ML20141C988
| ML20141C988 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 05/12/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20141C976 | List: |
| References | |
| 50-327-97-03, 50-327-97-3, 50-328-97-03, 50-328-97-3, NUDOCS 9705190292 | |
| Download: ML20141C988 (39) | |
See also: IR 05000327/1997003
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION II
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Docket Nos: 50 327, 50 328 *
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Report No: 50-327/97 03, 50 328/97-03
Licensee: Tennessee Valley Authority (TVA) *
Facility: Sequoyah Nuclear Plant Units 1 & 2
Location: Sequoyah Access Road .
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Hamilton County, TN 37379
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Dates: March 2 through April 12, 1997
Inspectors: M. C. Shannon, Senior Resident Inspector
D. A. Seymour, Resident Inspector
R. D. Starkey, Resident Inspector
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W. H. Hiller, Jr., Reactor Inspector (Section F) :
C. W. Rapp, Reactor Inspector (Section E8.6)
C. F. Smith, Reactor Inspector (Sections E2.2 and E8.1 4).
E. D. Testa, Reactor Inspector (Sections P and R)
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Approved by: H. S. Lesser, Chief
Projects Branch 6
Division of Reactor Projects ;
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Enclosure 2
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9705190292 970512
PDR ADOCK 05000327
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EXECUTIVE SUMMARY
Sequoyah Nuclear Plant, Units 1 & 2
NRC Inspection Report 50 327/97 03, 50 328/97 03 4
This integrated inspection included aspects of licensee operations,
maintenance, engineering, plant support, and effectiveness of licensee
controls in identifying, resolving, and preventing problems. The report
covers a six week period of resident inspection. In addition, it includes the
results of announced inspections by engineering and maintenance inspectors.
Q2erations
e The licensee had taken appropriate corrective action for the erratic
steam generator level controller (Section 02.1).
e The hydrogen recombiners and analyzers were operable and were being
properly tested and maintained by the licensee (Section 02.2). ,
e A violation was identified for failure to follow a procedure, which
resulted in a spent fuel pit (SFP) cooling system (SFPCS) misalignment
event. A positive observation was noted for operators promptly
identifying the misaligned SFPCS and the increase in SFP temperature.
However corrective action did not address the inoperable SFPCS flow
. instrument, procedures for positive verification of SFPCS flow,
instrument labeling, or use of unapproved operator aids (Section 02.3).
Maintenance
e A weakness was identified in the area of maintenance / work planning for
not promptly repairing an inoperable spent fuel pool cooling flow ;
indicator and not prominently displaying a work request tag on a
defective flow irstrument (Section 02.3).
e One violation was identified for failure to follow the requirements of a i
work order (W0) which subsequently resulted in an ESF actuation. Poor
work practices caused a loss of power to a shutdown bus on two
occasions. Planning, use of hold orders, voltage verification, crew
turnovers were ineffective in preventing the problems. (Section H2.1) ,
e One strength was identified for the thoroughness and timeliness with
which the licensee conducted its investigation of the ESF actuation
event (Section H2.1).
-e A non cited violation was identified for failure to perform adequate
post maintenance testing of a 6.9 kilovolt breaker (#1614) following
2. vendor refurbishment / maintenance / repair at the vendor's facility
(Section H2.2).
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) e A violation was identified for the failure to adequately test the
reactor trip breaker P 4 function (Section M8.2).
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e Not fully implementing / integrating the Westinghouse recommendations into ,
appropriate plant procedures was identified as a weakness (Section
M8.3).
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Enaineerina
e A weakness was identified for the failure to fully implement / integrate
the recommendations of the 1979 and 1987 Westinghouse letters regarding
i reactor trip breaker testing into appropriate plant procedures (Section
M8.3).
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e A violation was identified for failure to adequately respond to concerns
with both TDAFW sump pumps running continuously prior to the pumps
- becoming damaged / degraded and recurring sump level alarms (Section
E2.1).
e ' A violation was identified for failure to perform a thorough evaluation
, prior to disabling the TDAFW pump condensate high level alarm, resulting
in the plant being in a potentially unanalyzed condition (Section E2.1).
e The main steam dump drain system modification was technically adequate
and had been prepared in accordance with the requirements of the design
control program. The design objectives were consistent with the
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independent evaluation team's recommendation with the exceptions noted
(Section E2.2).
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e Two violations were identified for untimely corrective action to update i
environmental qualification (EQ) binders. Corrective action of updating :
the EQ binders to incorporate 100 day integrated accident dose inside
the containment and the annulus was not completed at the time of the l
inspection. Information transmitted from site engineering to Document i
Control and Records Management (DCRM). for updating the EQ binders were i
rejected because of administrative errors. Site engineering management
was not aware of this rejection until it was brought to their attention
by the inspector (Section E8.2).
e Technical reviews of material to be incorporated in the EQ binders
demonstrated that environmentally qualified equipment had maintained
their environmental qualification with an average core exposure of 1000
Effective Full Power Day (EFPD). Additionally, the licensee's
application of the free field beta dose reduction of 50% was verified to
be in accordance with the guidelines provided by NRR (Section E8.3).
Plant Support
e Radiological facility conditions and housekeeping in radioactive waste
storage areas were observed to be good, material was labeled
appropriately, and areas were properly posted (Section R1.2),
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- o Personnel dosimetry devises were appropriately worn (Section RI.2).
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e Radiation work activities were ap3ropriately planned, radiation worker
doses were being maintained well >elow regulatory limits and the
licensee was continuing to maintain exposures as low as reasonably
achievable'(Section RI.2).
- Contamination control was effective (Section R1.2).
e The licensee had effectively implemented procedures to track the
availability of radiation monitors and to demonstrate operability of
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area and effluent radiation monitors (Section R2.1).
e The monitors used for 10 CFR 70.24 compliance were operational, within
the required calibration frequency and detection requirements of
10 CFR 70.24 were met (Section R2.1).
e A non cited violation was identified as a result of the Office of
Investigation Case No. 2-96 015 and the inspector's independent
assessment of the closure of Unresolved Item 50 327, 50 328/96 04 12
(Section R8).
e The licensee effectively implemented a program to inform the local
population and transient population of actions to take in the event of a ,
plant emergency (Section Pl.1). ;
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- Installation and hydrostatic testing for the modifications to the high
pressure fire protection water system were being performed in accordance
with the licensee's design documents (Section F1.1).
e The-licensee had implemented a program that was effective in the
reduction of inoperable or degraded fire protection components and open
fire protection related maintenance work requests (Section F2.1).
e The material condition of the fire protection components was good which
indicated that approariate emphases was being placed on the maintenance l
and operability of t1e fire protection components (Section F2.1). I
e An effective fire watch program had been implemented as the compensatory
action for degraded fire protection components which met the commitments
to the NRC (Section F3.1).
e The fire protection staff and fire brigade / emergency response teams were 1
well organized and met the requirements of the site procedures (Section j
F5.1). i
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e A thorough and comprehensive self assessment was made of the facility's
fire protection program. Appropriate corrective actions had been
initiated to resolve the identified issues in a timely manner (Section j
F7.1).
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e The plans to replace the kaowool fire barriers with fire barrier
materials which meet the required Appendix R fire resistance rating was
identified as a positive action (Section F8.1).
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Report Details
Summary of Plant Status
Unit 1 began the inspection period at approximately 87% power, and was
coasting down for the Unit 1 Cycle 8 (01C8) refueling outage, which started on ;
March 22, 1997. When the report period ended the unit was defueled. l
Unit 2 began the inspection period in power operation. The unit operated at
power for the duration of the inspection period.
I. Doerations
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01 Conduct of Operations
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01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent
reviews of ongoing plant operations. The inspectors observed portions
of the following outage related activities: reactor power reduction and !
shutdown, reactor coolant system (RCS) cooldown using steam dumps,
initiation and operation of the residual heat removal system for RCS
cooldown, draindown of the RCS to the reactor vessel flange, and offload ;
of fuel from the reactor. In general, the conduct of operations was ;
satisfactory. Specific operational events and findings are detailed in
the sections below.
01.2 Review of Updated Final Safety Analysis Report (UFSAR) Commitments
While performing insaections discussed in this report, the inspectors
- reviewed the applica]le 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.
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02 Operational Status of Facilities and Equipment
02.1 Reoair of Unit 2 Loop 1 Steam Generator Level Controller
a. Inspection Scope (71707)
The inspectors reviewed the licensee's corrective actions related to
. repair of the Unit 2 Loop 1 steam generator level controller.
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.,b. Observations and Findinas ,
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Since December 1996, Unit 2 has experienced several instances where the '
Loop 1 steam generator level has increased and then returned to program l
level. The occurrences were random and could not be attributed to any ;
other operational evolution. The licensee monitored the output of the
2 LC 3 42 level controller (loop 1. controller) and concluded that the '
output of the controller was.not appropriate for the input. Rather than i
replace the entire controller, the licensee elected to replace the :
controller's K 1 relay which was believed to be the most likely cause of '
the drifting. The K 1 relay replacement was accomplished on March 6, ;
1997, under work order (WO) 97 002594: however, within hours of the i
replacement, steam generator level drifted approximately 3% high before
returning to normal. The licensee subsequently field adjusted the .
controller and noticed an improvement in the response of the controller. :'
Since the controller appeared to be controlling more normally after the
field adjustment, the licensee then began to monitor the response of the ,
three other controllers. On April 6. 1997, the Loop 2 steam generator '
level experienced a level increase. On April 8. 1997, the licensee ;
replaced the K 1 relay and field adjusted the Loop 2 controller. The '
licensee continued to monitor the response of the Unit 2 steam generator ,
level controllers as the inspection period ended.
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c. Conclusions
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The inspectors concluded that the licensee had taken appropriate
. corrective action for the erratic steam generator level controller.
02.2 Hydroaen Recombiners and Hydroaen Analvzers
a. Inspection Scope
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The inspector reviewed the recent work history. the problem evaluation .
reports (PER), and the recent surveillances related to the hydrogen *
recombiners and analyzers. The inspector also walked down accessible !
. portions of each system on both units and discussed the system health I
reports with the designated system engineers. !
b. Observations and Findinas )
There are two hydrogen recombiners and two hydrogen analyzers for each
unit. The inspector determined by reviewing recent surveillances that
each of the four components on both units met their functional test
acceptance criteria. The most recent deficiencies associated with the ;
recombiners (Unit 1 only) have been defective thermocouples. These
thermocouples are provided for convenience in testing and periodic i
checkout of the'recombiners and are not necessary to assure proper '
operation of the recombiners. Pro wr recombiner operation after an l
accident is assured by measuring t1e amount of electric power to the !
recombiner. Technical Specifications (TS) require periodic surveillance
tests that monitor temperatures with the thermocouples. However, only ;
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two of the three thermocouples are required to be operable to determine
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The most recent deficiencies associated with the hydrogen analyzers were ,
related to E/I modules, which convert the voltage signal from the '
analyzer to a current signal to drive the indicator in the control room.
The problem was determined to be that the E/I module would not stay in
calibration. The licensee determined that the module probably failed
due to age. The vendor manual recommends a replacement of this
component every five years. Based on this recommendation, the licensee ;
is revising the PM program to include replacement of these modules at j
the recommended interval.
c. Conclusions
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The inspector concluded that the hydrogen recombiners and analyzers were ,
operable and are being properly tested and maintained by the licensee.
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02.3 Incorrect Alianment of Soent Fuel Pit (SFP) Coolina System (SFPCS) :
a. Inspection Scope (71707)
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The inspectors reviewed a SFPCS misalignment event which resulted in an
increase (2 *F) in SFP temperature. I
b. Observations and Findinas
On March 24, 1997, the licensee attempted to align the C S SFP pump to
the A SFP heat exchanger and to alace the C S SFP pump in service. The
C-S SFP pump is common to both tie A and .B train of SFP cooling and can '
be aligned to either train's heat exchanger. System Operating '
Instruction
Revision 53, (SOI)78.1,SpentFuelPitCoolantSystem,Section5.4,%
was used to accomalish the alignment. Approximately 2
hours after the C-S pump was t1ought to be in service, operators
discovered that the C S pump discharge valve to the "A" SFP heat
exchanger was not open due to a> parent binding of the valve and noted an i
approximate 2 *F increase in SF) temperature. The pump, which does not i
have a minimum flow line, was apparently dead headed for 2 1/2 hours. l
Operations deterr.ined that no damage was done to the pump during that i
time. Operators opened the valve to establish normal flow to the heat i
exchanger. The licensee wrote Work Request (WR) C351955 on the binding
valve and PER No. SQ970772PER on the event.
The inspector discussed the event with operations personnel and
determined that the assistant unit operator (AV0) who performed the C S
pump alignment believed that he had fully opened the pump discharge
valve based on the >osition of the valve stem. (The valve stem extends
approximately 6 incies when the valve is fully closed. The AVO did not
notice an unapproved operator aid on the valve handwheel which stated,
" Caution this valve stem will extend 6" when valve is fully closed").
He then attempted to verify pump flow using 0 FI-78 40, SFPCS Flow
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Indicator, which indicated flow in excess of 2000 gallons per minute
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(gpm). However, the AU0 was not aware that the flow indicator had been
inoperable (pegged high) since July 25, 1995, or that 0 FI-78 40 was
actually the indicator for the B train rather than the A train. The A-
train indicator was indicating no flow which represented the actual
condition with the C S pumping running and its A train discharge valve
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closed. A Mt tag (C205381) was attached to the inowrable flow
indicator, however, the tag was positioned behind t1e indicator and was
further hidden behind a contamination zone placard which was attached to
the instrument rack. In that location, the WR tag was not visible to
the AVO.
The inspectors also determined that several significant factors !
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e S0178.1 did not include steps as to how the operator should verify ,
flow when placing the SFPCS in service; for example, verification of '
pump discharge pressure or pump flow.
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e The identification label on the two SFPCS flow instruments did not
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identify them as either A train or B train but merely listed the
instrument number and the title, "SFPCS Pump Flow Indicator." ,
Operations had not instituted compensatory actions for a SFPCS flow
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instrument which had been out of service since July 1995, nor had
operators been informed that the instruments, when working, were l
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considered by Operations management to be unreliable.
e Maintenance had not initiated prompt corrective action on the
inoperable flow instrument.
e The WR tag which was attached to the flow instrument was not
l prominently displayed on the instrument.
The licensee's corrective action was focused on the operator error, but
did not appear adequate to address aspects which appeared to impact the
human performance error such as flow indicator labelling, procedural
direction for instrument utilization to verify proper system operation,
unapproved operator aids, and longstanding broken equipment.
The inspectors determined that the cause of the SFPCS misalignment was
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the failure to follow procedure 50I 78.1 in aligning the SFPCS system by
not ensuring the C S pump discharge valve (0 78-588) was fully open.
This is considered a violation (VIO) of TS 6.8.1.a (VIO 50 327, 328/97-
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c. Conclusions
A violation was identified for failure to follow a SFP cooling system
procedure.
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A weakness was identified in the area of operations for not implementing
compensatory measures to address an inoperable SFPCS flow instrument and
for procedure S0178.1 not having steps for positive verification of
SFPCS flow.
A weakness was identified in the area of maintenance / work planning for
not promptly repairing an inoperable SFPCS flow indicator and not
prominently displaying a work request tag on a defective flow
instrument.
A positive observation was noted for operators promptly identifying the
misaligned SFPCS and the increase in SFP temperature.
08 Miscellaneous Operations Issues (92901) :
08.1 (Closed) Licensee Event Report (LER) 50 327/96001. Missed Fire Watch.
On March 14, 1997, the NRC issued a Severity Level IV violation.
Enforcement Action (EA) 97 092 01014, for failure to maintain
information required by Commission regulations that was complete and
accurate in all material respects. This event was discussed in NRC
Office of Investigations (01) Report No. 2 96 009, a synopsis of which :
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was attached to the Notice of Violation (NOV). No new issues were
revealed by the LER. The NOV will be closed during a future inspection.
08.2 (Closed) Unresolved Item (URI) 50 327/?6 08 01. Review Hispositionina of 1
EGTS Control Switch. This item is closed based on a subsequent review
of the issue documented in Inspection Report 50 327, 328/96 09,
Section 03.2. A non cited violation was issued for an inoperable "A"
train of emergency gas treatment system for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 43 minutes due
to operator error and was documented as a non cited violation (NCV), NCV
50 327/96 09 02.
II. Maintenance
M1 Conduct of Maintenance
M1.1 General Comments
a. Insoection Scope (61726. 62707)
The inspectors Observed and/or reviewed all or portions of the following )
work activities and/or surveillances:
e 0 SI 0PS 083151.A Six Month Test Requirement on Electric Hydrogen ,
Recombiner System Train A (Unit 1 & Unit 2) i
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e 0-SI-0PS 083 151.8 Six Month Test Requirement on Electric Hydrogen
Recombiner System Train 8 (Unit 1 & Unit 2)
e 1-SI-IFT 043 200.A Functional Test of Containment Hydrogen Analyzer
(1 H2AN 43-200) Train A
e 1 SI IFT 043 210.B Functional Test of Containment Hydrogen Analyzer
(1 H2AN 43 210) Train B
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e 2 SI IFT-043 200.A Functional Test _of Containment Hydrogen Analyzer i
(2 H2AN 43 200) Train A ,
e 2 SI IFT-043 210.8 Functional Test of Containment Hydrogen Analyzer i
(2 H2AN 43-210) Train B
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e WO 97 06117 Repair damaged control cable in main control
room
o WO 94 046B1 17 Remove control board switch and install patch
e 2 PI ICC 090 001.0 Calibration of spent fuel pit area radiation
o monitor 2 R 90 1
e 1 PI ICC 090-001.0 Calibration of spent fuel pit area radiation '
monitor 1-R 90 1
e WO 97 002594 Replace K 1 relay in 2-LC 3 42
e N PT 9 Licuid Penetrant Examination of ASME and ANSI
Coce Components and Welds
e 2-SI-MDG 082 102.A Two Year Mechanical Inspections Diesel Generator
2A A
e 0 HI MDG 082.004.0 Two Year Preventive Maintenance of Diesel
Engines
e 0 HI MDG 082-007.0 Four Year Preventive Maintenance of Diesel
Engines
e 1 SI MDG 082.102.0 Four Year SI, Four Year Preventive Maintenance
of Diesel Engines, Four Year, Six Year, and
Twelve Year Diesel Generator Mechanical
Inspection
e 0 S0 18 5 Fuel Oil Transfer
e 0 S0-82 1 Diesel Generator 1A 1
e 0 S0 82 3 Diesel Generator 2A A
e 0 S0 82 4 Diesel Generator 2B-B l
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e STI-155 Chemical Volume and Control System Interlock
Safety Function Demonstration
e WO 96 030737 000 Condensate Booster Pump 1A on 6.9 kV Unit Board
1B Relay, Meter and Transducer Calibration
e 0 PI-NUC 092-036.0 Incore Excore Detector Calibration
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e TI 53 Flux Mapping
e 0 SI 0PS-082 007.0 Diesel Generator Operability Verification
b. Observations and Findinas
The inspectors noted that the work activities and the perforcance of
surveillance activities were adequately performed.
M2 Maintenance and Material Condition of Facilities and Equipment
M2.1 Enaineered Safety Features (ESF) Actuations
a. Insoection Scope (40500. 62707)
On A)ril 4, 1997, the licensee experienced two ESF actuations both of
whic1 resulted in loss of the normal / alternate power supply to the 1A A
6.9 kilovolt (kV) shutdown board, the starting of all available
emergency diesel generators (EDG), and in the 1A A EDG tying onto the
shutdown board. The inspectors reviewed the causes of the two ESF
actuations.
b. Observations and Findinas ,
The first ESF actuation occurred on April 4, 1997, at 1:29 a.m. when ,
maintenance perJonnel drilled into a control power cable in the main l
control room while making preparation for installing a metal patch on ;
the control board in an area where an obsolete control switch had been !
removed. The work was being performed under WO 94-04681 17 and was the ;
seventeenth stage / component of Design Change Notice (DCN) M09179B. which
involved the removal of several control room switches starting in 1994.
The licensee initiated PER No. SQ970875PER and completed an event
critique report evaluating the event. The licensee determined the root
cause was electrical craftsmen employing a poor work practice by failing l
to use positive controls to preclude damage to panel internal wiring
while performing a drilling operation. The craftsmen stated they had
attemated to obtain a short drill bit and drill collar from the tool
room aut none were available. They then proceeded to do the job without
the special tools and indicated they thought they could sto) the drill
bit before it got to the wires, and that the drill bit whic1 they had
was short enough. The craftsmen did not inform their foreman or general
foreman of the tool aroblem even though both foremen were in the area
during the time of tie work activity. Because skill of the craft was ( ,
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relied upon in this maintenance activity, the WO did not contain i
specific instructions regarding the use of a drill collar or other
similar device. The craftsmen on this job were experienced and had ,
worked in the control room in past outages. The licensee concluded that
the only possible barrier that would have stopped the action of the -
craftsmen would have been the presence of the foreman or general foreman
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at the job site.
The second ESF actuation occurred on April 4, 1997, at 10:36 a.m., while
repairs (WO 97-006117) were being made to the control power cable which #
had been damaged earlier in the day. Following the first actuation,
operations and engineering mistakenly concluded-that the damaged cable
did not affect the operation of the alternate' feeder breaker.
Therefore,. operations realigned the alternate feeder breaker to the IA A '
shutdown board and stopped the IA-A EDG. However, two of the conductors
in the cable bundle were associated with the alternate feeder breaker,
which resulted in the second ESF actuation when maintenance began repair
of the cable. Also, prior to the cable repair, operations had not -
clearly communicated, to the Maintenance Electrical Group (MEG) and to
Maintenance Planning and Technical, their plan to close the alternate ,
feeder breaker. Lack of coordination led those groups to believe that
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both the normal and alternate feeder breakers would remain open
throughout the repair and post maintenance testing (PMT) of the damaged
- cable bundle.
When electricians were trimming the damaged cable during the repair, the
alternate supaly breaker tripped and the IA A EDG started and tied on to ,
the shutdown aoard. Site engineering determined that the iamediate :
cause of the event was grounding or shorting of the alternate fceder
breaker trip coil circuit, thereby causing the trip coil to actuate.
The licensee's event critique report associated with PER No. SQ970883PER
detailed numerous communication and technical errors which contributed
to.this event including: !
e No integrated plan was developed to assess and coordinate the
repair of the cable. The cable repair was treated as an urgent !
activity, but not as a sensitive activity, i
e The engineering evaluation of the impact of the damaged cable on
the alternate feeder breaker was not clearly communicated to ,
operations.
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e The work planner placed prerequisites in the WO (Step 4.1, Verify .
Breaker 1716 is Open) which required the alternate feeder breaker ;
to be open rather than requesting a Hold Order (HO) on the
alternate breaker. The normal supply breaker was tagg i out under
a H0.
e- The MEG General Foreman reviewed the H0 for the normal feeder ,
breaker and considered it to be adequate for the cable repair .
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e The H0 boundaries for the normal feeder breaker were inadequate. 1
l MEG did not recognize two of the conductors in the damaged cable
bundle came from a second terminal board independent of the other
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conductors in the bundle and that those two conductors were I
associated with the alternate supply breaker. 1
e During the work package review, the support senior reactor
operator (SRO) failed to notice the prerequisite step that
required the alternate feeder breaker to be open.
! e During the field verification prior to commencing work on the
damaged cable, HEG incorrectly verified that the alternate feeder
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breaker was open when, in fact, it was closed.
e MEG stated to the operations crew that the conductors in the cable I'
bundle were de energized. However, HEG had only checked one of
two terminal strips.
e MEG conducted a pre job briefing in the control room which did not
include all disciplines involved in the evolution,
o Prior to actual repair of the cable bundle, HEG did not verify the
conductors for voltage and did not reverify that all prerequisites
had been met.
The second ESF actuation occurred although numerous opportunities were
available to prevent it. Adequate instructions were available in the
prerequisites of the W0 which, if followed, would have ensured that the
alternate feeder breaker was open orior to commencing repair of the
cable. Personnel were not thorougl in reviewing. briefing, and
performing the WO requirements and subsequently failed to ensure that
the alternate feeder breaker was open before beginning the cable repair.
This failure to follow the instructions in a WO is identified as a
violation of TS 6.8.1.a (VIO 50 327, 328/97 03 02).
c. Conclusions
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One weakness was identified for electrical craftsmen employing a poor
work practice which resulted in drilling into a control c' ale which
initiated an ESF actuation.
One violation was identified for failure to follow the requirements of a
WO which subsequently resulted in an ESF actuation.
A weakness was identifieo when licensee management did not ensure
adequate planning of the sensitive activity of repairing a damaged
control cable to a shutdown board.
A weakness was identified when electrical maintenance personnel did not
perform a verification of cable voltage, a skill of the craft
expectation, prior to commencing repair of the damaged cable.
_ _ _ _ _ - _ _ _ _ _
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A weakness was identified for. the inadequate manner in which both
operations and maintenance personnel reviewed the W0 and the H0
associated with the cable repair.
A weakness was identified in the thoroughness with which MEG conducted a
shift turnover. The WO was not reviewed and the on coming electrical
crew did not correctly verify the status of the alternate feeder
breaker.
One strength was identified for the thoroughness and timeliness with
which the licensee conducted its investigation of the ESF actuation
event.
M2.2 Start Bus Alternate Electrical Supply Breaker Failure
a. Inspection Scope (62707)
The inspectors reviewed the events associated with two EDG trips, during
testing, due to high differential current conditions, which were caused
by a faulted shutdown 6.9 kV board supply breaker.
b. -Observation and Findinos
!
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At 11:26 a.m., on April 2, 1997, the IB B EDG tripped on phase
imbalance. Troubleshooting was performed and at 4:45 a.m., on April 3.
1997, the IB B EDG was restarted. Upon reaching 2.0 megawatts, the 18-B
EDG tripwd due to phase imbalance. The licensee continued to
troubles 1oot the 18 B EDG but did not identify a root cause for the
phase imbalance condition. The 1B B EDG was successfully tested late on
April 4, and was declared operable approximately 2:00 a.m. on April 5,
1997. At approximately 10:25 a.m., on April 6,1997, the operators
noted a low phase "B" voltage on Start Bus 1A and on 6.9 kV Unit Board ,
1H. In addition, the operators also noted that the 480 volt Unit Board '
1A "B" phase was also indicating low and an associated 480 volt
alternating current load supply breaker was found tripped.
During subsequent electrical system walkdowns by engineering and
j operations a loud rattling noise was noted coming from the Start Bus ;
alternate supply breaker "1614", a 6.9 kV/2000 amp breaker. Start Bus
'
l
1A was transferred to its nurmal supply breaker at 11:22 a.m., on !
April 6. At 11:50 a.m., the operators re)orted that the "1614" j
alternate supply breaker could not be racced off the start bus. - At
13:36 p.m., another attempt to rack the "1614" breaker out was
successful.
Subsequent troubleshooting of the "1614" breaker noted that the "B"
phase arching contacts were severely burned. In addition, the
licensee's investigation noted that the main line contacts were not
adjusted properly and did not make contact. The licensee performed a
detailed review of-the recent work history for the breaker to determine
whether the contacts had been adjusted improperly by maintenance
.
4
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11
personnel. The review noted that maintenance had not adjusted the
contacts.
The licensee noted that the breaker had recently been refurbished by the
vendor, which was supposed to include proper setting of the main line
contacts. Breaker o)eration had been tested after it was returned to
the site, however, t1e contact com)ression of the main line contacts had
not been verified. In addition, tie licensee did not perform a visual
line contacts which would have identified the
inspection of the
adverse condition ( m -ig/ inch gap). The onsite inspection / testing
activities were ina equ, ate and did not ensure that the vendor's
refurbishment / maintenance / repair activities were properly performed and
that the breaker was operable prior to installation in the plant.
There are eight 6.9 kV/2000 amp breakers that provide paths for the two
trains of offsite )ower to tne four 6.9 kV emergency plant buses. Six
of these breakers lad recently been refurbished by the manufacturer.
The licensee has subsequently inspected two of the breakers and did not
identify any problems. Inspection activities are planned for one of the
other installed breakers and no inspection activities are planned for
two of the breakers in that they have been fully loaded and do not
appear to have any problems. The last breaker was "1614" which failed
and has been returned to the vendor for repairs. For the two breakers
that were not going to be inspected, the licensee stated that these
breakers had been fully loaded with no problems and were considered to
be acceptable. The licensee noted that "as found" data would be
documented during the next maintenance interval for these breakers.
This corrective action appears adequate to prevent recurrence. The
licensee failed to perform an adequate testing of the "1614" breaker i
following refurbishment by a vendor, however this is being treated as a j
non cited violation consistent with Section VII.B.1 of the NRC ^
Enforcement Policy (NCV 50 327, 328/97-03 03). l
>
-
c. Conclusions
An NCV was identified for failure to perform adequate post maintenance ;
testing of a 6.9 kV breaker (#1614) following vendor
refurbishment / maintenance / repair at the vendor's facility. l
- M8 Miscellaneous Haintenance Issues (92902) .
t
c M8.1 (Closed) Insoector Follow up Item (IFI) 50 327. 328/96 09 03. Review !
Corrective Actions Related to Emeroency Raw Coolina Water (ERCW) Check !
Valve FailuCg. PER No. SO962283PER. The licensee initiated or revised
work requests to include inspection of the swing arms of the'seven
remaining ERCW check valves. Thus far, swing arms have been replaced on '
the LB, NB and JA ERCW discharge check valves. A Technical Support i
Investigation Request (TSIR) was issued which gave additional monitoring l
.
guidance to operations to routinely monitor the pump packing for I
leakage. Any leakage could indicate that the pump discharge check valve j
'
was stuck open. A Training Letter was issued to operations personnel on l
'
the information contained in the TSIR. Operations training reviewed
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training materials and procedures for possible revisions and determined
that no changes were required. The inspector verified the corrective
actions taken by the licensee and concluded the actions to be
appropriate.
M8.2 (Closed) URI 50 327. 328/97 01 02. Review of Adeauacy of Reactor Trip
Breaker Testina. Further review indicated that the licensee had not
adequately tested the Unit 2 reactor trip breakers following maintenance
activities in August and September 1996. This unresolved item is being
closed and the following violation is being opened to address this
issue.
(0 pen) VIO 50 328/97 03 04. Failure to Adeauately Test the Reactor Trio
Breaker P 4 Function. Further review concluded that the licensee had
not adequately been testing the Unit 2 reactor trip breakers. The
details of the inspector's review and the basis for this conclusion was
documented in inspection report 50 327, 328/97 01, Section M4.1, Reactor
Trip Breaker Testing. The licensee *.s failure to adequately test the
reactor trip breakers is a violation of NRC requirements.
M8.3 (Closed) URI 50 327. 328/97-01 04. Review Imolementation of
Recommendations from the 1979 and 1987 Westinahouse Letters Recardina
Reactor Trio Breaker Testina. Further review indicated that the
licensee had not fully implemented the recommendations of the
Westinghouse letters, which contributed to the inadequate testing of the
reactor trip breakers: however, the deficiency was not considered to be
a violation. Not fully implementing / integrating the Westinghouse
recommendations into appropriate plant procedures is being identified as !
a weakness.
1
III. Enaineerino l
E2 Engineering Support of Facilities and Equipment
E2.1 Unit 1 Turbine Driven Auxiliary Feedwater Pumo (TDAFW) Condensate Sumo
a. Inspection Scope (37551)
)
The inspector reviewed the sequence of events which culminated in the
tripaing of the one of the Unit 1 TDAFW sump pumps and the degradation ;
of t1e other sump pump. Loss of both suma pumps could have resulted in
an inoperable TDAFW pump if the sump had aacked up into the TDAFW i
turbine.
b. Observation and Findinas
On March 3.1997, during a walkdown of the TDAFW pump rooms, the
inspectors observed that the two Unit 1 TDAFW pump room sump pumps ran
continuously. Following that observation, the inspectors developed the
. _ _ . _ _. _- _ _ _ _ _ _ _. .
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following sequence of events which preceded the eventual determination :
by the licensee that the sump pumps were degraded: t
In early 1996, the licensee implemented DCN M11473A which, in part,
installed a new drain line to. direct Unit 1 steam generator blowdown 1
'
(SGBD) samale drains from the sample panel to the sump in either the
Unit 1 or Jnit 2 TDAFW pump room. The TDAFW sump is then pumped to the :
turbine building station sump. Prior to the DCN, the sample flow was
handled as radwaste and was directed to the auxiliary building floor ;
'
- drain collector tank (FDCT). P
'
DCN M11473A also changed the design of the level control instrumentation
for the TDAFW pump room sump. The mechanical float type level :
'
controller and switching mechanism was replaced by an electronic probe
4 type instrument, with multiple contacts for pump sequencing. The new
instrumentation used the same suma level setpoints which were previously
I used to control the sump pumps, w1ich resulted in a level control
problem and is discussed in a later paragraph.
On October 29, 1996, operations initiated Technical Support
sump high level annunciator was annunciating approximately every half
hour. The TSIR questioned whether the sump level switch needed
adjustment and whether the increased inflow to the sump from the SGBD
sample had exceeded the capacity of the sump pumps. Technical support
inadequately addressed the TSIR by referring only to a calculation ,
performed at the time of the DCN which determined that the combined '
inleakage to the sump would not exceed the pumps' capacity. Technical :
a
support did not perform an actual inspection of the pumps to address the l
TSI l. 1
I
On November 25, 1996, WR C359779 was written to address the sump level
'
switch and the frequent annunciation of the high level sump alarm. This i
WR was not implemented until March 21, 1997 under WO 96-041840. !
On November 30, 1996, the TDAFW sump high level annunciator, a common
annunciator for both units, was disabled because it was considered to be
a nuisance alarm. No compensatory actions or operator work-arounds were
initiated as a result of the disabled annunciator. In addition, the
licensee did not perform a safety evaluation prior to disabling the
,,
On December 28, 1996, operations initiated TSIR, No. 96 NSS 77 630,
which noted that one of the Unit 1 TDAFW sump pumps was running
continuously and the second pump was cycling on periodically to keep the
sump pumped down. The TSIR questioned if the increased inleakage into
the sump was normal: were the pumps designed for continuous operation: 1
and if one pump failed, could the remaining pump keep up with the !'
inleakage. Technical support believed that the questions asked by TSIR
No. 96 NSS 77 630, had been answered in their response to TSIR No. 96-
- NSS 77 580 and therefore did not place a high priority on addressing
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TSIR No. 96 NSS77-630. As a consequence, TSIR No. 96 NSS 77 630 was !
- not investigated by technical support until March 13, 1997.
On March 3, 1997, the resident inspector observed that both TDAFW pump l
aumps were running continuously. The control room was notified of
'
sump ,
the caservation. !
'
On March 5,1997, the licensee, apparently in response to the '
- inspectors' observations, initiated TSIR 97 NSS 77 668 which again
documented that the Unit 1 TDAFW sump pumps were running continuously. ;
On March 14, 1997, while verifying with operations the expected position !
(open or closed) of the TDAFW sump overflow valve, the inspector noted
. that at least one SR0 was not aware that the sump high level alarm was
4
disabled.
, .
On March 17, 1997, during troubleshooting of the sump level transmitter, {
the licensee discovered that the level transmitter low level set point .
had drifted low within its tolerance band and at that lower setting i
- would not allow the sump aumps to shut off. The troubleshooting also
i
determined that the inleacage to the sump was approximately 6 gpm and ,
that each sump pump was only pumping approximately 6 gpm (rated capacity '
of the pumas was 23.5 gpm) and appeared to be degraded. PER No.
a
SQ970558PE1 was written to document these findings.
!
On March 19, 1997, the "B" TDAFM sump pump tripped and a black'
- discoloration was observed on the pump motor casing. Subsequently, the -
On March 20, 1997, the licensee completed a technical operability l
evaluation in res)onse to PER No. SQ970558PER. The investigation
determined that t1e TDAFW sump pumps were not producing rated flow which 4
could result in sump overflow back through the low pressure steam traps
to the TDAFW aump turbine potentially affecting equipment o>erability.
The TDAFW turaine vendor stated that, with water in the tur)ine and in ;
the exhaust piping, the turbine governor may not control properly, which '
t could cause an overspeed trip of the turbine. As a compensatory
measure, the licensee opened the sump overflow manual isolation valves
on both units. This compensatory measure will remain in effect until a ,
permanent resolution is reached. ,
i !
The licensee subsequently discovered that the sump overflow valve had
been in a "normally closed" position since implementation of a field
change request in 1982 which added the overflow line to the sum). The !
operability evaluation concluded that the Unit 1 and Unit 2 TDAN aumps ;
'
were operable and that, with the compensatory measures in place, t1e
potential for sump overflow was mitigated.
A review of the initial TSIR (96 NSS 77 580) noted that the technical
support response to operations' concerns regarding the sump level switch >
setpoint and sump flow, was inadequate. Technical support j
inappropriately addressed the concerns by stating that sump inlet flow j
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was within design of the system but did not address why both pumps were -
running or why the high level alarm was routinely actuating. For the ;
second TSIR (96 NSS 77 630), Technical su) port did not address the t
concern until March 13, 1997, after the t11rd TSIR (97 N55-77 668) had
been written. The licensee *s failure to adequately resolve the i
deficient condition is considered to be inadequate and untimely response -
to offnormal and alarmed conditions-and is identified as a violation
(VIO 50 327/97 03-06). *
The NRC inspectors raised a concern with the potential to backfill the
TDAFW pump turbine casing if the condensate sump were to overflow. This
potential adverse condition could exist due to the licensee maintaining '
the overflow valve closed and due to the closed design of the sump. In i
addition, the sump pumps were powered from non safety related power
supplies. The licensee completed a technical operability evaluation and ,
noted that the TDAFW pump could become inoperable if the sump
inadvertently overflowed. This was based on the turbine casing being .
filled with water, resulting in the potential for an overspeed trip of -
the turbine. In addition, the inspectors noted that if the TDAFW pump
tripped on overspeed, due to the height and distance of the exhaust
line, the water from the turbine casing would drain back into the
turbine and potentially cause additional overspeed trips. The
evaluation concluded that the sump overflow valve should have been
maintained in the "open" position since it was installed in 1982. -
t
On November 30, 1996, the licensee disabled the TDAFW pump condensate
sump high level alarm. A thorough evaluation was not performed.
Disabling of the alarm placed the plant in a condition where the TDAFW
pump sump could have overflowed, causing the TDAFW pump to be inoperable '
and the operators would not have been alerted to the condition. The
failure to perform a thorough evaluation prior to disabling the TDAFW
pump sump high level alarm, is considered to be a violation (VIO 50-
327/97 03 07).
c. Conclusions
A violation was identified for failure to take adequate response to
resolve the concerns with TDAFW sump performance problems.
A violation was identified for failure to aerform a thorough evaluation
prior to disabling the TDAFW pump sump hig1 level alarm.
E2.2 DCN No. M12782A. Recommended Plant Modifications to Main Steam Dumo
Drain System
a. Jnspection Scope (37550)
The inspector reviewed )lant modification DCN No. M12782A and performed i
a field inspection of t1e installation in order to verify that the ]
design change had been developed in accordance with the requirements of
the design control program and that recommendations for system ;
modifications necessary to ensure reliable performance in accordance !
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16
with design objectives had been incorporated into the design change
package,
b. Observations and Findinas
PER No. SQ962633PER documented a water hammer event that occurred on
October 11, 1996, during a Unit 2 shutdown because of excessive leakage
through the Number 4 reactor coolant pump #2 seal. A search of the
Tracking and Reporting of Open Items (TROI) data base revealed that a
similar event had occurred in January 1993, the details of which were
documented on PER No. SQ931502PER. The root cause analysis of the water
hammer event of October 11, 1996, concluded that inadequate corrective
actions / recurrence control established for PER No. SQ931502PER did not
prevent this problem from occurring again. An independent evaluation
team was tasked with reviewing the Sequoyah main steam dump drain system
to (1) evaluate the design of the system , review the operating history
including the recent Unit 1 and 2 experience: (2) determine the most
likely cause for abnormal water accumulation: and (3) recommend any
modifications necessary to make the system function reliably in
accordance with its design objectives.
The independent evaluation team recommended that ball valves be
installed in the Unit 1 drain lines to automatically isolate each line ;
whenever its associated dump valve was in service. The evaluation team
also recommended that the Unit 2 camflex valves which perform this
function should also be replaced with ball valves and that the drain
tank drain line should be increased in size to allow the tank to drain
as fast or faster than it fills. Other recommendations for system
improvement included: ,
e Relocating Unit i vacuum pumps A and B drain lines to the drain
tank, in a similar manner to Unit 2, to allow them to drain and
preclude water induction into the vacuum pumps,
e Remove insulation from the 2 inch drain header and all field lines
up to the new ball valves to help subcool drain condensate and
prevent pressure drop induced flashing.
. * Provide control room indication and alarm of abnormal drain system
function.
- Re evaluate the design pressure of the steam dump drain tank and
modify the design if necessary, to accommodate pressurization from
the postulated failure of a drain isolation valve. Additionally,
revise design calculation EPM-JDW 110990 to include this event and
to include the additional condensation source estimates and system
flow capacity (EZFLOW) estimate.
The inspector reviewed plant modification DCN No. M12782A and performed
a walkdown of the installation to assess the extent to which TVA
management had implemented recommended corrective actions developed for i
resolution of water hammer events. The primary recommendation made by i
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17
the evaluation team concerning the use of ball valves in the drain lines
of Units 1 and 2 were not implemented by TVA management. Discussions
with responsible engineering personnel and review of objective evidence
revealed that at a 10% design review meeting held on January 27, 1997, a
decision was made to use Masonelian camflex valves for Unit 1. This
valve was similar to that which had been installed on Unit 2. TVA
management presented a technical evaluation of the leakage capabilities
of both valves which supported the decision to use the Masonelian
1
camflex valves. The inspector reviewed UFSAR Sections 9.3.1, 10.3,
10.4.7.1, and 10.4.9 along with the Safety Assessment that had been
prepared for the plant modification. Based on this review the inspector
concluded that the screening criteria had been correctly applied in
determining whether a 10 CFR 50.59 Safety Evaluation should have been
performed. UFSAR figures impacted by the plant modification are
scheduled to be revised to reflect the hardware changes installed by DCN
No. M12782A. A detailed technical evaluation of the plant modification
was performed based on review of the following design output documents:
'
.
o Drawing No. CCD 1, 2 47W801 1. Flow Diagram Main and Reheat Steam,
Revision 64.
e Drawing No. CCD 1-47W610 1 3, Hechanical Control Diagram Main :
,
Steam System, Revision 2.
- Drawing No. CCD 1, 2 47W6111-3, Hechanical Logic Diagram Main and
Reheat Steam, Revision 6.
,
o Drawing No. CCD 1, 2 45N601 2, Wiring Diagram Main Steam System
Schematic Diagrams Sheet 2, Revision 17.
'
- Design Change Authorizations (DCA) No. M12782-01 through M12782- i
43. ,
Based on the above review the inspector determined that the scope of the
-
plant modification included the independent evaluation team's
recommendations with the following exception. The plant modification
did not provide control room indication and alarm of abnormal drain
system function. Jo d scussions with TVA management concerning this
, omission the inspector was informed that it is TVA's management
'
expectation that a reading and documentation of the main steam drain
tank level by an assistant unit operator (AU0) each shift change will +
satisfy the intent of this recommendation. Additionally, diagnostic
equipment installed as part of the plant modification to monitor the
effectiveness of the design change will provide a warning of any
potential system problems.
Post modification test requirements specified in the DCN 3ackage was
reviewed and discussed with TVA engineering personnel. T1e basis for '
l
level switch LS 11176 setpoint used in the main steam dump drain tank
level control scheme was also discussed. The inspector determned that
'
'
a design basis calculation had not been prepared in suppor' of the level
switc's setpoints used to initiate condensate draining / receiving mode for
!
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the main steam dump drain tank. TVA management stated that level-switch ;
'
setpoints were never considered as having contributed to the water
hammer events and the values were the same as previously existed before :
the plant modification. 4
'
, c. Conclusion
,
The inspector concluded that the plant modification was technically
<
adequate and had been prepared in accordance with the requirements of !
,
the design control program. The design objectives were consistent with t
the independent evaluation team's recommendation with the exceptions -
noted.
E8 Miscellaneous Engineering Issues (92903)
- E8.1 (Closed) URI 50 327. 328/96-16 01. Inadeauate Safety Evaluation Resulted *
in Unreviewed Safety Question. URI 50 327, 328/96 16 01 was identified
'
in connection with both Units 1 and 2 exceeding 650 effective full power
days (EFPD) on December 29, 1989, and December 30, 1990, respectively. !
The licensing basis for electrical equipment important to safety
environmentally qualified in accordance with the requirements of 10 CFR '
50.49 was 650 EFPD. A 10 CFR 50.59 Safety Evaluation performed by the
- licensee to facilitate a core design change from 650 to 1000 EFPD failed
to address the requirements of 10 CFR 50.49 for environmentally !
qualified equipment and resulted in both Units operating outside their !
'
licensing basis.
'
On February 21, 1997. TVA management presented additional information
. which demonstrated that environmentally qualified equipment had
l maintained their environmental qualifications (EQ) for Unit operation in
excess of 650 EFPD. TVA management referred to communications with the
- - NRC during 1994 which resulted in NRC approval of "JC0 for PER No.
SQP900372." This justification for continued operation (JCO) bounded :
reactor core designs with U m average enrichment of less than 4.5% and '
1000 EFPD. The licensee also referred to design basis calculation TI-
!
RPS 48 Integrated Accident Dose inside Primary Containment and Annulus,
Revision 6, which demonstrated that the 100 day integrated doses inside
containment and the annulus were bounded by radiation values contained
in the EQ binders. The licensee concluded that no hardware changes were ,
!
needed and all corrective action for EQ related deficiencies had been
completed.
Site engineering management gave the inspector closure documentation for
PER No, 50940040I1 which stated that corrective actions for TROI
Sequence 26 and 36 had been completed. Sequence 36 specifically involved
revision of the EQ binders to incorporate 100 day integrated accident
doses based on the 1000 EFPD criteria including revision to the
Electrical Engineering Branch (EEB) calculations. The inspector
reviewed selected EQ binders in order to verify completion of TROI
sequence 36. Based on this review the inspector determined that the EQ +
binders in the Site Engineering office had not been updated. In :
discussions with engineering management the inspector was informed that :
i
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the plant official copies of the EQ binders were kept in Document !
'
Control and Records Management (DCRM). Pursuant to this discussion the
inspector reviewed selected EQ binders located in DCRM. The results of ,
this review revealed that most of the EQ binders had not been revised. i
Of the 21 EQ binders selected for Review 13 had not been revised. ;
'
Discussions with DCRM personnel revealed that the transmittals from site
engineering for updating the EQ binders had been rejected because of i
administrative errors. i
The inspector discussed DCRM rejection of the information transmitted to )
DCRM for updating the EQ binders with TVA management. In resaonse to :
this inspection finding, TVA management proceeded to update tie EQ l
binders in order to ensure that they would be available for review by
,
5
the inspector prior to the end of the inspection. Site engineering
management ap)arently had not been aware that the transmittals for
updating the EQ binders had been rejected by DCRM.
The inspector performed a technical review of the information
transmitted to DCRM in order to verify that the EQ binders would be .
revised to (1) incorporate 100 day integrated loss of coolant accident
(LOCA) radiation doses based on 1000 EFPD which remained bounded by test
values: (2) that the environmental drawing references had been deleted-
and (3) that information from design criteria SON DC V 21.0, SQNP '
- Environmental Design, Revision 4 would be added. Design inputs from !
.
Calculation TI RPS 48 into design basis calculations SQNAPS3110, and ,
SQNAPS3119 were also verified to be correct based on guidance from NRR i
concerning the use of the free field beta dose reduction of 50% for a
semi infinite cloud. Revised information related to the following EQ !
binders were reviewed during this effort:
- e SONEQ 50L 010. Solenoid Valves-Target Rock, Revision 10 ;
e SONEQ M0T 003, Induction Motors-Type RN Insulation inside [
Containment, Revision 22
e SONEQ CABL 050, Brand Rex Power & Control Cable XLPE INS /TVA Type
PXJ & PXMJ, Revision 24 ;
!
e SQNEQ MOV 002, Limitorque Actuators in the Valve Rooms,
Revision 25
o SQNEQ HTR 001. Westinghouse Heaters / Hydrogen Combiner, Revision 12 j
e SQNEQ PENE 006, Westinghouse Modular Electrical Penetration
(LVP/C&I), Revision 3
The inspector concluded that the above equipment was qualified in
accordance with the requirements of 10 CFR 50.49. Prior to leaving the '
site the inspector aerformed a cursory review of selected EQ binders in
DCRM and verified tlat the EQ binders had been updated. Based on
objective evidence reviewed this item is closed.
!
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E8.2 (Closed) URI 50 327. 328/96-16 02. Untimely Corrective Action for Non-
Conformina Plant Conditions. URI 50 327, 328/96 16 02 was written to :
document failure to revise EQ binders and Electrical Engineering Branch
(EEB) calculations to incorporate updated plant environmental :
conditions. This corrective action was transferred from PER No. :
2
SQP900372PER to PER No. SQ940040II TROI Sequence item 36 in December '
,
1990. On February 21, 1997, TVA management presented additional
'
information intended to demonstrate that the timeliness with which this
issue was resolved. The licensee stated that a significant amount of
work was required to incorporate corrected numbers in design documents
and EQ binders. Additionally, the licensee said that the containment l
dose calculatbn (TI RPS 48), was issued in October 1994 and the EQ
-
bindars cualification were verified to remain bounded. The licensee 1
.
concluded that the timeliness was consistent with the safety '
significance and the EQ binders had been revised to reflect revised dose
4' calculations on February 20, 1997. ,
On April 1, 1997, the inspector determined that selected EQ binders
located in both the DCRM and site engineering office had not been
revised in accordance with closure documents for PER No. SQ940040II TROI
Sequence 36. Additional information presented by the licensee during
the time of the inspection did not demonstrate timely resolution of a
non conforming plant condition that was first identified in December 18,
1990. URI 50 327, 328/96 16 02 is closed and a violation of 10 CFR 50
Appendix B, Criterion 16 will be identified for failure to implement
prompt corrective action for non conforming plant conditions, Violation
50 327, 328/97 03 08, Untimely Corrective Action for Non conforming
'
,
Plant Condition.
E8.3 (Closed) URI 50 327. 328/96 16 03. Inadeauate Desian Control for Non-
~
Conforminn Plant Condition._ URI 50 327, 328/96 16 03 was written to
document three examples of inadequate design control related to
licensee's failure to implement the design control program in accordance
with the requirements of the ANSI N45.2.111974 design control program
and the Nuclear Quality Assurance Plan TVA NQA PLN 89 A, Revision 6,
.
Section 7.0. On February 21, 1997. TVA management presented additional
F information in order to demonstrate compliance with the requirements of i
these d.ocument. The Nuclear Quality Assurance Plan requires the
licensee to implement measures that control plant configuration and
ensure that the actual plant configuration is accurately depicted on
drawings and other appropriate design output documents and is reconciled
with applicable design basis. TVA management 3rovided the following
additional information for resolution of this JRI:
Example 1: Calculation TI RPS 48, Revision 3, which documented the 100-
day integrated accident dose with 1000 EFPD was not incorporated into
design output documents. ,
The licensee stated that TI RPS 48, Revision 2, was the design basis
calculation and TI RPS 48, Revision 3, was issued only to resolve the
100 day integrated accident dose with 1000 EFPD. During the course of
the inspection the licensee also stated that UFSAR Figures 3.11.2-1 and
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3.11.2 2 were never revised to reflect the new 100 day integrated
accident dose based on 1000 EFPD operation because the design basis for
the E0 program had not been changed. The design basis for the E0
program as demonstrated by TI RPS-48. Revision 2 was-650 EFPD. This
post LOCA source term resulted in a radiation harsh environment which
was less conservative than that produced with an average core exposure
of 1000 EFPD, Given this radiation harsh environment, there was no
reasonable assurance that electrical equipment important to safety were
qualified for their application and would meet specified performance
requirements when subjected to the conditions predicted to be 3 resent by
TI RPS 48, Revision 3. The requirement of reconciling design ) asis
information with as built plant configuration was not demonstrated as
having been followed by TVA management.
Example 2: Calculation TI RPS 48 Revision 5, documented 100 day
integrated accident dose with 650 EFPD and does not accurately depict
actual plant configuration.
Design basis calculation TI RPS 48. Revision 5, calculated the 100 day
integrated accident doses inside containment and the annulus based on
650 EFPD. The licensee stated that this calculation TI RPS 48, Revision
5. returned the calculation to the original design basis conditions. In
example 1 above the licensee stated that the design basis for the E0
program had never been changed and this was the reason for not revising
the UFSAR figures. Both statements when taken together contradict each
other. With the approval and issue of TI RPS 48 Revision 5, TVA failed
to comply with the requirement that approved design output documents
shall accurately reflect "as built" plant configuration because at that
time both Units were operating outside their licensing basis of 650
EFPD.
Example 3: A formal calculation was not prepared, reviewed and approved
to support the JC0 for the increase in the 100 day integrated accident
dose inside containment and the annulus.
TVA management stated that the JC0 was supported by quality assurance
(QA) computer software and that the results were prepared and checked.
The licensee's design control program requires that design analyses
shall be performed in a planned, controlled and correct manner. TVA
management was unable to present objective evidence in the form of QA
,
records which demonstrated that this requirement had been met.
The inspector concluded that additional information presented by the
licensee on February 21, 1997, and during the course of the inspection
did not refute earlier inspection findings documented in NRC inspection
report 50 327, 328/96-16. This URI is closed and a violation of 10 CFR
50 Appendix B, Criterion 3 will be identified, VIO 50 327, 328/97 03-09,
Inadequate Design Control for Non-Conforming Plant Conditions.
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E8.4 (Closed) URI 50-327. 328L96 16 04. Technical Acceptability Of Reducina ;
the Calculated Free Field Beta Dose Inside Containment and the Annulus.
The acceptability of the licensee reducing the calculated free field
beta dose inside the containment and the annulus by 50% was reviewed by
-
NRR and determined to be acceptable. The results of NRR's review of
calculation TI RPS 48 Integrated accident dose inside containment and
annulus, Revision 6, was documented in a memorandum from Frederick J.
. Hebdon, Director, Project Directorate II-3, to Jon R. Johnson, Director.
Division of Reactor Projects, Region II, Subject: Response to TIA96- ,
025, Sequoyah Integrated Beta Dose (TAC No. M97734), dated February 21,
1997. This URI is closed based on NRR's review of the listed
.
calculation.
E8.5 (Closed) VIO 50 327. 328/96 05-04. Failure to Update the UFSAR as
Reauired by 10 CFR 50.71(e). The inspector verified the corrective
actions described in the licensee's response letter, dated August 16,
1996, to be reasonable and complete. No similar problems were
identified.
E8.6 (Closed) IFI 327. 328/95 03 09. Incorporation of Instrument Inaccuracy
Into Tests. In a December 16, 1987 memorandum, the licensee had
determined that sufficient margin existed in the accident analyses that
limiting values for safety system performance would be treated as
nominal. The licensee noted that this approach was consistent with
other recently licensed Westinghouse plants. The component cooling
system (CCS) example noted in this inspection item was an interim
, configuration while the CCS heat exchangers were being replaced. Heat
'
exchanger performance testing by the licensee for the first quarter of
1997, indicated that there is sufficient flow margin to offset any flow
measurement error caused by instrument inaccuracies. The inspector
concluded that instrument inaccuracies would not affect CCS safety
system performance.
E8,7 (Closed) URI 50 327. 328/96 13 06. Evaluate the Adeauacy of the Desian
of the Turbine Imoulse AFW Actuation Circuitry. This unresolved item is
a closed based on an amended response to TIA 96 021, Sequoyah Automatic
Auxiliary Feedwater Actuation Concurrent With A Turbine Runback (TAC NO.
M97281). The TIA concluded that the Sequoyah AFW system initiation and
control circuitry meets all NRC requirements and complies with the plant
design and licensing basis.
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IV. Plant Support
R1 Radiological Protection and Chemistry (RP&C) Controls
,
R1.2 Occuoational Radiation Exoosure Control Proaram ,
a. InsDeCtion SCoDe (71750. 83750)
'
As required by requisite sections of 10 CFR 20 and Technical
Specifications, the inspectors reviewed implementation of selected
elements of the licensee's radiation protection program (20.1101). The
review included obervation'of radiological protection activities
including personnel monitoring (20.1502), radiological postings . :
(20.1902), high radiation area controls (20.1601), and verification of ,
posted radiation dose rates, contamination controls within the !
radiologically controlled area (RCA)(20.1501) and container labeling ,
(20.1904). ALARA work planning (20.1702), pre job worker briefings, and ;
job execution observations were performed. The inspectors also reviewed i
licensee records of personnel radiation exposure and discussed ALARA '
program details, implementation and goals. ;
b. Observations and Findinas l
The inspectors toured the health physics facilities. Auxiliary Building l
including the refueling floor, Dry Active Waste (DAW) Storage Building, 1
and selected satellite radioactive waste storage areas. At the t'me of !
the inspection, radiological housekeeping was observed to be good.
Records reviewed determined the licensee was tracking and trending i
personnel contamination events (PCE). The licensee had tracked 53 PCEs l
for the 1996 calendar year (CY) which included skin and clothing l
contaminations. Radiologically controlled areas observed were '
appropriately posted and radioactive material observed was appropriately
stored and labeled.
The inspectors reviewed Operational and Administrative controls for
entering the RCA and performing work. These controls included the use
of radiation work permits (RWP) to be reviewed and understood by workers
prior to entering the RCA. The inspectors reviewed selected RWPs for
adequacy of the radiation protection requirements based on work scope,
location, and conditions. For the RWPs reviewed, the inspector noted
that appropriate 3rotective clothing, and dosimetry were required.
During tours of t1e plant, the inspectors observed the adherence of
plant workers to the RWP requirements. The inspectors observed personal
dosimetry was being worn in the appropriate location.
The inspectors discussed ALARA goals and annual exposures with licensee
management and determined the organizational structure and
responsibilities for the ALARA staff were clearly defined in
organizational charts. - Areas reviewed included source term reduction,
ALARA accomplishments, and future ALARA plans. A discussion with
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L licensee representatives and a review of pertinent records determined'
.the licensee site exposure, as recorded on thermoluminescent dosimeters,
for fiscal year (FY) 1996 was 402 person rem. The fiscal year 1996 goal
was 408 person rem.
.
The inspectors reviewed the Unit 1 Cycle 8 (U1C8) refueling outage dose i
, goal with licensee representatives. The revised outage goal was set at ,
'
l <225 person rem. On day 13 of the planned 47 day outage the
4 uncorrected dose was 99.732 person rem or ap3roximately 44% of the goal. ;
'
The PCE goal for the outage was set at <0.9 )CEs/1000 RWP hours. On day
13 of the outage there were 17 PCEs which was a rate of 0.835 PCEs/ 1000
RWP hours.
!
. The inspectors reviewed the activities associated with the planning and
,
execution of the work to remove the S/G manway/ inserts. The RWP ,
- (970034040000) for the work activity was reviewed. The inspector a
attended the worker pre job ALARA RWP briefing and observed the work
activities using a remotely located closed circuit T.V.. The job was
~
performed within the planned time. The uncorrected dose for the job was
- 0.719 person rem. The uncorrected dose for the installation of the j
. nozzle dams was 3.081 person rem. The two jobs were tracking at or '
- below the target. goals. On day 13 of the outage the UIC8 uncorrected l
'
cumulative exposure was 99.732 person rem. The planned exposure for day '
l 13 of the outage was 97.00 person rem.
,
The insactors took independent smears to verify contamination control
in the JAW Building Auxiliary Building, and Refueling Floor. All ,
'
smears were counted and determined to be " clean." The inspectors also i
independently walked the posted control boundary on the refueling floor ;
and determined that the radiation levels were all less than 3 millirem i
per hour and as stated on the most recent survey. 1
!
c. Conclusions
"
Radiological facility conditions and housekeeping in radioactive waste
storage areas were observed to be good, material was labeled
appropriately, and areas were pro Personnel dosimetry
devices were appropriately worn. perly posted.
Radiation work activities were
appropriately planned, radiation worker doses were being maintained well
below regulatory limits and the licensee was continuing to maintain ,
exposures ALARA. Contamination control was effective.
R2.1 Process and Effluent Radiation Monitors
.
a. Insoection Scope _(83750)
The inspectors reviewed selected licensee procedures and records for
recuired surveillances on area and effluent radiation monitors and for o
t raciation monitor availability.
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b. Observations and Findinas
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The inspectors toured the facility to observe the physical operation of ;
selected area and effluent radiation monitors in use. The inspectors
reviewed selected radiation and monitor surveillance procedures and i
records for performance of channel checks, source checks, channel
, calibrations, and channel operational tests.
Performance of those surveillances was required by the TSs and/or the .
'
Offsite Dose Calculation Manual (0DCM) to demonstrate that the
instrumentation was operable. Those records reviewed indicated that the
surveillances were current and had been performed in accordance with the
'
a)plicable procedures. The most recent system status report available,
w11ch covered the Seriod October 1996 through March 1997, indicated that :
the overall availa)ility for the Radiation Monitoring System remained at '
greater than 96% operability. The inspectors reviewed and discussed
operability trending records for both safety related and non safety
> related monitors with the radiation monitor system engineer and .
engineering management.
The inspectors reviewed the operation of permanently installed area
monitors (ARMS) 1-RE 901 and 2 RE 901 located in the vicinity of the
'
new fuel storage area. The inspectors verified that the monitors were
operational and were within the required calibration frequency at the
time of the inspection. The distance to the center point in the new
.'
, fuel storage was approximately 73 feet'for 1 RE 901 and about 31.5 feet
4
for 2 RE 90 1. These monitors are calibrated on an 18 month frequency
using 1-PI ICC 090-001.0 R0 and 2 PI-ICC 090 001.0 R1. Calculations
performed by the licensee SON S 50 0166 dated 03 22 97 demonstrated that
the detection requirements of 10 CFR 70.24 were being met. ,
c. Conclusions
Based on the above reviews, it was concluded that the licensee had
effectively implemented procedures to track the availability of l
radiation monitors and to demonstrate operability of area and effluent
radiation monitors. The monitors used for 10 CFR 70.24 compliance were
operational, and the required calibration frequency and detection
requirements of 10 CFR 70.24 were met.
R8 Miscellaneous RP&C Issues
(Closed) URI 50 327. 328/96-04-12. EA 97 106. Case No.2 96 015. !
Falsification of Rad Material Receiot Survey Records. This issue l
involves the falsification of a record of a radioactive material i
shipment following receipt of this material at the licensee's facility.
]
The U.S. Nuclear Regulatory Commission, Office Of Investigations, Field l
Office, Region II, initiated an investigation of this issue on May 8. I
1996, following notification of the incident by the licensee to NRC on i
April 29, 1996. A copy of the synopsis of the investigative findings is '
attached.
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The inspectors also reviewed the issue during this inspection. The
staff concluded that the Radiation Controls technician violated licensee
i administrative procedures RCI-6, Receipt of Radioactive Materials,
Revision 11 and RCI 23, Control of Radcon Records, Revision 2. The -
radioactive material in the drum was less than Type A quantities and,
therefore, a survey was not required by Federal Regulations (10 CFR
20.1906): however, the licensee required the survey as part of their
procedures. The licensee was informed that the failure to follow
administrative procedures was a violation. The OI investigation found
that two health physics technicians deliberately conspired to deceive
NRC inspectors and that a supervisor deliberately made a false entry on
a computer record without having a written document to support the data.
These aspects of the violation were considered willful.Section VII.B.1
of the Enforcement Policy states that the NRC may refrain from issuing a
Notice of Violation for licensee-identified Severity Level IV
violations. In this case, the violation was identified by the licensee,
the violation could not have reasonably been prevented by previous
corrective action and the violation was investigated and corrective
action taken by the licensee. In addition, with regard to the willful
aspects of the violation, as described in Enforcement Policy Section
VII.B.1(d), the circumstances were promptly reported to the NRC, the
violation involved acts of low level individuals, the violation appears
to be an isolated act and significant remedial action was taken by the
licensee to demonstrate the seriousness of the willful misconduct.
'
Therefore, this violation will not be subject to enforcement action
because the licensees efforts in identifying and correcting the
violation meet the criteria specified in Section VII.B.1 of the
Enforcement Policy and will be identified as a non cited violation (NCV
50 327, 328/97 03 10).
P1 Conduct of Emergency Preparedness Activities
'
Pl.1 Public Access to Emeraency Information ,
1
a. IDspection Scope (82701) ;
I
The inspectors reviewed selected licensee procedures and records for
informing the local population of evacuation plans and routes, results )
of verifications performed to assure that target populations are i
receiving the intended information, the frequency of updates methods for
informing transient )opulations of evacuation plans, and methods, if
any, for informing t1e local population of any unusual noises at the
plant. j
b. Qh_sgrvations and Findinas l
The inspectors reviewed the calendar that contains the Emergency
information for the public that was arepared by a multi-jurisdictional
cooperative effort of The Tennessee Imergency Management Agency (TEMA),
the local emergency management agencies in Hamilton and Bradley county :
and the licensee. The calendar has been distributed annually and the l
most recent mailing to 32,586 postal addresses was made during November i
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of 1996. Each address on mail routes and post offices within the 10 -
i mile Emergency Planning Zone (EPZ) are mailed a calendar. The list was
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routinely u> dated and the U.S. Postal Service will not accept mailing
lists that lave not been updated in the last six months. Spot delivery ,
verification was performed by the licensee. In addition to the
information calendar, newsletters were sent to the facility neighbors as
a a means of providing significant or necessary information to the public
around the plant. If- known in advance, the licensee provided advance
information as a courtesy notification to TEMA and local media. The ,
same courtesy notifications were made as soon as possible after non- '
emergency operational events such as steam releases. A 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
telephone number (1 800 467 1388) was available to the public for
informational inquires. This number was included on the calendar. i
The inspectors independently verified selected evacuation route
signs within the 10 mile EPZ and the emergency information signs posted
,
and maintained at public recreational areas and at private recreational
areas that allowed posting. These signs advised persons of what actions
to take should they hear the Prompt Notification System (sirens) sound.
If the sirens sounded, radio and television would advise the public of
the recommended actions to take. The signs also contained information ;
on how to contact the licensee for additional information.
c. Conclusions
Based on the above reviews, it was concluded that the licensee had
effectively implemented a program to inform the local population and
transient population of actions to take in the event of a plant
emergency. The licensee also provided a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> telephone number for
,
informational inquires.
.
F1 Control of Fire Protection Activities
'
F1.1 Liiah Pressure Fire Protection System Modifications
a. Inspection Scope (64704) <
The inspectors reviewed the work in process on the modifications to the
high pressure fire protection water system for compliance with the
licensee *s commitments to the NRC.
b. Observations and Findinas
Work was in process on DCNs M 08811 M 08812 and M 08813 which will
provide a new high pressure fire protection water system. These
modifications include the installation of two tanks, two fire pumps,
,
fire pump house, and the replacement of piaing and valves inside the
cower block. The new system will use pota)le water from the Hixson
Jtility District. Construction of the tanks and connection to the
I utility districts water system were completed in 1996. During this
inspection, work was in process on construction of the pump house.
installation of fire pumps, new underground water supply piping, and
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piping within the Turbine Building. This work was being performed under
TVA's " limited QA program" for fire protection systems.
The inspector performed a walkdown inspection of the work in process and
reviewed the installation work on the two 12-inch underground supply
piping lines from the new pum) house to the existing fire protection
yard piping north of the 161 (V switchyard. A review was also made of
the independent inspection activities for this installation.
Appropriate items had been identified for verification by the field
engineering group during the construction activities. However, during
the review of the work package for the installation of this piping, the
inspector noted that the installation work had been divided into
multiple work segment packages to facilitate installation and
construction activities. The licensee was not completing the
construction validation documentation as each work segment was completed
but was to provide documentation after all of the work for the entire
modification had been completed. The inspectors were concerned that
this documentation verification would be completed after the underground
piping had been buried and that the personnel involved with the initial
inspection activities may not be available at the completion of the
construction activities. To address the inspector's concern, the
licensee initiated action to provide verification documentation for each
work segment as each required line verification item was completed.
The hydrostatic test. Document 95 07297 002, for the two 12 inch supply
piping lines was completed on March 17, 1997. This test data was
reviewed by the inspectors and found to be satisfactory.
The fire protection water system modifications were scheduled to be
completed by late September 1997.
c. Conclusions
Installation and hydrostatic testing for the modifications to the high
pressure fire protection water system were being performed in accordance
with the licensee's design documents.
F2 Status of Fire Protection Facilities and Equipment
F2.1 Operability of Fire Protection Facilities and Eauioment (64704)
a. In meetion Scope
The inspectors reviewed the system engineer's status report on the Fire
Protection Systems for the first quarter 1997, open maintenance work
orders on the fire protection system and operation's list of degraded or
inoperable fire protection equipment to assess the licensee's
performance for returning degraded or inoperable fire protection
components to service. Inspections were also made of the plant's fire
protection systems and equipment to assess the material condition of
these items.
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b, Observations and Findinas !
The System Status report grading for the fire protection systems for the
first quarter of 1997 indicated that these systems were in need of
improvement due to continued problems with microbiological induced
corrosion (MIC) in the high pressure fire protection system, problems ;
with the fire detection system in the ERCW pumping station and the
Turbine Building, and an inoperable computer room C0 system. The
'
modification projects currently in process to instali a potable fire :
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protection water system consisting of water storage tanks and new fire
pumps and the replacement of the MIC damaged piping with new piping
should eliminate the problems with the fire protection water system.
The corrective maintenance work in arocess on the fire detection system
should improve the performance of t11s system. The modifications to the
,
control building heating, ventilation and air conditioning will restore
the CO, system to service. Completion of these items should result in ,
an improved grading for the fire protection systems. '
Overall, the number of degraded fire protection components has declined !
in recent months. Prior to September 1996, an excessive number of fire
,
protection components were routinely out of service or degraded. On
September 4, 1996 there were 97 components out of service or degraded.
The licensee initiated action to reduce this number to a more reasonable
number. As of the end of 1996, this number had been reduced to
approximately 28 components and averaged approximately 35 components
since January 1997. ,
As of March 19, 1997, there were approximately 34 degraded fire
protection components. Ten of these items involved components
considered temporarily degraded due to on going testing activities. The
remaining 24 involved actual components which were degraded or out of '
service. Appropriate TS required compensatory actions had been
implemented for these components. Some of these degraded components had
been in a degraded mode for a long period of time, such as the eight
inoperable fire dampers, inoperable C0 gsystem for computer room, and
the degraded Thermo Lag fire barriers installed in various areas
throughout the plant. The licensee had developed plans to correct these
items by the Summer of 1997, except for the Thermo Lag fire barriers.
The schedule for completion of the corrective actions on the degraded ,
components appeared to be reasonable, except for Thermo Lag. Correction
of the Thermo Lag issue was scheduled to be completed in late 1999. This
schedule is being reviewed by the NRC. 3
As of March 18, 1997, the number of open or outstanding work requests
related to fire protection components was approximately 209. This ;
number consisted of approximately 134 modifications,13 system '
enhancements and 62 corrective maintenance items. The corrective '
maintenance work requests consisted of minor corrective maintenance work i
such as leaking valves which did not affect the operability of the '
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com)onents. Since September 1996, the licensee has placed a strong
emplases on maintaining the fire protection components in service and
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reducing the total number of own maintenance work requests. The
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inspectors' review confirmed tlat this effort had been effective.
The inspectors toured the plant and noted that the material condition of
the operable fire protection systems was very good and the operable
components were well maintained.
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c. Conclusions
The licensee had implemented a program that was effective in the ;
reduction of inoperable or degraded fire protection components and open
fire protection related maintenance work requests. The material
condition of the fire protection components was good which indicated
that appropriate emphasis was being placed on the maintenance and
,
operability of the fire protection components.
F3 Fire Protection Procedures and Documentation
F3.1 Fire Watch Procram (64704)
a. Insoection Scope ;
The inspectors reviewed the Procedures FPI 0101, Revision 0. Control of
Ignition Sources, and FPI 0180 Revision 1. Compensatory Fire Watch
Responsibilities and Control, for compliance with the NRC requirements
'
and guidelines and reviewed the procedure implementation.
b. Observations and Findinas
Procedure FPI 0101 establishes the requirements for the fire watch :
activities to be provided for work involving ignition sources such as i
welding. The fire watch for these activities was required to complete
self study document FPT 213.500 Revision 0, Fire Watch Training
Refresher Course, and classroom training of FPT 213.001, Revision 4.
Fire Watch Initial Training. In addition, each fire watch received
instructions in the extinguishment of fire. This training was provided
to personnel in the plant modification and maintenance departments.
Procedure FPI 0180 delineates the duties and responsibilities for the
compensatory fire watch program for degraded or inoperable fire
protection components. Compensatory fire watch personnel were required ,
to be badged for security access to the specific plant fire areas
requiring a fire watch, complete general employee training, be familiar ;
with the requirements of Procedure FPI-0180, be familiar with the plant
'
areas requiring a fire watch, and briefed on the specific fire watch
assignment prior to performing the fire watch duties. The compensatory
fire watch personnel were not trained in fire extinguishment but were
expected to report any identified or potential fire conditions to the
control room. As of the date of this inspection, fire watch duties were
performed by wrsonnel assigned to maintenance. However, personnel
assigned to t1e modification de
of the compensatory fire watch.partment were being
This responsibility trained
was to to the duties
be assigned
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to the modifications department when the personnel were considered
qualified to perform these fire watch duties. .
Compensatory fire watch personnel were also using a bar code reader
device to read bar codes installed in strategic locations throughout the
facility. This bar code reader device was not considered the official '
record for the fire watch patrols but was being used to verify that the
fire watch patrols were actually being performed.
c. Conclusions
An effective fire watch program had been implemented as the compensatory
action for degraded fire protection components which met the commitments
to the NRC.
I
F5 Fire Protection Staff Training and Qualification
F5.1 Fire Protection Oraanization (64704)
a. InsDection ScoDe ,
. ;
The inspectors reviewed the organization and staffing of the operations
fire protection group for compliance with the facility's fire protection
program and the NRC guidelines and requirements.
b. Observations and Findinos
The fire orotection group was under the supervision of a Fire Protection
Manager w1o reported to the operations manager. In addition to the Fire
Protection Manager there were two engineers, a fire protection
s)ecialist, and five fire brigade / emergency response teams assigned to
t1e fire protection organization. Each fire brigade / emergency response
team was composed of a foreman and four team members who were certified L
for fire brigade, emergency medical, hazardous material, and confined
space rescue related duties. Training was in process to qualify each
fire brigade member to perform surveillance testing and minor
maintenance on all fire protection components. Classroom training on
the fire protection systems and components had been provided to
practically all of the fire protection personnel. Additional on job
training and staff certification were in process. The training for all
required fire protection staff personnel was scheduled to be completed
by the Fall of 1997, at which time the fire protection personnel will be '
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certified to perform testing and maintenance on the fire protection
components. ,
c. Conclusions
The fire protection staff and fire brigade / emergency response teams were
well organized and met the requirements of the site procedures.
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- F7 Quality Assurance in Fire Protection Activities !
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, F7.1 Self Assessment of Fire Protection Proaram (64704)
a. Inspection ScoDe ,
The status of the corrective actions implemented on the September 1996
report, Self Assessment of The Sequoyah Fire Protection Program, was j
reviewed.
b. Observations and Findinos l
.
The September 1996 self assessment of the fire protection program was .
thorough and comprehensive. The assessment identified four findings and i
17 weaknesses. Correction of these items was required to enhance the
facility's fire protection program and meet the nuclear industry's fire :
protection standards. Corrective action had been completed on two of
the findings and 10 of the weakness items. Work was in process on the >
remaining two findings and seven of the weakness items. The corrective :
,
action on these items was in various stages of completion with all work l
scheduled to be completed by late 1997, except for an item related to !
the upgrades to the procedures for the smoke removal activities
following a fire. Currently, smoke removal activities following a fire
for the most probable fires are addressed by site procedures. To :
address the smoke removal item requires a comprehensive reevaluation of i
j all plant areas and a revision to the existing procedures. This work !
was not scheduled to be completed until June 1998,
c. Conclusions
'
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A thorough and comprehensive self assessment was made of the facility's
fire protection program. Appropriate corrective actions had been
initiated to resolve the identified issues in a timely manner. ;
F8 Miscellaneous Fire Protection issues l
4
F8,1 Fire Protection Related NRC Information Notices
l
The inspector reviewed the licensee's evaluation for the following NRC
Information Notices (IN):
,
e IN 9218, Potential Loss of Shutdown Capacity During a Control
Room Fire
e IN 92 28, Inadequate Fire Suppression System Testing !
t
e IN 93 41, One Hour Fire Endurance Tests Results For Thermal ;
Ceramics, 3M Company FS 195 and 3H Company E 50 Interam Fire !
Barrier Systems j
e IN 94 28, Potential Problems with Fire Barrier Penetration Seals
,
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e IN 94 31, Potential Failure of WILw, LEXAN-Type HN 4 L, Fire Hose ;
Nozzles ;
e IN'94 58, Reactor Coolant Pump Lube Oil Fire
e- IN 95-36. Emergency Lighting
The licensee's evaluations and corrective actions for these ins were !
appropriate. l
l
Following the licensing evaluation of IN 93-41, the licensee developed a
modification package to replace the existing Kaowool fire barrier !
material on approximately 2000 linear feet of electrical raceways with a j
fire barrier material which will meet the 10 CFR 50 Appendix R required
fire rating. This material was to be installed in conjunction with the :
upgrade to the Thermo Lag fire barriers scheduled for 1999. The plans
to replace the Kaowool fire barriers with fire barrier materials which
meet the required fire rating was identified as a positive action.
F8.2 (Closed) IFI 50 327. 328/96 02-06. Evaluation of Corrective Action Taken
on TVA's Fire Protection _ Audit Findinas. This issue was addressed by
-
i
NRC Inspection Report 50 327, 328/96 10 and resulted in escalated 2
enforcement action. Therefore, this item is closed. ,
'
F8.3 (00en) VIO 50 327. 328/EA 96 269 01013. Inadecuate Identification and ,
Resolution of Fire Protection Deficiencies. This violation included a
"
total of eight issues. Correction action had been completed on four
issues. The work on the remaining items was scheduled to be completed
July 1,1997. This met the commitments of TVA's letter dated
December 19, 1996. 3
,
F8.4 (0 Den) VIO 50 327. 328/EA 96 269 01023. Inocerable CO, System. The
corrective action on this item was scheduled to be completed May 31, ;
1997. This met the commitments of TVA's letter dated December 19, 1996.
F8.5 (Closed) VIO 50-327. 328/EA 96 269 01043. Inadeauate Surveillance
Procedures for Fire Hose Stations Inside Reactor Buildinas. The
inspector verified that the corrective action identified by the
J
licensee's response of December 19. 1996, was reasonable and complete.
No similar problems were identified during this inspection.
F8.6 (Closed) VIO 50 327. 328/EA 96 269 01033. Failure to Perform
Surveillance Inspections of Fire Barrier Penetration Seals. The
inspector verified that the corrective action identified by the
licensee's res)onse of December 19, 1996, was reasonable and complete.
No similar pro)lems were identified during this inspection.
F8.7 (0 pen) VIO 50 327. 328/EA 97 092 01014. Failure to Perform Hourly Fire
Watch Patrols for Dearaded Fire Protection Components. This violation .
was identified during an investigation by the NRC Office of :
Investigation and was submitted to the licensee by NRC's letter dated
March 14, 1997.
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V. Manaoement Meetinas
X1 Exit Meeting Summary
The resident inspectors 3 resented their inspection results to members of
licensee management at tie conclusion of the inspection on April 25,
1997. The licensee acknowledged the findings presented. The inspectors
asked the licensee whether any materials would be considered
proprietary. No proprietary information was identified.
A regional inspector exited on April 4, 1997. Dissenting comments were
provided by the licensee in connection with the EQ violations
identified.
.
PARTIAL LIST OF PERSONS CONTACTED
Licensee
- Adney, R., Site Vice President
Alsup, R., Quality Assessment Supervisor
- Beasley, J. , Acting Site Quality Manager
- Bryant, L., Outage Manager
- Casey, J., Fire Protection Manager
- Driscoll, D. , Training Manager
- Fecht, M., Nuclear Assurance & Licensing Manager
Fink, F. Business and Work Performance Manager
- Flippo, T., Site Support Manager
,
- 0'Brien, B., Acting Maintenance Manager ;
- Herron. J., Plant Manager
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- Kent, C., Radcon/ Chemistry Manager 4
Lagergren, B., Operations Manager
'
- Rausch, R. Maintenance and Modifications Manager
Reynolds, J., Operations Superintendent i
Rupert, J., Engineering and Support Services Manager l
Shell, R., Manager of Licensing and Industry Affairs
- Smith, J., Licensing Supervisor
- Sumry, J., Assistant Plant Manager
- Valente, J., Site Engineering and Materials Manager
- Attended exit interview
1
INSPECTION PROCEDURES USED I
IP 37550: Engineering
IP 37551: Onsite Engineering
IP 40500: Effectiveness of Licensee Controls In Identifying, Resolving, &
Preventing Problems
IP 61726: Surveillance Observations
IP 62707: Maintenance Observations
IP 64704: Fire Protection Program J
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IP 71707: Plant Operations ,
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IP 71750: P1 ant' Support Activities i
IP 82701: Operational Status of the Emergency Preparedness Program
IP 83750: Occupational Radiation Exposure
IP 92901: Followup Operations
IP 92902: Followup Maintenance l
IP 92903: Followup - Engineering
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ITEMS OPENED. CLOSED. AND DISCUSSED
Ooened ,
lyp_q Item Number Status Description and Reference
,
VIO 50 327, 328/97-03 01 Open Failure to Follow Procedure S01-78.1 ;
in Aligning the SFPCS
'
(Section 02.3).
VIO 50 327, 328/97-03 02 Open Failure to Follow Instructions in a i
Work Order Resulting in an ESF ,
.
,
Actuation (Section M2.1).
NCV 50 327, 328/97 03 03 Open/ Closed Failure to Perform Adequate Post
'
Maintenance Testing of a Breaker ,
Following Refurbishment by a Vendor. l
(Section M2.2).
VIO 50 328/97 03 04 Open Failure to Adequately Test the ,
Reactor Trip Breaker P 4 Function i
(Section M8.2). l
l
VIO 50 327/97 03 06 Open Failure of Technical Su] port to l
Adecuately Resolve the Deficient 1
Concitions Related to the TDAFW l
Condensate Sump (Section E2.1).
VIO 50 327/97 03 07 Open Failure to Perform a Thorough
Evaluation Prior to Disabling the
TDAFW Condensate Sump High Level
Alarm (Section E2.1).
VIO 50 327, 328/97 03-08 Open Untimely Corrective Action For Non-
Conforming Plant Conditions (Section
E8.2). 1
VIO 50 327, 328/97 03-09 Open Inadequate Design Control For Non-
Conforming Plant Conditions (Section
E8.3).
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- VIO 50 327, 328/EA 97-092 Open Failure to Perform Hourly Fire Watch
01014 Patrols for Degraded Fire Protection
-
Components (Section F8.7).
NCV 50-327, 328/97 03 10 Open/ Closed Falsification of a Record of a
Radioactive Material Shipment '
.
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(Section R8).
,
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) Closed
Iypg Item Number Status
'
Description and Reference
LER 50 327/96001 Closed Missed Fire Watch (Section 08.1).
. URI 50 327/96 08 01 Closed Review Hispositioning of EGTS
Control Switch (Section 08.2).
IFI 50 328, 328/96 09 03 Closed Review Corrective Actions Related to
ERCW Check Valve Failure, PER
'
SQ962283PER (Section M8.1).
URI 50 327, 328/97 01 02 Closed Review of Adequacy of Reactor Trip
Breaker Testing (Section M8.2).
URI 50 327, 328/97 01 04 Closed Review Implementation of i
,
Recommendations from the 1979 and
1987 Westinghouse Letters Regarding r
Reactor Trip Breaker Testing l
(Section M8.3).
URI 50 327, 328/96 16 01 Closed Inadequate Safety Evaluation
Resulted In Unreviewed Safety
Question (Section E8.1).
URI 50 327, 328/96 16 02 Closed untimely Corrective Action For Non-
Conforming Plant Conditions (Section
E8.2).
URI 50 327, 328/96 16 03 Closed Inadequate Design Control For Non-
Conforming Plant Conditions (Section
E8.3).
URI 50 327, 328/96 16 04 Closed Technical Acceptability Of Reducing
The Calculated Free Field Beta Dose
Inside Containmcnt And Annulus I
(Section E8.4).
VIO 50 327, 328/96 05 04 Closed Failure to Update the UFSAR as
Required by 10 CFR.50.71(e)
(Section E8.5).
x
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URI 50-327, 328/96 13 06 Closed Evaluate the Adequacy of the Design 1
l of the Turbine Impulse AFW Actuation j
Circuitry (Section E8.7).
l IFI 50 327, 328/96 02-06 Closed Evaluation of Corrective Action
Taken on TVA's Fire Protection Audit
Findings (Section F8.2).
VIO 50 327, 328/EA 96 269 Closed Inadequate Surveillance Procedures .
for Fire Hose Stations Inside
-
01043
Reactor Buildings (Section F8.5).
VIO 50 327, 328/EA 96 269 Closed Failure to Perform Surveillance
01033 Inspections of Fire Barrier
Penetration Seals (Section F8.6).
URI 50 327, 328/96 04 12 Closed EA 97-085, Case No.2 96 015,
Falsification of Rad Material
Receipt Survey Records (Section R8).
The following item was closed by an in office review after being inadvertently
-omitted from a late 1996 inspection.
IFI 50 327, 328/95 03 09 CLOSED Incorporation of instrument
inaccuracy into tests (Section
E.8.6).
( Discussed
lype Item Number Status Description and Reference
VIO 50 327, 328/EA 96 269 OPEN Inadequate Identification and
01013 Resolution of Fire Protection
Deficiencies (Section F8.3).
VIO 50 327, 328/EA 96 269 OPEN Inoperable CO2 System (Section
01023 F8.4).
4
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SYNOPSIS
l
- The U.S. Nuclear Regulatory Commission (NRC), Office of Investigations. Region
l II, initiated this investigation on May 8,1996, to determine if a health
physics technician, at the Tennessee Valley Authority's (TVA) Sequoyah Nuclear
Plant, falsified a survey record which had been requested by NRC inspectors.
Licensee management referred the matter to the TVA Office of the Insmetor l
General (OIG) after the technician, on his own volition, confessed t1at he had i
filled out a form subsequent to his survey so it could be presented to NRC {
j. inspectors.
A review of the TVA/0IG investigative report and associated documents was conducted
by the Office of Investigations. It was substantiated that two health physics
l technicians deliberately conspired to deceive NRC inspectors with a false survey
l- record. It was further substantiated that their immediate supervisor deliberately
L made a false entry on a computer record without having a written document to support
the data.
1
Case No. 2 96 015
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Attachment
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