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| {{Adams
| | #REDIRECT [[IR 05000254/1998004]] |
| | number = ML20217G340
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| | issue date = 04/23/1998
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| | title = Insp Repts 50-254/98-04 & 50-265/98-04 on 980211-0331. Violations Noted.Major Areas Inspected:Operations, Engineering,Maint & Plant Support
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| | author name =
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| | author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
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| | addressee name =
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| | addressee affiliation =
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| | docket = 05000254, 05000265
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| | license number =
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| | contact person =
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| | document report number = 50-254-98-04, 50-254-98-4, 50-265-98-04, 50-265-98-4, NUDOCS 9804290114
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| | package number = ML20217G284
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| | document type = INSPECTION REPORT, NRC-GENERATED, TEXT-INSPECTION & AUDIT & I&E CIRCULARS
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| | page count = 29
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| }}
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| See also: [[see also::IR 05000254/1998004]]
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| =Text=
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| {{#Wiki_filter:.
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| U. S. NUCLEAR REGULATORY COMMISSION
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| REGION lli
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| Docket Nos: 50-254;50-265
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| License Nos: DPR-29; DPR-30
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| Report No: 50-254/98004(DRP); 50-265/98004(DRP)
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| Licensee: Commonwealth Edison Company
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| Facility: Quad Cities Nuclear Power Station, Units 1 and 2
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| Location: 22710 206th Avenue North
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| Cordova, IL 61242
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| Dates: February 11 - March 31,1998
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| Inspectors: C. Miller, Senior Resident inspector
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| K. Walton, Resident inspector
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| L. Collins, Resident inspector
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| B. Pulsifer, Licensing Project Manager, NRR
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| R. Ganser, Illinois Department of Nuclear Safety
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| l Approved by: Mark Ring, Chief
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| l Reactor P ojects Branch 1
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| 9804290114 980423 i
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| PDR ADOCK 05000254 i
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| G PDR
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| EXECUTIVE SUMMARY
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| Quad Cities Nuclear Power Station, Units 1 & 2
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| NRC Inspection Report No. 50-254/98004(DRP); 50-265/98004(DRP)
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| This resident inspection included aspects of licensee operations, engineering, maintenance, and
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| plant support.
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| l Operations
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| .
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| Non-licensed operators improperly retumed a safety-related breaker to service and
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| logged the equipment as being available for five days before detecting the deficient
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| condition. The failure to properly retum the component to service was considered a
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| violation of procedures (Section 01.2).
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| . Non-licensed operators injected incorrect grease into the station blackout diesel
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| generator fuel oil transfer pump, which could have made the pump inoperable due to
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| grease incompatibility. Initial corrective actions did not address extended operation of the
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| pumps with incompatible grease and were considered weak (Section 01.2).
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| Maintenance
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| . Reactor bottom head drain piping failed an in-service pressure test. The licensee l
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| conservatively used a reactor drain plug and a freeze seal to isolate the piping for repair
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| (Section M1.2).
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| . An instrument technician found electronic controller modules which were improperly
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| assembled by a contracted repair company. This condition was properly reported to alert
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| other facilities of a potential nonconforming condition (Section M1.2).
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| . A maintenance contractor operated valves with out-of-service (danger) tags attached.
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| This issue was considered a violation of the licensee's administrative procedures, and
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| demonstrated poor safety practices and ineffective control of contractor activities
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| (Section M1.2).
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| . The licensee identified standby liquid control system temperature switches, used to
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| satisfy a Technical Specification surveillance requirement, were set below the required
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| minimum temperature. There were prior opportunities to identify this missed surveillance
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| violation (Section M1.3).
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| . All source range nuclear instruments on both units were rendered inoperable because of
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| failure to perform Technical Specification required functional testing. Previous corrective
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| actions were not sufficient to ensure surveillances were performed in a timely manner.
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| This was considered a violation of surveillance testing (Section M1.4).
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| . Quad Cities was overdue on completion of a number of surveillance and preventive
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| maintenance items. The licensee was scheduling surveillances and preventive
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| maintenance items to be performed past the due date for the items. A violation was
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| issued for failure to perform snubber surveillances in the appropriate periodicity
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| (Section M1.5).
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| The licensee's corrective actions for previously identified testing deficiencies with the I
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| ' emergency diesel generator air start system were not technically adequate, and
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| procedure reviews failed to identify the problems (Section M3.1).
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| Enaineerino
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| The licensee was not successful in determining the root cause of the Unit 1 emergency
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| diesel generator failure to start in January 1998. Nonetheless, operations declared the
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| Unit 1 emergency diesel generator operable. No specific actions were recommended to
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| improve airstart system performance which was a suspected contributor to the start
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| failure. Similar failures had occurred in the past (Section E1.1). l
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| The prompt investigation team identified the cause of the Unit 1 emergency diesel
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| , generator failure to run on March 17,1998, to be a fuse block failure. The licensee took
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| l proper corrective actions to address the problem (Section E1.3).
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| . There were inconsistencies between two 10 CFR 50.59 summary report summaries and
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| ; the respective safety evaluations (Section E1 A).
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| Although licensee efforts to investigate emergency diesel generator time delay relay
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| ; fa:iures were good, significant reliability problems still existed. Engineering justification
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| for dedicating the relays as safety-related parts did not address vulnerabilities of the
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| [ relays to vibration. Engineering justification for exceeding Updated Final Safety Analysis
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| l Report limits for the relay settings was not thorough (Section E3.1).
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| . There were more preparations (meetings, drawing reviews and subsequent walkdowns)
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| by the examiners for the Unit 1 pressure test than other similar pressure tests. The
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| , examiners identified leakage which required repair prior to unit startup (Section E5.1).
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| Plant Support
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| ( . Repair of the Unit i reactor water cleanup drain line and disassembly of the Unit 1 "A" l
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| ; residual heat removal pump were two maintenance activities performed in higher l
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| l- radiation areas. The use of as low as reasonably achievable initiatives were effective for
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| ; the residual heat removal pump repairs (Section M1.2). j
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| l . The licensee was not aggressive in ensuring that radiation and contamination levels did !
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| not impact examiners and were kept as low as reasonably achievable in the Unit 1 drywell i
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| j (Section R1.1).
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| ;
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| . The Unit 1 scram discharge headers were recently hydrolased to reduce dose ratas for
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| ! hydraulic control unit work and to reduce dose rates in the general area (Section R1.2).
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| Report Details
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| Summary of Plant Stain
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| Operators maintained both Unit 1 and Unit 2 in cold shutdown during the inspection period due to
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| safe shutdown capability concems for both units and a planned surveillance outage for Unit 1.
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| The licensee performed both planned and emergent maintenance activities in parallel with
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| developing the safe shutdown analysis and implementing procedures for both units associated
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| with 10 CFR 50, Appendix R, " Fire Protection." i
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| l. Operations
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| 01 Conduct of Operations
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| 01.1 General Comments (71707)
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| During the period, the licensee identified problems with non-licensed operators not
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| maintaining proper configuration control of equipment important to safety. This included
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| I- the electrical output breaker for the Unit 2 station blackout diesel generator not being i
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| available for operation and log keeping errors.
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| 01.2. Non-Licensed Operator Errors )
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| a. Inspection Scope (71707) ,
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| L, Theinspectors reviewed problem identification forms, interviewed operators, attended
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| shift tumovers, observed work in the field, and interviewed operations managers.
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| b. Observations and Findinas
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| ! The inspectors noted several events attributed to non-licensed operator errors. Each
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| event was documented on problem identification forms and addressed by management.
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| b.1 Failure to Follow Procedures and Loa Takina Errors
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| ! On March 14,1998, operators retumed the Unit 2 station blackout diesel generator to
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| ! service. During the "retum to service," operators used a breaker installation checklist for
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| l- the electrical output breaker. However, the operators failed to charge the output breaker
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| as required by the checklist. With the breaker not charged, the breaker could not be
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| closed remotely and the station blackout diesel generator would not be able to supply
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| power to the electrical bus. The error during the "retum to service" resulted in an
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| equipment configuration error. After completing the "retum to service," and due to delays
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| in testing, operations department considered the station blackout diesel generator
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| available but not operable.
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| - Additionally, operators were required to ensure that the station blackout diesel generator
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| output breaker was charged and ready for operation on a daily basis. However, operator
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| logs indicated that this deficient condition was not detected for five days. The licensee
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| documented this condition on Problem identification Form Q1998-01413 and commenced
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| an investigation into the event.
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| The inspectors considered this a Violation (50-265/98004-01) for failing to implement
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| l Quad Cities Operating Procedure 6500-07, " Racking in a 4160 Volt Horizontal Type AMH,
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| AMHG or G26 Breaker," Attachment H. The individuals involved were disciplined and
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| operating crews were counseled about these events.
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| b.2 Wrona Grease Iniected into Station Blackout Diesel Generator Fuel Oil Transfer Pumo
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| Operating procedures required that the station blackout diesel generator fuel oil transfer
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| inboard and outboard pump bearings be injected with Chevron SRI-2 (green) grease.
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| However, operations personnel identified the pumps were injected with a Benton clay-
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| type (red) grease. The red and green greases were incompatible and could produce
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| j either a gummy-like orJelly-like material. This issue was documented on Problem
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| Identification Form Q1998-01184. The licensee reviewed this incident, and determined
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| that operators had likely injected the incorrect grease, either because of inattention to
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| detail or failure to follow procedures. The licensee's initial corrective action plan was to
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| replace both pumps in a future outage.
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| The inspectors determined that the licensee's root cause evaluation was weak in that it
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| did not address the failure of operations personnel to use the correct grease in equipment
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| important to safety. Additionally, the evaluation did not determine the ability of the pumps
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| to operate for an extended period of time with incompatible grease. Finally, the
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| inspectors noted that the proposed corrective actions were poor and did not specify
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| actions to prevent recurrence. After the inspectors presented these concems to senior
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| licensee management, the licensee decided to replace the pumps.
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| c. Conclusions
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| Problems with operators maintaining equipment in required configurations continued.
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| Incidents involving poor non-licensed personnel performance included the failure to
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| properly retum a safety-related breaker to service, and the failure to detect this condition
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| l during five routine operator rounds. Additionally, a station blackout diesel fuel oil transfer
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| pump was injected with the incorrect grease. The inspectors noted the licensee's initial
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| evaluation and corrective actions did not adequately address the operability of the pumps
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| for an extended period of time. After the inspectors discussed these concems with senior
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| licensee management, the licensee replaced both fuel oil transfer pumps.
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| O8 Miscellaneous Operations issues (92700)
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| 08.1 (Closed) Licensee Event Report 50-265/96002-00: High Pressure Coolant injection
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| l Inoperable Due to inadequate Venting. During the quarterly vent verification, operators
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| were unable to verify that the Unit 2 high pressure coolant injection was properly filled. A
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| small amount of air had been introduced into the system several months ear 1ier during
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| j maintenance. Procedures were changed, and the system was filled and vented. A
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| calculation was performed which concluded that the small amount of air would not have
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| prevented high pressure coolant injection from performing its safety function. The
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| inspectors verified the procedure changes were in place. This item is closed.
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| 11. Maintenance
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| M1 Conduct of Maintenance
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| M1.1 . General Comments
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| The inspectors observed various ' maintenance activities and determined that for the most
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| part, maintenance was conducted safely and in accordance with regulations. However,
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| the inspectors noted an instance of the licensee not properly monitoring work performed
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| by a contract worker. This resulted in the contractor operating out-of-service equipment.
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| There were further instances of missed Technical Specification surveillances.
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| ! M1.2 Work Reauest Observations
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| l a. Inspection Scope (61726. 62707)
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| The inspectors reviewed and/or observed the following maintenance activities and
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| assessed the workers' performance and compliance with plant requirements:
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| WR 950090066 Replace Unit 1 Emergency Diesel Generator Cooling Water Valves
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| WR 980016772 Calibrate Unit % Emergency Diesel Generator Time Delay Relays
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| WR 980016774 Calibrate Unit 2 Emergency Diesel Generator Time Delay Relays
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| !
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| WR 980018622 ' Inspect Unit 1 Feedwater Controllers for High and Low Current
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| Limits
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| WR 980021161 Perform 10-year inspection of Bus 31 Switchgear
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| WR 980021522 - Establish Freeze Seal for Reactor Water Cleanup System Pipe
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| l Repair
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| l- WR 980024637 Inspect All Unit 1 Feedwater Modules for Correct Polarity
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| l- WR 980024727 Inspect Unit 2 Jet Pump Modules for Correct Polarity' )
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| l WR 980028384 Adjust Interlock Cam on Breaker 804, Bus 31
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| b. Observations and Findinas
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| b.1 Deficiencies identified Durina Assembly of Controller Modules
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| An instrument maintenance technician completed a routine calibration of a controller
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| module removed from the feedwater system. The module tested satisfactorily, but during
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| module inspections, the instrument maintenance technician identified that a capacitor on
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| the module had failed. Further investigations by the technician determined that the
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| l capacitor was installed backwards. The technician identified a second failed feedwater
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| module with an incorrectly installed capacitor. The modules had previously been
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| refurbished by a contracted company, Integrated Resources, in March 1996. The
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| modules were calibrated by the licensee in the shop, then installed in the feedwater
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| system. The modules performed in service satisfactorily even with the fr.ud capacitors.
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| The licensee documented this cor,dition on Problem Identification Form 1998-01152.
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| Subsequently, the licensee identifiod approximately 180 modules in non-safety-related
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| applications which had been refurt>ished by Integrated Resources. By the end of the
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| inspection period, the licensee identified an additional five out of about 200 capacitors
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| were installed backwards, and identified other workmanship deficiencies. The licensee
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| notified other facilities of the defects identified. The licensee planned to repair the
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| affected modules prior to installation.
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| b.2 Overhaul of Unit 1 "A" Residual Heat Removal Pump
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| During the disassembly of the Unit 1 "A" Residual Heat Removal pump, the inspectors
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| noted good teamwork by electrical and mechanical technicians. Work was conducted in
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| a time-efficient manner since the work area was in an elevated radiation dose rate field.
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| Radiation protection reduced area dose rates by flushing then filling system piping,
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| constructing a lead shield around the work area, minimizing personnel access and using
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| remote cameras. These efforts resulted in radiation exposures less than anticipated.
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| The foreman initially in charge of the job was sent to training and the substitute foreman
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| was unable to spend much time at the work site due to administrative burdens. Lack of
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| supervisory oversight has been a contributor to maintenance problems in the past. While
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| most replacement parts for the job were staged and available, some parts were not
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| available. While preparation and oversight of this activity was not comprehensive,
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| maintenance completed the rebuild of the pump on schedule.
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| b.3 Repair to Reactor Water Cleanuo Pipino
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| During a pressure test, the licensee identified a through-wall leak on an unisolable section
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| of reactor water cleanup piping under the Unit i reactor vessel. Seveial repair methods
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| were evaluated. The licensee initially considered a freeze seal alone to isolate the piping,
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| i but eventually decided to use the seal and install a plug from inside the reactor vessel.
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| This required removal of the reactor vessel head, removal of some fuel assemblies, and
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| removal of other interference items. The repairs were completed using a remote welding
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| machine to minimize worker exposure due to the high dose rates under the reactor
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| vessel. The contingencies made available in anticipation of a freeze seal failure and the
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| use of a redundant method to prevent draining the reactor vessel were conservative. The
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| decision to plug the line inside of the reactor was conservative from an inventory control
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| perspective.
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| b.4 Valves Out of Position Durina Work by Vendor
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| Operators completed an "out-of-service" on the Unit 2 instrument air compressor. Later
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| on March 26,1998, an operator identified two drain valves (2-4799-919 and 2-4799-920)
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| that were required to be open and were tagged as open, were in fact closed. The
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| licensee documented this condition on Problem Identification Form Q1998-01512, and
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| subsequently determined that the valves had been improperly positioned in violation of
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| the attached out-of-service tags by a vendor who was working on the air compressor.
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| }
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| i The licensee used the out-of-service program to ensure personnel safety and system )
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| integrity. Operating tagged valves was indicative of knowledge and training weaknesses !
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| and poor control of contractors.- Fortuitously, in this case, the operation of the tagged
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| drain valves was of low safety significance. The inspectors considered this to be a
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| Violation (50-265/98004 42) of Quad Cities Administrative Procedure 230-04,
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| " Equipment Out-of-service," for operating equipment with out-of-service tags attached.
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| c. Conclusions ,
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| The inspectors concluded most maintenance activities were conducted in accordance
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| with regulatory requirements. However, poor contractor control and training resulted in
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| {
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| an unauthorized manipulation of a tagged valve. The licensee addressed the reactor
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| water cleanup piping repair in a conservative manner. The use of as low as reasonably
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| achievable initiatives were evident for the work on the "A" residual heat removal pump.
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| l An instrument technician alertly identified a workmanship rieficiency on electronic
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| l controller modules which had been refurbished by a contracted company.
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| M1.3 Missed Standbv Liould Control System Surveillance Due to inadeauate Procedure
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| a. Inspection Scope
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| The inspectors reviewed the licensee's corrective actions in response to the discovery of
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| a missed surveillance on the standby liquid control system.
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| l b. Observations and Findinas )
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| Dunng a review of licensee corrective actions to previous missed Technical Specification
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| surveillances, a Quality and Safety Assessment auditor identified that the as-left setpoints
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| of standby liquid control pump suction temperature switches for both units were lower
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| than the minimum temperature required by Technical Specifications. Technical
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| Specification Surveillance Requirement 4.4.A.1.C required the standby liquid control
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| system be demonstrated operable at least once per 24 hours by determining the
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| l temperature of the pump suction piping to be greater ther) or equal to 83 degrees
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| l Fahrenheit. To satisfy this requirement, control room operators verified the alarm,
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| " Standby Liquid Control Temperature Hi/Lo," was not actuated once per day.
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| 1 A quality and safety assessment auditor determined the setpoints of the temperature I
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| switches for the alarm for both units to be less than 83 degrees. The specified setting of '
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| the temperature switches was 83 plus or minus 5 degrees Fahrenheit which could have
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| routinely allowed temperatures below 83 degrees.
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| Although both reactors were in Mode 4, and the standby liquid control systems were not
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| required to be operable in Mode 4, the calibration had last been performed in May 1997
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| and both units operated in Mode 1 since that date. Therefore, the licensee concluded
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| that surveillance requirements had not been met for the standby liquid control system
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| ! during periods when it was required to be operable. An emergency notification system
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| l phone call was made on February 10,1998, to report the inoperability of the standby j
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| liquid control system for both units. The failure to adequately perform the surveillance i
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| t was a Violation (50-254/98004-03; 50-265/98004-03) of Technical l
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| Specification 4.4.A.1C. For corrective actions, engineers planned to add a thermocouple <
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| on the suction piping to the standby liquid control system pumps and initiated an
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| engineering request to increase the temperature setpoint of the Unit 2 heat trace
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| controller.
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| I Before the corrective actions could be implemented, licensee management changed the ;
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| method for satisfying the surveillance requirement. Instead of relying on the alarm,
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| operators locally measured the temperature of the suction piping once per day. The new
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| acceptance criterion was greater than or equal to 85.6 degrees Fahrenheit and included
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| uncertainties of both the installed thermocouple and readout device. However, after the
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| new surveillance method was implemented, operators identified temperatures on 2A,1 A,
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| and 18 standby liquid control system suction piping were below the acceptance criterion.
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| Operations declared the associated pumps inoperable. Operations supervisors increased
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| the surveillance frequency to twice per shift.
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| This surveillance requirement was new as of the Technical Specification upgrade
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| implementation in September 1996. The inspectors concluded that the licensee did not
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| sufficiently research the setpoint requirements to ensure new Technical Specification
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| requirements could be met. In particular, the effect of the heat trace cycle on the
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| temperature measurement and the potential for operator error had not been fully
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| evaluated. Dresden Station identified this and other problems with standby liquid control
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| system heat tracing in October 1997 and notified Quad Cities. Quad Cities documented
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| this issue on Problem Identification Form Q1997-04267, but the investigation failed to
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| recognize that the setpoints of the alarm could be below Technical Specification
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| requirements.
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| c. Conclusion
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| The licensee identified standby liquid control system temperature switches, used to
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| satisfy a Technical Specification surveillance requirement, were set below the required
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| minimum temperature. A prior opportunity to identify the issue existed.
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| M1.4 Missed Surveillance Tests for Source Ranae instruments
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| a. Inspection Scope
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| The inspectors reviewed the circumstances surrounding the licensee discovery that all
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| source range nuclear instruments were inoperable because of exceeding technical
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| specification surveillance frequency requirements,
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| b. Observations and Findinas
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| On February 20,1998, a shift manager identified that the source range nuclear
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| instrument functional tests, which were required by Technical Specification 4.2.G.3.b in
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| Modes 2 (with intermediate range nuclear instruments on Range 2 or below),3 and 4,
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| were not performed within the acceptable 31-day periodicity. At the time of discovery,
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| both units were in a cold shutdown condition. The source range nuclear instruments
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| were declared inoperable, tested satisfactorily on February 22,1998, then declared
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| operable. Licensee Event Report 2-98-01 was issued to detail the problem with missed
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| surveillances.
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| For Unit 2 the procedure which implemented the Technical Specifications requirement
| |
| (Quad Cities Instrument Surveillance 0700-10) was performed on October 15,1997, then
| |
| not again until February 22,1998. Unit 1 wa.s brought to Mode 3 on December 20,1997,
| |
| and the Technical Specifications 4.2.G.3.b surveillance was not performed until
| |
| February 22,1998. Failure to perform the surveillances rendered the source range
| |
| nuclear instruments inoperable. With one or more of the source range nuclear
| |
| instruments inoperable, all insertable control rods were required to be verified fully
| |
| l
| |
| 9
| |
| l
| |
| l
| |
| ,_
| |
| | |
| '
| |
| .
| |
| . .
| |
| ,
| |
| 4
| |
| inserted in the core with the reactor mode switch locked in the shutdown position within
| |
| one hour. Failure to perform the surveillances is a Violation (50-254/98004-04;
| |
| 50-265/98004-04) of Technical Specification 4.2.G.3.b.
| |
| The licensee determined that the surveillance requirements were missed because of poor
| |
| implementation of upgraded Technical Specifications in 1996. The fact that the
| |
| surveillance was required in Mode 4 was not recognized and not put into the controlling
| |
| surveillance procedure. In addition, the electronic work control system schedule for the
| |
| surveillances was changed without adequate review.
| |
| Because of the long history of surveillance problems at Quad Cities and failure of
| |
| previous corrective actions to eliminate the problem, the licensee reverted to a manual
| |
| scheduling system for Technical Specification surveillances using a line by line
| |
| verification of Technical Specifications requirements.
| |
| c. Conclusion
| |
| All source range nuclear instruments on both units were rendered inoperable because of
| |
| failure to perform Technical Specifications-required functional testing. Previous
| |
| corrective actions were not sufficient to ensure surveillances were performed in a timely
| |
| manner.
| |
| M1.5 Missed Surveillance and Preventive Maintenance 1
| |
| -
| |
| Missed Technical Specification Surveillance items
| |
| a. Inspection Scope
| |
| The inspectors reviewed the licensee's performance of preventive maintenance items
| |
| and surveillances including a surveillance where many snubbers were not performed
| |
| within required frequency.
| |
| b. Observations and Findinas
| |
| The inspectors spoke with licensee management about the failure to meet a Technical
| |
| Specification 4.8.F-required snubber visual inspection surveillance. Management had i
| |
| indicated that a small number of snubbers were not completed in the required frequency,
| |
| and actually went past the critical date. The critical date of a surveillance was the date at
| |
| which the surveillance was beyond the normal due date by 25 percent of original
| |
| surveillance interval. In this case, the licensee indicated that the 18-month interval was
| |
| exceeded by more than 25 percent on February 13,1998. The stated reason was that
| |
| unforseen circumstances, including inspector qualification prob; ems and a personal
| |
| emergency of the only qualified inspector, prevented completion of the last few
| |
| inspections.
| |
| The inspectors reviewed this and other surveillances and identified that the licensee had
| |
| been scheduling surveillances for performance past the due date (but before the critical
| |
| date) on a frequent basis. The snubber surveillance had been scheduled to start in
| |
| January 1998 during a planned outage, even though the due date for the surveillance was
| |
| thought to be September 1997, which was outside the 18-month interval from the last
| |
| 10
| |
| | |
| .
| |
| *
| |
| e.
| |
| .
| |
| refueling outage. A further review of other surveillances from October 1996 through 3
| |
| February 1998 showed 425 surveillances went past the initial due date compared to 6304 J
| |
| performed on time. Inquiries by the inspectors identified that operations, schedulers and
| |
| other planners often did not question the scheduling of a surveillance past its due date as
| |
| long as the plan was to be complete before the critical date. The problem was
| |
| exacerbated by use of the electronic work control system to extend the due date of
| |
| surveillances, without keeping track of the original due date. The inspectors noted that
| |
| according to the Technical Specifications Section 4.0.B basis, the 25 percent Technical
| |
| Specifications margin was not intended to "be used repeatedly as a convenience to
| |
| extend surveillance intervals beyond that specified for surveillances that are not
| |
| performed during refueling outages." The licensee issued Problem Identification
| |
| Form Q1998-01215 to document the problem.
| |
| Planning aspects also appeared poor because after shutting down Unit 1 in
| |
| December 1997, insufficient planning and management attention were applied to ensure
| |
| completion of the snubber inspections by the critical date. The licensee relied on one
| |
| qualified inspector on the last possible day to perform the remaining surveillance
| |
| requirements, and that plan led to failure to meet the requirements. Planning was also a
| |
| problem because the actual interval for inspection of the snubbers was identified to be
| |
| improper. The scheduled due date for the inspections after refueling outage Q1R14 was
| |
| ; set for September 1997, which was actually longer than 18 months past some of the
| |
| snubber inspections performed in eariy February 1996. Preventive maintenance item
| |
| l
| |
| '
| |
| Number 104537 was intended to initiate the snubber surveillances within the 18-month
| |
| period, but actually scheduled the surveillance at 18 months from the end of the Q1R14
| |
| snubber inspections rather than the beginning of those same inspections. This caused all
| |
| 118 snubber inspections to be beyond the critical date.
| |
| l The inspectors identified a similar scheduling problem for the snubber functional testing i
| |
| and service life monitoring surveillances. The licensee initially indicated that the
| |
| inspections were performed just prior to the critical date being exceeded. However,
| |
| following the inspectors' questions, engineers identified two snubbers which did not have
| |
| functional testing required by Technical Specifications Section 4.8.F.5 performed in the
| |
| r 18-month plus 25 percent period. Snubbers with in Service inspection numbers
| |
| i 10128-W-102 and 0200-W-127 were tested on January 8, and January 7,1998, ,
| |
| i
| |
| respectively. The critical date for these tests was January 6,1998. Failure to perform l
| |
| !
| |
| Technical Specification Surveillance Requirement 4.8.F in the appropriate interval was !
| |
| l considered a Violation (50-254/98004-05).
| |
| 1
| |
| Missed Psuventive Maintenance items
| |
| l
| |
| The inspectors reviewed other preventive maintenance items and identified that the
| |
| l licensee had not completed many of these items within the scheduled frequency of the
| |
| preventive maintenance work request. A licensee preventive maintenance report for
| |
| items required in shutdown modes identified that from October 1996 to February 1998,
| |
| 157 preventive maintenance items were on time, and 1,278 were overdue. The
| |
| inspectors identified specific instances where safety equipment preventive maintenance
| |
| .
| |
| tasks were overdue. For instance,9 Cutler Hammer 250 Volt direct current breaker
| |
| I
| |
| cubicle inspections exceeded the prescribed 6-year frequency. Twenty-one 480 V
| |
| General Electric breakers had exceeded their 3-year preventive maintenance frequency.
| |
| Station blackout diesel generator preventive maintenance items missed required
| |
| '
| |
| 11
| |
| l-
| |
| -
| |
| | |
| .
| |
| s
| |
| *
| |
| .
| |
| frequencies or had never been performed (Problem Identification Form
| |
| Numbers Q1998-00587 and 00590).
| |
| For some of the equipment (breakers), the inspectors identified that the vendor manual
| |
| recommended a yearly preventive maintenance whereas the Quad Cities preventive
| |
| maintenance item was scheduled for three years. The licensee had not ensured that the
| |
| preventive maintenance requirements met the vendor recommendations for inspection
| |
| types or frequency, and had not evaluated the effect of exceeding vendor
| |
| recommendations. In some cases the vendor had recommended yearly inspections,
| |
| I however, the licensee was recommending three-year inspections but allowed 25 percent
| |
| margin or four-year inspections. Even so, maintenance had fciled to complete
| |
| inspections within this four-year time frame. The licensee planned to evaluate the effects
| |
| , of not performing timely preventive maintenance on breakers and perform breaker
| |
| j inspections to ensure preventive maintenance items were current prior to startup.
| |
| l'
| |
| l c. Conclusion
| |
| The licensee was overdue on completion of a number of surveillance and preventive
| |
| maintenance items. The inspectors identified that the licensee was scheduling
| |
| surveillances and preventive maintenance items to be performed past the due date for
| |
| the items. A violation was issued for failure to perform snubber surveillances in the
| |
| l appropriate frequency. The licensee was conducting reviews conceming the effect on
| |
| ; equipment of not performing vendor recommended maintenance on time.
| |
| l
| |
| '
| |
| M3 Maintenance Procedures and Documentation
| |
| M3.1 Emeroency Diesel Generator Testina Procedure
| |
| a. Inspection Scope
| |
| i The inspectors reviewed emergency diesei generator testing procedures and issues
| |
| relating to Unresolved item 50-254/9700843; 50-265/9700843 regarding the status of
| |
| the air start system during emergency diesel generator testing. The inspectors reviewed
| |
| licensee actions, test procedures, and the Updated Final Safety Analysis Report
| |
| (Section 9.5.6) and discussed the issue with the Office of Nuclear Reactor Regulation.
| |
| b. Observations and Findinas
| |
| l
| |
| Previously, the inspectors identified possible deficiencies with the emergency diesel
| |
| ! generator testing procedures. The Technical Specification bases stated that the periodic ;
| |
| '
| |
| ; surveillance requirements verify that sufficient air start capacity for each emergency
| |
| l diesel generator is available without the aid of the refill compressors. The bases further
| |
| stated that with either pair of air receiver tanks at minimum specified pressure, there was
| |
| sufficient air in the tanks to start the emergency diesel generator. Revision 15 of
| |
| Quad Cities Operations Surveillance 6600-01, * Diesel Generator Monthly Load Test," did
| |
| not require the air compressors be off and the air tanks at minimum specified pressure.
| |
| Revision 18 of the procedure was intended to implement these actions, but the procedure
| |
| was incorrect and directed operators to bleed down pressure in the isolated air tanks.
| |
| The independent technical reviews and validation of the procedure change did not find
| |
| the error. Operators noticed the deficiency and uaed numerous field changes to correct
| |
| 12
| |
| l
| |
| | |
| *
| |
| , .
| |
| t .
| |
| !
| |
| l
| |
| the procedure on a temporary basis. A permanent change was in progress at the end of
| |
| the period. The failure to test the emergency diesel generator in accordance with the
| |
| design basis was not considered to be a test control violation because previous testing
| |
| had proven that the emergency diesel generator could be started at lower than
| |
| 230 pounds per square inch gauge air start pressure.
| |
| During the review of the revised procedure, the inspectors noted the " Limitations and
| |
| Actions" section su90ested to operators that a failed start of the emergency diesel
| |
| i generator with one set of air receivers isolated was considered a failure of the air receiver
| |
| l tank and not the emergency diesel generator and suggested that operators attempt a
| |
| i second start. These statements in the " Limitations and Actions" provided inappropriate
| |
| l and conflicting guidance to operators and were not supported in the body of the
| |
| ! procedure. The guidance was directly opposite of recent guidance given to operators
| |
| l after the emergency diesel generator start failure event of January 5,1998, (documented
| |
| l in inspection Report 50-254/97028; 50-265/97028). After that event, operations
| |
| I management emphasized the need to stop and evaluate the situation when abnormal
| |
| l events such as an emergency diesel generator failure occur. The licensee planned to
| |
| remove these statements when the procedure was revised.
| |
| l
| |
| ; c. Conclusion
| |
| i
| |
| j The inspectors had previously identified testing deficiencies with the emergency diesel
| |
| !
| |
| '
| |
| generator air start system. The licensee's initial corrective actions weru "ot technically
| |
| adequate and multiple reviews failed to identify the problems.
| |
| M8 Miscellaneous Maintenance issues (92902)
| |
| M8.1 (Closed) Inspection Follow-up item (50-254/94005-04: 50-265/94005-04): Problems with
| |
| Computer Room Ventilation System. In the past the licensee had numerous problems
| |
| l with the reliability of computer room ventilation. For corrective actions, the licensee
| |
| i
| |
| completed extensive maintenance to this system including the addition of preventive
| |
| maintenance items. The inspectors noted the reliability of the system had been
| |
| increased. This item is closed.
| |
| i
| |
| l M8.2 (Closed) Violation 50-254/95002-04: 50-265/95002-04: Torus Recoat Documentation
| |
| l Deficiencies. The NRC inspectors identified there was no documented review that the
| |
| l deficiencies identified during torus recoating were evaluated for acceptance, rejection or
| |
| rework. The NRC inspectors determined this violated requirements for maintaining
| |
| quality assurance records. The licensee changed the method of documenting and
| |
| reviewing these deficiencies. The inspectors reviewed the improved documentation.
| |
| This item is closed.
| |
| l
| |
| M8.3 (Closed) Unresolved item (50-254/96008-16: 50-265/96008-16): Intermixing of
| |
| Compression Fittings. The inspectors identified the licensee had intermixed various
| |
| manufacturer's compression fittings in the construction of hydraulic control units. The
| |
| licensee evaluated this condition as being acceptable in a parts evaluation. All
| |
| maintenance personnel had since been trained and procedures modified to ensure
| |
| workers do not mix compression fittings in all future uses. The inspectors reviewed the
| |
| applicable maintenance procedures and parts evaluation. As part of the parts evaluation,
| |
| various mismatched fittings were assembled and tested. The licensee concluded the
| |
| 13
| |
| l
| |
| l
| |
| i
| |
| | |
| -
| |
| e
| |
| l.
| |
| p. *
| |
| I-
| |
| fittings were acceptable for use in fit, form and function._ The inspectors noted the
| |
| l information provided was reasonable assurance that the mixed fittings would perform
| |
| l their function. This item is closed.
| |
| M8.4 (Closed) Violation 50-265/97002-04: High Pressure Coolant injection During Power
| |
| l Operation. In 1993 an instrument maintenance procedure was rewritten which removed
| |
| !
| |
| prerequisite steps requiring the procedure be performed in either shutdown or refueling i
| |
| modes. In addition, maintenance supervisors inadequately reviewed the procedure and {
| |
| schedulers inappropriately scheduled the procedure for power operations. For corrective
| |
| ]
| |
| actions, the licensee reviewed surveillances performed more frequently than quarterly to
| |
| ensure plant conditions were proper for testing. The licensee changed the maintenance
| |
| procedure to ensure the proper plant conditions were included. In addition, other j
| |
| L administrative procedures were changed to ensure proper review of surveillances prior to
| |
| ! performance. The inspectors reviewed the revised procedures. This item is closed.
| |
| l
| |
| M8.5 (Closed) Inspection Follow-up Item 50-265/97002-05: High Pressure Coolant injection
| |
| During Power Operation. The inspectors were concemed with the scheduling process
| |
| which allowed an instrument surveillance procedure be performed for the wrong plant
| |
| j conditions (see above item). The licensee changed an administrative procedure to
| |
| : require use of a daily work addition sheet and subsequent reviews to ensure proper plant
| |
| '
| |
| conditions were in place for testing. This item is closed.
| |
| l
| |
| M8.6 (Closed) Unresolved item (50-254/97008-03: 50-265/97008-03): Emergency Diesel
| |
| ! Generator Testing. This item is addressed in Section M3.1 of this report and is closed.
| |
| Ill. Enoineerina
| |
| E1 Conduct of Engineering
| |
| l E1.1 General Comments (71707)
| |
| The licensee continued to experience problems with emergency diesel generator
| |
| performance. A prompt investigation team could not positively identify the root cause for
| |
| problems associated with the Unit 1 emergency diesel generator failure to start in
| |
| January 1998. However, the prompt investigation team did identify the cause for a
| |
| second failure of the Unit i emergency diesel generator to run. The inspectors noted
| |
| improvements in the licensee's preparation and execution of visual test examinations of ;
| |
| the reactor vessel during pressure testing on Unit 1. !
| |
| E1.2 Root Cause of Unit 1 Emeroency Diesel Generator Failure Not Identified
| |
| a. Inspection Scope
| |
| l
| |
| The inspectors reviewed the continuing root cause investigation for the Unit 1 emergency ;
| |
| diesel generator failure on January 5,1998. I
| |
| 14
| |
| l
| |
| | |
| *
| |
| , .
| |
| .
| |
| b. Observations and Findinas
| |
| This failure was similar in several respects to emergency diesel generator failures that
| |
| occurred in August and October 1995, January and May 1997. In each of these cases
| |
| the emergency diesel generator failed to start but successfully started on a second
| |
| attempt some time later. Root causes were not always identified but the air start system
| |
| was the focus of the investigations. Binding of air start motors was identified in this most
| |
| recent event in addition to two of the previous failure events.
| |
| A previous corrective action was to inspect the air start motors for binding upon
| |
| installation. Since the air start motors were installed in December 1997 and one was
| |
| identified to be binding in January 1998, the inspectors noted that to inspect for binding
| |
| may not be effective. The licensee sent the air start motor offsite for further failure
| |
| analysis, and no binding mechanism or problem with the air start motor was identified.
| |
| Although the air start motor was replaced, no other corrective actions to address air start
| |
| system problems were taken prior to declaring the emergency diesel generator operable.
| |
| An action item to investigate air start motor binding was given a September 30,1998, due
| |
| date. A trend investigation team issued a report detailing a number of corrective actions
| |
| for improving reliability. The report, titled, " TREND INVESTIGATION OF EMERGENCY
| |
| DIESEL GENERATOR START FAILURES AND RECOMMENDATION TO INCREASE
| |
| RELIABILITY (Nuclear Tracking System number NTS 254-230-98-SCAQ00003)," was
| |
| issued March 2,1998. Recommendations in the report to add air start motor redundancy
| |
| (Nuclear Tracking System item 007-200-97-QRCR01-01) were not implemented.
| |
| The licensee had speculated that the air start motor problems were due to abutment of
| |
| the pinion gear to the emergency diesel generator ring gear which prevented the pinion
| |
| from turr,ing the ring gear. Engineers designed and performed a test on a similar model
| |
| diesel generator which indicated that abutment would not prevent a diesel start. No
| |
| further short term analyses of the air start motor problems were pursued. The inspectors
| |
| discussed with Com8:d management that the design of the Quad Cities emergency diesel
| |
| generators was susceptible to air start motor failures because only two air start motors
| |
| were available to crank the diesel, vice four motors available on many other similar
| |
| engines at nuclear plants. The system engineer indicated that the manufacturer
| |
| representative explained that one air start motor was not sufficient to start the emergency
| |
| diesel generator. Thus with the failure or reduced torque capacity on only one air start
| |
| motor, a Quad Cities emergency diesel generator may not start. Susceptibility of air start
| |
| systems on Quad Cities emergency diesel generators was identified to Quad Cities in a
| |
| June 2,1992, architect engineer report which compared the Quad Cities design to
| |
| 10 CFR 50, Appendix A requirements and to the Dresden Station design. Modifications
| |
| to improve reliability were recommended at that time, but were not implemented by
| |
| Quad Cities because it was believed that the method the Dresden Station used to
| |
| improve reliability (multiple start attempts) may introduce circuit problems. Other
| |
| methods to improve reliability were not addressed. I
| |
| On March 2,1998, the plant operations review committee reviewed a trend investigation
| |
| of emergency diesel generator failures and recommended that the Unit i emergency
| |
| diesel generator be declared operable based on troubleshooting and testing performed,
| |
| thirteen successful starts, and the replacement of the questionable air start motor. The -
| |
| operability recommendation was made even though no root cause was identified, a past
| |
| history of similar failures existed, and no short term actions to address air start motor
| |
| l
| |
| 15
| |
| | |
| '
| |
| .
| |
| .
| |
| 4
| |
| l
| |
| l
| |
| vulnerabilities were implemented. Subsequent to the plant onsite review committee
| |
| recommendation, operators declared the Unit 1 emergency diesel generator operable on
| |
| March 3.
| |
| c. Conclusion
| |
| The licensee was not successful in determining the root cause of the Unit 1 emergency
| |
| diesel generator failure to start in January 1998. Nonetheless, operations declared the
| |
| '
| |
| Unit 1 emergency diesel generator operable based on a history of successful starts. No
| |
| specific actions were recommended to address air start motor problems and design
| |
| vulnerabilities, although several root cause investigations and failure determinations had
| |
| pointed to air start motor failures in the past. The inspectors recognized substantial effort
| |
| was expended by the licensee to evaluate this emergency diesel generator failure.
| |
| However, the licensee's inability to determine a root cause and the lack of recommended
| |
| actions for airstart system problems caused the inspectors to be concemed with the
| |
| effectiveness of licensee corrective actions for diesel generator failures.
| |
| l
| |
| l E1.3 Unit 1 Emeroency Diesel Generator Tripped Durina Testina
| |
| 1
| |
| '
| |
| a. Inspection Scope (71707)
| |
| !
| |
| The inspectors reviewed problem information forms and the prompt investigation team
| |
| report associated with the Unit 1 emergency diesel generator electrically tripping during a
| |
| l
| |
| '
| |
| surveillance test. The inspectors also observed licensee walkdowns of the emergency
| |
| diesel generator and observed some maintenance activities.
| |
| b. Observations and Findinas
| |
| On March 17,1998, operators started the Unit 1 emergency diesel generator for testing
| |
| '
| |
| and electrically loaded the generator to the bus. After about 30 minutes, the emergency
| |
| diesel generator electrical output breaker unexpectedly opened. Operators previously
| |
| identified unusual light flickering during the test. After depressing the stop switch in the
| |
| control room, the operators detected further indications of unusual light flickering from the
| |
| f "run" and "stop" indicating lights.
| |
| Operators quarantined the faulty equipment and initiated a prompt investigation team.
| |
| The team gathered data from the event, visually inspected the equipment, and reviewed
| |
| electrical drawings in an attempt to determine the cause of the electrical fault. The team
| |
| concluded that a loose connection in a fuse assembly associated with the power supply
| |
| to the emergency dieael generator circuitry was the cause of the fault. The team also had
| |
| the same item checked on the other emergency diesel generators to ensure there was no
| |
| common mode failure, No discrepancies were identified. The licensee removed and
| |
| planned to autopsy the faulty fuse assembly. A new fuse assembly was installed, and the
| |
| diesel was later tested satisfactorily.
| |
| c. Conclusions
| |
| The licensee continued to have problems associated with the reliability of the emergency
| |
| diesel generators (see Section O2.2 in this report and inspection Report 50-254/97028;
| |
| } 16
| |
| l
| |
| ,
| |
| I
| |
| l
| |
| | |
| .
| |
| . .
| |
| .
| |
| I
| |
| 50-265/97028). The prompt investigation team identified the cause of the event and took
| |
| l proper corrective actions to address the problem.
| |
| l E2 Engineering Support of Facilities and Equipment
| |
| E2.1 Problems with Time Delav Relavs on Emeroency Diesel Generators
| |
| l a. Inspection Scope
| |
| The inspectors reviewed the licensee's troubleshooting and maintenance process for
| |
| failures of time delay relays similar to failures noted in December 1997 and documented
| |
| in Inspection Reports 50-254/97028 and 50-265/97028.
| |
| b. Observations and Findinas
| |
| ; On March 22,1998, the licensee identified problems with the timing setpoints of the
| |
| '
| |
| Unit i emergency diesel generator time delay relays 1 and 2. Time delay relay 2 limited
| |
| ; the amount of time the emergency diesel generator cranked during start attempts to
| |
| '
| |
| preserve starting air for another attempt. Timing out too early on time delay relay 2 could
| |
| prevent an emergency diesel generator start and possibly damage the emergency diesel
| |
| generator due to high temperature problems. Time delay relay 1 ensured that the
| |
| emergency diesel generator would stop (unless an auto-start signal was present) after
| |
| 90 seconds if sufficient oil pressure was not achieved in the emergency diesel generator.
| |
| Timing out too early on time delay relay 1 could cause the emergency diesel generator to
| |
| shut down in all but auto start situations. Both relays were Square D Type EQ1933G2
| |
| with a range of zero to three minutes.
| |
| The licensee assembled a prompt investigation team to review the operability of the
| |
| emergency diesel generator, and to identify what actions needed to be taken if it was
| |
| l found necessary to modify the time delay circuitry. The team identified a number of
| |
| l problems with the relays and their application.
| |
| l
| |
| l
| |
| . The relays were not designed for a vibration environment according to system
| |
| engineer discussions with the vendor (Engine Systems Incorporated). However,
| |
| '
| |
| the relays were installed on the emergency diesel generator skid which was
| |
| ; subjected to vibration during diesel operation.
| |
| !
| |
| l . The relays had a plus or minus ten percent stated repeat accuracy according to
| |
| the manufacturer, but were being set in an acceptable band of only half that
| |
| amount for time delay relay 2.
| |
| . The relays were very sensitive, and difficult to set property.
| |
| . The relays exhibited varying amounts of drift outside of the stated accuracy.
| |
| Some of the drift was associated with the difference between static and engine
| |
| running conditions.
| |
| The team concluded that the relays would likely hold to an acceptable calibration if the
| |
| setpoint band was changed to be within the stated accuracy of the relays. The time
| |
| delay relay 2 band was expanded from 15 to 16.5 seconds to 13.5 to 16.5 seconds. The
| |
| 17
| |
| .
| |
| i
| |
| | |
| .
| |
| <
| |
| .
| |
| time delay relay 1 setpoint band of 81 to 99 seconds was deemed acceptable. The team
| |
| also established by field testing that the relays would drift to actuate more quickly in a
| |
| vibration environment (by about two to four seconds). Based on six starts of the Unit 1
| |
| emergency diesel generator with only one failure of time delay relay 1 to maintain the
| |
| acceptable band and no time delay relay 2 failures, the station concluded that the Unit 1
| |
| emergency diesel generator was operable. Relays in the Unit 2 and Unit % emergency
| |
| i diesel generators were tested, and reset or replaced. The team concluded that all
| |
| '
| |
| emergency diesel generators were operable, and continued to pursue a long term
| |
| solution to time delay relay reliability, including potential replacement with relays not
| |
| affected by vibration, and movement of the relay onto a non-vibrating environment.
| |
| Engineers also planned weekly tests of the emergency diesel generators for at least three
| |
| weeks to establish a reliability trend.
| |
| Although the licensee's evaluation efforts were substantial, the inspectors were
| |
| concemed with the licensee's approach to determining operability.
| |
| . The inspectors identified that even though testing methodology was improved, a
| |
| number of time delay relay failures occurred outside the expected 10 percent
| |
| accuracy range. One time delay relay 2 failure occurred only three months after
| |
| relay replacement, and exhibited a six-second setpoint drift. Other time delay
| |
| relay failures were also documented because of repeatability problems. Although
| |
| several tests had been performed, sufficient data to establish an adequate
| |
| calibration frequency and methodology had not been developed by the close of
| |
| the inspection period. The licensee had planned at least three weekly tests during
| |
| running conditions for each emergency diesel generator, but had not started these
| |
| tests due to plant conditions.
| |
| . The inspectors observed the field setpoint for time delay relay 2 on the Unit 1
| |
| emergency diesel generator, it was set at 16.4 seconds which was in the
| |
| acceptable band provided by the procedure. However, the inspector identified
| |
| that the basis for allowing a setpoint greater than 15 seconds was not well ;
| |
| established. With a stated manufacturer accuracy of plus or minus 10 percent, !
| |
| cranking time for the emergency diesel generator could be as long as 18 seconds.
| |
| Updated Final Safety Analysis Report Section 9.5.6 indicated the starting air
| |
| system for the engine would crank the engine for 15 seconds or until the engine
| |
| started, that there was sufficient air for two 15-second starts, and if the engine did
| |
| not reach 200 rpm within 15 seconds, a diesel generator " fail to start" alarm would
| |
| annunciate in the main control room. Quad Cities design basis document
| |
| DBD-QC-009, Revision A, Section 4.1.7.2 indicated the 15-second cranking cycle
| |
| was determined to allow the maximum cranking time and still prevent the
| |
| equipment from overheating. Although the licensee documented this information
| |
| in a screening for Problem identification Form Q1998-00251, the justification for
| |
| not damaging components or for challenging the 15-second Updated Final Safety
| |
| Analysis Report criteria was not well established. This is considered an
| |
| Unresolved item (50-254/98004-06; 50-265/98004-06) pending review of
| |
| licensee justification for changing Updated Final Safety Analysis Report
| |
| requirements.
| |
| + The inspectors ieviewed the qualification paperwork which upgraded the
| |
| commercial grade time delay relays to a safety related status. Parts Evaluation
| |
| j 18
| |
| | |
| : ,. '.
| |
| l.
| |
| l
| |
| CE-89-1540 dedicated both time delay relays 1 and 2 for 10 CFR 21 safety-related
| |
| status. The evaluation clearly justified the need for the parts to be classified as
| |
| safety related. However, the authorizing evaluation (M-95-0697-00) provided by
| |
| the licensee as the document used to qualify the commercial grade part, did not
| |
| provide a discussion of critical characteristics for the relays. The inspectors
| |
| identified no discussion of any sort as to the qualification for vibration or seismic
| |
| conditions, high temperatures or other adverse conditions in the emergency diesel
| |
| , generator rooms during operation. This is considered an Unresolved item
| |
| (50-254/98004 07; 50-265/98004-07) pending further review of licensee
| |
| qualification information.
| |
| c. Conclusions
| |
| Although licensee efforts to investigate emergency diesel generator time delay relay
| |
| failures were good, significant reliability problems still existed. Engineering justification
| |
| for dedicating the relays as safety-related parts did not address vulnerabilities of the
| |
| relays to the vibration environments in which they operated. Engineering justification for
| |
| exceeding Updated Final Safety Analysis Report limits for the relay settings was not
| |
| thorough.
| |
| l E5 Engineering Staff Training and Qualification
| |
| l
| |
| l E5.1 Unit 1 Class 1 Leak Test
| |
| a. Inspection Scope (37551)
| |
| !
| |
| With the system pressurized to normal operating pressure, the inspectors accompanied
| |
| Level ll Visual Test-2 examiners during the operational pressure test of the Unit i reactor
| |
| vessel and attached piping both inside and outside the drywell.
| |
| I
| |
| b. Observations and Findinos
| |
| i
| |
| '
| |
| Licensee personnelinspected the Unit 1 pressure vessel, including head flange and all l
| |
| '
| |
| piping up to low pressure interfaces, with reactor pressure at 1000 pounds per square
| |
| l
| |
| inch gauge. Personnel training and numerous briefs were conducted prior to the
| |
| l pressure test to ensure examiners were properly informed of management expectations
| |
| and familiar with the newly approved procedures. Each examiner conducted walkdowns
| |
| of inspection points using marked up maps with specific inspection points prior to the
| |
| pressure test. ,
| |
| ,
| |
| i~ During the pressure test, the examiners used inspection mirrors and spotlights to assist in
| |
| examinations. The examiners were familiar with the piping and carried piping diagrams
| |
| and sign off sheets, which were marked while conducting examinations. The inspections
| |
| took several hours, as opposed to the twenty minute versions performed last summer on
| |
| l Unit 2. The examiners in the drywell were subjected to elevated ambient temperatures
| |
| and higher radiation dose rates. The inspectors observed the examinations and
| |
| determined that even under these difficult conditions, the examinations were thorough.
| |
| A portion of the visual test examination was located undemeath the reactor vessel. The
| |
| areas of leakage were not readily accessible and considerable effort was needed for the
| |
| 19
| |
| | |
| *
| |
| ,, .
| |
| .
| |
| examiner to identify the locations of leakage. However, from this examination, a leak in
| |
| the Unit 1 reactor bottom head drain line was identified and repairs were subsequently
| |
| initiated. The examiners determined a 2 inch reactor water cleanup pipe beneath the
| |
| reactor vessel had a through-weld leak. Similarly, the reactor vessel head flange leak
| |
| detection system alarmed indicating possible reactor vessel head flange leakage.
| |
| ,
| |
| Licensee management was informed of the results of the test. The licensee planned to
| |
| j address the leaks prior to unit staeo.
| |
| c. Conclusions
| |
| f
| |
| l The inspectors noted there were more preparations (meetings, drawing reviews and
| |
| I
| |
| subsequent walkdowns) by the examiners for this pressure test than other similar
| |
| pressure tests. Piping inspections observed were thorough. The examiners identified
| |
| i leakage which required repair prior to unit startup.
| |
| l
| |
| l E7 Quality Assurance in Engineering Activities
| |
| E7.1 Review of 10 CFR 50.59 Summary Report and Updated Final Safety Analysis Report
| |
| l Update
| |
| a. Inspection Scope (71707)
| |
| The inspectors reviewed the licensee's " Summary Report of Changes, Tests and
| |
| Experiments Completed," dated October 31,1997, and " Updated Final Safety Analysis
| |
| ,
| |
| Report (UFSAR) Update," dated October 22,1997. The inspection included a review of
| |
| l selected changes to the Updated Final Safety Analysis Report and 50.59 summary
| |
| l reports, and discussions with regulatory assurance personnel.
| |
| ;
| |
| b. Observations and Findinas
| |
| The inspectors reviewed " Summary Report of Changes, Tests and Experiments
| |
| Completed," dated October 31,1997. One summary in the report stated there was a
| |
| reduction in the margin of safety. Upon further review of the actual safety evaluation, it
| |
| was determined that the summary report was in error. A licensee letter dated March 20, ,
| |
| 1998, corrected this error. This was the second safety evaluation summary in this report l
| |
| which incorrectly indicated there was a reduction in margin of safety. The other safety l
| |
| evaluation,96-043, was discussed in Inspection Report 50-254/97022; 50-265/97022. I
| |
| On two occasions, information removed from Technical Specifications was either
| |
| changed without an evaluation or not placed into the Updated Final Safety Analysis
| |
| Report in its entirety. The items were removed from Technical Specifications with the
| |
| intention of being placed in the Updated Final Safety Analysis Report. In Technical ,
| |
| '
| |
| Specification Amendment 177 for Unit 1 and 175 for Unit 2, dated May 23,1997, previous
| |
| Technical Specification Section 5.4, " Reactor Coolant System," was removed from
| |
| Technical Specifications and was to be placed into the Updated Final Safety Analysis
| |
| l Report. The licensee was not able to provide documentation showing that all of the
| |
| information in Technical Specification 5.4 had been placed into the Updated Final Safety
| |
| Analysis Report.
| |
| { 20
| |
| l
| |
| l
| |
| | |
| .
| |
| , *
| |
| v
| |
| The second example involved the removal of Table 4.6-2, * Revised Withdrawal Schedule
| |
| For Quad Cities Unit 2" from the previous Technical Specification and placing the
| |
| l information into the Updated Final Safety Analysis Report in accordance with
| |
| Amendment 158. This table was the schedule for removal of the reactor vessel material
| |
| samples based on a surveillance program as defined in Section Ill.C of 10 CFR Part 50,
| |
| ; Appendix H. The azimuth location for one of the sample holders in the Updated Final
| |
| l Safety Analysis Report did not reflect the position shown in Table 4.6-2.
| |
| l
| |
| The licensee stated the Updated Final Safety Analysis Report would be corrected and the
| |
| information in previous Technical Specification Section 5.4 and Table 4.6-2 would be
| |
| included into the Updated Final Safety Analysis Report. On January 6,1998, the
| |
| Quad Cities Station Manager stated he would ensure that all the items removed from
| |
| Technical Specifications that were to be placed into controlled documents in accordance
| |
| with the Technical Specification Upgrade Program (Amendment 171 for Unit 1 and
| |
| A.mendment 167 for Unit 2) had been accomplished.
| |
| c. Conclusions
| |
| There were inconsistencies between two 10 CFR 50.59 summary report summaries and
| |
| the respective safety evaluations. Also, the Updated Final Safety Analysis Report update
| |
| identified two former Technical Specification items that were not placed into the Updated
| |
| Final Safety Analysis Report as intended. These inconsistencies pointed to a need for
| |
| more attention to this area to assure the licensing basis was properly maintained.
| |
| E8 Miscellaneous Engineering issues
| |
| E8.1 (Closed) Unresolved Item 50-254/94028-01: 50-265/94028-01: Incorrect Rod Withdrawal
| |
| Sequence Error. The licensee identified that the sequence for control rod withdrawal was
| |
| not in accordance with fuel vendor requirements. This condition existed when an
| |
| engineer developing the rod program did not encounter any waming messages of the
| |
| deviation from the software. The sequence was copied for rod withdrawals since
| |
| October 1991. The licensee analyzed this condition and determined the Technical
| |
| Specification requirements for energy deposition in the fuel during a rod drop accident
| |
| were not exceeded. The licensee corrected the rod withdrawal sequence error and
| |
| retrained nuclear engineering personnel. The software used in building the control rod
| |
| withdrawal sequence was reviewed for technical accuracy and validated. The inspectors
| |
| reviewed the licensee's investigation and corrective actions for this event. This item is
| |
| closed. j
| |
| E8.2 (Closed) Inspection Follow-up item 50-254/95005-05: 50-265/95005-05: Incomplete
| |
| Disposition of Information Notice 91-78. The information notice documented instances I
| |
| where safety-related breakers had failed due to existing blown fuses in the control circuit
| |
| that were not indicated. The issue was applicable to breakers at Quad Cities; however,
| |
| no changes to the control circuit were planned and operators were not aware that a
| |
| failure in the control circuit could prevent a breaker from closing but would not always be
| |
| indicated by the loss of indicating lights. The station chose to train operators and
| |
| presented this topic in a training session (95-6). The inspectors reviewed the training
| |
| module. This item is closed.
| |
| 21
| |
| | |
| *
| |
| ,. .
| |
| .
| |
| E8.3 (Closed) Unresolved item 50-254/96012-03: 50-265/96012-03: Altemate Battery
| |
| Replacement. Operators removed the Unit 2 altemate 125 Volt direct current battery
| |
| from service for a four month period. During an extended maintenance activity, the
| |
| attemate battery lost the ability to maintain a charge. The licensee removed the Unit 2
| |
| attemate battery and replaced it with the attemate battery from Unit 1. Both the normal
| |
| and attemate batteries from Unit 2 were tested satisfactorily. This item is closed.
| |
| E8.4 (Closed) Deviation 50-254/96015-01: 50-265/96015-01: Residual Heat Removal Service
| |
| Water Cooler Fouling. The inspectors identified that residual heat removal service water
| |
| cooling to the safety-related components was not trended as the licensee had committed
| |
| to in a licensee event report. The reason for the deviation was an inadequate tumover in
| |
| system engineering and no procedural requirement to trend and analyze system
| |
| performance. The licensee implemented a procedure to trend and analyze residual heat
| |
| removal service water system performance and electronically tied this procedure to the
| |
| surveillance test to ensure the system engirteer was notified of the test performance. The
| |
| inspectors reviewed the licensee's corrective actions. This item is closed.
| |
| E8.5 (Closed) Licensee Event Report (LER 50-254/96016) and (Closed) Violation
| |
| (50-254/96019-02al: Reactor Building Siding Damaged by High Wind. On May 10,1996,
| |
| high wind damaged the reactor building siding. The licensee identified reactor panel blow
| |
| out bolts, which fastened the siding to the structural steel, had been damaged prior to the
| |
| event. The licensee also identified that the bolts and structure had never been subjected
| |
| to inspection as required by a design drawing. This, and other issues, were discussed in
| |
| Inspection Report 50-254/96019; 50-265/96019 and were subject to enforcement action
| |
| (Enforcement Action 96-531). The licensee completed the corrective actions stated in
| |
| the licensee event report. The inspectors reviewed the corrective actions and verified the
| |
| reactor building structure was included in an inspection program. These items are
| |
| closed.
| |
| E8.6 (Closed) Violation 50-254/96019-01: 50-265/96019-01: 50-254/96019-02b:
| |
| 50-265/96019-02b: Design Control and Modification Violations Associated with i
| |
| '
| |
| Secondary Siding. These violations were associated with Enforcement Action 96-531.
| |
| The inspectors identified piping fastened to the reactor building blow out panels that was
| |
| not properly analyzed and a 10 CFR 50.59 evaluation which improperly concluded that a
| |
| change to the facility did not involve an unreviewed safety question. The licensee
| |
| completed the corrective actions documented in the response to the violation. The
| |
| inspectors verified the piping fastened to the reactor building blow out panels was
| |
| removed. These items are closed. ;
| |
| i
| |
| E8.7 (Closed) Unresolved Item 50-254/97006-06: 50-265/97006-06: Inservice Test
| |
| instrumentation Requirements. The inservice test alert and required action range limits
| |
| were calculated down to tenths of gallons per minute as noted during the standby liquid
| |
| control system surveillance. The installed gauge was in increments of two gallons per
| |
| minute. The inspectors reviewed the inservice test program requirements and concluded
| |
| that these limits were acceptable. This item is closed.
| |
| E8.8 (Closed) Unresolved item 50-254/97028-04: 50-265/97028-04): Emergency Diesel
| |
| Generator Fuel Oil Retum Piping Inadequately Supported. The inspectors identified that
| |
| the fuel oil retum pipe from the shared emergency diesel generator to the day tank was in
| |
| contact with an adjacent electrical conduit and questioned the distance between
| |
| 22
| |
| | |
| '
| |
| ..<
| |
| : *
| |
| I
| |
| supports. Engineering analyzed both conditions. Engineering determined the fuel oil
| |
| l retum piping was adequately supported and determined the interaction between the two
| |
| pipes, even during a seismic event, was within the design margins. The inspectors i
| |
| '
| |
| reviewed the supporting calculations. This item is closed.
| |
| IV. Plant Support
| |
| l
| |
| R1 Radiological Protection and Chemistry Controls j
| |
| i
| |
| R1.1 Unit 1 Drywell Radioloaical Conditions
| |
| a. Inspection Scope
| |
| The inspectors reviewed drywell conditions during and following a reactor pressure
| |
| boundary leak (Mt.
| |
| b. Observations and Findinas
| |
| During preparations for a Unit 1 drywell tour, inspectors and senior NRC management
| |
| were briefed by radiation protection technicians as to the contamination and radiation
| |
| levels in the basement and first two levels of the drywell. Contamination levels in the
| |
| Unit 1 drywell basement reached as high as 1 million disintegrations per minute per ,
| |
| 100 square centimeters. General area dose rates averaged about 80 millirem per hour. !
| |
| On the first and second levels of Unit 1 drywell, contaminations levels averaged about
| |
| 25,000 disintegrations per minute per 100 square centimeters. General area dose rates
| |
| on the first and second levels averaged about 60 millirem and 300 millirem respectively.
| |
| During the tour, inspectors identified some of the areas reading in excess of 500 millirem
| |
| per hour.
| |
| 1
| |
| Although the licensee indicated that the normal refueling outage process of chemical j
| |
| decontamination had not taken place tweduce dose rates, and the drywell had not been i
| |
| '
| |
| cleaned as it would for an outage, the inspectors considered the dose rates and
| |
| contamination levels abnormally high. Cursory reviews of several other boiling water
| |
| reactor drywells indicated general area dose rates in the range of 10 to 20 percent of the
| |
| Quad Cities Unit 1 levels, and contamination levels of 1 to 20 percent of the Quad Cities
| |
| Unit i levels. The high contamination levels had affected workers performing leak test
| |
| inspections in that they were required to wear face shields and full rubber gear during
| |
| drywell basement inspections. The high radiation levels affected all drywell workers,
| |
| especially leak test inspectors who needed to perform detailed piping inspections, and
| |
| may have been limited by dose concems. The inspectors identified that while the
| |
| radiation protection planning had incorporated as low as reasonably achievable
| |
| considerations, the management attention to high dose rates and contamination levels
| |
| did not lead overall to as low as reasonably achievable work practices.
| |
| Previous practices of cycling hydrogen addition (used to protect reactor recirculation
| |
| piping from cracking) was believed to be the reason for increased reactor system dose
| |
| rates. The licensee indicated that chemical decontamination was not possible for the
| |
| expected duration of the safe shutdown outage, and hanging lead shielding would not
| |
| yield as low as reasonably achievable radiation doses because of the excessive dose
| |
| 23
| |
| | |
| *
| |
| ,
| |
| ,.
| |
| .
| |
| accumulated in hanging the shielding compared to the amount of work remaining in the
| |
| drywell. The licensee agreed that contamination levels could be reduced to levels which
| |
| would not require face shields or as extensive rubber gear protection and formulated a
| |
| plan to spot clean Unit 2 prior to the leak test. Spot cleaning in the Unit 2 drywell reduced
| |
| contamination levels from over 2 million disintegrations per minute per 100 square
| |
| centimeters to about 75,000 disintegrations per minute per 100 square centimeters and I
| |
| allowed inspectors and workers to be free from face shields. Dose rates for the shut
| |
| down Unit 2 reactor at Quad Cities were about 20 percent of the Unit 1 rates due in part
| |
| to a recent chemical decontamination and in part to installation of depleted zinc injection.
| |
| Zinc injection was also instalfed in Unit 1 during the present outage.
| |
| The inspectors reviewed the licensee's plans to use zine injection for Unit 1. Chemical
| |
| decontamination prior to using zinc injection had been observed to reduce the high ;
| |
| radiation depositions prior to adding the zinc coating, and yield an overall lower dose rate l
| |
| for reactor systems. The licensee had not yet determined if a chemical decontamination
| |
| should be completed.
| |
| c. Conclusion
| |
| The licensee was not aggressive in ensuring that radiation and contamination levels did
| |
| not affect worker performance and were kept as low as reasonably achievable in the
| |
| Unit 1 drywell. Plans to use zine injection for Unit 1 were aimed at future radiation dose
| |
| reduction.
| |
| R1.2 Hydrolasina Effectively Reduced Dose Rates
| |
| The Unit i scrarc discharge headers were recently hydrolased to reduce dose rates for
| |
| hydraulic control unit work and to reduce dose rates in the general area. Station workers
| |
| had written a new procedure which allowed workers to perform the hydrolasing operation
| |
| faster than previously. The licensee found that personnel dose for this job was
| |
| significantly reduced. Over the last two hydrolasing efforts, the dose was reduced by
| |
| three to six times over previous performances. This was a significant contribution in
| |
| keeping exposure to workers as low as reasonably achievable.
| |
| R8 Miscellaneous Radiological Protection and Chemistry issues
| |
| ,
| |
| R8.1 (Closed) Unresolved item 50-254/96020-08: 50-265/96020-08: Weaknesses in !
| |
| Calibration Program. The inspectors identified a low flow condition in a radiological
| |
| '
| |
| l
| |
| effluent monitoring system. The licensee determined the cause of the radiological i
| |
| effluent monitor low flow was due to weak change management by the design engineer
| |
| and poor deficiency resolution by the instrument maintenance department. For corrective ;
| |
| '
| |
| actions, the licensee calibrated the appropriate flow switch and pressure indicators, and
| |
| included the pressure indicators in a calibration program. The licensee also developed a
| |
| calibration procedure for the flow switch on an 18-month frequency. The inspectors
| |
| consider this unresolved item closed.
| |
| l
| |
| The inspectors further questioned the licensee's calibration program used in support of
| |
| i safety-related systems. The inspectors opened Inspection Follow-up
| |
| Item 50-254/97002-06; 50-265/97002-06 to evaluate other safety-related instrument
| |
| calibration issues.
| |
| 24
| |
| i
| |
| e
| |
| | |
| i ,. ,
| |
| .
| |
| V. Manaaement Meetinos
| |
| X1 Exit Meeting Summary
| |
| The inspectors presented the inspection results to members of licensee management at the
| |
| conclusion of the inspection on March 31,1998. The licensee acknowledged the findings
| |
| presented.
| |
| ,
| |
| !
| |
| !
| |
| !
| |
| l
| |
| l
| |
| l
| |
| !
| |
| l
| |
| 1
| |
| l
| |
| 25
| |
| | |
| (
| |
| ? ,, : o
| |
| ! .
| |
| I
| |
| l
| |
| ! PARTIAL LIST OF PERSONS CONTACTED
| |
| l Licensee
| |
| l D. Sager Site Vice President
| |
| L. Pearce Station Manager
| |
| J. Walker Quality Safety & Assessment Manager
| |
| R. Holbrook Engineering Manager 1
| |
| R. Svaleson Operations Manager
| |
| G. Powell Radiation Protection / Chemistry Manager (Acting)
| |
| l A. Chernick Regulatory Affairs Superintendent
| |
| J. Kudalis Business Manager
| |
| R. Cook Electrical Maintenance Team Coordinator
| |
| l J. Weaver Training Supervisor
| |
| i
| |
| ;
| |
| l
| |
| ,
| |
| !
| |
| !
| |
| 26
| |
| i
| |
| i
| |
| | |
| 1
| |
| i
| |
| j ,.-!,-
| |
| l,
| |
| INSPECTION PROCEDURES USED
| |
| ! IP 37551: Offsite Engineering
| |
| l IP 61726: Surveillance Observations
| |
| IP 62707: Maintenance Observations
| |
| IP 71707: Plant Operations
| |
| IP 92700: .Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor
| |
| Facilities l
| |
| '
| |
| lP 92902: Followup - Maintenance
| |
| ITEMS OPENED, CLOSED, AND DISCUSSED
| |
| Opened .
| |
| 50-265/98004-01 VIO failure to follow procedures and log tracking
| |
| j errors
| |
| l 50-265/98004-02 NCV valves out of position during work by vendor
| |
| l '50-254/98004-03; 50-265/98004-03 VIO missed standby liquid control system
| |
| i surveillance due to inadequate procedure
| |
| l 50-254/98004-04; 50-265/98004-04 VIO missed surveillance tests for source range
| |
| instruments
| |
| 50-254/98004-05 VIO missed surveillance on piping snubbers )
| |
| 50-254/98004-06; 50-265/98004-06 URI EDG Updated Final Safety Analysis Report I
| |
| ! discrepancies
| |
| !
| |
| 50-254/98004-07; 50-265/98004-07 URI time delay relay qualification for part 21
| |
| Closed
| |
| 50-265/96002-00 LER high pressure coolant injection inoperable
| |
| due to inadequate venting
| |
| 50-254/94005-04; 50-265/94005-04 IFl problems with computer room ventilation
| |
| system
| |
| 50-254/95002-04; 50-265/95002-04 VIO torus recoat documentation deficiencies
| |
| 50-254/96008-16; 50-265/ % 008-16 URI intermixing of compression fittings
| |
| 50-265/97002-04 VIO high pressure coolant injection during power
| |
| operation
| |
| 50-265/97002-05 IFl high pressure coolant injection during power
| |
| operation
| |
| 50-254/97008-03; 50-265/97008-03 URI Technical Specification bases not in
| |
| agreement with procedures
| |
| 50-254/94028-01; 50-265/94028-01 URI incorrect rod withdrawal sequence error
| |
| '50-254/95005-05; 50-265/95005-05 IFl incomplete disposition of Information
| |
| Notice 91-78
| |
| 50-254/96012-03;50-265/96012-03 URI attemate battery replacement
| |
| 50-254/96015-01; 50-265/96015-01 DEV residual heat removal service water cooler
| |
| fouling
| |
| 50-254/96016-00 LER reactor building siding damaged by high
| |
| wind
| |
| 50-254/96019-02a VIO reactor building siding damaged by high
| |
| wind
| |
| 27
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| 50-254/96019-01; 50-265/96019-01 VIO design control and modifications violations
| |
| associated with secondary siding
| |
| 50-254/96019-02b; 50-265/96019-02b VIO design control and modifications violations
| |
| associated with secondary siding
| |
| 50-254/97006-06; 50-265/97006-06 URI inservice test instrumentation requirements
| |
| l
| |
| '
| |
| 50-254/97028-04; 50-265/97028-04 URI emergency diesel generator fuel oil retum
| |
| piping inadequately supported
| |
| 50-254/98004-02 NCV valves out of position during work by vendor
| |
| l 50-254/96020-08; 50-265/96020-08 UNR Weaknesses in Calibration Program
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| LIST OF ACRONYMS AND INITIALISMS USED
| |
| CFR Code of Federal Regulations
| |
| l
| |
| Comed Commonwealth Edison Company
| |
| DEV Deviation
| |
| IDNS lilinois Department of Nuclear Safety
| |
| IFl Inspection Follow-up item
| |
| l
| |
| IR inspection Report
| |
| -
| |
| LER Licensee Event Report
| |
| l
| |
| '
| |
| PDR Public Document Room
| |
| RG Regulatory Guide
| |
| UFSAR Updated Final Safety Analysis Report
| |
| l URI Unresolved item
| |
| i VIO Violation
| |
| '
| |
| WR Work Request
| |
| 1
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| 29
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