IR 05000346/1998013
| ML20237F245 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 08/25/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20237F240 | List: |
| References | |
| 50-346-98-13, NUDOCS 9809020149 | |
| Download: ML20237F245 (17) | |
Text
_ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ . _ - _ _ _ - _ _ . _ _
,
.l
,
U. S. NUCLEAR REGULATORY COMMISSION
!
REGION lll l
l Docket No: 50-346 l License No: NPF-3 '
Report No: 50-346/98013(DRP) l Licensee: Toledo Edison Company Facility: Davis-Besse Nuclear Power Station I l
l Location: 5501 N. State Route 2 Oak Harbor, OH 43449 s
l Dates: June 23 - August 7,1998
]
Inspectors: S. Campbell, Senior Resident inspector K. Zellers, Resident inspector g G. Harris, Senior Resident inspector, Ferml Approved by: Thomas J. Kozak, Chief Reactor Projects Branch 4 l
.
,
9009020149 990825 L PDR ADOCK 05000346 G PDR ,
- ____
_-_ _ _ - - - _ - _ - - - - - - - - - - _ - - __ . _
,
.
I EXECUTIVE SUMMARY Davis-Besse Nuclear Power Station Davis-Besse inspection Report 50-346/98013(DRP)
This inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a 6-week period of resident inspectio Operations
.
The inspectors determined that operators maintained the plant in a safe condition, were in control of important plant parameters, and that no equipment failure challenged the safe shutd.w,'n capability of the phnt after a tomado had caused a loss of offsite power and a rea< hv trip on June 24 (Section 01.1).
.
Overall, the inspectors concluded that operators exhibited appropriate knowledge and control during the relatively high number of startups and shutdowns that occurred during the inspection period. However, appropriate attention to detail was not displayed when a reactor operator did not verify that a turbine generator lift oil pump had started after he tumed the switch to on and when operators missed an opportunity to determine that the actual Axial Power Shaping Rod (APSR) position was not consistent with the position assumed in the estimated critical position (ECP) calculation. In addition, a turbine trip occurred when reactor operators could have been better prepared to synchronize the turbine to the grid after a forced outage (Section 01.2).
The inspectors determined that operations personnel did not recognize that Technical Specification (TS) 3.0.5 was entered when the emergency p mer supply for control room emergency ventilation (CREVS) Train 1 was inoperable coinciG.nt with CREVS Train 2 being inoperable. The apparent cause was a lack of written guidance pertaining to the complex relationship between the operability of station vent stack radiation monitors and CREVS operability. No violation occurred because of the short duration (13 minutes) of the condition (Section 01.3).
.
Maintenance personnel bypassed the operations work control unit review chain when performing weekly maintenance on the station vent stack radiation monitors. This did not meet plant management's expectation for the control of work and contributed to the failure to recognize entry into TS 3.0.5. (Section 01.3).
Maintenance
.
The inspectors concluded that station management effectively prioritized items that were operator burdens, such as control room annunciators that were locked in due to a discrepant material condition, during plan of the day meetings (Section M1.2).
.
The inspectors determined after the loss of offsite power on June 24, that emergency diesel generator (EDG) #1 Test Switch TS-3 was out of position, which resulted in a temporary loss of important EDG parameter local indications. The root cause was that an electrician performed an inadequate review of maintenance wo:t order paperwork when work was suspended for the night. No corrective action document was generated to
- _ _ _
7-.
.
further address the concem until July 25, after the inspectors brought the matter to the EDG engineer's attention (Section M1.3).
. The outage manager developed a comprehensive plan to address existing plant issues, including correcting a faulty indication for Control Rod 4-6, cleaning Loop 1 waterboxes, installing a furmanite injection plug for leaking Pressurizer Spray Valve RC-2, and repairing deficiencies previously identified on the main transformer during the forced outage to address chemistry issues. The inspectors concluded that the outage was well !
planned and included effective management involvement with the work activities l (Section M1.4). l j
l 4 After the inspectors identified a control room instrument was indicating low, maintenance personnel determined that the instrument was able to be calibrated to the low end of the band; however, they replaced the square root extractor for the instrument in order to l calibrate to the middle of the band. The inspectors concluded that maintenance personnel were proactive when they rmlaced the square root extractor for the instrument (Section M4.1).
.
Enoineerina
.. The inspectors rev;ewed plant engineering efforts to address problems with the integrated control system and to track maintenance activities pertaining to the service water intake l- structures. The inspectors determined that the integrated control system engineer and l
his backup effectively troubleshoot and supervised repairs of a problem with the integrated control system and that they took proactive measures to tune the system and replace components in order to obtain better system performance. Further, the service water system engineer was in the field providing effective oversight and guidance for contractor and plant maintenance staff during intake crib repairs, intake canal silt level determinations, and service water pump house structures cleaning activities l
,
(Section E2.1).
. The inspectors determined that actual APSR position (15 percent) did not match the ECP calculated position (30 percent) during a reactor startup. The apparent root cause was
, that a reactor engineer in the control room exhibited a lack of attention to detail when the
!
ECP was calculated. Additionally, the lack of a procedural requirement to ensure that the actual APSR position matched the ECP position was a weakness. The proposed changes to plant procedures should prevent rectJrrence. The effect of the error had no
' impact on safety (Section E4,1).
. The Station Review Board and the Management Review Committee were effective in ensuring that Potential Condition Adverse to Quality Reports were appropriately prioritized, assigned to the right organization, and resolved as scheduled (Section E7.1). :
, Plant Support l
. The licensee took conservative actions to address the relatively high secondary side sulfate concentrations caused by a resin intrusion by voluntarily shutting down the reactor and performing multiple steam generator fill, soak and drains. The sulfate levels were reduced below administrative levels and the plant was subsequently retumed to full power (Section R1.2). ;
i
'
l
'
l
- _ _ - _ _ _ _ _ - _ _
'
L l
l I.
! Report Details-1
Summary of Plant Status June 23 - June 24 The plant was operated at approximately 99 percent powe ' June 24 The reactor automatically shutdown because of a loss of offsite power due to a tomado passing by the station. An Alert was deciare June 24-25 - The station remained in an Alert status and the plant was maintained in Mode 3. Powerwas provided to safe shutdown equipment by two operating emergency diesel generators'(EDG).
June 25 One offsite powerline was restore June 26 0200 The Alert was downgraded to an Unusual Even . June 261405 The station exited the Unusual Event after two sources of offsite power
,
were restored.
L June 26 - July 1 The plant stayed in Mode 3 for a forced outage to conduct repairs to i l station equipment.
l- July _16 The plant was started up to Mode 1, then shut down to Mode 3 to perform i steam generator fill, soak, and drains due to high steam generator sulfate i concentrations caused by condensate domineralizer resin intrusion into the ,
steam generator l l
. July 6-22 The plant was started up and operated at approximately 100 percent-l power.
'
July 13 . The remaining offsite power line was restore July 23-26 - The plant was shutdown to Mode 3 to perform fill soak and drains of both steam generators to reduce sulfate level July 26 - August 7 The plant was restarted and operated at approximately 100 percent powe . Operations 01 Conduct of Operations 01.1 Observation of Control Room Activities Followino a Loss of Offsite Power 'nspection Scope (93702)
The inspectors observed the performance of plant equipment and personnel after the station was damaged by a tomado on June 2 Observations and Findinas
. When the tomado passed the vicinity of the plant, it caused damage to the switchyard resulting in the loss of all offsite power sources. When the loss of offsite power occurred, the reactor tripped on high reactor coolant pressure, the main turbine tripped because of the reactor trip, and the reactor coolant pumps and all station 13.8 kilovolt,4.16 kilovolt, and 480 volt power supplies became de-energized. Prior to the station losing offsite power, operations personnel had received sufficient waming so that both EDGs were started. When power was lost, both EDG output breakers automatically shut to re-energize redundant safety-related loads required for a safe shutdown. Because the feedwater and condensate' system was not powered by the EDGs, its heat removal 4 _ _ _ _ _ _ _ _
.
,
L capacity was lost, therefore, the decay heat of the reactor vessel was removed via the steam generators by the auxiliary feedwater system, the main steam safety valves, and the atmospheric vent valve The inspectors noted that control room operators were calm and had good control of vitar plant parameters. Reactor coolant pressure and temperature and steam generator level and pressure were being maintained close to nominal parameters for a post trip condition. The operators were in process of reviewing the emergency and annunciator alarm procedures and were in continuous communication with the NRC headquarters operations cente The inspectors initial observations of equipment anomalies included the following:
- Bus YAU was de-energized because inverter WA static transfer switch faile This caused the controls to Atmospheric Vent Valve (AW) #1 to be de-energize Additionally, the control of AW #2 was degraded in that the valve went to 10 percent open when the valve was taken to automatic operation. Operators were able to adequately compensate for this condition by cycling AW #2 from automatic to manual operation. The loss of bus YAU also caused the plant computer to not be available which prevented the display of helpful graphic presentations of plant status. Adequate indication of plant parameters was still available in the control room for the operators to maintain control of the plant. l
. The control of AW #2 was degraded in that the valve went to 10 percent open when the valve was taken to automatic operation. Operators were able to adequately compensate for this conditio . Some local control panel electrical status indicators for EDG #1 were not energized. The inspectors noted that a test switch on the panel was not in the proper position. See Section M1.3 for more discussion of this issu . The station fiber optic phone system had been disrupted by the storm, forcing the
. use of attemate circuits for communicatio * One of the steam generator code safety valves did not fully reseat, which caused the operators to slightly lower the steam generator pressures using the atmospheric vent valves in order to reseat the valv The circumstances surrounding the event and the licensee's recovery actions are described in NRC Inspection Report 50-346/9801 Conclusions The inspectors determined that operators maintained the plant in a safe condition, were in control of important plant parameters, and that no equipment failure challenged the l
'
safe shutdown capability of the plant after a tomado had caused a loss of offsite power and a reactor trip on June 2 O
!
,
!
l l
' ;
m
,
.
01.2 Reactor Shutdown and Startuo Observations . Inspection Scope (71707)
The inspectors observed reactor startups on July 1, July 6, and July 26, and reactor shutdowns on July 2 and July 2 . b . Observations and Findinos b1.1 Overall Assessment The inspectors determined that the reactor startup and shutdown procedures provided operators appropriate guidance to safely shutdown the plant, and that equipment performed in accordance with the descriptions in the Updated Safety Analysis Report (USAR). Operators performed pre-evolution briefs, strictly complied with procedures, effectively communicated, and were generally deliberate and diligent during reactor startup activitie b1.2 Exceptions to the Overall Assessment Main Turbine inadvertently Tripped During the July 26 startup, when the main turbine was being synchronized to the grid, a reactor operator focused his attention on an actual megawatt indicator rather than using additional indication such as demanded megawatts and steam header pressur Consequently, he demanded about 400 megawatts of load instead of the desired 50 megawatts. This caused a primary to secondary heat imbalance that caused the average reactor coolant temperature and steam header pressure to decrease. In response, the reactor operator reduced turbine load; however, he was still focused on the indicator for actual turbine load and caused the demanded turbine load to go to j
'
0 megawatts. When the turbine control valves went closed, reverse power relays actuated which caused the main turbine to trip. . The operator immediately recognized that he should monitored additional available indicators to control the turbine load. The inspectors determined that the operator had not been effectively prepared or briefed for this infrequently performed evolution. Control room operators responded in accordance with the turt>ine trip procedure and placed the plant in a stable condition. Subsequently, the turbine was synchronized to the grid without inciden Reactor Operator Failed to Notice that a Turbine Generator Lift Oil Pump Did Not Start l During the July 23 plant shutdown, a reactor operator was instructed to start the turbine
! generator lift oil pumps in preparation for securing the main turbine. He then tumed the l control switches for all six of the pumps to on, documented completion of the activity on l the procedure, and informed the shift supervisor that he had completed his task. The
[ inspectors noted that one of the lift oil pumps had not tumed on. The inspectors then l notified the reactor operator who then started the pump. Subsequently, the inspectors I discussed the issue with the cognizant system engineer to determine potential consequences had the pump remained off and determined that no damage to the turbine would have occurred. - The inspectors determined that the reactor operator did not i
__ . . . . . . . . . . .
j
.
.
conduct adequate self checking while starting turt>ine generator lift oil pumps which resulted in one of the pumps not being starte Operators Missed Opportunity to Determine that Axial Power Shaping Rod (APSR)
Position Was Not Consistent the Estimated Critical Position During the July 26 reactor startup, the inspectors identified, after control rod groups one through four were withdrawn during the approach to criticality, that actual APSR position was 15 percent while the APSR position assumed in the estimated critical rod position was 30 percent. The information that would have determined this problem was readily available for review by control room operators, but was not reviewed in sufficient detail to identify the problem. Also see Section E4.1 for a more detailed description of the observatio Conclusions Overall, the inspectors concluded that operators exhibited appropriate knowledge and control during the relatively high number of startups and shutdowns that occurred during the inspection period. However, appropriate attention to detail was not displayed when a reactor operator did not verify that a turbine generator lift oil pump had started after he
_
turned the switch to on and when operators missed an opportunity to determine that the actual APSR position was not consistent with the position assumed in the estimated critical position calculation. In addition, a turbine trip occurred when reactor operators could have been better prepared to synchronize the turbine to the grid after a forced outag .3 Ooerators Missed Entry into Technical Specification (TS) 3. Inspection Scoos (71707)
The inspectors performed a routine review of control room logs and determined that entry into and out of TS 3.0.5 should have been logge Observations and Findings The inspectors determined that from 0953 to 1006 on August 4, the emergency power supply for Control Room Emergency Ventilation System (CREVS) Train 1 was inoperable and that the redundant CREVS Train 2 was inoperable due to maintenance on a vent stack radiation monitor. Technical Specification 3.0.5 states, among other things, that when a system is determined to be inoperable solely because its emergency power source is inoperable (CREVS Train 1), it may be considered operable provided its redundant system is operable (CREVS Train 2), otherwise, within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, action shall be 1 initiated to place the unit in a mode in which the applicable limiting condition for operation does not appl The responsible shift supervisor indicated that he had believed that entry into TS 3. ;
'
was not required.' However, when the inspectors explained their understanding of TS 3.0.5, CREVS, and the vent stack radiation monitor detectors, the shift supervisor generated Potential Condition Adverse to Quality Report (PCAQR) 98-1507 and made late entries to the unit log indicating entry into and exit out of TS 3.0.5. Although entry l
4
. - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ w
- - _ _ - _ _ _ - _ _ - _ - - _ - _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _
B into TS 3.0.5 was not recognized, no violation occurred because the station had exited TS 3.0.5 within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The inspectors conducted operator intenriews and determined that differing opinions existed on whether TS 3.0.5 should have been entered, and that station documentation lacked adequate guidance pertaining to this issu Further review by operations management determined that when maintenance personnel performed the weekly vent stack radiation monitor maintenance, they bypassed the operations work control unit review chain and obtained permission to perform the maintenance directly from operations shift management. This practice did not meet management expectation for the control of work and contributed to the failure to recognize entry into TS 3. Conclusions The inspectors determined that operations personnel did not recognize that TS 3.0.5 was entered when the emergency power supply for CREVS Train 1 was inoperable coincident with CREVS Train 2 being inoperable. The apparent cause was a lack of written guidance pertaining to the complex relationship between the operability of station vent stack radiation monitors and CREVS operability. No violation occurred because of the short duration (13 minutes) of the conditio ~ Maintenance personnel bypassed the operations work control unit review chain when performing weekly maintenance on the station vent stack radiation monitors. This did not meet management expectation for the control of work and contributed to the failure to recognize entry into TS 3.0.5.
- O2 Operational Status of Facilities and Equipment 0 System Walkdowns (71707)
The inspectors walked down the accessible portions of the following engineered safety features and important-to-safety systems:
. Low Pressure injection I
. High Pressure injection )
. Component Cooling Water
. Low Voltage Switchgear
. High Voltage Switchgear ,
!
. Containment Air Coolers
. Control Room Emergency Ventilation l
. Emergency Ventilation System j No substantive concems were identified as a result of the walkdowns. System lineups and major flowpaths were verified to be consistent with plant procedures / drawings and the USAR. Pump / motor fluid levels were within their normal bands. Only very minor oil and fluid leaks were noted on occasion. Equipment material condition was excellent in all case ,
i i
L___-.___-____-__-__-____--___-_____________
, _ - _ _ __ ___ _ ______._ _ _ _ _ _ _ ____ __ _ ___ ___ _ __ __ _ _ - _ _ _
.
M1 . Conduct of Maintenance M1.1 Maintenance and Surveillance Activities (61726)(62707)
The following maintenance and surveillance testing activities were observed / reviewed during the inspection period:
-
DB-MI-03351, " Channel Functional Test of PSt.-4533A,4534A and 4535A Main Feed Pump 1 and 2 Turbine Hydraulic Oil Trip and Main Turbine Oil Trip r . ANTICIPATORY REACTOR TRIP SYSTEM Channel 1"
-
DB-SC-03071, " Emergency Diesel Generator 2 Monthly Test"
-
DB-SC-03164, " Channel Functional Test of the Manual Reactor Trip"
-
DB-SC-03110, "SFAS Channel 1 Functional Test"
-
DB-SS-04151, " Main Turbine Control Valve Test
-
DB-SS-04152, " Main Turbine Combined intermediate Valve Test"
-
DB-MM-03001, " Main Steam Safety Valve Setpoint Test" The inspectors concluded that the activities mentioned above were completed by qualified personnel using appropriate procedure M1.2 . Prio,,iketion of Maintenance Activities (62707)
The inspectors conducted frequent reviews of operations shift briefs and plan of the day meetings. ' Plant management was actively involved in the, day-to-day work activities and ensured items were worked as scheduled. The inspectors concluded that station management effectively prioritized items fwt were operator burdens, such as control room annunciators that were locked h dw to a discrepant material condition, during the meeting M1.3 Ememency Diesel G_grerator (EDG) Test Switch Left in Test Position While Maintenance Had Been Suspended insDeClion ScoDe (71707)
The inspectors conducted an inspection of the operatlng EDGs about three hours after the loss of off-site power event of June 24, and de. terr.,ined that Test Switch TS-3 was not in its normal position, which de-energized several important local indicators, Observations and Findinas The inspectors identified that Test Switch TS-3 on Control Panel C3615 for EDG #1 was not in its normal position. Additionally, the inspectors identified that indicators for generator volts, amperage, kilowatts, and power factor were not functioning. The inspectors informed operations management, who informed the operations support center. The switch was retumed to its normal position and the aforementioned indicators began functioning correctl .
.
On July 24,' the inspectors determined that no PCAQR had been written to document and investigate the problem with TS-3 being in the wrong position.- The EDG engineer then initiated PCAQR 98-1460. The preliminary investigation determined that prior to the loss
. of offsite power, an electrician performed routine preventive maintenance activities per Maintenance Work Order (MWO) 3-98-0390-01 on portions of the EDG circuitry that required electrical isolation by TS-3. Because he did not complete the MWO packages before the end of his work day, he intended to restore all abnormally positioned switches or lifted wires to their normal position before leaving for the day in accordance with management expectations. However, he did not retum TS-3 to its normal position because of an inadequate paperwork review. The worker indicated that he performed the job alone and was in a rush to finish his wor Mispositioning TS-3 did not render the EDG inoperable because the non-functional indicators were determined to not be essential to the operability of the EDGs. The indicators for voltage, amperage, and watts in the control room were functional and monitored. Although the operators saw that the EDG was running and that the breaker had closed to provide power to the safety-related busses, the non-functioning local indicators prevented equipment operators in the EDG room from fully monitoring the status of #1 EDG during the loss of offsite power event until TS-3 was retumed to its normal positio Conclusion The inspectors determined after the loss of offsite power on June 24, that EDG #1 Test Switch TS-3 was out of position, which resulted in a temporary loss of important EDG parameter localindications. The root cause was that an electrician performed an inadequate review of MWO paperwork when work was suspended for the night. No corrective action document was generated to further address the concem until July 25,.
after the inspectors brought the matter to the EDG engineer's attentio M1.4 Station Outaae Preparations (62707)
The inspectors observed station personnel prepare for the outage to reduce sulfate levels in the steam generators (see Section R1.2). The sulfate reduction required that the plant be shut down to fill, soak, and drain the steam generators. Before the outage, the outage manager developed a comprehensive plan to address existing plant issues including correcting a faulty indication for Control Rod 4-6, cleaning Loop 1 waterboxes, installing a furmanite injection plug for leaking Pressurizer Spray Valve RC-2, and repairing deficiencies previously identified on the main transformer. During the outage, the station personnel established a central outage organization that consisted of managers who provided direction on resolving plant issues. Computers were installed to provide the managers a means of referencing equipment configuration data bases. The inspectors
. concluded that the outage was well planned and included effective management t involvement with the work activities.
l
.
M4 Maintenance Staff Knowledge and Performance M4.1 Auxiliary Feedweier (6FW) Flow Indicator (F1-4630) for Post Accident Monitorina System Determined inoperable (71707)
During control room observations on July 30, the inspectors identified that AFW Flow Indicator F1-4630 indicated 0 gallons per minute flow when redundant instruments indicated about 80 gallons per minute flow. Control room personnel indicated that they had recently seen it display positive flow. After observing the indicator for several
- minutes, operators generated a deficiency tag, wrote PCAQR 98-1346, and declared the indicator inoperable. Subsequently, maintenance personnel determined that the instrument was able to be calibrated to the low end of the band, however, they replaced the square root extractor for the instrument in order to calibrate to the middle of the ban The inspectors concluded that maintenance personnel were proactive when they replaced the square root extractor for the instrumen Ill. Enaineerina E2 Engineering Support of Facilities and Equipment
. E Plant Enaineerina Suonori (37551)
The inspectors reviewed plant engineering efforts to address problems with the integrated control system and to track maintenance activities pertaining to the service water intake structures. The inspectors determined that the integrated control system engineer and his backup effectively troubleshoot and supervised repairs of a problem with the system and that they took proactive measures to tune the system and replace components in order to obtain better system performance. Further, the service water system engineer was in the field providing effective oversight and guidance for contractor and plant maintenance staff during intake crib repairs, intake canal sili level determinations, and service water pump house structures cleaning activities. The inspectors determined that plant engineers for the service water and integrated control systems provided effective oversight of maintenance activities on their system E4 Engineering Staff Knowledge and Performance E APSRs not in the Position Assumed by the Estimated Critical Position (ECP) Calculation Inspection Scope (71707)
The inspectors observed a reactor startup on July 26 and determined that the APSRs were not at the position assumed in the ECP calculation.
, Observations and Findinas l
On July 26, the inspectors observed operators withdrawing control rods to take the
,
reactor critical. Rod Safety Groups 1 through 4 had been withdrawn, and operators were L preparing to withdraw regulating rod Jroups five through seven to criticalit !.
l
.
1- The inspectors reviewed the ECP calculation and determined that the APSR specified
. position was 30 percent withdrawn, even though the actual position was at 15 percent withdrawn. The inspectors immediately brought this to the attention of a reactor engineer who was present in the control room for the reactor startup. He then requested that operators suspend reactor startup activities until a new ECP, with the actual APSR position, could be calculated. Within 10 minutes, the reactor engineer had calculated a more accurate ECP using actual APSR positions. The new ECP calculation was less than the previous calculation by about four rod position units, which was a negligible difference. ' Operators then proceeded with the startup until the reactor was taken critical.- I
. Operations personnel then submitted PCAQR 98-1464 to document the proble t Followup discussions with reactor engineering and operations personnel determined that startups were always done with the APSRs at 30 percent withdrawn, and so 30 percent was the value that was always input into the ECP calculations. However, station procedures did not require that the APSRs be at 30 percent prior to startup. The preliminary assessment by reactor engineering management was that a combination of a lack of attention to detail of reactor engineering personnel and a lack of procedural requirements were the cause of the event. Reactor engineering management planned to first determine if any other assumptions with the ECP procedures were not being procedurally verified, before proceeding with procedure changes that would prevent recurrences The inspectors reviewed the ECP and approach to criticality procedures and determined that they were adequate to fulfill the requirements of TSs. The inspectors also reviewed documentation of three other reactor startup ECPs. Overall, actual critical rod heights were within a conservative margin of the calculated estimated maximum and minimum critical rod heights. Actual critical APSR positions were consistent with the positions used for the ECP Conclusions The inspectors determined that the actual APSR position (15 percent) did not match the ECP calculated position (30 percent) during a reactor startup. The root cause was that a reactor engheer in the control room exhibited a lack of attention to detail. Additionally,
, the hek of ta procedural requirement to ensure that the actual APSR position matched the ECP position was a weakness. The proposed changes to plant procedures should
. pavent recurrence. The effect of the error had no impact on safet E7 Quality Assurance in Engineering Activities E Station Review Board and Manaaement Review Committee Performance (37551)
The inspectors observed that Station Review Board personnel effectively discussed the adequacy and status of high priority PCAORs97-293 (50.59 Safety Review and Evaluation Concem),97-1255 (Personnel Work on Energized Equipment Near-Miss), and 98-0337 (Inadequate Level of 10 CFR 50.59 Qualifications). Management Review Committee personnel effectively prioritized and assigned PCAQRs for actio !
- _ _ _ _ _ -
-
t E8 Miscellaneous Engineering issues (92903)
E (Closed) Unresolved item (50-346/97006-03(DRP)): Emergency Core Cooling System (ECCS) Leakage Rate Not Performed. This involved the licensee's identification that intemal (i.e., past check valves) gr!d extemal (i.e., past valve packing) leakages from the ECCS were not totaled to determine if radiation doses from the leakages were within USAR limits. The licensee considered only extemal leakages to satisfy the TS 6.8. requirement to conduct integrated leakages from each system. Further review identified that an NRC letter dated May 6,1980, concoming this subject indicated that the measurement of only extemal leakages satisfied TS 6.8.4.a requirements. Therefore, this item is close E (Closed) Unresolved item 50-346/93016-03 (DRS): Seismic Design of the Ultimate Heat Sink (UHS). The containment and emergency core cooling transient analysis was performed utilizing the non-seismic portion of the UHS. This appeared to be in conflic with licensee commitments in the USA By letter dated October 12,1995, Office of Nuclear Reactor Regulations (NRR) requested that the licensee provide information related to this apparent conflict. The licensee responded to that request by letter dated January 31,1996. By letter dated June 10, 1997, as supplemented by letters dated June 17 and October 3,1997, NRR requested that the licensee meet with the staff to discuss details of this issue. This meeting was held on November 13,1997, as documented in the meeting summary dated November 21,1997. Since this issue is being resolved and tracked by NRR, this issue, as a NRC, Region til issue is considered to be close IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls R Radioloalcal Protection Controls (71750)
The inspectors conducted routine tours of the radiologically restricted area and noted individuals using appropriate radiation work practices. Radiation and contamination areas were appropriately posted and rope barriers were installe I R1.2 Condensate Domineralizer Resin Intrusion into Once Throuah Steam Generators inspection Scope (71750)
The inspectors observed station personnel actions to address condensate domineralizer resin intrusion into the steam generators that occurred as a result of the June 24 loss of offsite power event, Observations and Findinas Subsequent to the June 24 reactor trio, secondary system sulfate levels were identified by chemistry personnel to be higher than administrative levels. The reactor startup was delayed as the licensee performed numerous steam generator fill, soak and drains to
I i
l
_____ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ . .
I
- _ _ _ _ _ - _ _ - _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ - _ - - _ _ - . _ -
.
reduce the sulfate levels. Once sulfates were below the administrative level, plant restart activities resumed. However, once 15 percent power was reached on July 1, sulfate levels had again increased. The plant was shut down and steam generator fill, soak, and drains were performed once again. On June 6, the plant was restarted and run at 100 percent power until June 22. The plant was again voluntarily shut down to further reduce the secondary side sulfate levels and on Jurse 26 was retumed to full power. No TS limits exist for sulfate levels in the condensate and feedwater system or for the steam generators. No immediate operability concems existed because of the high sulfate levels in the steam generators. The licensee is conducting a root cause investigation to determine the reason for the resin intrusion into the steam generators which will be reviewed upon its completio Conclusi9D The licensee too4 conservative actions to address the relatively high secondary side sulfate concentra!icos caused by a resin intrusion by voluntarily shutting down the reactor and performing mulVple steam generator fill, soak and drains. The sulfate levels were reduced below administrative levels and the plant was subsequently retumed to full power, i
!
V. Manaaement Meetinas X1 Exit Meeting Summary e
The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on August 7,1998. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
!
.
_
.
PARTIAL LIST OF PERSONS CONTACTED Licensee J. Wood, Vice President J. Lash, Plant Manager L Worley, Director, Nuclear Assurance
- R. Donnellon, Director, Engineering and Services F. Swanger, Manager, Design Basis Engineering J. Michaelis, Manager, Maintenance C. Price, Manager, Business Services
, M. Beier, Manager, Quality Assessment J. Freets, Manager, Regulatory Affairs L. Dohrmann, Manager, Quality Services G. Skeel, Manager, Security A. McAllister, Supervisor, Test / Performance J. Johnson, Supervisor, independent Safety Engineering Group M. Hoffman, Supervisor, Nuclear Training D. Ricci, Supervisor, Operations D. Isherwood, Supervisor, Support Services R. Greer, Supervisor, Supply Chain T. Chambers, Supervisor, Quality Assurance L. Myers, Shift Supervisor R. Coad, Superintendent, Radiation Protection C. Kraemer, Engineer, Regulatory Affairs
<
G. Wolf, Engineer, Licensing, Regulatory Affairs D. Meckfessel,- Quality Services Analyst NRC T. J. Kozak, Chief, Reactor Projects Branch 4 S. J. Campbell, Senior Resident inspector, Davis-Besse K. S. Zellers, Resident inspector, Davis-Besse l
!
L__________________ _ _ _ _ _ _ l
a
..
INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 61726: Surveillance Observations
. IP 62707: Maintenance Observation IP 71707: Plant Operations IP 71750: . Plant Support Activities IP 92903: Followup - Engineering IP 93702: Prompt Onsite Response to Events at Operating Power Reactors ITEMS CLOSED Closed 50-346/97006-03(DRP) URI ECCS Leakage Rate Not Performed 50-346/93016-03(DRS) URI UFSAR apparent discrepancy l
l
!
L__-_________--
_ - _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ - _ _ _ _ _ - - _ - _ - _ _ _ _ _ _ _ _ _ _
LIST OF ACRONYMS AND INITIALISMS USED AFW Auxiliary Feedwater APSR Axial Power Shaping Rod AW Atmospheric Vent Valve 3 BWST Borsted Water Storage Tank j CFR Code of Federal Regulations
"
CREVS Control Room Emergency Ventilation System ECCS Emergency Core Cooling System
~ECP Estimated Critical Position !
EDG Emergency Diesel Generator f ICS Integrated Control System IR Inspection Report MWO Maintenance Work Order NRC Nuclear Regulatory Commission -
NRR Office of Nuclear Reactor Regulations PCAQR Potential Condition Adverse to Quality Report TS- Technical Specification UHS Ultimate Heat Sink
- USAR Updated Safety Analysis Report I
L
-
,
I-
'
i
I
_ _ - - _ _ _ _ _ _ _ _ _ _ _ _ --___ _
j