these shutdowns and load adjustments. The inspectors observed very good
reactivity control during rod manipulations for Unit 2 and Unit 3 during shutdowns
and scheduled load swings. However, the inspectors also observed minimal
i supervisory oversight of the reactor operators during a recirculation pump speed
l change on Unit 2. The inspectors observed that the shift supervisor was involved in
several other activities unrelated to Unit 2 during this reactivity evolution.
The inspectors noted several instances during the period where the operators
knowledge of plant systems performance was inadequate and the procedures being
1 Tomcal headings such as 01, M8. etc.. are used in accordance with the Nf4C standardited reactor inspection report outline. Indivktual reporta are not
supected to address all outilne topics.
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used did not provide detailed guidance for the evolution being performed. These
unexpected events involved the start of the motor driven fire pump, trip of the Unit
2 main turbine, and Unit 2 main steam high radiation alarms are discussed in
Sections 03.2,04.1, and 04.2, respectively.
In addition, the inspectors identified that operations personnel failed to monitor the
temperature of the Unit 2 Condensate Storage Tank (CST) after the CST low
temperature alarm annunciated in the control room and was identified as not
working properly. Operations personnelinitially checked the CST tank and verified
that the tank was warm to the touch and that heating to the CST appeared to be
working. However, continued monitoring of this CST was not required after this
initial check. Outside temperature surrounding the CST was below freez;ng for
several nights prior to the inspectors raising this concern.
01.2 Unit 3 Plant Shutdown to Reolace 'E' Safety Relief Valve
a. Insoection Scone (71707)
The inspectors observed portions of the plant shutdown and startup evolutions for
the replacement of the Unit 3 'E' safety relief valve (SRV).
b. Observations and Findinas
N3C Inspection Report 50 277(28)/97-07 discussed station response and
monitoring following the identification of a high temperature on the 'E' SRV tailpipe.
PECO took conservative action to shutdown Unit 3 on November 28,1997 in order
to replace the SRV, based on an increasing temperature trend, inspections of the
removed SRV indicated :het some leakage had occurred at the secondary stage
disc.
The inspectors observed selected portions of the shutdown and stcrtup evolutions
on November 28 and December 1. Operator actions during reactivity manipulations
were deliberate and controlled. Overall, command and control and management
oversight were also very good,
c. Conclusions
PECO management took appropriate, conservative action to shutdown Unit 3 and
replace the 'E' SRV after observing a continuing upward trend in the tailpipe
tempera'ure. Operator performance during the shutdown and startup evolutions
was ver/ good.
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02 Operational Status of Facilities and Equipment
02.1 Shutdown of Unit 2 Due to Problems with the Electro-Hydraulic Control (EHC)
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System Pressure Reaulator Control
a. Insoection Scope (71707 & 37551)
On December 29, Unit 2 was shutdown to replace the secondary pressure amplifier
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card and the potentiometer assemblies on the pressure control unit for the 'B' EHC
regulator. Several other forced outage repairs were made to Unit 2 equipment,
includir.g repairing the externalleakage from the reactor feedwater check valve,
CHK 2 06-28B. This leakage was a main contrhutor to the drywell sump inleakage.
, instrument and control (l&C) technicians also inspected other subsystems of the
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EHC system. Challenges from fillow up actions from this inspection are discussed
in Section M4.1.
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The inspectors observed portions of the plant shutdown and startup and reviewed
- the safety evaluation and the temporary plant alteration (TPA) associated with the
EHC pressure regulator control.
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b. Observations and Findinas
On December 23,1997, plant management chose to shut down Unit 2 due to
problems with the pressure iegulatcr control circuit. On Decembe 15, the back up
EHC pressure regulator 'B' took control of reactor pressure without operator action.
Subsequent troubleshooting activities revealed that the 'B' pressure regulator
secondary pressure amplifier card operated erratically. These troubleshooting
activities also showed noise in the input from the pressure control unit motor-
operated potentiometer assemblies indicating degradation. The licensee issued
Performance Enhancement Program (PEPS) numbers 1000771 and ;0007838 to
analyze this issue and the December 15 reactivity management event.
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On December 20, a TPA was performed per Engineering Change Request (ECR) PB
, 97 03475, Revisions 000 and 001. This TPA adjusted the pressure control unit
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potentiometer so that the primary 'A' pressure regulator controlled pressure and
failed the 'B' normal / failure switch to the failed position. This action removed the
f 'B' pressure regulator from service to prevent inadvertent swapping between
regulators. This TPA was also written to allow replacement of the secondary
pressure amplifier card at power. A plant transient occurred during the shutdown of
Unit 2 because this TPA was instulad The transient is discussed in Section E2.2.
A safety evaluation was written to support continued operation of Unit 2 with only
the 'A' pressore regulator in service. This safety evaluation addressed the issue
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raised by the General Electric Services Information Letter (SIL) No. 614, " Backup
i Pressure Regulator" regarding the potential of being in an unanalyzed condition
when a BWR was operated without a back up pressure regulator. The inspectors
reviewed this safety evaluation and did not identify any safety concerns.
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On December 29, Unit 2 was shutdown to replace the amplifier card and the
potentiometer assemblies. Several other forced outage repairs were made to Unit 2
equipment, including repairing the externalleakage from the reactor feedwater
check valve, CHK 2 06 288. This leakage was a rr' in contributor to the drywell
sump i.eloakage. instrument and control technician:, also inspected other
subsystems of the EHC system. Challenges from follow up actions from this
inspection are discussed in Section M4.1.
The inspectors noted that the decision to replace the pressure regulator, motor-
driven, potentiometer assemblies and secondary pressure amplifier card of f line
instead of at power precluded the possibility of a plant translent due to EHC system
problems during replacement work. Also, the inspectors noted that the shutdown
allowed repair of CHK 2-06 288. The inspectors observed good control room
performance during the plant shutdown and start up.
c. Conclusions
The inspectors concluded that the licensee's decision to remove Unit 2 from service
to perform the EHC pressure regulator work showed conservative operational
decision making. The inspectors also viewed the other repairs performed while the
unit was off line as positive.
02.2 2 'B' Recirculation Pumn Speed Control Problems
a. Insnection Scope (71707)
On January 10,1998, operators observed that the 2 'B' recirculation pump speed
and Unit 2 reactor power increased slightly w;thout operator action. The inspectors
reviewed operations and engineering staff response to speed control problems with
the 2 'B' recirculation pump.
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b. Qbfsrs ations and Findinas
Operatort c.ntered off-normal procedures and initiated a PEP report due to the
unexpected reactivity addition when the recirculation pump speed increased.
Operators had seen smaller magnitude speed changes on the 2 'B' recirculation
pump earlier this year. Monitoring equipment had been installed on the pump motor
i generator sets to allow for engineering review of this phenomenon. The previous
I occurrences had been documented on an action request (AR).
l Engineering attributed the speed increase to excessive play in the motor generator
set speed controllinkage. This condition led to unexpected speed changes in the
dW aon of the last change. This condition occurred several hours after a
.culation pump speed was adjusted,
ant management and operators were aware of the issue, however, some operators
acre not fully knowledgeable or sensitive to the delayed nature of this reactivity
addition phenomenon. The inspectors noted that:
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- This was an operationally significant issue, however, operators were not
4 tracking this on the equipment deficiency list (for operationally significant
items) in the control room.
- Engineering and operat:ons did not include this on the material condition
focus list to ensure management attention on resolution of the issue.
- Some operators recognized this as a workaround, however, this issus was
not identified as an operator workaround (OWA) during a recent initiative to
document all m;nor OWAs.
As interim corrective action for this condition, engineering initiated a temporary
change to plant procedures to direct operators to turn the controller knob slightly in
the opposite direction af ter making a speed change. This was intended to reduce
the potential for the linkage clearanco/ play to cause speed drifting. Engineering e
recognized that this was a workaround and was considering options for further
repairs or replacement of linkage components. At the end of the inspection period,
operations management was still reviewing this issue for possible corrective
actions.
The inspectors found that operators responded appropriately after recognizing the
minor reactivity addition. While this condition did not lead to a significant reactivity
occurrence, it did reveal a continued lack of formality in tracking degraded
conditions of low to moderate significance.
The inspectors slso noted that although the speed drift problem was first
documented in April 1997 and had occurred at least three additional times, neither
operations or engineer!ng management had aggressively pursued the resolution of
this reactivity management issue. This was evidenced by the lack of inclusion in
the material condition focus list and the fact that it was not fullv * nsidered for
corrective maintenance or troubleshooting during the Unit 2 forceo outage in
December 1997.
c. Conclusions
Operators responded appropriately to an unexpected speed increase on the 2 'B'
recirculation pump and resultant increase in reactor power. However, this event
revealed continued weaknesses in operations tracking and understanding of some
degraded conditions as noted in Section M3.1 of this report and Inspection Report
50 277(278) 97-07. Additionally, operations and engineering management had not
pursued resolution or troubleshooting efforts consistent with similar reactivity
management or potential transient initiator issues.
- ., .- - _._ .__ _
_ _ _ _ _
_ _ . _ _ _ _ . . - _ _ _ _ - -_ _-.- - - - --
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02.3 .Q.pid Weather Preparations
a. Insoection Scoce (71714)
The inspectors reviewed station preparations for cold weather. The following
routine test procedures were reviewed: RT O 040 620 2, Revision 4, " Outbuilding
HVAC and Outer Screen inspection for Winter Operation," and RT 0 040 630 2,
Revision 4, " Winterizing Procedure."
.
b. Observations and Findinas
The licensee performed the cold weather preparation's routine test procedures in
early October. The tasks covered by the procedures included such items as placing
steam heating systems in service, energizing electric heaters, and shutting air
supply louvers.
During the review of '.he completed procedures, the inspectors identified some
discrepancies:
- Operators made a number of changes to the procedures in an informal
manner. For example, operators noted that several thermostats could not be
set to the temperature specified in the procedure, but they did not initiate a
temporary procedure change, contrary to instructions on temporary
procedure changes. Instead, operators initiated procedure enhancement
forms after completing the routine tests.
No corrective actions were taken for a few deficiencies. For example, some
switchgear building air filters were found to be dirty and were marked as
unsatisfactory, but no action request (AR) was generated to correct this
condition. Other examples involved heaters that did not energize, but the
reasons and/or corrective actions were not fully documented.
The inspectors walked down selected ereas of the site and verified that the
procedures were substantially completed. However, during this spot check, the
inspectors observed the followlag discrepancies:
- Some river outer screen structure heaters (3) were not energized.
Maintenance was performed on one of the heaters, but it wt.s not restored to
the energized position, as specified by the winterizing procedure.
- Three outer screen structure doors were not fully closed.
- Some outer screen structure door gaskets were damaged or missing.
- Emergency service water booster pump /Cardox building cubicle louvers were
open, allowing cold air to be blown directly into the building.
The inspectors discussed these findings with members of the operations staff.
Procedure changes were initiated and operators were directed to re-perform portions
of the routine test procedure. Operations management acknowledged that the
4
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T -g-w+,' ' ?-*--PTT e*'*P--F -*'r- ---'me - "
__ _ _ _ . _ .__ _ _ _ _ _ _ _ - _ _ . _ _ _ - _ _ _ _-
_ ___ _ _ _ _ _ _ - .
.
.
7
completion of those procedures did not meet department expectations for formality
and attention to detail.
The failure of operations personnel to adhere to the routine test procedures for cold
weather preparations was a violation of technical specification (TS) 5.4.1.
Technical specification 5.4.1 requires, in part, that written procedures are
implemented covering the applicable procedures recommended in Regulatory Guide
1.33, Appendix A, November 1972. (VIO 50 277(278)/97 08 01)
c. Conclusions
Station preparations for cold weather were performed adequately. However, the
inspectors identified a number of discrepancies associated with the documentation
and performance of the winterizing routine test procedures that reflected lapses in
formality and attention to detail. Concerns with procedural non adherence were
identified in Inspection Report 50 277(278) 97 07. This issue represented a f ailure
of operations personnel to ensure procedural compliance during procedure
performance.
02.4 Circulatina Water System Problems (Unit 2)
a. Insooetion Scone (71707)
The inspectors reviewed two instances of circulating water (CW) system problems
that led to operational transients (OTs),
b. Observations and Findinas
On two occasions during this inspection period, CW system problems caused
operators to enter OT procedures. On January 6,1998, the 2 'C' CW pump tripped
unexpectedly, and an initial attempt to start the standby 2 'B' CW pump failed.
The second event occurred on January 14, during a retest, following corrective
maintenance for the first issue, in this instance, the 2 'C' CW pump did not start
due to a failure of the associated discharge valve motor operator, which had
recently been repaired. The discharge valve operator motor cracked and broke
away from the valve operator during the second event preventing the valve from
being closed locally or remotely. This condition caused the 2 'C' pump to rotate in
the reverse direction due to CW flow recirculating through this loop.
During both events, operators observed lowering condenser vacuum, entered
appropriate off normal procedures, and reduced reactor power until condenser
vacuum stabilized,
Maintenance and engineering personnelinitiated investigations to determine the
causes of these events. The evaluation for the second event was to include a full
root cause analysis. Both investigations were stillin progress at the completion of
this inspection period,
,. - . _ . ,. ___
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8
The inspectors found that operator performance during both transients was
satiafactory. The inspectors will assess the results of PECO's investigations for j
these maintenance performance issues during future inspection activities.
c. Conclusion.1
Operator performance during two plant transients caused by CW system problems
was satisfactory PECO's investigations into both events were it progress at the
end of this inspection period.
The inspectors were concerned with these two non safety system equipment
failures which caused plant transients especially the second event that was caused
by the significant failure of the 2 'C' CW pump discharge valvo. The inspectors will
review the results of these CW system investigations for maintenance performance
issues. (IFl 50 277/97 08-02)
03 Operations Procedures and Documentation
03.1 Missed Technical Soecification (TS) Surveillance Reauirement (SR) Test for
Verification of Procer Flow in the Recirculation Looos
a. Insocction Scone (71707)
On January 2,1998, the Unit 2 reactor operator failed to perform the TS
surveillance requirements (SRs) for verification of proper flow in the recirculation
loops. The inspectors reviewed the documentation associated with these missed
SRs to determine compliance with TS requirements,
b. Observations and Findinag
On January 3, operations personnel discovered that they had missed performing
sections of the formal surveillance test that verified that TS SRs 3.4.1.1 and
3.4.1.2 were met. This test, Surveillance Test (ST)-0-02F 560 2, Revision 0, " Daily
Jet Pump Operability," verified that the recirculation loops were operating within TS
requirements and that the recirculation system jet pumps were operable. This ST
verified that the jet pumps were operable by meeting TS SR 3,4.2.1. Unit 2 was in
Mode 2, "Startup," at the tirne the surveillances were missed with the reactor
heating up and pressurized to 450 psig per the instructions in General Plant
Procedure (GP) 2, Revision 85, " Normal Plant Startup." A surveillance test, ST-0-
02F-560 2 was satisfactorily performed on January 3 after the missed SRs were
discovered.
Technical specification SR 3.4.1.1 verified that recirculation loop jet pump mismatch
was within specifications and TS SR 3.4.1.2 verified that core flow as a function of
THERMAL POWER was also within specifications. Both of these SRs were required
_. _ -
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.
.
9
to be performed in Modes 1 and 2 once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Technical specification SR 3.4.2.1 vorified that there was no degradation in jet pump performance; however,
this was only required to be performed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after greater than 25% reactor
thermal power was reached. This required the reactor to be in Mode 1, * Power
Operation."
The Unit 2 reactor operator determined, based on the wording in ST 0 02F 560-2,
that TS surveillances 3.4.1.1 and 3.4.1.2 were also not required to be performed
until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after greater than 25% reactor thermal power. The operator
discussed the ST requirements with the control room supervisor and the supervisor
agreed after reviewing the ST that the operators' interpretation of the ST was
correct. The operator marked the sections of the ST which performed TS SRs 3.4.1.1 and 3.4.1.2 as not applicable.
This event was documented in PEP 10007762. The " Regulatory Review" section of
this PEP noted that the licensee determined that TS SRs 3.4.1.1 and 3.4.1.2 were
satisfied on January 2 using alternate methods other than the ST 0-02F 560 2.
These methods included verifying that SR 3.4.1.2 was satisfied through the data in
the operator's daily surveillance log and SR 3.4.1.1 was satisfied by the reactor
operator's panel walkdowns and routine operator checks. In additio'1, parameters
on computer printouts showed that recirculation loop jet pump rnismatch was within
specifications of SR 3.4.1.1. Based on these alternate methods, the licensee
concluded that this issue was not reportable.
The inspectors noted during the review of ST 0-02F-560 2that the ST was unclear
and contained conflicting information regarding when each of the TS SRs were
required. The inspectors also determined based on the review of the PEP and all
other pertinent information that the recirculation loops were not operated outside of
the TS SR requirements. However, the inspectors did not understand how the
licensee determined that TS SRs 3.4.1.1 and 3.4.1.2 and the requirements of ST 0-
02F 560 2 woro met since these surveillances were not performed per the ST. The
inspectors were concerned with failure of operations personnel to fully understand
the requirements of the TSs for the recirculation loops surveillances and to review
the TSs when unclear information was found in the ST.
c. Conclusions
The inspectors concluded that the recirculation loops were not operated outside of
the TS SR 3.4.1.1 and 3.4.1.2 requirements when the unit 2 reactor operator failed
to perform ST-0-02F 560-2on January 2. However, the inspectors were concerned
that operations personnel failed to fully understand when these SRs were required
per the TSs. The inspectors were also concerned that the operations personnel
f ailed to review the TSs when unclear and conflicting information was found in the
ST. This issue will be tracked as an Unresolved item (URI) pending additional
l
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10
discussion with the licensee and final determination if the formal TS and ST
requirements were mot. This willinclude a review of past practicos for complying
with those surveillance requirements during startups and shutdowns and the
methods used to determine that the requirements were met for this event and the
reportability of this event. (URI 50 277/97 08 03)
O3.2 1)nexpected Start of the Motor Driven Fire Pumo Durina Clearance Removal for the
Diesel Driven Fire Pumo
a. Insocction Scone (71707)
The inspectora reviewed the clearance documentation and discussed the
unexpected start of the motor driven fire pump during diesel fire pump clearance
removal with operations personnel,
b. Observations and Findinqn
On December 8,1997, the motor driven fire pump auto started while valving in the
diesel driven fire pump during clearance removal for Clearance No. 97003830. The
clearance permitted various preventive maintenance tasks on the diesel engine and
associated valves and instrumentation to be performed.
The inspectors were monitoring control room operations during the clearance
removal. While aligning the diesel fire pump, the fire protection water supply
system momentarily fell below the low pressure automatic start setpoint for the
motor driven fire pump and the pump automatically started. The inspectors
questioned operations personnel about whether the start of the fire pump was
expected and whether the clearance had any cautions regarding the possible
starting of this pump during clearance removal. The inspectors learned that the
start of this pump was not expected and that the clearance had no cautions
regarding this issue. Subsequently, the motor driven fire pump was secured and the
clearance was changed to note this potential condition.
The inspectors were concerned that operations personnel did not fully understand
the fire protection water supply system performance and no cautions were
contained in the clearance to alert operators to the potential start of the motor
driven pump if system pressure dropped during valve re alignments,
c. Conclusions
The inspectors were concerned that the clearance for returning the diesel driven fire
pump back to service did not caution operations personnel that the motor driven fire
pump could start during valve realignments due to a sudden drop in system
pressure. Also, the operators were not fully aware that this potential unexpected
system condition existed.
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11
04 Operator Knowledge and Performance
2
04.1 Unexoocted Trio of Unit 2 Main Turbine Durina start uo
a. Insoection Scoos (71707)
During the Unit 2 reactor startup on January 1,1998, the main turbine tripped
automatically after it was inadvertently rolled to a speed of 1400 rpm. The
inspectors reviewed the circumstances leading up to this event, PEP 10007760 and
associated procedures from this event, and also discussed this event with
operations personnel and plant management.
>
,
b. Observations and Findinas
On December 31,1997, to support EHC testing by instrument and control (l&C)
personnel, the Unit 2 reactor operator (RO) reset the mechanical trip valve in the
main turbine overspeed trip system and selected 1800 rpm on the speed set, at the
main turbine (EHC) control panel. The RO also adjusted pressure set to 930 psig
>
during this testing. The l&C test procedure did not provide direction to restore the
1
EHC system configuration to the condition set prior to the testing. Therefore, the
main turbine, the pressure set setting, and speed select pushbutton were not
restored to the originalline up established by GP 2, Revision 85, " Normal Plant
Start-up" prior to the l&C testing.
On the morning of January 1, during the main control panel walkdown portion of
shif t turnover, the on coming shift manager noted that pressure set was at 930 psig
<
and directed the RO to readjust the setting to 150 psig (minimum setting). The
other two components configuration, however, remained misaligned. Unit 2 reactor
was made critical at 5:46 p.m. During the reactor coolant system (RCS) heat up,
when RCS pressure reached 50 psig, the RO was directed by GP 2 to reset the
main turbine as per Station Operating procedure (SO) IB.1.A 2, Revision 22, " Main
Turbine Startup and Normal Operation." The RO verified that the main turbine was
reset, but did not refer to all of the Instructions in SO 18.1.A 2, which contained
Instructions to verify that the speed set "ALL VALVES CLOSED" was selected.
At 6:25 p.m. during shif t turnover, with RCS pressure at 157 psig, the main turbine
control valves opened causing the main turbine to roll off the turning gear
- unbeknownst to the off going and on-coming operations personnel. The on-coming
'
RO noted that the turbine was not on the turning gear at about 6:35 p.m. when he
cracked opened the 'C' reactor feedwater pump discharge valve to restore a low
reactor vessel level condition. Subsequently, the control room supervisor (CRS)
directed the RO to commence rod pulls to raise RCS pressure to open the turbine
bypass valves. The CRS wanted to raise RCS pressure so that plant conditions
would steady out and prevent possible reactor vessellevel swings due to turbine
bypass valve cycling. No changes in the positions of any of the bypass valves were
observed as RCS pressure increased. Just prior to the main turbine trip, the main
turbine lube oil high temperature alarm and hydrogen seal oil / stator water cooling
trouble alarm were received in the control room.
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12
' Af ter the turbine tripped, operations personnel verified that the turbine tripped and
placed the turbine on the turning gear. The licensee evaluated any concerns with
- rolling the main turbine without pre warming. The licensee determined after
discussions with the turbine vendor, General Electric, that the turbine did not
experience any distress as a result of this event and was acceptable for long term
operation. The licensee documented this event in PEP 10007760.
'
Several key points in this event concerned the inspectors, ine.luding:
- the l&C test procedure did not contain any configuration controls to restore
the EHC system to the initial conditions found prior to testing.
,
- the control room staff did not restore the main turbine, the pressure set
'
setting, and speed select pushbutton to the originalline up established by
GP 2, Revision 85, " Normal Plant Start up" following the l&C testing.
'
- Inadequate control panel walkdowns occurred over several shifts.
I
Specifically, the main turbine, the pressure set setting, and speed select
pushbutton remained min aligned until the on-coming day shift shift manager
-
noted that pressure set was indicating 930 psig on January 1, and the
i turbine and speed select became self disclosing during the reactor startup.
'
- The RO did not adhere to procedure SO 18.1.A 2, " Main Turbine Startup and
Normal Operation" when resetting the main turbine. Specifically, the RO did
not verify that "ALL VALVES CLOSED" was selected on the turbine control
panel. -
- After the RO reported that the turbine was not on the turning gear, he did
not monitor his indications to verify the condition of the turbine. The turbine
speed was rotating for more than two hours. During this time, none of the
operations personnel assigned to Unit 2 observed any of the indications that
i the turbine was rotating and gaining speed other than coming off of the
turning gear.
open the turbine bypass valves even though he did not understand why the
turbine was off of the turning gear and no change in bypass valve position
was observed.
- The turbine trip became self evident to the operations staff after the main
- turbine lube oil high ternperature alarm and hydrogen seal oil / stator water
cooling trouble alarm annunciated in the control room.
.,
The PEP stated that the ROs believed that a dedicated supervisor should
'
have been assigned to oversee the Unit 2 startup evolution. Also, one of the
reactor operators thought that the work load was excessive during the
startup. Neither of these concerns was expressed by the operators during
this evolution.
4
,n- ,r - ew,- < - --,w, ,- .w, , g --- - ,, , a -, - - -- . .- n-- -- - - . - - ---r,-w w -.
_ _ _ _ __ _ _ __ _- _ ___ _
.
.
13
c. Conclusions
Based on the initial review of this event, the inspectors were concerned with the
failure of operations staff to fully understand and recognize the main turbine status
and the position of the turbine control valves and the speed select portion of the
EHC system. Further, the inspectors were concerned with the pulling of control
rods to increase RCS pressure while the turb!ne condition remained unknown. The
inspectors were also concerned with potential deficiencies and lack of coordination
between the operations startup and l&C testing procedures and with the rigor of
procedure implementation by the operators.
This issue appeared to be a violation of TS 5.4.1, " Procedures" due to the concerns
identified above. However, the inspectors needed to conduct additional reviews of
the procedures used during this event, review of strip charts and recorded data from
this e.ent, and further discussions with reactor engineering and operations
personnel. This issue will be tracked as an unresolved item (URI) pending further
review. (URI 50 277/97-08 04)
04.2 Qoit 2 Main Steam Line Hiah Radiation Alarms Durina Power Ascension
a. latpection Scone (71707 & 37551)
The inspector reviewed the actions of control room personnel for the two main
steam high radiation alarms that came in during power ascension following the trip
of the 2 'C' circulating water pump and 2 'A' reactor feedwater pump turbine trip
testing.
b. Observations and Findinag
On January 7,1998, operators entered Operational Transient (OT) procedure, OT-
103, Revision 6, " Main Steam Line High Hadiation" on two occasions. The highest
main steam line radiation monitoring reading was 1670 mr/hr. The main steam line
high radiation alarm setpoint was 1625 mr/hr Reactor power level at this time was
approximately 72% The main steam line radiation level at this power was normally
around 1000 mr/hr. General area radiation levels remained unchanged during this
transient. The 2 'A' reactor feedwater pump was not in operation when these
transients occurred.
'
Operators reduced power in accordance with OT 103. Af ter further investigation,
operations and engineering personnel determined that the hydrogen addition rates
may have been higher than expected for the feedwater flow rates. After discussing
this issue with the hydrogen addition system manager, operators manually reduced
the hydrogen addition rate to lower the main steam line radiation level to 850 mr/hr
or the normal background level for this reactor power value. Operations personnel
initiated PEP number 10007782 for this issue,
l
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.
14
For many years, the hydrogen addition system was not in service. During the past
two years, the system was placed back in service to reduce the effects of
intergranular stress corrosion cracking on core components and the recirculation
piping.
The inspectors reviewed OT 103 and Station Operating procedure (SO) 15.1.A 2,
Revision 0, " Hydrogen Water Chemistry System Startup and Normal Operation."
Procedure SO 15.1.A 2 contained a note that the main steam line radiation levels
would increase as a result of hydrogen injection. This procedure was used by the
operators during the reduction of the hydrogen addition rate. The inspectort also
discussed this issue with operations personnel.
The inspectors noted that operations personnel were not fully f amiliar with the
interactions of the hydrogen addition rate on main steam line radiation levels during
abnormal reactor feedwater system alignment plant startups. Also, the inspectors
noted that OT 103 did not contain any instructions in the procedure to reduce
hydrogen addition levels when the high main steam line radiation alarm was
received.
c. Conclusions
The inspectors were concerned with the completeness of the operators knowledge
of the effects of the hydrogen addition system on main steam line radiation during
startups and during abnormal reactor feedwater alignments. The inspectors were
also concerned that OT-103 did not contain instructions to lower the hydrogen
addition rate if the main steam line high radiation alarm was received. The fact that
the system was placed back in service during the past two years after several years
of being out-of service contributed to these concerns.
04.3 Standbv Llauld Control Pumo Clearance Restoration
a. Insoection Scope (71707 & 61726)
The inspectors reviewed the post maintenance testing and clearance restoration
performed by operations personnel on the 3 'B' standby liquid control (SBLC) pump,
b. Observations and Findinas
The inspectors noted during document review that post maintenance testing was
accomplished by performing a portion of a quarterly surveillance test. The operators
observed no adverse conditions during the test.
While verifying the clearance restoration, the inspectors found that one valve was
not fully returned to its required status. Specifically, the inspectors observed that
the 3 'B' SBLC pump discharge valve, HV 11 13B-3, was open but the lock was not
completely engaged. The required position per the clearance restoration sheet was
" locked open."
!
_j
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1
I
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15
,
The inspectors brought this deficiency to the attention of operations staff.
Operations personnel promptly locked the valve and initiated a verification of other
locked valves in the plant. Operators found one additional valve improperly locked
on the Unit 2 automatic depressurization system (ADS) backup nitrogen system. In
this instance, the lock was engaged, but the chain did not restrain movement of UA
valve handwheel. Tampering was not suspected in either instance since the valves
were in their proper positions.
The inspectors noted that the SBLC pump clearance restoration form required
independent verification of the valve positions, and the verifications were
documented as completed. Operations staff interviewed the operator who did the
independent verifications and found that he stated that he had performed the
expected actions to verify the position of valve. However,it was evident that both
the individual who positioned the valve and the independent verifier did not carefully
check that the lock was fully latched.
The inspectors determined that PECO took appropriate conective actions for this
issue. Upon discovering a second improperly locked valve, operations management
directed that full verifications of all accessible locked valves in the plant be
accomplished. No additional problems were discovered during this review.
Management communicated this issue to all operators and other site personnel who
'
have cognizance over locked components. The discrepancies had minimal safety
'
impact and did not affect system operability since the valves were in their correct
position.
The f ailure of operations personnel to fully adhere to the Instructions in clearance
- number 97003684 during restoration for the 3 'B' SBLC pump was a violation of TS 5.4.1. Technical specification 5.4.1 requires, in part, that written procedures are
implemented covering the applicable procedures recommended in Regulatory Guide
1.33, Appendix A, November 1972. However, this NRC identified vlotation was of
minor safety significanco and is being treated as a Non-Cited Violation (NCV),
'
consistent with Section IV of the NRC Enforcement Policy (NCV 50 277(278)/97-
08 05),
c. Concl4flRD1
The inspectors found a standby liquid control pump discharge valve in the correct
position, but not locked, as specified by the clearance restoration form. Although
of minimal safety significance, this and a second improperly locked valve discovered
by the licensee indicated that operators were not always rigorous in independently
verifying the condition of locked valves. Corrective actions for this issue were good
,
and included verification of all locked valves in both units.
J
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i
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_ . _ _ . _ . ...__..___ __ _ ._ _._ _ _ _ _ _ _ .. _ . _ _ _ _ __. _ -_ _ _ _
.
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16
<
4
07 Quality Assurance in Operations
j 07.1 Plant Ooerations Review Committee (PORC) Meetina
l
The inspectors observed two PORC meetings during the inspection period. The PEP
evaluation root cause for the September 1997,3 'B' Circulating Water Pump fire
was discussed at the first meeting. The problems and corrective actions associated
with the reactor feedwater pump high level f ailure to trip and the EHC transient
observed during the late December 1997 Unit 2 shutdown was discussed at the
second meeting. The inspectors noted good questioning attitude by Scensee
!
managemerit during these PORC meetings. Questions asked by the managers to
personnel presenting these issues were thorough ana reflected in depth safety focus
.
Into issues discussed.
.
11. Maintenance and Surveillance
M1 Conduct of Maintenance and Surveillance
M 1.1 Standbv Llauld Control Pumo Maintenance
a, lesp_qtetion Scone (62707)
The inspectors observed corrective maintenance performed on the 3 'B' standby
liquid control (SBLC) pump. Post maintenance testing and clearance restoration for
i this job was discussed in Section 04.3.
,
b. Observations and Findinas
The inspectors observed work performed per corrective maintenance work order
number C0177825 on the 3 'B' SBLC pump. Technicians investigated a minor oil
leak on a pump motor bearing and repacked the pump seals after discovering
Indications of slight leakage past the seals.
Technicians followed the requirements of the work order and maintenar.:e
procedures. After consulting with their supervisor, they determined that the bearing
oil leak was negligible, and no further work was required. The technicians were
i knowledgeable, and the supervisor provided oversight as needed. The inspectors
noted that the technicians documented their work on the work order.
'
c. Conclusions
l The inspectors observed that maintenance technicians working on the 3 'B' standby
liquid control pump were knowledgeable, well supervised, and followed the
'
maintenance procedures.
l
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17
.
l M1.2 Unit 3 Primarv Containment Local Leakaae Rate Testina (LLRT) Review (61726)
The inspector reviewed SE CM 01, " Primary Containment Leakage Rate Testing
- implementation Plan, Rev. 0" and ST/LLRT 20.00.01, Revision 0, " Local Leak Rate
Tests (LLRTs) Documentation and Tracking," to evaluate the results of the LLRTs
performed during the Unit 3 outage. These procedures also implemented the
performance based testing schedule provisions of the recently published Option B of
, 10 CFR 50, Appendix J. This review found that the overall maximum pathway
integrated local leak rate was approximately 0.426 La (i.e., the maximum allowable
leakage rate at the calculated peak contalament internal pressure during a design
- basis accident) versus the acceptance criteria of 0.6 La. Discussions with the LLRT
'
coordinator and a review of LLRT scheduling infermation indicated that only 40* of
all Tyre B & C tests had their testing interval extended under the Option B
provisions such that they did not require testing during the Unit 3 outage as
originally scheduled. Overall, the LLRT program appeared consistent with the
provisions of Option B, was well controlled and indicated good preventive
maintenance of containment isolmico valves as indicated by the successful overall
test results.
j M1.3 Motor Ooerated Valve Thermal Limit Bvoass Operabilltv
i
a. Inspection Scone (61726 & 62707)
The inspectors observed testing of several motor operated valve (MOV) thermal
bypasses. The licensee performed this testing at Peach Bottom after a reactor core
isolation cooling (RCIC) inboard steam valve was discovered with the wiring to the
thermal overload bypass contact lifted at the Limerick Generating Station.
b. Observations and Findinas
Normally, the control circuits on MOVs for automatically onerated isolation valves
are arranged so that motor thermal ocerload protection is provided. During certain
accident conditions, this protection is bypassed to prevent automatically initiated
valve operation from being interrupted by the motor thermal overload. This thermal
overload bypass is provided to allow the valve to reach the required position during
.
an accident.
!
, When the RCIC MOV deficiency was found at Limerick, the licensee discovered that
l their testing method checked both the thermal overload "sealin" leg and the
thermal bypass at the same time without separating out the individual contacts.
l Therefore, the condition of the RCIC thermal bypass contact went undetected since
- - the contact was not being tested separately. There is no requirement for this type
l of testing at Peach Bottom, however, engineering personnel conservatively
determined that a verification test of the MOVs would be prudent.
J
The licensee successfully tested the thermal overload bypass function on 22 MOV
isolation valves at Peach Bottom. No deficiencies were identified with the thermal
i
overload bypass circuitry for these valves. This population of MOVs represented a
1
_ ___._.m. ._ _ _ . - - _, . . __ .-. _ , .
___ - - _ _
e
.
18
sampling of approximately 10% of all valves with thermal overloads at the station.
Engineering personnel determined that this was a sufficient population to obtain
confidence that the rest of the thermal overloads for MOVs were installed correctly.
1he licensee planned to incorporate thermal overload bypass testing during the next
normally scheduled test for MOVs.
The inspectors observed testing of the thermal overload bypass function on selected
MOVs. The bypasses functioned properly and maintenance personnel accomplished
the testing in accordance with approved procedures. The maintenance personnel
maintained effective and precise communications between the control room and
work stations.
c. Conclusions
The inspectors concluded that testing of the thermal overload bypass function on
selected MOVs was proactive and showed conservative decision making. The
testing observed provided a good functional test of the bypass contact. The
inspectors also concluded that technicians displayed good adherence to procedures
during testing.
M2 Maintenance and Material Condition of Facilities and Equipment
M2.1 Standbv Liould Control Pumo Crankcase Oil Viscosity
a. lasoection Scoco (62701)
Tha inspectors reviewed the discovery of a higher than expected oil viscosity in the
3 'A' SBLC pump.
b. Observations and Findinas
On December 11,1997, technicians found that the viscosity of the oilin the 3 'A'
SBLC pump crankcase was significantly higher than expected. The oil sample result
indicated the viscosity value was 160 centistoke (cst), while the expected value
was 68 cst. Operations re sampled the oil to confirm the result. Since the high
viscosity value made the operability of the pump questionable, operators declared
the pump inoperable and entered the appropriate TS action statement. Technicians
drained and flushed the crankcase and then refilled it with the correct oil specified
by the lubrication program and the pump overhaul procedure.
Af ter further review, predictive maintenance technicians found that the oil viscosity
had been high since April 1996. To address the generic implications of this issue,
management directed that other SBLC pumps be sampled and that oil viscosity
values of all plant rotating equipment be reviewed for abnormal values. No
problems were identified for other safety related components.
PECO also found that predictive maintenance technicians had previously evaluated
the 3 'A' SBLC pump high oil viscosity and had received correspondence from the
_ . - _ _ . . _ . _ _ _ _ _ . _ _ _ _ _ _ _ _ . _ - _ _ _ _ _ . _
,
'
<
f
19 i
pump vendor tnat indicated that pump operation would not be adversely affected by
the high viscosity oil. However, the technicians did not formally document this
information at that time. After the December finding and subsequent review of
data, engineering concluded that the pump remained operable with the high
viscosity oil.
J
!
The Inspectors determined that operations took appropriate, conservative immedlete
actions to declare the SBLC pump inoperable. The inspectors also reviewed the
interim and planned long term corrective actions for this issue and identified no
concerns. Predictive maintenance personnelInitiated improvements to their review
4
and documentation processes,
c. Conclusions
, Operations took conservative action when they declared the 3 'A' standby liquid
control pump inoperable following the discovery of higher than expected viscosity
i oilin the pump crankcase. Investigation by PECO revealed that this condition had
been previously evaluated by predictive maintenance personnel, but had not been
formally documented, initial corrective actions to replace the oil, evaluate pump
operability, and rovlew viscosity records on other plant components were
'
satisfactory.
M2.2 Forelan Materialin 2 'C' Residual Heat Removal System Heat Exchanaer
- a. insoection Scone (62707 & 37551)
The inspectors reviewed PECO maintenance technielans' discovery of foreign
materialin the 2 'C' residual heat removal (RHR) system heat exchanger,
b. Observations and FindlDER
On January 5,1998, during maintenance on the 2 'C' RHR heat exchanger, :
technicians found broken glass, an electrical extension cord, and metal straps on
'
the RHR (shell) side of the heat exchanger. Technicians removed the glass but were
unable to remove the cord and metal straps.
After further investigation, PECO determined that the forelgn material had been
previously identified in the heat exchanger in 1994. At that time, engineering '
evaluated the material through a non conformance report (NCR) and dispositioned it
as "use as is." This NCR provided an evaluation which allowed the foreign rnaterial
to remain in the heat exchanger for an indefinite period of time. However,
maintenance did not initiate any action to track this condition and plan for the
removal of this material during subsequent maintenance periods. The inspectors
learned during discussions with PECO management that they recognized this as a
missed opportunity.
The inspectors noted that maintenance has now taken steps to track foreign
material conditions and similar interim "use as is" dispositions. Maintenance
4
, . ,n.n.-.-_.n,. ---w.- ...,, . --
y.,,._,, , __ . , -,, , - - . , - -
- - ,.,
- , , , , . , , - , - - - . , , ,w, ,.
-w .,,, , , - ,,--_ . , , . . , -,- - , . _ , , .
.-_ __. . . ____ _ _ . ._ _ _ ___ _ . _ . _ _ _ _ __ ___ _.__
.
.
20
determined that this will allow maintenance planning to include activities to attempt
to remove foreign material, as appropriate, during normally scheduled work.
The inspectors also reviewed the NCR generated as result of this issue. The
inspectors discussed the report with engineering staff and found that the evaluation
considered both normal and post design basis accident operation of the RHR heat
exchanger. Engineering concluded that the function of the heat exchanger was not
adversely affected, and that deterioration or movement of the material was highly
unlikely.
c. Conclusions
The inspectors had no concerns with operation of the RHR heat exchanger during
normal and post design basis accident conditions with the foreign material still
present based on the NCR review. This material, which included metal straps and .
'
an extension cord, was first identified in 1994 and had not been tracked for removal
during subsequent maintenance periods.
However, the inspectors concluded that PECO missed an opportunity to plan for the
removal of foreign materialin the 2 'C' RHR heat exchanger during the regularly
aheduled maintenance work, Thus, technicians did not expect to find this foreign
material during maintenance activities in January 1998.
M3 Maintenance Procedures and Documentation
M3.1 Eauioment Condition Notification to Ooerations
a. Insoection Scope (62707)
The inspectors reviewed the process for notifying operations personnel of corrective
maintenance problems and degraded equipment conditions. The inspectors referred
to AG CG-026.2, Revision 4, " Corrective Maintenance Action Request Initiation and
Processing."
b. Observations and Findinas
NRC Inspection Report 50 277(278)/97 07 uiscussed an instance of poor equipment
status control, in which a standby safety related station battery charger had been in
a degraded, inoperable condition for several months, but was not being tracked by
operations personnel. After further review by operations staff, they concluded that
1 they were not notified of the further degradation of this equipment in a timely
manner.
During this inspection period, both PECO and the NRC identified similar examples in
which operations were not fully informed of degraded conditions on safety related
equipment. Examples included the following:
.
,
w- pr- w *<--rv -%y--y m. .y7-- we w---wy;-+--swp-e-- - - , - - ->----------vw. , -4e.- g-W-w+ yea--.e* - - - -- e m.-s-
__ _._. _ _ _._ _____ _ _ ._..__ _ _._ _ _ _._ - _
. ,
.
'
21
- Maintenance noted a degraded condition on an RHR system motor operated
'
valve breaker, and the maintenance supervisor considered the component
operable. The AR for the problem was not routed to operations in a timely
,
manner for an operability determination. When operators reviewed the
condition, they declared the valve Inoperable. Operations raised concerns
about the untimely routing for the operability determination. Shortly af ter the
valve was declared inoperable; maintenance corrected the breaker problem
and the valve was made operable.
- The inspectors noted that ARs for packing leakage on safety related
instrument root valves were not toisted to operations for operability
determinations
valve was not routed to operations for an operability determination.
The inspectors discussed these findings with operations and maintenance staff.
Following the discussion, operations initiated a PEP report to review the issue and
developed corrective actions to communicati these issues to appropriate plant
supervision,
c. Conclusions
The station and the NRC identified instances where operations staff were not
informed of degraded conditions on safety related equipment in a timely manner.
The inspectors were concerned that the failure to inform operations of these
degraded conditions could result in operations personnel being aware of potentially
inoperable equipment. Some items identified during this inspection were of minor
significance; however, one issue involved an RHR valve that was declared
inoperable by operations after they became aware of the degraded condition on this
valve.
M4 Maintenance Staff Knowledge and Performance
M4.1 Unit 2 EHC Soeed Error Sianal Blas Due to Repair of Soeed Control Card Short
'
a. inspection Scope (62707 & 37551)
On January 4,1998, main steam line bypass valve, BPV 1, unexpectedly opened
approximeply 25% several times while the Unit 2 reactor operator was raising
reactor pcwer using control rods. Unit 2 was at appro@nately 96% power and
reactor pressure was stable at 1028 psig when this occurred. - The inspectors >
reviewed this issue and the licensee corrective actions that allowed Unit 2 to reach
100% power.
L
_ . . _ . . - - , _ . . _ _ . . _ _ _ . _ . _ _ _ _ _ _ . _ _ . _ _ _ - _ _ _ . - . - _ . - . _ . _ _ _ - .
_ _ _ _ _ . _ -. ___ _ _ _ _ _
__.__.______.___m. _ _ _ .
O
i i
22
b. Qbservations and Findinas
During replacement activities for the EHC pressure control unit, the l&C technichns
discovered a short circuit on a card in the speed control vection of the LHC system.
This short was due to a looso connection on the card. The instrument and bontrol
technicians tightened the connectinn and reinstalled the card.
During subsequent troubleshooting of this issue, l&C personnel discovered 0.5 volts
in the speed error circuitry that was producing a 15% speed error signal. This ;
signal should have shown 0% speed arror. This condition was documented on AR '
number A1128229. <
Ongoing analysis of this condition by eng!neering and l&C personnelindicated that
the 15% speed error was caused by the repair to the speed control card loose ;
connection. Retightening this connection was believed to have introduced the ,
speed error since this error had earlier been unknowingly compensated due tn the
~
,
short.
Engineering personnelissued a non conformance report (NCR) under ECR number
98 00036, Revision 000 to raise the load set value from 105% to 120% to
compensate for the speed error. This allowed the required 105% value to come out
of the summer for speed control and load control. This ECR contained a safety
evaluation for operating the unit with this change to the load set value. Several
operations procedures were also changed to reflect the revised nominalindicated
,
margin between the load set and actual power due to the speed bias.
Subsequently, the load set was raised and unit 2 power was increased to 100% on
January 8.
The inspectors reviewed the ECR, safety evaluation, and AR for this condition and
verified that the affected operations procedures had been changed. The inspectors
had no concerns with the change to the load set. However, the inspectors noted
'
during these reviews that l&C personnel did not fully understand the effect on the
EHC system of tightening the loose connection on the card in the speed control
section,
c. Conclusions
The inspectors had no concerns with the analysis or changes made to increase the
load set value to compensate for the speed error blas. However, the inspectors
were concerned with the fai!ure of the l&C personnel to fully understand the
operation of the speed control circuitry and what effect tightening the loose
'
connection would have on the signal and the EHC system.
l
--, .. - -- . . . - . - , _ - , . - - , , . . - . -
-. - . - . . . . . - - . - . - _ . _ _ - . .
- - _ _ _ -_ __ _ - - - . ___
.
.
23
lli. Enoineerina
E1 Conduct of Engineering
E1.1 Unit 3 Jet Pumo Riser Elbow Weld Crackina
a. Insoection Scone (37551)
The inspectors reviewed the interim operating strategy, safety evaluation, and flaw
evaluation for the cracks found in the jet pump risers during the October 1997, Ur,:t
3 refuHing outage,
b. Observations and Findinas
Engineering personnel performed an assessment of the cracks on the jet pump risers
and determined that the reactor could be returned to service and operated on an
interim basis pending repairs, with restrictions on recirculation flow to limit crack
growth by f a"gue. The licensee described its interim operating strategy in a letter
dated October 30,1997. The Office of Nuclear Reactor Regulation (NRR) staff
requested additionalinformation on November 7,1997, which the licensee provided
on November 17,1997. The licensee provided a revised interim operating strategy.
on November 19,1997. Thie interim strategy was implemented under the
provisions of 10 CFR 50.59, and limits recirculation flow to 91 % for up to 800
hours, and 80% for 2,224 hours0.00259 days <br />0.0622 hours <br />3.703704e-4 weeks <br />8.5232e-5 months <br />.
The NRR staff agreed with the licensee that no unreviewed safety question existed.
The staff concluded that the licensee's flaw evaluation is in accordance with
Appendix C to Section XI of the ASME Code, and that ASME Code component
structuralintegrity margins would be maintained for the specified operating porlod
under the interim operating strategy. The staff noted that the licensee reserved
18.4% margin in terms of final crack length to account for uncertainties and
inaccuracles in its evaluation. This margin gave the staff additional assurance that
the f acility could be safely operated until repairs are performed.
On December 22,1997, the licensee documented its decision to use a mechanical
clamp as the permanent crack repair, and that a repair outage is scheduled for early
March 1998. The licensee committed to inform the NRC of changes to the
operating strategy which require revision of the 10 CFR 50.59 safety evaluation.
The licensee will provide a summary of actual operating history documenting actual
recirculation flow rates and time periods under the interim strategy following the
repair outage,
c. Conclusions
The licensee's flaw evaluation for cracks found on the jet pump risers was %
accordance with the ASME code and provided adequate margin for continued safe
operation of Unit 3. The inspectors had no concerns with the licensee's safety
evaluation or interim operating strategy.
.
.
24
E2 Engineering Support of Facilities and Equipment
E2.1 Inadvertent Operation of Bvoass Vylves Durina Unit 2 Shutdown
a. Insoection Secow (71707 & 37551)
On December 29,1997, all nine bypass valves unexpectedly opened at 155 psig
EHC pressure during lowering of the 'A' EHC pressure set from 190 psig to 150
psig during the normal depressurization/cooldown of Unit 2. The inspectors
reviewed TPA performed per ECR number PB 03475, Revisions 000 and 001 which
contributed to this event and Operations General Procedure [GPb3, Revision 77,
" Normal Plant Shutdown."
b. Observations and Findinas ,
While lowering EHC pressure to allow a depressurization nf the Unit 2 reactor to i
less than 50 psig, all bypass valves opened. The reactor pressure was 120 psig at
the time. The EHC pressure set was immediately raised until all the bypass valves
closed. EHC pressure was then lowered at 1.0 psig increments. At 156 psig, six
bypass valves opened up. Pressure set was then raised to 159 psig and all six
bypass valves closed again. During these changes in EH. pressure, pressure
control swapped from the 'A' regulator to the 'B' regulator.
During this transient, reactor vessel level swelled from a steady state of + 22.0" to
+ 50.0" then back to + 22.0." The 2 'A' reactor feedwater turbine tripped
automatically during this trancient. This issue is discussed in section E2.1.
The licensee's investigation into this transient revealed that the TPA that removed
the 'B' pressure regulator from service helped cause this event. This TPA failed the
'
'B' normal /f ailure switch by installing a jumper which closed tne failure switch.
With this failure switch closed, the lower 1 kilohm resistor in the circuit shorted out
when the pressure sat point was lowered. This condition tied the voltage signal to
ground since the resistance was shorted out. This caused the 'A' regulator voltage
signal to be lower than the 'B' signal so that the 'B' regulator took control and
resulted in all the bypass valves opening.- After the vessel was depressurized, the
licensee jumpered the 'A' normal / failure switch and was able to r:aplicate the circuit
behavior with the 'A' pressure regulator circuitry. This TPA was removed and the
'B' pressure regulator motor operated potentiometer assemblies and secondary
pressure amplifier card was replaced prior to start up.
After reviewing the TPA and operations procedures, the inspectors noted that this
event was another example of the failure of the operators and engineering personnel
to understand what effect the work document had on the system. Specifically,
operations and engineering personnel did not fully understand the effect of the TPA
on the EHC system. The inspectors noted that the TPA was written to replace the
"B" pressure regulator card at power and not while shutdown. The inspectors
determined that the f ailure to fully understand ble effect of the TPA during
shutdown conditions inhibited operations personnel from adding procedural cautions
._ . - . - ._.
.
.
25
in the shutdown procedures. These cautions would have provided additional
assurance that the pressure regulation and turbine-generator control system
operated as required during the shutdown evolution,
c. Conclusions
The inspectors were concerned with the failure of operations and engineering
personnel to understand the effect on the EHC system of the TPA which was
designed to fail the 'B' EHC pressure regulator and allow replacement of the
secondary pressure amplifier card. This lack of system understanding contributed
to all the bypass valves unexpectedly opening which resulted in a reactor vessel
level transient.
E 2.2 2 'C' Residual Heat Removal (RHR) Pumo Suction to Torus Valve Motor Onorator
, Deficiencies
a. ingp_ggtlon Scone (62707 & 37551)
During scheduled maintenance, PECO maintenance personnelidentified a broken
clutch gear and found a motor brake installed to the RHR Torus suction valve motor
operator, MO 210-013C. The inspectors reviewed applicable documentation and
discussed these issues with engineering and maintenance personnel to understand
the causes and corrective actions for these deficiencies. The inspectors also
independently evaluated whether these deficiencies were applicable to other valves,
b. Observations and Findinag
While the 2 'A' RHR system was out of service, maintenance personnel found what
appeared to be a rnotor brake electrical connection on the 2 'C' RHR Torus suction
valve operator motor. Engineering personnel verified that the motor break was
installed. Review of this issue by engineering personnel revealed that the motor
brake installed on this valve was to have been removed by an engineering
modification in 1988. This engineering modification was also supposed to remove
the brakes from several other safety related valve operator motors. The RHR
system electrical drawing, M 1 S 65, Revision 96, " Unit 2 Wiring Diagram: Electrical
Schematic Diagram RHR System," did not show this electrical brake to the 2 'C'
RHR Torus suction valve operator motor.
McIntenance removed the motor brake from MO 210-013C prior to testing and
wrote PEP 10007785 to document this deficiency. Maintenance planned to change
the MOV maintenance procedure to add a step to verify that no motor brakes were
installed.
The inspectors reviewed NRC Information Notice 93 98, " Motor Brakes on Valve
Actuator Motor." This Information Notice discussed the potential for MOVs with
motor brakes installed to failif the design basis voltage was insufficient during a
degraded voltage condition to allow the motor brakes to re'7se. The inspectors
noted that the design basis voltage to the 2 'C' RHR pump suction to the torus,
._ _ _ _ . ._ ____._._ - _ . _ _ _ _ _ . _ _... _ . _ _ _ _ . _ . .
.
l *
I 26
MO 210 013C,was verified during the preventive maintenance program on the
- MOV.
During testing of this valve, the maintenance personnel noticed an abnormal noise
coming from the valve operator in the tripper finger area where the lever for
conversion to manual operation is located. Subsequently, maintenance personnel
, disassembled and inspected the valve operator and found a part of a tooth missing
from the worm shaft clutch gear. The worm shaft clutch gear and the grease in the
operator were removed and replaced. The knob which contacted the tripper fingers
was filed down to correct the noise problem. The valve operator was reassembled
and the valve was successfully retested and returned to service.
The inspectors observed portions of the valve operator's disassembly, reassembly,
and testing. The inspectors observed that the tooth breakage on the worm shaf t
clutch gear ran though the stamp mark on the end of the gear.
c. Conclusion
Based on the performance history and voltage available during an accident to the 2
'C' RHR pump torus suction valve, the inspectors concluded that the Installed motor
brake did not render this valve inoperable. However, the Inspectors were concerned
that other safety related MOVs could have motor breaks installed even though the
breaks had supposedly been removed per the 1988 engineering modification. The
inspectors will follow up on the identification and inspection of other MOVs for
motor brakes, any modification control issues concerning the 1988 engineering
modification, and any generic implications from the results of the failure analysos on
"
.a broken worn uhaft clutch gear. (IFl 50 277(278)/97 08 06)
E8 Miscellaneous Engineering Issues i
4
E8.1 (Closed) URI 50 277(2781/96-04-04:Emeraency Diesel Generator (EDG) Outout
Breaker Resoonse Durino Testing
On June 6,1996, operations personnel identified an unexpected condition during a
simulator exercise that affected all four EDGs. While any EDG was running and
unloaded, the output breaker would fail to automatically close following a loss of
offsite power. Generally, thit vas only possible during EDG testing prior to
paralleling the diesel to the grid. This condition was caused by a sealin of the 4 KV
breaker anti-pumping features and had unknowingly been introduced into the control
4
- , - - , w-- ..r , _ , - , _ . _ . . ,c,y ,_m_,.e y_._. ., , .,_. - _, . , _ - g- _w...m-_ -m.,~,,- ._, .._.- _ _ .-..
_ --. . -.- - _ - - - - - - __-._ - - -_. - _ - ---.
.
.
27
circuit logic in June 1995 daring modification P 231. Modification P 231 was
designed to provide automatic transfer from the EDG parallel mode to the
isochronous mode of operation. The EDG output breaker could be shut during this
condition by momentarily placing the breaker in the trip position to clear the anti-
pump relay seal in.
Interim corrective actions included: declaring the EDGs inoperable during testing;
training operations personnel and revising procedures to specify the required actions
to shut the EDG output breaker; and performing additional analyses to identify other
potential scenarlos where the EDG output breaker would lockout,
iho inspectors had no concerns with the interim actions, however, the inspectors
were concerned with any safety and regulatory significance associated with this
design condition. These concerns were forwarded to NRR for review. .
-
NRR visited the Peach Bottom site and reviewed the electrical distribution system
control and schematic diagrams and the current licensing basis. NRR concluded
that the safety significance of this design condition was low and the licensee
remained in compliance with the Technical Specifications during routine EDG
testing. NRR also determined that the EDG remained within the licensing basis and
was not required to respond to a loss of coolant accident or a loss of offsite power
while in this condition. NRR identified no new issues during this review. Based on
the NRR review and the licensee's interim corrective actions, the inspectors have no
further concerns with this issue.
IV. Plant Support
R1 Radiological Protection and Chemistry (RP&C) Controls
R1.1 Imolementation of the Radioactive Liould and Gaseous Effluent Control Proarams
a. Insoection Scooe (84750-01)
The inspection consisted of: (1) a tour of the plant, including the control room, (2) _
review of liquid and gsseous effluent release permits, and (3) review of
unplanned /unmonitored release pathways,if any,
b. Observations and Findinas
The inspectors toured Units 2 & 3, selected effluent radiation monitoring systenis
(RMS), selected air cleaning systems, and the control room. All effluent RMS and
air cleaning systems were operable at the time of this inspection.
Rad:oactivo liquid and gas release permits contained: (1) gamma measurement
,
results; (2) tritium measurement results; (3) projected dose calculation results; (4)
cumulative dose contributions from radioactive gas and liquid releases for the
current calendar quarter; (5) RMS readings 'before, during, and end of release); and
_ _ _ _ _ . _ . _ _ _ _ _ _ . . _ __._ _
___ . __ . _ . _
.
.
28
(6) aler. tnd alarm setpoints. The inspectors determined that tha licensee followed
associated procedures and the requirements of the Offsite Dose Calculation Manual
(ODCM).
The licensee completed a significant upgrade to the chemistry laboratory including
non radiological measuring equipment. Another notable improvement to the
radioactive effluent's program was new laboratory quality control sof tware,
c. Conclusiong
Based on the above reviews, the inspectors determined that the licensee
implemented the radioactive liquid and gaseous effluent control programs
effectively.
R2 Status of Radiological Protection and Chemistry Facilities and Equipment
R 2.1 Calibration of Effluent /Procest_ Radiation Monitorina Systems (RMS)
n. Insoection Scoce (84750-01)
The inspectors reviewed the most recent calibration results (electronic and
radiological calibrations) for the following effluent and process RMS with respect to
licensee procedures, Technical Specifications (TS) and ODCM requirements:
- Liquid Radwaste Effluent Monitor (common),
- Liquid Radwaste Effluent Flow Meter,
- Reactor Building Closed Component Cooling Monitors (both units),
- Service Water Effluent Monitors (both units),
- Emergency Service Water Effluent Monitor (common),
Main Stack Noble Gas Monitors (common, normal and wide range),
- Roof Vent Noble Gas Monitors (both units),
- Offgas Monitors (both units)
The inspectors also reviewed the most recent radiological calibration results
performed by the Chemistry Department staff for the following process RMS:
- Control Room Vent Monitor,
- Refuel Floor Vent Exhaust Monitors (both units), and
- litywell High Range Monitors (both units)
b. Observations and FindiO21
The Instrumentation and Controls (l&C) Department performed both the electronic
and the radiological portions of RMS calibrations. Calibration results were within
the licensee's acceptance criteria.
The inspectors noted no inadequacies pertaining to the calibration of the liquid
radwaste effluent flow meter.
__ _ __ _ _ ... _ _ _ ._ _ _ . _ __ _ _ _ _ _ __._ _ _ _ _ _
O
.
29
During a review of older RMS (manuf acturers other than Sorrento), the inspectors
noted that radiological calibrations were good, linearity checking was good, high
voltage was properly set by determining the optimum high '. >ltage Jet point, and
_
electronic alignments were appropriate. Tracking and trending efforts by the ,
syJtem engineer were very good.
,
During a review of newer RMS (manufactured by Sorrento), the inspectors noted
that the radiological calibration techniques used by the licensee were acceptable
because beta scintillator detectors are inherently stable. Linearity checking was
good. Tracking and trending efforts by the system engineer were very good.
However, the electronic portion of the calibration of these monitors was weak.
High voltage was checked at one point, but the inspectors noted that these RMS
continually self monitor high voltage. Electronic alignment checks were minimal.
This was discussed with the System Engineer who agreed to review the matter and
make changes to calibration procedures as appropriate. 4
c. Conclusions
Based on the above evaluation, the inspectors concludea that this program area was
good. A minor weakness was noted pertaining to the electronic portion of a
calibration of RMS manufactured by Sorrento.
R2.2 Surveillance Tests for Air Cleanina and Ventilation Systems
a. Insoection Scope (84750 01)
The inspectors reviewed the licensee's: (1) most recent surveillance test results,
and (2) performance summaries with respect to l echnical Specification (TS) and
Updated Final Safety Analysis Report (UFSAR) requirements for the control room,
standby gas treatment, and turbine building ventilation systems.
b. Observations and Findinas
The inspectors noted that deficiencies identified during surveillance testing were
corrected and as lef t conditions met the licensee's acceptance criteria.
The licensee periodically checked and recorded the differential pressure across
turbine building ventilation HEPA filters,
t
l The licensee's TS specify Regulatory Position C.6.a of Regulatory Guide (RG) 1.52,
Revision 2, March 1978, as the requirement for the laboratory testing of the
,
chercoal. RG 1.52 references ANSI N5091976," Nuclear Power Plant Air Cleaning
j Units and Components." ANSI N5091970 specifies that testing is to be performed
'
in accordance with paragraph 4.5.3 of RDT M 161T, " Gas Phase Adsorbents for
_ _ _ _ . -_ _. _ _ ___ _ _ _
_
=
I .
i ;
,
i 30
1
! Trapping Radioactive lodino and lodine Components." The most recent test results
met the licensee's existing charcoal test acceptance criteria. Charcoal efficiency I
testing was conducted by a vendor service. The inspectors inforrned the licensee of
alternative charcoal testing methodologies.
'
<
,
c. Conclusions
,
The inspectors concluded that the licensee maintained a good program for air
I
cleaning systems.
R3 Radiological Protection and Chemistry Procedures and Documentation-
a. insoection Scoos (84750 01)
. An ODCM review was conducted that consisted of: (1) review of set point
calculation methodologies: (2) review of selected parameters for calculating
- projected doses; and (3) review of ra; _. lve liquid and gaseous discharge
'
pathways. The inspectors also reviewed the 1996 Annual Radioactive Effluent
Report to verify implementation of the TS/ODCM.
l
b. Observations and Findinas
- The ODCM contained set point calculation methodologies for radioactive liquid and
j gaseous effluent RMS. The inspectois also noted that the ODCM contained all
! relevant parameters as found in Regulatory Guide 1.109, NUREG 0133, and site
specific factors. Radioactive liquid and gaseous effluent pathway diagrams were
- also provided as required. No new ODCM discrepancies were noted (see Section
i R8.2).
.
'
The Annual Radioactive Effluent Report provided total quantities of liquid and
! gaseous effluent released from both units and included projected doses to the
,
public. The inspectors determined that the licensee met the TS/ODCM reporting
requirements and the report contained the information specified in the ODCM. No
'
i obvious emissions, trends or anomalous measurements were identified.
,
c. Conclusions
i
The licensee's ODCM contained all the necessary information and guidance to
support the radioactive liquid and gaseous effluent control programs. No
4
discrepancies were noted pertaining to the Annual Radioactive Effluent Report. All
liquid and gaseous discharges for 1996 were well within regulatory requirements.
1
R7 Quality Assurance (OA) in Radiolegical Protection and Chemistry Activities
'
a. insoection Scope (84750-011-
1
The inspection consisted of reviews of the most recent TS required radioactive
effluents control program audit, surveillances, and a Chemistry Department self-
assessment.
_ _ . . _ . _ . . . _ . . .__ _ _ _ _ _ _ __ _ . . _ _ ,. _ _. _ . . , _ _ _ . - . _ _ . . _ , -
_ . - . _ _ - - - - - . - _ . - - - . - - - - - - . - - - - -
- l
4
- l
1
,
31
4
The inspectors reviewed the radiochemin.try laboratory quality assurance / quality
control (OC) programs to determine the adequacy of controls with respect to
sampling, analyzing, and evaluating data. The inspectors reviewed results
pertaining to: (1) the intra laboratory and inter laboratory comparison; (2) blind
- duplicate samples; (3) reproduction techniques (reproducibility for sampling and
analyzing); and (4) instrument control charts,
~
b. Observations and Findinas l
1
The 1997 QA Audit was effective and adequately covered the effluent control
program including ODCM implementation. A technical specialist with applicable
experience was on the audit team. No findings of regulatory significance were
identified.
No discrepancies were noted pertaining to the intra laboratory, inter-laboratory, or
,
blind sampling comparative tests. Laboratory QC data results indicated that the
licensee implemented very good quality control of Chemistry laboratory counting
equipment. l
>
'
c. Conclusions
!
Quality assurances of the effluents control program and quality control of chemistry
sampling analysis and detection equipment was considered to be very good.
R8 Miscellaneous Radiological Protection and Chemistry issucs
R8.1 Unroviewed Safety Question Review and Radioactive Effluents Control !
(VIO 50 278/97 03-01)
,
~
In NRC Inspection Report 50 278/97 03,it was noted that the licensee did not ,
formally consider potential impacts regarding radioactive effluents control prior to ,
'
breaching the turbine building that resulted in a violatir'n. The inspectors reviewed
the licensee's response to NOV 50 278/97-03 01 and considered the corrective
actions to be reasonable. Tha inspectors verified the corrective actions and
changes had been made by the licensee to better address the need for considering
impacts on the radioactive effluent's control program during the modifiedtion revle.w
process. Based on this review, the violation is closed,
in addition to the corrective actions implemented to address the violation, Chemistry l
department personnel conducted a thorough walkdown of the turbine building and 1
identified several perforations and seam cracks in the roof. Licensee staff analyzed !
each to determine whether the differential pressure at each location was either l
positive or negative. The licensee established continuous sampling stations at each i
of the holes where the differential pressure was positive. At the time of the
inspection, work orders had been initiated for repair and the engineering department
was conducting a safety evaluation of the existing condition. No major safety !
consequence is expected,
l
l
l
l
-- _ - = - ,-g,. % - g --yry+ -
p .,, , - ,yi.,-,.-,,,y- y - - - y- e-,w -
e
<
32
R8.2 Tour of Peach Bottom Unit 1
On December 4,1997, the inspectors toured the decommissioned Unit 1 facility.
This plant was a 40 MWe, high temperature, gas-cooled reactor and was shutdown
in October 1974. All fuel for this reactor has been removed from the site. The
inspectors did not identify any significant concerns with the maintenance of Unit 1
during this tour.
S1 Conduct of Security and Safeguards Activities
a. Inspection Scooe (81700)
Determine wnether the conduct of security and safeguards activities met the
licensee's commitments in the NRC-approved security plan (the Pian) and NRC
regulatory requirements. Areas inspected were: access authorization program;
alarm stations; communications; protected area access control of personnel and
packages and material,
b. Observat!ons and Findinas
Access Authorization Proaram The inspectors reviewed implementation of the
Access Authorization (AA) program to verify implementation was in accordance
with applicable regulatory requirements and Plan commitments, lhe review
included an evaluation of the effectiveness of the AA procedures, as implemented,
and an examination of AA records for seven individuals. Records reviewed included
both persons who had been granted and had been denied access. The AA program,
as implemented, provided assurance that persons granted unescorted access did not
constitute an unreasonable risk to the health and safety of the public and that
appropriate actions were taken when persons were denied access or had their
access terminated.
Alarm Stations. The inspectors observed operations in both the Centrai Alarm
Station (CAS), and the Secondary Alarm Station (SAS). This observation included
a! arm response, post turnover, and interviews with the alarm station operators. The
alarm stations were equipped vvith appropriate alarms, surveillance and
communications capabilities and were continuously manned by knowledgeable
operators. No single act could remove the piant's capability for detecting a threat
and calling for assistance because the alarm stations were sufficiently diverse and
independent. The Central Alarm Station (CAS) did not contain any operational
activities that could interfere with the execution of the detection, assessment and
response functions.
Communications. Both alarm stations were capable of maintaining continuous
intercommunications, communications with each security force member (SFM) on
duty, and calling for assistance from both on and offsite organizations. These
communications capabilities have been enhanced by the recent acquisition and
installation of more powerful radios in security and emergency vehicles.
- - . - - . - . - - - - - -- - - - . - . - - _ - - .
e
>
, .
33
.
Protected Area (PA) Access Control of Personnel and Hand-Carried Packaacs. The
- inspectors observed operations at the personnel access portal a number of times
during the course of the inspection. Positive controls were in place to ensure only
authorized individuals were granted access to the PA. All personnel and hand-
carried items entering the PA were pioperly searched and the last SFM controlling
access to the PA was in a position to perform this function effectively.
4
. PA Access Control of Material. The inspectors observed material processing in the
warehouse. The licensee had positive control measures for all materials entering
the PA. Materials entering the PA ware identified, searched and authorized by the
'
licensee. Materials entering the PA via the warehouse were searched by properly
trained and qualified individuals.
1
c. Qgngiusions
The licensee was conducting its security and safeguards activities in a manner that
protected public health and safety and that this portion of the program, as
,
implemented, met the licensee's commitments and NRC requirements.
S2 Status of Security Facilities and Equipment
a. Inspection Scooe (81700)
Areas inspected were: Testing, maintenance and compensatory measures; PA
detection and assessment aid; personnel and package search equipment and vehicle
barrier systems,
b. Observations and Findinas
Testina Maintenance and Compensatorv Measures. The inspectors reviewed
testing and maintenance records for security-related equipment and found that
documentation was on file to demonstrate that the licensee was testing and
- maintaining systems and equipment as committed to in the Plan. A priority status
- was being assigned to each work request and repairs were normally being
completed within the same day a work request necessitating compensatory
measures was generated. The inspectors reviewed security event logs and
maintenance work requests generated over the last year. These records indicated
.
that the need for compensatory measures was extremely minimal. When
'
necessary, the licensee implemented compensatory measures that did not reduce
the effectiveness of the security system as it existed prior to the need for the
compensatory measure.
, EA Detection and Assessment Aids. The inspectors observed the licensee's
performance test of the entire Intrusion Detection System (IDS). All zones of the
,
10S were tested, and generated appropriate alarms. The test of the IDS was
accomplished in accordance with the established testing procedure. The IDS was
- functional and effective. The inspectors observed camera coverage, in the CAS, of
the entire perimeter, while it was being walked down. The camera coverage and
overlap were very good. The licensee's assessment aids were functional and
effective.
-.- --- . .- . - . -. _ _ , - -
.
,
,
34
Personnel and Packaae Search Eauioment. The inspectors observed both the
routine use and the daily performance test of the licensee's personnel and package
search equipment. All search equipment was observed to perform its intended
function,
c. Conclusions
The licensee's security facilities and equipment were determined to be well
maintained and reliable and were able to meet the licensee's commitments and NRC
requirements.
S3 Security and Safeguards Procedures and Documentation
f
a. Insoection Scope (81700)
.
Areas inspected were: security program plans, implementing procedures and
j security event logs.
i
b. Observations and F;edinos
i
'
Security Procram Plans. The inspectors verified that selected changes to the Plan
, associated with the vehicle barrier system (VBS), as implemented, did not decrease
the effectiveness of the Plan,
i
Security Proaram Procedures. Review of selected implementing procedures
associated with the VBS determined the procedures were consistent with the Plan
>
commitments, and were properly implemented.
i
Security Event Loas. The inspectors reviewed the Security Event Log for the
- previous six months. Based on this review, and discussion with security
management, it was determined that the licensee appropriately analyzed, tracked,
,
resolved and documented safeguards' events,
c. Conclusions
Security and safeguards' procedures and documentation were being properly
implemented, Event Logs were being properly maintained, and effectively used to
analyze, track, and resolve safeguards events.
i
S4 Security and Safeguards Staff Knowledge and Performance
a. Insoection Scoce (81700)
Areas inspected were security staff requisite knowledge ano capabilities to
accomplish their assigned functions.
,
b. Observations and Findinas
Security Force Reauisite Knowledae. The inspectors observed a number of SFMs in
the performance of their routine duties. These observations included alarm station
- - . - - - . . _ _ - -.- _- - ---_ - - - _. --- - - -
4
.
I 35
i
operations, personnel and package access control searches, and PA patrols. In
addition, interviews were conducted with SFMs and security management.- Finally,
,
training records were reviewed (see S5). Based on all of the above activities, it was
determined that the SFMs were knowledgeable of their responsibilities and duties,
and could effectively carry out their assignments.
!
i
Resoonse Caoabilities. The inspectors reviewed the licensee's response strategies,
response drills and critiques and evaluated feedback to the training department for
lessons learned,
i
c. Conclusions
The SFMs adequately demonstrated that they have the requisite knowledge
necessary to effectively implement the duties and responsibilities associated with
their position.
S5 Security and Safeguards Staff Training and Qualifications
,
a. Insoection Scoce (81700)
i Areas inspected were security training and qualifications and training records.
- b. Observations and Findinas
, Security Trainina and Qualifications. The inspectors reviewed training records of
ten SFMs and observed weapons' qualifications for two SFMs. The records review
and weapons' qualification observation indicated that the security force was being
trained in accordance with the approved T&Q plan.
.
Trainina Records. The inspectors' review of training records determined that the
' records were accurate and contained sufficient information to determine the current
qualifications of the individual.
.
.
c. Conclusion
4
Suurity force personnel were being trained in accordance with the requirements of
the NRC approved T&Q plan. Training records were being properly maintained.
Finally based upon the findings documented in paragraph S4, the inspectors
determined that the training was effective and provided the security force with the
requisite information needed to effectively implement the Plan.
l-
S6 Security Organization and Administration
a. Insoection Scoce (81700)
Areas inspected were: management support, effectiveness and staffing levels.
1
. . . ...
p..-- -
.
.
36
b. Observations and Findinas
Manaaement Sucoort. The inspectors reviewed various program enhancements
made since the last program inspection to determine the level of management
,
support. These enhancements included the allocation of resources for the following
! activities:
Upgrade of the offsite communications system to include installation of new
more powerful radios in six security and emergency vehicles.
Upgrades to the assessment system, including the installation of six new pan
tilt and zoom video cameras and a new video switcher.
Installation of an upgraded video-capture system to enhance assessment
capabilities.
Training of ont : s Instrument and Control Technicians to repair radio
communicatiow systems, therefore, reducing the need for offsite support in
maintaining these systems.
Manaaement Effectiveness. The inspectors reviewed the management
organizational structure and reporting chain, Security managements position in the
organizational structure provides a means for making senior management aware of
programmatic needs. Senior management's positive response to requests for i
equipment, training and resources in general have contributed to the effective
administration of the security program.
Staffino Levels. The inspectors verified that the total number of trained SFMs
immediately available on a shift met the requirements specified in the Plan
c. Conclusiorig
The level of management support was adequate to ensure effective implementation
of the security program, and was evidenced by adequate staffing levels and
continued resource allocation to improved training and equipment to enhance
effective implamentation of the security program.
S7 Quality Assurance in Security and Safeguards Activities
a. Inspection Scoce (81700)
Areas inspected were: audit /self-assessment program, problem analyses, corrective
actions and effectiveness of management controls,
b. Qbservations and Findinas
Audit /Self-Assessment Proaram. The inspectors reviewed the licensee's Security
Program Audit Report (Assessment A1061530 conducted March 24-April 7,1997)
and Fitness-for-Duty (FFD) Audit Report (Assessment A1102592 conducted
l
l
.
.
37
August 2-October 2,1997). There were no findings in the security audit and one
deviation identified during the FFD audit.
The deviation was not indicative of major programmatic weaknesses. The FFD
audit was enhanced by the use of technical specialists. Finally, a review of the
response to the audit finding indicated that the actions taken to address the finding
would enhance program implementation,
The self assessment program was well defined and structured. Self assessments
were performed in the areas of security operations, access controls, security
systems and training. The self assessments were comprehensive, and results well
documented. The data generated was trended, and the results were well organized.
Problem Analyses. The inspectors reviewed data derived from the self assessment
program. The analyses was effective, and problem areas are trended and identified.
Corrective Actions. The inspectors reviewed corrective actions implemented by the
licensee in response to the internal QA audit. The corrective actions were effective,
and should prevent recurrence of the findings associated with the corrective
actions.
Effectiveness of Manaaement Controls. The inspectors observed that the licensee
has a program in place which was effective in identifying, analyzing and resolving
problems. The corrective actions taken by the licensee, in response to the audit
l findings were adequate and should prevent recurring problems. The same could be
said for the self assessment program relative to the ability of the licensee to identify
and analyze problems.
c. .Qrnclusions
TI e review of the licensee's Audit /Self-Assessment program indicated that the
audits were comprehensive in scope and depth, that the audit findings were
reported to the appropriate level of management, and that the program was being
properly administered. In addition, the corrective actions that were implemented
were effective.
S8 Miscellaneous Security and Safety issues
S8.1 Vehicle Barrier System (VBS) (Tl 2515/132)
General
On August 1,1994, the Commission amended 10 CFR Part 73, " Physical Protection
of Plants and Materials," to modify the design basis threat for radiological sabotage
to include the use of a land vehicle by adversaries for transporting personnel and
their hand-carried equipment to the proximity of vital areas and to include the use of
a land vehicle bomb. The amendments require reactor licensees to install vehicle
control measures, including vehicle carrier systems (VBSs), to protect against the
malevolent use of a land vehicle. Regulatory Guide 5.68 and NUREG/CR-6190were
1
J
__
.
l
l 38
issued in August 1994 to provide guide,ce acceptable to the NRC by which the
licensees could meet the requirements of the amended regulations.
A February 28,1996, letter from the licensee to the NRC forwarded Revision 8, to
its physical security plan. The letter stated, in part, that vehicle control measures
meet the criteria of 10 CFR 73.55(c)(7),(8) and (9) and Regulatory Guide 5.68
dated August 1994. A NRC June 19,1996, letter advised the licensee that the
changes submitted had been reviewed and were determined to be consistent with
the provisions of 10 CFR 50.54(p) and were acceptable for inclusion in the NRC-
approved security plan.
This inspection, conducted in accordance with NRC Inspection Manual Temporary
Instruction 2515/132," Malevolent Use of Vehicles at Nuclear Power Plants," dated
January 18,1996, assessed the implementation of the licensee's vehicle control
measures, including vehicle barrier systems, to determine if they were
commensurate with regulatory requirements and the licensee's physical security
plan.
S8.2 Vehicle Barrier System (VBS)
a. Insoection Scoce (Tl 2515/132)
The inspectors reviewed documentation that described the VBS and physically
inspected the as-built VBS to verify it was consistent with the licensee's summary
description submitted to the NRC and was in accordance with the provisions of
b. Observations and Findinas
The inspectors' walkdown of the VBS and review of the VBS summary description
disclosed that the as built VBS was consistent with the summary description and
met the specifications in NUREG/CR 6190.
c. Conclusion
The inspectors determined that there were no discrepancies in the as-built VBS or
the VBS summary description.
S8.3 Bomb Blast Analvsis
a. Insoection Scoce (Tl 2515/132)
The inspectors reviewed the licensee's documentation of the bomb blast analysis
and verified actual standoff distances provided by the as built VBS.
- . . - . _ _ _ _ _ _
- - . - - . _ - - - . - - ... - - - - . . .- . . - - . - .
'
.
.
39
b. Observations and Findinas
The inspectors' review of the licensee's documentation of the bomb blast analysis
determined that it was consistent with the summary description submitted to the
NRC. The inspectors also verified that the actual standoff distances provided by
- their as-built VBS were consistent with the minimum standoff distances calculated
using NUREG/CR-6190. The standoff distances were verified by actual field
, measurements.
.
!
c. Conclusion
No discrepancies were noted in the documentation of bomb blast analysis or actual
- standoff distances provided by the as-built VBS.
S8.4 Procedural Controls
.
a. Insoection Scooe (Tl 2515/132)
The inspectors reviewed applicable procedures to ensure that they had been revised
to include the VBS,
t
b. Qbservations and Findinas
The inspectors reviewed the licensee's procedures for VBS access control
measures, surveillance and compensatory measures. The procedures contained
effective controls to provide passage through the VES, provide adequate
surveillance and inspection of the VBS, and provide adequate compensation for any
- degradation of the VBS.
c. Conclusion
.
The inspectors' review of the procedures applicable to the VBS disclosed no
discrepancies.
S8.5 Security Force Strike Continaency Plans
a. Insoection Scope (Tl 2515/132)
1- Evaluate the licensee's strike contingency plans to verify that trained personnel are
available to support staffing levels consistent with staffing requirements and that
plans are in place to insure security operations continue in a safe and orderly
manner in the event of a strike.
-
b. Observations and Findinas
$ The inspectors reviewed the licensee's contingency plan to be implemented in the
event of a strike, and reviewed training and qualification records for contingency
force personnel that were available to replace striking officers in the event of a
strike,
!
. . .
_ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _
.
.
40
c. Conclusion
The licensee had taken appropriate action to insure that an adequate number of
trained and qualified personnel were available to meet regulatory required staffing
levels and continue security operations in a safe and orderly manner in the event of
a strike.
F1 Control of Fire Protection Activities
F1.1 Eire in the 2 'C' Service Air Comoressor
a. insoection Scooe (71707. 62707. & 71710)
The inspectors reviewed the station response to a fire in the 2 'C' service air
compressor on December 11,1997.
b. Observations and Findinas
Operators responded to a fire in the 2 'C' service air compressor at about 3:20 a.m.
on December 11,1997. The fire was extinguished within five minutes and was
limited to the compressor motor. PECO conducted a critique of the fire brigade
response and considereo that overall efforts were good, but found some
opportunities for improvement in communications between the control room and the
fire brigade.
PECO discovered that the fire was most likely caused by an inboard bearing cage
failure and subsequent overheating of the bearing. The inspectors reviewed the
maintenance history on the air compressor and found that annual preventive
maintenance had been conducted as scheduled.
In early November, predictive maintenance technicians identified noisy bearings and
high vibration on the compressor motor. The motor was placed on an increased
monitoring frequency (biweekly). Further readings in early December indicated
increasing vibration amplitudes and maintenance technicians recommended that the
motor be worked before its scheduled preventive maintenance date of May 1998.
The maintenance was tentatively re-scheduled for March 1998. Based on review of
the vibration data, maintenance technicians did not believe that failure was
imminent, so they did not request a higher priority for this corrective maintenance
issue.
The inspectors discussed the issue with the preventive maintenance technicians and
independently reviewed the bearing vibration data. The inspectors determined that
the data did not show signs of imminent failure. The inspectors had no concerns
with the priority the maintenance group placed on inis issue based on information
reviewed,
c. Conclusions
The station fire brigade response to a fire in the 2 'C' service air compressor motor
was good; however, operations identified some opportunities to improve
_ _ _ _ _ _ _
- - - .. . . - -- - - - - _ _ - - - - - ._-.. - . . - . . . _ .
.
,
,
41
communications between the control room and the fire brigade. The inspectors
reviewed predictive maintenance activities on this component and identified no
concerns. Technicians had been monitoring increased motor bearing vibration, but
the data did not indicate that a failure was imminent.
V. Manoasment Meetinas
X1 Exit Meeting Summary
,
The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on January 20,1998. The licensee acknowledged the
findings presented.
,
'
The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information was identified.
X2 Review of Updated Final Safety Analysis Report (UFSAR) Commitments
A discovery of a licensee operating their facility in a manner contrary to the Updated Final
,
Safety Analysis Report (UFSAR) description highlighted the need for a special focused
review that compares plant practices, procedures and/or parameters to the UFSAR
descriptions. While performing the inspections discussed in this report, the inspectors
, reviewed the applicable portions of the UFSAR that related to the areas inspected. The
'
inspectors verified that the UFSAR wording was consistent with the observed plant
practices, procedures and/or parameters. Since the UFSAR does not specifically include
security program requirements, the security inspectors compared licensee activities to the
NRC approved physical security plan, which is the applicable document. While performing
the security inspection discussed in this report, the inspectors reviewed Chapter 3 of the
Plan titled, " Protected Area Perimeter." Based on discussions with security supervision,
procedural reviews, and direct observations, the inspectors determined that barriers were
installed and maintained as described in the Plan and applicable procedures.
1
d
.
.
e
42
LIST OF ACRONYMS USED
action request (AR)
action statement (AS)
administrative guideline (AG)
APRM gain adjust factor (AGAF)
as low as-reasonably achievable (ALARA)
average power range monitors - neutron (APRMs)
central alarm system (CAS)
control rod drives (CRDs)
con'rol room emergency ventilation (CREV)
core power and flow log (CPFL)
core spray (CS)
core thermal power (CTP)
design input document (DID)
electro-hydraulic control (EHC)
eleventh refueling outage (3R11)
emergency core cooling system (ECCS)
emergency diesel generator (EDG)
emergency operating procedures (EOP)
emergency service water (ESW)
end-of-cycle (EOC)
engineering change request (ECR)
engineered safety feature (ESF)
fitness-for-duty (FFD)
fix-it-now (FIN)
functional testing (FT)
general procedure (GP)
Generic Letter (GL)
health physics (HP)
high efficiency particulate (HEPA)
high pressure coolant injection (HPCI)
high pressure service water (HPSW)
hydraulic control unit (HCU)
improved TS (ITS)
independent safety engineering group (ISEG)
inservice inspection (ISI)
inspector follow-up items (IFis)
instrument and control (l&C)
intermediate range monitor - neutron (IRM)
intrusion detection systems (IDS)
licensee event report (LER)
limited senior reactor operators (LSROs)
limiting conditions for operation (LCO)
load tap changer (LTC)
local leak rate test (LLRT)
loss of coolant accident (LOCA)
loss of off-site power (LOOP)
_
- - - _ _ _ - _ _ _ _ . _ _ . . _ _ _ _ . . . ___ _ _ .___ _ _.__- _
e
.
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43 l
l
low pressure coolant injection (LPCI)
lubricating oil (LO)
main control room (MCR)
,
modification (MCD)
motor generator (MG)-
nuclear maintenance division (NMD)
nuclear quality assurance (NOA)
NRC-approved physical security plan (The Plan)
nuclear review board (NRBi
offsite dose calculation manual (ODCM)
offsite power start up source #2 (2SU)
offsite power start-up source #3 (3SU)
Peco Energy (PECO)
performance enhancement program (PEP)
plant operations review committee (PORC)
'
post-maintenance testing (PMT)
primary containment (PC)
primary containment isolation system (PCiS)
-
primary containment isolation valve (PCIV)
protected area (PA)
quality assurance (QA)
quality control (QC)
radiation monitoring system (RMS)
radiologically controlled area ;RCA)
4
radiological protection and chemistry (RP&C)
rated thermal power (RTP)
reactor core isolation cooling (RCIC)
reactor engineer (RE)
reactor feed pump (RFP)
reactor operator (RO)
reactor protection system (RPS)
reliability centered maintenance (ROM)
safety evaluation report (SER)
- safety related structures, system and components (SSC)
,
scram solenoid pilot valve (SSPV)
secondary alarm system (SAS)
security force members (SFM)
senior reactor operator (SRO)
shift technical advisor (STA)
,
shift update notice (SUN)
source range monitor (SRM)
spent fuel pool (SFP)
standby gas treatment (SGTS)
station blackout (SBO)
. . ..- -_ . . _ _ - _ . _ - . . - . . -
o
.*
e
44
structure, system and component (SSC)
surveillance requirement (SR)
surveillance test (ST)
systems approach to training (SAT)
technical requirements manual (TRM)
,
technical specification (TS)
temporary plant alteration (TPA)
training and qualification (T&O)
turbine control valve (TCV)
turbine stop valve (TSV)
undervoltage (UV)
unresolved item (URI)
updated final safety analysis report (UFSAR)
vehicle barrier system (VBS)
wide range neutron monitoring system (WRNMS)
INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering Observations
IP 61726: Surveillance Observations
IP 62707: Maintenance Observation
IP 71707: Plant Operations
IP 71750: Plant Support Observations
'
IP 81700: Physical Security Program for Power Reactors
IP 84750-01 Radioactive Waste Treatment, and Effluent and Environmental Monitoring
- IP 92700
- Onsite Follow of Written Reports of Nonroutine Events at Power Reactor
Faci 4 ties
IP 92901: Operations Follow-up
IP 92902: Follow-up - Engineering
IP 92903: Follow up - f.1aintenance
IP 92904: Plant Support Follow-up .
'
'
IP 93702: Prompt Onsite Response to Events at Operating Power Reactors
Tl 2515/132: Malevolent Use of Vehicles at Nuclear Power Plants
ITEMS OPENED, CLOSED, AND DISCUSSED
Ooened
50 277/97-08-01 VIO Cold Weather Preparations Procedural Non-compliance
50 278/97 08-01 VIO Cold Weather Preparations Procedural Non-compliance
50-277/97-08-02 IFl Unit 2 Circulating Water System Problems
50-277/97 08-03 URI Missed TS SR Ter.t for Verification of Proper Flow in the
Recirculation Loops
50-277/97-08-04 URI Unexpected Trip of Unit 2 Main Turbine During Start-up
50-277/97-08-05 NCV Procedure Non-Adherence: Minor Safety Significance
50-?78/97-08-05 NCV Procedure Non-Adherence: Minor Safety Significance
50-277/97-08-06 IFl Review of Failure to Remove MOVs Motor Breaks and Broiwn
Worm Shaft Gear Failure Analysis
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50 278/97-08-06 IFl Review of Failure to Remove MOVs Motor Breaks and Broken
Worm Shaft Gear Failure Analysis
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50 277/97-08-05 NCV Procedure Non Adherence: Minor Safety Significance
50-278/97-08-05 NCV Procedure Non Adherence: Minor Safety Significance
j 50-277/96-04-04 URI EDG Output Breaker Response During Testing
50 278/96-04-04
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URI EDG Output Breaker Response During Testing
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50 278/97 03-01 VIO Inadequate Safety Evaluation for Unit 3 Turbine Building
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