ML20151B498
| ML20151B498 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 03/30/1988 |
| From: | Caldwell J, Cantrell F, King L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20151B480 | List: |
| References | |
| 50-338-88-01, 50-338-88-1, 50-339-88-01, 50-339-88-1, NUDOCS 8804080259 | |
| Download: ML20151B498 (14) | |
See also: IR 05000338/1988001
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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1o1 MARIETTA STREET. N.W.
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ATLANTA, GEORGI A 30323
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Report Nos.:
50-338/88-01 and 50-339/88-01
Licensee: Virginia Electric and Power Company
Richmond, VA 23261
Docket Nos.:
50-338 and 50-339
License Nos.:
Facility Name:
North Anna 1 and 2
Inspection Conducted: January 16 - February 23, 1988
Inspectors:
Y #ceI
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Mf/
eqt"Inspector
Date Signed
J. t.7 Caldwell, Senior ig{e
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L. P M ing, Resident 171
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Date Signed
Approved by:
,n I 8k
3 3MF9_
F. 'Cfntrell, Section Utgy'V
Da(e Si%ned
Division of Reactor Projects
SUMMARY
Scope:
This routine inspection by the resident inspectors involved the
following areas:
plant status, unresolved items, licensee action on previous
enforcement matters, licensee event report (LER) followup, review of inspector
follow-up items, monthly maintenance observation, monthly surveillance
observation, ESF walkdown, and operator safety verification.
During the
performance of this inspection, the resident inspcetors conducted reviews of
the licensee's backshift operations on the following days - January 18, 24, 28,
29, 31, February 1, 2, 3, 5, 6, 9, 11, 12, 15 and 16.
Results: One violation with two examples for failure to follow procedure and
failure to have an adequate procedure.
8804080259 880331
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REPORT DETAILS
1.
Licensee Employees Contacted
- E. W. Harrell, Station Manager
- R. C. Driscoll, Quality Control (QC) Manager
- G. E. Kane, Assistant Station Manager
- M. L. Bowling, Assistant Station Manager
J. A. Still, Superintendent, Operations
M. R. Kansler, Superintendent, Maintenance
- A. H. Stafford, Superintendent, Health Physics
- D. A. Heacock, Superintendent, Technical Services (Acting)
- J. L. Downs, Superintendent, Administrative Services
J. R. Hayes, Operations Coordinator
E. S. Hendrixson, Engineering Supervisor ( Acting)
D. E. Thomas, Mechanical Maintenance Supervisor
G. D. Gordon, Electrical Supervisor
L. N. Hartz,
Instrument Supervisor
F. T. Terminella, QA Superviror
J. P. Smith,
Superintendent, Engineering
D. B. Roth, Nuclear Specialist
J. H. Leberstein, Engineer
- G. G. Harkness, licensing Coordinator
- D. B. Roth, Nuclear Specialist
- T. R. Maddy, Superintendent, Security
- G. D. Miller, Licensing Coordinator (Surry)
Other licensee employees contacted include technicians, operators,
mechanics, security force members, and office personnel.
- Attended exit interview
NRC Regional Management Site Visit:
B. Wilson and
F. S. Cantrell
conducted a visit of the North Anna Power Station on February 3, 1988.
2.
Exit Interview (30703)
The inspection scope and findings were summarized on February 23, 1988,
with those persons indicated in paragraph 1 above. The licensee
acknowledged the inspectors findings. The licensee did not identify as
proprietary any of the material provided to or reviewed by the inspectors
during this inspection.
(0 pen) Violation 338/88-01-01: Failure to follow procedure and failure to
have ar. adequate procedure resulting in a 1000 gallon leak from the RCS
(see paragraph 8).
(0 pen) Inspection Follow-up Item 338,339/88-01-02:
Disc separated from
stem on RTD loop isolation valves.
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(0 pen) Unresolved Item 339/88-01-01: Potential for failure to perform a
post maintenance test (see paragraph 9).
3.
Plant Status
Unit 1
Unit 1 began the inspection period in Mode 5, day 4, of an unscheduled
27-day outage. Unit 1 entered the outage due to resin being discovered in
the secondary systems and the steam generators. On January 23, a 35 gpm
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leak developed on the
"B" Reactor Coolant System (RCS) loop RTD bypass
line. The unit was still in Mode 5 with the RCS level being maintained at
approximately 10 inches above nozzle centerline.
The cause of the leak
was the performance of maintenance on the wrong flange in the RTD bypass
line (see section 8 for details).
1he leak was identified and isolated
without any affect on the unit or the operating Residual Heat Removal
(RHR) punp. As a result, the station manager stopped all work inside
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containment until the work in containment could be reviewed to ensure that
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personnel performing the work had conducted proper pre-job planning. Work
in centainment was allowed to recommence on January 24.
On February 2, a pressurizer Power Operated Relief Va?;u (PORV) lifted at
its low pressure setpoint of 345 psig while starting the
"A"
Reactor
Coolant Pump (RCP) (see section 11 for details). On February 8, day 27 of
the resin intrusion outage, the licensee restarted Unit 1.
The reactor
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was taken critical at 0323 on February 8 and achieved 100% power on
February 12. The unit is operating at approximately 100% power as of the
end of the inspection period.
Unit 2
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Unit 2 commenced the inspection period operating at approximately 100%
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power. On February 12, the licensee voluntarily shutdown Unit 2 based on
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NRC concerns relating to the ASME Code Section XI compliance with several
containment isolation valves (see Inspection Report 338, 339/88-02). The
unit was in Mode 3 by 0135, the valves in question were tested and
repaired as necessary to ensure compliance with ASME Code Section XI, and
the unit was restarted on February 14.
As of the end of the inspection
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period, Unit 2 is operating at approximately 100% power.
Both Units
On January 21, 1988, the NRC conducted an enforcement conference with the
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licensee i n the Region II Atlanta of fice.
The enforcement conference
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involved a discussion on environmental qualification type violations (see
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Inspection Report 338,339/87-32) and the violations cssociated with
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inoperable steam flow instruments discovered during the Unit 2 start-up on
November 4 (see Inspection Report 338,339/87-38).
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On January 26, Station Management conducted a meeting with all the station
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supervisors to discuss the significance of the recent problems and
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violations that had been identified in the last several months.
The
meeting was conducted to ensure that station supervision was aware that
problems have occurred, that they understood their significance, and
finally that they understood the necessity to prevent their recurrence.
The resident inspector attended the meeting.
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4.
Unresolved Items
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An Unresolved Item is a matter about which more information is required to
determine whether it is acceptable or may involve a violation or
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deviation.
One unresolved item was identified during this inspection and is discussed
in paragraph 9.
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5.
Licensee Action on Previous Enforcement Matters (92702)
(Closed) Violation 338/87-24-01: Failure to have a Safety Evaluation for
Leaking Steam Generator Plugs and Foreign Objects. Maintenance procedures
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have been revised to include criteria for requiring a deviation report to
be submitted for any abnormal occurrence.
Administrative Procedure 5.3
includes a step in the list of review criteria to instruct the reviewer
that a station deviation report be submitted when unexpected activities
are encountered,
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6.
Licensee Event Report (LER) Follow-Up (90712 & 92700)
The following LERs were reviewed and closed. The inspector verified that
reporting requirements had been met, that causes had been identified, that
corrective actions appeared appropriate, that generic applicability had
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been considered, and that the LER forms were complete. Additionally, the
inspectors confirmed that no unreviewed safety questions were involved and
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that violations of regulations or Technical Specification (TS) conditions
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had been identified.
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(Closed) LER 338/87-17:
Steam Generator Tube Rupture. Responses will be
tracked under AIT report 338/87-24 dated August 28, 1988.
7.
Review of Inspector Follow-up Items (92701)
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(Closed)
IFI 338/87-24-08:
Review Securing of LHSI Pump Early.
The
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licensee has received concurrence from Westinghouse that the pump was
secured in the proper sequence as directed in the Emergency Response
Guidelines. The licensee has determined that overheating of the pumps on
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recirculation is not a valid concern for North Anna.
Therefore, the
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licensee has changed their Emergency Operating Procedure to secure the
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LHSI pumps after the leak has been isolated.
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8.
Monthly Maintenance (62703)
Station maintenance activities affecting safety related systems and
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components were observed / reviewed, to ascertain that the activities were
conducted in accordance with approved procedures, regulatory guides and
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industry codes or standards, and in conformance with Technical
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Specifications.
Unit 1 outage commenced on January 13 to flush and drain the steam
' generators due to resin intrusion.
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The most significant work accomplished during the outage was:
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a.
Replacement of "A" reactor coolant pump seal;
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b.
"C" main steam trip valve overhaul;
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c.
Motor changeout of "A"
recirculation fan;
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Overhaul of 1-SI-P-1B (LP I pump B);
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e.
Flush and fill of steam generators to remove resin fines,
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The inspector made containment entries to observe work on items (a) and
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(c) above.
No problems were identified.
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The Low Head Safety Injection Pump,1-SI-P-1B, was overhauled due to its
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marginal acceptance of the differential pressure criteria during previous
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periodic tests.
(See Inspection Report 338, 339/87-34)
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Following the pump overhaul, the inspector observed the installation of
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1-SI-P-1B (Low Pressure Injection Pump) and reviewed the purchasing of the
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spare parts that were replaced on 1-SI-P-18.
It was determined from
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discussion with the licensee's Engineering and Quality Assurance
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Departments that several of the
parts were purchased from another
facility as non-safety related. This included three shaft sleeves and "0"
rings.
The inspector had a concern that these were purchased as
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non-safety related parts instead of safety related.
The licensee had
written a risk release document which was dispositioned by Engineering
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saying that the non-safety related parts could be used until the next
outage. The risk release document is a licensee internal docurnent which
allows parts which do not meet all of the requirements to be released for
installation pending further engineering review. This review must be
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completed before the piece of equb.aent for which the parts were t; sed is
declared operable.
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The licensee has written a Technical Report No. ME 0011, Rev. 1, which
accepts the journal sleeves as meeting the three criterial for commercial
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grade as described in 10 CFR 21. The licensee then dedicated these sleeves
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for use as a base component in the LdSI pump based on the dimensional
requirements being verified by recefst inspection and receipt of a letter
from the pump vendor stating that the material is the some for commercial
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as for nuclear grade.
The licensee's intention, based on a letter from
the vendor verifying the parts as acceptable and Revision 1 of Technical
Report ME-0?ll, is not to replace the journal sleeves, but to accept them
as is.
This process was discussed with the NRC staff in Region 11 and
determine ' to be acceptable.
On Jant
23, with Unit 1 in Mode 5 and vessel level being maintained at
approximately 10 inches above nozzle centerline, the operator noticed an
increasing reactor sump level. The vessel level which was being monitored
by a standpipe located in the containment with a television monitor in the
control room also indicated a decreasing level.
The operators secured
letdown, increased makeup to the vessel and entered 1-AP-16, Excessive
Primary Leakage.
Shortly af ter discovering the loss of water from the
primary, the operators were contacted by mechanics in the containment and
informed of a leak from a loop B RTD bypass line flange
which the
mechanics could not isolate.
The operators maintained vessel level well
above that necessary to provide Net Positive Suction Head (NPSH) to the
operating RHR pump, continued to monitor the operation of the RHR pump and
dispatched four operators into the containment to isolate the leak.
The leak was isolated approximately 30 minutes after discovery by an
operator shutting one of the RTD bypass line isolation valves (1-RC-59)
inside containment.
The leak was determined to be approximately 35 gpm
and a little over a 1000 gallons had leaked into the containment sump.
The Health Physics (HP) Staff conducted sampling activities and determined
that an airborne condition did not occur and that there was no indication
of any radioactive release.
Following the leak isolation, the operators vented the operating RHR pump
and determined that no air or gases had entered the pump. Also the Shift
Supervisor had entered containment and determined that the standpipe level
scale (ruler) had been installed approximately six inches above where it
should have been, therefore, actual vessel level was being maintained at
approximately 16 inches instead of 10 inches above nozzle centerline.
Based on the above and the fact that the elevation of the flange which
caused the leak was actually above the top of the nozzle there did not
exist a potential for a loss of all RHR.
The inspector reviewed the licensee's procedures for installation of the
standpipe and the level scale (ruler). The instructions for installation
of the standpipe were contained in 1-0P-5.4, Draining the Reactor Coolant
System, which stated, "Request the planning dept, to generate repetitive
work orders to remove blank flanges and install the desired spool pieces
and level hose." There were no other instructions for installation with
the exception of a signoff in 1-0P-5.4 for the level hose installed
between 1-RC-104 and pressurizer vacuum breaker tee.
The inspector
determined, based on discussion with the operators, that the ruler is
installed by the operators without any procedure. The standpipe, a tygon
hose, is connected to valve 1-RC-104 which penetrates the Reactor Coolant
System (RCS) at an elevation approximately nozzle centerline.
Conse-
quently, the operators locate the ruler next to the tygon hose so that the
bottom of the ruler is located approximately the same elevation as the
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valve's,1-RC-104, penetration into the loop.
Since there is no formal
method or procedure to install the standpipe and level scale, then there
are no checks, signoffs or second verification to ensure that the
standpipe and level scale is installed properly. The failure to have an
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adequate procedure to ensure proper installation of the RCS level
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standpipe and reference level scale will be identified as the first
example of Violation (338/88-01-01).
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The licensee determined the cause of the leak to be the failure of the
mechanics to perform maintenance on the right flange inside containment.
The mechanics were requested to repair a leak on flow element flange
1-RC-FE-1491 per work order 5900070293.
The mechanics were to perform
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their
repair
per
Mechanical
Maintenance
Procedure,
K9-C-P-4,
Oisassembling, Inspection, Repairing, Reassembling Safety-Related Piping
System Bolted Flanges in General.
There were two flanges located in the same general area on the loop B RTO
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bypass line, one to the flow element 1-RC-FE-1491 which was the flange
that was supposed to be worked and the other to flow ori fice 1-RC-R0-1.
Both flanges had their lagging removed, neither had identification tags
installed and the wrong flange 1-RC-RD-1 was the only one with boric acid
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on it because the other flange had been cleaned in preptration for work.
Consequently, the mechanics choose the flange to wrrk, liased on the boric
acid buildup and the fact that they found several loose bolts, instead of
leaving the containment to make sure which was the right flange.
The
licensee also determined that the locatior of the item to be worked or
whether it would be identified was not discussed during the mechanics
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pre-work briefing.
The inspector questioned why maintenance on a loop RTD bypass line flange
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had not had isolation set prior to the start of work.
The licensee
informed the inspector that isolation had been considered but based on the
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elevation of the flange and the fact that vessel water level was being
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maintained well below that elevation, the Shift Supervisor considered
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isolation unnecessary. The inspector is aware of a desire on the part of
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the licensee not to use the RTO bypass line isolation valves because most
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of them have had their discs separated from the valve stem.
This
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condition was discovered by the licensee back in 1985 but was determined
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to be acceptable as long as flow through the RTD line was sufficient to
Consequently closing these valves may
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prevent them from being reopened by the RTO bypass line flow which would
result ia inoperable RTO loop protection signals. During the restart
following the outage sufficient flow was developed in the "B"
loop RTO
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bypass line indicating that the valves did unseat and continued operation
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with these valves was considered acceptable.
Based on the continued
acceptable RTD bypass ficw through these valves and the high dose that
would be encountered during their repair or replacement, t% licensee has
elected not to perform permanent repairs at this time.
However, the
licensee informed the inspectors that they intend to make oermanent
repairs in the future and are still in the process of determining the best
rae thod . The inspector reviewed the licensee justification for operation
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with inoperable valves, and requested regional review of this problem.
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This is identified as laspection followup item (338,339/88-01-02).
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The failure of the licensee to properly isolate and perform work on the
correct comoonent per Maintenance Work Order 5900070293 and MMP-C-P-4
resulting in approximately a 1000 gallon leak from the. RCS constitut's a
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failure to follow procedure.
This failure to follow procedure will
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identified as the second example of Violation (338/88-01-01).
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As a result of the event, the Station Manager stopped all work inside
containment until the event could be fully evaluated and until all othar
work could be reviewed to ensure that proper pre-job planning had been
performed. Work was allowed to recommence on January 24.
It should also
be noted that this event occurred just prior to the scheduled licensee
management meetings with all station personnel to discuss the importance
of attention to detail and proper adherence to procedures.
This
particular event was used as one of the examples of the problems that had
occurred stressing the importance of following procedures.
The meetings
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commenced on January 26, two days after the flange leak incident.
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All three steam generators were flushed and drained to remove any
intrusion of powdex resins. The feedwater and condensate lines were also
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flushed and sampled. An inspection of the condensate polishers indicated
that several internal candles had come loose at the bottom allowing resin
fines to escape. The licensee has had a manufacturer's representative in
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to look at the problem.
Procedures and tests are being developed to
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prevent recurrence. The licensee is writing a voluntary LER.
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The "C" Main Steam Trip Valve (MSTV),1-MS-TV-101C, was investigated to
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determine possible
problems due
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unusual
noise.
After the
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investigation, wMch was inconclusive, the valve failed to pass the
periodic test procedure 1-PT-212.9 for valve stroke.
The closing time
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took greater than six seconds on several attempts to perform 1-PT-212 9.
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This is greater than the maximum five seconds allowed by Technicil
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Specifications requiring the valve to remain inoperable.
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The inspector reviewed work request 530643 to overhaul the C MSTV.
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licensee replaced the springs in both actuators for the valve and the
valve still failed.
An engineering work request was written which
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increased the size of the bleed-off line from the actuators from a
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one-half inch line to a one inch line and an additional solenoid valve was
installed (via an approved modification).
Retest of the valves then
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indicated a 3.9 second closure which was acceptable.
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The inspector reviewed work request 371640 and observed the work on main
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steam non-return valve (1-NRV-102C) on Unit 1 steam generator "C" outlet.
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The non-safety related valve had been previously Furmanited to stop a leak
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and the Furmanite was being removed to allow repacking the valve for the
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permanent repair.
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The inspector also observed replugging of leaky tubes on the first stage
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feedwater heater 2-FW-E-1A for Unit 2.
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The inspector reviewed and observed work being performed per work request 238703 on Unit 2 auxiliary turbine driven feedpump.
The pump was being
repacked, the oil was drained and replaced, and a leaky lube oil cooler
was removed, plugged and reinstalled.
The inspector observed the
surveillance test performed after the work had completed (see Surveillance
Section for 2-PT-71.1).
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9.
Monthly Surveillanco (61726)
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
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conditions for operation (l.CO) were met and that any deficiencies
identified were properly reviewed and resolved,
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The inspector observed the following surveillances:
a.
2-PT-71.1, Test of Auxiliary Turbine Driven Feedpump.
The test
failed due to a high differential pressure which caused the relief
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valve to open. The governor was readjusted and the pump was retested
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satisfactorily.
During the course of the test, the motor driven
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auxiliary feedpump room filled with steam.
The licensee traced the
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problem to the drain lines from the turbine driven feedpump to the
motor driven feedpump room being crosstied and isolated by a foot
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valve which stuck open. This allowed drains from the turbine driven
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auxiliary feedpump to back up into the motor driven pump room. The
licensee worked on the foot valve and the volume of steam was
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reduced.
The licensee stated the amount of steam still leaking was
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insignificant and would be removed by the exhaust system.
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b.
On February 3,1988, the inspector observed Periodic Test 1-PT-212.4
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to determine closing time of 1-MOV-FW-154C, the main feedwater
isolation valve for
"C" steam generator. This valve failed the
periodic test by closing in excess of the required maximum of five
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seconds,
A deviation report anc work request was submitted to
Engineering who dispositioned them, stating under 6.5 seconds was
acceptable 'or the safety analysis (FSAR allowed closure time is 9
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seconds).
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c.
On February 3, 1988, at 1817, the Unit I reactor coolant pump "C" was
secured to stroke 1-TV-CC-102A and 1-TV-CC-100C using periodic test
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1-PT-212-1.
No prcblems were identified.
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d.
On February 11, 1988, as a resu; of a concern by an NRC Quality
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Assurance Audit Team, the lict : sue decided to stroke 2-TV-CC-203 A
and B, which are the componen cooling water from the residual heat
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removal and excess letdown heat exchanger (see Inspection Report 338,
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339/88-02).
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The resident inspector entered the Unit 2 outside penetration area
with a licensee engineer to witness the stroking of the valves using
Periodic Test 2-PT-212.1,
When the stroke test was performed on 203A, the valve closed limit
switch light never actuated in the control room.
It was observed by
the inspector that the valve started to close approximately 30
seconds after the solenoid was deenergized and the valve rotated 90
degrees to the close position.
A retest of the valve using a
stopwatch in the penetration area indicated the valve closad in 47.8
seconds.
Valve 203 B was also tested and closed in 62.5 secords.
This was above the required 60 seconds in Technical Specification
3.6-1.
The licensee engineer and inspector noted that one-fourth inch piping
was :nstalled on the outlet port of the solenoids.
The inspector
questioned if a modification had been made and was inf' med that the
valves were modified during the Unit 2 outage.
The ir.spector asked
the licensee to retest the valves without the tubing and research the
stroke times before and after the modification change.
The research
showed the times had changed significantly af ter the modification.
The licensee wrote an engineering work request and removed the tubing
and the valves retested at 16.5 and 24.4 seconds, respectively.
The inspector obtained copies of engineering work requests86-498 A,
B, and C, which installed the tubing on the discharge of the solenoid
valves.
It was determined that "ASC0" recommended to the licensee
that the exhaust port of their catalog NP-1 valves should be fitted
with downward pointing street elbows to prevent moisture from
entering the internal areas of the valve.
It stated that moisture
entering the internal areas of the valve could cause degradation of
internal parts, galling of piston, scale buildup and mechanical
failure of the valve.
In addition, QDR 35.1 and ASCO qualification reports AQR-67368 and
21678 require the solenoid operated valves be ven'ad and arranged
such that chemical spray will not enter the system through any vent
opening.
A review of the licensee Engineering Work Request that installed the
modifications revealed that the licensee allowed the use of tubing to
fitting adapters as well as street elbows to be installed.
The
tubing restricted the air flow causing the valves to close more
slowly.
A further review iiMicated that Administrative Procedure
3.8, Attachment 1 (Design Procedure Input Checklist) indicated on
page 3 that test requirements inu'uding in plant tests was marked not
applicable for all three engineerins work requests86-498 A, B and C.
The inspector was concerned that modifications had been made to the
valves without testing. The Technical Specification requires the
valves to be operable in Mode 1 thru 4.
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The inspector was informed that some of the valves were tested by
Operations during performance of routine
periodic test before
entering Mode 4 and even though the valves passed, some of the stroke
times had increased. The licensee did not identify at that time that
the stroke times had increased due to the modification. The licensee
is investigating to determine if any modifications were made after
leaving Mode 5.
Any modifications made af ter leaving Mode 5 would
require post modification testing prior to the valve being declared
unoperable.
This will be identified as Unresolved Item (URI)
339/88-01-01,
pending inspector review to determine
if
the
modifications were installed after leaving Mode 5 and if post
maintenance testing was performed,
e.
On January 29, the inspectors witnessed Special Test 1-ST-77 which
performed a retest on the LHSI pump 1B following its overhaul (see
Maintenance, Section 8). The test first placed the LHSI pump in the
recirculation mode and completed 1-PT-57.1B, ECCS Subsystem Low Head
SI Pump (1-SI-P-1B) satisfactorily. Then with the unit in Mode 5, the
pressurizer level at 10% and the pressurizer PORVs blocked open, the
licensee opened the LHSI pump discharge valve to perform a full flow
test of the pump which was not requireo by regulations.
Shortly
after the discharge valve was opened, and flow and pressure data were
taken, the LHSI pump was secured to prevent filling the pressurizer
solid (approximate 40 second run time).
Based on full flow data and associated discharge pressure data taken,
the pump was determined to be operating well above the design
operating curve. The licensee determined that the flow reading was
correct, based on a comparison with the change in pressurizer level,
and in line with the expected flow rate for those conditions.
However, the discharge pressure was too high.
The
licensee
determined, based on a calculation of the horse power needed to
develop the recorded discharge pressure and flow rate, that the pump
had an efficiency greater than one, which is impossible. Since the
flow rate had been determined to be accurate, the licensee concluded
that the discharge pressure data at full flow was not correct. Using
the data recorded from the recirculation phase of the pump operation,
both at full recirculation, approximately shutoff head and full flow,
the licensee was able to calculate, based on some conservative
assumptions, a best estimate of the discharge head of the pump at
full flow
This discharge head and flow data point was just below
the design head curve but above the curve used for the basis for
Emergency Core Cooling System (ECCS) performance. After discussion
with the vendor, a review of the vibration data which was very low,
achieving a satisf actory flow rate, the satisfactory performance of
the Technical Specification required surveillance, and an engineering
review of the calculational bisis for the estimate of the pump head
at full flow conditions, the licensee declared the LHSI pump 1B fully
operational.
The licensee has been unable to determine the cause of
the incorrect discharge pressure reading.
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11
f.
On January 29, the inspectors witnessed the stroke time testing of
MOV 18900, a LHSI pump discharge valve. The test which was conducted
per 1-PT-213.8, Valve Inservice Inspection (Safety Injection System)
was performed satisfactorily.
No violations or deviations were identified.
10.
ESF System Walkdown (71710)
The following selected ESF systems were verified operable by performing a
walkdown of the accessible and essential portions of the systems on
February 16, 1988.
The inspectors walked down the valve alignment of the Unit 1 Low Head
Safety Injection System using valve checkoff list 1-0P-7.1A.
The manual
valves inside containment and the valves in the safeguard valve pit area
were not checked.
No problems were identified.
The inspectors informed the licensee of the following observations:
a.
The valve area had various tools and trash laying around;
b.
Staging was installed in the Low Head Safety Injection (LHSI) pump
cubicles;
c.
Valves 1-SI-217 and 1-SI-314 need caps installed;
d.
Valve 1-SI-307 (Recirculation Line Vent) had boron residue on the
pipe cap and packing gland indicating a leak.
The licensee has removed the tools, trash, and staging from the LHSI area.
The inspectors also requested that the licensee perform safety evaluations
in the future prior to installing any equipment such as staging around
safety related equipment. The licensee has committed to performing these
safety evaluations.
No violations or deviations were identified.
11.
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 shif t 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 Technical Specification (IS) and Limiting Conditions for
Operations.
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{'
In the course of the monthly activities, the resident 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
4
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.
In
addition, the resident inspectors observed protected area lighting,
protected and vital areas barrier integrity and verified an interface
2
between the security organization and operations or maintenance.
.
On a regular basis, Radiation Work Permits (RWP) were reviewed and the
specific work activity was monitored to assure the activities were being
1
conducted per the RWPs.
3
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 operating and standby safety systems and
equipment; and confirming valve positions, instrument and recorder
readings, annuciator alarms, and housekeeping.
The following comments were noted:
'
On February 2, with Unit 1 in Mode 5 preparing to return to power
operation, a Power Operated Relief Valve (PORV) lifted at it's low
pressure setpoint.
The Unit was solid with pressure approximately
.
320 psig and the "B" Reactor Coolant Pump (RCP) operating just prior to
the event. The licensee had just started the "A" RCP and the operators
.j
were increasing pressure to maintain the necessary differential pressure
j
across the number one seal on the "A"
RCP.
By the pressure indication
available to the operator in the control room, primary pressure appeared
1
!
to be stable around 335 psig. However the PORV lifted at its setpoint of
345 psig. The operators immediately began reducing pressure by increasing
letdown to reclose the PORV but also tried to maintain the necessary
200 psig across the "A" and "B" RCP number one seals. The PORV reclosed
but the operators were unable to maintain the necessary differential
.
pressure across the number one seals and the "A" and "B" RCPs had to be
4
secured.
Initial NRC review of the events surrounding this value lifting
i
indicated no operational problems.
!
l
The licensee has determined several corrective actions which should
l
prevent recurrence of PORV activations during solid plant operations.
!
These corrective actions will be detailed in the LER 88-008 to be issued
l
by the licensee before March 2.
The inspector will review and follow up
on these corrective actions during the associated LER review and close
1
out.
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l
1
!
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I
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13
On February 12, the licensee voluntarily shut Unit 2 down in response to
questior.s raised by the NRC concerning compliance with ASME Code Section
XI on certain containment isolation valves (see Inspection Report
338, 339/88-02 for details).
These containment isolation valves were
associated with component cooling water to the RCPs and should not be
stroke tested with the RCPs running. Consequently, the licensee shut the
unit dcwn to allow securing of the RCPs for stroke testing and repairs as
necessary of the component cooling water containment isolation valves.
The inspectors witnessed the testing of several of the valves per
1-PT-212.1, Valve Inservice Inspection (Component Cooling System). All of
the valves were tested satisf actorily with the exception of TV-CC-201B
which closed in 62.4 seconds.
The Technical Specification (TS) require-
ment for this valve is less than 60 seconds and the results from the last
satisfactory test performed on October 25, 1987, indicated the valve
closed in 6.6 seconds.
The valve was declared inoperable and the
appropriate TS action statement was entered.
The licensee removed, overhauled and reinstalled the solenoid valves
associated with TV-CC-201B and all other valves that had previously failed
or were in the alert condition.
The overhaul and inspection of the
solenoid valve TV-SOV-CC-201B did not reveal any proolems which would have
caused the solenoid to stick.
The licensee completed retests of the
component cooling water containment isolation valves prior to the unit
restart. All the valves were tested satisfactorily and TV-CC-201B closed
in approximately 6.2 seconds. Unit 2 was restarted on February 14 and
placed back on line on February 15, 1988.
No violations or deviations were identified.