IR 05000528/1990046
| ML17305B297 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 12/19/1990 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | ARIZONA PUBLIC SERVICE CO. (FORMERLY ARIZONA NUCLEAR |
| Shared Package | |
| ML17305B296 | List: |
| References | |
| 50-528-90-46, 50-529-90-46, 50-530-90-46, NUDOCS 9101090029 | |
| Download: ML17305B297 (30) | |
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
~tt N
Docket Nos.
License Nos.
,
Licensee:
50-528/90-46, 50-529/90-46 and 50-530/90-46 50-528, 50-529, 50-530 NPF-41, NPF-51, NPF-74 Arizona Public Service Company
'.
0.
Box 53999, Station 9012 Phoenix, AZ 85072-3999 Facilit Name:
PI V
d N
I d
tt gtttt Units 1, 28
Ins ection Conducted:
November 4 through December 1, 1990 Inspectors:
Approved By:
D.
Coe, Senior Resident Inspector F. Ringwald, Resident Inspector J.
Sloan, Resident Inspector W. Ang, Project Inspector ong le Reactor Projects Branch,Section II qo a
e gne Ins ection Summar
Ins ection on November 4 throu h December
1990 (Re ort Numbers an Areas Ins ected: 'outine, onsite, regular and backshift inspection by e
ree ress ent inspectors and one regional inspector.
Areas inspected included: previously identified items; review of plant activities; engineered safety feature system walkdowns monthly surveillance testing; monthly'plant maintenance auxiliary building floor drain backflooding - Unit.1; essential chiller inoperable due to low freon level - Unit 1; inappropriate surveillance test acceptance criteria
- Unit 1; implementation of compensatory measures for auxiliary feedwater room water tight door deficiencies - Unit 2 control room essential filtration actuation system initiation - Unit 2; inadequate welding on supports for emergency diesel generator cooling lines - Units 2 and 3; core operating limits supervisory system out-of-service conditions-Units 2 and 3; review of licensee event reports-Units 1,
2 and 3; and review of periodic and special reports - Units 1, 2 and 3.
During this inspection the followinq Inspection Procedures were utilized:
30702, 61726, 62703, 71707, 71710, 92700, 92701, 92702, and 93702.
9101090029 901220 PDR
- DOCK 05000528
-2-Results:
Of the 13 areas inspected two non-cited violations were icemen.i+ed.
These pertained to a '))censee-identified seismic qualification deficiency on Emergency Diesel Generators in Units 2 and 3, and to a self-revealing personnel error which caused an inadvertent BOP ESFAS actuation.
Both events were properly reported to the NRC and licensee actions were evaluated to be adequate.
General Conclusions and S ecific Findin s
Si nificant Safet Matters:
None Summar of Violations:
Summar of Deviations:
0 en Items Summar
2 Non-Cited Violations (Units 2 and 3)
None 10 items closed, 3 items left open, and 1 new item opene DETAILS Persons Contacted:
The below listed technical and supervisory personnel were among those contacted:
Arizona Public Service Com an (APS)
"R. Adney, J. Bailey, B. Ballard,
- R. Bernier,
"H. Bieling, M. Conway,
- E. Dotson,
~R. Flood,
"R. Fullmer,
"D. Gouge,
- S. Guthrie,
- R. Henry, P.
Hughes,
"M. Ide,
"S. Kanter, F. Larkin,
.
J.
Levine,
~J. Napier,
- G. Overbeck,
- M. Radoccia,
"R. Rouse, G. Shanker, Plant Manager, Unit 3 Vice President, Nuclear Safety 8 Licensing equality Assurance, Director Licensing, Supervisor Emergency Plan/Fire Prevention, Manager Executive Vice President - Nuclear Engineering
& Construction, Site Director Plant Manager, Unit 2 suality Audits and Monitoring, Manager nit Operations, Manager (Ch. Plant Review Bd)
equality Assurance, Deputy Director Salt River Project, Site Representative Site Rad. Protection, General Manager Plant Yianager, Unit 1 Participant Services, Sr. Coordinator Security, Manager Vice President, Nuclear Power Production Compliance, Lead Technical Support, Site Director Site Nuclear Engineering Dept.,
Manager Compliance, Supervisor Commitment Management Project 2.
The inspectors also talked with other licensee and contractor personnel during the course of the inspection.
- Attended the Exit meeting held with the NRC Resident Inspectors on December lg;.1990.
Previousl Identified Items - Units 1
and 3 (92701 and 92702)
Unit 1 a.
(Closed)
Enforcement Item (528/89-56-08):
"Steam enera ors o
rove e
s ro en ver ressure and Re uired am sn o
one
-
nl s
an Chemistry Control Instruction (CCI)89-158 authorized the removal of nitrogen overpressure for the Unit 1 Steam'enerators (SG) during the period in question.
However, sampling capability was not restored to both Unit 1 SGs until November 19, 1989, almost three weeks after the licensee had identified the need to sample the SGs.
In Unit 3, an
b.
C.
authorized variance from the overpressure requirement had expired and had not been renewed as required.
The licensee has implemented several corrective actions.
These include:
improved work scheduling, involvement of chemistry personnel in outage planning, and enhanced procedural guidance for waiving sampling requirements.
Additionally, an evaluation of the effects of opening the steam generators without the nitrogen oyerpressure was performed, which concluded that no adverse safety effects had resulted.
The inspector concluded that the licensee's corrective actions were adequate.
This item is closed.
(Closed)
Enforcement Item (528/89-56-11):
"Diesel enera or eismic a
rea enin s
-
ni 702)
This violation resulted from inadequate corrective actions following identification of openings in the seismic gap area between the Diesel Generator Building and the Control Building of each unit.
The original problem was identified in LER 528/85-096 (issued on January 27, 1986)
and additional openings were not identified until October 23, 1989.
The inspector reviewed the licensee's conclusions regarding the cause of the inadequacy, which included difficulty in inspecting due to limited accessibility, and poor communication between the original civil and mechanical designers.
The corrective actions following the discovery of additional openings appeared adequate.
These actions included:
establishment of -stationary fire watches, modifying the plant design and sealing the penetrations, revising drawings, reinspecting the walls, and revising the fire barrier procedure to expand the scope of barrier inspections and to provide acceptance criteria for the inspection.
'he inspector concluded that licensee actions were adequate with respect to this deficiency.
This item is closed.
(Closed),Followu Item (528/90-28-04): "Belleville S rin ac e axa ion in imi or ue o or era e
a ve.
c ua ors
-
ni The loss of preload in MOV actuators due to SPR has resulted in MOVs not developing sufficient closing thrust.
This item was opened to.track the licensee's review and evaluation of findings indicating that SPR was observed in several MOVs at Palo Verde.
The inspector reviewed Engineering Evaluation Request (EER) 90-XE-072, which documents the licensee's evaluation.
The licensee obtained information from other utilities and from Limitorque to supplement the data from its own monitoring program.
Additionally, a Nuclear Plant Reliability Data System (NPRDS) search was conducted, but with negative results.
The
licensee found that other utilities have also experienced similar problems.
Failures were potentially attributed to improper establishment of spring pack preload during initial installation, improper heat treatment of the spring packs during manufacture, and creep induced=by leaving the valves closed (spring packs compressed)
for extended periods of time.
An evaluation of previous spring pack problems at Palo Verde determined that only three of the ll identified problems could have been attributed to SPR or spring pack gap.
These HOVs have been baseline tested and trended in accordance with NRC Bulletin IEB 85-03.
The licensee has developed and implemented a method of monitoring for SPR without removal of the spring packs.
This involves determining the decrease in thrust developed for a constant spring pack compression between successive tests over a period of time.
Additionally, the licensee plans to purchase equipment which will allow determination of improper preload and trending of SPR when the spring packs are not installed in the actuators.
This equipment would be used prior to installation during MOV overhauls, and when trending indicates possible SPR.
The licensee plans to maintain its current schedule of MOV baseline testing with completion expected about June 1991.
Based on this review, this item is considered closed.
(Closed)
Unresolved Item (528/88-01-03):
"N ion Cable Ties" nl (0 en) Violation (528 529 530/90-36-01):
"Licensed 0 erator an e ica ecor s
-
ni s
ose o
owu em
icense era or e ica ecor s
-
ni The 1988 NRC Safety System Functional Inspection team identified concerns related to the use of nylon ties to support cables in vertical cable trays and the need for the licensee to perform an analysis for that application.
The licensee performed evaluations and analyses for the use of nylon cable ties and submitted the results to the NRC.
NRR reviewed and discussed the analyses with the licensee.
The NRR Safety Evaluation of the licensee submittals, forwarded to the license'e by letter dated August 16, 1990, concluded that the licensee's analyses of the nylon cable ties adequately addressed the concerns raised in the Unresolved Item and considered the use of nylon cable ties at PVNGS to be acceptable.
This item is closed.
an ose ecor s
-
ni icense era or e ica During an inspection performed from Hay 14 through Hay 18, 1990, documented in Inspection Report 528, 529, 530/90-16, an Inspector Followup Item was identified regarding the adequacy of licensed operator medical records.
Subsequently, on July
19, 1990, the licensee reported in LER 528/90-09 discrepancies with licensed operator medical records.
A subsequent NRC followup inspection from July 16 - August 7, 1990, identified violations regarding licensed operator medical records and resulted in the issuance, on September 26, 1990, of a Notice of Violation and Proposed Imposition of Civil Penalty.
Since the Followup Item and the LER involve the same issue as the proposed civil penalty, the Followup Item and the LER will be administratively closed.
NRC inspection of the identified licensed operator medical record discrepancies.will be performed during inspection of the licensee's corrective actions for the Notice of Violation and proposed civil penalty.
(Closed)
Followu Item, 528/90-15-02):
"Ade uac of ADV 0 eratin roce ures an rasnsn
-
nl I'his Followup Item related to inspector questions regarding the procedures for operating ADVs from the Control Room and from the Remote Shutdown Panel.
The Followup Item also identified questions'egarding the licensee Job Performance Measures (JPH)
used for training operators for operation of the ADVs from the Control Room and the Remote Shutdown Panel.
As followup, the inspector reviewed the 'following procedures and JPMs and had discussions with licensee Training Department personnel.
(1) 410P - 1SGOl, revision 9, Hain Steam System Operating Procedure (2) 41AO - 1ZZ44, revision 2, Shutdown Outside the Control Room Due to Fire or Smoke (3) JPH SG011-J-C/R-Ol, Operate the ADYs from the Control Room during a Loss of SBCS (4) JPH SG008-J-PLT-OO, Operate the ADV from the Remote Shutdown Panel The inspector determined that the procedures had been clarified in response to the inspector's questions, new JPMs had been issued, and retraining of the operators was being performed as part of the routine training cycle.
The new JPHs clarified mo'st of the inspector questions.
Discussions with the Training Manager indicated that additional changes would be made to prov>de for the remainder of the inspector questions.
Those changes were performed and the revised JPMs issued on November 27 and 29, 1990.
The inspector had no further questions regarding the ADV operating procedures and the training JPHs.
Th)s Followup Item is closed.
(0 en) Followu Item (528/90-15-01):
"Or anization and es ons>
> ies roce ure a es
-
n>
This Followup Item identified a need for a revision of licensee administrative procedures that delineate the various licensee
organizations and responsibilities to reflect organizational changes that occurred in 1989 and 1990.
During the current inspection, the inspector reviewed the administrative procedures noted by the followup item and determined that those procedures had been changed to reflect the organizational changes that had occurred as of the date of that inspection.
However, the inspector also noted that changes in both the Engineering and Nuclear Production organizations that had recently occurred (approximately one month ago) were still not reflected in the applicable administrative procedures.
The inspector discussed the need for the procedural changes with licensee management and was informed that the procedural changes were being processed and would be issued by December 31, 1990.
Pendinq further inspection of the administrative procedures to verify that the licensee organization and
'esponsibilities are reflected 'correctly )n the administrative procedures, this Followup Item is left open.
Unit 3 (0 en) Violation (530/90-08-02):
"Lack of Timel Com letion o
orrec
>ve c ion or no era e
mer enc
>
sn The subject violation identified that Unit 3 Emergency Light fixture 3E(BN002-G and Emergency Lighting inverter 3E(BN004 were inoperable and had not been promptly repaired or replaced.
APS letter 102-01674-WFC/TRB/JJN, dated April 20, 1990, responded to the Notice of Violation, provided the reasons for the violation, and the corrective actions taken for the violation.
The equipment problems were corrected and subsequently, the inverter was replaced.
The.NRC inspector, accompanied by a gC inspector, performed a
sampling inspection of similar emergency lighting fixtures and inverters in the Units 2 and 3 Auxiliary Building to assess the adequacy of corrective actions performed by the licensee.
Dunng the inspection, no obvious nonconforming conditions were noted,.Out the following observations were made.
(1)
The Halophane inverters (six in the Auxiliary Building of each unit) had a voltage indicator on the front panel of each inverter.
Host of the indicators showed a reading of approximately 28 volts.
Two of the six inverters in Unit 2 and one of the six inverters in Unit 3 showed a
noticeably lower reading of'pproximately 26 volts.
The NRC inspector questioned the 'tower voltage indication of the three inverters.
The inspector was conformed by gC, the System Engineer, and the responsible Nuclear Engineering Department engineer, that the voltage indicators on the front panels of the inverters were not calibrated indicators and that periodic preventative maintenance performed on the inverters by taking direct voltage measurements verified that correct voltages were
.0
A being maintained.
However, due to problems with emergency lighting in the recent past, the inspector requested that the voltages for the three inverters with noticeably lower indications be measured and the measurements by verified by gC.
The licensee determined that the correct voltages were in fact being maintained by the inverters in question.
(2)
The NRC inspector noted that approximately 50 percent of the emergency lighting fluorescent light fixtures in Unit 3 had black spots or rings in the ends of the tubes.
In comparison, Unit 2 emergency lighting fluorescent light fixtures had significantly less black spots or rings.
The inspector inquired as to the significance of the black rings and the difference between the two units.
System Engineers informed the inspector that the black rings were normal and generally appeared as the tubes aged.
The
"
difference between the two units were explained by the difference in the time of relamping of Unit 2 fixtures versus Unit 3 fixtures, in that Unit 2 was more recently relamped.
The inspector requested the System Engineers to confirm th6 significance of the black ring by either reviewing vendor literature or contacting vendor technical representatives.
The System Engineer contacted the light fixture vendor, Dependable Products, and confirmed that the black rings were normal as the fluorescent tubes aged.
However, the vendor also stated that the ballast for the fluorescent light fixtures had an effect on the life expectancy of the lamps.
The System Engineer was informed by the vendor that the lamps would not last the rated 48,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> if the ballast is older than 5 years.
The System Engineer informed the NRC inspector that emergency lighting fluorescent light fixture ballasts are usually onTy replaced when they show signs of being defective, that is lamps flicker or the ballast no longer performs its function.
The ballasts are not periodically replaced on a preventative basis.
The NRC inspector requested the licensee to review its emergency lighting preventative
.
maintenance program and determine its adequacy in relation to any preventative maintenance it may deem technically necessary for the ballasts.
Pending completion of the licensee review of preventative maintenance requirements in relation to the adequacy of "
ang necessary preventative measures for fluorescent light fixture ballasts, the violation was left open.
3.
Review of Plant Activities (71707 and 93702)
a.
Unit 1 Unit 1 was maintained at essentially 100 percent power throughout'his report period, except for a brief downpower to about 64 percent on November 24, 1990, to allow repairs to the
Train "B" main feedwater pump speed sensors and an isophase duct fan.
b.
Unit 2 Unit 2 maintained approximately 100 percent power throughout, the report period with the exception of a-brief downpower to 76 percent on November 24 1990, due to a Core Operating Limits Supervisory System (COLSS) malfunction.
This is described in more detail in Paragraph 13 of this report, which also deals with a similar Unit 3 event.
c.
Unit 3 Unit 3 operated at approximately 100 percent power throughout this report period.with the exception of a brief downpower to 79 percent on November 26, 1990, due to a COLSS malfunction.
This is described in more detail in Paragraph 13 of this report.
d.
Plant Tours The following plant areas at Units 1, 2 and 3 were toured by the inspector during the inspection:
Auxiliary Building Control Complex Building Diesel Generator Building Radwaste Building Technical Support Center Turbine Building Yard Area and Perimeter The following areas were observed during the tours:
l.
0 eratin Lo s and Records - Records were reviewed against ec naca peer
>ca )on and administrative control procedure requirements.
2.
Honitorin Instrumentation - Process instruments were o serve or corre a son etween channels and for conformance with Technical Specification requirements.
3.
Shift Staffin
- Control room and shift staffing were o serve or conformance with 10 CFR 50.54.(k), Technical Specifications, and administrative procedures.
4.
E ui ment Lineu s - Various valves and electrical breakers were vers se o be in the position or condition required by Technical Specifications and administrative procedures for the applicable plant mode.
5.
E ui ment Ta in - Selected equipment, for which tagging reques s
a een initiated, was'observed to verify that
7.
8.
9.
10.
tags were in place and the equipment was in the condition specified.
General Plant E ui ment Conditions - Plant equipment was o serve or in >ca
>ons o
sys em leakage, improper lubrication, or other conditions that would prevent the systems from fulfillingtheir functional requirements.
Fire Protection - Fire fighting equipment and controls f
fttf tt Specifications and administrative procedures.
Plant Chemistr
- Chemical analysis results were reviewed or con ormance with Technical Specifications and administrative control procedures.
Securit
- Activities observed for conformance with regu a ory requirements, implementation of the site security plan, and administrative procedures included vehicle and personnel access, and protected and vital area integrity.
Plant Housekee in - Plant conditions and ma erma equspmen storage were observed to determine the general state of cleanliness and housekeeping.
Radiation Protection Controls - Areas observed included con ro porn opera ion, records of licensee's surveys within the Radioloqical Controlled Areas (RCAs), posting of radiation and hsgh radiation areas, compliance with Radiation Exposure Permits, personnel monitoring devices being properly worn, and personnel frisking practices.
The inspector observed continued evidence of cigarette smoking in the RCA (Unit j. Auxiliary Building Roof).
While exiting the RCA of Unit 1 on two occasions, the inspector alarmed the PCH-1B several times.
In both cases, the Radiation Protection (RP) technicians failed to respond to the alarms.
- The inspector brought these facts to the attention of the RP technicians at the RP island and to RP management, and the licensee counselled the RP technicians on that shift.
No violations of NRC requirements or deviations were identified.
4.
En ineered Safet Feature S stem Walkdowns - Units 1 2 and
Selected engineered safety feature systems (and systems important to safety) were walked down by the inspector to confirm that the systems were aligned in accordance with plant procedure During this inspection period the inspectors walked down accessible portions of the following systems.
Unit j.
o Essential Cooling Mater "A" and "B" Unit 2 o
None Unit 3 o
Essential Cooling Mater "A" and "B" No violations of NRC requirements or deviations were identified.
5.
Monthl Surveillance Testin
- Units 1 2 and 3 (61726)
a.
Selected surveillance tests required to be performed by the Technical Specifications (TS) were reviewed on a sampling basis to verify that: j.) the surveillance tests were correctly included on the facility schedule; 2)
a technically adequate procedure existed for performance 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.
Specifically, portions of the following surveillances were observed by the inspector during this inspection period:
Unit 3 P
d
.
~0iti o 73ST-9ZZ21 Visual Snubber Inspections Unit 2 Procedur'e o None Descri tion Unit 3 P
d
~lofti o 43ST-3DG01 Diesel Generator
"A" Test o 43ST-3DG02 Diesel Generator
"B" Test o 31ST-9DGOl Diesel Generator 18 Month Inspection No violations of NRC requirements or deviations were identifie.
Monthl Plant Maintenance - Units 1 2 and 3 (62703)
a.
b.
During the inspection period, the inspector observed and reviewed selected documentation associated with maintenance and problem investigation activities listed below to verify compliance with regulatory requirements, compliance with administrative and maintenance procedures, required equality Assurance/equality Control involvement, proper use of safety-tags, proper equipment alignment and use of jumpers, personnel qual)fications, and proper retesting.
The inspector verified that reportabi lity for these activities was correct.
Specifically, the inspector witnessed portions of the following maintenance activities:
Unit 1 Descri tion o
Troubleshoot
"A" Plant Protection System Low Pressurizer Pressure Operational Bypass Relays o
Troubleshoot and Rework Essential Chiller "B" Hot Gas Bypass Actuator o
Repair Refrigerant Leak on Essential Chiller "B" Compressor
"C" phase terminal Unit 2 Descri tion o
Troubleshoot Auxiliary Feedwater Pump Room Flooding Alarm Switches Unit 3
~Di ti o
Reinstallation and Melding on Diesel Generator Jacket Mater Supports No violations of NRC requirements or deviations were identified.
7.
Auxiliar Buildin Floor Drain Backfloodin
- Unit 1 (92700)
On November 26, 1990
'
gasket failed in the pre-action sprinkler station for the Auxi]iary Building 100 foot elevation west side.
The flooding which ensued exceeded the capacity of the non-Engineered Safeguard Features (non-ESF)
sump pumps, resulting in the water backing up in the floor drains, flooding portions of the 40 foot, 51 foot, and 88 foot elevations of the Auxiliary Building with contaminated water.
The 70 foot elevation was unaffecte Radiation Protection (RP) personnel posted the areas affected and commenced decontamination efforts.
On November 27, the inspector observed an RP Technician performing a
direct frisk of the floor of the 51 foot elevation, outside the remaining posted Contamination Area (CA).
The Technician identified a spot on the floor reading approximately 20,000 disintegrations per minute (dpm).
The contamination was difficult to remove because it was in a small defect in the floor coating, however subsequently the decontamination was successful.
The licensee also found and removed a 500,000 dpm hot particle (0. 19 uci of Cs-134 and Cs-137)
nearby, also outside the posted CA.
Both of these were considered fixed contamination.
An RP Night Order is being issued to institute a
new requirement to perform direct frisking of floors prior to the release (deposting)
of contaminated areas.
'This policy applies to corridors and other open areas where background radiation permits the use of frisking equipment, and is being implemented as a pilot program in Unit 1 only because of the higher incidence of foot contaminations in Unit 1.
The licensee plans to acquire floor frisking equipment to f'aci litate this new task.
The licensee is also evaluating the floor drain system to determine if changes in the design are warranted to prevent recurrence of the backf 1 ooding.
The inspector inquired if the licensee's internal flooding analysis addressed the worst case fire header pipe break in the Auxiliary Building.
The licensee had an engineering calculation which showed that flooding from a shear of the six-inch fire header (the largest in the area)
would not affect safety equipment on any elevation of the building.
Drain capacity was considered in the calculation.
The inspector noted that the gaskets in some of the pre-action stations are aligned so that water spray from a leaking gasket could impinge on the Containment Hydrogen Analyzers, which are in non-water tight cabinets approximately 30 feet away.
The "8" Hydrogen Aqalyz'er appears the most vulnerable.
This observation was discussed with the licensee's engineering staff.
The inspector concluded that the licensee's actions in response to this event were appropriate.
No violations of NRC requirements or deviations were identified.
Essential Chiller Ino erable
.Due to Low Freon Level - Unit 1 On November 10, 1990, the "8" Essential Chiller (EC "B") tripped on low refrigerant temperature during the performance of a surveillance test.
The chiller was found to have a low refrigerant (freon) level caused by a valve, which apparently had been inadvertently bumped and left partially open, allowing refrigerant to drain back to the
9.
storage tank.
The chiller was declared inoperable, and freon was added to restore the level to the normal band.
After a test run, the chiller was declared operable.
Additionally, a comment in the Area 5 Auxiliary Operator (AO) logs for that day indicates that the freon level is to be checked and maintained between 4-7/8 inches and 6-1/8 inches.
On November 13, 1990, the inspector observed that the freon level on EC "B" was 6-7/8 inches, outside the band noted above.
After bringing this to the attention of the Shift Supervisor, the inspector noted that the AO on-shift was unaware of the specified band, though the level was being logged in the comment section of the logs.
The Operations Manager informed the inspector that he had directed that the freon level band not be implemented or turned over to other operators because the information did not come from a qualified source.
Freon levels are not normally checked as part of Auxiliary Operator.
(AO) rounds.
The licensee has found that many variables affect the freon level, so that evaluating the observed )eyels is difficult unless controlled steady state conditions are first established.
This approach is in place, in that a weekly Preventive Maintenance (PM) task is performed to establish the conditions and adjust the levels as necessary.
'hile an operating band has been established, the licensee does not declare the chiller inoperable when the levels are outside of the band.
The licensee has not established freon levels above or below which the chiller is inoperable.
Technical concerns justify that levels must remain in a specific range for the chiller to perform its design function.
The licensee has committed to establishing these operability limits as they, apply to the conditions during the PM (EER 90-EC-31).
In addition, the licensee is removing the, handwheel from affected valves to minimize the risk of inadvertent opening.
This event is an Unresolved Item pending further review (528/90-46-01).
No violations of NRC requirements or deviations were identified.
Ina ro riate Surveillance Test (ST Acce tance Criteria-nl On November 13, 1990, the newly established acceptance criteria for differential pressure (DP) across spring loaded check valve 1CH-PDV-240 in the charging system could not be met during the performance of Surveillance Test (ST) 41ST-lCH06, "Charging Pump Operability Test."
The measured DP was 198 psid and the Surveillance Test procedure criteria was 200 psid.
Therefore, in accordance with procedural requirements both auxiliary spray valves were declared inoperable at 2:45 AH (NST), and the Action Statement for Technical Specification (TS) 3.4.3.2 was entered.
This TS Limiting Condition for Operation allows this condition to exist for six hours, and requires the plant to shutdown to Mode 3 in the next six hours.
The valves were declared operable eight hours later at 10:35 AM.
Power was not decreased because of licensee management
confidence of the imminent resolution of the problem.
The ST requires the OP to be greater than or equal to 200 psid as measured by the control board indication (1CH-POIC-240), which has a range of 0-200 psid and an instrument loop accuracy of four percent.
The licensee used higher accuracy instrumentation to obtain greater resolution and determined that a more accurate OP of 205 psid existed.
The ST was then satisfactorily completed.
In conjunction with this, the licensee's engineering staff determined in Engineer Evaluation Request (EER) 90-CH-127 that a
OP as low as 180 psid was acceptable to meet design criteria.
The 200 psid acceptance criteria had been established based on an Instruction Change Request (ICR) resulting from the disposition of EER 90-CH-064.
This EER evaluates the potential degradation of auxiliary spray flow due to potential leakage past air operated valves CHE-HV-0239 and CHE-PV-0240 under design bases conditions.
As part of this evaluation, the licensee determined that a
OP of at least 200 psid with two charging pumps running will ensure that sufficient charging flow will be delivered to the auxiliary spray header despite potential leakage past the valves in question.
A new System Engineer (SE) was assigned to this system while this EER was still open, and he apparently misunderstood the intent of this value in that he thought it was a minimum acceptable value, rather than merely an acceptable value.
The SE then initiated an Instruction Change Request (ICR) to revise the ST procedure to add this as a new acceptance criteria.
This misunderstanding was not identified during review of the EER or ICR by engineering supervision.
The Standards department, which implements procedure changes, confirmed the intent of the change with the SE, and then implemented the change after a required review for changes affecting the acceptance criteria for STs.
The proposed change was not walked down in the field or "dry run" to confirm its quality.
Following the event, Problem Resolution Sheet (PRS)
1366 was initiated by the licensee.
The inspector concluded that an incomplete turnover of SE responsibilities and inadequate technical reviews of this EER and ICR contributed to this event.
Additionally, the failure of the SE or Standards representative to field check the proposed change prior to implementation apparently contributed to the event, underscoring the potential benefits which could be realized by these support personnel performing physical in-plant verifications prior to initiating or implementing procedure changes.
The licensee acknowledged these comments and agreed this activity should have Seen better performed.
No violations of NRC requirements or deviations were identified.
10.
Im lementation of Com ensator Measures for Auxiliar Feedwater oom a er i
oor e scsenc)es
-
ni Material Non-conformance Report (MNCR) 90-FP-70 was issued to document insufficient water tight door sealing due to damaged dogs.
On November 27, 1990,'
dispos)tion to the MNCR was issued which
0
identified actions which were necessary until the doors were fully repaired.
These were:
(a)
When an auxiliary feedwater pump room flood level detector alarms in the control room, operations shall identify and isolate the flood source to stop the flow of water within 30 minutes; (b)
In the event of a room sprinkler activation, fire department personnel or operations shall turn off the sprinklers within 30 minutes; and (c)
Functionally test the four flood level detectors (RDNLSH131, RDNLSH11132, RDNLSHH133 and RDNLSHH134) or provide a roving compensatory flood watch at least every 60 minutes.
The Unit 2 Nipht Order implementing the above compensatory measures omitted item c" above due to its omission in the draft HNCR.
Unit 3 corrected the error in their night order, but did not notify Unit 2 of the apparent omission.
Unit 1 also retained the error in their night order.
The inspector commented that generic night orders appear to need stronger control to ensure accuracy and consistency between units.
The inspector also noted that Units 1 and 2 failed to correct the error resulting in initial confusion for a Unit 2 Shift Supervisor
's he tried to determine the required compensatory measures.
The inspector did not identify any occasion where the provisions of item
"c" were not met, and confirmed in Unit 2 on November 29 that the roving watch was posted.
The licensee acknowledged the need to improve generic unit Night Orders.
In addition, the inspector noted that the licensee's'unctional check of the flood level detectors revealed that several would not operate due to needing mechanical adjustments.
The inspector determined that the switches had been removed from the Preventive Maintenance (PM) checks since 1986.
Licensee management indicated that they we'e currently evaluating restoring these non-class switches to the PM program and were also including other flood warning devices in their review.
The inspector concluded that-this was appropriate.
No violations of NRC requirements or deviations were identified.
Control Room. Essential Filtration Actuation S stem (CREFAS)
nl la ion nl On November 13,.1990, both trains of CREFAS initiated during
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erformance of SnrveIll ance Test (ST) 36ST-9Sik01,
"Radiation onitoring Monthly Functional Test Procedure.'tep 8.3.9.2 of this procedure requires Operations to restore BOP-ESFAS channel
"A" to the desired operating configuration per an operations procedure, 420P-2SA01, which requires that the operator reset the trip signal prior to removing the channel from bypass.
The Operator performing
this task failed to reset the "trip/reset" signal in accordance with the procedure, so that CREFAS initiation occurred when channel
"A" was removed from bypass.
The CREFAS was then bypassed and reset before all required safety equipment had actuated.
The licensee therefore reset all equipment and reinitiated the CREFAS from the Balance of Plant Engineered Safeguard Features Actuation (BOP ESFAS)
"A" cabinet, and confirmed that all required components actuated.
The inspector observed this CREFAS re-initiation.
Problem Resolution Sheet (PRS)
1401 was initiated as a result of this event and the licensee ss preparing a Licensee Event Report (LER) as required.
The inspector will review the LER when submitted.
The operator was counseled and the licensee intends to route the LER to all operators when complete.
These corrective actions appear appropriate.
Although the failure to follow procedure is considered a violation of NRC requirements, this licensee-identified violation is not being cited because the criteria specified in Section V.G. of the Enforcement Policy were satisfied.
Inade uate Meldin on Su orts for Emer enc Diesel Generator oo sn snes -
ns s
an On November 8, 1990, the licensee identified cracks in fit-up tack welds in supports for the diesel generator jacket cooling water return header of the diesel generators in Unit 3 at Palo Verde.
The cracks were observed by the licensee during maintenance activities.
The cracks were at the top of the supports and in both diesel generators "of Unit 3.
The licensee also performed inspections of the diesel generator support welds for the Unit 1 and 2 diesel generators.
Matenal Nonconformance Reports (HNCRs) were initiated on that day.
These welds appear to have been made by the diesel generator vendor, Cooper-Bessemer.
No detailed support drawing was found to indicate the required weld size or length necessary for these supports.
Vendor discussions indicated that earlier designs had specified intermittent welds and that current design called for fillet welds the full length of the support.
However, it was not clear what was required at the time the diesel generators were ordered for Palo Verde.
Licensee engineering analyzed the supports for the required weld size and length with support loads contained in the diesel generator seismic report.
The licensee's analysis showed the following:
o The required weld was a 1/4" fillet weld, 3" in length on each ssde of the support at both the top and bottom ends.
o The supports (with tack welds) in both diesel generators in Unit 3 and the supports for the Unit 2 Train "A" diesel generator were structurally inadequate.
o The supports in both Unit 1 diesel generators and the Unit 2 Train "B" diesel generator were structurally adequat By approximately 10:30-PH on November 10, 1990, all deficient welds on the supports had been repaired.
During the course of this issue, the licensee has provided reports to the HRC as required by 50.72.
The licensee has been in communications'ith the vendor and has emphasized Part 21 reportinq requirements.'n addition, the licensee has provided notif>cation of this support issue with the Cooper diesel generator owners group.
A combined LER/Part 21 report was submitted to the NRC on December 7, 1990.
The inspector concluded that the Unit 2 Train "A" Emergency Diesel Generator (EDG) and both Unit 3 EDGs jacket cooling water return header supports had not met seismic qualification requirements since installation.
However, this licensee-identified violation is not being cited because the criteria in Section V.G. of the Enforcement Policy has been met.
While engineering analyses were being performed to determine the roper size and length of weld required for the supports, the icensee took the Unit 2 Train "B'DG out of service to perform weld repairs from approximately 9:30 PH on November 9 to 1:00 AM on November lg.
The inspector noted that the Engineering Evaluation Department (EED initiated an NNCR which resulted in declaring Unit 2 Train "A'DG inoperable at 7:24 AN on November 1D, 1990, and was based on an engineering analysis performed by the Site Nuclear Engineering Department (SNED), which was completed around midnight of that morning.
The inspector questioned the reason for the delay in issuinq the HNCR and determined that EED had taken the lead responsibility by verbal agreement with SHED.
Thus, SHED did not take direct action (initiating an MNCR) based on their analysis.
The inspector concluded that because of the short time interval of only a few hours and prompt EED action to field check the analysis prior to issuing the MNCR, this was an acc'eptable justification:
The inspector noted, however, that such verbal agreements to designate responsibIlity for implementing corrective action documents is not accounted for in licensee procedures and encouraged the licensee to consider ways to ensure this responsibility is maintained:
Licensee management acknowledged these comments at the exit meeting No violations of NRC requirements or deviations were identified.
Core 0 eratin Limits Su ervisor S stem (COLSS) Out-of-Service on
sons -
nl s
- an Units 2 and 3 both experienced sudden COLSS out-of-service conditions three days apart.
The apparent differences in the way each of these events was handled by the licensee pointed out the need for greater consistency in the way operators determine the va1idity of COLSS outputs and apply the appropriate Technical Specifications (TS).
COLSS is a computer program whose principle outputs provide limiting values of operating parameters which operators are required by TS to
maintain, such that the initial conditions for any analyzed accident will be within those conservatively assumed in the safety analysis.
The TS limitations on these parameters are given in TS 3.2. 1 for Linear Heat Rate, TS 3.2.4 for Departure from Nucleate Boiling Ratio (DNBR), TS 3.2.3 for Azimuthal Tilt, and TS 3.2.7 for Axial Shape Index (ASI).
In general, at 100 percent reactor power, the plant operates closest to the DNBR limit. If COLSS -is suddenly determined to be out-of-service with the plant at 100 percent power steady state, the minimum DNBR specified by TS 3.2.4 for this condition will not be met and plant power must be lowered until compliance with this more restrictive limit is achieved.
It is expected that subsequent fuel reloads and fuel configurations will not alter the need to reduce. power under these conditions.
However, at certain initial power levels less than 100 percent, and dependent upon the value of ASI, if COLSS were to go out of service, the TS requirement could already be met and a power change would not be required.
The inspector noted the following:
o COLSS does not have specific TS operability requirements or attendant surveillance requirements, yet operators may be required to take action specified by TS when COLSS is out-of-service.
Operators commonly refer to this condition as COLSS being "inoperable."
There is no definitive criteria, short of a clear system failure, which operators can rely upon to judge whether COLSS is out-of-service or not.
o The action requirements of TS 3.2.4 are to initiate action to increase DNBR (decrease reactor power) within 15 minutes and to meet a more restrictive minimum DNBR within one hour.
This action is invoked by:
1) recognition that COLSS is out-of-service and 2) determination that the more restrictive DNBR limit is exceeded.
However, when power is initially 100 percent, operators appear to inconsistently start the 15 minute and one hour clocks either when COLSS is found to be out-of-service or only when DNBR limits are formally determined to be exceeded.
o Survei.llance Procedure 7XST-XRXG3 is initiated during COLSS out-of-service conditions to formally determine and meet the specified TS limits on Linear Heat Rate (LHR), DNBR, Azimuthal Tilt (AZTILT), and Axial Shape Index (ASI).
Based on
.discussion with operations staff, it takes approximately five to ten minutes to perform RX03 to where non-compliance with the TS Limiting Conditions for Operation (LCO) is "formally" revealed.
o The differences between the Unit 2 event of November 24 and the Unit 3 event of November 26 illustrate that the expected response to COLSS problems is neither clear nor are the actual responses consistent:
1)
Unit 2 declared COLSS inoperable immediately upon noting a computer malfunction.
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2)
Unit 3 took approximately 25 minutes of discussion time following a COLSS alarm prior to declaring COLSS inoperable, and uncertainty still existed as to COLSS status at that time.
The time of "inoperability" was first made to be the initial alarm time.
Later, this time was changed by a log entry to be 25 minutes after the alarm, and was made after considerable discussion between the Shift Supervisor, Unit 3 operations management, and the inspector.
Unit 2 entered TS action 3.2.4.2.a, which allows one hour to achieve the LCO limit, at the tsme COLSS was declared inoperable.
Unit 3 enteied TS action 3.2.4.2.a after verifying DNBR to be outside acceptable TS LCO limits.
Both the Unct 2 and Unit 3 actions were considered by the inspector to be acceptable to meet TS requirements.
o The inspector further noted that Unit 3 entered action 3.2.4.2.a on the basis of verifying DNBR to be outside LCO limits, but without having completed an RX03 data entry for DNBR.
In addition, both Units j. and 3 power reductions were halted on the basis of control board indication of DNBR and prior to documentation of LCO compliance using RX03.
Based on the above, the inspector concluded the following.
1)
2)
3).
The licensee has no specific criteria to aid the operators in determining COLSS ability to meet the TS definition of being "in service."
Uncertainty of the validity of COLSS outputs existed in Unit 3 for 25 minutes before an operability decision was made.
The point of entry into TS action 3.2.4.2, and thus the initiation of both the 15 minute and one hour time clocks is not consistent.
The licensee has no written guidance to'pecify that the entry should be; a) when COLSS is declared out-of-service, or b) when operators have recognized by control board indication that DNBR limits are not met with COLSS out of service, or c) when RX03 is completed to the point of documenting that DNBR LCO limits are not met.
One Operations Supervisor stated that the LCO entry may be delayed until RX03 documents the out-of-specification condition.
However, other licensee management later stated the APS position that the action statement should be entered whenever COLSS is declared
"inoperable."
Such guidance may be complicated by initial power conditions other than 100 percent, which may not require a power reduction.
Furthermore, action required by the LCO {power reduction)
was stopped prior to an RK03 determination that the LCO was met in both cases.
The inspector considered that if
the licensee's policy allows delay of action statement entry until RX03 documentation is made, then it should also require RX03 documentation to exit the action statement.
The licensee committed to change RX03 and the alarm response procedure to provide better clarification on how to address COLSS, out-of-service conditions.
Further, the licensee initiated IIR 3-3-90-017 to better establish COLSS out-of-service criteria for use by operations staff.
No violations of NRC requirements or deviations were identified.
14; Review of Licensee Event Re orts - Units 1 2 and 3 (90712 an
)
The following LERs were reviewed by the Resident Inspectors.
Unit 1 a.
528/90-10-LO (Closed)
"En ineered Safet Features Actuation ause a i ra son e
mission n
or ocumen
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nest
b.
This event was described in Inspection Report 528/90-45 (Paragraph 9) and involved a containment purge isolation.
This LER provides results of the Root Cause of Failure (RCF)
evaluation performed by the licensee.
The RCF was determined to be incomplete calibration of the power supply for the Remote, Indicating Controller due to the omission of the appropriate steps in the Mork Order (MO).
The WO, performed in December 1989, lacked steps for the adjustment of the overcurrent potentiometer during the initial installation of the power supply.
These steps were in Preventive Maintenance Task 020403, portions of which were extracted to develop this MO.
The correct'ive actions, as documented in the LER, appear appropriate and adequate.
528/89-02-LO and -Ll (Closed)
"Non-uglified Com onents ns a
e on s
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nl The subject LER reported that on March 30, 1989, non-envir onmenta1ly qualified pressure gages were found installed on the positioners for the Atmospheric Dump Valves (ADV's) in Units 1, 2, and 3.
The LER further stated that the gages appeared to have been on the positioners since the positioners were originally placed in service.
The licensee's investigation of the condition determined that the non-qualified gages were supplied with the ADYs and the positioners, and with vendor instructions to replace the gages with pipe plugs upon installation of the positioners.
The
investigation further determined that a design change package had been issued to perform the work but had been erroneously signed off without all work being completed.
As corrective action, the licensee replaced the unqualified gages with appropriately qualified plugs.
In addition, the licensee performed a gA review of design change packages and procedures and ascertained that the reported condition was an isolated case.
The corrective actions were performed in conjunction with Restart Item No.
673 for each unit.
The NRC reviewed the problems encountered during the March 3, 1989, Unit 3 Unusual Event, including problems associated with the ADVs, during an Augmented Inspection Team inspection (Inspection Report 528, 529, 530/89-13)
and numerous subsequent follow-up inspections.
In addition, inspections of restart items for each of the units were also performed to ascertain completion of corrective actions and readiness for restart of each of the units.
The licensee's action for this LER appears to be appropriate and the LER is closed.
Unit 2 a.
529/90-ll-LO (Closed) "Inadvertent Control Room Essential ra ion n sneere a
e uar ea ures c sva son
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ns This event is described in this report in Paragraph ll.
The corrective actions described in the LER appear adequate.
The item is closed based on the above review.
15.
Exit Meetin (30703)
The inspector met with licensee management representatives
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eriodically during the inspection and held an exit meeting on ecember 10, 199 r