IR 05000293/1990007
| ML20043D499 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 05/31/1990 |
| From: | Gray E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20043D498 | List: |
| References | |
| 50-293-90-07, 50-293-90-7, IEB-90-001, IEB-90-1, NUDOCS 9006080127 | |
| Download: ML20043D499 (73) | |
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REGION I
, ' Docket No.: 50-293 Report No.: 50-293/90-07 Licensee: Boston Ed' son Company 800 Boy 1'. ton Street Boston,i4assacnusetts 02199 Facility: Pilgrim Nuclear Power Station Location: Plymouth, Massachusetts Dates: March 9 - April 30, 1990 Inspectors: J. Macdonald, Senior Resident Inspector A. Cerne, Resident Inspector C. Carpenter, Resident Inspector W. Olsen, Resident Inspector (Temporary Detail) L. Cheung, Senior Reactor Engineer, RI J. Trapp, Senior Reactor Engineer, RI J. Kauffman, Reactor Operations Engineer, AE0D K. Naidu, Senior Reactor Engineer, NRR Approved by: d A.Ae MJ/ lh H. Gray, Actin @ ief, Reactor, Projects Section 3A Date Inspection Summary: Inspection on March 9.1990 - April 30,1990 (Report No.
50-293/90-07) Areas Inspected: Routine safety inspection of actions on previous inspection findings, operational safety and plant operations, security, maintenance and surveillance, engineering support, raciological controls, safety assessment / ' quality verification and periodic reports.
EXECUTIVE SUMMARY Results: 1.
General Conclusions on Adequacy. Strength or.Veakness in Licensee Programs The licensee demonstrated excellent conduct of operations and outage man-agement during the recently completed mid cycle maintenance and surveil-lance outage.
The pre-outage planning meetings were well attended and were successful in developing a realistic critical path schedule. The daily outage status meetings were attended by key supervisory personnel.
Individuals in attendance were well prepared.
Conflicts were addressed and critical path schedules were revised as necessary. The licensee demonstrated the ability to integrate several major emergent work activities into the schedule and to accomplish these activities in a quality manner. Good organizational communications and supervisory attention were apparent throughout the outage. Operations eersonnel remained cognuant of plant i.
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e i i status and moMng outage activities at all times.
Control room response to the swirJ % : transfer failure and interruption of shutdown cooling on March 20, w > # < coordinated.
Inter-disciplinary communications were consistently effective as evidenced-l by the lack of unanticipated system actuations, off normal occurrences and event notifications.
Radiological controls were well maintained throughout the outage as docu-mented in sper.ialist inspection report 50-293/90-12.
The licensee investigation of the swing bus transfer faflure and subsequent inspection of all 480 VAC breakers represented a significant impact on the outage. Bus realignments, breaker removal, and inspections were conducted in a quality manner.
Outage recovery and the approach to startup was very deliberate.
System configurations and clearance restorations were verified and prerequisites were ensured prior to procession to ensuing plateaus.
Notwithstanding effective overall safety performance during the outage the inspectors identified several areas of concern.
The control room was very heavily traveled especially during day shift activities. At times, the number of people and additional noise level were_a distraction to the con-trol room operatorr.. The inspectors did note the Nuclear Watch Engineer (NWE) clear the control som of unnecessary personnel, indicating good command and control.
Although the official control room log entries are typically comprehensive ' and complete, the failure of the B RHR pump to trip as designed following the March 20 isolation of shutdown cooling suction was not immediately entered into the logs.
Addit.ionally, minor isolated weaknesses in the administration of equipment tagging were noted.
2.
Violations: A licensee identified non-cited violation of missed Technical Specification surveillances and improperly implemented 10 CFR 50.49 and 10 CFR 50 Appen-dix R requirements is discussed. The events were licensee identified, pro-perly reported and prompt corrective actions were taken (50-293/90-07-01, Section 3.7.4).
3.
Unresolved Items: , An unresolved item was identified concerning the implementation of the 480 VAC breaker task force long term corrective action (50-293/90-07-02 Section 5.5).
A second unresolved item was identified concerning the licensee review of an inadequate maintenance activity which resulted in the automatic loss of suction trip function for the B RHR pump being defeated (50-293/90-07-03 Section5.6).
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[- ~1 ,- - .. , , . i i TABLE OF CONTENTS PAGE 1.0 Persons Contacted............................ .......................
2.0 Summary of Facility Activities.......................................
e l 3.0 Operational Safety (IP 71710,71707,93702)..........................
. 3.1 Plant Operations Review.........................................
3.2 Safety System Review............................................
3.3 Review of Tagging Operations....................................
. 3.4 Operational Safety Findings.....................................
i 3.5 Inoperable Equipment............................................
3.6 Engi neered Sa f ety Feature Wa1 kdown..............................
3.7 Revi ew o f Pl a nt Ev en t s..........................................
3.7.1 "A" Recirculation Pump Motor-Generator Set Trip.......
3.7.2 Loss of Power to Swing Bus 6 and Loss of Shutoown Cooling.............................................
3.7.3 Group I Isolation on Sented High Water Level..........
3.7.4 Licensee Identified Violations........................
4.0 Security (IP 71707)..................................................
4.1 Observations of Physical Security...............................
5.0 Maintenance / Surveillance (IP 61726,62703)...........................
5.1 Turbine Control Valve Testing...................................
5.2 Replacement of Excess Flow Check Valves.........................
5.3 Local Leak Rate Testing.........................................
5.4 Observation of ADS Subsystems Manual Opening of Relief Valves... 20 5.5 Loss of Power to Swing Bus B-6..................................
5.6 Failure of "B" RHR pump to Trip upon Loss of Suction Path.......
6.0 Engineering / Technical Support........................................
6.1 Installation and Testing of Modifications..................,....
6.2 Rosemount Transmitters (IEB 90-01).............................
6.3 (Closed) Unresolved Item 85-35-02, Environmental Qualification Documentation Files Incomplete................................
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- Table of Contents
' L l I PAGE 7.0 Sa fety As se ssment/ Quality Veri fica tion...............................
7.1 Licensee Event Reporting........................................
7.1.1 LER 90-01.............................................
' 7.1.2 LER 90-02.............................................
7.1.3 LER 90-03.............................................
7.1.4 LER 90-04.............................................
7.1.5 LER 90-05.............................................
7.1.6 LER 90-06.............................................
7.2 Review of General Electric Inspection Activities................
8.0 Review of Periodic and Speelai Reports (IP 71707)....................
9.0 ManagementMeetings(IP 30703,40500,35502).........................
- The NRC Inspection Manual inspection procedure (IP) that was used as inspec-tion guidance is listed for each applicable report section.
. . ATTACHMENTS Attachment I - Chronology of Plant Events Attachment II - Circuit Breaker Diagrams Attachment III - Licensee handout from March 29, 1990 Management Meeting
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DETAILS 1.0 Persons Contacted Interviews and discussions were conducted with members of the licensee staff and management during the report period to obtain information per-tinent to the areas inspected.
Inspection findings were discussed peri-odically with the management and supervisory personnel listed below.
K. Highfill, Vice President, Nuclear Operations and Station Director E. Kraft, Acting Plant Manager D. Eng, Outage and Planning Manager L. Schmeling, Acting Deputy Plant Manager R. Fairbanks, Nuclear Engineering Department Manager D. Long, Plant Support Department Manager L. Olivier, Operations Section Manager N. DiMascio, Radiological Section Manager J. Seery, Technical Section Manager G. Stubbs, Maintenance Section Manager T. Sullivan, Chief Operating Engineer J. Neal, Security Division Manager P. Cafarella, Acting Systems Engineering Division Manager B. Sullivan, Fire Protection Division Manager 2.0 Summary of Facility Activities Pilgrim Nuclear Power Station (PNPS, Pilgrim, the lictnsee or the plant) commenced a planned reactor shutdown for a surveillante outage on March 9.
Following completion of the outage, the reactor os made critical at 3:10 a.m. on April 24.
The turbine generator was Lr W nonized to the grid on April 28 at 6:33 a.m.
At the close of this report period, the plant was at 84% power. A chronology of the outage is provir'ed as Attachment I to this report.
On March 11, the licensee notified the NRC Operations Center via the Emer-gency Notification System (ENS) when a false high reactor water level sig-nal resulted in a partial Group I primary containment system isolation i (section 3.7.3).
This notification was made in accordance with 10 CFR 50.72. Notification was also made on March 15 when the ENS line was in-operable and on March 20 when de-energization of two 480 VAC safety-related buses resulted in loss of shutdown cooling (SDC), secondary con-tainment isolation, automatic start of reactor building closed cooling water (RBCCW) pumps and isolation of drywell atmospheric and hydrogen / ! oxygen sampling systems (section 5.5).
On March 29, a management meeting was held between NRC Region I and the licensee to discuss licensee root cause analysis of a missed Technical Specification surveillance of two instrument line excess flow check valves i .
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and itcensee engineering evaluation of the salt service water pump dis- _ charge column fracture.
Licensee handouts from the presentation are in- ' cluded as Attachment III to this report.
On April 5, Senior NRC management from the Office of Nuclear Reactor Regu-lation (NRR) were onsite to tour the plant and meet with licensee manage-ment. Also on April 5, Mr. Jon Johnson, Chief, Projects Branch No. 3 re-sponsible for the oversight of Pilgrim was onsite to meet with the Resi-dent Inspectors.
' The following specialist inspections were conducted during this report period: a) Radwaste and Transportation, March 19 -23, 1990 (Inspection Report 50-293/90-10); b) Emergency Preparedness, March 26 - 30, 1990 (Inspectior Report 50-293/90-08); c) Radiation Controls specialist, April 16 - 20, 1990 (Inspection Report 50-293/90-12); and d) Seismic instrumentation survey on March 26, 1990.
! 3.0 Operational Safety 3.1 Plant Operations Review The inspector observed plant operations during regular and backshift hours of the following areas: Control Room Fence Line (Protected Area) ' Reactor Building Intake Structure Diesel Generator Building Turbine Building Switchgear Rooms , Control room instruments were observed for correlation between chan-r.els, proper functioning and conformance with Technical'Specifica-tions. Alarms received in the control room were reviewed and dis-l cussed with the operators. Operator awareness and response to these conditions were reviewed.
vintrol room and shift manning were com-pared with Technical Speci Mcation requirements.
Posting and control of radiation, contaminated and high radiation areas were inspected.
Use of and compliance with radiation work permits and use of required personnel monitoring devices were checked.
Plant housekeeping con-trols, including control of flammable and other hazardous materials, was observed. During plant tours, logs and records were reviewed to ensure ce. liance with station procedures, to determine if entries were correctly made and to verify correct communication of equipment status. These records included various operating logs, turnover sheets, tagout and lif ted lead and jumper icgs.
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l performed on backshifts including March 9, 12, 13, 15, 16,'19-22, 26-29, and April 2-6, 9-13, 17, 20, 24, 25, 27 and 30.
" Deep back-shift" inspections were conducted as follows: Time Date l 9:45 p.m. - 11:15 p.m.
3/20/90 6:45 p.m. - 8:45 p.m.
3/25/90 l 10:30 p.m. - 12:00 a.m.
4/7/90 ' 7:15 a.m. - 5:00 p.m.
4/16/90 9:00 p.m. - 10:30 p.m.
4/21/90 Pre-evolution briefings were noted to be thorough with appropriate i questions and answers.
The operators appeared to have good knowledge of plant conditions.
No unathorized reading material was observed and food, beverages and hard hats were kept away from control panels.
l The inspector noted that at times, the formality and appropriateness of communication in the control room was less than normally antici-l pated. Access control to main control board back panels was peri-odically lax. At times during tte outage, especially during the dayshift, the control room appeared overcrowded and noisy. On one ' such occasion, there were over 28 individuals in the control room with various conversations ongoing. Control of access to the control room could be improved.
However, the NWE did on occassion ask con-trol room personnel to minimize the noise level, illustrating appro-priate command and control.
3.2 Safety System Review . portions of the emergency diesel generators, reactor core isolation cooling, core spray, high pressure coolant injection, residual heat removal and safety related electrical systems were reviewed to verify , proper alignment and operational ' status in the standby mode. The review included verification that (1) accessible major flow path valves were correctly positioned, (ii) power supplies were energized, (iii) lubrication and component cooling was proper, and (iv) com-ponents were operable based on a visual inspection of equipment for leakage and general conditions. No violations or safety concerns were identified.
3.3 Review of Tagging Operations I l' Inspector observations of tagouts being prepared and performed iden- ' tified that weaknesses continue to exist in this area.
Effective implementation of the tagout procedure continues to be a problem area in that tags were noted to not be completely filled out and sequenc-ing of tag placement on valves continues to be a sporatic problem.
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) Controlled copies of P& ids frequently have Plant Design Changes (PDCs) outstanding against the drawing.
Inspector questioning deter-mined that the PDCs affecting P& ids are not filed in the control l room, but rather are maintained in document control, and that PDCs i are routinely not checked when directing control room activities such as tagouts and vent and fill of the systems. These discrepancies above were discussed with and are being reviewed by licensee manage-j ment.
They are, however, minor and administrative in nature, The following tagouts were reviewed: Tagout Description 89-34-3 Replacernent of old NWE tag on domestic water supply valve ' 90-10-25 "B" RHR pump breaker 152-603 90-23-19 HPCI turbine exhaust vacuum breaker 90-13-11 Restricting orifice - RCIC 90-13-12 RCIC pump restricting orifice , ' 3.4 Operational Safety Findings Licensee administrative control of off-normal system configurations ' by the use of temporary modifications and tagging procedures, was in compliance with procedural instructions and was consistent with plant safety.
Backshift inspections found operators to be alert and atten-tive.
Overall plant cleanliness and material condition continued to be good.
This was especially noteworthy considering that the plant was in an outage condition.
No deficiencies were found.
3.5 Inoperable Equipment Actions taken by plant personnel during periods when equipment was inoperable were reviewed to verify that: technical specification limits were met; 61 ternate surveillance testing was completed satis-factorily; and, equipment was properly returned to service upon com-pletion of repairs.
This review was completed for the following items: Date Out Date In System 3/10 3/10 "A" recirculation pump motor generator 3/13 3/17 Instrument rack 2205 4/21 4/22 "B" RHR pump breaker 4/19 4/22 4160 volt bus A-1 l' d
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i i 3.6 Engineered Safety Feature Walkdown i The inspector performed an engineered safety feature system walkdown i of the standby AC power system (diesel generators).
The inspection independently verified the status-of the system with the aid of a nuclear plant operator, who physically manipulated valves during the
walkdown, and assisted in the review of system circuit breakers and
control equipment.
The licensee diesel generator system lineup procedure 2.2.8, " Standby AC Power System (Diesel Generators)," was compared to controlled . system drawings, (P&ID M-259, M-223 and M-219) and the as-built con-t figuration.
Valve positions in the lineup procedure matched cor-responding valve positions on the system drawings, however, several valves listed in the lineup procedure were not indicated on the con-trolled system drawings.
This matter was discussed with the licensee
and it was stated that these types of problems are being addressed by ' the latest revisions to the system drawings.
Also, it was noted that two valves (39-HO-400A and 39-H0-400B) which are engine crankcase drains had their handwheels removed and attached to their respective valve bodies with wire.
Discussions with the licensee indicated that this was done to prevent inadvertent opera-tion of the valves.
The inspector also noted that attachments A and B to procedure 2.2.8
do not designate a required circuit breaker position for the nuclear operator to verify when performing the electrical lineup.
The pre-sent verification sheets only list BREAKER STATUS - OPEN OR CLOSED, A required position would preclude the possibility of error during the required review by the Nuclear Watch Engineer.
The inspector verified that the required instrumentation and control equipment was installed and functional.
No discrepancies were noted.
Several instruments were checked to verify that they were in calibra-tion in accordance with station procedures, and that Technical Speci-fication requirements were being met. The underground f uel oil stor-age tank level gauge was verified operational and a review of the records for completed maintenance-surveillance procedure 8.E.38, attachments 1 and 2, indicated that the required surveillances had been performed on time and were satisfactory.
The physical condition of the diesel generators was excellent, the L respective rooms were clean, well illuminated and maintained.
Equip- ' ment hangers and supports were made up properly and no leaking valve packing was found on any valves.
No potential fire hazards were I present in either diesel generator room. A station fire watch was posted, due to the area fire protection deluge system being inopera-tive.
The inspector had ne further questions.
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3.7 Review cf Plant Events ' 3.7.1 "A" Rerirculation Pump Motor-Generator Set Trip y On March 10 during testing of the "A" recirculation pump '
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motor generator Set (RMCS) prior to entering the mid-cycle outage, an automatic lockout of the "A" RMGS and resultant ! trip of the "A" recirculation pump occurred at approxi- - mately 98% pump speed. This testing was conducted per Tem-porary Procedure (TP) 90-011 " Testing of "A" Recirculation
System M-G Set."
The purpose of this testing was to opti-
mally tune the voltage regulator and determine the cause of < past voltage regulator /RMGS transients, as well as to ob- , tain current data on parameters associated with operation of the recirculation M-G sets prior to implementation of Plant Design Change (PDC) 90-14 as recommended by the ven-dor (General Electric). The testing basically consisted of - increasing and decreasing RMGS speed in increasing incre-ments and recording the system response and/or adjusting the voltage regulator.
The trip occurred shortly after increasing RMGS speed to 98%. The test director noted that voltage and current oscillations lasted for approximately 20 seconds before the generator field voltage decreased to below the setpoint to trip the "A" recirculation pump MG set.
The licensee con-l cluded that the voltage regulator was generally functioning i properly but was out of tune, and that this was the cause for the trip. The RMGS configuration for this test had the MG set feedback signal (tachometer) removed, similar'to the configuration that would result from implementation of PDC 90-14.
PDC 90-14 is intended to improve recirculation pump s' peed stability under steady-state and transient conditions by removing the existing MG set speed signal (tachometer) feedback loops, deleting several obsolete modules, and add-ing two new modules during the present mid-cycle outage.
Specifically, error limiter modules 262-036 A/B and speed controller modules 262-028 A/B are to be removed and new rate limiter modules are to be added. The licensee has had discussions with engineers at two other BWR plants similar to Pilgrim (Fitzpatrick and Monticello).
Similar problems
once existed at both of these plants: noisy feedback loops, 't instabilities in recirculation pump speeds, spurious lock-up and unpredictable pump trips.
Both plants installed essen- . tia31y identical modifications to PDC M '4 with reportedly i I .. ..
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excellent results.
Fitzpatrick reported no further abnor-malities with speed control in the three years after modi- . fications; Monticello had no problems in the six years ' after modification.
l Because of the previous RMGS trips, (documented in NRC In- ' spection Reports 50-293/89-12 and 50-293/89-13), the licen- , see made a series of temporary modifications in 1989 to add ' instrumentation / recorders for data collection and analysis c " for the investigation of these trips, Based on evaluation of the test results by systems engi-neering and the vendor obtained on December 7, 1989 at 27% , speed and on March 10, 1990 at 85% speed, the licensee con-
cluded that the voltage regulator performance is stable at these speeds. The licensee further concluded that this demonstrates that the voltage regulator is not broken nor in need of repair.
However, the licensee plans to perform further investigation into the voltage regulator instabil-ity problems and perform adjustments of the voltage regu-lator at high machine speed in response to voltage setpoint step changes to allow tuning of the voltage regulator and dampening of system response at rated. or near rated, machine speeds following the restart from present mid-cycle outage and installation of PDC 90-14.
The inspector concluded that licensee efforts to investi-gate and correct the conditions causing the RMGS trips appear to be appropriate and thorough.
PDC 90-14, based on industry experience, should improve R'iGS performance and reliability.
The plans to test and tune the voltage regu-lator following the outage at high pump speeds appcars necessary to end RMGS trips and, according to the vendor, can only be done effectively at high pump speeds. While the potential for an RMGS trip and a minor reactor runback during this testing exists, this testing is planned to be done at a low rod line and with little decay heat.
Thus, the potential loss of MG set during testing is of minor safety significance. The inspector concluded that instal-lation of PDC 90-14 and subsequent tuning of the RMGS volt-age regulator indicate management attention to improved performance of the RMGS's and a reduction of RMGS trips and , t plant transients, ' ! l ,
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3.7.2 Loss of power to Swing Bus B-6 and Subsequent Loss of [hutdown Cooling On March 20, swing bus B-6 was being powered via the B, train 480 VAC bus B-2 through supply breakers B-202 and B-602. Upon completion of A train outage maintenance and . surveillance activities, preparations were initiated to transfer the swing bus power supply from the B train to the A train, via bus B-1 (through supply breakers B-102 and B-601).
In order to accomplish the transfer, a loss of supply power from bus B-2 is simulated by pulling its undervoltage relay fuse. This action should initiate the automatic transfer of the bus B-6 power supply from bus B-2 to bus B-1.
The transfer action is accomplished in a break-before-make manner, i.e., the oncoming circuit breaker cannot be closed until the interlocking supply L breaker is open. Circuit breakers B-202 and B-102 are in-terlocked and breakers B-601 and B-602 are interlocked similarly. All these breakers are General Electric (GE) model AK-2A-50 breakers.
Breaker B-602 tripped and breaker B-601 closed as antici-pated. However, breaker B-202 failed to trip, and the in-terlock circuit prevented creaker B-102 from closing.
This resulted in an open supply breaker from both bus B-2 and bus B-1.
Therefore, bus B-6 experienced a loM of power.
Several attempts were made to trip breaker B-202 via the control switch, its manual push button, and by applying pressure to its trip paddle.
All attempts failed. Mean-
while, the trip coil was energized continuously for a pro- ' longed period, causing the trip coil to become overheated.
] The licensee opened the 4160 VAC circuit breaker A-608 to ' deenergize bus B-2, so that breaker B-202 could be safely racked out for inspection.
The licensee managed to momentarily reposition the " prop" (see section 5.5) and manually trip the breaker.
Once breaker B-202 tripped, breaker B-102 immediately closed and power to bus B-6 was restored. The total time that bus B-6 was without power was about one hour.
l When the licensee opened circuit breaker A-608, bus B-2 lost power. De-energization of bus B-2 resulted in the interruption of the ultimate heat sink flow (due to loss of salt service water pumps "0" and "E"), isolation of secondary containment, automatic start of RBCCW pumps and isolation of drywell atmospheric and hydrogen / oxygen sam-pling systems.
These systems performed as designed.
Additionally, this action caused an anticipated loss of
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, ' shutdown cooling because the "B" train isolation valve, MO-1001-478, on the shutdown cooling suction line closed.
However, upon de-energization of the bus and subsequent loss of shutdown cooling, the residual heat removal pump failed to trip as designed. This is described in section 5.6.
Power to bus B-2 was restored when breaker A-608 was closed after breaker B-202 was racked out. The total time that shutdown cooling was lost was about 37 minutes. The temporary loss of thutdown cooling resulted in a reactor coolant temperature increase of approximately 5'F (from 95'F to 100*F).
' The inspector concluded that operations personnel took , , timely action to de-energize the failed breaker, to restore lost eiectrical power to buses B-2 and B-6, to trip "B" RHR pump when it failed to automatically trip, and to restore shutdown cooling (SDC) and other equipment as appropriate.
Operators also were making preparations to remove tags from "A" and "C" SSW pumps in case difficulties were encountered with restoring power to bus B-2, and to jumper across breaker 52-102 in case breaker 52-202 could not be opened (52-102 and 52-202 are interlocked to prevent both being ! closed simultaneously). The inspector concluded that the event had minimal safety significance in that decay heat was low and the SDC was lost for only a short duration (37 minutes).
l Although plant operations were effective, log keeping and shift turnover was observed to be deficient following the de-energization of 480 VAC buses B-6 and B-2 when the "B" RHR system pump failed to trip as designed upon isolation of the shutdown cooling suction valve.
No log entry was made to this effect until the maintenance request was signed several hours later; also this deficiency was not effectively turned over to the oncoming shift. The licen-see will brief the NWE on effective shift turnover.
The inspector reviewed the licensee emergency action levels and determined that the licensee appropriately classified this as a non-emergency event.
The licensee made notifica-tion of the system activations to the NRC Operations Center via ENS.
3.7.3 Group I Isolation on Sensed High Water Level , On March 11 the licensee experienced an automatic actuation of the main steam (Group I) portion of the Primary Contain-ment Isolation Control System due to a false high reactor water level signal.
This resulted in closure of the main steam isolation valves (MSIV's), sample line isolation i . O
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Uyl < ~ valves and the inboard main = steam drain valve.(M0-220-1)'. - The outboard main steam drain valve (MO-220-2) remained , opened. _ This event was properly ~ reported to the NRC Opera-tions Center via ENS.
The Group I actuation occurred while in hot shutdown with.
' 1 reactor pressure at about-10 psig and reactor moderator . temperature approximately.260 degrees F.
The licensee was . performing a plant shutdown when_ level, instrument LI-263-100B on-the main control board rapidly increased from 25
inches to_approximately 50 inches.
The sensed level in-crease above the Group I PCIS high level setpoint'of 48- ) inches with main stwn. line pressure less than 880 psig. ' resulted in the isoittion.
The licensee determinea that the actuation was= initiated by signals from level.trans-mitters LT-263-58A and LT-263-588, which share a common- _,J sensing line and.are both located on instrument rack 2206.
w , The licensee determined the most probable root'cause of the ' false high reactor vessel water level signal was air e trapped either inside the instruments and/or instrument-tubing which gradually expanded es the= reactor pressure decreased.
The licensee postulated that air _ bubbles trapped.inside the sensing 1ines downstream of the condens- ) .ing chamber may have migrated to a vertical section of tubing and began to rise.
This would result in a slightly less posil.ive pressure on the reference leg' side of the .
associated level-. instruments, causing.the change in dif_- " ferential pressure to signal a false _ hi.gh water level, and the actuation, , c.
Since the "A" side level instruments on instrument rack 2205 did not exhibit a similar herease,_ and the outboard
drain valve MO-220-2 remained open, the licensee considers ' that this confirms the "A" side instruments were not 1: affected.. No level increase or unusual occurrences were indicated with the "A" side instruments. Valve M0-220-2 is ', - controlled from circuitry on the "A" side not associated - with the affected instruments.
Yhe licensee Emergency and Plant Information Computer (EPIC) system was not available to analyze the event be- - ' cause the event recording softu re had stopped recording-approximately one hour prior to the Group I isolation.
This occurred because a trigger for event recording that tripped approximately 14 hours earlier had not been reset.
However, EPIC " Delta Data" information which provides in-formation on points that changed state (digital) or ex- .. ceeded a band (analog) was available and used to confirm l, level increases at the output of level transmitters on the r )
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, "B" side.
The traces also showed no level increases or unusual occurrences with any "A" side instruments. The licensee also performed an aneljais to support trapped air - -in the "B" side. reference leg as the most probable cause of the= false high water level signal.
Corrective action to prevent recurrence of the actuation- -included backfilling of the sensing lines with demineral-ized' water prior to restart from the outage to minimize the K amount'of trapped air in the sensing lines. Also, instru-ments on both the 2205 and 2206 instrument racks were cali-brated following replacement of the two excess flow check valves-(section 5.2).
Licensee investigation of this actuatioiwas apnropriate and thorough. Conduct of the critique by the Operations Department was excellent with an appropriate questioning attitude to determine what events occurred, their sequence and probable causes.
The inspectors will continua to moni-tc? this area during routine inspection.
3.7.4 Licensee Identified Violations The-licensee recently discovered several instances.in which, specific TS ~ requirements had not been satisfied. These discoveries were the result of-continuing improvement in- - the licensee ability to identify and correct potential and' existing nonconforming conditions.
Each event is detailed 1 below.
(1) Technical' Specification (TS) Noncompliances Due to Requirements Ipconsistent with Plant Design The TS 4.1.B requires that during reactor power opera-tion the maximum frettion of Pimiting power density (MFLPD) be checked daily.
Reactor power operation is defined in TS 1.0.H as any operation.with the reactor mode select switch in the startup or run position, the reactor critical and above one. percent-power.
However,-on February 28, 1990, the licensee determined that MFLPD had not been checked daily as required by TS 4.1.b for several days in February and March 1989, During the time period from' December 30, 1988 to Narch 3 1989 plant operation was limited to five percent T-power or less in accordance with the BECo power Ascen-sion Test Program.
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... s' ~ 12; < ' m Kg Investigation into the cause of this event identified that plant procedure 2.1.15, " Daily Surveillance Log" - i directed MFLPD daily checks when' reactor power exceeded ' ! ten percent rather than when reactor power exceeded one percent as required by TS 4.1.B.
The MFLPD is calculated by the plar+ process computer via the P-1 program.
The P-1 progi C,<which performs the MFLPD.
! calculations from data oto ined from the local power-
range monitors (LPRM), does not function below ten i percent reactor power. Therefore, the TS requirement to theck ytFLPD at greater than one percent power is inconsistent with plant. process computer design' cap- , abilitias.
! wS inconsistency with existing plant procedure and L plant design limitations would not be apparent.during ! routine plant startups because reactor power is typi-cally increased from one percent power to greater than 25% power in less than twenty-four hours.
However, ! from December 30, 1988 until March 3, 1989, when reac-tor power operation was restricted to five percent power or less, the unusual scenario in which noncompli-ance with TS 4.1.8 would occur wts established.
During the licensee investigation of the MFLPD issue, a second related TS non-compliance issue was identi-
.fied as a-resu3t of a thorough rev\\ew.
On March 23, 1990, the licensee determined that a TS amendment (Amend.nent 110) to 1S 3.2.C and Table 3.2.C-1 issued
in 1988 changed the operability requirements for the ' flow biased APRM scram and' block from the run mode l only to the run, startup-and refuel modes of opera-
tion.
Contrary to the requirements imposed by the amendment j to TS 3.2.C and associated table, the flow biased APRM li > scram and rod block are set down, and not-flow biased, '_ when the reactor modo select switch is in refuel or startup. The APRM scram is sat down at less than or equal.to fifteen percent power in accordance with TS , 2,1.A.1.b and is calibrated at thirteen percent power.
The APRM rod block set down is not addressed in TS and !' is calibraw d at eleven' percent power, The TS to check MFLPD daily at greater than one per- , cent power and the TS for flow biased APRM scram and rod block operability in'startup and refueling repre-sent requiremts for which the plant is not designed for or capab b of acce olishir.g.
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t ti no adverse safety significance to these events. Al-though not. flow biased, the APRM scram and rod block are set down'at thirteen and' eleven percent of reactor , power in refuel and startup.
In order to ensure TS compliance as well as TS con-l sistency with plant design, on March 30, the licensee
requested and was granted a_ temporary waiver of com-
pliance by the NRC to enable the reactor mods select + L switch to be placed in refuel or startup to facilitate ' ongoing outage surveillance testing until an exigent-TS change could be submitted and~ processed by the.NRR staff.
On Apri? 5, an exigent change was submitted .,
- which proposed to amend TS 4.1.b.to requ're daily
't MFLPD checks at greater than 25% power and to amend TS 3.2.0 and the associated table to delete the require. ment to have the flow biased APRM scram and rod block - operable in refuel and startup. The staff reviewed the proposed changes and on April 18 issued Amendment 129 to the Pilgrim Station Operating-license revising TS to appropriately reflect plant design.
The licensee identification and resolution of these - ' roblems was indicative'of a proper questioning. atti-tude.
I (2) Inoperable Primary Containment Isolation Valve
(PCIV) Position Not Verified Daily The TS 4.7.A.2.b.2 requires that whenever a PCIV that receives an automatic isolation signal is inoperable, the position of the isolated valve in each line having an inoperable valve shall be recorded daily.
On March 30, 1990, contrary to the' requirements of TS 4.7.A.2.b.2, the licensee determined that the position of at.least one of the inoperable series PCIVs.in the de-activated RHR head spray line had not been verified daily since the-head spray system was retired in place in March 1986.
The head spray line was terminated and capped outside containment via PDC 86-20 and PCIVs M0-1001-(RHR)-60 and M0-1001(RHR)-63 were closed and their respective circuit-breakers were deenergized.
' With power removed from the valves as designed they were ur,able to respond to automatic signals, were technically inoperable, and were without remote con-trol. room position indication.
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Following the implementation of PDC .l 86-20 plant procedures were revised to delete selected surveillance testing of the valves:and to delete other.
A procedurai a eps involving the valves or to annotate the steps with statements which indicated the valves were electrically disarmed;'therefore,'the actions were not applicable.
Continuing licensee investigation into the root cause of this event identified a suspended plant design change (PDC 86-528, FRN 86-528-21) that was intended to reroute the power cables to PCIV MO-1001-60 to com- - ply with 10 CFR 50 Appendix R fire zone separation requirements.
The PDC was issued tt route the-power e cables to MO-1001-60 such that they would not' traverse the same fire zones as in-series PCIV M0-1001-63,- i thereby preventing a single fire from simultanece 5 l impacting the power cables and operation of both '! PCIVs. This condition did not present a concern 'h ' . the head spray system since the valves were de-energized.
However, the licensee reviewed alL e n ems to ensure fire zone separation criteria were met. -The
review identified.an equipment qualification and Appendix R concern with the reactor head vent line series isolation' valves, A0-220-46 and A0-220-47.
l In November 1985, during the initial EQ program imple-J , mentation it was determined that a common terminal i block (on junction box J321) for-the head vent line i valves had not been qualified to the design bases post - accident environment. As a compensatory measure to , the EQ rule, the licensee proposed to remove the power
fuse to the head vent line valves whenever reactor , l~ coolant system temperature was g reater than or equal to 212 degrees F.
The same compensatory measure was later utilized to meet Appendix R criteria.
In 1985, L the fuse was removed under the control'of a mainten-p ance request.
The fuse was-subsequently reinstalled [ at an undetermined later date, most probably during an , l: ensuing plant shutdown _when RCS temperature was re-i ' ' duced'below 212 degrees F.
Since the licensee cannot determine when the fuse was reinstalled, it assumed as i a minimum that the fuse.has been in place since plant ! ' startup in December 30, 1988.
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> Each of these events identified by the licensee pre-sented minimal safety significance.
The RHR head spray valves, M0-1001-60 and M0-1001-63, are de-energized in the closed position. Additionally, the , valvos continued to be tested in accordance with 10 CFR Sb Appendix J leak rate, testing.
' The head vent line valves, A0-220-46 and.AO-220-47, >
are one inch _in diameter. Steam leakage resultant.
! from the spurious opaning of the head vent line valve, in a post accident e+/ironment.would have a negligible impact on the drywell temperature and pressure pro-files enveloped by steam line or recirculation line rupture inside containment anaylsis.
Spurious head vent valve actuation resultant from a postulated Appendix R fire requiring plant shutdown from'outside u the control room is also enveloped by existing design bases line breaks.
, > Licensee corrective actions to these events have been approcriate, Head spra> valve M0-1001-60 has been , chain iocked closed and the head spray line PCIV's i inoperability has been issued as an active LCO, there- ' by necessitating daily verification of M0-1001-60' position. Aaditionally, the MO-1001-60 power leads . were disconnected at the valve and its motor-control center. A plant design change was implemented which a re-wired the head vent line valves' control switches to insert a short across the solenoid valves' coils-in the closed position.: The-short will cause the power'
. fuse to blow if a hot short developes-as would be , postulated'in the EQ and Appendix R programs.
i y .With respect to continuing corrective actions, the Engineering Design Review Board reviewed all plant design changes that are currently suspended..No addi-
tional problems were identified by.the. review. A .i separate review of the EQ data files and the current revision of the " Appendix R Safe Shutdown Analysis" was conducted which also did not identify further-con- , L cerns, i Licensee failure to comply with TS 4.1.B (MFLPD), TS 3.2.0 (flow ' biased APRM scram and rod block with RMSS in refuel and start-L up), TS 4.7.A.2.b.2 (inoperable pCIV position verification), as well as 10 CFR 50.49 (EQ) and 10 CFR 50 Appendix R is a viola- " . tion of NRC requiremants. However, because each of these events were of minimal safety significance; were identified and pro-perly reported by the licensee; and because the licensee took prompt, comprehensive actions to address these events'and to
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16-preclude recurrence of similar events, a Notice of Violation will not be issued in accordance with the discretion criteria ' (10 CFR 2 Appendix C) Section V.G of the Enforcement Policy.
These events are identified as a licensee identified, non-cited violation (NC4 50-293/90-07-01).
Because licensee corrective actions to these events are complete and have been determined by inspector review to be adequate, this item is closed.
4.0 Security 4.1 Observations of Physical Security Selected aspects of plant physical security were reviewed during regular and backshift hours to verify that centrols were in accord-ance with the security plan and approved procedures. This review included the following security measures: guard staffing, vital and protected area barrier integrity, maintenance of isolation zones, and implementation of access controls, including authorization, badging, escorting and searches.
No inadequacies were identified.
5.0 Maintenance / Surveillance 5.1 Turbine Control Valve Testing Turbine Control Valve (CV) testing is performed monthly to verify the ability of the four control valves to smoothly close fully and to document stroke times for trending purposes.
Testing also aids in preventing a valve from sticking in a fixed position by exercising the operating mechanism.
During previous monthly CV testing, the Number 1 CV responded erratically when the test pushbutton was de-pressed.
While reducing reactor power in order to place the reactor in cold shutdown for the outage, turbine CV testing was performed at the 66%, 52%, 60% and 65% oower levels.
The regular monthly CV testing was pe,rformed in accordance with procedure 8.A.9-2, " Turbine Testing-Monthly" along with Temporary Procedure (TP) 90-021, " Turbine Control Valve Test Monitoring." TP 90-021 provided the ability to monitor several turbine generator control responses, including the control valve relay, speed relay, control valve cam, bypass valve cam, pres-sure regulator servo-motor and the number 1 CV test solenoid. This information along with EPIC computer data was used to analyze the cause of the CV erratic behavior.
- At reactor power levels greatcr than 60%, when the CV test pushbutton was pressed, the CV F s-
.e ' as expected.
The expected re-sponse was the the c.- . c.c ase smoothly, then re-open when the '
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During the test, all four of the CV's ex-
hibited errat'c behavior at greater than 60% reactor power in that
when the' test pushbutton was depressed, the valve hesitated, then . began to close.
In accordance with the procedure, each time a con-trol valve did not operate as expected, that portion of the test was aborted and the plant was stabilized price tu proceeding with-testing of the other CV's.
This CV erratic behavior only occured during testing, not power operation, , The licensee checked and made adjustments to the hydraulic controls during the outage. The monthly control valve test was reperformed during plant.startup following the outage at 65% power with no dis-crepancies noted..All control valves opened as expected within the required time period and opened smoothly. No discrepancies were { noted.
- 5.2 Replacement-of Excess Flow Check Valves As reported in Inspection Reports 50-293/89-12 section 5.2 and '50-293/90-05 section 6.1, during testing of the approximately 80 in-strument line excess flow check valves, one of the valves tested and which failed to actuate was a Dragon Valve (of which Pi1 grim had only l two installed).. Failure to verify the operability of the two instru-ment'line-excess flow check valves resulted in the licensee request . and the.NRC grant of Regional Temporary Waiver of Compliance until the start of the March outage.
Duiing the-March outage, the licensee replaced the two excess flow creck valves. The inspector observed portions of 'the work and re- ' viewed the Plant Desigt. Change and work package.
Pre-evolution F oriefings were conducted with emphasis to the control' room operators on what they would observe and the expected alarms. The operators
were attentive and appropriate questions and answers on the expected annunciators were noted.
'The inspector also interviewed maintenance personnel.
Individuals were knowledgeable of the work plan and its scope and good attention-
to-detail and independent verification of jumper installation was noted during performance of reactor vessel high water level isola-p, tion.
The lif ted lead and jumper log was appropriately entered.
Quality Control'(QC) and health physics personnel were observed at ' the job site and were cognizant of their duties.
QC holdpoints we e , observed as required and administrative approvals and prerequisites For the job were noted to be followed.
The two affected excess flow check valves were replaced with Dragon valves which. actuate at 1.5 to 1.8 gpm. The two excess flow check valves were bench tested by the manufacturer on November 6, 1989.
The check valves closed when flow reached 1-2 gpm and reset leakage L , 4i
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' o was 0.2 to 0.7 gpm, meeting the licensee acceptance criteria.
No discrepancies were identified and the inspector had no further ques-tions.
5.3 Local Leak Rate Testing During the spring surveillance outage, numerous containment isolation q valves were local leak rate tested (LLRT).
Check valves had reverse flow / exercise testing to comply with the requirements cf ASME Section i X I '. All eight main steam isolation valves passed the as-found LLRT.
, ' Four valves failed the test: these included (1) M0-1001-29B, "B" Loop RHR Injection Valve; (2) 6-58A, Inboard Feedwater Check Valve; (3) 6-62A, Outboard Feedwater Check Valve and-(4) CK-1001-688, "B" Loop RHR Injection Check Valve.
Each of the failed valves was disassembled, repaired and re-assembled, followed by successful reperformance of LLRT or hydrodynamic test, as ' appropriate.
In May 1986 the licensee experienced recurring "B" RHR di: charge l piping high pressure alarms indicating leal, age from the reactir coolant system past the RHR 1001-68B check salve and the M0-1001-29B valve into the RHR discharge piping. Wl an the check- ! valve was tested in August 1987, the valve disc wcold not seat. The valve ~was repaired,in 1987, i During performance of the hydrodynamic test this outage, the licensee was unable to pressurize the test boundary.
Af ter disassembly of the check valve, inspection revealed an approximate 0.030 inch gap be-tween the top of the valve seat and disc Dody and an approximate 0.018 inch gap at 90 degrees posi+1on on the valve seat. The disc had became misaligned when_the eccentric bushings left from previous-maintenance apparentiy rotated, causing the hinge pin centerline to move and the valve dist to move.
The seat was striking the body of - the valve, apparently dua to previously performed inadequate main-tenance.
The licensee re welded the old trunnion holes, replaced the bushings, hinge pins and gaskets.
Reperformance of the hydrodynamic test of the check valve was successful.
'M0-1001-298 failed the as-found local leak. rate test again this out-age. Due i.o a' LLRT failure history of the valve, the valve was re-placed in 1987 with a new Anchor-Darling valve.
Leak rate testing . performed in August 1987 following its replacement resulted in the , ' new valve failing the LLRT. The valve was flushed and subsequently " passed the LLRT with zero leakage.
An LLRT performed one year.later ?: in September 1988 resulted in the= valve failing the as-found LLRT at t 26 ~ standard liters per minute (sim) (acceptance criteria is 7,89 ' slm).
Flushing of the system resulted in the valve again failing the ' ' LLRT at 10'.5 sim. After hydrodynamic testing and flushing of the i ! =
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. t RHR dishcarge piping, reperformance.of the LLRT on the 2001-29B re-
sulted in the valve passing with a 5.0 slm leak rate.
No further evaluation of the reliability of the valve was conducted until the current outaga.
The licensee' began to experience reactor coolant system leakage into the RHR discharge piping again in the fall of 1989 (see Inspection Report 50-2?3/ 89-13, section 5.0).
During the current outage, leak
rate testing of M0-1001-298 resulted in as-found leakage of 32.82 ' sim.
Inspection of the valve revealed' severe scoring of the disc and a valve body seat. Adequate corrective actions to. prevent recurrence of leak rate testing failures and adequate root cause analysis of the repeated failures following the leak rate-testing in 1987 and 1988 - were not evident in this case.
Inadequate maintenance performed on the 2001-68B check valve in 1987 also contributed to recurrence of repeated intersystem leakage in late 1989.
In addition, repeated leak rate testing' failures of 1001-29B did not appear to result in further licensee invescigation-irto root cause analysis of why an improved newly installed valve repeatedly failed LLRT, Considering previous NRC and licensee con-cerns in the area of intersystem leakage at Pilgrim, there appears to , have been inadequate ro>t cause analysis of the repeated LLRT fail- ' ures of the 1001-29B vaive during 1987 and 1988 testing. However, maintenance performed during this outage to repair the_ valves appeared ~l to be adequate to prevent recurrence of past intersy.; tem leakage.
' Inadequate Root Cause Analysis was brought to the attention of Qual-ity Assurance Department (QAD) personnel. QA0 has identified _to the senior staf f and Nuclear Managers _ Committee at the plant that-there exists an underlying philosophy that if a problem: exists, fix the problem. Adequate root cause analysis is not always performed.to . prevent recurrence of the problem or event'. The inspector will. con-tinue to review licensee root cause determinations as well as track QAD activities in this area.
- . The licensee established an LLRT failure analysis team to unduct root cause analysis and recommendations to. correct the. failures per their commitment to the NRC in BEco letter #87-039 dated March 1, 1987. The inspector observed the team in progress.
Root'cause
analysis by the team appeared very detailed, frank and well conducted , and recommendations appeared appropriate.
Discussions with test personnel during the testing indicated they were knowledgeable of the procedure and its requirements.
Conduct and oversight of the LLRT and hydrodynamic testing by the licensee .' Senior Test Engineers was excellent, consuientious and continues to-be a noteworthy licensee strength.
Although inadequate root cause analysis was performed on the 1001-298 valve following repeated LLRT.
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failures and inadequate mai tenence was performed on the 1001-688-check valve, LLRT and maintenance performed this outage appeared ade-quate te prevent recurrence of intersystem leakage, 5.4 Observation of Automatic Depressurization System (ADS) Subsystem . Manual Opening of lelief Valves The inspector observed operations department personnel performance-procedure 8.5.6.2, " ADS Subsystem Manual Opening of Relief Valves," on April 25, 1990 f rom the main control room.: A pre-briefing was conducted by the watch engineer for all personnel involved in the test prior to actual performance. The pre-briefing was thorough and concise. The required plant conditions were established and-allowed to stabilize as required by the procedure. Actual testing of the , relief valves was orderly and all the required data was' recorded.
The procedure was completed satisfactory and no discrepancies were noted, 5,5 Loss of Power to Swing Bus B-6 (1) Event Background As' detailed in section 3,7.2, on March 20, 480 VAC breaker B-202 failed to trip open thereby preventing swing bus power transfer operations from being accomplished.
Upon removal of B-202 from its cubicle, the licensee closely ' examined the breaker and ob-served that the " prop" (see item 5 of figure 2, attachment II), which holds the breaker closed and interfaces with the trip latch roller assembly,: had slipped out of its support at one end.
The bearing, the shim washer, and the retainer ring were missing. The licensee located the bearing in the breaker cubicle; but could not locate the shim washer and the retainer ring, The bearing is normally held.in place by the shim washer and secured by the retainer ring. The " prop" is. located at the-bottom of'the breaker and is difficult to obse'rve.
The licensee shipped breaker B-202 to GE in Philadelphia, Pennsylvania for evaluation and repair. GE overhauled the bretker, replaced the burned trip coil, and installed the miss-ing prop bearing, shim washer and retainer ring and returned the breaker to Pilgrim.
Meanwhile, the licensee organized a task force to investigate the breaker failure event. The task force consisted of two teams. Team one was assigned ta investigate the root cause of the breaker B-202 failure, while the second team, working in parallel, implemented corrective actions to ensure that all 480 VAC breakers would function properly.
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During the-initial inspection of five 480 VAC breakers by the- -licensee, two additional retainer rings were found missing in two non-safety related breakers-(B-310.and B-402).
It was later determined that the loss of these rings did not affect the operation of the breakers.
The licensee contracted GE to in-spect all 57 of the 480 VAC breakers, consisting of forty AK-25 < breakers, thirteen AK-50 breakers and four AKF breakers.
The GE inspections were controlled under the licensee's Quality Assur-ance Program.
The final root ause analysis issued by the licensee on April 3, 1990 indicated that the root cause for the missing retainer ring and the shim washer was one of the following: 1) they were not installed during the 1987 circuit breaker overhaul; 2) they were installed improperly; or 3) the installed retainer ring failed i in service.
Since the retainer ring and the shim washer could not be. located, a definitive root cause could not be established.
The inspector reviewed three GE inspection and overhaul proce - dures and the inspection reports for seven breakers (B-201, B-206,B-503,B-505,B-603,B-702,B-705).
No deficiencies were identified in this review.
The licensee inspection and repair of all of the 480.VAC breakers was completed on April 19. No additional missing re-tair.er rings associated with the prop were identified.
However, two deficiencies associated with other retainer rings were noted.
For breaker B-102, the arc contactor arm pin retainer clip fell off during testing.
This retainer clip was found-later to be oversized. The pin apparently was kept in place by the arc chute, which was removed for the test. With the arc - chute in its normal position, this condition would not h?vt presented an operability problem.
For breaker B-701 ( nor. - ' . related AK-50 breaker), the charging cutoff switch pin retc - clip was discovered to be missing while the breaker was beln; installed into its cubicle, after the GE inspection. Without this retainer clip, the charging motor continues to run to charge the= spring once the power is made up to the breaker.
Therefore, this condition could be easily detected if_other breakers had this problem. The licensee postulated that this retainer clip probably fell off during transit between the tur-bine deck where the GE inspection of this breaker took place and the breaker cubicle. Because of this deficiency, the licensee re-inspected all AK-50 breakers and verified that the charging cut off switch pin retainer clips were properly installed.
The licensee made an assessment as to whether or not the inspec-tion program should be expanded to include 4160 VAC breakers and moldnd case breakers.
They determined not to include these two types of breakerscln the inspection program because: 1) molded .
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case circuit breakers are not overhauled or disassembled. When'a-malfunction occurs, they are replaced; 2) the 4160 VAC circuit _ breakers were previously everhauled to a more detailed instruc-tion manual'and procedure.than the 480 VAC circuit breakers in-ciuding: specific fastener size: and assembly steps. Further, the 4150-VAC circuit breakers are operated and tested more often-than the 480 VAC circuit breakers. This operation and testing.
would tend to identify any breakers with operability problems
resulting from the 1987 overhaul; and 3):the plant operating history of 4160 VAC circuit' breakers-is good and these break m use fewer retainer rings as compared to the 480 VAC breakers.
The licensee also had discussions with NRC headquarters and regional specialists regarding potential failure of General. Electric magne-blast circuit breakers. They discussed several circuit breaker failures due to bent retainer ring and shim washers, and broken prop reset springs,. The licensee stated tha; t5e 1987 inspection and overhaul of the 4160V-breakers by GE included attributes pertaining to these items.
.l The ~ licensee confirmed that tha following additional short term
corrective at.tions had been completed: 1) the t ripping and clos-
- init logic circuits for breaker B-202 were checked to verify that the as-found condition conforms to drawings; 2) the remaining three B6 trar.fer breakers (B-102, B-601 and B-602) were over-hauled.
The licensee succe;; fully tested'the charging and clos- , ing times on all four transfer breakers; 3) maintenance proce-dure 3.M.3-6 (opening timing test) and 3.M.3-35 (live bus trans-fer) for the breakers associated with the bus B-6-transfer scheme, successfully verified the automatic transfer functions ! ' twice in each direction; and 4) the licensee measured and re-corded the precharge tiae and closing time of breakers B-102, B-202, B-601 and B-602.
(3) Licensee Long Term Actions l The licensee investigation task force team summarized the re-suits of their investigation in memo MSM90-104 dated April 19, 1990 to the plant management. The team recommended twelve long , term corrective actions. These recommendations are currently .under plant management review and evaluation; the recommenda- !' tions have been endorsed by the Operations Review Committee.
The plant management will decide which of these recommendations i will be implemented and the implementation date.
This is an unresolved item pending NRC revin of licensee management's de-cision regarding the recommended long term corrective action (50-293/90-07-02).
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, d (4)- Circuit Breaker Maintenance
The scheduled maintenance ' frequency for the AK-50 breaker is once per refueling outage.
In addition, each breaker receives an overhaul (by GE) every five years.
The inspector discussed the maintenance frequency with the GE representative at the ' Pilgrim site. The GE representative confirmed that as long as the breakers are overhauled every five years,.the preventive maintenance frequency of once per oucage is adequate even if one - = outage can last much longer than the nominal 18 month cycle.
The inspector reviewed the three year maintenance nistory of circuit breakers 8-102, B-202, B-601 and B-602.
These breakers , ' were still within the once'per outage frequency because Pilgrim - , had a long outage during the 1986-1988 period.
(5). Previous Failure On March 12, 1990, an automatic transfer'of 480V bus B-6 from
bus 3-1 to bus B-2 was being performed in preparation of isola- , tion of the 4160 VAC bus A-5.
This was to enable required sur- ' veillance testing of 4KVAC protective relays. While performing .this transfer, breaker B-202 failed to automatically close.
The b ' remaining breakers B-601, B-602 and B-102 operated. properly.. In approximately one minute, after determining that breaker
B-202 had not automatically closed, the B-6 bus transfer was a , successfully completed by closing breaker B-202 via its local switch' located on Panel B-2.
No root cause analysis was performed for this event.
The licen-- see did not have a spare breaker to temporarily replace breaker B-202. Therefore, the dccision was made to wait until power was a ' transferred back to bus B-1, at which-time breaker B-202 could be racked out for inspection.
, (6) C_onclusion ar.d' Assessment TM failure history of the swing bus _ indicated that several ft.ilures had occurred. Deficiencies in the licensee root cause , ar ilysis of the previous events were noted.
In addition,.the licensee lacked spare breakers (safety-related) to temporarily rap % the affected breakers so that the af.ected breakers r could be examined in a timely manner.
The need for the spare breakers was identified by the licensee on the task force recom-mended long term corrective acticn list (memo MSM 90-10a dated , ' April 19, 1990).
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, , The licensee is evaluating implementation of recommended long I term, action #9 including updating maintenance procedures to in- , clude appropriate inspection attributes of GE breaker overhaul ' procedures.
. The inspector concluded that the licensee short term corrective-actions for the March 20, 1990 breaker failure event were ade- , quate. As stated above, long term corrective actions are con-sidered unresolved pending licensee management decision.
5.6 Failure of "B" RHR Pump to Trip upon Loss of Suction Path l , During the March '20 swing bus transfer failure, as described in sec-tion 3.7.2' bus B-2 was de-energized in order to facilitate safe manual ' - rackout of the B-202 breaker.
Upon de-energization of bus B-2, shut- > down' cooling suction valve M0-1001-47 closed as designed, Closure-of
MO-1001-47 resulted in the isolation of all' suction paths to the "B" g RHR nump, which should have initiated an automatic trip of the RHR ' pump. 'However, the "B" RHR pump failed to trip automatically but rather was tripped remotely by control room operators.
Licensee investigation of this event identified that a 1988 mainten-ance activitiy (MR 88-46-434, October 1988) impacted the operation of the local control switch'for the pump circuit breaker (A603) which l prevented the pump trip function from actuating.
, Licensee inspection of the circuit breaker cubicle during trouble-shooting revealed that a black lead (#7) was lif ted and taped.
Lic- -er.see review of the MR indicated that the In-Process Control Sheet (IPCS) had been revised-to include additional lifting of leads and did not discuss the original lifted leads of the IPCS. When the lifted leads of the revised IPCS were relanded the black lead (#7) was not relanded.
> Continuiag licensee investigation revealed that during performance of the job, the original IPCS inadequately identified which ' lead to ' lift to remove 125 volt de power.
Instead, several leads were lifted at different times in an attempt to remove the 125 VDC power and not in accordance with the procedure.
After several leads were lif ted and power remained, the IPCS'was revised to include the cccrect leads to lift.
However, the revised IPCS did not ideritify those leads pre-viously lifted and therefore d'd not provide to reland those leads.
Two of the three originally lifted leous were relanded but the third lead (black lead #'/) was-not relanded due to the inadequate IPCS.
In L addition to the inadequate procedure, review of both the original and revised IPCS was inadequate.
Furthermore, the licensee did not-implement procedure 1.5.9.1, "Lif ted Leads and Jumpers." The lifting of the leads was not entered into the lifted lead and jumper (LLJ) log, the lifting of the ori-ginal leads apparently occurred over several shifts (not within the . , j - - . . .
m ,if
e 7,
required one eight hour shift-limit) and the person requesting the e lifted lead did not ensure that all the conditions of the applicable steps requiring documentation were met throughout the duration of the LLJ. After the lifted and taped black lead was discovered, it was-relanded to its required location on the terminal board and retorqued , as required.
The licensee has initiated Management Corrective Action Request (MCAR) 90-03 based on the inability to control activities affecting quality.
The failure of the "B" RHR pump to trip was of minimal safety signi-ficance in'that the trip is designed only for. protection of the pump-and was immediately corrected by alert operator action. Several weakness 2s were demonstrated by the licensee in the lack of implemt.n-tation of the _lif ted lead and jumper lor,, the ' preparation and issu-ance of an adequate procedure and proceh re revision, and finally, the performance of the job. Activities affecting quality were'not-appropriately controlled as required by 10 CFR 50 Appendix B and the Boston Edison Quality Assurance Manual. Pending licensee review of the activities surrounding the lifting of the lead and not relanding - the lead, including whether effective corrective actions are in place to prevent recurrence, this item is unresolved-(UNR 50-293/90-07-03).
6.0 Engineering / Technical Support , 6.1 - Installation and Testing of Modifications The inspector reviewed two Plant Design Changes (PDC) which were undergoing installation testing. A verification of the installation for. PDC 86-10', " Extended Test System" was performed.
The purpose of this system is to inject hydrogen into the feedwater system to reduce Intergranular Stress Creck Corrosion of primary components.
The in- , spection. consisted of a verification of system installation to selec-tively verify the installed hardware conforms to the as-built draw-ings. The verification process included confirmation that equipment model, dimensions, materials, including mounting details were cor-rect, A selective verification of the system installation found that the system had been installed in accordance with design documents.
Documentation for-installation was found to be detailed and complete.
Drawings reviewed were found to be accurate and had been entered into the plant configuration control system. The quality of,corkmanrhip for the ins W11ation of this system was good.
Preoperation test review and witnessing was performed for PDC 86-10, " Extended Test System" and PDC 83-51 " Emergency and Plant Information-Computer".
The inspection included discussions with test personnel, selective observations of test activities in progress, and review of documentation of testing already completea. The preoperational test procedures reviewed adequately demonstrated the capability of the system to meet predetermined performance requirements. The test pro-cedures were detailed and technically sound.
Personnel performing the tests were found to be knowledgeable of test requirements and l l I L__ a_:=_ _ _ =.. - - -- _
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' . 26-e
! cognizant of the system configuration. A review of performed test nrocedure steps indicated that the procedurcs were being followed and ' vr.umentation was complete.
The licensee r.rogram_ to have a desig- -nated. modification test engineer write-tert procedures as well as be responsible for the test performance was noted as a program strength.
6.2 Rosemount Transmitte-s (NRC Bulletin No. 90-01) _i . The inspector conducted a preliminary review of licensee activities with respect to-Rosemount transmitter issues described in NRC Bulle-tin 90-01', " Loss of Fill-Oil in Transmitters Manufactured by Rose-a mount." The licensee is currently formally tracking the performance ' of 73 Rosemount model 1153 transmitters installed at Pilgrim.- Tv date six transmitters have been replaced which exhibited fill-oil leakage drift behavior. One of the six failures was determined to be a response time failure, which failed within the licensee estaolished window of failure probability calculated by drift-tracking.
These ~ six transmitters were manufactured from what has been previously
identified in the bulletin as a non-suspect lot. This information- ' was' forwarded to the NRC Bulletin Technical Specialists.
The licensee has established an effective program to ensure proper-identification and tracking of Rosemount transmitters.
The inspec-tors'will review the licensee formal response to the bulletin upon . ' submittal.
The inspector had no further questions.
, 6.3 (Closed) Unresolved Item 85-35-02: Environ.nental Qualification Documentation Files Incomplete NRC Inspection Report 50-293/85-35 revealed that the licensee En- 'i vironmental Qualification Documentation Files (EQDF) for the C158 Alternate Shutdcwn Panel did not reference or include the documenta-
tion necessary to conclusively prove qualification for the General: Electric Type EB-25 terminal blocks in the panel.
The inspector con- ' firmed that the Equipment Qualification Evaluation Sheets for Alter-nate Shutdown Panel C158 (Revision 4 Sheets 1-8) now include the documentation required to demonstrate qualification for the EB-25 . terminal block.
This item is closed.
7.0 Safety Assessment / Quality Verification 7.1 Licensee Event Reporting The inspector reviewed the Licensee Event Repcrt (LERs) listed below to determine that with respect to the general aspects of the events: (1) the reports were submitted in a timely manner; (2) descriptions of the events were accurate; (3) root cause analyses we're performed; (4)- safety implications were considered; and (5) corrective actions implemented or planned appear sufficient to preclude recurrence of-similar events.
i
. ~_ _ _ IP' ! . .
'4 . 27' B "g 7.1 '.1 LER 90-01 %; * LER 90-01,'"Two Reactor Coolant System Instrumentation
Excess. Flow Check Valves Inappropriately Verified Operable a During Testing," addresses the February 9,1990 licensee determination that two instrument line excess flow check -, valves had not been adequately verified-to be operable , during November 1989 surveillance testing.
This event was.
previously documented in section 6.1 of IR 50-293/90-05.
Additionally, a Notice of Violatiun (90-05-01).was issued and an.unresolycd item (90-05-02) was identified in IR 50-293/90-05 regarding this event. The-LER provided an ,- extensive event description as well as.a comprehensive analysis of the design bases, including. failure conse-quenses, for the affected excess flow check valves.
Imme-diate compensatory measures and corrective actions were i also addressed.
However, casual analysis utilizing the , Human Performance Enhancement System and any resultant
-corrective actions will be repcrted in a supplemental LER expected to be issued on or before June 1.
7.1.2 LER 90-02
LER 90-02, " Contrary to TS, MFLPD Not Checked and APRM Rod Block 1Not Flow Biased in Refuel and Startup," addresses recent licensee discoveries that the above TS core monitor-ing requirements ~could not be accomplished due'to the limitations of plant system designs.
These events are documented in detail.in section 3.7.4 of this report. The LER vas well developed and-fulfilled the above criteria.
7.1.3 LER 90-03 -! LER 90-03, " Automatic Closing of the Group 1 PCIS Valves Due to a False High Reactor Water Level Signal During Shut-down," addresses the March 11, PCIS Group 1 isolation from ,
an apparent false high reactor water level signal.
This ~ event is documented in detail in section'3.7.3 of this re-port, Because the cause of this event can not definitively be attributed to entrained air the inspectors will increase observation of reactor water level instrumentation perform-ance during future reactor startups and shutdowns.
The LER fulfilled the above reporting criteria.
7.1.4 LER 90-04 LER 90-04, " Local Leak Rate Test Results of Two Feedwater Check Valves in Excess of Limits," addresses the failure of the "A" feedwater line containment isolation valves to pass the "as-found" local leak rate test during the current i i t
a - -
- , .1 4: , if k .1 '
. . surveillance outage. This event as well as a review of the
local leak rate test progren is documented in detail in j ' section 5.3 of this report.. This LER provides comprehen-- sive root cause analysis and corrective actions. Addi-i tionally, the LER appropriately identifies a similar occur-rence reported in LER 86-17-01.
. .7.1.5 LER 90-05
- -
i LER 90-05, "GE Type AK-2A-50 Circuit Breaker Did Not Trip Due to Latch Prop Misalignment," addresses the March 20 unseccussful swing bu: supply power transfer.
The transfer' ( ' was_ unsuccessful as the result of the failure of a~ supply-ing breaker, 52-202 (GE AK-2A-50), to trip open.
This event and subsequent licensee actions are documented in k detail in section 5.5 of this report.
This LER is a pre-liminary report with initial event discription abstract only. The licensee will submit a supplemental eport at the conclusion of their investigation into this avent.
The inspector had no questions regarding this LER.
, 7.1.6 LER 90-06 The LER 90-06, " Position of Primary Containment Isolar. ion Valve Nct Recorded Daily as Required By Technical Spec'fi-cations," addresses.the March-30 licensee determinatior that-the position of at least one of the two'inoperablo primary containment isolation valves in the ~ RHR' head spray
line had not been recorded daily as required by TS since the system was retired in place in 1986.
This event is discussed in detail in section 3.7.4 of this report._ This LER is' extremely well-developed.
The report provided a corrprehensive chronology of the. initial' concern regarding
the head spray line PCIVs as well ms the resultant EQ and-
Appendix R concerns regarding the head spray line and' head vent line reactor coolant system pressure boundary valves.
This LER fully addresseJ the reporting criteria above and l appropriately identified a similary event reported by LER L 90-01 (see 7.1.1 above).
' 7.2 ' Review of General Electric (GE) Inspection Activities The inspector observed the inspection activities performed by the team of GE service personnel on the 480 volt AK type (AK-2A-25, AK-2A-50, AKF-2A-50 and AKF-2A-75) metal-clad circuit breakers (CBs).
, Two GE teams performed the inspections, one during the day shift and l- ' the other during the _r.ight shift.
The purpose of the CB inspections L' was to review the physical condition of the CBs and to identify-miss- ' ing hardware items such as snap rings, starwashers, spacers and lock nuts.
In addition, the GE inspections verified the CB operability l .
_ .
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i and measured the_ insulation resistance and over-current trip set I points.
The GE personnel used procedures which_were approved by the
~ licensee to document the results and the-licensee Quality Control ! (QC) staff witnessed and verified that the pre-determined QC hold ' points were satisfied. The inspector selectively observed the in-spection activities and determined the following: 1) the in;pections .! were' performed in accordance with procedures approved by the lic>n-see; 2) all parts that needed grease were cleaned prior to the ' application of the new grease; 3) measuring instruments with current-calibration were used during electrical tests; 4) post-inspection: ! tests were performed to. verify the' acceptable operation of'the CB and- ., that the CB opened at the selected trip set point; and 5) the inspec-J tion findings were adequately documented.
The inspector reviewed the records associated with the GE inspection of the CBs. The inspector verified that the licensee had issued a maintenance work request for each CB inspected. The results of the.
inspection were documented on maintenance work plans.(MWPs) and on ' in process control sheets (IPCS) 1 and 2.
These MWPs included the .i following attributes: 1) required a review of documents, procedures i and drawings for latest revisions; 2) required a pre-job briefing; 3) recorded the serial number of the CB on the IPCS; 4) performed a visual inspection of the hardware and performed post-maintenance - checks as' outlined'in the IPCS.which included mechanical and elec-t trical; checks; verification of the tripping torque, and close and j trip anti pump features; and measurement of insulation resistance of-the main contacts; and 5)-verified that any parts replaced were acceptable by QC'and recorded on the IPCS.
t The inspector reviewed the results of the GE inspections and deter-mined that several deficiencies were repetitively. identified.
For example, several CBs had missing flat washers and star washers; had ordinary hexagonal nuts installed instead of lock 1 nuts; and had missing spacers and spacer bolts at the location where EC-type over-current tripLunits were used.
The inspector reviewed seven-NCRs in- 'itiated to document these discrepancies.
Based on this review, the inspector concluded that'both the licensee and GE had reviewed all the NCRs and provided adequate justification to successfully operate 'the CBs with the identified discrepancies.
The NCRs are summarized below: (1) NCR 90-084 documented that a bolt, flat washer, lock nut and a spacer were missing on CB B-106. The missing hardware was in-tended to fasten an auxiliary switch.
There was no auxiliary switch on this CB. The licensee intends to install the missing spacer during the next refueling outage.
, (2) NCRs 90-94, 90-95, 90-97, 90-77 documented a missing spacer on CBs B-104, B-103, B-105 and B-402.
The spacer was eliminated when the EC-type over-current trip device was replaced with a L b, . . .
.. . 3: 1 _ l-e.
, Micro Versa Trip Unit during the previous refueling ~ outage.
The missing spacer and spacer bolts did not a/fect the operability > o of.the CBs.
! - (3) NCR 90-68 documented that the hardware for CB B-406 was 'ncor-rect.
GE-evaluated the hardware and determined that the inspec- . tion instructions were incorrect and that the hardware was cor-- rectly installed.
The instructions used for the inspection of , CB B-406 were unique'to this CB and had not been used during inspections of the other CBs.
, . , -(4) NCR 90-70 documented hardware deficiencies in CB B-204B.
In addition, the eccentric bushings.were found to be oriented in the in:orrect direction and one of the two auxiliary switen con-tacts had to be cleaned to reduce the contact resistance.
" Based on the activities witnessed and'the documentation re-
viewed, the inspector concluded that the GE inspection activi-
ties were conducted in an acceptable manner.
The inspector had.
' no outstanding concerns in this area.
L 8.0 Review of Periodic and Special Reports Upon receipt, the inspector reviewed periodic and.special reports submitted pursuant to Technical Specifications.
This review verified, as applic-able:. (1)-that the reported information was valid and included the NRC-required data; (2) that test results and supporting information were con-sistent with design predictions and performance specification; and (3).that . planned corrective actions were adequate for resolution of-the: problem.
The inspector also ascertained whether any reported information should be classified as an abnormal occurrence. The following reports were reviewed: Monthly Operational Status Summaries.for February, March 1990 -- Operations Review Committee and Nuclear Safety Review and Audit Com- -- mittee Meeting Minutes . t 9.0- Management Meetings At periodic irtervals during this inspection, meetings were held with senior plant' management to discuss the findings. A summary of findings for the report period was also discussed at the conclusion of the inspec-Ltion and= prior to report issuance. No proprietary information was identi- -fied as being included ir the report.
Additionally, on March 29, a management meeting was conducted in the a Region I office to discuss licensee actions relative to the February 9 < - licensee determination that two instrument live excess flow check valves 'had not been properly verified to be operable as required by TS. The " licensee also presented the final status of metallurgical evaluation for the salt service water pump discharge column brittle fracture. These .
!
&
< + .: . r ' ., 31' i ' , -. . -
- 1 events' were documented in detail in IR 50-293/90-05 dated March 28, 1990.
The :-. . . eval. licensee presentations were very comprehensive'and indicated extensive
uation and depth of subject knowledge. The video slides utilized by the licensee during the presentations are identified in Attachment III to ' r- 'this report.
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u o, .- .- , ,- .- . -:,. ATTACHMENT I CHRONOLOGY OF PLANT EVENi: Date-Time Description i March 9 7:53 pm Commence reactor shutdown via recirculation _ pump' l i Match 10 Turbine-control' valve testing "A" recirculation
pump M-G set tripped ' March 11 4:50 am Main turbine off-line-5:14 am-Mode switch to startup 6:25 pm Group I isolation; ENS notification March 12-Unsuccessful automatic transfer of swing bus i B-6; circuit breaker B-202 failed to trip l ! March 13 Commenced isolation of instrument rack 2205 to replace excess flow check valve
March 15 ENS inoperable; notification via commercial L system . March 20-De-energization of 480 volt buses B-2 and B-6; i temporary less of shutdown cooling; ENS notification ' March 21 7:00 pm Completion of Key Event 1, "A" side surveillances , and maintenance complete LApril 15 Completion of Key Eventl2, "B" side surveillances and maintenance complete
! April.16 4160 VAC emergency bus A-5 and 'e6 loss of' voltage and degraded voltare test.
. April 21 Completion of Key Event 3; integrated testing , April.24 1:40 am Modo switch to startup commenced reactor startup 3:10 am Reactor critical April-28 3:42 am Mode switch to run 6:33 am Main generator synchronized to grid-
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> , TECII SPEC - REQUIRES OPERABILITY VERIFICATION ONCE/ CYCLE
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. 12/87 NEW VALVES INSTALLED . 7/88 INSITU TEST WAIVED - ! SATISFACTORY ASME-TEST AT MFR - ASME CGDE MFR (DRAGON)
- i VALVES AS INSTALLED SATISFY MISSION l - SAFETY SIGNIFICANCE MINOR - I i 'I I , , i ' . , .. ..- .
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11/88 TECH SPEC CLAR1,' CATION CHANGED . SURVEILLANCE DUE DATE-FROM RFO-8 TO 10/89 l EXCESS FLOW CHECK VALVE DUE DATE - RESCHEDULED FOR OCTOBER 89 OUTAGE 11/3/89 EXCESS FLOW CHECK VALVE TEST CONDUCTED i . FOR 80 CHEMIQUIP VALVES - 2 DRAGON VALVES i i NOT TESTABLE INSITU l ( ' . i 11/4/89 TEST OF TWO DRAGON VALVES WAIVED - . DETERMINED NO TEST REQUIRED BASED ON 7/88 [ I ENGINEERING' MEMO
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FAILURE AND MALFUNCTION PROCESS !
' I r I l PROCESS REVISION ! . ' -
.:.; t i $ F&MR REVIEW l . i i
i , ,
! ! i d " f p ' t ! i ,, = - - - - - . . - - - -. _, . = - - . -. - .
_ _ _. __ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ __ - _ .. - ..- .. - ... ... , , ., "' ..
t TECH SPEC CLARIFICATION PROCESS -
i
' a PROCESS WORKED AS INTENDED . , CURRENT CLARIFICATIONS REVIEWED . , ' ! . I i . j i ! $ h
1 t l
! ^ ' '~ .----- - L::X ^'~. . - = -. .
' . _
- .- - .. ~. - _ . - ! EXCESS FLOW CHECK VALVE SUPE 4ARY- ~ l PLANT SAFETY. SIGNIFICANCE PROPERLY j . CONSIDERED THRU OUT ,
HEIGHTENED ORGANIZATIONAL AWARENESS ! . i CURRENT PROCESSES ENSURE PROPER
. f COMPLIANCE REVIEWS CONTINUED IMPROVEMENT VERIFIED AND ! . RE-ENFORCED THRU PEER EVALUATION PROCESS AND'MGT SURVEILLANCE PROGRAM l ! i ) !
- I ! i ' ! , , _ . ' ! , . -.. . .- . _ . - - - -.... .. - ~ - .... . .
jg99 37 ~ - - ' - - .- . .- , -
. . a !
SALT SERVICE WATER PUMP . COLUMN STATUS l ! . i
i !
! ! - ! -l
! . R. V. FAIRBANK
- NUCLEAR ENGINEERING MANAGER !
BOSTON EDISON COMPANY ! MARCH 29,1990
. I ! - - _-- x- _ . ... . . ... _
- - - . .. .
-
- - - - =. - y . . 2- , ' ' .; ! > ' , SSW PUMP COLUMN STATUS ! (3/29/90) l
l
1.
OVERVIEW AND CONCLUSIONS
i 11.
EVENT DESCRIPTION a 111.
METALLURGICAL EVALUATION l h IV.
LONG TERM CORRECTIVE ACTIONS V.
SHORTTERM MITIGATING ACTIONS VI. CONCLUSIONS j l !
< f i f l - t
~ ~ . . __ ! ' - . ..
, BOSTON EDISON IS AGGRESSIVELY RESOLVING - . SSW. PUMP COLUMN FRACTURE ' !
BECO RESPONDED RAPIDLY AND THOROUGHLY i . l
REDUCED PROPERTIES FOUND IN ONLY ONE COMPONENT ) .
DEALUMINIFICATION AND WELD PROCESSES CONTRIBUTED TO . COLUMN FAILURE a ! LONG TERM SOLUTION IS AN ALLOY CHANGE .i . SHORT TERM MITIGATION IS STRESS REDUCTION AND FUNCTIONAL .
INTEGRITY ASSURANCE I , OPERABILITY REQUIREMENTS HAVE BEEN CONTINUOUSLY MET . !
I L CONCLUSIONS ! i - I ' ,_ .,. _ _ , _ .
- .- ., . , ' . . . . n- - , .
- 4-TYPICAL PUMP DRAWING
~ <
r
Pump u g ow ( J N l " Discharge [ Head . - . . .w . - vc , . @ ss24- ! .
.
- J.
! "W f @ p memes q , ! > E@ High Water , -- - -. , .y _ _ . . . - og. g-1
O
! , ) mBreak Location - g 'on Pump A , - ' ' h g.
Low Water {_ _. f
__ . ! { 9 is- ' ! , t , 4331* Pump Impen= l , - i 11.
EVENT DESCRIPTION ! . f . y m '==_a 4'w-T.%- - ,,r y, ,,, ,_ _ _ _ _ _ _ _. _ _ _ _ _ _ _ _j__, -
, - .- . . g
5 f SSW PUMP 'A' COLUMN 642D'
" . f FRACTURED 1/11/90 . , l l DROPPED DURING TRANSPORT - BRITTLE FRACTURE AT HIGH STRESS LOCATION - PRE-EXISTING FLAW FROM EARLIER WELD REPAIR NOTED - INITIAL CONCERNS AGGRESSIVELY PURSUED: ) - BRITTLE MATERIAL I OPERATIONAL STRESS LEVELS t SEISMIC LOADS OPERABILITY OF OTHER SALT SERVICE WATER PUMPS J POSSIBLE INDUSTRY CONCERNS i ASSESSING OPERABILITY OF THE REMAINING SSW PUMPS WAS- ! IMMEDIATE PRIORITY- ! . ! ! ! N.
MM EEmm
. . . - . ,- . . ' BASIS FOR OPERABILITY WAS REASSESSED - ) THROUGHOUT INVESTIGATION . INITIAL DETERMINATION BASED UPON ANALYSIS . i !
MECHANICAL PROPERTIES , . ALLOWANCE FOR BRITTLE MATERIAL ! s ANALYTICAL APPROACH ENDORSED BY DR. WILLIAM COOPER, . TELEDYNE ENGINEERING SERVICES l t NDE AND DESTRUCTIVE TESTING SUPPORTED OPERABLE STATUS j - STRESS MARGINS IMPROVED BY MITIGATING ACTIONS . !
I s i 11. N DESCRIPTIOfil
a .. ._ _ _ , _.
._ _ . .,. _ _ _
- - - - - -. - - - - - - - - - - - - - - - - - - - - - - _ _ - - - - - - - - _ - - . . - -
- ., - , . l - 7.
. , METALLURGICAlilNVESTIGATIONS ' I
- WERE EXTENSIVE
- TENSILE, AND HARDNESS TESTS !
i RADIOGRAPHY - SAMPLE EXAMINATION UNDER MAGNIFICATION - t CHEMICAL ANALYSIS- - , ~ i FRACTURE TOUGHNESS - ! ! ,! i I I
! i !
, W. METALLURGICAL EVALUATION i . .-. .- - . . ... . ..
. , . - - ~ .[ e El DEALUMINIFICATION
a ! q i SLOW COOLING DURING CASTING CAUSES EUTECTOID PHASE IN - . ALUMINUM BRONZE ALLOY t INTERCONNECTED EUTECTOID IS SUSCEPTIBLE TO . DEALUMINIFICATION THROUGH THE SECTION THICKNESS , ! DEALUMINIFICATION IS A PROGESSIVE CORROSION PROCESS ] . - EMBRITTLEMENT ~ - REDUCTION OF STRENGTH DEALUMINIFICATION OCCURS IN SEAWATER ENVIRONMENT ! M. METALLURGICAL EVALUATION j
- - t -
- -
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-! .i ' ! h , MATERIAL WITH REDUCED MECHANICAL PROPERTIES ' ! ! ! - - .!
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! , Figure 31.
Microstructure near tensile 1. a low mechanical property j material.
Inner surface of casting at top.
Corrosive attack has occured. Crain size smaller, more patches of pinkish eutectoid.
I Mount No. 9958 Mag: 226X l
M.METALLURG8 CAL EVALUATION l j , ! !
.. .
. _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ___ _ _ . . - . .- . ,
l - MATERIAL WITH EXPECTED MECHANICAL PROPERTIES i ! ..g u-- ..,
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i Figure 55. Columnar cast-grains at opposite end of 80" pipe { frot. fracture. Inner surface at left shows very slight attack.
l l Eutectoid areas are small and widely dispersed. Grain bounda- { ! ries are clean. Good Material. Mount No. 9%5 Mag: 226X j
h l E. METALLURGICAL EVALUATION t !
-
! I I !a 4. ,_,,_m._ _., . . , _ . __.. ___, .,,...__,__.,_...,..,-____.._,_m._._,,..
- - - - ._ _ _ _ _ __ . . _ ^ . ...-
j ROOT CAUSE ANALYSIS SUPPORTS CONTINUED ' - OPERATION / RESTART i i FRACTURE ZONE TENSILE TESTS EXHIBITED REDUCED TENSILE - STRENGTH AND PERCENT ELONGATION ! REDUCED MECHANICAL PROPERTIES LIMITED TO VICINITY OF - FRACTURE ZONE , ) PRE-EXISTING CRACK (PREVIOUS WELD REPAIR) IDENTIFIED AS - FRACTURE ORIGIN , ! ! , LAB TESTS DETERMINED ROCKWELL "B" HARDNESS TESTS DETECT
. ! MATERIAL HAVING REDUCED PROPERTIES I l FRACTURE TOUGHNESS TESTING AND ANALYSIS ESTABLISHED THAT - ! CRITICAL FLAWS ARE READILY DETECTABLE BY VISUAL OR LIQUID PENETRANT EXAMINATIONS . ! i ! HL METALLURGICAL EVALUATION J i J . .-. ._ .. -. . ...
-
- .__ _ _ ___. . _-_-_____ . ~ . , - . . w ! - LONG TERM SOLUTION - , MATERIAL REPLACEMENT
NEW COLUMNS MADE OF HEAT TREATED NICKEL ALUMINUM BRONZE
- ON ORDER ! ! - NICKEL STABILIZES ALUMINUM BRONZE ALLOY, REDUCES
i AMOUNT OF EUTECTOID FORMED l - REDUCE 0 EUTECTOID MEANS LESS DEALUMINIRCATION l - HEAT TREATMENT ENHANCES CORROSION RESISTANCE NEW COLUMNS ARE ON SCHEDULE . - FIRST SHIPMENT OF SIX EXPECTED MID APRIL 1990 l - SUBSEQUENT SHIPMENTS (LOTS OF SIX) EXPECTED AT ONE ! MONTH INTERVALS t ! ! ! REPLACEMENT SCHEDULE ESTABLISHED .
! i i IV. LONG TERM CORRECTIVE ACTION ! I 't
l3a ii i u ii i ,- '. . , . PUMP "A" WAS COMPREHENSIVELY TESTED HARDNESS - ULTRASONIC - RADIOGRAPHY - VISUAL INSPECTIONS - LIQUID PENETRANT EXAM - HYDRO - NO OTHER CRACKS - NO MORE MATERIAL HAVING REDUCED - PROPERTIES V.SHORTTERR8 R8tT9 GATING ACT9000S _ ..
.,,,, .... .. '
PRIOR TO INSTALLATION PUMP "A" - SAFETY MARGINS WERE INCREASED COLUMN TIE-RODS ON UPPER SIX COLUMNS - TRIPOD STABILIZER AT LOWER END (2 OF 3 ARMS - INSTALLED) REDUCES MAXIMUM COLUMN STRESS BY FACTOR OF TWO - i V.SHORTTERR8 RAITIGATING ACTIONS
~ ~ o .
SAFETY. MARGINS ON OTHER SSW . PUMPS WERE INCREASED PUMPS "B", "C", AND "E" - - VISUAL INSPECTION - ULTRASONIC TESTING - HARDNESS TESTING - NO EVIDENCE OF MATERIAL HAVING REDUCED PROPERTIES-TIE RODS ON UPPER SIX COLUMNS-TRIPOD STABILIZERS PUMP "D" o - VISUAL INSPECTION UPPER THREE COLUMNS - HARDNESS TESTING OF ACCESSIBLE LOCATIONS - NEW (1987) COLUMNS IN UPPER FOUR POSITIONS-TRIPOD STABILIZER - WILL BE PULLED / INSPECTED AFTER CURRENT OUTAGE V.SHORTTERRE R8ITIGATING ACTIONS
. . . ~ ,..,.l '
- ,3 SSW PUMP CONCLUSIONS i (3/29/90) BECO RESPONDED RAPIDLY AND THOROUGHLY .
REDUCED PROPERTIES FOUND IN ONLY ONE COMPONENT . DEALUMINIFICATION AND WELD PROCESSES CONTRIBUTED TO . COLUMN FAILURE LONG TERM SOLUTION IS AN ALLOY CHANGE - l i i
SHORT TERM MITIGATION IS STRESS REDUCTION AND FUNCTIONAL - i INTEGRITY ASSURANCE j s.
OPERABILITY REQUIREMENTS HAVE BEEN CONTINUOUSLY MET . L ! ! VL CONCLUSIONS , i ! t ' ,
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