IR 05000254/1997006
| ML20149K165 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 07/07/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20149K149 | List: |
| References | |
| 50-254-97-06, 50-254-97-6, 50-265-97-06, 50-265-97-6, NUDOCS 9707300027 | |
| Download: ML20149K165 (30) | |
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I U. S. NUCLEAR REGULATORY COMMISSION s
. o REGION ll1 3-
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Docket Nos: .50-254,.50-265'
License Nos: DPR-28, DPR-30 I I
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Report No: 50-254/97006(DR P), 50-265/97006(D RP) -
i Licensee: Commonwealth Edison Company (Comed)
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Facility: Quad Cities Nuclear Power Station, Units 1 and 2 i
Location: 22710 206th Avenue North Cordova, IL 61242 Dates: March 18 - May 5,1997 Inspectors: C. Miller, Senior Resident inspector K, Walton, Resident inspector
- L. Collins, Resident inspector R. Ganser, Illinois Department of Nuclear Safety
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Approved by: Wayne J. Kropp, Chief Reactor Projects Branch 1 t
9707300027 970707 w PDR ADOCK 05000254 G pm
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I EXECUTIVE SUMMARY This inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 7-week period of resident inspection, j l
Ooerations Operators performed complex tasks, such as response to transients, unit startups and unit shutdowns, well. However, several operator performance errors occurred during simple tasks. Previous inspection reports also have discussed operator performance issues (Sections 01.2 and 01.3).
Unit 2 fuel off-load activities were discontinued during the Unit 1 shutdown evolution to reduce the potential for distraction. Overview personnelincluding site quality verification
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(SOV), operations, engineering and station management were present during startups and .
shutdowns (Section 01.2).
Operators appropriately responded to a loss of power on a reactor protection system (RPS) >
bus. Operators restored power to the RPS bus and reestablished shutdown cooling.
(Section 01.4).
Two violations were identified regarding document control. in one violation, operators were using the wrong revision of a procedure which was obtained from a controlled set of procedures. The second violation was issued regarding records where a master retention schedule which lists required quality records and retention periods was'not maintained up-to-date (Section 01.3 and 07.2).
Maintenance e The inspectors observed lapses in worker attention to foreign material exclusion (FME) and
. personnelindustrial safety procedures. Radiation protection department monitoring and control rod drive hydraulic control unit (CRD/HCU) overhaul work indicated the licensee's continued emphasis on "as low as reasonably achievable"(ALARA) radiation dose exposure principles (Section M1.1).
Longstanding problems with standby liquid control (SBLC) flow meters used to verify pump operability led to a failed surveillance, entry into a limiting condition for operation (LCO),
and preparations for a unit shutdown. The adequacy of IST instrumentation is an unresolved item (Section M2.4).
Enaineerina The licensee's decision to expand invesselinspection activities based on information from another nuclear facility, was both warranted and proactive (Section E1.1).
The NRC previously identified that engineering did not adequately trend or analyze room cooler differential pressure for a period of time (see Deviation 50-254,265/96015-01).
The failure to analyze the degraded condition of the Unit 2 "B" core spray room cooler
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resulted in the licensee operating the facility for an extended period 'of time with a potentially inoperable train of core spray (Section E2.1). !
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The licensee identified on three separate occasions, broken auxiliary contact assemblies on 4 kilovolt (kV) breakers which were planned to be installed in the facility. The licensee's initial review of the importance of the issue was narrow in scope. However, subsequent
breaker inspection, evaluation of the condition, and resultant shut down~of Unit 1 were l appropriate (Section E2.3). '
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Plant Sucoort '
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j The first time efforts to decontaminate the Unit 2 torus suction header were partially
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An incomplete understanding of the fire hazards analysis resulted in an untimely I notification to the NRC (Section F4.1). .!
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Report Details Summarv of Plant Status l
Unit 1 started the period with operators decreasing load from full power to about 80 percent of full power operation due to equipment problems. During the period, operators shut down and started up Unit 1 twice due to various equipment problems (see chronology below) .
Unit 2 was shut down for refuel outage O2R14 on February 28,1997, and remained shut down thr' ghout the period.
l. Ooerations 01 Conduct of Operations 01.1 General Colpments (71707)
Using inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations.
During the inspection period, several events occurred which required prompt notification of the NRC pursuant to 10 CFR 50.72. The events and dates are listed below.
March 19 A notification was made due to Unit 1 high pressure coolant injection (HPCI) system being inoperable for about 75 minutes. Workers identified a HPCI component power supply cable as degraded. The !
licensee later determined the cable was not connected.
March 21 A notification was made due to the Unit 2 "B" core spray room cooler being inoperable due to fouling in parallel with the Unit 2 "A" core ' ,
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spray system being inoperable due to emergency diesel generator unavailability.
March 22 Operators shut down Unit 1 reactor due to unanticipated turbine !
equipment problems requiring a longer repair time.
March 27 A notification was made due to nonconformance with a fire hazards design requirement first identified on February 27,1996 (See Section E4.1). I March 29 Operators startup and synchronize Unit 1 to the grid.
March 31 A notification was made due to an inadvertent start of the Unit 1 j emergency diesel generator. "
April 3 A notification was made due to the Unit 1 high pressure coolant injection system being declared inoperable. Subsequent troubleshooting identified the reason for the turning gear motor ;
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April 7- A notification was made due to a failure of a single train safety system. Operators received freon alarms indicating the refrigerant compressor unit of Train B of control room ventilation had a leak.
The leak was later repaired.
April 7 A notification was made due to flow from both Unit 1 standby liquid control pumps being less than the inservice inspection required flow rates. Operations commenced shutdown of Unit 1 until the test could be repeated with properly calibrated gauges.
April 9 Operators notified the NRC that Unit 1 was shutting down due to concerns identified with cracked auxiliary switches in 4 kV breakers.
April 18 A notification was made due to loss of Unit 1 "B" reacter petection systern bus. Unit 1 lost shutdown cooling for several hours due to primary containment isolation system closing the suction valve to the operating residual heat removal pump. Various other system isolations occurred. (See Section 01.4).
May 1 A notification was made due to Unit 1 HPCI being declared inoperable since a code required inspection of a valve was missed.
01.2 Control Room Observations a. Insnection Scone (71707)
Yhe inspectors reviewed the sequence of events recorder, operator logs, and spoke to operators concerning the feedwater heater transient. The inspectors observed two shutdowns and two subsequent startups associated with Unit 1.
b. Observations and Findinas !
On March 19 during Unit 1 power ascension, control room operatois received '
annunciators indicating problems with the moisture separator drain tank (MSDT)
flows to the high pressure feedwater heaters. As required by annunciator response procedures, operators quickly reduced reactor power from about 98 percent to about 80 percent power. To effect feedwater heater repairs, the licensee removed the turbine from service with the reactor critical. However, af ter removing the turbine from service, the operators noted a second electrohydraulic control (EHC)
pump started unexpectedly. This required operators to shut down the reactor on March 22 and perform additional repairs on the EHC system.
Unit 1 was returned to service on March 29. However, on April 5 operators again were required to reduce Unit 1 reactor power due to problems associated with feedwater heater level control valves. Maintenance personnel adjusted a feedwater heater level controller and Unit 1 was returned to full power operation.
On April 9 operations declared 4 kV breakers on safety-supporting electrical busses as inoperable and shut down Unit 1 (See Section E2.3).
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With Unit 1 shut down on April 18, a loss of power to a reactor protection bus resulted in a loss of shutdown cooling. This required operators to reset the reactor protection system and reinitiate shutdown cooling operations (See Section 01.4).
The inspectors noted the control room atmosphere was quiet and controlled during most evolutions. Communications and coordination efforts were conducted smoothly with minimal distractions. A reduction in distractions was aided by the licensee's recently implemented effort to strictly limit control room access, and to a lesser degree, by reducing the number of phone calls to the control room.
The unit supervisors demonstrated good command and control of evolutions, and conducted periodic briefings to ensure all operators received current information concerning unit status. Operator communication with each other and with the unit supervisor was good. Unit 2 fuel off-load activities were discontinued during the Unit 1 shutdown evolution to reduce the potential for distraction. Overview personnel including site quality verification (SOV), operations, engineering, and station management were present during startups and shutdowns.
During one startup evolution, coordination of the nuclear station operators (NSOs)
was not commensurate with previous startups. This was primarily due to recent reassignment of persons in key positions within the operating crew. Overall, crew performance was adequate. All procedures were adhered to, and evolutions were safely conducted. During a startup, the inspectors observed that operators demonstrated professional demeanor in the conduct of unit startup evolutions. In this example, communications, self-checking, and adherence to all procedures and management expectations was excellent.
c. Conclusions Operators continued to be challenged by equipment problems requiring frequen'.
maneuvering of the units. The inspectors noted operators responded appropriately to transients due to the equipment problems. - Unit 1 shutdowns and subsequer't startups were well executed.
01.3 Operations Surveillances a. insnection Scooe (71707)
The inspectors observed operators performing surveillances and using operating procedures during routine control room mocitoring. The inspectors discussed with operators the errors that had occurred during the surveillance tests.
b. Observations and Findinos
- On March 31 prior to performance of a surveillance test, an operator over rotated the Unit 1 EDG control switch. This resulted in an inadvertent start of the EDG. The licensee documented this on Problem Information Form (PlF) 97-1241. The licensee determined methods used by operators to
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- operate a pistol-style grip switch were poor and initiated training for
- operators (See Section 08.2).
e. On April 3 the inspectors observed an operator performing Quad Cities Operating Surveillance Procedure (OCOS) 2300-01, ."High Pressure Coolant injection Periodic Test." The operator did not set the proper pump discharge pressure as required by the surveillance test. An operations supervisor, performing a peer check of the reactor operator setting discharge pressure, concurred that the proper discharge pressure was set. However, before proceeding with the test, a third operator identified and informed both
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operators that the incorrect discharge pressure was established. The proper
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discharge pressure was established and the test proceeded.
Previously, management suggested operating crews implement peer checks
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required. The inspectors spoke to management about this issue. This issue j was not documented on a PIF and the inspectors noted management missed an opportunity to enforce expectations with the individuals involved.
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j e On April 9 the inspectors observed an operator realigning the 250 VDC
- system after performance of a battery discharge test. The operator used a
] copy of Guad Cities Operating Procedure (QOP) 6900-16, " Transfer of Bus a
18 from MCC [ motor control center) 1 to MCC 2," Revision 8, from a
) controlled procedure book. During the procedure, operators in the plant
- performed steps not recognized in the control room copy of the procedure.
The operator identified that the control room copy of.the procedure did not
- have the proper revision. The operator stopped the procedure, reconciled
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differences between the two revisions, and completed the procedure. This
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condition was documented on PlF 97-1540.
l Revision 9 to the procedure returned both 250 VDC buses 18 and 2A to i
their normal source. However, Revision 8 to the procedure only returned 250 VDC Bus 1B to the normal source. Bus 2A powered important safety-
[ related components in Unit 2. However, Unit 2 was shut down at the time of the event and components powered by Bus 2A were not required by j Technical Specifications (TSs).
i The licensee acknowledged the failure of two barriers to prevent the use of incorrect revisions of procedures. The operator did not ensure the proper revision was in hand prior to performing the procedure and the wrong procedure revision was included in the control room controlled procedures book. The failure to maintain the proper revisions of operating procedures in control room controlled procedure books and the failure to ensure the use of the proper revision of the procedure was considered a Violation (50-254:265/97006-01) of 10 CFR Part 50, Appendix B, Criterion VI,
" Document Control."
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q e On April 15 the inspectors observed control room operators during the performance of Quad Cities Operating Surveillance Procedure (OOS)
6500-03 "4 kV Bus 14-1 Undervoltage Functional Test." The surveillance test was required to demonstrate the undervoltage relay operation and load'
shedding upon loss of voltage to Bus 14-1 and to verify that the Unit 1 diesel generator started and loaded in the required time. Bus 14-1 was a q
safety-related 4 kV bus that supplied power to emergency core cooling pumps. j The procedure allowed for the prerequisite steps to be performed in any logical order. Several of the prerequisite steps were performed by control room operators on the night shift. The day shift operators continued the procedure. Step C.1.t stated, Verify "At 901-8 Panel, BUSSES 14-1 and 24-1 TIE ACB is closed." The step was initialed as completed but the ,
breaker remained in the open condition. One of the load shedding functions !
to be tested included the tie breaker between the Unit 1 Bus 14-1 and the Unit 2 Bus 24-1. However, the test required that the tie breaker be closed to verify that it opened properly during the undervoltage test. Immediately after the undervoltage signal was introduced, the control room operator was -
required to verify that; the Unit 1 diesel generator automatically started, Annunciator E3,4 kV Busses 13-1/14-1 low voltage alarmed, and the Bus 14-1 and 24-1 tie breaker tripped. The operator could not verify that the tie j
i breaker had tripped since it was already open. The failure to properly implement the test procedure was a Violation (50 254:265/97006-02) of TS 6.8. A.
Immediately af ter the discovery of the discrepancy, the operators generated j PIF 97-1779 to document the error. The engineering staff wrote interim )
procedure 97-0057 to perform a modified version of the test to verify that the tie breaker tripped on an undervoltage condition on Bus 14-1.
The cause was considered to be a procedural adherence failure.
Management recently emphasized the use of " peer check" for operators to prevent such errors. In this case, peer check could have prevented the error from occurring, but was not used. Another barrier to prevent such errors, 1 the test briefing, failed to identify that the required test configuration did not match the plant configuration.
c. Conclusion During this inspection period, the inspectors were concerned with operator errors, and the effectiveness of the operator peer checks to prevent these errors. The inspectors concluded that these errors were similar to those previously documented in Inspection Report 50-254:265/96020 indicating a continuation of operator performance errors.
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01.4 Loss of 1B Reactor Protection System Bus Causes Loss of Shutdown Coolina (PlF 97-1851)
a. insoection Scooe (93702. 71707)
On April 18, the 182 electrical protection assembly (EPA) for RPS Bus 18 tripped unexpectedly causing a loss of power to the 1B RPS bus. The loss of power resulted in a loss of shutdown cooling and a partial primary containment isolation.
A report was made to the NRC via the emergency notification system (ENS). The inspectors observed the restoration of shutdown cooling and followed up on the root cause investigation and initial operator response to the event. The inspectors reviewed the Unit 1 logbook and spoke with operators to understand the sequence of events, b. Observations and Findinas The loss of power to the RPS Bus 18 occurred at 7:27 a.m. central standard time, when the 182 EPA deenergized unexpectedly. Two EPAs in series are designed to protect the RPS bus from an undervoltage, over voltage, or under frequency condition. The loss of the B RPS bus caused some valves in the primary containment isolation system to close. As a res alt, the reactor water cleanup (RWCU) system, which was controlling reactor watcr level, and the residual heat removal (RHR) system, which was removing decay heat. isolated.
Prior to the event, shutdown cooling was in service and the initial reactor water temperature was recorded as 150 degrees Fahrenheit. Operators responded to the event and entered Quad Cities Operating Abnormal Procedure (QCOA) 1000-2,
" Loss of Shutdown Cooling," and Quad Cities Operating Abnormal Procedure (OOA)
7000-1,"120 VAC Reactor Protection Bus Failure." Per OOA 7000-1, an operator was dispatched to the RPS bus to determine the cause of the bus deenergizing. No obvious reason for the condition was identified. Electricians were called to assist in checking the status of the 1B bus prior to reenergizing per QOP 70001, " Reactor Protection System MG Sets." i9o problems were identified and the 1B RPS bus was reenergized at 8:55 a.m. At 8:58 a.m. operators restored the RWCU system and at 9:17 a.m. RHR shutdown cooling (SDC) was placed in operation. The highest recorded reactor water temperature was 175.5 degrees Fahrenheit, an increase of about 25 degrees Fahrenheit during the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 50 minute period that SDC was off.
Based on discussions with operators, the inspectors found the first 70-80 minutes were used for troubleshooting the 182 EPA and the 1B RPS bus to determine the cause of the EPA trip and that the actual time spent to restore power and return RWCU and SDC to service was approximately 30-40 minutes.
Operators considered a band of 130 to 180 degrees Fahrenheit as an administrative limit for reactor water temperature during normal shutdown cooling operations.
The inspectors did not find any procedures that referenced these administrative temperature limits. A review of Unit 1 plant data and log books showed that
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l operators generally maintained temperature around 150 degrees Fahrenheit, but the temperature fluctuated between 140 and 170 degrees Fahrenheit. The inspecto s j questioned operations management about the wide temperature band and concluded that the_130 to 180 degree temperature band was a widely understood i but informal operating range. At the end of the inspection period, operators were reviewing past practices and procedural guidance for maintaining a temperature band while in shutdown cooling and planned to enhance existing controls.
The failed breaker was last calibrated on April 12,1997, with satisfactory results.
Testing after the failure revealed that the breaker was tripping prematurely and could not be reset. The breaker was replaced. The licensee reviewed five years of
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data on the EPAs and found one spurious trip of the 182 EPA had occurred in 1996. The licensee planned to upgrade the remaining EPAs with new breakers and upgraded circuit boards. The failed breaker was sent off site to the materials engineering group (MEG) for additional failure analysis.
c. C_qn, clusion The inspectors reviewed the initial operator response to the loss of shutdown cooling event and concluded that operators followed the appropriate procedures to restore power to the RPS bus and restore RWCU and RHR SDC. However, the control of the limit for reactor water temperature during normal shutdown cooling operations was not procedural defined and sometimes varied from shift to shift.
07 Quality Assurance in Operations 07.1 Premature Event Screenino Committee Event Closures The inspectors attended an event screening committee (ESC) meeting. The ESC evaluated the quality of corrective actions and disposition of events. The licensee has recently been using the ESC to disposition and close PIFs at an early stage to help reduce the number of open PIFs. The inspectors found that PIF 97-1295 which involved plant oversight review committee (PORC) members not being qualified for their function (specifically, the chairman) was closed with no corrective action taken. The items covered during the PORC were not reboarded because the licensee said that the function of the chairman was not critical enough to invalidate the results in addition, no action to ensure a repeat of the failure to operate with qualified members was called for and no action was initiated to review past meetings for qualified members was initiated. Although PORC is not required at Quad Cities, management has relied upon PORC as tte key organization to review the quality cnd effectiveness of plant decisions. The inspectors concluded that ESC decisions to close the PlF were not based on good corrective actions commensurate with the importance of the function of PORC.
Another PIF (971243) was closed which dealt with a potential degraded condition of fan noise on the shared EDG ventilation fan. The ESC committee closed the PIF with the understanding that the problem occurred once and had not repeated, and that an action request for the fan would be worked in September 1997. The nature
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of the root cause analysis, the effect of the fan's failure on EDG operability, and the
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effect of the operable but potential degraded condition on the Unit 2 startup were not discussed. The inspectors concluded that the decisions made by the ESC about the EDG PlF were not based on the criticalimportance of the shared EDG.
07.2 Quality Records Manaaement a. Insoection Scooe (39701)
The inspectors reviewed the licensee's process for identifying quality records and specifying the required retention period in accordance with 10 CFR Part 50, Appendix B, Criterion XVil and the Site Quality Assurance Manual. The inspectors questioned operations, site quality verification, and office support personnel to determine how completed procedures were documented as quality records.
b. Observations and Findinas The Site Quality Assurance Manual stated that the quality records program included those record types, controls, and provisions for storage and preservation contained in Nuclear Quality Assurance (NOA) -1, Supplement 17S-1 and that records were administered through a system which included an index of record type, retention period, and storage location.
The Quality Assurance Program Requirements for Nuclear Facilities outlined in NOA 1, Supplement 17S-1, covered receipt control of records. This supplement states that as a minimum the receipt control system shallinclude a method for designating the required records. The receipt control section also stated that each receipt control system shall be structured to permit a current and accurate assessment of the status of records during the receiving process.
The inspectors reviewed UFSAR Section 13.7 covering records. The UFSAR stated that control room record retention period was specified on the Commonwealth Edison Record Retention Schedule forms for each record.
The inspectors reviewed the master retention schedule which was the document intended to ipecify retention requirements for various plant procedures. The retention schedule did not specify whether the records were considered to be quality documents. Additionally, the retention schedule was not up to date. The inspectors identified that outdated procedures were listed and that some currently required surveillances were not listed. Also, new required surveillances since the implementation of the upgraded TS in September 1996 had not been added to the master retention schedule to designate the required retention period. The station procedure, Quad Cities Administrative Procedure (OCAP) 1200-1, " Station Records," stated that the responsible department records custodian shall update the master retention schedule when a new record is created. The custodian was responsible for determining if the record was a quality document. The inspectors found that the procedure was recently implemented and that the department
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records custodian was not following the procedure. The operations department records custodian told the inspectors that the custodians did not regularly review new procedures to determine if the procedures created quality records.
The inspectors identified several surveillances and other quality records that were not listed or were listed incorrectly on the master retention schedule including:
OCAP 0230-07, " Operability Determination" OCCP 1200-2, " Post LOCA Hydrogen and Oxygen Monitoring System" OCIS 2400-1, "Drywell Radiation Monitor Calibration and Functional Test" OCOS 1600-4, " Weekly Primary Containment Oxygen Concentration" The licensee told the inspectors that these records were properly retained even though they were not listed on the retention schedule. The licensee was in the process of upgrading the records management program, including the master retention schedule, but no completion date for the project was available. The inspectors concluded that records were not accurately identified as quality records, and that the station was not controlling quality records in accordance with the station procedure, the quality assurance manual and 10 CFR Part 50, Appendix B.
The failure to identify quality records and to establish retention requirements was considered a Violation (50-254:265/97006-03) of 10 CFR Part 50, Appendix B, Criterion XVil, " Quality Assurance Records."
c. Conclusion Over time, the licensee failed to ensure that the master retention schedule was updated to include newly created quality records. The inspectors identified that some TS required surveillances were not listed on the retention schedule and were not designated as quality records. This was considered to be a violation of 10 CFR Part 50 Appendix B, Criterion XVil, " Quality Assurance Records."
08 Miscellaneous Operations issues (92700)
08.1 (Closed) Insoector Follow-uo item (50-254:265/96006-04): Inattentive Test Director. The inspectors observed a test director in the control room in an inattentive state and brought this to the attention of the shift engineer. The licensee conducted an investigation. The individual was disciplined. The inspectors reviewed the investigation results and consider the item closed.
08.2 (Closed) Licensee Event Reoort (LER) (50-254:265/97007): Unit 1 EDG Mar! Due to Personnel Error. A r.oet room operator over-rotated a pistol grip stya EC'G control switch. As a r69 ult, the Unit 1 EDG inadvertently started. The operator was counseled and an operations supervisor provided direction to operators on proper operation of pistol grip switches. The inspectors considered this a violation of adherence to the surveillance procedure OCOS 6600-01, "EDG Monthly Load Test," since the switch was to be moved to the stop position instead of the start
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position. This licensee-identified and corrected violation is being treated as a Non-Cited Violation (50-254:265/97006 04), consistent with Section Vll.8.1 of the NRC Enforcement Policy. This LER is closed.
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08.3 (Closed) Violation 50-254:265/95005-02: Failure to Maintain the RHR Room Watertight Door Closed in Accordance with TSs. As corrective action the licensee developed procedure OCAP O250-06, " Control of In-Plant Watertight Submarine Doors." This procedure provided adequate guidance for control of the watertight doors. Several PlFs have been generated since the violation was written. Problem
Identification Form 95-2542 was written to address a worker leaving a door open !
long enough to retrieve a tool. The worker was unaware that the procedure did not allow this practice. The licensee coached the individual on the correct use of the procedure. Problem Identification Form 961780 was written to address an incident where a door was found latched but not dogged. The licensee did not i determine the person responsible; however, narrowed it down to a specific work i group. As follow-up action, the licensee addressed the issue through tailgate l meetings. The licensee's vigilance and attention to maintaining the integrity of watertight doors has been increased since June 1995 when the initiating violation ;
was identified. This item is closed. l 08.4 (Closed) Licensee Event Reoort 50-265/95007: Unit 2 HPCI Turning Gear Motor Failed to Start as the Turbine Coasted to a Stop. Following this event, the licensee suspected a failure of the turning gear to properly reset. The licensee performed a series of tests on an accelerated schedule; however, they were unable to reproduce
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the failure. One of the accelerated tests resulted in a turning gear engagement failure due to gear abutment; however, the license"3 procedures addressed this condition. There were two turning gear related wcurrences on the Unit 1 HPCI since this LER. The licensee has shown that neither of these was related to the event on the Unit 2 HPCI. This item is closed based on adequate follow-up action by the licensee.
- 11. Maintenance M1 Conduct of Maintenance (62707)
M 1.1 Observation of Maintenance Activities Durina Refuel Outaae 02R14 a. Insoection Scone Maintenance activities observed during this inspection period included: movement of emergency core cooling system (ECCS) suction strainers to the Unit 2 torus, Unit 2 turbine overhaul work, turbine stop valve HO 2-5699-MSV1 actuator rebuild, electrical maintenance department (EMD) switch replacement work on the 2202-20 panel for hydraulic control unit (HCU) banks three and four, CRD HCU overhaul work, snubber testing, preparation for chemical decontamination of the Unit 2 recirculation system, tube lance on the 18 control room heating ventilation and air conditioning (HVAC) heat exchanger, electrical maintenance department (EMD)
inspection of 4 kV breaker auxiliary contact assemblies, penetration sealing and
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i duct repair of the control room emergency ventilation system, and planned -
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inspection and maintenance of the 2B recirculation system motor generator (MG)~
i set slip rings and commutator.
b. Observations and Findinos
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- When workers attempted to lower the first of the new type ECCS suction
. strainers through the floor opening into the Unit 2 torus, there was i insufficient clearance due to interference from a section of structural steel.
Lack of adequate planning and pre-measurement caused some lost time and j unnecessary radiation exposure during this first attempt. All other aspects
- of this effort observed by the inspectors were satisfactory.
'e The inspectors observed contract workers perform overhaul work on a j Unit 2 turbine stop valve actuator HO 2-5699-MSV1, in accordance with j. work package WR 960076977. Work procedures were conducted j adequately, with the exception that foreign material exclusion (FME) controls i' were somewhat lax. The inspectors observed that there were items in a zone 2-work area that were not logged in on the FME log sheet, specifically
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some tape and gloves. The inspectors brought this to the attention of the workers, who did not appear to have a clear understanding of the FME i requirements. The workers removed the non-controlled items from the FME 5 zone. The workers discussed the procedures with the immediate supervisor i' to understand the FME requirements. The work package was current and workers adequately documented the work steps when completed.
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- e Overhaul work on CRD/HCUs was well coordinated. Radiation protection
! personnel were assigned full time to this job to coordinate work movement and to assure radiation exposure to workers was maintained ALARA. The
- total radiation exposure for the entire effort was approximately 55 percent of the amount allotted. This dose savings was due to job planning and worker diligence in minimizing dose, and by workers consistently remaining in the lowest possible dose areas throughout the entire job.
e The inspectors observed three scaffolding workers standing on high scaffold elevations in the Unit 1 turbine building who were wearing fall protection harnesses but were not hooked up to an anchor point. The inspectors questioned the acting foreman about the safety requirement for fall protection. The foreman reminded the workers of the safety requirement.
Later in the shift the tr.spectors verified that all of the workers were correctly adhering to the safety procedure. The inspectors discussed these observations with site safety engineers the following day.
- The inspectors observed EMD workers following a procedure in preparation for chemical decontamination of the Unit 2 reactor recirculation system. The project manager for the decontamination crew accompanied the EMD
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I workers and was closely involved in the activity. The inspectors observed that the projact manager and the workers observed good self-checking and second party verification (peer checking) techniques.
c. Conclusions in general, plant workers were attentive to radiation and personnel safety requirements, with only minor exceptions. Workers used approved procedures to perform work and contributed constructive suggestions to help minimize radiation l
exposure. Work areas were kept orderly and free of clutter. Job coordination in
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. busy work areas was good.
l l M2 Condition of Facilities and Equipment l
M2.1 Miscellaneous Material Condition issues (71707)
l The inspectors noted continued equipment problems affected reactor operations, and resulted in two forced shutdowns for Unit 1 during the period. Listed below are material condition issues that affected Unit 1 operations:
Breakers installed in safety-related electrical switchgear were identified as having
- auxiliary contact switches prone to cracking. This resulted in operations declaring the breakers inoperable and required shutdown of Unit 1 (See Section E2.3).
Repairs were made to an inoperable intermediate range monitor (IRM) -15. During startup of Unit 1, IRM-15 acted erratically. Operators declared the IRM inoperable again. The licensee subsequently replaced the IRM detector and declared IRM 15 operable. IRM-15 operated properly during subsequent startup of Unit 1.
During the shutdown of Unit 1, a valve on a hydraulic control unit exhibited leakage from a body to bonnet joint. The valve was cut out and replaced. A laboratory later determined the valve was missing a body to bonnet gasket due to maintenance performed a year previously.
Refuel bridge locked up twice due to problems with an electrical cable. The licensee later identified the cable was improperly manufactured. The cable was replaced and Unit 2 reactor defueling continued.
The normal drain valves from the moisture separator drain tanks to the high pressure feedwater heaters on Unit 1 were degraded and resulted in a plant i transient. The licensee shut down Unit 1 to effect repairs to the system. The licensee historically has had problems operating the feedwater heating system. The licensee's investigation identified the valves were undersized by industry standards, air leaks existed on valve actuators, and the system had been prone to fouling by l material from inside the system. Engineering determined the system was not l- periodically tested, there were no existing preventive maintenance items for the 3 system, and existing predictive maintenance activities were not adequate to trend l
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valvo performance. The licensee identified these issues and others, and panned to l implement corrective actions. l During the shutdown of Unit 1, operators noted increased flow through the turbine electrohydraulic control system. Engineers noted excessive seat leakage through spool valves in both intercept and stop valves manifolds. Spool valves in ten l actuators were replaced.
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c. Conclusion in each of the above cases, the inspectors reviewed the licensee's investigations (when performed) and corrective actions. The inspectors noted initial work on the IRM did not correct the condition. The inspectors noted work performed on the HCU introduced a problem which was not identified during post maintenance testing. The inspectors deemed the licensee's corrective actions appropriate to the circumstances.
M2.3 250 Volts Direct Current Batterv Testina a. Insnection Scone The inspectors observed portions of the Unit 2 modified performance test for the 250 volts direct current (VDC) safety-related battery (Quad Cities Technical Staff Procedure [OCTS] 0240-06). The inspectors reviewed the load duty cycle of the battery, the TS requirements for testing, and the UFSAR.
b. Q_bservations and Findinos (61726)
The modified performance discharge test was allowed by TS 4.9.C.5 to satisfy both the service test and the performance test. The modified performance discharge test was perforrned once every 60 months and was used to verify the battery's ability to meet the critical period of the load duty cycle and to measure the battery's capacity. The UFSAR (Section 8.3.2.1) stated that the battery was sized to start and carry the normal direct current (DC) loads required for safe shutdown on one unit, and the operational loads required to limit the consequences of a design basis event on the other unit, for a period of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> following loss of all alternating current (AC) sources. The 250 VDC battery systems are cross-tied such that each unit's battery feeds the high pressure coolant injection system (HPCI) system for that unit and the reactor core isolation cooling system (RCIC)
system on the opposite unit in addition to several other DC loads.
The licensee had recently updated the electricalload profile and determined that the most severe transient on the 250 VDC battery had changed from an intermediate loss of coolant accident to a steam line break outside of containment. The inspectors observed portions of the test and verified that the load applied to the battery conformed to the licensee's documented load profile for the steam line break scenario. The inspectors reviewed the completed procedure and verified that
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the calculated battery capacity of 100.7 percent was greater than the minimum acceptable battery capacity and that the TS requirement was satisfied.
t. The inspectors reviewed in detail the electricalload profile for the steam line break
) scenario and asked the system engineer to clarify several of the assumptions made l
- . in the calculation. The load profile based on Unit 1 assumed that Unit 1 HPCI and l j Unit 2 RCIC were in the test configuration when the steam line break and loss of offsite power occurred. The inspectors questioned why this configuration was more limiting than the HPCI system starting at the initiation of the accident since
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the operation of the injection valve, the auxiliary oil pump, and the steam supply
- - valve were significant loads on the battery. The inspectors also questioned the 1 system engineer if the HPCI suction path transfer from the contaminated l
condensate storage tank (CCST) to the suppression pool and any cycling of HPCI ,
. on and off was considered in the load profile. Additionally, the inspectors asked 1
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the system engineer to identify which Unit 2 safe shutdown loads were included in the load profile. This issue is an Inspector Follow up item (50-254:265/97006-05).
i c. Conclusions The modified performance discharge test for the 250 VDC battery was performed j successfully and appeared to meet TS requirements. The inspectors had some
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follow-up questions concerning assumptions made in identifying the limiting electricalload profile for the 250 VDC battery system.
M2.4 Standby Liauid Control System Testina i
a. Inspection Scooe(93702. 61726)
I f The inspectors observed portions of OCTS 0340-01, " Standby Liqu'd Control j. System Outage Surveillance" performed on Unit 2. The inspectors attended a pre-job briefing and observed operators in the field. The inspectors also followed up on an NRC ENS notification on April 7,1997, when the SBLC system on Unit 1 was i ' declared inoperable due to low system flow during quarterly surveillance testing.
I b. Observations and Findinas
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l- The outage surveillance tested portions of the SBLC system that could not be j routinely tested during reactor operations. The inspectors attended the pre-job
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briefing and noted good communication among operators. One equipment operator i specifically asked for an additional operator to assist in " peer check." The inspectors observed the portion of the test designed to verify the pump suction lines from the storage tank were not plugged. The test results were satisfactory.
i The. inspectors reviewed the test requirements against the TSs and noted that the
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test was designed to satisfy surveillance requirements for SBLC system specified in ,
i TS 4.4.A.4 and for isolation actuation specified in TS 4.2.A. The initiation of SBLC ;
j causes the isolation of the RWCU. The inspectors verified that the procedure i tested the isolation function. However, this portion of the test was not identified under the performance acceptance criteria section or under the discussion section
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which listed the TS requirements which were satisfied by the procedure. The licensee recently performed an audit of TS surveillance requirements and had also noticed the deficiency and planned to fix the procedure.
On April 7,1997, operators declared Unit 1 SBLC system inoperable when the j measured flow for each of the pumps was in the required action range of the i inservice test (IST) program criteria. The TS flow requirement of 40 gpm was l satisfied. The IST program baseline for the Unit 1 pumps was established at '
44 gpm with the required action range either greater than 48.4 gpm or less than 40.9 gpm. The measured flow for each pump during the surveillance was 40 gpm.
Once the pumps were declared inoperable, operators entered the action statement i for TS 3.4.A.1 which required at least one pump be restored in 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or the unit i to bo in hot shutdown in the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
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The licensee immediately suspected the flow meter which was in-line to the test
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tank since there were past problems associated with the meter. Under work request 970040020-01, instrument maintenance mechanics adjusted the zero reference for the flow meter. The flow test for the pumps was then successfully performed. The inspectors reviewed the calibration history for the flowmeters and found that the meters were sent offsite for calibration once a year. The inspectors reviewed the calibration data and found that the flow meter was often found to be out of tolerance during the as-found testing. The system engineer was aware of -
the problems with this particular type of flow meter and had identified a new style flowmeter to use. However, the modification packago initiated in 1995 had not yet been approved. The inspectors found that the margin between the established baseline flow rate of the pump and the IST and TS limits was small which increased the importance of accurate flow rate measurements. Additionally IST limits were calculated down to the tenth of a gpm (e.g.,40.9) and the installed gauge was in increments of 2 gpm. The inspectors reviewed several completed surveillances and found the operators were recording the flow in whole numbers and not attempting to read the gauge to meet the IST criteria. In this event, longstanding problems with the flow meter caused entry into an LCO and required operators to begin a reactor shutdown.
The vendor manual for the meter stated that a check and adjustment of the indicator should be performed at an interval established by the customer and that indicator response should be checked every six months. The inspectors asked instrument maintenance staff if these checks were performed and found that adjustment of the indicator was performed during the annualinstallation of the flow meter and that indicator response was checked during performance of the flow test.
c. Conclusion Longstanding problems with the SBLC flowmeters used to verify SBLC pump operability led to a failed surveillance, entry into a limiting condition for operation, and preparations for a unit shutdown. The installed gauge did not allow the operator to read the flow measurement with the precision required by the IST
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limits. Accurate flow measurement was particularly important in the SBLC system since little margin existed between the required flow and reference flow of the pumps. This issue is an unresolved item pendinp NRC review of IST instrumentation requirements. (URI 50 256:264/97006-06)
, Ill. Enaineerino
~El Conduct of Engineering i E1.1 Exoansion of Invessel Insoection Activities
, Based on information received from another nuclear station, the licensee decided to
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expand the scope of interior reactor vessel weld inspections to include core shroud vertical welds. The vertical weld inspections added about three days to the outage !
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schedule. The licensee performed both visual and ultrasonic inspections of four of 4 the six welds. (The other two welds were considered inaccessible.) These inspections did not identify any rejectable indications on the welds. The inspectors considered the addition of this inspection activity to be both warranted and
proactive.
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E2 ' Engineering Support of Facility and Equipment i
E2.1 Inocerable Core Sorav Room Cooler Due to Foulina
- a. Insoection Scooe (71707. 37551)
The inspectors spoke to system engineering, reviewed room cooler trend charts,
, and reviewed the licensees response to Deviation 50-254:265/96015-01. The inspectors reviewed Section 3.11.4, 6.3.2.1, and 9.5.5 of the UFSAR and an NRR safety evaluation related to comer rcom cooler heat removal capability.
s b. Observations and Findinas
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On March 21,1997, with Unit 2 in a refueling outage, the licensee opened and inspected the "B" core spray room cooler. The licensee found 10 of 18 tubes that were completely plugged with erosion and corrosion products. Six additional tubes were significantly plugged. Operations declared the room cooler incperable.
System engineering reviewed room cooler monthly differential p. essure
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measurements, and concluded the condition existed since abotit June of 1996. In addition, the shared emergency diesal annerator was inoperable a total of about
] nine days resulting in the "A" core spray pump room cooler not having an
emergency source of elec%ical power.
4 The licensee attributed the blockage of the room cooler to a previous attempt to hydrolaze upstream service water piping during the refuel outage in Spring of 1995.
This resulted in loosening debris, and later, required disassembly of the room cooler to remove erosion and corrosion products. The room cooler was placed back in service.
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In October 1996,in NRC Inspection Report 50-254;265/96015, the inspectors identified that the licensee had not implemented a 1992 LER commitment te trend and analyze residual heat removal room cooler differential pressure. Data recorded by QCOS 5750-09, "ECCS Room and DGCWP [diesei generator cooling water pump] Cubicle Cooler Monthly Surveillance Test," was not evaluated by the cognizant system engineer. In 1994, the licensee had removed the acceptance criteria for the cooler flow surveillance from the procedure, relying on engineering to trend and analyze the data. In response to the deviation, the licensee evaluated ECCS room cooler d/p in October 1996. At that time, system engineering identified 2 "B" core spray room cooler had exceeded the maximum criteria .in June 1996.
The room cooler d/p periodically exceeded the maximum criteria and showed an increasing d/p trend during the operating cycle. System engineering noted this condition and commented the cooler would be cleaned during the upcoming outage.
This condition was not documented on a PlF and the condition was not evaluated for operability. In addition, there were no attempts to clean and inspect the room cooler during plant operation.
The licensee attributed this event to inadequate flushing of the 2 "B" core spray room cooler after hydotazing, and a personnel error by the system engineer for not trending and analyzing the room cooler performance. Engineering could not determine the heat removal capebilities of the degraded "B" core spray room cooler.
The inspectors noted the shared EDG was inoperable with both units at power from October 21 to October 27,1996, and from January 15 to January 18,1997. The shared EDG provided emergency power to Unit 2 "A" core spray equipment. The emergency source of power to the Unit 2 "A" core spray room cooler was unavailable and the Unit 2 "B" core spray room cooler was inoperable since June 1996. The inspectors consider this to have been potentiaHy significant as ,
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TS 3.5.A.1 required both core spray systems to be operable with Unit 2 in operation.
During the outage, the licensee also opened and inspected all the other ECCS roorn coolers except the 2 "B" RHR room cooler. (The 2 "B" RHR room cooler was planned to be inspected later in the outage.) Flow through the Unit 2 HPCI room cooler was previously determined to be degraded but not inoperable. The licensee found pieces of zebra mussel shells plugging scme of the room cooler tubes. In all cases, the room coolers were cleaned prior to beng returned to service.
c. Conclusions The NRC previously identified that engineering did not adequately trend or analyze room cooler differential pressure for a period of time (see Deviation 50-254:265/96015-01). The system engineer had an opportunity to document, and evaluate the degraded condition upon responding to the deviation in October 1996. Missed opportunities to identify, document and analyze the degraded condition of the core spray room cooler resulted in the licensee operating a train of core spray for an extended period of time with a cooler in a degraded
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condition without evaluating its effect on operations. Failure to take timely corrective action for a condition adverse to quality was a violation of 10 CFR, Appendix B, Criterion XVI " Corrective Action" (VIO 50 254:265/96006-07).
E2.2 Facility Adherence to the UFSAR While performing the inspections discussed in this report, the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected. The inspectors reviewed plant practices, procedures and/or parameters to that described in the UFSAR and documented the findings in this inspection report. The inspectors reviewed the following sections of the UFSAR:
IR Section UFSAR Section Aoolicability 07.2 13.7 Reccrds M2.3 8. 3. 2.1 250 VDC System E2.1 3.11.4, 6.3.2.1, 9.5.5 CS room cooler For the sections reviewed, no issues with plant configuration or UFSAR accuracy were identified.
E2.3 Unit 1 Shut Down Due to Dearaded Auxiliary Switches in 4 Kilovolt (kV) Breakers a. Insoection Scone (71707,37551)
The inspectors observed licensee inspection of 4 kV breakers and attended engineering action meetings and plant operations review committee meetings to evaluate the degraded condition of the breakers. The inspectors monitored operators during the Unit 1 shutdown.
b. Observations and Findinas On February 11,1997, during breaker testing observed by a Quad Cities engineer at the manufacturer, an auxiliary contact assembly (ACA) on a 4 kV breaker was found broken. The manufacturer replaced the ACA. On March 5, the licensee identified a similarly broken ACA on another spare 4 kV breaker. The condition was documented on PlF 97-0822. On April 1,1997, the licensee identified a third broken phenolic auxiliary contact assembly (ACA) mounted on a 4 kV breaker prior to installation in a safety-related bus (PlF 97-1276). The failure resulted in the ACA physically separating from the support mount. The ACA provided ci itacts for both local and remote, indication and operation of the breaker. The licensee .nspected similar spare breakers and identified 12 of 14 breakers with similarly cracked, but not broken, ACA. The licensee removed and replaced two residual heat removal service water pump (RHRSWP) breakers in Unit 1 due to finding cracked ACAs. All of the inservice electrical breakers' ACAs were identified as being intact.
The licensee used Merlin-Gerin breakers in safety-related applications. These breakers supplied normal power to safety-related busses and power to the RHRSWPs. Engineering concluded that the breakers installed could not be deemed
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operable based on conditions identified on both installed and spare breakers. The licensee had not experienced any failures to operate with the installed breakers.
The breakers could be operated locally. However, the licensee declared the RHRSWP breakers inoperable and commenced shut down of Unit 1 on April 9, 1997, as required by TSs. (Unit 2 was already in a refuel outage when the deficient condition was identified.)
l The licensee tested and implemented a interim repair to the cracked ACAs. The tests were observed by the inspectors and NRR personnel (see below paragraph).
After the repairs to the ACAs, the affected breakers were considered operable for a limited number of cycles. The licensee planned to implement random weekly surveillances to ensure the breaker modification was monitored. The licensee considered the modification to the breaker as a potential long term repair and planned to continue testing the modification at an offsite laboratory. The licensee's long term corrective actions will be tracked by LER 254/97-011.
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c. Conclusions The inspectors noted the licensee had prior opportunities to identify the degraded
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ACAs condition and effect repairs prior to April 1. Similarly, the inspectors noted the PlF 97-0822 was marked by the events screening committee as not being a potential Part 21 notification. The inspectors considered the licensee's initial evaluation of PlF 97-0822 to be narrow in scope. Subsequent engineering evaluation of the ACAs condition resulted in the licensee viewing the condition on a wider perspective, including Part 21 aspects. The licensee subsequently decided to declare the breakers inoperable and shut down Unit 1 due to the unknown status of the electrical breaker ACAs. The additional surveillances to rnonitor the condition of the ACAs in the affected breakers was deemed by the inspectors to be an acceptable interim measure untillong term testing of the repair was completed.
E2.4 Modification to Auxiliarv Switch in Merlin-Gerin (M-G) Circuit Breakers a. Scope On April 14,1997, inspectors from NRC headquarters Office of Nuclear Reactor Regulation (NRR) met with the licensee's staff at the System Materials Analysis Department (SMAD) and reviewed the actions taken by the licensee to determine the root cause of the cracking of auxiliary switches installed in 4.16 kilovolt (kV),
M G circuit breakers at Dresden and Quad Cities. The inspectors also examined some of the failed breakers from Quad Cities and reviewed the licensee's proposed interim corrective action and development of permanent corrective action in consultation with the breaker supplier and the manufacturer. On April 15,1997, the inspectors observed testing of one of the failed M-G breakers at Dresden 2.
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b. Observations and Firdinas Root Cause Evaluation To investigate the cause of the cracks on the switches, SMAD assembled engineers from Dresden and Quad Cities, representatives from M-G, Square D Company (M-G's U.S. distributor), and Pacific Breaker Systems (the current supplier) and modifier of the M-G breakers for General Electric (GE) (Magne-Blast switchgear). SMAD evaluated numerous possible contributing factors and showed the inspectors the high-speed videos which captured the motion of the switches during the opening and closing of the breaker.
SMAD identified two potentially significant factors that distinguished the M-G l breakers at Dresden and Quad Cities from those at other U.S. installations and abroad: The type of switch wiring connections and the spring discharge feature.
To meet a licensee wiring requirement, the wires to the breaker auxiliary switches for Quad Cities and Dresden were connected using ring-tongue terminals . screwed onto the switch terrninals; whereas, all other installations used spado connectors.
In addition, the inspectors pointed out that connecting the wires after the switches were mounted could subject the switch mounting slots to extra stress during the tightening of the terminal screws.
The spring discharge safety feature in the Dresden and Quad Cities breakers, specified by ANSI /IEEE Std C37.04 for U.S. nuclear plants, was unique among all other installations of the affected type of M-G breakers because those facilities are the only U.S. nuclear plants with M-G breakers. The spring discharge feature, actuated by a mechanical rackout interlock for personnel safety, subjects the breaker to a complete closing and opening cycle in rapid succession every time the i breaker is racked out. This feature, with its associated significant increased stress on the switches (vibration and shock loading), was being considered as a possible contributing factor to the cracking of the auxiliary switches.
The upper auxiliary switch shaft is the fulcrum for the operating levers which operate the upper auxiliary switch, the bottom auxiliary switch and the open/close indicating flag. If the tabs of the mounting slots (which are molded into the phenolic switch body segments) crack and break off, the mounting T-bolts can come out of the slots and the switch will break away from its mounting bracket.
However, the switch remained attached to the operating levers by its shaf t and thus will hang down, typically about 1/4 inch below the mounting bracket. Thus far, cracks have been found only on the upper switch.
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l Failure Effects l Specifically, if the auxiliary switch broke loose as the breaker closed, the breaker may not have opened electrically (automatic trips, or local or remote hand switches) l unless the upper auxiliary switch changed state. If the auxiliary switch broke loose '
as the breaker opened, the breaker may not have closed electrically unless the switch changed state.
Prooosed interim Corrective Action The licensee's proposed interim corrective action was to replace all upper auxiliary switches that are broken or have visible pieces missing (but not ones that only have visible cracks) and then secure all the switches with nylon cable tie (ty-wrap), with Tygon tubing as chafing gear, as a backup to their regular mounting system. To test this proposed fix, the licensee cycled a breaker 225 times with the ty-wrap installed, the rear mounting slot tabs completely broken off and with the nuts i removed from the T-bolts that normally attach the switch to its mounting bracket. '
No failures occurred during this testing. This interim fix was also being seismically tested at Wyle Laboratories.
Testina of the Bus 23 Feeder Breaker at Dresden.
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On April 15,1997, the inspectors observed the Dresden 2 operating tests of its l Bus 23 M-G feeder breaker (from Bus 23-1). The intent was to demonstrate the prior operability of this closed breaker, whose local mechanical position indicator flag was stuck in an intermediate, nearly open position. Control room personnel opened and closed the breaker successfully several times accompanied by proper operation of the local and remote indicating lights. However, when the breaker was l opened, the position indicating flag on the breaker would go almost fully closed and l when the breaker was closed, the flag would return to its intermediate, mostly-open l position. When the technicians removed the front cover of the breaker mechanism i enclosure, the inspectors observed that the auxiliary switch was detached from its l mounting bracket and was hanging down about 1/2 inch.
c. Conclusions The inspectors concluded that the root cause investigation was proceeding satisfactorily although not completed. The licensee appeared to be effectively utilizing its contractors and the contractors were providing adequate support.
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IV Plant Support 1 R1 Radiological Protection and Chemistry Controls R 1.1 Torus Suction Header Decon1mination Efforts ,
a. Insoection Scoce (71707) l The inspectors spoka with Radiological Protection and Chemistry Controls (RPC)
staff and reviewed the results of the torus suction header decontamination efforts.
b. Observations and Findinas l The radiation levels in the torus suction header had historically resulted in the reactor building basement being treated as a high radiation area. During the recent Unit 2 refuel outage, the licensee removed the emergency core cooling system (ECCS) suction strainers and used a robot to clean the torus suction header. This effort had previously not been used and was considered experimental.
Consequently, equipment problems and schedule slippage resulted in cleaning only eleven of the sixteen bays. For the areas cleaned, post decontamination surveys showed doses decreased by up to 50 percent and some areas showed an increase in dose of up to 20 percent due to redeposition of fine particles.
The licensee intended to incorporate lessons learned from this effort to ensure the entira torus suction header would be decontaminated during the upcoming Unit 1 refuel octage. ,
c. Conclusio 13.
The inspectors concluded the torus decontamination efforts were good. However, first time use of equipment resulted in the torus suction ring header decontamination efforts not being fully completed.
F4 Fire Protection Staff Knowledge and Performance F4.1 Delinauent Reoortina of Event On March 27,1997, the licensee identified a previously corrected condition that l
was not reported in accordance with 10 CFR 50.72 requirements. The licensee's fire hazards analysis report required protection of low pressure piping frem high pressure systems. The licensee identified that during a postulated fire, no procedures were in place to ensure low pressure portions of the reactor water cleanup piping would be protected from the high pressure recirculation system.
This condition was documented on PlF 97-1132 and LER 50-254/97008. The licensee attributed this event to an incomplete understanding of the licensee's safe shutdown analysis. The licensee revised a procedure to correct the condition by May 28,1996, but did not report the condition until March 27,1997.
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l The licensee did not report the condition as being outside the design basis until ten months later. Failure to report the condition is considered a violation of 10 CFR 50.73. However, this licensee-identified and corrected condition was Non-Cited Violation (50-254:265/97006-08), consistent with Section Vll.B.1 of the j. Enforcement Policy.
V. Manaaement Meetinas
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X1 Exit Meeting Summary
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The inspectors presented the inspection results to members of licensee management at the
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1 conclusion of the inspection on May 2,1997. The licensee acknowledged the findings presented.
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The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information was identified, r
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... o PARTIAL LIST OF PERSONS CONTACTED i
Licensee l B. Pearce, Station Manager D. Cook, Operations Manager F. Famulari, Site Quality Verification Director J. Hutchinson, Site Engineering Manager J. Kudalis, Support Services Director J. Purkis, Work Control Supervisor B. Svaleson, Radiation Chemistry Superintendent M. Wayland, Maintenance Superintendent INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 39701: Records Program IP 61726: Surveillance Observations IP 62706: Maintenance Rule Inspection Procedure IP 62707: Conduct of Maintenance IP 71707: Plant Operations IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 93702: Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED, CLOSED, AND DISCUSSED Ooened 50-254;265/97006-01 VIO failure to maintain the proper revisions of operating procedures 50-254:265/97006-02 VIO failure to properly implement test procedure 50-254:265-97006-03 VIO failure to identify quality records and to establish retention requirements 50-254;265/97006-04 NCV Unit 1 EDG start due to personnel error 50-254:265/97006-05 IFl 250 volts direct current battery testing 50-254:265/97006-06 URI IST instrumentation requirements 50-254;265/97006-07 VIO Core spray room cooler clogged and degraded 50-254:265/97006-08 NCV delinquent reporting of event
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.50 254:265/95005-02 VIO failure to maintain the RHR room watertight door closed in accordance with TSs
- 50-254:265/96006-04 ~ lFl - inattentive test director 50 254:265/97006-04 NCV Unit 1 EDG start due to personnel error 50-254i265/97006-08 NCV delinquent reporting of event 50-265/95007 LER Unit 2 HPCI turning gear motor failed to start as the turbine coasted to a stop-50-254:265/97007 LER . Unit 1 EDG start due to personnel error Discussed '
50 254:265/97002-07 URI Maintenance Rule issues
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LIST OF ACRONYMS AND INITIALISMS USED
i AC Alternate Current ACA ' Auxiliary Contact Assembly ALARA As Low As Reasonably Achievable i ANSI American National Standards institute !
ASME American Society of Mechanical Engineers l CAM Containment .^tmosphere Monitor l CCST- Contaminated Condensate Storage Tank CFR Code of Federal hegulations CRD Control Rod Drive I d/p differential pressure DC Direct Current DGCWP Diesel Generator Cooling Water Pump ECCS Emergency Core Cooling System EDG Emergency Diesel Generator EHC Electrohydraulic Control EMD Electrical Maintenance Department l ENS Emergency Notification System EPA Electrical Protection Assembly ,
ESC Event Screening Committee !
FME Foreign Material Exclusion GE General Electric GL Generic Letter HCU Hydraulic Control Unit HPCI High Pressure Coolant Injection System HVAC Heating Ventilation and Air Conditioning (DNS tilinois Department of Nuclear Safety IFl Inspector Follow-up Item IRM Intermediate Range Monitor IST inservice Test kV Kilovolt LCO Limiting Condition for Operation LER Lice ~nsee Event Report LOCA Loss-of-Coolant Accident MCC Motor Control Center MEG Materials Engineering Group MG Motor Generator MPFF Maintenance Preventable Function Failure MRFF Maintenance Rule Functional Failure MSDT Moisture Separator Drain Tank NCV Non-Cited Violation NOA Nuclear Quality Assurance NSO Nuclear Station Operator PDR Public Document Room PIF Problem Identification Form PORC Plant Oversight Review Committee
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. 1 QCAP- Quad Cities Administrative Procedure OCCP <
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Quad Cities Chemistry Procedure
' QCIS - Quad Cities Instrument Surveillance ;
OCOA Quad Cities Operating Abnormal Procedure l
QCOS Quad _ Cities Operating Surveillance Procedure l
QCTS- Quad Cities Technical Staff Procedure '
OOA . Quad Cities Operating Abnormal Procedure OOP Quad Cities Operating Procedure -
QOS- Quad Cities Operating Surveillance Procedure
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RCIC Reactor Core Isolation Cooling System RG' Regulatory Guide RHR Residual Heat Removal RHRSWP Residual Heat Removal Service Water Pump
- RPC Radiological Protection and Chemistry Controls RPS- Reactor Protection System RWCU Reactor Water Cleanup
.SBLC Standby Liquid Control SDC Shutdown Cooling
, SIL . Service Information Letter j
. SQV Site Quality Verification l
TS- Technical Specification -l UFSAR Updated Final Safety Analysis !
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Volts Direct Current l VIO Violation 30