ML20244B815
| ML20244B815 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 05/17/1989 |
| From: | Caldwell J, Frederickson P, King L, Munro J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20244B805 | List: |
| References | |
| 50-338-89-08, 50-338-89-8, 50-339-89-08, 50-339-89-8, GL-88-17, NUDOCS 8906130306 | |
| Download: ML20244B815 (29) | |
See also: IR 05000338/1989008
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h4 UNIT ED STATES
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. NUCLEAR REOULATORY COMMISSION
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- 2 ATLANTA, GEORGI A 30323
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L Report Nos.: 50-338/89-08 and 50-339/89-08
Licensee: Virginia Electric & 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: March 21 through April 17, 1989 and April 25 through
May , 1989.
Inspectors: Y <S. mash /d 6 / /?/3 9
J. L. Caldwell, Se ior Ryident Inspector Date' Signed
-8.
L. P. King, Resident I
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Sf t 7lfr4
Date Signed
91 8. M 1,4 s/,7/r4
J. Munro, Resident' Inspector Datle Sibned
Accompanying Personnel: N. Economos
S. Lewis
. M. Shaeffer
Approved y: / / [
P.g Frddricksop(~ Acting Brapief
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Cate/ Signed
h
ivision of Reactor Projects
SUMMARY
Scope: This routine inspection involved the following areas: plant status,
maintenance, surveillance, operational safety verification, operating
reactor events, licensee event report followup, review of inspector
follow-up items, Generic Letter 88-17, refueling activities, and EDG
fuel oil storage and handling. During the performance of this
inspection, the resident inspectors conducted reviews of the
licensee's backshift operations on the following days: March 27, 30,
31, April 3, 5, 6, 10, 12, and 17, 1989.
Results: Within the areas inspected, there were two violations and two
apparent violations identified:
Violation: Failure to have adequate maintenance procedures to ensure
proper operation of ESF equipment 480 volt ITE breakers (paragraph
8).
Violation: Failure to comply with TS 4.6.1.1.a.1 for containment.
penetration vent and drain valves (paragraph 8).
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8906130306 890517 ,'
PDR ADOCK 05000338
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Apparent Violation: Potential for the SW and RSHXs to have been
inoperable (paragraph 4.b).
Apparent Violation: Inadvertent loss of reactor vessel level
(paragraph 6.d).
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REPORT DETAILS
1. Persons Contacted -
Licensee Employees
- M. Bowling, Assistant Station Manager
J. Downs, Superintendent, Administrative Services
- R. Driscoll, Quality Control Manager
- L. Edmonds, Superintendent, Nuclear Training
- R. Enfinger, Assistant Station Manager
- G. Flowers, Configuration Management Supervisor
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- M. Garton, Instrument Supervisor
G. Gordon, Electrical Supervisor
D. Heacock, Superintendent, Engineering
- G. kane, Station Manager
- P. Kemp, Supervisor, Licensing
- J. Leberstein, Licensing Engineer
- W. Matthews, Superintendent, Maintenance
T. Porter, Superintendent, Engineering
- J. Stall, Superintendent, Operations
- A. Stafford, Superintendent, Health Physics
F. Termine11a, Quality Assurance Supervisor
D. Thomas, Mechanical Maintenance Supervisor
Other ' licensee employees contacted during this inspection included
engineers, technicians, operators, mechanics, security force members, and
administrative personnel.
- Attended exit interview
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2. Plant Status
On March 21, the beginning of the inspection period, Unit I was in Mode 5,
day 24 of an outage, which commenced with the C steam generator tube leak
event on February 25. On March 23, Unit 1 experienced a loss of the IH
emergency bus while performing tests of the EDG. The de-energization of
the IH bus resulted in the tripping of the operable RHR pump (IA). The
unit was not in a reduced RCS inventory (pressurizer level at the time was
approximately 5 percent) and the IB RHR pump was started within 60 seconds
of the 1A RHR pump trip (see paragraph 4.a for details). On April 14, the
licensee conducted a SW flow balance test on the RSHXs. The results of
the test indicated potential inoperability of the SW/RS systems (see
paragraph 4.b for details). On April 16, Unit 1 experienced another loss
of the operating 1A RHR pump. The unit had approximately 5 percent level
in the pressurizer and the operators started the IB RHR pump in approxi-
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mately 6 minutes. The cause of the loss of an RHR pump was a fault in the
switchyard caused by a personnel error (see paragraph 6.c for details).
On March 21, Unit 2 was defueled, day 30 of the refueling outage. The
fuel reload commenced on March 26 and completed on March 28. On April 3,
Unit 2. experienced a loss of CCW to the operating RHR heat exchanger. The
unit was drained to approximately 5 inches below the vessel flange at the
time and therefore not in a reduced RCS inventory condition. The
operators restored CCW flow in approximately 25 minutes (see paragraph 6.b
for details). On April 5, the reactor vessel head installation was
completed and Unit 2 entered Mode 5.
On April 13, the Chairman of the Czechoslovakian Atomic Energy Commission
and six of his associates visited the North Anna Power Station at the
invitation of the licensee. The chairman and his group were given a
presentation and a tour of the station and associated facilities by the
licensee. The inspector briefly met with the Czechoslovakia personnel
while they were touring the simulator in the training building.
3. Maintenance (62703)
Station maintenance activities affecting safety-related systems and
components were observed / reviewed to ascertain that the activities were
conducted in accordance with approved procedures, regulatory gides and
industry codes or standards, and in conformance with lechnical
Specifications. The following details the inspector's findings / concerns,
a. ASCO S0V Failure Root Cause
NRC Inspection Report 338,339/88-02 identified concerns relating to
the failure of air operated containment isolation valves. These
failures were attributed to problems with the ASCO SOV not performing
properly. As a result of these concerns, the licensee committed to
perform a failure analysis of the ASCO SOVs. The need for this
analysis was further highlighted in Inspection Report 338,339/88-36,
which identified concerns relating to instrument air water and oil
contamination problems that may have been the cause or at least
contributed to the cause of the ASCO SOV failures. The inspector
obtained a copy of the licensee's failure analysis report and the
following is a brief summary of the report and its conclusions.
(1) The cause of increased containment isolation valve stroke times
was due to the installation of improperly sized tubing on the
exhaust portion of the SOVs. Valve stroke times have been
consistent since the replacement of smaller exhaust tubing with
larger tubing. There are seven SOVs still requiring exhaust tube
replacement. The licensee plans to replace the tubing prior to
the startup from the present refueling outages.
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(2) Several SOVs (ASCO mode 1 ~ NPX8321A1E) were found stuck in mid
position. Their failure can be attributed to the combination of
the water intrusion into the instrument air system, and mixing
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of the particulate contamination with assembly lubricants.
Consequently, the licensee concluded that ASCO NPX8321AIE SOVs
appear to be susceptible to particulat - contamination from the
instrument air system.
(3) Inspections were made on two SOVs ( ASCO model KX206-380-30)
which failed to operate once deenergized. In one case, the
likely failure mechanism was the adhesion between the
core / spring and solenoid sub-assemblies caused by oxidized
silicone lubricant deposits. In the other case, the root' cause
is inconclusive; however, a similar failure mechanism is
suspected. The licensee concluded that ASCO model KX206-380-3U
SOVs that are energized for prolonged periods may be susceptible
to the failure mechanism described above.
The licensee determined that the number of SOVs , (model
KX206-380-3U) which have failed to stroke since February 1988,
has been minimal. The two cases that have occurred were
inspected as discussed above. Paragraph 5.c of this report
contains an additional example of a SOV failure. The licensee's
engineering group feels this is an insufficient number to
definitely determine the root cause of ASCO SOV failures.
The licensee initiated EWR 89-166 to replace all SOV Mcdel NPX
8321AIE during the refueling outage. Once this modification is
complete, the model of ASCO SOV used on the inside air operated
containment ~1 solation valves will be different than those used on the
outside containment isolation valves for the same mechanical piping
penetration, except for the charging system trip valves. This will
help prevent common mode failures on a single penetration. The ISI
program has been revised to increase the frequency of stroke time
tests for many safety-related trip valves, exceeding ASCO's recommen-
dation in this area. Also, the quality of instrument air has
improved with modifications to the instrument air system. These
factors should increase the reliability of safety-related trip valves
whose pilot valve is an ASCO SOV.
b. LHSI Pump Maintenance
On April 10, the inspector witnessed portions of the overhaul of the
Unit 2 LHSI pump (2-SI-P-1A) per MMP-C-SI-1, Low Head Safety
Injection Pump Inspection, Repair and Seal Replacement. The
inspector observed the installation and torquing of the last two
columns on the pump shaft and the installation of one of the wedges
between the pump casing and the pump columns. No problems were
observed by the inspector.
c. Unit 2 Steam Generator Outage Work
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During the present Unit 2 refueling outage, the licensee conducted
numerous inspections and maintenance activities concerning the steam
generators. The following is a list of the activities and the
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results:
(1) : Steam generator eddy current testing was conducted on the tubes
of all three steam generators. All of the tubes were inspected
through the U-bend, except for several short U-bend radius Row 2
tubes, using the standard bobbin probe (both hot and cold legs).
In addition to the bobbin probe, the tubes in rows 8 through 12
/ere inspected to the seventh support plate using the 8 x 1
pancake probe (both hot and cold legs), and all other rows were
inspected on the hot leg side through the first support plate
using the 8 x 1 pancake probe. Any indication discovered by one
of the above methods was verified by the RPC probe. Also, 25
row 2 tube U-bends were inspected using the RPC probe. As a
result of the above inspection, four tubes in the A steam
generator,10 tubes in the B steam generator and 15 tubes in the
C steam generator are required to be plugged.
(2) Steam generator sludge lancing was conducted on all three steam
generators to remove sludge that had collected on the tubes and
. tube sheet. The results of the lancing involved the removal ~ of
288 pounds of material f rom the A steam generator, 312 pounds
from the B steam generator, and 226 pounds from the C steam
generator. This is comparable to the amount of that was removed
from the Unit 2 steam generators during the 1987 refueling
outage, which ranged from 230 to 270 pounds.
(3) As a result of the failed plug that caused a steam generator
tube leak event on the Unit I reactor in February of this year,
the licensee replaced several plugs in the Unit 2 steam
generators. The licensee determined that 13 hot leg plugs in
the A steam generator,10 in the B steam generator, and 30 in
the C steam generator would have to be replaced because they had
been determined to be susceptible to the same type of failure
that occurred in the Unit 1 C steam generator. Refer to
paragraph 6.d of this report for further details on the tube
plug concern.
(4) The Unit 2B steam generator J-tubes were inspected and
determined to be acceptable. The licensee had replaced the
Unit 2 carbon steel J-tubes with inconel J-tubes in all three
steam generators during the 1985 outage. Since the inspection
was satisfactory in the B steam generator, the other two steam
generators were not required to be inspected.
No violations or deviations were identified.
4. Surveillance (61726)
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The inspectors observed / reviewed technical specification required testing
and verified that testing was performed in accordance 'with adequate
procedures, that test instrumentation was calibrated, that limiting
conditions for operation were met, and that any' deficiencies identified
were. properly reviewed and resolved.
a. Loss of 1H Emergency Bus and 1A RHR Pump-
On' March 23, during the performance of 1-PT-82.3A, 1H: Diesel
Generator Test (Simulated Loss of Offsite Power in Conjunction.with
ESF Actuation Signal), the licensee inadvertently lost power to the
.1H emergency bus. The surveillance was intended to test the fast
start capability of the 1H EDG using a simulated safety injection and
90 percent degraded voltage signal. At the time of the surveillance,
Unit I was in Mode 5 with an RCS temperature of 102'F. Pressurizer
level was approximately 5 percent, the 1A RHR pump was operating and
the IH emergency bus-was being supplied by the alternate power source
through breaker 15H1. When the operator commenced the test, the
breaker upsteam of 15H1 (15B11) opened, causing 15H1 to also open and
de-energize the IH emergency bus. As a result of the : loss of the
bus, the operating 1A RHR pump, which is powered by the 1H bus, also
tripped. An operator stationed at the RHR pump controls immediately
started the - 18 . RHR pump, resulting in a negligible change in RCS
temperature. The IH EDG auto-started and loaded onto the bus in less
than 10 seconds as required. The IH EDG was subsequently paralleled
tc the alternate power supply and the IH bus was returned to normal.
The EDG-was secured in approximately 15 minutes.
The inspector reviewed the procedure 1-PT-82.3A and, as stated by the
licensee, there were no initial conditions or precautions requiring
the emergency bus to be powered by the . normal power' supply. Even
l though the procedure was inadequate in not requiring that the bus be
powered by the normal breaker 15H11, the operators stopped the test
on March 23 to determine if it was acceptable to continue with the
bus being powered from the alternate power supply. The Control
Operations Department was contacted and requested to determine if the
test switch would block the 15H1 breaker from tripping as it normally
does for the 15H11. The operators ' were informed that the 15H1
breaker would not trip; however, the Control Operations personnel
failed to check the upstream breaker 15B11, which was not blocked and
did trip on the simulated 90 percent degraded voltage signal.
The operations staff did an excellent job in stopping the test and
questioning the abnormal alignment. However, since the test proce-
dure did not have a requirement for the emergency bus to be powered
from the normal power supply, no formal change was required to
proceed in the abnormal alignment. The review conducted by the
Control Operations Department was informal and incomplete. This
informal review resulted in the failure of the Control Operations
personnel to identify that breaker 15B11 was not blocked by the test
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switch and would trip.
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.The. licensee'has initiated corrective action, which involves placing
in- al1~ applicable ' surveillance , tests, deviations that. prevent the
test from being performed in an abnormal ' electrical alignment. .The
- inspector has-verified that a procedure deviation does exist in 'the'
front of the control room copies of the following' surveillance tests;-
82.2A, 82.2B, 82.3A, 82.38, 82.4A, and 82.48. The licensee -has
committed to establishing a formalized approach for obtaining Control
Operations assistance, including a method of permanently ' capturing
and utilizing the information obtained. This apprea:h . will. be
developed and a schedule established for its implementation by May -
17, 1989.
b. Service Water to RSHXs Flow Balance
On April 4,- the inspector received a briefing on 1-PT-75.6, Service
Water System Flow Balance, prior- to performance of the test. This.
procedure was developed to allow for full flow testing of _ the SW
system through the RSHXs. The results of the procedure were designed-
to allow the licensee to determine if the design basis flow would
. actually be achieved through the RSHXs and provide data on the
maximum flow which could be allowed through the CCW heat.exchangers
during normal operations.
Concerns regarding the ability of the RSHXs-to perform their intended
safety function were raised in NRC Inspection Report 338,339/88-11.
These concerns involved potential increased fouling factor associated
with the RSHXs and the resultant reduction in their heat transfer
capabilities. However, during the discussion concerning the
increased fouling of the RSHXs, it was assumed that the heat
exchangers would receive their design SW flow.
Also, as documented in NRC Inspection Report 3'38,339/88-31, the
licensee identified a potential problem associated with SW flow
through the CCW heat exchangers. This concern involved SW pump and
CCW heat exchanger flow combinations which could prevent achieving
.the required SW through the RSHXs during an accident. An additional
complication involved the assumption that the SW pumps would deliver
a flow of 15,000 gpm per pump. This concern was identified as IFI.
'338,339/88-31-04, pending the SW flow testing that is being conducted
this outage.
The licensee conducted 1-PT-75.6 for the Unit 1 RSHXs on April 14.
The test performed head curve verifications on all four SW pumps and
indicated that the maximum flow rate for the pumps was actually
approximately 13,500 gpm instead of the 15,000 gpm that was expected
by the Itcensee. The results of the test also indicated that the SW
flow through two of the four RSHXs was below the required design flow
of 4500 gpm, as stated in the UFSAR, Table 6.2-2. The SW as-found
flow results are as follows:
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A RSHX - 5020 gpm
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B RSHX - 4850 gpm
C RSHX - 3740 gpm
.. D RSHX - 2650 gpm
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. The SW flow through the RSHXs is controlled by a throttle valve for
each heat exchanger (1-SW-103 A, B, C and D). The licensee was able
to . adjust these valves to achieve the following as-left SW flow
results:
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A RSHX - 4610 gpm
B RSHX - 4610 gpm
~C RSHX - 4570 gpm
L D RSHX.- 4660 gpm
Based on the discovery' of the SW flow below the required flow of 4500
gpm in two'of the RSHXs, the licensee notified the inspector of their
- findings and will follow up this notification with an LER in 30 days.
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The inspectors were able to determine that the last time the throttle
valves (103 A, B, C and D) were flow tested and adjusted was in 1981.
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Since that adjustment, major modifications have been 'made to the .SW
system, ' including the overhaul of the SW pumps, mechanical . and
chemical cleaning of the SW piping and' installation of new SW return
- headers with newly installed spray arrays and associated valves. As
a result of these modifications and maintenance, the licensee
conducted post modification testing but did -not include the
re-verification of the SW flow through the RSHXs (i.e., the throttle
settings of the 103 and 203 ~ valves). It is unclear whether the
improper throttle settings and resulting low SW flow rates were a
result of the modifications or of initially not being adjusted
properly. If adequate post ' maintenance testing had been conducted,
the licensee would had identified the RSHX SW flow rate discrepancies
earlier.
The combination of the questionable SW pump and CCW heat exchanger
configurations (see IR 338,339/88-33), and the identification of two
of the RSHXs having SW flow rates below design bring into question
the past . operability of the Unit 1 SW and recirculation spray
systems. This item will be identified as an apparent violation
338,339/89-08-03.
The test also demonstrated that the installed SW flow instrumentation
was not accurate. To ensure that the test flow data was accurate,
the licensee used temporarily installed ultrastnic flow
instrumentation and differential pressure instrumental!on installed
across each heat exchanger. The differential pressure instruments
agreed with the ultrasonic flow instrumentation for changes in the SW
flow during the throttle valve adjustments. This helped confirm the'
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accuracy of the ultrasonic instrumentation.
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The licensee also determined, based on the SW pump head curves, the
maximum SW flow rate which could be allowed through the Unit 2 CCW
heat exchanger during normal operation and still meet the design flow
through the Unit 1 RSHXs during accident conditions. This
determination was made by adjusting the Unit 2 CCW heat exchanger SW
flow to the maximum achievable with SW flowing through the Unit 1
RSHXs at their design flow of greater than 4500 gpm each. Then the
SW flow through the RSHXs was se;ured and the resulting flow through
the Unit 2 CCW heat exchanger was determired based on the SW pump
discharge pressure and head curve. This flow rate, as determined by
the SW pump discharge pressure, was 10,800 gpm. The installed flow
instrumentation indicated approximately 12,500 gpm return header flow
and approximately 14,500 gpm supply header flow, demonstrating the
installed flow instrumentation inaccuracies.
5. Operational Safety Verification (71707)
By observations during the inspection period, the inspectors verified that
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 inspectors verified compliance with selected
TS and Limiting Conditions for Operations.
In the course of the monthly activities, the inspectors included a review
of the licensee's physical security program. The performance of various
shifts of the security force was observed in the conduct of daily
activities to include: protected and vital areas access controls;
searching of personnel, packages and vehicles; badge issuance and
retrieval; escorting of visitors; patrols; and compensatory posts. On a
regular basis, RWPs were reviewed and the specific work activity was
monitored to assure that the activities were being conducted per the RWPs.
The inspectors kept informed, on a daily basis, of overall status of both
units and of any significant safety matter 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 inspectors conducted various
plant tours and made frequent visits to the control room. Observations
included: witnessing work activities in progress; verifying the status of
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operating and standby safety systems and equipment; confirming valve
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positions, instrument and recorder readings, and annunciator alarms; and
l observing housekeeping.
a. Tornado Watch
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On March 31, the licensee was notified that the area in which the '
! North Anna station is located was under a tornado watch. The control
room operators entered AP-41.1, Severe Weather Conditions, and took
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the necessary actions ' associated witho the tornado watch. The.
inspector reviewed the AP, conducted a tour, of the station grounds
'and : randomly selected portions of ;the' abnormal procedure action
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requirements to' be - verified. : The . inspector determined, based on-
observations, that the licensee was ' in' compliance with' the AP. A
severe weather condition did not develop.in the area:of the plant,
zb. Tour of High Radiation Areas
On April 12, the inspector made a ' tour of the following high
radiation areas with the Superintendent of Health Physics.
(1) The B' gas stripper room (lower level).
.No problems noted.
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l- (2) The A gas stripper room (lower level).
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The inspector observed the following:
(a) A leak downstream of a shut' capped drain valve on a heat
l3 exchanger.
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(b) A broken stem off of air operated valve IBR-P-108.
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(c) A loose ground strap on gas stripper discharge pump
1-BR-P-78.
l (d) Excessive boron on the gland of gas stripper discharge pump
l- 1-BR-P-78.
'(e) A . leaky gland on the suction valve to gas stripper
l- circulating pump 1-BR-P-10B.
l The inspector informed the Superintendent of Operations of the:
I above findings. The Operations Superintendent stated that an
I operator would be sent to these areas to document the problems
and ensure that a maintenance work request was written on each'
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item.
(3) Primary plant demineralized valve alley.
This area was generally clean, with the exception of two bags of
trash.
(4) Unit 2 seal injection filter area.
Health Physics had stopped work in this area due to housekeeping
problems. There was evidence that valve repacking had been in
progress. The gasket for the 4A filter head showed signs of
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The inspectors will conduct followup tours of these areas to
determine if the maintenance items are being corrected and if
housekeeping has improved.
c. Equipment Failures During February 25, 1989, Unit 1 Reactor Trip and
Cooldown to Mode 5.
The licensee has identified two valves in the list of equipment which
malfunctioned during the S/G "C" tube leak and subsequent cooldown to
Mode 5 of Unit 1. The identification of these valves and the related
failures are as follows:
(1) "C" Steam Generator Blowdown Trip Valve (1-BD-TV-100F) failed to
close.
(2) Inlet Valve to the RHR System (1-RH-MOV-1701) failed to stay
open following the reactor trip.
The inspector reviewed applicable deviation reports, work orders and
root cause analyses, performed by Maintenance Engineering to address
the problems.
In reference to blowdown isolation valve,1-BD-TV-100F, results of
the licensee's investigation show that the valve malfunctioned
because the ASCO SOV was stuck in the energized position. The valve's
function is to close on loss of power and/or air to the 50V, which is
its "f ail-safe" position. Because the application requires the
solenoid to remain ' energized during plant operation, heat is
generated and the licensee believes that this heat causes the small
amount of silicone lubricant, used by the manufacturer during valve
assembly, to oxidize and behave like a mild adhesive holding together
the core / spring and solenoid subassemblies, as previously discussed
in paragraph 3.a. With these SOV parts stuck together, the solenoid
was prevented from repositioning itself when de-energized on reactor
trip, and the pilot valve remained open. To overcome this problem,
the licensee has increased the frequency of stroking these type
valves and plans to replace five redundant SOVs used for outside
containment isolation, as discussed in paragraph 3.a.
In reference to 1-RH-MOV-1701, residual heat removal suction
isolation valve, the inspector ascertained that the valve failed to
stay open because relay PC-143 failed to operate. However, at the
time of this inspection, the subject valve was open and the suspect
breaker was locked out in the off position. The licensee was
delaying stroking this valve until after fuel had been removed from
the reactor.
d. Steam Gencretor "C" Tube Leak Resulting from a Mechanical Plug
Failure, Unit 1.
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The inspector met with the licensee's cogniza'nt engineer to. discuss
'the status of planned corrective actions'and obtain a progress report
.on the mechanical plug failure analysis by Westinghouse. The failed
. plug was located in S/G tube R3C60 of S/G "C". This failure has been ,
discussed in 'NRC Inspection Reports 338,339/89-03 and 89-07. The
-plug was used by Westinghouse in November 1985 to remove the~ subject
tube from. service when eddy current inspection showed it .to be
defective. The plug in question vas made from inconel-600 material-
produced from one of the two heats identified as NX3513 or NX3962.
The material was processed by 'Huntington Alloy per ASME SB-166 and
furnished' as one 'nch, rough turned - round bar in the as annealed
condition.
A recent- Westinghouse proprietary report on the failure analysis
performed on a leaky mechanical plug, removed from tube R3C6 of S/G
"A", North Anna Unit 2 in July 1987, reported that the plug had been
made from the same heat of material. The report described the
microstructure as one exhibiting various degrees of carbide- network
in the grain boundaries which is indicative of inadequate solution
annealing, i.e., low annealing temperature, insufficient time at
temperature or both. The material in question contains 0.018% carbon
_
and exhibited a hardness level of HRB 104 or HRC 28.5. Further, the
report stated that .this hardness level was indicative .of a
significant ' amount .of cold work resulting from manufacturing
practices. The failure mechanism was identified as primary water
corrosion cracking with an intergranular fracture. Mechanical plugs
made from those two heats of material include 515 in North Anna
Unit I and 319 in Unit 2.
A -review of photographs of the failed plug, following its removal
from S/G "C", showed that is had failed circumferentially at the
second landing. The-licensee is inspecting the tubes around R3C60 to
verify wall integrity and stated that the adjacent tube sustained
sufficient damage (dented) to preclude inspection with a standard
i size 0.720" diameter probe. The licensee will attempt to inspect the
tube with either a 0.610" or a 0.580" diameter probe to determine the
'
degree of damage.
In Unit 2, the licensee's tentative plans were to remove those plugs
in which an engineering evaluation could not demonstrate safe
'
operation when left in place (see paragraph 3.c for further details).
In Unit 1, plugs which are shown as unacceptable for safe operation
will be plugged with a specially designed appliance to preclude the -
recurrence of a similar failure.
No violations or deviations were identified.
6. Operating Reactor Events (93702)
The inspectors reviewed activities associated with the below listed
reactor events. The review included determination of cause, safety
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significance, performance of personnel and systems, and corrective action.
The inspectors examined instrument recordings, computer printouts,
operations journal entries, scram reports and had discussions with
operations, maintenance and engineering support personnel as appropriate.
a. Transportation Problem with a Reactor Coolant Pump Motor
On March 27, the licensee informed the inspectors that the
Westinghouse contracted trailer containing an RCP motor had broken
down approximately 12 miles from the North Anna station. The
inspector responded to the site of the breakdown and discovered that
the box containing the motor was still upright and intact on the
trailer. It appeared that the trailer, which was a low-boy, had
fatigued in the center on the right hand side, allowing the bottom of
the trailer to come in contact with the highway and generating
several brush fires along a two mile stretch. The truck driver
noticed that the load was getting much heavier, stopped the truck and
notified the licensee at approximately 11:00 a.m.
The HP technician at the site of the breakdown informed the inspector
that the radiation levels were as follows:
(1) The highest contact reading on the box external was 2 mr/ hour
(2) General area around the box was 0.3mr/ hour one meter from the
box
(3) The highest reading inside the box next to the RCP was Smr/ hour
at the top of the motor.
The inspector was also informed that no external or internal
contamination to the box was detected. The motor itself was in a
herculite bag and was reported to have both fixed and loose
contamination, but none of the contamination was detected outside the
I bag. The licensee also informed the inspector that the activity of
the RCP motor was estimated to be approximately 254 milicuries.
The licensee transported a crane and another low boy trailer to the
site and lifted the motor from the damaged trailer to a new trailer.
The motor was then transported back to the station. The motor was in
the process of being shipped by Westinghouse to their facility in
Pennsylvania for overhaul when the trailer failure occurred,
b. Loss of CCW to Unit 2 RHR Heat Exchanger
On April 3, the licensee experienced a loss of CCW to the Unit 2 RHR
heat exchangers. The unit was in Mode 5 with the reactor vessel
level at approximately 73 inches as indicated by the level standpipe.
This level is approximately five inches below the reactor vessel
flange; therefore, the licensee was not in a reduced vessel level
inventory condition as defined by Generic Letter 88-17. The
.
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operators determined the cause of the loss of CCW to be a loss of
instrument air to the CCW containment isolation valves which caused j
the valves to fail closed. Instrument air was restored and the
valves were reopened in approximately 25 minutes. The RCS
temperature, as indicated by the RHR pump discharge temperature,
increased from approximately 91 F to 96 F during the 25-minute
period. Details of the event are listed below.
At approximately 1:00 p.m., the control room operator responding to
an annunciator for RHR pump cooling low flow discovered the CCW
containment isolation valves which also supply the RHR heat
exchangers indicating shut in the control room. Operations personnel
were immediately dispatched to the area in the auxiliary building
where the CCW valves are located to determine cause for the closure
and to reopen the valves. This effort was hampered due to the CCW
valves being located in a contamination area requiring full
anti-contamination clothing. At 1:21 p.m. the operators reported
that there was no instrument air pressure to the CCW isolation
valves. These valves are air to open and spring pressure to close.
The operators proceeded to determine the cause for the loss of
instrument air and in parallel to prepare a jumper to get an air
supply to the CCW valves. At approximately 1:23 p.m. an operator
discovered an instricent air manual isolation valve closed which
isolated the air supply to the CCW valves. This valve was opened and
both CCW valves were reopened by 1:25 p.m., resulting in RCS
temperature (as indicated by RHR pump discharge temperature) to
decrease back toward the original temperature. l
The licensee determined, based on interviews with personnel in the
area, that a contract painter had t'een working on piping just above
the instrument air valve. This painter admitted to brushing up
against the instrument air valve handwheel, but reportedly stated
that he did not intentionally shut the valve. This instrument air
valve is located approximately 12 feet in the overhead, and has
approximately three turns from full open to full closed. The
inspector along with the Station Manager and the Operations
Superintendent entered the valve penetration ar2a where the
instrument air valve was located to inspect the valve. Based on
observations and physical manipulation of the valve handwheel, the
licensee determined that the valve was very easy to operate and could
have been closed by the physical contact of the painter.
Consequently, the licensee concluded that the valve had been
inadvertently closed by the painter.
The inspector had entered the control room shortly after the operator
had discovered the CCW isolation valves closed., The inspector
observed the operations staff to be very sensitive to the loss of
cooling water to the RHR heat exchangers and that prompt actions were
being taken to restore the cooling water. These actions included
notification of station management who responded to the control room,
discussions by the operations coordinator with both the electrical
.
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and instrument shops .to determine if L any work that they were
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performing could~have' caused the valve closure, dispatching operators
' to the area and trending '.the .RHR pump discharge temperature. The
emergency plan .' procedures 'were consulted to determine if. any - .
notifications'were required and the abnormal procedures 'for loss of
-RHR were consulted.
. c. . Loss of IH and 2J Emergency Busses
On' April 16, 1989,'at 1115, with both units in Mode 5, the station
lost the "C" Reserve Service Station (RSS) bus due to improper bus
rework and relay testing in' the switchyard. The function of the "C"
RSS bus is to provide power.. to the IH .and 2J emergency buses. The
inspector was- in the control room at the' time of the event and
observed the operations personnel response. Pressurizer levels
during.the event were 8 percent and_6 percent by cold calibration for
Units 1 and 2 respectively. The units were not in a midloop
operation at the time of.the event.
The event. occurred while contract personnel were performing' an
approved energizing procedure to rework the existing feed from the-
34.5kv bus 4. The procedure did not detail all of the leads to be
pulled or landed for the rework of the bus 4 feed. ' A technician had
marked up a panel-drawing, indicating the bus 4 leads to be pulled by
an' electrician. However, various leads from bus 3 were also marked
on the drawing from another step in the procedure. The technician.
failed to . inform the electrician.not to pull the leads for bus 3 and
left the immediate area. Consequently, when a bus 3 lead was lifted
c and went to ground, a 300 millisecond timer was ' activated and timed
out,: which - then deenergized the "C" transformer. The technician.
.upon realizing that had occurred, immediately notified the operations
personnel of the' occurrence.
The loss of the "C" RSS power supply ~to the IH and 2J emergency buses
resulted in the IH and 2J EDGs being auto-started. Component cooling
pumps auto-started and loaded as designed on both units. The Unit 1
"A" RHR pump, which was running at the time of the event, tripped on
undervoltage. Operations personnel entered 1-AP-11, Loss of.RHR, and
successfully started the Unit 1 "B" RHR pump. The decision to vent
the "B" pump prior to starting was made because operations personnel
were in the area at the time of the event and the pump had not been
run recently. This did not significantly delay the reestablishment
of shutdown cooling to the unit. All other major equipment
functioned normally, and operator response was appropriate.
l As part of the corrective actions to the event, the licensee
l discussed the evolution with the contractor technician. Further
discussions were held with the contractor management on the impact of
-
contractor actions on the safety of the plant. The licensee made a
four-hour report on the event.
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d. RCS Vessel Level
On April 26, Unit I was in Mode 5 with vessel level being maintained
in a level band of 68" to 72" above nozzle centerline. This level
band maintains level 26" to 30" above the " Reduced RCS Inventory"
level of 42". The vessel level was being monitored by a standpipe
located in the containment with a CRT monitor in the control room.
The operators were maintaining this level band by periodically
pumping any RCS leakage from the Primary Drain Transfer Tank (PDTT)
to either the RCS via the RHR System or to the Gas Stripper system.
Additionally, a head purge had been in progress for approximately 20
hours. During head purge, vessel level was erratic in indication but
remained on-scale. On observing a decrease in process vent flow, the
operators secured the head purge at 0224. When the purge was
secured, the RCS standpipe level dropped below the lowest ruler mark
indicated on the control room CRT monitor (68"). Personnel were
dispatched to the containment to investigate, and a makeup was
commenced to the RCS. RCS level was returned on scale in the control
room at 0315. A total of approximately 546 gallons was added to the
RCS from the VCT and level increased to 71". No problems were found
with the system line up in the containment, and the licensee
concluded the decrease in water volume was caused by diverting of
inventory from the PDTT to the Gas Stripper system to keep RCS
standpipe level on scale during the head purge. (Disc Pressurization
of the RCS loop isolation valves from an Accumulator causes a
positive in-leakage to the RCS of approximately .35 .5 gpm.) The
licensee further concluded that the head purge affected standpipe
indicated level by causing it to be erratic and indicate high.
On April 27 at 0500, with Unit 1 plant conditions as described above,
RCS standpipe level was again observed to be excessively erratic in
its indication. Head purge which had been in service at that time
for approximately 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> was secured to check standpipe level.
When the head purge was secured, standpipe level again went off scale
low (below lowest observable indication on CRT monitor - 64").
Makeup from the VCT and PDTT was started and 860 gallons were added
to restore level to 66". At 0545, a containment entry was made and
verified level was at 54". Thus, level decreased less than 54" to a
value that could have approached 42". Head purge was restarted and
level increased to approximately 70".
The inspector reviewed the controlling procedures for the plant
conditions and evolutions occurring at this time. These are
1-0P-5.4, Draining the Reactor Coolant System, and 1-0P-11.3, Purging
the Reactor Vessel Head. Neither procedure 1-0P-5.4, nor any other
procedure, addresses the methodology being utilized for the mainte-
nance of reactor vessel level. Specifically, the PDTT would be
pumped, as appropriate, to either the RCS (theough a temporary jumper
to the RHR system) or to the Gas Stripper system. Interviews with
the operators indicated a satisfactory knowledge of this system
line-up. The operators were also knowledgeable concerning RCS
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-leakage rates and accumulator in-leakage rates (calculated by the STA
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' once a shift). However, since neither .the RCS leakage calculations
or the operators ' tracked the amount'of inventory transferred from the'
.. PDTT to the Gas Stripper system, the maintenance of adequateLreactor
vessel level became primarily a function of an accurate standpipe
level indication.
~
>
Procedure 1-0P-11.3 precluder draining of. the RCS with a reactor
vessel head. purge in progress. Similarly, procedure 1-OP-5.4
cautions that. draining of the RCS is not allowed while purging the-
reactor head. Interviews with the operators indicated that they felt
in compliance with these procedures during a reactor. head purge'even-
when transferring.the RCS inventory f rom the PDTT. to the Gas Stripper
system. The: operators indicated that the purpose of the inventory
transfer was for maintenance'of reactor vessel level between 68" and
72" and not a purposeful lowering of level that would be accomplished
by a draining operation. The operators recognized that the reactor
head purge could cause standpipe l level to be erratic and indicate
inaccurately high. The assumptinn was made.that although this. level
indication could be inaccurate, as regards the exact reactor vessel
level, it could be relied on as a trending indicator to insure that
vessel level was being properly maintained during PDTT pumping
operations. This assumption proved to be incorrect with respect to
pumping of the PDTT and associated diversions of.RCS inventory to the
Gas Stripper system. The operators' actions over a period of hours,
, although intending to maintain level,. effectively established an RCS
draining evolution. Procedure .1-OP-11.3 provides no guidance or
precautions with respect to conducting evolutions that have the -
potential for reduction of reactor vessel level. Procedure 1-0P-5.4,
Step 5.31 also cautions that during Reactor Vessel Head Purging
operations, the RCS standpipe may inaccurately indicate low. This
statement is at variance with what was actually observed to occur.
The failure to control RCS stardpipe level and the failure to
identify and correct the problem after the April 26 event is
identified as an apparent violation (338,339/89-08-04). j
7. 'L'icensee Event Report Follow-up (90712) l
i
The following LERs were reviewed and closed. The inspector verified that 1
reporting requirements had been met, that causes had been identified, that
corrective actions appeared appropriate, that generic applicability had
been considered, and that the LER forms were complete. Additionally, the
inspectors confirmed that no unreviewed safety questions were involved and
that violations of regulations or TS conditions had been identified.
(Closed) LER 339/89-006, Pressurizer Code Safety Valves Out of Tolerance.
This LER documents the testing of the Unit 2 pressurizer code safety
relief valves which is performed every refueling outage. The relief
valves are removed from the plant and shipped to Wyle labs to be setpoint
and leak tested. The results of the test indicated that the as found lift
.
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setpoint pressure for the C relief valve. (2-RC-SV-255IC) was below the TS
'
3.4.3 criteria of. 2485 11% psig (actual setpoint was 2444)>and that the A
- relieff valve;(2-F.C-SV-2551A) leaked by the seat following the as found
- testing. The vendor performed maintenance on the' valves and the as left
setpoints were reported to be within the TS 3.4.3 criteria. During the
L , previous Unit 2 outage in 1987, the A and B reliefs exceeded the TS
criteria and again: the C relief was below the TS criteria-(as found 2447 '
psig). .The licensee has not b?en able to determine a root cause for the
setpoint drift.
J
' (Closed) LER 339/89-05, Main Steam Safety Valve Setpoints Out! of
.
L Tolerance. The LER-documented the ~ testing performed at Wyle labs of all
15 of the Unit 2 main steam code safety relief valves. Five of the
safeties exceeded the' TS criteria of 1%, two of which were lower and
l: three were higher than the TS criteria. The licensee conducted an.
evaluation and determined that the design pressure of the steam generators
would not be exceeded even though three of the safeties had setpoints
higher than the criteria. .The LER also stated that all 15 valves
exhibited some seat leakage following the as found testing. During the
1987 Unit 2 refueling outage, the licensee reported that 11 of the 15 code
safeties exceeded the TS pressure setpoint criteria (all higher) and.14 of
the~15 exhibited seat leakage following the as found testing,
p The vendor refurbished and retested the valves to ensure that the as left
'
pressure setpoints where within the TS tolerances and exhibited no seat
leakage. The licensee has not been able to determine a. root cause for the:
setpoint drift and leakage.
8. Action on Previous Inspection Findings (92701)
(Closed) Unresolved Item 338,339/88-33-07, Review of root cause analysis
and corrective actions regarding ECCS pump breaker problems. In NRC
Inspection Report 338,339/88-33, the inspector identified this URI pending
determination by the licensee of root cause analysis and corrective
actions concerning ECCS pump 480 volt breaker problems. A vendor
representative from Brown Boveri overhauled and cleaned several 480 ITE
u breakers. The result of the inspection indicated that the roller surfaces
- and latches were sticky and difficult to rotate. Dried mud and debris
were found inside the mechanism, and there was evidence that both
degreaser and oil based solvents had been used on the breakers. It-is
suspected that a contributing factor to the breaker malfunction was the
use of improper lubricant in non-compliance with the technical manual
'
recommendation combined with leaving the doors to the building housing the
breakers open with a far. blowing in dust and debris from outside during
the hot weather months. As a result, the licensee is planning to initiate
an EWR to be performed during this outage. The EWR will install a filter
and fan in the room housing the breaker. The inspector will monitor the '
licensee's action during the hot summer iaonths to determine if the
breakers are maintained free of dust and debris.
.
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In NRC Inspection Report 338,339/88-33 the inspector requested the- i
.
licensee to provide information regarding operability of the B Quench
Spray System since the pump breaker failed to close properly. Based on
Technical Specification 4.3.2.1.3 and Table 3.3-5, the Quench Spray Pumps
are required to develop an acceptable discharge pressure within 58
seconds. Periodic Test 1-PT-36.7.5 determined the response time for QS
pump 1-05-P-1B. The response time of 22.4 seconds was obtained during the
last performance of 1-PT-36.7.5 and the operator approximated the time
delay of the breaker closing to be 30 seconds. This places the pump
performance very close to the Technical Specification limit. Pump
1-QS-P-1B could have been inoperable depending on the exact breaker
closing time. The licensee submitted LER 89-001 " Sluggish Operation of
ITE 480 Volt Breakers Due to Inadequate Lubrication" to document the
problem. A review of this LER, revealed that the 480 volt breaker for the
inside recirculation spray pump (1-RS-P-1A) failed to close within the
time allowed by TS.
During the investigation of the maintenance procedure EMP-P-PL-01, 480
Volt Load Centered Air Circuit Breakers, the inspector determined that the
procedure did not include the specific lubrication requirements, specified
in the technical manual. The technical manual states that no lubrication
is required during the circuit breaker normal service life. However, if
the grease should become contaminated or if parts are replaced, any
lubrication should be done with NO-0X-ID or Anderol grease as applicable.
Technical Specification 6.8.1.a requires written procedures shall be
established, implemented and maintained, covering the applicable proce-
dures recommended in Appendix "A" of Regulatory Guide 1.33, Revision 2,
February 1978. Section 9 of Regulatory Guide 1.33 requires procedures for
performing maintenance. The failure of the licensee to have adequate
maintenance procedures to ensure proper operation of ESF equipment
breakers will be identified as a violation 338/89-08-01.
(Closed) Unresolved item 338,339/89-03-03, NRC review of TS 4.6.1.1.a.1.
The situation associated with this item involves the failure of the
licensee to verify the position of the three quarter inch up to two inch
capped vent and drain valves which are located within the containment
penetration boundary as recuired by TS 4.6.1.1.a.1. The licensee informed
the inspector that they had not considered these vent and drain valves as
containment isolation valves. The licensee believed that the TS
requirement only applied to manual isolation valves which isolated the
main pipe penetration. Consequently, the licensee admitted that they did
not perform the TS surveillance on these vent and drain valves.
TS 4.6.1.1.a.1 states, in part, that at least once per 31 days the
if censee will verify all penetrations not capable of being closed by
operable containment automatic isolation valves and required to be closed
during accident conditions are closed by valves, blind flanges, or
deactivated automatic valves secured in their positions. Periodic tests
1-PT-60.1 and 2-PT-60.1, Containment Integrity, is the test performed by
the licensee every 31 days to comply with TS a.6.1.1.a.1. This procedure
.
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inspects approximately 43 containment penetrations to verify that the
closure mechanism is closed (e.g. valve hatch, etc.). Howevar, the vant
and drain valves located between each containment isolation valve and the
containment penetration (outside of containment) were not listed in this
procedure. The failure of the licensee to comply with surveillance TS 4.6.1.1.a.1 will be identified as a violation 338,339/8S-08-02.
9. Generic Letter 88-17 Loss of Decay Heat Removal (TI 2515/101)
The inspectors reviewed Generic Letter 88-17 and the licensee's response
to the generic ' letter. At the time of the review, the licensee was
preparing Unit 2 for entry into a reduced RCS inventory condition as
defined by.the generic letter. Prior to entry into a condition with' RCS
level less than three feet below the vessel flange of the applicable
limit, the licensee experienced three events involving loss of RHR'
capability (see paragraphs 4.a 6.b and 6.c). During these events, the
operators demonstrated a heightened sensitivity concerning the loss of RHR-
and took prompt and aggressive corrective actions to restore RHR cooling .
-capability.
~The inspector has reviewed the li,ensee's procedures and controls
regarding loss of RHR. The following is a brief description of the
inspector's review,
a. Training
As discussed'in NRC Inspection Report 338,339/88-36, the inspector
attended the operator's tcaining session associated with the loss of
i. RHR events. The inspector _ felt the training was excellent for the
l- time; allotted. The inspector also attended a training session for
maintenance personnel on April 5. This session discussed the effect
maintenance activities can have on RCS level and the operating RHR
pump and components. The training also described the additional
controls which will be placed on ' any maintenance . activity that can
affect RCS inventory. The inspector felt that this training session
l. covered the concerns and controis associated with performing
'
maintenance during a reduced RCS inventory condition.
One observation made by the inspector was that the licensee did not
document the briefings conducted with maintenance personnel-
subsequent to the initial training sessions. This observation was
discussed with the licensee.
b. Containment Closure
l
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The inspector reviewed 2-OP-5.4, Draining the Reactor Coolant System,
and determined that the procedure required containment integrity to
be established in accordance with 2-PT-91, Containment Penetrations,
,
prior to RCS' level being reduced to less than 42 inches above nozzle
centerline. 2-PT-91 step 5.26 also requires that the containment
closure team be established prior to RCS level reaching 42 inches.
.
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- The inspector . verified that the SRO log listed. the names of the ,
maintenance personnel who were assigned to the containment closure
team during a particular shift. The inspector also reviewed the
, containment breach log which was attached ' to 2-PT-91 listing all '
penetrations other than the equipment hatch and personnel hatch which
L had to'be closed to establish containment closure.
l
One weakness identified > hy the inspector was the lack. of procedural-
requirements for the establishment of the closure team, the training
and briefing requirements for the team and the documentation of
personnel attending briefings. However, during the present outage
i
the inspector did not detect any lack of understanding of the purpose
!
and requirements for the team. The reason appears to be the
heightened sensitivity by both management and the operations staff to
i the issues concerning Generic Letter 88-17 and loss of RHR. However,
I. in the future, if these requirements are not formalized, they may not
I get implemented as effectively.
The inspector has discussed this observation with the licensee and
,
they have agreed to review the situation and provide some additional
I, procedural guidance and controls. The inspector will review the
l licensee's actions again during the Unit 1 outage and will include a
i review of the licensee's procedural guidance associated with
I
containment closure requirements.
c. RCS Temperature
The inspector reviewed 2-0P-5.4, Draining the Reactor Coolant System.
l This review revealed that step 4.9 and step 5.26 of the procedure
required the operator to verify that two core exit thermocouple are
operable prior to RCS level reaching 42 inches above nozzle center-
line (three feet below the vessel flange). The core exit
thermocouple are displayed on the core cooling monitor in' the
control room.
The inspector verified on several occasions while the Unit' 2 reactor
was in a reduced inventory condition that at least two thermocouple
were operable and that the operator knew which ones were operable.
L During the times checked, the inspector. observed five operable
L thermocouple indicating in the control and being logged by the
l operator in 1-Log-4A. The inspector compared the thermocouple
l temperature readings to the RHR pump discharge temperature and they
l were very close confirming the operability of the thermocouple. The
RHR pump discharge temperature was also being recorded via a strip
chart.
The inspector reviewed 1-AP-11.2, Loss of RHR. Attachment 7 of the
procedure included a set of curves illustrating the heatup of the RCS
following the loss of RHR. Even though Attachment 7 is located at
the back of 1-AP-11.2, the inspector could not find any reference to
.
1
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this set of curves in the body of the procedure. This observation
was discussed with the licensee.
d. RCS Water Level .
North Anna presently has only one means of RCS level indication
during reduced inventory condition. This means of indication is a
temporarily installed tygon hose with a TV csmera and continuous
monitor in the control room. In a letter from L. Engle, Project
Manager, NRR, to W. Cartwright, Vice President, VEPCO, dated
February 13, 1989, the NRC concurred with the use of only one means
of RCS level indication for the short term at North Anna.
The inspector observed the RCS level indicatior via the TV monitor on
each tour of the control room. The level indication was clear and
easily read. The operators were monitoring the RCS level
periodically and are required to log the results every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
During RCS draining evolution, the inspector observed an operator in
the control room on a head set monitoring the TV monitor while in
communication with an operator in the containment locally monitoring
the RCS standpipe level. The inspector observed portions of the
level standpipe hose during a tour of containment on April 11. No
problems were observed.
e. RCS Perturbation
The inspector reviewed 1-MISC-37, Assessment of Maintenance
Activities for Potential Loss of Reactor Coolant Inventory. This
procedure requires the Shift Superviser to assess all work orders
associated with the RCS, 51, RHR, RP or CVCS systems using the
following criteria:
(1) Component cannot be isolated completely from RCS.
(2) Operator action is required to maintain system level to permit
maintenance.
(3) Positive identification of component may not occur due to
similar devices in a surrounding area.
If the assessment of the above indicates there is a potential for
loss of RCS inventory, then the following actions are required:
(1) If maintenance requires an opening on the cold leg during
mid-loop operation, establish and verify a hot leg vent path.
' Ensure proper administrative controls are established to
inaintain the hot leg vent path until system integrity is
restored.
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(2) Conduct a pre-job briefing with maintenance personnel. Discuss
loss of inventory ' potential and contingency actions.
(3) Have .an operator accompany maintenance personnel to positively
identify the component and establish communications.
(4) Ensure makeup capability to the RCS is readily available.
(5) Establish communications between work site and control room.
(6) Notify the control room at the time work is started and when
work is suspended.
(7) Monitor RCS level (standpipe, pressurizer level, cavity level,
reactor vessel level) and containment sump level frequently
during the process.
(8) Notify the control room when the component is closed and system
integrity is restored.
All of the above items were discussed in detail during the
maintenance training session attended by the inspector on April 5.
l 2-OP-5.4, Draining the Reactor Coolant System step 3.0 requires that
l MISC-37 be entered into the action si iement status log and a copy
forwarded to the Shift Supervisor. This procedure also requires the
,
following:
(1) An operator to be stationed in containment in communication with
the Control Room to monitor RCS level during draining
evolutions.
l (2) All personnel involved in the draining evolution must attend a
pre-job briefing.
(3) No draining of RCS while purging the vessel head.
(4) The pressurizer PORVs and their isolation valves to be open
venting the RCS.
The inspector found the procedure to be somewhat confusing, but did
not observe the operators having any problems maintaining compliance
with the generic letter requirements. The inspector discussed the
procedure deficiencies with the licensee.
f. RCS Inventory Addition
The inspector verified that 2-OP-5.4 required that one HMSI and one
LHS1 pump be operable prior to the RCS level being lowered three feet
I
below the vessel flange. 2-MISC-35.1, CR0 Turnover Checklist
(Modes 5 and 6), step 7 requires the offgoing and oncoming CR0s to
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7. i st the two operable pumps and flow paths any time RCS level is
three feet or more below the vessel flange. The inspector
periodically verified based on control room indication the operable
pumps and flow paths. .
Abnormal procedure 2-Ap-11.2, Loss of RHR, establishes the criteria
for using the ECCS pumps to feed and bleed the reactor vessel. This l
procedure provid'.s attachments with the requirements for the use of J
either the HHSI pump or LHSI pump to maintain the core covered and to
remove decay heat.
g. Nozzle Dams ,
North Anna has loop stop valves and, therefore, does not use nozzle
dams.
4
h. Loop Stop Valves
The inspector reviewed a memorandum from J. O. Erb, VEPCO, to D.
A. Heacock, VEPCO, dated March 30, 1989, which stated that the ,
required vent path for the hot leg side of the vessel should be
greater than 19.19 square inches. This vent path is established to
prevent the hot leg side of the vessel from pressurizing with all
three of the hot leg stop valves closed and a hole in the cold leg
side. The lice.nsee's assumptions included 52 new fuel assemblies and
35 days since shutdown in determining the required vent size.
The licensee chose the vent path to be the flange opening for two of
the removed pressurizer safety relief valves. The licensee
determined that one opening was greater than 19.19 square inches but
to be conservative, they elected to use two openings.
To prevent foreign material from entering the opening, the licensee
installed screens over the openings. During a tour of containment
the inspector observed the openings and the screens. It appeared to
the inspector that the metal of the screens took up approximately
half of the area of the opening. The inspector questioned the
licensee and requested a calculation be performed determining the
effective area of the openings minus the ?rea of the screen metal.
The calculation was performed and reported to the inspector. The
report stated that the sum total of both openings was just over the
requirement of 19.19 square inches (actual 21.22 square inches).
The inspector's overall observation of the licensee's actions
regarding the potential loss of RHR was favorable. Both management
and the operation staff demonstrated increased sensitivity toward any
evolution potentially affecting RCS inventory. The actions and
procedures, even though several procedural upgrades are needed, were
more than adequate to comply with their commitments to the generic
letter. The minor procedural inadequacies were compensated for by
the operator training and resulting knowledge level of the
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requirements for operating in a reduced RCS inventory condition.
Although the licensee's program for operating during a known reduced
inventory condition was favorably reviewed, an RCS level control
event, which occurred after the generic letter inspection effort,
revealed a . fundamental problem with knowing the actual level when
using the standpipe system. This issue is discussed in paragraph
6.d.
10. Refueling Activities (60705, 60710)
The inspector reviewed the completed refueling master procedure 1-0P-4.3,
Controlling Procedure for Refueling. This review verified that the
precautions, initial conditions and action steps were completed and signed
off. The inspector observed that the applicable TS were listed in the
procedure and verified each time they were applicable.
The inspector interviewed the refueling coordinator and the refueling
shift supervisors. The inspector discussed the training activities for
the Westinghouse refueling personnel. The coordinator informed the
inspector that the contract refueling personnel were experienced refueling
personnel and received the training well.
During the 1987 refueling outages, the refueling activities went well with
the exception of two problems, one on each unit. These problems resulted
from the contract refueling personnel failing to follow procedures.
During the present Unit 2 refueling outage, the refueling shift
supervisors informed the inspector that the contract refueling personnel
were very receptive to their requests, unlike the previous outage. The
inspector was also informed that the refueling personnel followed the
procedures and their supervisor was very diligent in making sure that all
refueling steps were complete and properly signed off.
The inspector reviewed the deviation reports documented against the
refueling activities. This review did not reveal any problems similar to
the two reported problems during the 1987 outages. There were a couple of
minor discrepancies, but these errors did not have the potential for fuel
damage and were discovered by the refueling shift supervisor and
corrected.
The core off load commenced on March 14 and the reload was completed on
March 29. The only problem experienced during the fuel movement in the
reactor cavity involved new fuel assembly X44. This assembly would not
line up ar.d seat on the lower core plate. The assembly was removed and
inspected. The lower flow nozzle suffered some damage due to the lower
core plate alignment pens coming in contact with the lower nozzle feet.
The assembly was replaced with the same type of new fuel assembly
scheduled for Unit I refueting. The damaged assembly X44 had the bottom
nozzle removed and both the assembly and nozzle were shipped to
Westinghouse. The bottom nozzle will be replaced with a new one and the
fuel assembly will be shipped back to the station for use in Unit 1.
.
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11. Storage.and Handling of EDG Fuel Oil (25588)
On January 16,1967, the NRC issued IE Information Notice 87-04 to alert
the licensee of potentially significant. problems . pertaining to long-term
storage of fuel oil for EDGs. The , inspector reviewed the licensee's
programs . for maintaining adequate quality of the EDG fuel oil stored
on-site. Through reviews and interviews, the inspector determined that
the licensee:
-
Evaluated the aforementioned Information Notice 6nd other similar
industry events,
- Took actions as a result of the evaluation, including lean out of
fuel oil tanks, evaluation of samples for biologio. growth, and
evaluation of the use of additives to the fuel,
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Routinely. samples the fuel oil for viscosity, water, and' sediment in
accordance with TS, and
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Inspects and cleans fuel oil filters and strainers during outages.
No violations or deviations were identified.
12. Exit
The inspection scope and findings were summarized on April 17, 1989, with
those persons indicated in paragraph 1, The issue discussed in
paragraph 6.d. was summarized with the licensee on May 2, 1989. 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 provided to or reviewed by the inspectors
during this inspection. Dissenting comments were not received from the
licensee.
Violation 338/89-08-01, Failure to have adequate maintenance procedures to
ensure proper operation of ESF equipment 480 volt ITE breakers (paragraph
8).
Violation 338,339/89-08-02, Failure to comply with TS 4.6.1.1.a.1 for
containment penetration vent and drain valves (paragraph 8).
Apparent Violation 338,339/89-03-03, Potential for the SW and RSHXs to
have been inoperable (paragraph 4.b).
Apparent Violation 338,339/89-08-04, Inadvertent loss of reactor vessel
level (paragraph 6.d.).
A licensee oral commitment to develop a formalized approach for obtaining
control operations assistance and establish an implementation schedule by
May 17, 1989, was discussed.
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13. Acronyms and Initialisms
AP Abnormal Procedure
CAD' . Computer Assisted Drawing..
CAE. Condenser Air Ejector
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CDA Containment Depressurization Actuation
~CRO. Control Room Operator
DCP' Design Change Package
DUR Drawing Update. Request
EDG Emergency Diesel Generator
EP Emergency Procedure
ESF Engineered Safety Feature
EWR Engineering Work Requests
GPM Gallons Per Minute
HP Health Physics
IFI Inspector Follow-up Item
IR Inspection Report
LCO Limiting' Condition for Operation
LER Licensee Event Report
MCC~ Motor. Control Center
MOV Motor Operated Valve
MPC Maximum Permissible Concentration
MREM Millirem
NRC Nuclear Regulatory Commission
NSE Nuclear Safety Engineering
PDTT Primary Drain Transfer Tank
PES Plant Engineering Services
PORV Power Operated Relief Valve
PROM . Programmable Read Only Memory
PSIG Pounds Per Square Inch Gauge
PTSS Periodic Test Scheduling System
RMS Radiation Monitoring System
RS_ Recirculation Spray
RSHX Recirculation Spray Heat Exchanger
RTD Resistance Temperature Detector
RWP Radiation Work Permit
S/G Steam Generator
SALP Systematic Assessment of Licensee Performance
SI Safety Injection
SNSOC Station Nuclear Safety and Operating Committee
50V Solenoid Operated Valve
STA Shift Technical Advisor
TS Technical Specification
UE Unusual Event
URI Unresolved Item
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UFSAR Updated Final Safety Analysis Report
m _..J., _ _ _ . _ _ . _ _ . _ _ _ _ _ _ _ _ . _ , _ _ _ _ _ _ . _ _ . . _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ . _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ . _ _ . _ . _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
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VCT Volume Control Tank
WOG Westinghouse Owners Group
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