IR 05000321/1989016
| ML20248D199 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 09/20/1989 |
| From: | Brockman K, Menning J, Randy Musser NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20248D183 | List: |
| References | |
| 50-321-89-16, 50-366-89-16, NUDOCS 8910040153 | |
| Download: ML20248D199 (16) | |
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Report Nosi:M50-321/89-16and50-366/89J16
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Licensee:1-Georgia 1 Power. Company;
..P.O. Box!1295
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' Birmingham?AL 35201L
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A Docket Nos m :50-321 and 50-366
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Ocense~ Nos.:"DPR-57 and 'NPF-5
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Facility Name: A Hatch Uni _tst1'and 2
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7InspectiontDatesiL: July-22 - August 25, 1989 m
+ Ins'pectionlat Hatch site;near Baxley.. Georgia
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JJohn, K Menning, Senior Reffdent Inspector Date Signed
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RandfT1 - A. Musser, Residdtit Inspector.
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' ' Approved by':
M Q68f Ken E...Brdckman, Chief', Project Section 3B Uate Signed
. Division:of Reactor Projects SUMMARY
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Scope:
This: routine inspection was conducted at the site in the areas of
Operationa1 HSafety Verification. Maintenance.0bservation, Sur-ve111ance Testing. 0bservation,. Reportable Occurrences Operating
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C Reactor Events, Evaluation of Licensee's;Self-Assessment Capability,
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' Installation and Testing of Modifications, Inspection for Verf-
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fication 'of BWR Recirculation Pump Trip (TI-2515/95), Inspection for Verification of Mark I BWR Drywell. Vacuum Breaker Modifications (TI 2515/96),;and Action on Previous Inspection Findings.
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TResults: One non-cited ' violation was identified during this reporting period.
The NCVr(paragraph :5) was for'a. surveillance tracking software
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, deficiency; that 4resulted in inadvertent de-activation of a I
-surveillance task.
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P No specific 4 strengths or weaknesses of licensee programs were identifiedibased on the inspectors' findings'and observations in the areas inspected.'
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8910040153 890920 PDR ADOCK 05000321 l
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REPORT DETAILS 1.
Persons Contacted Licensee Employees C. Coggin, Training and Emergency Preparedness Manager D. Davis, Manager General Support J. Fitzsimmons, Nuclear Security Manager
- P. Fornel, Maintenance Manager 0. Fraser, Site Quality Assurance Manager
- G. Goode, Engineering Support Manager
- M. Goege Outages and Planning Manager W. Kirkley, Acting Health Physics and Chemistry Manager J. Lewis, Acting Operations Manager C. Moore, Assistant General Manager - Plant Support
- H. Nix, General Manager - Nuclear Plant H. Sumner, Assistant General Manager - Plant Operations
- S. Tipps, Nuclear Safety and Compliance Manager Other licensee employees contacted included technicians, operators, mechanics, security force members and office personnel.
NRC Resident Inspectors
- J. Menning
- R. Musser NRC management on site during inspection period:
G. Belisle, Chief, Test Programs Section, DRS, Region II S. Ebneter, Regional Administrator, Region II
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- E. Merschoff, Deputy Director, Division of Reactor Safety, Region II I
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragraph.
2.
Operational Safety Verification (71707) Units 1 and 2 Both Hatch units continued operating at power during this reporting period with Unit 2 continuing its end-of-cycle power coastdown.
Unit 2 was operating at approximately 80 percent of rated power at the start of the reporting period and operated at approximately 72 percent of rated power j
at the end of the period. At approximately 1611 on August 20, 1989, both Hatch units experienced unanticipated recirculation pump runbacks as a result of grid voltage fluctuations.
Unit I was reduced in power to approximately 510 MWe, while Unit 2 was reduced to approximately 345 MWe, Following checks of equipment performance, both units began power
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ascension with Unit.1 achieving rated power at 2005 and Unit 2 achieving c
maximum attainable power at 2053. The details of this event are discussed in-paragraph 6.
The inspectors kept themselves informed on a daily basis of the overall plant status and any significant safety matters related to plant operations. Daily discussions were held with plant management and various members of the plant operating staff. The inspectors made frequent visits to the control room. - Observations included control room manning, access control, operator professionalism and attentiveness, adherence to procedures, adherence. to limiting conditions for operation, instrument readings, recorder traces, annunciator alarms, operability of nuclear instrumentation and reactor protection system channels, availability of power sources, and operability of the Safety Parameter Display system.
These observations also included log book entries, tags and clearances on equipment, temporary alterations in effect, ECCS system lineups, containment integrity, reactor mode switch position, conformance with technical specification ' safety limits, daily surveillance, plant chemistry, scram discharge voluce valve positions, and rod movement controls.
This inspection activity involved numerous informal discussions with operators and their supervisors.
The operability of selected safety-related systems was confirmed on essentially a weekly basis.
These confirmations involved verification of proper valve and control switch positioning, proper circuit breaker and fuse alignment, and operability of related instrumentation and support systems.
Major components were also inspected for leakage, proper lubrication, cooling water supply, and general condition.
On August 1, 1989, the inspector confirmed the operability of the Unit 2 "A" Core Spray system loop.
Proper electrical, valve, and switch alignments were confirmed using Attachments 2 and 3 to procedure 34S0-E21-001-2S.
On August 3,1989, the inspector confirmed the operability of the Unit 2 RHRSW system.
Proper breaker, switch, and valve lineups were confirmed using Attachments 2 and 3 to procedure 3450-E11-010-2S.
On August 16, 1989, the inspector confirmed the operability of the Unit 1 "B" Core Spray system loop.
Proper breaker, switch, and valve lineups were confirmed using Attachments 2 and 3 to procedure 3450-E21-001-15.
On August 20, 1989, the operability of the Unit 1 SGTS was confirmed. Proper switch and valve lineups were verified using Attachments 1 and 3 to procedure 3450-T46-001-IS.
During the walkdown of the Unit 2 "A" Core Spray system loop on August 1, 1989, the inspector observed that valve 2E21-F3010A was not listed on the system valve lineup sheets (Attachment 3 to procedure 3450-E21-001-25).
This valve functions as a pump discharge pressure switch root valve. The inspector was initially concerned that existing procedures might not provide for periodic checking of the valve's position. After discussions with the licensee, the inspector determined that the position of 2E21-F3010A is checked during the performance of Attachment 2 to procedure 34G0-0PS-004-25, " Nuclear Boiler lineup and Reference Leg Backfill." This Attachment is performed when the unit has been in cold shutdown greater than 4 weeks or when required by operations management.
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During the walkdown of the Unit 1 *B" Core Spray system loop on August 16, 1989, the inspector observed that the actuator for valve 1E21-F019B indicated that the valve was closed while the remote indication in the control room indicated that the valve was open. This valve is norme11y in the open position as well as failing in the open position.
(Valve 1E21-F019B requires air to close and opens upon removal of air pressure using spring force.)
To confirm the valves' open status, the licensee checked several items.
First, the technical specification surveillance for pump and valve operability were determined to be current. Secondly, a suction pressure of 5 psig was determined to exist at the Core Spray pump, a value which corresp(onds approximately to the height (head) of water located in the torus the Core Spray pump suction source). Additionally, the licensee stroked the IE21-F019B valve to the closed position (using the control room indication as a reference) and returned to the open position (again using the control room indication as a reference). During the cycling of the valve to the original position, air was noted to be bled off from the valve actuator as expected for this valve returning to the open position.
Further investigation has revealed that the RHR suction valve 1E11-F0658,
"A" Core Spray system loop suction valve 1E21-F019A, and HPCI suction valve 1E41-F051 have similar conditions with their corresponding valve actuators.
The licensee has corrected the discrepant condition on the actuator for valve 1E21-F019B by etching the correct corresponding valve position onto the valve actuator.
A similar correction will be performed on the previously mentioned RilR, CS and HPCI valves.
No problems were noted in the corresponding valves in Unit 2.
Also noted during the walkdown were a few minor discrepancies as follows:
(1) valve IE21-F3002B (CS pump discharge outboard drain) was not labeled, (2) the handwheel for valve IE21-F019B-AS1 (air supply isolation to valve IE21-F019B) was missing, and (3) the upper bellows of valve 1E21-F069B (Jockey Pump system regulating valve) had a slight air leak.
These problems were brought to the attention of the Unit 1 Shift Supervisor.
l During the walkdown of the Unit 1 SGTS on August 20, 1989, the inspector I
observed that the descriptions of four valve control switches in procedure 3450-T46-001-IS were inaccurate.
The procedure describes the control switches for valves 1T41-F032A and B and IT41-F040A and B as keylock switches.
The inspector noted that the subject switches are not provided with keylocks.
These discrepancies were brought to the attention of the i
l Unit 1 Shift Supervisor.
I General plant tours were conducted on at least a weekly basis.
Portions i
of the control building, diesel generator building, intake structure, I
turbice building, reactor building, and outside areas were toured.
Observations included general plant / equipment conditions, fire hazards, fire alarms, fire extinguishing equipment, emergency lighting, fire barriers, emergency equipment, control of ignition sources and flammable materials, and control of maintenance / surveillance activities in progress.
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- Radiation protection controls, implementation of the physical-security
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program, housekeeping conditions / cleanliness, control of missile hazards, and instrumentation and alarms in the main control room were also observed.
In the area of housekeeping the following discrepancies were observed by it
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On August 4,1989, while touring the Unit 2 Reactor Building, the inspector discovered an accumulation of trash in the HPCI Room. This was brought to'the attention of the Unit 2 Shift Supervisor.
On August 14, 1989, potentially contaminated water was observed on
the floor adjacent to liquid sample panel 1P33-P101.
This panel is
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located on elevation 110 in the Unit 1 Reactor Building.
Additionally, apparently used items of anticontamination clothing were observed in a clean area adjacent to the RWCU heat exchanger room entrance on elevation 158 in the Unit 2 Reactor Building. These.
discrepancies were brought to the attention of health physics supervisory personnel.
The inspectors otearved selected operations shift turnover briefings to confirm that all necessary information concerning the status of plant systems was being addressed.
Each briefing was. conducted by the oncoming OSOS.
The inspectors noted that each OSOS discussed existing plant problems, activities that were anticipated for the shift, and any new standing orders or management directives.
Radiological and industrial safety were generally stressed.. The STAS discussed any recent procedure revisions that impacted on the attendees.
The inspectors attended shift turnover briefings on the following dates and shifts: July 30,1989 -
Evening; August 2, 1989 - Day; August 13, 1989.- Day; and August 20, 1989
- Day.
Several safety-related equipment clearances that were active were reviewed to confirm that they were properly prepared and placed.
Involved circuit breakers, switches, and valves were walked down to varify that clearance tags were in place and legible and that equipment was properly positioned.
Equipment clearance program requirements are specified in licensee procedure 30AC-0PS-001-05, " Control of Equipment Clearances and Tags." On July 27, 1989 Unit 1 equipment clearance 1-89-910 was walked down. This clearance was placed to isolate drywell cooling fan IT47-B008A-2.
On August 3, 1989 Unit 2 equipment clearance 2-89-701 was walked down. This clearance was placed to support the relocation of a Drywell Pressure / Torus Water level Recorder.
Implementation of the licensee's sampling program was reviewed by the inspector.
This review involved observation of sampling activities t
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(reactor coolant and tank sampling) and chemistry surveillance.
Related records were also reviewed.
During this inspection period, the inspector monitored the following activities.
On August 1,1989, the inspector observed the sampling and isotopic analysis (sum of six) of the Unit 2
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Off-Gas in accordance with procedures 64CH-SAM-001-0S and 64CH-RPT-002-05.
On August 21, 1989, the inspector observed a routina monthly surveillance of the Post Accident Sampling System using the Automated Isotopic Measurement System. An analysis was performed on a Unit 2 reactor coolant sample ~in accordance with procedure 62CH-SAM-031-OS.
The licensee's deficiency control system was reviewed to verify that the system is functioning as intended.
Licensee procedure 10AC-MGR-004-05,
" Deficiency Control System," establishes requirements and responsibilities for the preparation - processing, review, and disposition of deficiency reporting documents. This procedure applies to all deficiencies affecting equipment, procedures, or personnel.
Deficiencies are reported on Deficiency Cards.
On July 27, 1989, the inspector reviewed DCs that had been generated the previous two days. The inspector verified that DCs had been prepared as required by the controlling procedure and that several deficiencies that were noted in the Shift Supervisors' logs had been documented-on DCs.
More specifically, the inspector verified that DC 1-89-3162 had been prepared to document the unanticipated tripping of the Unit I hydrogen injection system.
It was also noted that DC 1-89-3150 had been generated to document the failure of Drywell Cooling fan 1T47-B008A-2.
On August 2,1989, the inspector also reviewed recently prepared DCs and verified that problems observed in the plant had been properly documented.
The inspector observed that DC 1-89-3225 had been prepared to document a leak in the cooling coil of the lube oil cooler for the motor of PSW pump 1P41-C001A.
It was also noted that DC 1-89-3226 had been generated to document erroneous readings on flow indicator 1E21-R601A for the "1A" Core Spray pump.
Selected portions of the containment isolation lineup were reviewed to confirm that the lineup was correct. The review involved verification of proper valve positioning, verification that motor and air-operated valves were not mechanically blocked and that power was available (unless blocking or power renoval was required), and inspection of piping upstream of the valves for leakage or leakage paths.
On August 1, 1989, the inspector reviewed the following Unit 2 containment isolation valves:
2T48-F325, 2T48-F327, 2T48-F332B, 2T48-F333B, 2T48-F334A, 2T48-F334B, 2T48-F335A, 2T48-F335B, 2148-F340, 2T48-F341, 2T48-F342C-H, 2T48-F363A, 2T49-F002A, 2T49-F002B, 2T49-F004A, and 2T49-F004B.
On August 2, 1989, the inspector reviewed the following Unit I containment isolation valves:
1T48-F324,1T48-F325, IT48-F326,1T48-F328A and B, IT48-F332A and B, IT48-F333A and B, IT48-F334A and B, IT48-F335A and B, IT48-F338, IT48-F339, IT48-F34G, and 1T48-F341.
No violations or deviations were identified.
3.
Maintenance Observation (62703) Unit 1 During the report period, the inspectors observed selected maintenance activities.
The observations included a review of the work documents for adequacy, adherence to procedure, proper tagouts, adherence to technical specifications, radiological controls, observation of all or part of the l
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actual work and/or retesting in progress, specified retest requirements, and adherence to the appropriate quality controls.
The : primary maintenance observations during this month are summarized below:
Maintenance Activity Date a.
Changing of Alarm Set Points on 07/27/89 Recorder IT47-R611 in accordance with MWO 1-89-3381 b.
Repair and Replacement of Power 07/31/89 Supply IC11-PS7 in accordance with MWO 1-89-3417 c.
Repair of the Upper Bearing Lube 08/02/89 Oil Cooler on the 1A PSW Pump Motor in accordance with MW0 1-89-3457 d.
Checkout of valve actuator positioner 08/17/89 on valve 1E21-F019B in accordance with MWO 1-89-3751 No violations or deviations were identified.
4.
Surveillance Testing Observation (61726) Unit 1 The inspectors observed the performance of selected surveillance.
The observation included a review of the procedure for technical adequacy, conformance to technical specifications, verification of test instrument calibration, observation of all or part of the actual surveillance, removal from service and return to service of the system or components affected, and review of the data for acceptability based upon the acceptance criteria. The primary surveillance testing observations during this month are summarized below:
Surveillance Testing Activity Date a.
ADS Actuation Logic Test 08/01/89 in accordance with procedure 42SV-B21-008-1S b.
APRM FT&C in accordance with 08/02/89 procedure 345V-C51-002-IS c.
RCIC Pump Operability in 08/03/89 i
accordance with procedure 34SV-E51-002-IS d.
Diesel Generator "1C" Monthly 08/22/89 Test in accordance with procedure 34SV-R43-003-IS
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On August 3,1989, during )the performance of the RCIC Pump Operability (procedure 345V-E51-002-IS, the inspector noted a minor procedural-discrepancy.. Specifically, step 7.2.30.1 instructs the operator to reduce l
the RCIC Turbine ~ speed to.about 2000 RPM.
The step incorrectly implies-that the operator.should be observing the turbine speed from gauge 1E51-R613. (RCIC Pump. Flow Indicator) in 1.ieu of gauge 1E51-R610 (RCIC Turbine Speed).
This condition was brought to the attention of the Operations Superintendent.
On August 22, 1989, during the performance of the "1C" Diesel Generator Monthly Test (procedure 345V-R43-003-IS), the inspector noted that-the surveillance procedure referenced annunciator numbers designated in Annunciator Response Procedure (ARP) 34AR-652-903-15.
However, the "1C" Diesel Generator related annunciators (located on panel 1H11-P652-3) are presently identified by numbers designated by ARP 34AR-652-001-1 as ARP 34AR-652-903-1S in not yet currently in effect.
ARP 34AR-652-903-IS is presently awaiting. typing and final approval under the licensees'
Procedure Upgrade Program.
Implementation of the procedure is planned by September 1, 1989.
This condition was brought to the attention of the Manager of Operations.
No violations or deviations were identified.
5.
Reportable Occurrences (92700) Unit 1 A number of LERs were reviewed for potential generic impact, to detect trends, and to determine whether corrective actions appeared appropriate.
Events which were reported immediately were also reviewed as they occurred to determine that technical specifications were being met and the public health and safety were of utmost consideration.
Unit 1:
89-03 Tracking Program Software Deficiency Results in Missed Surveillance This LER concerns a failure to perform monthly Turbine Control Valve Fast Closure functional testing as required by Unit 1 Technical Specification Table 4.1-1, item 11, and Table 4.2-9, item 3a.
Testing was not performed between December 10, 1988, and March 2, 1989, due to a software deficiency. The software for technical specification surveillance scheduling and tracking did not have any safeguards to prevent a surveillance task from being inadvertently de-activated.
The subject test was insertently de-activated on December 13, 1988, during the course of a surveillance task revision.
Testing was successfully completed on March 2, 1989, following the licensee's discovery that surveillance had been missed.
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Corrective actions involved changing the' scheduling and tracking program's. software and. issuing a Department' Instruction.
The' software was changed so that revisions to the critical scheduling' parameters L
of frequency, active indicator, due date, grace-
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indicator, grace period, bypass indicator, and date L
routine are challenged by the computer. The inspector verified: that these software changes. had, been made..
The Department Instruction was issued to compliment..
and clarify existing administrative controls.
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specifically, it was ' intended to provide explicit instructions concerning what to review when verifying a revised surveillance task and information on which fields are critical for correct surveillance scheduling.
The inspector reviewed Department" Instruction DI-REG-018-0489N, Rev.
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" Technical Specification Surveillance Data Base Verification,"
.and concluded that the intended actions had been completed.
This matter is a violation of Technical Specification Table 4.1-1, item 11, and Table 4.2-9, item 3a.
However, this violatior. meets the criteria in Section-V.G.1 of the NRC Enforcement Policy for not issuing a Notice of Violation and. therefore, is not being cited.
This matter, identified as NCY 321/89-16-01, is considered closed.
Review of the LER is also closed.
One non-cited violation was identified.
6.
OperatingReactorEvents(93702) Units 1and2 The inspectors reviewed activities associated with the below listed reactor event.
The review included determination of cause, safety significance, performance of personnel and systems, and corrective action, The inspectors examined instrument recordings, computer printouts, operations journal entries, and had discussions with operations, maintenance, and engineering support personnel as appropriate.
At approximately 1611 on August 20, 1989, the Unit 1
"B" reactor recirculation pump and the Unit 2 "A" and "B" recirculation pumps ran back to their number 2 speed limiters (44 percent of rated pump speed)
following an event in the 500 KV switchyard.
The Load Dispatcher was attempting to remove the Duval White Inductive Load Transformer from service.
This is done by opening Automatic Interrupter Mechanism (AIM)
Switch 179766 between the Duval White Line and the Inductive Load Transformer.
However, the AIM switch did not open fully.
The switch
opened only approximately 18 inches. This was not far enough to break the arc between the blades of the switch. With the continuous arcing, current continued to flow to six interrupters (two in series in each of the three
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lines) located.between'the AIM switch and the Inductive Load Transformer.
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The six interrupters are used when the switch is opened to help limit and break the arc.
They are,.in effect, large resistors which. are. engaged during. switch opening to carry most of the current passing through the switch.
They are designed to carry the current only approximately two minutes (while the switch is opening).
When the switch failed to open completely, current passed through the interrupters for longer than their rated one to two minutes. 'They overheated and disintegrated, destroying the interrupters and the surrounding ceramic insulators.
This broke the circuit and terminated the event in the switchyard..
During the event, the Unit I megawatt recorder indicated that load momentarily spiked to 850 MWe (from a pre-evut level of 780 MWe) with generator voltage spiking from 21.7 to. 23.6 KV.
Likewise, the Unit 2 megawatt recorder. indicated that load momentarily spiked to 590 MWe (from a pre-event level of 564 MWe) with generator voltage spiking from 24.7 to 28 KV.
Following the runbacks in recirculation pump speed, Unit 1 power level was reduced to 510 MWe while Unit 2 load was reduced to 345 MWe.
Reactor vessel water level in Unit i ranged from an indicated high level of plus 50 inches to an indicated low level of plus 28 inches during the transient.
The reactor vessel water level in Unit 2 ranged from an indicated high level of plus 48 inches to an indicated low level of plus 34 inches.
Each units' operators took manual control of the feedwater system and quickly stabilized water level.
Following checks of equipment performance, both units began power ascension with Unit 1 achieving rated power at 2005 and Unit 2 achieving maximum attainable power at 2053.
The problems with plant equipment as detailed above appear to be related to voltage fluctuations experienced while the switch was arcing.
The licensee has determined through review of SPDS tapes that the recirculation pump run backs did not result from valid signals (Low reactor water level and less than 20 percent feedwater flow in one feed pump).
At this time, it is believed that AIM Switch 179766 did not open completely because the switch's gears or gear assembly failed or froze.
The licensee has established an event review to more thoroughly examine the causes of the switchyard fault and the ensuing problems experienced by i
the plant.
Within the areas inspected, no violations or deviations were identified.
7.
Evaluation of Licensee Self-Assessment Capability (40500) Units 1 and 2 This inspection effort was performed to evaluate the effectiveness of the licensee's self-assessment programs.
The effort focussed on determining whether the licensee's self-assessment programs contribute to the prevention of problems by monitoring and evaluating plant performance, providing assessments and findings, and communicating and following up on corrective action recommendations.
The inspector initially reviewed activities of the PRB.
(Operations of the licensee's SRB were reviewed and discussed in NRC Inspection Report Nos. 50-321/88-41 and 50-366/88-41 and are not discussed in this report.)
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Responsibilities of the PRB are delineated in Sections 6.5.1 of the Unit 1 and Unit 2 technical specifications.
The PRB Charter is contained in Section 13.4A of the Unit 2 FSAR. Methods to be used in establishing the PRB and related implementing controls are. defined in licensee procedure 10AC-MGR-002-0S, " Plant Review Board Administrative Procedure."
The current PRB members have been designated by the Assistant General Manager - Plant Operations in letter LR-MGR-005-0789 dated July 19, 1989.
The inspector reviewed this letter and verified that the composition of the PRB is consistent with the requirements of Section 6.5.1.2 of the technical specifications.
The inspector reviewed PRB meeting minutes for the period August 4, 1988, to August 1, 1989.
These meetings were designated 88-102 to 88-181 and 89-1 to 89-69.
Based on the review of these minutes and discussions with the PRB Chairman and the cogrizant NSAC supervisor, the inspector determined the following:
The PRB has been satisfying technical specification requirements
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related to meeting frequency, use of alternate members, minimum quorum, and review responsibilities.
Members review material to be discussed prior to meetings, and the meetings are conducted on essentially an exception basis.
The requirement to review unit operations to detect potential safety
hazards is satisfied through the review of SORS.
Significant Occurrence Reports document significant conditions adverse to quality which are identified during the NSAC review of DCs.
Conditions requiring the preparation of a SOR are identified in Section 8.2 of procedure 10AC-MGR-004-0S, " Deficiency Control System."
The PRB utilizes subcommittees to conduct certain reviews.
The meeting minutes reflect reports from subcommittees such as those for E0Ps and DCRs, Documentation of PRB meetings is generally thorough and useful in
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determining topics discussed and the bases for conclusions.
Action items are clearly identified and followed up.
The PRB utilizes an "Open Item" tracking system to follow PRB-generated action items.
Requirements for the handling of Open Items are delineated in Section 8.3 of procedure 10AC-MGR-002-05.
The inspector observed that 34 Open Items were generated in 1988 and 12 Open Items have been generated to date in 1989.
Approval of the PRB is by no means automatic. The inspector observed
that questions or concerns raised by PRB members resulted in the return of many reviewed items to the originating groups.
The PRB also does not restrict its follow-up of weaknesses and problem areas to the specifics being reviewed or to technical specification-related activities.
For instance, Open Item 89-38-01 was generated following
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the review of an event caused by a loose wire. This item was opened to investigate how widespread the problem of loose wires was in the plant and, if appropriate, recommend corrective action.
Open Item 88-09-01 was generated to evaluate the design modification process for partial implementation of DCRs.
The concern was that safety evaluations for DCRs are typically written for the end product and not for partial implementation.
The inspector observed a PRB meeting on August 24, 1989. The chairman effectively lead the meeting and was sensitive to concerns and questions expressed by the members.
Members actively participated in discussions, and the discussions were not dominated by certain individuals.
It appeared that the PRB reviews were thorough and oriented towards safety.
No violations or deviations were identified.
Based on the reviews of PRB activities discussed above, the inspector concluded that the PRB does contribute to the prevention of problems by monitoring and evaluating plant performance, providing assessments and findings, and communicating and following up on corrective actions.
8.
Installation and Testing of Modifications (37828) Unit 1 The objective of this inspection effort was to verify proper installation and testing of plant modifications.
The inspector initially reviewed a Unit 1 PSW system iaodification.
This particular modification, DCR 1H89-162, was implemented to provide permanent tie-ins to the plant service water system for a temporary cooling system.
Specifically, this
change provides two permanent branch connections to the PSW system. One branch connection is located in the Turbine Building on a 16-inch line.
The other branch connection is located in one of the Unit 1 PSW valve pits on a 10-inch line supplying water to the Reactor Building.
This change provides for the addition of chilled water to the service water supplying the drywell coolers.
On August 24, 1989, the inspector performed a walkdown of the installed hardware to verify that the installation confirms to as-built drawings.
The piping in the turbine building and the PSW pit was examined and compared to WCN 89-162-02.
In each area, confirmation of equipment configuration, mounting details, and approximate dimensions and sizes were examined and determined to be as shown on the WCN.
It was determined through specific measurement and visual examination that the designated pipe and valves were installed.
The mounting bracket located in the PSW pit was also determined to be as specified on the licensees' as-built drawings.
Additionally, it was determined that since this modification
was only performed on a safety related portion of the Division I train of the PSW system (the portion of the PSW system located in the turbine building is not safety related), separation is still maintained between the redundant divisions of the system.
No violations or deviations were identified.
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9.
Inspection for Verification of BWR Recirculation Pump Trip - Multi-Plant Action Item C-02 (TI 2515/95) (61726) Units 1 and 2 This inspection effort was performed to verify the installation of recirculation pump trips under conditions indicative of an ATWS event in response to Multi-Plant Action Item C-02.
The inspector confirmed that the ATWS recirculation pump trips are indeed installed and functional via the examination of equipment and observation of the trips' operation luring actual reactor scrams.
For. instance, the recirculation pumps tripped on. low reactor vessel water level during the Unit 1 reactor scram on September 4,.1988.
The Unit 2 recirculation pumps tripped on low reactor vessel water level during that unit's reactor scram on August 5, 1988.. Operability requirements for the ATWS' recirculation pump trips are-contained in Unit 1 Technical Specification Table 3.2-9 and in Unit 2 Technical Specification Table 3.3.9.1-1.
Review of this matter by the resident inspectors is closed.
10.
Inspection for Verification of Mark I BWR Drywell Vacuum Breaker Modifications - Multi-Plant Action Item D-20 (TI 2515/96) (37828)
Units 1 and 2 This inspection effort was performed to verify that any torus to drywell vacuum breaker modifications required in response to Multi-Plant Action Item D-20 have been accomplished.
Generic Letter 83-08 related to modification of vacuum breakers on Mark I containments and identified a potential failure mode of the wetwell/drywell vacuum breakers in chugging and condensation oscillation phases of blowdown to the torus during a loss of coolant accident.
The Generic Letter requested that licensees provide a commitment to submit the results of plant unique calculations which either formed the bases for modifications to vacuum breakers or provided
. justification for their as-built acceptability.
Georgia Power Company's responses were submitted by letters dated June 9, 1983, and March 13, 1986.
The results of the NRR review of the licensee's responses were transmitted to GPC by letter dated April 1, 1987.
It was concluded that the. existing design was structurally adequate and required no modification.
Since no modifications were required, review of this matter by the resident inspectors is closed.
11. Action on Previous Inspection Findings (92702) Units 1 and 2 a.
(Closed) Violation 366/88-34-01 Inadequate Evaluation of ADS Design Deficiency The inspector reviewed the licensee's letter of response dated January 13, 1989.
Corrective action involved correcting the ADS design deficiencies via the implementation of DCRs.
The Unit 1 ADS design deficiency was corrected on November 16, 1988. The Unit 2 ADS design deficiency was corrected on December 17, 1988.
These corrective actions have been reviewed by the resident inspectors and the reviews were documented in NRC Inspection Report Nos.
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50-321/88-34, 50-366/88-34, 50-321/88-40, and 50-366/88-40.
Review of this matter is closed.
b.
(Closed) Violation 321/89-04-01, Deficient RWCU System Operating Procedure The inspector reviewed the licensee's letter of response dated April 8, 1989.
Corrective action involved revising procedures 34S0-G31-003-15 and 34S0-G31-003-2S to provide improved instructions for RWCU pump warming. More specifically, it was intended to include cautions against the possibility of partial voiding as system pressure and temperature decrease and instructions to prevent rapid system filling.
The inspector reviewed Rev. 6 of procedure 3450-G31-003-IS, " Reactor Water Cleanup System," and Rev. 7 of procedure 34S0-G31-003-25, " Reactor Water Cleanup System," and determined that the intended revisions had been made. The revisions were made to Sections 7.1.2 of the two procedures.
Review of this matter is closed.
c.
(Closed) Violation 366/89-06-05, Failure to Perform Daily Checks of A.C. Circuits Within Primary Containment The inspector reviewed the licensee's letter of response dated May 24, 1989.
Corrective action involved permanently revising procedure 34G0-0PS-030-2S, issuing a management memo from the General Manager emphasizing the need for attention to detail with respect to surveillance, and reviewing at least a 10 percent sample of upgraded surveillance procedures to determine if similar problems exist. The inspector reviewed Rev. 9 of procedure 34G0-0PS-030-2S, " Daily Inside Rounds," and confirmed that the procedure had been revised to provide for daily checks of circuits inside panel 2R25-S105.
The inspector also reviewed the General Manager's memo dated March 6, 1989.
Finally, signed off procedure review sheets were checked by the inspector confirming that the licensee had conducted the review of a 10 percent sample of surveillance procedures.
The licensee identified no problems which resulted or could have resulted in violations of technical specification requirements.
Review of this matter is closed.
d.
(Closed) Unresolved Item 321,366/86-41-02, Design of Transfer Canal Seals and the Seal Leak Detection System The system as installed was inspected by the Hatch resident inspectors during the period January 23 - February 19, 1988, with the
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conclusion that the licensee corrective actions had been completed j
(Inspection Report Nos. 50-321/88-05 and 50-366/88-05).
The
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installed system also was observed by the NRR Project Manager on l
March 29, 1986, and a Region based inspector examined the installed modifications during the period July 24-28, 1989, and verified that the modifications to the transfer canal seals and leak detection i
system were installed in accordance with the design modification i
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E package requirements.. Based on these inspections and the completed-L review by_ NRR of the adequacy of the design of the; originally.
- installed canal seals and leak detection system, we conclude that the modifications made by the licensee are sufficient to preclude another
'securrence similar to the December 2-3, 1986, event (141,000 gallon-fuel pool leak).
While the seals and leak-detection system as installed are not single' failure proof, the modifications made by the licensee should assure early detection of any seal-problems such that corrective actions can be taken. Review of this matter is closed.
12. Exit Interview (30703)
The inspection scope and findings were summarized on August 25, 1989, with those persons indicated. in ' paragraph 1 above.
The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspection.
Dissenting comments were not received from the licensee.
Item Number Status Description / Reference Paragraph 321/89-16-01 Opened and
.NCY - Inadequate Surveillance Closed Tracking (paragraph 5)
366/89-06-05 Closed VIOLATION - Failure to Perform Daily Checks of A.C. Circuits Within Primary Containment (paragraph 11.c)
321/89-04-01 Closed VIOLATION - Deficient RWCU System Operating Procedure (paragraph 11.b)
366/88-34-01 Closed VIOLATION - Inadequate Evaluation of ADS Design Deficiency (paragraph 11.a)
321,366/86-41-02 Closed URI - Design of Transfer Canal Seals and the Seal Leak Detection System (paragraph 11.d)
13. Acronyms and Abbreviations ADS Automatic Depressurization System
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Automatic Interrupter Switch AIM
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APRM - Average Power Range Monitor Annunciator Response Procedure i
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ATWS - Anticipated Transient Without Scram i
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Boiling Water Reactor BWR
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Deficiency Card DC
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Design Change Request DCR
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Division of Reactor Safety DRS
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ECCS - Emergency Core Cooling System Emergency Operating Procedure E0P
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Engineered Safety Feature ESF
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FSAR - Final Safety Analysis Report FT&C-Functional Test and Calibration Georgia Power Company GPC
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HPCI - High Pressure Ccolant Injection Kilovolts KV
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Licensee Event Report LER
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Maintenance Work Order MWO
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Megawatts Electric MWe
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Non-Cited Violation NCV
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NRC Nuclear Regulatory Commission
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NRR Office of Nuclear Reactor Regulation
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NSAC - Nuclear Safety and Compliance OSOS - On-Shift Operations Supervisor Plant Review Board PRB
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psig - Pounds Per Square Inch Gauge PSW Plant Service Water
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RCIC - Reactor Core Isolation Cooling RHR Residual Heat Removal
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RHRSW - Residual Heat Removal Service Water RPM - Revolutions Per Minute RWCU - Reactor Water Cleanup SGTS - Standby Gas Treatment System Significant Occurrence Report S0R
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SPDS - Safety Parameter Display System Safety Review Board SRB
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Temporary Instruction TI
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Unresolved Item URI
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Work Completion Notice WCN
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