IR 05000458/1986040
| ML20210D593 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 01/23/1987 |
| From: | Chamberlain D, Jaudon J, William Jones NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20210D536 | List: |
| References | |
| 50-458-86-40, NUDOCS 8702100122 | |
| Download: ML20210D593 (15) | |
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APPENDIX B U. S. NUCLEAR REGULATORY C0leilSSION
REGION IV
NRC Inspection' Report: 50-458/86-40 Docket: 50-458 Licensee: Gulf States' Utilities Company (GSU)
P. O. Box 220 St. Francisvilles, Louisiana 70775
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Facility Name: River Bend > Station (RBS)
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Inspection At: River Bend Station, St. Francisville, Louisiana
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Inspection Conducted: December 1 through 31, 1986
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Inspectors:
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D. D. #hamberlain, Sen:.or Resident Inspector Date Project Section A, Reactor Projects Branch
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\\ I% IB1 W. B. Jones, Reside)(t Inspector Da :e *
d Project Section A, Reactor Project Branch Approved:
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.J on, Ch f7 Project (Sjction A Dath
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React r Proje ts Branch 8702100122 870123 PDR ADOCK 05000458 G
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-2-Inspection Summary Inspection Conducted December 1 through 31, 1986 (Report 50-458/86-40)
Areas Inspected: Routine, unannounced inspection of licensee action on previous inspection findings, Licensee Event Reports (LERs), maintenance witnessing, safety system walkdown, surveillance test witnessing, operational safety verification and allegation followup.
Results: Within the areas inspected, one violation was identified (failure to follow surveillance test procedure, paragraph 6).
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DETAILS
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Persons Contacted Principal Licensee Employees
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- D. L. Andrews, Director, Nuclear Training W. J. Beck, Supervisor, Reactor Engineering
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W. H. Cahill, Jr., Senior Vice President, River Bend
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Nuclear Group m
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E. M. Cargill, Supervisor, Radiation Programs
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- D. E. Cathey, Senior Systems Engineer
- J. W. Cook, Lead Environmental Analyst
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- T. C. Crouse, Manager, Quality Assurance (QA)
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- J. C. Deddens, Vice President, River Bend Nuclear Group
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- D. R. Derbonne, Supervisor, General Maintenance
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R. G. Finkenaur, Electrical Engineer
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P. E. Freehill, Superintendent, Startup and Test A. O. Fredieu Assistant Supervisor, Operations
- D. R. Gipson, Director, Quality Systems P. Graham, Assistant Plant Manager, Operations
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E. R. Grant, Director, Nuclear Licensing Q
- S. C. Hagge, Senior, Electrical Engineer
- J. R. Hamilton, Director, Design Engineering
. ', n R. W. Helmick, Director, Projects A
G. K. Henry, Supervisor, Electrical Engineering
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K. C. Hodges Supervisor, Quality Systems
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- G. R. Kimmell, Supervisor, Operations Quality Assurance
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R. J. King, Supervisor, Licensing C
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A. D. Kowalczuk, Assistant Plant Manager, Maintenance-f
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- J. W. Leavines, Director, Field Engineering s.
I. M. Malik, Supervisor, Quality System
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- J. H. McQuirter, Licensing Engineer
't V. J. Normand, Supervisor, Administrative Services l,
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- W. H. Odell, Manager, Administration S
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T. F. Plunkett, Plant Manager S. R. Radebaugh, Assistant Plant Manager, Services
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- D. B. Reynolds, Supervisor, Administrative Support
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C. R. Roberts, Training Coordinator x A~
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M. F. Sankovich, Manager, Engineering
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- R. R. Smith, Licensing Engineer R. B. Stafford, Director, Operations QA
- K. E. Suhrke, Manager, Projects
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- R. J. Vachon, Senior Compliance Analyst
- D. W. Williamson, Supervisor, Operations
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E. J. Zoch, Supervisor, Design Engineering
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TheNRCseniorresidentinspector(SRI)andresidentinspector(RI)also interviewed additional licensee personnel during the inspection period.
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- Denotes those persons that attended the exit interview conducted on; January 8,1987. NRC resident inspector (RI), W. B. Jones also attended the exit interview.
2.
Licensee Action on Previous Inspection Findings y
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(Closed)OpenItem(458/8615-03): Monitor'llcensee actions relative to ventilation systems damper binding.
The licensee experienced problems with sticking of ventilation system dampers during thef first quarter of 1986. The cause of the sticking was determined to be binding of the damper shafts on the shaft seals.
These seals were installed during the preoperational testing phase to prevent air leakage around the, shafts. Apparently, the split brass bushings were machined at too tight of a tolerance, which resulted in binding of the dampers.
During the second quarter of 1986, the licensee completed a shaft seal modification on ventilation system dampers and instituted a shaft seal lubrication preventive maintenance program. The modification involved installing a 10 mil
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shim in the split brass bushings. The bushings contain a rubber 0-ring which provide the leakage seal around the shaft. The installation instructions required only slight loosening of the, seals so that the 0-ring seal would not be disturbed. A special silicone / graphite mixture was used to lubricate the seals. 7The preventive maintenance program now requires quarterly lubrication of these seals. The licensee has experienced no further damper sticking problems since the modification was completed and the preventive maintenance lubrication program was instituted.
This open item is closed.
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(0 pen) Open Item (458/8513-01): Standby diesel generator jacket
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water system / service water system engineering analysis.
The licensee has completed the engineering evaluation involving the diesel generator jacket water system stanoby temperature. Corrective actionstakgntomaingainthejacketwatersystemtemperatures between 130 F and 160 F for the division I and II diesel generators are described in modification request (MR)85-001 and the associated engineering and design change report (E and DCR) 85-001-01. The corrective actions taken includC heat tracing and insulating the I
jacket water stand pipe and insulating the service water piping l
inside the diesel generator rooms. These modifications were l
implemented under maintenance work request (MWR) 86-10569 and the work was signed off as complete on September 11, 1986. Temperature readings taken en the division I and II diesel generator revealed that the jacket water gnlet and gutlet temperatures were being maintaineg between 130 F and 160 F with service water temperatures as low as 55 F.
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'While. verifying that the work required by MWR 86-10569 had been completed, the RI noted that neither insulation around the jacket water heat exchanger nor the protective aluminum jacket over the insulation had been installed as described in the design change documents and the NWR. Specifically step 8, of the MWR work instructions required that.the insulation be installed per MR 85-001 and field change notices (FCN) I through 4.
Page 3 of the E and DCR which supplements MR 85-001 required that the jacket water heat exchanger be insulated and a 0.016 in. minimum thickness aluminum jacket be placed over all insulation to protect it in the event of a fuel oil or lube oil leak. This issue was discussed with licensee representatives and it was discovered that several problems with MR implementation had been identified in a qualityassurance(QA)auditconductedinDecember1986. Audit 86-12-I-DCON resulted_in several-quality assurance finding reports and in condition report CR-1858 being issued. The condition report addressed s'everal problems with the implementation of MR 85-0001
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including the failure to install the 0.016 in, minimum thickness insulation. Also, during this inspection, the licensee issued FCN 5 to MR 85-001 which deleted the requirement for insulating the jacket water heat exchanger. The insulation was determined not to be required based on operating experience with desired temperature control.
This open item will remain open pending the resolution of items identified in CR-1858. Also, since the licensee QA organization
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identified programmatic problems with the implementation of
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-MR 85-001, no NRC violation will be issued.
Instead, the resident
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inspectors will monitor licensee actions to correct the programmatic
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deficiencies identified in audit 86-12-I-DCON as an open item.
(458/8640-02)
l 3.
Licensee Event Reports (LERs) Review During this inspection period, the SRI and RI reviewed LERs for compliance with requirements established in 10 CFR Part 50.73, " Licensee Event Report 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 effect each event had on plant operation, operator actions that affected the course of the esent, and the corrective actions taken to prevent recurrence of the event. Completion of corrective actions for selected significant events was also verified.
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!85-009 ESF A.-tuation 85-011 Main Steam Line Isolation l
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.85-024 RWCU Isolation on High Differential Flow Signal 85-027 Inadvertent ECCS Initiation 85iO28 Loss of 13.8 KV Normal Switchgear 85-029 Closure of RWCU Outboard Isolation Valves85-030 RWCU Isolation 85-032 Spurious Actuation of Fuel Building Charcoal Filter Train 85-033 Electrical Junction Boxes Not Sealed as Required for Environmental Qualification 85-034 Structural Steel Supports in Standby Service Water System 85-035 RWCU Isolation 85-036 Inadvertent ECCS/ATWS Initiation
.85-037 Reactor Water Cleanup Isolation
,85-039 RWCU Isolation 85-040 Reactor Water Cleanup Isolation 85-041 Loss of Feedwater and Reactor Scram l
85-042 Division I RCIC Isolation
'85-043 Trip Setpoint Allowable Values Exceeded
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!85-044 RWCU Isolation on High Temperc.ture 85-045 ECCS Initiation 85-046 NSIV Isolation 85-047 Reactor SCRAM on IRM Upscale 85-048 RWCU Isolation 85-049 Division II RCIC Isolation 85-050 RHR Pump ana Valve Operability Surveillance Missed I
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,85-052 Residual Heat Removal (RHR) System Isolations85-054 Failure to Perform Surveillance Requirements85-057 Voltage Transient on Division I Power Buses
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Causes ESF Actuations
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85-058 Reactor Water Cleanup (RWCU) System Isolation Resulting from Failed Capacitor 85-059 Reactor Water Cleanup Isolation Resulting from Leaking Valves
"85-060 Reactor SCRAM on Loss of Feedwater Pump Due to Bearing failure i
85-061 Reactor Water Cleanup (RWCU) System Isolation
'85-063 Reactor SCRAM Due to Turbine Load Imbalance
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85-064 Hydrogen Sample Not Taken Contrary to Technical Specification Action
!86-001 Reactor SCRAM on Loss of Condensate Flow
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!86-002 Hand Held Radio Causes Loss of Offsite Power
,86-004 Struck Panel Causes Standby Service Water System' Initiation 86-005 Unlabled Switch Causes Activation of Water Curtain Leading to SCRAM 86-006 Feedwater Testable Check Valve Returned to Service Without Operability Test 86-007 Reactor SCRAM Due to Stuck Open Feed Water Regulator Valve l
86-009 Liquid Radwaste Release Without Operating l
Radiation Monitor 86-011 Hydrogen Sample not Taken Due to Changed Lock on Door 86-015 Reactor Shutdown Due to Inoperability of Purge Valves l
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8 86-017 Unqualified Tubing Installed Due to Procedural Error 86-019 Reactor Trip Resulting From Feedwater Heater Level Problems86-020 Automatic Initiation of Standby Gas Treatment System 86-022 Reactor SCRAM Due to Pressure Spike in Instrument Line 86-023 Diesel Generator Fuel Oil Valve Misalignment 86-028 Incorrect Transformer Tap Setting 86-029 Inadvertent Auto Start of Standby Service Water 86-032 Reactor SCRAM on Reactor Water Level 8 86-033 Reactor SCRAM Due to Blown Fuse in Reactor Protection System 86-034 Fuel Building Filtration Train B Automatic Start 86-035 Reactor SCRAM on Excessive Flow Transmitter Noise 86-039 Reactor SCRAM on Turbine Trip Due to High Vibration Signal l
86-058 Automatic Start of the Standby Water Pumps86-061 Loss of Sample Flow on Radiation Monitor 1RMS RE108 The above listed LERs are closed.
During this review of LERs, it was noted that some initial reports and supplemental reports were submitted late. Also, some reports (especially reports issued in early 1985) did not fully describe event details and/or corrective action. During a November 1986 meeting at the NRC Region IV office with GSU senior management, the general subject of content and i
tiraeliness of LERs was discussed. GSU management acknowledged a problem
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with LER submittals and outlined some of the steps they are taking to assure timely and quality submittal of LERs. The timeliness of LER i
submittals was also documented as an open item in NRC Inspection l
Report 50-458/86-33. The timeliness and quality of LER submittals will be monitored during future NRC inspections.
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No violations or deviations were identified in this area of inspectio..-
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Maintenance Witness
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During this inspection period, the RI observed maintenance activities performed under prompt maintenance work order (PMWO) request 55034. This PMi0 was initiated to implement the setpoint changes for the reactor core isolation cooling / residual heat removal (RCIC/RHR) system leak detection-system trip units 1E31*PDISN684A and 1E31*PDSN691A provided for in prompt modification request (PMR) 86-0128.
On December 10, 1986, the licensee experienced a RCIC pump high steam line flow isolatior, on trip unit IE31*N684A when no actual high steam flow differential pressure existed. The associated transmitter was verified operable, and the transmitter and trip units were verified to be in calibration under HWOS 55023 and 55026 respectively. The licensee determined that a water column is forming in the instrument line causing the instrument to see a negative 110 inches of water during RCIC operation because of a steam condensing effect. The licensee evaluated this condition under PMR 86-0128 and determined that the instrument-line break isolation setpoint could be reset to negative 210 inches of water. There is no Technical Specification (TS) limit for this setpoint. The licensee also evaluated the effect of this condition on the steam line break setpoint. This setpoint is presently limited to less than or equal to 156 inches of water by TS.
In order to allow for the negative 110 inches of water during RCIC operation, the licensee conservatively decided to _ reduce the steam line break setpoint to 46 inches of water. These setpoint modifications were performed on December 12, 1986. The licensee manually initiated the RCIC system three times on December 12, 1986, to verify that the water column forming in the instrument line was a repeating occurrence resulting in the instrument negative reading. The RI observed that operation of the RCIC system resulted in a consistent reading on 1E31-N684A of negative 110 inches of water.
Following the performance of the STP-209-0302, "RCIC Pump Operability and Flow Test," the RCIC system was declared operable and the associated limiting condition for operation terminated.
The licensee has experienced similar problems with the formation of water columns in the RCIC/RHR steam line break instrument line during the past year. A modification to the instrument line run was made during the previous outage; however, the modification did not correct the condition causing the water column. - The licensee is continuing with their evaluation of this-condition to correct the water column formation.
Technical Specifications (TS) required that licensee establish a final setpoint for these instruments based on the data taken during the startup test program.
In their letter to the NRC dated September 12, 1986, the licensee has requested a TS change that would allow the setpoint to remain at less than or equal to 156 inches of water until testing in the steam condensing mode may be performed.
It is not apparent from the review of the proposed TS change and setpoint data that this proposed TS change
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would be conservative. This area is considered unresolved pending correction of the water column formation condition and further evaluation of the proposed TS change.
(458/8640-03)
No' violations or deviations were identified in this area of the inspection.
5.
Safety System Walkdown
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On December 21, 1986, the SRI and RI performed a walkdown of the low ressure coolant injection (LPCI) mode of the B residual heat removal p(RHR) system. This system is required to be operable during operational conditions-1, 2, and 3 with an established flow path capable of taking suction from the suppression pool and transferring the water to the
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reactor vessel.
The system walkdown revealed the following:
system valves located on the major flow paths were properly aligned;
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cssociated instrumentation was properly aligned;
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no abnormal control room instrumentation readings or alanns were
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present; the RHR pump bearing oil reservoirs were properly filled; and
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I accessible hangers and snubbers were intact.
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Although no anomalies were noted which would affect RHR System i
operability, valves 1E12*MOV648 and 1E12*M0V53B were not shown on the associated Piping and Instrument Drawing PID-27-78 in their normal standby
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position. These valves had been aligned as required by the system i
operating procedure SOP-0031. Similar discrepancies between the PID and S0P were identified in NRC Inspection Report 50-458/86-20 for the i
RHR C system as Violation 458/8620-02. The licensee responded to this violation in their letter dated October 17, 1986, by conmitting to add a note to the PIDs, by December 31, 1986, stating that valve positions shown on the PIDs are for the normal mode of operation and are for information only. This note had not been placed on PID-27-78 as of the date of the system walkdown.
Subsequent discussions with licensee representatives revealed that the note was added by December 31, 1986, but the sample review of PIDs conducted by the licensee had revealed additional discrepancies with PIDs. The licensee will provide a revised response to Violation 458/8620-02 describing further actions to be taken regarding PID discrepancies by January 9,1987. This revised response will be evaluated when received by NRC Region IV.
No violations or deviations were identified in this area of inspection.
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6.
Surveillance Test Witness On December 12, 1986, the RI observed surveillance test STP-209-302,
"RCIC Pump and Flow Operability Test," performed in accordance with the licensee's inservice inspection program.
During the performance of the test, the RI noted that step 7.4.29 to this procedure was not completed as stated, but the step was signed off indicating that all the valve manipulations required by the step had been completed. Specificall step 7.4.29 requires that the reactor core isolation cooling (RCIC)y,test return to the condensate storage tank (CST) valve 1E51*MOVF059 be closed and that the RCIC test flow control valve to the CST 1E51*M0VF022 be closed. During the performance of this step, only the 1E51*M0VF059 valve was closed. When the RCIC pump minimum flow valve to the suppression pool did not automatically open as required by the subsequent step, the STP was terminated. This failure to complete the action required by step 7.4.29, prior to proceeding with the test was identified by the RI as an apparent violation.
(458/8640-01)
Several factors may have contributed to the above apparent violation.
These factors include:
first time perfonnance of this specific STP by the assigned engineer;
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inadequate communication between the engineer directing the test and
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the operator manipulating the system controls; the large number of changes that exist to the procedure (almost every
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page of the procedure was modified by a temporary change notice); and incorporation of two valve manipulations into one procedure step.
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The licensee does not have a formal program established to familiarize an individual with a particular surveillance prior to their performing the test for the first time. Discussions with the engineer's supervisor revealed that it was his practice to send an experienced' individual along with the person who will be performing a surveillance test for the first time to assist or clarify any misunderstanding that may occur. This did not occur in this particular instance and may have contributed to this violation.
The engineer who is performing this test has initiated a temporary change notice (TCN) to separate the two valve manipulations in step 7.4.29 into two steps. The STP is also presently being revised to incorporate all the previous TCNs.
This surveillance test, STP-209-302, was rerun on December 12, 1986, without further problems. The test frequency has been increased to once every 46 days because of the pump flow rate being high and in the alert range.
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7.
Operational Safety Verification The resident inspectors 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 rocm operational areas was controlled. Operators were questioned regarding lit.
annuciators and they understood why the annuciators were lit in all cases. Selected shift turnover meetings were observed and information A walkdown concerningplantstatuswasbeing(coveredinthesemeetings.RHR) system was conduc of the "B" residual heat removal results are documented in paragraph 5 of this report. Plant tours were conducted and overall plant cleanliness was good. During these plant tours, radiation protection area postings were observed to be accurate.
The resident inspectors also reviewed licensee actions on operational-events and potential problems. The results of reviews of selected items-are described below:
a.
Reactor Scram Caused by Turbine Runback - On December 26, 1986, with the unit at approximately 100 percent power, a main turbine high stator. cooling temperature caused a turbine runback which led to a reactor scram. The reactor scram occurred from high flux because of the reactor pressure increase from the turbine runback. The unit remained shut down while the licensee investigated the cause of the high stator cooling temperature. The licensee investigation revealed that the positioner on the stator cooling temperature control valve was apparently operating erratically. The positioner was replaced and subsequent valve manipulations revealed no problems. The unit was restarted on December 27, 1986, and the stator cooling system was j
closely monitored during power ascension and subsequent 100 percent power operation. No additional problems have been identified. The I
immediate licensee actions in response to this event are considered prompt and thorough and final closure of this event followup will be documented during routine LER review.
b.
Ventilation System Turning Vane Failures - This area of inspection was conducted to review licensee actions relative to the ventilation system turning vane failures that have occurred. These turning vanes are installed in ventilation system ductwork to reduce turbulence and direct air flow. The licensee identified broken or cracked turning vanes in the annulus mixing system in October 1985 and again in October 1986. The locations of the failures were in high turbulence areas. The licensee subsequently issued a revised condition report (CR-1598A) during November 1986 to reevaluate the generic l
implications of these turning vane failures. As a result, the
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licensee inspected an additional 11 turning vanes based on an established selection criteria. The selection criteria included vanes located in high velocity ductwork in large ductwork (greater than 12 in. by 12 in.) and in close proximity to safety-related equipment. No additional turning vane problems were identified as a result of these inspections.
In addition to the inspections, the i
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licensee added additional bracing and support to one turning vane and removed two turning vanes. The SRI discussed the licensee actions and any planned followup actions with licensee representatives on December 22, 1986. Since this discussion, the SRI was informed that a rereview of all safety-related ventilation-systems against the inspection criteria was being conducted to assure that all vanes that met the criteria were inspected. Also, in order to provide for routine followup) inspection of turning vanes, the surveillance testfor inspection of. f procedures (STPs to include inspection of nearby turning vanes. As of December 31, 1986, the licensee had identified one additional turning
. vane to be inspected based on the established inspection criteria.
The SRI will monitor the additional inspections and the revision of the STPs as an open item.
(458/8640-04)
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No violations or deviations were identified in this area of inspection.
8.
Allegation Followup This area of inspection was conducted to review certain areas of concern received by NRC Region IV relating to activities at River Bend. The review results for each area-is documented below:
a.
Insulated piping corrosion (Allegation 4-86-A-092) - This area of concern was that the chilled water and service water piping was insulated to preclude sweating and the piping was not painted or primed prior to insulation.. It was believed that this lack of priming / painting would allow the pipe to rust though within a few years. The review of this area revealed that the aforementioned piping systems are not primed / painted, but they'are insulated with
" Class J" antisweat insulation and the joints are taped with a vapor barrier adhesive. This type of. insulation apparently prevents
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sweating by preventing direct pipe contact with humid air. The lack
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of pipe contact with air should also limit rusting and the concern with the piping rusting through is not believed to be a problem.
The SRI will observe piping systems for excessive rusting as conditions allow during future inspections.
No violations or deviations were identified.
b.
Radioactive contamination spill (Allegation 4-86-A-103) - This area of concern was that a radioactive material spill occurred in September 1986 and that GSU attempted to cover up the information that the spill had occurred. There was also concern with worker safety during the spill cleanup effort. The SRI was informed of a spill in September 1986 and licensee actions for cleanup of the spill were monitored. The spill occurred when a piping leak in the condensate demineralizer tank room sprayed through an unsealed pipe penetration into the water treatment building and onto the ground through a gap between the two buildings. This spill was discovered
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by the licensee, and condition report CR86-1410 was initiated on September 16, 1986, to document corrective actions. The-SRI was infonned of the spill at that time. Radiationsgrveyresults revealed contamination levels to 5000 dPM/100 CM on the gravel areas outside the building. The spill area was roped off and subsequently cleaned up and decontaminated. Radiation protection controls for worker safety were in effect during the cleanup effort. The SRI did not find any evidence to support the allegation that there had been any effort by GSU to cover up information about the spill or that radiation worker safety was compromised.
No violations or deviations were identified.
c.
Inadequate maintenance worker staffing '(Allegation 4-86-A-114) - This area of concern was that following a lay off of maintenance support workers, GSU would not have a sufficient number of maintenance craft workers to maintain the plant. The SRI reviewed the number of maintenance workers in the electrical, mechanical and instrumentation disciplines. GSU is presently supplementing their permanent staff
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with union and contract labor. This supplemental support was reduced
significantly following an outage completion in late November 1986.
The SRI compared the present staffing level at River Bend with
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staffing at three other plants (a larger BWR, a smaller BWR and a
larger sized PWR). River Bend staffing fell between the smaller and
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l larger BWR and was slightly higher than the PWR plant. There was no data available on how these other plants use contract labor. The SRI
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also reviewed the corrective maintenance (CM) and preventive
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maintenance (PM) backlog status. The PM backlog did increase at the l
beginning of December 1986 but by the end of December the backlog was l'
reduced to the level prior to the layoff. The CM backlog had cycled up and down during December but no_ drastic increases were noted.
Maintenance staffing was discussed with GSU senior management, and the managers stated that the maintenance backlog would be monitored with the present staffing level and adjustments would be made as needed to control the backlog. There is no evidence at this time that the' lay off in November 1986 has caused any significant problems or increases in the overall maintenance backlog. The SRI will continue to monitor maintenance backlog during future NRC inspections including backlogs in each discipline.
No violations or deviations were identified.
9.
Unresolved Item An unresolved item is one about which additional information is required in order to determine if it is acceptable, a deviation, or a violation.
There is one unresolved item in this report.
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Paragraph Item No.
Subject
458/8640-03 RCIC/RHR Isolation Setpoint Change 10. Exit and Inspection Interview An exit interview was conducted on January)8,1987, with licensee representatives (identified in paragraph 1. During this interview, the SRI reviewed the scope and findings of the inspection.
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