IR 05000334/1989005
| ML20244B602 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 06/06/1989 |
| From: | Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20244B593 | List: |
| References | |
| 50-334-89-05, 50-334-89-5, 50-412-89-05, 50-412-89-5, IEB-89-001, IEB-89-1, IEIN-89-033, IEIN-89-33, NUDOCS 8906130186 | |
| Download: ML20244B602 (16) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos.:
50-334/89-05 License Nos.: DPR-66 50-412/89-05 NPF-73 Licensee:
Duquesne Light Company One Oxford Center 301 Grant Street Pittsburgh, Pennsylvania 15279 Facility Name: Beaver Valley Power Station, Units I and 2 Location:
Shippingport, Pennsylvania Dates:
April 1 - May 22, 1989 Inspectors:
J. E. Beall, Senior Resident Inspector S. M. Pindale, Resident Inspector P.
. Wi son, esident Inspector h[
Approved by:
v towell E. Tripbf Chief
/ D' ate Reactor Projects Section No. 3A Division of Reactor Projects Inspection Summary:
Combined Inspection Report Nos. 50-334/89-05 and 50-412/89-05 for April 1 - May 22, 1989 Areas Inspected:
Routine inspections by the resident inspectors of licensee actions on previous inspection findings, plant operations, security, radiolog-ical controls, plant housekeeping and fire protection, surveillance testing, maintenance, inoperable seismic instrumentation, steam generator tube plug-ging, AMSAC operational problems and licensee event reports.
Results:
No violations or unresolved items were identified. Persornel related errors as discussed in the last Resident Inspection Report continued to create operational challenges to the plant (Sections 4.3.1, 4.3.3 and 4.3.5).
A per-sonnel radiological safety concern was raised and resolved (Section 4.5).
Cer-tain seismic monitors were found to have been degraded for approximately two years and were corrected (Section 7). A steam generator tube failure at a dif-ferent site led to prompt licensee preventive measures (Section 8).
One reactor trip and safety injection was found to be due to a potentially generic-design flaw (Section 9). Two previously open NRC items were closed during this inspection.
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8906130186 890606 PDR ADOCK 05000334 O
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l TABLE OF CONTENTS Page 1.
Persons Contacted...........................
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I 2.
Summa ry o f Fa c i l i ty Act i v i t i e s..............................
3.
Status of Previous Inspection Findings (IP 71707, 92702, 92701)...............................
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'4.
Operational Safety (IP 71707,71710)........................
4.1 General..............
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4.2 ESF Wa1kdown...........................................
4.3 0perations.............................................
4.4 Plant Security / Physical Protection.....................
4.5 Radiological Controls..................................
4.6 Plant Housekeeping and Fi re Protection.................
5.
Surveillance Testing (61726)..............................
6.
Maintenance (62703).........................................
7.
Inoperable Seismic Instrumentation (61726, 92700)...........
8.
Steam Generator Tube Plugs (62703, 92700)..................
9.
Unit 1 Safety Injection and Reactor Trip Following De-energization of AMAC (71707, 93702)........
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10.
Inof fice Review of Licensee Event Reports (90712)...........
11. Unre~ solved Items............................................
12. Meetings (30703)............................................
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DETAILS 1.
Persons Contacted l
During the report period, interviews and discussions were conducted with members of licensee management and staff as necessary to ' support inspec-tion activities.
2.
Summary of Facility Activities At the beginning of the period, Unit 1 was at 100% power and Unit 2 was defueled and in the first refueling outage.
During the period, Unit I returned to a core life extension schedule which involved-operating at 90%
during the week. and 50% on the weekend.
Unit 2 completed the outage, l
loaded fuel and began plant startup. Unit 2 reached Mode 2, conducted low I
power physics testing, then experienced problems with the reactor vessel
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level indicating system, and returned to Mode 5 at the end of the period.
Unit 1 experienced a reactor trip and safety injection from 89% power on May 18 (see Sections 4.3_.6 and 9).
Unit 1 corrected the problem, re-started and was at 90% power at the end of the period.
3.
Status of Previous Inspection Findings
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The NRC Outstanding Items List was reviewed with cognizant licensee per-l sonnel.
Items selected by the inspector were subsequently reviewed
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through discussions with' licensee personnel, documentation reviews and field inspection to determine whether licensee actions specified in the Ols had been satisfactorily completed. The overall status of previously identified inspection findings was reviewed, and planned / completed licen-see actions were discussed for the item reported below.
3.1 (Closed) Unresolved Item (50-334/87-12-01):
The licensee was to resolve a potentially generic issue concerning a new postulated sequence of events that were potentially more severe than the Condi-tion II events analyzed in the Final Safety Analysis Report.
The postulated sequence of events involved a turbine trip event with a consequential loss of forced reactor coolant flow prior to a reactor trip.
The Westinghouse Owner's Group evaluation (ESBU/WOG-89-052)
concluded that the probability of the above scenario was too low to be considered as a Condition 11 evaluation and the licensee's offsite review committee concurred with that conclusion.
This item is closed.
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3.2 (Closed) linresolved Item (50-412/88-16-01):
Control room annuncia-tors' power supply modification. On January 28,-1988, Unit 2 exper-ienced a two hour loss of control room annunciators due to a fire.
All annunciators were affected because the various circuits involved
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in the non-safety system had little circuit isolation. The licensee completed a modification which added circuit protection and isolation features designed to limit the effect of a component failure such that only a portion of the annunciators would be lost following one failure.
The inspector reviewed the design package and maintenance work request and had no further questions.
This item is closed.
4.
Operational Safety 4.1 General Inspection tours of the following accessible plant areas were con-ducted during both day and night shifts with respect to Technical Specification (TS) compliance, housekeeping and cleanliness, fire protection, radiation control, physical security / plant protection and operational / maintenance adminit trative controls.
-- Control Room
-- Safeguard Areas
-- Auxiliary Building
-- Service Building
-- Switchgear Area
-- Diesel Generator Buildings
-- Access Control Points
-- Containment Penetration Areas
-- Protected Area Fence Line -- Yard Area
-- Turbine Building
-- Intake Structure
-- Reactor Containment
-- Spent Fuel Building
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4.2 ESF Walkdown The operability of selected engineered safety features systems was
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verified by. performing detailed walkdowns of the accessible portions of the systems. The inspectors confirmed that system components were in the required alignments, instrumentation was valved-in with appro-priate calit, ration dates, as-built prints reflected the as-installed systems and the overall conditions observed were satisfactory.
The systems inspected during this period include the Emergency Diesel Generator, Safety Injection and Recirculation Spray systems.
No concerns were identified.
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y 4.3 ' Operations During the course of the inspection, discussions were conducted with operators 'concerning knowledge of recent changes to procedures, facility > configuration and plant conditions. During plant tours, logs and records were reviewed to determine if entries were properly made,
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cod that equipment status / deficiencies were identified and communi-cated. These records included operating logs, turnover sheets, tag-out and jumper 16g's, process computer printouts, unit off-normal and draft incident reports. The inspector verified adherence to approved procedures for ongoing activities observed.
Shift turnovers were-witnessed and staffing requirements confirmed. Inspector comments or questions resulting from these reviews were resolved by licensee personnel.
In addition, inspections were conducted during backshifts and weekends on 4/2, 4/12, 4/15, 4/18, 5/1, 5/2, 5/8, 5/13, 5/14, 5/15, 5/17, 5/20 and 5/21.
4.3.1 ESF Actuation (4/12)
The Unit 1 Control Room Emergency Bottled Air Pressuriza-tion (CREBAP) Systen automatically initiated on April 12 due to personnel error.
During the performance of a sur-veillance test (OST 1/2.43.17A), the operator repositioned the wrong switch such that the test generated high radia-tion signal was not blocked and the CREBAP system actuated.
The procedure was clear and approved, and verbal communica-tions were adequate.
Licensee investigation also identi-fied two human factor considerations which may have con-tributed involving the orientation of the switches and use of a common key (same key operates both switches). Opera-tors verified no valid signal was present, reset the signal and normal system alignment was restored.
4.3.2 ESF Actuation,(4/24)
A Unit 2 containment purge isolation c;ccurred on April 24, due to airborne activity during decon activities in the reactor cavity.
The fuel pool gate valve was found not to be fully shut (mechanically bound in a partly open posit-ion) which provided a ventilation path into the cavity (draft) and helped create the airborne problem. The licen-see identified the cracked open valve, shut it fully and restored normal system lineup.
No internal dose was re-ceived due to the event according to followup testing of potentially effected personnel.
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4.3.3 ESF Actuation (4/27)
A Unit 2 emergency diesel' generator (2-1 EDG) automatically started and. loaded on April 27 due to personnel error dur-ing testing. The EDG and affected loads were secured and the normal lineup was restored.
The_ event occurred during the testing of an undervoltage (UV) relay on charging pump 2CHS P21C.
The technicians performing the test failed to defeat the output from the relay which went to the breaker powering one emergency bus (AE). The breaker tripped when the relay was W tested, the bus was deenergized, and the 2-1 EDG auto-started to restore power to the AE bus. After troubleshooting activities, the 2-1 EDG was secured and normal lineup was restored.
4.3.4 Partial Flow Blockage in Unit 2 Recirculation Spray Heat Exchangers Partial flow blockage was identified during surveillance testing of the Unit 2 recirc spray heat exchangers and reported on April 28.
The test acceptance criteria spec-ified a minimum flow rate of 12,000 gpm.
Initial testing measured 11,923.and 8,406 gpm for the A and B trains re-spectively. The four heat exchangers were opened for in-spection and the B and D heat exchangers (B train) were found to each contain about 25 pounds of Asiatic clams.
The components and piping were cleaned and flushed; satis-factory flow rates were achieved prior to the end of the Unit 2 outage.
Long term corrective actions include placing the heat exchangers in dry layup during operation and use of a bio-fouling prevention agent in piping which must remain water filled.
4.3.5 Unit 2 Inadvertent Feedwater Isolation On May 24, an inadvertent feedwater isolation occurred while performing Operating Surveillance Test (OST) 2.24.4, Steam Turbine Auxiliary Feed Pump Test. The OST was being performed to verify pump operability prior to entering Mode 3.
The OST required that feedwater flow to all steam generators (SG) be greater than or equal to 700 gpm at a discharge pressure of at least 1133 psig.
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After' the pump had been manually started, the pump's dis-charge valve was slowly opened to admit flow to the steam generators. 'Due to previous turbine speed control prob-lems, an operator, the Unit 2 shift supervisor and mainten-ance personnel were present at the pump to make any required adjustments to the turbine governor.
Initial "B" SG level was 58?; and in approximately one minute, the level in B SG had increased to about 70?5. At that point, a con-trol room operator notified the shift supervisor (located at the auxiliary feed pump) that
"B" SG level was rapidly approaching the 75% feedwater isolation setpoint.
The shift supervisor ordered an operator at the pump to shut the discharge valve and the shift foreman in the control room ordered a control room operator to shut the auxil;ary feed flow control valve to "B" SG. About one minute later,
"B" SG level reached 75P4 and a feedwater isolation occurred.
All systems responded as designed to the feedwater isola-tion signal.
The licensee made all required notifications to the NRC.
The licensee's preliminary investigation concluded that there were two major causes of the event.
The first cause was the lack of adequate preplanning in that the B SG level was too high at the start of the test to permit sufficient time to perform the test. The second cause was poor com-munications in that the control room operator was not aware that the test run would be longer than normal due to planned turbine governor adjustments.
The inspector noted that the OST contained no provisions to ensure adequate SG free volume prior to adding auxiliary feedwater.
The inspector will review in a followup inspection the licen-see's corrective actions.
4.3.6 Unusual Event On May 18, 1989, an Unusual Event was declared following a safety injection (SI) signal which tripped the plant from 89?J power.
The SI was caused by high main steam line pressure rate of change following the opening of the load rejection steam dump valves.
The cause of the event was determined to be a design flaw in the Anticipated Transient Without Scram (ATWS) Mitigating System Actuation Circuitry (AMSAC) in that when the AMSAC panel was inadvertently de-energized, the load rejection steam dump valves opened initiating the event.
For details, see Section 9.
No significant deficiencies beyond those discussed above were identi-fied during inspector review and followup of these events.
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4.4 Plant Security / Physical Protection Implementation of the Physical Security Plan was observed in various plant areas with regard to the following:
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Protected Area and Vital Area barriers were well maintained and not compromised;
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Isolation' zones were clear; Personnel and vehicles entering and packages being delivered to
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the Protected Area were properly searched and access control was in accordance with approved licensee procedures:
Persons granted access to the site were badged to indicate
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whether they have onescorted access or escorted authorization;
' Security access controls to Vital Areas were being maintained
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and that persons in Vital Areas were properly authorized.
Security posts were adequately staffed and equipped, security
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personnel were alert and kr.owledgeable regarding position requirements, and that written procedures were available; and Adequate illumination was maintained.
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No deficiencies were identified.
4.5 Radiological Controls Posting and control of radiation and high radiation areas were -in-spected.
Radiation Work Permit compliance and use of personnel mon-itoring devices were' checked. Conditions of step of f pads, disposal of protective clothing, radiation control job coverage, area monitor operability ana calibration (portable and permanent) and personnel frisking were observed on a sampling basis.
The.recently installed equipment and measures for hot particle control appeared effective, in particular, the use of screening monitors.
The inspector observed portions of the core reload and identified an unsafe practice by a contractor (Westinghouse) technician. The indi-vidual was assisting in reload activities on the mobile fuel bridge which runs on tracks along the reactor cavity and projects across the cavity. The technician was observed by the inspector to walk across one beam (about 6 inches wide) above the water surface of the cavity.
At that time, a fuel assembly was being reloaded and the bridge was over the reactor vessel.
No safety line or any other measure was used for the 10 - 15 foot trip. The technician was wearing two sets of cloth protective clothing and two layers of plastic foot covers.
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The bulky clothing, the multiple foot covers, and the beam narrowness were indicative of a need for protection against a slip or fall. The reactor cavity was filled with radioactively contaminated water (about 30 feet deep above the reactor vessel) possibly containing hot particles due. to fuel movement.
A fall would have resulted in im-
mersion, contamination, possible ingestion of radioactive material and possible physical injury due to impact with the bridge or cavity wall.
The inspector observed the technician repeat the unsafe practice-before reaching the immediate area (two round trips across the beam)
and questioned the individual.
The technician asserted that his actions were standard practice over many years. Tne inspector stated that the behavior was clearly unsafe and repeated this position to licensee senior management.
The licensee's initial response indi-cated that the practice was not without precedent and was not viewed as particularly unsafe because the potential fall was only a few feet (into the contaminated water).
After additional consideration, the licensee installed a safety line across the beam and used a harness type hookup to improve safety.
4.6 Plant Housekeeping and Fire Protection Plant housekeeping conditions, including general cleanliness -condi-tions and-control and storage of flammable material and other poten-tial safety hazards, were observed in varicus areas during plant tours.
Maintenance of fire barriers, fire barrier penetrations, and verification of posted fire watches in these areas were also observed. The inspector conducted detailed walkdowns of the access-ible areas of both Unit 1 and Unit 2.
Housekeeping in the Unit 2 radiologically controlled areas was impac-ted during -the Unit 2 refueling outage. Weaknesses in housekeeping were noted in Containment (IR 50-334/89-06; 50-412/89-06). Walkdowns of other Unit 2 radiologically controlled areas revealed similar weaknesses in high activity areas.
Areas were found littered with tools (such as wrenches, knives and flashlights), parts (such as gaskets, screws and washers) and debris (such as used gloves, cotton glove liners and paper swipes).
The inspector discussed these prob-lems with licensee management; all areas showed marked improvement near the end of the outage.
The inspector found the sump screen in the Unit 2 cable tunnel to be blocked.
The sump, which is designed for fire fighting water re-moval, had a temporary screen under the floor grating which had be-come clogged. The inspector identified the problem to the licensee and the screen was removed.
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5.
Surveillance Testing The inspectors witnessed / reviewed selected surveillance tests to determine whether properly approved procedures were in use, details were adequate, test instrumentation was properly calibrated and used, Technical Specifi-cations were satisfied, testing was performed by qualified personnel and test results satisfied acceptance criteria or were properly dispositioned.
The following surveillance testing activities were reviewed:
OST 2.36.2 Emergency Diesel Generator (2EGS*EG2-2)
Monthly Test, April 27, 1989.
OST 2.24.4 Steam Turbine Auxiliary Feed Pump (2FWE*P22),
Test May 14, 1989.
OST 2.24.7 Steam Driven Auxiliary Feed Pump (2FWE*P22) Auto Start Test, May 14, 1989.
OST 2.36.1 Emergency Diesel Generator (EGS*EG2-1)
Monthly Test, May 17, 1989.
No deficiencies were identified.
6.
Maintenance The inspector reviewed selected maintenance activities to assure that:
the activity did not violate Technical Specification Limiting Condi-
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tions for Operation and that redundant components were operable;
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required approvals and releases had been obtained prior to commending work; procedures used for the task were adequate and work was within the
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skills of the trade;
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activities were accomplished by qualified personnel; where necessary, radiological and fire preventive controls were ade-
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quate and implemented; QC hold points were established where required, and observed;
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equipment was properly tested and returned to service.
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MWR 892447 Install Temporary Modification to Turbine Impulse
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Pressure Channel III.
MWR 892448 Install Temporary Modification to Turbine Impulse
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Pressure Channel IV.
No deficiencies were identified.
7.
Inoperable Seismic Instrumentation
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During the troubleshooting of a system trouble alarm, tiie licensee dis-covered that two of the six site seismic monitors had incorrect settings for the functions associated with horizontal acceleration.
An internal fault had been indicated by a response spectrum analyzer trouble alarm on April 1.
These settings are designed-to trigger alarms and to initiate event tape recording.
The incorrect setpoints resulted from a surveil-lance procedure which contained incorrect values.
The surveillance was last performed in May, 1987.
The licensee recalibrates the instruments, revised the procedure, and sub-mitted a Special Report on April 24 as required by the facility Technical Specifications (TS 3.3.3.3.b).
The inspector reviewed the report and other associated documents and noted that four of the six monitors were fully functional during the period and the two degraded monitors would have been triggered by vertical motion.as designed. The Technical Specif-ications state (TS 3.3.3.3.c) that the immediate shutdown requirements (TS 3.0.3) are not applicable, so the facility was not operated in violation of the Operating License.
The facility did, however, operate for a pro-longed period (nearly 2 years) with a degraded ability to detect and men-itor seismic events.
In discussions with the inspector, the licensee agreed that this event hNhlighted the need to carefully review and per-form infrequent surveillance procedures.
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C.
Steam Gene.ator Tube Plugs On February 25, 1989, North Anna, Unit 1, experiersed a steam generator tube leak caused by the mechanical failure of a tube plug.
The plug crackeci and the top portion was propelled by RCS pressure up the empty tube.
The missile punctured the tube at the bend at the top and also damaged an adjacent tube.
The event was the subject of NRC Information Notice No. 89-33, " Potential Failure of Westinghouse Steam Generator Tube Mechanical Plugs."
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Investigation revealed that certain heats of thermally treated Inconel 600 were susceptible to Primary Water Stress Corrosion Cracking (PWSCC). Other
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facilities also identified examples of cracked tube plugs. These findings led to the issuance of NRC Bulletin No. 89-01, " Failure of Westinghouse Steam Generator Tube Mechanical Plugs" on May 15. The Bulletin requested site-specific. data and required several actions involving tube plug repair / replacement.
Unit I contains six tubes (all in "A" Steam Generator) with plugs fabri-cated from Bulletin-identified heats.
The licensee plans to repair /
replace these plugs during the next refueling outage scheduled to begin on
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September 1,1989, which complies with the Bulletin.
Unit 2 was in the i
first refueling outage when the material factors of the North Anna. Unit l
1, event became available. Unit 2 had 9 tubes plugged with affected n. ate-rials. The plugs in.the higher temperature side (TH) were repaired during-the outage using the " plug within a plug" method.
The PWSCC rate in-i creases with temperature so the remaining tube plugs are much less sensi-tive to PWSCC and substantial margi.. (over 5000 effective full power d:ys)
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The inspector found the actions taken by the licensee in response to the plug failure events to be good.
Particularly noteworthy was the licen-see's -prompt actions in the midst of an ongoing Unit 2 refueling outage
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which enabled the repair of the most potentially vulnerable tube plugs on Unit 2.
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9.
Unit 1 Safety Injection and Reactor Trip Following De-energization of AMAC
'The inadvertent down powering of the Unit 1 Anticipated Transient Without Scram (ATWS) Mitigating System Actuation Cirs:uitry ( AMSAC) panti resulted l
in a reactor trip and a safety injection (SI) with flow. On May 18, 1989, j
a technician inadvertently opened the electrical supply breaker to the i
Unit 1 AMSAC panel which caused ten of the mainsteam dump valves to open.
This rapidly lowered main steam pressure causing a high steam line press-i ure rate safety injection actuation and subsequent reactor trip.
The control room operators responded to the event in accordance with the licensee's erwrgency operating procedures. Tne high head safety injection pumps injected into the reactor coolant system and an Unusual Event was
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declared. The operators terminated safety injection within 10 minutes and stabilized the plant in Hot Standby (Mode 3) af ter the steam dump valves shut when reactor coolant average temperature dropped below 543 F (low-low Tavg).
The Unusual Event was terminated approximately 40 minutes after the event.
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. AMSAC was installed in Unit 1 in response to 10 CFR 53.62 " Requirements for Reduction of Risk from ATWS Events for Light-Water Cooled Nuclear Power Plants." AMSAC provides a non-safety-related backup system which is diverse and independent from the reactor protection system.
AMSAC is-designed to assure that the RCS will not be overpressurized during an ATWS event by providing a backup turbine trip and an initiation of auxiliary p
feedwater. Unit l's AMSAC system was designed by Foxboro to be compatible with the Westinghouse 7100 Series process instrumentation system.
The. five input signals to AMSAC include feed. flow (3 signals) and turbine impulse pressure (2 channels). One of the pressure signals was generated by PT-1MS-446.
The signal from this transmitter after passing through a signal isolator, provided input signals to other non-safety-related process instrumentation control circuits beside AMSAC via a current loop.
These circuits were connected in series.
Another process instrumentation control circuit that utilized the signal from PT-1MS-446 was a signal sum-mator which computed the temperature error for the load rejection steam dumps. The other pressure signal was generated by PT-1MS-447. One of the control circuits on this process instrumentation current loop was a lead-
' lag controller which transmitted the rate of decrease of turbine impulse pressure to signal circuit comparators which, in turn, tripped at 15% and 50% load rejection arming the steam dumps.
When the AMSAC panel was de-energized, a very large resistance was intro-duced to the current loops which provided input to the panel.
This, in
' turn, caused the current in these loops to drop essentially to zero (acted like an open circuit). Therefore, the load rejection bistables armed and the temperature error signal to the load rejection steam dump went to its maximum value. The load rejection steam dump valves then fully opened as designed, initiating the event.
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As a corrective action, the licensee modified the process instrumentation l
circuitry to make the turbine impulse pressure signals to the. load rejec-
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tion circuits independent of AMSAC.
Spare signal isolators were utilized tn route separate turbine impulse pressure signals to the load rejection circuits.
The licensee elected not to modify the feedwater flow signals since there were no adverse effects on plant operation when these signals dropped to zero (indication only).
Post-modification testing confirmed that de-energizing AMSAC would no longer affect the load rejection circuitry.
The licensee verified that the Unit 2 load rejection circuitry was unaf-fected by the Unit 2 AMSAC system by de-energizing the panel while the plant was shutdown. Unit 2's AMSAC system was also designed by Foxboro, but was designed to be compatible with the Westinghouse 7300 Series process instrumentation system utilized in Unit 2.
The inspector found licensee's actions in response to this event, includ-ing investigation, troubleshooting modification and testing, to be very good.
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Inoffice Review of' Licensee Event Reports (LERs)
The inspector reviewed LERs submitted t;> the NRC Region I Office.to verify that the details of the event were clearly reported, including accuracy of the description of cause and adequacy.of corrective action. The inspector determined whether further information was required from the licensee, whether generic implications were indicated and whether the event war-ranted onsite followup. The following LERs were reviewed:
Unit 1:
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LER: 89-02-00 Reactor Trip Due to Feedwater Regulating Valve Malfunction.
LER:.89-03-00 Inadvertent CREBAPS Actuation Due to Radiation Monitor Failure.
LER: 89-04-00 Inadvertent ESF Actuation.
LER: 89-05-00 River Water Pump Auto-Start - ESF Actuation.
tinit 2:
LER: 89-03-00 Reactor Trip Due to Main Feedwater Regulating Valve Failure.
LER: 89-04-00- Informational Report Providing Clarification of a 10 CFR 50.72 Notification.
LER: 89-05-00 Inadvertent Safety Injection.
LER: 89-06-00 Expansion Joint Liner Failures for Component Cooling Pumps.
LER: 89-07-00 Leak Collection Ventilation Flowpath Automatic Realignment Actuation.
LER: 89-08-00 Pressurizer Code Safety Valve Lift Setting Less Than Tech-nical specification Limit LER: 89-08-01 Revision to LER 89-08.
LER: 89-09-00 Degraded High Energy Line Break (HELB) Temperature Elements.
The above LERs were reviewed with respect to the requirements of 10 CFR
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50.73 and the guidance provided in NUREG 1022. The LERs were found to be of high quality with good documentation of event analyses, root cause determinations and corrective actions.
The inspector verified that the licensee had a procedure for the periodic inspection of reach rod operated valves (Unit 1 LER 89-05).
The failed valve had been inadvertently omit-ted from the procedure due to its location in an outlying building; the licensee had taken steps to add the valve and confirm that no other valves
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l were similarly omitted. The licensee committed'to check for loose parts in the Unit 2 steam generators during the first refueling outage (Unit 2 LER 89-03). The inspection was performed and no loose parts were identi-fled. The licensee concluded that not declaring an Unusual Event (Unit 2 LER 89-05) was correct; the inspector forwarded the appropriate documents for specialist followup. The technical position on PORV operability (Unit 2 LER 89-04) determination was also designated for further review.
11.
Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items violations or devia-j tions. 'iio new unresolved items were identified in this inspection report.
12. Meetings
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Periodic meetings were held with senior facility management during the
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course of this inspection to discuss the inspection scope and findings. A i
I summary of inspection findings was further discussed with the licensee at the conclusion.of the report period on June 2, 1989.
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