IR 05000289/1989001
| ML20247M597 | |
| Person / Time | |
|---|---|
| Site: | Crane  |
| Issue date: | 03/27/1989 |
| From: | Cowgill C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20247M584 | List: |
| References | |
| 50-289-89-01, 50-289-89-1, NUDOCS 8904060088 | |
| Download: ML20247M597 (15) | |
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U.S. NUCLEAR' REGULATORY COMMISSION
REGION I
Docket / Report No. 50-289/89-01 License:.OPR-50 Licensee:
GPU Nuclear Corporation P. O. Box 480 Middletown, Pennsylvania 17057 Facility:
Three Mile Island Nuclear Station, Unit 1 Location:
Middletown, Pennsylvania Dates:
January 15 February 25 and 27, 1989 Inspectors:
R. Conte, Senior Resident Inspector D. Johnson, Resident Inspector T. Moslak, Resident Inspector (Reporting Inspector)
A. Sidpara, Resident Inspector S. Chaudhary, Reactor Inspector, Region I J. Carrasco, Reactor Inspector, Region I Approved by:
MAM4Mk4 3/CV59 C. 'C4 gill, Chief, Reactor Projects Section 1A Date Inspection Summary:
Areas Reviewed: The NRC staff conducted routine safety inspections of plant acti-vities during full power operations. The inspectors reviewed the areas of plant operations, equipment operability (maintenance and surveillance) and licensee action on previous inspectinn findings. (see Table of Contents).
I Results: Plant operations and surveillance activities continue to be conducted safely and in a controlled, deliberate manner. Operations management anticipated potential disturbances to the feedwater control system during a corrective main-tenance activity and operators appropriately responded when an off normal condition occurred.
The cause of an unplanned control rod movement was expeditiously deter-mined.
Licensee action on previous inspection findings was adequate.
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8904060088 890328 PDR ADOCK 05000289 Q
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TABLE OF CONTENTS
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PAGE 1.0 Introduction and 0verview............................................
1.1 Licensee Activities.............................................
1.2 NRC Activities...................................................
1.3 Persons Contacted...............................................
2.0 Plant Operations.....................................................
2.1 Criteria / Scope of Review (NIP 71707)............................
2.2 Feedwater Flow Disturbance......................................
2.3 Fail ure of Relief Valve on Feedwater Heater.....................
2.4 Unplanned Control Rod Movement..................................
2.5 Operations Summary..............................................
3.0 Equipment Operability Review - Maintenance / Surveillance..............
3.1 Criteria / Scope of Review (NIP 61726/62703)......................
3.2 Emergency Core Cooling System Quarterly Surveillance............
3.3 Painting of the Spent Fuel Pool Area............................
3.4 Emergency Diesel Generator Monthly Surveillance.................
3.5. Plant Material Condition.................................
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3.6 Eq ui pmen t Op e rabi l i ty S umma ry...................................
4.0 Licensee Action on Previous Inspection Findings......................
l 4.1 Criteria / Scope of Review (NIP 92701/92702)......................
4.2 (Closed) Unresolved Item (289/86-03-23): Enhance Method to Perform and Document the Annual Reevaluation of Outstanding Lifted Leads, Jumpers and Temporary Modifications.............
4.3 (Closed) Unresolved Item (289/85-02-03): Evaluation of Support Ba s e P l a t e F l e x i b i l i ty........................................
4.4 (Closed) Inspector. Follow Item (289/86-06-09): Reactor Trip on April 11, 1986 Identified Problems Associated with T-Sat Monitor and Post Trip Window..................................
4.5 (Closed) Inspector Follow Item (289-86-10-02): Review of Fire Pump Building Damage Event.............
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4.6 (Closed) Unresolved Item (289/86-12-07): Control of Design I n p u t, U s e o f C AR I RS.........................................
4.7 (0 pen) NRC Bulletin 88-08, Thermal Stresses in Piping Connected to Reactor Coolant System.....................................
5.0 Management Meeting....!.............
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DETAILS 1.0 Introduction and Overview 1.1 Licensee Activities During this reporting period, the plant continued to operate at full power.
Reactor Coolant Pump operating parameters have stabilized. No major plant transients nor challenges to plant safety systems occurred.
As of February 25, 1989, the TMI-1 reactor was at 100 percent power, completing 166 days of effective full power operation.
1.2 NRC Staff Activities The purpose of this inspection was to assess licensee' activities during the power operations modes as they related to reactor safety, safeguards, and radiation protection. Within each area, the inspectors documented the specific purpose of the area under review, acceptance criteria and scope of inspection, along with appropriate findings / conclusions. The inspectors made this assessment by reviewing information on a sampling basis through actual observation of licensee activities, interviews with licensee personnel, or independent calculation and selective review of listed applicabic documents.
1.3 Persons Contacted
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- G. Broughton, Operations / Maintenance Director
- J. Colitz, Manager, Plant Engineering
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H. Hukill, Vice President and Director, TMI-1
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C. Incorvati, Audit Manager
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M. Nelson, Manager, Safety Review
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T. O'Connor, Lead Fire Protection Engineer
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- S. Otto, TMI-1 Licensing Engineer
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A. Palmer, Manager, Radiological Field Operations M. Ross, Plant Operations Engineer
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- H. Shipman, TMI-1 Operations
- D.
Shovlin, Plant Material Director
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C. Smyth, Manager, Licensing
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M. Wells, Media Manager
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S. Williams, Radiological Engineer
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- Denotes attendance at final exit meeting (see Section 5.0)
2.0 Plant Operations 2.1 Criteria / Scope of Review (NIP 71707)
The resident inspectors periodically inspected the facility to determine the licensee's compliance with the general operating requirements of Section 6 of Technical Specifications (TS) in the following areas:
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review of selected plant parameters for abnormal trends;
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plant status from a maintenance / modification viewpoint, including
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plant housekeeping and fire protection measures; control of on going and special evolutions, including control room
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personnel awareness of these evolutions; control of documents, including logkeeping practices;
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implementation of radiological controls; and,
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implementation of the security plan, including access control,
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boundary integrity, and badging practices.
Specific findings are addressed below.
2.2 Feedwater Flow Disturbance On January 23, 1989 at approximately 2:15 p.m., the licensee experienced a problem in the feedwater control system while maintenance personnel were replacing a differential pressure transmitter for the feed pump speed control system. Maintenance personnel were in the process of re-
. placing a failed differential pressure transmitter (SP118-DPTI) when they inadvertently lifted a ground wire common to a secor;d differential pres-sure transmitter (SP118-DPT2) that was automatically controlling the speed of the feedwater pumps.
Upon lifting the common ground wire, the signal from SP11B-DPT2 failed low causing an immediate increase in the feed pumps (FWP-P-1A/B) speed.
Control room operators quickly responded to this situation by placing the feedwater master controller, startup flow control valves (FW-V-16A/B) and the main feedwater regulating valves (FW-V-17A/B) in manual.
By taking manual control of the feedwater system, operators quickly stabilized feedwater flow.
Maintenance personnel were immediately informed of the disturbance to feedwater flow by plant opera-tions and reinstalled the ground wire.
Control room operators subse-quently returned the feedwater flow system to automatic control. Main-tenance and operations personnel critiqued the incident to establish the cause of the disturbance and identify what actions should be taken to prevent a recurrence.
Prior to performing this maintenance task, Operations Department super-vision and maintenance personnel briefed control room operators on potential problems the plant could experience while this task was in progress.
Subsequent to this briefing, operators were assigned specific control stations to monitor and respond to off-normal plant conditions while the maintenance task was being performed.
The inspector reviewed operator actions and plant status shortly (within 15 minutes) after the incident occurred.
Through review of strip charts, plant instrumentation and logs the inspector determined associated
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l equipment responded accordingly and operator actions were appropriate to return the plant to steady-state operation. The inspector concluded plant operations were conducted in a safe manner and no further review of this incident was necessary.
2.3 Failure of Relief Valve on Feedwater Heater On February 13, 1989 at approximately 5:47 p.m., a relief valve (HV-V-138) on the second stage feedwater heater became unseated and released steam to the atmosphere. This steam was extraction steam, at 485 psia pressure, that had passed through the high pretsure turbine and was used to preheat the feedwater going to the steam generator. The steam leak caused a loss of about 230 gallons per minute of water from the plant's secondary side, necessitating an equivalent make-up rate be made from the Condensate Storage Tanks to offset the loss.
Initial efforts to reseat the valve by temporarily gagging it and reduc-ing extraction steam pressure were unsuccessful. The valve remained open for approximately 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br /> and 45 minutes until a temporary modification was installed to gag the valve.
Cross-connections have been made between the 2A and 2B Feedwater Heaters and heater drains have been administra-tively maintained open to lessen the effects of any pressure transient
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that the 28 Feedwater Heater could experience.
If a high water level were to occur in the 28 Heater, alarms would indicate the condition in the control room ard manual actions could be taken to reduce heater level.
Such actions include isolating feedwater to the heater and removing the-gag on HV-V-13B.
The licensee has contacted its insurance underwriter i
and the American Society of Mechanical Engineer (ASME) Code Inspector
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to obtain authorization to operate with this-configuration. A replace-l ment valve has been obtained and tested and will be installed during the i
next outage.
The inspectors reviewed licensee response to the failure of the relief valve.
This review included examination of the installed gagging device; interviews with cognizant licensee representatives; examination of logs; control room displays / printouts and the safety evaluation for gagging the valve.
Through this review, the inspector determined the plant's nuclear safety was not adversely affected by the failure of the relief valve in the feedwater heating system.
As a result of minute leakage (approximately 0.003 gpm) of primary cool-ant into the secondary system small quantities of radioactive gases were released through the open relief valve.
The inspector determined the licensee monitored and quantified the amounts discharged.
Preliminary estimates indicate a total of 1051 microcuries of noble gases were re-leased resulting in an estimated off-site dose of 2.37 E-6 millirem ( mrem).. A total of 2.27 microcuries of I-131 were released, with an estimated off-site dose of 4.9 E-3 mrem. These quantities were deter-mined to be well within the regulatory limits specified in Appendix I of 10 CFR 50 for gaseous releases.
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As part of the review, the inspector verified the water levels in the Condensate Storage Tanks did not. decrease below the minimum level of 150,000 gallons (11 feet) as specified in the Technical Specifications.
Overall, the inspector concluded the licensee's response was timely and appropriate, demonstrating a conservative regard for personnel and nuc-
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lear safety.
2.4 Unplanned Control Rod Movement Through review of control room logs, the inspector determined operations personnel identified a potential problem with core reactivity controls.
On January 15, 1989, Group 7 control rods automatically inserted three percent, then returned to their nominal position over a 2-1/2 hour period.
A second similar event occurred on January 26, 1989 with an automatic insertion and subsequent withdrawal of Group 7 rods of about two and one-half percent over a 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> period.
The inspector discussed each incident with the licensee's Nuclear Engi-neering Department to determine what actions were taken to evaluate the phenomena.
After the initial event, the licensee reviewed the available data to identify possible contributors to affect reactivity changes in the Reac-tor Coolant System (RCS).
Two potential causes wer.' considered credible.
One was an unknown change in the soluble boron concentration and the other was a movement of one of the Group 8 Axial Power Shaping Rods prior to the Group 7 movement.
Following the initial event, operations per-sonnel defined what additional data should be collected if a second in-cident occurred.
Subsequent to the second incident, more detailed core data was collected and soluble boron samples were taken.
The boron samples confirmed a change in soluble baron concentration during the rod motions. With this confirming data, the licensee evaluated what plant activities were con-current with rod movement that could alter boron concentration in the RCS, Coincident with this period of rod movement, the licensee determined that planned temperature changes were occurring in the letdown purification-make-up system as part of a test to evaluate the effects of thermal cycling seal water injection temperatures on reactor coolant pump seals.
The postulated cause of changes in RCS boron concentration was the char-acteristic of the purification system demineralized resin to absorb cr release boron to the make-up stream dependent upon the demineralized temperature.
Lower temperatures of the letdown stream would result in a lower boron concentration of the make-up as a result of an increase absorption of boron in the demineralizers.
Higher temperatures of the letdown stream would result in a higher boron concentration in the make-up stream because boron would be released from the demineralizers.
Re-view of the water temperature data at the filters revealed a significant
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l drop in temperature (about 20 degrees F) while conducting the test fol-lowed by a return to normal temperature. Using published data on this effect, the licensee calculated the expected boron change for the ob-served temperature change.
The observed change in reactivity as indi-cated by rod insertions and withdrawals was consistent with the calcu-lated change.
Both incidents had similar changes in demineralized in-fluent temperature which corresponded to the timing of the rod motion.
With this evidence, the licensee concluded the root cause of the rod motion was a temperature induced swing in the RCS baron concentration.
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As part of the review, the inspector examined records of core parameters for the time periods in which rod motion occurred and determined regu-latory limits for flux imbalance and power distribution were not exceeded.
Through examination of licensee calculations and supporting data, the inspector concluded the licensee did a thorough and prompt evaluation to establish the cause of the control rod movements.
2.5 Operations Summary Operations were conducted in a safe, controlled manner. Operations man-agement anticipated potential problems during a corrective maintenance activity and took prudent action to prevent a plant transient.
Operators were vigilant in identifying and documenting off normal plant conditions.
Evaluation of off normal conditions was done in a timely manner with a high regard to plant and personnel safety.
3.0 Equipment Operability Review - Maintenance / Surveillance 3.1 Criteria / Scope of Review (NIP 61726/62703)
The inspectors. reviewed selected activities (listed in Attachment 1) to verify proper implementation of the applicable portions of the maintenance and surveillance programs. The inspector used the general criteria listed under the plant operations section of this report.
A more detailed review of equipment operability is addressed below.
l 3.2 Emergency Core Cooling System Quarterly Surveillance On February 1 and 2,1989, the inspector witnessed integrated surveil-lance testing of components comprising the Emergency Core Cooling System, l
Reactor Building Cooling System, Emergency Power Distribution System, and supporting auxiliary systems. The test conducted quarterly is to verify the operability of components of the High Pressure Injection Sys-tem, Decay Heat Removal System, Nuclear Services Closed Cycle Cooling System, Decay Heat River Water System, Nuclear Service River Water System, Reactor Building (RB) Ventilation System, RB Spray System and Emergency Diesel Generators. The "A" train for these systems was tested on Febru-ary 1, 1989, the
"B" train was tested on February 2, 1989.
Overall, this
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complex surveillance test demonstrated the operability of the aforemen-tioned systems and was accomplished in a manner which did not compromise plant safety.
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Prior to witnessing the test, the inspector reviewed the applicable pro-cedure... Surveillance Procedure 1303-5.2, " Loading. Sequence and Component Test and High Pressure Injection Logic Channel Test", Revision 30, dated January 31, 1989.
Through this review, the inspector determined the testing criteria conformed with the acceptance criteria stated in Tech-nical Specifications 4.1.1.14, 4.1.1.16, 4.5.1.2, and 4.5.2.4.
Addi-tionally, the inspector. determined the procedure specified the limits and precautions necessary to assure no limiting conditions for operation were entered when performing the test. Through review of the Locked Valve Log, the inspector determined that the prerequisite switching and tagging controls had been implemented prior to conducting the test for locked valves used for recirculation flow paths.
Because of the broad scope and complexity of the test, licensee manage-l ment assigned test performance responsibility to a separate operating
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crew that had considerable experience in conducting this surveillance.
Having this crew dedicated solely to testing freed the normal operating shift to maintain and monitor plant status.
Prior to conducting the test, the testing crew was briefed, personnel assignments were made for plant /
control room locations and communications were established with personnel stationed in remote plant areas.
The overall test coordination was ef-fective in minimizing interference with the operating shift.
During the testing, the inspector observed changes of indication of com-ponent status lights and station computer printouts in the control room, to verify components / systems had actuated as required.
The inspector physically observed actuation of the Emergency Diesel Generators during various aspects of the testing.
No violations of regulatory requirements were identified.
Equipment and support systems operated in accordance with the performance criteria.
In general, there was good command and control of the various test acti-vities. Operators and technicians were knowledgeable of plant design, equipment operability requirements, and testing criteria.
The Surveil-lance Procedure and associated operating procedures and administrative controls were properly followed.
3.3 Painting of the Spent Fuel Pool Area Recently the licensee painted the entire Spent Fuel Pool area that in-cluded floor, walls and handrails.
The utility group of the maintenance department did an adequate job of preparing and painting the area.
The inspector witnessed the painting activity in progress, reviewed the Job Ticket (JT), and discussed the job with the maintenance and engineering personnel.
The inspector determined the following:
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l The JT (CT-795) was too general.
It did not specify the type of
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paint to be used for different areas of the Spent Fuel Pool.
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upon the discussion with the painting crew, the inspector deterrained tuey had knowledge of the type of paint to be used and had received approval from the maintenance foreman.
However, the maintenance-manager agreed and implemented new departmental instructions that
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in the future the JT will be specific about the type of paint to
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be used.
The current practice included getting approval from Site Engineering
on the type of paint to be used.
Site Engineering received appro-vals from the Technical Functions group at Corporate. headquarters.
The inspector noted the current practice of approving a certain type of paint on a case by case basis existed because the paint specifi-cations for the buildings other than Reactor and Control Buildings were not available. The licensee agreed to expedite writing of the paint specifications. The inspector noted the entire paint approval process was informal. The licensee agreed to document the process.
I Additionally, the scope of work on the Job Ticket was changed on
February 9, 1989 by adding walls and handrails. The inspector noted the JT was approved on October 20, 1988, but the change of scope was not signed off by maintenance management; therefore, it was not clear who authorized the change. The manager of planning and scheduling group acknowledged the problem and planned to issue a formal memo advising the maintenance staff on how to initiate and approve the scope changes.
The licensee planned to revise the Unit I general corrective maintenance procedure (1407), section address-ing the scope changes.
Technical Specification 4.12.3.2.a requires that following signifi-
cant painting, the Auxiliary and Fuel Handling air treatment system be tested to verify that the HEPA and charcoal absorbers have not been degraded.
Since the amount of painting was not significant (less than 5000 square feet) the test was not performed. The in-spector reviewed an Engineering Evaluation 83-55 which addressed the testing of RB purge filters following painting in excess of 10,000 square feet of Reactor Building area. Accordingly, no filter degradation was noticed.
The inspector determined that the signi-ficant painting was not adequately defined for other plant areas.
The engineering manager agreed to provide specific guidance to in-corporate in the applicable painting procedures.
3.4 Emergency Diesel Generator Monthly Surveillance The inspector witnessed the monthly surveillance being performed on the emergency diesel generator 'B' in accordance with Surveillance Procedure 1303-4.16, " Emergency Power System".
The surveillance was intended to verify the manual starting of the emergency diesel.
The inspector noted the Auxiliary Operator (AO) performing the surveillance test was well
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trained and familiar with the surveillance requirements.
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steps were followed in sequence and results properly documented.
The communication-by the A0 with control. room personnel was clear and the inspector took special note the A0 repeated his communication with the control room personnel prior to taking any action.
3.5 Plant Material Condition During this inspection period, the inspector conducted several plant walkdowns in various facilities and identified several minor problems associated with the material condition of the plant. While these prob-lems did not have major safety significance it became clear the formal walkdown program implemented by the licensee following previous findings by the inspectors was not quite effective. The problems found'during this period were similar to previous ones such as improper mounting of supports, loose and missing bolts, improper use of tools,.etc.
The lic-ensee management acknowledged the inspectors findings and planned to take additional actions to train personnel and increase management involvement.
The inspectors will continue to monitor this area to assess the effec-tiveness of licensee actions.
3.6' Equipment Operability Summary Complex surveillance tests were well coordinated and controlled to mini-mize interferences with control room operations. Administrative weak-nesses were identified in the control of painting of plant areas.
Lic-ensee personnel performing in plant tours should improve their attention to detail.
4.0 Licensee Action on Previous Inspection Findings 4.1 Criteria / Scope of Review (NIP 92701/92702)
The inspector reviewed the following items identified in previous NRC inspections to assure the corrective actions were appropriate for the activity.
The inspector reviewed various modification packages, includ-ing system design descriptions and safety evaluations and verified cor-rective actions had been taken to resolve the items. A detailed review of these items is provided below.
4.2 (Closed) Unresolved Item (289/86-03-23): Proper Method to Perform and Document the Annual Reevaluation of Outstanding Lif ted Leads, Jumpers, and Temporary Modifications The Inspector reviewed the current revision (Rev. 26) to Administrative Procedure (AP) 1013, " Bypass of Safety Functions and Jumper Control",
and determined the inconsistencies identified in a past review of Revi-sion 22 have been adequately addressed.
Specific changes made to AP 1013 include stating in the annual follow-up review of the Temporary Modifi-cation (TM) what the intended final disposition of the TM is and stating
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in the body of the procedure that a written safety evaluation is required for every important-to-safety TM, i.e lifted lead, jumper or temporary mechanical modification.
The inspector reviewed the Electrical Jumper,
' Lifted Lead and Mechanical Modification Log and determined the admini-strative requirements specified in AP 1013 are being implemented for presently installed TM's.
This item is closed.
4.3 (Closed) Unresolved Item (289/85-02-03): Evaluation of Support Base Plate Flexibility This item was opened in Inspection Report 50-289/85-02. At the time of that inspection the licensee indicated that hand calculations had been performed for base plates with more than four bolts.
The licensee fur-ther indicated these calculations used conservative and simplified as-sumptions.
However, the calculations were not available at the site for review at the time of the inspection.
On February 6 and 7 the inspector reviewed and verified a typical cal-culation for the special case described above (specifically calculation No. DHH 125A).
The calculation was performed by Gilbert Commonwealth.
The inspector found the calculational methodology acceptable and con-firmed the calculated stresses on the plate, bolts and connecting welds are within stress allowables.
This item is closed.
4.4 (Closed) Inspector Follow Item (289/86-06-09): Reactor Trip on 4/11/86-Identified problems Associated with T-Sat Monitor and Post-Trip Window This item concerned a problem that occurred following the reactor trip on April 11, 1986. A computer alarm was' received that indicated less than 25 F subcooling margin on one channel. This was subsequently de-termined to be a response time problem with the Resistance Temperature Detector (RTD). A modification was completed to wrap the RTD with gold foil to enhance contact with the well and improve response time.
This was completed during the 7R outage.
Inspector review of post-trip data on a subsequent trip, October 30, 1988, revealed no problems with spurious indications of loss of saturation margin following the rehctor trip. Additionally, during the trip on April 11, 1986 plant pressure and temperature did not reach the post-trip window conditions in the nominal 10 minutes after trip. This was believed to be due to RTD re-sponse. This proble was not evident on the trip response of October 30, 1988. The licensee has changed the RCP trip criteria following loss of subcooling margin from 2 minutes to 10 minutes if the pumps are not immediately tripped.
This allows the operations to have more time to verify correct subcooling margin prior to taking any action.
Licensee action to resolve this concern was acceptable and this item is closed.
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4.5 (Closed) Inspector Follow-Up Item (289/86-10-02): Review of Fire Pump Building Damage Event Remaining aci. ion on this item consisted of review of licensee action to establish proper Preventive Maintenance (PM) intervals for Walworth type check valves.
The original valve that failed was a Walworth 5341WE swing check valve (FS-V-27).
The licensee completed a review of all check valves of this type, the affects of valve failure and established the appropriate maintenance frequencies.
The functions of approximately.66 check valves of this type was received.
Specifically for the fire ser-vice pumps FS-P-1, 2, 3, the associated pump discharge check valves have been incorporated into PM task MM002037 which will be accomplished on a 6 year interval.
This PM task consists of an open and inspect evolu-tion for the check valves.
The inspector reviewed the evaluation completed by the licensee and dis-cussed the PM program with material assessment personnel.
The inspector concluded that based on past failure and maintenance history for this type.of check valve, the frequency of maintenance proposed for these i
check valves was adequate.
This item is closed.
4.6 (Closed) Unresolved Item (289/86-12-07): Control'of Design Input of CARIRS This item pertains to the lack of documented procedure for use of "Com-puter Assisted' Records and Information Retrieval System" (CARIRS), and the use and interpretation of the system was not well understood by plant personnel.
The-inspector reviewed the licensee's actions in this regard and found them to be satisfactory.
The licensee has revised the document control procedures to describe the system and its use, and adequate training has been provided to the plant staff in its use.
The inspector observed the plant personnel, with whom he interfaced, were familiar and efficient in the use of this system.
This item is closed.
4.7 (0 pen) NRC Bulletin 88-08: Thermal Stresses in Piping Connected to Reactor Coolant System The licensee responded to the NRC on October 21, 1988 describing the steps implemented to evaluate and resolve the concerns raised in the bulletin.
The licensee indicated that systems connected to the reactor coolant system are: Make-up and Purification System; Core Flood System
and Decay Heat Removal System.
However, the only system affected by the bulletin was Make-up and Purification System which included High Pressure Injection System (HPI).
The licensee indicated the results of HPI ex-amination provided assurance there are no existing flaws in the system.
This item remains open pending the NRC review of the results of the licensee's ultrasonic testing.
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5.0 Management Meetings I
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The inspectors discussed the inspection scope and findings with licensee man-l agement weekly and at a final meeting on February 27, 1989. Those personnel
marked by an asterisk in paragraph 1.3 were present at the final management i
meeting.
The inspection results, as discussed at the meeting, are summarized in the cover page of the inspection report.
Licensee representatives did not indi-cate any of the subjects discussed contained proprietary or safeguards in-i formation.
Unresolved Items are matters about which more information is required in order to ascertain whether they are acceptable, violations, or deviations.
Unre-solved items discussed during the exit meeting are addressed in Section 4.0.
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ATTACHMENT 1 NRC INSPECTION REPORT NO. 50-289/89-01 ACTIVITIES REVIEWED Plant Operations
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Control room operations during regular and back shift hours, including fre-quent observation of activities in progress and periodic review of selected sections of the shift foreman's log and control room operator's log, and selected sections of other control room daily logs
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Areas outside the control room
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Selected licensee planning meetings During this inspection period, the inspectors conducted direct inspections during the following back shift hours.
Day /Date Time Monday,(Holiday), January 16, 1989 2:00 p.m. - 5:00 a.m.
Sunday, January 22, 1989 12:30 p.m. - 3:30 p.m.
Saturday, February 25, 1989 10:00 a.m. - 1:00 p.m.
Saturday, February 25, 1989 8:45 p.m. - 10:45 p.m.
Maintenance / Surveillance
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Emergency Core Cooling System Quarterly Surveillance
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Emergency Diesel Generator EG-Y-1A/B Monthly Surveillance
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Painting in the Fuel Handiing Building Reactor Coolant System (RCS) Leak Rate The inspector selectively reviewed RCS leak ; ate date for +he past inspection period.
The inspector independently ca1culated certain RCS leak rate data reviewed using licensee input data and a generic NRC " BASIC" computer program "RCSLK9" as specified in NUREG 1107.
Licensee (L) and NRC (N) data are tabulated Lelow.
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Attachment 1
TABLE RCS LEAK RATE DATA All Valves GPM OATE/ TIME
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CORRECTED DURATION L
N N
N L
G g
U g
U 02/21/89-0.0172-0.10-0.16-0.0556-0.0504 07:28:02 2 Hours 02/19/89 0.0812 0.08-0.08 0.0244 0.0197 16:45:59 2 Hours 02/18/89 0.071 0.07-0.09 0.0144 0.0138 16:29:11 2 Hours 02/24/89 0.0337 0.03-0.08 0.0244 0.0285 16:03:20 2 Hours G = Identified gross leakage U = Unidentified leakage L = Licensee calculated N = NRC calculated Columns 2 and 3, 5 and 6 correlate + 0.2 gpm in accordance with NUREG 1107. N is U
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corrected by adding 0.1044 gpm to the NUREG 1107 N due to total purge flow through U
the No. 3 seal from RCP's.
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