ML20209E283
| ML20209E283 | |
| Person / Time | |
|---|---|
| Site: | Catawba  |
| Issue date: | 07/01/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20209E273 | List: |
| References | |
| 50-413-99-03, 50-413-99-3, 50-414-99-03, 50-414-99-3, NUDOCS 9907140196 | |
| Download: ML20209E283 (36) | |
See also: IR 05000413/1999003
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U.S. NUCLEAR REGULATORY COMMISSION
REGION 11
Docket Nos:
50-413,50-414
License Nos:
Report Nos.:
50 413/99-03,50-414/99-03
Licensee:
DJke Energy Corporation
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Facility;
Catawba Nuclear Station, Units 1 and 2
Location:
422 South Church Street
Charlotte, NC 28242
Dates:
' April 25 - June 5,1999
Inspectors:
D. Roberts, Senior Resident inspector
R. Franovich, Resident inspector .
M. Giles, Resident inspector
D. Billings, Resident inspector - Oconee (Section E8.1)
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M. Franovich, Resident inspector - McGuire (Section 01.4)
8. Holbrook, Project Engineer (Sections M8.1 - M8.5)
W. Kleinsorge, Reactor Inspector (Sections M8.6 - M8.9)
R. Moore, Reactor inspector (Sections E2.1, E8.2 - E8.6)
E. Testa, Senior Radiation Specialist (Section R1.1)
P.. Tam, Senior Project Manager, NRR (Section E3.1)
K. VanDoorn, Senior Resident inspector - Watts Bar (Section M2.1)
Approved by:
C. Ogle, Chief
Reactor Projects Branch 1
Division of Reactor Projects
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Enclosure
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9907140196 990701
ADOCK 05000413
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$XECUTIVE SUMMARY
Catawba Nuclear Station, Units 1 and 2
NRC Inspection Report 50-413/99-03,50-414/99-03
This integrated inspection included aspects of licensee operations, maintenance, engineering,
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~ : and plant support. The report covers a six-week period of resident inspection, as well as the
results of announced inspections by regional reactor safety inspectors, other resident
inspectors, and an NRR senior project manager. [ Applicable template codes and the
assessment for items inspected are provided below.)
Operations
Several operational activities, including a response to a full turbine-generator load
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rejection event; reactor shutdown and startup operations; reactor coolant system
reduced inventory and midloop draining evolutions; and refueling activities, were
generally characterized by sai'ety-conscious operations, proper adherence to
procedures, and reliable equipment performance. For both reactor coolant system
. draindown evolutions, the inspectors observed effective controls and clear
communications. (Section 01.2; [1A,18,2A - POS])
Unit 1 was in the Mode 5 loops filled condition for approximately 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> without the
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redundant train of decay heat removal capability required by Technical Specification 3.4.7. The inspectors identified no immediate safety concerns during the event, in that
adequate core cooling was always available from the opera +ing A train. This event was
identified after operators noticed approximately 6,000 gallons of refueling water storage
tank contents had unexpectedly drained into the reactor coolant system through the
residual heat removal system. (Section 01.3; [1 A,1C - LER])
Following the Unit 2 main generator breaker motor-operated disconnect failure and full
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turbine load rejection event on May 3,1999, generator protective relays responded in
accordance with their design. The primary and secondary system plant equipment
functioned property, and the licensee's transient review of affected equipment and plant
performance during and following the 100 percent turbine-generator load rejection was
adequate. Operator actions to restore control rods above rod insertion limits were
performed promptly and in accordance with plant procedures and Technical
Specification requirements. (Section 01.4; [18,2A - POS))
A non-cited violation was identified for failing to properly implement Technical
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Specification surveillance requirements for verifying only one centrifugal charging pump
or one safety injection pump operable during low temperature overpressure protection
conditions. This resulted from a licensee-identified Technical Specification conflict that
had existed since both units were licensed. (Section 08.1; [28,4C - NCV))
-A non-cited violation was identified for the licensee's failure to promptly identify and
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correct a Technical Specification conflict regarding emergency core cooling pump
operability requirements during low temperature overpressure protection conditions. The
licensee had an opportunity in 1988 to resolve the discrepancy when it switched its
philosophy for Technical Specification 3.5.3 adherence from that of complying with the
associated surveillance requirement to complying with a conflicting footnote in the
limiting condition for operation. (Section 08.1; [58, SC - NCV))
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Maintenance
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The licensee identified missing ice basket screws in the Unit 1 ice condenser in excess
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of vendor-provided acceptance criteria. Appropriate repairs were initiated and licensee
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evaluations were considered adequate. Evaluation for continued operation of Unit 2 was
also adequate. An unresolved item was opened for the inspectors to follow the
licensee's actions to determine the root cause for the missing screws and any related
Technical Specification operability implications. (Section M2.1; [2A,48 - URl])
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A non-cited violation was identified regarding operation outside Technical Specifications
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with respect to analyzing grab samples at an incorrect lower limit of detection. (Section
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M8.4; [1C - NCV))
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A non-cited violation was identified for failure to test the auxiliary building filtered exhaust
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system in accordance with Technical Specification 4.7.7d.3. (Section M8.5; [28,4C -
NCV))
Enaineerina
Engineering demonstrated effective plant technical support related to the identification,
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investigation, and resolution of the degraded safety-related assured water supply for the
auxiliary feedwater pumps in May 1999. (Section E2.1; (48, SA, SC - POS; 2A - NEG])
Based on in-office review of the licensee's April 1,1999, annual summary on 10 CFR
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50.59 changes, onsite review of select 10 CFR 50.59, evaluations, and audit of the
licensee's procedures, the inspector concluded that the licensee complied with the
provisions of this regulation for the changes listed in the annual summary report. The
inspector also found the licensee's summary report for 1998 changes concise,
informative, and accurate. (Section E3.1; (48 - POS))
The Year 2000 (Y2K) checklist was completed per Temporary Instruction 2515/141.
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Overall, the Y2K project was about 90 percent complete and the contingency plan was
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about 90 percent complete. (Section E8.1; (4A - MISC))
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An apparent violation was identified regarding inadequate design implementation of 1987
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generic steam generator tube rupture analysis. (Section E8.2; (4A - eel])
A non-cited violation was identified regarding inadequate work instructions for post-
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maintenance testing of containmen .olation valves. (Section E8.4; [2B - NCV])
Plant Suoport
The inspectors identified a non-cited violation for failure to properly tag and identify
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equipment, in the waste monitor tank building, with loose contamination in excess of
procedural limits. (Section R1.1; [1C - NCV])
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Radioactive material was labeled appropriately and areas were properly posted.
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Personnel dosimetry devices were appropriately worn. Radiation work activities were
appropriately planned. (Section RI.1; [1C - POS])
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Report Details
~~ Summary of Plant Status
Unit 1 began the inspection period in Mode 5; the unit was in the fourth day of the End-Of-Cycle
11 refueling outage (1EOC11) Mode 6 refueling operations began on April 26,1999, and core
reload was completed on May 11,1999. The unit remained shut down until May 23,1999, when
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reactor startup was initiated. The unit was tied to the offsite electrical grid on May 24,1999, and
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power ascension activities commenced. On May 28,1999, operators reduced reactor power
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from 80 percent to 65 percent in response to a main generator bushing high temperature
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indication and oscillating stator cooling (KG) water flow indications to the bushing. Following
repairs, the power escalation was resumed and the unit reached 100 percent power on May 29,
1999. The unit operated at full power for the remainder of the inspection period.
Unit 2 began the inspection period operating at 100 percent power. On May 3,1999, a main
generator protective relay (neutral ground) c'aused the main transformer power circuit breakers
to open, resulting in a full turbine load rejection. This caused a turbine runback, which resulted
in the reactor being reduced to 13 percent power. A failed motor-operated disconnect (MOD)
associated with main gener/.or power circuit breaker 28 caused the ground protection relay
actuation. Operators further reduced reactor power to eight percerit (with the unit off-line) to
facilitate troubleshooting and repairs of the MOD. On May 4,1999, with reactor power stable at
eight percent, all three auxiliary feedwater (CA) pumps were declared inoperable as a result of
degraded flow from the assured suction so' urce, the nuclear service water (RN) system. The
degraded flow condition was caused by tubercle fouling of the RN piping. The licensee isolated
RN flow to the turbine-driven auxiliary feedwater (TDAFW) pump and declared the MDAFW
pumps operable. Operators performed a TS-required shutdown to Mode 4 on May 5,1R to
facilitate cleaning of the RN to CA system piping. During this fo:ced outage, the MOD for the
main generator breaker was replaced and the RN to CA piping was cleaned and successfully
tested. On May 15,1999, the reactor was taken critical and reached Mode 1 with a power
increase to approximately nine percent power. On May 16, an alarrn was generated during a
main turbine speed increase to 1800 rpm, indicating the presence of a generator field ground
fault. The main turbine was tripped and the unit was shutdown to Mode 4 to allow disassembly,
troubleshooting, and repair of the main generator. Testing revealed a fault at the midsection of
the generator rotor. The fault was attributed to a sliver of aluminum suspected of originating
from a rotor wedge. The sliver was removed, miscellaneous generator repairs were completed,
and generator reassembly commenced on May 27,1999. The unit remained in Mode 4 through
the end of the inspection period.
l. Operations
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Conduct of Operations
01.1 General Comments (71707)
The inspectors conducted frequent control room tours to verify proper staffing, operator
attentiveness, effective communications, and adherence to approved procedures. The
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inspectors: (1) attended operations shift turnovers and site direction meetings to maintain
awareness of overall plant status and operations; (2) reviewed operator logs to verify
operational safety and compliance with TS; (3) periodically reviewed instrumentation,
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computer indications,.and safety system lineups, along with equipment removal and
restoration tagouts, to assess system availability; (4) reviewed the TS Action item Log for. --
both units daily for potential entries into limiting conditions for operation (LCO) action
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statements; (5) conducted plant tours to observe material condition and housekeeping:
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and (6) routinely reviewed Problem Identification Process reports (PIP) to ensure that
potential safety concerns and equipment problems were resolved. The inspectors
identified no major problems from the above reviews.
01.2 Plant Operational Activities - General Comments (71707)
The inspectors observed several operational activities including a response to a full
turbine-generator load rejection event, reactor shutdown and startup operations, reactor
coolant (NC) system reduced inventory and midloop draining evolutions, and refuelmg
activities. For both NC system draindown evolu+ ions, the inspectors observed effective
control and clear communications. The inspectors confirmed that the NC system water
levelinstrumentation was reading within the allowable tolerances of the draindown
procedure. No deviations from administrative and' regulatory requirements were noted;
however, premature removal of communications equipment from containment and
incorrect installation of a steam generator nitrogen purge hose extended the time that the
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unit was in midloop perhaps by as much as an hour. The inspectors considered these
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delays in midloop, a risk-significant configuration, canecessary and avoidable. Overall,
the operational activities observed were characterized by safety-conscious operations,
proper adherence to procedures, and reliable equipment' performance.
01.3 Unit 1 Residual Heat Removal (ND) Train B inoperable Durino Cold Shutdown
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Inspection Sqnoe (71707. 03702. 40500)
The inspectors responded to the control room following notification that the Unit 1 ND
system train B had been declared inoperable due to an interlock that prevented a critical
1B ND pump suction valve from opening while the unit was in cold shutdown (Mode 5).
The inspectors verified that the plant was in a safe condition with the redundant train of
ND operable and providing adequate core cooling. The inspectors also assessed overall
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TS implications and the operators' attempts to restore the B train to operable status.
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This assessment included a preliminary review of operating procedures,. review of plant
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parameter trends, discussions with operators, and review of clearance tagout paperwork
to determine the safety significance of the event.
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Observations and Findinas
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On April 26,1999, at 10:00 a.m., the inspectors were informed by operators that Unit 1
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Train 8 of the ND system had just been declared inoperable due to an interlock that
preventer, cperators from opening valve 1ND-368, which supplied ND pump 1B suction
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piping from NC loop C hot leg. The interlock was associated with valve 1NI-1368, an ND
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pump discharge valve to the safety injection (NI) pumps (a flow path used for long-term
core cooling during post-accident recovery operations), which had been shut and de-
energized as part of an Ni system clearance tag-out boundary for outage work.
Operators discovered the problem during NC system draining activities after
approximately 6,000 gallons of water was inadvertently gravity-fed into the NC system
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from the refueling water storage tank (FWST) to which the 1B ND pump had been
aligned. Failed attempts to realign the ND pump to the NC system C loop were
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terminated when operators realized that valve 1ND-368 could not be operated from the
control room with power removed from interlocked valve 1NI-1368. Operators, who had
already terminated the NC system draindown evolution, isolated the ND pump from the
FWST and restored power to the NI valve. At approximately 11:05 a.m., operators
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successfully opened 1ND-368 (and in-series valve 1ND ?7A) and restored the second
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train of ND to operable status.
The inspectors, who were in the control room during the event, initially considered that
operators were slow to realize the connection between the interlocked valves 1ND-36B
and 1Ni-136B, which delayed the restoration of the second train of ND to operable
status. Discuscions with operators indicated that their response was deliberately paced
because restaration involved the removal of the clearance tag on the NI valve, which
was part of a maintenance work boundary. According to the operators, had there
been an actualloss of residual heat removal function, a more timely response would
have occurred in accordance with abnormal operating procedure AP/1/A/5500/19,
Revision 32, Loss of Residual Heat Removal System. The inspectors noted that the time
to core boilin0 had been calculated earlier that day to be approximately one hour and
verified that the A train of ND, which was in service at the time, was supplying adequate
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core cooling. Given the circumstances, the inspectors concluded that the operators'
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response was reasonable. However, the inspectors, upon reviewing the abnormal
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operating procedure, noted that it did not contain references to the loop suction valve
interlocks that could potentially prevent operators from opening the valves from the
control room even during a loss of ND event. The licensee took this procedural concern,
as well as other procedural issues associated with the valve interlocks, into consideration
during its root cause/ corrective action determination process conducted following the
incident.
Technical Specification 3.4.7 required, with the unit in Mode 5 (loops filled condition), that
one ND pump be operable and in service, and either a redundant ND pump be operable
cr at least two steam generators have water levels above 12 percent narrow range level
indication. The NI system tagout that de-energized valve 1NI-1368 was implemented at
apprcximatey 11:15 p.m. on April 22,1999. All four steam generators were drained to
less than 12 percent narrow range indication as of approximately 6:55 a.m. on April 25,
1999. The incpectors determined, as did the licensee, that a non-compliance with TS 3.4.7 had occurred in tnat the required redundant decay heat removal function had been
inoperable from 6:55 a.m. on April 25,1999, until 11:05 a.m. on April 26,1999, a period
of approximately 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br />. The TS required immediate restoration to operability if the
required redundancy was lost.
The licensee had just completed its review of the safety significance and root cause of
the problem at the close of the inspection period. This w- documented in Licensee
Event Report (LER) 50-413/99-07-00, Operation Prof
v Technical Specification 3.4.7 Caused by an Inoperable Train of Residual He
<al due to inadequate Work
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Sequencing. The inspectors planned to complete the
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lead to this event, as well as any regulatory and safety %nificance, upon addressing the
LER in a future inspection report.
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Conclusions
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Unit 1 was in the Mode 5 loops filled condition for approximately 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> without the
redundant train of decay heat removal capability required by TS 3.4.7. The inspectors
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identified no immediate safety concerns during the event, in that adequate core cooling
was always available from the operating A train. This event was identified after
operators noticed approximately 6,000 gallons of FWST water had unexpectedly drained
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into the NC system through the ND system. This event was documented in a LER that
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will be addressed in a future inspection report.
O1.4 Unit 2 Full Load Rejection and Turbine Runback
a.
Inspection Scope (71707. 93702. 40500)
On May 3,1999, at 6:15 p.m., a Unit 2 main generator protection lockout (neutral ground
fault) relay actuated and caused an automatic turbine runback f om 100 percent to
approximately 10 percent power. The inspectors responded to the control room to verify
compliance with TS and to assess control room operators' response to the event. The -
inspectors also performed a post-event review and evaluation of the licensee's plant
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transient assessment. The inspectors reviewed operator logs, operator aid computer
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(OAC) trends, related abnormal operating procedures, operator training materials, and
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design basis documentation. Discussions with involved plant operators we're also
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conducted.
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Observations and Findinas
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On May 3,1999, Unit 2 experienced c full turbine-generator (TG) load rejection with the
reactor at 100 percent power. At approximately 6:15 p.m., Unit 2, Zone G (main
generator electrical protection) neutral ground relays 59GN1and 59GN2 actuated and
caused both generator output breakers 2A and 2B to open. This resulted in the TG
being separated from the offsite electrical grid, which caused a turbine runback. The
inspectors responded to the control room and observed operator recovery actions. In
accordance with abnormal operating procedure AP/2/A/5500/03, Revision 18, Load
Rejection, operators were borating the NC system in order to restore the control rods
above the rod insertion limits. The inspectors verified that these actions were performed
within TS time limits. As designed, the reactor and turbine did not trip during the event.
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The transient lasted approximately ten minutes. Reactor power stabilized at
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approximately eight percent. The unit was subsequently shut down at 5:09 a.m. on
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May 5,1999, as a result of unrelated concerns over CA system operability (documented
in Section E2.1 of this inspection report). The licensee determined that the Z-phase of
the motor-operated disconnect to the 2A main transformer had failed and caused the
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electrical fault and that the mah generator protection lockout relays actuated properly.
The inspectors reviewed electrical schematics and observed the failed MOD and
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determined that the licensee reached a sound conclusion. The failed MOD was repaired
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on May.7,1999; however, the unit remained shutdown pending restoration of the CA
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system.
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The inspectors reviewed plant data indicating that all three pressurizer power-operated
relief valves opened at their setpoints. as expected, due to the initialincrease in NC
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system pressure and pressurizer levei following the TG load rejection. The PORVs were
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open for less than 3 seconds. In the secondary system, the steam condenser dump and
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atmospheric dump valves cycled following the load rejection as expected. The
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inspectors confirmed that neither the pressurizer nor steam generator safety valves
cycled during the event. , Pressures in both systems remained below the safety valve
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.setpoints. The rod control system was in automatic and responded as designed to the
mismatch between NC system average temperature (Tavg) and reference temperature
(Tref). Following the event, the licensee determined that the event was initiated by a
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degraded connection to MOD switch 2AG. An investigation was in progress at the end
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of the inspection period to determine the root causes of the event. The inspectors
determined that the licensee's post-transient review was performed in accordance with
PT/0/A/4150/02, Revision 3, Transient Investigation.
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Cpo_nclusions
The inspectors concluded that, following the MOD failure and full turbine load rejection
event, generator protective relays responded in accordance with their design. The
primary and secondary system plant equipment functioned properly, and the licensee's
transient review of affected equipment and plant performance during and following the
100 percent turbine-generator load rejection was adequate. Operator actions to restore
control rods above rod insertion limits were performed promptly and in accordance with
plant procedures and TS requirements.
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Operational Status of Facilities and Equipment
O2.1 Final Unit 1 Containment Walkdown inspection - General Comments (71707)
The inspectors conducted a final closecut inspection of the Unit 1 containment building
(both lower and upper elevations) prior to the unit entering Mode 4 conditions on
May 18,1999. Minor housekeeping items were identified to the licensee. The
-inspectors concluded these items did not pose an operability concem for the ECCS
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Operations Organization and Administration
06.1 World Association of Nu_c_I_ ear Operators (WANO) Report Review- General Comments
(71707)
During the inspection period, the inspectors reviewed the WANC report for a visit
conducted during July 1998. The final report was not available to the NRC until
April 1999. The inspectors detarmined that the results of the WANO evaluations were
generally consistent with the results of inspections conducted by the NRC. No new items
for followup were identified.
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Miscellaneous Operations issues (92901)
08.1 (Closed) LER 50-413/97-004-00: Inadequate Surveillance Resulting From a Conflicting
~ Technical Specification Limiting Condition for Operation and Surveillance Requirement
On June 6,1997, the licensee identified a conflict between ECCS Subsystems TS LCO 3.5.3 and TS Surveillance Requirement (SR) 4.5.3.2. A footnote in the Mode 4 TS LCO
for ECCS with Tavg less than 350 degrees Fahrenheit (F) permitted a maximum of one
centrifugal charging pump (CCP) and one safety injection (NI) pump to be operable
when an RCS cold leg temperature was below 285 degrees F [ Low Temperature
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Overpressure Protection Condition (LTOP)); whereas the SR required that al/ charging
and NI pumps, except the one operable charging pump, be demonstrated inoperable by
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. verifying the motor. circuit breakers were secured in tne open position or the pumps'
discharge piping to the NC system was isolated by two closed isolation valves.
The licensee determined that the TS LCO/SR conflict had existed since issuance of the
Catawba Unit 1 and 2 licenses in 1985 and 1986, respectively. However, the licensee's
surveillance test procedure PT/1(2)/A/4600/02D, Revision 0, Mode 4 Periodic
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Surveillance items, was initially setup for this TS to verify compliance with the more
conservative SR. Therefore, the licensee's periodic test program properly implemented
the TS SR until 1988, when the licensee changed its interpretation of TS compliance for
this case to mean adherence to the LCO requirement rather than the SR. After 1988,
the licensee's surveillance program verified up to one CCP and one Ni pump were
operable below 285 degrees F NC system temperature, contrary to the SR.
The licensee's review of historical records revealed that although the SR had not been
implemented properly after 1988, this was of no consequence until March 1991 because
the pump alignment was correctly controlled by Mode 4 operating procedures, which
. allowed only one CCP and no NI pumps to be operable. In March 1991, operating
procedure OP/1(2)/A/6200/06, Safety injection System, was revised to allow both.a CCP
and an NI pump to be operable to reduce the probability of Ni system failure on demand.
This change was in response to interim guidance stemming from concerns raised
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following a Westinghouse Owners Group shutdown loss of coolant accident analysis.
Upon identification of the TS conflict in June 1997, the licensee revised procedure
OP/1(2)/A/6200/06 on June 12,1997, to have operators disable the Ni pumps in
accordance with the SR. During its historical review, the licensee did not search for
specific incidents in Mode 4 where the TS SR pump restriction was compromised, but
assumed that since operating and surveillance procedures allowed it, and plant
operators would not have intentionally deviated from those procedures, that numerous
violations of the one-pump restriction occurred any time the plant was shutdown in
Mode 4 during LTOP conditions between March 1991 and June 1997, when the conflict
was identified.
The licensee later requested and received a TS amendment to eliminate the conflict.
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License amendment Numbers 170 (Unit 1) and 162 (Unit 2) were issued on
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August 28,1998. The amendment also included a change to TS 3.4.9.3 to restrict the
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number of ECCS pumps capable of injecting into the reactor coolant system during plant
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operation in Modes 4 and 5 and Mode 6 when the head is on the reactor vessel. Since
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this provision previously had not been included in TS 3.4.9.3, LTOP precautions were
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non-conservative in that they had not restricted ECCS pump operability in Modes 5 or 6.
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Applicable station procedures for both units were revised to ensure compliance with the
SR and the newly revised LCO. In January 1999, the licensee implemented new
improved TS which relocated all LTOP requirements into one specification, TS 3.4.12.
The inspectors verified that applicable LTOP instructions were properly incorporated into
the improved TS.- The inspectors verified that current operating and surveillance
procedures restrict operability to one CCP or one Ni pump for LTOP conditions.
The licensee determined that the safety significance of allowing a charging and an NI
pump to be operable during low temperature conditions in the past was mitigated by the
fact that adequate overpressure protection was provided by operable relief valves in the
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ND system, to which the NC was always procedurally aligned prior to reducing system
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temperature to 285 degrees F during plant cooldown. The inspectors verified that the
Updated Final Safety Analysis Report, Sections 5.2.2.2 and 5.4.7.1, described this
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capability for the ND system suction relief va;ves The inspectors also confirmed that
operating procedures required operators to ahgn the NC system to at least one train of
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ND prior to reaching LTOP temperatures. The licensee indicated that it would pursue
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another TS amendment that will allow a second pump to be operable and officially credit
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the ND suction piping relief valves as an alternate means of providing LTOP protection.
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This would be consistent with TS at the licensee's McGuire station.
Considering the fact that the NC loop suction valves are not currently credited in the
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licensee's TS or its basec for the LTOP function. the inspectors concluded that the
licensee failed to comply with the intent of the TS when P allowed two pumps to be
capable of injecting into the NC system during low temperature conditions. The
inspectors considered the licensee's past failures to verify the operability of only one
CCP during LTOP conditions to be a violation of TS SR 4.5.3.2. This Severity LevelIV
violation is being treated as a Non-Cited Violation (NCV), consistent with Appendix C of
the NRC Enforcement Pol;cy. This violation is in the licensae's corrective action program
as PIP 0-C97-1639. It is identified as NCV 50-413,414/99-03-01: Failure to Satisfy TS
Surveillance Requirement 4.5.3.2 by Verifying Only One CCP or One NI Pump Operable
During LTOP Conditions.
Concerning the previously conflicting TS, the , inspectors determined that the licensee's
initial corrective actions in 1988 were inadequate to correct the discrepancy between the
TS LCO and the SR. The licensee had an opportunity to identify tha TS conflict as an
adverse condition and correct it when surveillance procedures were modified to reflect
the LCO requirement rather than the SR. This resulted in the licensee being in
noncompliance with the TS SR for both units intermittently for nine years, during six of
which two pumps (a CCP and an Nl pump) were potentially capable of injecting into the
NC system and causing mass addition transients during LTOP conditions. The
licensee's failure to take prompt corrective actions is considered a violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions. This, Severity Level IV violation is
being treated as a NCV, consistent with Appendix C of the NRC Enforcement Policy.
This violation is in the licensee's corrective action program as PIP O-C9A 1G39. It is
identified as NCV 50-413,414/99-03-02: Failure to Take Prompt Cern stive Actions to
Resolve TS Conflict Regarding LTOP Pump Operability Requirements
This LER is closed.
08.2 LOpen) Unresolved item (URI) 50-413.414/98-01-01: Basis for Five-Minute Period of
Control Room Area Ventilation (VC) System inoperability with Compensatory Actions
This issue involved the licensee's use of a compensatory action to maintain the VC
system " operable" during planned maintenance that involved a breach of the control
room pressure boundary. The compensatory action involved provisions to ensure that
the pressure boundary would be restored within five minutes of a safety injection signal,
a radiation release within the plant, a high chlorine alarm at a VC systert intake, or the
sensing of chlorine at the work area. The licensee maintained that this provision would
allow the system to perform its design basis function within the time assumed in the
plant's accident analysis. The inspectors were concerned that the licensee's practice
may have introduced a new failure mechanism (failure to restore the pressure boundary
in a timely manner), which would require NRC staff review of the associated unreviewed
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safety question. On July 28,1998, Task interface Agreement (TIA) 98008 was provided
to the NRC's Office of Nuclear Reactor Regulation (NRR) to determine if manual
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compensatory actions could be relied upon to maintain the VC system operable for a -
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similar issue at he McGuire Nuclear Station. A response to the TIA was provided to the
NRC's Region 1. Office on March 31,1999 (please refer to inspection Report
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Attachment), incicating that the licensee's reliance on the compensatory measures
constituted a vio ation of TS. In response, the licensee has questioned the regulatory
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basis of NRR's p )sition. A meeting to discuss the differing perspectives was scheduled
for June 1S,1995. Pending resolution of the compliance issue, the licensee has placed
the VC s9 stem cc Tipensatory action on hold. The NRC's Region 11 Office will review the
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results of the TIA 1 a future inspection report. This item remains open.
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11. Maintenance
M1
Conduct of Mainte iance
M1.1 General Comments )n the Conduct of Maintenance and Surveillance Activities (62707.
61726)
The inspectors obser ed all or portions of the following maintenance and surveillance
activities:
MP/0/A7150/0t 5, Revision 20, Ice Basket Weight Determination
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SM/0/A/8510/0( 7, Revision 7, Ice Basket Corrective Maintenance and Tracking
SM/0/A8510/001, Revision 1, Ice Condenser FME Inspection
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MP/0/7150/006, I tevision 15, Ice Condenser Lower inlet Doors Testing and
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Corrective Mainte lance
IP/1/A3222/0958, Revision 3, Procedure for RTD and Thermocouple Cross
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Calibration by AM!: with Reactor Trip Breakers Closed or Open
IP/0/3220/038, Res sion 8, AMS Control Rod Drop Timing Test
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PT/1/A/4350/002A, Revision 91, Diesel Generator 1 A Operability Test
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The above maintenance anc surveillance activities were generally conducted with proper
adherence to procedures an i appropriate adherence to equipment calibration and
radiation protection requirem ints. Minor housekeeping items were identified by the
inspectors during a final Unit 1 ice condenser walkdown inspection which indicated a
need for more diligence in the area of foreign material controls following ice condenser
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maintenance.
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M2
Maintenance and Material Condition of Facilities and Equipment
M2.1 Missina Ice Condenser Basket Screws
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.insoection Scoce (62707)
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The inspectors reviewed the licensee's action regarding missing ice Condenser (IC)
basket screws in Unit 1. This included observation of 10 basket inspections including
external and intemal camera inspections, review of basket servicing infc tmi '
.1 for the
1EOC11 refueling outage a7d tne last outages for both u.7its, review of seiected
inspection data sheets for:tt e 1EOC11 outage, review of selected inspection data sheets
for the previous Unit 2 outage, review of PlP 1-C99-1734, review of a justi9 cation for
continued operation (JCO).fter Unit 2, and discussions with engineering and craft
personnel,
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Observations and Findinas
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On May 5,1999, the licensee discovered that certain iC baskets had screws missing
from basket coupling rings. The licensee performed an internal camera inspection for
every basket that was serviced (emptied and refilled). Maintenance personnel noted that
some. screws were missing and others had never been installed (no hole was evident
through the basket surface). This was reported and a PlP was generated.
The original 48-foot long basket assemblies are designed with four 12-foot long sections
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held together with three coupling rings. Each section is attached to the coupling ring with
24 screws,12 in each of the upper and lower joints. The licensee had established an
acceptance criteria of no more tnan two missing screws .in either joint. This was based
on guidance contained in Westinghouse Nuclear Safety Advisory Letter (NSAL)98-012.
The licensee identified a total of ni7e baskets which did not meet the acceptance criteria.
Six of these baskets were in Bay 13. Most unacceptable joints had three or four screws
missing; twn joints had six missing screws Six of the baskets were from Row 9 (inside
wall); two were frorn Row 1 (outside wall) and one was from Row 2. A total of 42 screws
were missing in the unacceptable baskets, of which 2.3 had never been installed. Two or
!ess screws were found missing in 43 additionaljoints. In ac'dition,11 screw heads were
faund missing and four loose screws were noted, but these joints did not fail the
licensee's inspection criteria. The licensee initiated cxternali7spections of all Bay 16
baskets that had not been serviced. This resulted i- :.100 percent inspection for
cot.pling screws in Bay 16 except for nine screws, v .ich were unable to be viewed due
te frast. A total of 393 basket camera inspections were performed; approximately two-
thirds of which were in Row 9. The licensee initiated rr i s of each of the unacceptable
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baskets on Unit 1 and initiated a JCO for Unit 2, whict sa operating in Mode 1 at the
time oithe Unit 1 findings.
The inspectors noted that the camera inspections were thorough and provided clear
resolution. Personnel were knowledgeable and sensitive to observing for missing or
broken screws. Westinghouse provided.an engineering judgement evaluation
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(EDRE-EMT-1153) for the as-found Unit 1 condition in a letter (DPC-99-034) dated
May 13,1999. This evaluation addressect the concem regarding the possible ejection of
a basket column or portion of a column and subsequent damage to the IC or other
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containment equipment. The evaluaticn stated, "The Westinghouse evaluation has
concluded / based upon existing previous a7alysis of unpinned ice basket columns and
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ice baskets with missing / broken ice basket sheet metal screws, and the results of
various test reports that a significant safety issue does not exist under the above
described out of design basis condition. The ice basket column or portions of that
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column cannot separate and eject from the ice bed with at least 6 of 12 sheet metal
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screws present at any coupling ring or bottom attachment ring assembly connection."
Previous testing was referenced that showed an individual screw could carry a load of
1208 pounds. Due to decreasing loads with basket height during a postulated event, the
load at the first coupling ring was calculated to be 987 pounds versus a load at the
bottom of the basket of 1560 pounds. Therefore, significant margin to failure existed
even with six missing screws. Previous analysis had also shown that only 30 percent of
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the baskets could pass through the intermediate door structura and the upper deck
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structure would stop any ejected baskets. Baskets located in Rows 1 and 9 would be
prevented from ejection by the intermediate structure. Possible damage to air handling
units had been previously evaluated as not being a concern. In addition, the licensee
evaluated the statistical validity of the Unit 1 inspection sample. This analysis showed
that the number of samples and distribution was statistically valid to assure the failure
rate (approximately 2.3 percent) was adequately determined. The licensee's evaluations
were considered reasonable and licensee actions were considered acceptable.
The licensee was still performing an evaluation to determine root cause, long-term
corrective actions, and TS operability /reportability implications at the end of the
inspection period. The inspectors considered, given the recent issues regarding ice
condenser material condition documented in NRC Inspection Reports (irs)
50-413,414/98-13,9d-16, and 99-11, and the outstanding questions regarding TS
operability, that this issue warranted further inspector review and will be tracked as
URI 50-413/99-03-03: Review of Missing Ice Basket Coupling Screws in the Unit 1 Ice
Condenser.
The licensee's Unit 2 JCO included an evaluation of Unit 2 inspection results from the
previous outage (Fall 1998), interviews of personnel and supervisors involved in the
previous inspection, and the Unit 1 statistical analysis and Westinghouse evaluation
desenbed above. The inspectors reviewed selected inspection data sheets, interviewed
several inspection personnel, and reviewed licensee documentation of interviews. The
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Unit 2 data showed that 72 baskets had missing screws in the top rings and several
missing screws were identified in stiffener rings. However, no missing screws were
found in coupling rings out of a sample of 219 baskets inspected. The interviews
inoicated that Unit 2 inspection personnel were sensitive to the potential for missing
screws during the previous inspection, which was supported by the fact that some of the
came individuals had identified the problem in Unit 1 in May 1999. Also, NRC
observations of camera inspections during the corresponding Unit 1 inspection
demoristrated that the inspections were thorough. The licensee's evaluation for
continued operation of Unit 2 was considered reasonable.
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Conclusions
b licensee identified missing ice basket screws in the Unit 1 IC in excess of vendor-
provided acceptance criteria. Appropriate repairs were initiated and licensee evaluations
were considered adequate. Evaluation for continued operation of Unit 2 was also
adequate. An unresolved item was opened for the inspectors to follow the licensee's
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actions to oetermine the root cause for the missing screws and any related past
operability implications. ,
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M8
Miscellaneous Maintenance issues (92902,92700)
During the review of the LERs discussed below, the inspectors identified that some root
causes and LER details were not thorough. For example, LER 50-413/98-013. Revision
1, did not explain why the procedure did not contain Technical Specification (TS)
requirements. Additionally, LER 50-414/98-001, did not address the fact that
established administrative control barriers failed to prevent a TS violation. LER 50-
413/98-009, was not clear or detailed as to the circumstances surrounding the
improperly set manual air register. These observations were discussed with licensee
managenient. The inspectors were informed that licensee management had recognized
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the need for improving LER quality and had initiated corrective actions. The inspectors
noted that an event investigation team hrM oviewed recent ventilation system issues
and LERs and had identified several deficiencies and made numerous corrective action
recommendations to improve the process. Corrective actions were identified dealing
with procedure usage, timeliness of corrective actions, root cause determinations, LER
quality and detail, personnel performance issues, training, and procedure revisions. The
inspectors observed that the corrective actions identified were either being implemented
or under review for implementation. The corrective actions were thorough, detailed, and
addressed the deficiencies identified during the LER review.
M8.1 (Closed) LER 50-413/98-007: Missed Technical Specification Surveillance on
Containment Penetration Testing Due to a Literal Compliance issue
This licensee-identified issue is discussed in Section M8.1 of IR 50-413,414/98-07, and
is the subject of NCV 50-413,414/98-15-04. The inspectors observed that corrective
actions for the LER were documented in PlPs 0-C98-2066,0-C98-2414, and 0-C98-
2366. The inspectors noted that corrective actions were reasonable and appropriate and
were either completed or in the process of being implemented. Based upon the
inspectors' review of ficensee actions, this LER is closed.
M8.2 (Closed) LER 50-414/98-001: Technical Specification 3.0.3 Entry Due to an inoperable
Annulus Ventilation System
This LER documented a licensee-identified ever t where the Unit 2 containment annulus
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ventilation system was determined to be increrable for a period of five and one-half
hours on March 12 and 13,1998, due to a blocked-open annulus ventilation boundary
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door. With both trains inoperable, TS 3.0.3 required a unit shutdown within the seven-
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hour time frame established in the specification. In this case, the door was unblocked
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and the ventilation system was declared operable prior to expiration of the TS-required
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time to shutdown. This event is discussed in Section 01.3 of IR 50-413,414/98-03 which
identified that the licensee's root cause determination concluded that the cause of the
event was an inadequate process for determining what compensatory actions were
required to perform work on the door. However, the inspectors noted that the licensee's
root cause analysis did not take into account that there were three clear statements in
the compensatory action manual prohibiting the work. The inspectors determined that
the root cause of the event was personnel error for failure to follow the guidance in the
compensatory action manual.
The inspectors concluded that the failure to follow the compensatory action manual
(required to support maintenance of a Regulatory Guide 1.33 system) was a violation of
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TS 5.4.1. This was considered a violation of minor significance in accordance with
Section IV of the NRC Enforcement Policy and is not subject to formal enforcement
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. action. The inspectors noted that the problem was documented as PIP 0-C98-0956.
Some corrective actions were completed and others were being actively implemente?
The inspectors noted that the corrective actions adequately addressed the failure to
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follow procedure aspect of the problem. The inspectors discussed the details and root
cause determination of the LER with licensee management. The inspectors were
informed that site management recognized a need to improve the quality of LERs and
had initiated corrective actions for improvement. Based upon the inspectors * review of
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licensee actions, this LER is closed.
]
M8.3 (Closed) LER 50-413/98-014: Both Diesel Generators inoperable Due to
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Misinterpretation of Technical Specification Resulting in a Failure to Perform a Diesel
)
Generator Surveillance Within the Required Surveillancc : - tval
(Closed) Notice of Enforcement Discretion (NOED) 98-6-013: Both Diesel Generators
inoperable Due to Misinterpretation of Technical Specification Resulting in a Failure to
Perform a Diesel Generator Surveillance Within the Required Surveillance interval
This licensee-identified issue is discussed in Section M1.2 of IR 50-413,414/98-08. The
IR documented that the NRC granted a NOED to the licensee on August 7,1998. The
report also documented that the previously missed TS surveillance for Unit 1, due to a
failure to request a TS amendment, constituted a violation of minor significance and was
not subjected to formal enforcement action. During the recent inspection, the inspectors
observed that the licensee documented the problem in PIPS 0-C98-2797,0-C98-2366,
and 0-C98-3781. The inspectors reviewed the licensee's corrective actions and acted
that the corrective actions were either completed, were being actively implemente
or
were being assessed for implementation. The TSs were amended. Based upon the
inspectors' review of licensee actions, the LER and NOED are closed.
M8.4 (Closed) LER 50-413/98-013-00 and 01: Operation Outside TS Regarding Analyzing
Grab Samples at an incorrect Lower Limit of Detection
The licensee identified this violation of TS on July 9,1998, during a review of a radiation
protection procedure in preparation to transition to the new improved TS. Radiation
monitors EMF 46A and B monitor the w ster in the component cooling system. When the
monitors are inoperable, TS 3.3.3.1.b and TS Table 3.3-6 required grab samples to be
analyzed for gross gamma rsdiation at a lower limit of detection (LLD) of no more than
1E-7 microcuries per milliliter. There was no means available to measure for gross
gamma radiation at the Catawba station. The licensee conducted the sampling.using
gamma isotopic analysis. Additionally, the samples were being analyzed at a LLD of
SE- 7 microcuries per milliliter. The inspectors determined that this was a violation of TS 3.3.3.1.b.
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~ The LER indicated that this event occurred because TS requirements were not correctly
reflected in the radiation protection procedures for analyzing grab samples for EMF 46A
and 8 du:ing periods when the radiation monitors were inoperable.
The inspectors reviewed the circumstance surrounding the violation and determined that
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the TS requirements were correctly reflected in procedure HP/0/B/1009/011, EMF Loss,
in 1984. Subsequent procedure revisions deleted the specific TS requirements and
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included the sampling methodology that was being used by the licensee. The root cause
identified by the LER failed to take into account the administrative controls for the
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procedure change process and whv the TS requirements were not reflected in the
procedure.
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The inspectors noted that the radiation monitor sampling requirements were relocated
from the old TS into the Selected Licensee Commitments (SLC) manual by a TS
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amendment as part of the transition to the new Improved TS. The sampling
methodology and LLD actually performed by the licensee was incorporated into the SLC
manual. The TS amendment was reviewed and approved by the NRC and the licensee
implemented the improved TS on January 16,1999. The licensee indicated that their
current sampling analysis method, gamma isotopic analysis, was more precise than the
gross gamma analysis and the LLD was sufficient to detect whether activity in system
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leakage is greater than release limits. The inspectors observed that this problem was
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documented in PIP 0-C98-2440, and all corrective actions were completed. This
Severity Level IV violation is being treated as a NCV, consistent with Appendix C of the
NRC Enforcement Policy, it is identified as NCV 50-413,414/99-03-04: Operation
Outside TS Regarding Analyzing Grab Samples at an incorrect Lower Limit of Detection.
. This LER is closed.
M8.5 (Closed) LER 50-413/98_0109: Both Units Entered Technical Specification 3.0.3 Due to
inadequate Testing of Auxiliary Building Filtered Exhaust System
This prob!em was identified by the licensee's ventilation system event investigation team.
The team was chartered following the recognition of an adverse trend regarding
ventilation system related events and LERs. FoHowing entry into TS 3.0.3, the 24-hour
allowance of suweillance requirement 4.0.3 was initiated for performing the required
suweillance testing of the system. The surveillance procedure was revised and the
system was satisfactorily tested during the 24-hour time period. The LER documented
that the root cause of the problem was that the surveillance procedure did not
adequately demonstrate the pressure relationship between the emergency core cooling
system (ECCS) pump rooms and all surrounding areas. The TS surveillance
requirement (previous TS 4.7.7d.3, now TS SR 3.7.12.4) was to verify that the ventilation
system was capable of maintaining the ECCS pump rooms at a negative pressure
relative to adjacent areas of the auxiliary building. The licensee did not previously test all
walls and floors to ensure a negative pressure existed.
The inspectors cbserved that the problem was tracked under PIPS 0-C98-2599, 0-C98-
2518, and 0-C98-1002. The completed corrective actions were thorough and detailed.
'The inspectors concluded that the violation of TS 4.7.7d.3 had little safety significance, in
that the system configuration, lineup, and testing methodology were not required to be
changed. The number and locations for data co;tection points were increased to
satisfactorily verify that the TS requirements were being met. This Severity LevelIV
violation is being treated as a NCV, consistent with Appendix C of the NRC Enforcement
Po! icy. It is identified as NCV 50-413,414/99-03-05: Failure to Test the Auxiliary Building
Filtered Exhaust System in Accordance with TS 4.7.7d.3.
The inspectors observed that during system testing activities for trains 1 A and 2A, under
TS 4.0.3, that damper 2ABF-D-11 failed to close and was repaired. Additionally, train 2A
failed to meet its test acceptance criteria due to a manually set air register that was
improperly set. The inspectors noted that the LER was not clear or detailed as to the
.
circumstances surrounding the improperly set register. The LER indicated that the
register was subsequently adjusted and the system met the acceptance criteria. The
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inspectors discussed this observation with licensee management. The inspectors were
informed that a detailed investigation had been completed and the cause of the
improperly set register was not determined. Management personnelin'ormed the
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inspectors that the details surrounding the damper should have been documented in the
LER. The inspectors were also informed that corrective actions had been initiated to
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improve the quality of LER documentation. Based upon the inspectors review of
licensee actions, this LER is closed.
M8.6 (Closed) LER 50-414/98-004-00: Error During Tagout Causes De-Energization of Vital
Bus and Actuation of Low Temperature Overpressure Protection
On September 6,1998, at 2:05 p.m., during tagout of Diesel Generator 8, the wrong
potential transformer was isolated, satisfying the logic for undervoltage on 4160. Volt
Alternating Current (VAC) Essential Bus 2ETB. The event was attributed to inadequate
work pra:tices, in that the appropriate verification was not performed to determine the
correct component to be tagged when labeling discrepancies were encountered. The
corrective actions included: personnel counseling; group meetings; tagoJt walkthroughs;
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revisions to the Removal and Restoration data base; placement of warning signs on ETA
and ETB drawers; the establishment of a system to identify " critical * tagouts for the
remainder of the then ongoin' 'utage; the establishment of a review team; replacement
of the 2A reacto. coolant pump ,.al; analysis of the effects on the regenerative heat
exchanger; an engineering evaluation of the structuralintegrity of the pressurizer;
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evaluation of non-licensed operator training; establishment of a long-term project to
validate and revise computerized tagouts for consistency with plant labels and drawings;
and stroke time testing and limit switch verification of all three power operated relief
valves.
This issue was identified in NRC IR 50-413,414/98-09 as Apparent Violation (EEI) 50-
414/98-09-01: Failure to Follow Procedural Guidance While implementing Clearances -
Two Examples. eel 50-414/98-09-01 was closed in IR 50-413,414/98-10 and identified
as the second example in NCV 50-413,414/98-10-01: Failure to Follow Procedural
Guidance While ;lmplementing Clearances - Two Examples. This issue was entered into
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the licensee's corrective action program as PIP 2-C98-3219.
Licensee Event Report 50-414/98-004-00 erroneously stated that both the 2ETB Bus
(the fuse crawer that was inappropriately accessed) and the Diesel Gen 28 Source PT
(the fuse drawer that should have been accessed) were located in the turbine building
when in pcint of fact both were located in the auxiliary building. In addition the LER
stated: " Ten minutes after the loss of power, indicated temperature of the water reached
a minimum of 234 degrees Fahrenheit..." Plant records indicate that the temperature
down ramp time was six minutes. The engineering evaluation of the structuralintegrity of
the pressurizer used the more accurate and conservative six minute time. The licensee
indicated that they would amend the LER to reflect actual circumstances.
PIP 2-C98-3219, when addressing the completion of corrective actions listed in LER 50-
414/98-004-00, in several cases, provided only terse statements of completion without
attribution (no objective quality evidence of completion was provided). The inspectors,
by observation and interviews were able to verify the completion of all the corrective
actions listed in the PIP.
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The inspectors concluded that the licensee had taken appropriate actions. This LER is .
closed.
, . M8.7 - (Closed) LER 50-414/98-006-00: Rod Control System Malfunction Due to Failed Card
Leading to Manual Reactor Trip and Engineered Safety Feature Actuation
On October 20,1998, during preparation for zero power physics testing following a
refueling outage, a problem was experienced during withdrawal of Control Rod Bank A.
The Bank A Group 2 rods were conservatively declared inoperable. On
October 21,1998, the unit was manually tripped from Mode 3 to facilitate troubleshooting
on the rod control system. A feedwater isolation occurred following the manual reactor trip as expected.
The root cause was determined to be an isolated failure of an integrated circuit chip (Z2)
on the 2AC Slave Cycler Lift Decoder Card, Corrective actions included: suspension of
the reactor startup and manual reactor trip to facilitate troubleshooting; replacement of
the slave cycler lift decoder card; and testing of the failed slave cycler lift decoder card to
determine the specific failure mechsmism. The issue was entered into the licensee's
corrective action program as PIP 0-C98-4116. The inspectors verified the completion of
corrective actions listed in that PIP. The inspectors concluded that the licensee had
taken appropriate actions. This LER is closed.
M 8.8 (Open) LER 50-414/99-001-00: Unanalyzed Condition Associated with a Relay Failure in
the Auxiliary Feedwater System due to an inadequate Single Failure Analysis
4
On January 15,1999, at 6:30 a.m., with Unit 2 operating in Mode 1, Power Operation, at
100 percent power, a relay faihre occurred which resulted in degradation of the auxiliary
feedwater system. This issue was discussed in IR 50-413,414/98-12 and identified as
inspector Followup Item (IFI) 50-413.414/98-12-01: Relay Failures Cause Two CA
Pumps to be Declared Inoperable. A failure analysis was performed to determine the
root cause of the failures. A compensatory measure, developed and implemented for
LER 50-413/97-009, was adequate for this event also. The compensatory measure was
to limit specific activity in the reactor coolant system to ensure that offsite doses are
bounded by previous analyses. Planned corrective actions include for engineering to
determine if any changes to the auxiliary feedwater system are required as a result of
this event and to implement a modification as required; and for engineering to perform a
failure analysis on the relay. The issue was entered into the licensee's corrective action
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program as PIP 0-C99-0199. The inspectors concluded that the licensee had taken and
planned to take appropriate actions to address the failed relay and resultant degradation
of the auxiliary feedwater system, and an unanalyzed condition which was reported in
LER 50-413/97-009. Licensee Event Report 50-414/99-001-00 stated that a revision to
that LER would be submitted to document the results of the relay failure analysis (due
July 14,1999).~This LER remains open pending NRC review of the relay failure analysis
and revised LER.
M8.9 (Closed) IFl 50-413.414/98-12-01: Relay Failures Cause Two CA Pumps to be Declared
This issue is the subject of and will be tracked by LER 50-414/99-001-00. This IFl is
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M8.10 (Closed) LER 50-413/98-05-01: Missed Tech Spec Surveillance on Auxiliary Building
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Ventilation System due to Misinterpretation of Surveillance Requirement 4.7.7.d.1
The issue discussed in this supplemental LER, and in original LER 413/98-05-00, was
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documented for closure in NRC IR 50-413/99-01. No further review is required; this LER
is closed.
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E2
Engineering Support of Facilities and Equipment
E2.1
Dearadation of Service Water Pioina to Auxiliary Feedwater System
a.
Inspection Scope (37550)
. The inspectors reviewed the licensee's activities related to the degraded safety-related
assured water supply source tc the auxiliary feedwater systam (CA), which resulted in
declaring all CA pumps inoperable. These activities included identification, immediate
corrective actions, extent of condition review, and actions to return the CA pumps to
operable status to support plant restart. The regulatory significance of this issue will be
addressed in a future inspection following the !!censee's completion of the root cause
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investigation and past operability evaluation.
b.
Observations and Findinas
A 10 CFR 50.72 report was made on May 4,1999, declaring all CA pumps inoperable.
During the ongoing Unit 1 refueling outage, the licensee investigated a pin hole leak on
the 1B train RN to CA piping and observed excessive build up of tubercles on the inside
of the six-inch piping. The tubercles were growth deposits from microbiologically
induced corrosion (MIC) on the carbon steel piping from the raw water used in the RN
system. The licensee performed flow testing which indicated that the tubercles caused
flow restriction which reduced the flow capability to the CA system from RN below the
value to support operation of the three CA pumps. This was a condition outside of the
design basis for the plant. Further investigation indicated that this condition applied to all
CA trains for both units. At the time, the Unit 1 No Mode condition required no operable
CA pumps; however, Unit 2 was in Mode 1 in which Technical Specifications required
three operable CA pumps.
The licensee's immediate corrective actions were timely and appropriate to return the
plant to a condition consistent with the design basis. These actions included evaluation
of flow conditions and isolation of the TDAFW pump to establish a MDAFW pump as
- operable with the restricted RN to CA piping flow capability. Technical Specifications
required one CA pump operable for mode changes and the subsequent shutdown of Unit
2. The licensee's evaluation determined that the RN to CA flow capability was adequate
for one pump, thereby supporting plant mode change to permit unit shutdown.
The licensee implemented appropriate corrective actions to restore, and verify by testing,
1
the design flow capability of the RN to CA piping for all trains. These actions and related
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evaluations were documented in PIP C-99-1675. Approximately 300 feet of the branch
piping for each train was, mechanically cleaned to remove the tubercles. The cleaning
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process was observed by the inspectors. Approximately 15 feet of six-inch diameter
piping directly off the RN header, which experienced the most severe tubercle growth,
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was replaced with eight-inch diameter piping. The piping branches were modified to add
,
the capability for flow testing and each was tested to verify adequate design flow
capability following the cleaning and piping replacement. All testing was complete on
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May 13,1999. The inspectors reviewed the flow test procedures and results which
verified adequate flow capability for the RN to CA branch lines. A periodic test was
developed to flow test each branch monthly to monitor MIC growth.
Long-term corrective actions included the initiation of a root cause investigation team
with team members from all Duke Power Nuclear Stations. A corporate assessment
team was initiated to evaluate the station's evaluation and resolution of this issue
including the station response and implementation of Generic Letter 89-13, Service
Water Systems Afecting Safety Related Equipment, dated July 18,1989. Further NRC
review of this item will be accomplished during the review of LER 50-414/99-002-00,
Both Catawba Units Operated Outside Their Design Basis and Unit 2 Forced Shutdown
as a Result of Flow Restrictions Caused by Corrosion of the Auxiliary Feedwater System
Assured Suction Source Piping Due to inadequate Testing.
.
c.
Conclusions
The licensee's identification, investigation and immediate corrective actions associated
with the degraded assured CA supply source were comprehensive. Actions were
appropriate and timely to retum the plant to a condition consistent with the design basis
following identification of the degraded condition. Adequate actions were implemented to
estab!ish all CA pumps operable to support unit restart.
E3
Enaineerina Procedures and Documentation
E3.1
Chanoes. Tests. and Experiments Performed in Accordance With 10 CFR 50.59 (for
1998)
a.
inspection Scope (37550)
By letter dated April 1,1999, the licensee submitted its annual summary report of all
changes, tests, and experiments, which were completed under the provisions of 10 CFR 50.59 during 1998. The licensee's summary report includes approximately 300 changes
made during the subject period. The inspector evaluated these changes against the
provisions of the regulation.
b.
Observation and Findinas
- The inspector reviewed the licensee's current (dated September 16,1998) version of
Nuclear System Directive (NSD) 200, "10 CFR 50.59 Evaluations," which is patterned
after NEl 96-07," Guidelines for 10 CFR 50.59 Safety Evaluations." This document
requires that changes be evaluated against the appropriate Final Safuy Analysis Report
(FSAR). Technical Specifications, and NRC Safety Evaluation Report sections to
determine if there is need for revision. Specifically, the criteria specified by 10 CFR 50.59 are broken down into seven (7) questions. For a change to be qualified for 10
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CFR 50.59, the answers te all seven questions must be "no." Based on review of this
document and the review of tiie licensee's 10 CFR 50.59 evaluations, the inspector
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determined tha. the.icensee's NSD 209 appropriately reflec:s the criter:a cf this
regulation and, if folowed accordingly, would ensure that t change was ccrrectly
evaluated unde r this regu!ation.
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The licensee has inct rporated appropr ate instructions in Section 209.12.7 of NSD 209
regard.ng wr.tir g sum naries for each change made under 10 CFR 50.59. As a reruit,
the licensee's t ummary reportfor 1998 changes made under 10 CFR 50.59 was
concise, inforrr ative, a 1d accurate.
I
The ins pector performed an in-office review of the licenseets summary report to
determine tha nature at d safety significance of each change. Through this review, the
inspector selected the following changes for more detailed onsite review:
Minor hiodificatio, CE-0$710, Setpoint Change for :nstruments NDPGE040 and
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NDPG! 050
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Minor hiodifications CE-09316 and CE-09317, Leave Fuel Pool Ventilation
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.Systerr Train Motor Opera!ed ! solation Dampers in the Open Positiun at All
Times
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Minor Hodification CE-095E4, Rercove the Control Room Floor as a Committed
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! Fire Bcundary
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Minor Modification CE-09561, Replace Valve 1NM144 With A New Valve
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Calcult tion CNC-1553.'26-00-0193, Rev. O, increased Burnable Poison Rod
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Assem 3ly B4C Concentration
Procedure OP/1/A/6150/001, Revision 80, and OP/1/B/6100/010G, Revision 51,
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Changing the Reactar Vessel Leakage Detection System Alignment from the
Inner CLRing to the Outer O-Ring
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Based en the detailed onsite review,11e inspector found that these changes were
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correctly evaltated by the licensee under the provisioris of 10 CFR 50.59.
At the end of e ach change summary, tne licensee listed the Updated FSAR (UFSAR)
sections that reed to be revis,ed to reflect the changes made under 10 CFR 50.59. The
licensee submitted Revision 7 of the UFSAR on April 8,1998. The staff's review of
UFSAR Revision 7 against the requirements of 10 CFR 50.71 is a separate action from
the current inspection. The s:aff will report findings of the UFSAR review in a separate
report.
c.
Conclusion
l
Based on in-o fice review of tFe licensee's April 1,1999, annual summary on 10 CFR 50.59 changen, onsite review of select 10 CFR 50.59 evaluations, and audit of the
licensee's procedures, the inspector concluded that the licensee has complied with the
provisions of t1is regulation fo the changes listed in the annual summary report
submitted on April 1,1999. The inspector also found the licensee's summary report for
1998 changes concise, informative, and accurate.
E8
Miscellaneous Engineering 13 sues (92903)
)
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E8.1
Year 2000_(L K) Readiness Proaram Review (Tl 2515/141)
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The staff conducted an abbreviated review of Y2K activities and documentation using
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Temporary ins truction (TI) 2515/141, " Review of Year 2000 (Y2K) Readiness of
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Camputer Systems at Nuclear Power Plants." The review addressed aspects of Y2K
management planning, dcicumentation, implementation planning, initial assessment,
detailed assessment, remediation activities, Y2K testing and validation, notification
,
activities, and contingency planning. The reviewers used Nuclear Energy Institute /
Nuclear Utilities Software Management Group (NEl/NUSMG) 97-07, " Nuclear Utility
Year 2000 Readiness," and NEl/NUSMG 98-07," Nuclear Utility Year 2000 Readiness
Contingency Planning," as the primary references for this review.
During the review, the licensee stated that the Y2K Readiness Project activities were 90
percent completed with cc'ntingency planning being approximately 90 percent complete,
and that both programs were on target to be completed by their scheduled due dates.
The results of this review will be combined with the results of reviews of other licensees
in 'a summary report to be issued by July 31,1999.
.
,
E8.2 LCJosed) LER 50-413/97-01: Unanalyzed Postulated Single Failure Affecting the Steam
Ge nerator Tube Rupture (SGTR) Analysis
(CJosed) LER 50-413/97-09-01: Unanalyzed Postulated Single Failure Affecting the
SGTR Analysis
These LERs addressed licensee-identified, old design issues in which the previously
ani lyzed limiting case of one stuck open power operated relief valve (PORV) for SGTR
wan determined not to be the limiting single failure. LER 50-413/97-01 was initiated in
February 1997, during an engineering review of the UFSAR Chapter 15 off site dose
analysis. The licensee identified that a single failure of a vital instrumentation and control
(l&C) distribution panel would result in loss of two PORVs to the closed position. The
acc dent analysis assumed the use of two PORVs for rapid depressurization and cool
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down during an SGTR. Technical Specification 3.7.1.6 required three of four PORVs
1
ope able per unit in Mode 1.
LER 97-09-01 was initiated in November 1997, as a result of a finding from a CA system
design review. it was identified that a loss of a vital I&C panel would result in the loss of
power to two PORVs and the CA pumps' flow control valves (FCVs) thereby losing CA
flow control from the control room which was assumed in the accident analysis. This
could result in steam generator (SG) overfi!! during an SGTR coincident with loss of
offsite power and a single failure. UFSAR Section 10.3, Main Steam Supply System and
Section 15.6.3.1, SGTR, stated that the control room operators can isolate the feedwater
flow to terminate the radioactive release to the atmosphere from the affected SG.
The licensee implemented timely and appropriate corrective actions to return the plant to
a condition consistent with the design basis. In general, these included administrative
controls to require four operable PORVs per unit, establish licensed operator action
requirements for local PORV operation, and establish more restrictive primary coolant
activity limits. Pending long-term corrective actions inc{uded a revised off site dose
analysis in LER 50-413/97-01 and for LER 50-413/97-09-01 as well as modifications to
the PORV and CA FCV vital l&C power supply Presently, Unit 1 modifications are being
implemented to improve the reliability of CA FCV air supply in response to an additional
vulnerability identified during the extensiveness review for these SGTR issues. NRC
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review of some of these corrective actions was docurnented in NRC IR 50-413,414/97-
05 and 50-413,414/98-11.
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The long-term actions were.not complete; however, they were entered into the licensee's
I
corrective action program as PlP 0-C97-0233 and 0-C97-3621 for LERs 50-413/97-01
and 97-09-01, respectively. The remaining LER 50-413/97-01 action to revise the offsite
,
dose analysis required design input resulting from the resolution of LER 50-413/97-09-
01. In developing the modifications to the vital l&C power to the PORVs and CA FCVs
the licensee determined that additional vulnerabilities would be introduced. During this
inspection, the licensee was revising LER 50-413/97-09 01 to change the commitment
dates and state that a risk analysis would be performed to provide a risk informed
resolution to this design concem which may not include a modification to the plant.
The inspector noted that the apparent delay in resolving the LERs was a result of
comprehensive extent of condition reviews performed as corrective actions. A failure
modes and effects (FMEA) analysis for PORV power supplies was performed for LER
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50-413/97-01. A more extensive SGTR FMEA was performed for LER 50-413/97-09-01.
The SGTR analysis identified additional single failure vulnerabilities such as the CA FCV
{
air supply. The additional failure vulnerabilities will be addressed in the revision, LER
'
50-413/97-09-02. The inspector concluded the licensee's identification and response to
the SGTR single failure vulnerabilities demonstrated good engineering performance and
focus on plant safety.
The previous NRC reviews of this issue did not address the regulatory significance. The
licensee identified that the root cause of these design deficiencies was an inadequate
design review when implementing the generic Westinghouse SGTR analysis
methodology in 1987. The LERs stated that the identified conditions were outside the
design basis of the plant in that they described an event that alone could have prevented
the fulfillment of the safety function of a system that is needed to mitigate the
consequences of an accident. This design control deficiency is contrary to the
requirements of 10 CFR 50, Appendix B, Design Control, and is identified as Apparent
Violation (EEI) 50-413,414/99-03-06: Inadequate Design implementation of 1987
Generic SGTR Analysis.
There were tr itigating factors associated with this violation. These included that the
underlying issue of the violation was licensee-identified during a self-initiated design
review; corrective actions were timely and effective to assure the plant was returned to a
condition consistent with the design basis; and appropriate reviews were initiated to
identify similar design issues. This design deficiency was not likely to have been
identified by routine surveillance or quality assurance activities and the design error was
not reflective of current licensee performance. Additionally, the licensee's historic review
of primary coolant activity determined that activity levels remained below the most
restrictive limits imposed by the corrective actions of the LERs. Therefore, there was
previously no potential of exceeding the offsite dose limit had the limiting SGTR event
occurred.
.
E8.3 (Closed) LER 50-413/97-007: TS 3.2.5 is inadequate for Reduced Flow Operation
This item addressed a licensee-identified design deficiency that resulted in an
inadequate analytical basis to support the reactor coolant (NC) flow-to-power limits in TS 3.2.5.c "NC Flow / Power Stairstep." The 1983 Westinghouse analysis basis did not fully
encompass UFSAR Chapter 15 transient and accident conditions. The licensee's
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evaluation and corrective actions were documented in PIP 0-C97-3429. The immediate
corrective actions were appropriate and timely. These actions established administrative
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._. controls to prohibit operation in the " restricted operating region" prescribed in the TS. .
The long-term corrective actions required an analysis to determine the appropriate
operating guidelines and revise the TS to reflect the revised guidance. The analysis was
,
complete and the revision was scheduled for submission June 4,1999. The licensee
reviewed the plant operating history and determined that the plant had not operated in
the restricted region of the TS therefore no TS limits were violated. This design control
deficiency constituted a violation of minor significance and is not subject to formal
enforcement action.
E8.4 (Closed) LER 50-413/98-03: Omission in Retest Manual Leads to Failure to Perform
Required Retest Prior to Restoring Containment Isolation Valves (CIVs) to Service
'
This item addressed the performance of inadequate post maintenance testing (PMT) due
l
to deficient work instructions which did not include TS-required valve isolation time
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testing in the PMT scope for CIVs. TS 3/4.6.3, Containment isolation Valves, required
time testing of containment isolation valves following maintenance. Corrective actions
included isolation time testing of the identified valves and a revision to tne Catawba
Retest Manual to include isolation time testing in the scope of PMT for CIVs. An
extensiveness review identified additional occurrences of CIVs returned to service
without the appropriate TS-required testing. Appropriate isolation times were verified for
these valves. Corrective actions were completed on March 30,1998. This severity level
IV violation is identified as an NCV, consistent with Appendix C of the Enforcement
Policy. It is in the licensee's corrective action program as PIP 0-C-98-0651 and is
identified as NCV 50-413,414/99-03-07: Inadequate PMT Work Instruction for CIVs.
E8.5 (Closed) LER 50-413/98-02: Incorrectly Set Valve Leads to Elevated Condensate
Storage System Temperature, Causing Condition Outside the Design Basis of the Plant
This report provides administrative closure for this LER. The NRC initiated an
augmented inspection team (NRC inspection Report 50-413,414/98-06) to review this
issue. NRC enforcement for this issue was documented as Violations 50-413,414/98-07-
01 and 98-07-05. The violations were closed in NRC IR 50-413,414/99-01 where it was
.
identified that the corrective actions were documented in the licensee's corrective action
program.
E8.6 (Closed) LER 50-413/98-10-00 and 01: Pinhole Leak in Auxiliary Feedwater (CA) Nozzle
Tempering Line Causes Non-Compliance with TS Structuralintegrity Requirements
The licensee identified a pinhole leak in the American Society of Mechanical Engineers
(ASME) Code 2 piping while in Mode 1 on Unit 1. This was inconsistent with TS
3/4.4.10.b which stated that leaks on ASME Code 2 piping were to be isolated or
repaired prior to heat up of the reactor coolant above 200 degrees Fahrenheit (F). The
immediate corrective actions were conservative,-including unit shutdown and isolation
and repair of all the tempering lines and were documented in PIP 0-C-98-2276. This
LER was a minorissue and was closed.
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, _IV. Plant Support
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Radiological Protection and Chemistry (RP&C) Controls
' R1.1
Radiological Protectio _r1
. a.
Inspection Scope (83750)
The inspectors reviewed personnel monitoring, ra'diological postings, high radiation area
controls, posted radiation dose rates, contamination controls within the radiologically
controlled area (RCA), and container labeling. In addition, As Low As Reasonably
Achievable (ALARA) work planning, prejob worker briefings, and job execution
observations were performed. The inspectors also reviewed licensee records of
personnel radiation exposure and discussed ALARA program details, implementation
and goals. Requirements for these areas were specified in 10 CFR 20 and TS.
b. , Observations and Findinas
The inspectors toured the health physics facilities, the auxiliary building, outside
i
radioactive waste storage building and waste monitor tank building. Radiologically
controlled areas, including radioactive material storage areas, high radiation areas, and
~
locked high radiation areas, were appropriately posted. During a tour of the waste
monitor tank building (WMTB), the inspectors requested several contamination smears.
One end of an open transfer hose, in the WMTB, had loose contamination of
approximately 36,000 disintegrations per minute per 100 square centimeters. Followup
contamination surveys, in the WMTB, found arproximately seven hoses, hose caps and
couplings with loose contamination. These contamination smears were in excess of
procedural loose contamination limits of greater than 1000 disintegrations per minute per
100 cquare centimeters. Several steps of Procedure SH/0/B/2000/006," Removal of
items from RCA/RCZ's and Use of Release / Radioactive Material Tags," dated October
22,1997, were violated. A followup tour by the inspectors, the next day, identified an
additional hose cap with loose contamination in excess of procedurallimits. The failure
to properly tag and identify equipment with loose contamination in excess of procedural
I
limits is a Severity IV violation that is being treated as an NCV, consisted with Appendix
C of the NRC Enforcement Policy. This NCV is identified as NCV 50-413,414/99-03-08:
Failure to Properly Tag and identify Equipment, in the WMTB, with Loose Contamination
in Excess of Procedural Limits. This issue is in the licensee's corrective action program
as PIP 0-C99-2052.
i
The inspectors reviewed operational and administrative controls for entering the RCA
and performing work. These controls included the use of radiation work permits (RWPs)
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 inspectors noted that
appropriate protective clothing, and dosimetry were required. During tours of the 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 observed workers properly using friskers at the exit locations from controlled
areas and properly exiting the protected area through the exit portal monitors.
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The inspectors discussed ALARA goals and annual exposures with licensee
management and determined the responsibilities for the ALARA staff were clearly
3
defined. The inspectors noted that team work by management, outage planning,
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operations, maintenance, chemistry and health physics in the ALARA program
contributed to the reduced outage and site doses.
{
The Calender 'f ear 1999 site exposure goal was set at approximately 156 person-rem.
At the time of the inspection (May 20,1999), the site person-rem dose was about 114
person-rem. Approximately 105 person-rem had been accumulated as a result of Unit 1
refueling activities.
Records reviewed showed that the licensee was tracking and trending personnel
contamination events (PCEs). The licensee had tracked approximately 44 PCEs as of
May 20,1999. This included skin and clothing contaminations. There were 33
contamination events to date for the outage.
i
. The inspectors reviewed the contaminate square footage data and observed that the
licensee was tracking approximately 6035 square feet or about 5 percent of the
controllable 157,900 square feet. The contaminated square footage had been reduced
from approximately 9255 square feet the week before. The decrease was attributable to
decontamination and cleanup from outage activities.
c.
Conclusions
One NCV was identified for failure to properly tag and identify equipment, in the WMTB,
with loose contamination in excess of procedural!imits. Radiological facility conditions in
radioactive material storage areas, health physics facilities, and waste storage building
were found appropriate and the areas were properly posted and radioactive material
appropriately labeled. Personnel dosimetry devices were appropriately worn. Radiation
work activities were appropriately planned.
V. Manaaement Meetinas
X1
Exit Meeting Summary
The inspector presented the inspection results to members of licensee management at
the conclusion of the inspection on June 15,1999. The licensee acknowledged the
findings presented. No proprietary information was identified.
PARTIAL LIST OF PERSONS CONTACTED
Licensee
R. Beagles, Safety Assurance Manager
M. Boyle, Radiation Protection Manager
S. Bradshaw, Safety Assurance Manager
G. Gilbert, Regulatory Compliance Manager
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R. Glover, Operations Superintendent
P. Herran, Engineering Manager
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R. Jones, Station Manager
G. Peterson, Catawba Site Vice-President
F. Smith, Chemistry Manager
. .R. Parker, Maintenance Manager
NRC
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R. Emch, NRR ~
P. T,am, NRR
INSPECTION PROCEDURES USED
IP 37550:
Engineering
IP 40500:
Effectiveness of Licensee Controls in identifying, Resolv.
and Preventing
Problems
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IP 81726:
Surveillance -
'IP 62707:
Maintenance Observation
IP 71707:
Plant Operations
IP 71750:
Plant Support Activities
IP 83750:
Occupational Radiation Exposure
IP 92700:
Onsite Follow up of Written Reports of Nonroutine Events
"
IP 92901:
Followup - Operations
IP 92902:
Followup - Maintenance
IP 92903:
Followup - Engineering
IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors
Tl 2515/141: Review of Year 2000 Readiness of Computer Systems at Nuclear Power Plants
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-413,414/99-03-01
Failure to Satisfy TS Surveillance Requirement 4.5.3.2 by Verifying Only One CCP or One Safety
injection Pump Operable During LTOP Conditions
(Section 08.1)
50-413,414/99-03-02
Failure to Take Prompt Corrective Actions to
Resolve TS Conflict Regarding LTOP Pump
Operability Requirements (Section 08.1)
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50-413/99-03-03
Review of Missing ice Basket Coupling Screws in
~the Unit 1 Ice Condenser (Section M2.1)
50-413,414/99-03-04
Operation Outside TS Regarding Analyzing Grab
Samples at an incorrect Lower Limit of Detection
(Section M8.4)
50-413,414/99-03-05
Failure to Test the Auxiliary Building Filtered
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Exhaust System in Accordance with TS 4.7.7d.3
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(Section M8.5)
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50-413,414/99-03-06
eel
inadequate Design implementation of 1987 Generic
SGTR Analysis (Section E8.2)
' '50-413,414/99-03-07
Inadequate PMT Work Instruction for CIVs (Section
E8.4)
50-413,414/99-03-08
Failure to Properly Tag and Identify Equipment, in
the WMTB, with Loose Contamination in Excess of
Procedural Limits (Section R1.1)
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Closed
50-413/97-004-00
LER
Inadequate Surveillance Resulting From a
Conflicting Technical Specification Limiting
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Condition for Operation and Surveillance
Requirement (Section 08.1)
50-413/98-007-00
LER
Missed Technical Specification Surveillance on
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Containment Penetration Testing Due to a Literal
Compliance issue (Section M8.1)
50-414/98-001-00
LER
TS 3.0.3 Entry Due to an Inoperable Annulus
Ventilation System (Section M8.2)
50-413/98-014-00
LER
Both Diesel Generators Inoperable Due to
Misinterpretation of Technical Specification
Resulting in a Failure to Perform a Diesel
Generator Surveillance Within the Required
Surveillance Interval (Section M8.3)
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98-6-013
Notice of Enforcement Discretion - Both Diesel
Generators inoperable Due to Misinterpretation of
Technical Specification Resulting in a Failure to
Perform a Diesel Generator Surveillance Within the
Required Surveillance interval (Section M8.3)
50-413/98-013-(00 & 01)
LER
Operation Outside TS Regarding Analyzing Grab
Samples at an incorrect Lower Limit of Detection
(Section M8.4)
50-413/98-009-00
LER
Both Units Entered Technical Specification 3.0.3
Due to inadequate Testing of Auxiliary Building
Filtered Exhaust System (Section M8.5)
50-414/98-004-00
LER
Error During Tagout Causes De-Energization of
Vital Bus (Section M8.6)
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50-414/98-006-00
.LER
Rod Control System Malfunction Due to Failed
Card Leading to Manual Reactor Trip and
Engineered Safety Feature Activation (Section
M8.7)
,
50-413,414/98-12-01
IFl
Relay Failures Cause Two CA Pumps to be
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Declared Inoperable (Section M8.9)
50-413/98-05-01
LER
Missed Tech Spec Surveillance on Auxiliary
Building Ventilation System due to Misinterpretation
of Surveillance Requirement 4.7.7 d.1
50-413/97-001-00_
LER
Unanalyzed Postulated Single Failure Affecting the
Steam Generator Tube Rupture (SGTR) Analysis
(Section E8.2)
50-413/97-009-01
LER
Unanalyzed Postulated Single Failure Affecting the
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SGTR Analysis (Section E8.2)
50-413/97-007-00
LER
TS '3.2.5 is inadequate for Reduced Flow Operation
(Section E8.3)
50-413/98-003-00
LER
Omission in Retest Manual Leads to Failure to
Perform TS Required Retest Prior to Restoring
CIVs to Service (Section E8.4)
50-413/98-002-00
LER
incorrectly Set Valve Leads to Elevated
Condensate Storage System Temperature,
Causing Condition Outside the Design Basis of the
Plant (Section E8.5)
50-413/98-010-(00 & 01)
LER
Pinhole Leak in Auxiliary Feedwater (CA) Nozzle
Tempering Line Causes Non-compliance with TS
StructuralIntegrity Requirements (Section E8.6)
Discussed
50-413/99-07-00
LER
Operation Prohibited by TS 3.4.7 Caused by an
Inoperable Train of Residual Heat Removal Due to
inadequate Work Sequencing (Section 01.3)
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. 50-413,414/98-01-01
Basis for Five-Minute Period of VC System
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Inoperability with Compensatory Actions (Section
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08.8) -
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50-414/99-001-00
LER
Unanalyzed Condition Associated with a Relay
Failure in the Auxiliary Feedwater System due to an
)
Inadequate Single Failure Analysis (Section M8.9)
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50-414/99-002-00
LER
Both Catawba Units Operated Outside Their Design
Basis and Unit 2 Forced Shutdown as a Result of
Flow Restrictions Caused by Corrosion of the
,
Auxiliary Feedwater System Assured Suction
Source Piping Due to inadequate Testing (Section
E2.1)
UST OF ACRONYMS USED
1EOC11
Unit 1 End-of-Cycle 11 Refueling Outage
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As Low As Reasonable Achievable
American Society of Mechanical Engineers
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CA
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Centrifugal Charging Pump
CFR
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Code of Federal Regulations
CIV .
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Containment isolation Valve
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Enforcement Action
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Emer0ency Core Cooling System
eel
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Apparent Violation
j
F
Fahrenheit
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-
Flow Control Valve
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Failure Modes and Effects Analysis
Final Safety Analysis Report
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FWST
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Refueling Water Storage Tank
Ice Condenser
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l&C
Instrumentation and Control
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IFl
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Inspector Followup item
IR
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Inspection Report
JCO
Justification for Continued Operation
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KG
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Generator Stator Cooling
LCO
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Limiting Condition for Operation
LER
Licensee Event Report
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Lower Limit of Detection
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Low Temperature Overpressure Protection
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MD%FW
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Motor-Driven Auxiliary Feedwater (pump)
MIC'
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Microbiological Induced Corrosion
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Motor-Operated Disconnect
NC
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Non-Cited Violation
ND
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NEl
Nuclear Energy institute
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NI
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Safety injection
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Notice of Enforcement Discretion
NRC
Nuclear Regulatory Commission
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-
Nuclear Reactor Regulation
Nuclear Safety Advisory Letter
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NSD.
Nuclear System Directive
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NUSMG
Nuclear Utilities Software Management Group
--
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OAC
Operator Aid Computer
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-
Personnel, Contamination Event
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Problem investigation Process.
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Post-Maintenance Testing
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Power Operated Relief Valve
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, RCA
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Radiologically Controlled Area
- RN
Nuclear Service Water
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RP&C
Radiological Protection and Controls
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. Radiation Work Permit
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Steam Generator Tube Rupture
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SLC-
Selected Licensee Commitment
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SR
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Surveillance Requitement
Tavg.
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(reactor coolant system) Average Temperature
Turbine-Driven Auxili,ry Feedwater (pump)
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TG
Turbine-Generator
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Tl
. Temporary Instruction
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Task Interface Agreement
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Tref _.
(reactor coolant system) Reference Temperature
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TS
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Technical Specification
Updated Final Safety Analysis Report
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Unresolved item
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Auxiliary Building Ventilation
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VAC
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. Volts Alternating Current
Control Room Area Ventilaticn
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World Association of Nuclear Operators
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WMTB
Waste Monitor Tank Building
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Y2K
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Year 2000
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This calculation is known as the three-minute-rule. The three-minute-rule is based on the
criteria in the dose assumption calculations that no credit is taken for any VC system actuation
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within the first three minutes of an accident. Therefore, the licensee's position is that three
'
-} minutes would allow adequate time to seal a given VC system or control room boundary breach
' and pressurize the control room, thereby ensuring doses to operators would not exceed limits.
The rule allows the VC system or control room pressure boundary to be breached as long as
contingency measures are in place to ensure that the system can be sealed within three
minutes of an ESF actuation. Examples of work performed using this rule include the following:
pulling new cable into the control room, propping open control room doors to allow routing of
cables to the reactor trip breaker room during rod testing, and performing maintenance on
,
common ventilation duct components.
3.0 EVALUATION
Region 11 concems center on the 10 CFR Part 50.59 evaluation conducted by the licensee on
the c~ompensatory measures. One of the issues for consideration when cond"mg a 10 CFR
.50.59 evaluation is, whether the activity could create the possibility for a malf
ion of a
different type than any evaluated in the SAR. The compensatory measure
estion is the
sealing of a given VC system or control room boundary breach. The licer'
ss the position
that the type of firestop sealant material used is the standard and it is uset .s permanent
sealant for all control room penetrations. As an added assurance, a backup supply of sealant
material will be available at the job site. The licensee concludes that "this compensatory
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measure does not create the possibility for any new type of malfunction that may hinder the
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ability of the VC system to pressurize the control room as considered in the SAR."
The problem, as Region !! correctly points out, is that manual action would be required to
reinstallthe seals should control room pressurization be required. The licensee's conclusion
neglects any potential for malfunctio, introduced by the manual action.
Now, in response to the two specific 4:. 'stions asked :n the TIA.
1. Does the licensee need to evaluate the impact of the manual compensatory measures on
the original degraded condition in its 10 CFR 50.59 review? In other words, does the
licensee need to evaluate the likelihood of a new failure mechanism because'the
penetration seal will be manually refilled in the first three minutes of an event?
' Response:
in all cases where a licensee proposes a change to the design of the facility (either temporary
or permanent) to cred.it manual operator action in place of automatic actions or to modify
previously credited manual actions, the licensee is required to evaluate the impact of the
proposed change as part of its 10 CFR 50.59 review. Although it is possible, it is not expected
that many determinations of operability will be successfulfor manual action in place of
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UNITED STATES
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NUCLEAR, REGULATORY COMMISSION
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March 31,1999 '
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MEMORANnUM TO: Loren R. Plisco, Director
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Division of Reactor Projects :
Region il
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FROM:
Suzanne C. Black, Deputy DirectorIh
,
Division of Licensing Project Management
Office of Nuclear Re. actor Regulation
SUBJECT:
TASK INTERFACE AGREEMENT (TIA 9.8008)- USE OF MANUAL
.
,
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COMPENSATORY ACTIONS ON CONTROL ROOM EMERGENCY
VENTILATION SYSTEM AT THE MCGUIRE NUCLEAR STATION,
UNITS 1 AND 2 (TAC NOS. MA2467 AND MA2468)
.
.
.
By memorandum dated July 29,1998, your office requested assistance in the evaluation of
Duke Energy Corporation's (DEC) potentialinappropriate evaluation of compensatory measures
pursuant to G'eneric Letter 91-18, Revision 1,"Information to Licensees Regarding NRC
Inspection Manual Section on Resolution of Degraded and Nonconforming Conditions." The
letter identified a specific appFcation involving the control room emergency ventilation system
(CREVS), and potential application to other systems at the McGuire site and other DEC units.
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Also, the letter indicated that this issue may be generic to the industry.
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The evaluation has been performed by the Plant Systems Branch with support from Technical
Specifications Branch, Operator Licensing and Human Performance Branch, Emergency
Preparedness and Radiation Protection Branch, and Generic issues and Environmental
Projects Branch. The attached staff evaluation concludes that the use of manuel compensatory
actions is a violation of the technical specifications.
This completes our effort on TlA 98008 and TAC Nos. MA2467 and MA2468 are closed, if you
have any questions regarding this review, please contact Frank Rinaldi at (301) 415-1447.
.
Docket Nos 50-369 and 50-370 '
Attachment: As stated
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cc w/att: R. Blough, RI
J. Barnes, Rll
G. Grant, Rlli
K. Brockman, RIV
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Attachment
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UNITED STATES
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, NUCLEAR. REGULATORY COMMISSION
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JASHINGTON, D.C.
20555-0001
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' SAFETY' EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION
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- TIA 98008
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U.SE OF MANUAL COMPENSATORY ACTIONS ON CONTROL ROOM EMERGENCY
VENTILATION SYSTEM
DOCKET NOS. 50-369 AND 50-370
1.0 INTRODUCTION
.
,
- By memorandum dated July 29,1998, from Loren R. Plisco, Director, Division of Reactor
Projects, Region 11, to John A. Zwolinski, Acting Director, Division of Reactor Projects 1/11, Office
of Nuclear Reactor Regulation, a Task Interface Agreement (TIA-98008) expressed a concern
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regarding a potentialinappropriate evaluation of compensatory measures pursuarrMo Generic Letter (GL) 91-18, Revision 1,"Information to Licensees Regarding NRC Inspection Manual .
Section On Resolution of Degraded and Nonconforming Conditions." The letter stated that the
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specific application ir"toives the control room emergency ventilation system (CREVS) at the
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l McGuire Nuclear Power Plant, and that the concem may apply to other systems at the McGuire
Plant and other units owned by the Duke Power Company. The letter also stated that this issue
,
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may be generic to the industry.
' 2.0 BACKGROUND
As described in the July 29 letter, the CREVS at McGuire provides normal and emergency
ventilation to the control room, control room area, and switchgear rooms. It includes both the
control area ventilation system (VC) and the control area chilled water system (YC). The
design has two independent trains that share common duct work. The design of the VC is such
that the maximum radiation dose received by control room personnel under accident conditions
!
is within the limits of General Design Criterion 19 of Appendix A to Title 10 of the Code of
Federal Reoulations (10 CFR) Part 50. The safety function is described as an automatic
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function (actuation on receipt of an engineered safety feature (ESF) signal)in the Updated Final
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Safety Analysis Report (UFSAR) and in the licensee's design basis documentation.
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)
Maintenance and modifications conducted (or proposed) breach (or will breach) the common
VC duct work or control room pressurization boundary. Through engineering analysis, the
licensee developed a calculation which allows the use of compensatory measures rather than
. declaring both trains of the system inoperable (declaring both trains inoperable would require
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entry into.TS 3.0.3).
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automatic action. As such, Information Notice 97-78 provides explicit criteria which should be
considered in performing such evaluations to ensure that the proposed changes have been
adequately evaluated with regard to human performance. In addition, Information Notice 97-78
-} refers the reader to GL 91-18 Rev 1 which discusses the app o i tr pr a eness of temporary use of
.
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operator action in place of automatic action and states, in part, that: " ....it is not appropriate to
take credit for manual action in place of automatic action for protection of safety limits to
consider equipment operable. This does not preclude operator action to put the plant in a safe
. condition, but operator action cannot be a substitute for automatic safety limit protection....".
With respect to the particular cited McGuire. example, it is not appropriate for a licensee to
,
purposefully degrade or create a non-conforming condition and then use a compensatory
measure as a means of bypassing Technical Specification Limiting Condition of Operation
action statements anr; associated action times or other license conditions. The staff's position
for the use of compensatory measures, as described in GL 91-18, Rev.1 was established as a
means for affording licensees the ability to take direct and prudent compensatory measures
upon'tbe discovery of a non-conforming or degraded condition to maintain the plant in a safe
conditi'on until the non-conforming or degraded condition could be evaluated and corrected. It
was not envisioned, nor is it appropriate, that such compensatory actions be used to avoid
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futfilment of license conditions or technical specifications.
2. !s it permissible for McGuire to use the three-minute-rule for planned breaches of the control
room ventilation system or is a Technical Specification change needed?
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Response:
f
The McGuire Technical Specifications (TS) has a surveillance requirement which verifies that
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either CREVS train can maintain a positive pressure within the control room boundary. If the
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CREVS duct work or control room boundary is breached such that the CREVS system cannot
achieve and maintain this positive pressure, then this surveillance requirement cannot be met
and the appropriate TS actions need to be entered. This would mean entry into TS 3.0.3 when
in MODES 1,2,3 or 4 and/or immediate suspension of Core Afterations, and movement of
i
irradiated fLel assemblies when in MODES 5 and 6 or during movement of irradiated fuel
assemblies. The Technical Specification Branch (TSB) finds that the three minute-rule does
not provide sufficient time or. guaranty that the . surveillance requirement could be performed or
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that the newly sealed breaches can maintain the boundary positive pressure. Thus, TSB finds
that implementation of the three minute rule would be a violation of the McGuire Technical
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Specifications.
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The Technical Specificatio.n Branch and the Owners Group recognized that the Standard
Technical Specifications (STS) were inconsistent with regards to the remedial measures to be
taken when breaching various ventilation controlled boundaries. The Owners Group Technical
Specification Task Force (TSTF) submitted a generic change to the improved STS (TSTF-287)
.
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which corrects these inconsistencies to allow 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to restore the boundary to OPERABLE
status and verify that the subject ventilation system can maintain the specified positive or
)
- . negative pressure. The staff is current ly reviewing the changes proposed in TSTF-287 for
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- inclusion in the STS (NUREG 1430 to 1434). The Technical Specification Branch recommends
that the licensee update their technical specifications to incorporate the TSTF-287 changes
once approved.
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4.0 CONCLUSION
Based on the above evaluation the staff concludes that the use of such action like the use of
compensatory actions on the control room emergency ventilation system is a violation of the
technical specifications. Accordingly, the Region should coordinate with the Office of
Enforcement to initiate the appropriate enforcement action.
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