IR 05000528/1991050
| ML17306A507 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 02/20/1992 |
| From: | Vandenburgh C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17306A505 | List: |
| References | |
| 50-528-91-50, 50-529-91-50, NUDOCS 9203060088 | |
| Download: ML17306A507 (53) | |
Text
U. S.
NUCLEAR REGULATORY COMMISSION EGION V Re ort Nos.
Docket Nos.
License Nos.
icensee Facilit Name Ins ect o
Conducted 50-528/91-50, 50-529/91-50, and 50-530/91-50 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 Palo Verde Nuclear Generating Station Units 1, 2, and
December 18, 1991, through January 25, 1992 t
roved B
an en urg
,
c ng Reactor Projects Section
g J. Sloan, (Acting) Senior Resident Inspector F. Ringwald, Resident Inspector H. Thompson, NRR Project Manager W. Ang, Project Inspector H. Mong, (Acting) Senior Resident Inspector Diablo Canyon Ins ection Summar
Ins ection on December
1991 throu h Januar
1992 Re ort Nos. 50-528 91-50 50-529 91-50 and 50-530 91-50
~ltd:
g ti, it, gi dg tliiti g ti gytt t resident inspectors, one Region V based project inspector, and one NRR project manager.
Areas inspected included:
followup on previously identified items; review of plant activities; engineered safety feature system walkdowns - Units 2 and 3; surveillance testing - Units 2 and 3; plant maintenance Units 1, 2, and 3; preparation for refueling - Unit 1; electrical junction box screws and blowout plugs missing - Units 1 and 2; unsuccessful feedwater swapover evolu-tion Unit 1; reactor coolant system-(RCS)
pressure boundary leakage, notifi-cation of unusual event (NUE) - Unit 1; both DC trains inoperable Unit 2; plant startup from refueling - Unit 2; reactor trip due to a broken control board switch Unit 2; steam generator low pressure reactor trip setpoint drift Unit 2 and 3; reactor trip on loss of instrument air Unit 3; plant procedures Units 1, 2, and 3; observation of simulator training - Units 1, 2,
and 3; licensee response to
CFR Part 21 reports of defects in Barton transmitters - Units 1, 2, and 3; falsified inspector training record for fire 9203060088 920220 PDR ADOCK 05000528
~ barrier inspections Units 1 and 3, and review of licensee event reports-Units 1, 2,
and 3.
'During this inspection the following Inspection Procedures. were utiliied:
42700, 60705, 61726, 62703, 71707, 71710, 71711, 92700, 92701, 92702, and 93702.
Jesuits:
Of the lg areas inspected,
'one violation was identified regarding the falsification of training records (Paragraph 19).
Ge eral Co c usions and S ec'c Findin
'ificant Safet Matters:
None Summar of Violations:
One cited violation Units
and
Summar of Deviations.
0 en Items Summar
Stren ths Noted:
None Two new followup items were opened, 16 followup items were closed, and 10 followup items were left open.
The licensee aggressively pursued potential indications of gaseous activity in the Unit 1 containment, ultimately identifying pressure boundary leakage from the pressurizer.
The licensee also demonstrated thoroughness in responding to a
CFR Part 21 notification regarding Barton transmitters which identified an error in the vendor's notification.
The licensee reduced personnel contam-inations in Unit 2 from 207 in 1990 to 92 in 1991.
Weaknesses Noted:
Continued weakness in the command and control of control room activities were observed during the unsuccessful feedwater swapover in Unit 1 and in simulator observations.
Corrective actions were weak and untimely in response to unex-pected steam generator low pressure reactor trip setpoint changes and to ineffective valve locking device II
ersons Co tacted QEETA Ls The below listed technical and supervisory personnel were among those contacted:
r'zona Public Service APS R.
- K.
- T
- L
- p
- E E.
R.
T.
R.
- D
- S
- R p.
- W.
S.
- J D.
G.
- f R.
C.
R.
- J H.
- T C.
- R
- B
- R Adney Albers Bradish Clyde Coffin Dotson Firth Flood Foster Fullmer Gouge Guthrie Harton Hughes Ide Kanter Levine Mauldin Overbeck Perez Prabhakar Russo-Rouse Schmadeke Shea Shriver Stevens Stevens Whitney Younger Plant Manager, Unit 3 Operations Monitor, guality Assurance/guality Monitoring Manager, Compliance Manager, Operations Unit 3 Engineer, Compliance Director, Engineering General Hanger; Training Plant Manager, Unit 2 General Manager, Outage Planning
& Management Hanager, guality Audits and Monitoring General Manager, Plant Support and Chairman, Plant Review Board Site Director, guality Assurance (gA)
Auditor, equality Audits and Monitoring General Manager, Radiation Protection Plant Manager, Unit I Senior Coordinator, Management Services Vice President, Nuclear Power Production Director, Site Maintenance
& Modifications Site Director, Technical Support (STS)
Technical Assistant, STS Manager, guality Engineering Manager, guality Control Supervisor, Compliance Manager, Work Control Unit 3 Manager, Radiation Protection Assistant Plant Manager, Unit 2 Manager, Nuclear Engineering Analysis Director, Nuclear Licensing
& Compliance Technical Specialist II, guality Audits Hanager, Maintenance Standards
Denotes personnel in attendance at the exit meeting held with the NRC resident inspectors on January 28, 1992.
The inspectors also talked with other licensee and contractor personnel during the course of the inspectio I
2.
Followu on Previousl Identified Items - Units
2 and
92701 and O.
92702
'a ~
Unit
0 en
CFR Part
e ort 89-18-
"ABB-C Power Distribution Inc.
Current Transformer CT Enca sulate Haterial" Units
and
92701 (2)
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 the clean and inspect preventive maintenance-(PM) task to inspect the CTs each time the PH task is performed, and a changeout program for CTs in environmental qualification (Eg) applications.
The walkdowns have been completed-in Unit 2.
In Units 1 and 3 the walkdowns are partially complete and the remaining walkdowns are scheduled for the next refueling outages.
'None of the walkdowns have identified any softening of CT material.
The PH task revision is being reviewed but has not been approved yet.
The licensee is evaluating the Eg applications to determine if a changeout program is applicable.
This item will remain open until the licensee has completed their Eg evaluation and the PM task has been revised.
0 en Violation 528 90-03-03
"Dama ed Fuel Buildin Roll-U Door" - Unit
92702 This item involved the installation of pneumatic jumpers, which shut the fuel building supply dampers long enough for the exhaust fan to damage the fuel building roll-up door, thereby rendering the fuel building essential ventilation system inoperable.
The licensee closed Engineering Evaluation Request (EER) 90-ZF-009 on November 7, 1991.
The inspector noted that the closed EER contained recommendations from the nuclear engineering department (NED) to administratively control activities which may impact the door, since hardware changes were not considered to be cost effective.
The inspector questioned how these recommendations were being tracked and was told by the supervisor of the component and specialty engineering group that they were neither being tracked nor addressed until the inspector raised these questions.
The inspector noted that Administrative Control Procedure 70AC-OEE02,
"Engineering Evaluation Request,"
Step 3.1.7, now requires that a
Condition Report/Disposition Request (CRDR)
be initiated to track disposition actions as a result of a revision which became effec-tive after this EER was closed.
The NED recommendations are currently being addressed by the component and specialty
engineering group.
This item will remain open until the NED recommendations are addressed.
0 en Violation 528 90- 0-02
" ost-Accident Sam PASS Over-Pressur ation" U it
S stem This item involved the overpressurization of the PASS system due to poor communications which led to a valve misalignment.
All the immediate corrective actions were complete.
This item has been left open to evaluate the completion of a commitment in the licensee's response to the Notice of Violation to evaluate "...the adequacy of administrative controls for formal communications for non-operations department personnel manipulating plant equipment at the PVNGS."
The Iicensee's initial evaluation included the chemistry departmeht, but did not include other non-operations department personnel.
This question is still being addressed by the licensee.
This item will remain open pending completion of this evaluation.
Closed Followu Item 528 91-04-02
"Undervolta e Rela Testin "- Units
2 and
92701 This item resulted from the NRC's observation that the method of testing Agastat undervoltage relays for Class-1E 4160 volt engineered safety features (ESF) electrical buses may result in skewed results because of preconditioning of the relays as part of the test.
Additionally, the acceptance criteria for the tests were not conservative with respect to the technical specification requirements.
Condition Report/Disposition Request (CRDR) 9-1-0144 was written to document the licensee's evaluation of these issues.
The licensee revised the test method and acceptance criteria to be consistent with the updated final safety analysis report (UFSAR) and the technical specifications.
Additionally, the licensee determined that the UFSAR, technical specifications, and surveillance test all use different methods of expressing the acceptable undervoltage setpoints.
The UFSAR expressed the values in terms of percentage of rated voltage, the technical specifications expressed the acceptance criteria in terms of primary bus voltage, and the surveillance test specifies the acceptance criteria in terms of voltage on the secondary side of a potential transformer.
The secondary side voltages are what are actually used for the setting of the relay setpoints.
The licensee also determined that the technical specification surveil-lance criteria are inconsistent with the UFSAR values, and requested its licensing department to address UFSAR and technical specification changes as necessary.
The inspector concluded that the appropriate immediate actions have been completed, and that the licensee has initiated and is tracking completion of other actions, including a proposed technical specification change which would. make the technical
(5)
specification values consistent with the UFSAR values.
These corrective actions appear adequate; therefore, this item is closed.
Closed Followu Item 528 91-15-01
" imitor ue Gre se Ins ection Ade uac
" Units
2 and
92701 This'tem involved identified deficiencies in the licensee's Limitorque valve grease inspection program.
The inspector noted in Inspection Report 528/91-35 that the licensee had identified each conclusion in Incident Investigation Report (IIR) 9-1-0064 as an individual action item and that individual commitment action tracking system (CATS) items were going to be created for each of these items.
Although CATS items have not been created for each individual item, the inspector noted that CATS items'hich
, represent consolidated conclusion items have been created.
In Inspection Report 528/91-35 the inspector also noted that the IIR conclusions appeared to adequately address lubrication, but not equipment qualification (Eg).
The inspector was provided with a final version of the IIR which included a conclusion which adequately addresses the Eg questions.
Since all corrective actions from IIR 9-1-0064 appear appropriate and are either complete or being tracked by CATS, this item is closed.
Closed Violation 528 91-19-01
" irewatch Trainin " -
U ts
2 and
92701 This violation occurred in January to February, 1991, when twelve firewatches performed firewatch duties prior to fully completing required training.
Immediate corrective actions by the licensee included verification that on-shift personnel performing compen-satory firewatch duties in the units had satisfactorily completed training requirements.
An interim list of firewatch personnel who had satisfactorily completed all training requirements was devel-oped on April 11, 1991, and was used to assign compensatory fire-watches for subsequent shifts.
The licensee also determined that similar training concerns existed for hot work firewatch quali-fications; therefore, corrective actions were also necessary for the hot work firewatches.
The licensee's long term corrective actions included:
(1) the development and distribution of a firewatch orientation guide to firewatch personnel on Parch 25, 1991, to provide guidance on duties and safety information; (2) the development of a firewatch training film on March 5, 1991, to enhance the training of person-nel performing firewatch duties; and (3) the development of a firewatch qualification card on June 19, 1991, to facilitate identification of qualified firewatches.
The licensee's long term corrective actions also included a revision to Administrative Control Procedure 14AC-OFP04,
"Firewatch Duties,"
on July 18, 1991, to reflect changes in responsibilities and implementation of the firewatch progra The inspector concluded that these corrective actions appear to be appropriate to prevent further violations in this area; therefore, this item is closed.
Closed Followu Item 528 91-26-01
"Atmos her c Dum Valve ADV Nitro en Su l
Re viator Fai ure" Unit 92701 This item involved a June 1991 failure of the nitrogen supply regulator for an ADV due to the presence of a foreign material on the seat of the regulator.
The licensee has experienced several similar failures and has taken various measures to clean the nitrogen system and prevent further failures.
The inspector reviewed the licensee's root cause of failure evalu-ation, documented in Engineering Evaluation Request (EER) 91-SG-134.
The EER concluded that the cause of this failure was probably due to metal fragments produced during the grinding of the hard seat and disk of the upstream nitrogen isolation valve, which is cycled and torqued to 100 foot-pounds (ft-lbs) approxi-mately once per shift.
Site Modification 1,2,3-SM-SG-025 was issued to install two soft-seated check valves in series. on the nitrogen supply line to allow the nitrogen isolation valve to remain normally open during operation.
The EER also stated that insufficient time has passed to allow proper assessment of the long-term benefit from the installation of filters in the nitrogen supply system, completed in February 1991.
The filter instal-lation was the most recent previous modification made in response to these problems.
Although the licensee's measures did not determine the specific source of the foreign material, the inspector concluded that the modifications did appear to enhance the reliability of the system by removing a likely source of foreign material.
This item is closed.
Closed Unresolved Item 528 91-31-02
"Auxi iar Feedwater AFW S stem Train Se aration" Unit
9270 This item involved a steam supply line for the "A" turbine driven AFW pump which was routed through the "B" motor-driven AFW pump room such that a pipe break on the steam line could result in the loss of all safety-related AFW.
The nonsafety-related
"N" AFW
.
pump would not be affected.
The item questioned the separation of the AFW trains as committed in UFSAR Section 10.4.9.3.J..
In response to this concern, the licensee performed an extensive study to determine the acceptability of the separation of the safety-related AFW trains.
The evaluation was documented in Study No.
13-MS-A70 dated January 13, 1992.
The study reviewed various General Design Criteria, NRC Branch Technical Positions, NRC Standard Review Plan, ANSI/ANS Standards, Bechtel Design Guides, and Bechtel Topical Reports.
The study also documented
performance of piping walkdowns and a review of various applicable analyses.
The study concluded that, although there are instances of AFW Train "A" components being physically located in the AFW Train "B" pump room, there was sufficient protection against postulated hazards to assure AFW essential train redundancy and to allow safe shutdown of the plant.
The forwarding memorandum further concluded that the UFSAR design basis requirements were met.
However, the study recommended that the UFSAR be revised to clarify how the design objectives were achieved (Hazards DBH, Open Item C2-061).
The licensee stated that a
UFSAR change would be submitted as recommended by the study forwarding memorandum.
The inspector confirmed with the NRR Project Manager 'that this UFSAR change (and the acceptability of the noted condition) will be reviewed by the responsible NRC technical branch when the change is submitted; therefore, this item was closed.
0 en Violatio 528 91-04-04
"Cont ol of Rotor-0 crated Valve esi n Information" Units
and 92702 This violation resulted from the licensee's failure to maintain design documents up-to-date.
The licensee has not yet finalized
'he method of control it will use for the data.
Therefore, this item will remain open pending the resolution of this question.
l
~Un't
0 en Followu Item 529 90-28-02
"Plant Monitor'n Com uter Database Errors" Unit 2 92701 This item involved the licensee's programs to control data used by the core operating limits supervisory system (COLSS)
program and to determine if COLSS is functioning properly.
Three actions remain open:
(1) to review the licensee's COLSS verification method, (3) to review Quality Deficiency Report (QDR) 91-0002, and (2) to review QDR 91-0003.
The licensee developed a checklist for operators to use to assist in the assessment of the status of COLSS.
The inspector observed the use of the checklist on two occasions where the operators were evaluating the operability of the COLSS following a COLSS outage.
In these cases, the inspector noted that the checklist was effec-tive, but somewhat slow to use.
The operators indicated that they were not yet familiar enough with the checklist to be able to rapidly complete it.
At the time, the checklist was issued as a
operations department night order.
It has since been incorporated into Operations Procedure 770P-9RJ04,
"COLSS Functional Verifi-cation."
This action is closed.
Quality Deficiency Report (QDR) 91-0003 addresses the control of vendor information related to the data for COLSS, core protection
calculators (CPCs),
and CECORE computer codes.
This QDR documents that such information will be channeled through the licensee's nuclear fuels management (NFM) organization to ensure proper verification and distribution.
Procedures 87AC-OCC08,
"Control of Vendor Information," and 87DP-OCC13,
"Supplier/ Contractor Document Control," were revised to designate the NFM organization as the design authority for that information.
This designation of this responsibility appears to have eliminated the types of problems which had been previously identified.
This action is closed.
Quality Deficiency Report (QDR) 91-0002 addresses the licensee's software configuration management program.
The QDR is not yet closed, and the quality audits department is currently involved in meetings with the engineering department to resolve disagreements regarding the content of an acceptable program.
This item will remain open pending completion of QDR 91-0002.
0 en Fo owu tern 5 9 91-04-02
" ualit of Test Gas Used for echnical S ecification TS Survei lances" Unit 2 92701 This item involved several inspector questions regarding the quality of the gas used by the licensee for TS Surveillance Requirement 4.6.4. 1 for the calibration test of the containment hydrogen monitoring system.
During performance of the test the inspector observed that the test gas used during the calibration appeared to be of commercial-grade quality and that the accom-panying gas analysis certificate from the vendor lacked sufficient specificity to assure the quality of the gas.
In response to these questions, the licensee initiated Quality Deficiency Report (QDR) 91-0130 to determine the quality requirements and establish traceability of the test gas.
After various reviews, the licensee concluded that test gas would either be procured from a qualified safety-related vendor from its approved vendor's list or procured as a commercial-grade item and be dedicated for safety-related use upon receipt by confirmatory test analyses.
The quality assurance (QA) department performed a
joint audit of a vendor with the Pacific Gas and Electric Company, in an effort to add the vendor to their approved vendor's list.
The audit was documented in a letter (028-03837-WPP/WMS),
dated December 20, 1991, from the APS QA department to the vendor.
The audit noted several weaknesses in the vendor's quality assurance program that precluded it from being placed on the licensee's approved vendor's list.
The licensee's QA department is working with the vendor to resolve those weaknesses.
In addition, on September 18, 1991, the licensee issued Material Engineering Evaluation MEE/ITTE 01045 to provide an alternative dedication process for the commercial-grade gas.
At the time of the inspection, the licensee had not concluded its evaluations for QDR 91-0130 and had not decided on its future method for procure-
i,
ment of test gasses.
The item was left open pending the licen-see's completion of its evaluations.
0 en Followu Item 529 91-26-01
"Control lement Drive echanism CEDH Fans and xhaust Stack Boltin ailures" - Unit 92701 This item involved the failure of CEDH fans and mounting bolts for the CEDH fans and exhaust stacks.
The licensee had installed
.
temporary instruments on one CEDH fan in Unit 1 to monitor vibration.
The root cause evaluation is still in progress, with Condition Report/Disposition Request (CRDR) 9-1-0024 expected to be completed in Hay 1992.
This item will remain open pending completion of the CRDR documenting the root cause evaluation.
0 en Followu tern 529 9 -35-02
"Valve Handwheel
"OP N" Direction Arrows Incorrect" - Unit 92701 This item involved the identification of several valves in safety-related systems with OPEN'irection arrows pointing in the incorrect direction.
This item has been addressed in Inspection Reports 528/89-13, 528/89-55, 528/91-35, and 528/91-40.
In addition, Condition Report/Disposition Request (CRDR) 2-1-130 was issued to address the concerns raised in Inspection Report 528/91-35.
During this inspection period, the inspector identified three additional valves in Unit 2 and one additional valve in Unit
with incorrect
"OPEN" direction arrows.
The licensee responded by initiating CRDR 2-2-36 and by initiating walkdowns in all safety systems to identify any remaining examples of incorrect
"OPEN" direction arrows.
As of the end of this report period, the licensee has identified five additional examples of incorrect
"OPEN" direction arrows on safety related valves or valve operators.
The licensee indicated that, although an effort is underway to identify and correct the incorrect
"OPEN" direction arrows, operators are trained to not rely on handwheel arrows for proper valve position identification or valve operation.
The licensee stated that the only exception to this guideline is in reverse acting valves which should all be properly marked.
Although the licensee's corrective action in this area has been ineffective until recently, the inspectors encouraged the licensee's recent positive action in this area'.
This item will remain open until CRDRs 2-1-130 and 2-2-36 are closed.
Closed Unresolved Item 529 91-35-03 '.
"D namic Anal sis of Pi in Usin Overla Hodellin Hethod"- - Unit 2 91702 The item involved the use of-an overlap modelling method for the seismic analysis of the piping from-the refueling water tank to
the safety injection (SI) pumps.
The inspector questioned the basis for the method and whether or not the recommendations of NUREG/CR-1980,
"Dynamic Analysis of Piping Using the Structural Overlap Hethod," were used.
In response to this item, the 'licensee reviewed the specific SI piping stress analysis problem and a sampling of other piping stress analysis problems to determine the basis and acceptability of the methodology used.
The reviews were documented in Hemorandum 284-00334-JAB/JWF, dated November 6, 1991, and Hemorandum 344-00532-JDS/RCL, dated November 15, 1991.
The memoranda documented the random review of 48 of 175 g-class calculations involving 113 individual stress problems.
The reviews concluded that, although NUREG/CR 1980 was not explicitly
'tilized during the plant's design phase, the piping stress analyses met the intent of the NUREG.
The reviews further concluded that the overlap modelling techniques used at PVNGS were acceptable and did not create a safety concern.
The licensee piping analysis design engineers also stated that overlap modelling would not normally be used for future piping analysis.
However, if they were needed, appropriate guidelines meeting the intent of NUREG/CR 1980 would be used.
The inspector concluded that the licensee performed a reasonable evaluation of the noted condition to show that the piping analysis previously performed met the intent of the NUREG.
This item was closed.
Closed Violation 529 91-35-05
"Visitor Left Unescorted"-
Unit 2 92702 This item involved an escort leaving the assigned visitor in the
"B" Train DC Equipment Room.
The licensee responded by issuing an employee news bulletin to all employees reminding them of their responsibility when assigned as escorts.
The inspector concluded that this appeared appropriate; therefore, this item is closed.
During this inspection period several additional examples of-failure to maintain escorted visitors within line of sight as required were witnessed by the inspector.
These were addressed with licensee management who conducted detailed investigations of each of these events.
After reviewing the results of these investigations and discussing these issues with regional safe-guards inspectors who also reviewed the licensee investigation results, the inspectors concluded that these examples were of minor safety significance.
The inspector encouraged the licensee to continue their emphasis on this issue to ensure that the program requirements continue to be met.
The licensee acknow-ledged the inspector's comment Unit 3 0 en iolation 530 9 -0 -0
" iese Genera o
s ect'o s
uri lant hutdown" Un t 3 62703 and 9270 This item involved the emergency diesel generator inspections that are required by TS Surviellance Requirement 4.8. 1. 1.2.d. 1.
During this inspection period the inspector observed portions of the January 6,
1992, calibration of the Unit 1 low lube oil trip pressure switch, 1DGA-PSL-0005, for the "A" emergency diesel generator.
The as-found value of the switch setting was 26.81 pounds per square inch (psi), below the 29.62 psi minimum value specified in Preventive Maintenance Work Order 532981.
The licensee adjusted the setpoint to within the proper range, but did not review the impact of the low as-found setting on operability of the emergency diesel generator and did not perform a root cause evaluation of the failure, as would have been performed, if the calibration had been a TS surveillance activity.
The appro-priateness of this calibration not being performed as a TS sur-veillance test is under review in conjunction with the review of Violation 530/91-01-01, dealing with emergency diesel generator surveillance testing, and this specific condition will be considered along with that review.
This item remains open.
0 en
'olation 530 91-01-02
"Lack of Timel Corrective Action for Emer enc Diesel Gene ator EDG Air Receiver Leaka e" U it 3 9201 The licensee responded to the Notice of Violation in a letter (102-02014 - WFC/TRB/JJN), dated April 19, 1991.
The licensee's response denied the violation, but acknowledged that the eval-uation process for determining whether conditions may render equipment inoperable could be improved.
The licensee further stated that -the system engineering program would be clarified by including a requirement for the system engineers'o review open safety-related work requests, which potentially could impact system availability, on a periodic basis to ensure that potential design basis concerns do not exist from identified deficiencies.
In a letter to the APS Executive Vice President, dated November 21, 1991, NRC Region V acknowledged the receipt of the licensee's response and informed the licensee that after further review of the violation and their response, Region V had concluded that the violation was valid.
The NRC acknowledgement letter further stated that the licensee's corrective action to invol.ve system engineers in the review of open safety-related work orders appeared appropriate and that the adequacy of the evaluation process would be included in future inspections.
The NRC inspector's review of the above noted corrective actions indicated that the licensee had issued Revision 1 to Adminis-trative Procedure 70DP-9ZZ01,
"System Engineers Walkdown Checklist and Guideline,"
on November 18, 1991, to add a requirement for the-10-
system engineers to review open safety-related work requests, which could potentially impact system availability, during the walkdown process to ensure that potential design basis concerns do not exist for identified deficiencies.
In addition, the licensee already had existing requirements 'in Paragraph 3.7.2 of-Admini-strative Procedure 70PR-OAPOl,
"System Engineer Program," Revi-sion I, stating that the system engineer performs work request reviews pertaining to important and/or critical work on assigned systems to remain cognizant of significant maintenance activities, potential problems, arid to identify recurrent system deficiencies.
In addition to the above noted programmatic corrective action, the licensee completed work on the leaking EDG air receivers and verified no leakage using Work Order 00458522.
- The licensee also initiated and performed engineering evaluations to determine the-acceptable air leakage rate for the starting air subsystem in EER 91-06-023.
The engineering evaluation was performed using a
seismic event lasting 24 seconds and determined how large a leak rate could be allowed in those 24 seconds and still be capable of starting the EDG's.
The calculation determined this leak rate to be 42.26 cubic feet/minute which was in excess of the compressor capacity of 32.2 cubic feet/minute.
The inspector had the follow-ing questions regarding the basis for the calculations:
(a)
The inspector questioned the rational for taking credit for the non safety-related, non-seismically analyzed and non-Class-1E powered compressor in the calculations.
(b)
Because the calculations only analyzed a single event (i.e.,
seismic),
the inspector questioned the applicability of the acceptance criteria for any other condition, such as:
~
normal operations without the compressors
~
effect on four hour coping upon implementation of the blackout rule
~
effect on ability to accomplish actions required for the EDG's by operations directives in response to an earthquake
~
effect on ability to accomplish annunciator response actions required in operations procedures
~
coordination of system tightness requirement such as the leakage acceptance criteria for the EDG air start system check valves upstream of the air receivers The inspector discussed the above noted questions with the system engineer, representatives from site nuclear engineering, and the director of site technical services.
The inspector -inquired
(3)
regarding the leak rate acceptance criteria to be used by system engineers and work planners for determining if any leakage identi-fied required no immediate corrective action or further engineer-ing evaluation.
The director of site technical services acknow-ledged the inspector's questions and committed to reevaluate the leak rate acceptance criteria to determine if an acceptance criteria could be used by system engineers and work planners for determining if any EDG air start system leakage conditions necessitated engineering evaluation or could be considered acceptable.
Pending completion of this'evaluation, the item was left open.
Closed Fol 1 owu Item 530 91-40-03:
"Auxi1iar Feedwater FW low Transmitte ual'n Valves Found
e " U '
92701 This item resulted from the licensee's November 5, 1991, discovery of improperly positioned equalizing valves in both "8" train flow transmitters for the auxiliary feedwater (AFW) system.
The inspector reviewed Condition Report/Disposition Request (CRDR) 3-1-0192 and Licensee Event Report (LER) 530/91-011, which docu-mented the licensee's evaluation of this event.
The licensee
'determined that this event had little-safety significance, since the train "A" flow monitors on each of the feedwater lines were operable and the inoperable train "B" monitors were used for indication only.
However, the licensee was unable to determine specifically when or how the valves were mispositioned.
The CRDR and LER indicate that a complete valve lineup was performed in Unit'.
The documents do not indicate if Units 1 or 2 were checked for position of the affected valves.-
The inspector checked the other Units and found that the equal-izing valves appeared to be closed as required.
The CRDR indicates that the instruments appeared to be functioning, and were, therefore, properly aligned during a surveillance test on October 27, 1991.
The licensee's interviews with all instrument technicians and operators who had been in the AFW vital area between October 27 and November 5, 1991, and a review of work orders possibly affecting the transmitters, did not identify any activity associated with the transmitters.
The inspector concluded that the licensee's corrective actions were adequate, but that checking the transmitters in the other two units should have been considered and documented.
The inspector further concluded that the licensee's efforts to determine the cause were adequate; therefore, this item is closed.
No violations of NRC requirements or deviations were identified.
- 12
Rev'ew Plant Activit'es
7 7 and 93702
'a ~
Plant V'sit b C Chai
- Dr. Ivan Selin, Chairman, Nuclear Regulatory Commission, met with Hr. Richard Snell, Chief Executive Officer of Pinnacle West Capital Corporation, (the licensee's parent company),
Mr.. Hark, DeHichelle, President of Arizona Public Service, and other licensee management personnel-on January 9,
1992.
Following the meeting, Dr. Selin toured Unit 1.
Hr. Jack Hartin, Region V
Regional Administrator, accompanied Dr. Selin.
Unit
C.
Unit 1 began this inspection period operating at 100 percent power.
On December 22, 1991, a feedwater transient caused reactor power to increase above 100 percent for approximately two minutes, peaking at about 103.7 percent.
Units 1 and 3 reduced power to 97 percent for 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> on December 27-28, 1991, while licensee management resolved its interpretation of licensed power limit.
After several discussions with the licensee and the Office of Nuclear Reactor Regulation (NRR), this event was determined not to be reportable.
On January 2,
1992, the licensee determined that pressure boundary leakage existed from a pressurizer level instrument steam space nozzle.
An unusual event was declared and the unit was shut down and cooled to Mode 5 on January 3,
1992 (see Paragraph 10).
Following completion of repairs to the pressurizer, Unit 1 was heated up to Mode 3 on January 12, 1992, and the reactor was brought critical on January 13, 1992.
Operators failed to successfully stabilize the plant following a feedwater control valve swapover on January 14, 1992, resulting in the plant going back down through the feedwater swapover point, after which the operators successfully stabilized the plant at approximately 14 percent power (see Paragraph 9).
The power ascension was resumed the next day with a successful feedwater swapover, and the unit was returned to essentially full power on January 20, 1992.
The plant operated at '100 percent power for the remainder of the reporting period.
Unit 2 Unit 2 began this inspection period in Mode 5 in a refueling outage.
Hode 4 was entered on December 31, 1991, and the plant closed the generator output breakers in Mode 1 ending an 84 day outage on January 9, 1992.. A reactor trip occurred approximately 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> later as described in Paragraph 12 of this report.
The plant was restarted and entered Hode 1, on January ll, 1992.
The plant completed power ascension testing
'on January 21, 1992, and
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operated at essentially 100 percent power for the remainder of the inspection period.
Unit 3 Unit 3 operated on essentially full power until December 27, 1991, when power was reduced to 97 percent for 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> while management resolved its interpretation of the licensed power limit following a feedwater transient in Unit 1 which had caused power to exceed 102 percent.
On January 7,
1992, Unit 3 experienced a similar feedwater transient, which caused power to peak at about 101.8 percent.
The unit operated at 100 percent power until the reactor tripped on January 24, 1992, following a reactor power cutback caused by the operators manually tripping the "B" main feedwater pump after a failed instrument air line induced a feedwater transient (see Paragraph 14).
A reactor restart was in progress as the inspec-tion period ended, with the reactor achieving criticality at 2:04 AN (HST)
on January 26, 1992.
Plan ou The following plant areas at Units 1, 2, and 3 were toured by the inspector during the inspection:
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Auxiliary Building
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Control Complex Building
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Diesel Generator Building
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Fuel Building
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Hain Steam Support Structure
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Radwaste Building
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Turbine Building
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Yard Area and Perimeter The following areas were observed during the tours:
(a)
0 eratin Lo s and Records Records were reviewed against technical specifications and administrative control procedure requirements.
(b)
Honitorin Instrumentation Process instruments were observed for correlation between channels and for conformance with technical specifications requirements.'.
~Eh if<< ff'i C t I
hift *t ffi g observed for conformance with 10 CFR Part 50.54.(k),
technical specifications, and administrative procedures.
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I E
Li II i
d i
i 1b k
were verified to be in the position or condition required by technical specifications and administrative procedures for the applicable plant mode.
The inspector identified some valves in Units 1 and 2 which had locking devices installed ineffectively, such that the valves could be manipulated without breaking or removing the lock.
In two of the valves, 1SGB-UV-500R and 2CHN-UV-524, the locking wire securing one side of the handwheel to a
'nearby handrail was so loose that the handwheels could be completely rotated.
The licensee corrected these deficiencies promptly upon identifi'cation.
The inspector twice observed (once in Unit
and once in Unit 2) that Containment Purge Valve CPB-UV-5A (an 8-inch isolation valve)
had its handwheel removed and locking wire wrapped around the stem to prevent reattaching the handwheel.
This procedural method of locking these valves appears to be ineffective, in that the locking wire can be slid down or off the stem, allowing the handwheel to be reattached.
Although not fully effective, the presence of locks, provides indication that the valves are not supposed to be manipulated without specific authorization, and the absence of handwheels provides an additional barrier to unauthorized operation of the containment purge valves.
The inspector noted that the licensee did not initiate action to evaluate the adequacy of the locking method for this type of valve after the repeat observation in Unit 2.
When the inspector questioned their corrective actions, the licensee initiated an informal evaluation.
After further questioning whether this condition met the threshold for initiating a Condition Report/Disposition Request (CRDR),
the licensee initiated CRDR 1-2-0028.
The inspector concluded that more attention to detail is warranted in applying locking devices per Administrative Procedure 40AC-OZZ06,
"Locked Valve and Breaker Control."
The licensee agreed that the containment purge valves had not previously been locked effectively and indicated that, with the exception of one containment purge valve which the licensee is still attempting to effectively lock, the deficiency had been corrected.
E ui ment Ta in
- Selected equipment, for which tagging requests had been initiated, was observed to verify that tags were in place and the equipment was in the condition specified.
General Plant E ui ment Conditions - Plant equipment was observed for indications of system leakage, improper-15-
lubrication, or other conditions that could prevent the systems from fulfillingtheir functional requirements.
(g)
(h)
(k)
Fire Protection Fire fighting equipment and controls were observed for conformance with technical specifications and administrative procedures.
tt it -dt i
tdi 1t
d for conformance with technical specifications and administrative control procedures.
~secur't 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.
~Hk
-11 t
dhoti d
t 11/did t
storage were observed to determine the general state of cleanIiness and housekeeping.
Radiation Protection Cont ols Areas observed included control point operation, records of licensee's surveys within the radiological controlled areas (RCA), posting of radiation and high radiation areas, compliance with radiation exposure permits (REP), personnel monitoring devices being properly worn, and personnel frisking practices.
Shift Turriover - Shift turnovers and special evolution briefings were observed for effectiveness and thoroughness.
The inspector questioned one operator regarding the reason why the essential spray pond trouble annunciator was locked in alarm.
This annunciator provides information that may affect:spray pond operability.
The reason the operator provided had been accurate when that operator received the alarm the previous day but that condition had cleared and the annunciator was in for two other reasons.
The inspector concluded that this represents inadequate turnover of current plant status.
The licensee acknowledged the inspector's comments.
No violations of NRC requirements or deviations were identified.
En ineered Safet Feature ESF S stem Walkdowns Units 2 and
7 710 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 procedures.
During this inspection period the inspectors walked down accessible portions of the following systems.
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~Uit 2 Trisodium Phosphate Baskets
~Uit 3 Train "A" High Pressure Safety Injection Train "A" Low Pressure Safety Injection Train "A" Containment Spray No violations of NRC requirements or deviations were identified.
5.
Surveillance Testin Units 2 and
617
Selected surveillance tests required to be performed by the technical specifications (TS) were reviewed on a sampling basis to verify that:
(1) the TS 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.
Specifically, portions of the following surveillances were observed by the inspector during this inspection period:
~U't
Procedure
~II 42ST-2ZZ09 Containment Cleanliness Inspection 36ST-2SE03 Excore Safety Linear Channel quarterly Calibration 42ST-2SGOS ADV Nitrogen Accumulator Drop Test 73ST-9SI03 Leak Test of SI/RCS Pressure Isolation Valves 42ST-2SG01 Main Steam Line Isolation. Valves Surveillance 4.7. 1.5 Unit 3 Procedure Descri tion 36ST-9SB02 PPS Bistable Trip Units Functional Test 43ST-3AF02 Auxiliary Feedwater Pump AFP-01 Operability Test During the performance of TS Surveillance Test (ST) 36ST-2SE03 on December 30, 1991 in Unit 2 the inspector noted that-the Instrumentation 8 Control (IKC) technician turned the wrong switch and recorded incorrect data during the performance of the ST.
After recording incorrect data during the performance of two steps and annotating the second as an out of specification reading, the technician recognized the error and repeated the steps correctly.
The inspector concluded that this represents inattention to detail.
The licensee agreed with the inspector's comments.
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>> ~
I0'o violations of NRC requirements or deviations were identified.
la t Maintenance U its
d 3 62 03 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 quality assurance/quality control 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.
Specifically, the inspector witnessed portions of the following maintenance activities:
Unit Repair Leak on GAN-V26 Gaseous Radioactive Waste Isolation Valve Inspect Train "A" Diesel Generator Jacket Water Heater Inspect Train "A" Diesel Generator Lube Oil Calibrate Train "A" Diesel Generator Low Lube Oil Pressure Switch Calibrate Train "A" Diesel Generator Position Pressure Switch Reinstall Train "A" Diesel Generator Reverse Power Meter Preparation for Weld of Pressurizer Nozzle New Fuel Receipt Inspection Unit 2
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Rework SGE-V346
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73TI-9ZZ44 AFC HV-33 Full Flow Test
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Troubl eshoot MSIV 170/171
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Preparation gAG Grout Fire Seal Unit 3
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Train "A" Diesel Generator Lube Oil Pressure Loop Calibration
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Train "A" Diesel Generator Bearing Oil Change a
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During Unit 2 maintenance on SGE-V346 on December 28, 1991, the inspector noted several valve manipulations and the breaking of a Swagelock fitting without specific direction in the work order.
Later discussions of these observations with the mechanical maintenance supervisor and the maintenance manager identified that the licensee considered it appropriate for mechanics to perform
"skill-of-the-craft" actions, such as manipulating valves and breaking and reconnecting fittings without specific steps in the work order for these actions.
The inspector noted disagreement on.
the threshold for these actions between the Unit 2 mechanical maintenance and quality assur ance (gA) departments.
A pen-and-ink change was made to add steps to the work order to address the-18-
breaking and reconnecting of a Swagelock fitting after it had-been disconnected as a result of concerns from a gA representative, who was present.
The inspector's discussions with the mechanical maintenance supervisor and the maintenance manager reveale'd that the maintenance department did not consider this pen-and-'ink change necessary but agreed to it to avoid a work delay.'he inspector encouraged the licensee to resolve the apparent disagreement between the gA and maintenance departments.
The inspector further encouraged the licensee to ensure that post maintenance retesting is appropriate even when maintenance personnel take "skill-of-the-craft" actions which are not
'ocumented in the work order.
b.
On January 14, 1992, in Unit 3, the inspector observed the inspection of the Limitorque SB-1 motor operator for 3CHA-HV-531
[the isolation from the refueling water tank to the suction of the emergency core cooling system (ECCS) pumps].
The purpose of the corrective maintenance task was, in part, to remove the compensator stack housing and check for the presence of grease, and to replace any grease fittings on the compensator stack housing with pipe plugs, per a Limitorque maintenance bulletin.
Although no grease is supposed to be present in the housing, approximately one fourth of the compensator was heavily coated with what appeared to be fresh grease.
Although the licensee informally determined that the amount of grease in the compensator stack housing would not affect operability of the valve, they did not verify whether a similar situation existed on the other units.
The NRC inspector checked in Unit 1 and found that CHA-HV-531 and CHB-HV-530 both have grease fittings on the compensator stack housing and that grease is present on the outside of the grease fitting, indicating grease is probably present inside the housing.
The Unit 1 valves and CHB-HV-530 in Unit 3, have not yet been inspected by the licensee.
The inspector concluded that the licensee had applied grease to inappropriate areas of the valves in all three units and that the operability of the valves could. have been affected.
Additionally, the inspector concluded that the licensee had not inspected the valves in Units 1 and 3 in a timely manner because these unit's valves were not inspected until after the NRC notified the licensee of the similar condition.
The inspector will review the licensee's maintenance practice for greasing these valves and the results of the licensee's inspections of the remaining SB-1 operators (Followup Item 530/91-50-01).
No violations of NRC requirements or deviations were identifie P e aration for Refueli
- Unit 60705 a
d 62703 The inspector sampled some of the licensee's activities in preparation for refueling because of weaknesses observed during the recently completed Unit 2 refueling, documented in Inspection Report 529/91-49.
Specifically, the inspector observed the receipt -inspection of two new fuel assemblies.
Additionally, the inspector observed preliminary checks performed on the refueling machine console, which utilized a simulator.
Personnel appeared knowledgeable of their equipment and responsibilities.
The inspector concluded that these activities were adequately controlled and conducted in accordance with approved procedures.
No violations of NRC requirements or deviations were identified.
Elect 'cal Junction Box Screws and B owout Plu s
iss'
Un'ts 1 and
71
On December 23, 1991, the inspector identified several electrical junction boxes in the Unit 2 containment building which were missing screws from the cover plates and/or had plastic plugs missing from implosion "blowout" holes in the bottoms of the boxes.
Many similar discrepancies were identified by the inspector during the containment cleanliness inspection surveillance test (42ST-9ZZ09) performed on December 27, 1991, On January 6,
1992, the inspector identified similar discrepancies in the Unit 1 containment building shortly before the unit was planning to heat up to Mode-4.
=The licensee replaced the missing screws and determined that the blowout plugs were not safety significant.
The inspector concluded that the licensee's maintenance restoration work practices were weak in that care had not been taken to ensure fasteners and plugs were replaced following maintenance.
Additionally, the licensee walkdowns of containment had not been thorough enough to identify these deficiencies.
The licensee acknowledged these comments.
No violations of NRC requirements or deviations were identified.
Unsuccessful Feedwater Swa over Evolution Unit
92700 and 93702 On January 14, 1992, the inspectors observed an attempted power increase from 14 percent to approximately 18 percent reactor power to accomplish the feedwater swapover evolution.
At the feedwater swapover point (a calibrated setpoint in the feedwater control system based on input from the control channel excore nuclear instrumentation)
the small downcomer feedwater control valves close and the large economizer control valves begin to come open.
This feedwater swapover evolution injects a large quantity of relatively cold water into the steam generator with the resulting reactor coolant system temperature transient.
The evolution did not proceed as planned and after reaching 20 percent-reactor power, the operators were unable to stabilize the plant and eventually returned to approximately 14 percent power.
Cold leg reactor coolant temper-
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ature exceeded the maximum limiting condition for operation and the shift supervisor appropriately entered the technical specification's limiting condition for operations action statement.
'uring this event the inspector noted that the licensee's command and control appeared unclear in that the assistant shift supervisor was initially designated as control room supervisor'o direct the evolution and the shift supervisor was to maintain an overall perspective.
During the evolution, the shift supervisor directed some individual operator actions while the assistant shift supervisor appeared to no longer be controlling the evolution.
This occurred without any formal
'ommunication of a transfer of control.
In addition, the plant power went from approximately 20 percent to 14 percent power with the feedwater control system swapping back from economizer to downcomer control without any specific direction from any operator, supervisory or otherwise.
Communication was informal with few repeat backs and many discussions between individual operators which were not loud enough for all the operators to hear.
The assistant plant-manager and the operations department manager observed the evolution.
The inspector concluded that ineffective command and control and poor communication directly contributed to the feedwater swapover not being completed as planned; The licensee conducted a critique of the event and an informal operations department investigation, which also concluded that while the operator's actions maintained the plant in a safe condition, ineffective command and control and poor communication directly contributed to the feedwater swapover not being completed as planned; When the feedwater swapover was attempted later that day with a different operating crew, management was again present to monitor operator actions.
The inspector discussed this event with the plant manager and questioned why a condition report/disposition request (CRDR) had not been initiated.
The inspector noted that an informal operations department internal evaluation was already in progress, but without a CRDR this information would not be available for trend analysis.
The licensee acknowledged these comments and initiated CRDR 1-2-29 to make the details of this event available for event trending.
No violations of NRC requirements or deviations were identified.
Reactor Coolant S stem RCS Pressure Boundar Leaka e
Notification Unusual Event NUE - Unit
93702 On January 3,
1992, Unit 1 declared an unusual event and commenced a
controlled plant shutdown for reactor coolant system pressure boundary leakage.
The leak was from the pressurizer instrument nozzle for Level Transmitter LT110X.
The leak was identified during a planned evolution to look for leaks in the pressurizer cubicle which would contribute to the elevated containment atmospheric activity and radiation monitor readings.
The inspector concluded that the decision to declare the NUE and shutdown the unit was appropriate.
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I
Shortly after the NUE was declared, the inspector entered the control room to evaluate the plant condition.
During a discussion concerning the leak's impact on plant operation, the inspector noted that the shift supervisor directed the operators to shift the pressurizer level" control system (PLCS) from channel X to channel Y so that the PLCS would not be selected to the potentially affected transmitter.
During subsequent discussions, the licensee indicated that they had previously identified the need to change the PLCS channel selection; however, their evaluation had concluded that immediate action was not required.'he inspector concluded that the decision to shift the PLCS from X to Y channel was not performed in a timely manner.
The licensee acknowledged the inspector's comments.
Following the shutdown, the plant was cooled down to Mode 5 and weld repairs were made to the leaking instrument nozzle.
The technical aspects of the repairs were reviewed by regional engineering inspectors who concluded that the repairs appeared to be appropriate.
This conclusion will be documented in Inspection Report 528/92-04.
No violations of NRC requirements or deviations were identified.
Bot C
rains Ino erable Unit 2 7170 At 12:05 AM (HST) on December 14, 1991, with the unit in Mode 5, both DC electrical trains were rendered inoperable when motor control center PKB-H42 was administratively removed from service for implementation of Design Change Package (DCP) 2XE-SG-163 prior to the restoration of PKA-M41 from implementation of the same change.
PKB-H42 was functional even though it had been released for the modification work.
When the licensee identified the condition at 9:00 AH the same day, the operators entered Technical Specification Action Statement (TSAS) 3.8.3.2, and immediately restored one DC train (by returning PKB-M42 to service),
as required by the TSAS.
Condition Report/Disposition Request (CRDR) 2-1-0271 was initiated to document the licensee's investigation of this event.
The licensee determined that the event was caused by an operator's error in annotating the Technical Specification Component Condition Record (TSCCR) for PKA-H41.
The TSCCR note stated that the work order for connecting PKA-H41 to the power supplies (part of the design change package)
did not affect operability of the "A" DC bus.
However, the TSCCR note was only true until the power supplies were connected to the
"A" DC bus.
Subsequently, another operator misinterpreted the TSCCR note.
After determining that no work orders were open against PKA-H41 except the power supply work order, the operator incorrectly concluded that the "A" DC bus was operable and released PKB-H42 for implementation of the DCP.
The inspector concluded that the operators had incorrectly communciated the conditions for operability in the TSCCR, and had consequently incorrectly assessed the operability of the "A" DC bus.
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No violations of NRC requirements of deviations were identified.
Plant Startu from Refuelin
- Un t 71711
'I The inspector reviewed the unit's readiness for restart following the refueling outage and selected restart activities.
The inspector concluded that the unit appeared ready for restart and power operations.
The inspector noted numerous housekeeping discrepancies (primarily in the auxiliary building).
The licensee indicated that this condition did not meet their management expectations and noted that this was being tracked as a management. priority item.
The inspector identified one top plug in a large trisodium phosphate (TSP) basket after the basket had been readied for plant operation and noted that it was promptly removed when it was brought to'he licensee's attention.
The licensee responded by describing specific action plans and schedules for addressing housekeeping, scaffolding, insulation and contaminated area issues.
No violations of NRC requirements or deviations were identified.
Reactor Tri D e to a Broken Control Board Sw tch U it 2 93702 On January 9,
1992, Unit 2 tripped from approximately 20 percent power during a feedwater. swapover evolution.
The reactor tripped on low steam generator water level after reaching the feedwater swapover point because, the number one steam generator economizer valve never received an open signal.
The automatic demand signal from'he control board controller was not passed to the valve because the manual/automatic switch in the controller had broken.
This resulted in breaking the wire which directs the automatic demand signal from the controller to the valve.
The licensee initiated Condition Report/Disposition Request (CRDR) 2-2-0012 which resulted in an investigation that identified additional broken switches on controllers in Unit 1, Unit 3, and the simulator.
The inspector concluded that licensee actions appeared appropriate.
No violations of NRC requirements or deviations were identified.
Steam Generator Low Pressure Reactor Tr'et oint Shi t U it 2 a d 3 92700 On October 5, 1991, the Unit 2 operators noticed that the steam generator (SG) low pressure reactor trip and main steam isolation engineered safety feature (ESF) setpoints for both SGs decreased by approximately 50 pounds per square inch (psi) for no apparent reason.
This occurred in plant protection system (PPS)
Channel
"B".
The resultant setpoints were approximately 50 psi below the minimum value allowed by the technical specifications.
The licensee generated a work order to reset the setpoints, and the system engineer was informed of the setpoint shift.
A further evaluation of the setpoint shift was not performed, because the time and date of the setpoint change was unknown and the licensee suspected a maintenance-related cause.
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l
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On October 15, 1991, the Unit 3 operators noticed that the SG low pressure trip setpoints decreased by approximately 50 pounds per square inch (psi) for no apparent reason.
This occurred in PPS Channel
"B,"
affecting both steam generators.
Condition Report/Disposition Request (CRDR) 3-1-0171 was generated to document the licensee's evaluation of this event.
The licensee could not determine when the setpoint had changed and could not recreate the condition.
The event was determined not to be reportable based on the assumption that the event occurred at the time of discovery.
On December 12, 1991, the Unit 3 SG low pressure reactor trip setpoint for SG number 1 on PPS Channel
"B" was again found to be approximately 50 psi below the allowable value.
This was identified during the performance of Surveillance Test 43ST-3ZZ16,
"Routine Surveillance Daily Midnight Logs."
CRDR 3-1-0236 was generated to evaluate this event.
Although the event was not considered reportable, the evaluation of this event is not yet complete.
Engineering Evaluation Request (EER) 92-SB-002, which was initiated as a result of this event, recommended implementing alarm points in the plant monitoring system, which already monitors the setpoint value, so that the specific time of future setpoint changes could be determined and possibly correlated with other indications to allow a definitive root cause determination.
On January 21, 1992, the Unit 3 low pressure'rip setpoints for both SGs on PPS Channel
"C" were found to be approxi'mately 50 psi below the allowable value.
This was identified during a board walkdown by the oncoming shift supervisor during shift turnover.
CRDR 3-2-0023 was generated to evaluate this event.
Affected PPS parameters in Channel
"C" were bypassed while the licensee performed troubleshooting activities.
The channel was declared operable on January 24, 1992, after troubleshooting failed to determine any deficiencies in the equipment.
The CRDR evaluation is not yet complete.
(The inspector noted that similar events subsequently occurred three times in PPS Channel
"B" in Unit 2 on February 4, 8, and 9, 1992, after the inspection period ended.
These occurrences will be reviewed as part of the followup item discussed below.)
The low pressure setpoint normally ramps up automatically as secondary pressure is increased, remaining approximately 200 psi below actual pressure until a maximum setpoint of 919 psi absolute (psia) is reached.
As steam flow and turbine load increases from no load to full load, steam pressure decreases from about 1170 psia to 1070 psia.
A single'eset push button for each channel allows the operators to manually decrease the setpoint for both SGs to 200 psi below the current pressure to allow for normal plant cooldown.
The setpoint is required to be greater than or equal to 912 psia while in Modes 1 and 2, and the normal setpoint is 919 psia.
In each'f the events, only'one of the PPS channels was affected.
Technical specifications require two channels to be operable.
The effect of a setpoint being low is that two of the remaining three-24-
channels must sense a
SG low pressure before a reactor trip or ESF system actuation will occur.
If one of the other channels is in bypass (for maintenance or testing),
both of the remaining channels must function properly for a reactor trip or ESF system actuation to occur at the pressure assumed in the updated final safety analysis report.
Following discussions initiated by the inspector regarding the basis for operability of PPS channels with setpoints shifting unexpectedly and without annunciation, the licensee increased the setpoint monitoring frequency from daily to hourly, and accelerated the implementation of the continuous setpoint monitoring as recommended by EER 92-SB-002.
The inspector concluded that immediate corrective actions taken by the licensee (by repairing and troubleshooting the affected channel)
were appropriate, and that the necessary further evaluation of the setpoint changes is aggressively being performed.
However, the inspector also concluded that the licensee was slow to,recognize the significance of
'he deficient conditions and to implement appropriate compensatory corrective actions.
The inspector will review the licensee's evaluations, as documented in the aforementioned CRDRs, upon completion.
(Followup Item 530/91-50-02).
No violations of NRC requirements or deviations were identified.
eactor Tri on Loss o
Instrument Air Un t 3 9370 On January 24, 1992, Unit 3 tripped from 100 percent power following a reactor power cutback ca'used by operators manually tripping the "B" main feedwater pump.
The operators tripped the "B" main feedwater pump in response to a loss of instrument air, which resulted in the mini-flow valves opening fully and bringing in the low feedwater suction pressure alarms on both pumps.
The low suction pressure trip circuit for the feedwater pumps will trip the "B" main feedwater pump first, so the operators decided that tripping the "B" main feedwater would increase the likelihood of keeping one main feedwater pump in operation during recovery.
The main feedwater pump trip initiated a reactor cutback which resulted in a reactor trip due to the resetting of the. reactor cutback timer from 16 seconds to zero seconds as described in Inspection Report 530/91-41, Paragraph 11.
Following the trip, the reactor coolant system temperature decreased more than expected and the operators decided to take manual control of the feedwater control system to reduce the feed rate to below the reactor trip override feed rate.
In addition, steam bypass control valve (SG-1008) failed to fully close as expected until 'the operators manually placed the control switch in OFF.
Following the event, the inspectors noted that the operators had failed to log the shifting of the feedwater control system to manual and placing SG-1008 in OFF in the control room log.
Other than these logging omissions, the inspector concluded that operators responded appropriately to the event.
The licensee acknowledged the inspector's observation.
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The reason for the loss of instrument air was a failure of a nonsafety-related 1-inch copper sweat joint which blew a short section of instrument air piping out of the system.
The shift supervisor requested immediate repairs to the instrument air system.
Mechanics inspected the failed piping and were directed by the shift supervisor to use it to repair the system to assist operators in plant recovery.
Although this corrective action eliminated the possibility for a more thorough root cause evaluation of the failure, the inspection by mechanics revealed that the previous sweat joint did not appear to have occurred with full insertion and was less than the normal width.
When questioned regarding the reuse of the copper piping, the maintenance manager indicated that no other material was immediately available and the priority had been system restoration to assist plant recovery.*
The inspector concluded that this action appeared appropriate.
No violations of NRC requirements or deviations were identified.
Plant Procedures
-. Units
2 and
42700 The inspector performed NRC Inspection Module 42700 on plant procedures.
Based upon a review of the 61 selected procedures, the inspector concluded that the procedures appeared to meet the technical specification requirements and had been reviewed for unreviewed safety questions in accordance with 10 CFR 50.59.
A sampling of working copies of checklists in the selected procedures found that the checklists were the latest revision.
Overall, the procedures appeared to meet the technical specification requirements with one administrative exception, which the licensee committed to correct.
No violations of NRC requirements or deviations were identified.
Observation of Simulator Trainin
- Units
2 and
71707 The inspector observed two simulator training sessions.
The licensee identified weaknesses in operator communication and command and control in both sessions, and observed an inadequate operator response to alarms in one training session.
The training staff provided critical feedback and facilitated constructive discussion with the operators concerning their performance in these areas.
The inspector concluded that the training staff was aware of management's-expectations and the need for improvement in the area of clear communication and command and control.
The inspectors will continue to follow the licensee's conduct of simulator training.
No violations of NRC requirements or deviations were identified.
Licensee Res onse to
CFR Part
Re orts of Defects in Barton Transmitters Units
2 and 3 -
92700 In November 1991, ITT Barton filed two 10 CFR Part 21 notifications regarding manufacturing defects in pressure transmitters.
The licensee-26-
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I
has observed the identified conditions in ITT Barton transmitters installed or in storage at Palo Verde.
The first defect involves wiring damage at the point of exit from the transmitter housing which could compromise the environmental qualifi-cation (Eg) of the transmitter.
No problems resulting from this defect have been reported by the industry.
The licensee inspected all 120 potentially affected transmitters in the warehouse and found three with the defect.
None of the 14 transmitters inspected in Unit 2 were found to have the defect.
The licensee determined, with 95 percent confidence and 95 percent quality, that no transmitters installed at any Palo Verde unit have the defect.
Additionally, the licensee determined that the defect would not compromise the Eg integrity of the transmitters, and that additional field inspections were not warranted.
The second defect involved a connecting pin inside some transmitters which may have inadequate clearance from a screw'head.
This condition could result in the transmitter failing low due to a short circuit.
The licensee performed inspections of transmitters in the warehouse and in Unit 2, which was shutdown at the time, and found several transmitters with less that the 1/16-inch clearance specified in the
CFR Part
notification.
The licensee questioned ITT Barton regarding the
'clearance specification and found that ITT Barton had made an error in the notification.
The clearance was supposed to be at least 0.018-inch.
Additional data from ITT Barton was used by the licensee to determine in Engineering Calculation ¹13-NC-XI-200 that 0.005-inch was the minimum required clearance.
ITT Barton responded by issuing a December 19, 1991, clarification of the
CFR Part 21 notification stating that the clearance should be 0.0l-inch instead of -1/16-inch, based on the licensee's calculation and including a factor of two for a safety margin.
Using the revised criteria of 0.005-inch clearance, no transmitters were identified with inadequate clearances.
The licensee plans to adjust all clearances to be not less that 0.01-inch.
Seven transmitters were identified in Unit 2 which did not require immediate inspection based on their function.
However, all suspected serial numbered transmitters were inspected.
The licensee committed to inspect the transmitters in Unit 1 during the refueling outage scheduled to begin in February 1992.
Only one of the
transmitters in Unit 1 was suspect, based on serial numbers, and this transmitter was inspected during the force'd outage in January 1992.
In Unit 3, 9 of 29 transmitters were suspect, based on serial numbers.
However, further communication from ITT Barton indicated that all Hodel 763 and Hodel 763A transmitters are now suspect.
The licensee intends to inspect all suspect transmitters with important safety functions prior to the September 1992 refueling outage unless a significant ALARA concern exists.
The others will be inspected during the refueling outage.
'The inspector concluded that the licensee's actions were appropriate and adequate, and that engineering had performed well in identifying the-27-
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error in the pin clearance information in the
CFR Part
notification and in developing a well-founded action plan for the inspections.
No violations of NRC requirements or deviations were identified.
Falsified Ins ector Trainin Record for Fire Barrier Ins ections - Units and
92701 On January 24, 1991, NRC Region V was informed that a training record related to fire barrier inspector training had been falsified.
These inspections were performed by a contractor (TENERA).
Contractor managers had notified Palo Verde of the record falsification.
The training record was related to classroom training for additional contractor personnel needed to perform fire barrier inspections at Palo Verde.
The falsification involved the addition of three names to the training record when, in fact, these three individuals had not 'attended the training.
Mhen interviewed, the contractor project manager admitted falsification of the record.
The licensee's investigation and conclusions are described in Incident Investigation Report (IIR)
3-1-91-018.
20.
The inspector reviewed IIR 3-1-91-018 and had discussions with licensee personnel at various times during the licensee's resolution of the matter.
The licensee's corrective actions included (1) performing a
review of the contractor's training records, (2) sampling the work performed by the three inspectors whose training records were falsified, (3) reviewing technical documentation of deficiency dispositions, and (4) reviewing the project manager's role in activities at Palo Verde.
The quality assurance department played an active role in the oversight of the resolution of this issue.
The licensee concluded that the falsification was an isolated case and that the missed training did not materially impact the inspectors'ork.
The inspector concluded that the licensee's corrective actions and conclusions appeared adequate.
The contractor's falsification of the required training record appears to be a, violation of 10 CFR 50.9 which requires that information required by NRC regulations to be maintained by the licensee shall be complete and accurate in all material respects.
CFR Part 50, Appendix 8, Criterion XVIII, required that records, such as personnel qualification, be maintained to furnish evidence of activities affecting quality.
Training records provide evidence of personnel qualifications; therefore, these records are considered to be a quality activity covered under
CFR Part 50, Appendix 8, Criterion XVIII (Violation 50-528, 530/91-50-03).
One violation of NRC requirements was identified.
Review of Licensee Event Re orts Units
2 and
92700 and 9270 The following licensee event reports (LERs) were reviewed by the resident inspectors:
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Unit t Closed ER 528 91-2- 0:
"Inadvertent Control o
m s
e tial iltrat'on ESF ctuation" - Unit
92700 This December 5,
1991, engineered safety features (ESF)
system actuation was caused by the failure of an operator to insure that the trip signal was cleared before resetting the actuation module during performance of a surveillance test.
The event was reviewed in Inspection Report 528/91-41, Paragraph 7.
This item is closed on the basis of the previous review.
Unit 2 Closed LER 529 91-03-LO:
"Manual Reactor Tri Durin Shutdown" Un't 92700 This event was discussed in Inspection Report 529/91-29 in Paragraph ll.
The LER does not suggest any additional issues.
This item is closed.
Closed LER 529 91-04-LO 1:
"Reactor Generator Tu bi e ri " - Unit 2 92700 ol ow n This event, was discussed in Inspection Report 529/91-29 in Paragraph 12.
The LER does not suggest any additional issues.
This item is closed.
Unit 3 Closed LER 530 90-05-LO
CFR Part
"Incorrect Backu Rin Material in Feedwater Isolation Valve 4-Wa Va ves" - nit 3 92700 This
CFR Part 21 report addresses improper materials provided by Anchor/Darling for 4-way valves which are part of the controls for the feedwater isolation valves (FWIVs).
This issue was previously evaluated in Inspection Report 528/90-28, Paragraph 14.
Additional failures of FWIVs are discussed in Inspection Report 528/91-15, Paragraph,7, although no additional improper material issues were identified.
This item is closed on the basis of previous review.
Closed LER 530 91-03-Ll:
"Inadvertent Containment S ra ctuation" - Unit 3 92700 This LER supplement addresses resolution of the licensee's position on the desired operator actions following inadvertent containment spray events at power.
Specifically, the licensee determined that reactor coolant pumps (RCPs)
should not be immediately manually tripped, as was done in the June 19, 1991, event in Unit 3.
Procedures have been changed to allow continued-29-
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operation at power, and continued RCP operation, for up to 10 minutes following an inadvertent containment spray event, as long as cooling water to the RCP seals is restored within that time and there are no apparent indications of damage to the RCP thrust bearings or motor. If cooling has been restored to the seals, operation beyond 10 minutes will be evaluated on a case-by-case-basis.
If it becomes necessary to stop the RCPs, the operators will first manually trip the reactor, as occurred in the subject event.
This LER is closed on the basis of the previous reviews of the event and original LER, and on the inspector's conclusion that the changes in corrective actions appear appropriate.
Closed ER 530 91-06-LO:
" oss o
Safet us PBB-S04" Un't 3-92700 This LER discussed an electrical ground which occurred on DC Control Power Bus NKNM46 on August 24, 1991.
Normal Supply Breaker NRNS06C to Startup Bus NANS06 opened resulting in a loss of power to the "B" train Class-1E 4160 volt bus (PBBS-04).
The licensee determined that rain water entered Plant Hultiplexer Cabinet 3ENANg03 through an inadequate seal around the cabinet's air conditioning penetration during a rain and wind storm.
The water caused an intermittent electrical short circuit between wires "P2" and "2" of the trip indication circuitry for Circuit Breaker NANS06C, causing the trip coil of Circuit Breaker NANS06C to actuate.
The licensee also determined that voltages discovered on the 13.8 kV bus (NANS06) after Circuit Breaker NANS06C opened were induced by the energized 525 kV transmission lines.
Finally,
- the licensee determined that this event may have been prevented if
,explicit instructions were included in the preventative main-tenance task to inspect for signs of moisture intrusion.
The licensee's interim corrective actions included repairs to the damaged internal circuitry of Plant, Multiplexer Cabinet NANg03, inspection of all switchyard multiplexer cabinets for Units 1, 2, and 3 for evidence of water intrusion and sealing of all deficient cabinets, cleaning and inspection of the internal components of all switchyard multiplexer cabinets, and upgrading of the air conditioning flashing for Plant Hultiplexer Cabinets NANg02 and NAN(03 in Unit 3.
The licensee also initiated corrective action documents which provided a detailed analysis of all plant multiplexer interfaces with external components to determine if there existed the possibility of inadvertent equipment actuations due to either a
multiplexer component failure or interface failure.
An evaluation was also provided of the multiplexer cabinet integrity and recom-mendations were submitted for corrective actions to prevent internal component failure induced by external means.
An evalu-ation was submitted on the necessity of upgrading the current-30-
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lg multiplexer system to increase the reliability and availability of the system.
Instruction change requests (ICR) have been submitted to incorporate instructions into Procedure 4XOP-XNA01 which would, allow energizing 13.8 kV busses, NANS05 arid NANS06, from their alternate sources, and'to incorporate instructions into the preventative maintenance tasks which direct the cleaning and inspection of the multiplexer cabinets.
The inspector concluded that the licensee's actions following this event and all corrective actions initiated appear to be appropriate.
This item is closed.
(4)
Closed LER 530 91-10-LO:
"ESF Actuations Caused b
Manual eener ization of Offsit owe
" U t 3
00 This LER identifies two partial loss of power events that occurred on November 15, 1991, in Unit 3, as a result of operators manually interrupting offsite power to each of the two 4160 volt engineered safety features (ESF) electrical buses, in response to a mobile crane coming in contact with the energized 13.8 kV power lines supplying half of the. offsite power to the unit.
This event was fully investigated by an NRC Augmented Inspection Team and reported in Inspection Report 530/91-47.
This LER is closed on the basis of this prior review.
(5)
C osed LER 530 91-11-LO:
"Auxiliar Feedwater low Transmitters E ualizin Valve Im ro erl Ali ned" Unit 3 92700 and
01 This event is discussed in Inspection Report 530/91-40, Paragraph 10, and in Paragraph 2 of this inspection report.
This
'item is closed.
No violations of NRC requirements or deviations were identified.
21. ~ill t
'n exit meeting was held on January 28, 1992, with the licensee's management representatives identified in Paragraph 1, during which the observations and conclusions in this inspection 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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