IR 05000245/1985026
| ML20202F729 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 04/04/1986 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20202F699 | List: |
| References | |
| TASK-03-04.B, TASK-1.C.1, TASK-2.B.1, TASK-2.F.1, TASK-2.F.2, TASK-2.K.3.57, TASK-3-4.B, TASK-3.A.1.2, TASK-RR, TASK-TM 50-245-85-26, 50-336-85-32, NUDOCS 8604140215 | |
| Download: ML20202F729 (18) | |
Text
- - - - - - - -
-
,
.
.
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report:
50-245/85-26; 50-336/85-32 Docket Nos:
50-245/50-336 License Nos.
Licensee:
Northeast Nuclear Energy Company Facility:
Millstone Nuclear Power Station, Waterford, Connecticut Inspection at: Millstone Units 1 & 2 Dates:
October 29, 1985 through December 30, 1985 Inspector:
John T. Shedlosky, Senior Resident Inspector Approved:
bkN 4hf86 E. C. McCabe, Chief, Reactor Projects Section 38 Date
!
i Summary:
Routine NRC resident (216 hours0.0025 days <br />0.06 hours <br />3.571429e-4 weeks <br />8.2188e-5 months <br />) inspection of plant operations, equip-l ment alignment and readiness, radiation protection, physical security, fire pro-tection, design changes, and surveillance.
The inspection was conducted during l
,
a period of time in which Unit 1 was shutdown for a refueling / maintenance outage, Unit 2 was shutdown for reactor coolant pump motor maintenance.
The inspection activities were specifically focused on the conduct of these outages.
l
I Findings:
No violations were identified.
Areas where licensee performance could be improved were identified in regard to defense-in-depth for offsite power during shutdown (Detail 5) and post-maintenance testing of scram pilot valves (Detail 7).
8604140215 860409 PDR ADOCK 05000245 O
_ - - -
-
.
..
.
.
.
TABLE OF CONTENTS Pag!!
1.
Summary of Facility Activities.......................................
2.
Defects in Jet Pump Instrument Nozzle Assemblies (Unit 1)............
3.
Defects in the Isolation Condenser Steam Supply Line (Unit 1)........
4.
Examination of a Previously Identified Recirculation Pipe Defect (Unit 1)...........................................................
5.
Loss of Normal AC Power (Unit 1).....................................
a.
Event Description...............................................
b.
Inspection Findings.............................................
(1) Coordination of Outage Activities..........................
(2) Test Technician Error......................................
(3) Emergency Gas Turbine Generator - Failure to Start.........
6.
Emergency Gas Turbine Generator Inspections (Unit 1).................
7.
Failure to Scram During Single Rod Testing (Unit 1)..................
8.
Main Turbine Inspection Program (Unit 1).............................
9.
Main Steam Line Pipe Restraint Failure (Unit 1)......................
10.
Low Pressure Coolant Injection System - Break Detection Logic Out of Specification (Unit 1).............................................
11. Monthly Observation of Surveillance and Maintenance..................
l 12. ACRS Sub-Committee Meeting (Unit 1)..................................
13.
Update of Licensee Actions in Response to the TMI Action Plan........
14.
Exit Interview.......................................................
15.
Closed Item Summary..................................................
Attachment A Jet Pump Instrument Nozzle Assembly Weld Inspection Data
)
-
!
i I
h,,,,.
.
...
.
.
.
.
.,,.
/
-.
_
.
.
.
DETAILS 1.
Summary of Facility Activities Unit 1:
The reactor was shutdown on October 26 for a fifty-six day refueling /mainten-ance outage.
Significant activities during the outage included weld overlay repair of the two jet pump instrumentation reactor vessel nozzles, replacement of safety-related valve motor-operators with environmentally qualified units and replacement of tne emergency gas turbine generator rotating field.
The reactor was made critical at 0534, December 21 and the unit turbine generator placed on line at 1436, December 23. The reactor reached full power at 0925, December 27.
Unit 2:
The reactor had been shut down since September 27 and remained shutdown through November 7 because of a failure detected in the "C" Reactor Coolant Pump motor on September 28.
As previously addressed in report 50-336/85-30, a generic failure mechanism required corrective actions to be taken for all four motors.
This work was completed on October 24; however Reactor Coolant Pump seal failures on October 27 and 29 ("B" Pump Seal) and November 2 ("C" Pump Seal) delayed reactor criticality until 1524, November 7.
The unit tur-bine generator was placed on line at 0702, November 8 and reached full power at 0017, November 11.
2.
Defects in Jet Pump Instrument Nozzle Assemblies - (Unit 1)
Ultrasonic examinations were made of both reactor vessel jet pump instrument assemblies as part of the 1985 Inservice Inspection Program. The assemblies serve as the pressure boundary seal where the jet pump differential pressure tap instrument lines leave the reactor vessel.
This was a special inspection performed because of problems identified at other Boiling Water Reactors.
On November 22, several welds in each of the two assemblies were rejected based on the ultrasonic examinations.
Based on initial ultrasonic examination, the licensee normally conducts ex-tensive manual examinations of reflections which are potential defects.
The pipe weld preparation can cause the geometry of the inside surface to affect the sound path.
By gathering additional data a more accurate weld plot may be constructed.
In this case, however, high radiation fields from material within the assemblies limited the time which could be spent for these evalu-ations.
This resulted in the repair of two possibly non-defective weld areas.
Problems were also caused by the design of the instrument assembly.
Each is made up with two eccentric reducers; their outside surface interfered with maintaining proper transducer contact normally needed for detailed inspections.
w
-
- -
-
-
-
-
-
-
- -
-.
E
.
.
.
.
The licensee used both automated and manual techniques for scanning and evalu-ation.
Ofthefiveweldsperassembly,twowererejectedfromassembly"A" and three from assembly "B'.
Both of the eccentric reducer to 12" pipe welds were found defective, as was the assembly "A" pipe to tube sheet weld.
Be-cause these three welds had strong indications of defects and required repair, the two other welds in the safe end to 8"x4" weld were also rejected.
The reflections at this weld in both assemblies were low in amplitude.
They were rejected because the additional examinations would have had to be conducted in radiation fields of up to 40 Rem / hour.
The licensee categorized the de-fects as possible intergranular stress corrosion cracking.
In each case the weld u., returned to an acceptable condition by applying a full strength weld overlay.
The design of the overlay was based on the con-servative assumption that each weld had a through-wall, 360 degree flaw.
The inspector observed portions of the inspection and reviewed the licensee's planning to maintain radiation exposures "As Low As Reasonably Achievable" (ALARA).
Following the discovery of the weld defects, the inspector reviewed the licensee's analysis which led to rejection and subsequent repair.
The inspector found that detailed ALARA reviews had been made and that they received strong management attention.
The actions which were requested in-cluded special training for workers using a full size mock-up.
This device was used for planning both the inspections and the repair operation.
The ALARA review also resulted in the installation of temporary shielding around the nozzle assembly and specified the sequence of repairs so as to provide additional self shielding.
The inspector found that the workers were well supervised by Radiation Protection Technicians who were active at the " job-site".
The application of weld overlays was covered closely by both engineering and QA/QC personnel.
The overlay was applied b.v automated welding equipment.
Type 308L filler material was used.
Follows.ig the repairs, the weld overlays were surface inspected for weld integrity using liquid penetrant and for bonding to the base metal using ultrasonic testing.
Both of these inspection techniques had been developed during the 1984 outage, when weld overlay was used to repair jet pump risers.
There were no unacceptable conditions iden-tified.
Attachment "A" to this report contains a tabulation of the welds which were inspected and the defects which were identified.
3.
Defects in the Isolation Condenser Steam Supply Line - (Unit 1)
As the result of ultrasonic examinations which were performed as part of the 1985 Inservice Inspection Program, a defect was found within the heat affected zone of the Isolation Condenser steam supply line.
The defect occurred in a 12-inch 304 SS portion of the line at a weld designated ICAC-F-13; it is
D
.
.
.
located in a Class 2 portion of the system.
The pipe has a nominal wall thickness of 0.688 inches. More than one indication was p' resent in the de-fect's 8-inch overall length.
The largest flaw was 0.220 deep and 2.5" long.
Repairs were made using a full strength weld-overlay with type 308L filler material.
The design of the weld overlay assumed that the defect was through-wall for a full 360 degrees.
The 0.430" thick overlay was applied by auto-matic welding equipment and was inspected for integrity with liquid penetrant and for bonding to the base material by ultrasonic examination.
The inspector observed portions of the repair and inspections.
The defect occurred in a section designated for augmented inspection because it is con-structed of sensitized piping.
There were no unacceptable conditions identi-fied.
4.
Previously Identified Recirculation Pipe Defect - (Unit 1)
During the 1984 refueling / maintenance outage, two defects were discovered in the heat affected one of a 28-inch Schedule 80 recirculation pump inlet pipe.
Those defects were discovered before the application of Induction Heating Stress Improvement (IHSI) throughout the recirculation system during that outage.
Defect size was determined through ultrasonic inspection and analysis with a comp' uter-based system (UDRPS).
Final analysis concluded the defects were 0.090 deep and 2.5" long, and 0.175" deep and 6.5" long.
The licensee elected to evaluate the flaws, both located at weld RCAJ-1, and justify continued operation without repair.
Two analyses to determine crack propagation were performed using fracture mechanics.
The first was based on NRC guidelines stated in SECY-83-267.C " Staff Requirements for Reinspection of BWR Piping and Repair of Cracked Piping," and NUREG-1061, " Report of NRC Piping Review Committee." The second analysis recognized the effects of the
..
application of IHSI.
Both analyses concluded that a substantial margin existed between a conserva-tively sized and grown flaw and the requirements of ASME BPV Code Section XI, paragraph IWB-3640.
The licensee re-examined the flaws at weld RCAJ-1 during the 1985 refueling /
maintenance outage and again used the computer based UDRPS system.
Because the ultrasonic data is stored digitally in the system bulk memory, each ex-amination result can be compared.
This was done and a high degree of data correlation reflected that there was no change in crack size between 1984 and 1985.
The inspector reviewed the licensee's program to implement their previous commitment for follow-on examinations and found no unacceptable conditions.
.
q
.
.
.
5.
Loss of Normal AC Power - (Unit 1)
a.
Event Description On November 21, 1985 at 1315, Millstone Unit I lost all AC power to station electrical distribution buses for four (4) minutes.
This resulted from the combination of both a personnel error made during surveillance of a generator output breaker and the failure of the gas-turbine generator to successfully complete its starting sequence. At the time of the event, the unit was in the twenty-sixth (26) day of a refueling / maintenance outage, the reactor ves-sel head was off, and the refueling cavity was flooded.
The licensee declared an Alert Condition at 1410 and downgraded that to an Unusual Event at 1511.
Prior to this event, off-site power was being supplied from the 345 kv switch-yard, "backfeeding" the Unit Transformer to the Normal Station Service Trans-former(NSST).
The Emergency Gas Turbine Generator (EGTG) was in normal stand-by service.
Its auxiliaries were powered from the EGTG output bus which was energized, also in normal standby lineup, from the off-site 23 kv line.
Both the Emergency Diesel Generator (EDG) and the Reserve Station Service Transfor-mer (RSST) were out of service for preventive maintenance.
Main generator output breaker 15G-6T-2 was open prior to the event as part of transfer trip testing.
Station power from offsite was consequently being supplied through main generator 345 kv output breaker 15G-5T-2.
At 1315 a test technician erroneously inserted a breaker failure signal into the control logic for 15G-6T-2; this opened 15G-5T-2 through the switchyard protection system.
Although the 4160 volt AC station service and safeguards buses were de-energized,- the loss of power logic saw the opening of both generator output breakers as a full load reject.
The logic as designed cannot differentiate between a full load rejection at power and tripping the genera-tor output breakers while "backfeeding" the Unit Transformer during a mainten-ance period while shutdown. A full load reject does not cause an EGTG start signal.
Therefore, there was no emergency start signal to the EGTG in this case.
In response, control room operators tripped open NSST feed breakers to buses 14A, 148, 14C and 14D to manually initiate the loss of power (LNP) logic.
Since the RSST was de-energized, this caused bus load shedding and automatic-ally started the EGTG.
During the gas turbine start sequence, the unit tripped as the result of high exhaust gas temperature. This is a safety shutdown with a trip point of 1300 degrees F.
Since the 23kv feeder breaker to bus 14G is tripped by the LNP and load sequencing logic, the unit lost all incoming power.
Switchyard personnel reported their error and re shut 15G-5T-2 about one (1)
minute after tripping.
Power was restored to safeguard buses and reactor shutdown cooling was restored after being lost for five (5) minutes.
The RSST was re-energized at 1850, November 21 and the EGTG was successfully started at 0041, November 22.
Throughout this event, Millstone Unit 2 remained on line at full power and Unit 3 was undergoing final preparations for initial fuel loading; both were unaffecte.
.
.
b.
Inspection Findings The inspector, who was in the control room during the recovery from the loss of power, reviewed the performance of equipment and personnel.
He found that the electrical distribution system including the LNP logic operated in accord-ance with its present design.
The licensee has been in the process of modi-fying that logic to provide a substantial upgrading of its capabilities.
The modified system will process an LNP action when a safeguards electrical bus or safety related station service bus with Feedwater Coolant Injection loads are in an undervoltage condition.
These modifications are expected to be completed during the 1987 refueling outage.
The present logic relies on monitoring RSST primary potential and breaker positions.
An unusual con-figuration resulted in delaying the EGTG start signal.
The loss of power condition was extended when the EGTG failed to start.
For a similar occurrence during reactor power operation, the unit generator would continue to supply the station service electrical system through the Unit Transformer and the NSST.
In the event of a loss of the NSST, loads would " fast transfer" to the RSST.
l (1) Coordination of Outage Activities The Operating License Technical Specifications do not prohibit the re-moval from service of both the RSST and a single emergency power source while shutdown.
Although the decay heat load was only 0.7% of the decay
!
heat following a trip from extended full power operation, the performance of switchyard breaker trip circuit testing which involved the sole AC supply line was not a conservatively prudent action.
The licensee's in-
!
vestigation also reached this conclusion.
Because the control room l
operators did not fully assess the consequences of the testing, the lic-
!=
ensee has implemented additional administrative policies which require these additional factors to be considered and for communications to take place between the control room and test personnel before authorizing switchyard breaker testing.
(2) Test Technician Error To properly perfor^m the breaker failure trip testing, the test technician was to open a switch and interrupt the trip signal to 15G-5T-2 which was the breaker in service.
In error, the trip to 15G-6T-2 was disabled.
,
i To prevent recurrence of this problem, Production Test Department per-sonnel on-site are assisting the Connecticut Light and Power Transmission
,
,
'
Department in writing more effective detailed procedures.
(3) Emergency Gas Turbine Generator - Failure to Start (Unit I)
,
l The Emergency Gas Turbine Generator (EGTG) failed to complete its start-
!
ing sequence when it tripped on high exhaust gas temperature.
Subsequent investigation found that this trip was a valid operation of a turbine
,
!
safety system.
Exhaust gas temperature exceeded the 1300 degree F trip
,
.
-
- -.
-
_
..
.
.
.
point and caused the unit to shut down.
High temperature was due to an excessive fuel supply rate.
Final analysis indicated that the fuel sup-ply rate had been increased to compensate for a malfunctioning component during post preventive ciaintenance grooming.
The EGTG had been removed from service for preventive maintenance and inspection. As part of these actions and to meet previous commitments-to the NRC, both the fuel servo-limiter and the air-start motor flow control valve were replaced with certified factory re-built components.
During testing conducted after that preventive maintenance, the servo-limiter was adjusted to bring the unit starting time to within the Tech-nical Specification 4.9. A.2 maximum of 48 seconds.
Nineteen (19) starts l
were performed during this grooming period, with the last of these on November 9.
It now appears that the servo-limiter settings needed to meet the maximum starting time increase with the unit cold.
In this case, that resulted in exhaust gas temperature reaching the protective trip point.
As the result of investigations conducted on November 21, it was deter-mined that the new air-start motor flow control valve was not supplying enough air to support the fast start requirements of the EGTG.
After the flow control valve was replaced with the previously installed one and the servo-limiter adjusted to normal fueling rates, the machine was started in 44 seconds with a peak exhaust temperature of 800 degrees F.
Final testing was satisfactorily performed at 0900, November 22 and the unit was returned to standby service.
The licensee does not have the capability to rebuild EGTG components such as the servo-limiter or the air-start motor flow control valve, but must rely on certified replacement parts.
Because of this event, has it be-came apparent that there is a need to closely monitor the performance of the flow control valve.
The licensee has started to monitor and record valve outlet air pressure during surveillance testing.
Subsequent testing of the air start valves found that the valve in place during the last operating cycle met the specifications for vendor bench testing of a rebuilt valve (47 to 49 psig outlet pressure).
The valve initially installed during this outage and the apparent cause of these problems was found to operate at 25 to 35 psig outlet pressure.
c.
Summary l
(1) The plant lineup during this shutdown period provided for one off-site power input backed up by the EGTG, which had been classified as operable through prescribed surveillance.
(2) There is no Millstone 1 Technical Specification Limiting Condition for Operation requiring backup AC power during outages.
The licen-l see provides backup AC power as a matter of good practice.
i
!
, -
-
,
-,
,
.
.
.
(3) During this event, decay heat load was not a significant factor because the reactor had been shut down for an extended period.
(4) Had offsite powcr rerrained unavailable for a prolonged period, the licensee could have pursued obtaining temporary power from the 23 kv line or from interconnection to Unit 2 power.
Neither of these is a normal source but either could have been resorted to in an emergency.
The low decay heat load provided ample time for such measures.
(5) Action to restore AC power was timely and effective.
(6) Surveilling, and thereby potentially perturbing, the sole on-line source of AC power unnecessarily challenged the AC power source.
The surveillance could have been done when another offsite power path was available and/or when both the EGTG and EDG were available.
Although Technical Specifications or facility procedures were not violated, this event illustrates that licensee performance could be improved in defense-in-depth for AC power while shut down.
(7) Corrective actions initiated by the licensee were acceptable.
(8) Defense-in-depth provisions for AC power sources will be examined during routine NRC inspections.
The inspector closely followed the licensee's investigation and corrective actions as they were being performed.
There were no unacceptable conditions identified.
6.
Emergency Gas Turbine Generator Inspections (Unit 1)
The licensee had committed to an inspection of the Emergency Gas Turbine Generator (EGTG) generator stator winding to verify that no latent damage was caused by an out of phase closure of a feeder breaker at a remote switchyard on December 18, 1984.
That inspection was conducted during the 1985 refuel-ing/ maintenance outage.
The internal inspection of the stator found that the end windings support system was tight and there was no sign of movement of the winding bars.
The connecting rings were found tight with no sign of vibration or wear.
The area around the stator bars was clean with no " dusting" or " greasing" to indicate bar vibration or movement and consequent insulation wear.
The rotating field was also inspected.
All electrical tests of the field in the as-found condition were satisfactory.
Although there was no distortion or elongation of the winding stack, the tape around the stack was observed to have lifted and cracked.
The tape appeared to be lifting only in the area
of the end turns where the windings are clear of any grounded components.
Because of this observation, the licensee elected to replace the field with
!
.
.
.
$
a rebuilt unit. The field replacement was completed on December 6.
The ven-dor has indicated that the problem with the tape was probably a result of a manufacturing flaw and not due to the December 18, 1984 incident.
There were no unacceptable conditions identified.
This item (50-245/84-27-01)
is closed.
- 7.
Failure to Scram During Single Rod Testing (Unit 1)
On December 24, 1985, at about 0415, three (3) control rods failed to insert during single rod insertion time testing.
These tests were being performed to meet the surveillance requirements of Technical Specification 4.3.C.1.
The reactor was at 25 percent power and normal' pressure and temperature (983 psig, 528 degrees F) at the time of the failure.
The licensee's immediate corrective action was to fully insert each control rod using normal drive pressure and then electrically disarm the drive at the hydraulic control unit.
This action complied with that required by Specification 3.3.D.
The licensee suspected that the cause of the failure was one or both of the scram pilot solenoid operated air valves (No. 117 or 118) failing to re posi-tion.
Both valves must reach their de-energized position to establish a vent path for the air-operated scram valves and cause control rod motion.
Four of the six pilot valves had been reworked during the outage preceding the in-progress return to power operation.
After the rods failed to scram, the pilot valves were removed from the hydraulic control units (HCU) as a set and bench tested prior to disassembly. Two of the three sets of solenoid valves were found with a defect in either the 117 or 118 valve.
All six valves were com-pletely rebuilt and bench tested prior to returning the associated HCU to service.
Following these maintenance actions, each control rod was success-fully scram time tested.
.The results from testing and inspecting the valves are listed below by HCU control rod number:
HCU 26-03: On the test stand, the 118 valve operated properly.
The 117 valve failed to actuate until the electrical solenoid was cycled several times.
Disassembly revealed that the Buna-N disc material located at one end of the solenoid core plunger had deteriorateo.
This type of failure had been identified by General Electric Company in a Service In-formation Letter (SIL), No. 128, Revision 1.
These valves had not been rebuilt since the SIL was issued; and therefore, the solenoid core plun-ger was an original part.
The licensee has had a program in place to completely rebuild the valves and therefore comply with General Electric's recommendations.
This re-building program has been in progress during the past two refueling out-ages.
However, both of the other two scram failures involved solenoid-operated valves which were rebuilt during the 1985 refueling / maintenance outage.
l
.
.
,
HCU 26-43:
The solenoid operated scram pilot valves from the second hydraulic control unit were bench tested.
During these tests, valve 118 operated properly but valve 117 failed completely.
Both valves were disassembled for inspection.
The core spring was found detached when removed from valve 117.
This defect would result in the type of failure which was experienced.
The licensee has not determined how the spring, which is wound to form a tapered cross section, became detached.
The solenoid core plunger is supplied as an assembly with the spring attached in the rebuilding kits supplied by the vendor.
The inspector has examined these components both in new kits and the suspect parts. When properly assembled, the narrow end of the spring is captured in a groove at the end of the plunger.
These could not be separated without using tools to pry the spring off.
The inspector postulated that the core plunger was supplied with the spring only partially engaged, possibly only to the ridge beyond the plunger groove.
If this was the case, the spring would disengage from the plunger when the solenoid was energized. Without the spring there would be no force to re position the plunger when the solenoid was de-energized and therefore no vent path would be established to open the scram valves.
Both of these valves were rebuilt and bench tested prior to installation on the HCU.
HCU 42-27: Both scram pilot valves were removed from the hydraulic con-trol unit (HCU) and bench tested; both performed satisfactorily during those tests.
The valves were then disassembled and inspected; there were no problems identified.
After examination both were rebuilt with new components and bench tested prior to returning them to service.
The licensee has not determined a cause for the failure.
The inspector observed that the scram pilot valves associated with HCU's 26-43 and 42-27 were rebuilt in place in the Reactor Building during the 1985 refueling outage and therefore were not bench tested.
The work order covering all of the rebuilding identified the post-maintenance re-testing as the individual rod scram tests.
These were the tests which demonstrated that there were problems resulting from the maintenance.
It is inappropriate to wait and perform this testing with the reactor at power for the following two reasons.
First, a common mode failure may have been introduced into numerous control rod drive scram components; second, bench testing was available to provide an effective test of the scram pilot valves.
The licensee's test stand allowed varying solenoid voltages and ai~r supply pressures while testing each valve.
After discussions with the inspector, the licensee committed to rebuild-ing the remaining solenoid operated scram pilot valves by June 1986.
These are the valves which have not yet been rebuilt to the recommenda-
. -. - -
-
-
,
.
.
.
tions of GE SIL 128, Revision 1.
In addition, each valve will be bench tested following the preventive maintenance prior to installation on the HCU and then each HCU and control rod will be individually scram time tested.
That work is now in proc ess.
These failures were detected by the licensee during prescribed scrveil-lance before a substantial power history (decay heat load) developed on the core, and were therefore not a serious safaty hazard.
The NRC was appropriately informed and corrective actions were acceptable.
This event was not found to be one which could reasonably have been expected to be prevented by corrective action for a previous violation.
However, because earlier testing was practicable but was not accomplished, this event is an instance where licensee performance could be improved in regard to accomplishing feasible post-c.aintenance testing before safety-related corponents are used to support power operation.
Scram pilot valve maintenance and testing will continue to receive routine NRC in-spection coverage.
8.
Main Turbine Inspection Program (Unit 1)
The licensee conducts routine inservice inspections of the main turbine rotor in accordance with a schedule established in conjunction with the NRC System-atic Evaluation Program (SEP) Topic III 4-B, " Turbine Missiles." Stress cor-rosion cracking has been identified ab)ve the keyway of the number four generator end rotor wheel.
This flaw was measured to be 1.4 inches in length in 1985.
This is an increase of 1.2 inches in the last eighteen (18) month operating cycle.
Because of the significance of this finding, the licensee informed the NRC by telephone on December 19 and in letters dated December 13 and 20.
Justification for operation with this type of flaw is made through determinis-tic calculations of crack propagation and probabilistic calculations of the flaw causing a turbine missile or turbine burst.
The turbine vendor has re-commended re-inspection after 1.2 years of operation.
Although the deter-ministic calculations of crack propagation resulted in an inspection interval of 2.5 years, the probabilistic calculations resulted in a more restricted period of operation.
An operational interval of 2.1 years results in a tur-bine missile probability of 1E-5 and an interval of 1.5 years results in a burst probability of 1E-4.
Since these intervals conflict with the next scheduled refueling outage, which is to commence in August 1987, the licensee is continuing with their evaluations.
They have an active commitment to the NRC Office of Nuclear Reactor Regulation concerning this issue.
The inspector confirmed that the calculational methods used were those which were previously reviewed by the NRC.
Reports have been accurate and timely.
There were no unacceptable conditions identifie.
.
.
9.
Main Steam Line Pipe Restraint Failures (Unit 1)
The licensee found substantial damage to main steam line pipe restraints during a routine visual inspectica on December 14.
These restraints are in the Turbine Building steam line tunnel near the Reactor Building membrane and support two of the four main steam lines.
They had been replaced in 1982 as part of a seismic upgrade program.
A review of plant transients-identified a turbine trip from full power on August 13, 1985 as the possible cause of this damage.
The licensee inspected the other steam line restraints; no damage was found.
The licensee has non-destructively examined the main steam lines at high stress locations; no pipe defects were found.
Welded attachments to the main steam lines were also examined; again, there was no damage found.
The re-straints have been re-designed based on calculated failure loads of 65,000 pounds at each support.
The work on both restraints was complete before placing the steam lines in service.
The licensee has installed twelve strain gauges to monitor the four main steam line restraints at the point which the damage occurred.
The instrumentation has been in service since the startup following the outage.
This included monitoring when the Main Steam Isolation Valves were opened.
There have been no abnormal readings recorded. The licensee intends to monitor these points through the current operating cycle.
The work in progress rebuilding the restraints was reviewed by the inspector.
In addition, the other main steam line restraints of the Turbine Building and Reactor Building steam tunnel were inspected.
There were no unacceptable conditions identified.
10.
Low Pressure Coolant Injection System - Break Detection Logic Out of Specification - (Unit 1)
As the result of surveillance testing conducted on December 19, three differ-ential pressure switches associated with the Low Pressure Coolant Injection (LPCI) break detection logic were found in the tripped position without pres-sure applied.
All three (DPIS-261-36A, -37A and -38A) monitor the "A" Recir-culation Pump differential pressure.
These are 0 to 60 psid range, Barton Model 288 instruments which have a required set point of 2 psid.
An accept-able set point range of 1.1 to 2.9 psid had been established for these devices.
The required surveillance frequency has been once each refueling outage.
Testing during this outage found one switch tripped due to internal corrosion; the others had setpoints which had drifted to below zero.
In each case, the switch would not reset when the Recirculation Pump was stopped.
These instruments are used within the break detection logic which selects the appropriate recirculation loop for LPCI injection.
Because of the failure of three switches in the tripped position, the LPCI logic would assume that the "A" Recirculation Pump was always running.
This only becomes a problem if the "A" pump is off and the "B" pump is running.
In this case, the logic would not recognize that only one pump was running and might select the broken loop for injectio.
..
.
The inspector reviewed the calibration documents which included SP 412G,
" Break Detection Valve Permissive Functional and Calibration," the Calibration Report for these instruments and the Department Instrument Records.
These
' devices have not had a poor performance history.
The licensee has committed to study the surveillance interval and possibly perform the functional and calibration testing during the operating cycle.
They will also include these instruments in a micro-switch contact integrity test program which is in place and investigate the possibility of installing case drains or other modifications to alleviate the problem of internal mois-ture. These instruments may be replaced with another type more suited for the low differential pressure setpoints.
There were no unacceptable conditions identified.
11.
Monthly Observation of Surveillance and Maintenance Unit 1:
--
Observed portions of inservice inspection ultrasonic examination of Class 2 Isolation Condenser Welds, October 31.
Observed portions of the Emergency Gas Turbine Generator (EGTG) Inspec-
--
tions, November 1, 21, 22, & 26.
Observed EGTG Surveillance Testing November 6.
--
--
Observed portions of Isolation Condenser weld overlay at ICAC-F-13, November 8.
Observed a special test, T 85-1-5 Conducted to verify that the positive
--
displacement Standby Liquid Control (SLC) pumps were able to operate throughout the level range of the SLC tank, meet their required flow rate and not cavitate due to inadequate net positive suction head.
The test was conducted on November 25.
Observed Emergency Diesel Generator operability testing November 26.
--
This test demonstrated the operability of new Grove Flexible relay valves in the air start system.
The diesel may now be surveillance test started on an individual air start valve by a selection using a key lock switch.
Observed Repair of Jet Pump Instrument Nozzle "B" by weld overlay
--
December 3.
--
Observed integrated Emergency Core Cooling Loss of Off Site power tests per SP 628.1 on December 14 and 15.
Observed portions of the replacement of Main Steam Line Restraints MS-
--
R-515 and MS-R-519 on December 17.
Observed rebuilding and testing of solenoid operated scram pilot valves
--
December 2.
q
.
.
Unit 2:
Observed portions of the rebuilding of a spare reactor coolant pump seal,
--
October 30 and November 4.
There were no unacceptable conditions identified.
12.
ACRS Sub-Committee Meeting - (Unit 1)
The Millstone Nuclear Station Sub-Committee of the NRC Advisory Committee en Reactor Safeguards conducted meetings on site on November 18 and 19 to address the Unit 1 Full Term Operating License.
The inspector accompanied Committee members during their tour of the unit and addressed the Committee on licensee performance.
13.. Update of Licensee Actions in Response to the TMI Action Plan The following is an update of licensee actions taken in response to the Three Mile Island Task Action Plan (TMI TAP) requirements.
This includes an over-view of equipment performance resulting from the inspector's observations of those systems installed because of Plan requirements.
Requirements for oper-ability and surveillance frequency are not stated in the Operating License Technical Specifications. However, the licensee's policies and programs con-cerning this equipment was reviewed.
a.
Emergency Action Operating Procedures - (Units 1 & 2);
TMI TAP Items I.C.1.2.B, I.C.1.3.B, II.B.1.3 & II.K.3.57 The symptomatic Emergency Operating Procedures have been developed for each plant to conform with the GE-BWR and CE-PWR Owners Group Emergency Procedures Guidelines.
These procedures have been in place and are part of the licensed operator training and re qualification programs.
There are no open items in this area.
b.
Reactor Coolant System Vents - (Unit 2);
TMI TAP Items II.B.1.2 & II.B.1.3 The remote operated vent systems have been installed on the reactor ves-sel head and the pressurizer steam space.
The inspector's findings and observations during the installation of this system were p eviously ad-dressed in report 50-336/80-19.
The operation of these devices is con-tained in the unit Emergency Operating Procedures.
Previously identified inspection findings in this area do not affect the operability of this system.
The licensee has completed action on two of three of these open items and they are considered to be resolved.
The first addressed the failure of the vent valve position monitoring system to indicate full open.
This problem was corrected by replacing the valve solenoid cover which eliminated magnetic interference with these devices. This item (50-336-84-07-02) is close _
.
.
.
Concerning the second open item, in a letter dated January 3, 1986, the NRC Office of Nuclear Reactor Regulation granted interim approval to the licensee's second ten year Inservice Test Program.
The program contains an alternate test exception for these valves to require testing only durin -refueling outa es instead of every three months.
This TMI action item 50-336/84-07-03 is closed.
A third item (50-336/84-07-01) documents the possibility of a " hot short" opening the vents.
The topic of " hot shorts" is a 10 CFR-50, Appendix R, Fire Protection Program issue which remains open.
There is, however, no open TMI TAP item on this aspect.
c.
Containment Monitoring Instrumentation - (Units 1 & 2);
TMI TAP Items II.F.1.3, II.F.1.4, II.F.1.5 & II.F.1.6 Instrumentation has been installed to monitor the Unit 1 and 2 contain-ment environment during post accident conditions.
This includes channels of wide-range instruments to monitor containment radiation, pressure, sump water level and containment atmosphere hydrogen.
This instrumenta-tion has been operational during the past two operating cycles and has been included in the licensee's surveillance and calibration programs although not addressed in the Operating License Technical Specifications.
The inspector has found that this equipment has been maintained in good operational condition during the period since installation.
There are no open items in this area.
d.
Reactor Vessel Water Level Instrumentation - (Unit 2);
TMI TAP Items II.F.2.3.B Two channels of reactor vessel water level instrumentation were installed during the last refueling / maintenance outage.
This computer-based system monitors reactor vessel water inventory using a system of heated junction thermocouples to detect conditions leading to inadequate reactor core cooling. The system also calculates core sub-cooling and displays core exit thermocouple temperature readings. This system was formally ac-cepted by the licensee on December 31, 1985 following a period of problem resolution and performance monitoring.
There are no open items in this area.
e.
Upgrade of Emergency Support Facilities - Technical Support Center; TMI TAP III.A.1.2.3 The site permanent Technical Support Center (TSC) was completed with the Unit 3 facility in 1985 and was demonstrated to be operational during the last Emergency Planning exercise which was conducted on October 7, 1985.
Licensee performance during this exercise was observed by an NRC team; the inspector monitored the TSC activities.
Observations and in-spection findings are contained in report 50-336/85-2 _
.
.
There were no unacceptable conditions identified. The performance of TMI TAP equipment is a routine inspection item.
This item is closed.
14.
Exit Interview At periodic intervals during the inspection, meetings were held between lic-ensee site management concerning the inspection scope and findings.
No pro-prietary information was identified as being in the report findings.
The following previously identified open items are closed in this report.
15.
Closed Item Status The following open items are closed in this report.
Unit 1:
50-245/84-27-01, Emergency Gas Turbine Generator Inspection (Detail 6).
Unit 2:
50-336/84-07-02, Reactor Coolant System (RCS) High Point Vent Valve Position Indication (Detail 13.b).
50-336/84-07-03, Inservice Test Frequency of RCS High Point Vent Valves (Detail 13.b).
r
.
..
ATTACHMENT A Tabulation of Welds Examined Within the Jet Pump Instrument Nozzle Assemblies (A&B):
A.
JPAF-1/JPBF-1 Reactor. Vessel Nozzle (SA 508 CS) to Safe-End (SB-166 Ni-Cr-Fe) Nominal Wall Thickness 0.422".
B.
JPAF-2/JPBF-2 Safe-End to 8"x4" Schedule 80 Eccentric Reducer (304 SS)
Manual examination only and was possible from Safe-End side only due to outside diameter geometric configuration.
C.
JPAJ-1/JPBJ-1 8"x4" Eccentric Reducer to 12"x8" Schedule 80 Eccentric Reducer (304 SS) Nominal Wall Thickness 0.500."
D.
JPAJ-2/JPBJ-2 12"x8" Eccentric Reducer to 12" Schedule 80 Pipe (304 SS)
Nominal Wall Thickness 0.688."
E.
JPAJ-3/JPBJ-3 12" Schedule 80 Pipe to Tube Sheet Nominal Wall Thickness 0.688."
Tabulation of Defects Recorded Within the Jet Pump Instrument Nozzles Assembly:
A.
Assembly A JPAF-2-SE 0.042" deep and 0.5" long low amplitude reflection recorded at 30% to 50% of DAC and located in the Ni-Cr-Fe Safe-End.
JPAJ-2 Two Flaws combined 0.100" deep and 4.66".long in weld heat affected zone (HAZ).
B.
Assembly B JPBF-2-SE First 0.090" deep and 0.5" long, second 0.060" deep and 0.625" long both low amplitude reflections recorded at 50% to 60% of DAC and located in the Ni-Cr-Fe Safe-End.
JPBJ-2 0.172" deep and intermittent 360 degree in weld HAZ.
JPBJ-3 0.344 maximum depth and intermittent 360 degree in weld HAZ.