IR 05000245/1986022
| ML20211F100 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 02/13/1987 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20211F056 | List: |
| References | |
| 50-245-86-22, 50-336-86-23, NUDOCS 8702240498 | |
| Download: ML20211F100 (18) | |
Text
io
____
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ - _ _ _ _ _
gI 6 0
.
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report:
50-245/86-22; 50-336/86-23 Docket Nos:
50-245/50-336 License Nos.
Northeast Nuclear Energy Company Facility:
Millstone Nuclear Power Station, Waterford, Connecticut Inspection at: Millstone Units 1 & 2 Dates:
November 4, 1986 through January 5, 1987 Inspectors:
Theodore A. Rebelowski, Senior Resident Inspector
-
Geoffrey E. Grant, Resident Inspector
}
Approved:
b M
2.hde 7 E. C. McCabe, Chief, Reactor Projects Section 3B Date Summary:
Report 50-245/86-22; 50-336/86-23 (November 4, 1986 - January 5, 1987)
Areas Inspected:
This inspection (241 hours0.00279 days <br />0.0669 hours <br />3.984788e-4 weeks <br />9.17005e-5 months <br />) included plant operations, outage activities, surveillance testing, periodic reports, and maintenance. A November 30 Unit 1 trip and December 23 and January 2 Unit 2 trips were inspected.
Outage inspections on Unit 1 included transformer replacement and testing, main feedwater valve repairs, drywell wall thickness measurements, and an Engineered Safety Features actuaction.
Unit 2 outage inspections included witnessing of service water pump replacement, hydrostatic test of the "B" service water system, fire damper modifications, steam generator tube sleeving, ALARA implementation, ECCS surveillance verification, reactor coolant pump motor runs, testing of the redundant remote shutdown panel, and two Engineered Safety Features actuations.
During this report period, a Unit 1 Emergency Preparedness Drill was conducted.
This inspec-tion period also included a site visit by NRC Commissioner Carr.
Results:
Unit 1 - No unacceptable conditions were identified.
Unit 2 outage activities exhibited good engineering practices, with thorough reviews of plant changes.
Two concerns were identified: electrical work activities contributed to two loss of normal power events while the plant was shut down and to a reactor trip during operation; and one trip was attributed to the use of outdated electrical drawings.
Licensee management initiated additional review of work completion checks and an engineering review of diagram revisions.
6702240490 870213 PDR ADOCK 05000245 G
,
.
..
_-_____________--_____n
.
6 c'
.
TABLE OF CONTENTS PAGE 1.
S umma ry o f Faci l i ty Acti vi ti e s.......................................
2.
Previously Identified Outstanding Items..............................
3.
Unit 2 Refueling 0utage..............................................
a.
Service Water System.............................................
b.
Allegation RI-86-A-134, Fire Damper Modification.................
c.
Partial Loss of Normal Power Test................................
d.
Turbine Inspection...............................................
e.
Main Condenser Replacement.......................................
f.
ECCS Surveillance Verification...................................
g.
ALARA............................................................
h.
Reactor Coolant Pump Motor Test..................................
i.
Fire Panel - Functional Test.....................................
j.
Steam Generator Eddy Current Testing and S1eeving................
4.
Commissioner Visit to Site...........................................
5.
Emergency Preparedness Drill - (Units 1 & 2).........................
-
l 6.
Review of Periodic and Special Reports...............................
'
7.
Trips and Engineered Safeguards Features Actuations..................
8.
Unit 1 0utage........................................................
9.
Drywell Wall Corrosion (Unit 1)......................................
10.
Allegation RI-86-A-122, Improper Pipe Restraints (Unit 1)............
11.
Model 12CFD Differential Current Relays..............................
12.
Management Meetings..................................................
l l
,
i
.
-D.'
'
DETAILS 1.
Summary of Facility Activities Unit 1 Early in the report period, Millstone 1 was operating at 100% power with some minor power reductions for condenser cleaning and Main Steam Stop Valve test-ing.
On November 30, the unit tripped due to a ground fault on the Main Transformer and a resulting generator and turbine trip.
On December 6, a radiation monitor module failure resulted in an Engineered Safety Features actuation [ Detail 7a(2)].
Outage maintenance included turbine end cover buildup (by welding and honing) to restore minimum clearance at the labyrinth seals, and main feedwater regulating valve repairs.
The transformer was re-placed, and the unit achieved criticality on December 13.
The unit was at 100% power at the end of the report period.
Unit 2 The plant was in Mode 6 (refueling) at 80 degrees F at the beginning of the report period.
Maintenance activities and design changes were ongoing.
On November 5, a loss of power occurred when an error by a technician created a ground fault.
The "A" diesel supplied unit power for approximately two hours prior to the reenergizing of the buses.
On November 14, a corporate electrical engineering department review declared the Diesel Generator output
breakers' differential current relays inoperable due to lack of seismic quali-fication.
The relays were removed and the diesels were available for emer-gency power [ Report Detail 11].
Misalignment'of stabs on a 4160V/120V trans-former produced a momentary undervoltage signal on November 29, causing a Loss of Normal Power (LNP) to bustes 24A and 24C [ Report Detail 7.b(2)].
The same transformer alignment problem caused a trip on December 23 from 50% power
[ Report Detail 7.b(3)].
Reactor startup began on 12/13.
A trip occurred on January 2,1987 (from 100% power) due to feedwater regulating valve solenoid failure [ Report Detail 7.b(4)].
By January 5, the unit was at 100% power.
2.
Previously Identified Licensee Items (Closed) Unresolved Item (50-245/86-03-01) Management Control of Hand Torqueing of Motor-Operated Valves Important to Safety.
NRC Inspection Report 245/86-03 noted that Valve 1-1C-3 did not function on January 6, 1986.
Review indicated that the valve did pass surveillance on February 5 and was manually torqued on February 6, but the licensee failed to stroke the valve after torquing.
The valve then failed to open during routine surveillance on March 26, 1986.
The licensee's corrective action included revision of Operating Procedure 3.7, Isolation Condenser System, to prohibit the manual torquing of motor-operated
valves.
i (
l I
.
)
'
D
.
Discussions with licensed operators found that they were aware of the event and the procedural change.
The disc of valve 1-lC-3 was replaced.
Retest was satisfactory.
This item is closed.
3.
Unit 2 Refueling Outage The licensee completed the refueling outage during this report period.
Major projects completed included replacement of piping components in the service water system, replacement of main condenser internals, and NDE and sleeving of Main Steam Generator Tubes.
The inspector observed a number of outage actions.
Findings follow:
a.
Service Water System The licensee's service water system required pipe replacement, NDE of several pitted areas, removal of service water valves for overhaul, overhaul of service water pumps, and a code hydrostatic test prior to restoration for operation.
These tasks required engineering review and special procedures to ensure proper cooling was available for spent fuel shutdown cooling.
Inspector review identified the following:
(1) Service Water to Reactor Building Closed Coolant Water (RBCCW)
Special Procedure 86-22, Heat Exchangers The licensee had determined that, during the refueling outage, ser-vice water to RBCCU might be interrupted.
The operators and plant staff were provided guidance on how to re-cover the operable in-service RBCCW train if it became fouled or required removal from service.
The guidance addressed electrical lineups, the reserve station transformer, containment integrity, enclosure building filtration, control room ventilation, and reactor coolant temperature including action levels for the shutdown cooling loop.
The procedure addressed fuel pool levels, RBCCW in-service system controls, early recognition of fouling of heat exchangers, temperature limits for the reactor coolant system, and operator briefings.
A licensee safety evaluation reviewed power availability, alternate cooling flow if the on-line RBCCW was lost, and spent fuel pool temperature.
The licensee found that no technical specification safety margins were reduced, and that the procedures created no unreviewed safety questions.
Inspector observations during service water repairs identified no loss of RBCCW flow and no fouling of Heat Exchanger,-
- -- - - - - -
_ --- _ ----- --- - - - - - - - - - - - - - - - - - - - - _ _ _
_ - - - - - - - - - - - - - - - - - ---_------ ---------_----_ - --_ _ ---_---------
.
- c
.
During replacement of the Turbine Building Closed Cooling Water (TBCCW) Heat Exchangers, items inspected were:
the type and fit of bolting material; valve installation and cathodic protection; torquing sequence adherence; and post work operation of the heat exchangers.
No deficiencies were identified.
The inspector had no further questions.
(2) Service Water Pump Repair The "A", "B", and "C" service water pumps were overhauled during the outage.
The inspector observed the removal and final placement of the "C" pump on the intake structure baseplate.
Bolting examined on a new spool piece installed in the service water system was found satisfactory.
The service water strainer floor mounts exhibited minor corrosion pockets.
Licensee review found acceptable thickness.
This item was verfied by the inspector.
The inspector noted an extensive housecleaning effort by the lic-ensee.
All piping and ducts were cleaned and painted where applic-able.
The inspector identified one area in the intake structure where the cabinets holding the pressure / flow service water instru-ments needed further cleaning.
That was accomplished by the licen-see.
During witnessing of this outage work, housekeeping, and procedural adherence, the inspector identified an excellent planning effort, and knowledgeable supervisors and tradesmen.
(3) Service Water System Hydrostatic Test On completion of service water system repairs, the "A" and "B" ser-vice water headers were hydrostatically tested.
The inspector wit-nessed the "B" train hydrostatic test and walked down the system between test boundaries.
Those boundaries included the "B" Diesel heat exchanger, the Reactor Building Closed Cooling Water (RBCCW)
Vital AC Switchgear Room Cooling coils, and inlet and discharge service water piping.
The inspection included:
Verification of pressure gauge calibration (QA).
--
Verification of system tie-in to the hydrostatic test pump.
--
(Flow path established.)
Verification of test boundaries.
--
!
Maintenance of test pressure (91 psig).
--
Verification of removal of air from the system.
--
Minor leakage at mechanical joints was identified and one valve on the diesel generator cooler vent exhibited leakage.
The vital AC
,
Switch Gear Room Cooling coils required repairs.
The inspector
,
witnessed licensee engineering and Quality Control inspector moni-
!
toring and documenting test pressure maintenance and identifying l
t-
.
'
o
.
\\
leakage areas.
Nonconformances on the strainer base plate and bolting were reviewed by the inspector.
No\\ deficiencies in test conduct or corrective actions were identified.
(4) Pipe Replacement Program The. licensee identified, during licensee ren-destructive examination (NDE) of the service water system, a numbet of areas with greater than 49% pipe wall loss.
Consequently, a number of elbows and fit-tings on the 24" RBCCW service water piping and an elbow on the 24" service water pump discharge were replaced.
Two areas in the ser-vice water system were identified with s6 vere wall thinning.
(a) A vertical run of 16" piping of nominal 0.375" wall thickness-was found to be 0.160" thick, a 57.4% loss.
Repair included a buildup of internal surfaces with epoxy bonding material (Benzola).
(b) A horizontal run of 3" piping downstream of valve 25W 181A was examined.
The area in question, downstream of valve 2-SW-181A, was a 10" length of copper-nickel pipe with a nominal 0.216 wall thickness.
This pipe is a discharge line from the 480v switchgear room cooler.
NDE readings measured about 0.080".
One area exhibited a reduction to between 0.030" to 0.010".
The licensee did not have the material to perform repairs.
Licensee engineering evaluation stated that, based on no leak-age during the hydrostatic test and due to the ability to isolate this section without losing service water, the system was operable.
The inspector witnessed the hydrostatic test.
No leakage was iden-tified.
The licensee committed to replace the thinned pipe upon receipt of new material and to confirm that a pipe hanger in this area will not effect seismicity of the service water system.
The piping was replaced on February 1, 1987, after the inspection period.
Seismic acceptability will be reviewed incident to routine inspec-tion.
b.
Allegation RI-86-A-134, Fire Damper Modification (Unit 2)
On October 28, 1986 the NRC resident inspector received, by telephone, two concerns about ventilation damper modifications.
These were:
(1) The method of repairing drill holes in both safety-related and non-safety related duct work.
(2) Why some ventilation dampers were reduced in size (approximately 1" on a 30" X 30" damper.)
.
a
.
Inspector review found that the licensee is modifying or replacing a number of Unit 2 fire dampers.
The change-over, documented in Plant Design change request No. 2-61-86, addresses Appendix R fire protection concerns.
The change upgraded 1.5-hour fire-rating dampers to 3-hour ones and installed additional dampers.
A safety evaluation was performed by the licensee's Mechanical En-gineering section.
The changes have been reviewed by the licensee with respect to 10 CFR50.59 and found not to be an unreviewed safety question in that:
flow testing of all the new and existing Unit 2 fire dampers in safety related systems confirmed their abil-ity to close under flow conditions; Turbine Building Ventilation System Fire Dampers are non-safety-related; and fire dampers in the Main Ventilation Exhaust system are non-safety-related.
No defi-ciencies were found in the licensee's evaluation.
The inspector observed several areas of fire damper change imple-mentation and found no degradation of the duct work. To assess whether testing did address full flow conditions, one test was wit-nessed and found satisfactory.
Dampers 2HV15, 16, 17 and 18 were examined by the inspector.
These are new dampers installed in ductwork passing through the lube oil Inspection of the interior of the ducting revealed previously room.
drilled holes which have been filled with epoxy.
The drilled duct areas were properly and successfully tested for leakage.
Inspector review found that no safety features were involved.
The inspector had no further questions on this aspect.
The inspector also viewed areas where protective (pyrocreate) coat-ing was applied from the floor / wall to the outside edges of dampers.
Reduced size dampers were installed to allow the dampers to expand and still assure proper closure.
A licensee safety evaluation was performed on the dampers listed as Category 1.
It found that the reduction in size affected line pressure without reducing total air flow, and that this was an acceptable condition.
The inspector witnessed, in part, test procedure T86-23 "Preopera-tional Test Procedure for Fire Dampers," to verify damper operations.
No unacceptable conditions were identified.
The inspector also concluded that repairs to non-Category 1 damper ducts were accept-able since the reduction in damper size did not affect total air flow.
The inspector had no further questions on this matter.
c.
Partial loss of Normal Power Test (Unit 2)
(1) Background On October 25, 1986 a partial Loss of Normal Power (LNP) test was conducted on Unit 2 Facility (train) I components.
Portions of Surveillance Procedure SP 2613C, " Engineered Safety Feature Systems
.
J
.
.
(ESF) Integrated Test" were used to perform the evolution. The test was conducted to satisfy interim operability requirements following mainteaance on the "A" Emergency Diesel Generator (EDG) and the Engineered Safety Feature Actuation System (ESFAS).
The test in-jects an LNP signal to ESFAS causing load shedding, EDG start, and load sequencing.
Parameters monitored include EDG start time, sequencer operation and timing, load shedding, load reject response, and load carrying capacity.
(2) Test The test was commenced by de energizing the Facility I vital 4160 V bus, causing a LNP start signal to be sent to the EDG from ESFAS.
Load shedding on the vital bus occurred and, after the EDG started and closed onto the bus, load sequencing commenced and progressed through the four sequence steps.
An EDG restart test then tripped the EDG, verified load shed, restarted the EDG, and verified correct resequencing. A partial loss of load test then verified that EDG output remained at 4160 +/-500V and 60 +/- 3 Hz after a 250 KW load was rejected.
The test had to be prematurely halted at this point due to EDG component heating caused by marine fouling of the Service Water system.
After cleanup of the fouling, the testing was resumed on the following day with the conduct of a loss of load test which verifies that the EDG does not overspeed after it sustains a loss of at least 1300 KW.
The final portion of the test was a one-hour full power run at 2750 KW.
(3) Results Post-test results review during this report period confirmed that all parameters measured during this test were within limits and, with the exception of the interruption caused by Service Water fouling, the test was fully successful.
Resident inspector review of the procedure, test results, and computer data printouts identi-fied only minor procedure errors.
These did not affect test per-formance or acceptability.
The inspector had no further questions, d.
Turbine Inspection (Unit 2)
During a May 1986 shutdown, the licensee examined turbine bucket dovetail fingers with the buckets assembled.
This ultrasonic test was to deter-mine if cracks exist in the dovetail bucket fingers.
A magnetic particle test of the alternator shaft on the alternator side of the generator end bearing also was performed.
These tests were part of the comprehensive turbine test program, and found no adverse conditions.
In addition, to determine torsional natural frequency of the unit and rotor torsional response due to electrical torque, a second set of tests was to be conducted to measure the last stage bucket response to the generator torsional stimulus caused by a phase unbalance torque.
The
.
p
,
licensee prepared a special test that required the installation of special monitoring equipment.
This test consisted of generating out-of-phase output during a turbine startup.
That could have an adverse effect on the unit's main transformer. A spare transformer was on site until loss of the Unit 1 transformer.on November 30.
Upon use of that trans-former for Unit 1, licensee management concluded that, based on the pre-vious physical inspections that found no abnormalities and the unavail-ability of a spare transformer, further testing at this time was inap-propriate.
The inspector discussed this item with site management.
The licensee has committed to perform the test during the November 1987 outage, based on availability of a replacement transformer.
This item will be further reviewed under the routine inspection program.
e.
Main Condenser Replacement A history of steam generator tube degradation has been attributed in part to the introduction of copper-bearing alloy products into the main feed system.
The largest contributor of copper was determined to be the main condenser which had 70-30 copper-nickel tubes.
The planned changes were to install titanium ASME SB-338 Gr2 tubes and tubesheets of ASME SB-265 Gr2.
This condenser internals replacement was the outage critical path item.
The inspector observed the removal of condenser tubes and the cutting, compression, and storage of the removed tubes.
Health Physics techni-cians monitored the removal of the heat exchanger and condenser tubes for contamination.
None was found.
In one condenser bay, the sludge after drainage had minimal activity.
This area was decontaminated.
On removal of tubes and inlet and exit water boxes, the replacement tube
,
segments were placed in the condenser bay and tied together at the tube sheets by welding.
On completion of fabrication, the condensers were flushed and hydro-staticallly tested.
Three tubes of a total of about 44,000 exhibited leakage and were repaired.
The inspector found that the replacement of the condenser was planned to assure orderly removal and replacement with a minimum effect on other activities. Materials were available on site.
The labor force was
.
knowledgeable about the project.
Proper engineering and supervision was noted.
The inspector's review of post-installation secondary chemistry noted a marked reduction in steam generator solids.
No deficiencies were identifie ".
-g-
'
.A
f.
ECCS Surveillance Verification The inspector reviewed the most recent ECCS pump operability and valve position verification check sheets.
In addition, the correct position of a number of accessible valves specified in tbc TS was physically con-firmed.
No valves were found incorrectly positioned or.not properly locked in the specified position. No missed surveillances or other de-ficiencies were identified, g.
Refueling Outage - ALARA Review The licensee's ALARA group was fully involved in setting, implementing,-
and maintaining ALARA goals during the Refueling Outage.
In all areas of potential high exposures, corporate and onsite ALARA coordinators reviewed procedural limits, geometry of work areas, compliance with pro-cedures, and improvements that could reduce dose rates and total expo-i sures.
The inspector observed that ALARA personnel in radiation work areas were monitoring personnel actions for compliance with procedures.
Open dis -
cussions of problem areas at the daily outage meetings aided in Man-Rem control.
The ALARA corporate goals were set at 600 Man-Rem vs. on-site estimates of 728 Man-Rems.
A total of 873 Man-Rems was expended.
The ALARA goals were exceeded due to additional exposures being received because of RCS-nozzle dam problems and higher than expected radiation levels in the steam generator primary sides after flushing.
(Steam generator decontamination had reduced activity to 5-8R/hr whereas a prior refueling decontamination achieved 2R/hr.) Further NRC review will be performed upon publication of the Annual Report'and the Refueling and Maintenance Outage Report.
The inspector attended a meeting on the methods and materials to be used during sleeving and plugging of steam generator tubes.
Discussion areas included lessons learned from the previous outage and resolution of out-standing issues, the new automated sleeving equipment including problems encountered at a similar facility, the need for work stations to be in areas that reduce the effect of shine from manholes, and personnel i-i training using mockups.
The meeting was evaluated as beneficial to
achieving ALARA goals.
All personnel reflected an aggressive attitude
!
towards the reduction of personnel exposures.
I h.
Reactor Coolant Pump Motor Test (RCP)
i l
The licensee experienced reactor coolant pump motor winding wedge dis-l placement in late 1985.
During this outage, special procedure 85-2-20, j
Rev. O addressed post-overhaul test runs of RCP motors.
Monitoring of
stator winding temperatures upon RCP motor start and at half-hour inter-l vals was performed.
!
,
"
,
t
'
.T-
The inspector observed the initial No. 3 RCP motor test, uncoupled.
Motor starting currents, speed, phase rotation, and vibration levels were acceptable.
Stabilization of bearing oil temperatures was reached within 30 minutes.
The lube oil strainer entrained some magnetic material.
Frequent changes to lube oil strainers were.made until a clear strainer was obtained.
The inspector found no unacceptable conditions.
i.
Fire Panel (C10) Functional Test During the refueling outage, a remote and redundant Shutdown (Fire) Panel was-installed.
The inspector monitored the construction red-line testing of circuits and Instrument and Control group setting of Steam Generator levels.
Functional tests included testing from the control room (CR)
and remote panel.
The inspector observed test control from'the CR and the effect at the remote panel.
For the activities observed, no defi-ciencies were identified, The inspector had no further questions.
j.
Steam Generator Eddy Current Testing and Sleeving The licensee's Inservice Examination program for Eddy Current testing was observed by a Region I Specialist Inspector (Inspection Report 50-336/86-24).
Preliminary review indicated that as many as 500 tubes per generator would be sleeved.
On reanalysis, the licensee determined that a lesser amount fell within the sleeving criteria.
The final number of tubes repaired included:
Steam Generator No. 1 - 9 tubes plugged and 160 tubes sleeved.
--
Steam Generator No. 2 - 19 tubes plugged and 65 tubes sleeved.
--
During sleeving operations, the inspectors monitored honing operations and sleeve positioning.
High radiation protection for individuals on working platforms was also observed.
No deficiencies were identified.
Post-outage chemistry sampling at 100% power indicated no significant primary to secondary leakage (0.06 gpm unidentified and 0.3 gpm identi-fied leakage).
The inspector had no further questions in this area.
4.
Commissioner Visit to Site During this inspection period, NRC Commissioner Kenneth M. Carr visited the Millstone Nuclear Station.
Unit 1 and 2 inspection included the following.
a.
Unit 2 - November 25 On November 25, the Commissioner was accompanied by licensee managers and the senior resident inspector during an inspection of control room boards and a walkdown of the service water system including the intake structure.
In addition, an inspection of main condenser retubing acti-vities was conducted.
A walkdown of the containment included the moni-
E..
t
~~
,o
toring of CRTs provided for viewing the Steam Generator tube repair and sleeving.
A visit was made to the steam generator mockup facility used for training.
b.
Unit 1 - November 28 The Commissioner monitored the shift turnover at Unit 1 at 6:30 - 7:30 a.m.
He attended the Unit 2 morning refueling meeting.
After the meet-ing, he toured the Emergency Gas Turbine facility.
c.
Management Exit In a licensee management exit meeting with the Commissioner, a number of topics were discussed including control room manning, 10 CFR 50 Ap-pendix R concerns, improving piping identification in plant systems, and degreed individuals on watch or on station.
5.
Emergency Preparedness Drill On November 19, an Emergency Preparedness Drill was conducted at Unit 1.
The resident inspectors were observers for the NRC Emergency Preparedness team.
Observation of licensee actions were made in the Control Room, Technical Sup-port Center, Emergency Operation Facility and operations center.
The inspec-tion results are documented in NRC combined report 86-245/86-23, 86-336/86-29, and 86-423/86-36.
6.
Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted pursuant to Technical Specifications were reviewed.
This review verified that the reported infor-mation 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 information should be classified as an abnormal occurrence.
The following reports were reviewed:
Monthly Operating Reports for plant operations from October 1 - October
--
30 and November 1 - November 31, 1986, (Unit 2).
Monthly Operating Report for plant operations from October 1 - October
--
30 and November 1 - November 31, 1986 (Unit 1).
No unacceptable conditions were identifie.
i
~
,9
7.
Trips and Engineered Safety Features Actuations a.
Unit 1 (1) Trip from 100% Power - Main Transformer Failure On November 30, Millstone 1 was at 100% power when a plant trip occurred at 9:21 p.m.
A main transformer fault, causing a generator ground, resulted in a turbine trip and reactor scran.
Plant and operator responses were proper.
Preliminary review indicated the failure was caused by transformer winding failure.
The transformer was replaced with an onsite spare.
The failed unit was sent offsite for repair (see paragraph 8.a.).
The inspector observed removal of the failed transformer and placement of the spare transformer.
Preoperational testing results were reviewed.
No deficiencies were identified.
(2) Actuation of Engineered Safety Feature (ESF)
On December 6 at 5:10 pm (Unit at 0 psig 115 degrees F), Reactor Building Hi-Rad Ventilation Monitor 33-1 tripped on a high upscale reading, actuating steam tunnel and reactor building isolation and automatic initiation of the Standby Gas Treatment System.
The area detector was checked by a portable detector and was found to be in agreement, with a low reading (1.2 mr/hr).
Invest!gation by the licensee concluded that an output voltage spike due to a failed sensor / converter module (repaired by modular replacement without identification of failure cause) had caused the inadvertent trip.
The inspector verified that no radioactivity was released to the environment by viewing off gas chart recorder data for the time frame of the incident.
No unacceptable conditions were identified.
b.
Unit 2 (1) Unit 2 - Loss of Normal Power - Actuation of Engineered Safety Feature At 2:23 pm on November 5, 1986, Unit 2 experienced a loss of normal AC power (LNP) which, due to outage conditions, resulted in only one 4160 V bus being energized by its associated Emergency Diesel Generator (EDG).
At the time, unit power was being supplied by
"backfeeding" the Main Transformer and supplying the Normal Station Service Transformer (NSST). The "B" EDG and the Reserve Station Service Transformer (RSST) were out of service for maintenance.
The unit was in Mode 6 (refueling) with the refueling cavity full, reactor vessel head removed, and refueling accomplished.
The LNP was caused by a technician inadvertently actuating a main generator fault relay, causing switchyard feeder breakers to open and de-energize the NSST.
The Engineered Safety Features Actuation System
!
,
d
.
.?
(ESFAS) sensed the subsequent undervoltage condition and actuated load shed and "A" EDG start.
Safety systems functioned properly.
All unit loads were returned to the NSST by 4:11 p.m.
The inspector observed the licensee's response and concluded that all steps to mitigate the power loss were perform,:d satisfactorily.
All Engineered Safety Feature Actuation Systems responded properly when the undervoltage condition was sensed.
The licensee stressed technician adherence to procedural " caution notes" to plant personnel.
The inspector had no further questions.
(2) Partial Loss of Normal Power - November 29 At 4:14 pm on November 29, with the plant shut down, an undervoltage condition caused loss of power to vital Bus 24C.
The Emergency Diesel Generator started.
Safety equipment sequenced on with the exception of service water pump "A".
The pump was manually started.
Licensee review did not identify the cause; the failure to start could not be duplicated.
The event cause was attributed to personnel hitting the bus with staging.
Later review of a December 23 trip, which is described in subparagraph 7b(3), identified the cause as an improperly in-stalled transformer.
The inspector identified no deficiencies in operator actions during the November 29 event.
(3) Unit 2 Trip from 50% Power-December 23 On December 23 Millstone Unit 2 was in power ascension testing when it tripped from 50% power at 8:56 a.m.
The Engineered Safety Features systems actuated satisfactorily except for "A" train large loads (including the service water pump).
The plant was stabilized and held at hot standby.
The trip occurred during technician tightening of two bolts on the back cover of a transformer.
The transformer (4160/120V vital AC to the 24C bus) stabs were misaligned, introducing a false under-voltage signal.
The buses were stripped and the main feed pumps were reduced to minimum speed, allowing the steam generators to reach the low level trip point.
That caused a reactor trip.
The "A" train loading problem was found to be caused by an under-voltage signal that remained on the bus due to the transformer re-maining in an abnormal position, thus not allowing large loads to sequence on that bus.
The licensee repaired the transformer by re-alignment of support frames and reforming the stabs to assure posi-tive contact.
A verification of other similar electrical devices was performed by the licensee with no inadequacies identified.
Licensee post-trip review identified no other inadequacies.
The
.
..
---.
. -
.
-
.
.
. - _.
d
.
,v.
inspector viewed a similar device and its internal support frame adjustment and drawer closures.
No deficiencies were observed.
The inspector had no further questions.
(4) Unit 2 trip - 100% power On January 2, with Millstone Unit 2 at 100% power awaiting xenon stabilization, the plant tripped at 8:37 a.m. due to low Steam Generator level. All systems responded satisfactorily.
A feedwater regulating valve cover lifted, necessitating renewal of the flexi-talic cover gasket.
,
Licensee event review indicated that, during performance of wiring
,
changes associated with installation of new fire curtains in the Diesel Generator Room, a technician shorted,out an electrical panel, tripping the plant.
The technician had placed his test leads on an improper terminal due to an inaccurate (outdated) wiring diagram.
Due to the trip, the power to the feed-regulator solenoids were re-moved.
The feed-regulator valve for Steam Generator 2 indicated lockup.
Licensee review of post-trip logs indicated that this had occurred before.
Licensee investigation of this aspect is still in progress.
'
The resident inspector observed control room activities and main-tenance involving testing before startup.
The licensee identified solenoid valve air leakage problems.
The accompanying loss of air
,
allowed closing of the feed-regulator air positioner.
This per-
'
mitted only limited feed flow to No. 2 Steam Generator, which re-sulted in a steam generator low level.
The licensee replaced the solenoids and the feed-regulator valve cover gasket.
Licensee investigation into diagram revisions is underway.
This item will be reviewed during LER review in a subse-quent inspection.
!
8.
Unit 1 Outage
'
On November 30, at 9:48 p.m., the reactor scrammed from 100% power.
The cause was determined to be a winding insulation failure which required replacement of the 700 MVA General Electric transformer.
!
a.
Transformer Replacement
A spare 850 MVA Westinghouse transformer was on site.
The voltage and current taps were adjusted to match the 700 MVA transformer outputs.
j Major work elements included fabrication of a new deluge spray system, new control wires and power cables, and testing as follows:
i
.
- ~,
av,-
,m-4
- - -, - -, - - - -, -, - - -,,,,-
,,n,-wm r-mw-r.r--,-
w_--m,__w---g-.-,-w--g,
,,-m-
--
,. - - -
. _. _ _ _ _ _ _ - _ _ _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _ _ _ _ _ _ _ _. _ _ _ - _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _
_ _ _ _ _ _ _ _ _
.
t
.
,v
Functional Testing and Installation Verification.
--
Main Transformer High Side Current Test.
--
Main Generator Isophase Bus Power Factor Test.
--
Main Transformer Power Factor Test, and Main Transformer Potential
--
Verification.
No deficiencies were identified in the testing.
The inspector witnessed the spare transformer installation.
The licensee plans to send the faulted transformer to G.E for refurbishment, with reinsta11ation ex-pected during the 1987 outage.
The inspector had no further questions on this item.
b.
Other Outage Work (1) Turbine End Plates There has been air leakage past turbine end plates for gland seal labyrinth packing.
The covers were removed.
Steam etched paths were found in the carbon steel end plates.
The inspector observed welding and honing repairs made to the covers to restore minimum clearance.
The air leakage was reduced, but the labyrinth packing will eventually require replacement or repair.
The licensee's June 1987 outage plans include additional inspections of this area.
The inspector had no further questions.
(2) Main Feed Valves The inspector observed the "A" main feed valve cage and body scoring and repair.
In addition, the licensee repaired minor valve yoke cracks.
The licensee's prior planning had identified repairs to be made if a shutdown occurred.
This information was reviewed against the planned outage length and numerous minor repairs (pack-ir.g changes, valve tests, etc.) were performed.
No deficiencies were identified in work practices.
In addition, the inspector noted that Quality Control personnel were monitoring maintenance activi-ties and testing.
(3) Surveillance Testing (Unit 1)
l During the report period, the inspector witnessed the following
'
surveillance on Unit 1.
Standby Gas Turbine Functional Test.
--
APRM Calibration.
--
Turbine Stop Valve Closure Functional Test.
--
,
.
The test technicians observed had current procedures, and proper instruction on plant conditions prior to testing.
During the testing, prerequisites were established, precauto'7s were acknowl-
'
edged, and acceptance criteria were clear to the Lechnicians.
All
_
-__
_
.
__
_
. _.. _ _ _ _ _ _ -.. _.
__
__ _ _ -,, _ _ _ _ _,
,
,1
surveillance test criteria were met.
Personnel u re knowledgeable and performed the tests in a manner that reflected proper training and understanding.
No deficiencies were identified.
9.
Drywell Wall Corrosion - (Unit 1)
The licensee was informed of an apparent loss of drywell wall steel plating thickness at Oyster Creek.
On November 30, Unit 1 tripped due to a main transformer failure.
During this outage, licensee NDE inspections were per-formad to measure drywell wall thickness and assess potential leakage paths.
Results were:
--
the drywell to reactor building bellows seal is intact and has not ex-perienced leakage.
The Leak detection flow switch h.id not alarmed.
Inspection of the sand-filled transition area (1 inch drain) to the torus
--
vent lines under the drywell found no water leakage.
--
Ultrasonic thickness readings were taken on the drywell spherical shell where the drywell lower level meets the steel shell.
The construction drawings depict a portion of the sand filled transition area at an elevation above the concrete floor elevation.
Thickness measurements taken there showed no wall thinning.
No corrosion was evident.
Inspector review of the test results and the areas examined identified no deficiencies.
The inspection was completed prior to return to power on December 15.
Sub-sequently, NRC Information Notice 86-99 was reviewed by the licensee and no further action was deemed necessary.
The inspector had no further questions on this item.
10.
Allegation RI-86-A-122, Improper Pipe Restraints - (Unit 1)
The Regional Office received telephone information on October 9 and 16 ex-pressing concern about adequacy of pipe restraints for check valves in the feedwater and main steam lines.
A regional review was undertaken and addi-tional information was requested from the licensee on November 7, 1986.
The licensee responded on December 15.
The licensee described the replacement of original feedwater check valves by Anchor Darling type valves in the steam tunnel and drywell.
(There are no check valves in the main steam lines.)
The new valves were larger than the original Crane check valves.
Reposition-ing of and modifications to piping support systems were required. The changes affected:
Relocation of attachment points of hangers.
--
Resolution of interferences, movement of axial rods, and rotation of the
--
pad eye welds to the flued head.
[
>
+
.
i 'T
The licensee has a complete history of the modification.
Documentation is available for further examination onsite.
Also, the licensee is presently reviewing the need for these restraints under " leak before break" criteria which result in a lower design stress requirement.
The concern underlying this allegation was found to have been previously ad-dressed by the licensee.
No unacceptable conditions were identified.
Re-gional office review of the licensee's response identified no safety concern.
The inspector had no further questions on this matter.
11. Model 12CFD Differential Current Relays (Units 1 & 2)
On November 14 at 3:00 pm, plant personnel were informed that a corporate engineering evaluation undertaken in response to IE Information Notice Number 85-82, " Diesel Generator Differential Protection Relay Not Seismically Quali-fied" determined that the General Electric Model 12CFD Differential Current Relays at various plant elevations in both Unit 1 and Unit 2 do not conform to seismic qualification requirements.
Affected equipment included the Unit 1 Emergency Gas Turbine Generator and i
A & B Reactor Feedwater Pump Motors, and the Unit 2 Emergency Diesel Genera-tors (EDGs).
The relays were removed from service.
Replacement Model 121JD relays are to be installed.
The relay removal was subject to a Plant Operations Review Committee evaluation which concluded that the equipment involved was operable with the relays removed.
The inspector verified the removal of all affected relays in Units 1 and 2.
,
Replacement relays were installed in the Unit 2 EDG-1 train. Unit 1 was re-turned to service, on completion of the transformer outage with all relays removed. The inspector identified no deficiencies in the review of engineer-ing evaluation of the removal of relays, tagging practices and reinsta11ation of relays in Unit 2.
12.
Management Meetinas During this inspection, periodic meetings were held with senior plant manage-ment to discuss the inspection content and findings.
A summary of the find-ings was discussed with the licensee at the conclusion of the report period.
'
No proprietary information was identified as being in the inspection coverage.
j No written material was provided to the licensee by the inspector.
,
.-y
, -
%
.-
m-m-
.--.~,------._-y-,--,_
,-------m 7,y- - -,
r---m,--ry,.n---
-m----,r_--,,-y--
,r-r
~
~=
-W-r 1r-