ML20141E803
| ML20141E803 | |
| Person / Time | |
|---|---|
| Site: | Monticello  |
| Issue date: | 06/18/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20141E780 | List: |
| References | |
| 50-263-97-06, 50-263-97-6, NUDOCS 9707010164 | |
| Download: ML20141E803 (20) | |
See also: IR 05000263/1997006
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION 111
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Docket No.
50-263
License No.
Report No.
50 263/97006(DRP)
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Licensee:
Northern States Power Company
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Facility:
Monticello Nuclear Generating Station
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Location:
414 Nicollet Mall
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Minneapolis, MN 55401
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Dates:
April 12 - May 27,1997
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inspectors:
A. M. Stone, Senior Resident inspector
J. Lara, Resident inspector
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Approved by:
J. McCormick-Barger, Chief
Reactor Projects Branch 7
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9707010164 970618
ADOCK 05000263
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EXECUTIVE SUMMARY
Monticello Nuclear Generating Station, Unit 1
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NRC Inspection Report 50-263/97006
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This inspection included aspects of licens6e operations, engineering, maintenance, and
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plant support. The report covers a 6-week period of resident inspection.
Ooerations
Control and performance of the reactor shutdown activities were excellent.
Communication and teamwork during the evolution were good (Section 01.2).
The inspectors concluded that the anticipated transient without a scram (ATWS)
system was tested in accordance with technical specifications (TSs) and as
described in the updated safety analysis report I'.*0AR). Operators responded
appropriately during simulated ATWS conditions (Section O2.1).
A violation of a TS-required procedure was identified for operators being unaware
that an essential service water pump was unnecessarily operating and had been
operating for about 46 hours5.324074e-4 days <br />0.0128 hours <br />7.60582e-5 weeks <br />1.7503e-5 months <br /> (Section 08.1).
Maintenance
The observed maintenance activities were performed in a professional manner and
in accordance with applicable TS and USAR requirements. However, isolation tags
for two valves were reversed because of inattention-to-detail by system engineering
(Section M1.1).
Ennineerina
The licensee's actions to address and resolve an inadequate net positive suction
head concern were appropriate. The decision to shut down and replace the torus
suction strainers was conservative (Gection E2.1),
The inspectors identified a concern regarding the adequacy of a TS which allowed
the alignment of two power sources through a common transformer. Discrepancies
between the as-design electrical system and USAR were also identified (Section
E2.2).
Licmcee corrective actions with respect to the reactor core isolation cooling
annunciator circuits were determined to be acceptable. An inspection followup
item was identified to review additional systems for fuse and drawing discrepancies
(Section E2.3).
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Report Details
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Summarv of Plant Status
The unit operated at power levels up to 100 percent power until May 9,1997, when
operators commenced a reactor shutdown as directed by plant management. A concern
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regarding the available net positive suction head (NPSH) for the core spray (CS) and
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residual heat removal (RHR) pumps was identified by plant personnel. After further
evaluation, plant management decided to shut down the unit to facilitate replacement of
the emergency core cooling system's torus suction strainers. This issue is discussed in
Sections 01.2 and E2.1.
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1. Operations
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Conduct of Operations
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01.1 General Comments
Using inspection Procedure 71707, the inspectors conducted frequent reviews of
ongoing plant operations. These reviews included observations of control room
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evolutions, shift turnovers, operability decisions, and logkeeping. Updated Safety
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Analysis Report (USAR) Section 13, " Plant Operations," was reviewed as part of
the inspection.
In general, the conduct of operations was acceptable. Operators' performance
during routine surveillances was excellent. Command and control during the
planned reactor shutdown were excellent.
01.2 Observations of Shutdown
a.
Insoection Scoce (71707)
As discussed in Section E2.1, the licensee conservatively decided to shut down the
reactor due to concems with the emergency core cooling system (ECCS) suction
strainers, On May 9,1997, operators commenced the shutdown. The inspectors
observed portions of the evolution. Documents reviewed included:
C.3. Shutdown Procedures
TS Table 4.1.1 and 4.1.2
b.
Observations and Findinas
The inspectors observed the infrequent evolution briefings conducted for both
operations crews involved in the shutdown. Extra non-licensed, licensed, and
senior reactor operators were available to support the operations crews. Nuclear
engineering personnel were also present. In each briefing, the shif t manager
emphasized self-checking practices; maintaining a questioning attitude: roles and
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responsibilities, including expectations on communication; and reactivity
management controls.
During the shutdown sequence, the licensee conducted individual control rod scram
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testing. During the test, the inspectors observed control room operators and also
accompanied non-licensed operators in the reactor building. The test was
conducted in a controlled manner with excellent communication between control
room operators, plant operators, and the nuclear engineer. The control room
operator continuously monitored core responses to the control rod manipulations.
The nuclear engineer provided excellent support to the operators.
The inspectors verified that the activities were performed in accordance with the
C.3 procedure and that TS-required surveillances were completed prior to changing
modes.
c.
Conclusions
Control and performance of the reactor shutdown activities were excellent.
Communication and teamwork during the evolution were good.
O2
Operational Status of Facilities and Equipment
O 2.1 Ennineered Safetv Feature System Walkdowns
The inspectors used Inspection Procedure 71707 to walk down selected portions of
the #11 and #12 emergency diesel generators (EDGs), the #13 diesel generator
(non-safety related), reactor core isolation cooling (RCIC), and high pressure coolant
injection (HPCI) systems. Minor housekeeping issues identified during the
walkdowns were promptly corrected by the licensee. No operability concerns were
identified.
02.2 Anticinated Transient Without a Scram Svstem Review
a.
Insoection Scooe (71707)
During this inspection period, the inspectors performed a review of the Anticipated
Transient Without Scram (ATWS) system. The purpose of this review was to verify
various operational and design features including the following:
Operation of the system in accordance with applicable TS requirements
Operation of the system in accordance with USAR description
System alignment in accordance with plant requirements
Surveillance procedures met the TS requirements
The inspectors reviewed the following documents:
TS Table 3.2.5
TS 3/4.13.H
USAR Sections 7.6.2 and 14.8
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Operations Manual B.5.6, " Plant Protection System"
Annunciator Response Procedures
Test 1227, Revision 7, "ATWS-RPT, ATWS-ARI, ASDS Rod Insertion and
B/U Scram Valve Functional Test"
Test 0279, Revision 2, "ATWS Reactor Level and Pressure Transmitter"
Test 0278a and b, Revision 6, "ATWS Recirculation Trip for Reactor
Pressure and Level Trip Unit Test and Calibration"
Work Order (WO) 9601857, Check / Adjust damping on ATWS transmitters
WO 9601874, Check / Adjust damping on ATWS transmitters
WO 9601877 Adjust Time Delay, ATWS Relay K101B
CR (Condition Report)95-117, "DVM time delay effects on timing of ATWS
pump trip time delay"
CR 94-280, " Spurious low-low level ATWS trip"
CR 92000179/399, " Reliability of ATWS mitigation systems"
CR 94000280, " Spurious low-low level ATWS trip on "B" channel"
CR 95000117, "ATWS system timer influenced by digital volt meter during
test"
Modification 930180, Reduce Sensitivity of RPV High Pressure SCRAM
Sensing Lines
SRI 96-026, " Time Response Adjustment of ATWS Level Transmitters
LT-2-3-180A-D and Level Trip Delay"
Calculation CA-93-082, High Pressure SCRAM Time Delay
b.
Observations and Finding
The inspectors verified that periodic surveillance testing was accomplished in
accordance with TSs. Logic drawings were reviewed to verify that relays were
properly challenged during surveillances. A detailed technical review of the
surveillance tests showed that specified acceptance criteria were appropriate and
reflected design parameters. The inspectors noted that formal calculations were
not available for the acceptance criteria; however, the licensee's effort to document
supporting calculations in surveillances was ongoing.
The material condition of the system was acceptable. Valves and electrical
equipment were verified to be in the correct positions. Outstanding WOs and CRs
did not impact system operability. The inspectors reviewed previous surveillance
tests and confirme'd that acceptance criteria were met. The inspectors also
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observed instrument and control technicians perform Test 0279. The procedure
was workable and the technicians performed in a professional manner.
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The inspectors observed two operations crews respond to ATWS situations during
simulator training. The scenarios involved an ATWS with and without a standby
liquid control (SBLC) system failure. The scenarios were challenging and required
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entries into several branches of the emergency operating procedures and abnormal
procedures. The significant operator actions from a probabilistic risk assessment
perspective included controlling reactor level and injecting SBLC. The crews
responded appropriately and demonstrated knowledge of the ATWS system.
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c.
Conclusions
The inspectors concluded that the ATWS system was tested in accordance with TS
and as described in the USAR. Operators responded appropriately during simulated
ATWS conditions.
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Miscellaneous Operations issues
08.1 (Closed) Unresolved item (URI) 50-263/97003-01: Operator Unawareness of an
Operating Emergency Service Water (ESW) Pump. The ESW pumps were normally
placed in a standby condition and were designed to automatically start upon a
transfer of the normal power source to the 4160 V buses to alternate power source
1 AR transformer or EDGs. On April 8,1997, a loss of power to the #15 essential
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. electrical bus occurred. Following the restoration of normal offsite power to bus
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15, operators performed walkdowns of control room panels and failed to identify
that the #13 ESW pump was still operating. As documented in inspection Report
(IR) 50-263/97003, this condition had existed for about 46 hours5.324074e-4 days <br />0.0128 hours <br />7.60582e-5 weeks <br />1.7503e-5 months <br /> prior to
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identification by the inspectors, on April 10,1997. During this time, four shift
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turnovers involving three crews had occurred between shift management, control
room operators, and auxiliary plant operators. Pump status lights in the control
room provided sufficient indications of an operating pump which should have been
identified by the on-shift crews. The licensee documented this issue in CR
97001149.
TS Section 6.5, " Plant Operating Procedures," required that detailed written
procedures covering plant operations areas be prepared and followed. TS Section 6.5.A.3 required written procedures covering actions to be taken to correct specific
and foreseen potential malfunction of systems or components, including follow-up
actions required after plant protective system actions have initiated. Administrative
procedure 4 AWi-04.01.01, " General Plant Operating Activities," Revision 17, step
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4.3.4.A required that all on-duty operators and the shift supervisor shall be aware
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of the plant status at all times. The failure of operations personnel from April 8 -
10,1997, to be aware of plant status, as evidenced by an unnoticed operating
safety-related pump, was contrary to the procedure and a violation of TS
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requirements (VIO 50 263/97006-01(DRP)).
11. Maintenance
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Conduct of Maintenance
M 1.1 General Comments
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a.
Insoection Scone (62703 and 61726)
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The inspectors observed all or portions of selected maintenance and surveillance
activities, included in the inspection was a review of the surveillance procedures or
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work orders listed as well as the appropriate USAR sections regarding the activities.
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b.
Observations and Findinas
In general, the inspectors found the work performed under these activities to be
professional and thorough. All work observed was performed with the work
package present and in active use. Technicians were experienced and
knowledgeable of their assigned tasks. The inspectors frequently observed
supervisors and system engineers monitoring job progress, and quality control
personnel were present whenever required by procedure. When applicable,
appropriate radiation control measures were in place.
The following work was observed. Specific concerns or observations are provided
where appropriate.
0026, APRM-Recirc Flow Instrumentation Calibration, Revision 20
0397a, SRV Low-Low Set System Quarterly Tests
WO 9704562, Collect Core Spray Pump Performance Data
WO 9703394: PC-14-2 Valve Leaks Throuah the Seat. The inspectors
independently verified the equipment isolation tagout and observed portions
of the post-maintenance test (PMT). The shift supervisor rejected the
original PMT because guidance on how to " verify no leakage through valve"
was not provided. The system engineer subsequently wrote specific steps
in an attachment to the test document.
WOs 9703795,9703797 and 9703798: Reolace Nitroaen Purae Solenoid
Valves SV3372. SV3373, and SV3381. The inspectors reviewed the
equipment isolation tags and identified that the tags placed on two root
valves were switched. Both valves were closed, therefore, this discrepancy
did not result in a personnel or equipment safety concern. The shift
manager immediately stopped the job until the discrepancy was resolved.
Prior to hanging the isolation tags, operators had noted that the root valves
were not labelled and requested assistance from the system engineer. The
system engineer reviewed the piping and instrument diagram and mistook
the valves' identities. Based on this inaccurate information, operators
subsequently hun 0 the tags on the wrong valves. Failure to hang the
isolation valves in accordance with the isolation procedure constituted a
violation of minor significance and is being treated as a Non-Cited Violation,
consistent with Section IV of the NRC Enforcement Policy
(50-263/97006 02).
WO 9704264: #12 EDG #2 Air Start Pressure Switch Huna UD. The
inspectors noted that the work was performed while the 1 AR transformer
was ooc of service and the IR transformer was degraded due to low voltage.
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The licensee responded that because the work did not render the EDG
inoperable, the reliability of the EDG would be increased. A probabilistic risk
assessment study showed an insignificant effect on risk. The inspectors
reviewed the USAR and TS and had no further concerns.
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Test 0013: IRM Scram and Rod Block /SRM Rod Block Calibration. This test
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was required per TSs 4.1 and 4.2 prior to the unit shutdown on May 9,
1997. The inspectors performed a technical review of the procedure to
verify that the acceptance criteria complied with TS-required values, the
sequence of steps did not pre-condition the test results, and the test was
conducted as described in the USAR. No discrepancies were noted.
Test 0081: Control Rod Drive Scram insertion Time Test. The inspectors
noted good communication between the plant operators, control room
operators, and the nuclear engineer. The evolution was conducted in a
controlled manner. Scram times were obtained from 113 fully withdrawn
control rods. Of the 113,8 control rods exceeded the 5 percent insertion
time acceptance criteria of 375 milliseconds. The diaphragms for the
associated scram solenoid pilot valves will be replaced prior to reactor
startup.
Test 1374: Monthiv Operability Test of #13 Diesel Generator. This diesel
generator was not safety-related but could be utilized during a station
blackout condition. The inspectors performed a technical review of the test
and verified that the system performed as described in USAR 8.4.2. The
inspectors noted that two indication lines showed signs of fretting caused by
loose metal clips. This was promptly resolved by the system engineer.
c.
Conclusions
The observed maintenance activities were performed in a professional manner and
in accordance with applicable TS and USAR requirements. However, isolation tags
for two valves were reversed because of inattention-to-detail by system
engineering.
M2
Maintenance and Material Condition of Facilities and Equipment (93702)
M2.1 Current Material Condition and Imoact on Ooerations Personnel
The inspectors conducted control room and plant inspections and interviewed
operations personnel to assess the material condition of plant equipment. During
this period, a pressure switch (PS 2-3-52-A), which provided an interlock for the
opening of the low pressure ECCS discharge valves, failed. The licensee
immediately initiated a work order and repaired the switch. The inspectors
reviewed TS table 3.2.2 and portions of USAR sections 6.2.2 and 6.2.3 and had no
concerns.
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Miscellaneous Maintenance issues (92700)
M8.1 (Closed) URI 50-263/97003-06: Personnel Errors During Undervoltage Relay
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Testing.
(Closed) Licensee Event Reoort (LER) 50-263/97006. RevisiorLQ: Emergency Diesel
Generators Started By Personnel Error During a Monthly Surveillance.
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On April 8,1997, surveillance Test 0301, " Safeguard Bus Voltage Protection Relay
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Unit Functional Test," Revision 21, was performed by testing undervoltage relays
and verifying that appropriate relay contacts closed upon the relays dropping out.
During the test, electricians failed to remove a test meter used to monitor continuity
across the relay contacts. As a result, the loss of voltage protection logic was
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satisfied resulting in the trip of the normal power source to 4160 V bus #15. This
resulted in the automatic start of the #11 and #12 EDGs and #11 EDG loading on
bus #15.
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The method to verify continuity (momentary contact or landing of meter leads) was
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left up to skill-of-the-craft, and there was no explicit procedural requirement to
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remove any installed test instruments upon completion of applicable procedure
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steps. Failure to provide adequate instructions for the performance of surveillance
Test 0301 is a violation of TS section 6.5.A.4, which required detailed written
procedures covering surveillance and testing requirements that could have an effect
on nuclear safety. However, this licensee-identified and corrected violation is being
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treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC
Enforcement Policy (NCV 50-263/97006-03).
As required by 10 CFR 50.73, on May 8,1997, the licensee submitted LER 97-
006, which documented the automatic actuation of an engineered safeguard
feature. The LER discussed the safety significance of the event,immediate actions,
corrective actions, and preventative actions. Corrective actions included meeting
with electrical maintenance personnel to discuss the lessons learned from this
event. Preventative actions included revising the surveillance procedure to provide
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instructions for the removal of installed test meters. Additionally, instead of using
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continuity measurements to monitor the status of relay contacts, voltage
measurement requirements were added. The inspectors witnessed the performance
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of the revised surveillance procedure 0301, " Safeguard Bus Voltage Protection
Relay Unit Functional Test," Revision 22, during the subsequent monthly testing of
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the degraded safeguards bus voltage relays. The test was satisfactorily performed.
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The inspectors considered the licensee's implementation of the corrective actions
discussed in the LER to be acceptable.
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M8.2 1 Closed) LER 50-263/97005. Revision 0: Failure to Analyze Diesel Fuel Samples
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Within the Technical Specification Required Surveillance Period, in response to
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Violation 50-263/96009-14, the licensee committed to review other surveillances
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for potential timeliness concerns. During this process, the licensee identified that
diesel generator fuel oil samples were taken monthly, but not analyzed within the
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TS surveillance time interval. Although analyzed late, all samples supported diesel
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operability. The procedure was revised to require the analysis prior to completing
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the surveillance. The inspectors considered this example to be acceptable
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implementation of corrective actions for a previous violation. Failure to analyze the
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fuel oil samples within the surveillance window is considered another example of a
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previous violation (VIO 50 263/96009 14).
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E2
Engineering Support of Facilities and Equipment
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E2.1
Concerns with Net Positive Suction Head for low Pressure ECCS Pomos
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a.
insoection Scoce (37551)
In February 1997, the licensee initiated a CR to evaluate the applicability of a NPSH
concern identified at another nuclear utility. On April 15,1997, the licensee
completed the evaluation and concluded that the concern was applicable. The
inspectors reviewed the licensee's evaluation, prompt operability determination, and
corrective actions. Several conference calls between cognizant NRC and licensee
staff members were held throughout this period. Also, the following documents
were reviewed:
LER 50-263/97007, " inadequate NPSH for the ECCS Pumps for Certain
Single Failures During Loss of Coolant Events"
CR 97001188, " Higher ECCS Suction Strainer Head Losses Calculated"
b.
Observations and Findinas
The current NPSH calculation assumed a 1-foot head loss per 10,000 gallons per
minute (gpm) through the suction strainers. The licensee determined that the actual
calculated head loss was about 11.7 feet. The licensee identified that under certain
conditions, the available NPSH for the CS pumps was insufficient and would result
in pump cavitation. Specifically, during a design bases loss of coolant accident, a
failure of the low pressure coolant injection (LPCI) loop select logic could cause all
four RHR pumps to inject into the broken recirculation pipe. This water would
suppress the drywell pressure and subsequently decrease available NPSH. The CS
pumps would be the only pumps available to recover reactor vessellevel. About 3
minutes into the accident, the available NPSH for the CS pumps would be less than
the required NPSH and would result in pump cavitation.
The licensee concluded that the CS pumps would remain operable and would
supply sufficient flow to the reactor vessel under deficient NPSH conditions. This
conclusion was based on previous vendor testing performed on a similar pump that
operated for several hours with NPSH deficits with no observable damage. The test
pump also supplied 90 percent flow for 30 minutes without damage. The licensee
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also performed calculations to show that the degraded flow was sufficient to re-
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flood and maintain level in the vessel.
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The inspectors requested support from the NRC Office of Nuclear Reactor
Regulation staff to review the licensee's basis for operability. The staff had several
technical questions and requested additional information with respect to (1) the
material similarity of the vendor-tested pump and that installed at the plant; (2) the
assumed containment overpressure available and required; and (3) how potential
strainer plugging from debris (as discussed in NRC Bulletin 96-03, " Potential
Plugging of Emergency Core Cooling Suction Strainers by Debris in Boiling Water
Reactors," was addressed.
The licensee performed strainer clogging calculations and concluded that debris
from insulation material had the potential to further degrade the available NPSH for
the CS pumps. On May 9,1997, the licensee conservatively decided to shut down
the reactor to replace the ECCS torus suction strainers.
c.
Conclusions
The licensee's actions to address and resolve the inadequate NPSH concern were
appropriate. The decision to snut down and replace the strainers was conservative.
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E2.2 USAR Chaoter 8 Electrical Svstems Concerns
a.
Insoection Scoce (37551)
The inspectors reviewed the licensee's offsite power supplies to evaluate whether
the plant electrical configurations were as described in the USAR and TS.
b.
Observations and Findinas
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A simplified electrical one-line diagram is shown in Attachment 1 of this report.
The USAR described three transformers to supply the site with offsite power from
substations and all three sources can provide adequate power for the plant's safety-
related loads. These included primary station auxiliary transformer 2R, reserve
transformer 1R, and reserve auxiliary transformer 1 AR. Transformers 2R and 1 AR
were considered one offsite source when 1 AR was supplied from 345-kilovolt (kV)
bus #1 since numerous common mode failures existed which could ause
simultaneous de-energization of both transformers.
in order to maintain 1R transformer operable, a minimum of 119 kV was required at
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the high voltage side of the transformer. The inspectors noted that on two recent
occasions, less than 119 kV was experienced at the high side of 1R transformer
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when the #10 transformer was taken out-of service. These two instances indicated
that 1R transformer was dependent on the 345-kV lines through the #10
transformer. The inspectors were concerned that system load growth had
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increased to where the plant would be outside the licensing basis whenever the
- 10 transformer provided power to both the 1 AR and 1R transformers. Although
the USAR was not clear on the dependence of the 119-kV and 345-kV lines on the
- 10 transformer, the licensee stated that the current design was within the
licensing basis. The inspectors were provided with a safety evaluation from a 1984
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modification (84MO41) which acknowledged the dependence on the #10
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transformer and possible low 115 kV bus voltage.
Additional reviews indicated that TS 3.9.A.1 allowed for continued plant operation
with transformers 1R and 1 AR serving as the two offsite sources. However, there
were no restrictions on both transformers being powered frorn the #10 transformer.
Thorefore, a loss of the #10 transformer would cause the unavailability of both
offsite sources; the de-energization of the 1 AR transformer and less than 119 kV at
the 1R transformor. The licensee stated that although allowed by TS, the 1R and
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1 AR transformers would not both be energized from the #10 transformer,
whenever possible. This operational restriction was not described in the TS or
USAR, but was in Operations Manual B.9.3-05, "345 kV Substation," section
A.2.c. The inspectors concluded that the current design of transformers 1R and
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1 AR being dependent on #10 transformer was not described in the licensee's USAR
and required further NRC review. This issue is an inspection Followup Item (IFl 50-
263/97006-04(DRP)) pending review by the Office of Nuclear Reactor Regulation.
Additional review by the inspectors indicated a discrepancy in USAR 8.3.3,
Performance Analysis. The USAR stated that " provisions are made for automatic,
fast transfer of the auxiliary load from the primary station transformer to the
reserve transformer or the auxiliary reserve transformer": (i.e. 2R,18, and 1 AR,
respectively). The inspectors noted that the electrical design included a fast
transfer feature from transformer 2R to 1R upon protective relaying actuation.
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However, there was no fast transfer feature of the auxiliary loads from transformer
1R to 1 AR. The licensee stated that there was never a fast transfer scheme for all
auxiliary loads among the three transformers. The inspectors noted that USAR
section 8.2.1 stated that transformers 2R and 1R were of adequate size to provide
the plant's full auxiliary load requirements. However, transformer 1 AR was sized to
provide only the plant's essential 4 kV buses and connected loads. The licensee
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was asked to evaluate the USAR discrepancy. The results of that evaluation will be
reviewed during a future inspection (IFl 50-263//97006-05(DRP)).
c.
Conclusions
The inspectors identified a concern regarding the adequacy of a TS which allowed
the alignment of two power sources through a common transformer. Discrepancies
between the as-design electrical system and USAR were also identified.
E2.3 As-Built Discreoancies in RCIC 250 Vdc Motedfipatrol Center (MCC)
a.
Insoection Scoce (37551)
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The inspectors performed a review of the licensee's 50.72 event notifications
associated with the RCIC system.
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b.
Observations and Findinas
On May 6,1997, the licensee reported to the NRC that the RCIC system was
declared inoperable due to an undervoltage alarm on the 250 volts-direct current
(Vde) MCC. The following day, the RCIC was returned to service and declared
operable after replacement of internal components on the MCC undervoltage
monitoring system. Later that day, the licensee again notified the NRC regarding a
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loss of the undervoltage alarm monitoring system for the RCIC 250 Vdc MCC. In
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this case, the ability to monitor the available power to primary containment group 5
isolation valves was lost. A loss of power could have gone undetected and;
therefore, could have resulte.d in a failure of the Group 5 valves to close on
demand.
Corrective action for the first event included replacement of internal electronic
components followed by a burn-in test of the annunciator monitor circuit. For the
second event, additional electronic components were replaced which were not
replaced for the first event. The inspectors reviewed the licensee's corrective
actions and post-maintenance testing and determined that they were acceptable.
During the review of ongoing work activities, the inspectors identified discrepancies
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regarding as-built configuration. These included:
as-built wiring connections for the reflash annunciator monitor were not
accurately reflected in drawing NF-36969-1;
fuses sized at 1 ampere (A) and 1.5 A were found installed whereas drawing
NF-36969-1 required 0.5 A fuses;
in MCC cubicle D31114 (RCIC test return valve MO-3502), a 6% A fuse
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was installed where a 6 A fuse was required (also, different fuse type)
undervoltage relay isolation fuses were shown on individual MCC bucket
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drawings but not on Class 1 elementary drawings. Class 1 drawings were
defined as drawings which were considered essential to safe and reliable
plant operation,
it should be noted that the wiring and fuses within the reflash annunciator
enclosure (first 2 items above) were categorized as nonsafety-related. At the end
of the inspection period, the licensee was reviewing past modifications and design
documents to determine if the discrepancies were the result of past design
weaknesses or current design and fuse replacement practices. This issue will be an
Inspection Followup Item pending further NRC inspections of additional MCC
circuits to determine if the incorrect fuse and drawing omissions were examples of
broad deficiencies (IFl 50-263/97006-06(DRP)).
c.
Conclusions
Licensee corrective actions with respect to the RCIC annunciator circuits were
determined to be acceptable. An IFl was identified to review additional fuse
configurations and drawings.
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E2.4 Core Sorav Test Retum Valve Position Limit Switch
a.
Insoection Scone (37551)
The inspectors reviewed the licensee's corrective actions regarding the potential for
the CS test return valve to remain partially open following an ECCS signal.
b.
Observations and Findinas
CR 97001001, " Potential Limit Switch Closure of CS Test Return MOVs on ECCS
Initiation," documented that modification 90ZO71 changed the control logic for the
CS Test return motor-operated valvas (MO-1749 and MO-1750). The change was
intended to bypass the close torque switch on an ECCS auto initiation signal,
thereby closing on the limit switch. However, this logic change resulted in the
valves closing to the position where the close indication light limit switch was set
(approximately 98 percent). Therefore, the valves could remain partially open and
divert flow from the reactor to the torus.
At the time that the licensee identified this issue, the test return valves had been
manually seated closed with the torque switch; therefore, no operability concerns
existed. The licensee performed WOs 9704004 and 9704065, CS Valves MO-
1749/1750, " Limit Switch Setting Determination," to determine the true valve
position at the close limit switch indication.
The inspectors reviewed the operability determination and observed the
implementation of the WOs to evaluate the effectiveness of the corrective actions.
The test return valves were stroked open and manually closed to determine the
valves' position based on the !!mit switch indication light. The licensee's evaluation
concluded that the vaives were essentially closed upon limit switch actuation.
Additionally, mcior contactor dropout time and motor inertia would p< ovide an
additional seating force. The inspectors did not identify any deficie 1cies during the
review of the licensee's operability and reportability determinations.
c.
Conclusions
The licensee's evaluation of the conditio, r.nd corrective actions were determined
to be acceptable.
E8
Miscellaneous Engineering issues (37551)
E8.1
(Closed) IFl 50-263/96002-01: This item pertained to a discrepancy in the USAR
regarding the performance of surveillances. The inspectors observed that
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instrument technicians lifted covers off of instrumentation during surveillances.
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However, USAR section 7.6.3.3.1 stated that operations personnel must remove
the cover plate, access plug, or sealing device from instruments. The licensee has
revised the USAR section (revision 14) to allow any authorized personnel to remove
the cover plate, access plug, or sealing device from instruments.
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E8.2 (Closed) IFl 50-263/96002-02: This item pertained to a discrepancy in the USAR
regarding the required fuel pool cooling temperatures. USAR 10.2.2.3 contained
two may uum spent fuel storage pool temperatures (125 degrees Fahrenheit ( F)
and 140 F). This issue was subsequently reviewed by the NRC as documented in
IR 50-263/96003, paragraph 3.4. Using more realistic decay heat loads, the
licensee determined a maximum spent fuel pool temperature of 140 F. The
licensee has revised USAR 10.2.2.3 (revision 14) to reflect the results of the
analysis.
E8.3 (Closed) IFl 50-263/96005-05: This item pertained to a discrepancy in USAR
section 8.5.2.2 which stated that each 125 Vdc battery was rated for 96 As at a
4-hour rate. However, the actual battery capacity as indicated on the battery
nameplate was 95 As at a 4-hour rate. The licensee had evaluated the actual
battery capacity and determined that the battery size was sufficient to carry design
loads. The licensee has revised the USAR section (revision 14) to reflect the actual
battery capacity.
IV. Plant Suonort
R1
Conduct of Radiological Protection and Chemistry Controls (71750)
During normal resident inspection activities, routine observations were conducted in the
areas of radiological protection and chemistry controls. No discrepancies were noted.
P1
Conduct of Emergency Preparedness Activities (71750)
During normal resident inspection activities, routine observations were conducted in the
area of emergency preparedness. No discrepancies were noted. Three notifications were
made to the NRC pursuant to 10 CFR 50.72. The licensee later retracted two notifications
involving a foss of a power monitoring system for the RCIC motor control center. The
inspectors agreed these events were not reportable.
S1
Conduct of Security and Safeguards Activities (71750)
During no; mal resident inspection activities, routine observations were conducted in the
areas o' security and safeguards activities. No discrepancies were noted. On May 14
1997, the intpectors met with the security superviser to discuss current security issues.
Topics included personnel performance trending, new training initiatives, status of
corrective actions to previously identified concerns, and material condition of security-
related equipment.
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V. Manaaement Meetinas
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Exit Meeting Summary
On June 3,1997, the inspectors presented the inspection results to the Plant Manager and
the Manager, Quality Services. The licensee acknowledged the findings presented.
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The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information was identified.
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PARTIAL LIST OF PERSONS CONTACTED
Licensee
M. Wadley, Vice President, Nuclear Generation
W. Hill, Plant Manager
M. Hammer, General Superintendent, Maintenance
K. Jepson, Superintendent, Chemistry & Environmental Protection
L. Nolan, General Superintendent, Safety Assessment
M. Onnen, General Superintendent, Operations
E. Reilly, Superir:tendent, Plant Scheduling
C. Sch!bonski, General Superintendent, Engineering
A. Ward, Manager, Quality Services
J. Wiridschill, General Superintendent, Radiation Protection
L. Wi P.orsen, Superintendent, Security
,
B. Day, Training Manager
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INSPECTION PROCEDURES USED
IP 37551:
Onsite Engineering
IP 61726:
Surveillance Observations
IP 62703:
Maintenance Observations
IP 71707:
Plant Operations
IP 71750:
Plant Support
IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor
Facilities
IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors
ITEMS OPENED, CLOSED, AND DISCUSSED
Ooened
50-263/97006-01
Failure to Follow Procedure: Operators Did Not Know Status of
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ESW Pump
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50-263/97006-02
NCV Failure to Hang isolation Tags on Correct Valves
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50-263/97006-03
NCV Failure to Provide Adequate instructions for Performance of
Surveillance Test
50-263/97006-04
IFl
Restrictions on Operation with #10 Transformer
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50-263/97006-05
IFl
USAR Discrepancy Regarding Fast Transfer Capability
50-263/97006-06
IFl
As-Built Discrepancies in RCIC Motor Control Center
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Closed
50-263/96002-01
IFl
Discrepancy Between USAR Description and Conduct of
Surveillances
50-263/96002-02
IFl
Discrepancy in USAR Regarding Fuel Pool Temperatures
50-263/96005-06
IFl
Discrepancy in USAR Regarding Battery Capacity
50-263/97003-01
Operator Unawareness of Operating ESW Pump
50-263/97003-06
Personnel Errors During Undervoltage Relay Testing
50-263/97005-00
LER
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Failure to Analyze Diesel Fuel Samples Within TS Required
Surveillance Period
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50-263/97006-00
LER
Emergency Diesel Generators Started By Personnel Error
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During a Monthly Surveillance
50-263/97006-02
NCV Failure to Hang Isolation Tags on Correct Valves
50 263/97006-03
NCV Failure to Provide Adequate instructions for Performance of
Surveillance Test
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Discussed
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50-263/96009-14
Test Results Not Evaluated Prior to Return of Equipment to
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Service
50-263/97007-00
LER
Inadequate NPSH for the ECCS Pumps for Certain Single
Failures During Loss of Coolant Events
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LIST OF ACRONYMS USED
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.A
Ampere
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Anticipated Transient Without Scram
CR
Condition Report
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Degrees Fahrenheit
DRP.
Division of Reactor Projects
ECCS-
. Emergency Core Cooling System
ESW -
Emergency Service Water
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gpm
. Gallons Per Minute
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High Pressure Coolant injection
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IFl
inspection Followup Item
IR .
Inspection Report
kV
LER-'
Kilovolt
Licensee Event Report
Low Pressure Coolant injection
Motor Control Center
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Non-Cited Violation
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Net Positive Suction Head
Post-Maintenance Test
Reactor Core Isolation Cooling
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RHR'
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SBLC
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TS
Technical Specification
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Updated Safety Analysis Report
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Vdc
Volt-Direct Current
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Violation
V
Volt
Work Order
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ATTACHMENT 1
Simplified Electrical Diagram
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No.10
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