ML20199H154
| ML20199H154 | |
| Person / Time | |
|---|---|
| Site: | Farley  |
| Issue date: | 11/17/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20199H100 | List: |
| References | |
| 50-348-97-11, 50-364-97-11, NUDOCS 9711260033 | |
| Download: ML20199H154 (43) | |
See also: IR 05000348/1997011
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U.S. NUCLEAR REGULATORY COMMISSION (NRC)
REGION 11
Docket Nos: 50-348 and 50-364
Report No- 50 348/97-11 and 50 364/97-11
License'. Southern Nuclear Operating Company. Inc.
Facility: Farley Nuclear Plant (FNP). Units 1 and 2
Location: 7388 North State Highway 95
s Columbia. AL 36319
Dates: September 7 through October 18, 1997
Inspectors: T. Ross. Senior Resident inspector (SRI)
J. Bartley. Resident inspector (RI)
R. Caldwell. R1
J. Canady - Itl from Hatch Nuclear Plant
(Sections M8.1 and M8.2)
N. Merriweather. Region 11 Reactor Inspector
(Sections E8.4 - E8.25)
J. Zimmerman. NRR (Section E1.2)
Approved by: P. Skinner. Chief. Reactor Projects Branch 2
Division of Reactor Projects
9711260033
971117
0 ADOCK 05000348
Enclosure 2
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EXECUTIVE SUMMARY s
Farley Nuclear Pcwer Flant. Units 1 and 2
NRC Inspection Report 50 348/97 11, 50-364/97-1)
This integrated ' inspection included aspects of licensee operations,
engineering, maintenance. and plant support. The report covers a 6 week
period of onsite resident inspector and region based specialist inspections.
Doerations
e Operator attentiveness to main control board (MCB) annunciator alarms
and response to changing plant conditions were prompt. Management's
persistent efforts to reduce the number of MCB deficiencies and achieve
" blackboard ~ were evident. Operating crews demonstrated a high level of
awareness of plant conditions and ongoing activities (Section 01.1).
c, Control Room professionalism, operator demeanor. teomwork. and
conduct of business in the main control room were appropriate and
effective. Shift supervisor (SS) command and control functions
and operations management oversight were evident (Section 01.1).
e Overall material conditions of Unit 1 and 2 structures, systems and
components (SSCs) were good. Almost all plant areas were clear of trash 0
and debris. Areas inside Unit 2 containment were in satisfactory
condition (Section 02.1).
- Safety system walkdowns and tours verified that accessible portions of
selected systems were adequately maintained and operational
(Sections 02.1 and 02.2).
e Operations had become complacent in its implementation of the Night
Orders Book (NOB). It was evident that some SSs were not always
reviewing the NOB in a timely manner (Section 03.1).
e Operations management implemented immediate and effective compensatory .
measures for Unit 1 by establishing more restrictive administrative
controls over primary coolant specific activity to address increased
projected end-of cycle (E0C) steam generator (SG) conditional tube
leakage (Section 04.1).
Maintenance
e Maintenance and surveillance testing activities were generally conducted
in a thorough and competent manner by qualified individuals in
accordance with plant procedures and work instructions (Section M1.1).
e Maintenance and sup) ort activities associated with the replacement of
PT456. Pressurizer >ressure Channel 2, were generally well-controlled,
and performed by competent and experienced personnel. A technical issue
concerning the adequacy of response time testing and the capability of
Foxboro transmitters to respond to high ramp rates was identified
(Section M1.2).
Enclosure 2
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e While the calibration and RTT associated with the realccement of PT456
were being )erformed. the OC supecvisor recognized tlat the transmitter
was not EQ 3ased on the purchase order number. (Section M1.2)
e Design change for R11/12 Containment Air Particulate and Gas Radiation
Monitors war properly implemented and exhibited good craftsmanship
(bection M1.3).
- Corrective actions were aroperly identified and satisfactorily
implemented for several _icensee Event Reports, and NRC violations and
open items (Section M8.1 through M8.7).
Emineerinq
e Engineering test procedure for fully withdrawing Unit 2 control rods to
a new position was well written and controlled. The evolution was
conducted in a smooth and deliberate manner (Section El.1),
o The NRC staff found Southern Nuclear Operating Company's (SNC's)
" Generic Letter 95-05 Safety Assessment" in response to Generic Letter 95-05 requirements to be adequate. Compensatory actions were
appropriate, and reporting requirements were adequately addressed
(Section E1.2).
o Overall. licensee response to identified service water pipe corroded
conditions was prompt and effective (Section E1.3).
e Resolution of Updated Final Safety Analysis Report (UFSAR) discrepancy
- 089 were not thorough. Calculations supporting the design of the a'.c
start system were non-conservative and were not validated against
existing air start test data. (Section E8.1).
- A violation was identifieJ for not performing reverse flow testing of
the turbine driven auxiliary feedwater (TDAFW) discharge check valve
V003 or V0020. F. and H to verify that the disk travels to the ser. on
cessation or reversal of flow (Section E8.6).
- A violation was identified for failure to recognize a TS change was
required for the safety evaluations performed for changes to the
Auxiliary Building Battery Service Test Procedure FNP-1(2)-STP.905.1 and
UFSAR Section 8.3.2 associated with PCN B-92-0-8099 to include the
results of Calculation 07597-E144 addressing design basis requirements
for battery duty cycle, load profile and voltage requirements (Section
E8.22),
o A violation was identified for failure to have a test program and
procedures for service testing of the TDAFW Class 1E battery to ensure
that the battery would meet the required battery duty cycle (Section
E8.8).
e A violation was identified for inapprc~iate acceptance criteria in the
surveillance procedure for verifying t.e forward flow of check valve
VO(n and for failure to follow drawings and instructions in the
Enclosure 2
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installation of the Unit 2 TDAFW battery structural / electrical component
installations (Section E8.7 and E8.9).
e A violation was identified because desigr control measures did not
ensure that calculations were verified and controlled adequately
(Section E8.16 and E8.25).
- A violation was identified for failure to correct a aeficiency
identified during the 1990 Safety System Self-Assessment (SSSA) of the
Component Cooiing Water (CCW) system involving differences between
Piping and Instrumentation Drawings (P&lDs) and procedures in
identifying caps on vent and drain lines (Section E8.20).
Plant Suonort
e On occasion, operators demonstrated poor work practices in applying
protective actions to prevent the inadvertent spread of contamination
during partial entries into contaminated areas. (Section R1.1).
e Overall cleanliness and housekeeping of radiologically controlled areas
(RCA) of the auxiliary building was good. Ongoing decontamination
efforts by the Health Physics (HP) department to reduce contaminated
surface areas were aggressive and continue to be successful (Section
R2.1).
e HP actions to address long-term storage of spent resins were prompt and
thorough (R8.1).
e An announced drill of the licensee's emergency plan was considered to be
reasonably challenging. Response facilities were manned and fully
03erational in a timely manner. Emergency response personnel properly
claracterized evolving events and made accurate and timely emergency
classifications and notifications (Section Pl.1).
e Security personnel activities observed during the inspection period were
performed well. Site security systems remained functionally adequate to
ensure physical protection of the plant (Section Sl.1).
- A violation was identified for failure to adequately control and mark
the Safeguard Information (SGI) maintained in the at-the-controls area
of the Main Control Room (Section $3.1).
Enclosure 2
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Report Details
Sunmary of Plant Status
Unit 1 operated continuously at 100% power for the entire inspection period.
Unit 2 operated continuously at 100% power for the entire inspection period.
On October 16. the unit reached 300 days of continuous operation at power.
I. Operations
01 Conduct of Operations
01.1 Routine Observations of Control Room Doerations
a. Insoection Scoce (Insnection Procedure (IP) 71707)
Inspectors conducted frequent inspections of ongoing plant operations in
the Main Control Room (MCR) to verify proper staffing, operator
attentiveness, adherence to approved operating procedures,
communications, and command and control of operator activities.
Inspectors reviewed operator logs and Technical S)ecification (TS)
Limiting Conditions of Operation (LCO) tracking sleets, walked down the
Main Control Boards (MCBs), and interviewed members of the operating
shift crews to verify operational safety and compliance with the TSs.
The inspectors frequently attended morning plant status meetings and
shift turnover meetings to maintain awareness of overall facility
operations, maintenance activities, and recent incidents. Morning
reports and Occurrence Reports (ors) were reviewed on a routine basis to
assure that the licensee properly reported and resolved potential
operational safety concerns.
b. Observations and Findinas
Overall control and awareness of plant conditions during the inspection
Seriod remained a strength, inspectors observed that the Unit 1 MCB.
Jnit 1 Balance of Plant (BOP), and the Emergency Power Board (EPB)
annunciator alarm aanels were frequently " blackboard." However, the
Unit 2 MCBs and B03 panels continued to have a few persistent
annunciators for known equipment problems. Management efforts to
maintain MCB deficiencies at very low levels and blackboard conditions
continued. The combined MCB deficiencies on Units 1 and 2 dropped to
ten, the lowest level for several months. Only two of the MCB
deficiencies were on Unit 1. The majority of the deficiencies involved
non safety-related instrumentation or equipment, and none resulted in a
TS LCO. Tagging and work control activities were conducted outside the
at-the controls (ATC) area of the MCR. Access to the ATC area was
controlled to limit unnecessary activities.
0)erator attentiveness to MCB annunciator alarms and response to
clanging plant conditions remained effective. Interviews with members
of the operating crew verified that they were consistently aware of
plant conditions and ongoing activities. There were no challenging
incidents or transients necessitating operator response during the
report period. Steady-state operations of both units were
Enclosure 2
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well-controlled and continued without any significant events. Operator
logs were of sufficient detail and scope. Shift staffing was verified
to be in compliance with procedural and TS requirements. Pre-shift
briefings of the operating crews by the shift supervisors (SS) were
generally concise and provided operators with shift direction and
priorities. Shift turnovers were accomplished in an orderly manner,
following a board walkdown by the off-going and on-coming operators and
SSs.
c. Conclusions
Control Room professionalism remained good. Operating crew
demeanor, team work, and conduct of business were effective. Unit
SS command and control, and operations management oversight were
evident.
0)erator attentiveness to MCB annunciator alarms and response to
clanging plant conditions were prompt. Management's persistent efforts
to reduce the number of MCB deficiencies were evident. The operating
crew consistently demonstrated a high level of awareness of existing
plant conditions and ongoing plant activities.
02 Operational Status of Facilities and Equipment
02.1 General Tours of Soecific Safety-Related Areas (IP 71707)
(:eneral tours of safety-related areas were performed by the inspectors
tcroughout both units to examine the physical condition of plant
equipment and structures, and to verify that safety systems were
properly aligned. These general walkdowns included the accessible
portions of safety-related structures, systems. and components (SSC).
Overall material conditions of Unit 1 and 2 SSCs were good. Almost all
)lant areas were clear of trash and debris. Some minor equipment and
lousekeeping problems identified by the inspectors during their routine
tours were reported to the responsible SS and/or maintenance department .
for resolution. None of the problems constituted an immediate safety or
compliance issue. However, some of the more significant findings
identified by the inspectors during routine plant tours did require
prompt response by the licensee, as follows:
1) The inspectors toured the Service Water Intake Structure (SWIS)
with the Team Leader (TL) responsible for the painters. The
inspectors pointed out the examples of the poor painting
preparation referenced in Inspection Report (IR) 50-348,
364/97-10. The TL concurred with the inspectors assessment. The
licensee's staff is evaluating methods to remove the old paint and
corrosion products from these areas for proper preservation and
painting. During the tour. inspectors also identified significant
external corrosion (i.e. , rust) on the 42-inch diameter Service
Water System (SWS) discharge piping where it penetrated the north
wall of the SWIS. The piping was subsequently examined by
Engineering Support (ES) personnel (see report section El.3 for
details), and properly cleaned and painted.
Enclosure 2
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2) On September 19. during a routine tour of the Emergency Diesel -
Generators-(EDGs), the inspectors identified that the locking tabs
for the IB EDG fuel rack jam nuts for cylinders 1,2.3.4,5.7.
8, 9 and.10 were not engaged. The inspectors verified that the
lock tabs were engaged on the 1-2A and 28 EDGs. The inspectors
immediately informed an SS. Occurrence Report (OR) 1-97-356 was
generated to document the issue. The licensee promptly evaluated
.the deficiency, checked the jam nuts to ensure'that they were not
--loose, and engaged the locking tabs. The licensee concluded that
-EDG operability was not impacted due to finding the jam nuts tight
prior to engaging the locking tabs.
3). During a routine tour on September 12. the inspectors identified
that an amphenol connection on the Unit 2 radiation monitor R29E
was disconnected. This lead provided power to the check source
mechanism for iodine detector Channels 3 and 4. The inspector
identified this to the SS and the lead was subsequently
reinstalled. The inspector reviewed Updated Final Safety Analysis
Report (UFSAR) Section 11.4, " Process and Effluent Radiological
Monitoring Systems " and found that paragraph 11.4.4.3 stated that
these radiation monitors would be source checked on a monthly or
quarterly basis. Although all of the TS recuired radiation
monitors were being regubrly source checkec , neither the
inspectors nor the licer >e could identify any procedures
requiring a monthly or quarterly source check of R-29A/B. This
UFSAR discrepancy was not previously identified by the licensee's
UFSAR reverification program. By the end of the report period,
the licensee was still investigating the need to conduct regular
source checks.
4) Although within TS required limits for level, the inspectors
questioned whether the 1A Accumulator water level was decreasing
at a faster rate than the other accumulators. Operations
personnel-performed a level trend analysis and were unable to
account for approximately 30 to 40 gallons of accumulator water.
At the next opportunity,
investigate a possible slow leak. Operations planned a containment entry to
5) Although previously identified as a deficient condition, the
inspectors found that leakage from the 1C. Component Cooling Water
(CCW) pump casing vent had increased significantly from its
original 1 drop per minute (dam) to 4-5 dpm. This increased
leakage resulted in considera)1y more uncontrolled wetting of the
pump skid surfaces with toxic, potentially contaminated chromated
water, After notifying the SS the inspectors observed that a
catch device was promptly installed.
While at power, a limited tour of the Unit 2 containment was conducted
on October 3,1997, in conjunction with a job to replace one of the
pressurizer pressure transmitters. The containment areas toured were in
satisfactory condition.
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Enclosure 2
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02.2 Biweekly Insoections of Safety Systems (IP 71707)
Inspectors verified the operability of the following selected safety
systems and/or equipment:
e Unit 2 High Head Safety injection (HHSI) System. A and B Train
e Unit 1 and 2 Residual Heat Removal (RHR) System. A and B Train
Accessible portions of the systems listed above were verified to be
properly aligned. The inspectors also observed them to be adecuately
maintained and in good operating condition. The inspectors dic not
identify any issues that adversely affected system operability. Minor
deficiencies noted were discussed with the appropriate SS. The
licensee's work to reduce the amount of potentially contaminated areas
has significantly improved radiological conditions in the Unit 1 A and B
Train RHR Pump Rooms. The majority of each room has been reclaimed
which allowed routine touring without donning protective clothing.
Decontaminatica efforts on the Unit 2 RHR pump rooms were in-progress.
These decontamination efforts were considered a proactive and positive
i ddiologiCal practice.
02.3 Verification of Safety Taaaina
a. Insoection Stone (IP 71707)
The inspectors verified that selected tagouts were implemented in
accordance with procedural requirements. The inspectors reviewed and
walked down selected devices tagged by the following tag orders (TOs):
e TO# 97-2283 Unit 1 Radiation Monitors Rll and R12
- TO# 97-2387-1 1B Emergency Air Compressor
b. Observations and Findinas
The inspectors verified that devices identified on the tag orders were
properly tagged. The device identifications were correct, tags were
conspicuously placed on the devices and the tags did not obscure control
room panel indications. The administrative aspects of filling out the
tagging order forms were complete and correct. The tags placed were
adequate for personnel safety and equipment protection.
c. Conclusion
The inspector; concluded that the reviewed safety tagging activities
were correct and met the procedural requirements.
02.4 TS LCO Trackina (IP 40500 and IP 717071
The inspectors routinely reviewed the TS LC0 tracking sheets filled out
by the shift foremen. All reviewed tracking sheets for Units 1 and 2
were consistent with plant conditions and TS requirements.
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103: Operations Procedures'and Documentation- ,
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03l1 Nicht Orders (IP 71707)
' Administrative procedure FNP-0-AP-16. Conduct of'0peration 1 0perations-
Group;: Revision 27. Section 6.2, establishes general requirements for
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the Night Orders-Book (NOB) maintained in the ATC area of the MCR. :
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Occasionallyr0perations_ management issued night orders for-the SSs to-
read and implement as appropriate. Resident inspectors routinely review J
the NOB for new entries. In the past. inspectors observed that the SSs-
were:very conscientious about initialing new night orders, acknowledging
that they had read and understood the entry. However, the inspectors -
frecently observed that- most of the SSs were no longer initialing new .
entries in the NOB. Although AP-16 did not require initialing of night
orders, this has been considered a good practice in the past.
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Furthermore, based on inspector interviews with SSs during the week of
-September 15. it became evident that some SSs were not always reviewing
the NOB in a timely manner (even when a specific entry'that expressly
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requested that it be-reviewed prior to going on-shift). The inspectors
discussed the use and purpose of the NOB with Operations management to
better understand its role and management expectations. After these
discussions..the N0B was reorganized to improve its useability and SSs
were coached-regarding its purpose.
04 Operator Knowledge and Performance
[ 04.1 Administrative Limit For Primary Coolant Activity-(IP 71707)
On September 11. Southern Nuclear Operating Company (SNC) held a
L conference call with the NRC to discuss its latest results regarding
end-of-cycle (E0C) steam generator (SG) conditional tube leakage and
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burst calculations using data from the last Unit I refueling outage
(UlRF14). During this call SNC concluded that it was required by
Generic Letter (GL) 95-05. " Voltage-Based Re) air Criteria for
Westinghouse Steam Generator Tubes Affected )y Outside Diameter Stress
Corrosion _ Cracking." Section 6. to notify the NRC that the EOC accident -
leakage exceeded the site-allowable leakage limit for Unit 1. By letter
. dated September 12. SNC submitted its GL 95-05 safety assessment and
-compensatory measures (see report paragraph E1.2 below).
- . Also during the conference call. SNC committed to implement immediate
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compensatory measures for _ Unit 1 by establishing more restrictive
administrative controls over primary coolant specific activity. These
administrative controls would limit the specific activity of primary-
! coolant to.0.15-microcurie per gram dose equivalent I.-131 (DEI) for
steady-state conditions and to 9 microcurie 3er gram DEI for transient
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conditions. The new limits are one-half of t1e limits specified by
- ^TS 3.4~.9. Specific Activity. On the following day, the inspectors
verified' that the NOB contained an entry regarding the new
administrative . limit for' primary coolant specific activity, The
inspectors also interviewed the Unit 1 day-shift SS- regarding his
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-knowledge of--the new DEI-limits. The inspectors also verified that all *
oncoming Unit 1 and 2 licensed operator crews were-subsequently briefed
on the new administrative limits prior to assuming on-shift duties.-
SNC's. commitment:to implement the more restrictive administrative limits
did not apply to Unit-2 until November 1.1997.
By letter dated September 17. SNC-submitted a license amendment for
UnitsEl and 2 to revise TS-3.4.9 to make it consistent with the more
restrictive' administrative limits for primary coolant specific activity.
II. Maintenance-
M1 Conduct of Maintenance
'M1.1- General Comments
x a. -Insoection Scone (IP 61726 and IP 62707)
Inspectors observed and reviewed portions of various licensee corrective
and preventive maintenance activities, and witnessed routine
surveillance testing to determine-conformance with plant procedures,
work instructions, industry codes and standards. TSs. and regulatory-
requirements. The inspectors observed all or portions of the following
maintenance and surveillance activities, as identified by their
-associated work order (W0), work authorization (WA), or surveillance
test procedure (STP):
e FNP-2-STP-80.1 2B EDG Operability Test. Revision 24
e FNP-1-SOP-7.0A
- Residual Heat Removal System
o FNP-1-SOP-7.0 Residual Heat Removal System
.e W0#S00079791 Perform DCP S96-2-9060 on U2 R11/12
e FNP-1-STP-201.18 Reactor Coolant System TE-412A-and TE-4120 Loop
Calibration and Functional Test. Revision 39
e FNP-2-STP-256.4 Pressurizer Pressure Sensor. Response Time Test.
Revision 5
e W0#M97006793 1B Emergency Air Compressor
e W0#00487300
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Calibrate Train B Differential Pressure
Transmitter per FNP-1-IMP-218.2. Control Room
Differential Pressure PDT-2768B. Revision 8
e FNP-1-STP-226.1 BIG Sequencer Operability Test Revision 6
e WA# WOO 482489- -1B Auxiliary Build _ing Battery-Equalization per
FNP-1-EMP-1341.08. Revision 3
e FNP-1-STP-11.2 1B RHR-Pump Quarterly Inservice Test. Revision
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e WA#W00483S49~ Preventative maintenance task on 2A Boric Acid
Tank temperature indication and alarm
b. Observations. Findinos and Conclusions
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.All observed maintenance work and surveillance testing was-performed in
accordance with work instructions procedures, and applicable clearance
controls. In general, safety-related maintenance and surveillance
1 testing evolutions were well-planned and execut: d. Responsible
l, personnel demonstrated familiarity.with administrative;and radiological
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controls. Surveillance tests of safety-related equipment were.
consistently performed in a deliberate step-by-step manner by personnel
in close communication with the Main Control Room (MCR). Overall,
operators, technicians, and craftsman were observed to be knowledgeable,
experienced, and well trained for the tasks performed.
M1.2 Reolacement of Unit 2 Pressurizer Pressure Transmitter
a. Insoection Scone (IP 62707 and IP 61726)
The inspectors observed maintenance and surveillance activities
associated with the replacement of 02B31PT456. Pressurizer Pressure
Channel 2. Specific activities included observation of time response
testing and calibration of the new transmitter, observation of various
pre-job briefings, reviews of completed test and calibration data
sheets, and an-at-power containment entry to observe installation of the
new transmitter. The inspectors reviewed FNP-2-STP-256.4. " Pressurizer
Pressure Sensor Response Time Test." Revision 5. FNP-0-IMP-430.16.
" Environmentally Qualified Instrument Replacement Procedure."
Revision 11'. FNP-2-STP-201.5. " Pressurizer Pressure PT-456." Rev. 22.-
Updated Final Safety Analysis Report (UFSAR) Section 15.4. " Condition IV
- Limiting Faults." UFSAR Section 7.2. " Reactor Trip System."
Westinghouse WCAP-13632. " Elimination of Pressure Sensor Response Time
Testing Requirements." Rev. 2. Electric Power Research Institute (EPRI)
' Report NP-7243. " Investigation of Response Time Testing Requirements."
and TS 3.3.1 requirements for reactor trip system instrumentation.
b. Observations and Findinas
On September 17.1997. PT456 drifted up approximately 10 pounds per
square inch gauge (psig) over an 8-hour period. On Seatember 23. PT456
failed a channel check and was declared inoperable. T1e licensee
initiated an LC0 and placed Channel II in trip within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, per
TS 3.3.1. Action 7. Occurrence Report (OR) 2-97-361 was generated to
document the failure.
Work order #97006926 was issued for re)lacement of PT456. On
September 24. the inspector observed t1e calibration and response time
testing (RTT) of the replacement Barton Model 763 pressure transmitter.
The calibration was performed in accordance with plant procedures with
no discrepancies.
While the calibration and RTT were being performed. the licensee
discovered that the replacement transmitter was not environmentally
- qualified (E0) even though it had been issued as E0. This was
identified by Quality Control (OC) personnel while answering questions
Josed by maintenance concerning E0 splices for the transmitter pigtails.
Juring the discussions, the QC supervisor recognized that the
transmitter was not E0 based on the purchase order number. Maintenance
was immediately notified that the transmitter was not E0 and to suspend
work. The licensee generated OR 2-97-369 to document the deficiency.
The licensee did not have any more Barton Model 763 transmitters in
stock but was able to locate several at another plant and arranged to
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have two transmitters shipped. However, on October 2. due to'
-complications with documentation and span differences, the licensee
decided to install a Foxboro transmitter (Model NEll) the same.as
installed on Unit-1.
The Foxboro transmitter was-installed under Design Change Package (DCP)
S-97-2 9276. The physical changeout of the original Barton transmitter
only required changing the mounting bracket and rerouting the sensing
line. The inspectors reviewed the DCP and determined that it adequately
addressed the mechanical aspects of the modification. Westinghouse
Electric Corporation provided SNC an evaluation comparing the Foxboro
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and Barton transmitters which concluded that'the performance of the two
transmitters was the same with respect to the uncertainty calculations.
However, the DCP and associated technical evaluation worksheet, did not
address possible response ramp rate differences between the Foxboro and
Barton transmitters.
The inspectors observed the calibration and RTT of the Foxboro ;
transmitter. The calibration was completed again with no discrepancies.
The transmitter response time was determined to be within the specified
limit of 0.23 seconds.
Technicians identified a problem while installing the transmitter on the
manufacturer-provided seismic mounting plate. The 3/8-inch Grade 5
bolts supplied with the mounting plate were too long. Therefore, the
maintenance staff shortened and rethreaded the bolts. When the
technicians attempted to torque one of the bolts, the threads stripped.
The licensee initiated OR 2-97-378 to document the event. The licensee
determined that the bolt failed due to poor workmanshi) when rethreading
the bolt. The licensee replaced the provided Grade 5 Solts with-
Grade B7 bolts. The inspectors concluded that this was adequate.
An inspector accompanied licensee personnel during the at-power entry
into Unit 2 Containment on October 3.1997, to observe installation of
the Foxboro transmitter. Inspectors attended the pre-job briefing and
ALARA briefings for Radiation Work Permit (RWP) 2-97-2490. The
briefings were comprehensive and com The containment entry was
conducted in a professional manner. plete.team demonstrated
The entry
teamwork and ex)editiously completed the assigned tasks. in tight
l quarters and a lostile environment. However, one problem arose due to
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not energizing electrical outlets in the work area prior to the entry.
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-The local portable air samples were unable to be collected. This pre-
planning issue was discussed with the on-shift SS.
- The ins)ectors subsecuently reviewed the Foxboro and Barton RTT data.
! UFSAR Clapter 15. anc background documentation. The inspectors
l identified an issue affecting the adequacy of the test procedure to
accurately measure the sensor response time. Accurately measuring
sensor response time is required to ensure that the total Reactor Trip
System (RTS) response time is less than the 2 seconds assumed in the
accident analysis. The RTS response time was defined in the background
documentation and licensee submittal as "...the time interval from when
the monitored parameter exceeds its trip setpoint at the channel sensor
Luntil loss of stationary gripper coil voltage."
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Enclosure 2
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The TS currently requires periodic time response testing of the RTS from
the output of the transmitters to the loss of stationary gripper coils.
The response time portion for the sensor is measured prior to installing
a new transmitter or after significant repairs to a transmitter. The
current limit-of 0.23 seconds for the transmitter was based on the
slowest response' time of a pressure transmitter determined through a
historical record search of FNP-transmitter respoilse times.
While reviewing the response time traces. the inspectors noted that
while the reference pressure transmitter was responding to the set ramp
rate of approximately 540 sig/sec, the Foxboro was only capable of--
responding at approximate 1 300 psig/sec. This difference in response
rate could be significant ecause the RTT procedure specified measuring
the response time for only a 40 psig 3ressure drop whereas the actual
pressure dro) during an accident is a)out 400 psig from normal operating
pressure (NO3) to the low pressure trip setpoint. If the transmitter
was able to respond at the tested ramp rate the test could adequately
measure the sensor response time. However, due to the transmitter's
slower response rate and the small 40 psig pressure drop. current RTT
does not accurately or conservatively measure sensor response time for
high ramp rates.
- The inspectors also reviewed the ex)ected Reactor Coolant System (RCS)
pressure ramp rate for large break oss of Coolant Accidents (LOCAs) as
identified in Section 15.4 of the UFSAR. Figures 15.4-3A through -3E
indicated that core pressure dro)s to 1600 asig in less than 0.5
seconds. This ramp rate was muc1 greater tlan even the tested 540
psig/second. The inspectors determined that, based on an actual
response rate of 300 psig/second the Foxboro transmitter could have a
real response time of approximately 1 second for the expected transient.
This is greater than the 0.23 seconds accounted for in the licensee *s
reactor. protection system (RPS) response time equations.
This issue was discussed in detail with licensee management on
October 8. On October 10. the licensee 3rovided the inspectors with the
test data Jackages for the most recent R)S and engineering safety
features (ESF) response time testing. The test data showed that, even
if I second was added to account for the slow response time of the
_
Foxboro transmitter, the RPS'and ESF time response would be within the
required limits. Also, the licensee identified that the accident
analysis for large break LOCAs did not depend on the control rod
insertion to shutdown the reactor. The accident analysis determined
that the reactor would be shutdown due to voiding and loss of moderator.
and would remain shutdown due to the injection of borated water from the
Refueling Water Storage Tank-(RWST) and cold leg accumulators. The
accident analysis information along with the current test data
alleviated the immediate safety significance of this issue.
Enclosure 2
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c. Conclusions
Maintenance and support activities associated with the replacement of
PT456 were generally well-controlled, and performed by competent and
experienced personnel. However, a non-E0 instrt. ment was inappropriately
issued for an E0 application and a re-threaded bolt failed due to poor
workmanship. Also, a technical issue concerning RTT and the capability
of Foxboro pressure transmitters to respond to high ramp rates was
identified. Due to the generic 1mplications of this issue, further
review will be cordacted by the NRC. This is identified as IFI 50-
364/97-11 01: RPS Response Time Testing.
M1.3 DCP S96-2-9060. Unit 2 R11/12 Containment Air Particulate and Gas
Radiation Moaitors (IP 62707 and P 37551)
The DCP was perfermed under WO S00079791 The purpose of the DCP was to
eliminate paper drive problems due to high flow rate through the paper
drive unit. The DCP accomplished this by bypassing approximately 40% of
the flow around the paper drive unit. The inspector reviewed the design
calculations (SJ-95-1024-001. Rev 0) and verified that Rll still met the
designed sensitivity with +.he reduced sample flow. The installation was
performed in accordante with the DCP. Craftsmanship was good. The
inspector verified that no new elbows of sharp bends were created which
could affect the sample flow.
H8 Miscellaneous Maintenance Issues (IP 92700 and IP 92902)
M8.1 (Closed) Licensee Event Reoort (LER) 50-364/97-03: Failure To Perform
Diesel Generator Surveillance Recuiremants Due To Procedural Inadecuacy
The licensee determined that the required 18-month surveillance of
TS 4.8.1.1.2.c.8 had not been performed on Unit 2 for EDG 1-2A. This
issue was discussed in Section M1.8 of IR 50 ^ 7. 364/97-05 and was
cited as an example of violation 50-348. 364 - 15-03.
The ins)ectors reviewed the Shared (Unit 1 and 2) Surveillance Schedule.
This scledule had a note for EDG 1-2A that instructed the Operations
group to ensure that the surveillance recu rements of procedure
FNP-0-STP-80.8. " Diesel Generator 1-2A 1000KW Load Rejection Test."
Rev. 10. were accomplished for each Unit.
. The inspectors were informed during discussions with licensee personnel
that procedure FNP-0-STP-80.8 was to be replaced with surveillance test
procedures FNP-1-STP-80.17 and FNP-2-STP-80.17. These procedures are
currently in draft and will enhance the licensee's corrective actions by
implementing unit-specific procedures for the 1-2A shared EDG.
Similarly, procedure FNP-0-STP-80.9 for the IC EDG was to be replaced
.with procedures FNP-1-STP-80.18 and FNP-2-STP-80-18.
Based upon the inspectors' review of documentation and the licensee's
'ctions this LER is closed.
Enclosure 2
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M8.2 (Closed) LER 50-348/97-05: Failure To Perform Nuclear Instrumentation
Surveillance Reauirements Prior To Mode 2 And 3 Entry
.-The licensee discovered that the reactor trip instrumentation
surveillance requirements of TS Table 4.3-1 were not met during a unit
shutdown on March 15, 1997. This issue was discussed in Section M1.8 of
IR 50 348, 364/97-05 and was an example of violation 50-348,
364/97-05 03.
The inspectors-reviewed the new maintenance surveillance test procedures
(Revision 0) for performing the nuclear instrumentation system (NIS)
source range channel level trip calibration and functional test. The
procedures are performed quarterly and ensure that the surveillance
requirement is met for functional testing while in mode 1. The
procedures are for source range channels N31 and N32 for both units.
The inspectors reviewed the licensee's Commitment Action Tracking
Licensing Information Processing System (CATLIPS). This system tracked
the licensee's corrective actions. Commitment #10172 of CATLIPS
documents the commitment to change the UFSAR to allow performing NIS
power range (PR) neutron flux low setpoint bistable calibration in
mode 1 to ensure that TS 4.3.1.1 surveillance requirements are met for
unit shutdowns.
The inspectors also reviewed the lessons learned training advisory
notice associated with the issues discussed in LER 50-348/97-05.
Based upon the inspectors * review of documentation and the licensee's
actions, this LER is closed.
M8.3 (Closed) Violation (VIO) 50-348. 364/97-05-03: Failure To Follow
Multiole TS Surveillance Reagjrements
The inspectors reviewed licensee corrective actions. Initial actions to
alleviate the adverse conditions satisfactorily addressed the immediate
issues. l.icensee Event Report 50-348/97-05. Failure To Perform Nuclear
Instrumentation Surveillance Requirements Prior To Mode 2 And 3 Entry.
documented the failtre to perform the quarterly functional tests and
shiftly channel checks for the NIS source range.(SR) and the NIS PR
channels low flux trip for mode 2. This LER was discussed and closed in
section M8.2 of this report. Licensee Event Report 50-364/97-03.
Failure to Perform Diesel Generator Surveillance Requirements Due to
Procedural Inadequacy, documented the missed surveillance associated
with not. conducting the 1-2A DG Load Rejection test for each individual
unit prior to taking surveillance credit. This LER was discussed and
closed in section M8.1 of this report. Selected u) dated Unit Operating
Procedures (UOPs) were reviewed and determined to lave been
appropriately revised. Additionally, the Shared (Unit 1 and 2)
Surveillance Schedule was reviewed and appropriate changes verified.
The inspector verified that training was provided to appropriate
personnel, concerning Code of Federal Regulations (CFR) 10 CFR 50.59
screening. Based on the licensee *s actions. this VIO is closed.
Enclosure 2
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M8.4 (Closed) liI 50-348. 364/96-09-04: CCW HX Ecoxy Coatino'and Broken Tubes
This item was opened to follow the performance of the epoxy coating
process used on the Component Cooling Water (CCW) heat exchangers (HXs)
and the-adequacy of the licensee's Nonconformance Disposition Reports
(NDR) in that the missing tube fragments would not impact the
operability of the CCW system.
The inspectors reviewed the' licensee's areventive maintenance (PM) tasks
for the CCW HXs and verified that a tas( was added to specifically
inspect the epoxy coating at 18-month intervals. The licensee inspected-
all three Unit 1 CCW HXs and one Unit 2 CCW HX after approximately three
to four months of onservice time. Some minor deficiencies were
identified and they were repaired prior to returning the HX to service.
The inspectors examined two of the HXs when they were opened for the
licensee's inspection. The coatings were intact with no signs of
separation from the base metal or erosion of material.
To assess the adequacy of the licensee's NDRs. the inspectors reviewed-
LERs written from January 1. 1997 to September 15. 1997. for instances
of foreign material probler's in the CCW system. The inspectors also
reviewed the documentation of licensee inspections of the CCW HXs and
interviewed the licensee personnel who conducted the inspections. No
issues involving foreign materials, i.e. tube fragments, were
identifled during the period reviewed. No further degradation of the
tubes, tube failures and fragmentation, were identified by the
licensee's subsequent inspections.
The inspectors concluded that the licensee's efforts to reduce erosion
of the CCW HXs tube sheets through epoxy coating were effective and the
coating was holding up well. The licensee's NDRs were accurate and
thorough as demonstrated by no instances of tube fragments impacting the
performance of the CCW system. The efforts to capture the broken and
severed tubes and establish " fences" to prevent tube fragment migration
were successful. Based on the inspectors review, this IFI is closed.
M8.5 (Closed) Inspector Followun item (IFI) 50-348. 364/96-13-03: Foreion
Material From Seal Injection System To Reactor Coolant Pumo (RCP) Seals
During the past Unit 2 refueling outage (U2RF11), very small pieces of
debris from the seal water injection filter 0-rings were discovered in
W e downstream seal water supply check valves. The inspectors reviewed
completed OR 2-96-325 and interviewed responsible personnel and
management. As part of their corrective actions, licensee maintenance
personnel inspected both seal injection filters, verified that existing
0-rings were in place, and lubricated the 0-rings per the vendor manual.
All three seal injection lines were subsequently flushed, with no
additional debris identified. Maintenance procedure FNP-0-MP-2.8.
' Replacement of Seal Injection Filters. Rev. O was written to ensure
proper installation of seal water injection filters, including 0-ring
Enclosure 2
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lubrication.- A 10 CFR E0.59 safety evaluation was also documented
regarding the potential introduction of foreign 0-ring material into the
reactor-coolant pump seals. This evaluation concluded that, due to the ,
size and constituency of the debris along with the torturous path of the-
RCP seal package, the likelihood of seal failure was minimal. This IFl
is closed.
M8.6 (Closed) LER 50-364/96-03: Steam Generator Tube Dearadation and Tube
Status
This LER was provided to satisfy TS 4.4.6.5.c which requires that steam
generator (SG) tube inspection results which fall into Category C-3
shall be considered a reportable event and reported ]ursuant to 10 CFR
50.73 prior to resumption of plant operation. The LER also served to
satisfy TS 4.4.6.5.a which requires that following each In-Service
Ins)ection (ISI) of SG tubes, the number of tubes plugged or repaired in
eac1 SG'shall be reported to the Commission within fif teen days of the
completion of the inspection, plugging, or repair effort. This LER is
closed.
M8.7 (Closed) VIO 50-348. 364/97-130 01014: Failure To Prescribe Document.ed
. nstructions For Procedures to Imolement Penetration Room Filtration
(PRF) Testina and Goeration
The inspectors reviewed the licensee's Commitment Action Tracking
Licensing Information Processing System (CATLIPS). Reply to the Notice
of Violation dated May 28, 1997. and procedures associated with the
applicable corrective actions. Twenty procedures were reviewed and
determined to have been appropriately revised in accordance with the
corrective action plan. Based on this review of the corrective actions
this VIO is closed.
III. Enaineerina
El Conduct of Engineering
E1.1. Unit 2 Rod Control Cluster Assemblies (RCCA) Full Withdrawn Rod Position
C!!Mlgt
a. Review Scone (IP 37551)
On September 19. a resident inspector observed Operations. Instrument
and Controls (I&C), and Engineering Support (ES) personnel im)lement
FNP-2-ETP-3607. RCCA Fully Withdrawn Repositioning At Power. Revision 0,
to fully withdraw the Unit 2 RCCAs from 225 steps to 226 steps,
b. Observations and Findinos
This infrequently performed evolution was briefed in accordance with
FNP-0-AP-92. Infrequently Performed Tests Or Evolutions. Revision 3. by
the Unit 1 Operations Superintendent. The procedure was well written
-and controlled by the ES test director. Operations personnel
implemented the procedure in a deliberate step-by-step manner under the
direct supervision of the ES test director and oversight of the
Enclosure 2
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- 0perations-Su)erintendent. The~ evolution went smoothly except that
annunciator F 5. COMP ALARM / ROD SE0/DEV. came into alerm and would not- ')
.
clearo 1This condition was investigated and later explained to thel
inspector as an expected phenomenum when considering the pre existing }
- digital. rod position' indication--(DRPI) Data A Channel failure.of rod
-J09.
t
c. Conclusions
The evolution was properly controlled and the reason for the annunicator ,
alarm was-adequately understood.
El.2E Generic i ztter (GL) 95-05 Reoortability and Safety Assessment
i
a. Review Scoce (IP 37551)
By-letter dated September 12.'1997. SNC addressed the reportability and
safety assessment requirements of GL-95-05. Section 6. The Materials
-and Chemical Engineering Branch of the Office of Nuclear Reactor- '
Regulation (NRR) reviewed SNC's letter using the criteria of GL 95-05.
Section 6. Specifically, the NRC staff reviewed SNC's safety
assessment compensatory measures, and reportability determination
(e.g. 10 CFR 50.72 or 50.73). .
b; Observations and Findinas
Voltage-based Steam Generator (SG) tube repair criteria was im)lemented
at Units 1 and 2. in accordance with GL 95-05. SNC evaluated tie affect
that recent SG tube leak and burst test results have on the End-of-cycle
.(EOC) conditional leakage and probability of burst calculations and
concluded that inclusion of the latest leak and burst test results
L caused Units 1 and 2 to reach the NRC staff notification limits of GL 95-05.
h ' GL 95-05 Section 6. Reporting Requirements, requires NRC staff
notification under certain conditions. One condition that requires NRC
staff notification occurs when a licensee determines that the E0C
accident' leakage will exceed the site-allowable leakage limit: another
occurs when a licensee determines the E0C conditional burst probability
exceeds 1 x 10. SNC calculated a limiting probability of burst-~to be
1.4 x 10' , which is below the NRC staff notification level. However,
when SNC incorporated the leak and burst test results from the recent
L -Unit 1 and 2. tube )ulls into the correlations used'as part of the GL 95-
-05 leakage and pro) ability of burst calculations, the projected E0C
. leakage from Unit 1 increased from 15.7 gpm to 20.4 gpm. This increase
i placed Unit -1 in-thelosition of having exceeded the =allcwable leakage-
'
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limit"of:13.7 gpm. . T1e revised E0C burst-probability was calculated to
be 1.2=x:10. -SNC also notified the staff that, with the most recent
! tube pull results-in the leakage and burst correlations the Unit 2 -
leakage was projected.to exceed the allowable leakage limit on November ;
l: 6L 1997 : The probability of bg'rst value remained under the NRC
notification limit- at 3.2 x 10 .
Enclosure 2 :
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On September 12. 1997, SNC provided the NRC staff a " Generic letter
95-05 Safety Assessment" for Unit 1 in accordance with the requirements
of GL 95-05 Section 6. It was also part of a September 17. 1997.
license amendment request for Units 1 and-2; The license amendment -
involved the reduction in the specific activity limits of dose
equivalent l* (DEI) steady sta;e and transient values from 0.3
microcurie / gram to 0.15 microcurie / gram, and 18 micro curies / gram to 9
-micro curies / gram, respectively. The DEI level reductions effectively
increase the maximum allowable accident leakage limit associated with
voltage based repair criteria from 13.7 gpm to 23.8 gpm (room
temperature conditions).
The staff reviewed the licensee's assessment against the criteria in
Section 6 of GL 95-05. Specifically. the review included SNC's
assessment of the safety significance, com)ensatory measures taken, and
actions with respect to reportability of t1e event.
SNC's assessment cf the safety significance of the increased EOC -
accident leakage was based on the actual plant steady state value of DEI
(less than 0.01 microcurie / gram). Using actual plant conditions, SNC
concluded that the radiological ex)osure from SG tube leakage in the
event of a main steam line break (iSLB) would not have exceeded the
licensing basis. However, the licensee failed to explicitly address the
radiological consequences of a MSLB assessed in two ways: (1) assuming
a preexist;ng iodine spike and (2) assuming an accioent-initiated iodine
spike. Since the licensee implicitly addressed both cases when the
licensee changed its administrative limits for both steady state and
transient values of DEI, the staff concurred with SNC's safety
assessment with respect.to leakage. Regarding the increased burst
probability. SNC citeg' operator action and engineering judgement to
conclude the 1.2 x 10 burst probobility was not safety-significant.
The staff concurred with SNC's conclusion.
SNC evaluated the reportability of the revised leakage and burst
probability numbers and determined the reportability of the issue was
covered by the requirements of Gl. 95-05 and no other reportability
requirements (e.g. , 50.72 or 50.73) ap)1ied. The staff reviewed the
reporting requirements and concluded tlat SNC has complied with the
requirements of Technical Specification 3.4.6 by having followed the
applicable reporting requirements outlined in Section 6 of GL 95-05.
4
c. Conchsiqos
The NRC staff'found SNC's " Generic Letter 95-05 Safety Assessment" in
res)onse to.the GL 95-05 requirements to be adequate. With respect to
leacage, the actual plant conditions combined with the administrative
limits established by SNC appear to ensure E0C accident leakage will not
result in radiological exposures exceeding regulatory limits. With
respect to conditional burst probability. the staff concludes the small
-increase is not safety-significant, The licensee's compensatory actions
were appropriate, and the reporting requirements appear to have been
adequately addressed.
_
Enclosure 2
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E1.3 FWS Discharoe Pine Corrcsion (IP 37551)
In response to inspector concerns regarding excessive SWS pipe corrosion
(see report section 02.1), the licensee initiated W0s #S97006667 and
- S97006668 to clean the Unit 1 and 2 SWS pipe and conduct nondestructive
examinations. Under the cognizance of ES engineers, plant personnel
performed ultrasonic testing (UT) of the affected SWS piping. The UT
results. including pit depth measurements, were then transmitted to
corporate engineering. Southern Company Services (SCS), for review as a
Request for Engineering Assistance (REA) 97-1557. In particular. SCS
was requested to calculate the minimum acceptable wall thickness.
Inspectors observed evidence of the SWS pipe cleaning. UT. and
subsequent priming of the external piping surface. An inspector also
reviewed the UT data recorded in the W0s, and reviewed the SCS reply to
REA 97-1557. The average UT )ipe wall thickness readings were ty)ically
0.51 inches, with a wall thic(ness of as low as 0.390 inches in tie
corroded areas. As noted in the original piping specification, this
piping was purchased for a minimum thickness of 0.428 inches. The
licensee concluded that the dee)est pit was approximately 0.125 inches
deep. Subsequent calculations )y SCS concluded the minimum allowed wall
thickness was 0.229 inches. Consequently, the existing SWS pipe
condition was acceptable. Overall, licensee response to the identified
SWS pipe corroded conditions was prompt and effective.
E8 Hiscellaneous Engineering 1ssues (92903)
E8.1 (Onen) IFI 50-348. 364/97-10-02: UFSAR Reverification Corrective Actions
a. Inspection Scoce
The inspectors selected 18 of the 868 UFSAR discrepancies for followup.
During this report period item #089 concerning the capacity of the EDG
air start systems was reviewed. An inspector reviewed the documented
response to the discrepancy. licensee calculations. UFSAR Sections 8.3
(Onsite Power Systems) and 9.5.6 (Diesel Generator Starting System). NRC
Standard Review Plan (SRP) 9.5.6. Rev. 1. and pre-startup EDG test data.
The review of the calculations was limited to the air starting
requirements for the Colt-Pielstic PC2 EDGs.
b. Observations and Findinas
The concern as stated in the UFSAR Verification database was: "The
statement that the accumulators have the capacity for five air starts
should be investigated to its origin in order to establish if it is a
design requirement which has been satisfied or if it is a one-time or
periodic testing requirement."
The licensee's closecut response to the questien was that this was a
design requirement and that based on calculations "no explicit testing
of this requirement and revision to the UFSAR" was necessary. The
inspector requested copies of the design calculations SM-90-1779-001.
" Diesel Generator - Air Start System." Rev.1. and SM-90-1779-02. " Air
Start System leakage Rate." Rev. 1. for review. These calculations were
performed in 1992 and 1993.
Enclosure 2
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The inspector reviewed the above calculations. including the licensee
assumptions. The. inspector also performed inde)endent calculations
_using the licensee's assumptions and formulas. )ut with the actual
pressure drop' observed by the inspector during routine EDG surveillance.
starts, to validate the licensee's-methodology. The inspector also-
compared the licensee's results to original CDG startup test data. The
' inspector determined the licensee's calculational methodology was non-
conservative. The licensee had failed to compare their methodology
against data from original EDG startup tests, specifically performed to
validate the design cf the air start system receiver capacity, nor did
the licensee's calculations reflect actual EDG surveillance data. The
inspector concluded that the licensee's response to the UFSAR
discrepancy lacked thoroughness in that the licensee's review failed to
recognize the existence of actual startup test data or use pressure ,
drops observed during routine surveillance testing.
The inspector also concluded that the startup test data demonstrated
that the EDGs were capable of five sequential starts from one receiver
without recharge. In response to the inspector's comments. the licensee
revised their resolution of item #089 to document existence of the
startup tests.
l While researching the above issues the inspectors identified another
!
UFSAR discrepancy. UFSAR section 8.3.1.1.7.2. Response to Design Basis
Events, states that the maximum required loads will not exceed the
continuous rating of any of the four design. basis diesel generators.
This statement was not accurate in that current design basis load for
the 1C EDG exceeds the continuous rating but is less than the 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br />
rating. The inspectors have reviewed the loading of the 1C EDG
previously and determined that exceeding the continuous rating was
acceptable because the licensee's TS surveillance tests the 1C EDG to
the 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> rating. This UFSAR discrepancy was identified to the
licensee for correction.
c, Conclusions ,
i
- The licensee resolution of UFSAR discrepancy #089 was not thorough or
complete. Calculations supporting the design of the air start system
l- were non-conservative and were not validated against existing test data.
L However, the inspector verified that startup test data demonstrated the
l
air start system was adequately sized. i
l
This IFI remains open pending additional review of the UFSAR ,
- reverification corrective actions. i
! E8.2 FClosed) IFI S0-348.'364/96-13-07: Certain Hiah Enerav Line Break (HELB) l
- solation Sensors Not Described In UFSAR l
l- This-NRC identified UFSAR discrepancy was originally entered into !
i CATLIPS for tracking as commitment #10253. However. as part of the
L u) coming conversion to the Improved Standard TS (ISTS). TS 3.3.3.7 for
i "ligh Energy Line Break Isolation Sensors" is to be removed and
l relocated to the UFSAR. Consequently, the licensee has closed CATLIPS
Enclosure 2
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commitment #10253 and opened item #506 in the ISTS conversion action
item database to track this UFSAR discrepancy. An inspector reviewed
item #506 of thc-ISTS conversion database. Since this item will be
-include'J in the ISTS revf ew, this IFI is considered closed.
E8.3 LClased) VIO 50-364/96-155-01014: Ste m. Genera, tor Tube Flaws With F*
Distance
"
Closeout M this V10 was previously documented in Section M8.1 of NRC
IR 50-348. 364/96-09.
E8.4 (Closed) Unreso'ved item 50-348(364)l37-201-01: Unorotected CST
Connections
On October 21, 1994. during the safety system self-assessment (SSSA) of
the auxiliary feedwoter (AFW) system, the licensee discovered that a
. number of piping and transmitter tubing connections to the Unit 1 and
Unit 2 Condensate Storage Tanks were not provided with missile
protection as described in the UFSAR. Section 9.2.6.6 of the UFSAR
stated that the lower 12 feet of the CST was designed to withstand any
rupture caused by missiles. To resolve this issue, the licensee issued
Incident Report 1-94-299. Licensee Event Report (LER) 94-005-00, and an
UFSAR change and associated 10 CFR 50.59 Safety Evaluation. The
inspectors noted that the licensee's LER (94-005-00) and the subject
Safety Evaluation had been reviewed previously by NRC as documented by
NRC Reports 95 20 and 96-07. respectively.
The licensee's corrective action involved issuing a change to the UFSAR
to reflect the as-built configuration of the CST piping without the
tornado missile arotection. The 10 CFR 50.59 Safety Evaluation of the
proposed UFSAR c1ange was completed on November 17. 1994. The 10 CFR
50.59 Safety Evaluation included a question (question number 6) asking.
"May the proposed activity create the possibility of a malfunction of
equipment important to safety of a different type than any previously
evaluated in the UFSAR?" The licensee answered this question "No."
However, the inspectors noted that as a result of this condition. a
tornado missile could damage some CST connections, thereby resulting in
a loss of inventory from the safety-related tank and affecting the
operability of the entire AFW system.
A 3robablistic risk analysis was pre)ared and documented in Calculation
REES-F-94-014 which indicated that t1e impact frequency with which a
tornado missile could strike exposed CST piping was on the order of
1.0 x 108 per year. The safety evaluation for the UFSAR change
compared the calculated impact frequency with which a tornado missile
could strike exposed CST piping (approximately 1.0 x 10~8 per year) to
the probability of occurrence ~of a design basis external event
-(approximately 1 x 10 per year) and concluded that this postulated
tornado event was-not required to be analyzed as an " accident" in the
UFSAR. The UFSAR was subsequently revised to include the PRA results
and to delete the requirement for missile protection of the subject CST
con 9ections-. However, the inspectors concluded that the comparison was
not an appropriate justification to determine that an unreviewed safety
Enclosure 2
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question-(US0) did not exist when the as-built )lant-configuration did
not conform to the configuration-described in t1e UFSAR.
In a letter to NRC dated July 11. 1997. the licensee committed to
provide missile protection for the subject connections by March 15,
1998 The insSector found that the licensee had developed and issued
DesihnChange)ackages(DCPs) 97-1-9172 and 97-2-9173 to add tornado
missile protective structures to CST connections in the lower 12' of
the tank The CST connections identified in the DCP to be tornado
missile protected were tank drain, vacuum degasifier tank connection,
and level transmitters with associated electrical conduit.
10 CFR 50.59 allows licensees to make changes to the facility as
described in the safety analysis report, without prior Commission
approval unless the proposed change, involves a change in the
technical specifications or an unreviewed safety question. The NRC has
reviewed the circumstances related to this issue and determined that a
USQ did exist; however, as described in the cover letter to this
report, the NRC is exercising enforcement discretion to not cite the
violation in accordance with Section VII.B.6 of the Enforcement Policy.
This unresolved item is closed.
E8.5 fClosed) URI 348.364/97-201-02: Tornado Protection of CST Level
. nstrumentation
UFSAR Sections 3.2.1.5 and 9.2.6.1 and Table 3.2-1 state that the AFW
system instrument and control (l&C) system equi 3 ment and CST equipment
were classified as Category I., respectively. U:SAR Section 3.5.4
states that Category I equipment and piping outside containment are
either housed in Category I structures or buried underground. However,
durir.g the walkdown of the Unit 1 CST. the inspectors observed that the
safety-related CST level transmitters and enclosures, as well as the
associated cables and conduits.'were outside, and routed above ground
around the tank perimeter without missile protection.
In a letter to NRC dated July 11, 1997, the licensee committed to
provide missile protection for the CST level transmitters and
associated conduits by March 15, 1998. As stated earlier, the licensee
had isseed'0 cps 97-1-9172 and 97-2-9173 to install missile protection
at both the Unit 1 and Unit 2 CSTs. The inspector verified that these
instruments were included in the scope of the DCPs.
This unresolved item is dis p itioned with URI 97-201-01, as described
in E8.4 and is now closed.
E8.6 -(Closed) URI 50-348.254/97 201-03: AFW Check Valve Reverse Flow Testina
The ins)ectors identified that TDAFW pump discharge check valves V003
or-V002L F and H wers nct included in the IST program for a reverse
flow valve closure test es required by the ASME Code. The licensee
agreed that either check valve V003 or check valves V0020. F and H were
required to close in order to perform the required safety function.
The licensee issued OR 1-97-048 on March 3. 1997, to assure that
required corrective actions were implemented in a timely manner. The
Enclosure 2
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licensee revised the Unit l' and -2.IST Plans. FNP-1-M 46 and FNP-2-M-071-
to require reverse flow testing of TDAFW check. valves V002D -F and.He .
every refueling outage. The.IST Program was also revised to identify
Lthat these valves have a safety function in the open and closed
position.
1
Surveillance Test Procedure FNP-1-STP-22:29. " Turbine Driven Auxiliary
- Feedwater Check Valve Reverse Flow Closure Operability Test." Revision 7
-
,
10; dated April 18, 1997, was issued to implement reverse flow testing - ,
- on the subject valves for Unit 1. The 3rocedure was implemented on-
Unit 1 and satisfactorily completed on iay 21, 1997. ;
In a letter to'NRC dated July 11. 1997, the licensee indicated that all- .
corrective actions had been completed including issuance of procedures .
1
-to perform the required testing. This response was in error in that: ~
-the Unit-2 procedure was not issued until September 12, 1997. The
inspector found that the scheduled date of completion-for-issuance of
-the Unit 2 Surveillance Procedure was in accordance with the corrective-
- action described in Occurrence Report 1-97-048 and the Open Commitment-
Tracking Report dated September 15. 1997. In accordance with these
documents, the Unit 2 Surveillance Test-Procedure FNP-2-STP-22.29 was
L scheduled to be issued and comaleted satisfactorily prior to Unit 2
Startup from refueling outage RF12 which is scheduled for Spring 1998.
. The licensee informed the inspector'of this discrepancy and-indicated :
'
that a revised submittal would be provided if necessary to clarify the
procedure' status. The inspector concluded that based on review of the
Occurrence Report and the Commitment Tracking database that the
,
'
corrective actions were being properly tracked and completed and no .
additional response on this item would be required. *
The ins)ector concluded that the failure to reverse flow test either
TDAFW cleck valve V003 or check valves V0020. F and H as required by
the ASME Code was a violation of TS Section 4.0.5 which requires
inservice testing of ASME Code classes 1. 2 and 3 pumps and valves in
o -accordance with Section XI of the ASME Boiler and Pressure Vessel Code .
-
and applicable Addenda. This is identified as Violation 50-348.364/97-
11-02. Failure to Perform Adequate IST of TDAFW Check Valves on-
Cessation or Reversal of Flow.
The unresolved item is closed. .
- - E8 J (Ciosed) URI 348.364/97-201-04
- AFW Check Valve Forward Flow Testina
'
- The inspectors reviewed Surveillance Test Procedure FNP-1-STP-22.13.
'
<
" Turbine Driven Auxiliary Feedwater Pump Check Valves Flow
Verification." Revision .14. dated May 7.1996. The insoectors noted
~
that because' of the testing lineup with the minimum recirculation flow
path open the-flow through TDAFW check valve V003 would be on the order
'
of 530 gpm when the pump was operated at.625 gpm. The; team concluded
'
that the acceptance criteria of' 625-gpm in Section 2.2 of FNP-1(2)-STP- -
22.13 was not consistent with the actual-test flow. The licensee
Lagreed with the finding and issued Temporary Change Notice (TCN) .14A
_
- and 12A to, revise procedures FNP-1(2)-STP-22.13.'
'
Enclosure 2
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The licensee's correspondence dated July 11, 1997. stated that
procederes have been revised to reflect current acceptance criteria and-
a review of Other orocedures was in progress. The ins)ector reviewed
Surveillance Test 3rocedures FNP-1(2)-STP-22.13 dated rebruary 28.
1997. and verified that they had been properly revised to reflect the
correct acceptance criteria for. full flow testing of check valves
01N23V003 and 02N23V003. The acceptance criteria for total flow i
-through the valve was changed to 450 gpm and the flow was being
measured down stream of the minimum recirculation flow path at flow
indicator FI-3229.
"
The failure to have adequate acceptance criteria in the surveillance
test procedure for verifying the forward flow for check valve V003 was
a-violation of 10 CFR 50 Appendix B. Criterion V. T;.ls is identified
as Violation 50-348.364/97-11-03. TDAFW Battery Installation and Check
Valve Test Deficiencies.
Based on the above the unresolved item is closed.
E8.8 (Closed) URI 50-348.364/97-201-05: TDAFW Pumo Battery Testina
The inspectors questioned the lack of service testing for the TDAFW UPS
Batteries to demonstrate the ability of the tattery to meet the design
duty cycle specified in the battery Design Basis Calculation 07597-E-
106. The inspectors did not have any immediate safety concern, since
the licensee's maintenance and testing provided reasonable assurance
that the battery could support the assigned load. The inspector
followed up on this item and concluded based on the review that a
failure to have a test program and procedures for service testing of
the TDAFW Class lE battery to ensure that the battery would meet the
required duty cycle was a violation of 10 CFR 50 Appendix B. Criterion
XI and TS Sectirn 6.8.1.a. This is identified as Violation 50-
348.364/97-11-04 Failure to Implement a Test Program for Service
Testing of the TDAFW Battery.
The licensee committed to aerform battery service testing during
refueling outage RF14 for Jnit 1 and RF12 for Unit 2 and to establish a
task to perform a service test every 18 months thereafter. The
architect engineer provided the licensee a draft procedure and safety
evaluation in Letter No. FP 97-0179 dated April 4. 1997. The Procedure
FNP-1-EMP-1352.04. " Turbine Driven Auxiliary Feedwater (TDAFW) UPS
-Battery Service Test." Revision 0 was issued on April 22, 1997. The
procedure was satisfactorily completed on Unit 1 on April 23. 1997.
The inspector reviewed the test results and the procedure and found
both to be acceptable. The battery test was a combined test to.
demonstrate that the as-found battery capacity was adequate to supply
calculated design basis accident load requirements for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and
station blackout load requirements for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The load profile
consisted of 70 amperes for the first minute followed by 53 am)eres for
the following.239 minutes. The acceptance criteria was that t1e
- battery terminal voltage remained greater than 42.6 volts dc after
being subjected to the service discharge test profile above.
This unresolved item is closed.
Enclosure 2
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E8.9 (Closed) URI 50-348.364/97-201-06: TDAFW Battery Installation
The inspectors reviewed the Unit 2 TDAFW battery installation and found
that various structural and electrical components were not installed in
accordance with the manufacturer's drawings and instructions. The
inspectors identified 6 specific deficiencies and 5 of those
deficiencies involved discrepancies between the battery installation
cod druings or procedures. The following deficiencies were noted:
e Five polystyrene s)acers were installed between the battery cell
and t1e end rail w1ere none were required.
- Structural steel bracing in the rear of the rack did not agree
with the drawing.
- Bolts were missing from the upper- and lower-tier tie rod
brackets.
e Silicon bronze bolting hardware was utilized at the cable
terminations in lieu of stainless steel hardware.
e The intercell battery connections were torqued to 75 in-lbs
instead of the required 125 in-lbs specified in the battery
manufacturer's instruction manual.
e The battery rack steel rails and tie rods exhibited corrosion.
The inspectors' review of these issues concluded that the failure to
install the Unit 2 TDAFW battery and rack in accordance with drawings.
procedures or instructions was a violation of 10 CFR 50 Appendix B.
Criterion V. This is identified as an example of Violation 50-
348.364/97-11-03. TDAFW Battery Installation and Check Valve Test
Deficiercies.
In licensee correspondence dated July 11. 1997, the licensee indicated
that the battery rack would be rebuilt per approved drawings and the
work would be completed by June 15, 1998.
The licensee issued REA 97-1408 to reconcile the differences between
the battery rack design and the installed configuration; and REA 97-
1444 to revise TDAFW battery maintenance procedures and appropriate
documentation to clarify acceptable fastener material. T1e licensee
received a response to REA 97-1408 in a letter dated July 31. 1997, and
indicated that the rack support frames had been installed 29 inches
apart instead of 25 inches apart as required by the drawings. The
recommended corrective action was to disassemble the rack and relocate
one of the sup) ort frames to within 25 inches of the other in
accordance wit 1 the design drawing. The response also included a
proposed work sequence to disassemble and reassemble the battery rack.
The licensee received a response to REA 97-1444 in Letter No. FP 97-
0396 dated July 31. 1997. Attached to this letter was a draft ABN
which provided information reflecting the acceptability of silicon
bronze or stainless steel fastener material for use on the Units 1 and
2 TDAFW UPS battery intercell and field cable connections.
Enclosure 2
4
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23
The licensee found that the maintenance procedures (for individual cell
replacement as well as periodic cleaning and inspection) specified
torque values that were less than recommended by the venuor. The
licensee evaluated this issue and determined that the torque values did
not affect the battery's safety function based on frequent periodic
battery maintenance and information received from the vendor that
indicated that acceptable connection resistance readings were
obtainable over a wide range of torque values. The licensee indicated
a review of torque values for all safety-related batteries was in
progress and the procedures would be revised appropriately. The
licensee indicated the specific TDAFW battery procedures would be
revised by June 15. 1998.
The licensee issued Deficiency Report #537766 to cleanup the battery
rack corrosion and install missing hardware. Tnis work was completed
on February 12, 1997.
The unresolved item is closed.
E8.10 (Closed) IFI 50-348/97-201-07: CST Level Alarm
The inspectors reviewed Calculation SM-87-4380-001, Revision 0 and
identified the following two concerns:
e The drift error for the sensor was not addressed in the
calculation.
e The total instrument tolerance calculated did not include the
deadband of 1% of span. (The inspectors found that it was not
clear from the design guidance document as to the circumstances
when to use deadband in uncertainty calculations.)
The inspector found that Calculation SM-87-1-4380-001 had been
superseded by Calculation SJ-97-1407-001 and Calculation SM-97-1407-
002. Calculation SM-97-1407-002. Condensate Storage Tank Low-Low Level
Alarm Setpoint Revision O. dated August 18. 1997, determined the
lowest allowable low-low level alarm setpoint on the Unit 1 and 2 CSTs.
The lowest allowable low-low level alarm setpoint was determined to be
1.456 feet from the bottom of the tank. However, to ensure adequate
margin, the licensee administratively set the low level alarm setpoint
at 5 feet - 3 inches or 63 inches. The administrative setpoint of 63
inches was used as an input into Calculation SJ-97-1407-001.
Calculation to Establish the Total Loop Uncertainty for Loops L-515 and
L-516. Revision 0. dated August 19, 1997. This calculation determined
the total loop tolerance for L-515 and L-516 and applied the loop
tolerance to the designated setpoint and process limit to verify that
all inaccuracies and allowances made would not ca$ e the alarm
initiation to fall outside safe process limits. The impector reviewed
Jortions of these calculations and verifled that sensor and rack drift
' lad been adequately addressed.
In regard to the issue on deadband, the licensee had revised the
Project Desk Instruction (PDI) 005.16. Process Instrumentation and
Control Setpoints, dated August 26, 1997, to clarify when the deadband
Enclosure 2
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component should be used in establishing 6cceptable setpoint tolerances
in uncertainty calculations. The inspector found the revision to PDI
005.16 clarifying when deadband should be considered to be acceptable.
This item is closed.
E8.11 (Ocen) URI 50-348.364/97-201-08: Tornado Protection of TDAFW Pumo Vent
Slak
.
The inspectors observed that the safety-related TDAFW pump vent stack
was installed on the roof of the Auxiliary Building and was not
protected from tornado generated missiles. UFSAR Section 3.5.4 states
that Category I equipment and piping outside containment are either
housed in Category I structures or buried underground. UFSAR Sections
6.5.1. 3.2.1.3. 3.2.1.5 and Table 3.2-1 state that AFW system equipment
and piping are Category 1. The ins)ectors noted that the requirements
of Criterion 111 and V of Appendix 3 to 10 CFR Part 50 were not met
because the installed condition of the TDAFW aump vent stack did not
conform to FNP design and licensing basis. T11s issue will remain open
pending additional NRC review.
E8.12 (00en) URI 50-348.364/97-201-09: Tornado Missi' Spectra
The inspectors observed that the safety-related emergency diesel
generators and the station blackout diesel generator exhaust silencers
for both units were installed on the roof of the diesel generator
building. The eaiament was judged to be protected ;M ust horizontal
generated missiles ay the b.ilding walls. However, a concern Nas
identified that the equipment was susceptible to vertical missiles and
other non-horizontal missiles. The licensee took the position that the
design basis for FNP was for horizontal missiles only. The issue was
left as an unresolved item pending further review by NRC to determine
if the tornado missile protection in the FNP design and lict ' sing bases
included missile spectra other than horizontal missiles. In a letter
to NRC dated May 28, 1997 the licensee provided additional information
to support its position on vertical missiles. This information was
being reviewed oy NRR and the' review is scheduled to be completed by
November 1997. This item will remain open pending completion of this
review.
E8.13 (Closed) IFl 50-348/97-201-10: CST Level Transmitter Freeze Protection
The inspectors identified three potential deficiencies with the
installation of the CST level transmitter 01P11LT516 and associated
freeze protection. In response to these concerns, the licensee issued
Work Orcors (WO) # 97001089. 97002478. and 97003706 to have maintenance
inspect and evaluate the adequacy of the heat tracing and islation
for level instruments 01P11LT515 and LTS16 and repair as required. All
work orders were completed on May 21, 1997. The inspector reviewed the
work history records to d-termine if the work was performed
satisfactorily and addressed the concerns. Based on this review, this
item is closed.
E8.14 (Closed) URI 50-348.364/97-201-11: AFW UFSAR Discreoancies 3
1
Enclosure 2
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The inspectors identified the following discrepancies between the
UFSAR as-built plant and design:
1. UFSAR Section 6.5.2.2.4 stated. "All valves in the AFW flow path
from the condensate storage tank to the steam generators were
normally open, with the exception of the fail open AFW flow-
control valves." This statement implied the AFW flow control
valves were not normally open. In accordance with the plant's ,
c)erating procedures, these valves were normally maintained in
t1e open position. The inspectors considered the UFSAR statement
was not correct.
2. UFSAR Section 3K.4.1.2.7, item F states the lowest safety-
related equipment in the main steam room is the atmospheric
relief valves at eltvation 133 ft. 3 inches. During the design
inspection aviit in February - March 1997, a walkdown identified
that the lowest safety-related components in the main steam valve
room were the Motor Driven A'ixiliary Feedwater (MDAFW) and
Turbine Driven Auxiliary Feedwater (TDAFW) discharge valves (HV-
3227A. B. C: HV-3228A B. C). The lowest solenoid valve was
located at elevation 131' - 0". Because thesc valves were
hated at a lower elevation than the atmospneric relief valves,
as stated in the above UFSAR statement, a concern existed
regarding the validity of the statement in the UFSAR that the
plant personnel would have approximately 4 additional hours to
isolate the turbine driven pump discharge through the feedwater
line break before water levels in the main steam room could
potentially ap3 roach the bottom of a safety-related component.
In addition, t1e inspectors observed that the limit switches
associated with the main steam isolation valves (MSIVs) were
located less than 1 foot above the floor, which was also below
the analyzed flood level.
3. DCP S-96-1-9008-0-001 replaced two - 3 amp fuses on the output of
TDAFW pump UPS rectified output with 5 amp fuses. However. UFSAR
section 8.3.3.2.C on page 8.3-41 still had references to 3 amp
fuses.
In response to items 1 and 2. the licensee issueri ABN 97-0-1074 to
revise the UFSAR. Design Calculation BM-97-1074-001. " Basis for time
in UFSAR Section 3K.4.1.2.7. Item F " was developed to support ABN 97-
0-1074 and document the design basis for the UFSAR statement regarding
time available to isolate the TDAFW pump flow through a feedwater line
break in the main steam valve room. The calculation results indicated
that the plant personnel would have approximately 3.18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> instead of
4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to isolate the turbine driven Jump discharge from the feedwater
line break before the water level in t1e main steam room reaches the
bottom of the safety related solenoid located at elevation 131'
UFSAR Section 6.5.2.2.4 was being revised to identify that the normal
position of the auxiliary feedwater control valves was open except
during auxilt ry feedwater system testing. In addition. -Section
6.5.2.3.3 wds being revised to reflect the normal position of the AFW
Enclosure 2
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flow control valves and their operation on an automatic pump start
signal.
The inspector found that the issue on fuse sizing had been previously
addressed by the licensee in ABN 93-0-0224. Revision 2. which was
issued in letter No. FP 95-0511 from Southern Company Services to
Southern Nuclear dated August 31, 1993. This ABN (93-0-0224) included
a revision to UFSAR Section 8.3.3.2.C to delete the fuse rating from
the UFSAR on the basis that fuse design was controlled by the fuse
manuals (Documents A 181987 and A-201987) and therefore, fuse rating
details need not be documented in the UFSAR. Attached to the ABN was a
50.59 Safety Evaluation, and UFSAR markups. The ins)ector reviewed the
UFSAR markup of the aroposed change and found it to 3e acceptable. The
ABN was approved by 31 ant Operations Review Committee (PORC) on
February 8. 1996. Based on these actions, item 3 is being
dispositioned in accordance with Enforcement Guidance Memorandum (EGM)
96 005 with no further action.
The inspector concluded that deficiencies 1 and 2 were examples of a
violation of 10 CFR 50.71(e). In accordance with the Enforcement
Policy, the failure to update the UFSAR normally would be categorized
as a Severity Level IV violation. However, at discussed in the cover
letter of this inspection report. enforcement discretion is being
exercised in accordance with Section Vll.B.3 of the Enforcement Policy.
The unresolved item is closed.
E8.15 (Ocen) URI 50-348.364/97-201-12: Stress Analysis Temoerature
This issue was identified to review the 'icensee's root cause
evaluation and corrective actions for the design deficiency documented
in Deficiency Notice (DN)97-001 involving incorrect dimensions and an
incorrect temperature utilized in the Com3onent Cooling Water (CCW)
piping stress calculations. The subject )N was generated to document
the as-found condition and initiate the corrective action process. The
DN stated that a Root Cause Evaluation Team (RCET) made up of SCS, SNC.
and BPC representation would be established to determine the root
cause: perform a review; and provide corrective action recommendations.
The .aspector found that this root cause evaluation was still in
progress. However, the corrective action to revise the Unit 1 and 2
CCW stress calculations had been completed. The licensee had issued
REA 97-1415 to revise the Unit 1 and 2 CCW Stress Calculations. A list
of the ind;vidual calculations as well as the criteria used to
determine if a calculation required revision were documented in DN 97-
001. Table A of DN 97-001 listed the CCW stress calculations for Units
1 and 2. The DN indicated in the notes whether a Change Notice had
been issued against a calculation or if the calculation was required to
be revised, Licensee letter No. FP 97-0394 dated July 31, 1997 which
was a final response from the design for REA 97-1415. inoicated that 30
CCW Stress calculations required revision as a result of this
deficiency. However, it indicated that additional calculations were
revised as part of the snubber reduction program for a total of 35
calculations that were revised.
Enclosure 2
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lhis item will remain open pending review of the results of the
licensee's root cause evaluation and proposed corrective actions.
E8.16 (Closed) URI 50-148.364/97 11 13: MOV Desinn Basis Differential
Pressure
The inspectors identified that the design basis differeritial pressures
identified in MOV Design Basis Document. U418109. Revision A for CCW
system containment isolation valves MOV 3046. 3052 and 3182 were non-
conservative as the effect of post-LOCA containment pressure was not
considered. These valves were located in the piping at penetration
numbers 42 and 14. which were the CCW supply to the RCPs and the CCW
return from the RCP oil coolers. UFSAR Table 6.2-31 identified these
penetrations as Type 11. UFSAR Section 6.2.4.1 defined Type 11
penetrations as serving those lines that connect directly to the
containment atmosphere. Therefore, the design basis differential
pressure for the containment isolation valves should have considered
the maximum post LOCA containment pressure that could exist when tlia
valves operate. The inspector concluded that the licensee's failure to
check and verify the adequacy of the design was a violation of 10 CFR
50 Appendix B Criterion 111. This is identified as an example of
Violation 50-348.364/97-11-05. Design Control Measures Did Not Ensure
that Calculations Were Verified and Controlled Ad?quately.
ABN 97-0-1098 was issued by the licensee on September 9. 1997, to
revise Units 1 and 2 MOV Design Basis Drawings. U418109 (Sheets 768.
78B. and 918) and U418110 (Sheets 618, 63B. and 76B). to incorporate
the new closing differential pressure values for the subject MOVs. The
ABN and associated 50.59 Safety Evaluation was reviewed and found to be
acceptable. The new c ksing differential pressure value for MOVs 3046
and 3182 was F psid and 52 psid for MOV 3052.
The unresolved item is closed.
E8.17 (Closed) IFl 50-3dL264/97-Il-J4. CCW Pomo Testina
Bechtel Calculation (41.4; BM-95-0776-001 "CCW System Evaluation Using
Degraded CCW Pump Curve." Revision 0 was performed under REA 95-0776.
This calculation documented the acceptability of the CCW system
performance with the pumas degraded approxiniately 10% from the vendor
test curves and stated tlat this degraded pump curve will be used for
comparina test data to verify the performance capability of the CCW
pumps. !he inspectors noted that the Inservice testing of the CCW
pumps was performed in accordance with procedure FNP-2-STP-23.1. "2A
Component Cooling Water Pump Quarterly inservice Test." Revision 14.
and similar )rocedures existad for the other two pumps. The inspectors
also noted tlat the CCW Functional System Description (FSD) and
procedure had not been revised to incor] orate the results of the above
calculation. An IFl was identified to review the revised IST procedure
and associated safety evaluation.
97-0-1080. Revision 0 and associated 10
Theinsb.ectorfoundthatABN
CFR 50. 9 Safety Evaluation )rovided for revising the UFSAR. CCW FSD.
SWS FSD, RHR FSD and CCW P&l)s to allow CCW pump opec 3tica with the
Enclosure 2
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minimum flow line isolated. This ABN revised affected documentation
based on using minimum analyzed CCW pump )erformance data for various
normal and accident configurations with tle minimum flow line open and
for operating the CCW pumps with the minimum flow line isolated. The
inspector reviewed the Component Cooling Water Functional System
Description. (A 181000). Revision 8 and observed that Revision 0 of ABN
97 0-1080 was incorporated into the FSD on July 8. 1997. The inspector
reviewed the lv CFR 50.59 Safety Evaluation for ABN 97-0-1080. Revision
1 and no unreviewed safety question was identified. This item is
closed.
E8.18 (Closed) URI 50-348.364/97 201-15: Post Modification Testina
This issue involved Design Change Package (DCP) 96 0-9012 2-006.
" Process Coating for CCW Heat Exchangers." which provided direction for
mndification of the CCW heat exchangers y application of an epoxy
coating (Plastocor) to the tubesheets, channel head, channel cover.
channel head shell relief line, approximately 12 inches into the
service water inlet and outlet lines, and 12 inches of the inlet end of
the tubes. The DCP, along with REA 96-1211. also provided direction
for plugging and stabilizing tubes. Procedure FNP 0-ETP-4418. "CCW
Heat Exchanger Epoxy Coating Application." Revision 1. implemented the
epoxy coating and Work Orders 96001476. 96001477, and 9600'.178 '
installed the stabilizing rods in the tubes. The inspectors noted that
neither the procedure used to apply the epoxy coating nor DCP 96-0-
9012-2-006 recuired post modification testing to ensure design flow
capability hac been maintained. The inspector concluded that the
concern that a flow test was required was based on engineering
,)udgement. The inspector could not identify any specific regulatory
requirements that would require flow testing. Therefore. this issue is
closed.
In a letter to NRC dated July 11. 1997. the licensee indicated that '
appropriate procedures would be revised by August 15. 1997, to
delineate post-mod testing requirements for maintenance replacement
design changes. The ins)ector reviewed Plant Modifications Procedure
FNP-0 PMP-100. " Design C'1ange Engineering Evaluation Preparation."
Revision 16 and noted that. It had been revised to delineate
requirements for post-modification testing for Maintenance Replacement
DCPs.
Enclosure 2
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E8.19 (Onen) IFl 50 348.364/97-201-16: Calculation Discrenancies
lhe inspectors identified several discrepancies in Calculation SC-96-
1211002. "CCW Heat Exchanger Maintenance Repairs * Revision 1. This
calculation documented the seismic and mechanical acceptability of the
modification. The deficiencies were noted in Sections 2.1. 2.3. 2.4.
and 2.5 of the calculation. The licensee issued REA 97 1407 to revise
the calculation. This item was identified to review the revised
calculation. The inspector followed up on this item and found that the
calculation had not been revised. However, in a letter to NRC dated
Juiv 11. 1997. the licensee committed to have the calculation revised
bytctober 15. 1997. This item will remain open pending issuance and
revi?w of the revised calculation.
E8.20.(L)osed)URI 50-348.364/97-201-17: Drawinn and Procedure Discrenanedgg
Procedures FNP-2 SOP 23.0A. " Component Cooling Water System." Revision
5: FNP-2-50P 2.lA. "themical and Volume Control System." Revision 8:
and FNP 2 SOP-1.lA. " Reactor Coolant System." Revision 6 were
checklists for the normal positions of valves and circuit breakers.
The inspectors identified numerous differences between the P&lDs for
the system (D-205002 Sheet 1. Revision 21: Sheet 2. Revision 10: and
Sheet 3. Revision 2) and procedures FNP-2-50P-23.0A and FNP-2-SOP 2.lA
concerning the existence of caps on vent and drain lines The
inspectors noted that item 5 of safety system self assessment (SSSA)
observation CCW-CM 01 was related to this item but was apparently not
corrected by the licensee. The SSSA observation was issued on April
19. 1990. The inspectors reviewed this issue and concluded that the
failure by the licensee to take corrective action for an identified
deficiency was a violation of 10 CFR 50 Appendix B. Criterion XVI.
This is identified as Violation 50 348.364/97-11-06. Failure to Take
Corrective Action for Difference Between CCW System Piping and
Instrument Drawings and System Operating Procedures.
Based on this action the unresolved item is closed.
E8.21 1 Closed) URI 50-348.364/97-201-18: CCW UFSAR Discrenancies
The inspectors identified the following discrepancies in the UFSAR:
1. Table 9.4-6A listed the room temperature for the Component
Cooling Pump Room at the beginning of the post-accident period as
119 degrees F whereas Table 3.11-1 indicated a design
temperature of 104 degrees F for the same room.
2. There are four relief valves (02P17V153. V154. V155. V158) on CCW
pipingbetweentheinboardandoutboardcontainmentisolation
vaives. These relief valves represent a release path to the
environment. However, these relief valves were not listed in
UFSAR Table 6.2-39 as containment isolation valves.
3. Table 9.3-1 did not ;nclude valve HV 2229, which was also a
safety-related, air-operated valve that received a safety
injection actuation signal (SlAS).
Enclosure 2
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. . _ _ _ _ _ -____ _ _ _ -
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30 ,
4. Several differences existed between UFSAR Tables 9.2-6 and 9.2-7 <
and Tables T-1 through T 5 in the CCW FSD. for example. UFSAR
Table 9.2 6 listed the charging pump lube oil cooler fle as 20 ;
gpm and FSD Table T 2 lists this flow as 30 gpm. ;
,
With the exception of item 1 above, the other deficiencies are
considered violations of 10 CFR 50.71(e) for failure to ensure that the
latest develo)ed material was included in the UFSAR. However. as .
discussed in E8.14 enforcement discretion is being exercised regarding i
these violations. In regard to item 1. the ins
item and concluded that no deficiency existed. pector reviewed this
This unresolved item is closed.
'
E8.22 (Closed) URI 50 348.364/97-201-19: TS Chance for Auxiliary Buildina
li10Cf1
Unit 1 and 2 Technical Specifications Section 4.8.2.3.2.c.5 for
Auxiliary Building battery service test specified a minimum cell
voltage requirement of 1.75 volts dc. Surveillance Procedures FNP-1-
STP-905.1 and FNP-2 STP 905.1. which perform the required service test
on the batteries s)ecified a minimum acceptable voltage at the end of ,
the service test w11ch was higher than that specified in the TS. The ;
inspectors noted that the 10 CFR 50.59 Safety Evaluations performed for
PCN B-92 0-8099 and the changes to FNP-1(2)-STP 905.1 stated that TS
were not affected. However, these changes required battery terminal
voltages higher than those specified in 1S. ,
10 CFR 50.36(c)(3). Technical Specification. Surveillance Requirements,
states that surveillance requirements are related to test to assure
that the necessary quality of systems and components are maintained and
that the limiting conditions for operation will be met. The failure by
the licensee to identify a required TS change and to submit the
application for license amendment is identified as Violation 50-
348.364/97-11-07. Failure to Change TS for Auxiliary Building Battery.
In a letter to NRC dated July 11, 1997, the licensee committed to
submit a revised TS by December 31, 1997.
Based on this action the unresolved item is closed.
E8.23 (Closed) URI 50-348.364/97-201-20: Fire Barrier Penetration Seal
Documentation
The inspectors noted that silicone foam fire penetration seal 45-121-26
contained copper tubing, This configuration deviated from the tested
u configuration, and an engineering evaluation of the acceptability of
-the deviation had not been documented in accordance with UFSAR Section
98.2.2.5.3. Inspection Report 97-12 identified other concerns with the
as built configurations of silicone foam fire barrier penetration- l
seals. An inspector followup item was identified to review the
L licensee's evaluations of deviations from tested fire barrier
configurations. This issue is added as another example to be reviewed
as part of IFl 50 348.364/97-12 01. Review of Engineering Evaluations
-
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Enclosure 2
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to Establish the Fire Rating or Fire Resistant Capabilities of Fire :
Rated Silicone foam Penetration Seals. Therefore, the unresolved item
is closed, t
E8.24 (Closed) URI 50 348.364/97 201-21: Electrical UFSAR Discrenancies ,
The inspectors identified the following discrepancies in the UFSAR: ,
1. UFSAR Section 8.3.1.1.3.A.2 stated that the unit auxiliary
transformer "B" megavolt ampere (MVA) rating at 65 degrees C was -.
47.99 instead of 46.7 as shown on drawing D 202706 t
2. Section 8.3.1.1.98 referred to Section 8.3.1.1.3 for interrupting
capacities for distribution panels. However, Section 8.3.1.1.3
did not include interrupting capacity data for distribution i
panels. >
3. Section 8.3.1.2 stated there were 21 600 V/208-V motor control
centers, however, the actual number of motor control centers
identified in the UFSAR totaled 19.
In regard to items 1 and 2 above. the inspector concluded that these
were additional violations of 10 CFR 50.71(e). However, as discussed
in E8.14. enforcement discretion is being exercised regarding these
violations. The inspector noted that item 3 had previously been
identified by the licensee's UFSAR Verification Program as item #070M.
A 50.59 safety evaluation. FVP-025 (B19500 Section 8), had been
prepared to revise the UFSAR. Included as part of the UFSAR change was
a markup of the UFSAR deleting the refersice to the quantity of load
centers. . The inspector reviewed the Safety Evaluation and UFSAR Markup
and found them to be acceptable, The inspector considered the
licensee's corrective action for item 3 to be adequate.
The unresolved item is closed.
E8.25 (Closed) URI 50-348.364/97-201-22: Control of Calculations
The inspectors identified that in several cases calculations that had
previously been superseded were not identified as such on the
calculation index: design basis calculations were not appropriately
revised to show the existing design condition; and affected
calculations were not-revised when new calculations were performed.
The inspector followed up on this issue and concluded that the
licensee's design control measures diri not ensure that calculations
were verified and controlled adequately. The failure to ensure
.
'
adequate design controls for calculations is identified as an example
l of violation 50-348,364/97-11-05. Design Control Measures Did Not
Ensure that Calculations Were Verified and Controlled Adequately.
Based on the above, the unresolved item is closed,
- Enclosure 2
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IV. Plant Supg r,t
R1 Radiological Protection and Chemistry Controls (IP 71750)
RI.1 Partial Entries into Contaminated Areas
An inspector observed a number of partial entries into contaminated
areas, in general, maintenance personnel were more conscientious than
operators in applying protective actions to prevent the inadvertent
spread of contamination during partial entt.es. The inspector observed
some examples of poor operator )ractices during partial entries. These
observations were discussed wit 1 Operations management.
R2 Status of Radiological Protection and Chemistry Controls Facilities and
Equipment (IP 71750)
R2.1 Radiolooically Controlled Area. Units 1 and 2
During tours of the radiologically controlled areas (RCA) of the
auxiliary building for Units 1. inspectors observed that overall
cleanliness and housekee)ing was good. Ongoing decontamination efforts
by the Health Physics (H3) department to reduce contaminated surface
areas continue to be successful. Floor spaces in the RHR pump rooms,
dnd Certain spent fuel o001 (SFP) cooling pump skids, have been
decontaminated due to HPs aggressive efforts. In concert with
decontamination efforts. HP has also redesigned catch devices to
minimize contamination and still control minor leaks.
R8 Miscellaneous RP&C (IP 92904)
R8.1 (Closed) IFl 50-348. 364/97-10-03: Review Licensee Evaluation for
Extended Onsite Storace of Contaminated Wet Resin
The licensee performed inspections of all the Sure)aks on September 9
and 19, 1997. The inspector observed the pre-job 3rief and portions of
the licensee's inspections of the Surepaks and steel liners containing
the contaminated wet resin. The inspections were thorough and
concentrated on the outer surface of the liners which were raised by a
crane for the inspection. The surface of the liners were acceptable
with only minor surface corrosion visible. The licensee also obtained
water samples of the water in the liner and the standing water in the
bottom of the Surepak for 3H analysis. This analysis indicated that
the water was of neutral pi and was not accelerating the minor-
corrosion observed. The licensee performed followup inspections on
October 16 and determined that the resins were not generating any
measurable quantities of gaseous products. The inspector reviewed the
licensee's )rocedure and schedule for periodically inspecting the
Surepak. T1e inspection data sheet required an inspection on a
quarterly basis. The licensee considers that these inspections will be
adequate to identify liner degradation before it becomes a problem.
This item is closed based on the licensee's actions.
Enclosure 2
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P1 Conduct of EP Activities (IP 71750)
>
Pl.1 Emernency Plan Drill
On September 10. 1997. resident inspectors and the NRR project manager
participated in an announced drill of the licensee's emergency plan.
As drill players. the inspecto-s considered the drill scenario
reasonably challenging. The Technical Support Center (TSC). Operations
Support Center (OSC) and Emergency Operations facility (EOF) were all
manned and fully operational in a timely manner. Durin9 the drill,
emergency respcnse personnel properly characterized evolving events and
made accurate and timely emergency classifications and notifications.
S1 Conduct of Security and Safeguards Activities (71750)
51.1 Routine Observations qi Plant Security Measures
During routine inspection activities inspectors verified that portions
of site security program plans were being properly implemented. This
was generally evidenced by: proper display of picture badges by plant
personnel: appropriate key carding of vital area doors: adequate
stationing / tours in the protected area by security personnel: proper
searching of packages / personnel at the primary access point and service
water intake structure: and adequate condition of security systems.
Security personnel activities observed during the inspection period
were performed acceptably. Site security systems remained functionally
adequate to ensure physical protection of the plant.
S3 Security and Safeguards Procedures and Documentation (IP 71750)
S3.1 Safenuards Material in The MCR Not Positively Controlled
On September 17. 1997, a resident inspector reviewed the following
safeguards documents located in the Unit 1 Shift Supervisor's (SSs)
l desk drawer in the at-the-controls (ATC) area of the Main Control Room
(MCR): a) Security Plan. Revision 32: b) Contingency Plan. Revision 7:
c) Contingency implementing Procedures, and d) Security Procedures.
the inspector verifjed that all these safeguards plans and procedures
were of the latest revision. However, the inspector identified the
following problems:
a) The folders containing the Contingency implementing Procedures
and Security Procedures were not marked as Safeguards Information
(SGI):
b) Access to the Unit 1 SS's desk was not positively controlled by a
lock nor constantly attended by the SS: and.
c) Although the MCR is an access-controlled vital area, access to
the MCR is not limited solely to those personnel authorized to
review SGl. Personnel not authorized to review SGI were
regularly granted access to the MCR. including the ATC area.
Enclosure 2
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The inspectors met with the Deputy Security Chief, and then with an
Operations Superintendent, to express concern that SGI located in the
MCR was not properly controlled to prevent access by unauthorized
personnel. All SGI was promptly removed from the MCR. placed in the
Central Alarm Station (CAS) which was required to be continually
staffed b security personnel, and properly marked as SGl. Inspectors
verified he licensee's corrective actions.
FNP 0-AP-72. Protection of Safeguards Information. Revision 9. Step
6.2.1. states "SGI is required to be under the control of an authorized
individual while in use to prevent unauthorized disclosure to persons
without a need to know. The requirement for control of SGI is met if
the matter is attended by an authorized individual even though the
information is not constantly being used." SGI in the MCR was not
being attended by an authorized individual during those aeriods every
day when the Unit 1 SS leaves his desk, and especially w1en both SSs
leave the ATC area. Step 9.1 of AP-72 also requires each document that
contains SGI to be positively marked in a precise manner, that was not
apparent on the SGI maintained in the MCR.
The provisions of AP-72 were consistent with the requirements of 10 CFR
73.21(d) for storing SGI in a locked security storage container
whenever left unattended; and, 10 CFR 73.21(e) for marking SGI in a
conspicuous manner as " Safeguards Information." Failure to adequately
control and mark the SGI maintained in the ATC of the MCR constituted a
violation of NRC regulations and licensee procedures as identified as
VIO 50-348, 364/97-11-8. Unattended And Unmarked SGI left in the MCR.
However. licensee corrective actions have been prompt and effective to
ensure SGI was controlled and marked pursuant to regulatory
requirements.
F8 Hiscellaneous Fire Protection Issues (IP 92904)
F8.1 (Closed) IFl 50 348. 364/96 006 07- Fire Main Failures
This item was opened pending metallurgical analysis of the failed
piping and implementation of longterm corrective actions. Southern
Company Services provided the results of the metallurgical analysis and
recommendations for action via letter dated December 5. 1996. The
inspectors previously reviewed this issue. but were unable to close the
item because the recommended corrective actions had not been
implemented.
The licensee implemented the recommended corrective action on September
1. 1997. Licensee staff identified all outside fire protection piping -
and inspected it to verify the integrity of the insulation and flashing
and that no water had penetrated and soaked the insulation, No
discrepancies were identified. The licensee also implemented an
eighteen month preventive maintenance task to perform this inspection.
The inspector verified the new PM task was entered into the information
management system.
The inspectors concluded that the corrective actions were thorough.
Based on the licensee's corrective action this IFl is closed.
Enclosure 2
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_ _ _ _ _ ___ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ ____ _ _ _ _ _ _ _ _ - - - - - _ _______-__
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V. Manaaement Meetinas and Other Areas
X1 Review of Updated Final Safety Analysis Report Commitments
A recent discovery of a licensee o>erating its 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 inspect ?ns
discussed in this re) ort, the inspectors reviewed the applicable
portions of the UrSAR that related to the areas inspected. The
inspectors verified that the UFSAR wording was consistent with the
observed plant practices, procedures and/or parameters, except for:
1) EDGs running in excess of their continuous rating (see Section
E8.1); and.
2) R-29 not being routinely source checked (see Section 02.1).
X2 Exit Meeting Summary
The inspectors presented the inspection results to members of licensee
management on October 21, 1997, af ter the end of the inspection period.
The licensee acknowledged the findings presented. The inspectors asked
the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information was
identi fied.
PARTIAL LIST OF PERSONS CONTACTED
Licensee
A. Harris. SNC Corporate Engineering Manager *
M. Aj1 uni, SNC Corporate Licensing Manager *
R. Badham. Safety Audit and Engineering Review (SAER) Supervisor
R. Coleman. Maintenance Manager
C. Collins. Operations Superintendent - Administration
S. Fulmer. Technical Manager
D. Gambrell. Design Team Leader. Southern Company Services (SCS)*
D. Grissette. Operations Manager
P. Harlos. Plant Health Physicist
R. Hill General Manager
C. Hillman. Security Chief
R. Johnson. Operations Superintendent - Support
D. Jones. Configuration Management Manager
H. Mahan SNC Corporate Senior Engineer *
R. Martin Maintenance Team Leader
l D. McKinney. Engineering and Licensing Manager *
M. Mitchell. Health Physics Superintendent
R. Monk. Engineering Support Supervisor
D. Morey Vice President - Farley Nuclear Project *
l C, Nesbitt, Assistant General Manager. Plant Support
l R. Ponder. SNC Corporate Senior Engineer *
Enclosure 2
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e
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0. Shelton. SCS Engineering Manager *
M. Stinson Assistant General Manager. Operations
G. Wilson SCS Senior Engineer *
J. Zimmerman. NRR Project Manager
- Supported NRC ins)ection at SNC Corporate offices and attended pre-exit
interview on Septem>er 19. 1997.
INSPECTION PROCEDURES (IP) USED
IP 37551-. Onsite Engineering
IP 40500. Effectiveness of Licensee Controls in Identifying. Resolving, and
Preventing Problems
IP 61726: Surveillance Observations
IP 62707: Maintenance Observations
IP 71707: Plant Operations
IP 71750: Plant Support Activities
IP 92700: Onsite followup of LERs
IP 92902: Followup - Maintenance
IP 92903: Followup - Engineering
IP 92904: Followup - Plant Support
ITEMS OPENED. CLOSED, AND DISCUSSED
Op311cd
lyng _ Item Number S.t31us Description and Reference
IFl 50-348. 364/97-11-01 Open RPS Response Time Testing (Section
M1.2).
VIO 50-348, 364/97-11-02 Open Failure to Perform Adequate IST of
TDFW Check Valves on Cessation or
Reversal of Flow (Section E8.6).
VIO 50-348, 364/97 11-03 Open TDAFW Battery Installation and
Check Valve Test Deficiencies
(Sections E8.7 and E8.9).
VIO- 503348. 364/97-11-04 Open r ailure to Implement a Test Program
for Service Testing of the TDAFW
Battery (Section E8.8).
V10 50 348, 364/97-11-05 Open Design Control Measures did not
ensure that calculations were
verified and controlled (Sections
E8.16 and E8.25).
Enclosure 2
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VIO 50 348, 364/97-11-06 Open inadequate Corrective Action To
Resolve Differences Between CCW
System P&lDs And Operating
Procedures (Section E8.20).
VIO 50 346, 364/97-11 07 Open Auxiliary Building Battery
Surveillance Test Criteria
inconsistent With TS (Section
E8.22).
VIO 50 348, 364/97-11-08 Open Unattended And Unmarked SGI left in
the MCR (Section S3.1).
G101Cd
lyne Item Number Status Descriotion and Reference
IFI 50 348. 364/97-10 03 Closed Review Licensee Evaluation for
Extended Onsite Storage of
Contaminated Wet Resin (Section
R8.1).
VIO 50-348. 364/97-11-11 Closed Unattended And Unmarked SGI Left in
The MCR (Section 51.1).
LER 50 364/97-03 Closed Failure To Perform Diesel Generator
Surveillance Requirements Due To
Procedural Inadequacy (Section
M8.1).
LER 50-348/97-05 Closed Failure To Perform Nuclear
Instrumentation Surveillance
Requirements Prior To Mode 2 And 3
Entry (Section M8.2).
VIO 50-348, 364/97-05-03 Closed Failure To follow Multiple TS
Surveillance Requirements (Section
M8.3).
IFl 50 348, 364/96-09-04 Closed CCW HX Epoxy Coating and Broken
Tubes (Section M8.4).
IFl 50 348, 364/96 06-07 Closed Fire Main Failures (Section F8.!'.
IFl 50 348, 364/96-13-03 Closed Foreign Material From Seal
Injection System To RCP Seals
(Section M8.5).
IFI 50-348. 364/96 13-07 Closed Certain HELB Isolation Sensors Not
Described In UFSAR (Section E8.2).
LER 50-364/96-03 Closed Steam Generator Tube Degradation
and Tube Status (M8.6).
Enclosure 2
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VIO 50-364/96-155 01014 Closed Steam Generator Tube Flaws With F*
Distance (Section E8.3).
VIO 50-348/97-130-01014 Closed failure To Prescribe Documented
50-364/97-130 01014 Instructions For Procedures To
implement PRF Testing and Operation
(Section M8.7).
URI 50-348. 364/97-201-01 Closed Unprotected CST Connections
(Section E8.4).
t
URI 50 348, 364/97-201 02 Closed Tornado Protection of CST Level
Instrumentation (Section E8.5).
URI 50-348. 364/97 201-03 Closed AFW Check Valve Reverse Flow
Testing (Section E8.6).
URI 50 348. 364/97-201-04 Closed AFW Check Valve Forward Flow
Testing (Section E8.7).
URI 50-348. 364/97-201-05 Closed TDAFW Battery Testing (Section
E8.8).
URI 50-348, 364/97-201-06 Closed TDAFW Battery Installation (Section
E8.9).
IFl 50-348/97-201-07 Closed CST Level Alarm (Section E8.10).
IFl 50-348/97-201-10 Closed CST Level Transmitter Freeze
Protection (Section E8.13).
URI 50 348. 364/97-201-11 Closed AFW UFSAR Discrepancies (Section
E8.14).
URI 50-348. 364/97-201-13 Closed MOV Design Basis Differential
Pressure (Section E8.16).
Ifl 50-348. 364/97-201-14 Closed CCW Pump Testing (Section E8.17).
URI 50 348, 364/97-201-15 Closed Post Modification Testing (Section
E8.18).
URI 50-348. 364/97-201-l'/ Closed Drawing and Procedure Discrepancies
(Section E8.20).
URI 50-348, 364/97 201-18 Closed CCW UFSAR Discrepancies (Section
E8.21).
URI 50-348, 364/97-201-19 Closed TS Change for Auxiliary Building
Battery (Section E8.22).
URI 50-348, 364/97-201-20 Closed Fire Barrier Penetration Seal
Documentation (Section E8.23).
Enclosure 2
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URI 50-348, 364/97-201-21 Closed Electrical UFSAR Discrepancies
(Section E8.24).
URI 50-348, 364/97-201-22 Closed Control of Calculations (Section
E8.25).
Discussed
Iygg Item Number Status Eescriotion and Reference
IFI 50 348. 364/97-10 02 Open UFSAR Reverification Corrective
Actions (Section E8.1).
URI 50-348. 364/97-201-08 Open
'
Tornado Protection of TDAFW Pump
Vent Stack (Section E8.11).
URI 50 348, 364/97-201-09 Open Tornado Missile Spectra (Section
E8.12).
URI 50 348. 364/97-201-12 Open Stress Analysis Temperature
(Section E8.15).
IFI 50 348. 364/97-201-16 Open Calculation Discrepancies (Section
E8.19).
Enclosure 2