IR 05000269/1992003
| ML16148A627 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 02/26/1992 |
| From: | Belisle G, Binoy Desai, Harmon P, Poertner W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16148A622 | List: |
| References | |
| 50-269-92-03, 50-269-92-3, 50-270-92-03, 50-270-92-3, 50-287-92-03, 50-287-92-3, NUDOCS 9203180136 | |
| Download: ML16148A627 (17) | |
Text
0-' t;%:UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, Lo ATLANTA, GEORGIA 30323 Report Nos.:
50-269/92-03, 50-270/92-03 and 50-287/92-03 Licensee: Duke Power Company 422 South Church Street Charlotte, NC 28242 License Nos.:
DPR-38, DPR-47, DPR-55, SNM-2503 Facility Name:
Oconee Nuclear Station Inspection Conducted: January
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February 1, 1992 Inspector:
e/
/
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,
P. E. Harmon, Senor es'd t Inspector Date:Signed B. B.,esai side In pe r
Date Signed W. K. Poertner,/ es en s ector DateSigned Approved by:
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G. A.' Belisle, Seic-t o Chief Date Si ned Division of Reactor Projects SUMMARY Scope:
This routine,, announced inspection involved inspection on-site in the areas of operations, surveillance testing, maintenance activities, system walkdown and inspection of open item Results:
Four violations were identified, concerning the failure to follow procedure (paragraph 2.f), an inadequate procedure (paragraph 2.j),
the failure to properly return instrumentation to service following a hydrostatic test (paragraph 4.c) and inadequate control of maintenance activities (paragraph 4.d)*
The inspectors expressed a concern that the licensee's fuse control program may not ensure that the proper fuses are installed in safety related circuits since replacement is based on the type of fuse previously installed and no on any documentation or drawin PDR ADOCK 05000269 G
REPORT DETAILS 1. Persons Contacted Licensee Employees
- H. Barron, Station Manager
- S. Benesole, Safety Review
- D. Coyle, Systems Engineering
- J. Davis, Safety Assurance Manager D. Deatherage, Operation Support Manager B. Dolan, Manager, Mechanical/Nuclear Engineering (Design)
W. Foster, Superintendent, Mechanical Maintenance
- J. Hampton, Vice President, Oconee Site
- 0., Kohler, Regulatory Compliance
- C. Little, Superintendent, Instrument and Electrical (I&E)
- M. Patrick, Regulatory Compliance
- B. Peele, Engineering Manager
- S. Perry, Regulatory Compliance
- G. Rothenberger, Work Control Superintendent
- R. Sweigart, Operations Superintendent Other licensee employees contacted included technicians, operators, mechanics, security force members, and staff engineer NRC Resident Inspectors:
- P Harmon
- W. Poertner
- B. Desai
- Attended exit intervie. Plant Operations (71707)
a. General The inspectors reviewed plant operations throughout the reporting period to. verify conformance with regulatory requirements, Technical Specifications.(TS), and administrative controls. 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 performance personne Activities within the control rooms were monitored on an almost daily basi Inspections were conducted on day and on night shifts, during weekdays and on weekend Some inspections were made during shift change in order to evaluate shift turnover performanc Actions
.2 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 T Operators were responsive to plant. annunciator alarms and were cognizant of plant condition Plant tours were taken throughout the reporting period on a routine basi The areas toured included the following:
Turbine Building Auxiliary Building CCW Intake' Structure Independent.Spent.Fuel Storage Facility Units 1, 2 and 3 Electrical Equipment Rooms Units 1, 2 and 3 Cable Spreading Rooms Units 1, 2.and 3 Penetration Rooms Units 1, 2 and 3 Spent Fuel Pool Rooms Unit 2 Containment Station Yard Zone within the Protected Area Standby Shutdown Facility Keowee Hydro Station During the plant tours, ongoing activities, housekeeping, security, equipment status, and radiation control.practices-were observe Within the areas reviewed, licensee activities were satisfactor b. Plant Statu Unit 1 entered the reporting period operating at 100 percent powe The unit was shutdown to hot shutdown conditions on January 26 due to problems with the reactor coolant makeup pump relief valve (paragraph 2.h).
Unit 1 was returned to power operation on January 2 Unit 2 entered the, reporting period at 96 percent power with Tavg controlling a few degrees below normal.to extend core lif Unit 2 was taken off-line at 2:00 a.m.,
on January 9 for a scheduled refueling outage. The unit remained shutdown in a refueling outage for the. remainder of the report perio Unit 3 entered the reporting period in a shutdown condition with startup activities in progress. The unit had been.in a forced outage since the reactor coolant system leak on November 23, 1991. The unit was declared critical at 2:23 p.m., on January 6. High level limits on the "B" Steam Generator prevented the unit from reaching 100 percent powe On January 14, Unit 3 tripped due to high SG level (paragraph 4.b).
The unit was returned to service at 2:01 a.m.,
on January 1 Power was decreased to 80 percent on
January 17 due to a leak in the 3B1 feedwater heater. On January 23, the unit was returned to 99 percent power following isolation of the 3B1 feedwater heater. The unit operated at this power level for the remainder of the report.perio c. Power Range Detector NI-7 Greater Than Four Percent Non-conservativ On January 7, 1992, with Unit 3 at approximately 90 percent power, the licensee determined that NI-7 was greater than 4 percent non-conservative compared to. thermal power calculation The unit was returning to 100 percent power after a.maintenance outage and was holding at.90 percent power to perform the feedwater venturi fouling coefficient adjustment.. When the fouling coefficient was adjusted, NI-7 indicated greater than 4 percent non-conservativ NI-7 was declared inoperable and its associated reactor protection system (RPS)
channel was tripped as required by the Technical Specifi cation NI-7 was recalibrated and the RPS channel rese The licensee presently plans to change the operating procedures to require that the fouling coefficient be reset to 1 when a unit is shutdown to prevent this event from recurring. Currently the fouling coefficient is only reset to 1 after a refueling outage when preventive maintenance is performed on the feedwater ventur d. Source Range Instruments Failure to Energiz On January 8, 1992, source range instruments NI-1 and NI-2 failed to energize during the Unit 2 shutdown for a refueling outage when reactor power was reduced below 10E-9 amps on the intermediate range nuclear instruments. The source range instrument power supplies were manually reset by the operators and the instruments energized and operated properly. The operators initiated a shift incident repor to document that the source range instruments had not energized and a work request was initiated to determine the caus The source range instruments are automatically deenergized above 10E-9 amps on the intermediate range to protect the neutron detector from saturation and are automatically-energized below 1OE-9 amps when power is reduce No operator action should be required to energize the source range instruments when power is reduced below 1OE-9 amp Reactor protection system (RPS) channels A and C supply power to NI-1 and NI-2 and are designed such that the high voltage output to the source range instruments is turned off above 1OE-9 amps and the power supplies remain energized. Removing the RPS module or removing power to the RPS channel deenergizes the source range power supplies and requires that the power supply module reset switches be depressed to reset the power supplie The licensee determined that AC power to both RPS channels A and C had. been lost during the operating cycle and that the power supplies had not been reset. Channel A had a loss.of power on March 27, 1991, and channel C had a loss of power on November 20, 1991. The licensee'
i presently evaluating actions to prevent this situation from recurring and plans to revise the annunciator procedures to require that the source range instrument power supplies recurring be reset after a loss of power to RPS channel.A or e. Unit 1 Concentrated Boric Acid Storage Tank (CBAST) Level Increas On January 10, 1992, the operators in the Unit 2 control, room commenced to transfer the contents of the Unit 2 CBAST to the spent fuel pool., per Enclosure 3.2.of Operating Procedure OP/1&2/A/1104/06, Spent Fuel Cooling Syste During the transfer, the operators noticed that the Unit 1 CBAST level was increasing and secured the transfer until the cause of the Unit 1 CBAST level increase could be determine The licensee determined that the procedure require personnel to open valve CS-74 (CBAST pumps 1 and 2 discharge crossconnect) but did not require personnel to close or check closed 1CS-70 (Unit 1 CBAST recirculation valve).
The licensee determined that approximately 3000 gallons of water had been transferred to the Unit 1'CBAST. The licensee has revised OP/1&2/A/1104/06 to prevent this event from recurrin f. Standby Bus Aligned to Lee Steam Station Switchyar On January 13, 1992, operators were supporting a performance test of the. undervoltage relays on standby busses 1-and 2, (SBB 1 and 2).
The test, PT/2/A/610/1C, Voltage Sensing Circuits, tests the emergency switching logic for the SBB The test required Operations to align the Lee Gas Turbine to the standby busses to provide voltage on' the busse The Lee gas turbine is an isolated source to the standby busses and is considered a qualified off-site source, while the. Lee steam station supply is not an isolated, qualified vital power suppl The Operations shift decided to align the Lee Steam Station to th standby busses instead of calling Lee Station and have the gas turbine started and aligne The step requiring the gas turbine to be aligned was marked N/A, Not Applicable, since the test would only require a voltage supply and vital or safety equipment would not actually be energized from the standby busse The shift crew did not consider that the Lee Steam Station did not meet. the requirements for an isolated off-site power source. If a degraded voltage had occurred along with a LOCA, Engineered Safeguards equipment would not have been protected and could have faile The shift crew aligned the Lee Steam Station to SBB 1 and 2 at 2:27 p. The shift crew was.subsequently notified by the Operations staff that SBB 1 and 2 operability may have been degraded. The test was terminated, and proper switchyard alignment restored at 3:17 The operations crew did not perform an adequate assessment of the required step. prior to marking the step N/A. As.a result, the intent of the procedure was changed, and a non-qualified power supply was aligned to the standby busse This is a violation of the requirement to follow procedures and will be tracked as Violation 50-269,270,287/92-03-01: Failure to Follow Procedure for Power Al ignment. Unit 2 Spill On January 21, 1992, approximately 800'- 1000 gallons of water was spilled into the low pressure injection pump room when maintenance personnel opened valve 2HP-82 in preparation for repacking the valv Valve 2HP-82 is the letdown storage tank (LDST)
drain to the component drain heade Prior to performing the maintenance, valve 2HP-82 had been red tagged in the closed position as a boundary valve for two block tagouts. The block tagouts isolated the high pressure injection (HPI)
system and the component drain system to allow maintenance activities on the two systems to support the refueling outage schedule.- The red tags were removed from valve 2HP-82 based on the fact that both systems were already isolated and drained, and that the respective block tagout boundaries would be restored prior to clearing either block tagou At the time of the event, valve 2CS-6 in the component drain system was removed for maintenance, and when valve 2HP-82 was opened, the spill occurre The cause of the spill was due to not completely draining the letdown storage tank when the HPI block tagout had been establishe The LDST had been drained using the HPI pump drains and had stopped decreasing.at approximately 30 inches indicated leve The licensee stated that the operators thought that the LDST level indicator was incorrect even though all LDST level indicators indicated 30 inches and the operators had issued the HPI block tagou The licensee initially theorized that the LDST outlet check valve prevented the LDST. from completely drainin However, after questioning by the inspectors, the licensee concluded that the LDST had not been properly vented and the LDST had. hydraulically locked and had not completely drained while draining the system. This spill resulted in the LPI pump room becoming a contaminated are The room will remain contaminated until the completion of the Unit 2 refueling outag h. Unit 1 Shutdown to Repair Reactor Coolant Makeup Pump Relief Valv On January 21, 1992, the safe shutdown facility (SSF) reactor coolant makeup pump (RCMUP)
was declared inoperable, effective January 17, 1992, at 10:00 a.m., due to the pump tripping for no apparent reason during surveillance testing to meet the requirements of Section XI of the ASME cod The pump had been tested January 17 but had stopped
during the performance of the surveillance procedure. The pump was restarted and ran for approximately 45 minutes to complete the surveillance.. No reason for the pump stopping was determined and no automatic trip signals were noted. When the test data was reviewed by the: responsible engineer it was decided to perform the surveillance procedure agai The decision to retest the pump was based on the fact that the pump vibration data was suspiciously low compared to normal readings. The pump was retested on January 21 and again stopped during the surveillance tes The pump was declared inoperable and an investigation was initiated to determine the cause of the pump stopping during the performance tes The licensee initially believed that the pump stopped due to problems in the pump start circuitry -that are bypassed during an emergency start signa On January 23 the pump was retested and the automatic trip signals were jumpered out while the pump was running and selectively removed to try to determine what signal was causing the pump to sto When the jumper was removed from the valve position interlocks, the pump subsequently received a.trip signal and stoppe The licensee informed the inspectors that the problem was in the test circuit and that a valve limit switch connection had to be the proble The engineer conducting the trouble shooting efforts went home' and while at home remembered that pump flow and discharge pressure had decreased earlier in the troubleshooting process when all the trip signals were jumpered and that the low flow trip signal had not been jumpered when the valve position interlock jumper ha been removed and the pump had stoppe The pump.was retested on January 23 and it was determined that the pump was tripping due.to the low flow interlock which is not removed from the start circuitry on an emergency start. *The licensee determined that the pump relief valve was lifting intermittently while the pump was runnin This caused a low flow indication which stopped the pum The pump discharge pressure during the test was approximately 2420 - 2450 psig and the relief valve was supposed to relieve at 2500 psi The licensee initiated an endurance run of the pum During this run, the relief valve lifted intermittently, cycled for approximately 20 minutes and then cycled one more time at which time discharge pressure did not return to 2420 - 2450 psig but stabilized at a lower pressure, originally thought to be 2380 psi The pump run was continue No-further cycling of the relief valve was observed because of the lower pump discharge pressure due to leakage across the valve seat estimated to be approximately 0.5 gpm. The licensee evaluated this condition and stated that as long as the pump could deliver greater than 26 gpm at a discharge pressure greater than 2361 psig the system could still perform its intended functio Subsequent to this evaluation, the licensee determined that an error had been made when the pump discharge pressure was recorded. During the extended pump run, the discharge pressure was actually 2350 psig as apposed to the 2380 psig which had been recorded. The discharge pressure signal was taken a.s a voltage reading and then converted to
a pressure readin The person recording the pressure had forgotten to subtract the 0 psig voltage reading from voltage recorde A power reduction to 20 percent power was commenced on January 25 to allow personnel entry into the reactor building basemen The throttle valve in the test flow path was adjusted to determine if discharge pressure could be increased above 2361 psig without the relief valve cyclin The testing was conducted on January 26 and was unsuccessfu The licensee took Unit 1 off-line at 11:40 a.m.,
on January 26 and the unit was in a hot shutdown condition at 3:30 p.m., on January 26 to allow replacing the relief valve. The licensee replaced the relief valve with a different relief valve set to lift at 2790 psig and performed a hydro of. a portion of the system to upgrade the piping and pump to the higher design pressure ratin This modification was scheduled to be accomplished at the next Unit 1 refueling outage and is presently being performed on Unit The unit was returned to service on January 29, 1992, at 1:20. i. Lack *of Coordination Between the Startup and Shutdown Procedure On January 28, 1992, during the startup following the shutdown associated with the SSF as discussed in-paragraph 2.h, RPS channel 'C' tripped on high flux at approximately 4 percent powe The operators in the control room recognized that the RPS high flux trip setpoint had not been reset to 104.75 percent powe Power was reduced by inserting control rods to prevent a reactor trip from occurrin The high flux trip setpoint had been reset from 104.75 percent to 4 percent power during the shutdown as required by OP/3/A/1102/10, Controlling Procedure for Unit Shutdown. The unit was maintained in hot shutdown conditions during activities associated with the SS Following completion of work on the SSF, startup activities were initiated per the Controlling Procedure for Unit Startup, OP/1/A/1102/0 Enclosure 4.2, Unit Startup From 250 Degrees F and 350 psig to Hot Shutdown, of OP/1/A/1102/01, directs resetting the high flux trip setpoint from 4 percent to.104.75 percent powe However, as discussed above, the unit was never brought down to 250 degrees F and 350 psi Therefore, Enclosure 4.2 was never entered and the resetting of the high flux trip setpoint was overlooke In addition, the capability exists to reset the high flux alarm with the newly installed chart recorder being the source of the alarm signa This alarm had not been reset to alarm at a lower power leve The inspectors believe that this problem was caused by inadequate coordination between the shutdown and startup procedures. A somewhat similar event had occurred and is discussed in NRC Inspection Report Nos. 50-269,270,287/91-0 In that particular case, inadequate coordination between the startup and shutdown procedures resulted in mispositioning two low pressure service water valve A violation
for failure to maintain plant configuration control was issue For corrective action in response to the violation.,'the licensee planned to review the -startup and shutdown procedures to identify similar problems by January 1, 1992. However,.the problem with the resetting of the high, flux trip setpoints was not identified. The inspectors believe that a more thorough review is warranted to prevent similar incidents in the futur.
Damaged Fuel Element On January 29, 1992, a control.rod and portions of *a fuel assembly were damaged during preparations for holddown spring replacemen The event occurred in the Units 1 and 2 spent fuel pool and did not result in any radiation releas Unit 2 had been defueled on January 22 and it was determined that fuel assembly 4RW's holddown spring needed.to be replaced due to a crack. Holddown spring replacement requires moving the fuel assembly to a special fuel rack which has a twelve inch stand at the botto This enables the fuel assembly to be elevated, thus allowing access to the top of the. fuel assembly for holddown spring replacemen With the fuel assembly in the.special fuel rack, there is sufficient clearance between the top of the fuel assembly housed in that rack and the bottom 'of the mast that is used to transfer fuel. _However, if the fuel assembly contains a-control component such as a control rod, there is not enough clearance to operate the mast following fuel assembly movemen Performance test procedure, PT/O/A/750/04, is normally used to replace broken upper end fitting holddown springs in fuel assemblie The procedure consists of two enclosure Enclosure 13.1 verifies that the Spent Fuel Pool (SFP) filtered 'exhaust system and radiation ins.trument alarms (RIA) 6 and 41 'are operabl Enclosure 13.2 of PT/O/A/750/04 first requires any component such as a control rod be removed from the fuel assembly, if present, and placed in a special location. The enclosure then directs that the fuel assembly be moved to the special location with the twelve inch platform. The holddown spring is then replaced by the B&W field change authorizatio Following the replacement, the enclosure directs returning the fuel assembly to its original SFP locatio In addition, prior to moving fuel in the SFP, the Reactor Engineering staff prepares Enclosure of.OP/O/A/1503/09,"List of Fuel Assemblies and/or Components, to be Relocated in the Spent Fuel Pool.. This procedure specifies step by step what assembly or component to move and to what locatio On the day of the event, fuel assembly 4RW was in its designated SFP location J-6 On the previous day, Enclosure 4.2 of OP/O/A/1503/09 had been prepared by Reactor Engineerin Step 5 of the enclosure involved moving fuel assembly 4RW from location J-65 to the special elevated rack location 0- Step 6 of the enclosure involved moving
the control rod in fuel assembly 4RW after the fuel assembly had been moved to the special fuel. rac In preparation for the holddown spring replacement, Reactor Engineering decided to stage fuel assembly 4RW and fuel assembly 4RW was moved to the special rack location by the performance of Step 5 of OP/O/A/1503/09 Enclosure During this time, the control rod was present in the fuel assembly, as the step requiring removal of control rod from the fuel assembly was Step 6. After placing fuel assembly 4RW in the special rack, 4RW was disengaged and an attempt was made to move the mast away from that position. While moving the mast, the spent-fuel bridge operator felt vibrations and a change in bridge motio The bridge movement was immediately stopped and. it was determined that the mast had hit the top of the control rod that was present in.fuel assembly 4RW. Further inspection.with underwater video cameras revealed that the top of the control rod had bent, and the mast would not clear the top of the control ro Since holddown spring replacement was not planned until the next day for fuel assembly 4RW, PT/0/A/750/04 which requires moving the component out of the fuel assembly prior to relocating the fuel assembly to the special location, was never use Failure to have adequate guidance or precautions in OP/O/A1503/03 to prevent movement of fuel assemblies containing a control element is considered Violation 269,270,287/92-03-02; Inadequate Fuel Assembly Movement Procedur In addition, the inspectors consider it a weakness that Enclosure to OP/0/A/1503/09 is prepared by a Reactor Engineer without any cross disciplinary or independent revie Following the event, all fuel pins in the fuel assembly were eddy current tested and no defects were identifie The damaged control rod was replaced and the fuel assembly was rebuilt using a different upper end fittin There were no radiological consequences as a result of this even k. Failure of a KeoweewUnit to Start On January 29, 1992, at 9:04 p.m., Keowee Hydro Unit Number 1 failed to star The Keowee operator attempted to start 'the unit and generate power. which would be added 'to the grid per the request of the dispatche The unit attempted to start; however, the field'and field flashing breakers failed to close. The Keowee operator started Keowee Hydro Unit Number'2 successfully and then checkedthe Unit 1 X-coil relays to determine if they were trippe The X-coi'l relays must reset after the breakers are tripped for the field and field flashing breakers to close on subsequent unit start signal The X-coil relays were not tripped and the Keowee operator attempted to start Unit 1 agai The start sequence was successful and the field and field flashing breakers closed as required and the unit paralleled to.the overhead power path as designed at approximately 9:16 The licensee could not determine why Keowee Unit 1 failed to start on the first manual start attemp The licensee believes that the X-coils may not have reset when the unit was shutdown previously and that when Unit 2 was started, the X-coil relays may have been mechanically agitated and rese The licensee had.replaced the X-coil relays with higher quality relays previously due to the relays mechanically binding and not resetting after the breakers were tripped, and have not experienced problems since they were replace The licensee is presently checking the X-coils after the hydro units are shutdown to ensure that the X-coils have reset and are evaluatin the problem to determine corrective action to prevent recurrenc. Unit.2 Midloop Operations (TI 2515/103)
The inspectors reviewed the licensee's actions with regard to reducing RCS level for midloop operations. The licensee's require ments for midloop operations are contained in operating procedure OP/2/A/1103/11, Draining and Nitrogen Purging of the RC System. The procedure requires that the following items be implemented prior to reducing RCS level below 50 inches as indicated on reactor vessel level indicator LT-5:
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- A containment closure survey is performed to identify containment penetrations that would need to be closed in the event of a loss of decay heat removal capability and to ensure that containment closure can be achieved within 2.5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> Two independent RCS-temperature indicators and alarm LT-5 operable and calibrate *Ultrasonic level instrument operabl Two LPI pumps operabl Both main feeder busses are required to be energized and two sources of electrical power are required to be availabl Two means of adding inventory to the RCS are require A review.of maintenance and testing activities to ensure no adverse effects on systems and components required for decay heat remova The inspectors reviewed and witnessed the performance of portions of procedure OP/1A/1103/11. When LT-5 was placed in service it did not agree within 5 inches of pressurizer level as required by the controlling procedur LT-5 and the pressurizer level instrument were calibrated and.LT-5 still did not agree within 5 inche The licensee revised the procedure to increase the allowable level
difference and continued with the drain down procedure. LT-5 agreed within approximately.1 inch of the ultrasonic. level indicator at midloop condition Walkdown of the Unit 3 Reactor Building Spray System (71710)
During this report period, the inspectors walked down the majority of the Unit 3 Reactor Building Spray (RBS)
system outside of containment. This walkdown included verification of system condition and configuration including piping, valves, pumps, instrumentation, motor control centers and the control roo The inspectors also reviewed valve lineup procedure OP/3/A1104/05, Reactor Building Spray., for the current mode of operation. All equipment including valves, switches, and breakers were found to be in their required positio Equipment condition as well as-housekeeping were found to be adequat Two drain valves that did not have identification (ID)
labels were brought to the attention of the operations staff. The staff immediately requested ID tags to be made for these valve Portions of the east penetration room were found to be poorly lit and this was brought to the attention of the staf Two valves, 3LWD-936 and 3LWD-937, were not included in the RBS system valve lineup procedure for the Low Pressure Injection (LPI)
syste These normally closed valves are located on one inch vent lines on the suction side of the RBS pumps and are contained in the flow diagram for the RBS system. The licensee.was informed of this configuration control proble The licensee has initiated a configuration problem report to determine the cause of the omission of these valves from the.valve lineup procedure as well as to incorporate these valves into the RBS valve lineup procedur Only the Unit 3 RBS system has these valves and therefore, Units 1 and 2 are not affecte The inspectors requested that the licensee provide the justification for having valves 3BS-15 and 3BS-20 open in the Engineered Safeguards (ES) mode of alignmen Valves 3BS-15 and 3BS-20 are located on one inch drain lines inside containment. They are left open to prevent inadvertent flow through the RBS nozzles during performance testing of the RBS pumps if leakage.were to occur past valves 3BS-1 and 3BS-During discussion with design engineering staff as well as operations staff, the inspector were informed that these valves have always been left open in the ES alignment and that the RBS system is designed to perform its intended function under the most limiting condition The licensee has agreed to provide the required documentation and design data to show that the inventory loss through valves 3BS-15 and 3BS-20 would not prevent the RBS system from performing its design function This issue is also applicable to Units 1 and The inspectors will review the licehsees documentation upon receip Within the areas reviewed, two violations were identifie.
Surveillance Testing (61726)
Surveillance tests were reviewed by the inspectors to verify procedural and performance adequacy. The completed tests reviewed were examined for necessary test prerequisites, instructions, acceptance criteria, technical content, authorization to begin work, data collection, independent verification where required, handling of deficiencies noted, and review of completed wor The tests witnessed, in whole or in part, were inspected to determine that approved procedures were available, test equipment was calibrated, prerequisites -were. met, tests were conducted according to procedure, test results were acceptable and systems restoration was complete Surveillances reviewed or witnessed in whole or in part:
TT/1/A/251/008 HPI Full Flow Check Valve Tes PT/3/A/115/08 RX Bldg Containment Isolation and Verificatio Within the areas reviewed, licensee activities were satisfactor No violations or deviations were identifie. Maintenance Activities (62703) Maintenance activities were observed and/or reviewed during the reporting period to verify that work was performed by qualified personnel and that approved procedures in use adequately described work that was not within the skill of the trad Activities, procedures, and work requests were examined to verify; proper authorization to begin work, provisions for fire, cleanliness, and-exposure control, proper. return of equipment to service, and that limiting conditions for operation were met.
Maintenance reviewed or witnessed in whole or in part:
WR 91020832 Perform Diagnostic Test on 2HP-2 MP/0/A/1720/010 System/Component Hydrostatic Tes HP-104 Replacemen b. Unit 3 Reactor Trip Due to Personnel Error At 10:01 a.m., on January 14, 1992, Unit 3 experienced a reactor trip from 94 percent power on loss of both Main Feedwater Pumps (MFWP)..
The anticipatory reactor trip upon actuation of, all four Reactor Protection System (RPS)
channels was caused due to high steam generator (SG)
level *and the subsequent trip of both MFWPs.'
The
"3B" SG high level setpoint was reached when Instrument and Electrical (I&E)
personnel erroneously fed a signal into the Integrated Control System (ICS) during troubleshootin Prior to the reactor trip, I&E personnel 'were troubleshooting the ICS delta Tc controller.. Switching from the auto position to the manual position was causing. upsets "in delta Tc contro. During this troubleshooting, an I&E technician. connected test leads to the current jack while the fluke multimeter was set to read voltage. As a result, the delta Tc signal was grounded causing the "B" feedwater demand to increase. The "B" MFWP responded and over fed the "3B" SG causing the level in the."3B" SG to reach the MFWP trip setpoin This caused both MFWPs to trip, and an anticipatory reactor trip. As a result of-both MFWPs tripping, emergency feedwater was auto matically initiate Following the trip, the "A" MFWP was placed back in service with recirculation in automati Problems were encountered with the.MFWP Motor Gear Unit (MGU), causing the "A" MFWP to trip, and consequently emergency feedwater reinitiate The "B" MFWP was placed in service and emergency feedwater was secure The "A" MFWP speed control problems were found to be due to the MGU.lower limit switch being broke The delta Tc analog memory module was found to have an offset with respect to the auto setpoint and the module was replace Besides a few minor problems, the post trip response was.normal. A maintenance incident report (MIR)
documenting this incident was initiated. A Licensee Event Report (LER) will also be issued. The MIR classified the cause of the incident as a failure of the technicians involved to ensure test leads were in the correct set of jacks prior to taking reading As part of the corrective actions, the licensee installed plugs on the current jacks of applicable multimeter This will require a deliberate action by the user of the multimeter to-install test leads in the current jac The resident staff will monitor this issue via LER 287/92-01 that describes the even c. Relief Valve 1HP-104 Replacemen On January 27, while 'Unit 1 was shutdown to resolve problems with the Reactor Coolant Makeup system, valve 1HP-104 was replace In preparation for the required hydrostatic test (hydro)l of the replaced valve and piping, maintenance personnel were directed to isolate and vent certain instruments in the hydro boundary. The instruments were vented by means of loosening test tee connections on 'the instrument Enclosure 13.3 of MP/O/A/1720/010, System/Component Hydrostatic Test, controls the removal, isolation, venting, and restoration of pressure and flow instruments prior to and following a hydr This general procedure allows the work planner to fill in instrument numbers for each separate instrument involve Both performer and independent verifier sign for the removal from service and the return to service of the instrument The removal steps include "Isolation valve closed", and "Test tee cap loosened" sign-off space The return to service section includes instructions to tighten the test tee caps and reopen the isolation valve After the work and hydro were completed, workers were directed to return the instruments to service. A copy of'the procedure was sent to the RIB personnel hatch, but the I&E worker already inside containment decided to not take the instruction sheets inside wit hi Instead, he took in a list of-the three affected instruments on a Component Out Of Normal.Sheet. After realigning the instrument valves,, the I&E workers exited containment and then signed the Enclosure 13.3 sheets as performer and independent verifie The workers later said that they did not realize that the test tee caps had been loosened and therefore had not tightened them. They did not carefully read the. instructions that they signed. They simply signed all the appropriate spaces in the restoration section When the RCMUP system was repressurized, the loosened test tee fittings began leaking, and one cap blew off. The pressurization was stopped and the event was. investigated. All the test tee fittings on the three instruments were found loosene I&E workers have received special instructions regarding taking detailed instructions to the job site because of previous instances of this natur Several options are available for work inside contaminated areas and in containment. These instructions were not followed in this instanc Failure to follow the requirements of MP/O/A/1720/10 to properly return instruments to service is identified as Violation 269/92-03-03:Instrumentation Improperly Returned to Servic d. Uncontrolled Work Activit On January 12, 1992, the inspectors reviewed work activities associated with the performance of WR 91020832 to perform a diagnostic test on valve 2HP-2 This,activity was critical path work for the accomplishment of the high pressure injection (HPI)
full flow check valve tes During the performance of the diagnostic test, a wire was pinched in the. valve operator and resulted in a control power fuse blowing when the valve was operate The maintenance personnel replaced the pinched wire and the blown fuse and notified operations that the valve was operable and could be operated to perform the HPI full flow check valve tes The inspectors reviewed the documentation associated with this work activity to determine how the transition from preventive maintenance to corrective maintenance was accomplished. The inspectors reviewed the work package and -interviewed the technicians and their supervisors that were performing the activit The inspectors determined that the corrective maintenance performed was not documented by the technician The technicians replaced the pinched wire with a wire obtained from the shop area. They did not document the lifting of wires or retermination of wires on the work 'request as required by Maintenance Directive 7.5.3, Work Request Implementatio They did not contact Quality Control as specifically required by the work request if parts were replaced or maintenance performed. The technicians did obtain a replacement fuse from supply. However, when questioned on how the correct fuse. replacement was identified, the inspectors were told that a like for like replacement was obtained.,
The inspectors have questioned the licensee before on how fuses are controlled and were-told that an indepth review was performed to ensure that the proper fu-se was reinstalled when a fuse was replace The inspectors expressed a concern that the licensee's fuse control program may not ensure that the proper fuses are installed in safety related circuits since replacement is based on the type of fuse that was previously installed and not on any documentation or drawin The failure to meet. the requirements of Station Directive 7.5.3 with respect to documenting work activities during the performance of W is identified as Violation. 270/92-03-04: Inadequate Control of Maintenance Activitie Within the areas reviewed, two violations were identifie.
Inspection of Open Items -(92700)(92701)(92702)
The following open items were reviewed using licensee reports, inspection, record review,-and discu.ssions with licensee personnel, as appropriate:
-(Closed) Unresolved item 269,270,287/91-26-03, Unintended Mode Chang The licensee has instituted a Technical Specification interpretation to define refueling shutdown as fuel in the reactor vessel with the vessel head closure bolts less than fully tensioned or with the-head. remove This interpretation resolves the inspectors concerns with respect to when the units are in a refueling outage and the requirements of technical specification 3.8 apply. This item is close. Exit Interview (30703)
The inspection scope and findings were summarized on February 4, 1992, with those persons indicated in paragraph 1 abov The inspectors described the areas inspected and discussed in detail the inspection finding 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 269,270,287/92-03-01 Violation -
Failure to Follow Procedure for Power Alignment (paragraph 2.f.).
269,270,287/92-03-02 Violation -
Inadequate Fuel Movement Procedure (paragraph 2.j.).
269/92-03-03 Violation -
Instrumentation Improperly Returned to Service (paragraph 4.c.).
270/92-03-04-Violation -
Inadequate Control of Maintenance Activities (paragraph 4.d.).