IR 05000387/1986002
| ML20202F356 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 03/27/1986 |
| From: | Strosnider J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20202F297 | List: |
| References | |
| 50-387-86-02, 50-387-86-2, 50-388-86-01, 50-388-86-1, IEIN-86-013, IEIN-86-13, NUDOCS 8604140145 | |
| Download: ML20202F356 (17) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No /86-02; 50-388/86-01 Docket No (CAT C); 50-388 (CAT C)
License No NPF-14; NPF-22 Licensee: Pennsylvania Sower and Light Company 2 North Ninth Street Allentown, Pennsylvania 18101 Facility Name: Susquehanna Steam Electric Station Inspection At: Salem Township, Pennsylvania Inspection Conducted: February 3, 1986 - March 14, 1986 Inspectors: R. H. Jacobs, Senior Resident Inspector P1 co.jpesidentInspector Approved By: Jz c dddr3 -
27/86 Strosnider, Chief, Reactor Projects date Section 18, DRP Inspection Summary:
Areas Inspected: Routine resident inspection (U1 - 111 hours0.00128 days <br />0.0308 hours <br />1.835317e-4 weeks <br />4.22355e-5 months <br />; U2 - 70 hours8.101852e-4 days <br />0.0194 hours <br />1.157407e-4 weeks <br />2.6635e-5 months <br />)
of plant operations, licensee events, open items, surveillance, Information Notice Followup, Unit I refueling outage and maintenanc i Results: The inspector noted that the drawings and procedures related to the ,
SLCS need to be revised to reflect the current configuration for the squib i valves (Detail 6.1); an RHR pump was operated without cooling water due to )
valve misalignment (Detail 7.3); and indications were discoverad on some '
invessel components and are being reevaluated (Detail 7.5).
Two violations were identified. One violation concerned a configuration change that was made to seismically qualified panels without a proper safety evaluation (Detail 2.2). The second violation concerned the installation of an expired squib valve in the SLCS (Detail 6.1).
ENWD4140145 Ehb0404 PDR ADOCK 05000387 G PDR
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DETAILS 1.0 Followup on Previous Inspection Items
- (Closed) Violation (387/83-03-02): Standby Gas Treatment System Inoperable In March 1983, the licensee reported that both trains of the Standby Gas Treatment System (SGTS) had been inoperable for a period of l
about 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The inoperability resulted from improper equipment blocking. The contributing causes of the violation were confusing schematic drawings used to generate the blocking, inadequate alarm response procedures, and operators not agressively pursuing alarm An enforcement conference was held and PP&L was issued a civil penalty for this occurrenc The licensee instituted the following corrective actions to prevent recurrence. Training sessions were conducted with each shift to address all aspects of the even Plant management conducted a daily review of operator logs for two weeks to emphasize proper log keeping practices. The affected alarm response procedures, AR-24-001 and AR-30-001, were revised to identify the inoperability
- of the SGTS train when a loss of control power occurs. Eighteen other alarm response procedures concerning loss of instrumentation power were also revised. Actions were also taken to reduce the number of nuisance alarms. Other actions taken included upgrading shift turnover sheets, issuing a station policy for working LC0 related jobs continuously to completion, including print reading in licensed operator training, and modifying administrative procedures to require clear identification of equipment affected and operational impacts of blocking request In addition, the licensee reviewed and updated selected safety-related electrical schematics to verify and/or include certain information concerning relay contact development, power supplies and drawing references. In the violation response dated May 20, 1983, the licensee indicated that states links and termination locations and details, would also be included in this drawing upgrade. The licensee subsequently decided to not include this information in the scope of the drawing upgrade effort. The licensee also developed load list drawings to enable plant staff to easily identify safety-related loads that might be affected by operating circuit breakers.
l The inspector reviewed documentation that the above corrective l, actions were adequately implemented and found no discrepancies.
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1.2 (Closed) Unresolved Item (387/83-15-02): Adequacy of ECCS Instrumentation Testing In June 1983, the inspector identified a concern with the adequacy of channel functional testing on ECCS systems. Specifically, the monthly Channel Functional Test (CFT) for reactor vessel pressure channels as conducted did not verify actuation of the relay which has contacts in the ECCS logic circuits for RHR and Core Spray injection valves. At approximately this time, the licensee undertook a major task force effort to review the surveillance program implementation and hence, this issue was not further pursued by the inspector until completion of the task force effor In October 1985, Region I issued a Notice of Violation for a similar concern associated with the adequacy of CFT on the HPCI syste This matter is still under review and will be tracked under Violation 387/85-28-03; 388/85-23-0 .3 .( Closed) Unresolved Item (387/84-21-01; 388/84-26-01): Control of Temporary Procedure Changes In July 1984, the inspector noted that the licensee had a large number of outstanding temporary procedure changes that had not been incorporated in permanent revisions to procedures. The licensee utilizes a Procedure Change Approval Form (PCAF) to initiate a change to a procedure. The_ inspector noted that several Operating Procedures had more than three PCAFs outstanding, or that the oldest PCAF was more than 60 days old, and the procedure had not been
- permanently revised. This appeared to be contrary to the station policy stated in AD-QA-00 The licensee's_ current policy states that the process to initiate a procedure revision will normally occur.when there are three PCAFs outstanding against a procedure or 60 days from the date of the Superintendent's approval of the oldest PCAF. The inspector reviewed Operations method of controlling PCAFs, Operations uses computer printouts to identify which procedures are in the above categories and monitors the procedure status closely. The number of PCAFs outstanding against procedures is tracked monthly by Operations. The inspector noted that Operations, in general, is complying with the above policy and that positive control of procedure changes is being maintaine .4 (Closed) Violation (387/84-38-04): Fire Brigade Members Assigned Without Required Training In December 1934, the inspector identified that four fire brigade members had not received all of the required training prior to being assigned to the brigade. Specifically, the four individuals had not recaived the initial Susquehanna-specific Fire Brigade training, nor had they been waived from the requiremen '
By letter dated March 27, 1985, the licensee responded to the violation, indicating that the four members were immediately removed from the brigade. The inspector verified that all four individuals have since received the required training. The inspector reviewed training records for several other brigade members in the Operations and Security departments. Both departments are closely tracking the training requirements and training status of fire brigade member No discrepancies were noted in the training records reviewe .5 (0 pen) Unresolved Item (387/85-18-03): Drywell Average Air Temperature Allegation In June 1985, the inspector followed-up an anonymous allegation concerning the method used to calculate Drywell average air temperature. The rev.iew identified several procedural deficiencies in the surveillance program. In response to the identified items, the following corrective-actions were completed by the licensee:
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The SPDS algorithm used to calculate Drywell average air temperature was returned to its original configuration under Work Authorizations (WA) S56022 and V5601 The algorithm now averages the four highest readings and is consistent with the Technical Specification Surveillance Requiremen Surveillance procedures S0-100/200-007, Daily Surveillance Operating Log, were revised to calculate the Drywell average air temperature in accordance with Technical Specification Surveillance procedure S0-100-002, Monthly Accident-Monitoring Instrumentation Channel Checks, was revised in PCAF 1-85-114 to designate the correct temperature recorders to be used to perform the surveillanc Surveillance procedure 50-200-002 was revised to correct the recorder references to be consistent with a previous procedure chang Surveillance procedures SI-173/273-311 were written to perform the 18-month calibration of the drywell temperature Accident Monitoring channels (TT-15790A and B). All channels are now calibrated on an 18 month basis, and the Operations and I&C procedures are now consistent, and correctly reflect the Accident Monitoring Channel The inspector observed the operation of the SPDS algorithm and reviewed :,everal completed surveillance procedures to verify that the correct averaging method is being utilize The revised procedure; were also reviewed. No discrepancies were identifie .- - -
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The current surveillance procedures used to calculate the average Drywell temperature, S0-100/200-007, are still somewhat confusing to the operators. The procedure should emphasize that the highest four readings should be used, unless both detectors at a particular elevation are inoperable. In addition, the asterisked note in the Technical Specification has been clarified since the initial inspector finding, and the current procedure is now overly conservative. The inspector discussed his concerns with the licensee, and the procedure is in the process of being revised for clarity. The inspector reviewed several completed surveillances and found that the operators are performing the surveillance as intended by the Technical Specification. The long term solution needed to correct this item is to revise the Technical Specification surveillance requirement to clarify the method of calculation and then reflect that change in the applicable procedure This item will remain unresolved pending revision of the Technical Specification surveillance requiremen .0 Review of Plant Operations 2.1 Operational Safety Verification The inspector toured the control room daily to verify proper manning, access control, adherence to aporoved procedures, and compliance with LCOs. Instrumentation and recorder traces were observed and the status of control room annunciators was reviewe Nuclear Instrument panels and other reactor protection systems were examine Effluent monitors were reviewed for indications of releases. Panel indications for onsite/offsite emergency power sources were examined for automatic operability. During entry to and egress from the protected area, the inspector observed access control, security boundary integrity, search activities, escorting and badging, and availability of radiation monitoring equipmen The inspector reviewed shift supervisor, plant control operator, and nuclear plant operator logs covering the entire inspection perio Sampling reviews were made of tagging requests, night orders, the bypass log, Significant Operating Occurrence Reports (S00Rs), and QA nonconformance reports. The inspector observed several shift turnovers'during the perio No unacceptable conditions were identifie .2 Station Tours The inspector toured accessible areas of the plant including the control room, relay rooms, switchgear rooms, cable spreading rooms, penetration areas, reactor and turbine buildings, diesel generator building, ESSW pumphouse, and the plant perimeter. During these tours, observations were made relative to equipment condition, fire
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hazards, fire protection, adherence to procedures, radiological controls and conditions, housekeeping, security, tagging of equipment, ongoing maintenance and surveillance and availability of redundant equipmen . Seismic Qualification of Containment Monitoring Cabinets
During a tour of the Unit 1 and Unit 2 reactor buildings in January 1986, the inspector noted that the panel doors for the Reactor Coolant Pressure Boundary Leak Detection System (C-227) and the Containment Atmosphere Analyzer (C-226) were removed or opened. These panels are seismically qualified and the inspector questioned the licensee concerning the impact on their qualificatio The licensee performed an engineering evaluation under Engineering Work Request (EWR) MIS 86-0043 to determine the acceptability of this practice. The evaluation, which was approved February 7,1986, stated that Wyle Labs seismically qualified the panels with a closed door. The door was felt to have sufficient weight and stiffness to potentially affect the dynamic characteristics / response of the panel. The EWR stated the doors should be reinstalled and left in the closed position to ensure the seismic qualificatio Following disposition of the EWR, a Significant Operating Occurrence Report (S00R) was issued on February 10, 1986 to document the event and initiate corrective action. The '
deficiency was also evaluated for reportability on February 18 and was determined to be not reportable. On March 11, 1986 the inspector conducted another tour of the Unit'2 reactor building and again found the panel doors ope The panel doors had been removed / opened in the past due to temperature related component failures in the panels, but recent modifications separated the temperature sensitive components from the heat sources and placed them in separate panels. It appears the doors had remained open based on past practice CFR 50.59 requires that a safety evaluation be prepared to provide the basis for changes made in the facility as described in the FSA Since the panel doors were installed during the seismic qualification testing, the removal of the doors should have been evaluated to determine the impact on the panel qualification. A written safety evaluation was not performed when the panel .. - - - _ - . . -
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doors were removed or opened. This is a Violation of 10 CFR 50.59 and station procedures (387/86-02-01; 388/86-01-01).
3.0 Summary of Operating Events 3.1' Unit 1 At 1:48 a.m. on February 15, Unit I was manually scrammed from 18 percent power, as scheduled, to commence the second refueling outage. The unit reached Operational Condition 5 on February 1 The outage activities are discussed in Detail .2 Unit 2 Unit 2 operated at or near 100 percent power for most of the inspection period. Scheduled power reductions were conducted throughout the period for control rod pattern adjustments, surveillance testing, and scheduled maintenanc .3 Inadvertent Containment Isolation Oue to Breaker Mislabeling (Unit
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- On February 16, 1986 at 9
- 00 a.m. a partial loss of power occurred l to the Unit 1, Division I, Nuclear Steam Supply Shutoff System (NS4)
when a Nuclear Plant Operator (NPO) opened RPS breaker CB5A on panel 1Y201A. According to the blocking permit, RPS breaker CB3A on panel
- 1Y201A was to be opened to deenergize power to the Division I APRMs for I&C maintenance. The breaker the NPO opened was labeled 1Y201A-C83A, but it was actually breaker 1Y201A-CB5A. The breaker operation caused isolation of the operating loop of RHR shutdown cooling, RWCU, and Reactor Building Zone III HVAC and initiation of the 'A' SGTS and CRE0 ASS trains. Following the actuation, the NPO was instructed to reclose the breaker, and at 9:05 a.m. the isolation signals were reset. Shutdown cooling was restored at 9:20
- _ The licensee issued a Significant Operating Occurrence Report (S00R) and made the appropriate ENS notificatio Subsequent investigation by the licensee found that four of the eight RPS 'A' bus breakers were mislabeled and the same condition existed on the Unit 2 RPS 'A' bus breakers. The breakers had been labeled in 1985 as part of a station-wide labeling program, and the drawing which depicted the breakers in panel 1Y201A (E-157) was incorrect. The labels were applied based on the left-to-right l sequence shown in the drawing. The labels have been corrected and a drawing change is being issued to correct the drawing errors. This l appears to be an isolated case due to the absence of additional drawings for this one panel. The inspector had no further concerns, l
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4.0 Licensee Reports 4.1 In-Office Review of Licensee Event Reports The inspector reviewed LERs submitted to the NRC:RI office to verify that details of the event were clearly reported, including the accuracy of description of the cause and adequacy of corrective action. The inspector determined whether further information was required from the licensee,_whether generic implications were involved, and whether the event warranted onsite. followup. The following LERs were reviewed:
Unit 1
- 86-001, Four CRE0 ASS Dampers Not Adequately Tested
- 86-001, Opening of Turbine Bypass Valves Caused Reactor Scram on Low Level 86-002, HPCI Inoperable Due to Leaking Pressure Control Valve 86-003, Emergency Core Cooling Systems Declared Inoperable
- Previously discussed in Inspection Report 50-387/85-36; 50-388/85-3 **Further discussed in Detail .2 Onsite Followup of Licensee Event Reports For those LERs selected for onsite followup (denoted by asterisks in Detail 4.1), the inspector verified that the reporting requirements of 10 CFR 50.73 had been met, that appropriate corrective action had been taken, that the event was adequately reviewed by the licensee, and that continued operation of the facility was conducted in accordance with Technical Specification limits. The following findings relate to the LERs reviewed on site:
4. LER 86-001, Opening of Turbine Bypass Valves Caused Reactor Scram on Low Level (Unit 2)
On January 21, 1986 at 8:15 a.m. the Unit 2 reactor scrammed from approximately 1 percent power when reactor vessel water level dropped to thirteen (+13) inches. The l
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reactor was in the process of being started up. The cause of the low water. level condition was the undetected opening of two turbine bypass valves. The control room operators were in the process of warming the steam lines to the High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) Systems when one Turbine Bypass Valve (TBV) started to open. Reactor pressure was at_122 psig and water level was 36 inches. No feedwater pumps were operating and the condensate system was in long path recirculation. Control rod drive cooling flow (63
.gpm) was feeding the vessel. Approximately ten minutes later a low water level alarm was received when level reached 30 inches. The operators attributed the decrease to the steam flow to the HPCI and RCIC steam supply lines,
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and they did not note that one bypass valve had opene To increase level, the operators decided to withdraw control rods to raise the coolant temperature. A second BPV opened after the rod withdrawals. With the BPV's open, each rod withdrawal increased steam flow out of the vessel and caused water level to continue to decrease until the automatic scram setpoin Following the scram the operators noticed the BPV's open and promptly closed them. All equipment operated per design during the transien The TBV's were set to open at 150 psig since the Technical Specifications require HPCI and RCIC to be operable above 150 psig. The operating range of the instrumentation is 150 to 1250 psig and the TBV opening at 122 psig wa determined to be within the 3 percent tolerance of the normal operating range of the instrument loop. It is calibrated at the normal operating pressure of 1000 psi The only TBV indications available to the operator are an indicator light on a control room panel for each of the five valves and an alarm initiated display on the main steam CRT. When the operator is monitoring reactor water level and pressure from the CRT displays, the indications are not in his normal field of vision. A PMS computer alarm should have sounded, but it went unnoticed. The LER incorrectly stated that no audible alarms were sounde This was discussed with the licensee, and it was their intent to mean that no normal control room annunciators had alarme To prevent recurrence, general operating procedures G0-100/200-002, " Plant Startup and Heatup" were revised to include a caution that turbine bypass valves can open anytime over 100 psig reactor pressure. The need for an additional audible alarm to inform the operators of a TBV opening is also being reviewed by plant managemen .
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A Human Factors Engineering design review of the Susquehanna control room was conducted by the NRC in October 1980. During this review, it.was noted that there was no annunciator message to draw operator attention when turbine bypass valves opened (HED Sd). The operator had to detect the change from green to red on the legend lights on the benchboard. In response, the licensee committed to develop a PMS computer alarm and a DCS generated Alarm Initiated Display (AID) to provide the operator with turbine bypass information. This AID was developed and was operational during this event, but as noted above, it was not in the operators normal field of vision and the alarm was not noted by the operator .2.2 LER 86-002, Standby Liquid Control System (SLCS) Sodium Pentaborate Quantity Less Than Allowable On February 6,1985, during performance of a 31-day surveillance on the SLCS storage tank solution, the licensee determined that the available weight of sodium pentatorate was 5,464 pounds, less than the Technical Specification minimum allowable of 5,500 pounds. The LCO was entered, a 50.72 report made to the NRC and, following the addition of 150 pounds of Borax and 150 pounds of Boric Acid, the available sodium pentaborate weight was determined to be 5,700 pounds. The LCO was cleared at 10:50 p.m. February 6,198 The inspector reviewed surveillance results SC-53-101 and discussed this occurrence with chemistry personnel to determine the cause of the low quantity. On February 3, chemistry determined the quantity to be 5,532 pound Following this sample, chemistry directed that 100 pounds of Boric Acid and 100 pounds of Borax be added. About 125 gallons of demineralized water were also added to bring the tank level up to 4,850 gallons. The chemicals and water were added on February 6 and the sample results after the addition were the out of specification quantity of 5,464 pounds. The inspector verified that proper chemistry procedures were followed including use of standards and backup samples. Since the quantity of sodium pentaborate decreased after chemicals were. added, it appears that either samples are not representative or some amount of chemicals were not dissolving. The system was not operated between February 3 and February 6. The inspector noted that the out of specification sample results were taken at a tank temperature of 98 F and the chemicals were added about 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> earlier at an even lower tank temperature (temperature not taken). The inspector discussed this with a Region 1 chemis y inspector who indicated that boric acid has a low l
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solubility constant which is very temperature dependen Other plants using boric acid to makeup sodium pentaborate concentration, add in smaller increments at higher tank temperatures. The licensee indicated that they would review this informatio .3 Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted by the licensee were reviewed by the inspector. The reports were reviewed to determine that they included the required information; that test results and/or supporting information were consistent with design predictions and performance specifications; that planned corrective action was adequate for resolution of identified problems; and whether any information in the repcrt should be classified as an abnormal occurrenc The following periodic and special reports were reviewed:
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Monthly Operating Report - January 1986 dated February 14, 198 Special Report 'B' Diesel Crankcase Overpressurization dated February 18, 198 Special Report - ECCS Injectica , dated February 25, 198 Special Report - RCIC Injection, dated February 25, 198 Special Report - SGTS Sping Noble Gas Channels Inoperable For Greater Than 7 Days, dated February 26, 198 Monthly Operating Report - February 1986, dated March 11, 198 Tne above reports were found acceptabl On January 18, 1986 the 'B' Diesel Generator was being run to demonstrate operability prior to taking a startup transformer out of service. After being unloaded the diesel was manually tripped when a crankcase explosion occurred. (This failure was previously discussed in Inspection Report 50-387/85-36; 50-388/85-32).
The licensee's investigation has concluded that the probable cause of the failure was that the 'B' diesel SL cylinder piston pin bolts were not initially torqued to the specified 690 ft-lbs. The piston pin bolts eventually loosened and allowed the piston pin to ' rock'
with respect to the connecting rod. Eventually the connecting rod to piston pin locating dowel fatigued and broke off. The loose bolting allowed the oil supply fed up through the connecting rod to escape between the connecting rod and piston pin, instead of through the oil distribution channels to lubricate the pi The lack of
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lubrication to the piston pin caused it to heat up and expand, pushing the piston pin covers against the cylinder liner, and causing severe scoring. The heat generated by the piston to liner interface caused the tin coating on the piston to melt and provided the ignition source to explode the crankcase gase The piston, cylinder liner, piston pin, piston pin bushing, piston i pin bolts, piston rings and connecting rod for the SL cylinder were replaced. The lube oil, lube oil filters and jacket water were also replaced. The other cylinder liners on.the 'B' Diesel were inspected for damage or discoloration and nothing abnormal was found. All of the piston pin bolts on the left cylinder bank of the
'B' Diesel were torqued to the specified 690 ft-lbs, but none of the bolts move Present licensee plans are to torque all the 'B'
Diesel right bank piston pin bolts following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of operatio During a subsequent outage of the 'A' Diesel Generator, all of the piston pin bolts were retorqued in 50 ft-lb increments. Two bolts out of the 32 checked moved slightly at 690 ft-Ibs, but not at 640 i ft-lbs. This was considered acceptable since it was within 10% of the specified torque. The need to check the torque on the 'C' and
'D' Diesel Generator piston pin bolts will be evaluated after the right bank of the 'B' Diesel is checke The 'B' Diesel Generator test during which the crankcase explosion occurred was considered a valid failure. The Diesel Generator Start Log indicates there have been two (2) diesel failures in the last one hundred (100) starts. The diesel test interval is currently one start every fourteen (14) days, per Regulatory Guide 1.108, Section C. .0 Monthly Surveillance and Maintenance Observation 5.1 Surveillance Activities The inspector observed the performance of surveillance tests to determine that: the surveillance test procedure conformed to technical specification requirements; administrative approvals and tagouts were obtained before initiating the test; testing was accomplished by qualified personnel in accordance with an approved surveillance procedure; test instrumentation was calibrated; limiting conditions for operations were met; test data was accurate and complete; removal and restoration of the affected components was properly accomplished; test results met Technical Specification and procedural requirements; deficiencies noted were reviewed and appropriately resolved; and the surveillance was completed at the required frequency.
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These observations included:
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SI-183-208, 31 Day Reactor Vessel Low Level 3 Channels LIS-821-N042A and B, performed on February 6,1986
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50-024-001D, Monthly Diesel Generator Operability Test, performed on February 27, 1986
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SM-175-204, 60 Month Division II 24 VDC Battery Discharge Performance Test, performed on March 13, 1986 No unacceptable conditions were note .2 Maintenance Activities The inspector observed portions of selected maintenance activities to determine that the work was conducted in accordance with approved procedures, regulatory guides, Technical Specifications, and industry codes or standards. The following items were considered during this review: Limiting Conditions for Operation were met while components or systems were removed from service; required administrative approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and QC hold points were established where required; functional testing was p_rformed prior to declaring the particular component operable; activities were accomplished by qualified personnel; radiological controls were implemented; fire protection controls were implemented; and the equipment was verified to be properly returned to servic On March 13, the inspector observed preventive maintenance on the limitorque actuator for the Unit 1 High Pressure Coolant Injection I (HPCI) full flow test valve (F008). The maintenance was performed l by E&S construction electricians under WA P-53264. A detailed work '
plan was available at the job site, but it did not include the referenced procedure, MT-GE-003, "Limitorque Valve Actuator Maintenance". The procedure data sheets were included in the work packages. The electricians were also performing terminations / determinations, and inserting / removing jumpers (as
, specified in the procedure), but without filling in the data sheet as the steps were performe The electricians indicated that they were performing the required verifications and would later fill out the data sheet. A schematic of the valve actuator was available at the job site. The electrician's supervisor checked on the job and QC was performing a surveillance on the job. The electrician in charge of the job appeared very knowledgeable. He indicated that he had reviewed the procedure before performing the work and had been involved in a number of similar maintenance jobs on limitorque actuators and felt that he did not need a procedure at the job sit Other than the above, the inspector noted no other unacceptable practice The inspector discussed the above concerns with the Electrical Maintenance Supervisor (Nuclear Department) and the Construction Production Supervisor (Construction Department).
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-The licensee indicated that not documenting terminations / determinations at the time they were performed was not considered acceptable practice l and that personnel performing such activities would be so informed.
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6.0 IE Bulletin and Information Notice Followup IE Information Notice No. 86-13: Standby Liquid Control System Squib Valves Failure to Fire On February 21, 1986, Information Notice 86-13 was issued to alert addressees to a potentially generic problem with explosive squib valves used in the Standby Liquid Control System (SLCS). During a
[ routine surveillance test at Vermont Yankee, the squib valves in both pathways of the SLCS failed to fire. The failures were due to l
altered wiring in the terminal box to the squib valve firing circuit I and incorrect wiring of the connector that is supplied with the squib valve primer chamber assembl The squib valves are connected to the plant's wiring via four pin connectors. The explosive primer chamber assembly has two sets of resistance wires, i.e. bridgewires, internal to the charge, either of which will fire the explosive. At Vermont Yankee, some of the charges were found to have different pin-to-bridgewire groupings so that when connected, they would not fire. The correct configuration was to have the bridgewires connected across pins 1-4 and 2-3. The pins are counted counter-clockwise from the number 1 pin (polarizing pin), which is larger than the other three pin The Information Notice stated that 19 suspect primer chamber assemblies had been procured by Susquehanna from CONAX. The assembly part number (P/N) is 1621-240-01, and the serial numbers (S/N) were listed as 675-681 and 686-69 . Followup of Suspect Primer Assemblies The inspector discussed the potential deficiency with the licensee, and an investigation was initiated to determine the status of both Unit's SLCS configurations and the location of the suspect primers. During the inspections it was noted that one of the suspect primer chamber assemblies, S/N 692, was installed in the Unit 2 syste The licensee also located eight of the suspect assemblies in the warehouse. Two of the primer assemblies, S/N 693 and 694 had been previously installed and successfully fired in the Unit 2 system. Review of the licensee's documentation and discussions with licensee procurement personnel concluded that 18 assemblies were ordered, of which six were sent to Riverbend (Gulf States Utilities)
to replace squibs that had been previously purchased by Susquehanna. Additionally, one of the remaining 12 (S/N 698) is not in the suspect group. The records indicate rr -
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that only assemblies 687-698 were received at the sit Assemblies 675-681 may have been sent to Riverbend, and the resident was informed of the potential deficienc *
The licensee has placed the 8 suspect primers remaining in the warehouse on hold until their acceptability has been verifie The inspector reviewed the procurement documentation, work authorizations, installation procedures and several NCR's associated with the suspect primers. Two NCRs were written on this batch of assemblies due to receipt inspection deficiencies identified in February 1984. NCR 84-479 was issued due to several documentation discrepancies: the purchase order had been written for P/N N27006-01, but the kits received were P/N 152-162-01; the manufacturing date/ shelf life data was not supplied; material certifications were not supplied; and heat treatment records were not supplied. The NCR was closed out March 17, 1984 after acceptable documentation was received for eight of the twelve valves. The different part number was determined to be acceptable by General Electric and was documented on a Deviation Disposition Request (DDR 30023). Materials-tratability was not available for four of the valves as c ocumented in NCR 84-489. The valves were eventually returned to the vendor and later returned to Susquehanna with the proper documentatio The NCR was closed March 28, 198 On January 31, 1984 NCR's84-201 and 84-202 were written to describe the configuration problems associated with the two different part numbers as discussed above. The Unit 1 NCR (84-201) was resolved on February 11, 1984 by replacing the assemblies with P/N 1532-162-01 with assemblies purchased from Riverbend (P/N N27006-01) as requested by GE Field Deviation Disposition Request (FDDR)
KR1-5004 dated January 31, 1984. The Unit 2 NCR (84-202)
was resolved on March 16, 1984 by test firing the squib valves in the Unit 2 circuit. The discrepancies were apparently due to design specifications used by CONAX in the manufacturing process. The suspect assemblies were manufactured based on a Military Specification (MILSPEC)
. in lieu of the required ANSI standard Primer assemblies with different pin-to-bridgewire configurations were identified by the licensee in February 1984, during the resolution of NCR 84-201 (WA-S43018).
Maintenance procedure MT-053-002, SBLC Explosive Valve Removal and Replacement, checked the resistance across the bridgewire pins prior to installation. The maintenance technicians identified that the bridgewires were connected in a configuration different from the vendor drawing and
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maintenance procedure. Based on the discrepancy, Nonconformance Report (NCR)84-237 was issued to resolve the problem. The conclusion was that the squibs were acceptable for use, and the assemblies were installe The deficiency was caused by incorrect drawings in the vendor manual for the assemblies. The NCR included a Drawing Change Notice (DCN) to correct the drawings. In actuality, the procedure was incorrect and the assemblies were correct. The squib valve drawing, M1-C41-18-1, remains uncorrected and the licensee is investigating to determine why the DCN was not incorporated. In addition, GE Elementary M1-C41-36, Bechtel Schematic E-166, and procedure MT-033-002 do not correctly reflect the as-built configuration of the squib circui The drawing deficiencies are unresolved pending completion of the licensee's review (387/86-02-02; 388/86-01-02).
6.1.2 Expired Primer During the inspections for the suspect primers, the system engineer identified that the Unit 1 'A' squib valve (148F004A) primer chamber assembly had exceeded its vendor recommended service life limit of 5 years. The assembly (P/N 1621-240-01, S/N 444) was manufactured in August 1979, but was installed April 23, 1985 under Work Authorization (WA) S53136. Unit I was shutdown for a refueling outage when the expired valve wus discovered and the system was not required to be operable. The licensee decided to include this primer into the scheduled performance of the 18-Month Injection Demonstration, SE-153-001, and then replace the primer assembly. A successful firing test was conducted on March 1, 1986 and demonstrated that the system was operable, although the primer had exceeded the recommended service life. The other installed primers were found to be well within the expiration date and the expired primer was replaced with one with an acceptable expiration dat The inspector reviewed the documentation associated with the installation of the expired charge. The 18-Month Injection and Initiation surveillance test, SE-153-001A, was completed on April 26, 1985. During that surveillance the 'A' squib was replaced, after being fired, by WA 553136. The precautions in the WA required the valve to be drawn from a " qualified" batch and that the batch number and serial number be recorded. The bridgewire resistances between pin 1-2 and 3-4 were also measured and recorded. There were no steps in the procedure which required the technician to verify or record the expiration date of the charg In addition, the material 1 ..
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identification tag (FORM 2778G) attached to the primer had a blank for the " Shelf Life Expiration" date, but it was not filled in as required by Administrative procedure AD-QA-200 and Material Section Instruction MC-01-011. The primer was from a batch received under Receipt Inspection Report (RIR)80-104 in June 1980. NCR 82-195 was written on these replacement kits on March 22, 1982 since GE had not provided the manufacturing date needed to calculate the shelf life. The NCR was closed July 14, 1982 when the date was received, but this delay may have contributed to the omission of the expiration date on the form. In addition, the licensee's program to track shelf life expiration was revised in March 1985, one month prior to the installation. The inspector observed the replacement kits currently in the warehouse and several completed work packages, and all included the expiration date on the for CFR 50, Appendix B, Criterion XV states that measures shall be established to control materials which do not conform to requirements in order to prevent their inadvertent use or installatio Installation of an expired squib is a Violation of this Criterion (387/86-02-03).
. Precautionary steps have been included in the applicable surveillance procedures (SE-153/253-001) subsequent to the installation of the expired primer, which require that the expiration date of the assembly being installed be recorded in the procedure and confirming that the expiration date is at least 36 months from the date of installation. These same precautions should be included in the maintenance procedure, MT-053-002, for those cases where the squib is replaced not in conjunction with the 18-month firings. The licensee is reviewing the maintenance procedur . Summary of Findings
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Based on actual field firing of the SLCS squib valves, either one of the two possible primer configurations will operate as designed. The concerns of the Information Notice have no impact on the system operabilit The maintenance procedures and applicable drawings do not correctly reflect the valve configuration !
installe The drawing deficiency had been )
previously identified, but it has not yet been corrected. The correct drawings have been procured from the vendors and should be incorporated into the plant drawings and procedures.
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