IR 05000334/1989001
| ML20235Y495 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 03/02/1989 |
| From: | Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20235Y493 | List: |
| References | |
| 50-334-89-01, 50-334-89-1, 50-412-89-01, 50-412-89-1, NUDOCS 8903140209 | |
| Download: ML20235Y495 (15) | |
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U. S. NUCLEAR REGULATORY COMMISSION Region I'
' Report Nos..
50-334/89-01 License Nos.: DPR-66 50-412/89-01-NPF-73
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Licensee:
Duquesne Light Company One Oxford Center 301 Grant Street
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Pittsburgh, PA 15279 Facility Name: Beaver Valley Power Station, Units 1 and 2.
- Location:
Shippingport, Pennsylvania Dates:
January 1 - February 15,:1989 Inspectors:
J. E. Beall, Senior Resident Inspectur S. M. Pindale, Resident Inspector P
R.
11 son Reactor Engineer Appro' red by:
Ah/
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[owell E. Trfp'p, Chief Date Reactor Projects Section No. 3A Division of Reactor Projects
' Inspection Summary: Combined Inspection Report Nos. 50-334/89-01 and 50-412/89-01 for January 1 - February 15, 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, control of diesel. generator fuel oil, feedwater regulating valve failure and maintenance, and setpoint control and facility modification programs.
Results: No violations or unresolved items were identified. Continuing weak-nesses were identified concerning implementation of the temporary modification programs (Section 9). Personnel related errors continue to create operational challenges to the plant (Sections 4.3.2 and 10). One previously open NRC item was closed during this inspection.
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l TABLE OF CONTENTS Page i
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1.
Persons Contacted......................
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Summary of Facility Activities
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3.
Followup on Outstanding Items (92701)............
4.
Plant Operations (71707, 71710, 93702)...........
4.1 General
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4.2 ESF walkdown.....
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4.3 Operations....................
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4.4 Plant Security / Physical Protection..
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4.5 Radiological Controls
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4.6 Plant Housekeeping and Fire Protection.......
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5.
Surveillance Testing (61726).................
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Quality Assurance Regarding Diesel Generator Fuel Oil (71707)..........................
7.
Main Feedwater Regulating Valve Failure (62703, 71707)....
8.
Safety Evaluations for Setpoint Changes (37702).......
9.
Unreviewed Facility Modifications (37700)..........
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10.
Personnel Errors (40500, 90712, 92700)............
11. Meetings (30703)
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DETAILS 1.
Persons Contacted 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. inspection period, Unit I was operating at 50%
power in accordance with the licensee's cycle-extension program which restricted Unit 1 to 90*4 power during weekdays with reductions to 50% on weekends.
Unit 2. began the period at full power.
Unit ~ 1 tripped on January 17 due to ' personnel error during post-maintenance testing (see Section 4.3.2).
Unit I was returned to service on January 19.
Unit 2 tripped on February 12 due to the mechanical failure of a main feedwater regulating valve (see Section 4.3.4), and remained shutdown in Mode 3 at the end of the period.
Unit 1 tripped on February 13 due to the failure of an instrument in the feedwater control system (see Section 4.3.5).
The failed instrument was replaced and Unit I was returned to service on February 14.
Unit I was at 90% power at the end of the period.
3.
Followup on Outstanding Items i
The NRC Outstanding Items List was reviewed with cognizant licensee per-sonnel.
Items selected-.by the inspector were subsequently reviewed through discussions with licensee personnel, documentation reviews and field inspection to determine whether licensee actions specified in the OIs 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.
(Closed) Unresolved Item (50-334/87-15-01):
Implement procedure changes to impose stronger administrative controls associated with both liquid and gaseous waste discharges. The inspector reviewed selected discharge pro-cedures and found that the appropriate nontrols had been incorporated into the procedures. This item is closed.
4.
Plant Operations 4.1 General l
Inspection tours of the following accessible plant areas were con-
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ducted during both day and night shifts with respect to Technical l
Specification (TS) compliance, housekeeping and cleanliness, fire protection, radiation control, physical security / plant protection and operational / maintenance administrative controls.
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-- 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 Some plant housekeeping and fire protection concerns were identified as discussed in Section 4.6.
4.2 ESF Walkdown The operability of selected engineered safety features systems were 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 calibration dates, as-built prints reflected the as-installed
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systems and the overall conditions observed were satisfactory.
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systems inspected during this period include the emergency diesel generator and auxiliary feedwater systems.
No concerns were identified.
The inspector attended a Unit 2 Onsite Safety Committee (OSC) meeting I
on January 26. Attendance of members required by Technical Specifi-cation 6.5.1 was met.
The agenda items observed included procedure and design change package reviews.
In general, member participation for safety issues was adequate. The inspector will continue to mon-itor the adequacy and effectiveness of OSC meetings and discussions during future inspections.
No significant concerns were identified.
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, and that equipment status / deficiencies were identified and communi-cated. These records included operating logs, turnover sheets, tag-l out and jumper logs, process computer printouts, unit off-normal and draft incide.it reports. The inspector verified adherence to approved procedures for ongoing activities observed.
Shift turnovers were witnessed and staffing requirements confirmed.
Inspector comments
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or questions resulting from these reviews were resolved by licensee personnel.
In addition, inspections were conducted during backshifts and weekends on 1/3, 1/5, 1/7, 1/12, 1/16, 1/17, 1/18, 1/19, 1/20, 1/23, 3/24, 1/26, 1/28, 2/2, 2/4, 2/5, and 2/12.
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4.3.1-Declaration of Unusual Event Due to Offsite Event On January 3, while Units _1 and 2 were operating at 90% and 100% power respectively, the licensee received a report at 6:15 p.m. from a nearby steel mill that an explosion, fire and possible - toxic. gas release had occurred.
Continued assessment to confirm. whether toxic gases were -involved were inconclusive, therefore,.the: licensee declared an Unusual Event at 6:45 p.m. in accordance with the Emergency Plan.
The control room ventilation systems were immedi-ately placed on full recirculation and personnel working outside were instructed to report inside.
At ' 7:30 p.m.,
the licensee 'was _ notified that only' coal. tar sludge (no toxic gases) were involved in the fire. The Unusual Event was terminated at that time.
The inspector reviewed the -
control room logs and reports and determined that the licensee had made the' appropr.iate notifications in accord-ante with the Emergency Plan and 10 CFR 50.72. ' No concerns were identified.
4.3.2 Reactor Trip Due to Personnel Error-
.0n January 17, 1989, Unit I automatically tripped from 90%
power due to a low steam generator ("A") level coincident with ' steam flow / feed flow mismatch reactor trip signal.
The trip occurred during post-maintenance' testing ~ activ -
'ities associated with.the
"C" bypass feedwater regulating valve-(BFRV).
Plant operators used Operating Surveillance Test (OST) No.1.1.10, Cold Shutdown Valve Exercise Test, to accomplish the post-maintenance test.
Due to operator error, the incorrect breaker war 'renergized causing the
"A" main feedwater regulating valve (MFRV) to close. As a consequence, the reactor tripped after the-low steam gener-ator level and steam flow / feed flow mismatch setpoint were reached on the affected ("A") steam generator.
The plant was subsequently stabilized in Mode 3 (Hot Standby). All safety systems performed as required. - The ' licensee made the appropriate notifications as required by 10 CFR 50.72, Reporting Requirements.
As noted in the previous NRC routine inspection report (50-334/88-31 and 50-410/88-24), a relatively large number of personnel errors have been the cause for several plant events.
The licensee included this event in the ongoing Independent' Safety Evaluation Group (ISEG) review of the personnel error caused events over the past six months.
' Additionally, the licensee performed a Human Performance Evaluation System (HPES) investigation to - systematically
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review 'the events leading. to the plant trip. The primary cause was identified as failure to implement self-checking
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practices ~during work.
Contributing causes~ identified include. interface design problems (non-descriptive label-ing)
and. inadequate -written communications.
Further
$nspector review identified job task interruption - as an additional cause not specifically listed as a-root cause on the HPES.
Specifically, plant operators were performing several concurrent activities, including clearance prepara-tion for posting, liquid waste processing and-equipment (valve) problems and other miscellaneous control room alarr response while attempting to perform OST 1.1.10.
Although not listed _on,the HPES, the licensee did recognize the. job task interruption concern _ separately.
Corrective actions for the reactor trip include management discussions with all operators (Unit 1 and 2) during shift turnover and licensed operator retraining sessions.
Topics discussed included attentiveness to duties and a summary of events leading to. the plant trip. Ongoing corrective actions include interviews with operators to obtain input-on methods to preclude further personnel errors. The sub-
-ject of personnel errors is discussed separately in Section
- 10. The inspector will also independently assess operator performance and interface during routine inspections.
4.3.3 ESF Actuation On January 19, the Unit 2 control-room emergency bottled air pressurization- (CREBAP) system automatically actuated l
during the performance of a chlorine detection system (CDS)
calibration.
When the maintenance surveillance ' procedure
~(MSP) was' performed, the circuitry for the detector being calibrated ("A").was placed in the tripped position. When the
"A" detector was installed in the ductwork, the
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chlorine detector actuated, satisfying the two out of three CREBAP actuation ~1ogic.
Plant operators verified that
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there was no chlorine present in the control room and then isolated the CREBAP bottles.
Additional tests were per-formed to verify that there was no chlorine release, and none was found. The pressurized bottles did not drop below the Technical Specification required values, and they were subsequently unisolated. The licensee notified the appro-L priate agencies in accordance with 10 CFR 50.72 reporting
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requirements.
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n The licensee determined that the chlorine probe was piaced in a plastic probe container following its calibration in
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the test device. The test device is located in the main-tenance-shop. To facilitate transporting the probe back to the ventilation room, the container was used..The. licensee subsequently determined thtt the plastic container acts as a chlorine absorber.
Therefore, when probe
"A" was inserted into the. ventilation stream, there was enough residual chlorine on the probe.to actuate an adjacent probe ("B").
. Additionally, the licensee found that the test device oven was leaking chlorine such that a 3 ppm concen-tration of chlorine gas was identified around the oven, and
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L the plastic containers were located close to the oven, thereby allowing for chlorine absorption. The oven concen-tration.is normally about 5 ppm.
To prevent similar occurrences, for the short term, t_he use of the plastic probe containers will be limited only. to those probes for.
storage. Additionally, a procedure change is being initi-ated to provide instructions on verifying that the probes contain no residual chlorine prior to installation in the-ventilation flow.
The inspector will review these actions during future routine inspections.
4.3.4 Reactor Trip Due to Component Failure On February 12, Unit 2 automatically tripped from 65% power due to high-high level in the
"C" steam generator.
The high-high level caused a trip of the main turbine which then produced a reactor trip since power was above the P-9 setpoint of 49%. All systems responded per design and the unit was stabilized in Mode 3.
The cause of the level rise was the mechanical failure of the internals of the "C" main feed regulating valve (MFRV) (2PdS-FCV 498).
For addi-tional details, see Section 7.
4.3.5 Reactor Trip Due to Instrument Failure Unit 1 automatically tripped from 90% power on February 13, due to low level in the "C" steam generater coincident with a steam-feed flow mismatch.
An instrument failure (I-P converter) caused the
"C" MFRV to close to the 25% open position. Level in the "C" steam generator dropped sharply leading to the reactor trip.
All systems responded per design and the unit was stabilized in Mode 3.
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- The defective component.was tested and found to produce.a
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25% open signal due.to a buildup of nearly microscopic particles in the two small orifices (0.016 and 0.018 inches in diameter) in the relay. of the converter. The converter translates an electronic signal (in the 400 milli-amp range) into an air pressure (3 - 15 psig). The inspector
. reviewed the design of the instrument air system supply and L
found that the air passes through a 5 micron ' filter which is located locally at the load.
The filter is sized,
_therefore, to prevent passage of particles at let.st two.
orders of magnitude smaller than the system orifices. The I-P converters were replaced for all.three MFRVs. a'nd the
. unit was returned to service on February 14. The licensee.
is evaluating operating history data to determine if a maximum' continuous service limit should be administratively imposed to prevent recurrence.
4.4 Plant Security / Physical Protection Implementation of the Physical Security Plan was observed in various plant areas with regard to the following:
Protected Area and Vital Area barriers were well maintained and
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not compromised; Isolation zones were clear;
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Personnel and vehicles entering and packages being delivered to
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the Protected Area were properly searched and access control was in accordarce with approved licensee procedures; Persons granted access to the. site were badged to indicate
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whether they have unescorted 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 knowledgeable regarding position requirements, and that written procedures were available; and Adequate illumination was maintained.
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LAt 12:11 am - on-February 4,1989, the Unit I control room received three pressurizer code ' safety. valve diaphragm test alarms -(one for each valve)_ within several seconds.
They were all immediately reset by plant operators. Within 15 minutes, the operators locally' verif-ied the. operability 'of the test' panel (located in the Auxiliary -
Building). The actual pressure instruments, whose function is tested via the remote. test panel, provide an indication of a safety valve bellows failure. The licensee then identified'one individual (secur-ity gu'ard) in the area at the time of the alarms, who was immediately escorted offsite and removed from site access pending further evalua-tion.
Since tampering was suspected,. the licensee searched several areas. for evidence of misalignment of safety equipment.
No defici-encies were-found. Followup investigation by licensee and contractor personnel and interviews with the individual involved concluded that tampering or malicious intent was not involved.
The apparent non-intentional bumping -of the above plant equipment and the associated corrective. actions were still under review at the end of the inspec-tion.
The inspector will closely monitor these activities in the next inspection period.
4.5 Radiological Controls Posting ~and control of radiation and high radiation areas were inspected.
Radiation Work ' Permit compliance and use of personnel monitoring devices were checked.
Conditions of step-off pads, dis-i posal of protective clothing, radiation. control job coverage, area
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= monitor operability and calibration (portable and permanent) and personnel frisking were observed on a sampling basis.
No concerns were identified.
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 various 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 Ur,it I and Unit 2.
Overall, housekeeping was found to be adequate for both units.
During detailed walkdowns of Unit I safety related electrical systems, the inspector observed trash (including newspapers, cigarette butts and dirt) under both emergency diesel generators, cardboard in a 480-volt emergency bus and excessive dust and dirt in certain nuclear instrument cabinets and other control room,sanels.
These and other deficiencies were-identified to the licensee for resolution; all identified items were corrected prior to the end of the inspection period.
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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 1.1.1, Control Rod Assembly Partial Movement Test, January 23, 1989 OST 1.7.1, Boric Acid Transfer Pump Operational Test, January 5, 1989 OST 1.36.1, Diesel Generator No. 1 Monthly Test, January 20, 1989 OST 2.26.1, Turbine Throttle, Governor, Reheat Stop, and Intercept Valve Test, February 7, 1989 OST'2.36.1, Diesel Generator No. 2 Monthly Test, January 25, 1989 No deficiencies were identified.
6.
Quality Assurance Regarding Diesel Generator Fuel Oil By letter dated April 14, 1980, the licensee responded to the staff's January 7,1980 letter regarding Quality Assurance (QA) requirements for emergency diesel generators (EDGs), fuel oil for Unit 1.
The licensee committed to gradually implement the regulatory position documented in Regulatory Guide No. 1.137, Fuel-0il Systems for Standby Diesel Genera-
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tors, _from then through the third refueling shutdown.
For Unit 2, the l
licensee made a similar commitment in the Final Safety Analysis Report, Section 9.5.4.
The licensee's commitment, and the staff's requirements, have been expressed in detail in Unit 2 Technical Specifications (TSs)
4.8.1.1.2.a.3 and 4.8.1.1.2.c through f.
Unit 1 TSs contain a similar TS , 4.8.1.1.2.a.3, however, do not contain detailed requirements similar to i
those in the Unit 2 Specifications 4.8.1.1.2.c through f.
While the lack of detailed specifications does not necessarily mean that the Unit I diesel fuel oil is subject to a less stringent set of requirements, the licensee should nevertheless evaluate the need for such specifications.
The inspector reviewed the licensee's Chemistry procedures and noted specified limits on water content, sediment, viscosity, sulfur content, cloud point and frequency of sampling and testing. The inspector reviewed selected logs and concluded that these documents indicated that the chem-istry procedures have been properly implemented.
In addition, a review of a licensee's QA audit report and an associated follow-up document pro-
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vided evidence that appropriate QA has been exercised with respect to the diesel fuel oil.
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Despite all of the abovr positive indications, there was no evidence that.
diesel fuel oil, a consumable item, has been clearly included in the licensee's QA program.
Specifically, procurement orders did not speci fy.
that diesel fuel oil is a safety-related item.
Consumable items where quality is necessary for functional performance of safety-related com-ponents should also be classified as safety-related, and thus be subject to the applicable provisions of 10 CFR 50, Appendix B.
The inspector discussed this concern with the licensee who stated that the appropriate actions or justification for exclusion of fuel oil in the licensee's QA program would be initiated.
The licensee's evaluation of Unit 1 TSs and the actions taken with respect to QA program inclusion /
classification will be reviewed during a future inspection.
7.
Main Feedwater Regulating Valve Failure The failed valve discussed in Section 4.3.4 was disassembled and the mech-anical damage was assessed.
The MFRV is a "pl ug-ba s ke t" design with a hollow, grooved can (the " plug") stroking inside a perforated cage (the
" basket").
Flow is through the perforations of the cage as exposed by the movement of the plug and down into the lower plenum of the valve and out, or through the hollow can into the upper plenum of the valve and out.
The plug is subject to large forces as the feedwater flow is broken down in the cage perforations which act as orifices.
Rotational forces are restricted by mechanical pins which are shrink-fitted into the basket from the valve stem.
Vertical forces are also involved as the upward flow through the hollow plug is across the bar-like anti rotation pin.
The forces on the plug and pin work the bar inside the plug and produce a
" peening out" effect which tends to enlarge the hole by wearing the seat-ing surface.
The inspector examined the failed MFRV and visible damage to both the bar l
and plug was evident.
The licensee disassembled the other two MFRVs and
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the pin plug fit was found to have loosened for both valves. The inter-nals of all three valves were shipped to the vendor for repair.
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The cause of the MFRV wear and failure is also related to the hardness of the internals themselves.
Unit 2 employs a sof ter stainless steel alloy than Unit 1 (Type 304 vs. Type 420 at Unit 1) with stellite facing for the plug surface.
In January 1988, the
"C" MFRV anti-rotation pin was replaced by a Unit I spare thus placing a Type 420 pin in a Type 304 seat-ing surface.
The harder pin enlarged the seating surface more rapidly than expected. This led to the "C" MFRV failure while the other two MFRVs (with Type 304 pin and plug) experienced only a loosening of fit during the same period.
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The licensee plans to repair the damaged and worn internals, complete the i
fuel cycle, and evaluate long term corrective actions for potential imple-
- mentation during the first refueling outage. scheduled to begin on March 17, 1989.
The inspector will review licensee plans' in a future inspection.
8; Safety Evaluations for Setpoint Changes
. Federal regulations authorize licensees to make changes in the facility and procedures unless it involves a change to the Technical Specifications or an unreviewed safety question (10 CFR 50.59).
The regulations also describe what reports and records are required as documentation.
The licensee uses the 50.59 process in making setpoint changes to plant sys-tems.
The licensee handles the 50.59 process by two different methods for setpoint changes.
In the first method, when setpoints are required to be changed due to a proposed permanent modification to a plant system, the licensee's Engi-neering Department uses a design change package (DCP) to implement the modification.
The proposed setpoint changes receive a 50.59 review as part of the 50.59 review for DCP. The review is conducted in accordance with the Nuclear Engineering Administrative Procedure 2.4 - Safety Evalua-tiens.
In a previous inspection (50-334/88-25 and 50-412/88-19), the inspector reviewed selected safety evaluations for permanent modifications and found them to be of good quality with adequate justification for stated conclusions.
The licensee handles setpoint change requests, which are not the result of hardware modifications, differently. When a setpoint change is requested, the requestor asks the Engineering Department via Engineering Memorandum
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(EM) to determine how the instrument / controller should be recalibrates.
Once that is completed, the licensee's Onsite Safety Committee (OSC)
determinos which station procedures require incorporation. of the new set-point and then performs a 50.59 review for that procedure if it is required. The 50.59 reviews for these setpoint changes are conducted in i
accordance with Site Administrative Procedure 10 - Onsite Safety Commit-tee. The inspector requested the safety evaluations for several setpoint changes that did not involve DCPs, but the licensee had not provided these i
records by the end of the inspection period.
The adequacy of the 50.59 review for setpoint changes not involving a DCP will be reviewed in a future inspection.
9.
Unreviewed Facility Modifications
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Licensees are required (10 CFR 50.59) to evaluate proposed changes to the l
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facility to assure that the change does not involve an unreviewed safety i
question. Complex permanent modifications and simple temporary modifica-l tions provide different but significant challenges to the evaluation process.
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On March 3,1988, the licensee identified that Unit I had started up and; j
operated for about 8 days with two of four high-high containment pressure bistables defeated (see Special Inspection Report 50-334/88-12). One con-tributory factor to the event was the 1980 deletion of nain control panel lights which indicated if these bistables were defeated. The 1980 modifi-cation (DCP-94) was a major one involving numerous systems and indicators.
A recent, simple temporary modification at Unit 2 involved bypassing an air dryer in the 2-1 diesel air start system. No time limit was specified and the dryer had been bypassed for about 6 months.
The NRC concern involved industry experience which includes diesel start failures due to l
water accumulation in starting air systems (Violation 50-334/88-28; I
50-412/88-22).
Licensee response to the above item is still in progress with programmatic actions scheduled to be complete by July 31, 1989.
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During this inspection period, the inspector identified two more examples of modifications which may not have had adequate review. An oscilloscope was noted to be installed in a Unit 1 nuclear instrument cabinet.
The oscilloscope was not found on any applicable drawings and did not appear to be seismically mounted. Licensee review indicated that the device had i
been installed at least nine years before and no review of the modifica-
tion was documented. The oscilloscope was removed pending further review and evaluation, j
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The second example involved duct tape on two safety related battery room ventilation intakes.
The inspector found that the tape had apparently been added to eliminate the excess amount of air being extracted from the non-safety related normal switchgear ventilation system (adjacent to the battery rooms) following recent' ventilation system modifications and flow balancing.
The application of duct tape over. about 75% of the louver surface area was intended to restore air flow to required values. It was not clear that the use of tape to adjust safety related ventilation sys-tems. received the appropriate level of review. In response to the inspec-i tor's concerns, the licensee completed a 10 CFR 50.59 safety evaluation for the above temporary modification on February 9.
The inspector re-viewed the safety evaluation and found it to be adequate.
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Violation 50-334/88-28-02; 50-412/88-22-02 remains open pending completion of licensee corrective actions and'further NRC review.
10.
Personnel Errors The apparent increase in personnel errors was noted by the licensee in LER 88-19 (Unit 2) and the licensee committed to perform additional-investiga-tion into potential common root causes (also see Inspection Report 50-334/
88-31; 50-412/88-24).
During this inspection period, another personnel error caused a reactor trip (see Section 4.3.2).
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The licensee's investigation was conducted by the Independent Safety l
l Evaluation Group and was completed on February 3, 1989.
The inspector found the ISEG study to be thorough and well documented.
The study also
. included the results of an employee survey. The study and survey results
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were consistent with areas for improvement including procedure clarity and l
completeness.
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The inspector conducted an independent review of all LER events since January 1988.
The inspector identified a total of nine events which were caused by operator error and which resulted in a reactor trip or an ESF actuation. Only one of the nine occurred during day shift on a weekday; all others were on backshifts or weekends.
Unit LER Date Time Event
88-03 1/29/88 0539 ESF
88-07 6/7/88 2155 Reactor Trip, SI
88-08 6/9/88 0149 Reactor Trip, during S/U
88-11 8/23/88 1716 ESF, during S/U
88-14 9/24/88 1103 (Weekend) ESF
88-14 10/3/88 1928 ESF
88-15 9/12/88 1630 ESF
88-16 11/15/88 1003 ESF
89-01 1/17/89 1835 Reactor Trip Two of the nine events, LERs 88-07 and 88-14 (concerning the 10/3/88 event), involved backshif t surveillance testing by one operator where two were previously used. One operator was adequate but had more to do than was customary.
Two other events, LERs 88-08 and 88-11, occurred during complex activities associated with plant startup on a backshift. The most recent event, LER 89-01, had interruption due to concurrent tasks as a contributor (see Section 4.3.2).
There are three shifts each day for twenty-one shifts a week and most work is scheduled for the five daylight shifts. If personnel error events were randomly distributed, more than one of the nine events would have been expected during the daylight shifts (only 11% of events during the 24% of the shifts). The low sample size (9) makes no firm conclusion possible, but it does suggest further review of the differences between the shifts might be of value.
Before January 11, 1988, the facility utilized a five shift rotation going to a six shift rotation on that date. The reactor operators man two posts in each control room such that the qualified personnel (at that time 23 for Unit 1 and 17 for Unit 2) were divided into five groups with the extra reactor operators available on shift as needed.
Similarly, the non-licensed operators (at that time about 60) were divided into five groups and then split between the two units as needed each shift. Using decimals to depict the average manning available on each shift, Unit I had 4.6 reactor operators, Unit 2 had 3.4 reactor operators and 12.0 non-licensed operators were available per shift.
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During this inspection period a year later, the number of personnel has declined.
In combination with the six shift rotation, the drop is signif-l icant.
Current shif t averages are 3.3 reactor operators on Unit 1, 2.5 reactor operators on Unit 2 and 7.3 non-licensed operators for the facility.
The Technical Specifications require a minimum of 2 reactor operators and 2 non-licensed operators per unit during operation above Mode 5.
The inspector contacted several other dual plant PWRs of similar size and found that the current Beaver Valley manning levels do not appear to be significantly below industry practice.
The current manning levels do, however, represent about a 25's drop in shift personnel from previous facility experience.
The inspector monitored several backshifts during the period (see Section 4.3) and identified no evidence of an overburdened operating staff during normal plant operations.
The higher error rate on backshifts may be unexpected for a lower level of available personnel available to get the work done.
One indicator that the above concern may have some merit is the lower error rate on the day shif t.
Current licensee practice is to double-shift at that time, that is, two full shifts are available. The shift personnel not standing watch are used for the work or tests scheduled for that time.
During complex events such as plant startups, one back shift. could be challenged to handle all the activities such as manual feed control and turbine roll. Discussions with shift supervision revealed that when such activities are planned off day shift, additional personnel are made avail-able. One method used is keeping one shift late and/or calling the next shift in early.
The licensee schedules most activities during the higher-staffed day shift.
Complex events on back shifts are dealt with by calling in more operators.
The threshold for when to call in help versus when on-shift personnel are adequate for unscheduled work may require more review by licensee management.
11.
Meetings Periodic meetings were held with senior facility management during the course of this inspection to discuss the inspection scope and findings. A summary of inspection findings was further discussed with the licensee at the conclusion of the report period on February 22.