IR 05000341/1988012
| ML20207B752 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 07/19/1988 |
| From: | Cooper R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20207B736 | List: |
| References | |
| TASK-2.K.3.28, TASK-TM 50-341-88-12, CAL, NUDOCS 8808040126 | |
| Download: ML20207B752 (27) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
- Report No. 50-341/88012(DRP)
Docket No. 50-341 Operating License No. NPF-43 Licensee: Detroit Edison Company 2000 Second Avenue Detroit, MI 48226 Facility Name: Fermi 2 Inspection At: Fermi Site, Newport, Michigan Inspection Conducted: April 1 through May 27, 1988 t
Inspectors: W. Rogers M. Parker S. Stasek T. Silko J. House P. Pelke .
Approved By: Richard . Cooper, Chie * 7[///88 '
Reactor Projects Section 3B Dats
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Inspection Summary Inspection on April 1 to May 27, 1988 (Report No. 50-341/88012(DRP))
Areas inspected: Action on previous inspection findings; operational safety; maintenance; surveillance; LER followup; followup of events; plant trips; Confirmatory Action Letter followup; Operational Safety Team Inspection followup; management meetings; TMI action item followup; Temporary Instruction followup; and regional request Resultv Six violations were identified (Paragraphs 2, 6, and 10). Two unresolved items were identified (Paragraphs 6 and 9) and four open items were identified (Paragraphs 3, 6, and 8).
8808040126 880723 PDR ADOCK 05000341 Q PDC
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DETAILS Persons Contacted
_ Detroit Edison Company
- P. Anthony, Licensing
- L. Bregni, Senior Engineer Licensing
- S. Catola, Vice President, Nuclear Engineering and Services
- C. Gelletly, General Supervisor Nuclear Engineering
$0. Gipson, Plant Manager
- L. Goodman, Licensing l
$D. Grimes, Fluids Systems Engineer
- R. Lenart, General Director, Nuclear Engineering
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$*W. Orser, Vice President Nuclear Operations
) #R. Stafford, Director NQA and PS I $W. Terrasi, General Supervisor Chemistry l $#*W. Tucker, Superintendent Operations
- C. Wald, Supervisor PQA
$E. Wilds, Lead Engineer Fluids
- U.S. Nuclear Regulatory Commission
$J. House, Regional Inspector
- M. Parker, Senior Resident Inspector
- P. Pelke, Project Inspector
$#*W. Rogers, Senior Resident Inspector
- T. Silko, Inspector
- S. Stasek, Inspector
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- Denotes those attending the exit meeting on May 27, 1988.
- Denotes those attending the exit meeting on June 1, 1988.
$ Denotes those attending the exit meeting on April 20, 1988. Followup on Previously Identified Items (Closed) Violation (341/87038-01): Failure to maintain locking devices on locked valves. This item was previously reviewed in Report No. 341/87046(DRP). The inspector reviewed further walkdowns conducted by the licensee in the drywell and high radiation area These walkdowns were conducted during the LLRT outage and had not been previously done because of ALARA/ inaccessibility reason Prior to coming out of the LLRT outage, the licensee performed surveillance P0M 27.000.01, "Locked Valve Lineup Verification." l This surveillance verified, including independent verification, the locked valve lineup for all valves listed on the Locked Valve List in POM 21.000.14, "Locked Valve Guidelines." All applicable valves were verified to be in the correct position with the correct locking device in place. A search of the licensee's record system indicated that the last time POM 27.000.01 was performed was in November 198 More frequent usage of this surveillance procedure would be beneficia ____ _ _____ - _- - _______________-________________-__ ____________- _ _ _ _
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Further walkdowns conducted by NRC inspectors have not identified any additional examples of missing locking devices on locked valves. The inspector reviewed DER 87-516 which was written to document the missing locking device on Valve C41-F024. Nuclear Security conducted an investigation at the Plant Manager's request and could not
- determine why C41-F024 was missing a locking device. This item is considered to be close b. (0 pen) Violation (341/88006-07): Failure to perform the afternoon shiftly channel checks by 2330 on March 13, 1988. The inspector reviewed DER 88-488 which documents the missed channel check Lessons Learned No. 88-04 was developed and placed in the Lessons Learned 8ook. DER 88-265,88-488, and LER 87-021 were reviewed with shif t members during the week of March 14, 1988. DER 88-265 dealt with the February 18, 1988 event in which the Core Spray differential pressure was not verified locally at least once per 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> LER 87-021 dealt with the June 7,1987 event in which the reactor coolant system leakage limit surveillance interval was exceeded by one hour. A line item was added on the "Routines Sheet" to collect surveillances on each shift. Additionally, the "Routines Sheet" was modified to include an NASS sign-off for each shift. Revision 1 to Operations Performance Standard (OPS) No. 206, "NSS Shift Turnover Briefing," was issued on April 11, 1988, to add that short term surveillances (both periodic and those performed to meet Technical Specification action statements with a frequency of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or less)
must be discussed during the shift turnover briefing, including when-they are to be performed and specifically who is to perform them.
l Subsequently, on May 4,1988, during the review of the completed daily and shif tly surveillances at 0700, the licensee discovered that the shiftly surveillances required during the 1600-2400 shift ,
on May 3, 1988, were not completed. The shiftly surveillances for the 0000-0800 shif t on May 4,1988 were complete The inspector l reviewed DER 88-0999 which documents this event.
l During this time frame, the licensed operators were on 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts, 0600-1800, and 1800-0600, while the non-licensed operators were working the normal six shift schedule (0800-1600,1600-2400, 0000-0800). The surveillances for the 0800-1600 shift on May 3, 1988 were performed at 0730 by the patrol NSO assigned to the 0600-1800 shift. At approximately 1430, the patrol NS0 became involved in a torus entry evolution and was required to inspect /
troubleshoot the torus-to-drywell vacuum breaker valves. The NASS was aware of the patrol NS0's activity but did not specifically reassign the responsibility for performing the surveillances. The l patrol NS0's involvement with the vacuum breaker valve inspection
- extended through his relief time of 1800 hours0.0208 days <br />0.5 hours <br />0.00298 weeks <br />6.849e-4 months <br />. The 1600-2400 shiftly surveillances would have been normally accomplished between 1600 and l
l 180 A shift turnover had occurred at 1545 for the non-licensed operators and a turnover occurred at 1830 for the licensed operator However, at both turnovers, each NSS failed to implement the requirements of OPS No. 206. In addition, the patrol NSO did not alert the NASS that he would not be able to perform the shiftly surveillance in the 1600-1800 time frame.
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During the period from 1800-2400 on Nay 3, 1988, the CRNSO on the 1800-0600 shift reviewed the Routines checklist and initialed that the shiftly surveillances had been completed. However, he did not physically review the completed curveillance sheats, but assumed that they had been completed. The surveillances are required to be completed every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Allowing for the 25% time interval extension, the next shiftly surveillance was due at 2230 on May 3, 198 The surveillance was subsequently completed at 0042 on May 4, 1988, 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 12 minutes beyond the critical completion dat Licensee investigation determined that all parameters were within Technical Specification requirements. This is a repeat example of Violation No. 341/88006-07. Additionally, the initial corrective actions to the original violation were not adequate to prevent a recurrence. This second failure to perform the shiftly channel checks is considered a violation (341/88012-01(DRP)) of Technical Specification surveillance requirement c. (Closed) Violation (341/87026-07(DRP)): Failure to perform channel checks on the Division II MSIV leakage control system pressure control instrumentation within the required time interval. Administrative Procedure POM 12.000.25, "Temporary Modifications," was reviewed to verify inclusion of requirements to revise and maintain critical plant documents such as drawings and procedures upon initiation of a temporary modification. The inspector also reviewed six temporary modifications that were outstanding at the time of the followup and verified that associated drawings and/or procedures were appropriately
"marked up" or annotated for use in the control room in r.ccordance with POM 12.000.25. No discrepancies were noted. This item is close d. (Closed) Violation (341/87006-01(DRP)): This violation involved a ,
failure of the design control process to appropriately verify the adequacy of the thermal recombiner system (TRS) desig Vendor drawings identified the blower seal to be designed for a cooling water flow of one gpm with a residual heat removal system pressure to the TRS of 100 psi. After failure of the TRS on January 9, 1987, the actual pressure was measured at 220 psi with a flow of 3 gp This caused an excessive inleakage through the blower seal into the TRS, resulting in failure of a Technical Specification surveillance tes As identified in the licensee's response to the Notice of Violation, NRC-87-008, dated June 12, 1987, the failure to detect the improperly sized orifices in the cooling water supply from the RHR system was caused by utilizing the keep-fill system instead of the RHR system during TRS testing. Since keep-fill is at a lower system pressure than RHR the inadequate testing led to the inability to detect the design error and prevented earlier detection. The licensee determined that the vendor installed orifices were improperly sized for the specific field conditions. The oversized orifices resulted in excessive seal inleakage, and cooling of the TRS heater gases.
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Properly sized orifices were manufactured per Engineering Design Package (EDP) 6846, and installed per Work Order 574116. This action was completed on January 22, 1987. Testing was successfully completed per Operating Order 653743 on January 27, 1987. The inspectors observed the majority of the troubleshooting and testing
- involving the TRS cooling water supply and orifice sizing to ensure adequate resolution of the design deficienc ~
Further evaluation of the event as described in Violation 341/87006-01, determined that improperly sized orifices were supplied by the vendor in the cooling water lines to the blower shaft seals. It was further determined that these vendor supplied orifices were improperly sized for the specific field conditions. This resulted in excessive seal inleakage and cooling of the recombiner heater gases. Properly sized orifices were installed on January 22, 1987 and testing was successfully completed on January 27, 198 (Closed) Violation (341/87006-02(DRP)): This item concerned a violation of 10 CFR 50, Appendix B, Criterion XI, Test Control, for failure to control TRS preoperational test and surveillance testin During preoperational and surveillance testing, a lower pressure (60 psi) keep-fill system was used versus the higher pressure (250 psi) RHR syste The RHR system is the designated post LOCA source of cooling water for the TRS. During a TRS surveillance test, the RHR system was started to support another activity c1d became the cooling medium for the TR Subsequently, the TRS was unable to successfully pass the surveillance test. The cause of the test failure was excessive TP.S blower seal inleakage that could only be identified while using the higher pressure cooling mediu As identified in the licensee's response to the Notice of Violation, ,
DECO Letter NRC-87-081, dated June 12, 1987, a decision was made during the preoperational test program and carried over into the surveillance test program to use the keep-fill system rather than the RHR system to test the design and operation of the TRS. The reason for the licensee's decision was to minimize the load on the RHR pumps. However, the licensee did not properly analyze the resulting impact on TRS operabilit A temporary change (T-4608) was made to Procedure 24.409.01, "Post LOCA TRS Functional Test," effective December 26, 1986, preventing the use of the keep-fill system during testin A permanent change was incorporated into Pro edure 24.409.01, Revision 7 on January 8, 1987. The operating procedure, 23.409, Revisiort 10 was issued on January 7, 1987. These procedures now require at least one RHR pump in service to provide cooling water to the blower and spray cooler any time a thermal recombiner is operatin (Closed) Violation (341/87006-03(DRP)): This item concerned a violation of Technical Specification 3.0.4 in which the licensee entered Operating Condition 2 without both divisions of TRS operabl This was a result of the test procedure, which implemented Technical Specification Surveillance Requirement 4.6.6.1.a. not requiring TRS seal cooling to be accomplished with the RHR system,
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At the time of TRS inoperability discovery, during surveillance testing on December 26, 1987, the licensee took action consistent with Technical Specifications and commenced a reactor shutdov The operating procedure and the surveillance test procedure were changed to require the use of the RHR system during TRS testing as discussed above and the RHR cooling water flow was throttled t the TRS to compensate for the higher RHR pressure. Upon completion of these actions on December 27, 1987, both TRS divisions were satisfactorily tested allowing the TRS to be declared operable and the plant shutdown was terminate Further evaluation of the event determined, as described in Violation 341/87006-01, that improperly sized orifices were supplied by the vendor in the cooling water lines to the TRS blower shaft seals. It was further determined that these vendor supplied orifices were improperly sized for the specific field conditions. This resulted in excessive seal inleakage and cooling of the recombiner heater gaser below Technical Specification limit Proper sized orifices were installed on January 22, 1987 and the TRS was successfully tested on January 27, 198 The completion of the corrective actions above resolved the specific problem associated with the TRS. To determine whether this type of problem existed with other systems, the licensee's Independent Safety Engineering Group (ISEG) was assigned to perform a review of select systems to identify similar test condition deficiencie Cight systems were selected for revie The inspector reviewed the completed ISEG report, ISEG-87-004, "Preoperational Test / Surveillance Test Performance Evaluation Report," dated June 29, 1987. The report did not identify any potential problems similar to the TRS deficiency, However, the report did identify deficiencies related to system "
operation, procedure problems and omission of testing requirement I Specific recommendations to resolve the deficiencies were provided and corrective action was being tracked by ISEG personne (Closed) Unresolved Item (341/88003-08(DRP)): Limiting Condition for Operation associated with the noninterruptible control air syste ,
This matter was reviewed and became a violation in Inspection Report No. 8801 h. ,( Closed) Unresolved Item (341/88006-06(DRP)): Position of an instrument rack valve associated with a reactor protection system drywell pressure inpu At 0915 hours0.0106 days <br />0.254 hours <br />0.00151 weeks <br />3.481575e-4 months <br /> on March 16, 1988, while performing a special valve lineup in preparatien for a Local Leak Rate Test (LLRT), the rack isolation valve for the Reactor Protection System (RPS) Channel C drywell high pressure instrument (C71N0500) was found in an apparent closed position. This information was brought to the Nuclear Shift Supervisor's attention and following completion of the LLRT the rack isolation valve was returned to its required open positio J
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The plant was in cold shutdown at the time of the event, but investigation determined that the rack valve had been in the not-tull-open position since the last time the valve was manipulated on October 16, 198 NRC and licensee investigations determined the cause of the valve mispositioning to be a failure to follow I&C
- Surveillance Procedure 44.010.039, "RPS and NSSS Drywell Pressure, Channel A2/C Calibration / Functional," in that the rack valve was not restored to its required positio The surveillance procedure included independent verification of the rsck valve positio Records indicate that on March 15, 1988, in preparation for an LLRT, an instrument repairman (utility-non-licensed) and an independent verifier (utility-licensed) performed a valve lineup in accordance with Procedure 41.000.09, "Process Instrumentation Removal From and Return to Service," and verified that the rack isolation valve was properly positioned. Both utility workers were interviewed and stated the rack valve position was not actually verified prior to or upon restoration of the LLRT. The line up sheet used by the utility workers provides a sign-off in one location signifying that all valves positions listed have been verified. In fact, the utility workers signed the lineup sheet indicating that the valves which actually changed position due to the LLRT were restored to proper position. The wurkers failed to realize that by s ign ing the lineup sheet it indicated that all valves listed, and not just the valves effected by the LLRT, were properly positione Failure to adhere to the procedural steps of 44.010.039, restore the rack valve to its proper position and provide independent verification; and failure to follow' Procedure 41.000.09, signing a valve line up sheet when not all valve positions listed on the sheet were verified, is concidered a violation (341/88012-10(0RP)) .
of Technical Specification Section 6. The Reactor Protection System (RPS) of Fermi 2 utilizes a one-out-of-two taken twice logic. This logic requires that either Channel Al or A2 of RPS Division I be actuated and Channel B1 or 82 of RPS Division II be actuated in order to receive a reactor scram signa RPS Channel A2 is defeated when the Channel C Drywell High Pressure instrument is valved out: however, a scram signal would have been generated if RPS Channel Al was actuated in conjunction with Channel B1 or B Channel C Drywell High Pressure instrumentation also provides an isolation signal to Division II of the NSSS system. Had an actual high drywell pressure condition occurred, several double valve ischtion protecticas would not have occurred, although single l
l valve isolations from the unaffected channels (Division 1) would l have been in effect. The Division II standby gas treatment system and backup air compressor (P53-0002) would not have initially automatically started due to the higher Channel C pressure setpoint, however, operator action could have manually initiated the equipment.
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In actuality, Channel C was not fully isolate Data available between October 1987 and February 1988 indicated that Channel C lagged behind Channels A, B, and D by approximately 0.5 psig during the time containment was pressurized. Since a calibration of Channel C pressure transmitter on March 24, 1988 indicated that b the transmitter and trip unit were within acceptable tolerances, it is concluded that any Drywell pressure trip function would have been inhibited until Drywell pressure reached approximately 2.38 psi A high Drywell actuation setpoint of 2.38 psig is greater than the maximum setpoint of 1.88 psig as specified in Technical Specification 2. This is considered a violation of Technical Specification 2.2.1 (341/88012-02(DRP)).
Immediate corrective actions by the licensee included the instrument being properly restored to service and all instrument repairmen completing required reading in March of 1988 regarding the proper performance and requirements of independent verification. Long term corrective actions included (1) a review of the instrument and control surveillances to ensure that all Technical Specification transmitters were included in an instrument (operations) lineup, (2) a procedural change was implemented which requires the performance of instrument lineups prior to startup from outages over 30 days long, (3) guidance was provided to licensed operators on the need to be aware of instrument discrepancies even if the instruments meet their channel check requirements, (4) required reading describing this event was issued to both maintenance and operations departments, and (5) training was provided to maintenance perconnel related to restoration to service and second verificatio The inspector reviewed partially or in whole Items (1) through (4)
and no inadequacies were identified. The inspector noted, with .
regard to Iten (5), that the training was provided but testing af terw:rds revealed a failure rate of 15%. The first level supervisors have been instructed not to have any individual who failed the test perform any independent verification. The licensee plans to retrain the individuals who did not successfully pass the initial training pr0 gra No other violations or deviations were identifie . Operational Safety Verification (717071 The inspectors observed control room operations, reviewed applicable logs and conducted discussions with control room operators during the period from April 1 to May 27, 1988. The inspectors verified the operability of selected emergency systems, reviewed tagout records and verified proper return to service of affected component Tours of the drywell, reactor building and turbine building 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 .
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The inspectors, by observation and direct interview, verified that the physical security plan was being implemented in accordance with the station security pla The inspectors observed plunt housekeeping / cleanliness conditions and verified implementation of radiation protection controls. During the inspection, the inspectors walked down the accessible portions of the standby liquid control system, scram discharge volume portion of the reactor protection system and the core spray system to verify operability by comparing system lineup with plant drawings, as-built configuration or present valve lineup lists; observing equipment conditions that could degrade performance; and verifying that instrumentation was properly valved, functioning, and calibrate 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 During these reviews, observations and walkdowns the inspectors noted: During the core spray (CS) system walkdown, the inspector identified to the nuclear supervising operator (NS0) that the Division 2 CS minimum flow valve (E21-031B) was close The NSO promptly returned the valve to the required position and a Deviation Peport (DER 88-1055)
was initiated, The licensee concluded that the valve automatically closed on a false high flow signal which was generated during an I&C preventative maintenance procedure (PM) on the Division 2 CS flow indicator. The indicator shares a common reference leg with a flow switch which provides input to the minimum flow valve logic. The PM on the flow indicator apparently caused a pressure spike in the instrument line which the flow switch sensed as greater than its .
setpoint of 635 gpm and generated a valve closure signal. The logic of the minimum flow valve generates an open signal on a low flow condition in conjunction with pump operation. With this logic, CS Division 2 remained operational due to the fact that the minimum flow valve would have properly opened upon actuation of the syste Corrective action by the licensee is to modfy the impact statement of the PM as to the possibility of a minimum flow valve closur The inspector reviewed the situation and the corrective actions
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and considered them acceptabl On May 17, 1988, the licensee began the initial inerting of Primary Containment. While inerting the torus, the Division 2 primary containment monitoring system (PCMS) torus monitor failed to provide accurate hydrogen and oxygen concentrations. Investigation determined that 1 leak on the suction side of the PCMS vacuum pump was causing inaccurate readings. The leak location, which did not jeopardize ;
primary containment integrity, was repaired and division 2 PCMS l was declared operable. While attempting to inert the drywell (D/W), l
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the D/W inboard purge valve (T4803-F602) was found to be inoperabl Operators took the appropriate actions under the license by closing the outboard containment isolation valves. With these valves closed a procedure change was needed to complete the inertin ,
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1 Procedure 23.406, "Primary Containment Nitrogen Inerting and Purge System," was revised to allow D/W inerting through the following steps: hold the D/W-to-torus vacuum breakers open, fead nitrogen into the D/W and bleed containment air out the torus purge lin Inspector review of the procedure determined that these actions were in compliance with Technical Specifications. At 2130 on May 18, 1988, inerting of the containment was completed and in compliance with Technical Specification 3.10.5. The inspector monitored the licensee's activitics related to containment inerting and no deficiencies were noted, c. The inspector reviewed Abnormal Operating Procedure 20.129.01, Loss of Station and/or Control Air. During the review the inspector noted that the list of equipment affected by loss of air was inaccurate and not complete. Also, the directions for operator response to such a condition were not as complete as would be expected. Improvement of this procedure is considered an open item (341/88012-03(DRP)).
d. On May 5, 1988, the inspector observed the NSS declare the containment vacuum breakers operable following completion of post maintenance testing of the vacuum breakers. Out of Service Log (OSL)88-334 had been written on the vacuum breakers on May 3, 1988, when they failed surveillance testing. The NSS changed the OSL to tracking after reviewing the completed surveillance test and found it to be a successful test. The NSS did not review the completed work raquest prior to declaring the valves operable. The inspector considered this an imprudent action and discussed this matter with operations management. Management did not consider this action appropriate and discussed the matter with the personnel involved. Inspection efforts will continue in this area to determine the frequency that these situations occu ,
e. The failure of the vacuum breakers invoked a Technical Specification action to change the testing interval of the vacuum breakers. The new testing interval is to be approved by the NRC. The licensee wrote DER 88-0949 to ensure the new schedule is submitted to the NR The inspector requested to know what the new schedule will b The licensee committed to provide the appropriate informatio .
f. During the week of May 1, 1988, the inspector could not identify one consolidated document that clearly showed what work requests had been authorized by the shift supervisor to be worked. A recent (
revision of the work request administrative procedure no longer l
required the operating authority to maintain a copy of the current work requests. The inspector identified this situation to operations i management and requested that a record be kept of outstanding work requtst Management directed that a notebook be kept in the shift
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supervisor's office containing a copy of those work requests. On
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May 22, 1988, the inspector reviewed the newly established notebook and found it to be very inaccurate. This condition was brought to operations management attention who indicated that clearer, more formal directions needed to be provided in the maintenance of the l notebook. Establishment of adequate controls on the notebook is considered an open item (341/88012-04(DRP)).
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d On a few occasions during the inspection period the inspectors noted that the engineered safety features status board was not being utilized by operations personnel. Operations management was informed of this situation and committed to emphasize board usage and is considering adding board activation to the OSL. The
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inspector will continue to monitor usage of the board and management actionsto assure that the board is use NoviolationsordeviationswereidentifiedinthisaYe . Monthly Maintenance 0bservation (62703)
Station maintenance activities on safety-related systems and components listed below were cbserved to ascertain tnot they were conducted in accordance with approved procedures, regulatory guides and industry codes or standards and in conformance with Technical Specification 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 initiatl g the work; activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and fire prevention controls were implemente Work requests were reviewed to determine the status of outstanding jobs and to assure that priority is assigned to safety-related equipment maintenance which may affect system performanc ,
The following maintenance activities were observed:
- emergency diesel generator inspection
- troubleshooting of the Division 1 hydrogen recombiner Follcwing completion of maintenance on the hydrogen recombiner, the inspectors verified that these systems had been returned to service properl P During the EDG 11 maintenance on April 6, 1087, in accordance with P0M 34.000.14, "Emergency Diesel Generators - Inspection," the inspector noted that Revision 9 was being used in the field, however, Revision 10 had been issued on April 5, 1988, and was available at the Production Information Conter (PIC). The inspector informed the field personnel, including QC, and the curre,t revision was obtained. The field personnel were unaware that the new revision had been issued. Subsequently, the inspector reviewed the completed surveillance package to determine if any
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steps were missed. The only concern identified was that Revision 10 had added an Attachment 3, "Parts Tracking Sheet," tc log any parts leaving the engine bay. The field personnel were logging this information on a draf t "Attachment 3," however, no completed log could be found by the inspector during a subsequent document revie ,, ,
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l Also during this review, the inspector noted that POM 12.000.07, Revision 26, "huclear Production Procedures and Orders," Paragraph 5. states that technical procedures shall be followed and ustd in accordance with the following: If there are no signoffs in the body of the procedure, the procedure need not be in hand when performing the
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activities it addresses. The licensee committed to review Paracraph 5.4.2 for procedural adequac Cc s.p'eted work requests were reviewed to verify that appropriate authorizations had been received to restore equipment to service, an adequate description of maintenance actions had been documented and appropriate independent verifications had been documente The work activities reviewed were:
- replacement of transmitter B21-N6900
.* hydraulic control unit repair During the review of Work Request 0232880209, the inspector noted that there was no independent verification for the restoration of two wires on HCU 26-1 This verification should have been documented on the interim alteration checklist as delineated in Procedure 12.000.080, "Conouct of Electrical Field Activities." This is considered another example of a violation of Technical Specification 6.8.1 (341/88012-10(DRP)) of licensee personnel failing to implement approved procedures associated with independent verificatio ,
No violations or deviations were identified in this are . Monthly Surveillance Observation (61_726)
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The inspectors observed Surveillance Test 24.409.01, "Post LOCA Therma'i Recombiner Functional Test," required by Technical Specifications and verified that: testing was performed in accordance with adequate procedures, test instrumentation was calibrated, limiting conditions for operatior were met, removal and restoraticn of the affected components were accomplished, test results conformed with Technical Specifications
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and procedure requirements 2nd were reviewed by personnel other than the individual directing the test, and any deficiencies identified during the testing were properly reviewed and resolved by appropriate nianagement personne The inspectors also witnessed portions of the following test activities:
- 24.415 Drywell Cooling Fan 1 and 2 Operability Test
- 27.106.05 Control Rod Drive Timing Test and Adfustment (Rod 46-47 only)
- 24.202.04 HPCI System Automatic Actuation / Suction Valve Auto l Transfer The inspectors performed a record review of completed surveillance tests.
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The review was to determine that the tests were accomplished within the l required Technical Specification time interval, procedural steps were j
l properly initialed, the procedure acceptance criteria were met, independent
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verifications were accomplished by people other than those performing the test,~and the tests were signed in and out of the control room surveillance log book. The surveillance tests reviewed were:
- 74.000.18 Chemistry Shif tly, 72 Hour and Situation Surveillances
- 24.203.01 CSS Discharge Piping Filled and Valve Position Verification
- 54.000.06 APRM Calibration
- 27.106.05 Control Rod Drive Timing Test and Adjustment
- 54.000.03 Control Rod Scram Insert Time Test
- 42.501.01 Diesel Fire Pump Battery Weekly Surveillance
- 27.501.23 Weekly Fire Protection Inspection During the surveillance reviews, the inspector noted that some of the acceptance criteria for 27.501.23 were not met. The Nuclear Shift Supervisor had reviewed the surveillance and improperly accepted the results as satisfactory. Although this surveillance was not one required by the Technical Specifications, the same level of post-surveillance review as would be performed for a Technical Specification surveillance was accomplished. The procedure was brought to the attention of the shift supervisor and operations management. Work requests were initiated for troubleshooting and repair of equipment to allow the satisfactory completion of the surveillance tes No violations or deviations were identified in this are . Licensee Event Reports Followup (92700)
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 corrective action to prevent recurrence had been accomplished in accordance with Technical Specification (Closed) LER 86-47 and Revision 1: Inuperability of TRS results in entry into Technical Specification 3. (Closed) LER 85026-01: On June 15, 1985, while in Operational Condition 4, the Emergency Equipment Cooling Water (EECW) system initiated automatically when a third Reactor Building Closed Cooling Water (RBCCW) pump was shut down as part of a normal pump rotation scheme. The resulting pressure transient caused the di fferential pressure across the EECW headers to decrease below the setpoint which initiated the EECW system. As previously discussed in Inspection Report No. 341/88006 under the closeout of LER 87051, EDP-8126 has been implemented to prevent inadvertent initiations of EECW when rotating RBCCW pump The LER discusses that the corrective action in 1985 was to modify the system operating procedure to place both divisions of the EECW system in manual override momentarily prior to switching RBCCW pumps until the transfer was completed and system flow was stabilized. A'out a year later, several EECW/RBCCW surveillance procedures were rivised to include these same steps to prevent inadvertent EECW actuations. The LER further
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states that performance of these procedural steps was of short to moderate duration and the system was restored to operability before the expiration of the time limit to change operational conditions specified in Technical Specification 3.0.3. However, the LER does not address that action was not taken within one hour to change operational conditions. DER 87-174 documents that at least on seven occasions both divisions of EECW were put in manual override simultaneously for periods exceeding one hou On other occasions, the time that both divisions were bypassed cnuld not be determined from the surveillance records. Examples include:
Procerire N Performance Date Time Both Divisions Bypassed 24.207.04 07/23/86 1 hr. 45 mi .207.08 03/03/87 2 h .207.09 04/03/87 1 hr. 30 mi .207.09 02/15/86 4 hr. 13 mi .207.09 06/04/86 2 hr. 27 mi .207.09 10/06/86 3 h .207.09 01/07/87 5 hr. 25 mi The DER. estimates that both divisions were bypassed for a total of 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br /> and 12 minutes over the period of time that the surveillance procedures were deficient. The inspector determined that the reactor was critical on January 7 and March 3, 1987. Failure to initiate action within one hour to place the unit in an Operational Condition in which the Specification does not apply when a LCO is not met is a violation of Technical Specification 3.0.3 (341/88012-05(DRP)). The inspector verified that all applicable procedures have been revised to prevent the bypassing of both EECW divisions simultaneousl (Closed) LER 87-028: During the performance of Surveillance 24.207.09, -
Division II EECW oump and Valve Operability Test on June 27, 1987, an automatic initiation signal for Division II was received at 2255. At the time, the EECW pumps were running. The operator manually overrode the EECW logic to re-establish cooling to the ncn-essential load DER 87-231 documents this event. On June 26, 1987, a plant systems engineer was requested to change POM 24.207.09 to remove all use of
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the manual override feature and substitute manual initiation of both divisions of EECW (see LER 85026-01 discussion above) since the procedure was to be used the same day. The engineer had just returned to day shift from working an 1800 to 0600 shift the past seven days. Procedure Change Request No. T5286 was generated to implement the changes. However, during the performance of the surveillance, the closure of Valve P44-F603 created a pressure transient (20 psid) such that EECW Division Il received an automatic initiation signa A. corrective action, caution statements were added to seven EECW surveillance procedures stating that performance of the procedure could auto-initiate either or both divisions of EECW. The inspector is concerned that further actuations of EECW during surveillance performance would not be reported to the NRC. The licensee committed to review these caution statements with respect to the implementation of EDP-8126 which
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added an 11 second time delay in the differential pressure initiation logic. This will be accomplished during the Technical Specification Improvement Program review of these procedures and is considered to be an Open Item (341/88012-06(DRP)).
Technical Specification 6.2.2.f states that administrative procedures shall be developed and implemented to limit the working hours of unit
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staff who perform safety-related functions (e.g., licensed Senior Operators, licensed Operators, health physics personnel, auxiliary operators, and key maintenance personnel). This requirement as stated does not exclude the limitation of overtime for Technical Engineer staff performing safety-related functions. The licensee's implementing Procedure POM 12.000.114 appears to apply the overtime restrictions to only operations personnel, key maintenance personnel, select health physics shift personnel, nuclear instrument repairmen, and instrument shop foreme The excessive use of overtime for the plant systems engineer that implemented the procedure change discussed above appears to violate Technical Specification 6.2. This is an unresolved item pending further evaluation (341/88012-07(DRP)).
(Closed) LER 87-038 and Revision 1: On August 15, 1987, during post maintenance testing of the return header isolation valve for Division II of EECW, an automatic initiation of Divisien I EECW occurred. Division I initiated because the Division II EECW makeup tank was supplying the Reactor Building Closed Cooling Water (RBCCW) pump suction hea Closing the isolation valve isolated the makeup tank that was in servic This tripped the RBCCW pump and caused Division I EECW to automatically initiat The implementation of EDP-1720 as previously discussed under the closeout of LER 85079-01 in Report No. 341/87045 should prevent recurrence. The RBCCW system is currently operated with the RBCCW Makeup Tank in service -
and both EECW Makeup tanks isolate During review of associated DER 87-304, the inspector noted that a handwritten and unapproved Sequence of Events (SOE) test developed by Operations was used to perform the post maintenance testing and other data gathering involving abnormal cy: tem configurations. Additionally, a routing form attached to the DER spet.ifically requested Operations to address this issue in the OER evaluation process. However, there was no documented evidence that this issue was subsequently addresse POM 12.000.06, Revision 1, "Data Collection for Dia9nostic Testing,"
prescribes that SOEs are to be used to provide instructions for (1) engineering evaluation and data collection to determine the need for repairs or modifications and (2) operation of c system or component for troubleshooting purposo Also, the SOE is to be coordinated by the lechnical Engineer and approved by OSRO. Failure to properly implement an SOE in accordance with POM 12.000.86 is an example of a violation of 10 CFR 50, Appendix B, Criterion V (341/88012-08(DRP)).
(Closed) LER 88-012: Containment drywell pressure rack valve not fully ope The LER was reviewed for accuracy in the description of the event, cause of the event, and corrective actions. No deficiencies were identified. The inspector noted that five LER's describing misaligned
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valves have been submitted by the licensee during the period of 1985 to 1987. Further discussion of this event is provided in Paragraph 2 of this repor The NRC will continue to monitor the licensee's pe,'formance in this are During this inspection period, the inspectors reviewed select licensee deviation event reports (DERs). Those DERs reviewed were:
DER 88-914: Reactor vessel pressure interlock. The interlock is actuated on decreasing reactor pressure at approximately 460 psig. Once actuated it allows the core spray injection valves, E21F005A and E21F0058 for Division I(II), to open when an emergency core cooling system signal is present. The interlock protects the core spray piping from overpressurization. The reactor vessel is normally at a pressure in excess of core spray piping pressure rating. Four pressure transmitters input to four logic channels in a one out of two taken twice configuration such that a trip system for each di"ision of ECCS is forme Techni:al Specification 3.3.3, Table 3.3.3-1 requires two channels per trip ',ystem to be operable when in cold shutdown and the associated ECCS is operable. If the number of channels is less than the minimuni stated in '.he Table, then Action 30 of the Technical Specifications Table is invoked. The action states, "For one trip system, place that trip system in the tripped condition within one hour or declare the associated ECCS inoperable."
In the Summer of 1986, the licensee acquired a letter dated July 22, 1986 from the Rosemount Company, manufacturer of pressure measurement devices, discussing an intermittent syndrome occurring to a small number of their pressure transmitters. The syndrome involved an instantaneous ,
output signal shift epscale or downscale for no apparent reeson. The transmitter output signal would then retern to normal following:
fluctuation of the input pressure, removal of the power supply voltage or continued cperation in the process. On August 29, 1986, Standing Order 86-23 was issued to the operating shifts describing this failur Transmitter B21-N690D is of the same model number as that discussed in
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the Rosemount lette On April 22, 1988, the plant was in cold shutdown while operators were performing post maintenance testing to conclude a scheduled outage. In the morning of that day, plant operators began pressurizing the reactor
' vescel, which would taka a number of shifts, to perform inservice leak testing at 1000 psig. While performing the afternoon (approximately 1600)
routine shiftly channel checks, one of the LPCI/ core spray pressure l instruments was observed t: he reading zero while the companion channels l read 560 psig. The instrument involved was B21-N690D. At 1618 that
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downscale tripping the channel, the NSS and NASS considered A. tion 30 I of Technical Specification 3.3.3 met.
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. . At 0115 on April 23, 1988, operators observed B21-N6900 reading zero during the night shift routine shiftly channel check At 0415, all of ECCS was declared inoperable due to surveillance testing of excess flow check valves during the leak rate test. With the inoperability declaration of ECCS, Technical Specification 3.3.3 Action 30 was no longer applicabl At 0800, operators observed B21-N6900 reading 600 psig, consistent with the other companion channels. Therefore, sometime between 0115 and 0800 the transmitter experienced the Rosemount syndrome due.to the process parameter change from the leak rate pressurization. The afternoon shift channel check also revealed the instrument reading consistent with its companion channels. At 2035, with reactor pressure at 1000 psig, the reactor pressure low annunciator alarmed intermittently in the control room. The annunciator should alarm only when pressure is less than 460 psig and one of the input devices to this alarm is Instrument B21-N690 Subsequent observation by operators of the B21-N690D indicator revealed the indicator fluctuating causing the alar At 2115, the NSS instructed I&C personnel to place the channel in the tripped condition. The channel was placed in the tripped condition by the installation of a jumper and DER 88-0914 was written at 214 Under the DER, the licensee concluded that the instrument failure was attributable to the Rosemount syndrome and this same instrument had experienced a similar failure on January 27, 1988. Three corrective actions were established in the DER. These were issuance of a night order on May 16, 1988, to the operating shifts requiring positive operator action to place a Technical Specification instrument in the tripped condition, replacement of the transmitter and development of Technical Specification trip sheets by August 30, 198 The inspector reviewed the licensee's investigation of this DER and met with the lead reviewer on numerous occasions. The inspector independently verified critical portions of the findings and came to the same conclusion-as to the sequence of events. The inspector verified that the corrective actions associated with replacement of the transmitter and issuance of the night order have occurred. Due to the time frame established for issuance of the instrument trip sheets the inspector did not verify that corrective action. The inspector determined through discussion with operations management that there was no procedural guidance as to how to trip an instrument channel or training on this situatio In conclusion, the inspector determined that the licensee did not comply with Technical Specification 3.3.3 Action 30 in that operators did not place the channel in a tripped condition, but relied upon the failure mechanism of the instrument tn the trippeo condition. Normally, trip circuits are designed with manual resets. However, there was no positive operator action necessary to reset the tripped condition on this particular circui As such, later the next day, the channel was not tripped even though operators felt that they had taken the necesscry actions to place it in the tripped condition. This is considered a violation (341/88012-09(DRP)) of Technical Specification 3.3.3 Action 3 _
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DER 88-1054: Possible Leak in the Main Steam Drain Piping. The pipe leak, located in the main steam tunnel, was identified when main steam line (MSL) Drain Valve B21-F600 was opened on May 19, 1988. The effected pipe is a 3" drain line used primarily during plant startup The MSL drain outside containment is a high energy piping system that has been classified as a moderate energy system for purposes of pipe rupture studie Due to this classification, the containment penetration (X-8) associated
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with this line has not been analyzed against pipe whip. To prevent further deterioration of the piping and subsequent pipe whip, Operations established, per the directions of Engineering, administrative controls on the B21-F600 valve such that the valve is not to be opened unless approved by the NSS. The inspector's review determined that if Valves B21-F016 and B21-F019 (MSL drain inboard and outboard valves)
are opened, the cracked pipe would be exposed to high pressure stea This information was presented to the licensee who extended the administrative controls on Valve B21-F600 to include Valves 821-F016 and B21-F019. The licensee plans to replace the cracked portion of piping during the next outage. The inspector confirmed that the piping would be replaced during the next outage and was scheduled on the forced outage workscop ~
No other violations or deviations were identified in this are . Followup of Events During the inspection period, several events occurred, some of which required prompt notification of the NRC pursuant to 10 CFR 50.72. The inspectors pursued the events onsite with licensee and/or NRC officials, in each case, the inspectors verified that the notification was correct and timely, if appropriate, that the licensee was taking prompt and appropriate actions, that activities were conducted within regulatory requirements and that corrective actions would prevent future recurrence. -
The specific events are as follows:
50.72 Events
- April 17, 1988 Engineering safety features actuation during modification activities to containment
- isolation circuitr * April 18, 1988 Engineering safety features actuation during modification activities to containment isolation circuitr * April 20, 1988 EDG 13 governor discovered cut of position rer.Jering the EDG inoperabl * April 20, 1988 Blown fuse causes shutdown cooling suction valve to close while in shutdown coolin ,
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- April 27, 1988 Short circuit in a light bulb causes CCHVAC to shift to the recirculation mode (engineering safety features actuation).
- April 29, 1988 Loss of ENS and off site telephone * May 7, 1988 Reactor scram due to raccoon shorting the Division 1 onsite distribution syste * May 8, 1988 Reactor scram while performing HPCI testin * May 10, 1988 Reactor scram caused by closure of the bypass valves due to an equipment failur Non 50.72 Events
- During a routine surveillance on the backshift of April 8-9, 1988, the licensee discovered a lowered liquid level in the standby liquid control (SLC) tank. Subsequent investigation revealed that about 130 gallons of approximately thirteen percent sodium pentaborate solution had leaked into the reactor vessel from the tank. The plant was in a maintenance outage at the tim A region' based chemistry specialist reviewed the chemistry ramifications of the event and licensee remedial actions on April 19-20, 198 Initial analysis indicated a boron level of about 20 ppm and action was taken to isolate and contain the contaminated water within the vessel and the Division 2 RHR system which was in operation at the time. The licensee then began a feed and bleed operation to remove the contamination, sodium pentaborate. Removal was being accomplished -
by using the deep bed demineralizers in radwaste in addition to reactor water cleanup demineralizers to remove sodium and boro One recirculation pump was used to maintain circulation through the vessel in order to prevent hideout of the sodium pentaborat The licensee's evaluations were directed toward using the most favorable paths to eliminate contamination in dead legs, and taps for sampling potential dead legs for sodium and boron had been identified. The licensee was also in the process of evaluating the effect of this occurrence on plant radiation levels due to neutron activation of sodium in the primary system.
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water for sodium and boron several times a day. By the end of the inspection, the boron levels had reached the licensee's sensitivity level of about 100 pp The sodium had reached about 10 ppb compared with 67 ppb measured on April 15, and with a range of 2 to 5 ppb seen previously in normal operatio The inspector had no significant concerns with the licensee's cleanup efforts in response to this occurrenc l -
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o The reason the SLC drainage took place was due to an operator not ,
following a procedure resulting in a partial restoration of the SLC l system to service following an 18 month surveillance of SLC involving l
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manual initiation of the pump and squib valve firing. The repositioning of the valves following the test established a drain path to the reactor vessel. The valves should not have been repositioned until after the squib valves had been replaced as required by the surveillance procedure. Contributing factors to the event were minimal turnover between the operators involved in the testing, lack of planning to assure enough personnel were present to replace the squib valve after pump initiation / valve firing, and a cumbersome draining configuration to establish the necessary conditions to allow the test to be performed making scheduling difficult. The event and corrective actions to this situation were discussed in the meeting with the NRC on April 13, 1988. A violation for the operator's failure to follow procedures will not be cited after considering the factors in 10 CFR 2, Appendix C, II. * On May 19, 1988, at 0515 (67% power), and on May 20, 1988, at 1130 (62% power) the control room operators noticed unusual behavior of the north and south reactor feedwater pum On both occasions feedwater flow oscillations occurred causing heater level and power oscillations, automatic start of the standby oil pump, and cycling of the feedwater control and bypass valve Prompt operator response to the events halted the oscillations. Following the events the reactor feedwater pump controls were "tuned".
No violations or deviations were identified in this are . Plant Trips (93702)
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Following the plant trips on May 7, 8, and 10, 1988, the inspectors ascertained the status of the reactor and safety systems by observation of control room indicators and discussions with licensee personnel concerning plant parameters, emergency system status and reactor coolant chemistry. The inspectors verified the establishment of proper communications and reviewed the corrective actions taken by the license All systems responded as expected, and the plant was returned to operation following each tri During the three post scram evaluations by the licensee, the inspector determined that additional improvements could be made in the methodology used by the licensee in evaluating operating events. The licensee had re:ently established a post-scram team but no useful documentation /
guidelines had been established with which to evaluate the even Specifically, key drawings such as the one showing EDG load sequence times were not a standard part of the evaluation, documentation providing expected alarms to look for on a scram was lacking, time clocks on the different computers were not routinely synchronized, no proper performance plots for HPCI, RCIC, etc. were available for comparison, and no ready
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file of all reactor water level instruments was available with their instrument tolerances and setpoints. Improvement to the scram evaluation program is considered an open item (341/88012-11(DRP)).
No violations or deviations were identified in this are _ Confirmatory Action Letter (CAL) Followup On April 19, 1988, CAL 88-009 was issued to the licensee. The CAL dealt with the loss of RHR cooling for 33 minutes with the operating RHR pump being deadheaded for that same length of time on April 9, 1988, and the damage observed to the moisture separator reheater (MSR) following plant shutdown for the local leak rate testing outag The inspector followup
! on each licensee action identified in the CAL is provided below, RHR Event
- The licensee determined the most probable cause of valve closure was due to a failed relay in the valve logic circui The suspect relay was replaced. The suspect relay was then
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bench tested for an extended period of time to recreate the failur The relay functioned properly. The relay is scheduled to be destructively tested to try to determine the failure mechanis * The licensee determined that no damage had been caused to the RHR pump by a torus to torus pump run while monitoring bearing vibration and visual observation of the pump while runnin * Before the event occurred the licensee per ormed Safety Evaluation 88-0074 documenting the rationale for considering .
the RHR system operable with the minimum flow valve deenergized closed. After the event the licensee reviewed the safety evaluation and came to the same conclusion. The inspector reviewed the safety evaluation and could not draw the same conclusion. This matter is considered unresolved (341/88012-12(DRP)) until that information is obtained. In
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the interim the licensee has committed to monitor pump flow every 15 minutes should this same configuration arise agai MSR Damage
- The licensee concluded that MSR debris did not intrude into the reacto This conclusion was based upon chemistry analysis and sampling the reactor vessel bottom head drain with negative result * The inspector confirmed through completed work request review that strainers were installed in the flash tanks. The inspector verified that the operating procedure was chenged to align l
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feedwater flow through the feed pump suction strainers when the startuo level control valve is in us * The inspector reviewed the results of the bottom head drain sample and found it acceptabl .
- The inspector reviewed the inspection plan for the feedweter system and the results of the inspection. The inspector reviewed the rationale for those few sections of piping not inspected and determined them reasonabl * The inspector verified that the feedwater system was flushed during startup and power ascensio * The inspector verified that the chemistry personnel had been directed to sample the reactor coolant on a weekly basi * The inspector verified that written direction had been provided to inspect the MSRs, reactor feedwater pump suction strainers and flash tank strainers at the appropriate time interval Closure of this CAL is contingent upon completion of the root cause determination for the closure of Valve E11-F015B, completion of the strainer inspections and verification of implementation of reactor coolant samplin No violations or deviations were identified in this are . Followup of Select Operational Safety Team Inspection (OSTI) Findings An OSTI was conducted from July 27 to August 7, 1987 and the inspection '
was documented in Inspection Report No. 87030. As identified in the cover letter of that report, Region III would followup on those finding Those OSTI findings specifically identified for resident followup were performed during this inspection period. The OSTI findings are identified below along with the results of the inspector's followup on the finding.
l In reviewing Onsite Review Organization (OSRO) activities the OSTI
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team identified a concern that newly hired individuals were not specifically provided training regarding the Fermi 2 plant. In j one case an individual had been licensed and trained at another I
operating boiling water reactor. However, this individual had not been trained on the Fermi 2 Technical Specifications, license requirements, administrative procedures, and differences between Fermi 2 and the previous plant. The team believed the effectiveness of individuals could be further enhanced through selected Fermi 2 ,
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Discussions with the training department identified that no specific action had been taken to address this concern. They did point out that newly hired individuals for management positions are selected l
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based upon'their previous training and experienc Therefore, the licensee believes that little or no training was required for these individuals based upon their previous experience. In some cases the licensee has provided additional training to new hires, such as SR0-Certification and Mitigating Core Damage Training. This training is not required nor is it part of the formalized training requirement Selection, training and qualification of personnel at Fermi 2 is
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governed by Nuclear Organization - Fermi Managemcat Directive (FMO)-FH0-TQ1 - Training and Qualification. Implementation of this directive is through the Fermi Training and Qualification Manual, Fermi Interfacing Procedure (FIP)-FIP-TQl-05-SQ. This training and qualification manual provides the job qualification requirements for each position at Fermi 2. Training Program Descriptions (TPD's) and Qualification Program Descriptions (QPD's) provide the qualification and training requirements for specific individual positions at Ferm This program is fairly new and will become fully implemented December 31, 198 The licensee's current program requires minimal training to bring these individuals on-board, such as: Access Authorization Training and Radiological Emergency Response Training. Specific selection requirements are determined by the hiring department and ara not addressed by the training organizatio During control room observations, the OSTI identified numerous administrative controls that were out of date or had conflicting requirements. The inspector reviewed the licensee actions to resolve the specific findings and the adequacy of some of the administrative controls currently in plac Temporary Modifications: The licensee has changed the requirement to perform a monthly audit to a quarterly audit to alleviatc excessive reviews. Review of the monthly and quarterly audits since the OSTI determined that they havs been timely. The licensee is currently reviewing their program with regard to transferring responsibility for the temporary modification program to the technical support grou Temporary modifications receive an engineering review within 21 days of implementation of tha modification. No restrictions exist to limit the maximum time a temporary modification can exis Duplicate and Uncontrolled Log Books / Indexes: Review of logs, procedures and indexes in the control room identified that some of the specific concerns identified in the OSTI report still were presen Two versions of the Process Computer Input /0utput index were in the control room. Uncontrolled procedures were in the control room, but were being maintained current. However, there was no program in place to ensure that these information copies would be maintained. A plant order currently exists requiring prncedures be updated at remote locations throughout the plant. These uncontrolled (information only) procedures should have been included in the plant orde A Technical Specification cross reference was available in
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I two different versions. Both versions were for information onl This information is not available as a controlled document as it has not been verified to be totally accurat Inconsistent Requirements for Reviews and Audits: Plant procedures have not been updated to resolve the conflicting requirement to audit
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the defeated alarm log. Procedure 21.000.02, Operations Logs and Records, requires a monthly audit whereas Procedure 23.621, Main Control Room Annunciator and Sequence Recorder, requires a weekly audit of defeated alarms. The licensee has been conducting a weekly audit. However, the inspector observed two instances where the shift supervisor had not approved the defeating of four annunciators in January of 198 Operator Aids: Review of Plant Order EF0-8080, Operators Aids orocedure in the control room identified that the licensee is not fully implementing this procedure. Drawings located throughout the ,
plant (information copies for training) were not given unique numbers for tracking and were not included during monthly audit Adherence to Procedures and Logs: The emergency diesel generator operating log was missing entries on times and dates for shutdown and unloading. The monthly audit of the operator aid log v:as not being performed. The shift supervisor had not reviewed two alarms for approval to defeat them in the alarm defeat log. The required reading was not up to date for some of the individuals on shif The failure to perform quality related activities in accordance with established procedures or instructions and the failure to adequately prescribe procedures or instructions as exhibited by the above examples is considered of a violation (341/88012-08(DRP)) of 10 CFR 50, Appendix B, Criterion During an OSTI observation of troubleshooting activities associated with the hydrogen recombiner system, numerous temporary procedure revisions caused difficulty in implementing the procedures. This identified a concern that the procedure revision process did not support proper work performance. The inspector reviewed the hydrogen
. thermal recombiner procedures and observed surveillance testing and noted that these procedures had been revised to correct the specific concern of excessive temporary change Review of NOIP 11.000,131, Procedures, Manuals and Orders, identified no restrictions to the number or extent of temporary changes a procedure may hav The licensee indicated that they had reviewed their program and believed that it was sufficiently restrictive to limit the amount of temporary change Review of temporary procedures identified that 137 temporary changes were written to date in 1983, of which only 42 were currently outstanding. There were only three procedures with more than one change outstanding, of which one procedure had three change No other violations or deviations were identifie ~
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1 Management Meetings On April 13, 1988, the licensee's management met with NRC Region III I management in Glen Ellyn, Illinois. The licensee provided a presentation {
of the major results of a Safety System Functional Inspection initiated
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by the license On April 13, 1988, the licensee's management met with NRC Region III management in Glen Ellyn, Illinois, to discuss the significant events of the weekend of April 9-10. The licensee provided their corrective actions to the events. Afterwards the major elements of a CAL (see Paragraph 9) were discusse . THI Item Review (Closed) THI Item II.K.3.28: Verify Qualification of Accumulators on Automatic Depressurization System (ADS) Valves. This item was previously reviewed in Inspection Report No. 50-341/88006(DRP). During the period, thi inspector performed a walkdown of the Primary Containment Pneumatic Supply System. No problems were identified. This item is considered to be close . Review of Temporary Instructions (tis) TI 2515/90 Scram Discharge Volume Capability (25590)
A detailed review of Scram Discharge Volume (SDV) capability was performed during the inspection period. The inspector reviewed the design of the SDV including the Instrument Volumes (IV)
against the requirements of Technical Specifications, FSAR, and SER as well as the applicable portions of the General Electric .
Design Specification for the Control Rod Drive System (22A6249).
Conformance was verified in the areas of minimum allowable volumes, IV level instrument placement, instrumentation diversity and setpoint determination, valving redundancy, hydraulic coupling, and independence of power supplies. Appropriate setpoints for scram, rod block, and alarm functions were verified in place
. with associated annunciation available in the control roo No deficiencies were identifie A walkdown of the 50V, IV and associated piping was conducted to verify to the extent practical, that equipment as-built configuration was in conformance with construction drawings and P& id All installations appeared to conform with design documents, fechnical Specification and Inservice festing (IST) requirements were verified to be incorporated into the surveillance program for continued operability of the SDV/IV. During review of Surveillance Procedure 24.106.04, "SDV Vent and Orain Valves Operability Test,"
discrepancies were noted in the specified acceptance criteria for stroke times between those in the body of the procedure and those on the attached data sheet. Moreover, one acceptance criterion was not consistent with a Technical Specification limit. When this matter was brought to the attention of licensee personnel, a procedure change was immediately initiated and subsequently issue . _ _ - _ _ _ _ . ._
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The inspector then performed an independent verification of a sample of actual test data taken utilizing the previous procedure revision to assure all data was within acceptable limits. Additionally, three similar surveillance procedures issued during the same time frame were reviewed to ensure the identified discrepancies were isolated to the
. one procedure. No further problems were identifie This TI is closed, TI 2515/93 QA Requirements for Diesel Generator (D/G) Fuel Oil (71707)
The inspector reviewed station purchasing requirements, receipt inspection controls, and chemistry sampling and analysis procedures relating to the procurement and storage of D/G fuel oi Currently, D/G fuel oil is purchased as a commercial quality (CQ)
item at Fermi and is subsequently qualified for its safety related application via chemical sampling / analysis, the specifics of which are delineated in Technical Specification A blanket purchase order (NX-163669) was prepared in September 1987 to obtain fuel oil for the D/Gs from Empire Petroleum In The associated inspection requirement form outlined in detail the tests required upon receipt of the oi During the review, the inspector found that D/G fuel oil was not included in Fermi's computerized "Q-list." From discussions with licensee personnel, it was determined that this was because fuel oil is considered a consumable material at Fermi and the Q-list is limited to hardware oriented items onl However, appropriate administrative controls appeared to be in place to obtain and maintain the D/G fuel oil at an acceptable level of qualit ,
This TI is close . Regional Requests In a memorandum dated April 27, 1988, the Director of NRC Region III Division of Reactor Safety requested to be informed when the welds in the shroud support access hole cover discussed in IE Information Notice 88-03
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are inspected by the licensee. In the exit of June 1, 1988, the senior resident inspector requested that the licensee inform the resident's office when/if such an inspection is planned.
l 1 Unresolv_ed Items Unresolvmi items are matters about which mere information is required in order to ascertain whether they are acceptable items, violations or deviations. Unresolved items disclosed during the intpection are discussed in Paragraphs 6 and {
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1 Open Items Open items are matters which have been discussed witn the licensee, which will be reviewed further by the inspector, and which involve some action on the part of the NRC or licensee or both. Open items disclosed during
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the inspection are discussed in Paragraphs 3, 6 and . Exit Interview (30703)
The inspectors met with licensee representatives (denoted in Paragraph 1)
on April 20, May 27, and June 1, 1988, and informally throughout the inspection period and summarized the scope and findings of the inspection activities. The inspector also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspector during the inspection. Tne licensee did not identify any such documents / processes as proprietar The licensee acknowledged the findings of the inspection. Also during the exit, the inspector informed the licensee of a letter dated June 16, 1987, from the Vitro Corporation to the NRC discussing problems with automatic load sequencers. The letter identified Fermi 2 as having received one of these load sequencer .
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