ML20236J663
| ML20236J663 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 06/26/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20236J656 | List: |
| References | |
| 50-327-98-06, 50-327-98-6, 50-328-98-06, 50-328-98-6, NUDOCS 9807080301 | |
| Download: ML20236J663 (42) | |
See also: IR 05000327/1998006
Text
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U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-327. 50-328
License Nos:
Report ~No:
50-327/98-06. 50-328/98-06
Licensee:
Tennessee Valley Authority (TVA)
Facility:
Sequoyah Nuclear Plant. Units 1 & 2
Location:
Sequoyah Access Road
Hamilton County. TN 37379
Dates:
April 26 through June 6, 1998
Inspectors:
M. Shannon. Senior Resident Inspector
R. Starkey. Resident Inspector
R. Telson, Resident Inspector
D. Thompson, Safeguards Inspector (Sections S1. S2 and
S4)
W. Kleinsorge. Reactor Inspector (Section M1.3)
H. Whitener. Reactor Inspector (Section E2.5 and E2.6)
C. Smith. Reactor Inspector (Sections E8.3 through
E8.7)
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J. Colaccino. Reactor Engineer. NRR. (Section E2.5 and
E2.6)
J. Blake. Reactor Inspector (Section M3.1)
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Approved by:
Harold O. Christensen. Chief
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Reactor Projects Branch 6
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Division of Reactor Projects
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9807080301 980626
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Enclosure 2
ADOCK 05000327
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EXECUTIVE SUMMARY
Sequoyah Nuclear Plant. Units 1 & 2
NRC Inspection Report 50-327/98-06. 50-328/98-06
This integrated inspection included aspects of licensee operations,
maintenance, engineering, plant support, and effectiveness of licensee
controls in identifying, resolving, and preventing problems: in addition. it
included the results of regional security, steam generator inservice
inspection (ISI), pump and valve ASME Section XI testing, post maintenance
testing, and engineering corrective action inspections.
Ooerations
A positive finding was identified in that the operators performed well
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in addressing the degrading plant conditions prior to the automatic
reactor tri) and performing the subsequent recovery actions.
In
addition. t7e plant startup was well performed.
In both evolutions,
communications was considered to be good (Section 01.2).
A negative finding was identified in that the assistant unit operator's
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(AUO) actions of tapping on the valve / valve limit switch, without
guidance from the control room caused the loss of the as-found
condition of a valve that had failed to fully stroke (Section 01.3).
The inspector identified a negative finding when operators failed to
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locally monitor the Unit 2 turbine driven auxiliary feedwater (TDAFW)
pump during a maintenance run of the pump (Section 01.4).
The inspector concluded that the licensee has implemented compensatory
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actions to address the issue of part length control rod drive mechanism
(CRDM) potential cracking (Section 02.1).
A positive finding was identified in that the licensee responded
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promptly and appropriately to an essential raw cooling water (ERCW) leak
inside the Unit 1 annulus which had rendered a radiation monitor
containment isolation valve inoperable (Section 02.2).
Maintenance
A positive finding was identified in that the licensee executed a well
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planned forced outage schedule following the May 19. 1998. Unit 1
reactor trip (Section M1.1).
A negative finding was identified for the licensee's failure to
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establish a preventative maintenance (PM) activity (18 years) for
sampling or changing emergency diesel generator (EDG) generator bearing
oil (Section M1.2).
A positive finding was identified in that post maintenance testing was
conducted appropriately and in a manner consistent with procedural and
regulatory requirements (Section M1.3).
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A weakness was identified in the Work Order process relating to
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documentation deficiencies (Section M1.3).
A concern was identified with the potential deficiencies in maintenance
and inspection procedures which resulted in ice condenser ice basket
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dam'ge and also did not promatly identify the damage, for at least ten
Uni. 1 ice baskets (Section 12.1).
A weakness was identified for a less than effective program for the
identification and correction of water intrusion into electrical
components (Section M2.2).
A concern was identified for the potential improper compression setting
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and the potential inadequate post maintenance testing of the shutdown
bus alternate supply breaker (Section M2.3).
A strength was identified in that eddy current data evaluation and
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management tools were strong components of the licensee's program for
steam generator degradation management (Section M3.1).
Enaineerino
A violation was identified for failure to perform an adequate safety
e
evaluation prior to making modifications to the waste gas analyzer
system (Section E2.1).
A positive finding was identified based on System Engineering
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successfully developing and implementing an action alan to remove boron
from the Unit 1 lower compartment coolers (Section E2.2).
A weakness was identified due to continuing steam dump system problems
which resulted in the May 19. 1998. water hammer event and piping
sapport damage (Section E2.3).
A positive finding was identified based on engineering support of
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facilities and equipment when a licensee identified steam generator
hydraulic snubber leak was properly assessed for operability and a
thorough corrective action plan was promptly implemented (Section E2.4).
Observation of pump tests. review of pump test procedures, and review of
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pump parameter trend data indicate that the licensee has established and
implemented an adequate pump IST program.
The insSectors noted that the
limiting values for pum) acceptance criteria were Jased on the most
conservative of the tec1nical specification. design basis, or code
calculated values (Section E2.5).
The acquisition of a new software program for analysis, tracking and
trending IST data was considered a positive addition to the IST program
(Section E2.5).
The inspectors concluded that the licensee had developed and implemented
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an IST program which, in general, was consistent with the regulations
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and the ASME Boiler and Pressure Vessel,Section XI code.
However. one
violation, with three examples for failure to adequately implement
Section XI code testing requirements, was identified during the
inspection (Section E2.6).
Plant Sucoort
A positive finding was identified based on the licensee conducting its
security and safeguards activities in a manner that protected public
health and safety.
This portion of the program. as implemented, met the
licensee's commitments and NRC requirements (Section S1).
A violation was identified for a failure to properly control access at
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the sally port (Section 51).
A positive finding was identified in that the licensee's security
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facilities and equi) ment were determined to be very well maintained and
reliable even thoug1 a test procedure for standardized testing of the
intrusion detection equipment had not been developed (Section S2).
The excellent Engineering and instrumentation and controls (I&C) support
was the major contributing factor to continued operability of the
detection and assessment equipment (Section S2).
A positive finding was identified in that the security force members
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(SFMs) adequately demonstrated that they have the requisite knowledge
necessary to effectively implement the duties and responsibilities
associated with their day-to-day and contingency response duties
(Section S4).
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Report Details
Summary of Plant Status
Unit 1 automatically trip]ed from 100% power on May 19. 1998, due a low-low
steam generator level.
T1e sequence of events was initiated by a
malfunctioning 480 Vac shutdown board breaker and the subsequent failure of a
vital 120 Vac inverter.
Repairs were made to affected electrical equi) ment
and the unit was restarted and achieved criticality on May 20; the tur]ine
generator was returned to service at 8:54 a.m.. on May 21: and Unit I reached
100% power on May 22. 1998.
Unit 2 operated at full power for the entire inspection period.
Review of Uodated Final Safety Analysis Report (UFSAR) Commitments
While performing inspections discussed in this report, the inspectors reviewed
the applicable portions of the UFSAR that were related to the areas inspected.
The inspectors verified that the UFSAR wording was consistent with the
observed plant practices, procedures, and/or parameters.
I. Operations
01
Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure 71707. the inspectors conducted frequent
reviews of ongoing plant operations.
In general, the conduct of
o)erations was considered to be good based on operator actions following
t1e reactor trip on May 19 and the subsequent plant startup on May 20.
Instances of weak operations performance were noted based on an
assistant unit o)erator tapping on a valve limit switch and lack of
operator oversigit during post maintenance testing of the turbine driven
,
auxiliary feedwater pump.
01.2 Automatic Reactor Trio Due to loss of Vital Inverter
a.
Insoection Scooe (71707)
The ins)ectors reviewed the events and observed the activities related
to the Jnit 1 automatic reactor trip on May 19, 1998, and the subsequent
startup on May 20, 1998.
b.
Observations and Findinas
AT 10:43 a.m., on May 19.1998. Unit 1 experienced an automatic reactor trip from 100% power.
The inspectors observed the various control room
activities just prior to the trip and the recovery actions following the
trip.
Surveillance activities were in progress on the 1Al-A vital 480 volt
alternating current (Vac) shutdown board and the shutdown board was
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being transferred to its alternate supply breaker.
The system is
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designed such that the normal supply breaker is opened and then the
alternate supply breaker is manually closed.
Following closure of the
alternate sup)ly breaker, the operators noted an arcing sound and smoke
coming from t1e alternate supply breaker cubicle.
The alternate breaker
was reopened and the normal supply breaker was re-closed. The total
evolution took approximately 45 seconds.
During the time period that the alternate breaker was closed onto the
vital bus, the vital 120 Vac inverter experienced voltage spikes of
sufficient magnitude that the output fuses for the silicon control
rectifiers failed and deenergized the 120 Vac vital Bus 1.
Loss of
vital 120 Vac Bus 1 caused a loss of channel 1 of the steam flow
instrumentation for all four steam generators which led to a closure of
all four main feedwater regulating valves.
The loss of Steam Flow
Signal also caused the main feedwater pumps' master control circuitry to
run tha feedwater pump speed to minimum.
The operators made an attempt
to recover the feedwater regulating valves and feedwater pump speed
control; however, the plant tripped on low-low steam generator level
approximately 35 seconds after total loss of the vital inverter.
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The. operators experienced other abnormal plant conditions that further
complicated recovery actions.
Due to the loss of vital 120 Vac Bus 1.
feedwater isolation valves to steam generators #1 and #3 did not
automatically close when the feedwater isolation signal was generated.
The operators had to manually close the valves.
In addition, the loss
of the vital 120 Vac bus caused a loss of essential and nonessential
control air to containment and caused letdown to isolate. As a result.
the pressurizer level increased and pressurizer pressure increased
until the pressurizer power operated relief valves (PORVs) opened.
The inspector was in the control room area at the start of the event and
observed control room operator activities just 3rior to the trip and
following the trip.
The inspector noted that tie control room operators
followed the applicable procedures and clearly communicated plant
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conditions during the recovery.
Pending actions were fully discussed
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prior to implementation and interim shift status briefings were
detailed.
The inspectors also observed the Unit 1 startup on May 20. 1998.
Pulling of the shutdown bank rods was started at 3:30 p.m. and Unit 1
entered Mode 2 at 5:28 p.m.
At 6:27 p.m.. on May 20. 1998, the reactor
went critical. The inspectors observed good communications and
procedure adherence during the startup.
The root cause for the automatic reactor trip was a faulted 480 Vac
supply breaker. This issue is discussed in more detail in Section M2.3
of this report.
c.
[gnclusions
The inspectors concluded that the operators performed well in addressing
the initial plant conditions prior to the automatic reactor trip and in
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performing the subsequent recovery actions.
In addition, the plant
startup was well coordinated.
In.both cases communications were
considered to be good. -This is considered to be a positive finding.
01.3 Inaoorooriate Tacoina of Valve Limit Switch
a.
Insoection Scooe (71707)
The inspectors reviewed the licensee's actions in response to
ina)propriate status light . indication for the 2A residual heat removal
(RHR) system temperature control valve.
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'b.
Observations and Findinos
On June 1.1998, during routine control room observations, the
' ins)ectors noted that the licensee was experiencing problems with the-
lig1t indication for the 2A RHR system temperature control valve 2-FCV-
74-16.
Status light panel 2-XX-55-6C indicated that the valve was not
fully open. The licensee had previously successfully completed the
stroke time testing of this valve and after completion of the post
maintenance testing of the 2A RHR pump the valve did not indicate fully-
open as required.
The control room operators dispatched an. AUO to verify the valve
)osition. The AU0 informed the control room that the valve appeared to
)e fully open. The control room operators called the system engineer to
discuss the valve problem and initiated a work request (WR C-397112) to
check on the limit switch.
~Several minutes later the inspectors and the control room operators
observed.that the 2-FCV-74-16 status light indication went'out. The
control. room operators contacted the AUO again'to verify valve status.
The AVO. stated that he had tapped on the valve with his flashlight. .The
-licensee subsequently identified that the ' collar on the valve, stem for
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operation of the fully open limit switch was loose. .It was retightened
and the valve was successfully stroke time tested.
.c.
Conclusions
The AUO's actions of tapping.on the valve / valve limit switch, without
guidance from the control room, caused the loss of the as-found
condition of the valve. .This item is identified as a negative finding.
- 01-.4 Ooerators Fail ~ to Locally Monitor TDAFW Pumo Durina Maintenance Run'
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~ Insoection Scooe'(71707)
a.
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The inspector followed u) on the failure of Operations to station an
- operator at' the Unit 2 T)AFW pump during a maintenance run of the pump.
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b.
Observations ^and Findinas
On. June 5,1998,- the inspector entered the Unit 2 TDAFW pump room during
a' maintenance run of the pump and observed the inboard pum) shaft
packing failure. The ins)ector observed black smoke, sparcs and heard a
)opping noise during' the 3rief interval prior to the pump being stopped
Jy the main control room. At the time of the packing failure, a
mechanical maintenance technician'was in the pump room.
However, there
. were no o)erations personnel. in the area.
Prior to the packing failure,
the pump lad been run twice that day, once for an' ASME Section XI test
and a second-time to perform the check valve test. The packing failure
occurred during a third pump run following a change out of the bearing-
-oil.
Once the pump was stopped, the inspector remained in the area for
approximately 30 minutes during which time no one from operations
, arrived in the area to inspect the pump for damage
The inspector informed the Unit Supervisor and Shift Manager of the
absence of an AVO or other Operation's personnel in the area during the
. maintenance run of the TDAFW. The ins)ector was informed later in the
day by the Operations Superintendent t1at it was management's
. expectation that an operator be in the area during running of safety
related~ equipment. However, miscommunication occurred between a
licensed operator in the control room and the responsible AUO. which
resulted 'in no operator being present in the. area during the TDAFW pump
run.
The licensee initiated PER No. SQ980695PER to document the failure of
the Unit 2 TDAFW inboard packing. The pump was subsequently inspected,
the packing replaced, and an ASME Section XI test was run prior to-
' operations declaring the pump operable.
On June 6. 1998, Operations management issued Standing Order 98-032.
entitled Equipment Monitoring, which stated that whenever safety related
or any other large piece of equipment is started, stopped, or tested, an
o)erator. is expected to be present to monitor equipment performance for
t1e duration of the equipmcot test.
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c.
Conclusions
The inspector . identified'a negative finding when operators failed to
locally monitor the Unit 2 TDAFW pump during a maintenance run of the
pump.
02.
Operational Status of Facilities and Equipment
02.1 Plan -for Addressina Part Lenath Control Rod Drive Mechanisms (CRDM)
Potential Crackina
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a.
Insoection Scoce (71707).
The inspector reviewed the licensee's compensatory actions which were
put~in place;until TVA and the Westinghouse Owner's Group (WOG) resolve
the issue of part length CRDM potential cracking.
bs Observations and Findinas
In a letter to the NRC, dated April 9,1998. TVA provided its plan
to address the industry issue of part length CRDM cracking, a problem
which was first identified at the Prairie Island. Nuclear Plant. The
' letter stated that TVA believes that the data and evaluation to date
suggests that the finding on the one part length CRDM at Prairie Island
is- related to a unique set of circumstances at that facility a id
configurations at Sequoyah and Watts Bar are less susceptible to this
phenomenon.
TVA stated that it will continue to follow industry
initiatives addressing this issue and may further revise the outlined
comprehensive approach based on the results of these initiatives.
Until the TVA and WOG evaluation is completed. TVA has issued guidance
to the Operations staff to heighten awareness and implement compensatory
.RCS leakage monitoring actions. The inspector verified that on April 7.
1998. Standing Order 98-020.. Interim Increased RCS Leakage Monitoring,
was issued to Operations personnel.
Specifically, each shift was
directed to monitor the following parameters: containment moisture.
' containment pressure, containment radiation levels, containment
temperature, and containment sump levels.
A more in-depth technical
rev4ew will be performed to identify the source of leakage identified
above a pre-established threshold.
c.
Conclusions-
The inspector. concluded that the licensee has impl'mented compensatory
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actions to address the issue of part length CRDM potential cracking.
02.2 ERCW Leak Inside Unit 1 Annulus
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a.
Insoection Scooe (71707)-
The inspector reviewed the circumstances involving an ERCW pin hole leak
inside the Unit 1 annulus which resulted in the inoperability of the
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1ower compartment radiation monitor containment isolation valve.
- b. Observations and Findinas-
On June 3. 1998, at 12:08 a.m., while troubleshooting a ground on vital
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battery board;I. . electricians identified 1-FCV-90-107. the Unit 1 lower
compartment radiation monitor containment outboard isolation valve, a
normally open. valve, as being the source of the ground. At 3:37 a.m..
operators. observed from' control room indications that 1-FCV-90-107 was
. indicating mid-position, declared the valve inoperable and entered the
action statement.of TS 3.6.3. Containment Isolation Valves. At 4:10
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a.mi. during an inspection of 1-FCV-90-107 in the Unit 1 annulus.
. electricians and radiation control technicians identified a water leak
- in the general area of 1-FCV-90.-107, but were unable to identify the
source of the-leak. Operators subsequently isolated ERCW cooling water
to upper com)artment cooler 1B. which stopped the leak.
The inspector
arrived in t1e control room at 4:15 a.m. and observed the licensee's
response.and resolution to the problem of the inoperable containment
isolation valve.
The licensee; believing that the problem with 1-FCV-90-107 was a
grounded limit switch, attempted to clean and dry out the limit switch
which had apparently been exposed to spray from the ERCW leak. After
the cleaning efforts proved to be unsuccessful, the decision was made to
replace the limit switch.
Prior to replacing the limit switch the
containment penetration was isolated'at 7:12 a.m. to comply with the
action statement of TS 3.6.3.
The limit switch was then replaced. 1-
FCV-90-107 was stroke time tested and declared operable and at 9:50 a.m.
TS 3.6.3 was exited.
Isolation of the containment penetration also
rendered the lower compartment radiation monitor (1-RM-90-106)
ino)erable which required entry into TS 3.4.6.1. Reactor Coolant System
Leacage. At 10:30 a.m., following repairs to 1-FCV-90-107, radiation
monitoring of lower containment was reestablished and TS 3.4.6.1 was
exited. At no time were any TS action statements exceeded.
This event
was documented in PER No. SQ980671PER.
Later on June 3. the licensee inspected the Unit 1 annulus and
discovered a pin hole leak in a section of 2-inch diameter ERCW piping
to the;18 upper compartment cooler. The licensee stated that this
section of piping was verified not to have been leaking during the week
of May 24. 1998. when the piping had been ultrasonically tested (UT) for
pipe wall' thinning.
During the UT of the pipe no abnormalities were
identified. The pipe will remain isolated until the next refueling
outage at which time repairs will be made,
c.
Conclusions-
The inspector concluded that the licensee responded promptly and
appropriately to an ERCW pipe leak inside Unit 1 annulus which had
rendered a radiation monitor containment isolation valve inoperable.
This is considered a positive finding.
08'
Miscellaneous Operations Issues (92901)
08.1
(Closed) URI 50-327. 328/98-03-03. Potential Failure to Meet UFSAR
Requirements. Failure to Revise the UFSAR. Inaoorooriately Closina a
10c ification Packaae. and not Establishing a Periodic Samolina Proaram
for the Waste Gas-Collection System.
This issue was discussed in
Section E2.1 of this report and resulted in a violation for failure to
perform an adequate safety evaluation prior to making modifications to
the waste gas analyzer system.
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08.2 (Closed) URI 50-327/98-03-01. Potential Failure to Enter TS 3.11.2.5 LC0
Action Statement When Samoles Indicated High Concentrations of Oxygen in
the PRT.
The inspectors completed a review of the licensee's design
basis docurrents and discussed this issue with regional management.
It
was concluded that the PRT would not be applicable te TS 3.11.2.5.
However, the licensee did revise their waste gas sampling procedures to
limit explosive gas concentrations in the pressurizer relief tanks
(PRT). volume control tanks, spent resin stor6ge tank 6 rid waste holdup
tanks to be consistent with the TS explosive gas limits of less than 2%
oxygen with great'.. than 4% hydrogen.
The inspectors concluded that no
violation of TS occurred.
II. Maintenance
M1
Conduct of Maintenance
M1.1 General _ Comments
a.
Insoection Scooe (61726 & 62707)
Using inspection procedures 61726 and 62707 the inspectors conductea
frequent reviews of ongoing maintenance and surveillance activities.
The inspectors observed and/or reviewed all or portions of the following
work ac wities and/or surveillance:
1-MI-TFT-201-051.A
Relay Functional Test For 480V Shutdown
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Board 1Al-A. Rev. 2
WO 98-004981-000
Repair of Water Intrusion Into Control
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Station For ERCW Pump Traveling Screens
2-SI-IFT-092-N41.1
Functional Test Of Power Range Nuclear
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Instrumentation System. Channel 41. Rev. 9
WO 97-013195-000
Repair Oil Leak On Main Feedwater Pump Oil
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Filter
0-PI-IXX-092-N45.0
Calibration Of Power Range Nuclear
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Inc.trumentation System Following
Incore/Excore Detector Calibration. Rev. 6
0-PI-SFT-032-001A
Auxiliary Control Air Compressor "A"
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Operability Test. Rev. 4
b.
Observations and Findinos
On May 19. 1998. Unit 1 entered a forced maintenance outage following an
automatic reactor trip.
The inspectors noted that the licensee had a
well planned forced outage schedule and completed approximately 50 work
orders prior to restarting the unit.
Some of the major activities
included repairing an air leak on a main feedwater regulating valve.
repsiring an electro-hydraulic control oil leak on the 1A main feedwater
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(MFW) pump, and sparing out a main bank transformer which haa been
indicating higher than normal combustion gas concentrations.
C.
Conclusions
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The licensee executed a well planned forced cutage schedule following
the May 19, 1998. Unit I reactor trip. This is a positive finding.
M1.2 Eneraency Diesel Generator Bearino Oil Samol g
a.
Inspection Scoce (62707)
The inspector reviewed the issue regarding periodic oil samples not
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being taken on emergency diesel generator (EDG) generator bearing oil
and the fact that the generator bearing oil had never been changed
during the inservice life of the EDGs.
b.
Observations and Findinas
During a predictive maintenance (PM) lobe oil PM optimization review.
the licensee discovered that oil in all four EDG generator bearing
housings had never been sampled or changed during the approximate 18
years of EDG service.
Following this identification, samples were taken
from each of the EDGs. The sample analysis indicated elevated levels of
iron. lead, tin. silicon. copper and zinc. as well as elevated viscosity
and neutralization number, indicative of the acidity of the oil.
PER
No. S0980378PER dated April 10. 1998, documented the discovery of the
lack of generator bearing oil sampling or change-out and discussed root
causes, extent of condition, vendor recommendations, and corrective
actions.
On May 5. 1998, the licensee com)leted a Technical Support Investigation
Request (TSIR) which concluded tlat there was no technical basis
requiring immediate oil replacement and no operability concern with any
diesel generator in performing its intended safety function.
The TSIR
recommended that oil replacement be scheduled during upcoming EDG
outages unless opportune times occur earlier.
Work Requests were
written to change the generator bearing oil in each EDG.
The inspector discussed with the licensee the vendor and owners group
recommendations regarding generator bearing oil change-out.
The
generator portion of vendor manual E130-0010 recommended that the oil be
drained and flushed at least once a year. The bearing manufacturer
recommended oil change-out based on run time hours.
(None o' the
Sequoyah EDGs have exceeded the bearing manufacturer's run time hour
limits.) Finally, the owners group recommended maintenance program did
not specifically state any requirements for generator bearing oil.
Although it appears that there were no specific vendor recommendations
which applied to the ty)e service to which the EDGs are exposed, the
licensee had never esta)11shed a PM activity to either sample or change
the generator bearing oil on EDGs.
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The inspector reviewed Surveillance Instruction (SI)-102 M/M. Diesel
Generator Monthly Mechanical Inspections, and concluded that maintenance
personnel have been visually checking the generator bearing oil level
sight gauge on each EDG once each month, during the EDG monthly
surveillance o)erability run.
Following identification that the bearing
oil had never Jeen sampled the licensee revised SI-102 M/M to include a
quarterly samaling frequency. The frequency of oil change out will be
conditional. Jased on results of the quarterly oil sample analysis.
Inspector discussions with Operations management indicated that
generator bearing oil levels have not been monitored by operations.
The licensee performed an extent of condition review on safety related
rotating equipment and determined that all lubricated equipment reviewed
had a preventative maintenance task to perform lube oil change-out or
sampling.
The licensee's review of EDG attendant equipment revealed
that the EDG air compressors, which are non-safety related did not have
a PM for oil change-out, although the oil filters had been changed every
three months. All the EDG air compressors had been replaced, on an as
needed basis, within the last five years. The licensee has revised the
PM procedure to change the EDG air compressor oil filters and oil every
six rionths.
c.
Conclusions
A negative finding was identified for the licensee's failure to
establish a PM activity for sampling or changing EDG generator bearing
oil.
M1.3 Post Maintenance Testina (PMT)
a.
Insoection Scoce (62700)
To evaluate the licensee's program for PMT, the inspectors reviewed:
the licensee's written practice for PMT. three recent assessments
addressing PMT. the corrective action documents associated with those
assessments, and com)leted work order (WO) packages.
The inspectors
also conducted a walc down inspection of the equipment associated with
several completed WO packages.
From January 1. 1998 to A)ril 27, 1998,
the licensee completed approximately 2000 WO packages.
T1e inspectors
selected for review a sample of 30 WO packages, from that period,
representing 21 systems and all three maintenance disciplines
(mechanical, electrical and instrumentation).
The WO packages were
reviewed for adequacy of PMT and observations were compared to the
licensee's written practice and the UFSAR.
The 30 WO packages were
reviewed for proper capture of unavailability times, as required by the
maintenance rule. 10 CFR 50.65.
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b.
Observations and Findinas
PMT was implemented at the Sequoyah Nuclear Plant by SSP-6.31.
" MAINTENANCE MANAGEMENT SYSTEM PRE- OR POST-MAINTENANCE TESTING".
[
Revision 10. effective April 22, 1998.
As a result of their review, the
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'. inspectors. identified to the licensee some inconsistencies and a number
of enhancements.
The licensee indicated that they would address those
items in the next revision of-SSP-6.31.
'
Self-Assessment SA-MTN-98-003. ." Post-Maintenance Testing". was conducted
- -
u
February 9-27, 1998. Assessment SA-MTN-98-003 identified three findings
L
which were addressed in three problem evaluation reports (PERs).
These
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findings included: documentation deficiencies in some W0s: WO scope
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changes made without re-review by the Operations Department: and some
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personnel ap3 roving WO activities which were not on the PMT approval
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list. The t1ree PERs addressed the specific examples identified and
!
took or planned a) pro')riate actions to prevent reoccurrences of similar
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circumstances. .T1e PER's' corrective action plans did not address
similar problems in the remainder of the licensee's completed WO
'
packages.' Assessment NA-S0-98-28. " WORK ORDER (WO) CLOSURE BACKLOG".
com)leted April 7.-1998, indicated that over 50 3ercent of the WO
paccages reviewed were submitted for closure wit 1 deficiencies, the
l
majority of which .were the result of inattention to detail. (human
performance).
A PER was issued to address this issue and remains open.
Assessment SA-MTN-98-05. " Maintenance & Modification Quarterly Self -
'
Assessment". conducted March 16-A)ril 4.1998, identified problems using
not applicable (N/A) in W0s.
A PER was issued to address this issue and
remains open. .Of the 30 completed WO packages reviewed by the
inspectors. 12 were electronic records, for which the licensee provided
computer screen prints for review, no discrepancies were identified.
The. remaining 18 completed WO packages reviewed were hard copy records
L
reproduced from microfilm in some cases, completed by handwriting.
No
deficiencies were identified in 6.
The remaining 12 contained
I
documentation deficiencies, which included: missing signatures: missing
'
data; missing documents: vague PMT acce)tance criteria: and PMT
g
accomplished. but'not documented as sucl. _Several WO packages
a)parently had their pages out of order, making it' difficult to follow
t1e course of work.
Page numbering would have alleviated this
difficultly. A space is provided for page numbering on most pages in WO
packages but that option was infrequently used. The inspectors did not
identify any examples of inadequate or inappropriate PMT.
The inspectors consider the documentation deficiencies, identified by
both the licensee and.the NRC, the result of inattention to detail and a
'
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_ eakness in the licensee's Post Maintenance Test Program.
w
Equipment' unavailability time as it relates to 10 CFR 50.65 was properly
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captured for the 30 WO packages reviewed by the inspectors.
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c.
Conclusions
Post maintenance testing wasl conducted appropriately and consistent with
procedural and regulatory requirements.
A weakness in the licensee's Post Maintenance Test Program relating to
documentation deficiencies was identified.
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M2
Maintenance and Material Condition of Facilities and Equipment
M2.1. Damaae to Multiole Ice Condenser Ice Baskets.
a.
Insoection Scooe (61726)
Inspectors reviewed Problem Evaluation Report No. SO980597PER. Technical-
Operability Evaluation (TOE) 1098-061-0597 and applicable maintenance
and surveillance procedures in connection with a recent licensee finding
{
of ten damaged Unit 1 Ice Condenser Ice Baskets.
1
b.
Observations and Findinas
On May 19. 1998, during a Unit 1 forced outage the licensee conducted
an inspection of the ice condenser. The inspection identified lateral
deformations in the vicinity of the bottom su) port rings of nine baskets
and torn ligaments in the same area of a tenti basket.
T0E~1098-061-0597.. performed to assess ice condenser operability,
concluded that, due to the limited number of baskets involved, the
damage to the ice baskets did not degrade the ability of the ice
condenser to limit peak pressure in the containment following a LOCA or
Discussions with the . system engineer indicated
!
that the baskets had probably been damaged by jacking from below while
l
attempting to free them during previous outages.
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The inspectors' evaluated the ice condenser ice basket maintenance and
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surveillance procedures for adequacy with' regard to maintaining ice
basket mechanical integrity durina and following efforts to break loose
frozen-in-place ice baskets from Tattice framework. .The licensee's
procedure for breaking ice baskets free allows up to 4.000'lbs, of
upward thrust to be applied to the bottom of the ice basket while
simultaneously applying twisting and lifting forces.
The procedure
cautions against excessive force that would cause basket damage, yet
contains no guidance to inspect for damage before during or after
.
basket-freeing activities.
Surveillance procedure 0-SI-MIN-061-003.0 " Ice Condenser - Ice Baskets"
describes ice condenser. ice basket visual inspection requirements in
- accordance with Technical Specification Surveillance Requirement 4.6.5.1.C.
Reliance ~on this surveillance procedure alone to identify
the type of damage addressed in PER S0980597PER appeared to be
inadequate.in that-(1) The procedure only. required sampling six of the
1944 baskets once every 40 months and (2) the procedure required that
the baskets be unpinned and lifted ten feet before the ins)ection.
Because of these. requirements, the surveillance could not 3e performed
on damaged frozen-in-place baskets and could fail to identify damage in
the vicinity of basket bottoms due to the baskets having been lifted
before. inspection.
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The licensee in res)onse to heightened regulatory interest and ongoing
concerns regarding tieir ice condensers, formed a self-assessment team
to evaluate this and other issues.
To date the licensee's self
assessment process has identified approximately fifteen additional PERs
that were being generated in connection with the licensee's assessment
team's findings.
c.
Conclusions
The )otential deficiencies in maintenance and inspection procedures
whici resulted in ice condenser ice basket damage and the failure to
identify the damage, for at least ten Unit 1 ice baskets is considered
to be an Unresolved Item (URI 50-327/98-06-01).
M2.2 Water Intrusion Into Essential Raw Coolina Water (ERCW) Buildina
Electrical Boxes
a.
Insoection Scooe (62707)
The inspectors reviewed the licensee's corrective actions related to
3revious events where water was found inside various electrical junction
aoxes.
b.
Observations and Findinas
On April 20, 1998, the inspectors identified water intrusion into the
ERCW building vital motor control center (MCC) b-B ERCW MCC.
The
licensee subsequently discovered that rain water was entering the screen
wash control switch junction box and draining down the cable into the
MCC. Discussions with the licensee indicated that other susceptible
junction boxes in the ERCW building had been inspected for water
intrusion.
This issue was discussed in Inspection Report 98-04 and a
negative finding was identified at that time.
On May 18, 1998, the inspectors were conducting a walkdown of the ERCW
building and noted several electrical boxes that appeared to have been
subjected to water intrusion.
This issue was discussed with the
licensee and the licensee subsequently opened the suspect electrical
boxes. The licensee found that six fire protection electrical
Jull
boxes had internal evidence of water intrusion.
In addition t1e
licensee found five additional electrical boxes with deteriorated cover
gaskets which needed to be replaced.
In October 1996. Unit 2 experienced a turbine run back that led to a
reactor trip due to water intrusion into the turbine impulse switches.
,
The licensee noted that electrical box sealing requirements were
!
proceduralized for the safety related buildings, but were not specified
for the turbine building.
The appro)riate procedures were revised to
include sealing requirements for tur)ine building electrical boxes.
In
addition, the licensee stated that im] roved inspection methodology for
inspection for water intrusion would )e developed.
Based on the two
recent inspector findings of water intrusion into ERCW electrical boxes.
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13
the licensee's corrective actions for the previous 1996 violation have
not been fully effective in the identification and correction of water
intrusion issues.
c.
Conclusions
i.
A weakness was identified for a less than effective program for the
i
identification and correction of water intrusion into electrical
L
compon'ents.
M2.3- . Failure of the Alternate Sucoly Breaker to Shutdown Bus 1Al-A
a.
Insoection Sccue (62707)
,,
The inspectors reviewed the work history and observed the
troubleshooting: efforts for the alternate supply. breaker for shutdown
Bus 1Al-A following the reactor trip on May 19,
b.
Observations and Findinos
On May 19. 1998, while placing the alternate supply breaker in service
for shutdown Bus 1Al-A. the breaker started to make an arching noise and
began smoking.. The' operators immediately removed the breaker from
_
service. When the breaker was subsequently. inspected. the licensee
identified that .the main line contacts were severely pitted and burned.
The manufacturer's technical representative assisted the licensee in
disassembly and troubleshooting of the faulted breaker. The inspectors
observed portions of.the' disassembly and observed that the licensee
identified that the breaker did not have the pro)er contact alignment or
compression. This preliminary cause explained way the breaker began
arcing with much less than design loading when it was placed in service.
Further review of the licensee's work history and discussions with the
licensee revealed that-this breaker had previously. failed to close on
demand and had been extensively overhauled (January 1998).
Following
the corrective maintenance. the breaker was reinstalled as the alternate
supply breaker.
The breaker remained in standby from January until the
failed transfer on May 19.
-Inspector review of work documents indicated that the contact
compression was-set in accordance with the maintenance 3rocedure during
)
the corrective maintenance activity. However, the breater failed
following its first closure onto a loaded bus. The inspectors
~ determined that this maintenance activity would be considered to be
l
online maintenance and would carry the associated risk for online
maintenance.
In this case. )erformance of the post maintenance
1
testing / load testing of the areaker carried the risk of deenergizing the
shutdown bus
The apparent improper compression setting of the breaker
i
[
main contacts and the potential inadequate post maintenance testing for
breaker loading is considered to be an unresolved item pending further
. review (URI 50-327/98-06-02).
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14
c.
Conclusions
An unresolved item was identified for the apparent improper compression
setting and the potential inadequate post maintenance testing of the-
shutdown bus alternate supply breaker.
M3
Maintenance Procedures and Documentation
-M3.1 Steam Generator-(SG) Degradation Manaaement'
a.
Insoection Scooe (50002)
-The inspectors reviewed.the licensee's programs for steam generator
' degradation management and eddy current data evaluation.
b.
Observations and Findinos
Steam Generator Degradation Management: The inspectors reviewed the
degradation history-for all of the Sequoyah steam generators. The
records showed that the major contributor to tube plugging in' Unit I has
been 'an increase in the number of 3rimary water stress corrosion
cracking (PWSCC) indications at tu)e support plate (TSP) locations.
In
Unit 2 the major contributors to tube plugging were PWSCC at the top of
the tubesheet (TTS) and PWSCC in the small radius U-bends. The total
number of tubes plugged at the end of fuel cycle eight for each SG was
1
as follows:
-Unit 1 SG 1: 77 p gged
2.273%
Unit 2 SG 1:-31 p ugged
0.915%
SG 2:-104
ugged 3.070%
SG 2: 91 p ugged
2.686%.
-SG 3: 205
ugged '6.051%
SG 3: 58 p ugged
1.712%
SG 4: 239
ugged 7.054%
SG 4: 22 p ugged
0.649%
,
The inspectors reviewed the licensee's plans for degradation management
which included alternate plugging criteria-(APC) for PWSCC at TSP
locations.
(The licensee had already received approval for an APC for
ODSCC (secondary side SCC) at TSP locations.
The licensee was also
- actively involved in development of an inspectable electro-sleeving
process to mitigate'PWSCC problems.
Eddy Current (EC) Evaluations: Thslicensee'sEC'dataevaluation
- methodology:for using Bobbin Coil data to screen dented TSP
intersections for PWSCC was reviewed by reviewing selected EC data from
i
the last Unit.1 outage.
The Bobbin Coil lissajous signals provided the
)
analysts with a conservative screening process for indicating which
!
~ dented TSP intersections should be inspected with EC RPC Coils.
-The licensee's Access-based EC data sorting and evaluation program
provided an orderly. auditable record of the decision process for-
. plugging / repair lists. The use of the program ensured that all data
were considered in the selection of in-situ pressure test candidates.
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.c.
Conclusions
Eddy current data evaluation and management tools were strong components
of.the licensee'c program for steam generator degradation management.
M8
Miscellaneous Maintenance Issues (92902)
M8.1
(Closed) LER 50-327/97013. Revision 1. Missed Surveillance as a Result
,
of an Inadeauate Procedure.
Revision 0 to this LER was discussed and-
closed in IR 50-327, 328/98-04. .The issue of the missed breaker
surveillance in revision 0 resulted in the identification of a non-cited
violation, 50-327. 328/98-04-03.
During the licensee's extent of -
-condition review, an additional breaker was identified which had been
mistakenly omitted from the surveillance program during a surveillance
procedure revision.
The additional breaker, identified in revision 1.
was the isolation device protecting a safety-related bus from a
nonqualified load, the onsite paging system.
Other that the additional
breaker, identified during the licensee's extent of condition review, no
new issues were revealed by ~ revision 1 of the LER.
M8.2 (Closed) IFI 50-327/98-03-04. Follow Licensee's Review of the Section XI
Valve Testina Procedure to Determine if a Better Method Would Be
Available to Test the CCS Pumo Discharge Check Valves.
The inspectors
reviewed the mainten6nce history for the five CCS pump discharge valves
and for the essential raw cooling water pump discharge valves and did
not identify any instances that would indicate check valve damage due to
- slamming shut during testing.
Engineering indicated that the valves
were designed to operate with the as observed differential pressure
conditions. Based on the review, the inspectors concluded that the
present CCS pump testing method did not appear to be causing any check
valve problems and therefore would be considered to be acceptable.
III. Enaineerina
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E2
Engineering Support of Facilities and Equipment
E2.1 Modifications to the Waste Gas Analyzer System
a.
Insoection Scooe (37551)
The inspectors reviewed the modification to the waste gas analyzer
system which the licensee implemented during the U2C8 refueling outage.
= b.
Observations and Findinas
-In May 1997. the licensee' prepared Design Change Notice (DCN) M-11549-A
to re) lace the Waste Gas Analyzer (common to both units) with a more
relia)le, state-of-the-art analyzer.
Prior to the modification, the
Waste. Gas Analyzer monitored various tanks in the Waste Disposal System
and' Chemical and Volume Control System (CVCS) for hydrogen and oxygen
= concentrations. The concentrations were. indicated, recorded, and
c
alarmed at the analyzer. The modification, which was completed on
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October 6.1997, converted the sampling system from an electrically
actuated tank selection, which aligned various tanks to the gas analyzer
for sampling, to an automatic and grab sample operation.
The new
analyzer automatically sampled the in-service Waste Gas Decay Tank only.
The modification eliminated the automatic sampling the pressurizer
relief tank (PRT). Volume Control Tank (VCT). Holdup Tank (HUT). and the
Spent Resin Storage Tank (SRST) and )rovided for only grab sampling
capability for these tanks.
Unc'er t1e new design configuration, these
tanks are sampled from a separate sample header which is physically
separated from the waste gas analyzer.
In March / April 1998, the inspectors, while following up on a related PRT
gas sampling issue (IR 50-327. 328/98-03), reviewed the licensee's 10 CFR 50.59 safety evaluation for the modification to the waste gas
analyzer system.
The inspectors determined that the safety evaluation
did not adequately address the elimination of the automatic sampling
system and replacing it with grab sample capability for the PRT. VCT.
HUT. and SRST. The safety evaluation referred to taking grab samples.
but did not evaluate the adequacy of grab samples as compared to an
automatic system nor did it recommend sampling frequencies or procedure
changes to ensure that grab samples would be taken.
By not ensuring
that grab samales would be obtained, the licensee created a situation
where the tan (s went unsampled for an extended period of time with the
)otential to develop explosive / combustible concentrations of oxygen and
lydrogen.
The inspectors concluded that the licensee failed to perform an adequate
safety evaluation prior to modifying the waste gas analyzer system.
'
This is identified as a violation of 10 CFR 50.59 (b)(1) which requires
that the licensee shall maintain records of changes to the facility and
that these records include a written safety evaluation which provides
the bases for the determination that the change does not involve an
unreviewed safety question (VIO 50-327, 328/98-06-03).
In March 1998 the licensee reopened the closed DCN package and revised
the safety evaluation.
The ins)ectors concluded that the revision
corrected the deficiencies in t1e evaluation and adequately addressed
the elimination of the automatic sampling capabilities of the waste gas
,
analyzer. The revision also added an attachment to the DCN modification
criteria which specified the sampling frequency of the PRT. HUT. VCT,
and SRST.
Procedure 0-PI-CEM-000-080.1. Chemistry Sampling Requirements
NRC Inspection and Enforcement (IE)Bulletin 80-10. was revisec
on May
l
11. 1998, to include quarterly sampling of the PRT. VCT. HUT and SRST.
The inspectors reviewed Amendment 13 to the UFSAR which stated that "The
online gas analyzer determines the quantity of oxygen and hydrogen in
'
the volume control tank, pressurizer relief tank, holdup tanks. gas
decay tanks, and spent resin storage tank by monitoring the waste gas
header, or by selecting the individual sample Joint.
The waste gas
analyzer provides an alarm on high oxygen and lydrogen concentration."
Amendment 13 was the "living" UFSAR when the waste gas analyzer
f.
t
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modification was planned and implemented. Amendment 13 was formally
issued in March 1998.
In March 1998 the licensee revised the "living" UFSAR. Amendment 14. to
correctly state the present as built design of the waste gas analyzer
system. That amendment stated that. "The online gas analyzer determines
the quantity of oxygen and hydrogen in the waste gas decay tank that is
in service. The Volume Control Tank. Pressurizer Relief Tank. Holdup
Tanks, and Spent Resin Storage Tank may be analyzed by grab sample as
plant conditions require.'
'
By the end of this inspection period, the licensee had recommended
)
several corrective actions as part of a root cause investigation for PER
S0980240PER. However, the licensee had not yet demonstrated the ability
to consistently take reliable gas samples from the PRT. A DCN has been
drafted to modify the sampling system piping to allow unobstructed grab
samples to be taken.
c.
Conclusions
One violation was identified for failure to perform an adequate safety
evaluation prior to making modifications to the waste gas analyzer
system.
E2.2 Hgron Accumulation on Containment Coolers
a.
Insoection Scooe (37551)
The inspectors reviewed the licensee's Technical Operability Evaluation
(T0E) and corrective actions regarding the boron accumulation on the
Unit 1 lower compartment coolers (LCC).
o.
ObsWVations and Findinas
The licensee identified in PER No. SO980347PER that a Unit 1
unidentified reactor coolant system (RCS) leak was causing boron to be
dispersed in the air in lower containment.
(IR 50-327, 328/97-18
discussed the increase in Unit 1 unidentified RCS leakage.) The
airborne boron then plated out on any wet surface. As air was drawn
into the LCCs the boron accumulated on the wetted portions of the
cooler coils. On April 1. 1998, system engineers performed a
walkdown/ visual inspection of all Unit 1 LCC coils.
LCC B-B was
observed to have the most accumulation of boron on its cooling coils as
com)ared to the other LCCs. The ins)ection also showed that the amount
of Joron in the fan rooms was more tlan had been seen previously during
j
a similar inspection in February 1998.
On April 8.1998, the licensee made an entry into Unit 1 lower
containment fan room 1 to measure airflow of the B-B LCC.
The data
obtained was used for TOE 1-98-030-0347-00 and TVAN calculation MDQ1030-
980016 to determine how the heat removal capacity of the coolers was
affected by the boron buildup.
The analysis concluded that boron
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18
accumulation on the B-B LCC cooler would not reduce the heat removal
capacity of the cooler to below design heat load arovided that the ERCW
temperature heat sink remained equal to or less t1an 72 F.
During the
time the TOE was in effect. ERCW temperatures were less than 72 F.
On April .16.1998, operators changed the inservice LCC fan combination
and removed LCC B-B from service.
ERCW still flowed though the-cooling
coils and thus, with the fan stopped, condensation on the coils
increased as did the accumulation of boron on the coils (washing).
Later on April'23. 1998, operators isolated ERCW to the B-B LCC. but the
fan remained inservice. With no ERCW cooling to the cooler the
l
condensation on.the cooler coils stopped and the boron dust was blown
away by the cooler fan (baking). The air flow was significantly
l
improved following the. evolution. On April 29. 1998, system engineers
{
l
measured the air flow of LCC B-B and noted an improvement of about 60%
l
-in the air flow. After this successful evolution, the licensee took new
L
air flow measurements and recalculated t5ct a maximum allowed ERCW
temperature of 84.5 F would allow the LCC to perform within their design
i
basis. Based on the reevaluation, the TOE was closed on May 15, 1998.
The inspectors reviewed the licensee's calculations and field data and
concluded that the TOE closure was appropriate.
c.
Conclusions
System Engineering successfully developed and implemented an action plan-
to remove boron from the Unit I lower compartment coolers. This is a
positive finding.
_
E2.3 Steam Dumo Water Hammer Event Followino Plant Shutdown
a.
Insoection Scooe (37551)
The inspectors reviewed the Unit 1 steam dump water hammer event which
occurred several hours ~after the May 19. 1998, automatic reactor trip.
b.
Observations and Findinos
Following the Unit 1 reactor trip on May 19, the inspectors walked down
. the steam dump system to verify 3 roper operation._
Immediately following
the trip. the inspectors noted tlat the steam dump system was operating
as' designed.. Previous improper steam dump o)eration at the Sequoyah
~ ite had resulted in significant piping and langer damage and, as a
s
result, the. licensee had implemented several design changes to improve
operation'of the system.
On May 20, during the reactor startup, the inspectors noted a deficiency
tag on steam dump valve 1-FCV-1-111
When questioned about the
deficiency the control room operators noted that 1-FCV-1-111 was
isolated and would remain isolated due to damage from a water hammer
!
event. --The ins)ectors walked down the . steam dump system again and
'
observed that tie'line from steam dump valve 1-FCV-1-111 to the
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19
condenser was being supported with a chain fall.
One of the three
spring can supports had been broken.
Subsequent discussions with the licensee indicated that after the one
steam dump isolation discharge valve had been isolated for corrective
maintenance. the downstream discharge line filled with condensation from
the condenser. The licensee reported that due to a long horizontal run
of the line, as the line filled with condensation, steam trapped in the
line collapsed and caused a water hammer event.
In addition,
j
discussions with engineering indicated that the discharge of the
condensate booster pump recirculation line into the condenser
would/could cause rapid filling of this steam dump line and that this
was a known problem that had not yet been resolved.
'
In October 1996, water in the steam dump line on Unit 2 caused a
significant water hammer event that resulted in cracking of the main
steam supply piping from the main steam header to the steam Jump system.
Since the event, the licensee had implemented several modifications to
improve the operation of the steam dump system. However, based on the
water hammer event on May 19, 1998, the continuing problems with the
steam dump system are being identified as a weakness.
Following the water hammer event, the licensee inspected the steam dump
piping welds and did not identify any indications of pipe cracking based
on visual and magnetic particle inspections.
However. licensee
management decided that this steam dump line would remain manually
isolated until the next refueling outage. Although the licensee
conducted surface inspections of the piping welds, ultrasonic testing of
the welds could not be performed due to the high temperature of the
piping.
c.
Conclusions
A weakness was identified due to continuing steam dump system problems
,
which resulted in the May 19. 1998, water hammer event and piping
support damage.
E2.4 Unit 2 Steam Generator Looo Four (2-SG-4) Hydraulic Snubber Fluid Leak.
a.
Insoection Scoce (37551)
The inspectors observed onsite engineering response to the discovery of
a loss of SG snubber hydraulic fluid.
b.
Observations and Findinos
On April 29, 1997, during a weekly Unit 2 containment inspection, an AUO
observed that fluid could not be seen in the sight glass of the
reservoir servicing five Paul Munroe Snubbers for the Unit 2 number 4
Hydraulic fluid was immediately added to restore fluid
to normal and level was monitored to assess leak rate. A potential
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20
snubber operability concern, under TS 3/4.7.9 was recognized and
addressed on April 30, in TOE 2-98-068-0489.
The T0E concluded the snubbers would remain operable as long as fluid
level could be maintained in the reservoir and, based on the volume
required to refill the reservoir, sufficient fluid had been continuously
available to maintain uninterrupted snubber o)erability.
PER No.
SO980489PER was generated on May 4 to track t1e issue.
The licensee used a flexible neck fiber optics camera to identify the
L
'
leaking flexible hoses connecting the reservoir to the snubbers. Direct
personnel access to the area was not attempted due to high at-power
radiation levels.
' The licensee's ins)ections indicated that the leaking fluid had not come
into contact with lot piping which could have been a concern due to the
'
potential for production of hazardous decom)osition gases. The Material
. Safety Data Sheet and licensee-conducted la3 oratory tests confirmed that
lost lubricant posed a negligible fire loading risk.
The licensee
reported a long term corrective action plan to replace the present
clamp-type flex fittings with more reliable threaded fittings at the
next scheduled outage. subsequently installed a temporary drip
collection apparatus until permanent repairs can be effected.
'
c.
Conclusions
A positive finding was identified concerning engineering support of
' facilities and equipment when a licensee-identified steam generator
hydraulic snubber leak was properly assessed for operability and a
thorough corrective action plan was promptly implemented.
LE2.5 Inservice Testina Proaram Activities
a.
Insoection Scooe (37551 and 73756)
The. inspectors observed all or portions and reviewed documentation of
the following pump testing as required by the ASME Section XI IST
program as implemented through the technical specifications and 10 CFR 50.55a(f).
. -
1-SI-SXP-063-201.B." Safety Injection Pump B-B Performance Test".
-
2-SI-SXP-072-201.A," Containment Spray Pump 2A-A Performance Test".
,
,
b.
Observations and Findinas
Tests
- The inspectors observed the quarterly test on Containment Spray Pump 2A-
A and Safety Injection Pump B-B and reviewed the test procedures for
these pumps. Calibrated test instrumentation for flow and pressure
,
-measurements met code requirements for accuracy and range.
Vibration
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21
data were collected from pre-identified points on the equipment.
These
data were verified to be in the acceptance range and stored for later
analysis by engineering. The test parameters of flow, pressure and
vibration data met the ASME code acceptance criteria.
The tests were
successful and performed in accordance with the test procedure.
Trendina
The inspectors reviewed the trending plots for certain pumps in the
auxiliary feedwater, safety injection. containment spray anc emergency
raw cooling water systems.
Data indicated that the pumps met the
frequency requirements and acceptance criteria for differential pressure
and vibration over the last 12 months.
Sequoyah is in the early stages of improving their ability to analyze,
track and trend IST data with the acquisition of a new software system.
The new software program has the capability of retrieving for each
component in the IST program specific test, design and maintenance
information.
The inspectors considered the new analysis tracking and trending
capabilities a positive addition to the IST program.
c.
Conclusions
Observation of pump tests, review of pump test procedures, and review of
pump parameter trend data indicated that the licensee has established
and implemented an adequate pump IST program.
The ins)ectors noted that
the limiting values for pump acceptance criteria were Jased on the most
conservative of the technical specification, design basis, or code
calculated values. Additionally, the acquisition of a new software
program for analysis, tracking and trending IST data was considered a
positive addition to the IST program.
E2.6 Maintenance Procedures and Documentation
a.
Insoection Scone (73756)
The inspectors e iewed various aspects of the ASME Section XI IST
program as implemc ted through the technical specifications and 10 CFR 50.55a(f).
b.
Observations and Findinas
Scooe of the IST oroa am
The inspectors reviewed the Program Basis Document. Revision 5. plant
system drawings, and the design criteria documents for the auxiliary
feedwater safety injection, and component cooling water systems.
This
review was performed to verify that the appropriate components had been
included in the test program.
The inspectors did not identify any
components omitted from the test program in this review.
.
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Valves
The inspectors did not witness any valve testing but did review test
procedures frequency of testing and implementation of the test
schedule.
The following procedures were reviewed:
0-SI-SXV-003-266.0. ASME Section XI Valve Testing. Revision 3
I
2-SI-SXV-00-201.0. Full Stroking of Category "A" and "B" Valves During
Operation. Revision 0
2-SI-SXV-000-203.0. Full Stroking of Category "A" and "B" Valves During
Cold Shutdown. Revision 0
The test procedures were well written and easy to follow. Acceptance
criteria were included in each procedure. The procedures documented the
test results and were reviewed for any change in schedule by the IST
Lead Engineer.
For a selected set of valves the inspectors reviewed the
performance tracking records for two cycles and specific valve tests for
the last two quarterly tests.
The inspectors found that the licensee
had implemented.and controlled test frequency.
Sfroke Time Testina of CCS Outlet Isolation Valves on RHR Heat
Exchanaers
- Inspection Report 50-327, 328/98-03 documented inspector concerns
regarding the licensee's ASME Section XI testing of CCS valves.
URI 50-
327, 328/98-03-06 was o)ened to identify potentially inadequate valve
testing, specifically tie CCS outlet isolation valves on the RHR heat
exchangers. FCV-70-153 and FCV-70-156 for both units. The ASME
Inservice Valve Testing Program Basis Document. ) age 15. Stroke Time
Test.. states that: " power operated valves shall lave their stroke time
measured while traveling to the position (s) denoted in Appendix A.
Appendix A-ASME Inservice Valve Testing Tables, requires that Valves
- FCV-70-153 and FCV-70-156 only be stroke timed tested in the open
direction. This position is the automatic response direction or initial
response direction for MOVs.
MOVs are not stroke timed in both
directions of travel." The licensee does exercise valves FCV-70-153 and
FCV-70-156 in both directions, but only times them in the open
'
direction.
Subsequent to the initial inspection. the ins)ectors, after further
- review, concluded that Valves FCV-70-153 and ~CV-70-156 have functions
which could require them to be stroked in either direction during
accident conditions. As an example, following an accident, only one
train of RHR could be required to be inservice due to the alignment or
failures ~of CCS pumps.
Emergency Abnormal Procedure. EA-74-1. Placing
RHR Shutdown Cooling in Service, specifically refers to placing one
train of RHR in cooldown mode, which indicates that Valves FCV-70-153
and FCV-70-156 would have to be opened or closed to achieve the desired
-lineup.
Based on this review, the inspector determined that these
,
valves have both an open and closed function.
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23
Technical Specification 4.0.5. Inservice Testing Program, requires that
inservice testing of ASME code Class 1. 2. and 3 pumps and valves shall
be in accordance with Section XI of the ASME Boiler and Pressure Vessel
code and applicable Addenda as required by 10 CFR 50.55a. Codes and
Standards. Section (f). Inservice Testing Requirements.
identifies ASME/ ANSI OM-1987 edition of the code and Oma-1988 addenda as
the required codes. ASME/ ANSI OMa-1988 Addenda to ASME/ ANSI OM-1987.
Operation and Maintenance of Nuclear Power Plants. Part 10. Section
4.2.1.2. Exercising Requirements. Part (a) requires that valves shall be
.
tested to the position (s) required to fulfill its functions (s). The
failure to strole time test Valves FCV-70-153 and FCV-70-156 in both the
open and closed directions is identified as the first example of
,
'
violation. VIO 50-327, 328/98-06-04. Although this problem was
initially identified by the licensee, specific and comprehensive
corrective action to prevent recurrence had not been determined by the
licensee at the time the unresolved item (50-327, 328/98-03-06) was
identified ~ by the NRC.
Timeliness of Relief Reauests
The licensee's second 120 month IST Program interval started on December
15. 1995.
Prior to the interval start date, the licensee submitted
!
'
relief requests associated with the second 120 month program interval.
.Many of these requests for approval to perform alternative tests in
place of the code specified testing had been previously approved.in the
first 120 month IST 3rogram interval. .The NRC issued a Safety
Evaluation Report (SER) for-the second 120 month IST. program interval on
March 20. 1996.
In the SER relief requests RP-03. RV-05 and RV-06 to
perform alternative-tests were denied.
However, a 180-day delay was
granted on RP-03 for the licensee to. resubmit additional information.
Through an oversight, the licensee did not provide additional
'information for NRC review on RP-03 by September 20, 1996. The licensee
continued to conduct the alternate tests in RV-05 and RV-06 after. March
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20, 1996, and RP-03 after September 20, 1996, without NRC approval. The
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licensee subsequently resubmitted requests for relief for RP-03. RV-05
'
and RV-06 in letters dated December 22, 1997 and April 16. 1998.
The
staff is in the process of evaluating these submittals.
Technical Specification 4.0.5 requires that inservice testing of ASME.
,
Code Class 1, 2 and 3 pumas and valves shall be performed in accordance
i
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with Section XI of the ASiE Boiler and Pressure Vessel Code and
-
a)plicable addenda as required by 10 CFR 50. Section 50.55a. except
L
w1ere . specific written relief has been granted by the Commission.
10 CFR 50.55a. (a)(3) provides for alternative tests but requires NRC
approval prior to implementation.
Performing alternative tests without
. prior NRC approval is identified as the second example of violation. VIO
50-327.328/98-06-04.
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Relief Valve Procedure
During the review of Procedure 0-ST-SXV-000-264.0. Testing Setpoints of
Safety and Relief Valves (ASME Section XI Category C Valves). Revision
0. the test procedure for Class 2 and Class 3 pressure relief valves,
the inspector noted that the procedure did not contain a direction to
conduct a 10-minute hold time between valve openings. Technical specification 4.0.5 specifies that testing of ASME Code Class 1, 2. and
3 pumps and valves shall be performed in accordance with Section XI of
the ASME Boller and Pressure Vessel Code and applicable addenda as
required by 10 CFR 50.55a. Codes and Standards. Section (f). Inservice
Testing Requirements.
10 CFR 50.55a identifies ASME/ ANSI OM-1987
edition of the code and Oma-1988 addenda as the required codes.
ASME/ ANSI OM-1987 edition. Part 10 references Part 1 for relief valve
requirements.
Part 1. Paragra)hs 8.1.1.8. 8.1.2.8. and 8.1.3.7 require
a minimum 10 minute hold time 3etween valve openings.
Additionally
Paragraph 8.3.3(e) requires that the hold time be specified in a written
procedure.
Failure to s)ecify the minimum 10 minute' hold time in the test procedure
as required ]y the ASME code is identified as the third example of
violation. VIO 50-327.328/98-06-04.
c.
Conclusions
The inspectors concluded that the licensee has developed and implemented
an IST program which. in general. is consistent with the regulations and
the ASME Boiler and Pressure Vessel.Section XI code.
However, one
violation, with three examples, for failure to adecuately-im]lement
Section XI code testing requirements was identifiec during t1e
inspection.
E8
Miscellaneous Engineering Issues (92903)
E8.1
(Closed) URI 50-327. 328/98-03-06. Potential Inadeauate Section XI Valve
Stroke Testina. Section E2.6 of this report identified violation 50-327,
328/98-06-03 for inadequate Section XI valve stroke testing.
Based on
this violation, the unresolved item is considered to be closed.
E8.2 (Closed) IFI 50-327/97-18-06. Followuo on Concern with Two Year
Surveillance on Remote Position Indication Verification.
The issue of
performing the two-year remote position verification was reviewed during
the region based inspection of the ASME Section XI pump and valve
testing program.
Based on a review of the licensee's program and
discussions with regional and NRR inspectors. the inspector concluded
that the licensee was adequately implementing the Section XI requirement
for valve remote position indication verification.
E8.3 (Closed) VIO 50-328/98-01-01. Failure to Perform a 10 CFR 50.59
Evaluation for Chanaes Made to the 2A-A Motor Driven AFW Pumo.
The
j
licensee's response dated April 29. 1998. was considered acce] table.
The inspector reviewed procedure SPP-3.1. Corrective Action,
Revision 0.
{
)
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!
25
and verified that the corrective action program had been revised to
include the guidance of Generic Letter 91-18. Revision 1. concerning the
disposition of degraded and non-conforming items.
The inspector also
reviewed the following documents prepared and used in connection with
the replacement of Unit 2 MDAFW pump with a pump from Watts Bar:
Design Change Notice (DCN) T-12799A. Replacement of motor driven
.
Work Order (WO) No. 97-001409-000. Implement DCN T-12799A.
.
Replace 2-PMP-003-0118/2A MDAFWP with WBN MDAFWP. dated January
15. 1997.
Work Controlling Document No. 2-PI-SFT-003-727A. Motor driven AFW
.
pump 2A-A full flow test, dated November 2. 1997
Work Controlling Document No. 2-SI-SXP-003-201A. Motor driven AFW
.
pump 2A-A performance test. Revision 2.
Based on review of the above documents the inspector verified that MDAFW
pump 2A-A was replaced with a pump from Watts Bar Nuclear Facility.
The
replacement pump had both performance and full flow tests performed and
satisfactorily met all acceptance criteria.
The replacement pump was
declared operable and returned to the operations staff on October 30,
1997.
This item is closed based on objective evidence reviewed.
E8.4
(Closed) VIO 50-327.328/97-03-08. Untimely Corrective Action for Non-
conformina Pl?nt 'ondi ti ons .
The licensee's response dated June ll.
1997, was considered acceptable.
The ins)ector reviewed the corrective
actions completed in connection with PER
10.
SO940040II. TROI Sequence
item 36.
Based on this review the inspector verified that 14
essentially mild calculations had been revised by design change notices
(DCNs) M-08779 and M-08780 to specify accident radiation doses based on
i
a source term of 1000 effective full power day (EFPD) average core
i
exposure.
The calculations were also revised to delete references to
environmental drawings and added references to Design Criteria Document
No. SON-DC-V-21.0.
One hundred and fourteen E0 binders were also
revised to address the environmental parameters in design criteria SON-
DC-V-21.0.
The inspector reviewed the revision log of 12 randomly
selected E0 binders and verified that they had been revised to delete
references to environmental drawings and to include accident radiation
doses based on 1000 EFPD average core exposure.
This item is closed
based on objective evidence reviewed.
E8.5 (Closed) VIO 50-327.328/97-03-09. Inadeouate J)esian Control for Non-
conformina Plant Conditions.
The licensee's response dated August 20,
1997, was considered acceptable.
The inspector reviewed design basis
!
calculation TI-RPS-48. Integrated Accident Doses Inside of Primary
Containment. Revision 6. and verified that the maximum 100-day
integrated doses inside the containment and annulus were based on an
average core exposure of 1000 EFPD with 5% U-235 enrichment.
The
maximum 100-day integrated doses inside containment and the annulus were
_ _ _ - _ - - _ _
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26
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calculated to be 3.157 E+7 rads beta and 6.83 E+6 rads gamma.
l
Additionally, the 100-day free field beta dose doses were determined to
be 6.311 E+8 rads and 1.009 E+6 rads for the containment and annulus
respectively. The inspector reviewed design criteria SON-DC-V-21.0.
Environmental Design, and verified that 'it had been revised to
incorporate thel 100 day integrated accident doses delineated in
,
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calculation TI-RPS-48. Revision 6.
L
UFSAR Section 15.1.7.1. Activities in the Core, states that the design
l
basis LOCA' source terms are based on an average core exposure of 1000
EFPD with an enrichment of 5% U-235.
The UFSAR also requires each
l
reload fuel evaluation to verify that the consequences of an accident
previously evaluated has not changed. The inspector concluded that with
issuance of the above design output documents and changes to the UFSAR
incorporated by Amendment 13 the licensee has established consistency
i
between the plants licensing basis and the design criteria used for 10
l
- CFR 50.49 environmental qualification of electrical equipment. This
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item is closed based on objective evidence reviewed.
E8.6 (Closed) IFT 50-327.328/98-01-05. Turbine Driven AFW Pumo Room Exhaust
'
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Fan E0. .The result of the SSEI concluded that flow rate of the DC
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exhaust fan for the turbine ~ driven AFW pump' room was reduced without a
'
formal revision to the calculation. The SSEI also determined that the
calculation did not address events such as station blackout (SB0) and
that the upper temperature of 120 degrees Fahrenheit was not used for
environmental qualification of the DC exhaust fan.
The inspector. reviewed design output documents and verified the
technical adequacy-of the calculated air flow rates for the following
conditions:
Air flow rate required to maintain normal maximum temperature of
104 degrees Fahrenheit.in the room with all three fans in
operation.
. .
Air flow required to maintain the LOCA maximum temperature of 110
degrees Fahrenheit in the room with the emergency A.C. and D.C.
exhaust fans in operation.
Air flow required to maintain the LOCA maximum temperature of 110
degrees Fahrenheit in the room with only the D.C. emergency
exhaust fan in operation during a loss of off-site power.
The following design output documents were reviewed:
Design Criteria SON-DC-V-21.0 Environmental Design. Table 1.
' Auxiliary Building. Elevation 669. TD Aux. feedwater pump room
U-1.
Calculation No. EPM-DLM01-030887. SON HVAC Verification Program :
- -
HVAC Cooling Load calculations: Aux. Bldg. TDAFW Pump Room, dated
June 2. 1987.
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27
Calculation No. SON-31C-D053-EPM-RG-060987 HVAC Equipment
a
Requirements Evaluation: TDAFW Pump Room, dated May 19. 1998.
Drawing CCD No. 1, 2-47W920-2. Mechanical Heating and Ventilating
.
and Air Conditioning. Revision 2.
The inspector verified that the heat loads documented in calculation
EPM-DLM01-030887 and which were used as design inputs for calculation
SON-31C-0053-EPM-RG-060987 were correct.
The total heat load at the
maximum temperature during a loss of off-site ]ower was documented in
calculation EPM-DLM01-030887 as 37636 BTUH.
T1e heat load used for
calculating the air flow required under this condition was 35.516 BTUH.
The reason given for this difference was that the D.C. fan motor heat
load of 2120 BTUH was subtracted from 37636 BTUH because the fan motor
was installed outside the room.
The installation details for the 0.5 HP
D.C. emergency exhaust fan was verified from drawing number 1,2-47W920-
2.
The inspector determined that the heat load of 35516 BTUH used in
the calculation for determining flow rates with only the D.C. fan in
o]eration was justified.
Based on this review the inspector concluded
tlat the required flow rate of 1077 CFM determined by analysis was
correct.
The supplied flow rate of 1200 CFM provided a 10% margin which
ensured that the LOCA maximum temperature of 110 degrees Fahrenheit will
not be exceeded with only the D.C. emergency fan in operation during a
loss of offsite power. This item is closed based on objective evidence
reviewed.
E8.7 (Closed)IFI 50-327.328/98-01-06. Terry Turbine Governor Minimum Voltaae
Requirements.
During the SSEI TVA 3rovided documentation which
supported the licensee's position tlat the required minimum terminal
voltage of 100 Volts D.C. at the terminals of the Woodward governor was
acce] table. WA had no documentation, however, from the governor vendor
whic1 corroborated the minimum voltage requirements identified by the
turbine vendor.
The inspector reviewed the following documents in
connection with resolution of this item:
Calculation No. SON-VD-VDC-001. 125 Volts D.C. Instrument Power
.
System. Appendix 11. dated January 1. 1998.
Drawing CCD No.1-45W646- 6. Wiring Diagrams Feedwater Pump
.
Turbines Schematic Diagrams. Revision 2.
Facsimile from Woodward Governor Co. to TVA dated May 12. 1998.
.
Subject: EGM Power Supply.
The governor vendor in the referenced facsimile stated that test data
demonstrated that a 20% variation in input voltage to the power resistor
assembly, i.e.
120 VDC to 95 VDC. resulted in a 6% variation of input
voltage to the EG-M control box.
The vendor verified that the
controlling minimum voltage requirement was the input to the EG-M
control box. The vendor also stated that at minimum voltage to the
power resistor assembly, the minimum voltage to the EG-M control box.
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terminals 1 and 2. must be 42 VDC in order to conservatively assure
reliable operation.
Based on review of design-basis calculation SON-VD-VDC-001. Appendix M.
the inspector determined that the worst case calculated voltage to the
EG-M control. box was 102.96 Volts with a minimum voltage of 103 Volts to
o
the power resistor assembly. .This value of-103 Volts was calculated at
the end of the.125 VDC battery 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> duty cycle when the battery
terminal. voltage was 104.4 Volts. The inspector concluded that a
minimum voltage of 100 Volts to the EG-M control box was acceptable
based on the vendors test data which. bounded the worst case calculated
voltage of 102.96 volts. This item is closed based on review of
objective' evidence.
IV. Plant Sucoort
R8
. Miscellaneous RP&C Issues (92904)
- R8.1- (Closed) VIO 50-328/97-18-07: Personnel Monitorina Discrepancies: Two
examples of not pro)erly frisking out of a posted radiologically
controlled area. T1e inspector reviewed the corrective actions
described in the licensee's response letter. dated March 13. 1998, to be
reasonable and complete.
No similar problems were identified.
S1
Conduct of Security and Safeguards Activities
..
a.
'Insoection Scooe (81700. 92904)
The purpose of the inspection was to determine whether the conduct of
. security and safeguards activities met the licensee's commitments in the
NRC-approved security plan (the Plan) and NRC regulatory requirements.
The security program was inspected during the period of April 27 to May
1. 1998.
Areas inspected. included the access authorization program,
alarm stations and communications, and protected area access control of
personnel and hand-carried packages
b .-
Observations and Findinas
Access Authorization (AA) Proaram-
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The inspector reviewed implementation of the AA program to verify
implementation was in accordance with applicable regulatory requirements
,
.and Plan commitments. The review included an evaluation of the
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' effectiveness of the AA procedures, as implemented.'and an examination
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of AA records for 46 individuals.
Records reviewed included both
persons who had been granted and had been denied access. The AA
program, as, implemented, provided assurance that Jersons granted
unescorted access did not constitute an unreasonable risk to the health
and safety of the'public. Additionally, the inspector verified by
reviewing access denial records that appropriate actions to remove
individuals' access were taken when individuals were denied access or
access was terminated.
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Alarm Stations-
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The inspectL caserved operations of the Central Alarm Station and the
Secondary Alarm Station and verified that the alarm stations were
equi) ped with appropriate alarms, surveillance and communications
capa)ilities.
Interviews with the alarm station operators found them
knowledgeable of their duties and responsibilities. The inspector also
verified, through observations and interviews, that the alarm stations
were continuously manned, independent, and diverse so that no single act
could remove the plant's capability for detecting a threat and calling
L
for assistance, and the alarm stations did not contain any operational
'
activities that could interfere with the execution of the detection,
assessment, and response functions. . The inspector closed violation
97-07-01, concerning failure to take required compensatory ~ action during
a security system failure. The NRC did not require a response to the
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violation because the' corrective actions taken and )lanned to correct
.the violation and prevent recurrence and the date w1en full compliance
i.
was achieved was already adequately addressed on the' docket in IR 50-
i
327. 328/97-07, dated July 24. 1997.
L
Communications
The inspector verified. by document reviews and discussions with alarm
station operators, that the alarm . stations were ca)able of. maintaining
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continuous intercommunications. communications wit1 each security force
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member (SFM) on duty, and were exercising communication methods with the
'
local law enforcement agencies as committed to in the Plan.
Protected Area (PA) Access Control of' Personnel and Hand-Carried
Packaaes
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L On April 29 and 30,1998, the inspector observed personnel and package
'
search activities at the personnel _ access portal. The inspector
determined.:by. observations. -that positive controls were in place to
ensure only authorized individuals were granted access to the PA and
- that all personnel and hand-carried items entering the PA were )roperly
searched. ~However, the' inspector determined during review of tie
l
Security Event Logs (SELs) that on May 8. October 22.. December 11, 1997.
and March 27. 1998. individuals had gained access to the PA without
,
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utilizing the badge and hand-geometry system at the vehicle sally port.
The four individuals were licensee employees-who were authorized
unescorted access.
Based on the SEL dated May. 8.1997. the officer at
the ' sally port failed to ensure that the individual entering the PA used
the card reader and hand-geometry.
The-licensee determined that'the
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event was caused by personal error and a warning letter was placed in
the individual's file. - On October 22. 1997, another officer at the
sally. port failed to ensure that the individual entering the PA used the
card reader and hand-geometry. The licensee stated that as corrective
L.
action. "the card reader was relocated to_ provide the officers with a '
better view of.the card reader and hand geometry to ensure that this
type event did not reoccur." Additionally, they stated that they
retrained the officers and took disciplinary action against the
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individual.
However, the licensee was unable to provide the inspector
with any documentation to validate these statements.
On December 11.
1997, a third event occurred at the sally port when a security officer
failed to assure that an individual entering the PA used the card and
hand-geometry reader to gain access.
The officer was counseled and no
further action was taken.
On March 27. 1998, the fourth event of an
officer failing to control access via the card reader and hand-geometry
reader at the sally port occurred. The corrective action for the event
was closed with the statement that "the officer no longer was employed
by the Tennessee Valley Authority (TVA)."
The inspector identified that the initial corrective actions had failed
to be effective in that the same type events were continuing to occur.
Based on the inspectors findings the events do not meet the criteria of
NUREG-1600. VII B.1 to be classified as a Non-Cited Violation. Security
management stated that they had viewed the events as single occurrences
over a year period and had not noted that there was a continuing trend
of failing to control access at the sally port. After senior management
became aware of the events. immediate and thorough corrective action was
implemented. The corrective action as of May 1. 1998 was:
.
I
-
To write a problem evaluation report (PER) (S0980501)
-
To require the security officer at the sally port to physically
take the badge and swi)e it through the card reader and then
watch the person use tie hand-geometry
-
To issue temporary orders to the sally port officers limiting
the number of vehicles in the sally port to one
-
To dispatch supervision to the sally port to verify that the new
post orders and officer actions were acceptable and to discuss
the new requirements with the officer on post
-
To ensure that all TVA and contractor supervision understand the
problem, and the immediate corrective action
-
To brief the event at the plan of the day meeting
-
To issue a site bulletin on changes that were made at the sally
port
,
-
To require senior management to review all security event
reports for trending and analysis
-
To present selected security PERs to the Management Review
Committee for their consideration
,
Additionally, the licensee is continuing to review the event and are
.
considering additional corrective actions.
l
_ _ _ _ _ _ _ - _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _
__
31
Paragraph 5.2.4. Revision 4. dated September 10. 1996, states.
" Verification of each individual will be with the hand geometry system
which provides a nontransferable means of identifying individuals,
coupled with the badgecard reader.
Both the badgecard and hand geometry
shall be necessary for normal access to the PA.
Hand geometry shall
provide assurance that only authorized personnel are allowed access to
the PA."
Physical Security Instruction - 32. Revision 16. Appendix N. Post 12.
and 13 - Vehicle Search / Access Control, paragraph 3.6. states. " Ensure
individuals with PA badges utilize the hand geometry readers."
On May 8. October 22. December 11. 1997, and March 27. 1998, an
individual did not utilize the badge and hand-geometry system prior to
entering the PA at the vehicle sally port.
The four individuals were
licensee employees who were authorized unescorted access.
The failure to
properly control access at a sally port constitutes a violation (50-327,
328/98-06-05).
c. Conclusions
The licensee was conducting its security and safeguards activities in a
{
manner that protected public health and safety and this portion of the
'
program, as implemented. met the licensee's commitments and NRC
requirements.
i
A violation was identified for failure to properly control access at the
sally port on four different occasions.
S2
Status of Security Facilities and Equipment
a.
Insoection Scooe (81700)
Areas inspected were:
Testing, maintenance and compensatory measures. PA
detection aids, and PA assessment aids.
b. Observations and Findinas
Testina. Maintenance and Compensatory Measures
The inspector reviewed testing and maintenance records for security-
related equipment and found that documentation was on file to demonstrate
that the licensee was maintaining. and with the exception of the PA
intrusion detection system,
testing systems and equipment as committed
to in the Plan. A priority status was being assigned to each work
request and repairs were normally being completed within the same day a
work request necessitating compensatory measures was generated.
The
inspector reviewed SEls and maintenance work recuests which were
generated over the last year.
These records incicated that the need for
compensatory measures was minimal.
When necessary, the licensee
,
1mplemented compensatory measures that did not reduce the effectiveness
!
E_________
_ _ _ _ _ _
_ __
_ - . . . _ _ _
_
_j
_- _
-___ __ __ - ___ _ _ _ _ _ _ - _ _ _ __
i
32
of the security; system as it existed prior to the need for the
I
compensatory measure.
Assessment Aids
'On April 29, 1998.~ the inspector evaluated the effectiveness of the
assessment aids. by observing on closed circuit television.'a SFM
conducting a walkdown of the PA. The assessment aids had good picture
- quality and excellent zone overlap. Additionally, to ensure Plan-
-commitments were satisfied, the licensee had procedures in place
requiring the implementation of compensatory measures in the event'the
alarm station operator was unable to properly assess the cause. of an
alarm.
PA Detection Aids
'On April 29. 1998, the inspector observed testing of five of the
~ intrusion detection systems in the plant PA. The zones tested were
capable of. detecting. attempts to pass'a sphere under (to simulate
crawling) and over (to simulate-jumping) the intrusion detection system
1(microwave).
The inspector' observed four. attempts by an-individual to
l
pass through the E-Field. The inspector..while reviewing the seven day
)eriodic instruction (PI) PI-SS0S-000-630.W. "Seven Day Functional Test
or Non-Card readers: Alarms and Closed Circuit Televisions'.' Revision 4.
'
. dated November ~7. 1996, and the annual testing procedure (" Post
Maintenance Testing No. 92.~ Revision 0). determined that the licensee
l
had established procedures to test the security equipment.
However. as
part.of the testing procedure, the licensee had not established a
consistent testing method and the number of. tests.to be conducted for
each system.
Therefore, the security equipment may not function to the
licensee's expectations. During discussion with-the licensee concerning
their testing measure they also had concluded that a method and standard
needed to be established to ensure the security detection equipment
operated to the ex)ectations. The licensee had scheduled a meeting on
May 6. 1998, for.tle three TVA nuclear facilities to develop an equipment
testing-method.
Upon detection of equipment failures, the licensee
implements immediate corrective actions which included the establishment
of compensatory measures and submission of a work order to the I&C
3
Department. The inspector determined, by observations and by reviewing
'
the testing documentation associated with the equipment repairs. that the
repairs were made in a timely manner and that the equipment was
. functional and-effective, and. met the requirements of the Plan,
c. Conclusions
j
-The -licensee *s security- facilities and equipment were determined to be
very well-maintained and reliable even though a test procedure for-
L
standardized testing of the intrusion detection equipment had not been
9
. developed.
4
'
Y
._ -
_
_.
. _ - -
_ _ - _ _ _ _ _ _ _
_ _ _ - _ _ _ - _ _ - _ _ _ _ _ _ _ _ _ _____
33
The excellent Engineering and I&C su) port was the major contributing
factor to continued operability.of t1e detection and assessment
equipment.
- S4_ Security and Safeguards Staff Knowledge and Performance
a.
Insoection Scooe (81700)
. Areas inspected were security staff requisite knowledge and response
capabilities.
b. Observations and Findinas
Security Force Recuisite Knowledae
The inspector observed a number of SFMs in the performance of their
routine duties
These. observations included alarm station operations,
i
personnel and package. searches. and visitor processing. Additionally.
the ' inspector interviewed SFMs and security management.
Based on all of
the above activities. it was determined that the SFMs were knowledgeable
of their responsibilities and duties, and could effectively carry out
their. assignments.
Resoonse' Capabilities
l
On April 29, 1998, the inspector conducted a review of the documentation
i
of: drills for May 20. June 1. July 29-30. August 6. 7 & 9. Se)tember 23- ,
October 1 & 2. 1997, and April'8 & 10. 1998.
Additionally, tie lnspector
reviewed the table-top time line drills conducted September 12 & 28.
November 1, 2 & 24, December 7 & 10. 1997, and January 3. 11 &.17, 1998.
The drills were developed by using the target sets developed and refined
by the licensee and the Operational Safeguards Response Evaluation.
The
benchmark _for the drills was the NRC design basis threat. The criteria
used by the licensee to determine response capability were:
(1) can the
isecurity force provide a sufficient number of. responders, (2) are they
. appropriately armed, (3) are they in protected fighting positions. and-
(4) will they be.in time to interdict armed intruders. The inspector, by
)
review of the licensee's drills and discussions with security personnel,
1
determined that the licensee's ability to defend against the design basis
threat is adequate.
c. Conclusions
The SFMs adequately demonstrated that they have the requisite knowledge
necessary to effectively implement the duties and responsibilities
-associated with their day-to-day and contingency response positions.
!
-
__ _ _ __
_ - - _ - _ _ _ - - _ - _ _ _ _ _ - _ _ - - - - _ _ _
_ - _ _ _
34
V. Manaaement Meetinas
X1- Exit Meeting Summary
The inspectors ] resented the inspection results to members of licensee
management at tie conclusion of the inspection on June 12. 1998, and on
May 1. May 15. June 4 and June 5.1998 (for regional based inspections).
The' licensee acknowledged the findings presented.
An inspectors' exit was held on May 22. 1998, and was not held with the
Residents closure exit. The licensee stated that they believed the
- failure to test MOVs in both d;rectirs was licensee identified and met
the criteria;for a non-cited-7 olaticn. The inspectors stated that this
would be considered lit the Regics Management review.- A re-exit was held
by conference call on. June 4. 1998. At which time the examples failure
to test valve a in both directions when the valve had a safety function
' n both directions was discussed, the failure to meet 10 CFR 50.55a in
i
the timeliness of relief request submittal.s. and the failure to meet the
code requirements to include the hold. time between valve openings in test
procedures were identified as a violation. The-licensee restated his
position regarding the licensee-identified failure to test in both
directions when valve functions required both directions.
i
During the inspection period, the inspectors asked the licensee whether
..I
any materials would be considered proprietary.
No proprietary
information was > identified.
PARTIAL LIST OF PERSONS CONTACTED
Licensee
!
- Bajestani. M., Site Vice President
Burton. .C. . Engineering and Support -Systems Manager
Butterworth. H., Operations-Manager
- Gates. J.. Site Support Manager
- Freeman. E., Maintenance and Modifications Manager
L
-*Herron. J.. Plant Manager
.
i
Kent. C.. Radcon/ Chemistry Manager
!
Koehl. D. , Assistant Plant Manager
O'Brien. B., Maintenance Manager
.
Salas. P.... Manager of Licensing and Industry Affairs
L
Valente. J., Engineering & Materials Manager
l
- Attended exit interview
INSPECTION PROCEDURES USED
- IP 37551
Onsite Engineering
IP 50002:
-IP< 61726':
Surveillance Observations
IP 62700:
Maintenance
IP 62707:
Maintenance Observations
_ _ ___ _ _ __ _ _ _
35
IP 71707:
Plant Operations
IP 73756:
Inservice Testing
IP 81700:
Physical Security Program for Power Reactors
IP 92901:
Followup - Operations
i
IP 92902:
Followup - Maintenance
IP 92903:
Followup - Engineering
IP 92904:
Followup - Plant Support
ITEMS OPENED. CLOSED. AND DISCUSSED
Opened
Tvoe
,11pm Number
Status
Description and Reference
50-327/98-06-01
Cpen
Potential Deficiencies: in
Maintenance and Inspection
Procedures Which Resulted In
Ice Condenser Ice Basket
Damage and Did Not Promptly
Identify the Damage (Section
M2.1).
50-327/98-06-02
Open
Potential Improper Corrective
Maintenance Activities Related
to Improper Breaker Contact
Compression Setting and
Inadequate Post Maintenance
Testing (Section M2.3).
50-327, 328/98-06-03
Open
Failure to Perform an Adequate
Safety Evaluation Prior to
Making Modifications to the
Waste Gas Analyzer System
(Section E2.1).
50-327. 328/98-06-04
Open
Failure to Adequately
Implement Section XI Code
Testing Requirements (Three
Examples) (Section E2.6).
50-327. 328/98-06-05
Open
Failure to Implement Adequate
Access Controls at the Vehicle
Sally Port (Section S1).
Closed
11D.g
Item Number
Status
Description an(! Reference
50-327. 328/98-03-03
Closed
Potential Failure to Meet
UFSAR Requirements. Failure to
Revise UFSAR. Inappropriately
Closing a Modification
_ _ _ - - _ _ _ _ _ _ _ .
,
36
Package and Not Establishing
i
a Periodic Sampling Program
for the Waste Gas Collection
System (Section 08.1).
50-327/98-03-01
Closed
Potential Failure to Enter TS 3.11.2.5 LCO Action Statement
When Samples Indicated High
Concentrations of Oxygen in
the PRT (Section 08.2).
LER
50-327/97013. Rev. 1
Closed
Missed Surveillance as a
Result of an Inadequate
Procedure (Section M8.1).
IFI
50-327/98-03-04
Closed
Follow Licensee's Review of
the Section XI Valve Testing
Procedure to Determine if a
Better Method Would Be
Available to lest the CCS Pump
Discharge Check Valves
(Section M8.2).
50-327. 328/98-03-06
Closed
Potential Inadequate Section
XI Valve Stroke Testing
(Section E8.1).
IFI
50-327/97-18-06
Closed
Followup on Concern with Two
Year Surveillance on Remote
Position Indication
Verification (Section E8.2).
50-328/98-01-01
Closed
failure to Perform a 10 CFR 50.59 Evaluation for Changes
Made to the 2A-a Motor Driven
AFW Pump (Section E8.3).
50-327, 328/97-03-08
Closed
Untimely Corrective Action for
Non-conforming Plant
Conditions (Section E8.4).
50-327. 328/97-03-09
Closed
Inadequate Design Control for
Non-conforming Plant
Conditions (Section E8.5).
IFI
50-327, 328/98-01-05
Closed
Turbine Driven AFW Pump Room
Exhaust Fan E0 (Section E8.6).
IFI
50-327. 328/98-01-06
Closed
Terry Turbine Governor Minimum
Voltage Requirements (Section
E8.7).
- _ _ _ _
_ - _ - _ _ _ _ _ _
. _ _ -
37
50-328/97-18-07
Closed
Personnel Monitoring
Discrepancies (Section R8.1).
50-327, 328/97-07-01
Closed
Failure to take required
compensatory action during a
security system failure
(Section S1).
LIST OF ACRONYMS USED
Access Authorization
-
AFW -
APC -
Alternate Plugging Criteria
ASME -
American Society of Mechanical Engineers
AUD -
Assistant Unit Operator
CCS -
Component Cooling System
CFR -
Code of Federal Regulations
CRCM -
Control Rod Drive Mechanism
CVCS -
Chemistry and Volume Control System
DCN -
Design Change Notice
EC
-
Eddy Current
EDG -
EFPD -
Effective Full Power Days
-
Environmentally Qualified
ERCW -
Essential Raw Cooling Water
FCV -
Flow Control Valve
GL
-
Generic Letter
HUT -
Holdup Tank
HVAC -
Heating Ventilation and Air Conditioning
I&C -
Instrumentation and Control
IFI -
Inspector Followup Item
IR . -
Inspection Report
ISI -
In-Service Inspection
)
l
LCC -
Lower Compartment Cooler
l
LER
-
Licensee Event Report
.
LOCA -
Loss of Cooling Accident
MCC -
Motor Control Center
i
i
MDAFW . Motor Driven Auxiliary Feedwater
!
' MFW -
Main Feedwater
'
NRC -
Nuclear Regulatory Commission
NRR -
Nuclear Reactor Regulation
-
Protected Area
PER -
Problem Evaluation Report
Periodic Instruction
)
-
-
Predictive Maintenance
-
Preventative Maintenance
PMT -
PORV -
Power Operated Relief Valve
PRT -
Pressurizer Relief Tank
PWSCC-
Primary Water Stress Corrosion Cracking
RCS -
_ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _
_ -
_
_
~
, - _- _ - __ _
38
RHR -
Residual Heat Removal System
SEL -
Security Event Log
SFM -
Security Force Member
-
-
Surveillance Instruction
SRST -
Spent Resin Storage Tank
SSEI -
Safety System Engineering Inspection
TDAFW-
Turbine Driven Auxiliary Feedwater Pump
TOE -
Technical Operability Evaluation
TROI -
Tracking and Reporting of Open Items
TS
-
Technical Specifications
TSIR -
Technical Sup) ort Investigation Request
TSP -
Tube Support ) late
TTS -
Top of tubesheet
TVA -
Tennessee Valley Authority
TVAN -
Tennessee Valley Authority Nuclear
UFSAR - Updated Final Safety Analysis Report
URI -
Unresolved Item
-
Ultrasonic Testing
i
Vac -
Voltage Alternating Current
VCT -
Volume Control Tank
Vdc -
Voltage Direct Current
!
VIO -
Violation
-
Work Order
WOG -
Westinghouse Dwners Group
,
-
Work Request
l
)
l
l
!
l
_ _ _ _ _ _ _ _ _ _ _ _ _ _ .
_ _ _ _ _ _
,