IR 05000213/1986016
| ML20202F597 | |
| Person / Time | |
|---|---|
| Site: | Haddam Neck File:Connecticut Yankee Atomic Power Co icon.png |
| Issue date: | 07/08/1986 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20202F561 | List: |
| References | |
| TASK-2.F.2, TASK-3.A.2.1, TASK-TM 50-213-86-16, NUDOCS 8607150198 | |
| Download: ML20202F597 (14) | |
Text
_ _ - _
.._
.. _ - _
_.
__
-.
_ -
..
._
-
-. -.
_
i
.
!
.
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-213/86-16 DCS Nos:
50-213/86-05-06 50-213/86-06-02
,
Docket No.
50-213 50-213/86-05-08
'
50-213/86-05-17 License No.
OPR-61 50-213/86-05-18 i
50-213/86-05-24
Licensee:
Connecticut Yankee Atomic Power Company 50-213/86-05-27 I
P. O. Box 270 50-213/86-06-04 Hartford, CT 06101 50-213/86-06-17 50-213/86-06-19 Facility:
Haddam Neck Plant, Haddam, Connecticut 50-213/86-06-22 50-213/86-06-28 Inspection at: Haddam Neck Plant Inspection conducted: May 28 through July 8, 1986 Inspectors:
Geoffrey Grant, Resident Inspector Stephen Pindale, Resident Inspector Paul D. Swetland, Senior Resident Inspector Approved by:
b kO+/AL 9/8l86 I
E. C. McCabe, Chief, Reactor Projects Section 3B Date Summary:
I j
Areas Inspected:
This was a routine resident inspection (156 hours0.00181 days <br />0.0433 hours <br />2.579365e-4 weeks <br />5.9358e-5 months <br />) of the fol-
'
lowing areas: plant operations, radiation protection, physical security, fire pro-tection, maintenance, surveillance, open items, licensee events, and TMI Action
Plan Implementation.
!
Results:
Inspector review identified satisfactory performance in all areas.
Six NRC open inspection findings were closed.
Unresolved items were identified re-j garding design change discrepancies for the main steam isolation valves (Detail
]
3.1) and HPSI recirculation valve operation (Detail 3.3).
3
,
J l
i
!
8607150198 860709 PDR ADOCK 050002 3
- _.
.
. -. _ _ - _ -. - -
-
- - -
-.
- - -
. - -
...
- _ _ -..
-
-
-,
__
_ _ _ _ _ _ _ _ _ _ _ _
.
.
TABLE OF CONTENTS Page 1.
S umma ry o f Fac i l i ty Act i v i ti e s.......................................
2.
Review of Plant Operations...........................
...............
3.
Observation of Maintenance and Surveillance Testing..................
4.
Followup on Previous Inspection Findings.............................
5.
Followup on Events Occurring During the Inspection...................
6.
Followup on TMI Action Plan Items.............
......................
7.
Review of Periodic and Special Reports...............................
8.
Unresolved Items...........
........................................
9.
Exit Interview.....................................
...............
.
l f
.
i i
i
..
.
. _ -
. _.
.
=
=
.
DETAILS 1.
Summary of Facility Activities At the start of the inspection period, the plant was operating at full power.
On June 2, 1986, a manual load reduction to 70% power was accomplished due to failure of the load runback circuit to reduce plant load following a spurious actuation of the nuclear instrumentation system (NIS) negative rate dropped rod protection.
After repair of the slipping turbine load-limiter clutch which prevented the automatic runback, the plant was returned to full power on June 2.
On June 4, operators manually tripped the plant after main feedwater system (MFW) fluctuations resulted in rapidly decreasing steam generator (SG) levels.
The MFW problems were caused by a failed closed heater drain tank level con-trol valve.
After repairs to the level control valve on June 5, full power operation resumed following short secondary chemistry clean-up holds at 5 and 20%.
On June 17, the same level control valve again failed shut and operators again manually tripped the plant in anticipation of low SG 1evels.
The level control valve was modified to prevent the separation of the valve stem and
operator which caused both the June 4 and 17 events.
During the June 17 shutdown, main steam isolation valve (MSIV) stroke testing revealed that the MSIV air operating accumulator did not have adequate cap-acity to close all four MSIVs. The plant was returned to criticality but power operation was delayed until June 23 while MSIV air system modifications were implemented.
!
A reactor trip from zero power occurred on June 19, after NIS power range
{
drawer 34 had failed, due in part to elevated control room temperature.
Upon
!
repairs to the NIS and control room ventilation, and completion of MSIV test-ing, plant startup began on June 22.
The plant tripped at 10% power on June 22 because a reactor protection system loop low flow relay contact had been obstructed by a small piece of ceiling
'
tile.
Upon identification and correction of the cause of the trip, plant operation resumed on June 24.
After secondary chemistry holds and completion of a 3-loop flow measurement test, full power was achieved on June 27.
Another spurious load runback actuation occurred on June 28.
Operators diag-nosed the spurious condition and over-rode the signal before a significant power drop occurred.
The plant remained at full power until the end of the inspection period.
2.
Review of Plant Operations Plant operation was observed during regular tours of the following plant areas:
-
-
- _ _ _
. -. -
.. - -
._.. _
_,-
.
-
--.-
-
..
.--
._ -
.
- -
.- -
.
--
Control Room
--
Security Building
--
Primary Auxiliary Building Fence Line (Protected Area)
--
--
Vital Switchgear Room
--
Yard Areas
--
Diesel Generator Rooms
--
Turbine Building
--
Control Point
--
Intake Structure and Pump Building
,
Control room instruments were observed for correlation between channels and for conformance with Technical Specification requirements.
The inspector observed various alarm conditions which had been received and acknowledged.
Operator awareness and response to these conditions were reviewed.
Control room and shift manning were compared to regulatory requirements.
Posting and
'
control of radiation and high radiation areas was inspected.
Compliance with Radiation Work Permits and use of appropriate personnel monitoring devices were checked.
Plant housekeeping was observed, including control and storage
-
of flammable material and other potential safety hazards.
The inspector also examined the condition of various fire protection systems.
During plant tours, logs and records were reviewed to determine if entries were properly made and communicated equipment status / deficiencies.
These records included operating logs, turnover sheets, tagout and jumper logs, process computer printouts, and Plant Information Reports.
The inspector observed selected aspects of plant security including access control, physical barriers, and personnel monitoring.
As noted below, no unacceptable conditions were identified.
2.1 The inspector reviewed the status of control room alarm annunciators which are routinely in alarm during plant operations.
This assessment was to determine the extent to which these constant alarms mask actual or new plant conditions.
Only one main control board alarm, pressurizer relief tank (PRT) high temperature, is annunciated constantly.
This
~
alarm condition results from an indicator equipment failure rather than
,
an actual abnormal condition.
Repair parts have been back-ordered for several months.
The inspector verified that PRT temperature was indi-l cated, recorded and logged on an auxiliary indicator and that rapid PRT t
condition changes would be annunciated by relief valve position indicator alarms and PRT pressure and level annunciators.
!
The inspector also observed that several electrical distribution system i
bus high voltage alarms are very often in an alarm condition.
This is
'
due to normally high off-site grid voltage over which operators have little or no control.
High bus voltage is an equipment aging concern.
The licensee stated that no abnormal equipment insulation degradation had been identified to date.
The inspector indicated that, if present grid voltage values were acceptable for long term equipment operation, then adjustment of alarm setpoints to remove these " normal" alarms would enhance operator recognition of unacceptable voltage changes on distri-bution buses.
Licensee action in this regard will be reviewed during routine control room observations.
Overall, however, the relative few number of normally lit annunciators contributes positively to operator knowledge of plant operating condition discrepancies.
I
.
- -...
.--
.
- -
.------
_
-
--.
.
-
__
- _ _ _ _ _ _ _
.
2.2 During an NRC team inspection of the licensee's fire protection program in June 1986, a weakness was identified in the licensee's procedures for safe shutdown of the plant following certain analyzed fires.
Abnormal Operating Procedure 3.2-8, Plant Operation Outside Control Room, did not provide for adequate make-up water supplies to fully cooldown the plant.
This discrepancy is documented in NRC Region I Inspection Report 50-213/
86-17.
Prior to plant startup on June 23, 1986, the inspector verified that Procedure 3.2-8 had been revised to include several alternate feed-water supplies.
As a final alternative, a dedicated connection was im-plemented to refill the demineralized water storage tank with river water using the diesel-driven fire water pump.
Revision 11 to Procedure 3.2-8 was reviewed by the Plant Operations Review Committee and approved on June 20, 1986.
The inspector had no further questions in this area.
3.
Observation of Maintenance and Surveillance Testing The inspector observed various maintenance and problem investigation activi-ties for compliance with requirements and applicable codes and standards, QA/QC involvement, safety tags, equipment alignment and use of jumpers, per-sonnel qualifications, radiological controls, fire protection, retest, and reportability.
Also, the inspector witnessed selected surveillance tests to determine whether properly approved procedures were in use, test instrumenta-tion was properly calibrated and used, technical specifications were satis-fied, testing was performed by qualified personnel, procedure details were adequate, and test results satisfied acceptance criteria or were properly dispositioned.
The following activities were reviewed:
Main Steam Isolation Valve (MSIV) Stroke Tests (Surveillance 5.1-12)
--
Installation of MSIV Air Accumulator Modifications in accordance with
--
Plant Design Change 86-837
--
Flood Protection Equipment Inspection and Inventory (Preventive Mainten-ance 9.5-125)
--
Power Range Nuclear Instrument Channel 34 Power Supply Repairs
--
Monthly Core Cooling Surveillance (SUR 5.1-4)
3.1 During a plant shutdown on June 17, 1986, the licensee conducted MSIV stroke time testing in accordance with Technical Specification (TS) 4.9.
These were the first MSIV stroke tests following plant heatup after the 1986 refueling outage.
The licensee had revised the test procedure, SUR 5.1-12, Main Steam Line Isolation Trip Valve Tests, during the outage to require stroking the MSIVs without makeup from the non-safety-related control air system.
This change resulted from industry and NRC notifi-cations (NRC Information Notice IEN 85-84) indicating that some MSIVs have failed to close without makeup from a potentially unreliable support system.
In the June 17 tests, 3 of a MSIVs closed within the 10 second TS acceptance criterion, but the fourth valve tested (in any sequence)
failed to completely close.
.
.
.
The MSIVs are check valves installed in the steam lines such that steam flow to the main turbine closes the MSIV.
The valve flapper is attached to an air piston.
Normally, control air pressure holds the piston and flapper up against a spring on the upper side of the piston.
A valve closure signal vents the air under the piston and the spring pushes the flapper into the steam flow stream.
Steam flow slams the valve shut.
In order to assure that the MSIVs shut fully, an air closure system pressurizes the top of the operating piston at the same time the control air is vented from the bottom.
Closing air for all four MSIVs came from one air accumulator normally pressurized to 93 psi by the control air system through a check valve.
The air closure system was not constructed to seismic standards and is not single-failure proof.
The licensee has since upgraded the quality assurance (QA) controls for of the system to a Category I rating.
(That did not involve any design change.)
After the licensae determined that the accumulator at 93 psi would not close all four MSIVs, it was shown that 97 psi would close the MSIVs.
The control air system could not reliably maintain 97 psi to the accumu-lator because of overall air system loading and the fact that the MSIV closure system bleeds air slowly due to a small amount of leakage in the c
system.
The licensee concluded that the air accumulator system would have to be modified to assure that the TS full stroke test could be com-pleted without make up from the control air system.
The plant remained critical at zero power with the upstream, manual main steam non return valves closed pending completion of satisfactory modifications.
On June 18, the licensee attached an additional air supply volume to the accumulctor system.
This was a non-safety grade standard 2 cubic foot, 2000 psi air flask separated from the accumulator by an orificed check
,
valve.
MSIV stroke testing conducted with the additional air volume also failed to close all four MSIVs.
The additional air supply volume was
!
removed.
Design change PDCR-86-837 was then developed to convert the air closure system to a nitrogen supply system which maintains accumulator pressure at 115 psi.
Through several iterations, the licensee arrived at a design which maintained the current QA boundary of the system, provided over-pressure protection from the 2000 psi bottled nitrogen supply and pro-vided adequate operating pressure margin to assure that all four MSIVs stroke closed within the 10 second TS criterion.
Upon restoration of the modified system to operation, the inspector re-viewed the design change package.
Two piping components installed inside the QA boundary had not been procured to the upgraded QA status of this system.
In addition, the design limitation that only 1 of 16 nitrogen bank bottles be in service to the MSIV closure accumulator to prevent exceeding the installed relief capacity had not been incorporated in the normal operating procedure for the nitrogen system.
The licensee had, however, included a verification of proper nitrogen bottle alignment in the operating logs.
The licensee upgraded the non-QA valve and fitting
.
_ _
_
_
_ _
__
_
_ _ - -
_
. __..
i
.
.
to QA status.
Nonconformance Report 86-334 dated June 21, 1986, docu-ments this upgrade.
Procedure 2.26-2, Normal Operation of Nitrogen Gas System, was modified to include the one flask in service at a time limi-tation.
The inspector subsequently determined that the installed ac-l
"
cumulator pressure gage is also not a safety-related component.
The use of calibrated, non-safety-related gages is an accepted practice at the site.
Since this gage is for operator information only, the licensee isolated the gage and tagged the isolation valve to allow opening only as required for operator readings.
A qualified low accumulator pressure alarm annunciates on the main control board to warn operators of system malfunctions.
During the installation of PDCR 86-837, several system setpoint changes were required to prevent lifting the system relief valve each time opera-tors raised pressure to reset the low pressure alarm.
Frequent lifting of the relief valve on June 21 resulted in damage to the valve seating surfaces.
After repair of the relief valve and final acceptance of the modified system, plant startup resumed on June 23, 1986.
At a meeting
'
with the responsible licensee supervisors and managers on June 25, 1986, t
the inspector noted the following concerns related to the design basis
.
of the MSIV closure system and the implementation of design change con-trol measures for PDCR 86-837.
Inadequate material issue / control resulted in installation of non-QA a.
material in the QA boundary.
b.
System turnover review of PDCR 86-837 installation documents failed to identify material discrepancies.
i The independent design review and Plant Operations Review Committee
c.
review of PDCR 86-837 failed to identify the omission of nitrogen i
bank operating procedure revisions.
d.
The inspector questioned the correlation of the as-designed and
!
tested MSIV closure system to the in service inspection criteria of 10 CFR 50.55a(g) and Section XI of the ASME code.
In addition, the inspector requested that the licensee evaluate whether failure
of the MSIVs to close under low steam flow conditions could lead l
to a total loss of feedwater event similar to the one identified in a July 29, 1985 report in accordance with 10 CFR Part 21 from the Florida Power and Light Company.
j The licensee's generic use of non-safety-related gages in safety-e.
related systems was identified as a potential operability concern for those unisolated gages in leak tight systems or systems without
!
a qualified makeup system.
The licensee committed to evaluate these concerns, develop corrective actions, as required, and document the results in the Licensee Event Re-port (LER) to be filed on this matter.
The licensee also committed to i
l f
e
.,--n--
, - -,-n,
- - - - - -..,
- - - -.
. - -,.
-. ~
_,,,, - - - -.
.,-,,e
-_n,_.--------nr_m...,,-,..,-,,
..-v
.
.
'
evaluate the use of non-safety-related gages in all safety-related sys-tems within 90 days.
Based on the inspector's verification of MSIV sys-tem operability and licensee implementation of immediate corrective ac-tions for the system integrity and procedural deficiencies noted above, the inspector determ.ined that this matter would remain unresolved pending comoletion of the licensee commitments and NRC review of the LER for this event. (UNR 213/86-15-01)
3.2 During routine plant walkthroughs, the inspector noted that several valve operator flood protection seals above the ion exchanger trench had de-teriorated.
Upon notification, the licensee implemented activities to repair the discrepant seals and to install covers over the seals to pro-tect them from the weather.
In addition, the inspector verified that preventive maintenance procedure 9.5-125, Flood Protection Equipment In-spection and Inventory, had recently been revised to provide more de-tailed inspection of the condition of flood protection barriers.
The
!
inspector had no further questions in this area.
3.3 On July 3, 1986, the licensee performed the monthly core cooling recir-culation surveillance test (SUR 5.1-4).
During the test, the high pres-sure safety injection (HPSI) system common recirculation valve (SI-HCV-1881) was fully opened to verify operation of the two HPSI pump discharge check valves.
When the operator opened the valve, the handwheel became unthreaded from the valve stem.
That rendered both HPSI trains inoper-able in that full HPSI flow to the reactor could not be obtained with the system in that configuration.
Within 45 minutes, maintenance per-sonnel rethreaded and closed the valve.
SI-HCV-1881 is opened to verify check valve operability.
More informa-tion is needed to determine Technical Specification compliance for core cooling during the test (i.e., actual HPSI flow with SI-HCV-1881 open).
The consequences of operating the valve during normal plant operations is currently under evaluation by both the licensee and NRC.
This is an unresolved item pending licensee evaluation and its review by NRC (UNR 213/86-16-02).
4.
Followup on Previous Inspection Findings During the course of the inspection, six NRC open items were reviewed.
The inspector found licensee actions with regard to these areas to be sufficient
to close these items.
Details follow:
4.1 (Closed) Violation (213/85-13-03 and 85-21-08) The licensee failed to properly implement the biennial review program for station procedures, and subsequent corrective actions failed to prevent recurrence of this problem.
The inspector verified that the licensee currently implements a new biennial procedure review tracking system.
The Office Supervisor (0S) who is responsible for the program maintains a computerized listing
'
of all applicable station procedures and the associated due dates.
Six months before any procedure is due for its review / update, the 05 issues
_ _,
_.
- - -
-.
.-
-
-.
.
.
. _ _ _ _
.
t i
l i
j a memorandum to the responsible department head as a reminder that the procedure (s) are due to be completed within six months.
If the proce-
dure (s) are still not updated two months before its due date, the OS is-sues a controlled routing which requires a written response to station management from the department head within 30 days.
At least one month remains for management action before the procedure review is overdue.
There are currently no procedures that are overdue for review / update.
j The new tracking program maintains appropriate controls over the biennial
,
procedure review / update program.
These items are closed.
.
4.2 (Closed) Followup Item (213/85-21-02) The inspector was to verify that
,
temporary modifications to the emergency generator cooler outlet valves were included in the annual report of modifications required by 10 CFR 50.59.
The inspector reviewed the licensee's annual report dated Febru-ary 28,1986.
The EDG cooler modifications were included under the special test conducted under 10 CFR 50.59 which verified the acceptabil-ity of disabling the cooler outlet valves for an extended period of time.
This test was performed satisfactorily in accordance with procedure SPL 10.7-233, Diesel Service Water Valve Test.
The inspector had no further questions in this area.
4.3 (Closed) Violation (213/85-21-13) The licensee failed to review and ap-prove three temporary procedure changes within 14 days of their imple-
'
mentation.
The licensee implemented several remedial actions to prevent recurrence of these problems including serializing and logging of TPCs prior to use and routine collection and forwarding of original TPCs to
,
the Plant Operations Review Committee clerk.
The inspector verified that these corrective actions had been incorporated in Revision 17 to admini-strative control procedure 1.2-6.4, Temporary Procedure Changes.
No further instances of late TPC reviews were identified.
This item is closed.
l 4.4 (Closed) Violation (213/85-21-15) The licensee failed to implement system
"
surveillance procedures within one month following modification of the power-operated relief valves (PORVs) as required by plant procedures.
The licensee implemented procedure 5.7-112, PORV System Operability Test and satisfactorily completed the test on April 16, 1986.
The licensee l
also verified that other procedure revisions required by modifications
!
in 1984 had been implemented.
Only one other procedural discrepancy was identified and corrected during this review.
A feedwater flow transmit-l ter calibration procedure (SUR 5.2-45) was not cancelled after the ap-
!
propriate revised testing requirements were incorporated in a different
procedure.
The licensee concluded that improved personnel awareness and
,
training in design change program controls would prevent recurrence of
'
these failures.
The inspector identified no further discrepancies.
This
item is closed.
i
,
>
,
_, _, _,
_. - _... _. _. _ _ _, _, _, _
,
,
_
.m..-_,___.-y,_.7,_,.
-,,_.y
., -, - - _ ~ -,
..,
-
__.
_
.
.
_
.
_ _ -._ _._ _.-
_ _ _ _. --_
!
-
f i
1 4.5 (Closed) Unresolved Item (213/86-03-01) NRC was to determine the accept-l ability of proposed licensee actions relative to a self-identified error in the small break loss-of-coolant accident (SBLOCA) analysis.
For cer-tain SBLOCAs in the #2 reactor coolant loop, long term core cooling could not be assured.
On April 28, 1986, NRC Licensing issued a Safety Evalu-
ation Report accepting the licensee's interim corrective actions for response to these SBLOCAs, and granted exemption from the single-failure criterion (GDC-35) for two motor-operated valves in the long term core cooling flow path.
Implementation of licensee commitments in this regard are documented in NRC Region I Inspection Report 50-213/86-06.
The in-
,
spector had no further questions in this area.
,
5.
Followup on Events Occurring During the Inspection 5.1 Licensee Event Reports (LERs)
The following LERs were reviewed for clarity, accuracy of the description of cause, and adequacy of corrective action.
The inspector determined whether further information was required and whether there were generic implications.
The inspector also verified that the reporting require-ments of 10 CFR 50.73 and Station Administrative and Operating Procedures had been met, that appropriate corrective action had been taken, and that
,
the continued operation of the facility was conducted within Technical
,
Specification Limits.
- 86-19 -- Defective Steam Generator Tube Not Plugged
- 86-20 -- Reactor Trip During Turbine Vibration Testing
!
f i
86-21 -- Nuclear Instrumentation Dropped Rod Setpoint Drift
- 86-22 -- Turbine Runback During Nuclear Instrumentation Adjustment
- 86-23 -- Spurious Turbine Runback Actuations
!
- - Events detailed in NRC Region I Inspection Report 50-213/86-06 5.2 During May and June of 1986, numerous abnormal fluctuations within the nuclear instrumentation system (NIS) power range drawers caused plant l
transients or were over-ridden by operators upon recognition of the
spurious nature of the actuations.
Power range drawer spikes often re-
!
sult in actuation of the negative rate (1 of 4 channel logic) dropped rod protection circuit.
This circuit causes a control rod motion block and initiates a main turbine load runback to 70% power if the plant is
,
!
operating above that power.
During this inspection period, spurious load runbacks occurred on June 2 and June 28.
The licensee attributed the NIS anomalies to aging equipment, and also to elevated main control board temperatures (90-100 degrees F) which existed due to degradation of the control room ventilation system.
The licensee is rebuilding NIS drawer power supplies in order to reduce spurious transients.
A vendor repre-
,
,
i
-
. -
.
_ _
.
.
.
- -
_ _ _ _ _
..
.
-
sentative has been onsite to assist the licensee in upgrading the per-formance of the NIS.
The inspector verified that the NIS transients have provided conservative safety system actuations and that the required level of reactor protection has been maintained.
The licensee has in-itiated a project to evaluate the replacement of the NIS drawers with state of the art instrumentation.
On June 2, the spurious actuation of the turbine runback circuit failed to runback the turbine to 70% power.
Operators manually reduced power, following the required actions.
The runback failure was caused by a misaligned clutch plate in the turbine governor valve load-limiter con-trols.
The load-limiter was repaired.
Full power operation resumed on June 2.
Inspector review of the operating records and corrective actions associated with this event revealed no unacceptable conditions.
On June 19, 1986, the reactor tripped from zero power while troubleshoot-ing a failure of NIS channel 34.
With the reactor critical and the main steam isolation valves (MSIVs) closed due to problems in the MSIV closure system, the control room ventilation system was taken out of service for maintenance.
Apparently because of the resultant elevated temperature in the control room, a power supply burned out in the channel 34 NIS drawer.
Licensee inspection and testing revealed that only the channel
,
i 34 drawer was affected.
The trip occurred when the technician trouble-shooting the NIS failure replaced the blown fuse in the failed drawer.
The shorted power supply overloaded the vital instrument bus and the resultant voltage transient cleared the closed MSIV reactor trip bypass which normally bypasses this trip below 10% reactor power.
That resulted in a trip because the MSIVs were shut.
The licensee expedited completion of the ventilation system repairs and rebuilt the failed NIS drawer.
Control room temperatures have been moderate since completion of the ven-tilation system repairs.
However, NIS system transients have continued and licensee evaluation and corrective actions are ongoing.
Ongoing performance of the NIS will be reviewed during routine NRC inspection.
5.3 On June 4, 1986, the plant was manually tripped from 100% power when feedwater flow control problems resulted in rapidly decreasing steam generator (SG) levels.
Plant systems responded normally following the trip.
The post-trip review revealed that the heater drain tank level control valve failed shut, preventing full feedwater flow from reaching the SGs.
The valve failure occurred because the valve operator-to-stem connector came apart.
The connector was reassembled and plant operation resumed on June 5.
On June 17, a similar plant trip occurred when the same level control valve failed shut.
The licensee disassembled the valve in order the identify the root cause of the repetitive separation of the stem-to-operator c+1nector block.
No definitive cause was iden-tified, however, the licensee modified the connector block to hold the block in position with set screws.
The inspector verified that, although previous feed control problems have been caused by failures of this valve, no previous failures of this connector block were documemted prior to
-
.-
-
.
-
-
.
-
..
.
..
-
--
.
.
--..
.
.
'
I j
these events.
The reactor was returned to criticality on June 17 but
'
further plant startup was delayed due to the main steam isolation valve j
problems discussed in paragraph 3.1 of this report.
!
5.4 On June 22, 1986, the plant tripped from 10% power during scheduled 3-l loop flow measurements.
One reactor coolant loop was idled for the flow measurement.
This condition inserted half a low flow trip signal which requires two loop low flow conditions to actuate the reactor protection system (RPS) between 10% ard 74% reactor power.
As plant power rose above 10%, the automatic bypass (P7) of the loss of flow protection was cleared and an unannunciated trip occurred.
Licensee investigation re-vealed that a small piece of ceiling tile had lodged between the contacts
.
of one of the RPS relays, creating a second, unannunciated half trip
signal which completed the loss of flow logic and tripped the plant upon i
clearing P7.
The piece of ceiling tile remained from the replacement
!
of the control room ceiling during the recent refueling outage and may i
have been blown into the relay during outage testing of a new Halon fire suppression system.
The licensee inspected all other main control board
j relays subject to foreign material entry or obstruction.
No other fouled
!
relays were identified.
No other pieces of tile were found in the main
control board area, but several other pieces of foreign material (wire wrap) were found in the area and removed.
Upon completion of trouble-shooting, inspection, and cleanup the licensee restarted the reactor.
l Secondary plant startup commenced on June 24, after completion of MSIV closure system repairs detailed in paragraph 3.1 of this report.
No
>
further abnormal conditions were identified.
,
5.5 On June 19, 1986, the licensee notified the inspector that an evaluation
'
of preliminary results of destructive testing of a steam generator (SG)
U-tube removed from SG #2 during the recent refueling outage revealed that a previously undefined eddy current test (ECT) result was actually a tube crack penetrating 82% through wall.
The licensee stated that
similar undefined indications existed in over 500 SG tubes with potential cracks between 20% and 100% of wall thickness.
These indications are all located near the tube end, at about the center of the tube roll. area.
,
j Since a significant portion of the tube roll would remain intact follow-ing a complete through-wall penetration of a crack, the licensee con-cluded that the tube structural integrity would be maintained, and that
!
progression of this problem would be indicated by increased primary to secondary system leakage.
Licensee review of previous ECT data indicates that the cracking phenomenom is not progressing.
The cause of the tube cracking is thought to be stress corrosion cracking initiated on the primary side of the tube.
The licensee notified NRC Licensing of their
'
preliminary findings on June 19.
Subsequently, a conference call was held between NRC and the licensee on June 20 to discuss the details.
)
,
Following that call, the licensee submitted a letter to NRC documenting the safety basis for continued operation pending completion of the
,
i evaluation of this problem.
On June 26, the NRC. issued a Safety Evalu-l ation Report (SER) concurring in the licensee's position that adequate structural integrity exists, and that further degradation will be moni-t
.
,
.. _, _ - _ __ _ - - - - _
. - - _ _, _
.
_ _ _
-. _, - - - _...
.--__,. _ _. _ -, _.
-._,,--.
-
--
.
-. -
...
-
.---
__ --
-
. --
.
'
tored and limited by existing Technical Specification limits on primary
'
to secondary leakage.
The SER sets a corrective action plan submittal due date of September 30, 1986.
The inspector had no further questions pending the results of the ongoing evaluation.
i 6.
Followup on TMI Action Plan Items 6.1 II.F.2.3.B - Reactor Vessel Level Indication On December 12, 1985, NRC approved the licensee's design for monitoring of inadequate core cooling (ICC).
This design included two independent trains of reactor vessel level instrumentation and upgraded reactor coolant subcooled margin monitors and core exit thermocouples.
These plant modifications were implemented during the January - April 1986
.
refueling outage.
The inspector verified the completion and testing of these design changes in accordance with plant design change request PDCR 86-755.
No discrepancies were identified.
The inspector noted that, while the inspection aspects of this action plan item are closed, final
M'C approval of the ICC system awaits licensee submittal of the imple-
'
';ntation report referred to in the licensee's February 1, 1985 commit-ment letter.
6.2 III.A.2.1 and III.A.2 - Emergency Response Facilities (ERF)
!
i By letter dated June 23, 1986, NRC Licensing concluded that satisfactory l
licensee performance in two successive annual emergency exercises demon-I strated the adequacy of upgraded emergency response _ facilities pending NRC Region I completion of the final ERF appraisal.
NRC addressal of outstanding appraisal findings will be included in outstanding reviews of accident instrumentation upgrades and the control room design review, or as new items.
NRC review of licensee performance during the annual emergency exercises is documented in NRC Region I Inspection Reports 50-213/85-06 and 86-12.
The inspector had no further questions in this area.
7.
Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted pursuant to Technical Specification 6.9 were reviewed.
This review verified that the reported in-formation was valid and included the NRC required data; that test results and
"
supporting information were consistent with design predictions and performance specifications; and that planned corrective actions were adequate for resolu-tion of the problem.
The inspector also ascertained whether any reported in-formation should be classified as an abnormal occurrence.
The following periodic report was reviewed:
--
Monthly Operating Report 86-05, for plant operations from May 1-31, 1986.
- --
-
_
--.
w
..
-,
.
.
i
8.
Unresolved Items Unresolved items are matters about which more information is required in order to determine whether they are acceptable items or violations.
Unresolved items identified during this inspection are discussed in Paragraphs 3.1 and 3.3.
9.
Exit Interview During this inspection, meetings were held with plant management to discuss the findings.
No proprietary information related to this inspection was identified.
s