IR 05000528/1992022
| ML17306A946 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 08/19/1992 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17306A944 | List: |
| References | |
| 50-528-92-22, 50-529-92-22, 50-530-92-22, NUDOCS 9209080055 | |
| Download: ML17306A946 (55) | |
Text
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~ice see 50-528/92-22, 50-529/92-22, and 50-530/92-22 50-528, 50-529, and 50-530 NPF-41, NPF-51, and NPF-74 Arizona Public Service Company P. 0.
Box 53999, Station 9012 Phoenix, AZ 85072-3999
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Ins ection Conducted Hay 31 through July 18, 1992 ns ectors D. Coe, F. Ringwald, J. Sloan, L. Tran, Senior Resident Inspector Resident Inspector Resident Inspector Resident Inspector (Rotational Assignment)
roved B
ong, e
Reactor Projects Sec ion II a e gne Ins ection Summar
Ins ection on Ma 31 throu h Jul
992 Re ort Numbers 50-528 92-22 50-529 92-22 and 50-530 92-
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d t N tilt t g ti ty tt four resident inspectors.
Areas inspected included:
review of plant activities engineered safety feature system walkdowns - Unit
surveillance testing - Units 2 and
plant maintenance Units 1, 2, and 3 thread engagement Unit
temporary instruction 2515/113, review of reliable decay heat removal during outage - Unit
annunciator jumpers Units 1 and
reactor trip breaker (RTB) undervoltage trip assembly (UVTA) issues-Units 2 and 3 reactor trip breaker (RTB) troubleshooting activities Units 1, 2, and
radiation monitor RU-146 inoperable without Operations awareness Unit 3 920908 OCK o5o 52El oo55 9>o82o POR
{EDG) start failure - Unit 3 molded case circuit breaker procedure inadequacy - Units 1, 2, and
13.8 KV fault/startup transformer outage - Units 1, 2, and 3 procedure deficiency concern - reactor coolant system (RCS)
depressurization - Units I, 2, and
meeting with APS managers on July 2, 1992 followup on previously identified items - Units 1, 2, and 3 review of licensee event reports - Units 1, 2, and 3 During this inspection the following inspection procedures were utilized:
30702, 40500, 61726, 62703, 71707, 71710, 90712, 92700, 92701, and 93702.
J~eQts:
Of the 17 areas inspected, one violation was iden'tified regarding improper preventive maintenance administration, and one violation was identified regarding the adequacy of a control room procedure for mitigating a stuck open spray valve.
e e C
c usions and S ec d
s:
S n
a t Sa et Matte s:
None ol tos.
I - Units 1, 2, and 3 1 - Unit
ev tos None te s
Three new items were opened, 20 items were closed, and two items were left open.
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N Meaknesses oted:
Initial efforts in evaluating continued Gf reactor trip breaker failures to close appeared not to be thorough and complete.
It was only after discussions with NRC personnel that the breaker's procurement and design change'istory were evaluated in detail by APS personnel.
The licensee failed to incorporate adequate guidance in their procedure to respond to an RCS pressure control system malfunction, resulting in multiple strategies being employed for a stuck open pressurizer spray valve during operator licensing exam The below listed technical and supervisory personnel were among those contacted:
o a
ubl'c Se v ce Co n
PS
- R. Adney, T. Bradish,
- R. Flood, R.
Fountain, S. Guthrie,
- W. Ide, A. Johnson,
~J. Levine, D. Mauldin, G. Overbeck,
- R. Rouse, T. Shriver, R. Stevens, Site Re resentat ves Plant Manager, Unit 3 Manager, Licensing and Compliance PJant Manager, Unit 2 Supervisor/Acting Manager, guality Audits
Monitoring Site Director, guality Assurance/guality.Control
{gA/gC)
Plant Manager, Unit I Supervisor, Compliance
'ice President, Nuclear Power Production Director, Site Maintenance 8 Modifications Site Director, Technical Support Supervisor, Station Operating Events Department Assistant Plant Manager, Unit 2 Director, Nuclear Licensing and Compliance
+D. Draper,
+H. Benac, R. Henry, Site Representative, Southern California Edison Manager, El Paso Electric Site Representative, Salt River Project The inspectors also talked with other licensee and contractor personnel during the course of the inspection.
- Denotes personnel in attendance at the Exit meeting held with the NRC resident inspectors on July 20, 1992.
The inspectors were briefed on reorganizations in the Site Technical Support, Engineering and Maintenance Oepa'rtments.
No questions or concerns were identified.
2.
eview of P ant ctivities Units and
40500 1707 and 93702 a.
~S'te On Dune 26, 1992, a brush fire spread under a two mile portion of the North Gila electrical transmission line.
The fire was also within one mile of the Kyrene line.
These are two of the five lines which provide offsite power to the units.
The licensee responded to the fire and established contingency plans in the event the fire presented an additional threat to the units.
The inspector reviewed the licensee's actions and contingency plans and concluded that they appeared appropriat On June 28, 1992, three earthquakes occurred with epicenters in Southern California.
Palo Verde Nuclear Generating Station (PVNGS) measured ground acceleration up to 0.014g.
The licensee determined that this was below the threshold required to activate their emergency plan.
Inspections were conducted, and the licensee concluded that the earthquakes had no affect. on plant systems.
The inspector reviewed the licensee's actions and concluded that they appeared appropriate.
b.
c ~
MtM Unit 1 achieved full power on June 1,
1992 following its third refueling outage and remained at essentially 100 percent power throughout the remaining inspection report period.
~Ut 2 Unit 2 remained at essentially 100 percent power throughout the inspection report period.
d.
~Ut 3 Unit 3 remained at essentially 100 percent power throughout the inspection report period with the exception of a reactor cutback due to a trip of "B" main feed pump on June 3, 1992.
The licensee did not determine the exact cause of the trip and, following testing, restored the pump to service.
Unit 3 reached full power on June 6, 1992.
This is the fourth reactor cutback due to a trip of the "B" main feed pimp since September. 8, 1990.
Troubleshooting recorders, which had been monitoring the pump, were removed a few weeks before this event and were reinstalled with additional monitoring points following this event.
~Pt t The following plant areas at Units 1, 2, and 3 were toured by the inspector during the inspection:
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Auxiliary Building Control Complex Building Diesel Generator Building Fuel Building Hain Steam Support Structure Radwaste Building Technical Support Center Turbine Building Yard Area and Perimeter
The (4)
(5)
(10)
(11)
following areas were observed during the tours:
erat o
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d Records were reviewed against technical specifications and administrative control procedure requirements.
o itor st u
e t t o - 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 Part 50.54. (k),,technical specifications, and administrative procedures.
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verified to be in the position or condition required by technical specifications and administrative procedures for the applicable plant mod g I d t 'P
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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 Cond tions Plant equipment. was observed for indications of system leakage, improper lubrication, or other conditions that could prevent the systems from fulfillingtheir functional requirements.
atilt PI flghtt p t lp t
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I observed for conformance with technical specifications and administrative procedures.
Lilt Ch I t
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d f conformance with technical specifications and administrative control procedures.
~Securit
- Activities observed for conformance with regulatory requirements, implementation of the site security plan, and administrative procedures included vehicle and personnel access, and protected and vital area integrity.
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storage were observed to determine the general state of cleanliness and housekeeping.
Radiation Protection Contro s Areas observed included control point operation, records of licensee's surveys within the radiological controlled areas, posting of radiation and high radiation areas, compliance with radiation exposure permits, personnel monitoring devices being properly worn, and personnel frisking practice l
2122 ~ttt t ttl2 t d
1
1 tt briefings were observed for effectiveness and thoroughness.
No violations of NRC requirements or deviations were identified.
n ee ed Safet eature SF S ste alkdowns - Unit
An engineered safety feature system was walked down by the inspector to confirm that the system was aligned in accordance with plant procedures.
During this inspection period the inspectors walked down accessible portions of the following system.
o High Pressure Safety Injection (HPSI)
No violations of NRC requirements or deviations were identified.
Su ve lance est n
Units 2 and
6 726 Selected surveillance tests requi,red to be performed by the technical specifications (TS) were reviewed on a sampling basis to verify that:.1)
surveillance tests were correctly included on the facility schedule; 2)
technically adequate procedures existed for performance of the surveillance tests; 3) surveillance tests had been performed at the frequency specified in the TS; and 4) test results satisfied acceptance criteria or were properly dispositioned.
Specifically, portions of the following surveillances were observed by the inspector during this inspection period:
Urrj~t
~rocedure esc tio 36ST-9SB02 PPS Bistable Trip Units Functional Test 36ST-2SB16 CPC Input Loop Calibration for Channel
"A" PVNGS Unit 2 gg3t 3 tt d
2~Ii t 32ST-9ZZ34 Battery Charger Surveillance Test
"D" PK Charger (H14)
No violations of NRC requirements or deviations were identified.
ant Maintenance Units
2 and
62703 During the inspection period, the inspector observed and reviewed selected documentation associated with the maintenance and problem investigation activities listed below to verify compliance with regulatory requirements, compliance with administrative and maintenance procedures, required quality assurance/quality control department
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involvement, proper use of safety tags, proper equipment alignment and use of jumpers, personnel qualifications, and proper retesting.
The inspector verified that reportability for these activities was correct.
The inspector witnessed portions of the following maintenance activities:
o ADV-178 Reassembly (31HT-9SG04)
o SIB-HV-609 Stud Replacement o
Hegger Cable, and Work on Cable Splice between AE-NAN-X01, Unit 2E-NAN-S05 and 3E-NAN-S06 o
Replace Limit Switch on SGA-UV-134A o
Troubleshoot
"A" Reactor Trip Breaker o
Troubleshoot
"B" Reactor Trip Breaker o
Install Seismic EPLAN Storage Cabinet
~Unit o
Replace DGB-V-670 o
Sample and Change Oil EDG "B" Outboard Generator Bearing o
Calibrate EDG "B" Lube Oil Pressure Switch PSL-008 o
Inspect EDG "B" Generator Brushes o
Troubleshoot
"B" Reactor Trip Breaker o
Calibrate ASN-PSH-332G "B" Pipe Way Pressure o
Post Haintenance EDG "A" Run On July 10, 1992, the inspector observed a portion of the change-out of the Foxboro Auto/Hanual controller for Steam Bypass Control Valve 1001 in Unit 3 under work order 541696.
The inspector noted that the technicians had difficulty installing the new controller because a stop plate made the controller larger than the hole in the mounting bracket.
After discussion, the technicians removed the stop plate and installed the controller.
Before placing the instrument back in service, the technicians discussed the difficulty with Instrumentation and Controls (IKC) supervision.
The personnel concluded that the installation was correct because Foxboro Service Instruction (SI) 1-02212 directed that
I
the plate should be removed and discarded.
The inspector noted that the work order did not contain instructions regarding removal of the plate, reference to the Foxboro SI, or comments on the work continuation sheets
'ocumenting the installation difficulty.
The technical manual referenced in the work order did not contain Foxboro SI 1-02212.
The inspector discussed these observations with the IKC supervisor, and the supervisor concluded that the work order was inadequate, the technical manual did not contain a necessary document, and the technicians should have documented the installation difficulty in the work order.
The inspector agreed with the ISC supervisor's conclusion.
The IEC supervisor initiated a
CRDR to investigate these issues and issued a Newsflash to the Mork Control and ISC departments in all units.
No violations of NRC requirements or deviations were identified.
ead n'
erne t - Un t
0 During a walkdown, the inspector identified that the Unit 1 "B" train HPSI Long Term Cooling Iso'lation Valve, I-J-SIB-HV-609 had inadequate thread engagement on the nuts and studs connecting the motor operator to the yoke assembly.
The inspector found that all four studs were approximately 50 percent recessed into the nut.
The licensee initiated Material Nonconformance Report
{NNCR) 92-SI-1089 to address this condition.
The studs were replaced with longer studs in accordance with the disposition of the HNCR.
The inspector noted that the replacement of the studs was timely.
A review of work order 531504 indicated that the motor operator mounting bolts and studs.had been previously replaced in an attempt to meet the requirements of design change notice 18 to drawing 13-J-ZZS-220.
Although the stud length was specified in the drawing, note 5 stated that the stud length may be longer than required to provide full tap engagement and that good judgement should be used to ensure that the stud is bottomed and the nut is fully engaged.
Subsequent to the stud replacement, the licensee performed a calculation, OI-HC-SI-324, and concluded that reduced thread engagement was sufficient to hold the operator to the yoke during a Safe Shutdown Earthquake (SSE)
event.
The inspector noted that the work order appeared to contain sufficient detail and concluded that maintenance personnel failed to reinstall the studs and nuts as instructed by drawing 13-J-ZZS-220 during the performance of work order 531504.
The licensee initiated CROR 9-2-0364 to identify the root causes and develop corrective actions to prevent future thread engagement deficiencies.
This is another example of inadequate thread engagement identified in the Notice of Violation in Inspection Report 50-528/529/530/92-17.
After the
7.
exit meeting, licensee. management agreed to incorporate this issue in their response to that Notice of Violation.
e ie of e
ab e eca eat mo a urin Outa e - nit Tem o a
nst o
5
The inspector reviewed the licensee activities for the Unit 1 refueling outage that had the potential to significantly contribute to a loss of decay heat removal capability from the reactor.
The inspector reviewed the Unit 1 Third Refueling Outage Shutdown Risk Assessment.
In the assessment, the licensee evaluated the Unit
refueling outage schedule to determine if the plant conditions established for the various outage phases, and the corresponding equipment outages, would maintain an adequate margin of safety and compliance with plant technical specifications.
The assessment focused on electrical distribution, reactivity control, reactor coolant inventory control, decay heat removal, and containment integrity.
Several recommendations were made as a result of the assessment, and all of the recommendations were, incorporated into the outage schedule.
The inspector noted that the licensee had procedures to control components to ensure the continued'removal of decay heat from the reactor.
For example, procedure 410P-1ZZ10,
"Hot Standby to Cold Shutdown Node 3 to Node 5," and procedure 410P-1ZZ12,
"Node 6 Operations,"
discussed the precautions and limitations designed to minimize the potential for a loss of reactor cooling.
The inspector noted that the licensee evaluated work to be performed during the outage and prepared an equipment outage plan that was used to minimize the potential for a loss of decay heat removal.
This, evaluation included a review of electrical equipment that would be available during
'arious periods in the outage.
The inspector noted that one offsite power source and one onsite power source remained available throughout the outage.
The licensee stated that nonstandard electrical line-ups had been analyzed to ensure that sufficient load carrying capacity and protective circuit activation would exist.
The licensee also used approved procedures for such line-ups.
The inspector reviewed temporary modification 1-92-PK-009 which supplied temporary power to allow for restoration of the safety related PB and PG buses.
The temporary modification included the load analysis which ensured that the breaker could carry sufficient load.
Licensee personnel also indicated that they would declare the emergency diesel inoperable when its field flashing source (Class lE battery)
was removed from service for maintenance or testing.
The inspector considered that the licensee's programs for maintaining reliable decay heat removal during outages appeared adequate.
This temporary instruction is closed.
No violations of NRC requirements-or deviations were identifie to Jum ers Un'ts
The inspector questioned why the temporary modification program was not being used for this activity.
The inspector also questioned whether an engineering, evaluation or 10 CFR 50.59 evaluation was needed.
The inspector further questioned whether any controls were in place to limit the number of these jumpers installed in the plant or in a single system.
The licensee was considering the inspector's questions at the end of the inspection period.
The licensee's response to these questions will be evaluated in an u'pcoming inspection (Unresolved Item 529/92-22-01).
No violations of NRC requirements or deviations were identified.
eactor Tri Breaker RTB Undervolta e Tri ssembl UVTA Issues-Unit and 3 62703 and 93702 un nd The licensee developed a program to interpret the work control and temporary modification procedures to permit the installation of temporary jumpers across field inputs to the annunciator system.
The jumpers are installed to disable the inputs from defective field devices.
The purpose of this was,to prevent an annunciator window from being constantly in alarm, or repeatedly cycling in and out of alarm.
Jumper s have been installed in Units 1 and 2.
The jumpers were documented in the Control Room Discrepancy Log, and in work orders which were being kept open as long as the jumpers were in place.
No engineering evaluation of the installed jumpers has occurred.
Unit 3 management decided to not utilize this program because of questions about the need for an engineering evaluation and 10 CFR 50.59 evaluation.
U t UV A Anomal On July 8, 1992 during the performance of surveillance test 36ST-9SB04 in Unit 2, RTB "B" {a General Electric. breaker),
the undervoltage trip assembly (UVTA) failed to reset when the breaker was opened.
This is a known problem with these devices.
The corrective action specified in the procedure was to pull'the fuse, which deenergized the UVTA and allowed it to cool.
When the fuse was pulled, an electrician noticed that the UVTA armature did not move up to the fully tripped position as expected.
The front portion of the armature stopped approximately half way between the closed and open stops.
Testing was halted, and the licensee reassembled the root cause of failure
{RCF) team which previously investigated problems with the Unit 3 GE reactor trip breaker (described in Inspection Report 50-529/92-15).
The breaker and cubicle were quarantined until a root cause of failure investigation plan was developed.
To limit the troubleshooting impact on the plant, a replacement breaker was tested and installed in the
'!B" cubicle.
The licensee repeated the maintenance history review performed in April 1992, with an emphasis on UVTAs.
In addition, a
GE representative came to the site to assist with troubleshootin it roub s
Results The most safety significant troubleshooting result was that in the as-found condition, two of three positive trip tests failed to trip the breaker with the UVTA armature travel limited by a I/32 inch shim.
This indicated that the breaker performance was degraded; however, when the armature was permitted full travel, the UVTA always tripped the breaker.
Other maintenance errors and problems were identified by the troubleshooting actions.
The UVTA was not correctly installed in the breaker in that the top front tab was resting under the mounting plate rather than inserted into the slot in the mounting plate for the tab.
In addition, the UVTA coil was not seated properly against the back of the UVTA frame due to a bent coil lamination.
Engineering determined that generally, Units 1 and 2 had been changing only the coil at the 18 month change-out interval while Unit 3 had been changing the entire UVTA.
The inspector noted that either approach met the environmental qualification requirement of. Equipment Change Evaluation (ECE) SB-A006, Revision 0, but ECE-SB-A006, Revision 1, required the replacement of the entire UVTA.
The System Engineer concluded that replacing only the coil increased the probability of future problems.
Another noted problem was that the dropout voltage adjustment screw lockwire was routed up in the slot for the trip paddle.
Mhile the lockwire routing-did not interfere with the armature and the trip paddle, this position was not considered appropriate by engineering.
The UVTA trip paddle was damaged and showed signs of plastic deformation.'ome very small metal shavings or chips were found in the breaker and in the breaker cubicle, but sufficient material was not avai1able for chemical analysis.
The shunt trip device to trip paddle c1earance was zero rather than the 0.030 to 0.050 inches recommended by technical manual GEK-64459B.
mmed ate Aetio As a result of the concern that the abnormal armature position (between stops)
suggested a potential for the UVTA to fail to trip the breaker, the licensee immediately implemented test plans to test all other GE RTBs on site.
The Unit 2 "A" RTB had just been tested for other reasons and was considered to be satisfactory.
The Unit l RTBs tested satisfactorily.
Mhile setting up for the test of the Unit '3 "B" RTB, the UVTA failed to reset when the breaker was opened.
The RCF team expanded the scope of their effort to include the Unit 3 anomaly.
The testing was halted and troubleshooting was initiated.
After the Unit 3 "B" RTB UVTA problem was resolved and tested satisfactorily, the Unit 3 "A" RTB was tested satisfactorily.
U t 3 UVTA Anomal and T oub eshootin Results Troubleshooting revealed that the Unit 3 UVTA armature to rivet gap was excessive.
The licensee indicated that the GE representative had a
proprietary drawing which contained a note specifying the proper technique for measuring the armature to rivet gap.
This detail was not in GE technical manuals GEK-7310 or GEK-64459B.
Engineering decided to
10.
replace the UVTA for continued RCF analysis on July 9, 1992.
After replacing the UVTA, the breaker was adjusted, tested satisfactorily, and returned to service.
Additional testing of the failed UVTA occurred on July 10, 1992, but details of the testing were not documented in the work order.'he inspector questioned this and was told that a late entry would be made to the work order to document what the electrician remembered; however, about a week had passed.
The failed UVTA was given to engineering for RCF evaluation.
Co c s
o and L censee es o se The inspector concluded that it was appropriate for the licensee to reassemble the RCF team, and that troubleshooting was generally well controlled.
The inspector did conclude that the Unit 3 testing which was performed on July 10, 1992, should have been documented so the results would have been available to engineering for RCF evaluation.
The inspector understood that several maintenance errors were discovered, and concluded that the error which caused the excessive armature to rivet gap was in part due to inadequate instruction in the vendor technical manual.
At the conclusion of the inspection period the inspector noted that the root cause of the anomalies in Unit 2 and 3 were not determined.
The significance of these root causes will be evaluated in a subsequent inspection (Followup Item 529/92-22-02).
No violations of NRC requirements or deviations were identified..
eactor Tri Breaker RTB Troubleshootin Activit'es - Units
and
~97~0 Licensee troubleshooting activities of reactor trip breakers continued after the inspection documented in Inspection Report 528/529/530/91-15.
The inspector noted that General Electric (GE) specified the minimum trip shaft paddle to undervoltage armature clearance of 0.030 inches in a letter dated April 16, 1992.
Arizona Public Service Company (APS), after experiencing difficulty in setting up a breaker to its specified tolerances, was notified by letter from GE on June 24, 1992, of a change in this clearance from 0.030 inches to 0.005 inches.
On June 26, 1992, APS was notified by GE that the Palo Verde trip paddies were slightly larger (by 0.10 inch) than specified in drawings.
GE subsequently sent APS a letter, GE/ANPP-92-KRS-0702 of July 2, 1992, which described a 1982 design change which shortened the radius dimension from the center of the trip shaft to the tip of the paddle by 0.1 inch.
The GE letter also stated that "The use of the longer or shorter trip paddle in an AKR-4BE-30 breaker that has been properly maintained and adjusted will not affect the breaker opening function."
All APS breakers had the longer paddies.
This condition was documented on Supplier Deviation Disposition Request (SDDR)
1574 dated June 26, 1992.
The System -Engineer said that all but one breaker will have the shorter paddies installed when they are refurbished by GE, and the one breaker which was recently refurbished will have the longer trip paddle replaced by the shorter one.
Based on several discussions with APS and NRC managers it appeared that a
thorough review of breaker origin, procurement process, and design history had not been performed by APS when the additional breaker problems were identified.
The licensee appeared to focus on the fact that the breaker failure mode (failure to re-close after opening)
was not a safety issue and therefore did not appear to aggressively pursue the problems to assure continued operability of the breaker.
Four GE RTBs have failed to close at Palo Verde.
The Unit 1 "A" RTB failed to close on May 1, 1992, as described in Condition Report/Disposition Request (CRDR) 1-2-0323.
The Unit.3 "B" RTB failed to close on June 21, 1992, as described in CRDR 3-2-0226.
The Unit 2 "A" RTB failed to close on July 6, 1992, as described in CRDR 2-2-0205.
As part of the troubleshooting effort, APS engineers have travelled to the GE facility in Atlanta, Georgia on several occasions.
The root causes of the failures to close determined by APS and documented in Inspection Report 528/529/530/91-15 were questioned by APS and by the inspector as a
result of the correspondence described above.
'rovide their final analysis and recommendations on breaker serial number N2689500011 by August 7, 1992.
This is the Unit 3 "A" RTB which failed to close on two separate occasions during March.1992 and is described in CRDR 3-2-0102.
APS will await final action to resolve the failure to open concern until they receive the final conclusions and recommendations from GE.
The inspector will review the troubleshooting results and corrective actions will be reviewed when they are finalized (Followup Item 528/92-22-03).
No violations of NRC requirements or deviations were identified.
adiatio Monitor RU-1 6 Ino erable tho t 0 erat ons Awareness - Unit 3
~7077 On May 27, 1992, the licensee discovered that RU-146, the fuel building high range radiation monitor, had been inoperable since May 23, 1992.
The radiation monitor had been previously declared operable without first releasing the clearance on the sample pump for RU-146.
The presence of the clearance was not known because RU-146 is normally in a standby mode.
RU-146 was returned to service on May 28, 1992.
No fuel movement or crane movement over the spent fuel pool occurred while RU-146 was inoperable.
The licensee initiated CRDR 3-2-199 and later determined that the cause of the inoperable radiation monitor was a personnel error by the Assistant Shift Supervisor.
The Assistant Shift Supervisor was disciplined.
Special Report 3-SR-92-003 was issued on June 18, 1992.
The inspector concluded that the licensee's actions appeared appropriate.
No violations of NRC requirements or deviations were identified.
Emer enc Diesel Generator EDG tart Failure - Unit 3 92700 The inspector reviewed Special Report 3-SR-92-001 regarding the valid test failure of the Unit 3 "A" EDG on March 10, 1992.
The licensee
'4
C determined that the failure was the result of a flow restriction in spring-loaded check valve 3OGA-V570, which is part of the diesel air start control system.
Each EDG has two air start subsystems.
The EDG is functionally tested monthly with one of the two subsystems (alternately) isolated.
In January 1992, the licensee revised the test procedure to require depressurizing the air header between the isolated air start subsystem and the air-operated control valve that opens (on a start signal) to create a flowpath from the star ting air receivers to the EDG starting air valves.
The start failure occurred during the first performance of the surveillance test on Unit 3 EDG "A" since the test procedure was revised.
The licensee determined that the restricted flow through 3DGA-V570 prevented the air-operated control valves from fully opening, which in turn restricted the flow from the air receivers such that the check valve in the depressurized header did not close.
The in-service air start subsystem was then providing air to repressurize the depressurized header via cross-connect piping through the open check valve and partially open air-operated control valve.
The in-service subsystem was unable to simultaneously provide sufficient air to the diesel air start valves to start the EDG in the required time interval.
The licensee performed a root cause of failure (RCF) analysis of the s'pring-loaded check valve failure, and also confirmed that the air start subsystem header check valve that had not closed had performed as designed.
All six EDGs on site have subsequently been successfully tested using the revised test procedure.
Additionally, the licensee has replaced the failed spring-loaded check valve and its counterparts in the other air start.subsystem and on the "B" EOG in Unit 3.
The inspector reviewed the licensee's compliance with regulatory requirements for testing 3DGA-V570.
Table. 3.2-1 of the Updated Final Safety Analysis Report (UFSAR) and Section 9.5.6 of the Palo Verde Safety Evaluation Report (SER) both indicate that those air start subsystem components which are external to the diesel engine package, with some exceptions, are designed to seismic Category I, ASME Section III, Class 3, requirements.
However, 3DGA-V570 is part of the diesel engine package, as indicated on drawing 03-M-DGP-001.
The SER indicates that alternate requirements exist for the engine-mounted air starting piping and components, concluding that they are intentionally over designed and are considered equivalent to ASME Section III Class 3 components.
However, as they are not ASME components, ASME Section XI testing is not required.
The licensee revised the test procedure as an enhancement resulting from a
RCF evaluation from an unrelated EOG air start subsystem solenoid failure that occurred in 199I.
That evaluation went beyond the immediate failure analysis and looked at the testing of the entire air start subsystem.
The inspector concluded that the licensee's previous and current test procedure meet applicable regulatory requirements, and that the current
t
test procedure tests the safety function of 3DGA-V570 more thoroughly than required.
Additionally, the licensee's engineering organization was proactive in the performance of the 1991 RCF evaluation, resulting in the procedure change which later revealed the 3DGA-V570 flow restriction that might not otherwise have been detected.
The licensee's corrective actions for this failure appear to be adequate.
No violations of NRC requirements or deviations were identified.
o ded se Ci cu reaker P ocedure de uac
- Units
and
6 703 The inspector reviewed revision three of procedure 32HT-9ZZ74,
"Molded Case Circuit Breaker Test," for appropriate instructions on the mounting of these breakers.
The procedure addressed two mounting configurations for these breakers and specified appropriate torque requirements for mounting hardware.
The inspector noted that three different mounting configurations existed in safety-related applications, and the three
'ounting configurations varied depending on the type of panel in which the breaker was installed.
The inspector noted that the mounting configuration of molded case breakers in DC distribution panel PKA-D21 was the configuration that was not addressed in the procedure.
Specifically, the breakers were installed in the panel using 0.25 inch screws.
The inspector questioned the torque requirements for these screws since the configuration was not addressed in the procedure.
The System Engineer stated that the absence of this torque specification did not violate seismic mounting requirements, and the circuit breaker vendor did not recommend a torque specification.
In addition, the inspectot noted that the licensee's procedure for torque requirements, 30DP-9MP02,
"Tightening and Fastener Preload," did not specify a torque limit for this size of screw.
The inspector's sampling of molded case circuit breaker instal'lations did not reveal any cases where breakers were clearly installed improperly.
The inspector concluded that the procedure could be enhanced to provide details of the third mounting configuration.
The Naintenance Standards Technician responsible for this procedure added this issue to ICR 53152 so that details would be provided for this third mounting configuration.
No violations of NRC requirements or deviations were identified.
13.8 KV Fault Startu Transformer Outa e - Units
and 3 62703 and 3702 On June 19, 1992, startup transformer AE-NAN-XOl was tripped by the phase to ground differential protective relay.
Power was restored in Units 2, and 3 via the alternate supplies.
Troubleshooting revealed a defective splice in underground cabling in a manway between AE-NAN-XOl and the Unit 3 3E-NAN-SOG bus.
This manway had been flooded in 1988, and the manway seal had been reworked.
When this manway was opened for troubleshooting, very little water was present, and the cabling appeared dry.
The splice was preserved for root cause of failure evaluation and a new splice was installed.
Engineering concluded that the splice had failed apparently
due to water intrusion.
The splice kit used to replace the failed splice was not the latest design from Ray Chem Corporation.
After discussions with Ray Chem, Engineering concluded that the replacement splice using the older design splice kit is adequate, but to provide additional assurance, a Hipot test should be performed on the cable at the next AE-NAN-X01 outage.
In addition, all remaining splice kits in the warehouse will be replaced with the newer design splice kits.
The inspector concluded that the licensee actions appeared appropriate.
No violations of NRC requirements or deviations were identified.
15.
peed e De 'c c
Conce
-
e to Coola t ste CS e ressu i ati
-
ts d
02
During a simulator scenario event of a stuck open pressurizer spray valve, NRC examiners identified an apparent procedure deficiency.
The alarm response procedure implemented by the licensee to address this event was 4lAL-IRK4A, "PZR PRESS HI-LO."
This procedure guides the operator to close the spray valve with the control room hand switch or to enter the emergency operating procedures (EOPs)
on low RCS pressure.
The procedure provided no additional mitigating guidance.
As a result, the NRC examiners observed three different groups of applicant reactor operators attempt to mitigate this event in the facility simulator using different strategies.
a.
One group isolated control air to the affected spray valve, which promptly closed the valve and stopped the RCS depressurization.
Appropriately, this was accomplished before EOP entry was necessary.
b.
A second group tripped all reactor coolant pumps
{RCPs) to reduce spray flow.
EOP entry was required on low RCS pressure.
c.
A third group tripped two RCPs and left two running, in accordance with the EOPs.
However, the EOPs did not specify which RCPs to trip for this specific event.
This crew failed to consider the consequences of the further RCS depressurization that would result by leaving the RCP running in the loop with the stuck open spray valve.
All of the above strategies mitigated the event, and the EOPs were correctly used.
However, some strategies challenged the plant safety systems and RCS subcooling margin more than others.
Because the event in question, if unmitigated, presents a direct challenge to RCS subcooling and therefore potentially affects successful implementation of natural circulation heat transfer, the examiners determined that this alarm response procedure did not provide adequate guidance to mitigate a slow RCS depressurization event.
This was considered a violation of 10 CFR Part 50, Appendix B, Criterion V (Violation 528/92-22-04)
which requires activities affecting quality to be appropriate to the circumstances.
The examiners were also concerned that this weakness.
was not identified by the licensee during the course of simulator training sessions.
-14
0
The licensee acknowledged these concerns and revised the alarm response procedure.
This new revision was given to the NRC Chief Examiner at the pre-exit meeting on tune 11, 1992. It contained additional guidance to isolate control air in an attempt to cause the spray valve to fail closed.
It also provided timely RCP tripping str'ategy.
Therefore, the NRC Chief Examiner determined that the revised procedure was adequate.
The licensee expressed the position that the original procedure was adequate, but acknowledged it should have been previously enhanced.
The NRC maintains that the procedure presented an unnecessary risk of challenge to subcooling margin, and therefore, the procedure was inadequate.
However, the licensee's action was timely and responsive to this issue, and no licensee response is required.
One violation of NRC requirements was identified.
u t
ss rance a d Ov rsi ht Additional discussion focused on the Independent Safety Engineering Department and its reorganization into the gA organization in the guality Engineering department.
One of the goals for the Independent Safety Engineering Department was to be more intrusive than in the past.
Mr.
Perkins commented that to be truly effective the organization had to have technically valid and safety significant findings, and should have the*
support of the line organizations.
Mr. Guthrie and Mr. Hamlin agreed with the comments.
eet t
PS ana ers Or ani at o
s 30702 On July 2, 1992, Mr. S. Guthrie (Site Director, guality Assurance)
and Mr. K. Hamlin (Director, Nuclear Safety) of APS met with K. Perkins and others of the Region V staff to discuss organizational changes being made in the guality Assurance (gA) and oversight organizations.
The discussions highlighted the APS review of all oversight organizations in March 1992, which included guality Assurance (gA), the Plant Review Committee, the Independent Safety Engineering Department, and the Offsite Safety Review Committee.
This review identified areas in these organizations which could be improved, such as redundant and fragmented assessment efforts, a more effective industry event response capability, and more performance based assessments.
This review also provided attributes for a more effective and efficient oversight organizational structure.
These attributes included a single point of accountability for oversight inspections and assessments, a clear distinction between day-to-day inspection efforts and assessments and high level oversight, continued support of senior APS management with the Offsite Safety Review Committee, and more effective use of resources.
Mr. Guthrie highlighted the goals of the gA organization and how each component of gA was envisioned to function to provide the necessary assessment and oversight capability.
Of particular note was that the guality Monitoring group was emphasizing their time in the plant to review ongoing work, and that the information developed by the guality Monitoring group was used in the performance of gA audits.
Mr. Guthrie
noted that the guality Control department was increasing its field time and eliminating time spent supporting work order processing.
Hr. Perkins noted that these discussions were beneficial in keeping regional management informed about organizational'hanges and the regional staff would be reviewing the results of the changes through inspections to determine their effectiveness.
No violations of NRC requirements or deviations were identified.
17.
o owu o
ev ou F990~
a.
~U~t de t ed t s - Un ts
and 3 (I)
C osed Violatio 528 9 -05-0
"
core nstrument
't drawn" -
U it 9 702 o e This violation occurred on February 25, 1992, when contractor maintenance personnel misinterpreted the flexibilityallowed in a procedure and withdrew an incore instrument (ICI) manually, contrary to the requirements of the procedure, which required use of the ICI hoist.
The licensee deleted the misinterpreted step and added steps al.lowing manual ICI withdrawal.
Additionally, appropriate personnel were briefed on the importance of verbatim procedural compliance.
These corrective actions appear to be adequate.
This item is closed.
(2)
Closed V o1ation
- 528 92-05-02
" lant P otection S stem PPS Set oint Left ncorrect F
1 owi Surve'ance Test" Un t 92702 This violation occurred on February 4, 1992, when a technician failed to ensure that the steam generator number 2 low pressure reactor trip and engineered safety features actuation system trip setpoint in Channel
"B" of the PPS was restored following partial performance of the monthly functional test.
In addition, a Reactor Operator failed to note the incorrect setpoint during an hourly check required by the Control Room Data Sheet Instructions.
The licensee revised the surveillance procedure to add detailed action steps to direct performers on how to attain and determine the steam generator low pressure trip setpoints.
This provides added assurance that the minimum allowed value for the trip setpoint is attained prior to restoring the steam generator low pressure trip.
The licensee's response to this event included a determination that adjusted reactor trip setpoints should be verified by a second person.
The licensee initiated appropriate procedural changes.
Although not mentioned in the response to the violation, the inspector noted that the licensee generally continuously monitors
II
the steam generator low pressure setpoint on control room displays, and now uses the plant computer as the source of data for confirmation of the setpoint on the control room data sheets.
The inspector concluded that the licensee's corrective and preventive actions were adequate.
This item is closed.
b.
~Un t (1)
osed o
owu tern 9 9 -0
"Control Ele ent ve echan sm C
D an and aust S
k Hountin Bolt a
es"-
9 70 This item addresses the failure of CEDH fans, fan mounting bolts, and exhaust stack mounting bolts, multiple examples of which were identified during 1991.
In one instance, an exhaust duct was found to have only 1 of 16 bolts in place, barely restraining the 1125 pound duct from falling onto reactor coolant piping and other safety-related components.
Fan failures also resulted in a forced downpower and subsequent reactor trip of Unit 2 on August 9, 1991.
The in'spector reviewed the final disposition of Condition Report/
Disposition Request (CRDR) 9-1-0024, which documents the licensee's root cause of failure evaluation and corrective actions.
The CRDR evaluation determined that different'root causes applied to the failure of each of three different generations of installed CEDH fans.
All the fans failed due to improper (insufficient or excessive)
lubrication, caused by lack of a maintenance procedure and inadequate maintenance training.
Bolting for one fan failed because an incomplete flange connection allowed transverse motion of the assembly and resulted in vibration loosening the mounting bolts.
The remaining bolting failures were'caused by excessive cyclical loads induced by catastrophic fan bearing failures.
As a result of this evaluation, the licensee initiated several significant corrective'ctions:
o A final disposition to Material Nonconformance Report (HNCR)
91-HC-9007 was issued making wire rope slings, installed to restrain the exhaust ducts from falling on other equipment, permanent plant equipment.
o Fans with Dow Corning Holykote FS-3451 grease are being rebuilt with Chevron SRI-2 grease.
o Grease lines have been installed from the fan assemblies to the
air conditioning unit housing roof in Units 1 and 2 to allow Maintenance to lubricate the fans while operating and to minimize fan starts/stops and the time required inside the containment building.
Similar modifications in Unit 3 are scheduled for the September 1992 refueling outage.
~
~
o A Design Change Package (DCP) was developed to install permanent vibration monitoring onto the CEDM cooling fans.
o Maintenance managers have been asked to ensure maintenance personnel are trained on the problems a'ssociated with over-lubrication of'mechanical components.
o A Preventive Maintenance (PM) task has been created to replace the bearings and grease seals of the CEDM cooling fans on a
refueling cycle frequency.
o CEDM cooling fan and exhaust stack bolts are. being replaced with SAE Grade 8 high strength bolts.
o A maintenance procedure for lubricating the CEDM cooling fan bearings was scheduled to be developed.
The inspector noted that guality Assurance monitoring of specific corrective actions had been performed, and guality Assurance was also scheduled to review the actions not yet completed.
The inspector concluded that licensee completed and intended actions were adequate.
This item is closed.
{2)
Closed io at on 529 9 - 9-01
"CEA Su o t lat orm owered ithout ro e Re ue eve
" Un't
0 The inspector reviewed licensee procedure 420P-2ZZ12,
"Mode 6 Operations,."
and noted that changes had been implemented to provide more detail for the major refueling steps beginning with vessel head removal and concluding with commencement of defueling. Specifically, the procedure now requires the refueling Senior Reactor Operator
{SRO) to make several reports as the evolution proceeds, which are signed off as individual procedure steps.
In addition, an appendix
.
has been added to delineate the refueling SRO's duties and responsibilities within this procedure.
The inspector concluded that these changes would provide better overall control of this evolution.
In addition, the inspector witnessed portions of this procedure implemented during the Unit 1, 1992, outage and concluded that the procedure was well controlled.
Based on these observations, this item is closed.
(3)
0 en Violation 529 91-49-02
"Core Alteration Without SRO esent" U 't 2 92702 As noted above, the inspector concluded that based on a review of the modified procedures and observation during the Unit 1 refueling, the licensee's corrective actions related to refueling evolutions were adequate.
However, as stated in the licensee's response to the violation, dated March 2, 1992, actions were being taken to address the underlying root causes of supervisory involvement, procedure
e
adherence, and communications.
Among these was a detailed organization and programmatic analysis of human errors which resulted in the selection of Operation, Haintenance, and Site Technical Support for more focused assessments.
The licensee reported in a letter dated Hay 29, 1992, tha't due to recent events, this assessment will not be complete until August 31, 1992.
Because of the extensive review being undertaken by the licensee, and the=-
importance of addressing the underlying causes, which also were related to the mobile crane event in Unit 3 in November 1991 and more recently the reactor trip breaker malfunction and loss of plant annunciator events, the inspector concluded that this item should remain open until the results of the licensee's assessment and any further corrective actions can be reviewed.
Closed
'olation
1-9 0 'Co e
iterations e
o ed t out Communicatio s
t b s ed" -
U t 2 92702 Based on the same review noted in 50-529/91-49-01 above, this item is closed.
Closed V'olation 529 9 -
-04 '
uel ransfer Gate 0 ened efore Boro Sam les ake
" Unit 9 702 This violation was the result of a error by a Shift Supervisor (SS)
who signed a procedure step in error.
Following shift turnover, during which the problem was not identified, the Assistant SS authorized lifting of the fuel transfer gate based on the incorrectly signed step which indicated that a boron sample had been taken.
Since it had not, a procedural violation occurred.
The licensee administered discipline to the SS and Assistant SS, and briefed Unit 2 operations personnel on management expectations during shift turnover and with regard to administrative control.
The inspector concluded this was appropriate.
The resident inspectors will continue to periodically observe shift turnover activities.
This item is closed.
Closed Violation 529 91-49-05
"Technical S ecif'cation TS ot Met Fo owin Inverter rans'fer" U it 2 92702 This item was deemed by the NRC not to 'be a violation and was not included in-the NRC enforcement letter to the licensee dated February 3, 1992.
This item is administratively closed.
Closed Violation 529 91-49-06
"Failure to Res ond o Control Room Annunciator" - Unit 2 92702 The licensee's corrective actions for this and the other violations identified above related to NRC inspection report 91-49, and included heightened management/supervisory presence to observe plant activities.
This included placing the Assistant Plant Hanager.,
\\
Operations Manager, and Operations Supervisor on shift rotation for a period of several months.
The observations made by these persons were intended to give management a more clear assessment of how management expectations were being achieved and to provide direct
.
feedback when they were not.
The inspector observed this effort over several months and through discussions with the principals concluded that the result was beneficial.
However, long term effectiveness will result only from continued management/supervisory involvement and awareness with plant activities.
On the basis of the licensee's completed actions, this item is closed.
Further review of the licensee's detailed programmatic assessment will be done as noted under item 50-529/91-49-02 above.
0 en ollowu Item 529 9 -05-04
"Essential S r Pond SP um Brea er ai ed to Close
ema d" -
U t 9270 This item involved a safety-related GE Magneblast 4l60 Volt circuit breaker which failed to close on demand.
guality Deficiency Report ((DR) 92-0038 is still open.
The equipment lists which identify
=
specific equipment that would require early engineering involvement in troubleshooting to preserve and examine conditions which might assist in root cause of failure analysis is complete.
This item will remain open pending review of gDR 92-0038.
Closed Followu Item 529 92- 0-01
"Auxi Feedwater Valves ot ncluded n Survei a ce est
" -
U t 92 0 This item involved the exclusion of the power-operated valves in the auxiliary feedwater flow path from the valve position verification surveillance.
This item is separate from LER 528/92-08 which involved the non-essential auxiliary feedwater flow path.
On March 20, 1992, procedure 40ST-1AF05,
"Monthly Auxiliary Feedwater Alignment Verification," was identified to only verify the position of the manually operated valves in the AFW flow path from the primary supply tank to the steam generator.
gua1ity Assurance (gA)
initiated CRDR 9-2-0191 questioning the adequacy of the procedure in meeting Technical Specification
{TS) 4.7.1.2.a.2.
TS 4.7.1.2.a.2 requires that "Each auxiliary feedwater pump shall be demonstrated OPERABLE at least once per 31 days on a
STAGGERED TEST BASIS by verifying that each valve (manual, power-operated, or automatic)
in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position."
In response to the CRDR, the licensee's Compliance and Operations Standards departments concluded that verification of the power-operated valves in their "correct" position is a simple verification of operability, and that these valves are verified OPERABLE on a continuing basis and there is no need to document in a surveillance procedure that the power-operated valves are in their "correct"
position every 31 days.
Based on this the licensee's Compliance department concluded that the issue is not reportable.
gA rejected the CRDR's response and maintained that the procedure no longer met the intent of the surveillance requirement.
On Nay 11, 1992, after several discussions, Operations Standards and gA agreed that the "desired" position for these valves can be opened, closed, or throttled, depending on the operational mode of the plant.
Operations Standards amended their previous response.
The power-operated valves in the flow path of the essential AFW pump to the SG were added to the 31 day surveillance procedure required to be checked in the 'open, closed, or throttled position with power available as the "desired" position.
On June 18, 1992, the inspector noted that procedures 40ST-9AF07,
"Auxiliary Feedwater Pump AFA-POl Monthly Valve Alignment," and 40ST-9AF08, "Auxiliary Feedwater Pump AFB-P01 Nonthly Valve Alignment," included the requirement to verify the power-operated valves.
After the issuance of the procedures, gA discovered in a Combustion Engineering system interface agreement that the "desired" position of these power-operated valves are closed during normal operation.
The licensee modified the procedures to denote that the "desired" position is closed unless the AFW pump is in service.
Subsequent review revealed that these valves were verified closed in procedures 4XST-XAF02 "Auxiliary Feedwater Pump AFA-POl Operability Test 4.7.1.2 a 5 c" and therefore, the issue is not reportable.
This issue is closed based on this review.
Unit 3 Closed V'olation 530 91-01-01
"Diesel Generator Ins ection Surveillances Not Perfo med Dur n Shutdown" - Unit 3 9270 The NRC identified this violation of Technical Specification Surveillance Requirement (SR) 4.8.1.1.2.d.1 which prohibits performance of Emergency Diesel Generator
{EDG) 18 month inspections during plant operation.
The inspector confirmed that the licensee had modified the appropriate surveillance test (ST) procedures to require performance only during plant shutdown conditions.
The associated LER (528/91-02)
was reviewed and closed in NRC Inspection Report 528/92-17 (under the incorrect LER number 528/92-02).
However, pursuant to the inspector's review, two other concerns were noted which were not related to the specific LER issue.
One was that the SR specified performance of an EDG inspection "in accordance with procedures prepared in conjunction with
manufacturer's recommendations."
The recommendations in the technical manual section defining annual'nspections included
"checking the operation and calibration of all control and safety shutdown devices."
The inspector noted that the licensee had implemented calibration of safety shutdown devices in their Preventive Maintenance (PH) program, not in their ST program.
Based on discussion with NRR, the inspector concluded that the language of the SR would allow the licensee to use the manufacturer's recommended inspections to formulate ST procedures without specifically requiring each and every recommendation to be implemented as an ST.
However, where the licensee has chosen to implement manufacturer's recommendations as preventive maintenance tasks, they should still conform to the.manufacturer's guidelines for periodicity and to their PH program requirements.
The inspector subsequently identified one EOG generator differential relay safety shutdown device (active in the emergency run mode)
which had not been calibrated in two years, and was therefore beyond its specified PM frequency of 18 months without management approval as required by the licensee's PH program.
This question was left open in NRC Inspection Report 528/91-35 until the licensee could confirm the need for corrective action.
The inspector reviewed the licensee's evaluation of this event (CROR 9-1-0200).
The licensee found that the PM interval had been changed in March 1991 from every refueling to every 18 months, but that the need to change th'e due date for the next task or to authorize exceeding the 25 percent grace period had not been recognized.
The inspector concluded that this represents inadequate attention to ensuring important EDG instrumentation is maintained in accordance with manufacturer's guidelines and is a failure to follow the PH program.
The failure to follow PM program procedures is a violation of NRC requirements
{Violation 528/92-22-05).
Following a review of licensee corrective action associated with CRDR 9-1-0200, which included rescheduling and completing several EDG relay PH tasks, issuance of a new procedure which provides specific review requirements for PH task interval changes, and review of other PH tasks which may have been subject to this same deficiency, the inspector concluded that the corrective actions appeared appropriate and that a licensee response to the violation was not needed.
The second concern unrelated to the LER issue was identified in NRC Inspection Report 528/91-50 under a followup discussion of this open item.
It involved the lack of a root cause of failure evaluation for an EDG low lube oil pressure switch. which had been found outside of its tolerance.
This issue was further reviewed during the Instrumentation and Control inspection (NRC report 528/529/530/92-14) during which it was determined that these switches were found out of tolerance 52 times in 67 calibrations without a root cause evaluation, trend analysis, or corrective action.
This finding was used as one example in a 'violation issued with that repor P
Licensee response to this violation will be reviewed in a subsequent inspection report.
Based on the above review, this item is closed.
C osed o at'on 530 9 -0 -0
"Lac of Time or ective ct on o
Emer enc D'e el erator DG Ai ece ve eaka e"-
U 't 3 92 0 This violation was left open in Inspection Report 528/91-10 pending the completion of an evaluation of,the leak rate acceptance criteria for the EOG air start system.
In response to this, the licensee completed Engineering Evaluation Request (EER) 92-DG-OIO, which the inspector reviewed.
EER 92-DG-010 referenced EER 91-DG-023, which concluded that an inability to maintain at least 185 pounds per square inch gauge (psig) in the air receivers would be an indication that the diesel may not be able to provide its design basis 10 second star t.
Based on this review, this item is closed.
osed ollowu tern 530 9 - 6-03
"Reactor Coola t um RC ermination Criteria Fol ow'onta'e t S a
Event" -
U t 3 92 01 This item addresses the appropriate actions to be taken with respect to RCP operation following a containment spray actuation..
NRR reviewed the licensee's actions during the June 19, 1991 inadvertent containment spray at power event in Unit 3.
NRR,'n a letter to Region V dated Harch 2, 1992, concluded that the licensee's actions were not fully acceptable, because at least one RCP was not returned to service within one hour, as required by TS 3.4.1.2.
As a matter of general practice, it was the Staff's position that natural circulation should be relied upon only as a last resort when forced circulation is not available.
However, the Staff considered the licensee's corrective actions, described in Licensee Event Report 530/91-03, Supplement 1 (see Inspection Report 528/91-.50) to be acceptable.
This item is closed based on the adequacy of the licensee's current procedural guidance, as presented in LER 530/91-03 and reviewed by NRR.
Units
2 and
Closed
CFR Part
Re ort 89-8-:
"ABB-CE owe Distr'bution Inc.
Current T ansforme CT nca sulate Hater al"-
Units
2 and
9270 This item involved a softening of the epoxy-anhydride encapsulate material in CTs due to high humidity conditions.
The.licensee
evaluated this condition in Engineering Evaluation Request
{EER)
89-XE-28 which recommended walkdowns in all units, a change to th'
clean and inspect preventive maintenance
{PM) task to inspect the CTs each time the PM task is performed, and a change-out program.
A clarification with engineering identified that the abbreviation Eg in the EER closeout referred to equipment, and not environmental qualification applications since these CTs are in mild environments.
As such, equipment change-out was determined not to be required.
Fifteen of the eighteen walkdowns are complete with no softening of encapsulate material noted in any CT.
The remaining walkdowns will occur during the next Unit 3 outage.
The procedure revisions are complete and the preventive maintenance tasks have been revised and final approval wi11 be completed shortly.
Based on the results of the walkdowns, the licensee's evaluation, and the procedure revision for continual monitoring, this item is closed.
C osed Unresolved tern 528 91-9-01
" ualit Classi ication o
the Sa et u
ment Status S stem SESS
" - Units
and
~97011 This item originated from inspector identification of a deficient licensee analysis allowing a reduction in the quality classification of SESS.
The licensee made four commitments to resolve the issue as documented in inspection report 528/91-29.
The inspector reviewed the licensee's closure documents for these items (memorandum 283-00886-JHH/REB and attachments).
The first two commitments were to review SESS engineering documentation for consistency of terminology and to document how they were complying with regulatory requirements related to SESS and associated Class ZE circuits.
Numerous revisions were made based upon this review, including the Design Criteria Manual, System Description Manual, UFSAR, Component Classification Evaluation for SESS, 27 Equipment Change Evaluations, and 12 Engineering Evaluation Requests (EER) which were superseded by a single EER which was appropriately revised.
The inspector concluded that these changes would minimize the risk of future misuse of terminology such as "isolation device", "quality related",
and "safety related."
The change also appeared to make the various documents clear and consistent with respect to how regulatory requirements were being met.
The third commitment was to identify other Associated Class lE circuits in the plant to ensure they met IEEE 384 requirements.
The licensee's review determined that the SESS circuit is the only circuit connected to a Class 1E power source that does not employ IEEE 384 "isolation devices".
and which therefore must rely upon an analysis per IEEE 384 and Regulatory Guide 1.75.
The inspector concluded that this review appeared adequate, The final commitment was to evaluate the need for training appropriate engineering personnel on the correct use of related terminology.
The licensee issued a memorandum to on-site and off-site engineering supervisors clarifying SESS and IEEE 384
terminology.
The inspector concluded that the licensee had met their commitments, and that the actions taken appeared appropriate.
This item was listed as unresolved because the requirements of IEEE 384 and Regulatory Guide 1.75 appeared not to have been met and further NRC review was needed to establish if a deviation from these requirements had existed.
The inspector determined that the required analysis per IEEE 384 had been performed, but was inadequate.
Subsequently the licensee performed a more thorough analysis which demonstrated compliance.
The inspector considers that the licensee's further actions have addressed the larger issue of continued compliance and that no further NRC action is necessary.
This item is closed.
One violation of NRC requirements was identified.
18.
ev ew f License vent e or s
9 700 and 3
Through direct observations, discussion with licensee personnel, or review of the records, the following LERs were closed.
a.
~i~t 91-08 v s on L
"RCS e ka e
oss bl Exceed'n akeu Oue o
92-01 ev o
"React h tdown e 'd b ec ical S ec'atio s"
This LER resulted from the licensee's determination that reactor coolant system pressure boundary leakage existed at a pressurizer instrument nozzle.
This event was documented in NRC Inspection Reports 50-528/9)-50 and 50-528/92-04.
The inspector concluded that the licensee's efforts to identify the source of high containment gaseous activity were thorough and the decision to shutdown the unit to Mode 5 for weld repair was appropriately conservative.
The region based inspectors who reviewed the weld repair documentation concluded that the repair was conducted in accordance with ASME Code requirements.
Subsequently during the 1992 refueling outage the licensee replaced this and six other similar Inconel 600 pressurizer nozzles that were evaluated as highly susceptible to primary water stress corrosion cracking (PNSCC).
Similarly, highly susceptible hot leg sample line nozzles were replaced in Unit 2 during the 1991 refueling outage.
This completes the replacement of all highly susceptible nozzles for all three units
{none were identified in Unit 3).
The licensee's actions to replace high susceptibility nozzles appears proactive, and the identification and resolution of the Unit 1 defective
)
92-03 nozzle appears to be thorough.
Based on these reviews, this item is closed.
ev on
"Hi sed e
ical S eci icatio ct on Due to This is closed based on the closure of Violation 528/92-05-02 in paragraph 17 of this report.
91-07 v
o
Conta me t t
r eci
'
on 't Core lteratio c.
~Ut 3 91-10 d
Rev s o
" SF ct t o s Caused b
anua eener izat'on o
site Powe
"
d.
~ll t
'and This supplement updates corrective actions taken as a
result of the November 15, 1991 event initiated by a crane coming into contact with offsite power lines feeding Unit 3.
The event is described in detail in Inspection Report 530/91-47.
The inspector reviewed the revised corrective actions and concluded that they were appropriate.
This LER is closed.
92-08 Revision LO
"Surve lance Re uireme t or Nonessent al uxi 'ar eedwater Hot e
ormed" This LER involved failure to verify the position of several valves in the flowpath from the non-essential auxiliary feedwater (AFW) pump to the steam generator (SG).
Technical Specification (TS) Surveillance Requirement 4.7.1.2.a.2 requires that
"Each auxiliary feedwater pump shall be demonstrated OPERABLE at least once per 31 days on a STAGGERED TEST BASIS by verifying that each valve (manual, power-operated, or automatic) in the flowpath that is not locked, sealed, or otherwise secured in position, is in its correct position."
The licensee verified that each valve in the flow path from the non-essential AFM pump to the SG was in its correct position upon discovery.
The licensee revised procedure 40ST-9AF06, "Auxiliary Feedwater Pump AFN-P01 monthly Valve Alignment," to include verification of these valves'osition in the flowpath..
To preclude the recurrence of a similar event, the Independent Safety
Engineering Group (ISEG) is performing a review of the TS ST procedures to verify that the surveillance requirements are met.
The inspector review the revised Procedure and discussed the issue with the ISEG review personnel and concluded that the corrective actions appear appropriate to prevent recurrence.
This item is closed.
No violations or deviations of NRC requirements were identified.
19. ~t An exit meeting was held on July 20, 1992, with licensee management and the resident inspectors during which the observations and conclusions in this report were generally discussed.
The licensee did not identify as proprietary any materials provided to or reviewed by the inspectors during the inspection.
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