ML20127K927
| ML20127K927 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 05/22/1985 |
| From: | Branch M, Elrod S, Luehman J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20127K910 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-2.B.1, TASK-2.E.4.1, TASK-2.F.2, TASK-2.K.3.05, TASK-TM 50-338-85-12, 50-339-85-12, IEIN-83-84, NUDOCS 8506270658 | |
| Download: ML20127K927 (10) | |
See also: IR 05000338/1985012
Text
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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101 MARIETTA STREET,N.W.
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ATLANTA, GEORGI A 30323
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Report Nos.: 50-338/85-12 and 50-339/85-12
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Licensee: Virginia Electric and Power Company
Richmond,.VA 23261
Docket Nos.: 50-338 and 50-339
License Nos.: NPF-4 and NPF-7-
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Facility Name: North Anna 1 and 2.
Inspection Conducted: April'1 - May 5, 1985
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Inspectors:
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M. W.
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,' Senior Resident Insp64 tor
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J. G.
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S.~Elrof. Section Chief
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Division of Reactor Projects
SUPEARY
Scope:
This routine inspection by the resident inspectors involved 167
inspector-hours on site in the areas of licensee event reports, previously
identified items, engineered safety features (ESF) walkdown,1NI action plan
items, operational safety . verification, monthly maintenance and monthly
> surveillance.
Results:
One -violation and one deviation were identified: Failure to properly
perform ' surveillance, paragraph 10, and failure to properly set the turbine load
limiter, paragraph 9, respectively.
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REPORT DETAILS
1.
Licensee Employees Contacted
E. W. Harrell, Station Manager
G. E. Kane, Assistant Station Manager
M. L. Bowling, Assistant Station Manager
J. A. Stall, Superintendent, Technical Services
J. R. Harper, Superintendent, Maintenance
R. O. Enfinger, Superintendent, Operations
G. Paxton, Superintendent, Administrative Services
A. L. Hogg, Jr., Quality Control (QC) Manager
S. B. Eisenhart, Licensing Coordinator
J. R. Hayes, Operations Coordinator
J. P. Smith, Engineering Supervisor
R. C. Sturgill, Engineering Supervisor
D. E. Thomas, Mechanical Maintenance Supervisor
A. H. Stafford, Health Physics Supervisor
E. C. Tuttle, Electrical Supervisor
R. A. Bergquist, Instrument Supervisor
F. P. Miller, Quality Assurance (QA) Supervisor
F. T. Terminella, QA Supervisor
G. Flowers, Licensing Coordinator
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J. Leberstein, Licensing Coordinator
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Other licensee employees contacted included technicians, operators,
mechanics, security force members and office personnel.
2.
Exit Interview
The inspection scope and findings were summarized on May 7, 1985, with those
persons indicated in paragraph 1 above.
The licensee acknowledged the
inspection findings.
The licensee did not identify as proprietary any of
the materials provided to or reviewed by the inspector during this
inspection.
3.
Licensee Action on Previous Inspection Findings
Not inspected.
4.
Unresolved Items
An Unresolved Item is a matter about which more information is required to
determine whether it is acceptable or may involve a violation or deviation.
One unresolved item was identified during this inspection and is discussed
in paragraph 8.
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5.
Plant Status
Unit 1 operated at or near 100% during the entire inspection period.
Unit 2 entered the inspection period operating at or near 100%. However, on
April 18, at 0608, the unit was taken off line due to high unidentified
reactor coolant system leakage.
The leakage was detennined to be packing
leakage from Unit 2 valve 2-RC-6.
Injection of Furmanite into the packing
area reduced leakage to an acceptable value and the unit was returned to
100% power at 1952 on April 21.
On April 26, at 0915, the unit automatically tripped from 100% power when
125 VAC vital bus 2-1 was inadvertently deenergized. The loss of vital bus
2-1 caused the reactor protection system to sense a tripping of reactor
coolant pump A breaker; thereby, tripping the plant in anticipation of a
low flow condition. The unit was returned to 100% power at 1130 on April 30
after several days of operation at reduced power due to secondary plant
chemistry holds.
6.
Licensee Event Report (LER) Followup
The following LERs were reviewed and closed.
The inspector verified that
reporting requirements had been met; causes had been identified; corrective
actions appeared appropriate; generic applicability had been considered; and
the LER forms were complete.
Additionally, for those reports identified by
asterisk, a more detailed review was performed to verify that the licensee
had reviewed the event; corrective action had been taken; no unreviewed
safety questions were involved; and violations of regulations or Technical
Specification (TS) conditions had been identified.
- 338/80-70
Containment Air Particulate Monitor Inoperable.
- 339/80-92
Train B of the Safety Injection System Failed to
Reset Following a Functional Test.
- 339/84-11 Rev. 2
2H Emergency Diesel Generator (EDG) Trips.
- 339/85-04
Forced Shutdown Caused by Inoperable EDG
- 339/85-05 Rev. 0 & 1
Unit 2 Reactor Trip.
(CLOSED) LER 338/80-70 Containment Air Particulate Monitor Inoperable.
A
design change to correct the described problem has been implemented by the
licensee.
LERs dealing with the same subject were addressed in Inspection
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Reports 338,339/84-09.
(CLOSED) LER 339/80-92 Train B of the Safety Injection System Failed to
Reset Following a Functional Test.
LER 339/82-14, which was closed in
Inspection Reports 338, 339/83-31, addressed the same relays discussed in
this LER.
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(CLOSED) LER 339/84-11 Rev 2, 2H Emergency Diesel Generator (EDG) Trips.
The inspectors have reviewed and closed the two previous submittals of this
report.
This revision supplies some additional information on the actions
the licensee r'ans to take or is taking.
(CLOSED) LE'
'/85-04 Forced Shutdown Caused by Inoperable EDG.
As
discussed '
- report, inoperable EDGs have been the subject of a number
of reports by tne licensee.
The Office of Nuclear Reactor Regulation (NRR)
and NRC Region II are closely monitoring the licensee's implementation of
the program discussed in this report.
(CLOSED) LER 339/85-05 Revisions 0 and 1, Unit 2 Reactor Trip.
The
inspectors have reviewed the licensee's actions, and they appeared to have
been proper.
The fact that the tripping of a grid transformer caused the
loss of two Reserve Station Transformers (RSS) was discussed with NRR and
the licensee.
NRR stated that the licensee's off-site electrical distri-
bution system is of acceptable design.
As stated in the LER, the licensee
is reviewing the design, because, eventhough the present design is
acceptable, it may not be the optimum design with respect to continuity of
power.
(OPEN) LER 338, 339/85-03 Flooding Potential Not Previously Evaluated. The
licensee identified this deviation from a commitment, reported it, and has
taken temporary corrective actions.
Long term corrective actions are still
being evaluated by the licensee and will be reviewed upon implementation.
7.
Followup of Previously Identified Items
(CLOSED) Inspector Followup Item (IFI) 338, 339/84-27-04 Service Water Spray
Riser Degradation.
The licensee has committed to replacing the present
spray arrays with ones made of stainless steel.
They have also increased
routine surveillance of the arrays by the operators to identify spray risers
requiring repair.
In response to Violation 339/84-04-01, the licensee
increased the frequency of spray array inservice inspections to conform with
the requirements of North Anna Unit 2 License Condition 2.c.(5) and Regu-
latory Guide 1.72.
(CLOSED) IFI 338/83-24-02 Log Entry to Meet Surveillance Requirement 4.4.1.3.2.
This log entry needed a change to fully address the requirements
of the surveillance. The inspectors have reviewed both 1-LOG-4 and 2-LOG-4,
and both have been changed to more completely address the surveillance.
(CLOSED) IFI 338, 339/84-09-01 Failure of a Single Fire Damper Causing
the Loss of Both Trains of Safeguards Area Ventilation System (SAVS). The
inspectors and the licensee have reviewed this issue.
The inspectors can
find no other ventilation systems in the plant where a similar situation
exists.
The licensee recognizes the potential problem with the damper
location in the SAVS but feels that the eighteen month damper inspection
along with the monthly flow test ensure that any problems are quickly
identified.
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(CLOSED) IFI 338, 339/84-01-03 Brown Bovery Type SHK Circuit Breakers.
The breaker inspection recommended by IE Notice 83-84 was conducted on both
units during the 1984 refueling outages.
The periodic followup inspection
of the breakers has been incorporated into electrical maintenance procedure
EMP-P-PH-01 " Electrical Checkout of 4160 Volt Air Circuit Breakers."
(2-20-85).
(OPEN) IFI 338, 339/84-04-04 Correction of Discrepancies Found in the
Auxiliary Feedwater System Walkdowns.
With the exception of the update of
drawing 11715-FM-74A, the identified problems have been corrected.
(OPEN) IFI 338, 339/84-27-05 Correction of Problems in Offsite Review
Committee Procedures.
This item is no longer an Unresolved Item.
The
licensee has committed to revising the present offsite review Technical
Specification to more accurately reflect the present organization structure.
Additionally, the licensee committed to revising their offsite review
committee administrative procedures to incorporate quorum requirements for
the required monthly meeting.
The implementation of these changes is an
Inspector Followup Item.
8.
Hydrogen Recombiner
a.
While reviewing the North Anna TS, the inspectors discovered surveil-
lance requirements that appear to conflict with the North Anna Safety
Evaluation Report (SER) for TMI action item II.E.4.1 (Dedicated Hydro-
gen Penetrations).
Specifically, TS 4.6.4.2.a, which may be conducted
during power operations, requires a six month hydrogen recombiner
functional test involving aperation of the equipment and comunicating
containment atmosphere with the external recombiner.
Meanwhile,
TS 3.6.1.1 for containment integrity while in modes 1, 2, 3, and 4,
requires valves not receiving an automatic closure signal be maintained
closed. Revision 3 of the licensee response to TMI item II.E.4.1 dated
May 31, 1982, described the recombiner system and proposed several
modifications to the originally-installed system which did not require
automatic closure of the containment icolation valves.
NRR accepted
the licensee modification in a letter dated January 12,1984 and
specified the containment penetration valves should be opened only
under specific administrative control as specified in post-accident
procedures.
Additionally, the hydrogen recombiner is designed and
tested to 10 psig while containment pressure for the first hour after
the design basis accident may increase to approximately 45 psig.
The
recombiner should not be needed during the first hour of the accident
and is normally not needed until approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the
accident when containment pressure has been reduced below the 10 psig
design pressure.
However, every six months during testing, there
exists an approximately four hour time period where the system could be
overpressurized if an accident occurred.
An additional concern is that the system as described in the licensee's
TMI response, Revision 3, dated May 31, 1982, is not like the
actually-installed system as described on system drawings 11715-FM-
106A-8, 11715-FM-92A-11 and 1K 50-FM-92A-10.
Specifically, the inlet
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to the hydrogen recombiner does not tap off the containment vacuum pump
suction downstream of the Phase "A"
isolation as stated, and under
accident conditions, it will not be necessary to open the vacuum pump
isolation valves to establish flow to the recombiner and/or hydrogen
analyzer as stated.
Additionally, the drawing submitted in the
licensee NUREG 0737 response is outdated and not correct.
The licensee has been requested to provide to the inspectors, the
latest correspondence between themselves and NRR on item II.E.4.1.
This item will be considered unresolved pending outcome of the licensee
efforts. This item is identified as Unresolved Item 356,339/85-12-01.
b.
The inspectors observed portions of the testing accomplished on one of
the post accident thermal hydrogen recombiners following replacement of
the motors on that unit.
Subsequently, the inspectors reviewed the
following procedures:
1-0P-63.1
" Post Accident Thermal Hydrogen Recombiner" (4/18/85)
1-PT-68.1.1
" Containment Hydrogen Recombiner Functional Test -
1-HC-HC-1 (10-05-83)
1-PT-68.1.2
" Containment Hydrogen Recombiner Functional Test -
2-HC-HC-1(10-05-83)
1-PT-68.2.1
" Containment Hydrogen Recombiner System - Operability
Testof1-HC-HC-1(10-27-82)
1-PT-68.2.2
" Containment Hydrogen Recombiner System - Operability
Testof2-HC-HC-1(10-05-83)
The inspectors had the following comments on their observations and
reviews.
(1) The functional test procedures for recombiners 1-HC-HC-1 and
The procedure
2-HC-HC-1 are substantially )different in format.
for 1-HC-HC-1 (1-PT-68.1.1
references 1-0P-63.1 for the
performance of many of the action steps.
Engineering Work Request
(EWR)83-335 recommended that " stand alone" functional test
procedures, rather than those that reference other procedures, be
implemented for the hydrogen recombiners.
This has been done for
2-HC-HC-1(1-PT-68.1.2).
(2)
1-PT-68.1.1 does not contain all the Initial Conditions and
Precauticns of 1-PT-68.1.2 and step 4.6 of 1-PT-68.1.1 references
the wrong section of 1-0P-63.1.
(3)
1-PT-68.2.1 does not contain the formula for computation of
corrected purge blower flow (Q) provided by the vendor (EWR
83-335).
(4) The inspectors noted that the operator performing the testing on
the hydrogen recombiner became confused when calculating the
measured purge blower flow rate (Qo).
This confusion was caused
by the fact that purge blower inlet pressure (PBo) which was read
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on PI-HC-205-1 read out in inches of Hg while the formula requires
the reading to be entered in psia.
Either a conversion factor
needs to be provided or the formula needs to be changed to reflect
the units being read.
Followup of these comments is identified as IFI 338, 339/85-12-02.
9.
Turbine Load Limiter
The inspectors conducted a review of recent operational transients in which
mately 940 megawatts electrical (MWE) perating at 100% load (i.e., approxi-
the main electric turbine generator, o
assumed an additional 40 MWE when a
large electrical station was removed from the grid resulting in voltage
and/or frequency droop.
To better explain the significant of the turbine
load increase, a brief description of the North Anna design follows:
Each North Anna unit utilizes a 1000 MWE turbine generator that is oversized
when compared to the licensed electrical output equivalent of 2775 megawatts
thermal reactor power, or 954 MWE. This difference in rating results in the
four turbine governor valves being at an average position of 80% open when
the reactor is at 100% power.
The turbine control system utilizes a
governor valve position limiter; however, in the past, this limiter was set
at 100% and did not restrict turbine load increases above the electrical
load equivalent of 100% reactor power. Section 15.2.11 of the Updated Final
Safety Analysis Report (UFSAR) states " excessive loading by the operator or
by system demand would be limited by the turbine load limiter".
The inspectors reviewed the UFSAR, system drawings and technical manuals
but were unable to locate a turbine load limiter as described in Safety
Analysis 15.2.11 of the UFSAR.
The licensee was requested to review their
design and provide their findings. As an interim measure, licensee manage-
ment provided instructions to the operating crews to set the turbine
governor valve position limiter to a value of 2% above the 100% reactor
power governor valve position, i .e. , approximately 82%.
Subsequent
correspondence with the turbine vendor indicated that the governor valve
position limiter was the load limiter discussed in the UFSAR. As discussed
earlier, licensee procedures previously set the governor valve position
limiter at 100% - effectively rendering it inoperable as the load limiter
described in the UFSAR.
Even though the turbine load limiter has not been used as described,
excessive load increase accident protection is provided by overpower delta
T, overtemperature delta T and power range high neutron flux trips.
The
licensee has committed to modifying operating procedures to set the governor
valve position limiter where it will perform the load limiter function.
The failure to properly use the governor valve limiter as the load limiter
described in the UFSAR is identified as Deviation 338,339/85-12-03.
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10. Station Batteries
During a routine plant inspection of the station battery rooms, numerous
cell electrolyte levels were above the maximum level mark for seven of the
eight batteries on both Units 1 and 2.
TS require the battery cell
electrolyte level to be raaintained between the minimum and maximum level
indication marks.
The vendor, when contacted by the licensee, informed the licensee that even
though cell electrolyte levels being slightly high posed no immediate
operational problems, the levels should be reduced into the normal operating
range.
The licensee determined that approximately two weeks before the inspectors
identified this concern, the cell electrolyte levels had been adjusted to
the top of the operating band, and during subsequent charging, levels must
have slowly increased to above the indicated maximum.
The inspectors reviewed the latest completed 1-PT-85 and 2-PT-85, "D.C.
Distribution System", which were performed on April 30, 1985.
These per-
formance tests are performed every seven days to meet the requirements of TS
surveillance 4.8.2.3.2 which, in part, requires the verification of proper
electrolyte level for the battery pilot cells.
On May 1, 1985, the elec-
trolyte level of at least one pilot cell (Battery 2-II) was clearly above
the maximum level indication mark, and as mentioned earlier, numerous other
cells exhibited the same condition.
The failure to properly conduct the surveillance requirements of TS 4.8.2.3.2 is identified as Violation 339/85-12-04.
11. ESF System Walkdown
The following selected ESF systems were verified operable by performing a
walkdown of the accessible and essential portions of the systems on May 3,
1985:
Unit 1
1H Diesel Engine Cooling Water (1-0P-6.1A)
IJ Diesel Engine Cooling Water (1-0P-6.2A)
1H Diesel Engine Lube Oil System (1-0P-6.3A)
Diesel Air (gine Lube Oil System (1-0P-6.4A)
IJ Diesel En
1-0P-46.4A)
Unit 2
2H Diesel Engine Cooling Water (2-0P-6.1A)
2J Diesel Engine Cooling Water (2-0P-6.2A)
2H Diesel Engine Lube Oil System (2-0P-6.3A)
Diesel Air (gine Lube Oil System (2-0P-6.4A)
2J Diesel En
2-0P-46.4A)
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Upon the completion of the walkdowns, the inspectors had the following
comments.
a.
Valves 2-EB-16,17, 62, and 63 are required to be locked open by
Attachment 2 of North Anna Power Station Administrative Procedure
ADM 19.29.
These valves are in fact locked open; however, 2-0P-46.4A
requires them only to be open.
b.
Small air leaks were noted on valves 1-EB-39 and 2-EB-83.
Correction of these discrepancies is identified as Inspector Followup Item
338,339/85-12-05.
12. TMI Action Plan Items
The inspectors reviewed the status of outstanding TMI Action Plan Items and
performed the action specified in the applicable IE Manual Chapter 2515
Temporary Instruction. The status of those items reviewed are as follows:
a.
Closed:
(Units 1 and 2) II.B.1.2 (Install Reactor Coolant Vents): As
stated in the March 4, 1985, VEPC0 response, serial number 85-091, to
Enforcement Action EA 84-57 described in inspection report 50-338,
339/84-06, the installation was completed by opening the manual
isolation valve.
b.
Closed:
(Units 1 and 2) II.F.2.3.B (Implement Reactor Vessel Level
Instruments):
As stated in a March 7,1984, letter to NRR, Serial
Number 047A, VEPC0 ensured the level instruments were operable after
the 1984 refueling outages,
c.
Closed:
(Units 1 and 2) II.K.3.5.B (Auto Trip of Reactor Coolant
Pumps):
The licensee proposal to include manual tripping instructions
in their emergency procedures was verified complete.
13. Routine Inspection
By observations during the inspection period, the inspectors verified inat
the control room manning requirements were being met.
In addition, the
inspectors observed shift turnover to verify that continuity of system
status was maintained.
The inspectors periodically questioned shift
personnel relative to their awareness of plant conditions.
Through log review and plant tours, the inspector verified corr,eliance with
selected TS and Limiting Conditions for Operations.
During the course of the inspection, observations relative to Protected and
Vital Area security were made, including access controls, boundary
integrity, search, escort and badging.
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On a regular basis, radiation work procedures (RWP) were reviewed and the
specific work activity was monitored to assure the activities were being
conducted per the RWPs.
Radiation protection instruments were verified
operable and calibration / check frequencies were reviewed for completeness.
The inspector kept informed, on a daily basis, of the overall status of both
units and of any significant safety matters related to plant operations.
Discussions were held with plant management and various members of the
operations staff on a regular basis.
Selected portions of operating logs
and data sheets were reviewed daily.
The inspector conducted various plant tours and made frequent visits to the
Control Room.
Observations included:
witnessing work activities in
progress; verifying the status of operating and standby safety systems and
equipment; confirming valve positions, instrument and recording readings,
annunciator alarms, housekeeping and vital area controls.
No violations or deviations were identified in these areas.