ML20128J976
| ML20128J976 | |
| Person / Time | |
|---|---|
| Site: | Farley  |
| Issue date: | 09/27/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20128J933 | List: |
| References | |
| 50-348-96-07, 50-348-96-7, 50-364-96-07, 50-364-96-7, NUDOCS 9610100247 | |
| Download: ML20128J976 (30) | |
See also: IR 05000348/1996007
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U.S. NUCLEAR REGULATORY COMMISSION (NRC) ,
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REGION II
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Docket Nos: 50-348 and 50-364 i
License Nos: NPF-2 and NPF-8 l
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Report No: 50-348/96-07 and 50-364/96-07
Licensee: Southern Nuclear Operating Company (SNC). Inc.
Facility: Farley Nuclear Plant (FNP), Units 1 and 2
Location: 7388 North State Highway 95
Columbia. AL 36319
Dates: July 21 - Auguri 31, 1996
Inspectors: T. Ross. Senior Resident Inspector
J. Bartley, Resident Inspector
B. Siegel, Project Manager (Section E1.1 & E8.2)
W. Kleinsorge, Reactor Inspector (Section M1.2)
R. Chou, Reactor Inspector (Section El.3)
Approved by: P. Skinner. Chief, Projects Branch 2
Division of Reactor Projects
Enclosure 3
9610100247 960927
PDR ADOCK 05000348
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EXECUTIVE SUMMARY
Farley Nuclear Power Plant. Units 1 And 2
NRC Inspection Report 50-348/96-07. 50-364/96-07
This integrated inspection included aspects of licensee operations.
engineering, maintenance, and plant support. The report covers a 6-week
period of resident inspection.
1
Doerations i
e Overall, both units operated well at steady state full power. The
conduct of operations by Operations personnel and management was
consistently in compliance with procedures and regulatory requirements
(Section 01). i
e Shift operators remained very attentive to plant conditions. and were i
quite knowledgeable of plant status and ongoing activities (Section 1
01.1).
e The receipt inspection, handling and transfer of Unit 2 new fuel was
methodical and very well controlled (Section 01.2).
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Overall housekeeping and physical conditions of the 31 ants remained
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adequate. A number of minor leaks and equipment pro 3lems were
identified by the inspectors that could have been found by plant
personnel, especially system operators on their routine tours (Sections j
02.1 - 02.3).
- The incident report and root cause process continued to be an effective
tool for identifying and resolving significant plant problems, with one
notable exception. The licensee continued to struggle with the ongoing
problem of repetitive fire protection system multimatic valve failures
(Section 07.1).
Maintenance
e Maintenance and surveillance testing activities were routinely conducted
in a thorough and competent manner by well qualified individuals in
accordance with plant procedures and work instructions. Two minor
deficiencies were identified regarding the bagging and tagging of parts.
and the rigging safety program (Sections M1.1 and 1.2).
e The potential safety concern regarding reactor trip breaker (RTB)
secondary contact block cracking was promptly resolved by an aggressive
inspection and repair program (Section M8.1).
e One violation was identified regarding the inappropriate adjustment of
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the compensating voltage for Unit 1 intermediate range detector NI-35
l (Section M8.2).
Enclosure 3
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Enaineerina
e Safety evaluations of plant and procedure changes, tests and oxperiments
were conducted and reported pursuant to the provisions of 10 CFR 50.59.
All associated changes were accurately reflected in the Updated Final
Safety Analysis Report (UFSAR). However, it was noted that in the
routine report of 10 CFR 50.59 evaluations submitted to the NRC some
improvement is warranted in the level of detail used to describe these
changes (Section E1.1).
e One deviation was identified for failing to accom31ish several
commitments made in a license amendment request tlat was approved by the
NRC on September 28. 1995 (Section E1.2).
e A documentation weakness was identified regarding the use of an
ambiguous statement for documenting the review of several stress
calculations that was intended to ensure the conditions recuired by
American Society of Mechanical Engineers (ASME) Code Case b-411 were ,
met. This concern was resolved during the inspection (Paragraph E1.3). l
Additional examples of a previously issued vic.ation were identified '
involving multiple discrepancies found between field installation and
the approved drawings (Paragraph El.3)
Plant Suocort
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e Implementation of radiological controls in the radiologically controlled
areas were evident and generally effective. 0"erall . the radiologically
controlled areas were well maintained, adequately posted. and exhibited
good housekeeping, except for minor protlems in the piping penetration
rooms (Section R1.1). Unit 2 spent fuel inspection activities were well I
controlled (Section R1.1). l
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e Security activities continued to be performed in a conscientious and l
capable manner, assuring the physical protection of protected and vital
areas (Section 31.1)
e An emergency drill was well coordinated by Emergency Planning personnel
(Section P4.1)
e One unresolved item was identified regarding the installation and
inspection of Kaowool fire barriers on conduits and cabling that
terminate at safety-related motor-operated valve actuators (Section
F2.1).
e The root cause of continuing multiple failures of pre-action sprinkler
system multimatic valves remains indeterminate. Past corrective action I
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efforts have only been partie'ly successful (Section F8.1).
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Report Details
Summary of Plant Status
Unit 1 operated continuously at 100% power for the entire inspection period
except for routine main turbine generator (MTG) governor valve testing.
Unit 2 operated continuously at 100% power.for the entire inspection period
except for routine MTG governor valve testing.
I. Operations
01 Conduct of Operations
01.1 Routine Observations of Control Room Ooerations (71707)
Using Inspection Procedure-(IP) 71707, the resident inspectors conducted
frequent inspections of ongoing plant operations including routine tours
of the main control room (MCR) to verify proper staffing, operator
attentiveness, and adherence to approved operating procedures. The
l inspectors also regularly reviewed operator logs and TS Limiting
l Condition of Operation (LCO) tracking sheets, walked down the main
! control boards (MCB), and interviewed members si the operating shift
! crew to verify operational safety and complience with TS. The
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inspectors attended daily plant status meetings to maintain awareness of
overall facility operations, maintenance activities, and recent
incidents. Morning reports and Farley Nuclear Plant Incident Reports
(FNPIR) were reviewed on a routine basis to assure that potential safety
concerns were properly r~eported and resolved.
Overall control and awareness of plant conditions during the inspection
period were excellent. During tours of the MCR. the inspectors
regularly observed that very few MCB, emergency power board (EPB), and ,
balance of plant panel annunciators were in alarm at any one time.
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Several persistent annunciator alarms are preventing the Unit 1 and 2
MCBs. and the EPB, from achieving " blackboard." Operator attentiveness
' to, and knowledge of, plant conditions and status of ongoing activities
I continued at a high level. Although still quite low, the combined
l number of MCB deficiencies has grown to 25 which is more than double
what it was earlier this year. Several unit 2 MCB deficiencies are
l awaiting the upcoming refueling outage.
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01.2 Unit 2 Receiot. Insoection. and Transfer of New Fuel (71707)
The inspector observed the receipt inspection and transfer of new fuel
assemblies from the shipping containers to the Unit 2 spent fuel pool
(SFP). The inspector reviewed FNP-0-FHP-3.0, Receipt and Storage of New
Fuel, Revision 28. and verified that licensee personnel were following
the procedure. The inspector found the licensee personnel knowledgeable
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about new fuel receipt. Licensee personnel were very methodical and
- thorough in their handling and inspection of the new fuel assemblies.
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02 Operational Status of Facilities and Equipment
02.1 General Tours of Specific Safety-related Areas (71707?
General tours of FNP specific safety-related areas were performed by the
resident inspectors to examine the physical conditions of plant
equipment and structures, and to verify that safety systems appeared
properly aligned. Limited walkdowns of a more detailed nature of the
accessible portions of safety-related structures, systems and components
were also performed in the following specific areas:
o Control Room Air Conditioning Systems (CRACS) and Emergency
Ventilation Systems, trains A and B
e Unit 1 and 2 SFP
e Unit 1 and 2 Containment Spray addition tanks !
e Unit 1 and 2 Residual Heat Removal (RHR) heat exchanger (HX) rooms l
e Unit 1 and 2 Turbine Building l
e Service Water Intake Structure (SWIS). including Service Water I
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System (SWS) pumps, switchgear, and battery rooms l
e Unit 1 and 2 Component Cooling Water (CCW) pump and HX rooms i
e Unit 1 and 2 Boric Acid pump and mixing tank rooms
e Unit 1 and 2 Charging pump rooms
e Unit 1 and 2 Waste Monitoring Tank rooms
e Unit 1 and 2 Recycle Holdup Tank rooms
e Unit 1 and 2 vital 4160 volt alternating current switchgear rooms,
trains A and B l
e Unit 1 and 2 piping penetration room (PPR) on 100 foot elevation i
e Unit 1 and 2 PPR on 121 foot elevation
e Unit 1 and 2 SFP ventilation equipment rooms
e Unit 1 and 2 Hot Shutdown Panels
e Unit 1 and 2 vital 125 volt direct current switchgear and battery
charger rooms, trains A and B
e Unit 1 and 2 turbine-driven Auxiliary Feedwater (TDAFW) pump rooms
e Unit 1 and 2 Main Steam (MS) valve rooms
Overall material conditions and housekeeping for both units were
generally adequate. Minor equipment condition and housekeeping problems
identified by the inspectors were reported to the responsible shift
supervisor and/or maintenance department for resolution. The physical
appearance of the floor level in Unit 1 and 2 PPRs at the 121 foot
elevation, and Unit 1 PPR at the 100 foot elevation, continue to look
well worn with some random debris and discarded tools / material. An
inspector identified about 8 valves with packing leaks. and other
oil / grease spill problems, in the PPRs which had no deficiency reports
(DR) written against them. Also, even though the Unit 1 letdown
isolation valve (01E21HV8152) had a DR for a significant body to bonnet
leak, there was no catch bag installed to control the dripping water and
boric acid accumulation on the floor. The inspector held discussions
with responsible plant management regarding the effectiveness of routine
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rs by the system operators and Health Physics (HP) technicians in
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, noticing and reporting these type of ecuipment deficiencies. A similar
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comment was made in the last integratec inspection report (IR) 96-06.
Section 02.1.
02.2 Biweekly Insoections of Safety Systems (71707)
The resident inspectors used IP 71707 to verify the operability of the !
following selected safety systems: '
e Unit 1 High Energy Line Break (HELB) Sensors
e Unit 2 HELB Sensors 1
Technical specifications (TS) Table 3.3-10 for Units 1 and 2. provides a
list of HELB isolation instrumentation. A resident inspector walked
down all the instruments identified in TS Table 3.3-10 (i .e. . pressure I
switches, differential pressure sensors, and flooding detectors) and l
reviewed the most recent loop calibration and functional test records. l
Two minor discrepancies were identified regarding a drawing error and I
the flooding detector setpoint versus the UFSAR. These discrepancies l
were discussed with responsible FNP maintenance personnel. The I
inspector did not identify any immediate, safety significant problems l
that could adversely affect HELB system operability. However, serious
housekeeping deficiencies involving the flooding detectors in the Unit 1
and 2 MS valve rooms were observed. It was evident that the flooding
detectors and their immediate surrounding areas had not been cleaned for
many years. Res3onsible maintenance personnel could not ascertain that
these detectors lad ever been cleaned. The accumulation of spider webs,
dirt, dust, nesting material, feathers, and bits of trash around the
flooding detectors was profuse. Upon being informed of these
cot ditions, the licensee promptly examined the detectors and confirmed
the suspended ball floats were not obstructed.
02.3 Enaineered Safeauards Feature System Walkdown
a. Insoection Scone (71707)
A resident inspector used IP 71707 to perform a detailed walkdown of the
accessible portions of the Unit 1 SWS. The inspector also used portions
of FNP-1-SOP-24.0A, Service Water System - Outside Structures. Revision
3. FNP-1-SOP-24.08. Service Water System - Auxiliary Building. Revision
3. and various SWS drawings. The inspector performed these walkdowns in
the SWIS. diesel generator (DG) building. Unit 1 auxiliary building, and
Unit 1 valve box 1.
b. Observations and Findinas
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The inspector found that overall material conditions of equipment was
i adequate. However, the inspector did identify a number of minor
housekeeping, material condition, and labeling discrepancies which were
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discussed with the licensee for correction. Some of examples of these
discrepancies were: ;
e Corrosion on the SWS #3 and #4 battery terminals.
e Battery rooms were dirty (large quantity of dead mayflies). i
= 01P16G508A-A. U1 A-TRN SWP LUBE & COOL CONTROL PANEL. contained
debris such as light bulbs, terminal nuts, and a roll of
electrical tape.
e SWS strainer (A & B trains) shaft seal drain lines blocked. j
e 01P16PDS572. U1 B TRN SW STRAINER DP SWITCH. was labelled as no i
longer calibrated but the A train switch was still calibrated.
e U1 A train strainer had significant corrosion on inlet and outlet
)i)e connections.
e _a)el plate component nomenclatures (noun names) on the 600 V
motor control centers in the SWIS and the DG building did not
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match those listed in FNP-1-SOP-24.0A.
e FNP-1-SOP-24.0A identified 01P16V519/537 and 518/536 as being on j
the EPB when they are on the MCB. ,
- e Valve labels for 01P16V569 and V570 (B train strainer backflush
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line isolations) were reversed.
None of these discrepancies were significant enough to adversely affect
j the operability or operation of SWS equipment. i
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C. Conclusions
The inspectors concluded the SWS was operable and adequately maintained. l
However, the licensee needs to cantinue focusing attention on
housekeeping in the SWIS and preservation of the SWS piping around the i
strainers.
02.4 Tao Orders (71707)
During the course of routine inspections portions of the following tag i
orders (TO) and associated equipment clearance tags were examined by the
l inspectors:
All tags and tag orders examined by the inspectors were properly l'
executed and implemented.
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07 Quality Assurance in Operations ,
07.1 Effectiveness of Licensee Control in Identifyina. Resolvino. and
Preventina Problems (71707 and 40500) i
l The resident inspectors scanned all FNPIRs initiated. and approved by
the operations manager during the inspection period to ensure that plant
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incidents that effect or could potentially effect safety were properly
documented and processed in accordance with (iAW) FNP-0-AP-30.
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" Preparation and Processing of Incident Reports Certain selected
FNPIRs were reviewed in detail as part of the routine inspection
program. ,
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Overall, the inspectors concluded the licensee's program for identifying l
and resolving problems remained effective, and was being accomplished 1
IAW AP-30. Plant personnel and management exhibited an appropriate l'
threshold for identifying problems, initiating FNPIRs and assigning
formal root cause teams. The Operations manager remained attentive to
the FNPIR backlog and interfaced well with other managers to keep the
backlog at a manageable level. Each new FNPIR received prompt attention
and was regularly discussed by management in the morning status / plan of
- the day meeting. Direct derivations and formal root cause analyses
- continued to be conducted by experienced plant staff in a rigorous and
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thorough manner. The results of these efforts were almost always
effective at preventing recurrent problems. One notable exception was
the inability of the licensee and vendor to determine the root cause of
repeated failures of Grinnell multimatic fire suppression valves to
properly actuate (see Section F8.1).
08 Miscellaneous Operations Issues l
08.1 Review of Facility Operatino License (FOL) Conditions
The inspectors reviewed the facility's current license conditions of
FOLs NPF-2 and 8. in response to an issue at another plant. The
inspectors found that most of the original license conditions had
expired, and the licensee appeared to be operating the plant in
accordance with the remaining active license conditions.
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II. Maintenance
M1 Conduct of Maintenance
M1.1 General Comments
Inspectors observed and reviewed portions of various licensee corrective
and preventative maintenance activities, and witnessed routine
surveillance testing, to determine conformance with plant procedures.
work instructions, industry codes and standards. TS and regulatory
requirements.
a. Inspection Scone (61726. 62703 and 62707)
The resident inspectors observed all or portions of the following
maintenance and surveillance activities, as identified by their
associated work order (WO) or surveillance test procedure (STP):
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e FNP-0-STP-60,12 Emergency Response Data System Operability Test
e FNP-2-STP-80.1 28 Emergency Diesel Generator (EDG) Operability
Test
e WO S96001477 2B CCW HX Epoxy Coating
e FNP-1-STP-33.2A Reactor Trip Breaker Train A Operability Test
e FNP-1-STP-33.28 Reactor Trip Breaker Train B Operability Test
l e FNP-2-STP-33.2A Reactor Trip Breaker Train A Operability Test
e FNP-2-STP-33.2B Reactor Trip Breaker Train B 0)erability Test
e 'WO M00457538 Fire Suppression Valve 2A-100 Repair
e WO 596003021 2B EDG Slow Start Testing
o WO M00543008 On Line Leak Seal by Installation of a Furminite
Box on a Unit 2 Extraction MS Elbow
e WO M0056659 Replacement of a Valve in Fire Protection System ;
b. Observations. Findinas and Conclusions
All of the aforementioned maintenance work and surveillance testing l
observed by the inspectors were performed IAW work order instructions.
procedures, and applicable clearance controls. No adverse findings were
identified. Safety-related maintenance and surveillance testing
evolutions were well planned and executed. Responsible personnel
demonstrated familiarity with administrative and radiological controls.
Surveillance tests of safety-related equipment were consistently
performed in a deliberate step-by-step manner by personnel in close
communication with the control room. Overall, craftsmen and technicians
appeared knowledgeable, experienced, and well trained for the tasks they
performed.
In addition, see the discussion below regarding a specific maintenance
activity observed by a Region II inspector (Section M1.2).
M1.2 WO S960030281. lA Soent Fuel Pool Exhaust Fan Motor Overhaul
a. Insoection Scooe (62703)
A Region II inspector observed removal and transport activities related
to the approximately 350 pound 1A SFP exhaust fan motor. The activities
included removal of the motor from the fan assembly, movement of the
motor to the edge of the auxiliary building roof, the lifting of the
motor from the roof to ground level and the transporting of the motor to
the shop for repairs.
b. Observations and Findinas
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Maintenance activities were conducted by knowledgeable personnel
consistent with site procedures and regulatory requirements, except as
noted below.
- After the removal of the 1A SFP exhaust fan motor, the electrical <
maintenance technicians failed to bag and tag the fasteners and
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other parts left in the Unit 1 SFP exhaust fan room as required by i
paragraph 5.2.6. of procedure FNP-0-EMP-1002.01, Electrical !
Maintenance Precautions and Limitations, Revision 14. '
o Craft personnel and first line supervisors were unaware of the
source for the color coding requirements of slings and chain
hoists. Further they were uncertain as to which color represented
a current inspection / test for slings or chain hoists. This is
considered a weakness in the licensee's rigging safety program.
c. Conclusions
Overall, the maintenance activities observed by the inspector were
conducted in a thorough and professional manner pursuant to plant
)rocedures and work instructions. However, an example was noted where a
)agging and tagging procedure requirement was not followed, and a
potential weakness was noted related to the licensee's rigging safety
program.
M8 Miscellaneous Maintenance Issues (92902)
M8.1 (Closed) Insoector Follow-uo Item (IFI) 50-348. 364/96-06-02. Reactor '
Trio Breaker Secondary Contact Block Crackina
l a. Insoection Scoce
A Region II inspector and resident inspectors observed maintenance
activities involving the inspection of the RTB and RTB bypass breaker
secondary contact blocks in res)onse NRC IN 96-44, " Failure of Reactor
l Trip Breaker From Cracking of Plenolic Material in Secondary Contact
I Assembly." These inspections were performed under the following Work-
l Orders:
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e S96002741 Unit 2 "B" Train RTB Breaker
e 396002739 Unit 2 "B" Train RTB Bypass Breaker
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e S96002740 Unit 2 "A" Train RTB Breaker
e S96002738 Unit 2 "A" Train RTB Bypass Breaker
e S96002737 Unit 1 "B" Train RTB Breaker
e S96002735 Unit 1 "B" Train RTB Bypass Breaker
e S96002736 Unit 1 "A" Train RTB Breaker
e S96002734 Unit 1 "A" Train RTB Bypass Breaker
b. Observations and Findinas
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The licensee implemented a 3rogram to inspect the Westinghouse DS-416
breakers used for RTBs and )ypass breakers during planned maintenance.
The inspections were scheduled to be completed by the end of September
1996. The licensee inspected Unit 1 "B" RTB bypass breaker secondary
l contact blocks first and did not observe any cracking on the secondary
j contact blocks. The inspector observed the inspection of the Unit 2 "B"
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train RTB bypass breaker on August 14. 1996. The electricians were
thorough and quick to note a hairline crack on one of four secondary
contact blocks.
The licensee decided to accelerate the inspection schedule based on
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identification of the first crack. The inspections were complete by the
mornino of August 16, 1996. There are eight model DS-416 breakers each
containing four secondary contact blocks. The licensee identified
cracks in 4 out of 32 secondary contact blocks. The licensee
- conservatively reph ed all four blocks even though the cracks in three
l of the four blocks we. minor. The fourth block's cracking was
significant enough that there was a potential for small pieces to fall
! into the contact block fingers.
The inspector observed the inspection of 6 of the 8 breakers. The
electricians were thorough and conscientious. The inspector reviewed
the work order and post maintenance testing and determined they were :
adequate. The inspections were well controlled by operations to '
minimize the risk of an accidental reactor trip.
c. Conclusions l
The licensee's inspections were well controlled. The inspectors ;
concluded that the licensee's response and corrective actions were
adequate. The licensee identified cracks in 4 of 32 inservice secondary l
contact blocks. This IFI is considered closed.
M8.2 (Closed) Unresolved Item (URI) 50-348/96-04-05. NIS Intermediate Ranae
Compensatina Voltage Ad1ustment Below NIS SR Count Threshold
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On May 4. 1996, a resident inspector observed Instrumentation and
Control (I&C) technicians adjust the compensating voltage on Nuclear
Instrumentation System (NIS) intermediate range channels NI-35 and 36,
as documented in IR 96-04. By letter dated July 11, 1996, the vendor
confirmed that any adjustments to the compensating voltage when plant
power is below the bottom of the intermediate range. and the source
range (SR) level is less than 100 cps, would result in
undercompensation. In this letter, the vendor affirmed that adjustments
to the NIS intermediate range compensating voltage should not be
performed under the aforementioned conditions. Also, once compensating
voltage is properly set. additional adjustments should not be necessary.
The Precautions and Limitations of FNP-0-IMP-228.4. Nuclear
Instrumentation System Intermediate Range Compensating Voltage
Adjustment. Revision 4. dated June 7. 1995 are consistent with the
l vendor statements made in their letter dated July 3.1996.
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The I&C technicians that adjusted the compensating voltage of NI-35 and
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36. after the Unit 1 shutdown on May 4. 1996, did not fully understand
the implications of the IMP-228.4. Precautions and Limitations. They
adjusted the compensating voltage of NI-35 while it was indicating below
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10E-11 amps (i.e.. bottom scale) and its associated NIS SR channel NI-31
was indicating about 70 cps. As such, the I&C technicians adjusted NI-
35 contrary to IMP-228.4. Precautions and Limitations. Steps 5.3 and
5.4. which resulted in the inadvertent undercompensation of NI-35.
Subsequent investigation by the licensee, and discussions with the
vendor, concluded that the degree of undercompensation was not
significant enough to warrant any readjustment. The safety consequence
of having slightly undercompensated NIS intermediate range detectors is
insigni ficant. However, from an operational standpoint, failing to
clear P-6 would prevent the automatic energization of the associated SR
detector. Although, the operators could do so manually.
In the July 11. 1996 letter, the vendor also recommended that the
licensee should determine its own plant specific NIS SR level to ensure
proper compensating voltage adjustment rather than rely on a generic
range of 100 to 500 cps which is less exact and confusing to the I&C
technicians. In fact. a similar incident occurred on January 14. 1995
when a resident inspector witnessed the adjustment of NI-36 compensating
voltage while reactor power was below 10E-11 amps and SR counts were
fluctuating between 80 to 150 cps. For this and other reasons, the
licensee readjusted both NI-35 and NI-36 back to their original
compensating voltage settings.
The undercompensation of NIS intermediate range channel NI-35 was
accomplished contrary to the Precautions and Limitations of IMP-228.4
which is a violation of the procedural requirements of TS 6.8.1. This
violation is considered a repeat of a similar event that occurred on
January 14, 1995, and is identified as violation (VIO) 50-348/96-07-01.
Misadjustment of Unit 1 NIS Intermediate Range Compensating Voltage.
This violation effectively closes URI 50-348/96-04-05.
III. Enaineerina
El Conduct of Engineering
El.1 Chanaes. Tests and Experiments (CTEs) Performed In Accordance With 10
CFR 50.59
a. Insoection Scope (37701)
By letter dated April 29. 1996. the licensee submitted Revision 13 to
the Farley UFSAR for the time period of April 25. 1994. to November 4
1995. This letter also included a Summary Report of all changes, tests.
and ex3eriments that were completed under the provisions of 10 CFR 50.59
over t1e same time period. The licensee's April 29. 1996, summary
includes about 149 changes made during the subject period.
The Senior Project Manager from the Office of Nuclear Reactor Regulation
(NRR) at NRC headquarters conducted an assessment and inspection of the
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following licensee's activities to determine if the requirements of 10
l CFR 50.59 were satisfied.
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i e CTEs evaluated under 10 CFR 50.59 that were identified in the
j licensee's April 29. 1996. letter. The review also included:
i 1) Comparison of description of changes reported to the staff
- under 10 CFR 50.59 to the description of the changes
j contained in the licensee's 10 CFR 50.59 evaluations.
I 2) Comparison of the UFSAR changes to the changes contained in
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the licensee's 10 CFR 50.59 evaluations.
j 3) Selected design change packages.
j e The licensee's 10 CFR 50.59 screening process.
! e The administrative procedure associated with nuclear safety
evaluations.
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2 e Trai ing associated with 10 CFR 50.59 activities.
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i b. Observations and Findinas
l CTEs Performed Under 10 CFR 50.59 Identified in the Aoril 29. 1996
l Letter
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! Under the provisions of 10 CFR 50.59. a licensee may (1) make changes in
i the facility as described in the safety analysis report. (2) make
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changes in the procedures as described in the safety analysis report,
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and (3) conduct tests or experiments not described in the safety 3
analysis report, without prior Commission approval, unless the proposed
l CTEs involve a change to the TS incorporated into the license or an l
- unreviewed safety question (US0). The regulation defines a US0 as a i
i proposed action that (a) may increase the probability of occurrence or -
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i consequences of an accident or malfunction of equipment important to
- safety previously evaluated in the safety analysis report. (b) may
j create a possibility for an accident or malfunction of a different type
J than any previously evaluated in the safety analysis report, or (c) may
reduce the margin of safety as defined in the basis for any technical
specification.
The licensee's 10 CFR 50.59 evaluations are patterned after NSAC-125.
" Guidelines for 10 CFR 50.59 Safety Evaluations." June 1989. This
document requires that changes be evaluated against the appropriate l
FSAR TS. and NRC Safety Evaluation Report (SER) sections to determine ,
if there is need for revision. Specifically the criteria specified by
10 CFR 50.59 are broken down into seven (7) questions. For a change to
be made under 10 CFR 50.59, the answers to all seven questions must be
"no". The inspector reviewed the licensee's USQ criteria and determined
Enclosure 3
.. . . . - .. .
l -
!
11
they appropriately reflect the criteria of this regulation and that, if
followed accordingly, would ensure that changes are performed in
l accordance with this regulation.
l
The inspector performed an in-office review of the licensee *s summary to
determine the nature and safety significance of each change. Through 1
this review, the inspector selected the following changes for more '
l detailed review on site. The selected changes, which are listed below,
- included a variety of systems, different engineering disciplines. l
temporary modifications, and procedure changes. 1
REPORT IDENTIFIER TITLE
(from 4/29/96 letter)
l
l
1. ABN 94-0-0311 R0 Revision to reflect as-built plant.
2. DCP 94-1-8744-001 Electro-hydraulic control fluid pump
replacement.
3. DCP 95-1-8806-0-001 Removal of steam dump warming lines. l
4 DCP 95-1-8823-0-001 Temporary SWS return from CRACS. l
5. DCP 95-2-8847-0-001 Fuse modification for refueling :
water storage tank switches.
6. DCP B-88-1-4773-1-001 Sequencing for additional emergency
loads.
7. DCP B-90-2-7129-0-001 Containment emergency lighting.
8. DCP B-93-1-8536-0-002 Steam generator (SG) narrow range
level tap.
9. DCP B-93-2-8626-1-001 SG median signal selector. '
.
10. DCP S-91-1-7578-0-001 Undervoltage (UV) relay
modi fication.
11. DCP S-91-2-7662-0-008 RHR pump / motor coupling
modification.
12. DCP S-93-1-8587-0-001 Zinc addition and monitoring system.
13. DCP S-93-1-8684-0-003 Reactor coolant pump UV and
underfrequency modification.
14. DCP S-93-2-8546-0-001 Rod control power from motor
generator set.
15. FNP-2-ETP-2098, R0 Flow test of the TDAFW pump.
16. FNP-2-ETP-3032, R0 Procedure for Unit 2 Zinc addition.
17. FP 94-0302, R0(1) Isolation of SWS to containment
cooler.
18. PCN B-91-2-7432 R1 Deletion of CCW pump trip.
19. PCN S-91-1-7661. R5 RHR coupling modification.
20. REA 93-0121. R0 (S) Safety evaluation for containment
pressure-temperature analysis.
21. REA 95-0798 R0 (S) SFP cooling flow reduction.
22. SNC FS SECL, R0 (1) FSAR small break loss of coolant
accident modeling error.
23. SNC FS SECL, R0 (S) Condensate storage tank missile
3rotection.
24. SNC FS SECL, R0 (S) :SAR change operator action times.
Enclosure 3
'
l
'
.
i
12
25. SNC TS LS SECL R0(S) Peak clad temperature accounting
errors.
26. W SECL 93-196, R3 (S) Valve PCV-145 setpoint change.
27. W SECL 93-246. R0 (S) Reanalysis of inadvertent emergency
core cooling system at power.
l
The inspector reviewed these evaluations and determined that they were
correctly performed under 10 CFR 50.59. The evaluation packages
provided by the licensee, in addition to addressing the seven questions
in accordance with the NSAC guidance, contained UFSAR changes and safety
evaluations as required.
The inspector compared the description of changes reported to the staff
i under 10 CFR 50.59 in the April 29, 1996, report to the description of
the changes contained in the licensee's 10 CFR 50.59 evaluations. The
'
inspector identified six descriptions in the licensee's report to the
NRC (Items 9,12,14,16,19 and 20 above) that were either incomplete,
did not identify the nature of the change (e.g. , design change,
procedure change) or used plant-specific acronyms that were not readily
recognizable. Although 10 CFR 50.59 states that description of the CTEs
in the licensee's report to the NRC may be brief, since the NRC staff
and the general Jublic utilize these reports to assess the nature of
these changes, t1e licensee should attempt in future reports to improve
the descriptions provided in the areas identified.
The inspector compared the UFSAR changes identified in the 10 CFR 50.59
evaluations to the actual changes contained in Revision 13 to the UFSAR.
No discrepancies between these two documents were identified.
The inspector reviewed six design change packages (Items 7, 9, 10, 11,
12 and 18) to determine if they contained any additional information
(other than that 3rovided by the licensee) that could be used to support
the findings of t1e 10 CFR 50.59 evaluations. The inspector concluded
that the design change Jackages did not provide any additional
information, and that t1e 10 CFR 50.59 evaluations provided by the
licensee, which are part of the design change packages, contain all the
information necessary to evaluate the CTEs performed by the licensee
under 10 CFR 50.59.
In reviewing the design change packages the inspector observed that the
10 CFR 50.59 evaluation process for revisions to design changes could be
confusing to someone who is unfamiliar with the process. The licensee
recently changed the process for offsite design changes (design changes
made at corporate headquarters in Birmingham), but retained the old
process for onsite design changes (design changes made at FNP).
Under the old procedure, the licensee would perform an initial 10 CFR
50.59 review. However, subsequent revisions to the package only cover
changes made in the most recent revision. Therefore, design change
packages may contain more than one valid 10 CFR 50.59 evaluation and all
Enclosure 3
. _ _ _ _ . .
,
-
.
.
13
the revisions would have to be read to obtain an understanding of all
the design changes made.
Under the new procedure for offsite design changes, the most recent 10
CFR 50.59 revision replaces all the 10 CFR 50.59 evaluations previously
issued for the design change. This is therefore a "living document"
for each design change and does not recuire reading previous revisions
to understand the entire scope of the cesign change. For minor design
changes that do not meet the threshold for requiring a 10 CFR 50.59
review (i .e. , changing the location of a support), the most current 10
CFR 50.59 evaluation remains valid. These minor design changes are
identified in the design change package check list, which is normally
located at the front of the package.
The inspector did not find that this resulted in any errors; however,
the potential exists if someone from the licensee's staff becomes
involved who is unfamiliar with the design change process (see
discussion below on 10 CFR 50.59 training).
10 CFR 50.59 Screenina Process
The inspector reviewed approximately 100 screening evaluation documents
for change packages that the licensee determined did not satisfy the
criteria requirement for perfonnance of a 10 CFR 50.59 review. Most of
these documents cover the July 1, 1996, to July 16, 1996, time period.
The inspector concluded, based on the fact that none of the screening l
documents reviewed were incorrectly evaluated (exceeded the threshold 1
that would require a 10 CFR 50.59 review), that the licensee's screening
process is acceptable.
The Administrative Procedure Associated With Nuclear Safety Evaluations
The inspector reviewed Farley Administrative Procedure FNP-0-AP-88,
" Nuclear Safety Evaluations." Revision 0. December 11. 1990, that is
applicable to all Farley Project activities that require 10 CFR 50.59
evaluations. The inspector concluded, based upon this review, that
acceptable formal procedural guidance has been established for
implementing the requirements of 10 CFR 50.59 for proposed CTEs related
to: (1) assessing and documenting if 10 CFR 50.59 applies: (2) assessing
l
'
and documenting if a change to the plant TS or an unreviewed safety
question is involved: (3) the preparation of 10 CFR 50.59 safety
evaluations: (4) making 10 CFR 50.59 applicability determinations; and
l (5) answering the questions in 10 CFR 50.59(a)(2) that define an
'
unreviewed safety question.
Trainina Associated With 10 CFR 50.59 Activities
l
The inspector reviewed the licensee's training program, which is
contained in the Farley Technical Staff and Management document TSM-510.
" Nuclear Safety Evaluations." May 1996, and associated training material
Enclosure 3
l
_ _ _. __ _. .
___ _ __-- _- _ _ . .- _ _ _ . _ - _
,
- -
.
.
14
l used by the training department. The manual and training material
include: (1) ZyIndex use: (2) examples of 10 CFR 50.59 evaluations,
violations, and screening material for 10 CFR 50.59 applicability; (3)
10 CFR 50.59 evaluation guidelines: (4) NSAC 125 and guidance related to
its use; and (5) Administrative Procedure FNP-0-AP-88. The inspector
concluded'that the manual and training material used provide sufficient
information for the licensee's staff to perform acceptable 10 CFR 50.59 '
reviews.
As previously mentioned under the 10 CFR 50.59 evaluations discussion,
the inspector observed that the evaluation process for revisions can be
confusing to someone unfamiliar with the process. In reviewing the
procedures and training aspects of the licensee's program, the inspector
did not find any information related to the evaluation of revisions.
This observation was discussed with the licensee and it is the
inspector's understanding that the licensee is modifying the employee
training and/or the procedures manual to address how revisions to
evaluations, covered under 10 CFR 50.59 process, are handled.
c. Conclusion
Based on in-office review of the licensee's April 29, 1996, submittal,
which contained a summary report en 10 CFR 50.59 changes, and the onsite
audit of the licensee's evaluations. procedures manual, and training
program, the inspector concludes that the licensee has complied with the
provisions of 10 CFR 50. 59 for the changes listed in the summary report. l
El.2 Pressure Sensor Resoonse Time Testina TS SER Commitments (37551) j
During the period from June 10 through August 13, 1996, the Safety Audit
and Engineering Review (SAER) group conducted a routine audit of the FNP
" Surveillance Testing Program Administration." During this audit., SAER
auditors identified that several licensee commitments stated in NRC SER
dated September 28, 1995 and the TS Bases had not been properly .
implemented. l
By letter dated August 17, 1994, as supplemented by letters dated June
15 and August 11, 1995. SNC had submitted an operating license amendment
request to eliminate TS surveillance requirements for periodic response
time testing (RTT) of pressure and differential 3ressure sensors in the
Reactor Trip System (RTS) and Engineered Safety reature Actuation System
(ESFAS). Included in this request were several commitments regarding >
revisions to plant procedures and administrative controls. The NRC SER
dated September 28, 1995, approved SNC's TS amendment request based upon
these commitments, which were also included as part of the TS Bases.
However, the licensee failed to properly fulfill its commitments prior
to implementing the TS amendment changes approved by the NRC (i.e.,
Facility Operating License amendment numbers 116 for Unit 1 and 108 for
Unit 2). This resulted in a SAER audit finding.
Enclosure 3
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.
.
15
>
Of the several commitments made by SNC in their letters to the NRC. and
,
affirmed in the NRC SER, three specific commitments were not
accomplished. These commitments, as stated in the SER. were as follows:
(1) Revise applicable plant surveillance test procedures to
>
stipulate that allocations for pressure sensor response times must
2
be verified by performance of an appropriate RTT prior to placing
'
a sensor in o)erational service and re-verified following
maintenance tlat may adversely affect sensor response time, such
as replacing the sensing assembly:
(2) Revise plant procedures and other appropriate administrative
i controls to stipulate that pressure sensors utilizing capillary
J
tubes, e.g., containment pressure, must be subjected to RTT after
initial installation and following any maintenance or modification
activity which could damage the capillary tubes:
) (3) Utilize allocated sensor response times in accordance with the
4
methodology contained in Section 9.0 of WCAP-13632. Revision 2. to
verify total RTS and ESFAS channel response time.
,
1
Item (1) was only partially addressed by surveillance test procedure
changes made for Unit 1. and not at all for Unit 2. Item (2) was
entirely overlooked for both units. And, item (3) was addressed by
surveillance test procedure changes for Unit 1 but not for Unit 2.
Failing to fulfill formal commitments made to the NRC constituted a
. deviation (DEV) identified as DEV 50-348. 364/96-07-02. Failure To
Fulfill Pressure Sensor RTT Commitments.
E1.3 Snubber Reduction Proaram (SRP) - Unit 1
a. Insoection Scooe (37550)
A Region II reactor inspector reviewed the SRP documentation, discussed
,
the program with the engineers, and walked down the main steam and
auxiliary feed water lines for the snubber removal and support
- modifications on Unit 1 in order to determine if licensee activities
complied with industrial standards, regulatory recuirements, and
! licensee commitments. The inspector also reviewec the theory of snubber
reduction, new seismic s)ectra generation, and ASME Code Case N-411
application for the snub)er reductions.
. b. Observations and Findinas
, The inspector discussed the SRP with the licensee engineers and
management. The purpose of the SRP was to reduce the total number of
snubbers in the plant in order to reduce snubber maintenance cost.
The licensee performed the snubber reduction as a plant modification.
As part of the modification review, the inspector reviewed portioris of
Enclosure 3
!
__ ._ _ ___ __ _ . _ _ _ _ ____ __-_.
.
16
Revised Stress Calculation No. 90. Snubbers Reduction - Main Steam
Piping, Rev. 9. The calculation concluded that .
-
The pi3e stresses met ASME code requirements.
'
-
19 snu)bers out of 40 snubbers were no longer required and removed
(a 48 percent reduction).
j -
10 pipe supports with increased loads but only one of them
,'
required field modification due to a load capacity limitation of
the sway strut for this support. i
-
All the anchor loads were less than original design loads and
, acceptable. !
-
All sup) ort movements had been reviewed and found to be !
accepta)le.
The inspector concluded that the portion of the stress calculations
reviewed was adequate.
]
! To get more benefit from the snubber reduction program, the licensee
further applied the ASME Code Case N-411 to the snubber reduction
analysis in the reactor building and portions of the auxiliary building .
resulting in a significant snubber reduction up to 60 percent. The i
licensee plans to apply the Code Case N-411 to the MS line inside the '
auxiliary building for the stress calculation reviewed in order to
- remove more snubbers. The Code Case N-411 allowed the licensee to use
spectra with specific relaxed damping values.
The inspector discussed with the licensee engineers and concluded that
<
the theory and steps for generating the new spectra to meet N-411
requirements were adequate.
However, the inspector noted a documentation weakness in this process in
that the licensee had not clearly documented their evaluation that the
results of several stress calculations had been reviewed to meet the
i conditions required by using Code Case N-411. The licensee plans to
revise the already completed stress calculations for the SRP and, in the
future. add a clear statement to indicate that the conditions for using
Code Case N-411 have been reviewed and evaluated to meet the
applicability requirements after the completion of the stress
calculation.
I The inspector walked down the MS and auxiliary feedwater lines with
'
licensee engineers to inspect the pipe supports in the field, including
, the modifications for the snubber reduction, in order to assess the
effectiveness and quality of the supports for the SRP and to compare
, them with the documented drawings. The inspection elements included
dimensions, member sizes, component sizes, weld sizes and symbols, base
plate sizes, anchor bolt diameters and edge distances, sway strut sizes
, and swing angles, etc. The discrepancies found by the inspector are
listed below:
,
'
Enclosure 3
r
4
'
.
17
Suooort No. Rev. System Discreoancies
No.
MSB144-R11 A MS Pre-existing Discrepancy:
Base plate in Item 4 was measured 3/4"
thick. The drawing specifies 1" thick.
PCN-B078-063 Rev. 3 approved the 3/4" base
plate, but the drawing was not updated.
MSB145-R11 A MS Pre-existing discrepancies: j
l
(1). A 5 1/2" horizontal edge distance
was measured on the right side anchor
bolts at the base plate. The drawing
specifies 3".
(2). A 1/8" fillet weld was measured at
the bottom of the horizontal 6" X 6" tube
and the base plate. The drawing specifies
5/16".
Design change package (DCP) discrepancy:
(3). The sway strut was off more than 5
degrees horizontally which exceeded the
Grinnell manufacturer installation
tolerance.
MS-R90 N/A MS DCP discrepancy:
The sway strut support exists in the
field. The stress isometric drawing
D-514771 showed the support was
deleted.
MS-R91 N/A MS DCP discrepancy:
The snubber support MS-R91A (one snubber)
exists in the field. The stress isometric
drawing D-514771 showed the support was
completely deleted.
Enclosure 3
. _ . - _ - . .- .. .- . __ . __ ____
.
18
MS-R95 N/S MS DCP discrepancy:
The support with one snubber exists in the
field. The stress isometric drawing D-
514771 showed the support was deleted.
AFW-R64 A AFW DCP discrepancies:
(1). A 5" wide flange beam was measured
in the field. The drawing specifies the
wide flange 6"x15.5 #/ft which indicated
the installed beam was undersize.
(2). A sway strut distance was measured
2*-21/2" from the pipe centerline to face
of steel. The drawing specifies 2*-1
9/16".
AFW-R65 C AFW DCP discrepancies:
(1). Two weld connections at the top and
bottom flanges of the same size of wide
flange W5x16, items 10 and 11, were not
fillet welds as the drawing specifies
because it was im]ossible to perform the
fillet welds at t1ese locations due to the
same size of the wide flanges.
(2). No weld size and symbol were shown
in the drawing for the weld connection
between item 10 and the existing steel.
AFW-R67 A AFW Pre-existing discrepancies:
(1). No weld sizes and symbols were
specified between items 1, 2, 3. and 4.
(2). The orientation of item 3 was not
speci fied.
DCP discrepancy:
(3). A load pin and two studs for pipe
clamps were not double nutted, nor were
there staked threads to prevent the nuts
l from backing off.
l
!
Pre-existing discrepancies refer to those that existed prior to the
i modification for the snubber reduction. DCP discrepancies are those
'
that occurred after the com]letion of modification for the DCP
implementation for the snub)er reduction. The discrepancies found above
between the documented drawings and the field installation collectively
l constitute a violation of 10 CFR 50 Appendix B, Criteria V which states
l
Enclosure 3
.. . . _ _ .__ _ .
-
.
19 !
in part, that activities affecting quality shall be accomplished in
accordance with documented drawings. The discrepancies above are
considered as additional examples of Violation 50-348, 364/96-10-01. but
are only applicable to Unit 1.
c. Conclusions
A violation was identified for the pipe supports which had multiple
discrepancies between the field installation and the approved drawings.
This violation is considered part of the Notice of Violation issued in
IR 96-10, and should be addressed in the SNC response to VIO 50-348.
364/96-10-01. One weakness, resolved during the inspection, was
identified for the unclear or unverifiable documentation for reviewing
the results of the stress calculation to meet the requirements for the )
application of ASME N-411 code case.
E8 Miscellaneous Engineering Issues (92903) i
E8.1 (Closed) IFI 50-348/96-06-05. Inocerable And Possibly Stuck Unit 1
Incore Detector
On July 18. 1996, a resident inspector observed the performance of an
incore flux map on Unit 1 using the moveable incore detector system '
(MIDS). During the flux map. the )osition indication for detector C )
became so erratic and unreliable tlat the responsible nuclear engineer
was unable to determine if the detector could be placed back in storage.
FNPIR 96-192 was written to investigate the problem and appropriate
precautions were taken to preclude containment entry. The licensee
subsequently repaired the position indicator for MIDS detector C and
confirmed it was properly stored. Later. the inspector observed another
monthly incore flux map and verified that detector C position indicated
correctly. This IFI is closed.
E8.2 (00en) IFI 50-348. 364/95-18-06. Electrical Distribution System
Functional Insoection (EDSFI) - Dearaded Voltaae Commitments
l
URI 50-348. 364/92-17-05 related to degraded grid voltage relay setting
specified in the TS was closed out in IR 50-348, 364/95-18 based on an
NRC SER. dated August 9. 1995, which was included as Attachment 1 to the
inspection report. Section 4.0 of this SER identified two pending
commitments by SNC. These commitments involved: (a) changing the TS to
include LCO: and (b) surveillance requirements for degraded grid alarm
relays, and describing the offsite system operating voltage range in the
next FSAR update. i
1
1
The NRR inspector verified that the commitment related to describing the ,
offsite system operating voltage range was included in Revision 13 to l
the UFSAR submitted to the NRC by letter dated April 29. 1996. This I
closes Item 4(b) of this commitment item identified in the NRC SER. ;
,
I
l Enclosure 3
-
-
.
.
20
The licensee's commitment to change the TS to include LCO and
surveillance requirements for degraded grid alarm relays, as per Item
4(a) of the NRC SER, will not be completed until the Improved TS package
is submitted and approved by the staff. The licensee is currently
planning to submit the Improved TS package in April 1997 and NRC
approval will take about 6 to 8 months.
IV. Plant Sucoort
1
R1 Radiological Protection and Chemistry Controls I
R1.1 Tours of the Uni _t 1 and 2 Radioloaically Controlled Areas (RCA) - 71750
During the course of the inspection period the resident ins)ectors
conducted numerous tours of the auxiliary building RCA for Jnits 1 and
2. In general. HP control over the RCA, and the work activities
conducted within it, were good. Material condition and housekeeping in
the Unit 1 and 2 RCA were typically well maintained, minor exceptions
being the PPRs (as discussed in Section 02.1).
Unit 2 Soent Fuel Insoection
On August 8. 1996, a resident inspector observed the licensee and fuel
vendor examine four Uriit 2 Cycle 5 spent fuel assemblies using an
underwater camera. These assemblies were being considered for reuse in
the upcoming Unit 2 Fuel Cycle 12. Based on past industry experience,
the licensee and vendor were specifically ins)ecting the upper nozzle
block bulge joint for excessive corrosion. T1e inspection activities
went smoothly. Appropriate radiological and foreign material controls
were in place and effectively implemented. However, one person's key
card came loose from his security badge and fell into the Unit 2 SFP.
The card was subsequently retrieved a couple of days later.
P4 Staff Knowledge and Performance in Emergency Preparedness
P4.1 Emeraency Drill (71750)
A resident inspector observed the conduct of an Emergency Preparedness
drill conducted on July 30. 1996. The inspector observed activities in
the plant simulator, emergency offsite facility and technical support
center. The exercise was well coordinated by the emergency planning
sta f f..
S1 Conduct of Security and Safeguards Activities
S1.1 Routine Observations of Plant Security Measures (71750)
During routine inspection activities, resident inspectors verified that l
portions of site security program plans were being properly implemented.
This was evidenced by: proper display of picture badges by plant
Enclosure 3
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-
.
.
21 !
personnel; appropriate key carding of vital area doors: adequate
stationing / tours of security personnel: proper searching of '
packages / personnel at the Primary Access Point and SWIS: and adequacy of
compensatory measures (i.e.. posting of guards) during disablement of
vital area barriers. Security activities observed during the inspection
period were well performed and appeared adequate to ensure physical
protection of the plant. Guards were observed to be alert and attentive i
,
while stationed at disabled doors and access covers to critical i
underground equipment (e.g. SWS valve boxes). Posted positions were
manned with frequent relief.
F2 Status of Fire Protection Facilities and Equipment
F2.1 Kaowool Fire Barriers (Units 1 and 2) - 71750
a. Insoection Scope
On July 24. 1996, a resident inspector identified that the Kaowool
protecting 01E21MOV8107. CHARGING LINE ISOLATION VALVE had pulled away
from the motor-operated valve (MOV) junction box exposing approximately
two inches of conduit. During the period August 22-23. 1996, the
inspector identified seven additional safety related valves with Kaowool
discrepancies. These were:
e 01P16V507. 1C SW PUMP TO A HDR ISO
e 01E21MOV81308. CHG PUMP SUCT HDR ISO ,
o 01E21MOV81318. CHG PUMP SUCT HDR ISO l
e 01E21LCV115D. RWST TO CHG PMP ,
e 01P16V003A. SW TO 1A CCW HX !
e 02E21V8130A. CHG PUMP SUCT HDR ISO 4
b. Observations and Findinas
The inspector identified that the Kaowool had slumped away from the MOV
junction boxes exposing one to two inches of the conduit for the
identified MOVs. The inspector notified the licensee as each deficiency
was identified so that fire watches could be established as necessary.
The inspector noted that in some cases the flammastic used to seal the
Kaowool and Zetex covering to the MOV junction box had separated and
allowed the Kaowool to droop away from the MOV. In the majority of
cases no flammastic was used to seal the Kaowool and the installation
depended on the Kaowool and Zetex stiffness to hold the Kaowool against
the MOV.
On August 28. 1996, the inspector noted that the licensee had made
repairs to 8130B and 81318. These repairs censisted of filling the gap
between the Kaowool and the MOV with flammastic. The flammastic was
installed to fully cover the end of the Kaowool and then tapered to
become narrower at the MOV junction. It did not appear that an effort
Enclosure 3
.
. - _ . .- .
.
22
had been made to close the ga) and then seal the joint with flammastic.
The inspector was concerned tlat these were not appropriate repairs.
!
The inspector reviewed FNP-0-PMP-507. Kaowool Installation Procedure.
Revision 5 and FNP-0-FSP-43. Visual Inspection of Kaowool Wraps.
Revision 5. Neither procedure specifically referenced installation or
inspection of the Kaowool at the MOV termination. However. PMP-507.
step 6.2.8. stated that "In areas such as floors. walls, and ceilings
where the blanket wrap ends fire protection seals shall be installed as t
specified using mastic coatings such as..." It did not specifically 1
address terminations at the MOV junction box. Also FSP-43 did not
specifically address inspection of the Kaowool terminations at the MOVs. '
c. Conclusions
The inspector could not conclude that plant procedures 3rovided adequate
guidance to control the installation and inspection of (aowool for MOV
conduits, or that existing guidance was being adequately applied. This
item is identified as URI 50-348, 364/96-07-03. Inadequate Installation
and Inspection of Kaowool Fire Barriers. Resolution of this item will
require further information on the specific 10 CFR 50. Appendix R
requirements of installed Kaowool and results of the licensee's
- investigation into the total scope of the problem. l
1
F8 Miscellaneous Fire Protection Issues (92904) '
,
F8.1 (Ocen) IFI 50-348. 364/96-02-03. Pre-action Sorinkler System Failures
In March of 1996, the licensee initiated two FNPIRs (1-96-71 and 2-96-
78) to investigate the high percentage of the pre-action sprinkler
system failures. In particular, the clappers inside the Grinnell model
A-4 multimatic valves were failing to trip open, either automatically or
manually. The licensee assembled a formal root cause team to determine
the cause of the problems and recommend corrective actions. Although,
neither the root cause team or the vendor was able to determine the
- ultimate cause of the problems, a number of recommendations were made.
These included numerous preventative and corrective maintenance
procedure enhancements, replacement of all internal diaphragms.
- replacement of all preaction solenoid valves, detailed internal
i
inspections (including dimensional measurements of moving parts),
cleaning of all multimatic valves, and retesting of all multimatic
1 valves. Furthermore, the surveillance frequency for all multimatic
valves was accelerated from once every 18 months to two months, then six
j months and ultimately every year.
However, since this major recovery effort, additional clapper failures
have occurred. On August 12, 1996, two clappers (2A-51 and 2A-100)
failed to trip when they should have following an inadvertent actuation
1
'
of the Unit 2 pyro panel (FNPIR 2-96-209). Then again. on August 22.
1996, during conduct of the two month accelerated surveillance test.
Enclosure 3
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clapper 2A-48 failed to trip either automatically or manually (FNPIR 2-
96-225). The licensee has reassembled its root cause team and continues
to work closely with the vendor. This IFI remains open.
V. Manaaement Meetinas and Other Areas
X1 Review of UFSAR Commitments
A recent discovery of a licensee o)erating their facility in a manner
contrary to the UFSAR description lighlighted 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 inspector reviewed the applicable portions
of the UFSAR that related to the areas inspected. The inspectors
verified that the UFSAR wording was consistent with observed plant
practices, procedures and/or parameters. Only one exception was
identified, as follows:
e UFSAR Appendix 3K, Section 3K.4.1.2.7 specifies the flooding
detectors are set to activate at a level of six inches above the
127 foot floor elevation. However, the detectors are set at four
inches above the floor which appears to be conservative.
X2 Exit Meeting Summary
The resident inspectors presented the inspection results to members of
licensee management on September 5. 1996, after the end of the
inspection period. The licensee acknowledged the findings presented.
The resident inspectors asked the licensee whether any materials
examined during the inspection should be considered proprietary. No
proprietary information was identified.
Enclosure 3
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PARTIAL LIST OF PERSONS CONTACTED
.
Licensee
W. Bayne, Chemistry / Environmental Superintendent
R. Coleman, Maintenance Manager .
, S. Fulmer Technical Mtnager !
l H. Garland Assistant Maintenance Manager
D. Grissette. Operations Manager :
R. Hill. General Manager - Farley Nuclear Plant
'
R. Martin, Su)erintendent Operations Support
M. Mitchell, dealth Physics Superintendent
R. Monk. Engineering Support Supervisor - Equipment Evaluation
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C. Nesbit. Assistant General Manager - Support )
,
J. Odom. Superintendent Unit 1 Operations ;
J. Powell, Superintendent Unit 2 Operations
L. Stinson, Assistant General Manager - Plant Operations
J. Thomas, Engineering Support Manager i
B. Yarce, Plant Modifications and Maintenance Support Manager
W. Warren. Engineering Support Supervisor - Performance Review
G. Waymire, Safety Audit and Engineering Review Site Supervisor
.NE l
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B. Siegel. Senior Project Manager - Farley Nuclear Plant l
I
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Enclosure 3
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INSPECTION PROCEDURES USED
IP 37550: Engineering
IP 37551: Onsite Engineering
IP 40500: Effectiveness of Licensee Controls in Identifying. Resolving, and
,
Preventing Problems
l IP 61726: Surveillance Observations
IP 62703: Maintenance Observations
IP 62707: Maintenance Observations
i IP 71707: Plant Operations
IP 71750: Plant Support Activities
,
IP 92902: Followup - Maintenance
( IP 92903: Followup - Engineering
IP 92904: Followup - Plant Support
,
ITEMS OPENED, CLOSED, AND DISCUSSED
! Opened
Iygg Item Number Status Descriotion and Reference
VIO 50-348/96-07-01 Open Misadjustment of Unit 1 NIS
,
Intermediate Range Compensating
l Voltage (Section M8.2)
DEV 50-348, 364/96-07-02 Open Failure To Fulfill Pressure Sensor
! RTT Commitments (Section E1.2)
l URI 50-348, 364/96-07-03 Open Inadequate Installation and l
,
Inspection of Kaowool Fire Barriers- 1
l (Section F2.1)
l
l Closed
Tygg Item Number
_
Status Descriotion and Reference
l IFI 50-348, 364/96-06-02 Closed Reactor Trip Breaker Secondary
i
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Contact Block Cracking (Section
M8.1)
IFI 50-348/96-06-05 Closed Inoperable And Possibly Stuck Unit 1
Incore Detector (Section E8.1)
URI 50-348/96-04-05 Closed NIS Intermediate Range Compensating
,
Voltage Adjustment Below NIS SR
! Count Threshold (Section M8.2)
!
- Enclosure 3
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Discussed
l
T_.ype Item Number Status Description and Reference
IFI 50-348, 364/95-18-06 Open EDSFI - Degraded Voltage Commitments
(Section E8.2)
l IFI 50-348. 364/96-02-03 Open Pre-action Sprinkler System Failures
(Section F8.1)
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LIST OF ACRONYMS USED
l ABN As-built Notice
l AP Administrative Procedure
ASME American Society of Mechanical Engineers
CCW Component Cooling Water
CFR Code of Federal Regulations
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CRACS Control Room Air Conditioning System
CTE Changes. Tests, and Experiments
DCP Design Change Package
DG Diesel Generator
DEV Deviation
DR Deficiency Report
EDG Emergency Diesel Generator
EMP Electrical Maintenance Procedure
EDSFI Electrical Distribution System Functional Inspection l
EPB Emergency Power Board
ESFAS Engineered Safety Feature Actuation System
ETP Engineering Test Procedure
FHP Fuel Handling Procedure
FNP Farley Nuclear Plant
FNPIR Farley Nuclear Plant Incident Report
FOL Facility Operating License
HELB High Energy Line Break
HP Health Physics
HX Heat Exchanger
IAW In Accordance With
I&C Instrumentation and Control [ Department]
IFI Inspector Followup Item
IMP Instrumentation Maintenance Procedure
IP Inspection Procedure
IR Inspection Report
LCO Limiting Condition for Operation
MCB Main Control Board '
MCR Main Control Room
MIDS Moveable Incore Detector System
MOV Motor-operated Valve
MS Main Steam ,
MTG Main Turbine Generator
Enclosure 3
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NIS Nuclear Instrumentation Lfstec
NRC U.S. Nuclear Regulatory Co m..,sion
NRR Office of Nuclear Reactor Regulation
PCN Production Change Notice
PDR Public Document Room
PMP Plant Maintenance Procedure
, PPR Piping Penetration Room
'
RCA Radiologically Controlled Area
REA Request for Engineering Assistance
RTB Reactor Trip Breaker
RTS Reactor Trip System
RTT Response Time Test
SAER Safety Audit and Engineering Review
SER Safety Evaluation Report
SFP Spent Fuel Pool
SNC Southern Nuclear Operating Company
S0P System Operating Procedure
SR Source Range
SRP Snubber Reduction Program :
'
STP Surveillance Test Procedure
SWS Service Water System
SWIS Service Water Intake Structure
TDAFW Turbine Driven Auxiliary Feedwater
TO Tag Order
TS Technical Specifications
UFSAR Updated Final Safety Analysis Report
URI Unresolved Item
US0 Unreviewed Safety Question
UV Undervoltage
VIO Violation
WO Work Order
!
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Enclosure 3
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