IR 05000458/1990013
| ML20044A314 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 06/19/1990 |
| From: | Constable G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20044A313 | List: |
| References | |
| 50-458-90-13, NUDOCS 9006280326 | |
| Download: ML20044A314 (10) | |
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1 APPENDIX
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U.S. NUCLEAR REGULATORY COMMISSION i
REGION IV
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r NRC Inspection Report: 50-458/90-13 Operating License:
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Docket: 50-458
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Licensee: Gulf States Utilities Company (GSU)
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P.O. Box 220
St. Francisville Louisiana 70775 Facility Name:
RiverBendStation(P.BS)
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Insper. tion At:
RBS, St. Francisville Louisiana
Inspection Conducted: May 1 through Gune 16, l')90 Inspector:
E. J. Ford, Senior Resident inspector
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Approved:
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(G L. - Constable. Chief. Proje'.:t Section C Date
Division of Reactor Projects
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Inspection Summary Inspection Conducted May 1 through June 16, 1990 (Report 50-458/90-13)
Areas Inspected: Routine,unannouncedinspectionoflicenseeevent-report (LER)
review, followup of events, operational safety verification, maintenance observation, and surveillance observation.
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Results: Within the areas inspected, no violations or deviations were identified.
An inadvertent loss of security system power led to a good demonstration of the ability of the security organization to respond with compensatory measures.
During this reporting period the licensee has continued actions to mitigate the effects of an apparent pinhole leak through the fuel cladding. Reactor engineers were able to localize and minimize the leak by prudent control rod adjustments.
Efforts were made to reduce radiological effects in the plant by
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measures to reduce sources of process leakage and adjustment of ventilation as
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required.
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'The licensee's contract with uni >
employees is due to expire on June 23, 1990, and work stoppage contingency plans have been prepared and discussed with NRC l
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9006280326 900621 PDR ADOCK 05000458 G!
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DETAILS 1.
Persons Contacted
- G. Bysfield, Supervisor, Control Systems
- E. M. Cargill, Director, Radiation Programs J. W. Coo (, Technical Assistant
- T. C, Crouse, Manager, Administration
- W. L. Curran, Site Representative, Cajun L. A. England. Director Nuclear Licensing C. L. Fantacci, Supervisor, Radiological Engineering D. Fauver, Supervisor, Radiological Health R. W. Prayer, Director, River Bend Projects
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A. O. Fredieu Supervisor, Operations
- F. D. Graham, Plar.t Manager W. C. Hardy, Supervisor, Radiation Protection
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- G. X. Henry, Diretter. Quality Assurance Operations
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K. C. Modges, Supervisor. Cheinistry
- G. R. Kintnell, Director. Qulity Services
- D. N. Lorfing, Supervisor, Nuclear Licensing
- J. C. Maher, Licensing Engineer
- J. Miller, Director Engineering Analysis
- W. H. Odell, Manager, Oversight
- T. F. Plun'kett, General Manager - Business Systems & Oversight
- J. P. Schippert, Assistant Plant Manager - Operations, Radwaste and.
Chemistry
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B. Smith, Supervisor, Emergency Planning
- M. Stein Supervisor, Civil / Structural
- K. E. Suhrke, General Manager - Engineering and Administration J.' Venable Assistant Operations Supervisor S. Young, Supervisor, Reactor Engineering The inspectors also interviewed additional licensee personnel during
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the inspection period.
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- Denutes those persons that attended the exit interview conducted on June 15, 1990.
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Plant Status The plant operated at essentially 100 percent power the entire month of May 1990.
On June 8,1990, af ter reducing power for the weekly scheduled main turbine valve testing, the licensee elected to remain at reduced power (approximately 88 percent) in order to perform corrective
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maintenance on a feedwater pump (FWP-1C) which had developed excessive vibration.
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Followup of Events (93702)
During this inspecticn period, the inspector reviewed licensee condition reports (CRs) and 10 CFR 50.72 reports and held discussions with various plant personnel to ascertain the sequence, cause, and corrective actions taken for plant events. Discussions of selected events are given below:
Security System Failure On May 22, 1990, at 1:50 p.m. (CST), a potential fire was reported on the 123-foot elevation of the normal switchgear building.
Electrical inverter IHS-!NV1 located in that area was reported to have smoke issuing from it. The shift supervisor directed that the plant fire alarm be sounded and that the fire brigade respond. Af ter investigating, the fire brigade reported that' there was not a fire. However, the inverter suffered a loss of power which caused vital area security doors to be inoperable by
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normal means.
In response, the shift supervisor directed nonessential personnel not to-enter any vital areas and for those already in a vital
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area to refrain from using door " thumb-latches" to exit those areas, compensatory security personnel were dispatched to control and account for personnel desiring to exit through vital area doors, and electrical maintenance personnel were promptly dispatched to troubleshoot the faulty inverter. Preliminary repairs were made and the system returned to operability after approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
The inspector was in the main control room at the time of the event and monitored the licensees' actions.
The inspector also noted that security established a manual compensatory system at the protected area control point to properly control and account for entering and departing personnel.
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'The overall response to this event was timely and effective.
Elevated Offgas Pretreatment Samples - Possible Fuel Leakage (Followup)
On April 24, 1990, chemistry samples of reactor water coolant identified
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an increase in activity which indicated that a pinhole leak had developed in a fuel bundle. This was the first indication of a fuel leak after 4 J
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years of plant operation. As a result of the leak, the total activity of the gaseous effluents increased and is expected to remain higher than normal until Refueling Outage No. 3 (RF-3) which is scheduled to begin
September 30, 1990.
On May 4, 1990, the offgas pretreatment sample indicated a release rate from the condenser into the delay line and treatment system of
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l samples which were approximately 440 uci/sec. The licensee attributed this increase to the withdrawal of a group of four control rods on May 3,
1990. The four control rods had been withdrawn one step each from notch position 34 to notch position 36 (out of a full insertion and withdrawal rangeof0-48).
The licensee continued to note an upward trend in the
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offgas system sample readings and, as a result, the licensee reinserted
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the four control rods to their previous position (34) and ceased all rod movenent.
This action was taken to allow the plant reactor engineering
department to have more samples taken to detennine the source of the leak.
The licensee reported that isotopic analysis of the offgas data still indicated an equilibrium distribution, which is characteristic of a pinhole leak in the cladding (refer to NRC Inspection Report 60-458/90-10).
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This rate is a small fraction of the 290 millicurie per second Technical Specification limitt however, the licensee has reported elevated plant stack release levels for fission gasses and iodine.
Iodine-131 concentrations at the stack are 1.5E-10 microcuries per cubic centimeter.
This corresponds to a release rate of 6.5E-3 microcuries per second.
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On May 31, 1990, a licensee representative reported that 1 of 14 environnental air samplers indicated positive (or Iodine-131 for the first time. The detected activity was nonnalized at 1E-14 nicrocuries per cubic cettireter for the 7-day sample period. The state of Louisiana is aware of fhe feel pin leak and has environmental samplers located near the plant as part of a mutine monitoring program.
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Based on the spectrum of fission products, the licensee believes that the failed fuel pin is part of a fuel bundle installed in the core during the first refueling. Nonnally such a bundle would remain in the core for an additional cycle, but it will be removed during refueling this fall because of the leak.
The licensee has a failed fuel action plan which delineates required actions for further elevation of release rates.
The licensee is following the action plan.
The licensee has implemented enhanced radiological controls due to increased levels of gaseous activity in the turbine and containment buildings; however, airborne levels are not so high that special breathing apparatus is required.
On June 1,1990, af ter consultation with General Electric, the licensee repositioned the four-control-rod grou) that contained the' rod (Control Rod 28-13) nearest the fuel bundle wit 1 the leaking fuel pin. The rod group was moved into the core from the full-out position (Step 48) to a point (Step 26) just above the suspected location of the fuel pin leak.
The pretreatment offgas sample activity dropped from approximately 6000 uci/sec to 950 uci/sec as a result of this rod movement. The sample activity has remained in the 800-1100 uci/sec range from approximately June 8-16, 1990.
(The trend of this data has been independently verified by the inspector using diverse indicators.) This action was taken after a detailed evaluation of control rod exposure to neutrons to assure that rod worth neasurements remain in specification.
The licensee does not plan to withdraw this control rod group until required to do so because of fuel burnup at the end of core life. This is not expected to occur until August 1990.
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5 Hole in Ground due to Erosion On May 29, 1990, the licensee discovered a large hole in the ground near the circulating water system (CWS) pump structure. The structure is outside of the protected area but inside the owner-controlled area.
The roughly circular hole was 12-15 feet deep and approximately 10 feet in dismeter, its closest edge is about 6 feet south of the CWS structure.
i After investigation, buried Pipe Line 2-CWS-144-7-4 was found to have no
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cap on the end of the pipe; this apparently caused an erosion problem resulting in the hole. The licensee immediately constructed a hazardous
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area barricade.
i This pipe would have provided circulating water to the condenser of
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cancelled Unit No. 2.
It is not ccnnected to Unit No. 1 and has no effect
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on the operating unit.
The licensee is evaluating further corrective action.
J No violations or deviations were identified.
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Operational Safety Verification (71707)
The inspector conducted daily control room tours to observe operational
activities and review plant status. During these tours, the inspector noted that operations management personnel were frequently in the control room. The inspector also noted tlat proper access controls were enforced and that control room staffing always met or exceeded requirements.
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On May 15, 1990, the inspector perfonned a walkdown of the nonsafety-related 4.16 KV electrical boards in the normal switchgear building to
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verify appropriate breaker positions for the supplied power and loads, and Division 11 4.16 KV vital (g normal power o)eration the Division I and board to board ties. Durin
safety-related)loards,IENS*SWG1Aand IENS*SWG1B are powered from the nonsafety-related Preferred Station Service Transformers 1RTX-XNRIC and IRTX-XNRID, respectively,
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Additionally, the Division III 4.16 KV vital board,1E22*S004, is nonnally powered from nonsafety-related 4.16 KV Electrical Board INNS-SWG1C.
However, INNS-SWG1C can be powered from either INNS-SWG1A or 1NNS-SWG1B (which in turn are aowered from the preferred Station transformers).
Thus, an incorrect
)reaker lineup would potentially tie together IENS*SWG1A and 1 ENS *SWG1B, which are required to be electrically separated.
The inspector used " Start Up Electrical Distribution Chart EE-1AC" to verify a proper breaker lineup. The following breakers were examined and d
found to be correctly positioned:
INNS-SWG1A; ACB05, ACB06, ACB017, ACB029
INNS-SWG1B; ACB13, ACB14, ACB15, ACB28
1NNS-SWG1C; ACB23, ACB24, ACB25
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On May 17, 1990, the inspector toured the 95-and 70-foot elevations of the auxiliary building.
During this tour, the inspector noted general housekeeping to be acceptable and observed that valves associated with the (LPCS), residual high pressure core spray (HPCS), low pressure core spray (RCIC) systems on
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heat removal (RHR), and reactor core isolation cooling the 70-foot elevation (referred to as the " crescent area") were properly aligned. The inspector also verified that radiological controls were adequate. Specifically, the inspector verified that high radiation area Door AB-095-03 (RHR "C" room) and very high radiation area Door AB-095-04 (RCIC room) were locked as required. The inspector noted that hi radiation yellow and magenta rope barriers in the RHR "A" and "B"gh rooms were adequately secured and did not allow for inadvertent entry into the posted area.
It was also noted that the established contamination zone i
immediately outside the reactor water cleanup pump room (door AB-095-17)
was similarly properly barricaded and had the proper notification signs, While touring the west end of auxiliary building Elevation 95, the inspector observed a length of ropt barrier draped over an overhead pipe, The inspector notified the radiological protection foreman of the barrier, and he promptly dispatched a technician to investigate.
The foreman subsequently informe6 the inspector that there was no apparent reason for the rope barrier to be where it was, but noted that work had been previously performed on an LPCS valve in that area. The rope barrier was removed by the technician.
This does not represent a radiological safety problem and is not indicative of the licensees' normal control of radiological materials. However, it is an instance of inattention to detail.
The inspector also verified that the following radiological protection (RP)
equipment on both elevations was within the calibration due date and was properly functioning.
On elevation 95:
RM-14 Serial No. 7096
air monitor, Serial No. 0475
portable continuous air monitor 1RMS-RE220
air monitor, Serial No. 0366
On elevation 70:
air monitor, Serial No. 0463
Additionally, the inspector verified the following equipment to be properly functioning and within the calibration due date at the RP control point:
(at the Turbine Building "T" tunnel entrance on the 98-foot elevation)
RM-14. Serial No. 5290
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l Eberline Personnel Contamination Monitors (PCM-1B), Serial Nos. 508
and 274
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On May 31, 1990, the inspector toured the 70, 95, 114, 141 and 170-foot
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elevations of the auxiliary building. Housekeeping was good on all elevations. The inspector noted that painting / preservation work is
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continuing in the crescent area (70-foot elevation) with good results.
The inspector also noted that lamping was satisfactory on these elevations, However, a large fraction of lamps in the RHR rooms need to be replaced.
The RHR rooms currently are high radiation areas and relamping will have to be done with this as a consideration.
i The inspector verified that all energency core cooling system (ECCS)
valves in the crescent area were in the correct position by observation of
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the valve operator position indicator, the stem position indicator, and
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the valve stem position with respect to the valve yoke.
On the 95-foot elevation, the 19spector verified that the test return line. to the
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suppression pool valves (MOV 24A, B, and C) were closed and the minimum
flow line valv9s (MOV 18A, B, and Ci were opened. The first set of
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valves, if mispositioned, would be a major diversion pathway for ECCS
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water; tto second set of valves are required to be open on low pressure ECCS systems for pump protection.
The LPCS test return and minimum flow
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vc1ves (MOV 12 and MOV 11, respectively) were also correctly positioned.
The inspector utilized Radiation Work Permit RWP 90-0002 and was issued t.n alarming dosimeter by RP technicians in order to conduct an inspection of the RHR "A" and "B" equipment rooms. These rooms are designated as high radiation areas. The inspector noted that the high radiation rope barricades were properly posted and constructed so as to preclude inadvertent entry. Stay time in the room by the inspector was kept to a minimum in observance of "as low as reasonably achievable" (ALARA)
principles.
For both rooms, the RHR heat exchanger inlet, outlet, and bypass valves (MOV 047,003,and048),theshutdowncoolingisolation valve (MOV 006), the nenual fuel pool cooling isolation valve (V 066), the manual minimum flow isolation valve (V 018), the RHR pump discharge line manual (locked open) isolation valve (V 029), and the RHR to radwaste system isolation valves (V 040 and 049) were observed to be properly positioned. On the auxiliary building 170-foot elevation the inspector observed the containment air lock to be properly rope barricaded and posted as an " Airborne Radiation Area" in accordance with the plant conditions at 'that time.
It was noted that the personnel cor.tamination nonitor, PCM-1B (Serial No. 343), in the area was out of service.
Subsequent discussions with RP personnel indicated that workers exiting r.ontainment at this point would be required to perform a whole body frisk with the nearby RM-14 (Serial No. 5965) and then proceed to the RP control point at the "T" tunnel (turbine building 95-foot elevation). This appears to be an acceptable practice pending the return of the PCM-1B to service (theinspectorhadpreviouslycheckedthemonitoringequipmentat this RP control point). The RM-14 (Serial No. 5965) was verified to be within the calibration due date and properly functioning. Discussions j
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On the auxiliary building 114-foot elevation, the inspector verified the proper position of the RHR injection valves (MOV 027A, 0278, and 0420). Also, the inspector verified correct breaker positions on the 114-and 141-foot elevations for the following safety-related electrical motor control centers:
1EHS*MCC 28 and 2D, 1EHS*MCC 2E, 1EHS*MCC 2F and 2H, and IEHS*MCC 2K, The inspector noted that all breaker switches were correctly positioned or had a properly authorized clearance tag.
The inspector also toured the Standby Gas Treatment System "A' and "B" rooms on the 141-foot level and the general areas on all elevations.
Periodically, during the inspection period, the inspector observed the RP shif t turnover process, read RP logs, and discussed general and specific radiological conditions in the plant with RP technicians end foreman.
The inspector observed security personnel perform their duties of personnel
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and package search.
Vehicles were properly authorized and controlled or escorted within the protected area (PA).
Personnel access was observed to be controlled in accordance with established procedures. The inspector conducted site tours to ensure that compensatory posts were properly implemented as required following an equipment failure or degradation.
The PA barriers were adequately illuminated and the isolation zones were free of transient materials.
On May 23, 1990, the inspector toured the central alarm station (CAS) and discussed the status and usage of various security monitoring devices with
the assigned officer. The inspector received satisfactory answers to
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questions regarding the operability of various indicators in the CAS. The inspector discussed the impact of the damaged inverter on security systems with the officer who had been on duty at the secondary alarm station at the time of the event.
No violations or deviations were identified.
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5.
Maintenance Observation (62703)
On May 31, 1990, the inspector observed the performance of a preventative l
maintenance (PM) task on the LPCS system. LPCS is part of the emergency
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core cooling system, which is designed to prevent excessive fuel cladding s
temperatures in the event of a loss of coolant accident. The PM task
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involved the calibration of local flow and pressure indicators for the system.
Specifically, E21*PIR001 and E21*PIR002, the LPCS pump local l
suction and discharge pressure indicators, were calibrated. Also, "kcep l
fill"SubsystempumpindicatorsCSL-PI125(suctionpressure),
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CSL-PDI135 (pump differential pressure), and CSL-FI121 (flow indicator)
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authorizingMaintenanceWorkOrder(HWO)P539023.
The technicians, as directed by the MWO, utilized the following LPCS loop calibration reports
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for calibration data:
LCR No. 1.ILCSL.004 LocalFlowIndicators)
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LCR No. 1.ILCSL.003 Local Differential Pressure Indicators)
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LCR No. 1.!LCSL.001 Locally Mounted Pressure Indicators)
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The inspector later reviewed the calibration data sheets and verified that all "as-left" values were within acceptable limits.
l The inspector discussed the work in progress with the technicians and concluded that they had a good working knowledge of what was required to properly perform the task and were adhering to administrative controls.
i No violations or deviations were identified.
6.
Surveillance Test Observation (617?6)
On Ma) 24, 1990, the inspector observed performance of the final portions of Surveillance Test Procedure STP-204-4209, "LPCI Pump B Discharge Flow-Low Monthly Chfunct; 18 Month Chcal, 18 Month LSFT (E12-N0523 E12-N652B)." The purpose of this serveillance is to perform a channel calibration of pump discharge flow instrumentation as required by Technical Specification 3/4.3.3.1 Teble 4.3.3.1-1.B.1.e.
Additionally, this procedure satisfies a portion of the Logic Systcm Functional Testing (L$FT)
requirements of Technical Specification 3/4.3.3.2, Table 4.3,3.1-1M.1.e.
1his test applies an input to Transmitter E12-N052B and verifics that the LPCI Pump B Discharge Flow-Low Reinys E12A-K5YB and E12A-K1128 energize.
The inspector discussed the test with the technician. The technician knew the purpose of the test and how the objectives were met, had received authorization to perform the test, and had satisfied other necessary prerequisites prior to performing the task. The inspector verified by observation that leads requiring relanding had the proper administrative 1y-required (GMP-0042) lif ted lead tags, required test equipment in use was within the calibration due date, and independent verification required to that point had been documented. Subsequently, the inspector reviewed the attachments to the completed procedure and verified that test results were acceptable.
No violations or deviations were identified.
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Licensee Plans for Coping With a Strike (92709)
The licensee's contract with bargaining unit employees is due to expire on June 23, 1990. The inspector has reviewed the licensee's strike contingency plans in accordance with inspection program requirements.
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On June 11, 1990, the licensee, in a conference call with the NRC staff,
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described how staffing and surveillance needs would be met.
In general.
the licensee has sufficient trained and qualified resources to continue j
routine operation.
Shift operations would be conducted by licensed individuals who are normally on shift. The shift rotation would be the sane as that normally used for outages.
The last strike at Gulf States Utilities occurred in 1975.
If a tentative settlement is reached, the International Brotherhood of Electrical Workers (IBEW) has 7 days to ratify the contract.- The bargaining unit includes nonmanagement operators, maintenance personnel, and technicians but does not include security personnel. RBS was described as 45 percent unionized.
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Qcensee h ent Reports (LERs)
(92700)
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During this inspection period, the inspector reviewed the following LER for comp 19nce with requirements established in 10 CFR 50.73:
(Closed)LER(458/90-018): " Reactor Water Sample Valve Isolation
(ESF) Due to Blown Fuse." A sample isolation valve went to the-c?csed position due to a blown fuse coincident with the conduct of.s surveillance test on asscciated circuitry.
An investigation by the licensee disclosed thet the banana jacks
(previously installed insulated clips) were properly utilized, the procedurally-required jumper to these jacks was in an open area of the panel, surrounding metal in the area was insulated, and there were no visible arc marks to indicate that a jumper had possibly shorted, blowing the fuse. Additional investigation failed to disclose the cause for the fuse failure.
The licensee replaced the fuse, reset the isolation logic, and
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reopened the reactor water sample valve. A modification (MR87-0576) to provide indication for Division I and 11 for nuclear steam supply system isolations has been scheduled for completion during the third refueling outage.
This LER is closed.
9.
Exit Interview An exit interview was conducted with licensee representatives identified in paragraph 1 on June 15, 1990. During this interview, the NRC inspector l-reviewed the scope and findings of the report. The licensee did not identify as proprietary any infonnation provided to, or reviewed by, the inspector.
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