IR 05000237/1989005
| ML17201Q430 | |
| Person / Time | |
|---|---|
| Site: | Dresden  |
| Issue date: | 04/21/1989 |
| From: | Harrison J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17201Q428 | List: |
| References | |
| 50-237-89-05, 50-237-89-5, 50-249-89-05, 50-249-89-5, IEIN-86-053, IEIN-86-53, NUDOCS 8905010136 | |
| Download: ML17201Q430 (21) | |
Text
U. S. NUCLEAR REGULATORY COMMISSION REGION I II Report Nos. 50-237/89005(DRPJ; 50-249/89005(DRP)
Docket Nos. 50-237; 50-249 License Nos. DPR-19; DPR-25 Licensee:
Commonwealth Edison Company P. 0. Box 767 Chicago, IL 60690 Facility Name:
Dresden Nuclear Power Station, Units 2 and 3 Inspection At:
Dresden Site, Morris, IL Inspection Conducted:
January 7 through March 17 and April 11, 1989 Inspectors:
s. G. Du Pont D. E. Jones D. E. Hi 11 s Approved By: ~~~~
J. Harrison, Chief ol/)z1/ec:
Reactor Projects Section 18 Date Inspection Summary Inspection during the period of January 7 through March 17 and April 11, 1989 (Report Nos. 50-237/89005(DRP); 50-249/89005(DRP))
Areas Inspected:
Routine unannounced resident inspection of the licensee's corrective actions associated with previously identified inspection findings, plant operations, maintenance and surveillance activities, safety assessment and quality verification, events, and event report Additionally, the licensee's activities associated with heat shrinkable tubing (TI 2500/17)
and Technical Specification required reports were evaluate Results:
During this inspection period the following strengths and weaknesses were noted:
0 Two violations were identified during this inspection perio One pertained to an operator error, failure to follow an approved procedure during ground checking operations (Paragraph 3).
The second pertained
_to inadequate post maintenance testing performed in 1986 on the control rod drive (CRD) hydraulic control units (Paragraph 4).
Several ESF actuations occurred during the inspection perio The majority of these were associated with the undervoltage testing performed as part of the Unit 2 refueling outag The licensee has performed an 090~010136 R90421
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0 evaluation of the actuations and self-identified several root causes as part of their ESF reduction progra The licensee 1s corrective actions associated with these actuations are considered to be progressive and an indication of positive management involvemen Unit 2 was returned to operation following a refueling outag The startup was error-free and excellent coverage was provided by the licensee 1 s management and quality assurance staf The licensee 1 s operations staff demonstrated excellent initiative by identifying and correcting additional concerns with the 4KV breaker In response to the preventive maintenance concerns identified by the NRC Maintenance Team Inspection, the operations staff performed an 100 percent walkdown of the 4KV breakers and identified two additional concern The walkdown found two breakers, one 2000 and one 1200 amp rated breaker, installed in the wrong amp rated cubicle Additionally, the staff identified the root cause as the lack of external amp rating identificatio Both of these problems were promptly corrected (Paragraph 3).
- DETAILS Persons Contacted Commonwealth Edison Company
- E. Eenigenburg, Station Manager
- L. Gerner, Production Superintendent
- C. Schroeder, Services Superintendent C. Allen, Performance Improvement Supervisor T. Ciesla, Assistant Superintendent - Planning D. Van Pelt, Assistant Superintendent - Maintenance J. Brunner, Assistant Superintendent - Technical Services
- J. Kotowski, Assistant Superintendent - Operations R. Christensen, Senior Operating Engineer G. Smith, Unit 2 Operating Engineer K. Peterman, Regulat9ry Assurance Supervisor W. Pietryga, Unit 3 Operating Engineer J. Achterberg, Technical Staff Supervisor R. Geier, Q.C. Supervisor D. Sharper, Waste Systems Engineer D. Adam, Assistant to the Assistant Superintendent - Technical Services J. Mayer, Station Security Administrator D. Morey, Chemistry Services Supervisor D. Saccomando, Health Physics Services Supervisor
- E. Netzel, Q.A. Superintendent The inspectors also contacted and interviewed other licensee employees, including members of the technical and engineering staffs, reactor and auxiliary operators, shift engineers and foremen, electrical, mechanical and instrument personnel, and contract security personne *Denotes those attending one or more exit interviews conducted informally and formally at various times throughout the inspection perio.
Previously Identified Inspection Items (92701 and 92702)
(Closed) Open Item (249/86009-18):
SSOMI' deficiency 4.1-Followup correcti.ve action recommendations contained in the November 24, 1986, letter from Mr. Partlow to Mr. Norelius pertaining to CEC0 1s fail~re to adequately document 10 CFR 50.59 review The inspector verified the implementation of corrective actions through reviews of 10 CFR 50.59 evaluations pertaining to six plant modifications accomplished during the recent Unit 2 refueling outag The corrective actions appeared to ensure adequate documentation of the safety review This item is considered to be close (Closed) Open Item (249/86012-09):
SSOMI Deficiency 2.2-Verify issuance of new procedure for safety evaluation The inspector verified that administrative procedure OAP 10-2, 10 CFR 50.59 Review Screening and Safety Evaluations, was issue OAP 10-2 contained requirements that ensured safety evaluations are performed for setpoint changes, temporary alterations, temporary shielding, procedure changes,
and modification Additionally, new and special procedures are required to have safety evaluations-performed prior to us This item is considered to be close (Closed) Open Item (249/86012-65):
SSOMI Deficiency 2.7-The SSOMI identified discrepancies between isolation valve test valves contained in the Technical Specifications, FSAR and surveillance tests, DOS 1600-1 and 1600-1 This item was also identified by the Diagnostic Evaluation (DET) and subsequently resolved in inspection reports 237/88023 and 249/8802 (Closed) Open Items (237/87007-03 and 249/87006-03):
Review the performance of the control rod drives (CRD) during Unit 2 operating Cycle 11 for recurrence of notch 02 event The inspector reviewed the response of the CRD~ during reactor scrams subsequent to corrective actions (documented in inspection reports 237/87007 and 249/87006) and noted that the licensee actions have prevented recurrenc These items are considered to be close (Closed) Unresolved Item (237/88017-28):
Diagnostic Evaluation (DET)
Item 2.2. Verify corrections to control testing of ASME Section XI pump testin This item was reviewed and resolved in inspection reports 237/88023 and 249/88024 (Paragraph 6).
Based upon this review, this item is considered to be close (Closed) Unresolved Item (249/86012-66):
SSOMI Deficiency 2.7-The SSOMI identified that valve cycling tests did not verify proper stroke times as required by ASME Section X The Inservice Testing (!ST)
inspection, documented in inspection reports 237/87026 and 249/87026, verified that the licensee 1 s !ST Program, submitted April 15, 1988, adequately addressed and resolved the SSOMI concer This item is considered to be close (Closed) Bulletins (237/87002-BB and 249/87002-BB):
These items are considered to be administratively closed because all required actions were completed and documented in inspection reports 237/87040 and 249/8703 (Closed) The following inspection items were administratively reviewed and closed by the NRC based upon duplication, or the lack of significance and requirements, or corrective actions being in place to prevent recurrence:
237/85033-03 237 /86013-07 237/86018-01 237/87006-18 237/87009-01 237/87033-01 237/87033-04 237/87033-05 237/87033-06 237/88900-01 237 /88067-IN 237/87046-IN 237/88014-GL 237/88055-IN 249/83020-01 249/85005-07 249/85013-01 249/85029-03
249/87005-3L 249/87008-01 249/87032-01 249/87032-04 249/87032-05 249/87032-06 249/87032-11 249/87037-01 249/87037-02
237/87033-11 237/87038-01 237/87038-02 249/86006-01 249/86015-07 249/86022-01 No violations or deviations were identifie.
Plant Operations (71710, 71707 and 93702) Enforcement History 249/88003-ll 249/88014-GL During this inspection period one violation (237/89005-0l(DRP);
249/89005-0l(DRP)) and two licensee identified violations (10 CFR 2, Appendix C) were identifie The violation pertained to a personnel error while checking for DC ground Operational Events (1)
on* March 4, 1989, Unit 2 scrammed on low reactor water level from 92% powe The scram occurred while operators were performing DC ground checks on the 125 Volt DC syste During the ground check, an equipment operator opened and then closed a breaker switch which caused a loss of power to the DC powered relays for the oil pressure sensing switche for the reactor feedwater pump This resulted in a trip of the previously running Reactor Feedwater Pumps 2A and 28 and an automatic start of the Standby Reactor Feedwater Pump
- 2C.-
The resulting vessel water leve~ decrease caused a reactor scra The equipment operator ~lso opened and closed another breaker switch which caused the isolation condenser and one recirculation system sample valve to close and the inboard Main Steam Isolation Valve (MSIV) DC solenoids to lose powe As vessel water level recovered, the main turbine and Reactor Feedwater Pump 2C tripped at the high vessel water level setpoint of +55 inches. *The Turbine/Generator trip caused an automatic transfer of auxiliary power from the Main Auxiliary Transformer to the Reserve Auxiliary Transforme The corresponding momentary voltage drop during the transfer resulted in a loss of power to all MSIV AC solenoid The inboard MSIVs automatically closed due to the loss of power to bcith their AC and DC solenoid The outboard MSIVs did not close because their DC solenoids were not affecte Operators un-isolated the isolation condenser and allowed it to auto-matically initiate on high reactor pressure due to the MSIV closur The MSIVs were subsequently reopened and normal cooldown was commence (2)
On March 14, 1989, after just placing the Economic Generation Co~trol (EGC) System into operation on Unit 2, power rapidly increased from 765 MWe to 808 MWe when core flow increased to 100.7 E6 lbm/hr within a two minute time fram This exceeded the upper total core flow limit of 98.0 E6 lbm/hr prescribed by Technical Specifications for EGC operatio This power increase greatly exceeded the rate limit of 0.2 MW/min., as well as the upper power limit of 780 MWe set on the EGC
(3)
( 4)
( 5)
controller at the tim In addition, no corresponding alarm was generated when the control room operator manually tripped EGC upon noticing the increas On January 21, 1989, while Unit 2 was shutdown during a refueling outage, a Reactor Protection System (RPS) actuation occurred without any rod motio The actuation occurred while drywell coolers were being started for post outage testin RPS supply busses 28 and 29 received undervoltage trips during the starting of the coolers and Bus 24-1 (which feeds busses 28 and 29), received a overcurrent tri The B RPS motor generator was lined up to the A RPS bus while the B RPS bus was lined up to unregulated powe The licensee determined that the cause of the overcurrent trip of bus 24-1 was due to the time-delayed overcurrent relay being set on an incorrect*
tap settin The licensee initiated corrective actions, including a verifi-cation of correct tap settings for all relays that were set during the Unit 2 refueling outag The corrective actions were completed prior to the unit restart on February 19, 198 On January 31, 1989, Unit 2 experienced an Anticipated Transient Without Scram (ATWS) protection system actuation initiated by low vessel water level, while shutdown for a refueling outage.
Prior to the actuation on January 30, 1989, check valve 2-263-2-17B was taken out of service for bench test and level transmitters 2-263-23B and 230 were valved out as part of the outage checklis However, the level transmitter equalizing valve was left in the closed position which caused the instrument to drift and fail dowriscale; causing the ATWS instrument to actuate on low Rx leve The Shift Foreman checked the instrument and opened the equalizing valve, which allowed the level instrument to go upscale; thus allowing the ATWS system to be rese The licensee determined that the root cause of the ATWS actuation was due to inadequate work request instructions and personnel erro On February 4, 1989, an ESF actuation (reactor scram without control rod motion) occurred on Unit 2 during undervoltage (UV) and logic testing in preparation for returning to operation from the refueling outag The ESF actuation occurred due to a high signal spike on the APRM and IRM Channels when Transformer 22 to Bus 23 was tripped per the UV tes The B train of Standby Gas Treatment (SBGT) automatically started per design, but the 2/3 diesel generator and the 2B Low Pressure Coolant Injection (LPCI) pump failed to perform
their automatic function The 28 LPCI pump received a start signal but the motor trip coil failed, preventing the pump from startin The 2/3 diesel generator ventilation fan failed to start because of a failed relay which prevented the diesel from loading onto the bu The LPCI motor coil and the diesel generator vent fan relay were replaced on February 5, 198 On February 5, 1989, a second event related to the UV test occurre The licensee was in progress of raising vessel
. level from 138 to 300 inches when the 2/3 and-Unit 2 diesel generators automatically started and loaded onto the busses (because of UV testing).
The 28 Core Spray and the 2C and 2D LPCI pumps started and injected into the Unit 2 vesse The vessel level increased from 138 to 178 inches prior to securing the pump The root cause of the automatic injection was personnel error during a. lineup of test instruments to the high drywell pressure transmitte The vent on the test rig was inadvertently closed and pressure from the test source leaked through the test pressure regulator to initiate the high drywell pressure signa The licensee replaced the leaking test regulator and held a critique on the personnel erro That portion of the test was re-performed successfull (6)
On February 9, 1989, Unit 2 received a Group 5 primary contain-ment isolation signal (Isolation Condenser).* At the time of the isolation, the unit was shutdown with fuel reloade The isolation was caused by restoration of primary containment isolation system instrumentation after the primary hydro test and in preparation of the unit startup from the refueling outag The restoration of the instruments required back filling of the sensing lines and a spurious isolation signal occurred on the Group 5 instrument On February 11, 1989, a second Group 5 Isolation occurred when a differential pressure instrument was improperly isolated and the instrument flow check valve was being removed for maintenanc (7)
On February 19, 1989, Unit 2 went critical following a 113 day refueling outage that started on October 3IT, 198 Major work accomplished during the outage included the completion of 42 modifications, complete recoating of the torus, main turbine overhaul, human factors control room modifications, replacement of heat damaged cables in the drywell, SRM/IRM/LPRM tube replacement (5 each), vacuuming of all 177 control rod drive guide tubes, mechanical stress improvement of 106 welds, 24 weld overlays and units 2 and 2/3 diesel generator modifica-tion During the dual unit outage, November 27 to December 5, 1988, the common service water system isolation valves were replaced, ADS cables were separated and the Unit 3 LPCI heat exchanger was repaire * Approach to the Identification and Resolution of Technicil Issues From a Safety Standpoin (1)
Following the March 4, 1989 scram, the licensee conducted portions of DOS 1600-7 and DOP 6900-6 to verify their under-standing of the sequence of event The licensee determined the cause of the event to be a~ equipment operator who was not following the procedure while checking for DC ground The procedure DOP 6900-6, required that the control room shall be notified prior to de-energizing any circuit breakers and prohibited operations of specific breaker These prohibited breakers were clearly identified in the procedur However, the operator relied only on the prohibited breakers being distinguishable by red warning labels on the distribution panel to ensure compliance to the procedur During the refueling outage, these breakers were re-labeled with white labels containing red letterin This change in labeling contributed somewhat to the inappropriate operation in that the operator had not been made aware of the label chang Since the equipment operator was not following the instructions contained in the procedure, this change of breaker labeling did not prevent the operator from proceeding to check all the circuits on the distribution panel including the prohibited one Following the event, the licensee temporarily marked the prohibited breakers with red tape in anticipation of changing to more distinguishable label OAP 7-16, Control of System and Component Labeling, Revision 1, prescribes specific administrative controls for changes of plant labels and tags, including review and approval by a shift superviso However, this procedure does not govern changes made in conjunction with the on-going major re-labeling progra The licensee is investigating possible program changes to ensure that on-shift crews are notified of major or significant label change The failure of the operator to inform the control room prior to de-energizing circuit breakers and the subsequent de-energizing of circuit breakers prohibited by procedure DOP 6900-6 is considered to a violation of Technical Specifications 6.2.A (237/89005-01; 249/89005-01).
The licensee took immediate corrective actions by insuring that all operators were familiar with procedure DOP 6900-6 and the specific identification of the circuit breaker These actions are considered to be adequate to prevent recurrence and as such, no reply to this violation is require (2)
During the core flow transient on March 14, 1989 (noted above),
the Unit 2 operator took immediate action by tripping the EGC controlle Although the recirculation flow during the transient peaked at 100.7 E6 lbm/hr and exceeded the technical specification limit for EGC operation, the operator 1 s actions limited the magnitude of the transient and prevented possible exceeding of any safety limit The licensee also took prompt action by restricting any further operation on EG Additionally,
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a special troubleshooting procedure was developed to control testing and to perform a diagnostic evaluation of the EGC syste Since the licensee took prompt actions to prevent recurrence, the violation was self-identified, the event was reported and the violation of the technical specification would not have otherwise been greater than a Severity Level IV violation, this is considered to be a self-identified violation (per 10 CFR 2, Appendix C) and no notic~ of vfolation is issue The NRC does not gen~rally issue notice of violations in these cases to encourage and support licensee initiatives for self-identification and correction of problem Responsiveness to NRC Initiatives For the above events, the inspectors verified that the notifications were correct and timely, if appropriate, that the licensee was taking prompt and appropriate actions, that activities were conducted within regulatory requirements except as noted, and that corrective actions would prevent further recurrenc (1)
While following up on the scram of March 4, 1989, an NRC inspector noted that documentation did not exist for a portion of DOP 6900-6 that was conducted by the licensee to verify (2)
the sequence of events that led to the reactor scra The licensee subsequently re-performed that portion of the sequence and documented the results in the unit log boo The purpose of the licensee's test was to determine the response of the isolation condenser valve The inspector also witnessed the subsequent unit restart and verified that it was conducted in accordance with appropriate procedure Following the March 1989 exit by the NRC Maintenance Team, the licensee's operations staff initiated actions to identify and correct additional concerns regarding the 4KV breaker The NRC inspection had identified concerns with the preventive maintenance activities associated with the breaker In response to these concerns, the operations staff performed a 100 percent walkdown of the breaker The walkdown identified two additional concern The first concern identified that two breakers installed in the wrong cubicle Specifically, the walkdown identified a 2000 amp rated breaker installed in a 1200 amp cubicle and a 1200 amp rated breaker in a 2000 amp cubicl The second concern pertained to the identification of the breaker amp rating The amp rating of a breaker was not identified external to the breaker and requires the breaker to be removed from the cubicle to confirm the ratin The licensee corrected these findings by installing the correct rated breakers into the cubicles and by developing an external amp rating identification on all 4 KV breaker The licensee also conducted an evaluation of the safety significance of the two breakers being installed in the wrong cubicle Since the tripping relays and circuits are
- associated with the cubicles and not to the breakers directly, the overcurrent and undervoltage relays were not affected and would have provided adequate protection for both combinations of breaker/cubicle arrangement The over-current settings on the 2000 amp cubicle was within the range of the 1200 amp breake This arrangement (1200 amp breaker in a 2000 amp cubicle) was the least conservative and still provided adequate protectio The above event was identified and corrected by the license Additionally, no prior existing violation pertaining to this event had been identifie Based upon these considerations and the licensee 1 s corrective actions, this is conside~ed to be a licensee self-identified and corrected violation (10 CFR 2, Appendix C) and a notice of violation will not be issue Assurance of Quality, Including Management Involvement and Control Management involvement was effective during the above event The NRC inspectors noted the presence and involvement of the on-shift management representatives during the investigation of these events, as well as the unit restart following the scram of March 4, 198 The Unit 2 startup from the refueling outage is considered to be an
.excellent example of management and quality assurance involvement resulting in a error-free evolutio In addition, discussions with other management personnel indicated their concern in addressing the root causes and corrective actions associated with these event Several of the above events occurred during undervoltage testing and restoration of instrumentation during the Unit 2 refueling outag The licensee evaluated these events initially as personnel error In addition, these events were included in the licensee 1s ESF actuation reduction progra The goals of the program are to determine the root cause and corrective actions to prevent recurrenc Since the number of occurrence of events associated with undervoltage testing is considered to be high, the effective-ness of the licensee 1s program will be evaluated during subsequent inspection This is an unresolved item (237/89005-03; 249/89005-03).
Effectiveness of Training and Qualification Review of the operating events demonstrated mixed effectiveness of training and qualificatio The March 4, 1989, scram was attributed to a personnel error in that an equipment operator failed to follow a procedure and a example of questionable trainin The March 14, 1989, operator response to the EGC transient demonstrated excellent training effectivenes General Observations of Operations The inspectors observed control room operations, reviewed applicable logs and conducted discussions with control room operators during this perio The inspectors verified the operability of selected
emergency systems, reviewed tagout records and verified proper return to service of affected component Tours of Units 2 and 3 reactor buildings and turbine buildings were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks, and excessive vibrations and to verify that maintenance requests had been initiated for equipment in need of maintenanc In general, operations were conducted in the control room in a professional manne The inspectors, by observation and direct interview, verified that the physical security plan was being implemented tn accordance with the station security pla The inspectors observed plant housekeeping/cleanliness conditions and verified implementation of radiation protection control Housekeeping remained good with a steady improving tren During the inspection; the inspectors walked down the accessible portions of the systems listed below to veri.fy operability by comparing system lineup with plant drawings, as-built configuration or present valve lineup lists; observing equipment conditions that could degrade performance; and verified that instrumentation was properly valved, functioning, and calibrate The inspectors reviewed new procedures and changes to procedures that were implemented during the inspection perio The review consisted of a verification for accuracy, correctness, and compliance with regulatory requirements.
These reviews and observations were conducted to verify that facility operations were in conformance with the requirements established under technical specifications, 10 CFR, and administrative procedure The following systems were inspected and verified to be in correct system configurations:
Units 2 and 3 High Pressure Coolant Injection (HPCI)
Unit 2 emergency diesel generator Units 2 and 3 Low Pressure Coolant Injection (LPCI)
No other violations or deviations were identified in this are.
Maintenance and Surveillance (62703, 61726 and 71710)
During this inspection period, the inspectors observed maintenance activities on safety related and balance of plant system These activities. included replacement of the Unit 2 control room instrumenta-tion and the overhaul of the instrument air compressors and the several control rod drive In general, these activities were conducted in accordance with approved procedures and standard The maintenance personnel demonstrated very good maintenance practices and knowledge of the activities being performed.
In addition to the above maintenance activities, the inspectors observed Technical Specification required surveillance testing of the core spray,
- LPCI, HPCI and emergency diesel generators on both unit These surveillances were also conducted error-free, demohstrating a sound working knowledge of the activities being performe During this inspection period, no Technical Specification required surveillances were misse The following items were considered during this review:
the limiting conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and wer~
inspected as applicabl Additional items reviewed included verifi-cation that functional testing and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; and activities were accomplished by qualified personne Also, the inspectors verified that parts and materials used were properly ceitified; radiological controls were implemented; and fire preventi6n controls were implemente Work requests were reviewed to determine status of outstanding jobs and to assure that priority is assigned to safety related equipment maintenance which may affect system performanc Enforcement History During this inspection period, one violation (237/89005-02; 249/89005-02) pertaining to inadequate post maintenance testing performed on the CRD system in 1986 was issue Operational Events The following operations events had maintenance and/or surveillance activities as contributor (1)
On February 20, 1989, the isolation condenser was declared inoperable due to a failed contactor breaker on the service water inlet valv The breaker was replaced and the condenser declared operabl (2)
On March 14, 1989, the HPCI System was declared inoperable due to a damaged Gland Seal Leakoff (GSLO) pump breake After the GSLO pump started to lower HPCI Gland Seal Condenser Hotwell level, the pump failed to automatically stop, although the Hotwell was empt Attempts to stop the GSLO pump with the control room switch and local stop button also faile The GSLO pump was tripped by opening and closing the breake During troubleshooting a further attempt to start the pump to check operability also resulted in failure of the breake Further investigation showed damage to contacts in a relay assembl The assembly was replace (3)
The licensee informed the NRC that defective electrical cables were discovered on December 17, 1988, during installation of the Unit 2 diesel generator pre-lubrication system modificatio While making electrical connections, the licensee found that the inner insulation jackets of the 10 AWG wire were cut along
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the length of wir These cuts appear uniformly approximately every 7 inches with a cut length of about 1 inc The cable was a 3 conductor 10 AWG manufactured by Okonit The licensee initiated an investigation of the defective cable and contacted the manufacture Based upon discussions with the manufactu~er, it was determined that the flaw was created during the manu-facturing process and was caused by.a defective roller on the cable manufacturing machin It was also determined that the cable was part of a custom made lot that consisted of three reels totalling about 5100 fee A review of the purchase orders revealed that all three reels were purchased by Dresde The licensee found that the cable of one reel had also been used for a modification on the Unit 2 Control Rod Drive hydraulic system and that the other two reels were still stored in their warehous All of the installed defective cable was removed by the licensee and hold tags were placed on the other two reels of cable to prevent usag The licensee evaluated this occurrence for Part 21 reportability and requested Okonite, via a formal letter dated January 9, 1989, to provide a root cause analysis and actions to prevent recurrenc Based upon the licensee's evaluation, Part 21 reporting was deemed not applicabl The inspector reviewed the licensee's evaluation and concurred with their conclusio On January 30, 1989, the licensee informed the NRC that, during disassembly of two charging water check valves (valves 115)
on the control rod drive Hydraulic Control Units (HCUs), the internal bal1 checks were found to be missin The disassembling of the valves were being performed as investigative actions associated with the failure of these valves to pass an earlier leak rate tes The test was being performed as part of the licensee's !ST upgrade efforts and these check valves had not been previously tested for Unit A similar test had been performed on Unit 3 during the previous refueling outage without any failure Three HCU charging water check valves experienced excessive leakage during the Unit 2 test, JlO, Ell and Nl Valve Nl3 was inspected but no noticeable damage or deterioration of the internal ball check was foun The internal ball check was replaced for this valve and it subsequently pas~ed the leak rate tes Upon disassembly of valves JlO and Ell, the internal ball checks were found to be missin The valve material is 304 stainless steel.and the ball checks are stellit Subsequently, the licensee determined that the ball check that was missing from valve E-11 was caused by an inadequate main-tenance procedure that was used on the affected HCU during a disassembly of the HCU scram inlet valve in August 198 Because of the scram inlet and charging water check valve configuration, both valves must be disassembled in order to perform maintenance on either valv The maintenance work request did not require visual verification of the charging water check valve internals during restoration of the scram inlet valv The maintenance work request was also inadequate in that a leak test was not specified during post maintenance
- testin The licensee was unable to determine the actual cause of the missing internal ball check from valve J-1 However, it is believed that this missing part was also due to ma~n tenance activities that were performed during or before 198 The licensee does not believe that the internal ball checks were missing since initial installatio This is based on the fact that the Hydraulic Control Unit is inspected and shipped from the manufacturer as a complete uni In addition, a review of maintenance practices for the charging water check valve demonstrated that the internal ball check must be extracted from the valve body and will not accidentally fall ou The following were considered to be contributors to this event:
0 Prior to 1988, the licensee did not test the charging water check valves as part of the inservice test (IST)
program and as such did not detect the missing internal ball check Prior to 1988, the licensee's maintenance procedures on the scram inlet valves did not provide adequate instructions to ensure that the charging water check valve internals were installed prior to closure of the scram inlet/charging water check valves connection.
The safety significance of the event was determiend to be extremely low, by the inspector, in that the shutdown margin during the operating cycle was sufficient with all seven control rod drives potentially inoperable at their fully withdrawn position Additionally, for the drives to be considered inoperable, the reactor would have to be below 500 psig pressure and all control rod drive pumps inoperable during a reactor startu The failure to perform adequate post maintenance testing following maintenance activities on the HCUs is considered to be a violation of Technical Specifications 6. (237/89005-02; 249/89005-02).
As noted in Paragraph 4.c of this report, the litensee took prompt corrective actions to prevent recurrence and as such, no reply by the licensee is require (5)
On February 21, 1989, with Unit 2 at 16% power and Unit 3 at 93% power, the licensee, while performing an engineering revi~ determined that a Unit 3 design basis accident (loss of offsite power, and a failure of the Unit 2 125 Volt DC system)
could cause the loss of both Units 2 and 3 Standby Gas Treatment Systems concurrentl The licensee discussed the sequence of events and compensatory actions taken during a
. conference call with NRR and Region III on February 21, 198 The licensee is evaluating possible plant modifications and/or procedural changes to permanently resolve this issu * Approach to the Identification and Resolution of Technical Issues From a Safe~y Standpoin (1)
Following the discovery of the damaged relay assembly for the HPCI GSLO pump, a replacement relay assembly was procured and installe During post maintenance testing, the contacts in this *relay assembly wer*e. found to also be damaged, such that the HPCI GSLO pump would not star The problem was traced to a degraded capacitor*which allowed pump starting current to be applied across contacts not designed for that curren The contacts in the replacement relay assembly were repaired and the assembly was re-installe The failed capacitor was also replace Subsequent testing demonstrated that the HPCI GSLO pump was operabl Additionally, during troubleshooting of this problem, it was discovered that a wire had been landed on the wrong side of the local staft switch contact such that the HPCI GSLO pump could not be started locall The wire was re-landed in the correct locatio Also, it was discovered that the wiring diagram (12E2684B),
which shows the local switch, was incorrect. It matched neither the schematic control diagram (12E2532) nor the actual wiring in the fiel Errors on the schematic control diagram had been corrected on November 8, 1988, but a corresponding correction to the wiring diagram had not been mad The licensee corrected the drawing error prior to the unit startu (2)
On November 11, 1988, the licensee performed surveillance, DOS 300-3, "Cold Shutdown CRD Accumulator Charging Water Check Valve Leak Test, 11 on Unit This was the first performance of the leak test on these check valves; previously in 1988 the same surveillance was performed on Unit 3, also for the first tim Initial results of the test indicated seven charging water check valves had failed the the test acceptance criteria and an additional three valves had marginal result A similar leak test previously performed on Unit 3 had a 100%
pass rat The acceptance criteria of the test required the charging water check valves to maintain the hydraulic control unit (HCU) accumulators at greater than 980 psig (the low pressure alarm setpoint) for five minutes after tripping the operating control rod drive (CRD) pum On Decemb~r 26, 1988, all ten of the affected charging water check valves were flushed w1th clean demineralized water per an approved special procedur On January 6, 1989, the affected check valves were tested for leakage through the scram inlet valve or the charging water check valv The results of this test indicated that three of the ten check valves did not have leakage through the charging water check valve **
On January 18, 1989, the charging water check valve leak test was again performed on the seven check valves that failed the testing performed on November 11, 198 Faur of these passed the acceptance criteria. The three that failed, CRDs E-11, J-10 and N-13, were then disassembled and inspected on January 30,198 The visual inspection of N-13 did not reveal any apparent defects or obstruction A new internal ball check was installed and the check valve passed the subsequent leak tes However, the visual inspection of the other two check valves revealed that the internal ball checks were missin Also, see 4.b.(4) abov The licensee informed the findings of the visual inspection to the NRC duty officer via the EN During the review of the event pertaining to the missing HCUs check valve internals, the licensee completed the*
following corrective action The maintenance procedures was revised to ensure that the internal ball checks are installed and tested following maintenanc The licensee investigated the effects on the shutdown margin of having three HCUs failing the charging water leak tes The licensee also investigated the possibility of the stellite ball checks deteriorating and the stellite material being injected into the Scram Inlet Valve or the control rod drives.
The licensee's evaluation of the shutdown margin demonstrated that an adequate margin to criticality was maintained at all times during operating cycle 1 This evaluation assumed that all seven affected control rods would not be able to fully insert during a reactor scram, with low reactor vessel pressure (less than 500 psig), and that both CRD pumps were inoperable or trippe The charging water check valves are designed to allow the stored water in the HCU accumulator to scram the associated control rod during conditions when reactor vessel pressure is less than about 500 psi and no CRD hydraulic flow is availabl However, the licensee's calculations also demonstrated that under the same conditions and assumptions, with the most reactive control rod also inoperable at the fully withdrawn position (rod notch 48), adequate shutdown margin would not have been maintained throughout the ope~ating cycl This situation could only have occurred during unit startup and wtih reactor pressure at or near 200 psig, because the flange ball check (internal to the drive mechanism) would still have lifted admitting fluid at reactor pressure (200 psig) under the drive piston with sufficient force (800 psig) to overcome the drive break-away pressure of approximately 260 psid which should drive the mechanism to the fully inserted positio However, at this low pressure without accumulator pressure, the insertion time may be outside the Technical Specification requirement Above 500 psig reactor pressure, the drive will
fully insert in approximately 5.5 seconds without any assistance from the accumulator A review of General Electric's operating and maintenance instruction manual, GEI-92807A, Hydraulic Control Unit, revealed that the postulated drive failures are not related to charging water ~heck valves and that preventive maintenance on these valves is not required except when performing maintenance on the scram inlet valve This, in addition to the design requirements, indicates that under normal conditions, greater than 500 psig reactor pressure, the drives should fully insert without the assistance of the accumulator During startup conditions, the. normal rod pattern does not exceed 50% rod density (half of the rods fully inserted with the others at the fully withdrawn position) until reactor pressure is above 500 psi In this condition the reactor is at less than.1 percent thermal power with very little positive reactivit Although the licensee did not perform a postulated shutdown margin calculation for this condition, it is easy to derive that if all seven rods were in rod groups that would have resulted in being at the fully withdrawn positions and if the highest worth rod had failed at the fully withdrawn position, the shutdown margin would probably have been achieved as long as the high worth rod was not adjacent to any of the affected rods.
To have exceeded the shutdown margin during startup conditions, several additional errors would have had to occu First, an operator error concurrent with a failure of the rod worth minimizer must occur to have these two rods adjacent to one another, since the core should be greater than 50% rod density at less than 500 psig (Black and White rod pattern).
Secondly, one of the adjacent rods must be the highest worth ro Both of these conditions are unlikely and did not occur during cycle 1 The highest worth rod, D-9, was not adjacent to any of the seven affected rod Additionally, not all of the seven rods would have been withdrawn prior to 500 psig because of the black and white checkered rod patter The licensee performed an analysis of the possible injection of the stellite ball check (Haynes Stellite Grade 3 Alloy) into the vesse The analysis of the material breakdown revealed that the stellite ball contained 27.5 grams of cobal The model evaluated two possible methods of breakdow These were a slow dissolving method evenly over a 500 day period (approxi-mately one operating cycle) and an instantaneous injection metho The cobalt concentration, via the slow injection model, would have resulted in an increase of :25uCi/gm each da In addition, a sample containing 1 liter of vessel water at these concentrations would range from 4 REM for the slow dissolution, to 200 REM fo~ instantaneous ~njection. A review of reactor coolant samples during the previous 2 operating cycles indicated that doses of these magnitudes were not
occurring and that concentration of cobalt was stable in a range of 1Xl0-4uCi/gm to 1Xl0-3uCi/g Based upon the above evaluations, the licensee determined that the safety significance of the event was very lo The inspector reviewed the licensee's evaluations and concurred with the conclusio These actions demonstrated a very good approach to resolving technical issues from a safety standpoin Responsiveness to NRC Initiative The licensee demonstrated outstanding performance in response to NRC concerns regarding potential generic implications of the defective Okonite cables by promptly pursuing Part 21 reportability and determination of the extent of the cable proble Additionally, the licensee took immediate actions to recover all of the defective cable that was installed within the plan Assurance of Quality, Including Management Involvement and Contro The licensee demonstrated excellent management and quality assurance involvement in all of the above event This involvement resulted in imprJvements of several maintenance activitie Examples included post maintenance test procedures and the detection and removal of defective cables associated with safety related system No other violations or deviations were identified in this are.
Safety Assessment/Quality Verification (35502, 90712, 92700)
The inspector reviewed the Quality Assurance (QA) Onsite and Offsite audits performed in 198 The review was conducted to assess the effectiveness of the licensee's program to identify significant trend A total of 4 offsite and 56 onsite audits were reviewed, and the findings of the audits were analyzed to determine the existence of significant trend The audit findings were analyzed and assigned by the inspector to a matrix cont~ining the 18 QA criteria found in 10 CFR 50 Appendix B - Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plant Apparent trends were noted in the following areas:..
Criteria II Criteria V Criteria VI Criteria XVII QA Program Instructions, Procedures and Drawings Document Control QA Records The apparent trends were then compared to the licensee's trending progra The licensee's program was found to be effective in tren9ing audit
findings and identifying significant trends that may develo The four areas that the inspector had identified were also found and documented by the license The licens~e developed and completed corrective actions to arrest these trend No violations or deviations were identified in this are.
(Closed) TI 2500/17, Inspection Guidance for Heat Shrinkable Tubing (25017) and IE Information Notice 86-53 The Temporary Instruction required verification of how the licensee addressed IE Information Notice (IN) 86-53, Improper Installation of Heat Shrinkable Tubin The IN addressed specific problems on Unit 3 that were identified by the Safety System Outage Modification Inspection (SSOMI).
Subsequent to the SSOMI findings, the licensee committed to inspect Unit 2 Raychem splice A total of 466 splices (56%) were inspected with a total of 7 deficiencies being identifie All of the improperly installed splices, on both Units 2 and 3, were corrected prior to returning the units to servic The SSOMI followup team inspected several of the reworked Raychem splices and considered them to be acceptabl The licensee revised DMP 040-25, Installation and Removal of Raychem Heat Shrink Products, in July 1987 to incorporate the vendor's application guide that includes drawings for different splice configurations and a checklist that preplans and prepares for each splic For example, the procedure includes attributes such as, verification that splices are not installed over the braiding, verification of proper splice kit (size and environmental qualification), adequate splice overlap, minimum bend radius, and that the splices are properly cooled prior to placement in conduit or junction bo Raychem has provided two hands-on workshops to the electrical maintenance staff and the quality control (QC) inspec:t:.ors in October 1985 and January 198 The inspector reviewed several work requests regarding the installation of Rayche'm splices and found them to be in compliance with DMP 040-2 The installers and QC inspectors were properly trained and qualified and the splices were properly installed and met EQ requirement This TI and IN are considered close.
Licensee Event Reports Followup (93702)
Through direct observations, discussions with licensee personnel, and review of records, the following event reports were reviewed to determine that reportability requirements were fulfilled, immediate corrective action was accomplished, and action to prevent recurrence had been accomplished in accordance with Technical Specification (Closed) LER 249/88006-01:
HPCI Area Temperature Switches Exceeded Technical Specification Limit Due to Instrument Setpoint Drif This supplemental report was issued to provide an update regarding the corrective actions implemented to resolve the High Pressure Coolant Injection (HPCI) room and Main Steam Line (MSL) tunnel temperature switch
calibration proble The cause of the HPCI temperature switches* failure to trip within the required limit was attributed to instrument setpoint drif The corrective actions included establishing a task force to review the instrument configuration and calibration method Additional testing and augmented inspections of the temperature switches were also performe As a result of this review, an improved calibration method was implemente Replacement of the temperature switches is also under revie (Closed) LER 237/88022-01:
Heat Damage to Upper Elevation Drywell Components Due to Closed Ventilation Hatche This supplemental report was issued to summarize the results of the task force investigation and to summarize repair work either completed or scheduled as a result of this even The cause of the.excessive temperatures on the fourth and fifth drywell elevations was attributed to lack of forced ventilation to the fifth elevation (the Reactor Head Area) that resulted from the ventilation hatches being close The root cause of this event was attributed to deficiencies in two.procedures (DOS 1600-10 and DMP 1600-5).
The procedures were revised to clearly specify the required verification that the two manway hatches, two ventilation supply hatches and two ventilation return hatches in the refueling bulkhead are ope In addition, a checklist in DMP 1600~5 was revised to include a sign-off that the ventilati9n and manway hatches were left wired ope Repair/
replacement work on valves, cables, insulation, paint, snubbers and motors were completed prior to Unit 2 restar This LER is currently being evaluated for potential enforcement actio *LER 249/88006-01 was reviewed against the criteria of 10 CFR 2, Appendix C, and the incidents described meet all of the following requirement Thus no Notice of Violation is being issued for the LE The event *was identified by the licensee, The event was an incident that, according to the current enforcement policy, met the criteria for Severity levels IV or V violations, The event was appropriately reported, The event was or will be corrected (including measures to prevent recurrence within a reasonable amount of time), and the event was not a violation that could have be~n prevented by the licensee 1 s corrective actions for a previous violatio No violations or deviations were identified in this are.
Report Review During the inspection period, the inspectors reviewed the licensee 1 s Monthly Operating Reports for January and February 198 The inspectors confirmed that the information provided met the requirements of Technical Specification 6.6.A.3 and Regulatory Guide 1.1.
Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, items of noncom-
. -,
'*-
~
pliance, or deviation Unresolved items disclosed during the inspection are discussed in Paragraph.
Exit Interview (30703)
The inspectors met with licensee representatives (denoted in Paragraph 1)
on March 17 and April 11, 1989, and informally throughout the inspection period, and summarized the scope and findings of the inspection activi-tie The inspectors also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspector during the inspectio The licensee did not identify any such documents/processes as proprietar The licensee acknowledged the findings of the inspection.
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