IR 05000458/1986032
| ML20214U822 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 11/26/1986 |
| From: | Chamberlain D, Jaudon J, William Jones NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20214U797 | List: |
| References | |
| 50-458-86-32, IEIN-85-017, IEIN-85-17, NUDOCS 8612090412 | |
| Download: ML20214U822 (11) | |
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APPENDIX E':
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S. NUCLEAR REGULATORY CON!ISSION~
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REGION IV
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NRCInshedtionReport: 50-458/86-32
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Docket: 50-458 (
Licensee Gulf States Utilities Company (CSU)
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P. O. Box 220
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St.'Franciaville, Louisiana 70775
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l Facility Name River Bend Station (R6S)
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Inspection Att River Bond Station, St. Francisv111e, Louisiana
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Inspection Conducted: September 15 through October 31, 1986
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Inspectors:
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D. D.(4hamberlain, Senior Resident Inspector.
-Date (pars. 1, 2, 4, 5, 6, 8 and 9)
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W. B. Jones, Tc 6 dent Inspector D.ite (para. 1, 3, 5, 6, 7 and 8)
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// jd Approved:
_J[Re Jaudon,' Chief. Project Section A Dat'e
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tor p ojects Branch
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Innpection Summary
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Inspection Conducted ScLtenber 15 through Octuber 31,, _1986_,(Repo r t 50-458/86-32)
Arcan_Innpoeted: Routine,unannouncedinspectionoflibenseeactionon previous inspection findings, Licennee Event Reports (LERs), licensee action on IE Noticos, operational safety verification, survelliance witnessing, maintenance witneaning and anfety nystem walkdown, Ronuits: Within the areas inspected, no violationn or deviations woro identifiod.
0612090412 061201 PDR ADOCK 05000458 G
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DETAILS 1.
Persons Contacted Principal Licensee Employees
- W. H. Cahill, Jr., Senior Vice President, River Bend Nuclear Group
- E. M. Cargill, Supervisor, Radiation Programs
- T. C. Crouse, Manager, Quality Assurance (QA)
J. C. Deddens, Vice President, River Bend Nuclear Group R. G. Finkenaur, Electrical Engineer
- P. E. Freehill, Superintendent, Startup and Test A. O. Fredieu, Assistant Supervisor, Operations D. R. Gipson, Assistant Plant Manager, Operations E. R. Grant, Director, Nuclear Licensing B. R. Hall, Assistant Superintendent, Field Quality Control (Stone and Webster)
- J. R. Hamilton, Director, Design Engineering
- R. W. Helmick, Director, Projects
- G. K. Henry, Supervisor, Electrical Engineering
- R. J. King, Supervisor, Licensing
- A. D. Kowalczuk, Assistant Plant Manager, Maintenance
- V. J. Normand, Supervisor, Administrative Services
- T. F. Plunkett, Plant Manager
- R. L. Spence, Resident Quality Control Manager (Stone and Webster)
R. B. Stafford, Director, Operations QA
- K. E. Suhrke, Manager, Projects D. Williamson, Supervisor, Operations The NRC senior resident inspector (SRI) and resident inspector (RI) also interviewed additional licensee personnel during the inspection period.
- Denotes those persons that attended the exit interview conducted on November 14, 1986.
NRC resident inspector (RI), W. B. Jones also attended the exit interview.
2.
_ Licensee Action on Previous Inspection Findings a.
(Closed) Open Item (458/8623-01):
Monitor of licensee actions to reduce the large number of open quality concerns.
Beginning in August 1986, the licensee implemented several actions to reduce the relatively large number of open quality concerns.
Also, the prioritization of quality concerns revealed that a relatively small number of the open concerns were high priority concerns.
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SRI; reviewed the open quality concern status and concluded that the
licensee actions to reduce the number of open quality concerns has besn effective.
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This item is closed.
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3.
Licensee Event Report (LERs) Review m
Ouringithis~ inspection period, the SRI and RI reviewed LERs for compliance-swith re'quirenehts established in 10 CFR 50.73 Licensee Event Report
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System.
Specifically, the LERs were reviewed for accuracy and clarity of the event description, the cause of each component or system failure or personnel error, the failure mode and the effect each component had on plant operation, operator actions that affected the course of the event, and the corrective actions taken to prevent reoccurrence of the event.
The following LERs were reviewed:
.85-012 Problems with Division I Standby Switchgeer
'85-013 Remote Shutdown Panel Power Supply in Main Control Room x 85-014 Low Level in Standby Cooling Tower 85-015 Control Room Ventilation Local Intake Radiation Monitors
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Inoperable s85-017 Shutdown Cooling Suction Valve Isolation 85-021 Automatic Initiation of HPCS System
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,The above listed LERs are closed.
4.
Licensee Action on IE Nbtices (
This area of inspection was' conducted.to review licensee action relative
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to IE Information Notice No. 85-17, "Possible Sticking of ASO Solenoid gValves".
IE. Notice 85-17 was' issued to inform licensses of a potential
.~ problem with ASCOssolenoid valves on main steam isolation valves (MSIVs)
which might preverst the h5IVs from closing.
Supplement 1 of IE N Notice 85-17 was issued to provide followup information regarding the
N reasons for' sticking of the ASCO solenoid valves.
The specific problem
'noted occurred with ASCO Model HTX 8323-20V solenoid valves used at Grand
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Gulf.
ASCO believes that the valve. failures resulted from high
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' temperature sticking of the lower core-to plug nut faces.
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T The licensee evaluation of this problem revealed that the ASCO' solenoids i
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which failed at Grand Gulf were commercial grade products which were not environmentally qualified. The ASCO solenoids (NP-8323-A20E) at River
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Bend Station (RBS) were designed and manufactured for nuclear service and
\\ ave passed General Electric (GE) and ASCO environmental qualification h
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tests. Grand Gulf has since replaced the HTX 8323-20V solenoids with the NN 8323-A20E solenoids used at.RBS as recommended by GE.
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i environmentally qualified solenoid was also included in a control sample placed in test ovens with the solenoid valves that stuck at Grand Gulf.
The environmentally qualified solenoid did not stick under the test conditions which had caused sticking in the other solenoid valves.
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RBS is already equipped with the qualified solenoid valve model the licensee has concluded that this problem is not applicable to RBS.
This IE Notice (85-17) is closed.
5.
Operational Safety Verification The SRI and RI observed operational activities throughout the inspection period and closely monitored operational events. Control Room activities and conduct were observed to be well controlled and efficient.
Proper control room staffing was maintained and access to the control room operational areas was controlled. Operators were questioned regarding lit annunciators and they understood why the annunciators were lit in all cases.
Selected shift turnover meetings were observed and information concerning plant status was being covered in these meetings. A walkdown of the standby service water (SSW) system was conducted and the results are documented in paragraph 8 of this report. The plant was shutdown on October 4,1986,.for a planned outage to remove the main turbine screens and to perform local leak rate testing of selected components. Also during the outage, surveillance testing is being conducted and selected maintenance items are being completed. The plant was still in the outage at the end of this inspection period. Prior to and during the plant outage, several plant tours were conducted. These tours revealed that overall plant cleanliness has deteriorated because of the outage. The SRI discussed this with licensee management and licensee actions to return the plant to pre-outage cleanliness levels following the outage will be monitored by the resident inspectors.
Plant areas not affected by the outage were observed to be at an acceptable cleanliness level.
The resident inspectors also reviewed licensee actions on several operational events and potential problems. The results of reviews of selected items are described below:
a.
Reactor Core Isolation Cooling (RCIC) System Valve Failure - On September 8,1986, the inboard isolation valve 1E51*M0V076, which isolates the 3/4 inch RCIC steam supply warm up line inside the drywell, failed to completely stroke close during isolation time surveillance testing. The licensee's actions to attempt closure of IE51*M0V076 are described in NRC Inspection Report 50-458/86-27, paragraph 7.
In meeting the requirements of Technical Specification (TS) 3.6.4, the licensee closed the outboard RCIC steam supply isolation valve 1E51*M0V064 which also serves as the outboard isolation valve for the RCIC warmup line. This action isolated the steam supply to the RCIC turbine thus making the RCIC system inoperative. With the high pressure core spray operable, the licensee had until September 22, 1986, to either restore the RCIC system to operable status or initiate a reactor shutdown as described in TS 3.7.3.
The licensee was scheduled to begin a planned outage on October 4,1986, which would require placing the reactor in cold
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5 shutdown. Based on this schedule and an analysis, which demonstrated that maintaining RCIC operable would not increase the consequences of an accident, the licensee requested an emergency TS change which would relieve them of the requirements of TS 3.6.4 until October 4, 1986, for 1E51*M0V076. 'This relief was granted on September 19, 1986, and the RCIC system restored to operable status on the same day. The reactor was subsequently shutdown as required by the emergency TS change on October 4, 1986.
Following the reactor shutdown the licensee manually closed 1E51*M0V076 and removed the motor operator for analysis of the failure mode. The RI is continuing to monitor the licensee's actions involving repairs to the motor operator.
No violations or deviations were identified in this inspection area.
b.
High Pressure Core Spray (HPCS) System Level 8 Trip Bypassed - On October 5,1986, with the plant already shutdown for a planned outage, the licensee discovered a condition that would have placed them in a 12-hour shutdown Limiting Condition for Operation (LCO) on September 21, 1986. A reactor vessel water level transmitter for the level 2 high pressure core spray (HPCS) system initiation had drifted high and the licensee took the action. required by TS to place the instrument in the trip condition.
It was not realized at this time that the slave trip unit for.the level 8 HPCS injection valve isolation was rendered inoperable by this action. With a level 8 HPCS trip unit inoperable, TS require the HPCS system to be declared inoperable.. RCIC was inoperable at the time due to a warm up line valve problem. With both HPCS and RCIC inoperable, TS require the plant to be in hot shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The licensee received an emergency TS change which allowed them to declare RCIC operable approximat '! 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br /> after the 12-hour LC0 time clock initiation.
Therefore, the licensee exceeded the 12-hour shutdown LC0 by approximately 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />. Upon discovery of this condition, the licensee immediately notified the NRC and initiated an investigation of the cause and effect of this problem.
The licensee discovered that operations personnel apparently did not have a good understanding of the master trip units / slave trip units interrelationships. This lack of understanding led to the problem identified. The licensee has initiated action to provide personnel instruction and to provide some clear method of identifying which trip units are intertied with slave trip units. The investigation also revealed that although TS would have required HPCS to be administratively declared inoperable, HPCS would have been operable for the intended safety function of initiating under a loss of coolant accident and injecting water into the vessel. With the level 8 slave trip unit inoperable, the HPCS injection valve would not close on high vessel water level but the high level alarm was still available. The operator could have initiated closure of the HPCS injection valve from the main control board to terminate the HPCS injectio _.
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The licensee will document this problem in a. Licensee Event
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Report (LER) and NRC closure of this condition followup will be I
completed during routine LER review.
c.
Elgar Electrical Power Line Conditioners - The licensee has experienced problems with the Elgar Power Line Conditioners (PLC)
that are designed to provide a stable 120 volt AC power source for control and indication circuits for both safety and nonsafety-related loads. The problem occurs during electrical distribution system transients resulting in the PLC control fuses blowing and the feeder breaker tripping.
This results in a. loss of power.to plant control and indication circuits that-are fed from the affected PLC.
During the plant outage, the licensee has taken several actions to determine the cause and to correct the identified problems; An Elgar service representative was involved in testing and investigation of the problem. Testing and investigation indicates that electrical transients cause oscillations in the buck and boost circuit of the-
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PLC, which causes the control-fuses to blow.
The loss of the PLC d
fuses then causes a shunt trip to activate and trip the feeder breaker to'the PLC.
Potential fixes for this problem include installation of surge capacitors at the PLC, removal of the shunt trip, and adjustment of the PLC voltage control circuit.
The licensee plans to remove the shunt trip on all PLCs during the outage and to install indicating lights for indication of fuse failure.
This will cause the PLC to act as a normal 480/120 volt transformer when the fuses blow and will prevent a total loss of power to plant loads.
The installation of surge capacitors and adjustment of the voltage control circuits will be accomplished during a future outage when parts are received.
In addition to the PLC trip problem, operations personnel have experienced difficulty with the available design documents in identifying individual loads which are fed from the PLC distributions panels. There are no load lists or panel drawings that identify what each individual panel breaker feeds. The identification of individual loads requires a' laborious review of electrical schematics and cable drawings.
The licensee design organization has committed to provide controlled panel drawings which will identify cables, cable drawing reference and a brief description of the load for all 120 volt AC and DC distribution panel breakers. This effort will be completed by December 31, 1986.
Also, an additional effort is on going to provide for a more detailed description of the individual load functions for the PLC distribution panel loads.
The SRI will continue to monitor licensee actions in this area during future inspections as an open item.
(458/8632-01)
d.
Diesel Generator Fuel Oil Injection Pump Cap Screw Failures - During surveillance testing of the Division I standby diesel generator on September 23, 1986, the number 2 cylinder fuel oil injector pump was observed to be bouncing around and fuel oil was spraying out of the n
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pump overflow line. The licensee immediately shut down the diesel generator and initiated an investigation of the problem.
It was found that 3 of the 4 allen head capscrews that secure the number 2 cylinder fuel injection pump base assembly to the engine had broken.
The licensee's corrective actions and root cause analysis for the bolt failures included:
testing of the fuel oil injection pump and injector;
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testing of material properties of the failed bolts and of a
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sample of non-failed bolts; obtaining required capscrew torque value (120 ft-lbs) from the
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diesel engine manufacturer (TDI);
obtaining independent verification of the torque value from a
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research institute;
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checking existing torque values for the Division I & II diesel
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engines; determining that while the existing values ranged from 45 ft-lbs
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to 120 ft-lbs with an average of 92 ft-lbs, none of the existing values were below a calculated minimum capscrew torque of 34 ft-lbs necessary to resist dynamic action of the fuel oil injection pump; torquing all of the capscrew bolts to the required 120 ft-lbs;
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replacing the Division I diesel number 2 cylinder fuel oil
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injector pump, injector tubing, injector assembly and base assembly capscrews;
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performing the 24-hour surveillance test of the Division I
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diesel generator; and
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initiating a design change for locking the capscrews in place.
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The apparent root cause of the bolting failure was a loss of preload in one capscrew of the affected pump base.
However, no uniquely t
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A research of previously completed corrective maintenance records revealed that no work had been performed on these capscrews.
The licensee has marked the capscrews for easy identification of
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loosening and they will monitor during future surveillance testing.
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The SRI considers the licensee response to this problem to be prompt and thorough.
No violations or deviations were identified in this area of inspection.
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Surveillance Test Witness-During this inspection period the SRI and RI observed the performance of several surveillance tests and reviewed the data packages for each of these tests. The following surveillance tests were observed:
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Surveillance Test STP-201-3601 - The RI observed the performance of STP-201-3601, " Standby Liquid Control Injection Test," conducted on October 22, 1986. This surveillance test implemented the 18-month requirement of TS 4.1.5.d.1 for initiating one of the standby liquid control (SLC) system loops, including an explosive valve, and verifying that a flow path from the pumps to the vessel is available.
During the review of the test data, the RI noted that the squib valve explosive charge installed in the
"B" SLC loop had been removed prior to initiating the test and replaced with an explosive charge from the onsite warehouse. The test was successfully performed and the original explosive charge and new squib valve internals were installed by maintenance work request (MWR)-61483. The SRI and RI discussed the basis for TS 4.1.5.d.1 with the licensee, which discussed the need to replace the explosive charges in the valves at regular intervals to assure that these valves will not fail because of deterioration of the charges. TS 4.1.5.d.1. requires that both injection loops be tested within 36 months. The licensee has initiated a temporary change notice (TCN) to STP-201-3601 requiring the SLC loop be tested in the "as found" condition and controls implemented to assure the 5-year shelf / service life for the explosive charges are not exceeded. The resident inspectors also reviewed the conditions which led to the replacement of the original explosive charge with the charge stored in the onsite warehouse prior to performing the test. A condition report initiated on October 14, 1986, identified that replacement kits for the squib valves including the trigger assembly and primer chamber had been improperly stored in a Level C warehouse as described in ANSI N45.2.2, " Packaging, Shipping, Receiving and Storage," rather than Level B storage which utilizes temperature control, from November 1985 to October 1986. The licensee subsequently evaluated the effects Level C storage may have had on the squib valves.
Resistance measurements of the bridgewires and the voltage drop across the squibs was found to be within acceptable limits. An engineering evaluation by the licensee of the environmental conditions the squib valve assemblies experienced while stored in the Level C warehouse determined that the squib valve assemblies should not have suffered sufficient degradation of the explosive charge to effect the 5-year storage / service life.
Also, the vendor indicated to the licensee that if the squib valve is exposed to temperatures greater than 120 F the valve will fail open a " safe condition,"
because of self actuatio..
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The SRI and RI are concerned with the controls for the storage of safety-related replacement parts. This area of concern will be reviewed by NRC inspectors during subsequent inspections. This is an openitem(458/8632-02).
b.
Surveillance Test STP-305-1606 - The RI observed the performance of STP-305-1606, " Battery 1ENB* BAT 01A 18-Month Service Discharge Test,"
on October 23, 1986. This surveillance test implemented the 18-month requirement of TS 3/4.8.2.1 for verifying battery capacity using a dummy load with a load profile similar to that expected for a design basis accident.
Prior to the licensee performing this test the SRI reviewed the test data package for STP-305-1607, "ENB* BAT 01B 18-Month
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Service Discharge Test," performed on October 8, 1986. The SRI noted that the required load profile readout from the load tester only printed out every 15 minutes, which does not document each load profile value. Only the initial setup of the load tester is printed which shows the required load steps. This is sufficient if the load tester performs correctly, but there was no documented observation of each load profile step by the test personnel. This was discussed with licensee personnel and a procedure change was initiated to require documented observation of each load profile step by the test personnel. The RI verified that a similar procedure change was initiated for the Division I battery test and used during the performance of the test. The load profiles were observed to be equal to or greater than the profile load required by the above technical specification. The Division II battery test data was deemed adequate based on current calibration of the load tester and proper performance of the load tester during this subsequent Division I test.-
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Surveillance Test STP-305-1604 - The SRI observed the performance of STP-305-1604, " Battery Charger IENB*CHGRIB Load Test," on-0ctober 14,-1986..It was observed that the test current was approximately 304 amps for the required 8-hour load test and that the charger output voltage did not drop below the minimum allowable of 130.2 volts. The technicians performing the test were knowledgeable of the test requirements and lifted lead tags were attached to the electrical leads that had been lifted for the test. The performance of this test satisfies the 18-month surveillance requirement of TS Section 4.8.2.1.C.4 for the Division II battery charger.
No violations or deviations were identified in this area of inspection.
7.
Maintenance Witness During this inspection period, the RI observed portions of selected corrective maintenance activities to verify that maintenance activities are being conducted in accordance with approved procedures, TS and appropriate industrial standards and codes. The following activities were observed:
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i Standby Liquid Control (SLC) Explosive Valve. Replacement - The.RI
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request.(MWR)'61483 which was initiated to replace the B SLC squib valve assembly. This was a planned maintenance activity, necessary.
.to restore.the SLC system to operable status following the performance of surveillance test STP-201-3601 on October 22,.1986.
Prior to the licensee initiating work, the RI verified that _ required administrative approvals and tagouts were obtained. Radiological
- controls were also properly implemented and observed by maintenance personnel during the performance of the maintenance activity. The replacement charge for the explosive valve was certified as having been from a manufactured batch in'which a charge had been previously
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fired. The RI reviewed the qualified 5-year shelf / service life
records for the replacement explosive charge and verified the
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qualified. life will not be exceeded during the 36-month cycle TS allows until the valve is again tested.
. Diesel Generator Governor Oil Water Intrusion - During the
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performance of surveillance test STP-309-0202, " Diesel Generator Division II Operability Test," on.0ctober 17, 1986, the licensee manually shutdown the diesel because of water intrusion into the
. governor oil reservoir. This condition was noted by the nuclear equipment operator (NE0) while monitoring the diesel generator's (DG)
. support systems. The licensee's decision to shutdown the DG was conservative in that, although no erratic responses were noted with the governor control system, the apparent increasing reservoir oil level and foaming of the oil may have resulted in governor control problems.
The source of the water in leakage was believed to be the jacket water - governor oil cooler heat exchanger. A tracking LC0 and maintenance work request (MWR) were initiated for assemblage of information and to repair the heat exchanger respectively. Following replacement.of the governor oil cooler on October 18, 1986, the licensee bench' tested'the. heat exchanger and-was unable to identify
.any leakage ' path which would account for the water intrusion.
Subsequent investigation by the licensee revealed that a previous MWR worked on October 5,1986, identified that a stainless steel fitting, where the governor oil cooler Jacket water outlet line ties into the main return header at the jacket water standpipe, was leaking engine coolant. The licensee ha's: postulated that the engine coolant entered the oil reservoir through the fill' cap. Although the cap is held closed by a spring, the sealing surface is not designed to form an air tight bond. -Since the density of water is greater than the governor oil fluid, the water settled to the bottom of the oil reservoir, below the sight glass and went unnoticed prior to starting the diesel. The apparent increase in oil level following the start
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of the diesel resulted from the foaming action between the oil and water. No~ further. cases of water intrusion-into the governor oil fluid have been noted by either the RI or licensee.
No violations or deviations were identified in this area of the inspection.
8.
Safety System Walkdown During this inspection period, the SRI and RI performed a walkdown of the SSW, system to verify proper system alignment for operability as required by Technical Specifications for Operational Conditions 1, 2, 3, 4, and 5.
It was observed that:
system valves' were properly aligned;
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no abnormal control room instrumentation readings or alarms were
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present; no leakage from major components was present;
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the SSW pump bearing oil reservoirs were properly filled; and
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accessible hangers and supports were intact.
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No anomalies were noted that would have affected the SSW system operability.
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No violations or deviations were identified in this area of inspection.
9.
Exit and Inspection Interview An exit interview was conducted on November 14, 1986, with licensee representatives (identified in paragraph 1). During this interview, the SRI reviewed the scope and findings of the inspection.
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