IR 05000397/1992031
| ML17289B005 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 11/09/1992 |
| From: | Johnson P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17289B004 | List: |
| References | |
| 50-397-92-31, NUDOCS 9212010155 | |
| Download: ML17289B005 (77) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report No:
Docket No:
License No:
Licensee:
Facility Name:
Inspection at:
50-397/92-31 50-397 NPF-21 Washington Public Power Supply System P. 0.
Box 968 Richland, WA 99352 Washington Nuclear Project No.
(WNP-2)
WNP-2 site near Richland, Washington Inspection Conducted:
August 24 October 4, 1992 Inspectors:
R.
C.
. W. P.
D. F.
R.
C.
D. L.
Sorensen, Senior Resident Inspector Ang, Acting Senior Resident Inspector Kirsch, Reactor Inspector Barr, Senior Resident Inspector, Trojan Proulx, Resident Inspector Approved by:
P.
H.
ohnson, Chief React Projects Section
Date Signed
~Summar:
Ins ection on Au ust
1992 October
1992 50-397 92-31 Areas Ins ected:
Routine inspection by the resident inspectors of control room operations, licensee action on previous inspection findings, operational safety verification, surveillance program, maintenance program, licensee event reports, special inspection topics, and procedural adherence.
During this inspection, Inspection Procedures 41500, 61715, 61726, 62703, 71707, 71710,,
90712, 92700, 92701, 92702 and 93702, and TI 2515/115 were used.
Safet Issues Mana ement S stem SIMS Items:
None.
Results:
General Conclusions and S ecific Findin s
Weaknesses:
Review of completed local leak rate test (LLRT) procedure records identi.fied several procedure documentation discrepancies similar to those recently identified in Inspection Report No. 50-397/92-25.
While these 9212010155 921109 PDR ADOCK 05000397
discrepancies did not appear to challenge the validity of the test results obtained, they further illustrated the'need for senior management attention to procedure adherence concerns at WNP-2 (Paragraph 8).
Si nificant Safet Matters:
None.
Summar of Violations and Deviations:
No violations or deviations were identified.
0 en Items Summar
Two followup items and four LERs were close DETAILS Persons Contacted
- L. Oxsen, Acting Managing Director
- V. Parrish, Assistant Managing Director for Operations
- J. Gearhart, guality Assurance Director
- C. Powers, Engineering Director
- J. Baker, Plant Manager
- L. Harrold, Assistant Plant Manager
- G. Sorensen, Regulatory Programs Manager
- C. McGilton, Operational Assurance Manager
- D. Pisarcik, Radiation Protection Manager
- D. Feldman, Assistant Maintenance Manager
- A. Hosier, Licensing Manager
- S. Davison, guality Assurance Manager
- J. Peters, Administrative Manager
- W. Schaeffer, Acting Operations Manager
- R. Webring, Plant Technical Hanager
- L. Grumme, Manager, Nuclear Safety Assurance
- R. Koenigs, Manager, Design Engineering
- C. Noyes, Manager, Engineering Programs
- D. Larkin, Manager, Engineering Services
- S. Washington, Nuclear Safety Engineering Manager
- G. Moore, Supervisor, Engineering Data
- R. Yosburgh, Supervisor, Safety Analysis
- R. Derusseau, Bechtel, Contract Engineer
- C. Fies, Licensing Engineer The inspectors also interviewed various control room operators, shift supervisors and shift managers, and maintenance, engineering, quality assurance, and management personnel.
- Attended the Exit Meetings held on September 25 and/or October 8, 1992.
Plant Status At the start of the inspection period, the plant was in Mode 4 (cold shutdown), with the startup on hold until the provisions of the NRC Confirmatory Action Letter (CAL) associated with the power oscillation event of August 15, 1992 were satisfied.
The reactor was restarted on August 30, and achieved full power on September 3.
On September 6,
reactor power was decreased to 65'o perform a rod adjustment and for repair of the dump valve for feedwater heater 5B.
The reactor was returned to full power later that day.
On September 8, feedwater heater 6B tripped, resulting in a momentary power excursion to 103.5~ power.
Control room operators reduced power to 80% to troubleshoot and repair the 6B heater.
The licensee performed a safety evaluation for full power operation with reduced feedwater temperature, and subsequently returned the reactor to full power on September 11.
On September 20, 1992, a
faulty governor for one of the diesel engines of Emergency Diesel Genera-tor (EDG) number 1 resulted in EDG 1 not fully loading and consequently
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failing its monthly TS surveillance test.
The troubleshooting, repair, and testing of the EDG took longer than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
The licensee requested and received a temporary waiver of compliance from the TS to preclude a
shutdown.
The testing of the new governor for EDG 1 was completed on September 24, and the licensee declared EDG 1 operable.
On September 27, the High Pressure Core Spray (HPCS) Diesel Generator, DG-3, failed to load during its monthly operability surveillance.
DG-3 was repaired and declared operable on September 29.
The plant remained at full power for
'he remainder of the inspection period.
3.
Previousl Identified NRC Ins ection Items 92701 92702 The inspectors reviewed records, interviewed personnel, and inspected plant conditions relative to licensee actions on previously identified inspection findings:
a.
Closed Violation 397 92-03-03
Im ro er Isolation of Control Rod Drive H draulic Exhaust Water Valve.
A violation of Technical Specification 3.1.3.1 occurred when an inoperable control rod was not isolated properly by shutting the exhaust water isolation valve.
Although this violation was identified by the licensee and the correct valve was shut at the time the condition was identified, a Problem Evaluation Request (PER)
was not written to document the problem and assess whether or not the condition was reportable.
The licensee amended PPH 2. 1. 1 (Control Rod Drive System Operation)
to provide proper direction for isolation of an inoperable control rod.
The condition was also reported to the NRC pursuant to 10 CFR 50.73.
In addition, the Plant Hanager issued a memorandum to all licensee personnel to stress the importance of writing PERs for any condition or situation that appears abnormal.
The inspector reviewed the licensee's corrective actions, and concluded that they were satisfactory.
This item is closed.
b.
Closed Violation 397 92-09-03
Im ro erl Confi ured Standb Li uid Control SLC S stem Seismic Su ort.
While firing and replacing the squib valves for the SLC system, licensee personnel loosened, but failed to reconfigure, a seismic support.
PPH 10. 10.2,
"SLC Squib Valve Test and Replacement,"
required the support to be loosened but did not provide adequate direction for reassembly.
The licensee's corrective actions for this violation included tightening the restraint and revising PPH 10. 10.2 to provide more specific direction for loosening and tightening seismic restraints.
In addition, PPH 10.2.29 was revised to include more detailed configuration and clearance requirements on U-bolt type supports.
The inspector walked down the SLC system, the specific seismic support, and a sampling of other SLC system pipe supports.
No additional violations were identified.
The inspector reviewed the revised procedures and determined that the licensee's corrective actions were satisfactory.
This item is close l t'l
c.
Review of Other 0 en Items The inspector reviewed the following open items for licensee corrective actions.
However, the licensee's corrective actions were not sufficiently complete to close them:
N.
~g 90-28-03 92-03-02 92-09-04 Weaknesses Noted in Diesel Fuel Oil Procurement and Testing Require further Actions to Resolve Inadequate 50.59 Review of Containment Atmosphere Control (CAC) System Test Deviation from FSAR SLC Tank Heater Band 92-09-01 No Flashing Light for High-High Radiation Area 92-09-02 No Corrective Action for Leaking SLC Pumps No new violations or deviations were identified.
4.
0 erational Safet Verification 71707 a.
Plant Tours The following plant areas were toured by the inspectors during the course of the inspection:
Reactor Building Control Room Diesel Generator Building Radwaste Building Service Water Buildings Technical Support Center Turbine Generator Building Yard Area and Perimeter b.
The following items were observed during the tours:
(1)
0 eratin Lo s and Records.
Records were reviewed against Technical Specification and administrative control procedure requirements.
(2)
Monitorin Instrumentation.
Process instruments were observed for correlation between channels and for conformance with Technical Specification requirements.
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d for conformance with 10 CFR 50.54.(k), Technical Specifica-tions, and administrative procedures.
The attentiveness of the operators was observed in the execution of their duties.
The control room was observed to be free of distractions such as non-work related reading materials and radio ~
i'
E ui ment Lineu s.
Valves and electrical breakers were veri-fied to be in the position or condition required by Technical Specifications and administrative procedures for the applicable plant mode.
This verification included routine control board indication reviews and conduct of partial system lineups.
Technical Specification limiting conditions for operation were verified by direct observation.
E ui ment Ta in
.
Selected equipment, for which tagging requests had been initiated, was observed to verify that tags were in place and the equipment was in the condition specified.
The inspector reviewed the tags for clearance order 91-9-C026 on September 22.
The inspector noted that the tag for valve DCM-V-10A2 was not hanging on the valve but was lying on the floor nearby.
The inspector informed the Shift Hanager, who promptly directed an Equipment Operator to rehang the tag.
The clearance order was for caution tags, and the valve was still in its correct position.
The condition did not appear to cause a safety or operability concern.
The inspector discussed with the Operations Hanager the need for assuring that tags be maintained and emphasized the need for thorough audits of the clearance order process.
The Operations Hanager acknowledged the inspector's concern.
General Plant E ui ment Conditions.
Plant equipment was observed for indications of system leakage, improper lubrica-tion, or other conditions that would prevent the system from fulfilling its functional requirements.
Annunciators were observed to ascertain system status and operability.
Floor Drains system check valves FDR-V-27 and 28 were observed to be chattering, apparently due to the differential pressure between the cable spreading room and the radwaste building.
The purpose of FDR-V-27 and 28 was to prevent the spread of airborne radioactivity (if a problem exists)
from the radwaste building sumps to the cable spreading room.
The licensee identified this problem in January of 1991, and issued a plant modification request (PHR) to redesign these check valves.
The PHR was not scheduled to be accomplished until 1994.
This was discussed with the licensee and the licensee described it to be a discrepancy that was given a lower priority than other more urgent work.
The licensee's disposition appeared to be reason-able.
However, the licensee continues to have a large backlog of items requiring corrective action.
The licensee's correc-tive action backlog and prioritization for completion of those actions will continue to be reviewed by the NRC inspectors.
Fire Protection.
Fire fighting equipment and controls were observed for conformance with administrative procedures.
Plant Chemistr
.
Chemical analyses and trend results were reviewed for conformance with Technical Specifications and administrative control procedure (iO)
(i2)
Radiation Protection Controls.
The inspectors periodically observed radiological protection practices to determine whether the licensee's program was being implemented in conformance with facility policies and procedures and in compliance with regulatory requirements.
The inspectors also observed compliance with Radiation Work Permits, proper wearing of protective equipment and personnel monitoring devices, and personnel frisking practices.
Radiation monitoring equipment was frequently monitored to verify operability and adherence to calibration frequency.
On August 31, during a tour of the turbine building, the inspector found a high radiation area boundary rope on the floor with the sign facing downward.
Although radiation levels were 1-2 mr/hr, licensee procedures required the area near the main condenser to be posted as a high radiation area prior to power ascension greater than 65~ power.
The reactor was 15%
power at the time.
The inspector informed the lead Health Physics Technician (HPT) and the problem was corrected.
The licensee initiated a Problem Evaluation Report (PER) to address the root cause of the problem, and the HPT's were briefed on the occurrence.
Plant Housekee in
.
Plant conditions and material/equipment storage were observed to determine the general state of clean-liness and housekeeping.
Housekeeping in the radiologically controlled area was evaluated with respect to controlling the spread of surface and airborne contamination.
During tours of the reactor building and other vital areas, the inspector noted a large number of housekeeping deficiencies.
This included loose scaffolding, unsecured tool boxes, unattended electrical cabling, loose paper trash, and unsecured hand carts and ladders.
None of these deficiencies posed an immediate operability problem.
These housekeeping problems were discussed with the Shift Hanager and licensee management, and the problems were corrected.
~Securit
.
The inspectors periodically observed security practices to ascertain that the licensee's implementation of the security plan was in accordance with site procedures, that the search equipment at the access control points was opera-tional, that the vital area portals were kept locked and alarmed, and that personnel allowed access to the protected area were badged and monitored and the monitoring equipment was functional.
Overtime.
The inspectors reviewed the licensee's overtime records to ascertain if the licensee was in compliance with the overtime restrictions of the Technical Specifications.
Any deviations from the TS were properly authorized by the Plant Manager.
The inspector noted that a significant number of licensed operators worked many 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts to support vaca-tions and licensed operator training.
The licensee appeared to have no extra personnel outside of their 5 crew rotation, to
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make up for any absences.
This practice was discussed with the plant manager to ascertain licensee compliance with TS requirements.
Licensee management acknowledged the inspectors'bservations and stated that (1) routine use of overtime was not their intent, (2) operators were being carefully monitored by management to ascer tain their capability of performing their assigned tasks, and (3) the operators would see reduced overtime in early 1993 after the next initial license exam.
c.
En ineered Safet Features Walkdown Selected engineered safety features (and systems important to safety)
were walked down by the inspectors to confirm that the systems were aligned in accordance with plant procedures.
During the walkdown of the systems, items such as hangers, supports, electrical power supplies, cabinets, and cables were inspected to determine that they were operable and in a condition to perform their required functions.
Proper lubrication and cooling of major components were also observed for adequacy.
The inspectors also verified that certain system valves were in their required position by both local and remote position indication, as applicable.
Accessible portions of the following systems were walked down on the indicated dates.
~Ss tern Diesel Generator Systems, Divisions 1, 2, and 3.
Hydrogen Recombiners Low Pressure Coolant Injection (LPCI)
Trains "A", "B", and "C" Low Pressure Core Spray (LPCS)
High Pressure Core Spray (HPCS)
Reactor Core Isolation Cooling (RCIC)
Residual Heat Removal (RHR), Trains IIAl and II8ll Dates September 8,
September
September
September
September 8,
September
September
Scram Discharge Volume System Standby Liquid Control (SLC) System Standby Service Water System Standby Gas Treatment System 125V DC Electrical Distribution, Divisions 1 and
September 8,
September 8,
September
September
September 3,
250V DC Electrical Distribution No violations or deviations were identified.
September 3,
5.
Diesel Generator Failures 93702 On September 20, 1992, EDG 81 failed to fully load, due to a governor fai lure, during its monthly operability test.
The plant EDG's have had no previous recent problems with governors.
The complexity of the troubleshooting, replacement, and testing for restoring the EDG to an operable condition required more than
hours to complete.
The licensee requested and received a Temporary Waiver of Compliance (TWC) to extend the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement an additional three days, to preclude a shutdown.
The licensee successfully completed repair and retesting within the time allowed by the TWC, and declared the EDG operable.
However, the following apparent licensee performance weaknesses were revealed during these acti vities.
The diesel failed to start on September 22 due to an improper lineup.
For one portion of the troubleshooting, the licensee used the concept of a "human danger tag."
This concept (permitted in the licensee's procedures)
allows use of an equipment operator (EO) guarding the component to prevent its operation.
This option was employed for the EDG air start isolation valves.
When the troubleshooting was completed, the EO failed to open the air start isolation valves, so the EDG failed to start when receiving the start signal.
This condition was identified by the licensee's testing process, preventing an operability concern.
The booster for the EDG (removed for the troubleshooting)
was improperly reinstalled on September 23 after the governor was replaced.
The connections for the supply lines and the discharge lines were interchanged.
This was identified by the licensee, and.corrected prior to further testing.
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The licensee had to repeat the surveillance test (PPH 7.4.8.1. 1.2.1,
"EDG-1 monthly Operability") performed on September 24, because the minimum loading of 4400 kilowatts (KW) for the EDG 1 was not maintained for the duration of the test.
The load at the end of the test was allowed to decrease to 4350 KW.
This was discovered by the system engineer during data review following completion of the surveillance.
The governor vendor examined the faulty governor and advised the licensee of a relaxed spring in the mechanical governor.
However, further licensee root cause evaluation indicated a problem with cleanliness of the governor oil.
The licensee appeared to be performing a comprehensive root cause evaluation for the failure.
However, at the end of this inspection period, the root cause evaluation had not been completed.
Reasonable assurance existed in the root cause program to ascertain that generic corrective action would be completed if determined to be necessar b.
During the performance of the Division 3 (or HPCS)
EDG monthly operability test, the HPCS diesel failed to fully load.
The test was secured and the action statement for HPCS DG inoperability was entered.
The HPCS diesel was found to have a faulty motor operated potentiometer (MOP) in the electrical governor.
The MOP was replaced, the diesel was retested, and the diesel was declared operable.
For each of the above problems, the licensee initiated PERs to address the root causes of these issues.
The root cause evaluations were in progress at the end of this inspection period; the root cause program included reasonable assurance that corrective action will be completed.
No violations or deviations were identified.
6.
Surveillance Testin 61726 Surveillance tests required to be performed by the Technical Specifica-tions (TS) were reviewed on a sampling basis to verify that:
(1)
a technically adequate procedure existed for performance of the surveil-lance tests; (2) the surveillance tests had been performed at the frequency specified in the TS and in accordance with the TS surveillance requirements; and (3) test results satisfied acceptance criteria or were properly dispositioned.
In addition, the inspector reviewed several completed surveillance procedures for accuracy and completeness as described in paragraph 8 of this report.
Portions of the following surveillance tests were observed by the inspectors on the dates shown:
7.4.3.2.1.4 Leak Detection System Channel Functional Test Dates Performed September
7.4.8.1.2.12 HPCS Diesel Operability No violations or deviations were identified.
September
7.
Plant Maintenance 62703 The inspector observed and reviewed documentation associated with maintenance and problem investigation activities.
Compliance with regulatory requirements and with administrative and maintenance procedures was verified.
Appropriate gA/gC involvement; proper use of clearance tags, proper equipment alignment and use of jumpers; personnel qualifications; and proper retesting were ascertained.
The inspector verified that reportability evaluations were performed as required.
The inspector witnessed portions of the following maintenance activities:
Descri tion Dates Performed AP-0460, Replace MOP in HPCS Diesel September
'
AR-8581, Replace Connectors for Flow September 14-16 Proportional Composite Sampler During observation of the two connector s for the flow proportional composite sampler, the inspector found that the work instructions appeared to provide the craftsmen with adequate detail to perform the task.
The inspector observed the craftsmen deenergize the sampler, remove the wiring harnesses, remove the circuit card, and replace the connector.
The craftsmen closely examined the circuit card.
They observed three damaged power supply resistors and severe discoloration of the circuit card in the area under the resistors.
At the direction of their supervisor, the craftsmen initiated an HWR to replace the resistors and repair the board.
The supervisor, in consultation with the craftsmen, determined that the circuit board was operable, even though the resistors and the circuit board were damaged, because the sampling system was working prior to the maintenance.
The inspector observed the following:
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The work instruction provided the craftsmen with adequate detail to perform the task.
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The craftsmen followed the work instructions.
The craftsmen performed a critical inspection of the circuit board.
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The craftsmen did not document that they found two mounting screws missing on the circuit card.
This may have contributed to the wiring harnesses coming loose.
The licensee could not locate the applicable vendor manual.
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The uncontrolled prints the craftsmen were using indicated that modifications had been made to the circuit board without proper documentation.
Hecause the system was designated as a quality class 2 system, the licensee was not required to maintain configuration control over this component.
However, the observation of no vendor manual and outdated prints may be indicative of a weakness in configuration management.
The above was discussed with licensee management, who stated that the vendor manual would be provided to the inspector, and the prints would be updated.
No violations or deviations were identified.
8.
Containment Inte rit 61715 The inspector reviewed various aspects of the licensee's programs for maintaining containment integrity.
This inspection included reviews of completed surveillance procedures, interviews with personnel and walkdowns of various penetrations.
The licensee appeared to be in compliance with technical specification requirements and final safety analysis report (FSAR) commitment The inspector reviewed the following procedures for verification of containment integri ty:
Procedure Descri tion 7.4.6.1.3.2 7.4.6.1.2 Primary Containment Personnel Airlock Leak Rate Test Inside Primary Containment Integrity Verification 7.4.6.1.1 7.4.6.1.2.4 Primary Containment Integrity Verification Containment Isolation Valve and Penetration Local Leak Rate Testing (LLRT)
The inspector verified that each of these procedures properly implemented the applicable technical specification and was performed within the proper time interval.
However, the inspector noted a number of procedure documentation discrepancies in the completed copies of the LLRT proce-dure.
These discrepancies were similar to those identified in Inspection Report No. 50-397/92-01, and addressed by the corrective actions described in the licensee's letter dated July 10, 1992.
While these discrepancies occurred prior to the licensee's implementation of these corrective actions and did not appear to challenge the validity of the test results obtained, they further indicated the need for senior management attention to procedure adherence concerns at WNP-2.
The inspector apprised the Assistant Plant Manager of the above observations, and the original copy of the LLRT procedure was corrected.
These observations were also reviewed by the Instrumentation and Control supervisor with the craftsmen to provide them feedback on the I&C shop's performance.
No new violations or deviations were identified.
Verification of Plant Records Tem orar Instruction 2515 115 The purpose of the inspection associated with this TI was to determine if the practices of licensee personnel performance regarding surveillances, fire watches and operator logs could result in record falsification.
The scope of this inspection included independent inspector observation of equipment operator rounds, and verification that the licensee developed an adequate program for prevention of record falsification.
The inspectors found that the Supply System had a self-monitoring program in place and that the self-monitoring program met the intent of the TI.
The licensee initiated this program in Harch of 1992, prior to the issuance of NRC Information Notice (IN) 92-30, as a result of notification of log falsification at another reactor site.
The licensee found six instances of potential log falsification, and over one hundred instances of missed fire tours.
One of these discrepancies appeared to result in a Technical Specifications violation, and was subsequently reported to the NRC pursuant to
CFR 50.72 in LER 92-23,
"Hissed
'II
Technical Specification Surveillance and Fire Tour Data Due to Less than Adequate Work Practices."
Because of the number of discrepancies, the licensee increased the scope of their followup investigation to include Chemistry, Health Physics, Maintenance, Security, and guality Control.
No additional significant problems were found.
The licensee subsequently submitted Revision 1 of LER 92-23 that provided additional investigation results and corrective actions, and a licensee commitment to perform periodic survei llances of log keeping practices.
Corrective actions by licensee management, as outlined in LER 92-23, Revision 1, included disciplinary action for individuals whose logs contained unexplained discrepancies, plant and Supply System management memoranda to more clearly define management expectations, and revised procedures to proide more specific direction for logkeeping.
The LER also described similar followup investigations conducted by the licensee in other organizational areas.
Based on the licensee's assessments and corrective actions, and resident inspection, this TI is closed.
No violation or deviations were identified.
Licensee Event Re ort LER Followu 90712 92700 The following LERs associated with operating events were reviewed by the inspector.
Based on the information provided in the report it was concluded that reporting requirements had been met, root causes had been identified, and corrective actions were appropriate.
The below LERs are considered closed.
LER NUMBER DESCRIPTION 92-23-0]
92-30 92-34 92-36 Hissed TS Data during Fire Tours and Equipment Operator Rounds Containment Isolation and ESF Actuation due to Trip of Inverter IN-3 ECCS Pump Room Seals not Watertight Containment Lighting not Deenergized as Required by TS No violations or deviations were identified.
Desi n Basis Documentation Pro ram 37700 The licensee established and began a program to identify and document the engineering design basis for WNP-2 in 1988.
The program is controlled by procedure no.
PDS-6, Revision 4, dated November 18, 1991, titled "Design Requirements Document Program Description and Writers Guide."
This document was supplemented by an informal desktop instruction providing additional requirements and detail to implement the program plan.
The
12 "
licensee observed the need to further evaluate their controlled procedure to assess the need to include the needed additional detail.
The licensee had visited four other utilities to obtain industry perspec-tive on Design Requirements Document (DRD) programs and had evaluated the recommended DRD topic list of NUREG 1397, Appendix F, and the NUNARC guideline document by means of a guality Action Team.
The format, scope, and content were redefined to address user concerns.
The inspector observed that a discussion of the system interfaces appeared to be missing and the licensee agreed to evaluate the inclusion of this area in their DRDs.
The licensee has identified 62 systems and 20 topics for completion in the program and scheduled these accordingly through 1995, the year projected for program completion.
Ten systems have been completed; how-ever, these were in various stages of rework before final approval.
Ten topical reports and seven system Design Requirements Documents (DRDs)
have been completed and approved.
Three, scheduled for completion in 1992, are in the final signoff process.
The licensee has established an ambitious schedule for 1993, consisting of fourteen systems and two topical reports.
The bulk of the safety related systems and topics have been completed or are well along in the generation process.
The inspector examined the completed and approved DRDs for the standby liquid control (SLC) and reactor recirculation (RRC) systems and the topical report for Electrical Separation.
The DRDs appeared to conform to specified engineering standard requirements.
The inspector did observe, however, that the DRDs appeared to be heavily oriented to a paperwork review with minimal consideration to the "state of the actual hardware installation.
The licensee's verification and validation processes were not specified by the program procedure and were not heavily focused upon field verifi-cation of design requirement implementation in the actual hardware or procedures for operation or testing of the system.
The design verifica-tion process used by the licensee consists of about 24 questions focused on assuring that the DRD contents conform to a standard of uniformity regarding the items to be included in the written DRD.
The licensee had performed some field verifications to answer specific questions; however, the licensee has no program for and does not implement any disciplined process to establish a verification and validation checklist, or to document the results of any field verifications performed.
The licensee representatives stated that they had made a conscious deci-sion not to perform a verification and validation program for the DRDs because they consider that other systems and programs are in place which accomplish the same thing.
For example, the following programs were felt, by the licensee, to accomplish the equivalent of a verification and validation program:
(1) periodic reviews of operating, surveillance and test procedures required by Technical Specifications; (2) system walkdown activities being done for other reasons; and (3) the setpoint calculation review program currently being performed.
The inspector acknowledged the licensee's position but observed that other utilities had found value in conducting a verification and validation program focused on assessing the
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-13-state of field conformance to the system design requirements and the designer's intent.
The inspector examined the listing of open items for the SLC and RRC systems and the licensee's processes for dealing with open items.
The inspector found that the individual engineers were responsible for open item tracking and closure and that open items were not systematically reviewed and worked off the list in a controlled manner.
The licensee considers that their engineering staff is sufficiently trained and know-ledgeable of established problem evaluation and reporting systems to ensure that important issues are not overlooked during the DRD generation process.
The licensee's Nuclear Safety Assurance Group performed an assessment of the Supply System's DRD program and issued a report in February, 1991.
The assessment was a substantial effort resulting in several findings.
The inspector reviewed the findings and concluded that some remain appli-cable to the current status of the DRD program; for example:
(1) the DRD program description does not cover all features of the program activi ties (an informal desktop instruction exists providing additional requirements and detail to implement the program plan);
and (2) there are no provisions for verifying and validating the completed DRDs.
No violations or deviations were noted.
Individual Plant Examination 37700 The licensee had recently completed, and submitted to the NRC, the Individual Plant Examination (IPE) for internal events.
The inspector reviewed the IPE to obtain information regarding those systems and components which the licensee had determined to exhibit the highest risk significance and the accident sequences which provided the greatest contribution to plant risk.
Section 6 of the IPE contained several recommendations for other plant organizations to consider to reduce plant risk; however, these had not yet been communicated to the affected plant organizations.
The results of the IPE had only recently been communicated to senior utility management and the licensee's management was in the beginning phases of assessing how the results of the IPE could best be utilized to reduce risk exposure.
The inspector discussed some of the initiatives used by other utilities to utilize the IPE results with representatives of the Supply System.
No violations or deviations were identified.
Inde endent Safet En ineerin Grou 40500 The licensee had established a Nuclear Safety Assurance Group (NSAG),
independent of line management and chartered to improve operational nuclear safety at the plant.
The NSAG consists of two separate organiza-tions: Nuclear Safety Engineering, which performs both technical assessments and operating experience reviews; and Operational Event Analysis and Resolutions, which focuses heavily on performing root cause assessments of operational events.
The Nuclear Safety Assurance Department issues a monthly report of their activitie The NSAG staffing is defined by Technical Specification Section 6.2.3 and the functions are specified by the Safety Analysis Report (SAR) response to THI Action Item I.B. 1.2, amendment no. 43, dated September 1991.
The licensee's staffing appeared to conform to Technical Specification requirements.
The licensee had established a set of procedures to implement the commit-ments of the SAR; these appeared generally adequate for the functions.
The NSAG performed an assessment in July 1992 of the degree with which NSAG adhered to the requirements of their own procedures, and reported the results of that assessment to the Supply System Deputy Hanaging Director by letter dated September 1,
1992.
The self-assessment identified several instances of procedure adherence problems.
The corrective actions specified provide for procedure revisions, implementa-tion of procedure requirements and staff training.
The inspector examined the following documents:
(1) quarterly plans for NSAG activities; (2)
NSAG staffing and qualifications; (3) the listing of open Operating Experience evaluations which remain to be closed; (4) the list of technical assessments completed by NSAG; (5) monthly reports of NSAG activities; and (6)
a sample of recently completed Technical Assessments (Erosion/Corrosion Honitoring, Shutdown Safety, and Core Instability Event Review).
The inspector concluded that:
the industry experience assessment backlog was not excessive and was being managed; the licensee appeared to be performing NSAG activities as required by Technical Specifications and the SAR (except that the recent Augmented Inspection Team report No.
50-397/92-30 identified one failure involving a BWR Owners'roup commu-nication);
and the licensee's activity plans in this area provided for continued conformance.
The Technical Assessments were substantial analyses of the topic, providing valuable recommendations and findings.
No violations or deviations were identified.
MNP-2 Corrective Action Pro ram 30702 Licensee representatives met with members of the regional staff in the Region V office on October 5, 1992 to discuss their root cause and corrective action programs and, to a lesser extent, Licensee Event Report (LER) 50-397/92-035,
"Inadequate Testing of the Scram Discharge Volume Vent and Drain Valves Due to Insufficient Test Instructions."
The following persons were present:
Mashin ton Public Power Su
S stem WPPSS J.
C. Gearhart, Director, guality Assurance J.
W. Baker, Plant Hanager J.
E. Rhoads, Hanager, Operational Events Assessment and Review (OEAR)
H. P. Reis, Compliance Supervisor
1
,I I
l'
-15-Nuclear Re ulator Commission NRC Re ion V
S. A. Richards, Deputy Director, Division of Reactor Safety and projects P.
H. Johnson, Chief, Reactor Projects Section
P.
P. Narbut, Regional Team Leader F.
Gee, Reactor Inspector D. E. Corporandy, Project Inspector The licensee representatives summarized their corrective action program as presented in Attachment A, and identified the following problems:
~
The corrective action backlog is high and the licensee has set goals to reduce the backlog.
According to graphs provided in Attachment A, Engineering, Haintenance, and Operations appear to be far from their fiscal year (FY) 93 goals.
~
LERs summarizing root cause have not always provided sufficient details of the problem in that contributing causes and other conditions are not always included in the report.
Omission of management factors is an example.
~
Training and refresher courses for OEAR staff have been deficient in some cases.
~
Regarding LER 50-397/92-035, the licensee agreed with earlier NRC observations that the LER narrative was difficult to understand, certain details of the event were missing, and the root cause was neither accurate nor insightful.
In general, the licensee agreed with the NRC observations.
However, the licensee still believed inadequate post maintenance testing to be the primary root cause, because neither the original nor revised maintenance work request (HWR) testing would have satisfied technical specification operability requirements.
The licensee submitted a revision I to the original LER in order to correct these deficiencies.
The inspectors intend to review the revised LER.
NRC Observations and Conments The NRC made the following observations and comments on the licensee's corrective action program:
MNP-2's LER format differs from that recommended in NUREG 1022, Supplement 2.
In particular, MNP-2 LERs do not have a specific section on "root cause" as recommended by the NUREG.
The licensee acknowledged that they would review the NUREG for potential enhancements to their current LER format.
NRC Region V review of LERs focuses on licensees'verview and response to events.
Caution should be exercised that management goals to reduce corrective action backlog are not misinterpreted by line personnel as an attempt to discourage the PER process.
management should
-16-continue to encourage employees to elevate problems to the appropriate level of attention through the PER process.
I5.
~Ei II The in'spectors met with licensee management representatives periodically during the report period to discuss inspection status, and exit meetings were conducted with the indicated personnel (refer to paragraph 1)
on September 25 and October 8, 1992.
The scope of the inspection and the inspectors'indings, as noted in this report, were discussed with and acknowledged by the licensee representatives.
The licensee did not identify as proprietary any of the information reviewed by or discussed with the inspectors during the inspectio I
'l~
WNP-2 COEU&CTIVEACTIONMANAGEMENTPROGRAM AGENDA 1.
INTRODUCTION 2.
PRESENTATION OF SUPPLY SYSTEM'S CORRECTIVE ACTION PROGRAM 10CFR50 APPENDIX B ARTICLE 16 PROGRAM CONDITIONS ADVERSE TO QUALITY REQUIRE PROMPT IDENTIFICATIONAND CORRECTION.
SIGNIFICANT CONDITIONS ADVERSE TO QUALITYREQUIRE A
E T BE DETERMINED & CORRECTIVE ACTION TO PRECLUDE REPETITION.
GUIDINGMEIHODOLOGYFOR ROOT CAUSE DETERMINATION MEASURES FOR IDENTIFYINGANDD ACTIONS.
G CORIKCZIVE EFFECTIVENESS EVALUATION&BENCHMARKING MAJOR PROGRAM IMPROVEMENTS TRACKINGAND STATUS SELF ASSESSMENT SEPTEMBER 1992 IN RESPONSE TO NRC REQUEST STAFF TINNING & SENSITIVITYTO HUMANPERFORMANCE AND MANAGEMENTFACTORS.
3.
LER 92-035, INADEQUATETESTING OF THE SCRAM DISCHARGE AND VENT DRAINVALVESDISCUSSION 4.
ADDITIONALTOPICS 5.
FEEDBACK
WNP-2 CO&K,CTIVEACTION MANAGEMENTPROGRAM 10CFR50 APPENDIX B ARTICLE 16 CONDITIONS ADVERSE TO QUALITYREQUIRE PROMPT IDENTIFICATIONAND CORRECTION OPERATING QUALITYASSURANCE PROGRAM DESCRIPTION NUCLEAROPERATINGSTANDARD130 "CONTROLOF NON-CONFORMANCES ANDCORRECTIVE ACTIONS" PPM 1.3.12 "PLANT PROBLEMS-PROBLEM EVALUATIONREQUEST (PER)" PROCESS LINKS TO PPM 1.3.15 PPM 1.1.8 "INCIDENTREVIEW BOARD" PPM 1.3.45 "HUMANPERFORMANCE ENHANCEMENTSYSTEM PROGRAM" (VOLUNTARYNEAR MISS &JOB IMPROVEMENT ELEMENT)
J
~
C
SIGNIFICANT CONDITIONS ADVERSE TO QUALITY REQUIRE CORRECTIVE ACTIONTO PRECLUDE REPETITION T
BE DETERMI D
OPERATING QUALITYASSURANCE PROGRAM DESCRIPTION NUCLEAR OPERATING STANDARD¹ 30 PPM 1.3.15 " PLANT PROBLEMS-PLANT PROBLEM REPORTS (NCR,MDR,PDR)"
PPM 1.3.48 "ROOT CAUSE ANALYSIS" PPM 1.3.45 "HUMANPERFORMANCE ENHANCEMENT SYSTEM PROGRAM" (PERFORMANCE SHAPING FACTORS ASPECTS)
GUIDING METHODOLOGY FOR ROOT CAUSE DETERMINATION INPO GOOD PRACTICE OE-907 OF JANUARY 1990 MANAGEMENTOVERSIGHT AND RISK TREE (MORT)
INITIATIVETO IMPROVE LICENSEE EVENTS EVALUATIONPROGRAMS IN REGION V SIGNIFICANTCONDITIONS DEFINITIONAND SENSITIVITY SPECIFIC GUIDANCEON CRITERIADOES NOT EXIST. HIGHJUDGEMENT FACTOR. WNP-2 DEVELOPED CRITERIA ANDADJUSTED BASED ON EXPERIENCE AND NRC FEEDBACK.
LIKE THE JURISPRUDENCE AREA THE THRESHOLD IS PRIMARY INFLUENCED BY PRESIDENT. PERIODIC ADJUSTMENTS ARE NEEDED TO STAY IN LINE
,(
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MEASURES FOR IDENTIFYINGAND DETERMINING CORRECTIVE ACTIONS PER IDENTIFICATION ANYEMPLOYEE PER IS VALIDATEDBY SUPERVISOR, CONDITION ASSESSED BY SHIFT MANAGER FOR IMMEDIATEACTIONS & REPORTABILITY REFERRED TO MANAGEMENTREVIEW COMMITTEE (MRC)
CONTINUALLY SENSITIVE THAT SUBTIER PROGRAMS ELEVATE APPROPRIATE CONDITIONS TO THE PER/PLANT PROBLEM LEVEL
CONDITIONS ADVERSE TO QUALITYCORRECTIVE ACTIONS MRC REVIEWS ADEQUACYOF INITIALCORRECTIVE ACTIONS INCIDENT REVIEW BOARD ORB) INVESTIGATION & RECOMMENDATION OF IMMEDIATECORRECTIVE ACTIONWITH MRC CONCURRENCE STARTED IN MAY 1992
RIINIPICANTUDNDITIQNP AD RRRR TQ QUALITYIDRNTIPIR PY A PRR IU!RULTP IN MRU COMMISSIONING A FORMAL ROOT CAUSE EVALUATION OPERATING EVENTANALYSIS&RESOLUTIONS IS ASSIGNED ALEADROLE INRCA DETERMINATIONS DETERMINE DETAILS OF EVENT, WHAT, HOW, AND WHY OEAR ESTABLISHES ROOT CAUSE(S) FOR THE EVENT DISPOSITIONER PARTICIPATES IN CORRECTIVE ACTION DETERMINATION THE IMPLEMENTING DEPARTMENT MANAGER IS RESPONSIBLE FOR THE ADEQUACYOF THE CORRECTIVE ACTION IMPLEMENTINGDEPARTMENT MANAGERAPPROVES CORRECTIVE ACTION TRC REVIEWS RCA AND RECOMMENDED CORRECTIVE ACTIONS, RESOLVES DISAGREEMENTS ON ROOT CAUSES Ec C/As OR APPEALS ISSUES TO MRC THE PLANT QA MANAGERVERIFIES THE ADEQUACYOF THE DISPOSITION
',
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i f
TRACKING C/As ARE PLACED ON THE PLANTTRACKINGLOG (PTL) WITH SCHEDULES ALLC/As ARE GIVEN A REQUESTED PRIORITY ASSIGNMENT MONTHLYSTATUS REPORTS ARE GENERATED FOR ALLIMPLEMENTINGDEPARTMENTS PLANT MANAGERS MONTHLYSTAFF REVIEWS STATUS AND TARGET SPECIFIC LATE AND HIGH PRIORITY ACTIONS FOR SCHEDULE RESOLUTION
EFFECTIVENESS EVALUATION CORRECTIVE ACTION EFFECTIVENESS AUDITS ARE PERFORMED BY QUALITYASSURANCE OPERATING EXPERIENCE PROGRAM EFFECTIVENESS EVALUATIONS ARE PERFORMED BY CONSULTANTS AND INPO PERIODIC NRC INSPECTIONS PERIODIC BENCHMARKING%ITH OTHER UTILITIES
t(
RECENT EFFECTIVENESS EVALUATIONS
'/90 4/90
'/90 NRC INSPECTION 50-397/89-38 SIGNIFICANTCONDITIONS ADVERSE TO QUALITY CJ BOSTED, RC SORENSEN, PH JOHNSON (MOV LOOSE FASTENERS)
NRC INSPECTION 50-397/90-11, RCA PROGRAM & C/As-FR HUEY, JB MARTIN,AD TOTH (GENERAL RCA & HPES & C/A PROGRAM REVIEW)
EXTERNAL CONSULTANT OPERATING EXPERIENCE PROGRAM EFFECTIVENESS EVALUATION-JL CREWS, DC TIMMINS,RD MADDEN 11/90 NRC INSPECTION 50-397/90-27, WNP-2s ROOT CAUSE ANALYSIS PROGRAM-DL GAMBERONI, WJ WAGNER (GENERAL RCA & C/A PROGRAM REVIEW)
'/91
'/92 3/92 REQUESTED INPO HPES/RCA ASSIST VISIT-DR. GA HUGHES. BENCHMARKEDOUR PROGRAM WITH CALLOWAYS EXTERNAL CONSULTANT OPERATING EXPERIENCE PROGRAM EFFECTIVENESS ASSESSMENT-GD BOUCHEY, J HONECAMP SS CORRECTIVE ACTION AUDIT91-589
f t
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'1
WNP-2 PROBLEM IOENTIFICATIOH AHD RESOLUTIOH PROCESS HISTORY TIMELINE INFORMAL RCA PROCESS FORMAL RCA PROCESS PROCESS IMPROVEMENTS
'1983 -1954 HCR/PDR PROCESS FORMULATED AND IMPLEMENTED PPN 1.3.12 REV ~
198$
1986
'1 987 I
I I
195d ROOT CAUSE PROCEDURE ISSUED PPll 1.3.48 REV ~
1989 PLANT PROBLE}l REPORT PROCEDURES ISSUED PPN 1.3.12 REV 13 PP}I 1.3.1S REV ~
1990 I
1991 I
1992 IHCIDEHT REVIEW BOARD (IRB)
PROCEDURE ISSUED PP}l 1.1.5 REY ~
(FUEL LOAD OEC. 83)
HPES PROGRAM I HIT IATED POST TRIP REVIEW REVISED POST TRIP (APRIL 2d,
'1988)
REVIEW IMPROVED PER/RCA PROCESS DEVELOPS FORMAL RCA TRNG.
BT EGEG IN HOUSE RCA
'TRNO ~
DEVELOPED EYALS DONK TO NON}TON tROORAN EFFECT PERS SETTLED BV OHE GROUP (GEAR)
PP}l 1.3.1S REY 3 ISSUED NOYS/
NODS INCLUDED IN SCOl'E OF DEAR PP}I 1.3.48 REY 3 ISSUED INTERNAL FACTORS LEADIHG To PROCESS CHANGES S
REACTOR SCRAMS FOLLOWING R-2 REACTOR BLDG.
ROOF RUPTURE EVENT LER 88-007 DURINO FOLLONUl'EVI EH E
PRKYIOUS OVKRPRKSSURE TRANSIENTS HKRE IDENTIFIED AS PDRS/NISSED OPPORTUNITIES PP}l 1. 3. 1S REY 4 ISSUED LARGE BACKLOG OF HCRs/PDRs EXTERNAL FACTORS LEADING To PROCESS CHAHGES NRC SSFI TEAN INSPECTION IR 57-19 NRC NONT NTO SS KS ON CLEARANCE AND RKtEAT HUNAN ERRORS NCR BACKLOG ~ S77 HCR BACKLOG 1958
~ 577 1959
~ 193 1990
~ }0<
'1991
~ 117 1992
~ 118 SEVERAL NRC INStKCT REPORTS ON POST TRIP/
RCA PROCESS SKYERAL NRC INSPKCT ~
REPOR'TS DESCRIDE RCA CONCERNS
~
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MAJORPROGRAM IMPROVEMENTSHAVEBEEN MADETO CONTINUOUSLYIMPROVEPROGRAM REVISED PROCEDURES TO STREAMLINEAPPROVAL AND ADMINISTRATIVEPROCESS QUALITYIMPROVEMENTS THROUGH CENTRALIZINGTHE DISPOSITIONER PROVIDED ADVANCEDPROBLEM SOLVING TECHNIQUES TRAINING PROVIDED BASIC RCA TRAINING& INPO HPES TRAININGTO PLANT STAFF
J J
TIMELINESS IMPROVEMENTS BY HAVINGTHE RCA ENGINEER FACILITATE CORRECTIVE ACTION TIMELINESS IMPROVEMENT THOUGH ESTABLISHING A DEDICATED RESOURCE TO FACILITATECORRECTIVE ACTION CLOSURE ESTABLISHED A CORRECTIVE ACTION BACKLOGREDUCTION PLAN
TOTALWNP-2 RO AUSE ANALYSIS Not Submitted for TRC/MRC Approval Note: Begkrnlng 1/1/QZ ACAs /rom NOV/NOOs were added to the scope.
5/28/gg IABswere added to the department work scope.
ta NOV/NOO RCAs a 12 gtgs have been completed. 1hts scope was not considered ln seteng the FYKIgosh.
Cl LLI
0)0 CL Cl
40
O EC
50 or Less RCAs awaiting completion by the start of R-8.
No NCRs > 45 Days or PDRs/MDRs o 60 Days old Except those being managed to a specific closure plan.
Jul-91 Aug.91 Sep-91 Oct.gt Nov-91 Dec-91 Jan-92 Feb-92 Mar-92 Apr.92 May 92 Jun-92 Jul-92 Aug-92 Sep-92 Oct-92 Nov-92 Dec-92 Jan-93 Feb-93 Mar-93 Apr-93 May.93 Jun-93 MONTH-YEAR
~ TOTALNCRS ~ TOTALPDRS ~ TOTALMDRS
~ TOTALRCAS ~ OEA RCAS
CTIVEAC N COMPARISON FY91 vs FY-92 vs FY93 Opened 600 500 400 300 517
................................................385'........373
..
328 268 4 7 200 100
183....1.73.. 197
93
29 211 116 150 194
JUL AUG SEP OCT NOV DEC JAN FEB MAR APR MAY JUN MONTH FY-9l C/A'S OPENED ~FY-92 C/A's OPENED ~F7-'93 C/A's OPENED Attachment 6
't q
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CTIVEACTPN COMPARISOÃ FY-91 vs FY-92 vs FY-93 Closed 600 500 400 300 3 5 272 4 0 309 335 200 100 1 9 JUL AUG SEP OCT NOV DEC JAN FEB MAR APR MAY JUN MONTH
~FY-91 C/A's CLOSED +FY92 C/A's CLOSED ~FY-93 C/A's CLOSED Attachment 7
~il e
OPEN CO CTIVEACTIONS (NCRA's, MDRA's, PDRA's)
400 CORRECTIVE ACTIONS 350 300 250 200 150
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JASOND JFMAMJ JASOND JFMAMJ JASOND J FMAMJ J I
I
I
MONTH
+CORRECTIVE ACTIONS %GOAL FY91 %GOAL FY92 ~GOAL FY93 KSCHED LONG TERM C/As + >I YEAR OLD TOTAL DOES. NOT INCLUDELONG TERM C/As AND C/As AWAITINGADMINISTRATIVECLOSURE Attachment 8
f.
I P
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CTIVEACTIONBKLOG VS. FY-93 GO~S As of October 1, 1992 250 CORRECTIVE ACTIONS 200
'198 150
100
0 554
24 31
- 19 8: 6 5.'6
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- 2018
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~ 4 0:
TECH ENG MAINT OPS TRG PMAN HP BPC PIS QA DIR HS AD ORGANIZATION C/As l5C/A BACKLOG + FY 93 GOAL-
IMPROVED LINEMANAGEMENTACCOUNTABILITYAND INVOLVEMENT ESTABLISHED INCIDENTREVIEW BOARD
l
ESTABLISHING A SITE WIDE PRIORITY SYSTEM ESTABLISHING BACKLOGREDUCTION GOALS INCREASED BENCHMARKINGACTIVITIES
L i"
OPEN PL4 ACTIONS (NCRAS, MDRAS, PDRAS, OERs, LERS, NOVS, PER4S, QFRAS)
800 PLANTACTIONS 700 600 5 5 500 632 613 663 666 653 621
~
640 699 6.
622
~
663 636 IS %
bAdKLOC REIIVCTIOSI
5 5 465 613 694 655 4 5 400 300 200 188 191204105 Ig61851 11 I 100
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23 J
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M A M
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MONTH
~PLANTACTIONS - LTACT+GOALFY92 %)I YEAR OLD - LTACT ~SCHED LONG TERMACT. %GOAL FY93 TOTAL DOES NOT INCLUDELONG TERM Cps AND Cps AWAITINGADMINISTRATIVECLOSURE
))
j
SELF ASSESSMENT SEPTEMBER 1992 INRESPONSE TO NRC REQUEST TO REASSESS EFFECTIVENESS OF RCA AND C/A PROGRAM REVIEW RECENT LERs & RCAs PERTAINING TO MANAGEMENTFACTORS LERs SUMMARIZERCA ANDINCLUDEROOT CAUSES BUTCONTRIBUTINGCAUSES ANDOTHER CONDITIONS ARE NOT ALWAYSDETAILED CONFIRMATIONOF MANAGEMENTFACTORS AND DEVELOPMENT OF CORRECTIVE ACTIONS MAY REQUIRE ADDITIONALANALYSIS; MAY BE DETERMINED IN THE RCA APPROVAL PROCESS AFTER THE LER IS TRANSMITTED. SUPPLEMENTAL LERs ARE PROCESSED INTHESE CASES
O P~
I If 1
STAFF TRAINING&SENSITIVITYTO HUMANPERFORMANCE AND MANAGEMENTFACTORS ALLBUT ONE NEW OEAR STAFF MEMBER HAS RECEIVED INPO HPES TRAINING NOT ALLSTAFF HAVERECEIVED MORT ANALYSISTRAINING. MORT TRAININGIS USUALLY PROVIDED WITHINONE YEAR. REEVALUATINGTHIS TRAININGPOLICY SOME REFRESHER THROUGH ADDITIONALUSE OF MORT (USE IT OR LOSE IT)
IRBs HAVEREALLYHELPED TO GET FACTS AND ADDRESS THE HUMANPERFORMANCE AND IMPLEMENTATIONDEFICIENCIES IN MANAGEMENTPROGRAMS AND PROCESSES TRAINING ON DETERMINING MANAGEMENT PROGRAMS AND PROCESS PROBLEM ROOT-CAUSES IS WARRANTED OVER AND ABOVE MORT FOR OEAR STAFF EVALUATING TRAINING FOR TRC MEMBERS ON PERSONNEL PERFORMANCE AND MANAGEMENTFACTORS ELEMENTS HEIGHTENED SENSITIVITYDURING OEAR MANAGER, IMPLEMENTINGMANAGER, AND TRC APPROVAL OF RCAs
(
r
l
REVIEW OF EVENTS WITH PMT IMPLICATIONS FEW INSTANCES WHERE DEFECTIVE PMT WAS A CONTRIBUTOR THOSE CASES OF DEFECTIVEPMT CORRECTIVE ACTIONS WERE PROPOSED BUT NOT PROCESS ORIENTED 1992 BASIC ROOT CAUSE TREE SPECIFICALLYTARGETS PMT PERIODICALLYREVIEWRCAs FOR MESSAGES INAREAS OF INTEREST; PERFORM ASSESSMENT EVALUATIONS
'
(
f
NRC PRESENTATION LER 92-35 SCRAM DISCHARGE VOLUME VENT AND DRAIN VALVE TIMING NRC CONCERNS Narrative runs both events together Agree; was difficultto understand LER resubmitted with additional detail and clarification Missing certain facts Agree; details provided with the rewrite of the LER.
Root Cause not accurate or insightful CRD-V-181 Inaccurate Post maintenance testing still believed to be the cause.
Neither MWR nor available surveillance tests would have completely satisfied TS OPERABILITY requirements.
Personnel aspects could have been better communicated in LER.
Surveillance test Computer output mislabeled and misleading.
"Closed" really meant "not fully open" Condition existed since the procedure was first written.
Reportability - Tech Spec violation vs. condition which could have prevented a safety function.
V-181 was functional, if slow.
Redundant valve was shown fully operable by testing Safety function may have been delayed but not prevente NRC PRESENTATION LER 92-35 SCRAM DISCHARGE VOLUME VENT AND DRAIN VALVE TIMING Reportable Condition Operation in conditions prohibited by Technical Specifications CRD-V-181 slow Surveillance tests inadequate Causes CRD-V-181 - Inadequate post-maintenance testing Original instructions were inadequate to satisfy Technical Specification requirements Would not have satisfied ASME requirements - used different test method.
Would not have included TS for timing from 504 rod density "after receipt of scram signal" No other testing was scheduled
/ planned during restart.
Believed operable based on altered tests.
Would most likely have noted slow time.
Changed instructions to ASME test; led to false conclusion that valve timing was satisfactory.
ASME test does not satisfy all TS requirements (rod density, scram signal not covered)
Also used "closed" indication.
Test technique being re-evaluated by Tech staff.
Did not include TS verification testing.
Management methods for controlling PMT changes are informal and need re-evaluation.
Contributing caus Tech Spec Surveillance test inadequate Relied on misleading computer point Valve somewhat unique in position indication arrangemen I A
)
'