ML20056D167
| ML20056D167 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 07/13/1993 |
| From: | Belisle G, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20056D154 | List: |
| References | |
| 50-338-93-18, 50-339-93-18, NUDOCS 9308050053 | |
| Download: ML20056D167 (10) | |
See also: IR 05000338/1993018
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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101 MARIETTA STREET, N.W., SUITE 220
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ATLANTA, GEORGIA 303234199
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Report Nos.:
50-338/93-18 and 50-339/93-18
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Licensee:
Virginia Electric & Power Company
5000 Dominion Boulevard
Glen Allen, VA 23060
Docket Nos.: 50-338 and 50-339
Facility Name: North Anna 1 and 2
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Inspection Conducted: May 9 - June 19, 1993
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Inspectors:
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JohnYork,TcKngSeniorResidentInspector
Date Signed
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D. R. TayloffRp) dent Inspector
Date Signed
Accompanying Inspector: A. B. Ruff
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G. A. Belisle, SectidTPChief
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Division of Reactor Projects
SUMMARY
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Scope:
This routine inspection by the resident inspectors involved the following
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areas: plant status, operational safety verification, maintenance
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observation, modifications, surveillance observation, and licensee event
report followup.
Inspections of licensee backs':ift activities were conducted
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on the following days: June 5 and 6, 1993.
Results:
In the operations area:
A switching order was carried out to isolate switchyard transformer No. 1 for
preventive maintenance. The procedures used to perform the evolution and
communications to the control room were effective (para 4.b).
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In the maintenance / surveillance area:
A violation was identified when hydrogen analyzer (1-HC-H2A-101) pressure
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switch (PS-3) tubing (sensing line) was discovered to be disconnected. This
rendered the hydrogen analyzer inoperable for a period of time that exceeded
the Technical Specification Limiting Condition for Operation. The problem was
930B050053 930713
ADOCK 05000338
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thought to have been caused by failure to implement steps in an I&C
calibration procedure and is another example of recent problems identified
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with implementing I&C procedures (para 3.a).
Small concentrations of water were identified in the Unit 2 turbine AFW pump
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lube oil. The amount of water was determined not to be an operability
concern.
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In the engineering technical support area:
The addition of eleven vent valves on the Unit 1 LHSI system appears to have
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decreased the pressure transients and pressure peaks on the system during LHSI
pump starts. System engineering involvement with testing of the system and
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data analysis was evident (para 6.a).
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The inspectors observed the replacement of some Thermo-Lag and will continue
to observe the modification (para 5).
In the safety assessment / quality verification area:
A critique of a practice emergency drill was self-critical. Some weaknesses,
primarily attributed to poor communications, were identified. A second
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practice drill is being held in July (para 3.b).
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REPORT DETAI S
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1.
Persons Contacted
Licensee Employees
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L. Edmonds, Superintendent, Nuclear Training
- R. Enfinger, Assistant Station Manager, Operations and Maintenance
J. Hayes, Superintendent of Operations
D. Heacock, Superintendent, Station Engineering
- G. Kane, Station Manager
- P. Kemp, Supervisor, Licensing
W. Matthews, Superintendent, Maintenance
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J. O'Hanlon, Vice President, Nuclear Operations
- D. Roberts, Supervisor, Station Nuclear Safety (Conference Call)
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R. Saunders, Assistant Vice President, Nuclear Operations
D. Schappell, Superintendent, Site Services
R. Shears, Superintendent, Outage and Planning
- J. Smith, Manager, Quality Assurance
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A. Stafford, Superintendent, Radiological Protection
- J. Stall, Assistant Station Manager, Nuclear Safety and Licensing
Other licensee employees contacted included engineers, technicians,
operators, mechanics, security force members, and office personnel.
NRC Resident Inspectors
- J, York, Acting Senior Resident Inspector
- D. Taylor, Resident Inspector
- Attended exit interview
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2.
Plant Status
Both units operated the entire inspection period at or near 100 percent
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power.
3.
Operational Safety Verification (71707)
The inspectors conducted frequent visits to the control room to verify
proper staffing, operator attentiveness and adherence to approved
procedures. The inspectors attended plant status meetings and reviewed
operator logs on a daily basis to verify operational safety and
compliance with TS and to maintain awareness of the overall operation of
the facility.
Instrumentation and ECCS lineups were periodically
reviewed from control room indications to assess operability.
Frequent
plant tours were conducted to observe equipment status, fire protection
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programs, radiological work practices, plant security programs and
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housekeeping. Deviation Reports were reviewed to assure that potential
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safety concerns were properly addressed and reported. Selected reports
were followed to ensure that appropriate management attention and
corrective action was applied.
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t. .
Inoperable Hydrogen Analyzer
The inspectors reviewed DR 93-800, which stated that the tubing
(sensing line) for pressure switch PS-3 was found disconnected.
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The pressure switch is for containment hydrogen analyzer
1-HC-H2A-101. This condition was discovered on May 9 by an
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auxiliary operator while hanging configuration control labels.
A review conducted by the licensee showed this tubing was last
disconnected e February 9, 1993, Instrument Calibration Procedure
ICP-HC-1-H2A-101, Containment Hydrogen System Reactor Containment
Hydrogen Analyzer. The tubing was discennected during the
procedure while performing calibrating of pressure switch PS-3.
It is believed that the tubing was not properly reconnected
following this calibration. The pressure switch is used to
provide a system trouble alarm in the event of low flow through
the analyzer while in operation. Once this condition was
discovered, the analyzer was calibrated and returned to service.
With the sensing line disconnected, the hydrogen analyzer is
inoperable beccuse it would give an erroneous analysis.
TS 3.6.4.1 requires two independent containment hydrogen analyzers
(shared between units). The action statement allows one analyzer
to be inoperable for up to 30 days and both to be inoperable for
seven days. The hydrogen analyzer in question was thought to be
inoperable for a period of 89 days without the requirements of the
action statement be;ng performed. The inspectors reviewed the SR0
logs and confirmed that the second analyzer was never
out-of-service for a period longer than that allowed by TS. The
failure to meet the TS requirements for hydrogen analyzer
operability is identified as violation 50-338/93-18-01.
The inspectors reviewed the ICP and discussed this concern with
the licensee. Step 4.'4, of the procedure, gives instructions for
calibrating pressure switches PS-2 and PS-3.
Following the
calibration, there is a procedural step which states, " Remove test
equipment from the test connection and restore PS-3 tubing to
normal . " The connection is also checked by return-to-service step.
4.5.6 which states, " Verify PS-2 and PS-3 tubing restored to
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normal"; however, this is not an independent verification and can
be perform =d by the same individual who originally connected the
tubing.
Further, performance of step 4.4 " analyzer calibration"
would have caught this condition by receiving the low flow alarm
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during the calibration.
However, step 4.4 was performed prior to
step 4.3.
Nothing in the procedure prohibited this.
To prevent
this condition from recurring, a PAR was made to the procedure.
The inspectors also discussed with the licensee the possibility of
a containment breach during system operation. Based on the
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operation of the system and the location of the i" PS-3 tubing,
the opening would create a point of in-leakage not out-leakage.
The licensee confirmed this with the hydrogen analyzer vendor.
Prior to finding PS-3 tubing disconnected, an adverse trend in the
performing I&C procedures was noted by the licensee and the
inspectors. A violation for performance errors was issued in NRC
Inspection Report Nos. 50-338,339/93-14 along with a summary of
errors.
Since that time, the inspectors attended an 508 meeting
to discuss a CNS North Anna I&C performance review report. The
report provided a detailed description of recent I&C events and
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causes.
Recommendations from the report included revising
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expectations and providing training on independent and
simultaneous verifications.
Further recommendations included a
procedure upgrade program review to determine corrective actions
needed to address the identified weaknesses with the technical
review and validation of technical procedures. The report also
stated that the procedure update program needs to be reviewed with
respect to limited expertise, limited resources and performance
measures. The report also identified several enhancements. A
Management level 1 project activity was initiated to implement the
I&C Human Performance Improvement Plan. To date, licensee
management has been aggressive in identifying causes for the
apparent trend in I&C performance and implementing corrective
actions.
The PS-3 tubing disconnect event was reported to the NRC
by LER 50-338/93-16.
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b.
Practice Emergency Drill
On June 16, the inspectors observed the licensee perform a
practice emergency drill. This drill was not required by
regulations.
The control room simulator, TSC, and OSC were manned
during the drill. The scenario cor.sisted of an operational basis
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earthquake causing several equipment related challenges including
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a small RCS leak, total loss af charging capability, and a
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containment breach. The drill scenario led to declaring a site
area emergency and full accountability of station personnel.
During the drill, the inspectors noted several deficiencies
concerning communications. These deficiencies were also
identified by the licensee.
These communication deficiencies,
along with other licensee identified deficiencies were discussed
during the drill critique.
To ensure that the drill deficiencies are properly resolved, the
licensee intends to have a second practice drill in July.
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c.
Potential Problem With Rod Control System
The licensee evaluated the rod control event that occurred at the
Salem plant to determine if it applied to North Anna. This
potential problem involved the rod control system that could cause
an inadvertent withdrawal of one or more control rod cluster
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assemblies in a selected bank. Westinghouse and the owners group
are evaluating this event. The licensee briefed the licensed
operators on this event and explained the potential failure mode.
The operators were cautioned to be alert for rod movement. The
operators continue the normal process of verifying that rod motion
is proper for the required movement. The inspectors reviewed the
safety evaluation 93-SE-JCO-004 and the justification for
continued operation 93-04.
One violation was identified.
4.
Maintenance Observation (62703)
Station maintenance activities were observed / reviewed to ascertain that
the activities were conducted in accordance with approved procedures,
regulatory guides and industry codes or standards, and in conformance
with TS requirements.
a.
AFW Pump 011 Change
On May 27, lube oil for the Unit 2 steam turbine driven AFW pump
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was changed due to a high concentration of water. The work was
performed using skill-of-the craft per WO 162481. The inspectors
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witnessed removing the pump from service per M0P 31-03 and tagout
for the work, and also observed change out of the lube oil and
removal of the lube oil cooler to test for leakage.
Performance
of the M0P and tagout by the auxiliary operator are thorough. The
oil was changed because the water content exceeded manufacturer's
recommendations.
Following the monthly PT of the turbine driven
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AFW pump on May 18, the oil was sampled.
The analysis and results
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of that sample were determined to be out-of-spec at 0.4% water
content, but it was not reported to maintenance engineering until
May 26. At that time, a second sample was taken from the oil
reservoir and it indicated a 4% water content. This sample was a
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stagnant sample was not representative oil sample. The inspectors
noted that the oil being removed from the reservoir was milky,
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indicating water intrusion. A sample drawn from the reservoir
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while purging the bad oil confirmed water but at a lower
concentration of 0.326%. The lube oil cooler was tested and no
leaks were identified.
The inspectors discussed the water content of the oil with site
engineering to verify that low water concentrations are not an
immediate operability concern. The system engineer stated that
operability was not a problem but noted that low water in the oil
concentrations could have a long term degradation effect on the
bearings. The manufacturer recommends oil changes when the
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percent water reaches 0.2%.
The inspectors reviewed DR 93-267
written February 9,1993, for the same problem.
The DR resolution
recommended increased sampling from once per quarter to once per
month to correspond with the monthly pump run. The DR further
recommended maintenance engineering involvement if the percent of
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water approaches 0.2%.
For this last case, the sample was drawn
on May 18, but maintenance engineering was not informed until 8
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days later. After the oil was changed out, the pump was run
satisfactorily. Deviation report 93-909 was issued to document
the most recent problem.
b.
Switchyard Maintenance
On June 15, the inspectors observed performance of a switching
order which isolated switchyard transformer No.1 (500 KV/36.5 KV)
for preventive maintenance. The switching, isolation of the
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transformer, and the lineup to ensure that the power for vital
loads supplied by transfer Bus "F" remained available from an
offsite source was performed in a satisfactory manner. The
inspectors verified that TS 3.8.1.1 requirements for two
independent circuits between the offsite transmission network and
the onsite Class IE distribution system were maintained.
The switching operation was accomplished using 0-M0P-26.5,
Transferring "C" RSS transformer from Bus 3 to Bus 5 and returning
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to Bus 3 from Bus 5; 0-M0P-26.20, 34.5 KV Bus No. 3 Maintenance,
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and 0-M0P-26.9, 230 and 500 KV Equipment Switching. The
inspectors observed that the personnel involved discussed each
procedure step prior to performing it and they also informed the
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control room prior to any action that could effect the units. The
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M0Ps were well written and the switchyard components were well
labelled.
No violations or deviations were identified.
5.
Modifications (37828)
Thermo-Lag Replacement in the Auxiliary Building
The licensee uses Thermo-Lag 330 fire barrier systems in panel and
conduit shapes as radiant shields (one half hour fire rating) and as one
and three hour fire barriers at North Anna. Thermo-Lag is not used as a
fire barrier system for cable trays.
The Thermo-Lag in conduit shapes
is used as a fire barrier to protect the power cables for Unit I
charging pump IC and Unit 2 component cooling pump 1A.
The licensee is
currently replacing this material with Interam E-50 wrap (a 3M product).
The inspectors observed removing part of the Thermo-Lag in locations
where additional supports were required because of the additional weight
added due to the higher density 3M Interam E-50 wrap. Three layers of
3M Interam E-50 are being installed on the two armored cables.
Part of
the installation of the first two layers was observed by the inspectors.
A discussion was held concerning overlap, banding of the wrap, caulking,
and training of the installers by the 3M company.
Inspections and
acceptance criteria were discussed with the QC inspector observing the
job.
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In the licensee's response of April 12, 1993, to Generic Letter 92-08,
Thermo-Lag 330-1 Fire Barriers, it was stated that preliminary _ plans for
replacement had been made and that final plans would be conveyed to the
NRC. This supplemental response was being prepared at the end of the
inspection period. The original submittal states that any new fire
barrier system installed will satisfy NRC regulatory requirements for
one and three-hour rated barriers.
Licensee management stated in a
telephone conference with the NRC that until the applicable licensing
actions are taken, fire watches will be maintained in order to comply
with the 10 CFR 50 Appendix R requirements.
No violations or deviations were identified.
6.
Surveillance Observation (61726)
The inspectors observed / reviewed TS required testing and verified that
testing was performed in accordance with adequate procedures, that test
instrumentation was calibrated, that LCOs were met and that any
deficiencies identified were properly reviewed and resolved.
a.
LHSI Pump PT
On May 24, the inspectors observed performance of I-PT-57.lA,
Emergency Core Cooling Subsystem-Low Head Safety Injection Pump
(1-SI-P-1A).
Incorporated into the procedure was a one time
change to allow measuring transient the pressure surges during the
pump start and to calculate the gas void in the system.
During
the last refueling outage,11 additional vents were added to the
Unit 1 LHSI system to allow for better venting. Gas voids in the
piping have been the cause for a long standing problem with
excessive pressure spiking during pump starts.
Pressure spiking
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has lead to a cracked weld on instrument tubing and relief valves
lifting. One relief valve on Unit 2, 2SI-RV-28458, failed to
reseat following lifting and is currently gagged shut. The gagged
relief valve is scheduled to be replaced during the next refueling
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outage. The Unit 2 LHSI system is also going to be modified
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during this outage.
During the test, a peak pressure of 318 psi occurred for about 0.2
seconds. This pressure is above the relief valve setpoint of 257
psig and the relief valve briefly unseated.
Seventy ml of water
discharged from the relief valve during the pressure transient.
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The inspectors noted that LHSI pipe movement (a normal result of
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pressure transient pump starts) was not nearly as severe as was
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observed during previous pump starts before the additional vent
installation.
Following the test run, the void in the LHSI piping
was determined by slowly depressurizing the system to a collection
bottle and measuring the amount of water displaced.
Based on the
calculation, 0.55 cubic feet of gas void existed.
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On May 28, the inspectors attended a SNSOC meeting which included
an update of the LHSI pressure surge problem.
The most recent
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pump start was compared to previous starts.
From this testing, it
was concluded that the peak pressure decreased and that there are
fewer transient pressure peaks.
For example, during a September
1992 test, peak pressure reached 449 psig.
In December 1992, the
pressure reached 420 psig. The current pressure test shows a 25
percent pressure decrease. The licensee will continue to collect
data to establish an optimum venting periodicity.
It appears the
addition of the vents has decreased pressure transients and
pressure peaks on the system during LHSI pump starts. System
Engineering involvement in analysis of the test data and
presentation of data to SNS0C was evident.
b.
Feedwater Valves Partial Stroke Test
On June 14, the inspectors observed 1-PT-213.24, Valve Inservice
Inspection (Feedwater Regulator Valves Partial Stroke).
The
procedure verifies that the main feedwater regulator valves and
the bypass feedwater regulator valves are operable by performing a
partial stroke of each valve.
Test observations were made from the Unit I mechanical equipment
room where an auxiliary operator was also stationed to observe
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valve stem motion. The test was satisfactory. The surveillance
was performed to meet Section XI inservice test requirements for
the valves.
No violations or deviations were identified.
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7.
Licensee Event Report Followup (92700)
The following LERs were reviewed and closed. The inspectors verified
that reporting requirements had been met, that causes had been
identified, that corrective actions appeared appropriate and that
generic applicability had been considered. Additionally, the inspectors
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confirmed that no unreviewed safety questions were involved and that
violations of regulations or TS conditions had been identified.
(Closed) LER 50-338/92-06, Manual Reactor Trip during Startup when Four
Rods Dropped into the Core
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Unit I was in a shutdown condition and a reactor startup was initiated
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on March 5, 1992. During the start up with control bank A rods at 208
steps and control bank B rods at 80 steps, the rods in group 2 (4 rods)
of control bank B dropped into the core.
The reactor trip breakers were
manually opened in accordance with Abnormal Procedure (AP-1.2) and all
the other rods were inserted (dropped) into the core. The NRC was
notified, EN 22941, as required by the Code of Federal Regulations.
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An investigation by the licensee identified that the CRDM firing cards
were degraded with circumferential cracks in the soldering joints. The
card was replaced, and subsequently all firing cards for both Unit I and
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2 were visually inspected. Cards that showed excessive aging and cracks
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in solder joints were replaced with a new style firing card.
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addition, preventive maintenance procedures I-IPM-RCS-001 and
2-IPM-RCS-001, which were reviewed by the inspector, were developed to
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routinely inspect the Rod Control Cabinets every refueling outage.
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Exit (30703)
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The inspection scope and findings were sumarized on June 23, 1993, with
those persons indicated in paragraph 1.
The inspectors described the
areas inspected and discussed in detail the inspection results listed
below. The licensee did not identify as proprietary any of the material
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provided to or reviewed by the inspectors during this inspection,
Dissenting coments were not received from the licensee.
Item Number
Description and Reference
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VIO 50-338/93-18-01
Inoperable Hydrogen Analyzer (Paragraph 3.a)
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10.
Acronyms and Initialisms
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CFR
Code of Federal Regulations
Corporate Nuclear Safety
Control Rod Drive Mechanism
DR
Deviation Report
Instruinentation and Control
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Instrument Calibration Procedure
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KV
Kilovolts
LC0
Limiting Condition for Operation
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LER
Licensee Event Report
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LHSI
Low Head Safety injection
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Milliliter
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M0P
Maintenance Operating Procedure
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NRC
Nuclear Regulatory Comission
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Operational Support Center
Procedure Action Request
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Pounds Per Square Inch Gage
Periodic Test
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Quality Control
Reserve Station Service
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SNSOC
Station Nuclear Safety and Operating Comittee
SOB
Station Oversight Board
Senior Reactor Operator
TS
Technical Specification
Work Order
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