IR 05000269/1994024
| ML16222A872 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 09/21/1994 |
| From: | Harmon P, Sinkule M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16154A670 | List: |
| References | |
| 50-269-94-24, 50-270-94-24, 50-287-94-24, NUDOCS 9410130198 | |
| Download: ML16222A872 (20) | |
Text
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900 ATLANTA, GEORGIA 30323-0199 Report Nos.:
50-269/94-24, 50-270/94-24 and 50-287/94-24 Licensee:
Duke Power Company 422 South Church Street Charlotte, NC 28242-0001 Docket Nos.:
50-269, 50-270, and 50-287 License Nos.:
DPR-38, DPR-47, and DPR-55 Facility Name:
Oconee Units 1, 2, and 3 Inspection Conducted: July 31 - August 27, 1994 Inspectors:
__/__
P. E. Harmon, Senior Vside Inspector Date Signed W. K. Poertner, Resident Inspector L. A. Keller, Resident Inspector P. G. Humphrey, Resident Inspector
Approved by:
f 1-4 4 2&
e /Z / /f M. V. Sinkule, Chief, Date Signed Reactor Projects Branch 3 SUMMARY Scope:
This routine, resident inspection was conducted in the areas of plant operations, surveillance testing, maintenance activities, and engineering and technical assistanc Results:
During this inspection period, two Deviations were identifie One Deviation involves the Penetration Room Ventilation System not meeting the Design Basis requirements, paragraph 6.a. The other Deviation involves improper piping code classifications in the High Pressure Injection Systems, paragraph A Unit 3 trip occurred which was accompanied by a dryout of one of the steam generators. This event revealed apparent deficiencies in the licensee's Emergency Operating Procedures and is identified as an Unresolved Item, paragraph 2.c. In addition, the licensee's corrective actions to correct a system deficiency in the turbine bypass valves did not appear to be timely or adequate, and contributed to the steam generator dryout. This is also considered an Unresolved Item, paragraph PDR ADOCK 05000269
PDR-
A third Unresolved Item concerns past operability of the Keowee Overhead power path when maintenance personnel disabled an interlock during routine maintenance, paragraph One weakness was identified in the translation of modification information into maintenance activities, paragraph REPORT DETAILS Persons Contacted Licensee Employees
- B. Peele, Station Manager
- E. Burchfield, Regulatory Compliance Manager D. Coyle, Systems Engineering Manager J. Davis, Engineering Manager T. Coutu, Operations Support Manager
- B. Dolan, Safety Assurance Manager W. Foster, Superintendent, Mechanical Maintenance
- J. Hampton, Vice President, Oconee Site D. Hubbard, Component Engineering Manager C. Little, Superintendent, Instrument and Electrical (I&E)
G. Rothenberger, Operations Superintendent R. Sweigart, Work Control Superintendent Other licensee employees contacted included technicians, operators, mechanics, security force members, and staff engineer *Attended exit intervie. Plant Operations (71707) General The inspectors reviewed plant operations throughout the reporting period to verify conformance with regulatory requirements, Technical Specifications (TS), and administrative control Control room logs, shift turnover records, temporary modification log, and equipment removal and restoration records were reviewed routinely. Discussions were conducted with plant operations, maintenance, chemistry, health physics, instrument & electrical (I&E), and engineering personne Activities within the control rooms were monitored on an almost daily basis. Inspections were conducted on day and night shifts, during weekdays and on weekends. Inspectors attended some shift changes to evaluate shift turnover performance. Actions observed were conducted as required by the licensee's Administrative Procedures. The complement of licensed personnel on each shift inspected met or exceeded the requirements of TS. Operators were responsive to plant annunciator alarms and were cognizant of plant condition Plant tours were taken throughout the reporting period on a routine basis. During the plant tours, ongoing activities, housekeeping, security, equipment status, and radiation control practices were observe *
2 Plant Status Unit 1 began the reporting period at approximately 64 percent power for repairs to the lB main feedwater pump. The Unit was returned to 100 percent power on August 1, 199 On August 20, 1994, power was reduced to less than 15 percent power and the turbine generator was taken off-line to repair the generator output motor operated disconnects. The unit was returned to 100 percent power on August 21, 1994. The Unit operated at approximately 100 percent power for the remainder of the reporting perio Unit 2 completed an outage that began on July 27, 1994, to repair a tube leak on the "2A" Steam Generator. The unit was restarted on August 8, 1994, and operated at power for the remainder of the reporting perio Unit 3 began the reporting period at 100 percent power with elevated Reactor Coolant System (RCS) activity. On August 1, 1994, RCS samples indicated that Dose Equivalent Iodine (DEI)
activity had exceeded 0.5 microcuries per milliliter, requiring a power.reduction per the licensee's administrative guidance. Power was subsequently reduced to 90 percent later that day. On August 2, 1994, the licensee determined that the samples indicating DEI in excess of 0.5 were in error, and restored power to 100 percen On August 10, 1994, the unit experienced a reactor trip from 100 percent power (see paragraph 2.c).
On August 11, the unit was restarted. During the subsequent power ascension on August 12, the unit tripped from 42 percent power (see paragraph 2.d).
The unit resumed full power operation on August 14, 1994, and remained at or near full power throughout the remainder of the inspection perio Unit 3 Reactor Trip, Blowdown of 3B Steam Generator, Notification of Unusual Event (NOUE), and Related Issues Background The Integrated Control System (ICS) provides fully automatic control of reactor power, steam generation rate, and generated load by processing selected signals of measured plant parameter The ICS is powered by 125 VAC panel board "KI" which is normally powered from the KI inverter. The KI inverter has two battery backed power supplies and is designed to perform a "bumpless" transfer from the primary DC power supply to the alternate DC power supply via a static transfer switch internal to the inverter. Additionally, there is an "ASCO" transfer switch, immediately downstream of the inverter, which will automatically transfer the power for panel board KI to the AC Regulated Power System. The transfer of power via the ASCO switch takes approximately one half second. This temporary interruption of power results in a false high steam generator level signal and a
- subsequent trip of both main feedwater pumps. This in turn results in an anticipatory reactor trip. Additionally, the temporary loss of power to the KI panel board results in some of the ICS automatic functions transferring to manual contro There are two turbine bypass valves (TBVs) on each steam heade One of the functions of the TBVs is pressure control following a reactor trip. The TBVs are normally controlled by their associated control room Bailey station. If the station is in manual the operator controls TBV position via the Bailey toggle switch. In AUTO their position is controlled by the setpoint bias. Setpoint bias is established by the operator with the bias control knob on the Bailey station. Following a reactor trip, with the TBVs in AUTO, the setpoint bias will automatically shift to setpoint plus 125 psig. This limits the cooldown of the RCS following a reactor trip. When the KI panel board loses power the TBVs shift to manual control and fully close. When power is restored, the TBVs randomly reposition due to the random output voltage produced by the Static Analog Memories (SAM) modules which are internal to the TBV control circuitr August 10 Unit 3 Trip and Related Issues At 4:25 a.m., on August 10, 1994, Unit 3 experienced a reactor trip from 100 percent power. The cause of the trip was the loss of both main feedwater (MFW) pumps. The automatic trip of both main feedwater pumps occurred as required when the associated Integrated Control System (ICS) temporarily lost power (less than 1 second). The temporary loss of ICS power occurred when fuses internal to the 3KI inverter blew. Power to the ICS was restored when the "ASCO" transfer switch, immediately downstream of the inverter, automatically transferred to the alternate power source (AC Regulated Power System). When the ICS was repowered, the TBVs went to manual and randomly positioned at 22% open for the steam generator 3B valves and 11% open for the steam generator 3A valves. The operators did not immediately recognize the temporary loss of panel board KI, or the status of the TBVs. Due to the subsequent divergence of steam generator pressures (i.e., steam generator 3B at 600 psig and steam generator 3A at 800 psig) and RCS cooldown, a steam leak was suspecte This prompted the isolation of the 3B steam generator, which was completed at 4:27 a.m., with the 3B steam generator pressure at 550 psig. A NOUE was made at 4:57 a.m., due to the secondary side depressurization, which required entry into the "Excessive Heat Transfer" section of the Emergency Operating Procedures (EOP).
The lowest post-trip RCS temperature was 524 degrees fahrenhei The lowest pressurizer level was 35 inches. After the isolation of the 38 steam generator, RCS average temperature (Tave) was maintained at approximately 538 degrees fahrenheit with the 3A Motor Driven Emergency Feedwater (MDEFW) pump and the Turbine Driven Emergency Feedwater (TDEFW) pump feeding the 3A steam
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generator. Additionally, a small amount of emergency feedwater was leaking past isolation valve FDW-316 into the 3B steam generator. This leakage was not enough to establish any level in the 3B steam generator, but did maintain steam generator pressure at approximately 800 psig on 3B (saturation pressure for water at 538 degrees fahrenheit is 946.88 psia).
The steam generator pressure readings indicated that the 3B steam generator was dry with only a steam atmosphere. The leakage into the 3B steam generator only became apparent much later (7:51 a.m.), after the TDEFW pump was secured and the 3B steam generator pressure began to decreas With the primary plant stable, and the 3B steam generator maintaining approximately 800 psig, the operators elected to maintain the 38 steam generator isolated until after shift turnover (6:30 a.m.).
This was due in part to the perceived risk of feeding this essentially dry steam generator with relatively cold emergency feedwater. Prior to the trip, there was relatively high RCS activity (DEI = 0.25 microcuries per milliliter).
After the trip, DEI spiked at 5.56 microcuries per milliliter. Cooling down and depressurizing the RCS in order to minimize the risk of a steam generator tube leak was not considered necessary by the license Although there was guidance in the licensee's EOP for recovering a hot/dry steam generator, due to the amount of time the SG had been isolated, the licensee contacted the steam generator vendor (Babcock & Wilcox) to consult over concerns of possible thermal shock to the tube sheet region upon initiation of feedwater. B&W indicated that there were no additional concerns associated with recovering the SG and that they should follow their existing EOP guidance. At approximately 7:51 a.m., the TDEFW pump was secured which caused the 3B steam generator pressure to slowly decreas After the 3B steam generator pressure began decreasing, the differential temperature between the steam generator shell and tubes began to increase. As the licensee prepared to recover the 3B steam generator they became aware that there was a limit of 60 degrees for the differential temperature (tubes hotter than the shell) listed in the Babcock & Wilcox Technical Basis Documen (Note: This was not discussed during the phone conversation mentioned above.)
At 11:33 a.m., the 3B MDEFW pump was restarted, which due to the leakage past 3FDW-316, allowed some recovery of pressure (and differential temperature) in the 3B SG. At approximately 11:50 a.m., MFW pump B was restarted and used to feed SG 3A. At 12:02 p.m., a combination of MFW and EFW was used to feed SG 38 through the auxiliary feedwater ring. At approximately 1:00 p.m., the level and pressure in steam generator 3B were recovered. At 1:37 p.m., on August 10, 1994, the licensee exited the NOUE and remained in hot shutdown to conduct their post trip review. The inspectors responded to the plant shortly after the trip and observed all control room activities until the licensee exited from the NOU As stated above, when the licensee began preparations to recover the 3B SG, they became aware of the B&W limit for differential temperature between the tubes and shel This limit was established by the vendor to minimize compressive stresses on the SG tubes. The licensee had not incorporated this generic guidance into their procedures/training. Consequently the operations staff was initially unaware of this limit and eventually exceeded the limit by 22 degrees fahrenheit. While discussing the particulars on how to re-establish feedwater to the 3B SG, a licensee employee recalled that there was a limit for tube/shell differential temperature. The inspectors determined that absent this recollection (which was not part of any formal training) there was no formal mechanism (i.e., alarms/procedural guidance) to alert the operators to this limit. Therefore, it was somewhat fortuitous that the limit was not exceeded by more than 22 degrees. The inspectors concluded that the maximum SG tube/shell differential temperature was an important limit that should not have been exceeded. As of the end of the inspection period the licensee was still evaluating the adequacy of their EOPs for this event. This item is identified as Unresolved Item (URI)
269,270,287/94-24-01: Compressive Limit for Steam Generator Differential Temperature Exceede B&W Nuclear Technologies (BWNT) performed an evaluation of the transient data to assess the status of the 3B SG as a result of exceeding this limit. This data included the 5 shell thermocouple data points, 3B steam generator pressure, and RCS temperature and pressure, over the time period of concern. BWNT compared the Unit 3 data to data from previously analyzed transients and to the Steam Generator Functional Specification. Based on this evaluation, BWNT informed the licensee that the transient did not adversely affect the steam generato The fact that the TBVs randomly reposition after power restoration was known by the licensee since at least 1986. Following the Rancho Seco event of December 1985, the licensee evaluated the effects of a restoration of ICS/non-nuclear instrumentation (NNI)
power per the B&W Owners Group recommendation TR-032-ICS. As part of this evaluation, the licensee recognized that following a-loss of power to the TBVs, the TBVs would randomly reposition when power was restored. This was due to the Static Analog Memory (SAM) modules, internal to the TBV control circuitry, producing a random output voltage upon power restoration. This output voltage is translated into TBV position demand (0-100%). The licensee subsequently evaluated the feasibility of replacing or modifying the SAM modules in order to eliminate the random repositionin However, due to monetary controls and high backlog of proposed modifications at the time, the licensee did not feel that modifying the TBVs was cost effective. On April 29, 1993, a momentary loss of Unit 2 KI power was experienced. During the unit recovery, the control room operators observed that the TBVs were in manual and partially open, which resulted in some minor
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overcooling of the RCS. In the Licensee Event Report (LER 270/93 01) for this event, the licensee stated that the overcooling could have placed the unit in a less than adequate shutdown margin position if the operators had not taken prompt action to close the TBVs. In the Corrective Actions section of the LER, the licensee committed to "evaluate the Integrated Control System to enhance the Turbine Bypass Valve control circuitry".
This evaluation was completed on November 15, 1993. The evaluation concluded that new SAM modules that were not subject to random output voltages on restoration of power should be installed. The modification to install the new SAM modules was prepared on June 30, 199 Following the August 10, 1994 event, the licensee installed these new modules on all three units (work was completed on August 13, 1994).
The inspectors questioned whether the licensee had ever incorporated any procedural guidance to specifically check the status of the TBVs immediately following a reactor trip. The licensee responded that the only procedural guidance was the Loss of KI Abnormal Procedure. The inspectors noted that by the time the operators would reference the guidance in this procedure, one or both steam generators could be blown dry. The lack of adequate procedural guidance, or other corrective actions, from June, 1986 until August 13, 1994, is identified as URI 269,270,287/94-24-02:
Corrective Actions Associated With Turbine Bypass Valves Randomly Repositionin The KI inverter failure which ultimately caused the event was another in a series of inverter failures resulting in plant transients (for example, refer to LERs 287/92-03 and 270/93-01).
The licensee has had long-standing plans to replace these inverters. The Unit 1 inverters were replaced during the last refueling outage. Unit 2 & 3 inverters are scheduled for replacement during their respective upcoming.outages. The licensee was unable to determine the root cause of the fuse failures in the 3KI inverter associated with this latest even The licensee attempted to run the inverter on a "dummy" load as part of their trouble-shooting efforts, which resulted in the inverter continuing to blow fuses. Due to the unreliability of this inverter the licensee decided to restart the unit with panel board KI being powered from the AC Regulated Power Supply. The inspectors noted that operating under this arrangement resulted in Panel board KI being without a backup power source. Accordingly, the inspectors verified that the licensee had a procedure for the complete loss of K Unit 3 Reactor Trip from 42 Percent Power On August 12, 1994, Unit 3 experienced a reactor trip from 42 percent power. The cause of the trip was low pressure in the hydraulic oil system on the only operating main feed pump (3B MFW pump).
Emergency feedwater actuated and performed as expecte I7 All post trip responses were normal with the exception of the pressurizer spray valve control switching to manua The pressurizer spray valve shifted to manual due to the voltage transient on the AC Regulated Power System associated with the quick bus transfer following the reactor trip. The pressurizer spray valve controller is normally powered from the KI inverter (via panel board KI), and therefore not susceptible to the voltage transients associated with a reactor trip. However, due to the problems associated with the KI inverter on August 10, 1994 (see paragraph 2.c above), the unit was started up with panel board KI being supplied from the AC Regulated Power Syste The cause of the low hydraulic oil pressure in the 3B MFW pump was determined to be a failed gasket in the hydraulic system which allowed hydraulic pressure to bypass the emergency governor lockout valve and return directly to the sump. The pressure eventually dropped to the actuation setpoint of the pressure switches associated with the Reactor Protection System. The 3B MFW pump operated as expected following replacement of the subject gasket. The licensee indicated that this gasket would be replaced on the other five pumps during the upcoming refueling outage The inspectors responded to the site immediately following the trip. All activities observed were satisfactory. The post trip recovery and equipment response was fairly routine with the exception of the pressurizer spray valv Within the areas reviewed, two unresolved items were identifie.
Maintenance and Surveillance Testing (62703 and 61726)
Maintenance activities were observed and/or reviewed during the reporting period to verify that work was performed by qualified personnel and that approved procedures adequately described work that was not within the skill of the craft. Activities, procedures and work orders (WO) were examined to verify that proper authorization and clearance to begin work was given, cleanliness was maintained, exposure was controlled, equipment was properly returned to service, and Limiting Conditions for Operation were met. The following maintenance activities were observed or reviewed in whole or in part:
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Nuclear Safety Modification NSM 12881 (Work Order 94009533)
During the reporting period, the inspectors reviewed activities in progress associated with the replacement of the Unit 1 battery chargers and inverters. The modification was implemented in 4 part Part A (Replacement Of The Vital Inverters) and B (Replacement Of The Essential Inverters) were done during the Unit 1 outage. Part C (Replacement Of The Vital Battery Chargers) and D (Replacement Of The Non-QA Battery Chargers) were being implemented after the refueling outage with the unit operating at
power. In addition to the above, the modification involved several breaker and electrical cable changes and replacement On August 16, 1994, the inspector reviewed the installation of a 12-inch cable tray for cables associated with the IPA, 1PB, and 1PS Battery Chargers. The work effort was performed per Work Order Task 94009533 0 It included the addition of a cable tray hanger. The hanger was installed per Maintenance Procedure MP/0/A/3019/004, Hanger-Pipe-Removal, Installation, or Modificatio The replacement of the Non-QA battery chargers and associated electrical cables was reviewed on August 17, 1994. This effort was performed per Work Order Task 94009533 0 During this review, the inspector determined that the work effort had been properly authorized and the activities had been documented as require Perform Mechanical/Electrical Preventative Maintenance On 1SD-285 Operator (Work Order 94057053)
Activities were reviewed by the inspector during the performance of preventative maintenance activities associated with Unit 1, valve SD-285. The effort was authorized per Work Order Task 94057053 01, and was performed in accordance with procedure, IP/0/A/300/001, Limitorque Electrical Preventative Maintenanc The inspectors determined that documentation was completed for each step performed and the equipment was maintained to an acceptable cleanliness standar Preventative Maintenance NI-3 Intermediate Range Instrument Calibration (Work Order 94033628)
On August 18, 1994, the inspector reviewed the calibration of Nuclear Instrument NI-3 while in progress. The work effort was being performed per Instrument Procedure IP/0/A/0301/003C-1, NI-3 Neutron Flux Instrument Calibration, which was required to be performed on an annual basis to satisfy a Technical Specification requirement. The activity was authorized per Work Order Task 94033628 0 The inspector verified that the technicians were following the procedure and had properly documented each step performe However, the procedure had three changes incorporated and had not been revised. The changes were extensive and resulted in a difficult procedure to follo Repair 1PR-115 to Ensure Proper Operation (Work Order 94056331)
On August 25, 1994, the inspectors observed work in progress associated with the repair of 1PR-115. This valve is a damper valve in the suction line to the 1A penetration room ventilation (PRV) charcoal filter. Operating as a check valve, the purpose of 1PR-115 is to prevent water intrusion into the charcoal filter due to convective flow of moist air from the penetration room when the PRV system is not operating. Repairs were necessary, because the valve was not closing properly after operation of the PRV fa The inspectors' work observation included a review of the associated work package, as well as verification that adequate isolation and testing was accomplished. No discrepancies were note Perform Minor Modification OE-6715 (Work Order 94050400)
This modification replaced the Static Analog Memory modules in the circuitry that controls the TBVs. This modification was necessary due to the TBVs randomly repositioning after power restoration (see paragraph 2.c).
All activities observed were satisfactor Surveillance activities were conducted with approved procedures and in accordance with site directives. The inspectors reviewed surveillance performance as well as system alignments and restorations. The inspector assessed the licensee's disposition of discrepancies which were identified during the surveillance. The following surveillance activities were observed or reviewed in whole or in part:
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Penetration Room Ventilation System Power Supply Failure Vacuum Test (TT/1/A/0110/005)
This test was conducted to determine whether the PRV system could maintain a vacuum relative to the surrounding auxiliary building under certain power supply failures (i.e., Main Feeder Bus TC or TD).
The inspector observed the test conducted for Unit 1 on August 8, 1994. The penetration room pressure was lower than all the auxiliary building rooms under all scenarios tested. This demonstrated acceptable performance for the Unit 1 PRV syste All activities observed were satisfactor ICS / Integrated Master Control Turbine Bypass Valve Control (IP/0/B/0322/003)
This procedure is for calibration of Integrated Master Control and Turbine Bypass Valve (TBV) control instrument components. This test was conducted in Unit 3 on August 13, 1994, after the installation of new Static Analog Memory (SAM) modules. The SAM modules were replaced due to their randomly repositioning the TBVs
after restoration of power (see paragraph 2.c).
All activities observed were satisfactor Motor Driven Emergency Feedwater Pump Test (PT/2/A/0600/13A)
The inspectors reviewed the surveillance activities performed on the 2A motor driven emergency feedwater pump. The test procedure operates the pump for greater than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> in recirculation to the upper surge tank, verifies that the pump meets the requirements of ASME Section XI, and verifies proper operation of valves FDW-313, FDW-314, FDW-372, and FDW-374. All activities observed were satisfactory and all test acceptance criteria were verified to have been me Penetration Room Ventilation System Monthly Test (PT/1/A/0170/05)
The inspectors reviewed the surveillance activities performed on the lB penetration room ventilation system. The test procedure initiates flow through the charcoal filter and verifies proper operation of the system. The test was performed due to maintenance activities being performed on the 1A penetration room ventilation syste The inspectors reviewed the procedure and monitored test activities in progress. The inspectors noted that the flow rate achieved was higher than previous tests performed, but still within the acceptable band. Subsequent investigation by the licensee determined that the crossconnect valve between the two trains was leaking by the seat and that isolation of the "A" train increased indicated flow in the "B" train due to the location of the flow instruments. The crossconnect valve was subsequently repaire Within the areas reviewed, licensee activities were satisfactor.
Onsite Engineering (37551)
During the inspection period, the inspectors assessed the effectiveness of the onsite design and engineering processes by reviewing engineering evaluations, operability determinations, modification packages and other areas involving the Engineering Departmen On August 1, 1994, the licensee determined that a failure may have occurred to declare a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Limiting Condition of Operation (LCO) on the Keowee overhead emergency power path during annual preventative maintenance on the Keowee underground Air Circuit Breakers (ACBs). This condition was identified during a review/rewrite of Maintenance Procedure MP/O/A/2001/2, Inspection and Maintenance of Keowee ACBs and Associated Disconnects and Bu In 1991, the licensee modified the underground breaker circuitry to allow closure of the Keowee overhead ACB if the underground ACB
disconnect switch was opened. Prior to the modification, the overhead breaker would only close on an emergency start if the underground breaker was open. The modification allowed the overhead emergency power path to remain operable if the underground breaker was closed, but the disconnect ope The licensee's procedure review identified that during breaker maintenance, the circuitry modified to allow operation of the overhead power path with the underground breaker closed for maintenance activities was defeated during the maintenance to prevent personnel injury from a remote close operation. This condition had not been recognized previously and made the overhead power path inoperable when the associated underground breaker was close Technical Specification (TS) 3.7.2 allows one of the two emergency power paths to be inoperable for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> provided the alternate power path is verified operable within one hour and every eight hours thereafte The licensee reviewed previous maintenance activities conducted on the underground breakers and determined that since 1989, maintenance activities had been completed within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> except for one occasio The maintenance activity lasting greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> resulted from spare part availability problems and the associated underground breaker had been opened while parts were obtained. Based on this review the licensee determined that the overhead emergency power path had been operable during maintenance activities conducted on the underground breaker The inspectors questioned the adequacy of the evaluation performed to determine past operability of the overhead power path. The TS requires that the alternate power path be verified operable within one hour and every eight hours thereafter if one of the two emergency power paths are inoperable. The licensee's operability evaluation did not address whether the associated underground breaker had been closed longer than one hour during the maintenance activities reviewed. The licensee stated that the operability evaluation would be revised to address the inspectors concerns. Pending completion of the licensee's operability evaluation, this item is identified as URI 269,270,287/94-24-03:
Past Operability of the Keowee Overhead Emergency Power Path During Maintenance Activities on the Associated Underground Feeder Breake The inspectors consider the failure to properly translate the modification completed in 1991 into maintenance requirements, and the failure to identify that the maintenance activity made the overhead power path inoperable if the associated underground breaker was closed, a weakness in the licensee's maintenance progra No violations or deviations were identifie *
12 Plant Support (71750)
The inspectors assessed selected activities of licensee programs to ensure conformance with facility policies and regulatory requirement During the inspection period, the following areas were reviewed: Plant Operations Review Committee (PORC) Meeting During the inspection period, the licensee implemented the PORC process at Oconee. The inspectors attended several meetings to assess the new process. The PORC process was mandated for all three Duke Power sites by corporate management, with implementation in August 1994. The inspectors concluded that the process was adequately managed and focused on the appropriate safety issue One PORC meeting on August 23, 1994, was especially successful in determining the appropriate actions to be taken to arrange an insulator surveillance. High tension line insulators had previously been identified by type and vendor to have defects in the epoxy used in manufacturing. The original plan for inspecting the insulators at Oconee would have required deenergizing and taking out of service all three units' startup transformers at the same time. PORC members were very resistant to taking the startup transformers out of service while operating at full power. This arrangement would result in natural circulation following a trip, because the Reactor Coolant Pumps would not be able to transfer to their alternate source (i.e., the startup transformer). The PORC recommended an alternative plan which would perform the insulator inspections for each unit during scheduled refueling outage While this plan will result in a longer time to conclude and some additional equipment and maintenance costs to implement, plant safety will be enhanced. The inspector concluded that this PORC session made conservative, safety-conscious decisions in this matte Fire Protection During routine tours, the inspectors reviewed the housekeeping and fire extinguisher throughout the plant. Housekeeping was maintained to acceptable standards and it was noted for the extinguisher observed, that the licensee had inspected each within the previous 30 days. One section of fire protection was taken out of service for hydrant repair and compensatory measures were implemented during that outag No violations or deviations were identifie II
13 Inspection of Open Items The following open items were reviewed using licensee reports, inspection record review, and discussions with licensee personnel, as appropriate: (Closed) Unresolved Item 269,270,287/94-22-02: Design Basis Requirements for the Penetration Room Ventilation System Testing conducted during 1992 revealed that penetration room ventilation system (PRVS) and control room ventilation system (CRVS) operability could be affected by Auxiliary Building ventilation system (ABVS) air handling unit/fan combination This was because these combinations could result in Auxiliary Building rooms adjacent to the penetration rooms being at a lower pressure than the penetration rooms. The Design Basis Specification for the PRVS stated that during operation, the system would establish and maintain a negative pressure in the penetration room with respect to the surrounding areas (outside atmosphere and Auxiliary Building).
Since the testing conducted in 1992 demonstrated that the PRVS could not maintain a negative pressure with respect to the Auxiliary Building with a non-safety ABVS fan or AHU inoperable, the licensee entered the LCO for TS 3.15.1a (PRVS operability)
whenever certain ABVS equipment was inoperable. As a result of this apparent reliance on non-safety equipment, the inspectors questioned the licensee on how they met their design basis for the safety-related PRVS. In response, the licensee stated that the Design Basis Document was in error in stating that the PRVS had to maintain a negative pressure with respect to the Auxiliary Building, and that their previous entries into TS 3.15.1a due to inoperable ABVS equipment were conservative. The licensee's basis for this position were several statements in the Final Safety Analysis Report (FSAR) which read as follows:
"The RB penetration room is maintained at a negative pressure of greater than 0.06 inches water with respect to the outside atmosphere when the penetration room fans are in operation". (FSAR Section 6.5.1.3)
"If during operation the leakage increases causing a decrease in negative pressure below 0.06 inches water with respect to the outside atmosphere,...".
(FSAR Section 9.4.7.2)
The inspector agreed that these statements did not specifically address the required penetration room pressure relative to the Auxiliary Building. However, the inspector did not agree with the licensee that these statements encapsulated the design basis requirements for the PRVS. The inspector noted that these FSAR statements had recently been amended and that the previous
versions did not have the phrase "with respect to the outside atmosphere".
Furthermore, Section 6.2.4.2 of the FSAR (also page 5-46 of the original SAR) stated:
"All penetrations except the following are grouped within or vented to the penetration room. Any leakage that might occur from these penetrations will be collected and discharged through high efficiency particulate air (HEPA)
filters and charcoal filters to the unit vent as described in Section 6.5.... In this manner, leakage which might occur from these penetrations will be isolated from leakage which might occur through the Reactor Building itself".
Additionally, page 14-63 of the SAR states:
"It is assumed that 50 percent of the RB leakage will go into the penetration rooms which will be maintained at a negative pressure as described in 6.5. The atmosphere in these rooms is discharged through charcoal filters to the unit vent. The charcoal filters are assumed to be 90 percent efficient for iodine remova The remaining 50 percent of the RB leakage is assumed to escape directly to the atmosphere. By this method a maximum of 55 percent of the iodine released from the RB is ultimately released to the atmosphere".
The inspectors concluded from these statements, as well as corresponding statements in the Safety Evaluation Report, that the licensing basis assumes all leakage into the penetration room would get filtered prior to release, and that there was no provision for any leakage short-circuiting the PRVS via leakage into the Auxiliary Building. The inspectors determined that the only means for ensuring all leakage into the penetration room gets filtered is to either have the penetration rooms air tight, or at a negative pressure with respect to its surroundings (i.e., both the atmosphere and Auxiliary Building) during the accident. The licensee agreed that they were not in complete agreement with the FSAR, but felt that any leakage from the penetration rooms into the auxiliary building would be minor, and therefore this issue had minor safety significance. This matter is identified as Deviation (DEV) 50-269,270,287/94-24-04: Design Basis Requirements for the Penetration Room Ventilation Syste (Closed) Unresolved Item 269,270,287/91-03-01: High Pressure Injection Piggyback Issues This item involved several issues associated with operation of the low pressure injection (LPI) and high pressure injection (HPI)
systems in the piggyback mode of operation. The first item involved the potential overflow/overpressurization of the letdown storage tank (LDST) during the piggyback mode of operation. The licensee revised the emergency operating procedures to open the
- letdown line to LPI pump suction isolation valve HP-363 to prevent overpressurizing the LDST. The piping downstream of the HPI mini flow recirculation isolation valves up to HP-363 is Class III (Duke Class "C") piping. When initially identified, the inspectors questioned the acceptability of this piping classification since containment sump water would be flowing through the piping in the piggyback mode of operation. The HPI design bases document (DBD) stated that piping that could transport containment sump water is required to be Duke Class "B" (Class II).
The licensee stated that the DBD was in error and would be revised. The inspectors had also questioned the potential single failure vulnerability associated with valve HP 363 and the appropriateness of allowing containment sump water to be transported throughout the non-safety portions of the HPI system with respect to radiation levels in the Auxiliary Buildin Inspector followup on this Unresolved Item included verification that the licensee revised the inservice test program to include valves HP-363, HPI purification to LPI.suction valve, and HP-78, LDST inlet stop check valve. The inspectors also confirmed that the licensee performed a design study to address radiation levels in the Auxiliary Building. The design study concluded that flushing of the recirculation lines would be required for access to the post accident liquid sampling valve pane In addition to the above, the inspectors reviewed the HPI design bases document and determined that the DBD still indicated that HPI recirculation piping should be Class II (Duke Class "B").
From a review of the Oconee Final Safety Analysis Report (FSAR),
it was determined that Chapter 3, Design of Structures, Components, Equipment and Systems, Section 3.2.2.1, System Classification, states:
"Class II systems, or portions of systems, are those whose loss or failure could cause a hazard to plant personnel, but would represent no hazard to the public. Class II systems normally contain radioactive fluid whose temperature is above 212 degrees F, and in addition those portions of Engineered Safeguards Systems which may see recirculated Reactor Building sump water following a LOCA."
Following a small break LOCA and subsequent depletion of the borated water storage tank (BWST), the LPI system is aligned to the Reactor Building sump and the LPI system is then aligned to the suction of the HPI pumps to provide a suction source to the HPI pumps and valve HP-363 is opened to prevent overpressurization of the LDST. In this mode of operation, the HPI piping downstream of the HPI mini-flow recirculation isolation valves will see recirculated Reactor Building sump water. The failure to meet the code class requirements contained in the FSAR with respect to the HPI piping downstream of the HPI mini-flow isolation valves is
identified as DEV 269,270,287/94-24-05:
Improper Code Classificatio The second item addressed in the Unresolved Item concerned the adequacy of the licensee's ECCS flow instrumentation. The flow instruments were air operated, non-seismically qualified, and did not meet single failure criteria. The licensee's position was that these instruments fell under Regulatory Guide 1.97 commitments and would be replaced per the previous commitments made to the NRC. This item was discussed with the Office of Nuclear Reactor Regulation and found acceptable. The licensee has replaced the ECCS flow instruments with qualified flow instrumentatio (Closed) Unresolved Item 269,270,287/92-08-02: Operability of the Low Pressure Service Water System This item identified that nonsafety-related portions of the Low Pressure Service Water (LPSW) system were not seismically qualified, that the isolation valves did not automatically isolate that portion of the system, and that the isolation valves were not powered from safety-related power supplies. Based on the identified concerns, the valves were provided a safety-related power supply and their controllers were moved closer to the control roo This matter was subsequently reviewed in depth during the NRC service water inspection conducted November 1 through December 14, 1993, and resulted in the identification of URI 269,270,287/93-25-02 concerning the single failure vulnerability of the system. Accordingly, URI 92-08-02 is considered closed, as the remaining issues will be followed up under the service water inspection findin (Closed) Inspector Followup Item 269,270,287/92-24-06: Net Positive Suction Head Requirements This item identified that under certain design basis conditions the available net positive suction head (NPSH) to the LPSW pumps could be below required NPSH values. The licensee contacted the pump manufacturer and determined that short-term operation for 30 minutes with inadequate NPSH would be acceptabl This issue was reviewed in depth by the NRC service water inspection conducted November 1 through December 14, 1993, and resulted in the identification of Violation 269,270,287/93-25-03A for failing to perform adequate calculations and evaluations to support facility design. Accordingly, URI 92-24-06 is considered close (Closed) Inspector Followup Item 269,270,287/92-24-03: Containment Pressure/Temperature Response
- I17 This item was opened to track the licensee's actions with regard to performing a topical report on containment mass and energy release and containment response methodology. The licensee submitted Topical Report DPC-3003-P, Mass and Energy Release and Containment Response Methodology, to the NRC by letter dated August 11, 1993. The Topical Report is presently under review by the NRC staff. The inspectors note that approval of the Topical Report will require Technical Specification changes with respect to maximum allowable containment pressure during normal operation (1.2 psig vs 1.5 psig) and the containment spray actuation setpoint (10 psig vs 30 psig). Review of Licensee Event Reports (92700)
The below listed Licensee Event Reports (LER) were reviewed to determine if the information provided met NRC requirements. The determination included: adequacy of description, compliance with Technical Specification and regulatory requirements, corrective actions taken, existence of potential generic problems, reporting requirements satisfied, and the relative safety significance of each event. The following LERs are closed: LER 269/92-18, Design Deficiency Results In The Inoperability Of Oconee Emergency Electrical Power Sourc On December 2, 1992, the licensee determined that during emergency conditions, available DC voltage may have been inadequate to close the generator field and field supply breakers for the Keowee Hydro Units and air circuit breakers 5,6,7, and 8. The failure to close would have occurred at reduced DC voltages as a result of inadequate motive force applied to the breakers. The breakers are Westinghouse DB-50 breakers and utilize a closing coil for breaker closure. At reduced voltages the closing coil could have deenergized prior to breaker closure due to less momentum being imparted to the closure mechanism at the reduced voltage Licensee corrective actions included adding a time delay to the breaker circuitry to permit the closing coil to remain energized for a longer period of time to ensure breaker closure with a degraded DC system voltage and completion of the Design Basis Document for the Keowee 125 VDC power syste LER 287 92-04, Control Rod Drop During Troubleshooting Due To Unknown Cause Results In An Automatic Trip During troubleshooting activities on the Unit 3 Rod Control System on September 29, 1992, an unexplained malfunction caused all three regulating rod groups to deenergize and fall into the core. At the time of the event, reactor power was at 73%. Due to the large negative reactivity insertion of the regulating rod groups, reactor power was rapidly reduced, and the Integrated Control
System (ICS) attempted to reduce turbine power to match reactor power. The result was a sizeable power mismatch with reactor power much lower than turbine power. This resulted in decreasing RCS pressure and a reactor trip on Low RCS Pressure at 1800 psi At the time of the trip, 9:16 a.m., reactor power had been reduced to 4%.
At the initiation of the transient, operators observed only a single rod group dropping. Each of the operators insisted that only the group 5 rods had dropped, and several seconds later the Low RCS Pressure trip occurred. The licensee's review of the transient data disputed the single rod group drop scenario. The reactor engineering group concluded that all three regulating rod groups had dropped due to an undetermined cause. Troubleshooting and failure analysis of various components did not reveal a root cause. The licensee concluded that a spurious, non-recurring failure had occurred in the Rod Control System solid state circuitry. As the problem has not recurred, this LER is considered close No violations or deviations were identifie.
Exit Interview The inspection scope and findings were summarized on September 6, 1994, with those persons indicated in paragraph 1 above. The inspectors described the areas inspected and discussed in detail the inspection findings addressed in the summary and listed below. The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspectio Item Number Description/Reference Paragraph 50-269,270,287/94-24-01 URI: Compressive Limit for Steam Generator Differential Temperature Exceeded (paragraph 2.c).
50-269,270,287/94-24-02 URI: Corrective Actions Associated With Turbine Bypass Valves Randomly Repositioning (paragraph 2.c).
50-269,270,287/94-24-03 URI:
Past Operability of the Keowee Overhead Emergency Power Path During Maintenance Activities on the Associated Underground Feeder Breaker (paragraph 4).
50-269,270,287/94-24-04 DEV:
Design Basis Requirements for the Penetration Room Ventilation System (paragraph 6.a).
50-269,270,287/94-24-05 DEV:
Improper Code Classification (Paragraph 6.b).