IR 05000397/1989017
| ML17285A671 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 07/24/1989 |
| From: | Johnson P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17285A669 | List: |
| References | |
| 50-397-89-17, NUDOCS 8908180156 | |
| Download: ML17285A671 (17) | |
Text
Report No:
Docket No:
Licensee:
U.S.
NUCLEAR REGULATORY COMMISSION REGION V
50-397/89-17 PA RA OV QNI Washington Public Power Supply System P. 0.
Box 968 Richland, WA 99352 Facility Name:
Inspection at:
Inspection On:
Inspectors:
Washington Nuclear Project No.
(WNP-2)
WNP-2 Site near Richland, Washington June 4 - July 9, 1989 C. J. Bosted, Senior Resident Inspector R.
C. Sorens n, Resident Inspector Approved by:
o nson, ie React r Projects Section
Summary:
Ins ection on June 4 - Jul 9,
1989 (50-397/89-17
~ zy/i ate igne A~d:
i i
p room operations, licensee action on previous inspection findings, engineered safety feature (ESF) status, surveillance program, maintenance program, licensee event reports (LERs), special inspection topics, procedural adher-ence, and review of periodic reports.
During this inspect. on, Inspection Procedures 30703, 61702, 61705, 61706, 61707, 61726, 62703, 74707, 71710, 71711, 90712, 90713, 92700, 92701, 92702, and 93702 were utilized.
Resul ts:
f'wo violation of NRC requirements were identified:
(1) Ineffective correc-tive action was taken to prevent repeated isolations of shutdown cooling during a surveillance test of excess flow check valves, and (2)
A maintenance technician operated valves and connected test equipment to potentially contaminated systems inside a posted radiological zone without following the requirements of the radiological work permit.
Weaknesses were noted in the above violations in that surveillance procedures were weak and corrective actions did not go beyond the immediate resolution of the problem.
The adherence to radiological work practices by some plant personnel does not appear to meet the expectations of management.
Nine followup i tems and one LER were closed; two new items were opened.
8908180i5b 890731 PDR ADOCK 05000397 G
PNU
DETAILS 1.
Persons Contacted L. Oxsen, Assistant Managing Director for Operations D. Bouchey, Director, Licensing and Assurance
"C. McGilton, Manager, Safety and Assurance C.
Powers, Plant Manager
"J. Baker, Assistant Plant Manager K.
Cowan, Nuclear Safety Assurance Manager C.
Edwards, equality Control Manager R. Graybeal, Health Physics and Chemistry Manager
"J.
Harmon, Maintenance Manager A. Hosier, Licensing Manager D.
Kobus, equality Assurance Manager R. Koenigs, Technical Manager
"S.
McKay, Operations Manager J.
Peters, Administrative Manager W. Shaeffer, Assistant Operations Manager R. Webring, Assistant Maintenance Manager M. Wuestefeld, Assistant Technical Manager The inspectors also interviewed various control room operators, shift supervisors and shift managers, and maintenance, engineering, quality assurance, and management personnel.
"Attended the Exit Meeting on July 7, 1989.
2.
Plant Status At the start of the inspection period, the plant was shut down for its annual refueling outage and in Mode 5.
It entered Mode 4 on June 13.
On the weekend of June 17 and 18, inadvertent ESF actuations occurred three different times while the licensee was conducting excess flow check valve testing (this is discussed further in paragraph 7).
The final restart meeting was held on June 23.
Following completion of the outage on June 25, the reactor was taken critical.
During the startup, however, two intermediate range monitor (IRM) instruments failed to respond to increasing neutron counts; the reactor was shut down and two IRM cable connectors under the reactor vessel were repaired.
On June 26, the reactor was again taken critical and power was raised to the heating range to increase plant pressure to approximately 400 psi.
After an inspection of the drywell at 400 psi the pressure was raised to normal operating pressure.
Following the testing of the safety relief valves, which were worked on during the outage, power was raised to 15K.
The generator was placed on line and power was raised to 25K.
'While performing turbine overspeed trip tests, the reactor tripped when turbine first stage pressure increased during turbine valve swapover concurrent with turbine throttle valve being less than 90K open (this is discussed further in paragraph 10).
The reactor was taken critical again early on June 29.
After raising reactor power to 15K for turbine overspeed trip tests, the reactor was
shut down by manually scramming to determine control rod scram times.
The reactor was restarted on July 1; power was raised to 100K on July 7 and remained there for the balance 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:
Closed Enforcement Item 397/89-04-01:
Failure to Verify HPCS DG Trips were bypassed Trip bypasses circuitry for the high pressure core spray (HPCS)
diesel generator (OG) were required to be checked periodically by the Technical Specifications.
These trip bypasses are used to prevent certain DG trips from functioning during plant emergency conditions.
As the result of an error during the startup testing period for the plant, the licensee had tested only a portion of the circuitry, and this error had become incorporated into the periodic surveillance test procedure.
Once this condition was known, the operability of the DG was not questioned and appropriate action was not taken.
This event also was not reported under the requirements of 10 CFR 50.73 within 30 days of discovery.
The licensee submitted a Technical Specifications change request on December 1,
1988 to make the requirements for the HPCS DG the same as for the other safety related DGs.
As a result, the licensee did not follow up on this issue.
The licensee did perform a test of the ci rcuitry on February 3,
1989 to confirm that it was operating correctly.
Management has undertaken meetings with technical staff personnel, operations and maintenance personnel regarding the proper followup of licensee-identified Technical Specification noncom-pliance.
An LER was submitted on May 19, 1989 (LER 89-08).
The licensee also initiated actions to provide more assistance from the Compliance group in evaluating potentially reportable issues.
License Amendment number 66 was issued on March 30, 1989, changing the requirements of the HPCS DG to those of the other safety related DGs.
This item is closed.
b.
(Closed Enforcement Item 397/89-04-02
- Failure to evaluate HPCS OG operabil>ty per Techn)cal Specsfscat>on 4.0.g'he corrective actions for this item are discussed in item 89-04-01.
This item is closed.
C.
(Closed)
Enforcement Item 397/89-04-03):
Failure to Report HPCS Inoperable per 10CFR 50. 7 The corrective actions for this item are discussed in item 89-04-01.
This item is closed.
d.
Closed)
Enforcement Item 397/88-40-01):
Failure to Sample Charcoal after 720 Hours of Operation.
It was noted that the charcoal filter medium had not been sampled after 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of operation and had been run for over 940 hours0.0109 days <br />0.261 hours <br />0.00155 weeks <br />3.5767e-4 months <br /> before the filter was removed from service and a sample taken.
The licensee has changed plant procedure PPM 7.0.0 "Shift and Daily Instruments Checks" to require that the charcoal be sampled after 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of operation and before reaching 920 hours0.0106 days <br />0.256 hours <br />0.00152 weeks <br />3.5006e-4 months <br /> (125K).
The inspector reviewed revision 17 of this procedure, issued on February 13, 1989 which included this change.
This item is closed.
e.
(Closed)
Followu Item (397/87-19-10):
Proceduralized Safeguards Lacking in Maintenance Program.
Scheduled maintenance for safety related equipment was being deferred without controls on who or why this was done.
No proce-dural controls or programs were found defining who could authorize deferral of scheduled preventive maintenance.
The maintenance manager issued a notice to the maintenance depart-ment that stopped all deferrals of safety related maintenance.
In discussions with the maintenance manager, the inspector was told that the only way that maintenance could be deferred was to obtain his permi'ssion, and that he had not granted any deferrals since January 1988.
He stated that controls on deferral of maintenance would be proceduralized in an upcoming procedure revision.
Based on this conversation, this item is closed.
f.
Closed Followu Item (397/87-19-25):
No Procedure Covering Seismic Control of Lifting Equipment Storage of overhead-lifting devices in the standby service water pumphouses was found not to be controlled.
This was expanded to other safety related areas with similar findings.
The licensee modified plant procedures 3. 1.4,
"Minimum Startup Checksheets,"
and 10.2.53,
"Seismic Requirements for Scaffolding, Ladders, Tool Gang Boxes, and Metal Storage Boxes," to include a
section for overhead-lifting device storage.
The inspector reviewed both of these procedures and witnessed the check of these devices for the last startup.
This item is closed.
g.
Closed)
Followu Item 397/87-30-03):
Assess Acceptability of MMS.
On November 18, 1987, the quality assurance department issued a stop work order to the plant staff based on discrepancies found in the Materials Management System (MMS).
The order was issued as a
precaution following an audit of the spare parts used for safety related equipment.
After an overhaul of the MMS and the methods of supplying safety related spare parts was accomplished,.the stop work order was lifted on May 1, 1989.
The gA department was satisfied with the efforts to correct the deficiencies found.
Since the lifting of the stop work order, several problem evaluation requests have been submitted for identified problems, indicating a self-critical attitude by the spare parts organization.
This item is closed.
h.
Closed)
Followu Item (397/88-14-01):
Clearance Order Improvements.
After several near-misses involving inadequate electrical clear-ances, the plant manager stopped all electrical work until a review commi4ee could be formed-to review the clearance order tagging process on electrica~Mems.
Interoffice memoranda were issued by plant management on May 17 and 27, 1988, and several plant procedures were revised.
The inspector reviewed PPM 1.3.8,
"Equipment Clearance and Tagging," revision ll, issued March 10, 1989.
This incorporated INPO Good Practice OP-203,
"Tagging Procedures for the Protecting of Personnel, Components, and-Systems".
The procedure established a "Work Control Center Group" that. produces all electrical tagging in the plant.
These efforts are considered adequate to address this issue; this item is closed.
i.
(Closed)
Unresolved Item (397/87-19-14):
Evaluation of Combined Effects of Setpoint Methodology with Off-Normal and Seismic Conditions.
Setpoints for safety related instrumentation were found to contain a
tolerance band for inaccuracies which did not include environmental or seismic effects.
Since this issue was raised, the licensee has initiated a progi am to evaluate the setpoint methodology, based on accepted national standards, to include off-normal plant conditions and seismic events.
This program is in the final stages of development and will be issued shortly after the end of the reporting period.
Licensee management has committed to write a letter to Region V by July 31, 1989 to address their program and the milestones that they expect.
Based on this commitment, this item is closed.
The licensee was not ready to close the following previously identified items:
88-40-02 Timely Action Not Taken For Delinquent Surveillance on Degraded Voltage Protection 87-19-11 Nitrogen Tank Potential Threat to Diesel Generators
4.
0 erational Safet Verification (71707 a.
Pl ant 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 Mater Buildings Technical Support Center Turbine Generator Building Yard Area and Perimeter b.
The following items were observed during the tours:
0 eratin Lo s and Records.
Records were reviewed against Technical Speclf>cat)on and administrative control procedure requirements.
(3)
(4)
Monitorin Instrumentation.
Process instruments were observed for correlation between channels and for conformance with Technical Specification requirements.
~Si<<N i
.C
d hfdf ig conformance with 10 CFR 50.54.(k),
Technical Specifications, and administrative procedures.
The attentiveness of the operators was observed in the execution of their duties and the control room was observed to be free of distractions such as non-work related radios and reading materials.
E ui ment Lineu s.
Valves and electrical breakers were verified 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 Specifications limiting conditions for operation were verified by direct observation.
(5)
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.
General Plant E ui ment Conditions.
Plant equipment was observed for indications of system leakage, improper lubri-cation, or other conditions that would prevent the system from fulfilling its functional requirements.
Annunciators were observed to ascertain their status and operabilit (7)
Fire Protection.
Fire fighting equipment and controls were observed for conformance with Technical Specifications and administrative procedures.
(8)
Plant Chemistr
.
Chemical analyses and trend results were reviewed for conformance with Technical Specifications and adminisuat,ive control procedures.
(9)
Radiation Protection Controls.
The inspectors periodically o served ra lo ogsca protection practices to dI.termine 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 Exposure Permits, proper wearing of protective equipment and personnel monitoring devices, and personnel frisking practices.
During a tour on July 4, the inspector observed an instrumentation technician improper ly performing work inside a posted contaminated area.
See paragraph 9 for additional information.
Radiation monitoring equipment was frequently monitored to verify op i ability and adherence to calibration frequency.
(10) Plant Housekee in
. Plant conditions and material/equipment storage were observed to determine the general state of cleanliness and housekeeping.
Housekeeping in the radio-logically controlled area was evaluated with respect to controlling the spread of surface and airborne contamination.
(11) ~Securit
.
The inspectors periodically observed security practices to ascertain that the licensee's implementation of the security plans was in accordance with site procedures, that the search equipment at the access control points was operational, 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.
One violation associated with this area is discussed further in paragraph 9.
5.
En ineered Safet Feature S stem Walkdown 71707 71710 Selected engineered safety feature systems (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.
The inspectors also verified that the system valves were in the required position and locked as appropriate.
The local and remote position indication and controls were also confirmed to be in the required position and operabl 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 Meat Removal (RHR), Trains
"A" and "B" Dates June
June
June 23, 28,
June 23,
June 23,
June
June
Scram Discharge Volume System Standby Liquid Control (SLC) System 125V DC Electrical Dis'tribution, Divisions 1 and
June
June
June
250V DC Electrical Distribution No violations or deviations were identified.
June
6.
Sur veil 1 ance Testin (61726)
a ~
Surveillance tests required to be performed by the Technical Speci-ications (TS) were reviewed on a sampling basis to verify that:
1)
the surveillance tests were correctly included on the facility schedule; 2)
a technically adequate procedure existed for performnce of the surveillance tests; 3) the surveillance tests had been performed at the frequency specified in the TS; and 4) test results satisfied acceptance criteria or were properly dispositioned.
b.
Portions of the following surveillance tests were observed by the inspectors on the dates shown:
Procedure Descri tion Dates Performed 7. 4. 8. 2. l. 13 18-Nonth Battery Testing 7.4.3. 1. 1.61 Scram Discharge Volume Level Transmitter CFT June
June
7.4.3.3. 1.58 High Pressure Core Spray System July 4 Transfer on Low CST Level 7.4.3.3. 1.22B Main Steam Line High Flow 7.4.11.2.1.2.1 Drywel 1 Sample No violations or deviations were identified.
7.
Excess Flow Check Valve (EFC Testin 93702 July 4 July 4
.While conducting periodic EFC valve surveillance testing on the weekend
- of June 17 and 18, three different inadvertent engineered safety feature (ESF) actuations occurred.
EFC valves are required to be tested each
months by the Technical Specifications and are required to check flow against a 10-15 psi differential pressure, depending on the application.
PPM 7. 4. 6. 3. 4. 1 implements this surveillance requirement, which is per-formed by I8C personnel.
Plant conditions were established by raisi ng reactor pressure vesses (RPV) level to approximately 300", compressing the trapped air in the top of the RPV.
This caused pressure in the RPV to increase to approximately 100 psi where it was controlled in a pre-selected pressure band to provide the necessary differential pressure to cause EFC valve operation.
A pressure band was maintained by running a
control rod drive (CRD) pump continuously at reduced flow, which slowly increased pressure, and by venting pressure periodically through valves
'n an RHR heat exchanger.
Controlling pressure in this manner allowed sufficient RPV pressure to ensure the EFC valves would operate against the required differential pressure when they were tested.
The test was conducted by isolating all instruments affected by an EFC valve to preclude damage to the instruments or inadvertent ESF actua-tions.
A downstream drain valve'was then opened to allow sufficient flow for the EFC valve to seat.
The first ESF actuation occurred on June 17, when the selected control pressure band was too high.
The test procedure did not provide instructions to control system pressure nor did it reference the channel functional test (CFT) for the high pressure trip setpoint.
The nominal setpoint for isolating shutdown cooling (SDC) on high RPV pressure was known to be less than or equal to 135 psi.
The shift manager selected a
pressure band of approximately 100 to 125 psi; however, the setpoint'for SDC isolation had been set conservatively at 122 psi.
When RPV pressure reached this setpoint, an inadvertent ESF occurred which isolatedSDC.
The second ESF actuation occurred when an I8C technician performing valve manipulation for the EFC testing opened the wrong valve.
The procedure was found to not specify valve numbers, nor provide clear instructions to I8C personnel performing the test as to which valves were to be manipulated for each detector tested.
This caused a level indicating switch to sense low RPV level, which resulted in a half scram condition.
It also caused a pressure pulse which affected the sensing lines of other RPV level detectors, resulting in a Level 2 actuation of the high pressure core spray (HPCS)
emergency diesel generator and opening of the
HPCS injection valve.
The HPCS pump would have started also, presenting a significant potential for low temperature overpressure of the RPV, but the circuit breaker control power fuses are normally removed in cold shutdown to preclude this type of accident.
The third ESF actuation occurred when the control room operators were unaware that the instrument being used to monitor and control plant pressure was isolated as part of the test.
The test procedure di.d not specify which instruments would be affected by isolating each detector.
The instrument indicated a constant value for an abnormally long period of time, and system pressure slowly increased but was not observed on other instruments.
Another high pressure SDC isolation occurred when pressure increased to 122 psi.
In addition to the inadequate test procedure, this event demonstrated operator inattention and poor communications between operators and I8C personnel.
Plant management halted EFC testing after the third actuation, and dis-patched members of operations and maintenance management to establish more effective control of the testing.
The events depicted above indi-cated a weakness in the degree of control and direction provided by plant management over required surveillance testing.
Corrective actions taken after the first shutdown cooling isolation also were not adequate to preclude recurrence.
The licensee's failure to take sufficient corrective action to prevent SDC isolations twice on high pressure actuation during conduct of the same procedure is considered a violation of 10 CFR 50, Appendix B, Criterion XVI (Corrective Action) (Enforcement Item 397/89-17-01)
.
8.
Plant Maintenance (62703)
During the inspection period, the inspectors observed and reviewed documentation associated with maintenance and problem investigation activities to verify compliance with regulatory requirements and with administrative and maintenance procedures, required gA/gC involvement,'roper use of safety tags, proper equipment alignment and use of jumpers, personnel qualifications, and proper retesting.
The inspectors verified that reportabi lity for these activities was correct.
The inspectors witnessed portions of the following maintenance activities:
Descri tion Dates Performed Replace inverter IN-1 per AT 8733 Correct DIV 1 DG overheating per AV 1998 June
June
No violations or deviations were identifie.
Work Inside a Posted Radiolo ical Area (71707)
During a tour of the Reactor Building on July 4, the inspector observed an instrumentation and control (I8C) technician performing a channel functional test (CFT) on the "B" main steam line"high flow detector in instrument rack H22-P022 on the 471 foot elevation of the building.
The CFT is performed on the detectors, located in a steel frame enclosure that had been surveyed and posted as a contaminated area by the health physics (HP) department.
A standard HP barrier with a sign had been placed across the front of the enclosure.
The inspector observed this 'test periodically over an approximate 45-minute time period.
During two of the three, times the inspector was in the area observing the CFT, the performance, of the technician was satisfactory.
The third time the inspector passed through the area, he observed tlat'technician operating valves inside the contamination barrier with bare hands.
The inspPP:~ walked over to the technician to see if the pasted.HP conditions had changed and observed that the HP barrier and sign were st) 11 in place.
The technician proceeded to complete work on that detector, when another technician came on the scene and had the first technician sign off a step in the procedure that denoted the completion of that phase of the test.
The first technician then proceeded, bare handed, to start connection of his test equipment to another detector, inside the HP barrier, to continue with the rest of the test procedure.
The inspector immediately proceeded to inform the Shift Manager, who had the test stopped and dispatched an HP technician to the test location.
The HP did not find contamination on the technician or his equipment, and instructed the I8C technician on proper HP practices.
The HP technician monitored the remainder of.the CFT.
L'icensee management started an investigation on July 5 into the reasons for this breakdown in HP practices.
Plant management also took steps to identify potential attitude concerns when these findings were raised by the inspector.
A six-month trend of radiological occurrence reports (RORs) were discussed with the inspector on July 6.
Management stated that at that time they did not think that a "cultural attitude" problem existed.
The inspector's review of the
RORs for the first six months of the year indicated that three of the 33 were caused by people reaching across an HP contamination barrier and another by working inside a
contamination barrier without following the requirements of the radiation work permit (this was considered a fourth case).
Coupled with the inspector's observation, these make five examples out of 34 which indicate to the inspector that some individuals working in the plant are not demonstrating a correct attitude towards radiation protection.
The radiation work permit (2-89-007)
under which these technicians were working required that rubber gloves be worn when working on or opening potentially contaminated systems inside the barrier.
The fai lure to follow the RWP is considered a violation of plant procedures and of Technical Specification 6.8. 1 (Enforcement Item 397/89-17-02)..
10.
Plant Startu Fol 1 owin Refuel in (71711)
Following completion of the refueling outage on June 25, the reactor was taken critical.
Two intermediate range (IRM) instruments subsequently failed to respond to increasing neutron counts; the reactor was shut down, and two IRM cable connectors were repaired.
On June 26, the reactor was again taken critical and power was raised to the heating range to increase plant pressure to approximately 400 psi.
After an
,
inspection of the drywell at 400 psi the pressure was raised to normal.'perating pressure.
Following testing of the safety relief valves, which were worked on during the outage, power was raised to 15K.
The generato'r was placed on line and power was raised to 25K.
While performing turbine overspeed trip tests, however, the reactor tripped when turbine first stage pressure increased during turbine valve swapover, concurrent with turbine throttle valves less than 90K open.
This event was another indication of a poor surveillance procedure, in that (1) the steps documenting an infrequent surveillance test were included in a lengthy startup procedure, and (2) the procedure was not sufficiently explicit on how the test should be conducted or controlled.
Another startup was initiated on June 28, with the reactor achieving criticality early on June 29.
After raising reactor power to 15K for turbine overspeed tr'ip tests, the reactor was shut down by manual scram to determine control rod scram times.
The reactor was restarted on July 1 and power was raised to 100K on July 7.
During the times that the reactor was taken critical and during the turbine overspeed tests, the inspector was observing control room activities.
The inspector observed the use of the check sheets and procedures by the operator.
Operations and corporate management as well as Nuclear Safety Assurance Group (NSAG) and gA personnel were in the control room observing these critical evolutions.
The inspector walked down the plant prior to plant startup and performed the normal safety system verification.
Systems verified included the low pressure injec-tion mode of the residual heat removal system, high and low pressure core spray, control rod drive hydraulics, and the reactor protection system.
The inspector also toured the drywell with the Assistant Plant Manager just prior to plant startup to assess housekeeping and general readiness for startup.
The drywe11 was considered by the inspector to be cleaner than he had ever seen it before.
No violations or deviations were identified ll.
Core Power Distribution Incore Detector Calibration and Core Thermal Power Evaluation 61702 61705 61706 During the power escalation following the initial plant trips for scram response testing, the inspector had several opportunities to review the core power distributions were calculated using the plant computer.
These were all determined to be satisfactory.
The final core power distribution will be performed after the plant reaches 100K power and stabilizes.
During the power increase the computer is relying on calibration values for the local power range monitors (LPRM) obtained at
'
lower power levels.
The inspector concluded that enough thermal margins existed with the monitored conditions that no concerns exist.
The incore detector calibration, core power distribution, and thermal power evaluation will be reviewed further after equilibrium full power conditions are established.
No violations or deviations were identified.
12.
Followu on Socket Weld Failures 92702 The inspector reviewed the licensee's actions taken to correct a socket weld failure that occurred on a HPCS drain line during a surveillance test (see inspection report 89-13).
The fai lure was vibration induced, coupled with a design weakness which made the weld susceptible to vibration induced fatigue failure.
The vibration was a result of throttling HPCS flow through the test loop to meet the required pump flow and differential pressure conditions for the survei'llance test.
Action was taken by the licensee to, repair the failed socket weld by redesigning the vent and drain lines to reduce the moment arm and by providing butt welds vice socket welds for increased strength.
The lice"csee reviewed the characteristics of every other -vent and drain connection in the HPCS system.
Each was reviewed for its vibration potential and its configuration susceptibility to fatigue failure.
Any combination of these that made the connection a candidate for failure was inspected by magnetic particle and liquid penetrant examination.
Nine were inspected in this way.
Due to the nature of socket welds, these are the only types of nondestructive examination (NDE) that would provide meaningful results.
This was also accomplished for an additional 20 to 25 vent and drain connections in the reactor core isolation cooling (RCIC) and reactor recirculation control (RRC) systems where significant vibration is known to have occurred.
No indications were identified from either of these two NDE methods; however, these two particular tynes of NDE methods are only effective for indicating flaws at or near the surface of the weld and will not reveal flaws in the interior.
Other problems of this nature have been identified by the" licensee wherein flow induced vibration, often from improper application of valve design, led to socket weld fai lures.
For instance, in the RHR system, steps were taken to administratively control flow by Qhrottling with valves that will minimize flow induced vibrations.
I(~addition, valves are being replaced, one or two at a time during each refueling outage, with valves correctly designed for throttling applications.
However, HPCS-V-23, which is used during the above mentioned surveillance testing to achieve the required flow rates and differential pressures, had not been investigated as to its design characteristics and proper application for its service requirements.
Since it is likely that HPCS-V-23 could be the cause of the vibration problem in the HPCS system, and that reducing the vibration problem wi 11 ultimately reduce the likelihood of fatigue failure of socket welded joints, this appeared to merit further study by the licensee.
However, no course of action for HPCS-V-23 had been proposed by the licensee, indicating a reluctance to determine the root cause of and eliminate the vibration problem.
.This was communicated to plant management, who acknowledged the inspector's comments.
The
Assistant Plant Manager committed to assess the vibration problem in the HPCS system and correct it by the end of the 1990 refueling outage.
13.
Review of Shutdown Mar in Determination 61707)
The inspector reviewed the licensee's initial shutdown margin determi-nation after refueling.
It was performed just after initial criticality was achieved on the morning of June 25.
The highest worth control rod was analytically determined by the fuel vendor; therefore, the Technical Specification required shutdown margin is 0.38K delta K.
PPM 7.4. l. 1 was the licensee's implementing procedure for this surveillance. 'he inspector reviewed the completed procedure, and verified certain assump-tions made in the calculation by'reviewing fuel vendor submittals.
The inspector independently calculated the shutdown margin based on the licensee's data and arrived at a value of 2.237K delta K.
This was the same value that the licensee determined and was well within the requirement.
No violations or deviations were identified.
14.
Licensee Event Re ort LER Followu 90712 92700)
The following LERs associated with operating events were reviewed by the inspectors.
Based on the information provided in the reports it was concluded that reporting requirements had been met, root causes had been identified, and corrective actions were appropriate.
The below LERs are closed.
LER NUMBER LER 89-02-00 DESCRIPTION Reactor Scram Due to Shorted Main Transformer Line Insulator.
No violations or deviations were identified.
15.
Review of Periodic and S ecial Re orts 90713 Periodic and special reports submitted by the licensee pursuant to Technical Specifications 6.9. 1 and 6.9.2 were reviewed by the inspector.
This review included the following considerations:
the report contained the information required to be reported by NRC requirements; test results and/or supporting information were consistent with design predictions and performance specifications; and the reported information was valid.
Within the scope of the above, the following reports were reviewed by the inspectors.
Monthly Operating Report for May 1989.
No violations or deviations were identifie.
Exit Meetin (30703)
The inspectors met with licensee management representatives periodically during the report period to discuss inspe'ction status, and an exit meeting was conducted with the indicated personnel (refer to paragraph 1)
on July 7, 1989.
The scope of the inspection and the inspector's findings, as noted in this report, were discussed and acknowledged by the licensee representatives.
The licensee did not identify as proprietary any of the information reviewed by or discussed with the inspector during the inspection.
The licensee management committed to provide NRC Region V with a letter by July 31, 1989 that addresses their program and milestones for setpoint methodology including off normal conditions and seismic events.
Management also committed to assess and correct the vibration problem in the high pressure core spray (HPCS)
system by the end of the 1990 refuel-ing outage.