IR 05000321/1979024
| ML19249C793 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 08/02/1979 |
| From: | Dance H, Rogers R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML19249C789 | List: |
| References | |
| 50-321-79-24, 50-366-79-28, NUDOCS 7909180521 | |
| Download: ML19249C793 (7) | |
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UNITED STATES
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101 MARIETT A sT., N.W., sulTE 3100 ATL ANT A, GEORGI A 30303
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Report Nos. 50-321/79-24 and 50-366/79-28 Licensee: Georgia Power Company 270 Peachtree Street, N. W.
Atlanta, Georgia 30303 Facility Name: Hatch I and 2 Docket Nos. 50-321 and 50-366 License Nos. DPR-57 and NPF-5 Inspection at Ha h Site ne r Baxley, Georgia 7!/ /7 9 Inspector:
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v7 R. FT gers, esident Ins Tr,
NS Branch Dat4 Sigded
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Approved by:
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H. C. Dance, Section Chief, RONS Branch gateSigned SUMMARY Inspection on June 2 - July 3, 1979 Areas Inspected This inspection involved 28 inspector-hours onsite of the Unit i refueling outage, Unit 2 startup testing, technical specification compliance, reportable occurrences, and security procedures.
Results Of the five areas inspected, no apparent items of noncompliance or deviations were identified.
An example to a previous item of noncompliance involving failure to provide a written report within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> was noted (paragraph 10).
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DETAILS
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Persons Contacted Licensee Employees
- M. Manry, Plant Manager
- T. Moore, Assistanc. Plant Manager
- T. Greene, Assistant Plant Manager S. Baxley, Superintendent of Operations R. Nix, Superintendent of Maintenance C. Coggins, Superintendent of Engineering Services W. Rogers, Health Physicist / Radiochemist C. Bellflower, QA Site Supervisor Other licensee employees contacted included construction craftsmen, technicians, operators, mechanics, security fcree members and office personnel.
- Attended exit interview 2.
Licensee Action on Previous Inspection Findings Not inspected.
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Unresolved Items None.
4.
Exit Interview
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The inspection scope and findings were summarized on June 7,15, 28 and July 3,1979 with those persons indicated by an asterisk in Paragraph I The examples to the previous item of noncompliance on timeliness of above.
facsimilie reports was discussed with the licensee on June 7,1979.
5.
Tours of the Plant (Units 1 and 2)
The inspector conducted plant tours periodically during the inspection interval to verify that monitoring equipment was recording as required, equipment was properly tagged, operations personnel were aware of plant conditions and were alert, and plant housekeeping efforts were adequate.
Some tours were conducted on backshifts and on weekends.
Review of Nonroutine Events Reported by the Licensee (Units 1 and 2)
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following licensee event reports (LERs) were reviewed for potential The generic problems, to detect possible t. rends, and to determine whether corrective actions appeared appropriate. Events which were reported imme-technical distely were also reviewed as they occurred to determine that specifications were being met and that the public health and safety was of
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utmost consideration.
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-2-LER No.
Report Date Subject 50-321/79-35 6/7/79 Inability of IA D/G to carry full load 50-321/79-39 7/6/79 Cardox initiation in cable spreading room 50-366/79-20 2/8/79 Low day tank level on 2A D/G 50-366/79-38 5/30/79 Radiation Monitoring System lines not siesmically qualified 50-366/79-39 5/30/79 Valve seat leakage excessive 50-366/79-40 6/4/79 Feed water flow differential pressure elements piped incorrectly 50-366/79-43 6/11/79 MSIV auto bypass switches set high 50-366/79-45 6/11/79 HPCI failure to start due to water in oil 50-366/79-46 6/11/79 RCIC failure to start due to broken check valve 50-366/79-49 6/21/79 HPCI condensate pump trip 50-366/79-50 6/21/79 HPCI suction valve failed to open 50-366/79-53 6/26/79 Main steam line radiation trip set high High Pressure Coolant Injection and Reactor Core Isolation Cooling Malfunctions 7.
and Test Programs (Units 1 and 2)
June 3, 1979 Event On June 3, 1979, a condensate system malfunction resulted in a reactor trip from a low water level in the reactor vessel. The High Pressure Coolant Injection (HPCI) and the Reactor Cor2 Isolation Cooling (RCIC) systems The following is failed to perform as designed following the reactor trip.
a detailed description of the initiating event and the failure of the HPCI and RCIC systems.
The reactor was operating at full power, conducting power ascension testing A condensate booster pump tripped, on low following a maintenance outage.
The low suction suction pressure, at approximately 6:50 p.m. on June 3.
pressure appears to have been caused by operation of the condensate deminer-alizers in manual flow control instead of automatic flow control. Tripping of the condensate booster pump resulted in a decrease in condensate header pressure which caused one of the two operating feedwater pumps to trip on low suction pressure. The remaining feedwater pump continued to operate
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-3-but the resulting mismatch between steam flow and feedwater flow resulted in the reactor vessel water level decreasing and a reactor trip occurred on low water level. Approximately five minute after the reactor trip, the reactor vessel water level low low setpoint was reached and an automatic actuation signal for the HPCI and RCIC systems was initiated.
The HPCI steam turbine driven pump received the initiation signal but did not start because the turbine stop valve failed to open. Water was present in the HPCI turbine oil system and the auxiliary oil pump apparently did not develop sufficient control oil pressure to open the turbine stop valve.
Investigation has revealed two sources of water that may have entered the turbine oil system. One source of water inleakage was a water cooled oil A second cooler which, following the event, was identified to be leaking.
A of water inleakage was from a leak in a seal injection pipe.
source closed valve in the HPCI pump seal cooling cavity drain pipe allowed the leaking seal injection pipe to fill the drain cavity to a level above the pump shaft. This allowed water to enter the bearing housing. The drain line valve was not included in the system valve lineup procedure due to an error on the as-built plant drawings. The Unit 1 HPCI system has been verified not to have an isolation valve in the cavity drain pipe.
The RCIC system started as designed and operated for approximately one minute, then tripped due to a failed (ruptured) turbine exhaust diaphragm on the RCI pump turbine. An internal check valve linkage stub broke, which caused the ten-inch check valve disc in the. turbine exhaust line to come loose. This disc blocked the valve outlet, cuasing a high pressure in the turbine exhaust line and rupturing the turbine exhaust diaphram.
The reactor remained shutdown until investigation, repair and corrective actions to the HPCI and RCIC systems were completed as follows:
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The leaking HPCI seal injection pipe was repaired by replacing a section of the leaking pipe.
The seal injection pipes are being
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evaluated to determine if additional structural supports are required to prevent vibration induced failure.
The HPCI oil system was drained, flushed and refilled twice.
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The HPCI oil cooler in the system was identified as a possible source of water inleakage and subsequent testing with nitrogen confirmed the
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existance of a leak. A study has been initiated by the licensee to identify a method whereby water in the oil systems of the HPCI and RCIC turbines may be readily identified. In the interim, the HPCI oil is being sampled on a weekly scheduled.
The HPCI turbine bearings were inspected for possible damage. The
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inspection revealed no deficiencies.
The valve in the bracket drain pipe was locked open prior to startup and an evaluation was initiated to determine if the valve could be
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removed. The valve has been added to the system valve lineup procedure.
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The RCIC ten-inch valve was repaired and [dified to prevent recurrence.
repres9 tative of the valve vendor
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A design engineer and service (Walworth) were onsite to determine the cause of failure and the The failure was attributed to cycling of proper corrective action.
the swing check valve disc against its stop and failure of the stub where the stub locking pin is inserted. This was corrected by welding the nut to the replacement disc instead of drilling a hole for pinning.
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The vendor The valve was reassembled and leak tested satisfactorily.
representatives informed the licensee that, to their knowledge, this was the first instance of this particular failure mechanism experienced on this type Walworth check valve. The licensee evaluated the service application of other Walworth check valves utilized in plant safety systems and verified their acceptability.
The licensee verified that the Unit 1 RCIC turbine exhaust valve was
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supplied by a different vendor.
The RCIC turbine exhaust diaphragm was replaced.
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The RCIC and HPCI systems were tested and verified to be fully opera-
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tional following the maintenance activities.
The plant safety review board reviewed the a:currence including all investigative actions, repairs and other corrective actions prior to
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the unit returning to service.
The confirming written notification of this event was late in arriving the Regional office as discussed in the letter of transmittal.
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at This is another example of noncompliance regarding reporting transmitted to Georgia Power Company (GPC) in letter dated July 20, 1979. On June 7, 1979, the Regional Director and. members of his staff met with a senior GPC representative in Atlanta, Georgia to discuss this occur-rence and proposed corrective actions.
Significance of the Occurrence
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Facility Technical Specification requires the RCIC to be operable but it is not part of the emergency core cooling systems. In this particular event, it should be noted that one feedwater pump continued to supply water to the reactor vessel and maintained water level approximately +en feet above the top of the core. The lowest water level reached during the event was minus duration of approximately one minute. Had the forty-five inches for a water level continued to decrease, the low Pressure Coolant Injection System and the Core Spray System would have been automatically actuated.
June 27, 1979 Event 27, 1979, the Main Steam Isolation Valve (MSIV) closure test was On June conducted from full power and the HPCI and RCIC systems received their initiation signals when reactor water level reached its low low setpoint.
Both systems, however, isolated on high steam line differential pressure yh
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and had to be started manually The isolation signals appeared to be transient The in the d/p signal associated with a normal start sequence.
spikes isolation signals are designed to protect the reactor in case of a break in the respective steam lines.
This second simultaneous failure of the HPCI and RCIC systems to perform as designed resulted in a hold on either Unit starting up until the NRC was satisfied with the licensees efforts to determine the cause of the failures, reevaluate all previous failures or abnormal performances associated with these systems, evaluate maintenance and repair activities and plant practices which may affect these systems, and to establish a comprehensive retest The above program to verify the reliability of the HPCI and RCIC systems.
hold was contained in a confirmation of action letter to GPC from the NRC Region II Director on June 28, 1979.
The inspector ret with licensee representatives on July 1 and 2 to review the results of their investigation. Analysis of past failures, changes being made to operating procedures, modifications made and being considered and the planned retest program for the HPCI and RCIC systems were discussed in detail. A comprehensive Unit 2 retest program for both the HPCI and RCIC was developed to assure system operability.
The program included twelve quick starts at varying pressures between 150 - 1000 psig and five cold starts at operating conditions. The Unit I retest program will reflect the Unit 2 experience. NRC and QA hold points are incorporated into the referenced test procedure. The inspector and the Region II office concurred in the planned retest program, and the corrective action taken. A Confirma-tion of Concurrence letter was sent to APC on July 5,1979.
The Resident Inspector will continue to follow this item.
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Technical Specification Compliance (Units 1 and 2)
During this reporting interval, the inspector verified compliance with selected limiting conditions for operation (LCO's) and results of selected surveillance tests. These verifications were accomplished by direct obser-vation of monitoring insutrmentation, valve positions, switch positions, and review of completed logs and records. The licensee's compliance with selected LCO action statements were reviewed on selected occurrences as they happened.
9.
Elevated Tritium Samples (Units 1 and 2)
On June 27, 1979, the Licensee reported additional information relative to its investigation of the tritium leaks to the plant yard. This information was reported as a supplement (revision 3) to the origiual report on this matter (LER 50-321/1979-021).
This report confims a second source of tritium contamination other than the nitrogen purge line. The source is leakage over a period of time from the condensate storage tank (CST) transfer pumps.
Intermittent leakage from this source as well as that from the nitrogen purge line has been terminated.
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These leaks have contributed to elevated tritium levels in the outfalls of the surface and subsurface drainage system which discharge above the river boundary but within the property boundary of near the restricted areaThe tritium levels as previously reported in the Georgia Power Company.
The highest tritium concentration outf alls have remained relatively constant. concentration is 0.1% of the 3.01/1.
This from an outfall is 3.1 x 10
maximum permissible concentratioa of 3.0 x 104Ci/l allowed by NRC Regulation The outfalls remain 10 CFR 20 for liquid releases to unrestricted area.s.
dry a part of the time and, accordingly, there is no flow to the river during such periods.
The State of Georgia is continuing to provide offsite environmental surveil-lance around the Hatch facility and has found no evidence of elevated tritium levels in the Altamaha River, private water wells in the area, or public drinking water supplies in the near communities.
Additionally, the NRC has conducted independent environmental measurements Region II's evaluation of the safety significance of onsite and offsite.
these tritium levels remains unchanged.
The levels detected are well to the health and within the established limits and present no threat safety of workers at the facility or members of the general public.
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