IR 05000528/1988025
| ML17304A372 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 08/11/1988 |
| From: | Burdoin J, Coe D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17304A370 | List: |
| References | |
| 50-528-88-25, 50-529-88-24, 50-530-88-23, IEB-87-001, IEB-87-1, NUDOCS 8808300181 | |
| Download: ML17304A372 (13) | |
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos.
50-528/88-25, 50-529/88-24, 50-530/88-23 Docket Nos.
50-528, 50-529, 50-530 License Nos.
NPF-41; NPF-51, NPF-74 Licensee:
Arizona Nuclear Power Project P.
O.
Box 52034 Phoenix, Arizona 85072-2034 Facility Name:
Palo Verde Nuclear Generating Station (PVNGS) Units 1, 2 and
Inspection Conduc d:
u
988 t ough July 22, 1988 Inspector:
do n, Pr ect I pector D te Signed D.
H.
Co
, Reactor Inspector Approved by:
S.
Richards, Chief, Engineering Section D t Signed s (iiss Date Signed
~Summar:
Ins ection on Jul
1988 - Jul
1988 Re ort Nos.
50-528/88-25 50-529/88-24 and 50-530/88-23 Areas Ins ected:
An unannounced inspection by two regional inspectors of various vital areas and equipment in the plant, and follow-up of enforcement items, open items, and bulletins/notices/Part 21.
Inspection Procedures Nos.
71707, 25020, 25585, 92701, 92702, 92703, and 30703 were used as guidance for the inspection.
Results:
No violations or deviations were identified.
The licensee s
corrective measures for enforcement items and actions on follow-up items were appropriate, well documented and adequate.
8808300 5OPO528 8SOSi2 pDR ADOC~
O pv G
DETAILS
'.
Persons Contacted The below listed technical and supervisory personnel were among those contacted:
Arizona Nuclear Power Pro 'ect ANPP
"B. Albert, Licensing Engineer
"J. Allen, Plant Manager, Unit 1
~T. Cotton, Assistant Manager, Training N. Hallas, Operations Engineer
"J.
Haynes, Vice President, Nuclear Production
"W. Ide, Plant Manager, Unit 2
- L. Johnson, Nuclear Safety Engineer S. Karimi, Compliance Engineer M. Lantrip, Senior Mechanical Engineer J.
Quan, Licensing Engineer
"K. McCandless-Clark, Compliance Engineer D. Nichols, Supervisor, General Training
.
"A. Rogers, Manager, Licensing
"T. Shriver, Compliance Manager
"L. Souza, QA/Quality Audits 8 Monitor ing J.
Summy, Systems Engineer
- 0. Zeringue, Plant Manager, Unit 3 The inspector also talked with other licensee personnel during the course of the inspection.
"Attended the Exit. Meeting on July 22, 1988.
2.
Area Ins ection 71707 An independent inspection was conducted in the Unit 1 Containment, and Control and Auxiliary Buildings.
The inspector examined areas and equipment for debris, potential hazards, oil and water leakage, and equipment condition, e.g., oil level, valve position, and electrical connection configuration and cleanliness.
The equipment and areas inspected included:
A. -
Two 4160/480V switchgear rooms (trains A and B).
B.
Four 125 V battery rooms.
C.
Four battery equipment rooms.
D.
Inside Containment, Elevations 80', 100', 120'40'nd over steam generator No.
2.
E.
Control Room.
Housekeeping and equipment status appeared to be acceptable.
No violations or deviations were identifie.
Follow-u of Enforcement Items 92702 Closed 50-528/88-01-19 Electrical Panel Fasteners Missin During the safety system functional inspection conducted in January/
February 1988, vital static inverters had 9 of the 19 thumb screws missing from the front panel on 1EPNDN14 and 12 of the 19 thumb screws missing from the front panel on 1EPKDN44.
An investigation of this incident by the licensee did not identify a cause for the missing thumb screws.
A walkdown was conducted and work order 273654 was issued to replace mi.ssing thumb screws on the inverters 1EPNDN14, lEPKDN44, 1EPNAN11, 1EPNBN12, 1EPNCN13, and 1EPKCN43.
Corrective action to prevent recurrence of this type violation include two parts.
1)
The work control process is being revised to require that items, with obvious physical deficiencies, requiring maintenance be visibly marked, where possible, to clearly indicate that the discrepancy has been identified and the appropriate document initiated to correct the discrepancy.
2)
A procedural guidance is being developed which will establish guidelines for maintenance activities.
This guidance will address issues such as post maintenance clean up and ensuring that upon completion of a maintenance activity items such as cover plate screws are properly replaced or deficiencies reported.
In order to ensure the proper significance is placed upon this document it will be issued as an approved procedure.
To verify the licensee's corrective actions, the inspector examined the completed work order (273654),
and inspected in the field the.six above identified vital static inverters to ensure that the required thumb screws were in place.
The licensee's corrective actions in response to this violation appear to be adequate to achieve compliance.
This item is closed.
No violations or deviations were identified.
Follow-u of Previous Identified Ins ection Items 92701
/
A.
Closed 50-528/87-37-09 0 en 50-529/87-36-09 and Closed 50-530/87-38-09 E
Trainin Pro ram at the Plant Site I
The,Eg inspection team examined the Eg training program for electrical and instrumentation and control (I8C) maintenance personnel at the plant site, and found the program to be sketchy and undocumented.
The inspector reviewed this item with the licensee's supervisor of general training at the site.
The onsite Eg training program is presently being reviewed and revised to upgrade and formalize the program.
The licensee expects to have this program in place by
Jan'uary, 1989.
The actions proposed by the licensee appear adequate to correct this area of weakness.
This item is closed for Units 1 and 3, but remains open for Unit 2.
The status and actions for Unit 2 will be reported in a future inspection report.
Closed 528/87-26-01 Low Pressure Safet In ection Pum Seal Failure On July 4, 1987, the Unit 1 reactor was in Mode 4 at 330 degrees F
and being cooled by the Train "A" low pressure safety injection pump (LPSI) through the shutdown cooling (SDC) system.
The pump's mechanical seal failed and resulted in a pump trip.
The Train "B" LPSI pump was placed in service and subsequently developed an approximately 1 gpm seal leak.
Following completion of the cooldown, the licensee conducted an investigation into the nature of these failures.
On July 15-17, NRC Region V inspectors reviewed the licensee's progress and learned that the "A" train LPSI pump mechanical seal shaft packing "0" ring had swollen and the seal faces were found to be worn and chipped.
The "B" pump was not yet disassembled during this inspection.
The licensee was investigating two possible seal failure mechanisms:
1) operation at temperatures greater than 300 degrees F,
and 2) use of metal cleaning solvents which contain petroleum derivatives.
Because the analysis was not complete by the end of the inspection, this item was left open for further follow-up.
Subsequent to the above inspection, the licensee received the results of a chemical analysis of the "A" train LPSI pump "0" rings and, based on this analysis and their own tests, concluded that contact with residual cleaning solvent (trade name "Enviroguard")
had caused the swelling.
The specific mechanism for swelling appeared to be the absorption of petroleum derivatives present in the solvent.
The "B" train LPSI pump seal was disassembled and found to be leaking due to what appeared to be "dirty" seal faces.
The "0" rings were not found to be swollen or otherwise damaged.
The "dirt" was also present on the shaft sleeve area where it had adhered and caused a slight buildup.
Samples of this deposit were sent off-site for analysis and found to contain elements normally expected to be present in reactor coolant.
The only abnormality, a high calcium content, was attributed to contact with lagging during pump disassembly.
The inspector noted that the work practices used during pump disassembly apparently allowed entry of lagging dust into the area of interest, introducing an additional variable which had to be considered during the licensee s investigation.
The inspector considered that investigatory work in general should be precisely controlled in order to gain maximum benefit from available information.
The cause of this buildup of residue was not firmly established but was conjectured by the licensee to be caused by pump
operation with reactor coolant system (RCS) temperatures greater than 300 degrees F. It was clear, however, that the failures of the two pump seals were. not directly related.
Based on the above analysis of these failures, the licensee implemented three corrective actions.
The use of cleaning solvents other than alcohol and demineralized water have been prohibited on LPSI and Containment Spray (CS)
pumps (CS pumps have seals identical to LPSI pumps).
A Plant Change Request (PCR)
and associated engineering evaluation were submitted and approved for replacing the existing "0" rings with those of a different material having a
higher temperature rating and better resistance to chemical absorption.
Finally, a caution was added to procedure 420P-(1/2/3)ZZ10, Hot Standby to Cold Shutdown Mode 3 to Mode 5, to minimize SDC operation at RCS temperatures greater than 300 degrees F.
In addition, the NRC issued Information Notice No. 87-51:
Failure of Low Pressure Safety Injection Pump due to Seal Problems, on October 13, 1987 based on this problem, thus notifying other licensees of the potential for generic problems with similar mechanical seals.
The inspector noted that the licensee had not documented, in writing, their root cause analysis for the "A" train pump failure and had been unable to arrive at a conclusive root cause for the "B" train pump failure.
The inspector suggested to cognizant licensee personnel that, although no requirement existed to do so, documentation of root causes may be appropriate in this case.
However, the inspector concluded that an appropriate analysis had been conducted and that corrective actions were taken consistent with the analysis and with reasoned engineering judgement.
This item is closed.
No violations or deviations were identified.
5.
Follow-u of NRC Bulletin(s Licensin Event Re orts and Part
s
~92703 A.
Closed NRC Bulletin 87-01
"Thinnin of Pi e Walls At Nuclear Power Power Plants" This NRC Bulletin requested licensees to submit information concerning their programs for monitoring the thickness of pipe walls in high-energy single-phase and two-phase carbon steel piping systems.
The licensee's letter dated September ll, 1987 responded to the actions requested in the bulletin.
The inspector reviewed with the licensee the responses to the actions requested.
The licensee identified codes and standards to which the piping systems were designed and fabricated.
Several codes including ASME Sections I, III and VIII; ASTM; ANSI B16.5; and ANSI B31.1, were used for the design and fabrication of Palo Verde's piping system Specific information for individual systems is described in FSAR Table 3. 2-1, which was reviewed by the inspector.
The licensee has developed pipe erosion monitor ing guidelines (EEDG-40 Revision 0 dated October 15, 1987) which address point selection criteria, inspection frequency, inspection method and replacement/repair decisions.
Point selection criteria currently include review of piping drawings and actual plant installation while considering whether the component:
Is carbon steel pipe Contains less than lX chrome,
.5X Molybdenum,
.3X Copper Is a flow restricting device Contains fluid temperatures greater than 250 degrees Fahrenheit Contains flow velocities greater than 14 feet per second Has fittings or flow restrictions within five pipe diameters Experiences changes in flow direction The licensee methodology for selecting single-phase erosion points utilizes criteria developed from EPRI/NUMARC recommendations.
All pipe lines meeting the criterion are input into the
"CHEC" program to determine the relative erosion wear rate and minimum wall thickness.
The engineering department then selects susceptible erosion points based on the program output and recommended inspection locations.
Inspection frequency of the selected inspection points is expected to be each refueling outage.
The inspection method will be nondestructive examination or an equivalent method.
Results of each examination will be compared to the minimum allowable wall thickness to determine whether replacement/repair should be immediate or during the next outage.
The inspector reviewed the pipe erosion monitoring guidelines, EEDG-40 Revision 0 dated October 15, 1987, and verified that it is adequate.
At the time the licensee responded to this bulletin, no inspections for identifying pipe wall thinning had been performed.
However since September 1987 wall thinning inspections have been performed on Units 1 and 2, during the first refueling outages for these units.
The erosion/corrosion examination made on system piping for the two units during their refueling outages were as follows:
Unit 1 Locations Condensate System Extraction Steam Drains and Vents Feedwater System Five Nine Twelve Unit 2 Locations Condensate System Extraction Steam Drains Feedwater System Steam Generator Drains and Vents Ten Twenty-Nine Eighteen Five The inspector examined the data points and pipe wall thickness results from these inspections.
In no case, was the wall thickness less than nominal wall thickness minus 12 manufacturer's minimum wall thickness tolerance.
The inspector discussed the interpretation of results of these inspections with the licensee.
The licensee concludes that no significant piping wear has taken place to date, and that the data gathered represents a good base line for future pipe wall thickness inspections.
It is concluded that the licensee's program for ensuring that pipe wall thicknesses are not reduced below allowable thickness is adequate and responsive to the bulletin.
This bulletin is closed.
Closed 528/88-08-LO and 528/529/530/88-02-P Reactor Coolant S stem Leaka e Monitor Ino erable Due to Personnel Error and
CFR Part
Re ort of Defective Monitor Software LER 528/88-08-LO was associated with the licensee's discovery that the containment radiation monitor required by Technical Specifications was not operable due to software algorithm assumptions which became incorrect following a change from automatic filter paper advance to weekly manual changeout of a stationary filter.
In parallel with the LER, the original equipment manufacturer (OEM),
Kaman Instrumentation Corporation, submitted a
Part 21 report which addresses this problem.
The licensee's interim solution was to increase the frequency of filter changeout to once a day for the affected monitor.
This action avoids the algorithm problem and ensures complete operability.
As a permanent solution the licensee completed action on an Engineering Evaluation Request (EER 88-Sg-34) which modified and validated a change to the software algorithm.
At the time of this inspection, the upgraded algorithm had been partially installed in Unit 2 and was scheduled for installation in Units 1 and 3.
This item is close No violations or deviations were identified.
6.
Follow-u of NRC Tem orar Instructions TI A.
Closed TI 2515/86 Im lementation of Generic Letter No. 81-21 Natural Circulation Cooldown 25585 The purpose of this TI is to verify that PWR licensees have implemented programs for the control of natural circulation (NC)
cooldown in accordance with their commitments to Generic Letter (GL)
No. 81-21.
The licensee's assessment in response to GL 81-21, dated August 28, 1981, included commitments to:
(1)
Demonstrate by analysis and test that controlled NC cooldown from operating conditions to cold shutdown conditions, conducted in accordance with their procedures, should not result in reactor vessel voiding; (2)
Verify by analysis that supplies of condensate grade auxiliary feedwater are sufficient to support their cooldown method; and (3)
Provide in their training program instruction in theory and procedures for natural circulation cooldown of the plant(s).
NRR's letter of April 18, 1988 and the attached safety evaluation report (SER) found acceptable the licensee's responses and commitments (dated August 20, 1981; January 31, 1985; August 29, 1985; and February 9, 1987).
The licensee's letter of February 9, 1987 contained an evaluation of the natural circulation cooldown test that was performed on Unit 1 in January 1986; and also, demonstrated that there was sufficient inventory of condensate grade auxiliary feedwater to support cooldown by natural circulation.
The inspector examined the licensee's operating Procedure(s)
and Training Program to verify the licensee's implementation of NC cooldown.
The following operating procedures were reviewed:
41AO-1ZZ13 Natural Circulation Cooldown (Unit 1).
42AO-2ZZ13 Natural Circulation Cooldown (Unit 2).
43AO-3ZZ13 Natural Circulation Cooldown (Unit 3).
The three above procedures were considered adequate to perform a safe natural circulation cooldown.
The inspector reviewed lesson number NLA06-02-RC-009, Course/Lessons;
"Thermodynamics and heat transfer/natural
circulation", which is a four hour period of instruction taught during fundamentals of operations.
The inspector also reviewed simulator scenario lesson number NLC31-03-RC-034-,01, entitled
"Natural circulation cooldown."
The inspector sampled the training records of twenty seven reactor operators; seven from Unit 1, eight from Unit 2, and twelve from Unit 3; and determined that these personnel had attended and passed one or both of the above identified natural circulation cooldown training courses.
During the recent auxiliary transformer fire event at Unit 1 on July 6, 1988, Natural circulation was used for approximately twelve hours to maintain the Unit in Mode 3, Hot Standby, until the reactor coolant pumps were returned to service.
The inspector examined the records of primary system temperatures (Th/Tc) taken at intervals during this twelve hour period.
Delta T was maintained between
and 35 F.
The licensee's operating procedure(s)
and training program for implementing the requirements of GL 81-21, "Natural Circulation Cooldown", were found acceptable.
The licensee's demonstration of natural circulation cooldown of Unit 1 in January 1986 and the recent use of natural circulation to maintain Unit 1 in Hot Standby (Mode 3) for approximately twelve hours, supports the conclusion that the licensee has satisfactorily met the requirements of GL 81-21.
Thi s itern i s cl osed.
(0 en TI 2500/20 -
Com liance With Antici ated Transients Without Scram ATWS Rule
CFR 50.62 25020 The objectives of this TI are to determine compliance with 10 CFR 50.62 for ATWS mitigating systems that are not safety related, and to review the effectiveness of the gA controls applied to major activities (design, procurement, installation, and testing) for ATWS equipment per GL 85-06,
"gA Guidance for ATWS Equipment That is Not Safety Related,"
and to assess the operational readiness of this ATWS equipment.
The inspector examined the licensee's letter 161-000074-JGH/BJA dated March 13, 1987, in which the licensee committed to being in compliance with this rule prior to startup following the third refueling outage after July 24, 1984, for each PVNGS unit.
PVNGS Unit 1 recently completed its first refueling outage, therefore the ear liest compliance deadline will likely be in 1990.
The licensee has, up until now, allowed Combustion Engineer ing (CE) to pursue this matter with NRR on the CESSAR docket.
Presently the SIC Branch of NRR is reviewing and evaluating CE's submittal on the auxiliary feedwater initiation system.
Upon completion of NRR's evaluation, the inspection in this area will continu This item remains open and will be reported in a future inspection report.
No violations or deviations were identified.
7.
Exit Meetin 30703 The inspector conducted an exit meeting on July 22, 1988, with Mr. J.
G.
Haynes and other members of the staff as indicated in paragraph l.
During this meeting, the inspector summarized the scope of the inspection activities and reviewed the inspection findings as described in this report.
The licensee acknowledged the concerns identified in the report.