ML20133F692
| ML20133F692 | |
| Person / Time | |
|---|---|
| Site: | Farley  |
| Issue date: | 12/23/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20133F684 | List: |
| References | |
| 50-348-96-13, 50-364-96-13, NUDOCS 9701140327 | |
| Download: ML20133F692 (52) | |
See also: IR 05000348/1996013
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l U.S. NUCLEAR REGULATORY COMMISSION (NRC)
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REGION II
l- Docket Nos: 50-348 and 50-364
( License Nos: NPF-2 and NPF-8
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Report No: 50-348/96-13 and 50-364/96-13
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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
l Dates: October 13 - November 23, 1996
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Inspectors: T. Ross. Senior Resident Inspector
i J. Bartley, Resident Inspector
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J. Blake Reactor Inspector (Sections M1.2 and
M1.3)
M. Ernstes. Operator Licensing Examiner
(Sections 02.2 and 02.3)
E. Girard. Reactor Inspector (Section E8)
G. Kuzo. Senior Radiation Specialist (Sections
R1.1 R1.2. R2.2. R3. R6. and R7)
N. Merriweather. Reactor Inspector (Section
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El.1)
W. Miller. Reactor Inspector (Sections F2 F3.
FS. F6 F7. and F8)
Approved by: P. Skinner. Chief. Projects Branch 2
Division of Reactor Projects
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! Enclosure 2
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9701140327 961223
PDR ADOCK 05000348
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EXECUTIVE SUMMARY
, Farley Nuclear Power Plant. Units 1 And 2
l NRC Inspection Report 50-348/96-13, 50-364/96-13
This integrated inspection included aspects of licensee operations,
engineering maintenance, and plant support. The report covers a 6-week
period of resident and regional inspections.
I Ocerations
e Operations performed well in controlling plant conditions during Unit I
steady state full power operation and Unit 2 shutdown. The conduct of
l Operations personnel and management was consistently in compliance with
j procedures ar.d regulatory requirements (Section 01).
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e Shift operators remained very attentive to plant conditions, and were
quite knowledgeable of plant status and ongoing activities. However,
the shift superintendent needs to consistently ensure that distracting
activities in main control room (MCR) are kept to a minimum (Section
l 01.1).
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i e The defueling and refueling of Unit 2 was accomplished in a )rofessional
i and competent manner: although, there was a considerable num)er of minor
i instances where foreign objects were found in P.he reactor cavity and-
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spent fuel pool (SFP) (Section 01.2).
e Operators responded well to a Unit 2 solid plant pressure transient
(Section 01.4).
l e Overall housekeeping and abysical conditions were generally just
adequate. However, houseceeping in the Unit 2 radiologically controlled
area (RCA) (especially the piping penetration rooms, decontamination
room, and new fuel storage area) was considerably improved over previous
outages (Section 02.1).
e Safety system walkdowns verified selected systems were properly aligned
and capable of fulfilling their design function (Sections 02.2 and
02.3).
e An unresolved item was identified concerning the interpretation of
technical specification (TS) requirements for penetration room
filtration (PRF) system operability requirements (Section 02.6).
j e Licensee efforts to identify. resolve, and prevent problems remained
effective (Section 07.1).
e Conduct of Nuclear Operations Review Board met TS requirements and
appeared thorough (Section 07.2).
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Enclosure 2
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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 (Section M1.1).
e Unit 2 service water system code boundary valve replacement activities
appeared to be conducted in a manner consistent with the licensee's ;
quality programs. and reflected the licensee's understanding of the
relative risk importance of this system (Section M1.2).
e The original scope of steam generator (SG) inspections, and subsequent
expanded scope, demonstrated the licensee's apparently conservative
approach to determining the structural integrity of the Unit 2 SGs
(Section M1.3).
e Several major maintenance, modification, testing, and inspection
activities were well planned and implemented during the Unit 2 refueling
outage (Section M1.4. 5. 6, 8. and 11).
e A poor maintenance work practice resulted in the entry of foreign
material into the Unit 2 reactor coolant pump seal injection system
(Section M1.10).
Enaineerina
e Design change packages and plant modifications were developed and
accom)lished in an acceptable manner (Section El.1 and 2). Engineering
and t1e maintenance craft interfaced well during modification work
(Section El.1 and applicable M1 sections).
e An unresolved item was identified regarding a design issue associated
with the Unit 1 and 2 SG common tap for steam flow and water level not
meeting IEEE-279 (Section E1.3).
e The Unit 2 control rod test and evaluation program pursuant to NRC
Bulletin 96-01 was comprehensive and satisfactorily verified control rod
operability (Section E1.4)
e The remaining open commitments for Generic Letter 89-10 were completed
satisfactorily (Section E8).
Plant Suocort
e In general, radiation work permit (RWP) guidance was adequate for
routine RCA and the Unit 2 eleventh refueling outage (U2RF11)
activities. Except for one individual, all personal exposures were less
than administrative limits and were within 10 CFR Part 20 limits. A
Enclosure 2
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violation was identified for two examples of inadequate implementation
of RWP dressout requirements (Section R1.1).
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o The "As Low As Reasonably Achievable" program guidance and
implementation were acceptable, with no negative trends identified
(Section R1.2). ;
e Health Physics (HP) control over the RCA. and the work activities
conducted within it, were good. Material condition and housekeeping in !
the Unit 2 RCA. considering ongoing outage activities, were much better
than in the past (Section R2.1).
e No significant concerns were identified regarding radiation monitoring
system (RMS) operability or supplied breathing air equipment (Section
R2.2).
e Abnormal effluent releases have increased (Section R3).
e The HP organization and staffing provided ap3ropriate radiation
protection coverage of routine and outage jo) evolutions (Section R6).
e Proposed audits of refueling outage radiation protection activities were
adequate: the planned use of outside auditors to assist was considered a
program enhancement (Section R7).
- Security activities continued to be performed in a conscientious and
capable manner assuring the physical protection of protected and vital
areas (Section S1.1).
e A violation was identified for failing to search a vehicle prior to ;
entering the protected area (Section S8.1),
o The number of outstanding fire protection system work requests was high.
Corrective maintenance on degraded fire protection systems was being !
accomplished in a timely manner. Corrective actions have been effective :
in improving fire pump reliability. However, the root cause analyses of
frequent automatic pre-action sprinkler system failures has not been
effective. A program weakness was identified in that these sprinkler
systems were not being maintained in their normal design configuration.
Daily fire protection status reports were considered a positive means of
identifying degraded fire protection systems and implementing the
appropriate compensatory measures (Section F2.1).
- Surveillance tests of fire protection systems and features met the
requirements of the Updated Final Safety Analysis Report (UFSAR) or
evaluations had been provided to justify the deviations (Section F2.2).
e Fire protection program implementing procedures met the intent of the
NRC guidelines and requirements. Procedure implementation and general
Enclosure 2
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housekeeping related to the control of combustibles within the plant
were satisfactory (Section F3).
e Fire brigade organization and training met the facility's procedure
requirements and performance of the fire brigade during a drill was good
(Section F5).
e Coordination and oversight of the facility's fire protection program met
UFSAR commitments. Responsible personnel worked together as a team,
along with coordination by the Fire Marshall, to implement the site fire
protection program (Section F6).
e Audits and assessments of the fire protection program were thorough with
corrective actions taken on major discrepancies in a timely manner. l
However, resolution on recommendations and comments to enhance the fire
protection program were not timely (Section F7).
e Evaluations of fire protection related Information Notices (IN) were
appropriate and the recuired corrective actions had been completed. l
except for IN 93-41 anc IN 95-36 (Section F8).
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Enclosure 2
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Reoort Details
Summary of Plant Status
Unit 1 oaerated continuously at 100% power for the entire inspection period.
On Novem)er 22 the unit achieved 200 days of continuous operation.
' Unit 2 remained shutdown for its eleventh refueling outage during the entire
inspection period. The original 48 day refueling outage was extended to 64
days due to unexpected increase in repair scope of SG U-tubes. On October 23.
the reactor core was defueled, and on November 21. the reactor core was
reloaded. Restart was scheduled for December 14, 1996.
I. Operations
01 Conduct of Operations
01.1 Routine Observations of Control Room Goerations
a. Insoection Scooe (Insoection Procedure (IP) 71707)
Resident inspectors and a regional inspector (during the week of
November 4 - 8. 1996) conducted frequent inspections of ongoing plant
operations in the MCR to verify proper staffing, operator attentiveness.
adherence to approved operating procedures, communications, and command
and control of operator activities. The inspectors also regularly
reviewed o)erator logs and TS Limiting Condition of Operation (LCO)
tracking sleets, walked down the MCBs. and interviewed members of the
operating shift crew to verify operational safety and compliance with
TS. The inspectors attended daily plant status meetings to maintain
awareness of overall facility operations, maintenance activities, and
recent incidents. Morning reports and Occurrence Reports (OR) were
reviewed on a routine basis to assure that potential safety concerns
were properly reported and resolved.
b. Observations. Findinas and Conclusions
Overall control and awareness of plant conditions during the inspection
period were excellent. During tours of the MCR. the inspectors observed
that the Unit 1 MCBs were frequently in a " blackboard" condition.
Whereas. the EPB had one persistent annunciator alarm and Unit 2 outage
conditions resulted in numerous annunciator alarms. Aggressive efforts
to reduce MCB deficiencies to very low levels were effective. The
combined number of MCB deficiencies have been reduced to less than half
the number that was existing earlier this year.
Operator attentiveness and response to plant conditions was generally
very good; however, on occasion certain distractions were observed.
Although access to the MCR was regulated for 0)erations business only,
some crews allowed personnel not assigned to t1e MCR to linger and
discuss non-work related issues for up to 10 minutes. At times both
reactor operators for Unit 1, which was at 100% power, had their backs
Enclosure 2
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to the MCB. engaged in non-work related conversation with the Shift '
Supervisor (SS) and personnel not assigned to the MCR. Interviews with
the operators indicated that they were aware of plant conditions and the
status of on-going activities. Even though no adverse consequences
resulted from these few lapses in attentiveness. this practice may not l
be conducive to maintaining the record of exemplary operator response to '
slowly developing transients documented in previous reports during this
cycle.
01.2 Unit 2 Defuelina and Refuelina Ooerations
a. Insoection Scooe (IP 60710)
Resident inspectors observed defueling activities on October 22. during-
the. day and night shifts. The ins)ectors also observed refueling
o)erations during the aeriod Novem)er 19 through 21. Activities were
03 served in the MCR S P. and containment.
b. Observations and Findinas
All defueling and refueling activities observed by the resident
inspectors were performed in a well controlled and methodical manner in
accordance with (IAW) FNP-2-UOP-4.1. Controlling Procedure For
Refueling..and FP-APR-R11. Westinghouse Refueling Manual. The !
inspectors observed the refueling pre-job brief on November 15. 1996.
The brief was thorough and covered the necessary information and
)rocedural requirements. No significant incidents occurred during fuel
landling and all fuel assemblies were landed in their appropriate
locations. However, the licensee and an inspector identified a.
considerable number of minor instances of foreign materials entering the
Unit 2 SFP and reactor cavity: SFP - key card, electrical pigtail,
strips of adhesive tape and clear plastic, and a tie wrap: Reactor
Cavity - small rubber bulb hammer, and a three inch diameter aluminum
disk. The ins)ector discussed the numerous foreign material intrusion
aroblems with :NP management. Although all such materials appear to
1 ave been located'and removed, responsible management was evaluating the
adequacy of foreign material controls .
c. Conclusion
The inspectors concluded that fuel handling was accomplished in a
professional and competent manner. Although no significant incidents
occurred, there were some foreign objects found in the SFP and reactor
cavity.
Enclosure 2
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01.3 Unit 2 Cooldown for U2RF11 (IP 71707)
On October 14 and 15. a resident inspector observed the cooldown and
sol'.d plant operation of Unit 2 IAW FNP-2-U0P-2.2. Shutdown Of Unit From
Hot Standby To Cold Shutdown. Cooldown was accomplished in a controlled
and purposeful manner. But, shortly after reactor coolant system (RCS) i
temperature was decreased below 200 degrees Fahrenheit, the licensee ,
delayed further cooldown in order to conduct a seat leak test of the'
residual heat removal (RHR) loop suction valves IAW FNP-2-STP-158, RCS
Pressure Isolation Valve Leak Test. Although this test was previously
planned and evaluated for risk significant consequences, it did require
plant conditions (i.e., isolation of RHR system) contrary to TS 3.4.10.3
for low temperature overpressure protection and certain precaution
statements of U0P-2.2. Also, at this point of U2RF11 reactor core
decay heat was very high. The operating crew did an excellent job
establishing and maintaining unit conditions to support the seat leak ,
tests. Ap3ropriate TS LCOs were entered and tracked. However, the '
ins)ector Jecame concerned that neither UDP-2.2 or STP-158 provided
muc1, if any, guidance to the o)erators on the necessary plant i
conditions and how to control t1em effectively. The resident inspector !
discussed the lack of guidance with Operations management.
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01.4 Solid Plant Pressure Transient - Unit 2 (IP 71707)
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On October 15. 1996, operators responded to an overpressure and loss of i
RCS inventory transient. The event was apparently caused by a charging
flow' perturbation when charging flow control valve (FCV) 122 went shut.
An o)erator was very prompt in observing the decrease in charging flow
and ] umped open FCV-122. However, charging flow jumped to a) proximately
100 gpm. Thi.s increase in charging flow. in combination wit 1 the
automatically reduced letdown flow, caused RCS 3ressure to spike and '
lift RHR relief valve 02E11V0015A ("A" train) w11ch failed to reseat.
This event resulted in approximately 3000 gallons of RCS fluid being
discharged to the pressurizer relief tank and required securing the
reactor coolant pumps (RCP) due to low RCS pressure. The licensee
conservatively secured all high voltage and low voltage switchyard work
while the 2A RHR train was out of service to repair V0015A (2B emergency
diesel generator (EDG) was tagged out for 18 month outage) and all
penetration work.
The inspectors observed the licensee's recovery actions which included
stabilizing the plant and removal and bench testing of 02E11V0015A. The
inspectors concluded: 1) the operating crew performed well in
identifying the condition and stabilizing the plant: 2) the licensee
staff maintained good control and took conservative actions; and 3) the
investigation into the cause of the event was thorough.
Enclosure 2
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! 01.5 Larae Service Water Soill In Unit 2 Containment (IP 71707)
On November 15. during return to service of Unit 2 containment coolers.
Operations failed to 3revent a 7000 gallon spill of service water (SW)
into containment on t1e 155 foot elevation. The spill eventually *
flooded the containment basement level (105 foot elevation) to about six
inches deep. Subsequent investigation by the licensee, as documented in
occurence report (OR) 2-96-351. determined that Operations had directed
contract pipefitters to loosen SW flanges to the A & B containment
coolers on October 25. The loosened flanges were needed as vent paths
to expedite draining both coolers. However. Operations failed to
control the physical status of these containment coolers via tagorder or
other a)plicable documentation. Consequently, when the time came to
refill )oth coolers, the operating crew was unaware of the loosened
flanges prior to reintroducing SW to the containment coolers. But even
with inadequate configuration control. Operations missed an opportunity
to identify the situation or minimize the spill by not walking down the
coolers prior to refill or monitoring the refill operation in
containment. Nobody was contaminated and no' plant equipment was damaged
during the spill although SG work on 105 foot level was halted until
cleanup was completed. Work on the lower level was recorrmenced the next
day.
02 Operational Status of Facilities and Equipment
02.1 General Tours of Soecific Safety-related Areas (IP 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:
e Unit 1 and 2 SFP and SFP cooling systems
e Unit 2 containment
<e Unit 2 turbine-driven auxiliary feedwater (TDAFW) pump rooms
e Unit 2 motor-driven auxiliary feedwater pump rooms
e Unit 1 and 2 component cooling water (CCW) pump and heat exchanger
(HX) ronms
e Unit 1 and 2 hot shutdown panels
e Unit 1 and 2 vital 4160 volt alternating current switchgear rooms,
trains A and B
e Unit 1 and 2 aiping penetration room (PPR) on 100 foot elevation
e Unit 1 and 2 JPR on 121 foot elevation
e Unit 1 and 2 vital 125 volt direct current switchgear and battery
charger rooms, trains A and B
e Unit 1 penetration room filtration system (PRF)
e Unit 1 primary sample room and radiochemistry lab
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Enclosure 2
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e Unit 2 RHR pump rooms
e Unit 2 containment spray pump rooms
e Unit 2 main steam (MS) valve room
Service water intake structure (SWIS), including SW system pumps
and switchgear
e Unit 1 and 2 turbine building
e Unit 2 charging pump rooms
e Unit 1 and 2 boric acid pump and mixing tank 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 SS 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. Unit 1 was beginning to
show the effects of less attention due to Unit 2 outage. However the
inspectors noticed that Unit 2 housekeeping in the PPRs looked much
better than during past outages. This was a remarkable achievement when
considering the SW system William Powell gate valve replacements being
accomplished in the 121 foot PPR elevation. Management attention to
this area was very evident. Also, the accumulation of outage solid
radioactive waste (radwaste) in the decontamination room and 155 foot
elevation RCA spaces and hallways (especially the new fuel storage area)
was considerably improved over previous outages.
02.2 Biweekly Insoections of Safety Systems (IP 71707)
A regional inspector used IP 71707 to verify the operability of the
following selected safety system.s:
e Unit 1 CCW
e Unit 1 and 2 SFP cooling
The inspector used portions of FNP-1-SOP-23.0A. Com)onent Cooling Water
System. Revision 3. and walked down all the accessi]le valves and
components of both trains of the Unit 1 CCW system. The inspector did
not identify any immediate, safety significant problems that could
adversely affect CCW system operability.
The inspector walked down accessible valves and components for both
trains of the Unit 1 and Unit 2 SFP cooling system. The inspector did
not identify any immediate, safety significant problems that cou'd
adversely affect SFP cooling system operability. The inspector iound
that overall material conditions of equi) ment was adequate. Some minor
housekeeping, material condition, and la)eling discrepancies were
discussed with the licensee for correction. Examples of these
discrepancies were:
Enclosure 2
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The inspector found the position indicator for valve 01G31V007.
" Demineralized Water to SFP Isolation." lying on the floor beneath
the valve.
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The casing vent for the 2A SFP pump was leaking excessively
, despite the isolation valve being closed and the line capped.
l There was a collection bag under the line, and the area
l immediately around the pump was designated as a contamination
area. However, the bag was full and leaking on the pump housing.
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The hand wheel on the skimmer pump casing drain valve. 02G31V039,
appeared to have been stepped on. bending the valve stem.
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An unauthorized operator aid was noted above the Unit 2 SFP to
refueling water storage tank (RWST) isolation valve 02G31V021B.
"Open 1 1/2 turns for 100 gpm" was written in pencil on the wall.
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The sample line below Unit 1 SFP cooling sample valve.-01G31V011A
was plugged with a boron buildup.
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An inactive red hold tag was found on the SFP purification outlet
j to refueling cavity (N1031V021A). (See paragraph 02.5)
! 02.3 Enaineered Safeauards Feature System Walkdown
l a. Insoection Scoce (IP 71707)
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The ins]ector performed a detailed walkdown of the accessible portions
of the Jnit 1 and Unit 2 hydrogen recombiners and the Unit 1 and Unit 2
post accident hydrogen analyzers (PAHA). The inspector also used
portions of FNP-1-EEP-1. Loss of Reactor or Secondary Coolant. Revision
15, in order to walkdown the equipment as it would be used in an
- accident situation.
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l b. Observations. Findinas and Conclusions
l The inspector found that overall material conditions of equipment was
l adequate with the exception of a concern with the 2A hydrogen
recombiner. A conduit leading to the 2A hydrogen recombiner had pulled
away from the connector exposing the wires within. This could affect
the operability of the recombiners if the wires were exposed to post-
loss of coolant accident atmospheric conditions. Some minor
housekeeping, material condition, and labeling discrepancies were
discussed with the licensee for correction. Examples of these
discrepancies were:
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pencil labels on the Unit 2 PAHAs.
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no warning signs on the Unit 1 hydrogen sample lines to alert
personnel to the exposed heat tracing as on Unit 2.
! Enclosure 2
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Other than the broken conduit, none of these discrepancies were
significant enough to adversely affect the operability or operation of ;
j hydrogen recombiners and PAHA equipment.
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02.4 Containment Tours - Unit 2 (IP 71707)
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l Resident inspectors toured Unit 2 containment on several occasions
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during the outage. The initial tour. conducted two days after the unit
l shutdown, only identified one oil spot from a snubber leak. No RCS or
l other fluid system leaks were identified. However, the inspectors were
l concerned about trash and loose tools / equipment which was already
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accumulating in containment. This concern was discussed with plant
management at the exit meeting for Inspection Report (IR) 50-348.
364/96-09.
02.5 Tao Orders (IP 71707)
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During the course of routine resident inspections, portions of the
following tag-orders (TO) and associated equipment clearance tags were
examined by the inspectors:
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l' e TO# 94-0791: SFP purification
e TO# 96-2911-2: 2B RHR pump
l All tags and T0s examined by the inspectors were properly executed and
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implemented, with certain exceptions. During the walkdown of valves
! associated with Unit 1 SFP cooling a red hold tag associated with TO
l #94-0791 was observed on SFP purification outlet to refueling cavity
isolation valve (N1G31V021A). Review of the Unit 1 TO log revealed that
l this T0 was no longer active. The tag had been initialed as cleared on
l March 20, 1994. Due to the large amount of time since the T0 had been
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cleared, it could not be determined if the tagging official had ensured
all tags had been removed. i
After determining that the tag was hanging in error, the operating crew
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removed the tag from the valve handwheel. The valve was in its required
position. OR 1-96-338 adequately addressed this issue. The inspector
verified that none of the other tags associated with this T0 were still
hanging.
Also during the ins)ection period two ors (2-96-308 and 2-96-375) were
written regarding t1e loss of control over a 2B SG manhole cover hold
tag and a nitrogen hose hold tag and caution tag on tygon hose running
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through penetration 90. Licensee and contractor investigations were in
! progress.
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Enclosure 2
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l 02.6 Technical Soecifications Comoliance (IP 71707)
- A resident inspector, while performing MCR observation on November 19.
1996. overheard operators discussing a possible TS compliance issue
I which occurred on October 30, 1996. The inspector discussed the issue
with the operators and reviewed the Unit 2 MCR log entries for October
E 30.
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I On October 30. the licensee was moving fuel in the SFP. The 2A startup
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transformer (normal power supply to the "A" train safety busses) and the
4 1-2A EDG (emergency power supply for "A" train safety busses) were out !
of service (00S) for outage work. At approximately 10:22 am, the '
i licensee commenced performance of FNP-2-STP-20.2. Penetration Room
j Filtration System Train A (B) Monthly Operability Test, on "B" train.
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The lineup for this surveillance test procedure (STP) required isolating
the "B" train PRF system suction from the SFP. AT this time, the "A"
i train PRF was running on its alternate power supply (i.e. 2B startup
i transformer). The night shift operators reviewed TS 3.9.13 and 3.7.8,
and at 7:59 pm decided that they did not meet the TS requirements to
1 move loads over the SFP. The operators informed the SS at 8:20 pm. The
- movement of loads over the SFP was terminated and Operations management
I was notified. The Operations manager reviewed the situation and
concluded TS requirements were met. The handling of loads over the SFP
- , was recommenced at 9
- 23 pm.
! The inspectors independently reviewed TS 3.9.13 and 3.7.8 and determined i
j that train A PRF was inoperable from October 29 through November 2 while
- the "A" train normal and emergency power supplies were 00S.
. Furthermore, on October 30. the "B" train PRF to the SFP was rendered
l inoperable by shutting the "B" train PRF suction to perform STP-20.2.
i The inspectors met with plant management to discuss the issue, and
i participated in various conference calls with the SNC corporate office.
i After considerable discussion licensee management continued to disagree
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with the inspector's and operating crew's interpretation of TS
requirements. To resolve this issue, the licensee subsequently
i documented their position in a letter to the NRC dated November 27
1 1996. requesting a formal TS interpretation. Until the NRC responds to
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the SNC letter, this issue is identified as Unresolved Item (URI) 50-
364/96-13-01. PRF Operability Requirements for SFP.
. 07 Quality Assurance in Operations 4
07.1 Effectiveness of Licensee Control in IdentifYina. Resolvina. and
Preventina Problems (IP 71707 and 40500).
The resident inspectors scanned all ors initiated, and approved by the
operations manager during the inspection period to ensure that plant
incidents that effect or could potentially effect safety were properly
documented and processed IAW FNP-0-AP-30. " Preparation and Processing of
Enclosure 2
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Incident Reports Certain selected ors were reviewed in detail as
part of the routine inspection program.
Overall, the inspectors concluded the licensee's program for identifying
and resolving problems rtmained effective, and was being accomplished l
IAW AP-30. Plant personnel and management exhibited an appropriate '
threshold for identifying problems, initiating ors. and assigning formal '
root cause teams. Each new OR received prompt attention and was l
regularly discussed by management in the morning status / plan of the day
meeting. Direct derivations and formal root cause analyses continued to I
be conducted by experienced plant staff in a rigorous and thorough
manner. The results of these efforts were almost always effective at
preventing recurrent problems.
The following ors were reviewed and corrective actions were verified:
o 2-96-301. MOV 3318A found open
e 2-96-346, 2A RHR motor wouldn't rotate while bumping for rotations l
(refer to paragraph M1.6 for more details) l
e 2-96-309. Wiring discrepancies during solid state protection
system walkdown
07.2 Nuclear Ooerations Review Board (NORB)(IP 40500)
TS 6.5.2 defines the function. composition. responsibilities, and
authority of NORB. A resident inspector monitored the NORB conducted on
November 15. 1996. The inspector observed good discussions on problem i
areas. The inspector also verified that the NORB met TS requirements
for members.
08 Miscellaneous Operations Issues (IP 92901) .
l
08.1 (Closed) Licensee Event Report (LER) 348/95-10 Actuation of Engineered
Safety Feature Equipment Due to Loss of Main Feedwater i
This event was discussed in IR 50-348. 364/95-19. No new issues were
revealed by the LER.
JI. 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. l
work instructions, industry codes and standards. TS and regulatory
requirements.
Enclosure 2
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, a. Insoection Scooe (IP 61726. 62703 and 62707)
} The resident inspectors and a regional inspector observed all or
i portions of the following maintenance and surveillance activities, as
- identified by their associated work order (WO). work authorization (WA).
or STP:
'
e FNP-1-STP-23.1: 1A CCW Pump Quarterly Inservice Test (IST)
e FNP-0-STP-80.17: Diesel Generator 2C Operability Test
e- FNP-2-STP-40.3: Phase A Isolation-Test
e FNP-2-STP-627: Local Leak Rate Test of Containment Penetrations
e WA# 120102: Unit 2 Fuel 0xide Measurement
e FNP-2-STP-40.1: B2F Sequencer Operability Test and B2F B2H
Sequencer Load Shedding Circuit Test
e FNP-2-ETP-4411: 28 Residual Heat Removal / Low Head Safety
Injection Pump Curve Development Test
e FNP-2-STP-228.1: Nuclear Instrumentation System Source Range N31
Calibration and Functional Test
e WO# M96004427: 2A Charging Pump Seal Repair
e FNP-2-STP-40.7: Emergency Core Cooling System Branch Line Flow
Test
e WO#00079621: Relug 2B RHR Pump
b. Observations. Findinas and Conclusions
All of the aforementioned maintenance work and surveillance testing
observed by the inspectors were performed IAW work 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 MCR. Overall, craftsmen and technicians appeared
knowledgeable, experienced, and well trained for the tasks they
performed.
In addition, see the discussions below regarding certain major
maintenance and testing activities observed by the resident inspectors
and a Region II inspector (Sections M1.2 through M1.11).
M1.2 Service Water Valve Reolacement. Unit 2 (IP 73753)
a. Insoection Scooe
The inspector reviewed SW System valve replacement activities through
inspection of materials: review of procedures and drawings; observation
of work activities; and discussions with craft and engineering
Jersonnel. The activities were inspected for compliance with the Farley
JFSAR and licensee quality requirements. This area of maintenance work
Enclosure 2
1
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.
l
11
was selected for observation because of the relative importance of the
SW system in the licensee's IPE.
b. Observations and Findinos
The licensee was in the process of replacing carbon steel gate valves
l with stainless steel butterfly valves as the code boundary valves ;
between the American Society of Mechanical Engineers Class 2 and Class 3 l
portions of the SW system. The change was being made due to corrosion
problems with the carbon steel gate valves. At the time of the
inspection, the valves had been replaced in the train A portions of the
l SW system, and work was in progress for the train B valve replacement.
l In train B, the gate valves had been removed and the piping was being
! prepared for installation of piping and flanges necessary for the
l. installation of the butterfly valves.
i Along with a licensee materials engineer, the inspector conducted an
! inspection of the condition of inside surfaces of piping in the vicinity
, of the valve replacement locations. The piping contained an oxidized
I
coating, several millimeters in thickness, that obscured the inside
surface of the alping. The materials engineer was able to easily remove
! the coating wit 1 a putty knife so that various locations of the inside
surface could be examined.
, The piping inside surfaces were found to contain some small pitting )
l indications, but in general the piping did not appear to have suffered l
'
appreciable wall loss due to corrosion. The ends of the piping which '
- had been machined in place, in preparation for welding, were examined to
l' assess the relative depth of the pitting. On the surfaces examined, the
pits appeared to be only a few millimeters in depth, and therefore I
within the corrosion allowance for this piping wall thickness.
During discussions with craft personnel, the inspector was informed that
.
the piping sections examined by the inspector were representative of the .
l piping. conditions noted during the entire modification project. Several l
. of the craft personnel noted that they had ex)ected to find the piping
l in poor condition, and had been impressed wit 1 it's relatively good
l condition, and how easily the pipe ends cleaned up for weld preparation.
The inspector did witness the_ liquid penetrant examination of a weld l
repair in the Class 2 weld preparation for a 6-inch valve (02P16V044BL ;
The area being repaired was due to removal of a linear indication, '
resulting in a 2.5-inch by 7/8-inch area being ground in the end of the
pipe.
The inspector reviewed two work packages representative of the work
being done: one package for a 12-inch diameter valve and the other for a
6-inch diameter valve. The inspector noted that the work packages were
i set up in a " traveler" format with individual work sheets for each of
- the different welding operations required for each valve replacement.
l The work packages appeared to be very complex, but after discussing the
,
- Enclosure 2
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jobs with the craft personnel on the scene, it was apparent that they
understood the process and how the job was to be documented.
c. Conclusions
t
l The SW code boundary valve replacement activities appeared to be
'
conducted in a manner consistent with the licensee's quality programs.
The fact that the licensee had a materials engineer assigned to oversee
- these replacement activities, along with other work on the SW system.
I was a positive indication that the licensee understood the relative IPE
l
importance of the system.
M1.3 SG Inservice Insoection (ISI). Unit 2 (IP 73753)
- a. Insoection Scooe '
The inspector reviewed ISI inspection activities involving the Unit 2 SG
tubing. The review consisted of discussions with licensee and
- contractor personnel
- review of eddy current and ultrasonic test
! results: and an independent review of a portion of the eddy current,
l bobbin inspection, test data from the "C" SG.
i
l b. Observations and Findinas
l
l Farley 2 is a Westinghouse 3-loop unit with series 51 SGs. Each SG
contains 3388 U-bend tubes made of Inconel 600. The nominal tube
outside diameter is 0.875 inch with a nominal wall thickness of 0.050
inch: the tubes were expanded into the tubesheet using a mechanical
hardroll. process. Unit 2 reached initial criticality in May 1981, and
this outage is the eleventh (11th) refueling outage.
During this refueling outage, the licensee's eddy current plans included
a 100% bobbin coil inspection of all tubes in each SG from the cold leg
side concurrent with a 100% rotating coil inspection of the hot leg tube
sheet. These basic inspections were to be followed by rotating coil
inspections of bobbin coil indications, particularly at hot-leg support
plate intersections and in free spans. The licensee was using the plus-
point probe for the rotating coil inspection for the first time.
As a result of the planned inspections, a significant number of new
indications were detected. Because of these new indications, the
licensee initiated a special program to establish structural integrity
of the "A" SG: this program would then be followed by special programs
- on the "B" and "C" SGs. There were five types of inspection findings
- that were determined to be " Free Span Structural Integrity Issues" which
i
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j Enclosure 2
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were the focus of the continuing inspection activity in the "A" SG.
These findings are as follows:
Inside Diameter (ID) >180 at or above the Bottom of Roll
. Circ crack: Transition (BRT)
,
j Outside Diameter :
t Circ crack: >180 at or above the BRT i
3
. Axial cracks: Crack length of >0.4 inches. above the BRT.
!- Axial & Circ Mixed: If no " null" between circ and axial, Indication
! at or above BRT.
!
Free span above roll transition: Plus point indication >2 volts
i In addition to these tubes. 20 Single Axial Indications and Multiple
i Axial Indications with axial crack length >0.3 inches, above the BRT
i were included in the continuing inspections.
There was a total number of 59 tubes included in the additional
inspection activities. The inspection activities included: a repeat of
>
the plus-point-inspection using a slower speed in order to generate more
data points, and ultrasonic examination (UTEC) of all ID cracks in the ;
. sample (52 of the 59 tubes had ID cracks). 1
4 l
'
j The data from the additional plus-point and UTECs were currently.being
1 analyzed to select the appro riate sample tubes for in-situ pressure
i testing and also for tube pu ls
!
l At the time of this inspection, in the "B" SG. fifteen (15) tubes had
i been selected for " slow" plus-)oint and UTEC. UTEC equipment was being
L installed in the "B" SG. In tie "C" SG data analysis from the original
j bobbin and plus-point examinations had just been completed.
! One finding of note, in the "C" SG was a bobbin coil indication at the
first hot leg support. plate on tube No. R34C53. This tube was plugged
'
in October 1990 with an indication that had been confirmed by Rotating
i Pancake Coil (RPC). (This was before the licensee had received approval
. to use a voltage-based alternate plugging criteria, and tubes were
, plugged upon confirmation of an indication by RPC.) The tube remained
i plugged until March 95 when it was unplugged and bobbin coil examination
- showed the indication to be 1.89 volts, which was below the plugging
. criteria of 2 volts. During this inspection, bobbin coil examination
measured the indication as 6.73 volts. This is a significant growth
'
i rate for one fuel cycle.
,
j In discussions with the licensee the inspector learned that, while this
one tube (R34C53) is a singular case because of its large ap]arent
~
growth rate, there does appear to be a pattern where tubes tlat have
f Enclosure 2
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14
been plugged and later returned to service apparently show larger l
indication growth rates than tubes that have remained in service.
Using the contractor's evaluation equipment, the inspector reviewed
bobbin-coil, eddy current data for the following "C" SG tubes:
R34C37: R06C26: R07C35: R46C51: R45C46: R34C53:
R42C54: R45C56: R35C60: R31C60: R27C68: R30C67:
R32C65: R37C64: R41C64: R42C64: R39C65: R40C67:
R33C71; R30C72: R35C74: R35C76: R32C42: R24C78:
R26C77: R23C75.
During this review. the inspector paid particular attention to
indications at the hot leg support plate locations.
The inspector also observed preparations for the UTEC of a sample of "B"
SG tube indications. The preparation work activities were observed via
video monitoring equipment in the contractor's trailer. The UTEC system
was being used to cuantify the lengths and depths of a representative
sam)le of crack incications found using the plus-point eddy current
pro)e. The inspector also reviewed data alots of the nine tubes from
the "A" SG that had been inspected. At t1e time of the inspection the
only indication that had been depth sized by UTEC was a half-inch long,
axial indication located five inches above the top of the tubesheet in
tube R28C26: that indication had been sized as less than 0.020" in
depth.
c. Conclusions
Based on the review of the planned scope of the SG inspection, and the
expanded scope of inspections after significant numbers of indications
were found, the licensee appears to have taken a conservative approach
to determining the structural integrity of the Unit 2 SGs.
M1.4 2B EDG 18 month insoection (IP 62707)
The inspector reviewed the completed work packages and observed limited
portions of the following work on the 2B EDG:
e MP-14.1 18 Month Inspection
e Replacement of Lube Oil HX, Intercooler HX, Jacket Water HX tube
bundles due to inlet tube sheet erosion concerns.
- Inspection /realacement of #2 Air Start Header air start check valves
for exhaust baccleakage.
All work was completed per procedure in a professional manner. Post
maintenance testing was completed satisfactorily.
Enclosure 2
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l- M1.5 W0s #96002615. 96002618. and 96002619: Insoection of Charaina Pumo
, Casinas (IP 62707)
- '
The resident inspectors reviewed the licensee's inspection of charging
- Jump casings.for cracks and boric acid corrosion concerns identified by
i
4RC Information Notice (IN) 94-63. The licensee utilized an ultrasonic
testing (UT) inspection process to inspect the nozzle ends. .This
)rocess was tested using mockups to verify it could detect defects
aetween the cladding and the case as small as 0.09 inches. The
inspectors reviewed the test package and determined it was adequate.
The inspections revealed no indications of cladding cracks in the nozzle
ends.
However, just prior to the outage, a failure of the 2A charging pum)
required removal of the rotating assembly. With the rotating assem)1y
removed, the licensee identified rust stains on the casing clad. UT and
RT testing in areas of rust stain showed no indications of a crack or
wastage of the casing. The licensee videotaped the indications and sent
copies to Westinghouse and Pacific Pumps for further analysis. The
analysis indicated that there were possibly two cracks in the cladding
but there was negligible wastage of the casing. Initial recommendations
were to conduct UT inspections of the casing and nozzles on an increased
frequency. However, as of the end of this re) ort, no formal
recommendations or actions had been taken. T1is will be tracked as
Inspector Followup Item (IFI) 50-364/96-13-02. Increased Frequency Test
Program for Charging Pumps due to Cladding Cracking.
M1.6 Desian Chanae Packaae (DCP) S95-2-8966: Chanaeout of RHR Pumo Imoellers
(IP 62707)
The resident inspector reviewed the DCP and observed work in progress
and the post-modification testing. This DCP was performed to enhance
pump performance at higher flows to provide a larger margin for pump
degradation. The DCP was performed on Unit 1 during the last refueling
outage. Overall work was well controlled. However, rework was required
to relug the motor leads because an incorrect lug / crimp size was used
and the motor ratings required upgrading from 380 to 400 horsepower.
The lugging deficiency was identified on November 11, 1996, when the 2A
RHR pump failed to start during the post-modification testing. On-
investigation the licensee found an open circuit where the lug on the
motor lead had pulled off the wire. The motor leads were 49 strand #6
wires. The original lugs were #4 lugs. Maintenance personnel initially
tried to relug the motor leads using #6 lugs but they were too small.
Maintenance personnel reverted back to the #4 lugs (as used by the
manufacturer) and crim)ed the lugs with a #8 die. The maintenance
personnel found that t1e lugs were not tight enough on the 2B RHR pump
so they recrimped the 2B RHR pump motor leads with a #7 die. They did
not go back and recrimp the lugs on the 2A RHR pump.
Enclosure 2
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1 16
i The licensee relugged both RHR pumps using #6 lugs s)ecifically sized
i for 49 strand wire per WO S00079621. An inspector o) served the
i relugging of the 2B RHR pump. The inspector reviewed FNP-0-EMP-1370.01,
Cable Termination. Splicing and Repair. for specific guidance on lugging
- criteria. The inspector determined that the procedure only provided
general guidance and relied on skill-of-the-craft for determining lug
i sizing requirements.
!
3 The inspector observed the post-modification testing of the pumps per
i FNP-2-ETP-4411, 2B Residual Heat Removal / Low Head Safety Injection Pump
i Curve Development Test, Revision 0. The inspector reviewed the test
J.
+
prerequisites and procedure and observed the evolution prebrief and
3erformance of the test. The licensee found that the maximum brake
l lorsepower (Bh)) requirement at a runout condition of 4400 gallons per-
minute was higler than expected (between 380 and 390 Bhp). The RHR l
, motors have a 380 Bhp rating. To prevent exceeding the motor ratings
- the licensee placed administrative controls on the use of the RHR pumps
- until formal evaluations could be completed. The licensee performed a
50.59 evaluation. performed additional testing on the RHR
,
analyzed the impact of the increased loading on the EDGs.As pumps, and
a result
! of the 50.59 evaluation and the related safety evaluation, the licensee
'
was able to uarate the RHR pum) motors to 400 Bhp. The ins)ectors l
- observed the 31 ant Operations Review Committee meeting at w1ich the ;
issue was discussed and reviewed the 50.59 Jackage. The inspectors
i
"
concluded the evaluation was thorough and t1e motor uprate was
adequately justified.
- M1.7 FNP-1-STP-24.1: Service Water System Quarterly IST
i a. Insoection Scooe (IP 61726)
i An inspector observed the entire performance of FNP-1-STP-24.1, 1A, 1B,
3 and 1C SW Pump Quarterly IST.
1
! b. Observations and Findinas
4
"
The SW sytem pumps performed as expected. The inspector verified that:
1) all initial conditions and prerequisites were satisfied and 2) test
instrumentation was calibrated and of the proper range. The inspector
j also verified selected data point calculations.
1 c. Conclusions
!
-This IST of the unit 1 Train A SW system pumps, including the swing 1C
pump, was performed IAW the procedure steps of STP-24.1. No
a deficiencies were identified.
..
Enclosure 2
1
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l'
. M1.8 STP-40.0: Safety In.iection With Loss Of Offsite Power Test - Unit 2 (IP
61726)
,
On November 16. a resident inspector observed the conduct of FNP-2-STP-
40.0. Safety Injection With Loss Of Offsite Power Test. Overall, this
fully integrated, challenging and complex test was very well
orchestrated. No significant procedural problems or performance errors
were identified. All systems and components operated per design during
the test except: 1) minipurge dampers would not reopen: 2) hydraulic
contol valve 603A failed to fully open (due to binding): 3) 2A and 28
RHR pump flows were less than required: and 4) the mini-flow for 2C
charging pum) sprung a serious packing leak. Also, the 2A charging pump
was unavaila]le for the test due to repairs. and the 20 containment
cooler fast speed breaker was put in test.just prior to STP-40.0 due to
its fan rotating in reverse direction. Deficiency Re] orts were written
to address identified equipment problems. 2A and 2B 1HR flow discharge
valve stops were subsequently readjusted and pump flow retested
satisfactorily.
M1.9 WOf 596000458: Unit 2 TDAFW Pumo Governor Valve Stem and Soacer/ Washer
Reolacement (IP 62707)
On October 28. a resident inspector observed implementation of i
modification DCP-2-95-8939 by several mechanics. This DCP replaced the i
Unit 2 TDAFW pump governor valve stem, spacers. and washers based on
problems described by IN 94-66. The concern involved the use of l'
incompatible materials that would cause the stem to bind resulting in
turbine overspeed trips. The DCP and WO directed the installation of
new components made of vendor recommended materials. The inspector
observed the component replacements per approved work instructions and
inde)endently verified material compositions by reviewing applicable
purclase orders.
M1.10 RCP Seal Iniection System Foreian Material Intrusion (IP 62707)
OR 2-96-325 was written to document an investigation into the source and
cause of foreign debris (i.e.. pulverized 0-ring material) discovered in
six of nine RCP seal injection check valves. The seal injection check
valve internals were inspected during U2RF11 due to prior evidence of
debris from seal injection filter 0-ring material (Maintenance Incident
Report 95-02) and a seal injection flow transient during Unit 2 fuel
Cycle 11 (Incident Report 2-96-161). The discovery of additional 0-ring
material downstream of the seal injection filters led to the preliminary
conclusion that a poor work practice used during installation of RCP
seal injection system filters (i.e., failure to lubricate 0-rings per '
manufacturer recommendations) has resulted in the introduction of 0-ring
fragments throughout the seal injection flow path to the RCP seals. The
inspectors will review the licensee's completed OR and applicable safety
evaluation, and verify corrective actions. This issue is identified as
Enclosure 2
_ _. _ _ _ _ _ _ _ _ - _ _ _ _ _ - _ _ . . . . _ . _ _ _ _ . _ _ _ . _
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l 18 I
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IFI 50-348, 364/96-13-03, Foreign Material From Seal Injection System To I
! RCP Seals.
!
i
M1.11 Reset Motor-Ocerated Valve (MOV) Toraue_5 witches to Hiaher Values
! (IP 62707)
.
l
- The NRC ins)ectors reviewed documentation and observed work in progress !
j to verify tlat the licensee was resetting MOVs IAW a previous commitment '
- made to the NRC in response to IR 94-28. The schedule, provided in a
l March 3, 1995, letter from the licensee to the NRC, required 10 Unit 2
i
MOVs to be reset in the current Unit 2 refueling outage. The related
- work observed by the inspectors involved resetting MOV 2-32108. The
j- documentation reviewed was selected from a sample of 3 of the 10 valves
i and included: work authorization 451260 for resetting MOV 2-88878 and
, W0s 75880 and 75865 involving activities to replace MOVs 2-3019B and 2-
i 3134 (requiring them to be reset). The inspectors concluded that the
Unit 2 MOV were being reset IAW the licensee's commitment,
f M8 Miscellaneous Maintenance Issues (IP 92902)
i M8.1 (Closed) LER 50-364/95-08: Reactor Trip During DEH Card Changeout
! This event was discussed in IR 50-348, 364/95-20. No new issues were
! revealed by the LER.
!
! III. Enaineerina
l El Conduct of Engineering
j i
j El.1 Desian Chances 'and Plant Modifications i
i I
a. Insoection Scooe (IP 37550)
l The inspector reviewed design changes and plant nomfications that were !
j being implemented on Unit 2 during the current ref. ting outage to )
-
determine if these activities were being Jerformed ,- / regulatory '
! requirements.1_icensee commitments, and tie design modification
- procedure. Walkdowns were also performed in order to inspect the
? implementation of the modification in the field.
b. Observations and Findinos
The licensee had 46 DCPs on the list of plant modifications that had
been approved and scheduled to be worked during the U2RF11. The
inspector reviewed four DCPs as listed below that involved significant
electrical modifications:
DCP 95-0-8816, Provided design to convert the MCR air conditioner units
from water to air cooled units. This modification is being implemented
Enclosure 2
1
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by the licensee to improve reliability, maintenance and operation of the
MCR air conditioning system.
DCP 95-2-8875, Provided design to delete 13 MCR recorders and associated
wiring on Unit 2. replace four recorders with computer points, replace
three recorders with vertical scale indicators, add a new recorder to
~
monitor SG feedwater pump suction pressure, replace two obsolete MCB j
trend recorders, and add jacks to the moveable incore detector system to
provide for the connection of a portable recorder.
DCP 91-2-7186, Provided design to install interposing relayscin the l
, circuitry for high energy pipe break switches. The current high energy
- )ipe break switches are obsolete and the approved re]lacement switches
l lave only one set of contacts instead of two as on t1e existing
switches. The addition of these relays will allow replacement of
existing switches.
DCP 87-2-4592, Provided design to automatically load an instrument air
,
compressor on the EDGs by the engineered safety system or loss of
l
'
offsite power (LOSP) sequencer, block the pressurizer heater backup
group A during sequencing and provide a manual bypass for unblocking. l
The )lant modifications required to be performed by the above DCPs had ;
not )een completed. The inspector conducted interviews with the i
appropriate assigned engineers to discuss the scope of the modification, ,
work completed and remaining, and testing that would be performed for !
functional acceptance. The inspector, accompanied by the assigned
engineer, performed walkdowns in the field to examine the work completed ,
on modification DCPs 95-0-8816. 95-2-8875, and 91-2-7186. I
With regard to DCP 95-0-8816. the inspector examined the modifications
of the A and B trains of the MCR air conditioner units. The A train- i
modifications were com)lete and functional. The B train was being
worked this outage. T1e inspector examined the conduit routing for the
new 600 VAC power cable for the B train condenser unit and found it to
be acceptable. The routing was examined from motor control center 1G in
the auxiliary building to the B train condenser unit on top of the
control building. Intermediate routes also included the MCR via
conduit. A revi;w of the UFSAR and RG 1.75. Revision 0, confirmed that
this routing was consistent with the licensee's commitments on RG 1.75.
The inspector concluded that the modifications performed to date
appeared to be acceptable.
l
- The inspector examined portions of work performed under DCP 95-2-8875 to
l delete specific MCR recorders. The inspector accompanied by the
- assigned engineer, toured the MCR to examine the Unit 2 MCB and the
I recorders that were being removed. While in the MCR the inspector
i observed the craft determinating the Metal Impact Monitoring System
i Recorder. The craft noted that the wires could not be determinated at
both ends because one end was soldered. The craft notified the engineer
l
j Enclosure 2
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who was accompanying the inspector at that time of this problem. A >
short time later, the engineer issued a field change for the wires to be 1
I
determinated at the one end only, taped and spared. - On a subsequent :
tour of the MCR. the inspector observed that the Metal Impact Monitoring !
I
Recorder had been removed as recuired by the DCP and the internal wiring -
had been determinated at one enc only, the ends of the wires had been
sealed with tape, and each wire had been labeled. spare. The inspector :
found the completed work to be acce) table. In regards to this issue.
the inspector found that the craft lad a good questioning attitude and
that engineering interfaced well with the craft to resolve this problem. ;
'
The inspector held discussions with the licensee regarding the
- . instruments that are within the scope of RG 1.97 1 e., Types A. B. and C
-
l
l
and Categories -1 and 2 instruments. These instruments are required by :
! RG 1.97 to be uniquely identified on MCBs as post accident monitoring
i instruments. The results of these discussions revealed the following
information regarding the licensee's methods for labeling MCR ,
'
,
instruments. An internal Alabama Power Company letter dated December
j 14, 1987, " Marking of Main Control Room Indicators =" indicated that
orange labels were being used as markers of E0 indicators to aide the
operators in identifying those instruments that would be more reliable
under accident conditions. Some time later the orange labels were
removed by the licensee and replaced with name)lates with black
lettering and white backgrounds with "E0" in tie label description. The
licensee's RG 1.97 Compliance Review Report No. A-204866. Revision 4.
dated November 28, 1995, requires that certain instruments be marked as
RG 1.97, but it does not specify how these instruments will be marked or
labeled. The inspector selected four Category 1 indicators from the
Compliance Review Report (i.e.. PI-402A, 402B, 403A. and 403B) and
confirmed in the MCR that they had been marked as "E0" The inspector
also noted that DCP 95-2-8875 3rovides design to delete the Boric Acid
Flow Strip Chart Recorder whic1 is Variable 102 in the RG 1.97
Compliance Review Report. In accordance with the Compliance Re) ort this
variable is not required to be marked on the MCB. Although no RG 1.97
indicators were identified without labels, the inspector had a concern
that the labeling of E0 instruments may not be adequate because there
may be other RG 1.97 instruments that are not E0 that are required to be
labeled.
The licensee acknowledged the inspector's concern regarding RG 1.97
labelling and subsequently conducted a thorough re-review of the issue.
Based on this re-review. SNC issued a letter dated December 5,1996 to
the NRC revising their commitment from using orange bars on the NCBs to
^ the "E0" designator. Furthermore, this letter confirmed that all RG
1.97 required variables specified in their 3revious commitment were
marked "E0." except for MS line 3ressure. R4ST level, and condensate
i storage tank level. But since t1ese instruments were not located in
! harsh environments and are uniquely identified by the plant's emergency
l
response procedures no additional identification is warranted.
4. Enclosure 2
i
-
- . - - . _ - _ _
,
-
.
21
The inspector reviewed portions of Revisions 7 and 8 to Design
Calculation E-42 Steady State Diesel Generator Loading Calculation for
LOSP, Safety Injection (SI) and Station Blackout (580). to confirm that
the additional loads ) laced on the EDGs by DCPs 8816 and 4592 had been
properly assessed. T1e inspector found that Revision 8 assessed the
load additions from DCPs 8816 and 4592 and concluded that EDG 1C steady
state load would exceed the continuous rating by less than 5 percent in
some design basis scenarios and SB0 scenarios, but would remain well
below the yearly 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> rating of 3100 kilowatts. This was found to
be acceptable. The steady state loading for EDGs 1-2A, 18 and 2B
remained below the continuous rating for all design basis and SB0
events.
Field wod on DCP 91-2-7186 was inspected and found to be acceptable.
The in:;pector reviewed the 50.59 evaluations for the DCPs identified
above to verify that they were adequate and that an unreviewed safety
question did not exist,
c. Conclusion l
The inspector concluded that the design changes and plant modifications
were adequate and the work completed on the above modifications was ;
acceptable. The craft demonstrated a good questioning attitude during
the removal of the Metal Impact Monitoring Recorder which resulted in a
Field Change to the DCP. Engineering was also timely in providing an
acceptable solution to the problem. I
El.2 DCP S94-2-8752: Reolacement of Service Water System William Powell Gate
Valves (IP 37551)
The inspector reviewed the DC.P. UFSAR requirements for containment
isolation valves. TS requirements, and the valve technical data. The
inspector observed selected portions of the following:
e Removal of the old valves
e Preparation of the pipes
e Installation of the new valves
e Testing and setup of the MOV actuators
e Environmental qualification of MOV actuators
Work was generally performed IAW the DCP and plant requirements. Some
minor deficiencies were noted with foreign material exclusion controls
on the new valves in the laydown area and "As Low as )easonably
Achievable" (ALARA) practices in the work area. These deficiencies were
promptly corrected by the licensee.
Enclosure 2
l
,
<
. .
.
22
El.3 SG Level Control and Protection System Outside Desian Basis (IP 71707) j
After reviewing Westinghouse issued Nuclear Safety Advisory Letter 96-
004 dated October 8. 1996 the licensee concluded that under certain
conditions the SG level control and protection features for Units 1 and
2 do not meet Section 4.7.3 of IEEE-279 as re
On November 7. SNC promptly notified the NRC, quired
including thebysenior
resident inspector, pursuant to 50.72(b)(1)(ii)(B) for a condition
outside the design basis. Unit 1 steam flow channel selector switches
were selected to the channel IV position to eliminate the problem of a I
common tap for the steam flow transmitter and narrow range SG water
level that exist for channel III. Resident inspectors verified selector l
1
switch position and caution tags on steam flow channel switches for Unit
1. Unit 2 has the same design problem but is currently shutdown for
U2RF11. The licensee has declared Unit 1 steam flow and SG water level
protection features operable, and plans to resolve Unit 2 design problem
with a longterm fix prior to startup. Resident inspectors will review ,
the Unit 1 operability determination and continue to follow up on I
licensee longterm corrective actions for Unit 2. This issue is !
identified as URI 50-348, 364/96-13-04 Common Tap For SG Steam Flow l
Transmitter And SG Narrow Range Water Level System Fails To Meet IEEE- i
279. l
E1.4 Control Rod Test and Evaluation Proaram .
l
On October 12 through 14, 1996, the engineering support group and
Operations conducted FNP-0-ETP-3661. Control Rod Test and Evaluation
Program, in order to accomplish special rod control tests, evaluations
and reporting requirements committed by the SNC response to NRC Bulletin
96-01, Control Rod Insertion Problems. A resident inspector observed
the conduct of ETP-3661. Appendix A. Observation Of Timely Rod Insertion
During Reactor Trip, as documented in NRC IR 50-348, 364/96-09. All
control rods were observed to insert properly. Appendix B. Multiple Rod
Testing Using Automated Measurement System Equipment, and Appendix E,
Control Rod Recoil Verification, were subsequently performed while still
in Mode 3. prior to cooldown for U2RF11, but not observed by the
inspector. The completed test procedure and test results were reviewed
by the inspector and found to be satisfactory. No abnormal control rod
drop characteristics were indicated. Additional control drag testing by
the vendor in the SFP and control rod drop testing using FNP-2-STP-112.
Rod Drop Time Measurement, in Mode 3 was planned during U2RF11 to
complete licensee NRC Bulletin 96-01 commitments.
Enclosure 2
- - - ..- - . - . - - . - . - - - . - - . - .- . - -- ---
'
.
, .
<
.
23 i
l E8 Miscellaneous Engineering Issues (92903) ,
!
E8.1 (Closed) IFI 50-348. 364/94-28-01. Evaluation of'Settinas for Cones- I
l Vulcan MOVs 8811A/B and 8812A/B Usina the EPRI PPP Model. ,
This item was opened to track the licensee's completion'of a commitment
to evaluate the settings of seven 14-inch solid wedge Copes-Vulcan gate '
valves using criteria developed in the Electric Power Research Institute
'
l (EPRI) Performance Prediction Program (PPP). The licensee's commitment
l
'
was made in response to an NRC concern regarding the reliability of the
valves' settings. The settings were questioned by the NRC because they
had been based on a method that recuired extensive extrapolation. The
subject valves were employed for RFR sump suction isolation and were
identified 1-8811A. 1(2)-8811B. and 1(2)-8812A/B. Their active safety
function was to open.
l In the current inspection. NRC inspectors reviewed and assessed the
! documented actions which the licensee had taken to meet their
l'
commitment. This review included Calculation SM-90-1653-018. Rev. O. ,
which determined oaening thrust requirements for the seven valves: and a i
letter identified :ile: ENG 15 90-1653. Log: FP 96-0346. which evaluated
the results of the calculation. The inspectors checked a sam)le of the 1
calculation inputs and verified that they were consistent wit 1 values ;
given in the licensee's UFSAR and design-basis document. They also !
verified that the licensee's calculation employed criteria developed by
the EPRI PPP and that the calculation had been independently verified by l
a separate organization. Further, the inspectors performed an
independent hand calculation which confirmed the accuracy of a
" cracking" computation included in the licensee's calculation.
The licensee's evaluation included comparisons of previously determined
valve capabilities with the opening thrust requirements determined in 1
Calculation SM-90-1653-018. These com)arisons showed that the present
capabilities and settings of five of tie seven valves were adequate, as
they exceeded the opening thrust recuirements. However, the comparisons
showed that the other two valves dic not have sufficient reduced voltage
capabilities to provide the opening " cracking" (unseating) force
requirements under worst case design accident conditions. The
capabilities of these two valves were shown to be 0.4 and 6 percent less
than recuired. (Note: The torque switches of the valves had been
.
r bypassec for the unseating or " cracking" portion of the opening stroke,
!
such that the valves' full reduced voltage capabilities were not
i
restricted by torque switch settings.) To su
i
two valves to perform their safety functions,pport the adequacy
the licensee 3rovidedof
a these
- rationale that the actual cracking force requirements for t1e Farley
valves were lower than determined in the EPRI PPP calculation. Also.
! they stated that the valves' reduced voltage capabilities were actually
i higher than initially considered. based on the measured stem friction
'
coefficMnts for each of the valves. The inspectors reviewed supporting
licensee data :nd considered it insufficient to support lower cracking
l Enclosure 2
4
4
)
!
. . . _ - . . .
'
.
.
24
force requirements. However, the inspectors found that the licensee's
test results supported a dynamic stem friction coefficient of 0.18.
Reduced voltage capabilities calculated using this stem friction
coefficient were sufficient to provide the required cracking forces.
The reduced voltage capability calculated by the licensee for the worst
case valve (1-8811A) using this stem friction coefficient exceeded the -
calculated minimum opening thrust requirement by approximately 1
percent. The other six valves had estimated capabilities more than 10
percent greater than required (much greater than 10 percent in most
cases).
The inspectors concluded that the licensee had satisfactorily completed
their commitment for these valves and that this provided additional
support for the capability of the valves to perform their active safety
function. On this basis the IFI was closed. However, the inspectors
noted continued weakness in the licensee's support for the capabilities
of these valves because of the following:
. The EPRI PPP criteria used by the licensee has not yet been
demonstrated to satisfactorily apply to valves manufactured
by Copes-Vulcan.
. Even assuming the EPRI PPP criteria was applicable, the
licensee's data for valve 1-8811A only supported a limited
margin of thrust capability above that required to perform
its safety function.
E8.2 _(Closed) IFI 50-348. 364/94-28-02. Evaluation of Settinas for
Westinghouse Unit 2 MOV 8811A Usina the EPRI PPP Model.
This item was opened to track the licensee's completion of a commitment
to evaluate the thrust setting for a 14-inch Westinghouse flexible wedge
gate valve using criteria developed in the EPRI PPP. The licensee's
commitment was made in response to an NRC concern that the setting was
based on EPRI PPP data but had not been determined IAW the related
criteria which EPRI had under development in the PPP. The subject valve
was omployed for RHR sump suction isolation and was identified 2-8811A.
Its active safety function was to open.
In the current inspection. NRC inspectors reviewed and assessed the
documented actions which the licensee had taken to meet their
commitment. This review included Calculation SM-90-1653-019. Rev. O.
which determined opening thrust requirements for the valve; and a letter
identified File: ENG 15 90-1653. Log: FP 96-0346. which evaluated the
results of the calculation. The inspectors checked a sample of the
calculation inputs and verified that they were consistent with values
given in the licensee's UFSAR and design-basis document. They also
verified that the licensee's calculation employed criteria developed by
the EPRI PPP and that the calculation had been independently verified by
a separate organization.
Enclosure 2
9
.
4
25
The licensee's evaluation com)ared the previously determined valve
capability with the opening t1 rust requirement determined in Calculation
SM-90-1653-019. This comparison showed that the present thrust setting
for the valve was satisfactory, as it exceeded the opening thrust
requirement determined in the calculation.
The inspectors concluded that the licensee had satisfactorily completed
their commitment for this valve and that the results confirmed the
adequacy of the setting used. On this basis the IFI was closed. j
E8.3 (Closed) IFI 50-348. 364/94-28-03. Evaluation of Settinas for Pratt .
Sutterfly MOVs Usina the EPRI PPP Model. l
This item was opened to track the licensee's completion of a commitment
to evaluate the settings for 16 butterfly valves manufactured by Henry
Pratt. The evaluation was to be performed using criteria developed in
the EPRI PPP. The licensee's commitment was made in response to an NRC
'
concern that the licensee did not have any useful diagnostic data to
support the settings used for these butterfly valves. Torc ue l
requirements for the valves had been established using guicance from the
valve manufacturer. The valves were divided into groups. Their
functional names and valve numbers were as follows:
Functional Name Valve Numbers
Turbine Building Service Water 1(2)-0514, 1(2)-0515, 1(2)-
l Isolation Valves 0516. and 1(2)-0517
>
Steam Generator Heat Exchanger and if2)-3149 and 1-3150
Boron Thermal Regenerative Chillers
Service Water Isolation Valves
. . Component Cooling Water Valves to RHR 1(2)-3185A/B
.
Heat Exchanger
1
In the current inspection. NRC inspectors reviewed and assessed the
documented actions which the licensee had taken to meet their
commitment. This review included Calculations SM-90-1653-017, SM-90-
1653-014, SM-90-1653-015, and SM-90-1653-016, which determined the
torque requirements for these valves. Additionally, the inspectors
reviewed the licensee's evaluations of the results of the above
calculation, which were documented in a letter identified File: ENG 15
90-1653. Log: FP 96-0346.
The inspectors checked a sample of the inputs to the calculations and
- verified that they were consistent with values given in the licensee's
UFSAR and design-basis document. They also verified that the licensee's
calculation employed criteria developed by the EPRI PPP and that the
calculation had been independently verified by a separate organization.
Enclosure 2
- . . _ _ __ __ _ _ _ . _ _ _ _ _ _ . _ _ . _ ~ _ _ . _ - _._ .__
.. .
26
The licensee's evaluations compared the valves' torque settings with the
l torque requirements determined in the EPRI PPP calculations. This 1
comparison showed that the present torque settings were satisfactory. l
except that the torque settings for the turbine building SW isolation j
l valves were too low in one accident scenario. The torque switches for j
l these valves had been bypassed in the region of concern and the valves J
were capable of performing their safety function. The inspectors found
-
that the licensee had initiated documentation (e.g. W0s 450972, 450973.
450974, and-450975) to reset the torque switches to the higher values
determined by the calculation.
The inspectors concluded that the licensee had satisfactorily completed
their commitment for these valves and that the results showed the valves l
were acceptable for operation. On this basis the IFI was closed.
IV. Plant Sucoort
4
R1 Radiological Protection and Chemistry (RP&C) Controls
- i
l R1.1 Radiolooical Controls I
i
a. Insoection Scooe (IP 83750) l
The inspectors discussed planning and observed implementation of
,
selected RWP requirements associated with the following routine tasks
l and U2RF11 outage job evolutions,
o RWP 096-0081. Waste Processing, Revision (Rev.) 0, effective
January 1, 1996.
e RWP 296-0154, Special Plant Maintenance. All Work Associated with
i Primary Steam Generator Manway and Diaphragm Removal and
Installation in Containment. Refueling, Rev. O, effective October
1. 1996.
e RWP 296-0161. Refueling, Rev. 0. effective October 1, 1996.
e RWP 296-0196, Special Plant Maintenance. Work Associated with the
l Boron Injection Tank (BIT) Removal, Rev. O, effective October 1.
l 1996.
e RWP 296-0198. Special Plant Maintenance Work Associated with
Replacement of Service Water Isolation Valves & Actuators to
Containment Coolers 2A, 2B, 2C, 2D and the Reactor Coolant Pump
Motor Air Coolers, Rev. O. effective September 24, 1996.
l e RWP 296-0199, Special Plant Maintenance. Work Associated with
,
Replacement of Service Water Isolation Valves & Actuators to
. Containment Coolers 2A. 28. 2C. 2D and the Reactor Coolant Pump
Motor Air Coolers Rev. 0, effective October 1, 1996.
Enclosure 2
l
l
l
_
.
.
27
Job planning and pre-job briefings were discussed and evaluated for
selected RWP guidance. In addition, the inspectors observed licensee
radiation surveys conducted adjacent to the transfer canal outside of
containment and reviewed the adequacy of auxiliary building controls and
postings in place during transfer of irradiated fuel.
The inspectors made frequent tours of the RCA. and reviewed and
discussed specific procedural guidance, selected survey results and
postings. The site dose expenditure and dose expenditure for selected l
U2RF11 tasks were reviewed and discussed with HP supervisors and ;
technicians. l
In addition. FNP OR Number 96-227 dated October 7. 1996, documenting
details of a worker who exceeded plant administrative quarterly dose
limits and an associated discrepancy between his thermoluminescent
dosimeter (TLD) and digital alarming dosimeter (DAD) monitoring results
were reviewed and discussed. The status of licensee followup actions
regarding the event were discussed in detail.
b. Observations and Findinas
Excluding two identified events involving BIT system maintenance and
laundry 3rocessing, all work activities observed were conducted IAW the
establisled RWP requirements. Initial reviews and surveys to establish
controls and postings were IAW FNP-0-RCP-4 Refueling Survey. Rev. 13a.
dated October 21, 1996. Administrative and physical controls, and
established postings within the auxiliary building during movement of
irradiated fuel were verified to be adequate based on measured dose
rates.
TS 6.11 requires, in part, that procedures for personnel radiation
protection be prepared consistent with the requirements of 10 CFR Part
20 and be approved, maintained and adhered to for all operations
involving personnel radiation exposure. Procedure FNP-0-M-001. Health
Physics Manual. Rev. 12. effective July 14. 1996. Section (S) 6.4
requires any entry into the RCA to be governed by a RWP. During tours
of the RCA during the week of October 21, 1996, the inspectors
identified the following issues.
e On October 22, 1996, a worker performing maintenance on the BIT
recirculation pump equipment located adjacent to the auxiliary
building 100 foot elevation batching crea, was observed kneeling
and crawling within an area posted as " contaminated" without the
required coverall dressout specified by RWP-096-0196. Special
Plant Maintenance, effective October 1. 1996.
e On October 24. 1996, a HP support worker was observed operating
the automated laundry monitor (ALM) without proper gloves and shoe
covers as required by RWP-096-0081. Waste Processing. Rev. O.
effective January 1, 1996.
Enclosure 2
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.
,
.
28
Initial corrective actions for the identified RWP compliance concerns
included work stoppage, counseling of individuals involved and
subsequent discussions with supervisors. None of the involved
individuals were found to be contaminated during RCA exit surveys. For
the BIT maintenance work issue, the inspectors requested the licensee to
conduct contamination surveys within the posted contaminated area where
the work was observed on the auxiliary building 100 foot elevation.
Licensee survey results indicated contamination levels (beta / gamma) were
less that 200 disintegrations per minute per 100 square centimeters, j
Discussions with HP staff indicated that the area was posted as a
contaminated area due to the potential for release of contamination from
within the BIT equipment during the maintenance activities. The
licensee initiated FNP OR Nos. 96-1002 and 96-1003 for the identified !
RWP compliance concerns. On October 25. 1996, licensee representatives {
informed the inspectors that preliminary review indicated that observed )
improper dressout observed for the ALM operations resulted from i
misinterpretation of RWP requirements by the responsible supervisor of
the involved worker.
On October 25, 1996, the inspectors attended and observed a pre-job
briefing associated with removal of the SG manway diaphragms. !
Meaningful discussions between HP and maintenance staff were noted i
regarding changes to previous storage practices following diaphragm i
removal. Previous use of large shielded containers were discontinued i
with new storage to be provided using drums containing water for
shielding. The use of the water filled drums improved dose reduction
efforts and reduced safety concerns associated with movement of the ;
large containers within containment. From subsequent discussions with i
licensee representatives regarding this change, the inspectors noted I
that although evaluated, the licensee had evaluated the change in i
storage methods qualitatively, a detailed evaluation of the dose i
reduction effect using the new water filled drums was not documented. i
The ins)ectors reviewed and evaluated licensee actions associated with
FNP OR io. 96-27. dated October 7, 1996. The report documented an HP ,
support individual's dose as measured by TLD of 1122 millirem (mrem)
which exceeded the established administrative quarterly limit of '
1000 mrem. Licensee followup also identified a significant difference,
a] proximately 44 percent, between the TLD and the DADS used to monitor 1
tie worker's dose for the quarter. On average. TLD to DAD monitoring
result comparisons were less than five percent. The worker was excluded
from further RCA entries and an investigation initiated. Review of the
individual's daily DAD entries, indicated maximum potential for exposure
to elevated dose rates occurred on September 6 and 10. 1996, during
placement of spent filters in High Integrity Containers in a Radwaste
exclusion area. General license followup included interviews of all
personnel involved and review of radiation control 3ractices associated
with the subject filter placement: verification of JAD calibrations and
calibrator operation, and confirmation of TLD readings; and
determination and evaluation of filter isotopic data and energy response
Enclosure 2
.
.
29
of personnel monitoring equipment. The licensee had assigned the
subject individual the 1126 mrem exposure resulting in a year-to-date
(YTD) total effective dose equivalent (TEDE) exposure of 1160 mrem. At
the end of the onsite inspection, no definite causes for the observed
differences between TLD and DAD quarterly dose results were identified
and licensee evaluations were continuing.
As of October 24. 1996, maximum TEDE results 1160 and 806 mrem, were
reported for two individuals involved with handling spent filters within
the radwaste facilities in September 1996. Extremity shallow dose
exposure results of 5762 and 5414 mrem were reported for these
individuals. For the outage activities reviewed, the maximum individual
dose, i.e.. deep dose equivalent, of 300 mrem was documented for a
contractor involved with eddy current testing.
. c. Conclusions
In general. RWP guidance was adequate for routine RCA and U2RF11 outage
activities. Documentation of detailed dose reduction efforts and
calculations 'should be improved. Excluding one individual, all personal
exposures were less than administrative limits and all individuals were
within regulatory limits. Licensee review and followup actions for a
worker exceeding quarterly administrative dose limits were adequate.
Two examples of inadequate implementation of RWP dressout requirements
were observed. These examples were identified as Violation (VIO) 50-
348.364/96-13-05. Failure to Follow Radiation Work Permit For Use of
Proper Protective Clothing .
R1.2 Imolementation of the ALARA Proaram
a. Insoection Scoce (IP 83750 and 84750)
The licensee's ALARA program guidance and implementation associated with
the current outage activities were discussed and reviewed. In addition. 1
selected radiation control performance indicators were reviewed and
discussed with licensee representatives.
b. Observations and Findinos
For 1996 which included a single refueling outage, licensee
representatives established a dose goal of 250 rem. This dose
expenditure for the site is similar to the 251 rem expended in 1994,
also single outage year. As of October 23. 1996, the licensee YTD dose
expenditure was documented as 10.503 rem compared to a predicted
exposure of 43.925 rem. The difference was expected, in part, as a
result of delays in the outage schedule.
The amount of contaminated floor space, excluding containment and
exclusion areas, was repcrted as less than or equal to approximately
eight percent since 1994. As of September 27, 1996. licensee listed 5.5
Enclosure 2
a
.
- . .
30
percent of floor space as contaminated, a slight decrease from 5.7
percent reported in Jan 26, 1996. Similar values. 5.26 and 8.38 3ercent
were reported for April and July 1995 respectively. For 1994, t1e
licensee reported contaminated floor space ranging from 6.0'to 8.2
percent.
For 1996, only one personnel contamination event (PCE). defined as
contamination levels exceeding 5000 disintegrations per minute, was I
reported. For single and dual outage years of 1994 and 1995, the
licensee listed 55 and 74 PCEs, respectively. The majority of PCEs were
identified for contractors and were associated with poor work practices.
The inspector reviewed ALARA initiatives conducted during the U2RF11
outage IAW the long-term exposure reduction program outlined in FNP
Exposure Reduction Plan, dated May 1993. The inspector discussed and
verified implementation of the following ALARA program items including
cobalt reduction, crud trap flushing, early boration, elevated pH and
boron / lithium management, improved ALARA training and awareness, remote
personnel monitoring, robotics and selected SG maintenance enhancements.
The licensee had suspended the zinc injection program since the U2RF9
outage but was expected to resume its implementation during the current
outage.
c. Conclusions
Implementation of established ALARA program activities was verified. No
significant negative trends were observed for the performance indicators
reviewed.
R2 Status of (RP&C) Facilities and Equipment 1
R2.1 Tours of the Unit 1 and 2 Radioloaically Controlled Areas (IP 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 considering ongoing outage activities, were much
better maintained than in the past (see Section 02.1).
R2.2 General walkdowns of radiation monitorina systems
a. Insoection Scooe (IP 83750 and 84750)
The inspectors reviewed and evaluated general housekeeping and verified,
where applicable, operability of selected process and effluent RMS
detectors, electronics, sampling lines and flow meters. The following
RMS samplers or detectors, i.e. radiation elements (REs), and associated
equipment were included in the walkdowns: Unit 1 (U1) containment
atmosphere particulate (RE-11) and gas (RE-12): U1 turbine building
Enclosure 2
. _ _ _ _ . _ _ _ . _ . . . _ _ . _ _ _ . _ _ . _ _ _ _ . _ _ - _ _ _ . _ ,
.
4
.
s
31
ventilation exhaust normal range (RE-15): U1 & U2 plant vent gas (R-
298) and particulate (RE-29A): MCR air supply (RE-35A&B): and U1 & U2
- . post accident sampling system airborne particulate (RE-67).
In addition, the inspectors reviewed and discussed program guidance and
testing of air to ensure service air compressor system supplied Grade D
respirable air for use, as applicable, during U2RF11' job evolutions.
,
b. Observations and Findinas
,
In general. housekeeping practices associated with RMS detectors and
equipment were improved relative to conditions observed for the period
of August 12-16. and 26-30. 1996 and documented in-IR 50-348. 364/96-10.
- dated September 27, 1996. Only two examples of poor housekeeping
L practices associated with the RMS equipment skids or sample locations
l were noted during equipment walkdowns conducted on October 25, 1996.
The examples included unsecured equipment stored within the U1 plant
vent particulate (RE-29A) sampler area and excess filter pa)ers being
stored within the U1 Plant Vent sampler cabinet (RE-29B). _icensee
l representatives stated that the identified concerns would be corrected
in a timely manner.
The inspectors also verified that the service air compressor system was
tested to certify supplied breathing-air as Grade D for potential use
l
during outage activities. Licensee representatives collected Unit 2
'
containment breathing system air samples on October 15, 1996. IAW FNP 2- l
RCP-112. Sampling of Service Air to Meet Respiratory Limits, dated ;
September 9. 1996. Sample-results verified that the U2 containment air
quality exceeded the established limits for Grade D air based on the
Compressed Gas Commodity Specification G7.1.1973.
c. Conclusions
Overall. no significant concerns were identified for RMS operability and
for certification of the supplied breathing air equipment. Licensee
tests verified that the service air compressor system supplied Grade D ]
respirable air IAW 10 CFR 20. Appendix A requirements.
R3 RP&C Procedures and Documentation l
a. Insoection Scooe (IP 83750)
Records of the previous 1996 YTD occupational radiation doses for
approximately 20 contractors hired specifically for U2RF11 outage tasks !
- were reviewed and discussed with licensee staff. l
L
i
The inspectors also reviewed selected effluent release data. In
i particular the inspectors reviewed and discussed abnormal effluent
i releases documented for the period 1994 through October 21, 1996.
3 Enclosure 2
i- !
I
i
4
- , , . , , . . - . - . , . . _ . , . - . .n _. .,-~r.-, , _ _ _ , .
,,
. _ _ . . _ _ _ _ _ . _ _ . _ _ . _ _ __ _ . _ _ __
i .'
'
l-
l
32
b. Observations and Findinas *
The inspectors verified that all contractor persennel had provided a
signed u)-to-date NRC Form 4, or equivalent ar;or to conducting initial
work witlin the RCA. Further the licensee lad received, or was in the
l process of obtaining reports of each individual's 3revious 1996 dose
L equivalents from the most recent employers for worc involving radiation
I
exposure.
l For 1994 no abnormal effluent releases were identified. In 1995 only
one abnormal effluent release associated a small U1 primary to secondary
, leak and the venting of the atmospheric relief valves following a U1
l -reactor trip was identified and evaluated. The event as documented in
'
chemistry incident report (CIR) 1-95-009. resulted in a increase-in
offsite dose. For 1995, dose estimates from all effluents were a
t fraction of a percent of the allowable offsite dose calculation manual
(0DCM) limits. As of October 21. 1996, three abnormal effluent releases
'
were reported and documented in CIRs-1-96-19. 1-96-30, and 1-96-33. The ,
inspector noted that CIR 1-96-19 documented and calculated a negligible ,
dose effect from required surveillance testing of the U1 TDAFW Jump
during a small primary to secondary leak. The two remaining CIls
l identified a continuous leak of effluents containing tritium through the
l U1 MS line atmospheric relief valve. Effects of the leak were to be
l documented in the 1996 annual effluent report,
c. Conclusions
l Licensee records of previous dose estimates for outage contractors were
being completed IAW 10 CFR 20.2104 requirements. Documentation
regarding effluent releases was prepared IAW ODCM requirements and
demonstrated release data verified offsite doses were small fraction of
a percent of the allowed limits. The number of abnormal releases have
increased since 1994, mainly, as a result of U1 primary to secondary
leakage associated with required or inadvertent ecuipment operation, or
maintenance problems. These abnormal releases hac a negligible
contribution to offsite doses.
!
l R6 RP&C Organization and Administration
i
a. Insoection Scooe (IP 83750)
!
l Recent changes to the HP organization and staffing levels for the U2RF11
outage relative to the 1995 U2RF10 were reviewed and discussed. From
facility tours and observations of work in progress the inspectors
evaluated staffing adequacy and proficiency of the HP technicians
providing job coverage.
I
Enclosure 2
- - - - -
,. -
. .
. . - - - - . - - _ . - - - - _ - - - - -- . _ . - , - - - -
t .
'
4-
i-
- 33
4
I
b. Observations and Findinas >
The HP organization and permanent staff for routine operations have
remained relatively stable. Since a previous U2 refueling outage in
-
1995, the only organizational change involved combining the plant health
i physicist and radwaste supervisor positions and elimination of a
! permanent HP technician position. Currently, the permanent HP staff
>
physicists /radwaste su)ervisor, five iP foremen and 33 senior
- technicians. During t1e current outage, the licensee sup)1emented the
i- staff with approximately 50 contract HP 3ersonnel and 21 iP and ,
J
chemistry staff members from Vogtle and latch Nuclear Plants. Overall. I
'
j the numbers of non-permanent HP personnel employed during the current
i outage decreased by approximately 15 technicians, approximately ten
- junior and five (senior) HP technicians since the previous U2RF10
outage. I
! No concerns regarding job coverage nor HP technician proficiency were
l identified during observation of fuel movement. RHR pump maintenance,
i and SW valve replacement activities.
c. Conclusions !
! No concerns were identified for the current organization. The amount of
j job coverage and proficiency of HP technicians were considered adequate
- for the early outage tasks observed. j
.
l R7 Quality Assurance in RP&C Activities
1
R7.1 Licensee Self-Assessment Activities
a. Insoection Scooe (IP 84750)
The inspectors reviewed and discussed the detailed plans for audits
scheduled to be conducted during the U2RF11 outage. The following audit
plans were reviewed in detail.
e Safety Audit and Engineering Review (SAER) Audit Report No. 96-
0A/41-1 Refueling Outage Activities
e SAER Report No. 96-PRM/23-1. Primary Vendor Services Audit
e SAER Report No. 96-FL/27. Fuel Loading
e SAER Report 96-PRTP/32. Post Refueling Test Program
In addition, supplemental audit staffing was reviewed and discussed.
.
Enclosure 2
_. _ _ _ . . _ . . _ _ _ _ _ __ _ _ _ . . _ _ _ _ . _ _
< .
,
t
34
'
b. Observations and Findinas
Review of the audit plan details verified that radiological 3rotection
issues were included in the SAER evaluations scheduled for t1e current
outage. Audit plan details included, in part, observation and
'
verification of radiological work controls for routine outage activities
and radiography practices internal exposure controls, housekeeping and
cleanliness, personal qualifications and certifications, and
verification of completion of Standard Test Procedures conducted during
the outage. From review of audit plans and discussions with SAER
auditors, the inspectors determined that specific job evolutions to be
reviewed included radiological controls associated with U2 fuel
movement, SG maintenance and SW valve replacement activities. The
inspectors directly observed auditors conducting radiological work
practice observations for auxiliary building SW valve replacement and U2
containment fuel movement activities.
An additional outside auditor with senior reactor operator (SRO)
experience was scheduled to assist the FNP SAER group during the current
outage, In addition, SAER management stated that in response to
concerns addressed in NRC IR 50-348/96-10, 364/96-10 dated September 27,
1996, an individual from the Vogtle Nuclear Plant with extensive
chemistry and radiation arotection experience was scheduled to
participate in a future RP&C audit in early 1997.
,
l
c. Conclusions
No concerns were noted for ongoing and proposed audits of radiation
control and chemistry activities. The scheduling of outside auditors to
assist in review and evaluation of RP&C. program areas was considered a
program enhancement.
R8 Miscellaneous RP&C Controls Issues (92904)
R8.1 (Closed) LER 50-348. 364/95-06: Licensed Material Shicoed to Incorrect
Destination by Common Carrier
This LER was a minor issue and was closed.
S1 Conduct of Security and Safeguards Activities
S1.1 Routine Observations of Plant Security Measures (IP 71750)
During routine inspection activities, resident inspectors verified that
portions of site security program plans were being properly implemented.
This was evidenced by: 3 roper display of picture badges by plant
personnel: appropriate cey carding of vital area doors; adequate
stationing / tours of security personnel: proper searching of
packages / personnel at the primary access point and service water intake
structure; and adequacy of compensatory measures (i.e., posting of
Enclosure 2
- .
35
guards) during disablement of vital area barriers. Security activities
observed during the inspection period were well performed and appeared l
adequate to ensure physical protection of the plant. Guards were
observed to be alert and attentive while stationed at disabled doors and !
access covers to critical underground equipment (e.g., SW system valve
boxes). Posted positions were manned with frequent relief.
S8 Miscellaneous Security and Safeguar,ds Issues (IP 71750) l
S8.1 (Closed) URI 50-348. 364/96-09-05: Failure to Search Contractor Trailer
Prior to Entry Into the Protected Area (PA)
On October 10, 1996, a resident inspector observed security guards
escort a Westinghouse sludge lance trailer into the PA that was not
searched. The trailer was posted as a RCA. A security guard outside
the PA gate did search the truck, cab, and driver prior to entering the
PA. After subsequent review of licensee corrective actions, and
interviews with responsible individuals and su ervision, the inspector
concluded that this instance constituted a vio ation of the FNP Security l
Plan, section 4.4.2 that requires searching all vehicles. materials and
packages prior to entering the PA. with certain exceptions established
as Categories I - IV. Categories I and III would allow certain types of
materials or packages to enter the PA without being searched as long as l
they were under continuous direct observation, or positive controls were ,
put in place, respectively. Categories II and IV did not apply to this '
situation. Also it was the inspectors judgement that the RCA boundary
around the trailer did not constitute a personnel hazard per Category
II. The other categories did not apply to this situation.
Security guards did not search the Westinghouse sludge lance trailer
prior to entering the PA. and subsequently relinquished direct
observation of the trailer without establishing positive control. A
search was not conducted until the following day on October 11. Upon
notification of the problem, immediate corrective actions were taken by
the Security Chief to promptly and effectively address the problem. By
the end of the IR period, longterm corrective actions were still being
pursued that should considerably improve effectiveness of future PA
searches. Good coordination was evident by the Security Chief with
other FNP departments and outside sources in developing a new permanent
policy. This issue is identified as VIO 50-348, 364/96-13-06. Failure
To Search Truck Trailer Prior To Entering Protected Area, and closes
this URI.
Enclosure 2
. . - . - - . . - . _ _ _ - - . - . - . _ . _ - - . - - . - _ - .
,
.
t . .;
~
1
j 36
j F2 Status of Fire Protection Facilities and' Equipment
F2.1 Doerability of Fire Protection Facilities and Eauioment
'
i
l
a. Insoection Scoce (IP 64704)
The inspectors reviewed the open maintenance W0s, maintenance history.
- and incident reports on the ' facilities . fire protection systems and
- features, and inspected these items to determine the performance trends
- and the material conditions of this equipment.
b. Observations and Findinas
i- Maintenance Observations:
As of November 12. 1996, the total number of open maintenance work '
- requests related to the fire protection systems and features was 81. *
l These work requests were grouped as follows:
5 :
j Kaowool Fire Barriers 38 i
Fire Protection Water Systems 34 ,
'
.
5
l C0're
Fi Doors 2 :
- Fire Pumps 1
Fire Detection System l
- 1 i
i 81 ;
i
- All except five of these work requests were issued in 1996. The work
requests issued prior to 1996 were minor repairs which did not affect
the operability of these systems. The Kaowool work requests involved a
j number of recently identified discrepancies. Work was in process to
-
correct these issues.
There was not a backlog of open work requests.
l
l Fire Protection Related Incident Reoorts: .
'
!
i The licensee initiated 54 incident reports from January 1. 1993 through
- October 31. 1996. on fire protection related items, such as fire pumps. -
l automatic sprinkler systems, fire detection system. CO2 systems, fire
- barriers, and fire watch activities. These incident reports were as
.
follows:
! Fire Protection System / Feature Number Percent
!
l
j Fire Pumps 14 25.8 !
- Fire Watch 9 16.4
j Sprinkler and Fire Hose Systems 9 16.4
Fire Alarm System 8 14.6
- CO2 Systems 8 14.6
1 Enclosure 2
a
.
$
_
. _ _ _ _ _ _ _ . _ - . . _ _ _ _ _ . . _ _ _ . _ . _ _ . _ _ . . _ _ . _ . . _.
,
.
t , i
i'
1
- - '
- 37
'
i Personnel Errors 4 7.1
i Fire Barriers 2 3.5
4
Fire Doors _1 B :
.
Totals 55 100.0
i Incident reports related to the recent Kaowool problems where not :
- included in this list.
s
- Most of the abnormal occurrences, exceat for the Kaowool problems. -
l during this period were related to pro)lems with the fire pumps, fire l
4
watches and water suppression systems. .
i
l
i Fire Protec' tion System Ooerability:
!
,
A review of the Fire Protection portion of the Plant's Daily Status
Report for November 12, 1996 indicated the following components or
systems were out of service:
l
j Fire Protection System Unit 1 Unit 2
i
,
i Kaowool Fire Barriers 49 24
i Fire Doors 8 16
Fire Barrier Penetrations 3 6
Automatic Sprinkler Systems 1 12
- Fire Hose Stations 0 1
- Fire Detection System 1 2
The inspector considered the number of fire protection systems out of 1
i service to be excessive. However, this high number was attributed to i
the current Unit 2 refueling outage and the repairs in process for the i
} Kaowool fire barrier discrepancies Appropriate compensatory measures
j had been implemented for the equipment which was out of service. ;
i
- The status report provided the licensee with a good means of identifying
j out of service fire protection equipment to assure that appropriate
compensatory measures were implemented.
] During the plant tours. the inspector noted that the maintenance and
'
material condition of the fire protection equipment were satisfactory,
exce)t for a significant number of pre-action automatic sprinkler valves
- whic1 were set wet. These valves are designed to be maintained in the
i close position and activate to the open position by signal from the
- associated fire or smoke detection system. When these valves are
- - maintained in the tripped or open position, the water flow alarms to
j these systems are placed out of service and sprinkler system actuation
1 would not be transmitted by the alarm system. This increases the
- possibility of water damage to plant equi) ment in the event of
inadvertent actuation of these systems. _eaving the pre-action valves
in the tripped position for appreciable long periods of time has been a
!
} Enclosure 2
I
i
>
- ,, , - _ . _
- _= -
-
~, . >
- .
.
38
normal practice at Farley for several years. This is identified as a
program weakness.
In March 1996, as documented by NRC IR Nos. 50-348, 364/96-02 and 96-07.
multiple failures occurred during the routine operability testing of the
pre-action automatic sprinkler system valves. Approximately 9 of the 27 1
pre-action system valves installed to provide fire protection for safety
related areas failed to operate automatically upon an actuation signal
from the fire detection system, i.e. the valves would not operate from
- the normally closed to the open water flow position. The licensee !
implemented additional preventive maintenance measures for these valves.
contacted the vendor for assistance and scheduled an accelerated
surveillance testing program. The surveillance testing of these valves
was changed from 18 months to two months. Prior to the August 1996
scheduled tests, two valves failed to operate 2n August 12 following an
l inadvertent action of the fire alarm panel. On August 22. during
l performance of the two month accelerated surveillance testing
- activities, one additional valve failed to operate either manually or-
automatically. The licensee assembled a root cause team and continued
to work with the vendor to determine the cause of these failures. One
of the failed valves was sent to the vendor's test laboratory for
further evaluation. The results of this evaluation were not available
at the conclusion of this inspection. The vendor was scheduled to
]articipate during the next surveillance testing of these valves in
)ecember 1996. The reliability of these valves is considered
questionable until the licensee identifies the cause of these failures
and implements appropriate corrective action to resolve the problem.
This issue is being tracked as IFI 50-348, 364/96-02-03, Pre-action
sprinkler system failures.
j From January 1993 through October 1996, multiple failures of the diesel l
-
engine driven fire Jumps to start on demand were identified or diesel l
engines had to be slut down due to operability problems. Exam)les of-
these problems included: inoperable electrical selector switcles,
! electrical starter switch, engine starter, engine batteries leaking
! engine coolant hose connector, ruptured coolant hose connector, and
i leaking oil from the lubrication system. The inspector reviewed
approximately 14 incident reports which had been issued on the diesel
driven fire pumps.
To establish a high confidence level on the operability of these pumps,
the automatic start surveillance test for the diesel driven pumps was
changed in May 1995 from monthly to every two weeks and the frequency of
the functional and capacity tests was changed from 18 months to
annually. The last recorded failure of a diesel driven fire pump was
September 26, 1995. The licensee )rovided the inspector with trending
, information which indicated that t1e performance of the two diesel
l driven fire pumps in the 18 months prior to November 1996 had improved
j as follows:
i I
! Enclosure 2
. . ., __ _ _ . - - -
._ _ __ _ _ _ _ _ _ -._ _ . _ _ _ _ . _ _ _ _ _ _ . _ . _
<
.
,
e
39
Diesel Driven Fire Pump 1 Three start failures in previous 228
demands for a reliability of 98.7%
Diesel Driven Fire Pump 2 No start failures in previous 195 demands 1
for a reliability of 100%
!
1
The licensee's program to establish a high level of confidence in the '
i
operability of these pumps was considered pro-active.
The licensee informed the inspector that replacement parts for the
station fire alarm control panels were no longer manufactured and were
becoming difficult to obtain. The existing system was operable but due
to the lack of replacement parts, future reliability may be a problem.
c. Conclusions
The number of outstanding work requests related to the fire protection
systems was high. However, there was not a backlog of outstanding W0s.
Corrective maintenance on degraded fire protection systems was being
acccmplished in a timely manner. The fire pumps and automatic sprinkler
systems sustained reliability problems during the past two years due to
.a number of operational failures. The licensee had taken positive
corrective action initiatives to resolve these concerns. This action
was effective for the fire pumps but currently has not been effective on
the resolution of the problems with the automatic sprinkler systems. !
Leaving the 3re-action valves in the tripped position for long
'
of time has )een a normal practice at Farley for several years.This periods
is
identified as a program weakness.
Replacement parts for the site fire alarm system were difficult to
locate. The system was operable but reliability may decline due to lack
of readily available replacement parts.
The daily fire protection status report was considered a positive means
of identifying degraded fire protection systems and to implement the
appropriate compensatory measures for inoperable systems.
F2.2 Surveillance of Fire Protection Features and Eauioment <
.
a. Insoection Scooe (IP 64704)
The inspectors reviewed the surveillances and tests scheduled for the
various fire protection systems and features to determine compliance
with UFSAR Section 9B Attachment C.
b. Observations and Findinas
Available documentation or cross reference material was not available to
indicate that'all of the tests and inspections listed by UFSAR Section
- 9B Attachment C had been incorporated into cppropriate plant
Enclosure 2
. -. . .. . .
.- - _ . - . - . . - . - - . - ~ . -. - - - . - _ - -
,
'
'
'
- . !
,
.
i
- '
40
!
l surveillance procedures. Therefore, the inspector selected 18 fire
i protection inspection and surveillance requirements from the UFSAR to
- verify that these items had been incorporated into the surveillance
procedures. It was noted that the operability test of the automatic
fire and smoke detectors did not meet the frequency listed by the UFSAR.
b UFSAR Section 98.C.1.1.2 requires accessible smoke detectors to be ,
demonstrated operable once per six months. The licensee had recently
, changed this test requirement. The new test requirement was to
demonstrate fire and smoke detector operability once per two years.
The licensee provided two 10 CFR 50.59 Evaluation Reports. Diesel
i Building Fire Detector Surveillance Frequency Revision dated September
i 24, 1996, and Change for Frequency of Smoke Detector Testing dated
i November 21, 1995. These evaluations used past satisfactory test
a
results and the bench test, sensitivity calibration and enhanced
cleaning and maintenance program performed on each detector every two l
years as justification for changing the test frequency. In addition,
the evaluation indicated that trending of the detector test program and
,
failures were to be monitored. If the failure rate increased, the two
- -year test frequency would be adjusted accordingly to ensure that
i adequate reliability of the fire detection system was maintained.
.
Tharefore, the justification provided to change the testing frequency
- from six months to two years was appropriate.
. c. Conclusion
, ;
.
The surveillance and tests of the fire protection systems and features
- met the frequencies specified by UFSAR Section 9B A)pendix C except for
the functional operability test of the fire and smote detector
instrumentation. The frequency of these tests was recently changed from
six months to two years. The evaluation performed by the licensee to
justify this change was appropriate.
.
l F3 Fire Protection Procedures and Documentation
.
a. Insoection Scooe (IP 64704)
a
'
The following Station Administration Procedure and Fire Protection
- Procedures were reviewed for compliance with the NRC requirements and
guidelines:
-
FNP-0-A0P-29.0 Revision 13. Plant Fires
-
FNP-0-EIP-13. Revision 14. Fire Emergencies
-
FNP-0-EIP-3401. Revision 3. Transient Fire Load Analysis
,
-
FNP-0-AP-35. Revision 20. General Housekeeping and Cleanliness
- Control
4
Enclosure 2
.
,
--
. . - _ _ _ _ _ _ _ . ~ . _ . _ _ . _ . - . _ _ _ . _ . - . _ _ . _ .
. .
-
L
41
-
FNP-0-AP-36. Revision 12. Fire Surveillance Procedures and
Inspections ,
-
' FNP-0-AP-37. Revision ll, Fire Brigade Organization
-
FNP-0-AP-38. Revision 10 Use of Open Flame
-
FNP-0-AP-39. Revision 12. Fire Patrols and Watches.
-
FNP-0-AP-45, Revision 15. Training Plan
Appendix P. Fire Brigade Training Program
Appendix 0 Fire Brigade Retraining Program *
-
FNP-0-AP-63. Revision 5, Conduct of Operations. Engineering
L Support Department. Section 2.1.4 Fire Protection Program ,
l Plant tours were performed to assess procedure compliance.
l
b. Observations and Findinas
The above procedures established the administrative guidance used to
implement the fire protection program at Farley and included the
- requirements for the control of combustibles, ignition sources and fire
l brigade organization and training. The procedures met the intent of the
l NRC reauirements.
-
l The operability, surveillance and test requirements for the fire
protection systems and features had been removed from the TSs and
incorporated into UFSAR Section 9B Attachment C. These requirements met
, the requirements for the fire protection features which were formerly in
! the TSs. except for the testing of the fire detection system as
! discussed in Section F2.2. However, an appropriate evaluation had been
l provided to justify this change.
i
- The inspector performed plant tours and noted that the general
l housekeeping related to the control of combustibles within the plant and
l implementation of the other fire prevention procedure requirements were
l satisfactory.
l
L c. Conclusions
l
, The fire protection program implementing procedure met the intent of the
l NRC guidelines and requirements. Implementation of the fire protection
l and prevention procedures and the general housekeeping for control of
l combustibles within the plant were satisfactory.
,
l'
! Enclosure 2
. - . .-
_ __
,
.
' .
,
42
F5 - Fire Protection Staff Training and Qualification
a. Insoection Scooe (IP 64704)
The inspector reviewed the fire brigade organization and training for
compliance with the facility's fire protection program and the NRC
guidelines and requirements and witnessed a fire brigade drill.
b. Observations and Findinas
The organization and-training requirements for the Farley plant fire
brigade were established by Procedure FNP-0-AP-37, Fire Brigade
Organization, Revision 11. The fire brigade for each operational shift
was composed of a fire brigade leader (operations shift foreman) and
three brigade members (non-licensed system operators) from operations
and one brigade member from security. The fire brigade leader was l
normally a licensed SRO. Each fire brigade member was required to '
receive initial, quarterly and annual fire fighting related training and
satisfactorily com)lete an annual medical evaluation to certify
participation in tie fire brigade. There were a total of 104 operations
personnel and 24 security personnel on the plant's fire brigade. j
The inspector reviewed the Training Department's training summary ;
records and verified -that the training for the fire brigade personnel ;
was up to date. A minimum of six drills were performed each quarter. and i
scheduled such that each fire brigade member attended at least two
~ drills per year. Most of the fire brigade drills had been unannounced
drills.
On November 13 the inspector witnessed a fire brigade drill involving a
simulated fire at the fire pumps' diesel fuel tank and fire pump house.
The fire brigade leader and four fire brigade members responded in full
fire fighting turnout gear. Personnel from HP and operations also ,
responded to the drill. The action by-the brigade met the established ,
drill objectives, except for some minor problems encountered with self
However, additional e
contained breathing apparatus.available if this equipment had actually been
was conducted with the fire brigade members following the drill.
c. Conclusions i
The fire brigade organization and training met the facility's procedure
requirements and the performance by the fire brigade to a drill during
this inspection was good. ;
.
Enclosure 2
'
.
'
.
.
43
F6 Fire Protection Organization and Administration
a. Insoection Scope (IP 64704)
The licensee's management and administration of the facility's fire
protection program were reviewed for compliance with the commitments to
the NRC and to current NRC guidelines
b. Observations and Findinas
The Plant Operations Assistant General Manager was designated as the
onsite manager responsible for the administration and implementation of
the fire protection program. The daily control of the fire protection
]rogram was assigned to the station Fire Marshal who reported to the
Engineering Support Supervisor under the management of the Engineering
Support Manager and the Plant Support Assistant General Manager.
Most of the surveillance ins)ections and tests corrective and
preventive maintenance for t1e fire protection systems and features were
provided by a designated maintenance team composed of three mechanical.
three electrical, and one I&C maintenance craft personnel, and two
system operators (non-licensed operators). This maintenance team worked
primarily on fire protection systems and other plant support systems
such as heating and ventilation components and was under the supervision
of the Maintenance Manager. The Fire Marshal reviewed all completed
surveillance and test 3rocedures and coordinated the maintenance work
activities to assure tlat appropriate inspections, tests and maintenance
were performed. Engineering technical support was provided as needed
from the engineering personnel on site and from the corporate office
staff in Birmingham. Alabama.
The responsibility for the fire brigade training was assigned to a fire
brigade training instructor in the Training Department.
There did not appear to be a formal program for trending fire protection
condition reports and performance of fire protection system te. sting.
However. periodic informal interface between the Fire Marshal and
various personnel assigned fire protection related functions was being
made to coordinate the implementation of the fire protection program.
c. Conclusions
The coordination and oversight of the facility's fire protection program
met the licensee's commitments to the NRC in the UFSAR. The personnel
assigned various fire protectico related functions were working together
as a team and with coordination by the Fire Marshal to implement the
fire protection program at the site.
Enclosure 2
-_ _ __ .. ._ _ . _ . . ___ . _ _ _ . - . _m.__ ._. _ _ _ _ _ . _ . _ _ . _
,
- .
44 :
F7 Quality Assurance in Fire Protection Activities
a. Insoection Scooe (IP 64704)
The following quality assurance (0A) audit reports were reviewed: ;
,
Audit dated 8/24/89 Station Fire Protection Annual / Triennial
Audit 1
Audit dated 5/30/90 Station Fire Protection Annual Audit
i
Audit dated 8/3/92 Station Fire Protection
Annual / Biannual / Triennial Audit
Audit dated 3/30/93 Station Fire Protection Annual / Triennial
Audit
Audit dated 5/17/94 Station Fire Protection Biannual Audit
Audit dated 8/19/94 Station Fire Protection Annual Audit
Audit dated 8/10/95 Station Fire Pr c'J
Annual / Biannual /Trienn.ai Audit
Audit dated 7/22/96 Station Fire Protection Annual Audit
b. Observations and Findinos
These audits were thorough and identified a number of findings.
recommendations and comments for program enhancements. A different
independent fire protection specialist was provided for each of the
audits. This provided different perspectives of the fire protection
program. The corrective actions taken on each of the audit findings,
recommended enhancements and comments from each 0A report were reviewed
by the inspector. The corrective actions for major discrepancies or
findings were found to have been completed in a timely manner. However,
action on the recommendations and comments which were made to enhance
the program were not addressed in a timely manner. Three of five
enhancement items in the 1993 audit, three of five in the 1995 audit and
two of five from the 1996 audits had not been completed. A formal
program was only provided to track the completion of the corrective
actions for major discrepancies.
c. Conclusions
The audits and assessments of the facility's fire protection program
were thorough and corrective actions were taken in a timely manner to
resolve major identified discrepancies. However, resolution on
recommendations and comments to enhance the fire protection program was
not timely.
Enclosure 2
. . - - . - . . = - - - - - - - - - - - - - . - . - - . ~ -. .-.. - . -
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j F8 Miscellaneous Fire Protection. Issues (IP 92904)
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F8.1. Fire Protection Related NRC ins
} a. Insoection ScoDe
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The inspector reviewed the licensee's evaluation for the following NRC
,
ins:
!
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IN 92-18. Potential Loss of Shutdown Capacity During a Control
Room Fire
]
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IN 92-28. Inadequate Fire Suppression System Testing
,
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IN 93-41. One Hour Fire Endurance Tests Results for Thermal
i Ceramics, 3M Company FS-195 and 3M Company Interam e-50 Fire
- Barrier Systems
IN 94-28. Potential Problems with Fire Barrier Penetration Seals
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IN 94-31. Potential Failure of WILCO LEXAN-Type HN-4-L. Fire Hose
i Nozzles
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IN 94-58. Reactor Coolant Pump Lube Oil Fire
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b. Observations and Findinas
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i The evaluations for these ins were. appropriate and the appropriate
actions had been completed, except for IN 93-41 and IN 95-36.
IN 93-41. One Hour Fire Endurance Tests Results for Fire Barrier Systems
l
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A review of the licensee's evaluation of the Kaowool one hour fire
, barriers installed at Farley found that these barriers did not meet the
!
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NRC guidelines of Generic Letter 86-10 Su]plement 1. The princi)le
deviations from the NRC guidelines were: (aowool was not tested Jy an
j independent laboratory in an approved large scale furnace, temperature
- measured on the external raceway exceeded 165 C [ tested raceways were
l approximately 426 C]. cable was damaged oy the fire tests, tested
'
configurations did not match in plant installations, and fire barriers
! were not subjected to a hose stream test after the fire test.
. Therefore, the adequacy of the installed fire barriers at Farley is
, being reevaluated by the NRC. This issue was previously identified as
! URI 50-348, 364/96-09-08 and remains open pending completion of the
NRC's reevaluation.
!
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- Enclosure 2
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IN 95-36. Emeraency Liahtina
The licensee was reevaluating this IN due to recent problems with the
Appendix R. 8-hour emergency lighting units. The licensee's
reevaluation of this IN will be reviewed during a subsequent NRC
inspection.
l
c. Conclusions
The evaluations and the actions taken on the reviewed ins were
appropriate, except for IN 93-41. An URI was identified for IN 93-41
concerning the adequacy of the one hour Kaowool fire barriers. The
licensee was reevaluating IN 95-36 for applicability at Farley.
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, High Energy Line Break (Outside Containment),
provides no description of the pressure differential switch high
detectors identified in TS 3.3.3.7 for High Energy Line Break
(HELB) Isolation Sensors. Inspection followup of the licensee
resolution of this omission is identified as IFI 50-348, 364/96-
13-07. Certain HELB Isolation Sensors Not Described In UFSAR.
X2 Exit Meeting Summary
The resident inspectors presented the inspection results to members of
licensee management on November 27. 1996, after the end of the i
inspection period. The licensee acknowledged the findings presented. - i
The resident inspectors asked the licensee whether any materials
examined during the inspection should be considered proprietary. No
proprietary information was identified.
Enclosure 2
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PARTIAL' LIST OF PERSONS CONTACTED ,
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l Licensee
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W. Bayne. Chemistry / Environmental Superintendent
R. Coleman Maintenance Manager
S. Fulmer. Technical Manager
H. Garland. Assistant Maintenance Manager
D. Grissette. Operations Manager
R. Hill, General Manager - Farley Nuclear Plant
R. Martin. Su)erintendent Operations Support
M. Mitchell, iealth Physics Superintendent
R. Monk. Engineering Support Supervisor - Equipment Evaluation
C. Nesbit. Assistant General Manager - Support
J. Odom. Superintendent Unit 1 Operations
l J. Powell. Superintendent Unit 2 Operations
l L. Stinson. Assistant General Manager - Plant Operations
l
J. Thomas. Engineering Support Manager
-
B. Yance. Plant Modifications and Maintenance Support Manager
W. Warren. Engineering Support Supervisor - Performance Review
l G. Waymire. Safety Audit and Engineering Review Site Supervisor
1
l NRC
J. Zimmerman Project Manager - Farley Nuclear Plant j
INSPECTION PROCEDURES USED I
! ;
l IP 37550: Engineering
IP 37551: Onsite Engineering
IP 40500: Effectiveness of Licensee Controls in Identifying. Resolving, and l
Preventing Problems !
IP 60710: Refueling Activities '
IP 61726: Surveillance Observations i
l IP 62703: Maintenance Observations !
l .IP 62707: Maintenance Observations
IP 64704: Fire Protection / Prevention Program
IP 71707: Plant Operations
IP 71750: Plant Support Activities
IP 73753: Inservice Ins)ection '
IP 83750: Occupational Radiation Exposure
IP 84750: Radioactive Waste Treatment. and Effluent and Environmental
Monitoring
IP 92901: Followup - Operations
i IP 92902: Followup - Maintenance
'
IP 92903: Followup - Engineering
IP 92904: Followup - Plant Support
i
Enclosure 2
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i ITEMS OPENED, CLOSED, AND DISCUSSED
?
! Ooened :
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T.ygg Item Number
_ Status Description and Reference
! URI 50-364/96-13-01 Open PRF Operability Requirements for SFP
- (Section 02.6). i
'
IFI 50-364/96-13-02 Open Increased Frequency Test Program for
Charging Pumps due to Cladding
l Cracking (Section M1.5).
- 3
IFI 50-348. 364/96-13-03 Open - Foreign Material From Seal . Injection
System To RCP Seals (Section M1.10).
URI 50-348, 364/96-13-04 Open Common Tap For SG Steam Flow
, Transmitter And SG Narrow Range
- Water Level System Fails To Meet
j IEEE-279 (Section E1.3).
,
VIO 50-348, 364/96-13-05 Open Failure to Follow Radiation Work
{ Permit For Use of Proper Protective
j Clothing (Section R1.1).
) VIO 50-348, 364/96-13-06 Open Failure To Search Truck Trailer
j Prior To Entering Protected Area
- (Section S8.1).
IFI 50-348, 364/96-13-07 Open Certain HELB Isolation Sensors Not
Described In UFSAR (Section X1). i
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Closed
l Tygg Item Number Status Descriotion and Reference
?
LER 50-348/95-10 Closed Actuation of Engineered Safety
, Feature Equipment Due to Loss of
3 Main Feedwater (Section 08.1). ;
- LER 50-364/95-08 Closed Reactor Trip During DEH Card
j Changeout (Section M8.1). !
1
1 IFI 50-348, 364/94-28-01 Closed Evaluation of Settings for Copes-
- Vulcan MOVs 8811A/8 and 8812A/8
Using the EPRI PPP Model (Section
, E8.1).
!
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Enclosure 2 i
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IFI 50-348, 364/94-28-02 Closed Evaluation of Settings for ;
4
Westinghouse Unit 2 MOV 8811A Using '
] the EPRI PPP Model (Section E8.2).
,
j IFI 50-348, 364/94-28-03 Closed Evaluation of Settings for Pratt-
4 Butterfly MOVs 'Using the EPRI PPP
j.
Model (Section E8.3).
! LER 50-348, 364/95-06 Closed Licensed Material Ship)ed to
! Incorrect Destination ]y Common
! Carrier (Section R8.1).
i URI 50-348. 364/96-09-05 Closed Failure to Search Contractor Trailer
Prior to Entry Into the Protected-
Area (Section S8.1).
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Discussed
!-
i 1322 Item Number Status pescriotion and Reference
!
' 50-348, 364/96-02-03
IFI Open Pre-action sprinkler system failures
l
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(Section F2.1).
h
i URI 50-348, 364/96-09-08 Open Adequacy of Kaowool qualification
j tests to scope installed
-
,
configurations (Section F8.1). '
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i: Enclosure 2
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LIST OF ACRONYMS USED
ALARA As low As Reasonably Achievable
ALM Automated u undry Monitor
Bhp Brake Horsepower
BIT Boron Injection Tank
BRT Bottom of Rolled Transition
CCW Component Cooling Water
CFR Code of Federal Regulations
CIR Chemistry Incident Report
CO, Carbon Dioxide
DAD Digital Alarming Dosimeter
DCP Design Change Package
EDG Emergency Diesel Generator
EPB Emergency Power Board
EPRI Electric Power Research Institute
E0 Environmentally Qualified
ETP Engineering Test Procedure
FCV Flow Control Valve
FNP Farley Nuclear Plant
HELB High Energy Line Break l
HP Health Physics I
HX Heat Exchanger !
IAW In Accordance With
ID Inside Diameter
IFI Inspector Followup Item l
Information Notice
'
IN
IP Inspection Procedure
IPE Individual Plant Examination
IR Inspection Report
ISI Inservice Inspection
IST Inservice Test
LCO Limiting Condition for Operation
LER Licensee Event Report
LOSP Loss of Offsite Power i
MCB Main Control Board
MCR Main Control Room
MOV Motor Operated Valve
mrem millirem
MS Main Steam
NORB Nuclear Operations Review Board
NRC U.S. Nuclear Regulatory Commission
ODCM Offsite Dose Calculation Manual
00S Out of Service
OR Occurrence Report
PA Protected Area
PAHA Post-Accident Hydrogen Analyzers
PCE Personnel Contamination Event
PDR Public Document Room
. pH The negative logarithm of the hydrogen concentration.
Enclosure 2
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PPP Performance Prediction Program
PPR Piping Penetration Room
PRF Penetration Room Filtration
OA Quality Assurance i
Radwaste Radioactive Waste !
RCA Radiologically Controlled Area
RCP Reactor Coolant Pump
RE Radiation Element
RG Regulatory Guide
RMS Radiation Monitoring System
RP&C Radiological Protection and Chemistry
RPC Rotating Pancake Coil i
RWP Radiation Work Permit l
RWST Refueling Water Storage Tank l
RxxCxx SG tube location (e.g. R20C26 - Row 20 Column 26) l
SAER Safety Audit and Engineering Review
SB0 Station Blackout
SFP Spent Fuel Pool
SI Safety Injection
SNC Southern Nuclear Operating Company
SOP System Operating Procedure
SRO Senior Reactor Operator
SS Shift Supervisor
STP Surveillance Test Procedure
TDAFW Turbine Driven Auxiliary Feedwater
TEDE Total Effective Dose Equivalent
TLD Thermoluminescent Dosimeter
TO Tag Order
TS Technical Specifications
U2RF11 Unit 2 eleventh refueling outage
UFSAR Updated Final Safety Analysis Report
UOP Unit Operating Procedure
URI Unresolved Item
UT Ultrasonic Testing
UTEC Ultrasonic Examination
VIO Violation
WO Work Order
YTD Year-to-Date
)
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Enclosure 2
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