IR 05000483/1997014
| ML20198F585 | |
| Person / Time | |
|---|---|
| Site: | Callaway  |
| Issue date: | 08/06/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20198F577 | List: |
| References | |
| 50-483-97-14, NUDOCS 9708130083 | |
| Download: ML20198F585 (22) | |
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CRCLQBMRE U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket No.:
50 483 License No.:
NPF 30 Report No.:
50 483/97 14 Lict.nsee:
Union Electric Company Facility:
Callaway Plant Location:
Junction Highway CC and Highway O Fulton, Missouri Dates:
June 22 through August 2,1997 Inspectors:
D. G. Passchl, Senlo Resident Inspector D. N. Graves, Senior Project Engineer, Project Brancn B W. M. McNeill, Reactor inspector Approved By:
W. D. Johnson, Chief, Project Dranch G ATTACHMENT: Supplemental Inf ormation e
9708130083 970006
PDR ADOCK 05000403
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I EXECUTIVE SUMM_A.AY Lullaway Plant NRC Inspection Report 50-483/97 14
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Operation 3 Management's direction to reduce load to 95 percent reactor power to gain
additional margin to the lirnits for the heat flux hot channel f actor F(q) and axial offset was conservative and timely (Section 01.2).
Operators responded well to an Unusual Event involving failures in the plant
annunciator system. Operators remained focused on plant parameters. Operators carried out compensatory actions until the annunciator system was fully restored.
Management and technical support were very good (Section 01.3).
There were weaknesses in plant procedures regarding the criteria for declaring the
Unusual Event, which led to about a 6-hour delay in declaring the Unusual Event.
There was confusion on what constituted minimum acceptable field power supply voltage and what constituted a failure of "most or all annunciators" (Section 01.3).
Maintenangs Material condition and housekeeping of accessible areas of the auxiliary building,
the fuel building, the essential service water pumphouse, and most areas of the turbine building were very good (Section M2.1).
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A noncited violation was identified durlog Licensee Event Report 96 008 chseout
review. Plant electricians performed a weekly battery surveillance on the wcong train of batteries. This resulted in Train B of the station batteries being without a
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current surveillance for approximately 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> (Section M8.2).
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A noncited violation was identified during Licensee Event Report 97004 closeout
review. Tbh involvec missed surveillances on feedwater isolation and turbine trip i
slave relays (Section MO.41. The licensee had, on several occasions, performed the surveillances at power instead of "during refueling."
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An axist. offset anomaly has t.ausad shutdown margin to reduce at a faster rate than
predicted. Th I;censee wasin compliance with the Technical Specifications and was aggressively mof6torin(l the shutdown margin and other plant parameters to ensure the plant rcUtened within operating limits (Section E1.1).
A noncited violatam was identified during Unresolved item 97-007-05 closeout
review. The insper. tors identifled a discrepancy between the Final Safety Analysis Report and the actual responn time of control room ventilation isolation system radiation monitors. The licensee did not perform a 10 CFR 50.59 evaluation to ensure that an unreviewed safety question did not exist (Section E8.11
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flenort Details Summarv of Plant Status The plant began the inspection repost period near full power operation.
On July 10,1997, operators began a gradualload reduction to 95 percent reactor power.
The licensee was operating close to the limits for axlat flux difference and the heat flux hot channel factor F(q). The licensee reduced power to gain additional margin to these limits.
On July 19,-1997, an Unusual Event occurred as a result of a failure of the plant annunciator system.; The licensee properly responded and restored the annunciator system to operable status the following day.
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The plant ended the inspection report period at 95 percent power.
l. Operations
Conduct of Operations 01.1.Qeneral Comments (71707)
The inspectors conducted frequent reviews of ongoing plant operations, in general, the conduct of operations was professional and safety-conscious. Plant status, operating problems, and work plans were appropriately addressed during daily turnover and plan of the day meetings. Plant testing and maintenance requiring control room coordination were properly controlled. The inspectors observed several shift turnovers and noted no problems.
01.2 Gradual Power Reduction a.
Inspection Scoos (71707)
The inspectors reviewed the licensee's actions for the gradual power reduction.
The inspectors' review of the licensee's compliance with requirements associated with the heat flux hot channel f actor F(q), axial offset, and shutdown margin is addressed in Section E1.1.
b.
Observations and Findinas On July 10,1997, the licensee began a gradual load reduction to 95 percent power.
There were no plant parameters, test results, or reactivity measurements that required the load reduction. The licensee was experiencing an axial offset anomaly and had been operating close to operating limits for the heat flux hot channel factor F(q) and axial offset. Power was reduced to gain additional margin for these parameters. The licensee accomplished the load reduction at approximately one half percent per day.-
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2-The inspectors had no concerns with operator performance during the power reduction. The inspectors found that management's direction to reduce load to gain additional margin to the heat flux hot channel f actor F(q) and axial offset was conservative and timely.
01.3 Unusual Event for Failure in Plant Annunrdator System a.
Insnection Scone (9370.2)
The inspectors responded to the site to review the licensee's actions in response to a f ailure in the plant annunciator system.
The inspectors reviewed:
Suggest on Occurrence Solution Report 97 0852;
Procedure OTO RK 00001, " Loss of Control Room Alarms," Revision 5; and
Procedure EIP ZZ 00101, " Classification of Emergencies," Revision 20.
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Qbservations and nndinas On July 19,1997, at approximately 4 p.m. (CDT), lightning strikes in the area of the water treatment plant resulted in the failure of numerous annunciators in the control room. Plant operators verified plant parameters were within limits, contacted instrumer.t and control technicians, and began to perform
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Procedure OTO RK-00001. This procedure described the method for monitoring various vital equipment and plant parameters to allow continued safe operation of the plant.
Approximately 30 minutes after the evert began, licensee personnel discovered and disconnected four failed connector cards in the "RK" nonsafety related plant annunciator system. These f ailed cards had caused the voltaCe for four annunciator field power supplies to drop to 25 VDC. The normal voltage for these power supplies was approximately 125 to 130 VDC. Af ter disconnecting the cards, the voltage of the field power supplies returned to normal and approximately 90 percent of the annunciators were restored.
Several system engineers assisted in the subsequent troubleshooting. At approximately 10 p.m., the licensee determined that, during the first 30 minutes of the event, the majority of the annunciators may not have been functional. The licensee notified the NRC at 10:34 p.m., that an Unusual Event condition existed between 4:15 p.m. and 4:30 p.m. because of the f ailed annunciators.
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Callaway Plant remained stable during the event, with no Camage to any safety-related equipment. All control room instrumentation and plant computer displays were available to operaters to motiitor plant status throughout the event.
The licensee appropriately performed compensatory measures directed by Procedure OTO RK 00001. Although most of the annunciators were restored af ter the first 30 minutes of the event, the licensee continued to perforrn the compensatory measures until the annunciator system was fully restored the following day at 3:48 a.m. The licensee formed an event review team to investigate this event.
The inspectors found that plant operators performed well during the event.
Operators remained focused on operating the plant safely. Management responded promptly at the onset of the event and provided proper direction and technical support.
The inspectors reviewed the licensee's delayed decision in declaring the Unusual Event. The criteria for the Unusual Event was defined in Procedure EIP ZZ-00101, Attachment 1, " Unplanned loss of most or all alarms (annunciators) for greater than 15 minutes." The applicable indicator for this condition was f ailure of three of the four field power supplies for greater than 15 minutes.
Shortly af ter the event began, the shif t supervisor decided not to declare an Unusual Event. The reasons were:
Operators checked the field power supplies as part of the immediate actions.
- Operators noted that the field power supplies had not failed since they indicated 25 VDC. The operators were unaware at this time that 25 VDC was a degraded voltage; At approximately 4:11 p.m. switchyard breakers for one of the three offsite
power sources opened and re closed because of a lightning strike. The annunciator was received in the control room. This provided an indication that not all annunciators were lost; and The shif t supervisor dispatched equipment operators to test various local
annunciator panels shortly af ter onset of the event. Several tests brought in the corresponding control room annunciators. This also provided indication that not all annunciators were lost.
The inspectors found that the shif t supervisor's initial decision not to declare the Unusual Event was in accordance with plant procedures. This was because there was indication to operators that the power supplies had not failed and because there was no conclusive indication that most annunciators had f ailed.
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4-The inspe:: tors found that the licensee made a more conservative interpretation of plant procedures in declaring the Unusual Event later, af ter further evaluation and troubleshooting.
The inspectors found weaknesses in operator procedures for describing minimum acceptable annunciator field power supply voltages and in what constitutes a failure of "most or all annunciators.' The licensee agreed and had already identified action to clarify the procedures.
The inspectors reviewed the licensee's event review team meeting minutes and found the proposed actions to De comprehensivo, c.
Conclusiong The inspectors concluded that operators responded well to this event. Operator actions to carry out compensatory actions until the annunciator system was fully restored were conservative. Management and technical support were very good.
There were weaknesses in plant procedures regarding the criteria for describing minimum acceptable annunciator field power supply voltages and in what constituted a f ailure of "most or all annunciatcrs." The licensee's proposed actions from the event review team meeting were comprehensive.
Operational Status of Facilities and Equipment O2.1 Rg.ylow of Eauinment Tanouts (71707)
The inspectors walked down the following tagout:
Workman's Protection Assurance 23497 Residual Heat Removal Train A.
- The inspectors did not identify any discrepancies, All tags were on the correct devices and the devices were in the position prescribed by the tags.
11. Maintena_nqn M1 Conduct of Maintenance M 1.1 Reneral Comments Ma.lDienance a,
Indngglipn Scone (627S21 The inspectors observed or reviewed portions of the following work activities:
Work Activity W191446 - Replace Fuse Block in Cubicle NN0111 (Feeder
Breaker to Westinghouse Process Protection Set 1 Cabinet);
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5-Work Activity C575024 Install New Breaker for Valve EFHV0060 (Essential
Service Water Train b from Component Cooling Water Heat Exchanger B);
Work Activity C600988 - Replace Orifice in Component Cooling Water to
Residual Heat Removal Pump A Seal Cooler Flow Element EGFE0089; Work Activity P603299 - Motor Operated Valve Periodic Test of Component
Cooling Water to Residual Heat Removal Heat Exchanger A lsolation Valve EGHV0101; and Work Activity W193716 Troubleshoot and Repair Ultimate Heat Sink
Cooling Tower Fan, b.
Qhelvations and Findinas The inspectors found no concerns with the maintenance observed. All work observed was performed with the work packages present and in active use. The inspectors frequently observed supervisors and system engineers inonitoring job progrebs, and quality control personne! Were present when required.
M1.2 General Comments Surveillance a.
Inspection Scone (61726)
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The inspectors observed or reviewed all or portions of the following test activities:
Surveillance Procedure OSP-SJ L1P64, " Containment Isolation Valve Leak
Rate Test for Valve SJHV00128 (Post Accident Sampling Pressurizer and Reactor Coolant System Inner Containment Isolation)," Revision 0; Surveillance Procedure OSP Al P0002, "Section XI Turbine Driven Auxiliary
Feedwater Pump Op3rability," Revision 24; Surveillance Procedure OSP-SF 00001, * Shutdown Margin Calculation "
Revision 18; Surveillance Procedure OSP NE-0001B, " Standby Diesel Generator B Periodic
Tests," Revision 2; and Surveillance Procedu.e ISF BB OP458B, " Analog Channel Operational Test on
RCS (Reactor Coolant System) Fressure Channel 4," Revision 9.
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QhSRIHl!RD1AD.d Finding Surveillance testing observed during this intpection period was co'iducted satisfactorily and in accordance with the licensco's approved programs and the Technical Specifications.
M2 Maintenance and Material Condition of Facilities and Equipment M2.1 General Comments (62707)
The inspectors made several tours of the plant. Material condition and housekeeping of accessible areas of the cuxiliary building, the feel building, the essential service watet pumphouse, and most areas of the turbine building were all very good.
M3 Maintenance Procedures and Documentation M3.1 Waate Gas Holdup _S.ystem Exolosive Gas Monitqrinn Instrumentation a.
lmnntion Scone (617261 The inspectors reviewed procedures and processes used to demonstrate operability of the explosive gas monitoring instrumentation in the waste gas holdup system.
The inspectors reviewed ',he following:
Procedure ISL HA-000A1(B1), " Loop Anlzr; Waste Gas Analyzer,"
Revision 11(14);
Procedure RSP-HA-0004A(4B), " Standardization of the Gaseous Radwaste
System Analyzers on Panel HA 161(162)," Revision 0; Vendor Manual M 725 00122, " Instruction Manual for Catalytic Hydrogen
Recombiner";
Brooks inctrument Design Specification Sheet DS-i355;
Instrument Society of America Recommended Practice ISA RP16.5,
" Installation, Operation, Maintenance instructions for Glass Tube Variable Area Meters (Rotameters)";
Final Safety Analysis Report Section 16.11.2.7.1; and
Request for Resolution 14181 Revisions A and B.
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Qtnervations and findinas indications and controls for the explosive gas monitoring instrumentation in the waste gas holdup system were located mainly on catalytic hydrogen recombiner waste processing system Panels HA 101 and HA 162 in the radwaste building.
Operability requirernents of the explosive gas monitors were described in Final Safety Analysis Report Section 16.11.2.7.1.
The operability requirements included a channel calibration of both instrument channels at least once per 92 days. The licensee used Procedures ISL HA 000A1( B1) and RSP HA 0004A(-48) to provide documentation and instructions for calibrating both of the waste gas holdup system explosive gas monitoring channels. Although the calibration requirement is once per 92 days, the licensee has been performing the cahbration monthly to coincide with a separate requirement to perform a monthly channel test.
The inspectors noted that Pequest for Resolution 14181, Revision A, identified that the oxygen and hydrogen flow indicators (rotameters) on Panels HA 161 and HA 162 were not routinely calibrated. The request for resolution questioned whether these rotameters should be calibrated, since these rotameters were part of the explosive gas monitoring instrumentation described in Final Safety Analysis Report Section 16.11.2.7.1.
Plant engineering personnel concluded on Request for Resolution 14181, Revision A, that the rotameters could not be calibrated because of lack of any adjustment capability. The inspectors found this evaluation to be weak, since the conclusion was unsupported.
The licensee re-evaluated the issue and provided documentation in Request for Resolution 14181, Revision B. Plant engineers concluded in this revision that calibration of the oxygen and hydrogen rotameters on Panels HA 161 and HA 162 was not required. The following basis was provided:
According to Manual M-725 00122, the ability of the oxygen analyzer to
detect oxygen concentration was independent of the flow rate.
The licensee contacted a representative for the manufacturer of the
rotameters at Brooks Instruments. The representative informed the licensee that calibration of the rotameters was not required for the application used at Callaway.
The section on recommended maintenance in Recommended
Practice ISA RP16.5 did not include a recommendation to periodically verify the calibration of the rotameters, i
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However, the licensee found that Manual M 725-00122 did state that the hydrogen analyzers were flow sensitive. The licensee evaluated this and again concluded that the hydrogen rotameter did not require calibration. The licensee provided the following justification.
Calibration of the system involved sending a waste gas sample through the hydrogen analyzer and recording the flow rate. A standard gas sample with a known concentration of hydrogen was then sent through the hydrogen analyzers at that same flow rate. The hydrogen analyzers were then adjusted to read the true hydrogen concentration. The system was then rechecked and not up to process future waste gasses using this same flow rate until the next calibration. The licensee found that, although it was not critical that the rotameters display the true hydrogen flow rate passing through the system, it was important that the rotameters have good repeatability.
The licensee did some research on repeatability of the rotameters. According to Specification Sheet DS 1355, the repeatability of the rotametars was very good, to within 0.5 percent of full scale. The licensee concluded that this would have no significant impact on hydrogen recombiner rotameter readings.
Although there was no recommendation by the Brooks representative and in Recommended Practico ISA RP16.5 to calibrate the rotameters, there were recommendations to check for leaks, deterioration, and wear. The licensee stated that the rnonthly calibrations and channel tests were sufficient to identify those problems.
The inspectors agreed with the licensee's assessment that the rotameters on Panels HA 161 and HA 162 did not require periodic calibration given the method of processing waste gasses at a constant flow rate.
The inspectors reviewed the test and calibration records for the waste gas holdup system explosive gas monitoring channels performed within the last 2 years. The inspectors found that the licenseo performed the surveillance testing satisf actorily in accordance with the Final Safety Analysis Report Section 16.11.2.7.1.
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Conclusions The inspectors concluded that:
The licensee has been performing testing and calibration of the waste gas
system explosive gas monitoring channels in accordance with requirements; The rotameters on Panels HA 161 and HA-162 did not require periodic
calibration given the method the licensee uses to process waste gasses at a constant flow rate; and,
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The monthly channel calibrations and channel tests were sufficient to check
for leaks, deterioration, and wear of the totametert M8 Miscellaneous Maintenance lasues (92902)
M8.1 IOnen) Licensee Event Bgport (LEN 60 483/96007: missed surveillance and literal Technical Specification compliance violaticns due to personnel oversight.
The missed surveillance, identified by the licensee, involved a loop calibration for Component Cooling Water Flow Transmitter EGFT0062 that had not been performed during the April 1995 refueling outage. This activity had initially been scheduled every 18 months as a preventive maintenance activity as opposed to a surveillance. The frequency was subsequently changed to 36 months based on performance results, which would be allowed for a preventive maintenance 1,ctivity.
Because this calibration was a Technical Specification required surveillance, the frequency change was inappropriate and resulted in a violation of Technical Specification 4.7.3.b.1. Additional reviews by the licensee determined that portions of other surveillances required to be performed "at least once per 18 months during shutdown" were actually being performed in Mode 1 and had been performed in this mode since plant startup.
The inspector reviewed the corrective actions for the missed loop calibration and determined that the surveillance had been appropriately captured in the surveillance data base with the correct frequency and plant conditions. Licensee reviews ioentified several other Technical Specification required surveillances that were being performed as preventive maintenance tasks and relocated them into the surveillance data base. None of those had exceeded their scheduled dates.
While reviewing the corrective actions for the surveillances performed in Mode 1 vice shutdown, the inspector determined that, although the curveillances were currently scheduled to be performed in the next refueling outage, the surveillance data base had not been changed to reflect that they were to be performed while shutdown. The inspectors will review the licensee's actions further as they are completed.
M8.2 (Closedi LER 50-483/96008: missed Technical Specification surveillance of 125 VDC batteries due to cognitive personnel error.
This event involved an electrician performing a weekly battery surveillance on the wrong train of batteries resulting in Train B of the station batteries being without a current surveillance for approximately 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br />. The licensee identified this condition during a surveillance data review and immediately took actions to collect and verify data that demonstrated the operability of the Train B battery. Additional corrective actions included counseling of the individual and revisions to the battery surveillance data sheets to include the specific train of battery being surveilled.
Additionally, the license reviewed other cases in which a generic procedure could
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- 10-allow the incorrect train to be surveilled because of lack of specificity in the procedure regarding component identification. The inspector reviewed the completed corrective actions and concluded that they were adequate to preclude recurrence, This event constituted a noncompliance with Technical Specification 4.8.2.1.a, which requires that the batteries be surveillance tested once every 7 day 6. This nonrepetitive, licensae identified, and coirected violation is being treated as a noncited violation consistent with Section Vll.B.1 of the NRC Enforcement Policy (50-483/9714 01L M8.3 [ Closed) Licensee Event Renort 50 483/97003: error in the Technical Specificatloa description for turbine driven auxiliary feedwater pump start.
The licensee identified that, during submittal, approval, and implementation of Amendment 43 to the Operating License in 1989, an error was introduced into the Technical Specifications regarding the conditions required to cause an automatic start of the turbine driven auxiliary feedwater pump. The error went unnoticed until identified by the licensee on March 31,1997. The NRC was informed. Ir. addition to verifying that the turbine driven auxiliary feedwater pump Ftart logic was being operated as designed, the licensee initiated an emergency Technical Specification change to correct the error. The change was subsequently approved by NP.C and incorporated by the licensee. The licensee's license amendment process was revised to provide additional review and scrutiny of license amendment requests.
The plant was never operated outside of the design basis as a result of this administrative error, and the licensee's corrective actions were appropriate.
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M8.4 (Closed) LER 50 483/9700t missed surveillance per Technical l
Specification 4.3.2.1 on the turbine and feedwater pump trip slave relay due to cognitive personnel error.
This LER involved a missed surveillance for Slave Relay K620 that was required to be performed each cold shutdown exceeding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. On one occasion, in October 1995, the surveillance was not performed following a cold shutdown condition exceeding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. During additional reviews of this event by the licensee, they discovered that slave relay surveillance tests for Relays K620 and K630 had, on several occasions, been performed at power instead of "during refueling" as required by Technical Specifications.
Corrective actions included verifying that the surveillance tests were technically accurate and verifying that testing at power provided the same assurance of operability as testing during refueling. The task sheets for the subject surveillances were revised to specifically note the exact condition requirements of the Technical Specifications. The responsible individuals were counseled on the importance of reviewing Technical Specifications when revising surveillance procedures to ensure all applicable requirements are me '
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These occurrences represent noncompliances with ths Technical Specifications regarding the addressed surveillance requirements. This nonrepetitive, licensee-identified, and corrected violation is being treated as a noncited violation in accordance with Section Vll.D.1 of the NRC Enforcement Policy (50 483/9714 02).
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E1 Conduct of Engineering E1.1 Axial _ Of fset Anomalv a.
Insocction Scone (37551)
The inspectors reviewed actions the licensee was taking to address an axial offset anomaly. This included review of the licensee's compliance with requirements for maintaining various reactor cora parameters within specified values.
The inspectors reviewed:
Cycle 9 Reactor Engineering Trend Reports;
Procedure ESP ZZ 00014 " Heat Flux Hot Channel Factor," Revision 20;
Technical Specifications 3/4.1.1.5; 3/4 1.3.0, 3/4.2.1, and 3/4.2.2;
Cycle 9 Core Operating Limits Report;
Suggestion Occurrence Solution Report 961821; and
Procedure OSP SF 00001, " Shutdown Margin Calculation," Revision 18.
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Observations and Findinas During this operating cycle the licensee experienced a substantial deviation from the predicted behavior of core axial offset. This deviation was a gradual unexpected power shift toward the bottom of the core and began to occur around
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4,000 megawatt days per metric ton of uranium of core burnup. The power shift would continue until enough fuel had been used in the bottom of the core that power shifted back to the top of the core. This shift would happen later in core life.
The licensee identified that the most likely cause of the axial offset deviation was a buildup of crud on the outside of the fuel pins in the upper spans of the core. This would create the presence of negative teactivity in the upper regions of the core, forcing the power shape to skew toward the bottom of the core.
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12-The axial offset deviation resulted in deviation from expected values for several core parameters. These included: (1) the limit for the heat flux hot channal factor F(q);
(2) the limit for axial flux difference; and (3) the limit on shutdown margin. The licensco confirmed that the deviation from expected values did not represent a safety hazard and began a detailed investigation.
lief' Flux Hot Channel Factor F(a)
The inspectors reviewed Technical Specification 3.2.2 for requirements associated with the heat flux hot channel factor F(q). The limit on this parameter ensured that fuel damage did not occur due to overpowering any given location in the core.
On July 7,1997, calculations from an incore flux map indiccted that the value of the heat flux hot channel factor F(q) exceeded the surveillance limit defined in
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_ Technical Specification 4.2.2.2.c. Although the more restrictive limit defined by the Limiting Condition for Operation of Technical Specification 3.2.2 was not exceeded, there were actions that the licensee was required to take after exceeding the surveillance limit. The licenseo properly followed the required actions, by placing tighter limite on the upper and lower limits for axial flux difference and by resetting the associated alarm setpoints.
A subsequent flux map the following day demonstrated that the surveillance limit had not been exceeded; however, the proximity to the heat flux hot channel f actor F(q) surveillance limit was still so close that the new limits on axial flux difference were left in place while further evaluations were conducted.
Determination of the heat flux hot channel f actor F(q) is normally performed every 31 effective full power days with an incore flux map. However, because of an increasing trend on several occasions, the licensee was required to perform the heat flux hot channel factor F(q) measurement every 7 effective full power days.
Performance of the weekly measurements was required by Technical Specification 4.2.2.2.o. The inspectors reviewed the weekly measurements and identified no concerns.
The inspectors reviewed trend reports for the heat flux hot channel f actor F(q) for the present operating cycle and had discussions with reactor engineering personnel.
Although the surveillance limit had been exceeded during the operating cycle, the inspectors determined that the licensee had never exceeded the Limiting Condition for Operation value for the heat flux hot channel factor F(q) during the current operating cycle. Exceeding the Limiting Condition for Operation value for the heat flux hot channel f actor F(q) would have required the licensee to reduce reactor power,
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13-The inspectors reviewed recent performances of the heat flux hot channel f actor F(q) determination per Procedure ESP ZZ 00014. The inspectors found that the licensee wcs properly performing the procedure and documenting and reviewing the results. The inspects,.s identified no concerns.
Axlal Flux Dif fere_ngs Axial flux difference involves a comparison of the power produced in thu top of the core to the pcwor produced in the bottom of the core. A positive axial flux difference implies that more power is being produced in the top half of the core than the bottom half of the core. A negative value implies more power is being produced at the bottom half of the core than the top half of the core. The limits for axial flux difference were specified in Technical Spe::ification 3.2.1 and in the Core Operating Limits Report.
As muntioned previously, the incore flux map perfortned on July 7,1997, resulted in the licensee placing tighter restrictions on the upper and lower limits for the axial flux difference than originally specified in the Core Operating Limits Report. For the negative limit, the axial flux difference value at 100 percent power was adjusted from 17,0 percent to 15.5 percent. Exceeding the upper or lower limits would have required the licensee to reduce reactor power.
The inspectois reviewed trend reports for axial offset during the present operating
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cycle. Axial offset is the axial flux difference divided by the fraction of reactor powei, Axial offset wac trended since it provided a more direct indicator of the actual axial flux distribution in the core at different power levels.
Just prior to reducing reactor power to 95 percent, axial offset was at the lowest value for the cycle, at approximately 14.0 percent. This was well below the predicted value of 1.0 percent, but within the lower administrative limit of 15.5 percent. After the power reduction to 95 percent reactor power, axial offset was aoproximately 11.5 percent. The power reduction allowed more margin to the lower limit: at 95 percent reactor power the lower limit was approximately 18,0 parcent.
The axial offset anomaly has caused the licensee difficulty in controlling the amount of available shutdown margin. Other problems related to the anomaly included the adverse effects of xenon transients and potentially higher than expected outage dose rates, jihutdown Marain The axial offset anomaly has caused shutdown margin to reduce at a f aster rate than predicted. This was due primarily to the combination of two factors:
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The formation of crud deposits at the upper elevations of the fuel occurred at
a rate greater than anticipated. Doron concentration was enhanced within the crud, concentrating a neutron poison and inserting negative reactivity at the upper elevations of the fuel. The licensee's calculational model assumed that, upon a reactor trip, all this boron would be released, resulting in a positive reactivity insertion at the upper elevations of the core. Therefore, more negative reactivity would have to be inserted to make and keep the reactor subcritical.
The axial offset anomaly caused less fuel to be depleted near the top of the
core. As happens upon a reactor top, the temperature of the coolant at the top of the core would decrease with an attendant increase in coolant density. With more available fuel and denser coolant at the top of the core, more positive reactivity would exist at the top of the core than would normally exist. Therefore, more negative reactivity would have to be inserted to overcome the positive reactivity.
Technical Specifications 3.1.3.6 and 4.1.1.5.2 require that the shutdown margin in Modes 1 and 2 be greater than or equal to 1300 pcm. As of July 28,1997, shutdown margin had reduced to a value of 1511 pcm. The licensee's calculation showed shutdown margin reaching 1300 pcm on August 15,1997. At that time, in order to preserve the shutdown margin at 1300 pcm, a power reduction would be required. The inspectors reviewed the licensee's current performance of shutdown margin calculations in accordance with Procedure OSP SF 00001 and identified no concerns.
Procedure OSP SF 00001 assumed a 10 percent uncertainty for the available rod worth. The inspectors noted that the licensee had an approved safety evaluation to assume a 3 percent rod worth uncertainty. This would extend the date when shutdown margin would be at 1300 pcm. The licensee has not yet assumed the 3 percent rod worth uncertainty in the shutdown margin calculations because shutdown margin trend curves generated by Westinghouse and the licensee differ.
The licensee was working to resolve those differences prior to assuming the
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3 percent rod worth uncertainty.
The licensee was taking the following actions as a result of the axial offset anomaly.
- On June 10,1997, the licensee began performing weekly shutdown margin calculations fut more accurate tracking and trending. In addition, the licensee was developing a program to provide a real time computer display of the shutdown margin. The program would gather the necessary data from the plant computer, perform the calculation, and display the results. The licensee would still perform a separate calculation once per week.
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15-The licensee began to evaluate acceptability of an increase to the control rod
insertion limits from 101 steps to 181 steps on Control Rod Bank D. This would allow approximately 10 extra days until the shutdown margin limit was reached.
The licensee revised the Core Operating Limits Report to incorporate a
change to the upper and lower limits for the axia' flux difference. The new limits specified new full power upper and lower limits of + 6.0 percent and 17.0 percent, respectively. The purpose of the revision was to generate additional margin to the heat flux hot channel factor F(q) limit.
The licensee, in concert with Westinghouse, performed a safety evaluation to
address the impact of the crud deposition on the various postulated design basis accidents. The safety evaluation concluded that the axlat offset anomaly did not represent an unreviewed safety question and, hence, would not adversely affect plant operation. The licenseo planned to re evaluate the safety evaluation in August 1997 and perform another safety evaluation if necessary.
The licensee has been holding weekly conferences with Westinghouse
personnel since the beginning of June 1997. The purpose of the conferences was to discuss current concerns regarding the anomaly and set priorities for resolving those concerns.
The inspectors will continue to follow the licensee's actions. Pending further review of the acceptability of using a 3 percent rod worth uncertainty in shutdown margin calculations, and the other actions the licensee is taking, this is considered an inspection followup item (50 483/9714-03).
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Conclusions The inspectors concluded that the licensee was in compliance with the Technical Specifications for the heat flux hot channel factor F(q), axial flux difference, and shutdown margin. The licensee was aggressively monitoring shutdown margin and the other plant parameters to ensure the plant remained within the operating limits.
E8 Miscellaneous Engineering issues (92903)
E8.1 (Closed) Unresolved item 50-483/9707-05: Response time discrepancy with control room ventilation radioactivity monitors.
The inspectors identified a discrepancy between the Final Safety Analysis Report and plant test practices. The discrepancy involved the response time of the control room ventilation isolation system.
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C 16-The inspectors reviewed:
Suggestion-Occurrence Solution Report 97 357;
NUREG 1405, " Accident Source Terms for Light Water Nuclear Power e
Plants";
Final Safety Analysis Report Sections 15.6.5.4 and 15A.3; and
Final Safety Analysis Report Tables 7.3 7 and 15.6 8.
- Final Safety Analysis Report Table 7.3 7 stated that the response time of the control room ventilation radioactivity Monitors GKRE04 and GKRE05 was less than 3.0 seconds. Monitors GKRE04 and GKRE05 continuously monitor the supply of air of the normal heating, ventilation, and air conditioning system for particulate, iodine, and gaseous radioactivity. The monitors isolate cantrol room ventilation from the outside environment in the event high airborne radioactivity is introduced into the centrol room heating, ventilation, and air conditioning supply duct.
The only response time test performed on the monitors was la April 1984, during preoperational testing. The response time reported for Monitor GKRE04 was 4.1 seconds. The response time reported for Monitor GKRE05 was 3.8 seconds.
The licensee initiated action to resolve the discrepancy between the Final Safety Analysis Report and the preoperational test results.
The licensee could not identify a reason for the discrepancy and could not identify any documentation that would indicate an effort to validate the 3.0 second response time listed in the Final Safety Analysis Report Table 7.3 7.
The inspectors considered the acceptance of the as is condition of the response time for Monitors GKRE04 and GKRE05 to be a de facto change to the facility as described in the Final Safety Analysis Report. As such, the licensee was required by 10 CFR 50.59 to evaluate and document the acceptability of the change to ensure that an unroviewed safety question did not exist. The inspectors considered the acceptance of this de facto change a violation of 10 CFR 50.59.
The licensee had already identified the need to review the system containing Monitors GKRE04 and GKRE05. This was described in the licensee's letter of February 5,1997, which committed them to review the Final Safety Analysis Report. in the letter, the licensee stated that a task team was formed in March 1996 to determine the scope of review required to provide assurance that the Callaway Plant is operated according to the Final Safety Analysis Report.
The task team completed the review in July 1995 and identified actions and prioritized various Final Safety Analysis Report sections for review. One section identified for review was the control building heating, ventilation, and air
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17-conditioning system containing Monitors GKRE04 and GKRE05. The licensee's action plan was to perform the review from August 31 through September 18, 1998. The licensee had identified a review team and estimated 520 man hours to complete the review.
The Commission recently approved modifications to the NRC Enforcement Policy (NUREG 1600) to address departures from the Final Safety Analysis Repmt.
Section Vll.0,3 of the Policy, " Violations involving Old Design Issues," addresser enforcement discretion when licensees identify the problem. Although NRC inspectors identified the error in Final Safety Analysis Report Table 7.3 7, it is apparent that the licensee would have identified those errors in light of the defined scope, thoroughness, and schedule of their review plan.
The f ailure to evaluate and document the acceptability of the Final Safety Analysis Report response time discrepancy for Monitors GKRE04 and GKRE05 represented a noncompliance with 10 CFR 50.59. This is being treated as a noncited violation in accordance with Section Vll.B.3 of the NRC Erforcement Policy (50-483/9714 04).
The licensee completed a preliminary investigation and did not identify any operability issues. The licensee found that Final Safety Analysis Report Section 15A.3 stated that only radiation dose due to a postulated lots-of-coolant accident was discussed in Final Safety Analysis Report Chapter 15. This was because a study of the radiological consequences in the control room due to various postulated accidents indicated that the loss-of-coolant accident was the limiting case. As such, the ventilation path containing Monitors GKRE04 and GKRE05 would isolate on a safety injection signal before these monitors would detect sufficient activity to initiate the control room ventilation isolction signal.
The licensee evaluated other accident scenarios to assure that the loss of-coolant accident was still the bounding control room dose accident assuming the delay in the response time of Monitors GKRE04 and GKRE05. The licensee found that the
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loss of coolant accident was still the bounding control room dose accident.
I The licensee also performed research regarding monitor response time and did not identify any significant degradation over time. The licensee identified that the only real contributor to monitor response time was from the monitor's counter and signal conditioning circuit. The licensee found that the response time of the counter and conditioning circuit was not a limitation of the installed hardware but a design feature to reject spurious inputs.
The inspectors agreed with the licensee's preliminary evaluation. The inspectors found that the difference between the preoperational test measured response times of 4.1 and 3.8 seconds and the Final Safety Analysis Report stated response time of 3.0 seconds would not signihcantly affect the control room dose consequences from a loss of coolant acciden *
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18-Pending the inspectors' review of the licensee's completed actions to resolve the discrepancy in final Safety Analysis Repoit Table 7.3 7, this is considered an Inspection Followup Itern (50 483/9714-05).
LE_flAnLS_UnR011 R1 Radiological Protection and Chem!stry (RP&C) Controls R 1.1 General Comments (717501 The inspectors observed health physics personnel, including supervisors, routinely touring the radiologically controlled areas. Licenseo personnel working in radiologically controlled areas exhibited good radiation worker practicos.
Contaminated areas and high radiation areas were properly posted. Area surveys posted outsido rooms in the auxiliary building were current. The inspectors checked a sample of doors, required to be locked for the purpose of radiation pr'Jection, and found no problems.
MOBORemafitRat11[191 X1 Exit Meeting Summary The exit meeting was conducted on August 1,1997. The licensee did not express a position on any of the findings in the report.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
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S_tPELEMENTAL INFORM ATION LARTIAkt&T OF PERSQRS_Q.ONTACTEQ Licensee R. D. Affolter, Manager, Callaway Plant H. D. Bono, Supervising Engineer, Regulatory Support, Quality Assurance
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D. G. Cornwell, General Supervisor Electrical, Maintenance M. S. Evans, Superintendent, Health Physics D. T. Fitzgerald, Superintendent, Security D. W. Grif fith, Engineer, independent Safety Engineering Group, Quality Assurance R. T. Larnb, Superintendent, Operations J. V. Laux, Manager, Quality Assurance A. C. Passwater, Manager, Licensing and Fuels G. L. Randolph, Vice President, Chief Nuclear Of ficer R. R. Roselius, Superintendent, Chemistry and Radwaste M. E. Taylor, Assistant Manager, Work Control W. A. Witt, Superintendent, Systems Engineering INSPECTION PROCEDURES USEQ 37551 Onsite Engineering 61726 Surveillance Observations 62707 Maintenance Observation 71707 Plant Operations 71750 Plant Support Activities 92002 Followup - Maintenance 92903 Followup Engineering
'!S702 Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED, CLOSED, AND DISCUSSEQ Onened 9714-01 NCV Missed Technical Specification surveillance of 125 VDC batteries (Section M8.2)
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2-9714 02 NCV Missed Technical Specification surveillance of turbine and
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feedwater pump trip slave relays (Section M8.4)
9714 03 IFl Axial offset anomaly issue (Section E1.1)
9714-04 NCV Final Safety Analysis Report response time discrepancy for Monitors GKRE04 and GKRE05 (Section E8,1)
9714 05 IFl Resolve discrepancy in Final Safety Analysis Report table for Monitors GKRE04 and GKRE05 (Section E8.1)
GMad 96008 LER Missed Technical Specificatien surveillance of 125 VDC batteries (Section M8.2)
9714 01 NCV Missed Technical Specification surveillance of 125 VDC batteries (Section M8.2)
97003 LER Technical Specification error in description of turbine driven auxiliary feedwater pump start (Section M8.3)
97004 LER Missed Technical Specification surveillance on turbine and feedwater pump trip slave relays due to personnel error (Sectiori M8.4)
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07014 02 NCV Missed Technical Specification surveillance of turbine and feedwater pump trip slave relays (Section M8.4)
9707 05 UNR Response time discrepancy with control room ventilation radioactivity monitors (Section E8.1)
9714 04 NCV Final Safety Analysis Report response time discrepancy for Monitors GKRE04 and GKRE05 (Section E8.1)
Discussed 96007 LER Missed surveillance and literal Technical Specification compliance due to personnel oversight (Section M8.1)
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