ML20058H423
| ML20058H423 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 09/10/1993 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML20058H410 | List: |
| References | |
| 50-528-93-35, 50-529-93-35, 50-530-93-35, NUDOCS 9312130077 | |
| Download: ML20058H423 (30) | |
See also: IR 05000528/1993035
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION V ;
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Report Nos. 50-528/93-35, 50-529/93-35, and 50-530/93-35
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Docket Nos. 50-528, 50-529, and 50-530
License Nos. NPF-41, NPF-51, and NPF-74
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Licensee: Arizona Public Service Company i
P. O. Box 53999, Station 9082
Phoenix, AZ 85072-3999
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Facility Name: Palo Verde Nuclear Generating Station
Units 1, 2, and 3
Inspection
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conducted: July 13 through August 16, 1993
Inspection
Location: Wintersburg, AZ .
Inspectors J. Sloan, Senior Resident Inspector '
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H. Freeman, Resident Inspector
A. MacDougall, Resident Inspector
F. Ringwald, Resident. Inspector .
B. Olson, Project Inspector l
T. Alley, Department of Energy Inspector
Approved By /< d f/o/13 f
K. Wong, Chief L/ D&te Signed
Reactor ProjectsSection II !
Summary: j
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Areas Inspected: Routine, announced, resident inspection of:
- the review of plant activities
e engineered safety features walkdowns - Units 1 and 3
- surveillance testing - Units 1, 2, and 3
- plant maintenance - Units 1, 2, and 3 i
e quality assurance audit report - Units 1, 2, and 3
- employee concerns program temporary instruction - Units 1, 2, and 3
- auxiliary feedwater valve testing - Unit 2
- steam generator U-tube plug mis-insertion - Unit 2 ,
- proportional heater failure - Unit 2 _.
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- steam generator tube rupture followup issues - Unit 2
- restart issues - Unit 2 '
- technical specification interpretation - Unit 2
- blowdown heat exchanger inspection - Unit 3
- emergency diesel generator "B" rocker arm failure - Unit 3
- followup on previously identified items - Units 1, 2, and 3
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9312130077 931203
PDR ADDCK 05000528
G PDR
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~* review of licensee event reports - Units 1, 2, and 3
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During this inspection the following inspection procedures were utilized: !
2500/28, 37701, 40500, 61726, 62703, 71707, 90712, 92700, and 92701.
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Safety Issues Manacement System (SIMS) Items: None.
Result 1
General Conclusions and Soecific Findincs: [
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Strengths: '
- Operators in Unit 2 kept their focus on nuclear safety and demonstrated
good communications and self checking during a period of high activity
(Paragraph 2.d.13).
- On two occasions in Unit 3, workers. demonstrated good attention to detail i
by identifying and resolving errors in the work order (Paragraphs 14 and !
15).
- Workers were thorough and deliberate and displayed good teamwork during
repairs to the "B" emergency diesel generator in Unit 3 (Paragraph 15). '
- Mechanics were particularly meticulous in their cleaning and handling of ';
replacement parts, and used a particularly high degree of care while l
reinstalling the components during planned maintenance of a charging pump j
in Unit 1 (Paragraph 5). ,
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Weaknesses: i
- A formal review was not performed regarding the identification of an
abnormal tube crack growth rate and an axial tube crack located in the
tube free span region in Unit 2 Steam Generator 22 (Paragraph 11.b). :
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- Steam generator tube rupture diagnosis and mitigation activities were not .
adequately prescribed in the emergency operating procedures (Paragraph. i
11.c). :
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- Two additional examples of a failure to document surveillance testing :
deficiencies were identified in Unit 1 (Paragraph 4). !
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- During the diagnostic testing of an auxiliary feedwater valve a torque
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switch was damaged when the worker failed to tighten the torque switch
set screw. Additionally, the work order did not have documentation for
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reinstallation of the torque switch (Paragraph 8).
- Two cases of work orders that did not provide adequate guidance for the
worker to properly complete the job were identified in Unit 3 (Paragraphs
14 and 15). ,
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Sionificant Safety Matters: None.
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-Summary of Violations: Of the 18 areas inspected, two cited violations were !
. identified. One violation in Unit 2 involved the failure the properly review -
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abnormal tube crack growth rates and free span axial tube crack in Steam ,
Generator 22. The second violation involved weaknesses in the emergency !
operating procedures concerning steam generator tube rupture diagnosis and ;
mitigation activities. ,
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Summary of Deviations: None.
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Unresolved Items: One item remained unresolved regarding a work order not !
providing a step for installation of the torque switch and the subsequent i
failure of the technician to properly adjust the torque switch after ;
installation (Paragraph 8) i
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DETAILS !
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1. Persons Contacted j
The below listed technical and supervisory personnel were among those
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contacted: ,
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R. Adney, Plant Manager, Unit 3 l
S. Bauer, Senior Engineer, Nuclear Regulatory Affairs 1
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R. Bernier, Supervisor, Nuclear Regulatory Affairs, Technical l
l R. Bouquot, Supervisor, Quality Audits and Monitoring '
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T. Bradish, Manager, Nuclear Regulatory Affairs :
P. Coffin, Engineer, Nuclear Regulatory Affairs ;
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J. Dennis, Manager, Operations Standards / Plant Support !
R. Flood, Plant Manager, Unit 2 :
R. Fountain, Supervisor, Quality Audits and Monitoring i
R. Fullmer, h nager, Quality Audits and Monitoring ;
D. Gouge, Director, Plant Support
W. Ide, Plant Manager, Unit 1 '
J. Levine, Vice President, Nuclear Production l
D. Mauldin, Director, Site Maintenance and Modifications
J. Minnicks, Manager, Valve Services
G. Overbeck, Director, Site Technical Support ,
R. Prabhakar,. Manager, Independent Safety and Quality Engineering ;
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C. Russo, Manager, Quality Control i
C. Seaman, Director, Quality Assurance and Control l
R. Spencer, Quality Control !
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Others l
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J. Draper, Site Representative, Southern California Edison l
F. Gowers, Site Representative, El Paso Electric -;
R. Henry, Site Representative, Salt River Project j
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Denotes personnel in attendance at the Exit meeting held with the- !
NRC resident inspectors on' August 17, 1993. !
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2. Review of Plant Activities - Units 1. 2. and 3 (71707) j
a. Unit I f
Unit end-of-cycle
I began the inspection l
The coastdownperiod
continued. at 89%Tc p'ower with Tstabilizedakat.554'F.
550 *F on' t
July 18, 1993. Power was then allowed to decrease to a lower-limit ,
of 72% power, reached on August 12, 1993. Dilution maintained l
reactor power at 72% until the end of the-inspection period. A' !
Notice of Unusual Event (NUE) was declared on August 5,1993, at -l
7:30 p.m. when the meteorological tower instrumentation failed '!
during a severe weather disturbance. The NUE was terminated on :
August 7,1993, at 11:07 p.m. when required instrumentation was '
restored. :
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_ . . b. Unit 2 -
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At the end of the previous inspection period on July 9,19'93,
approximately 100,000 gallors of circulating water (CW) spilled onto ,
the turbine building floor while establishing conditions to draw a '
vacuum in the "A" main condenser. The static head of the cooling -
tower apparently forced water back through an unseated CW isolation
valve and out of open "B" main condenser manways. It appeared that
the valve remained slightly open due to mis-adjustment of the . limit :
switches of the valve. The water which soaked into the land
surrounding the turbine building was analyzed for radioactivity and !
found to be below regulatory limits.
Unit 2 began this inspection period in Mode 5. After completing
inspection and repair work on the steam generators, Unit 2 began
plant heatup and entered Mode 4 on August 10, and Mode 3 on August :
11. On August 13, an unisolable steam leak was discovered on a -
defective steam generator instrument nozzle weld. The unit
commenced plant cooldown to conduct repairs and entered Mode 5 on
August 14. The unit ended the inspection period in Mode 5. ;
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c. Unit 3 !
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Unit 3 operated the entire inspection period at 1005; power. On 8
August 6, 1993, a severe storm caused exterior damage to portions of
the Turbine building. Several pieces of sheet metal were torn off ,
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and flying debris punctured the plant vent piping. The hole was a !
few inches long and was quickly repaired. The storm did not cause [
any other damage and did not impact plant operations or safety. l
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d. Plant Tour I
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The following plant areas at Units 1, 2, and 3 were toured by the
inspector during the inspection
e Auxiliary Building !
- Control Building i
e Diesel Generator Building ;
- e Fuel Euilding
e Main Steam Support Structure
e Radwaste Building
e Turbine Building !
e Yard Area and Perimeter i
e Containment Building j
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The following areas were observed during the tours: !
(1) Ooeratina logs and Records - Records were reviewed against f
Technical Specifications and administrative control procedure
requirements. l
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(2) Monitoring Instrumentation - Process instruments were observed !
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for correlation between channels and for conformance with ;
Technical Specifications requirements. j
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(3) Shift Staffina - Control room and shift staffing were observed
for conformance with 10 CFR Part 50.54.(k), Technical :
Specifications, and administrative procedures. ;
(4)- Ecuipment lineuos - Various valves and electrical breakers were
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verified to be in the position or condition required by i
Technical Specifications and administrative procedures for the '
applicable plant mode.
(5) Eauinment Taccina - Selected equipment, for which tagging j
requests had been initiated, was observed to verify that tags !
were in place and the equipment was in the condition specified. !
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(6) General plant Eouipment Conditions - Plant equipment was
observed for indications of system leakage, improper i
lubrication, or other conditions that could prevent the systems ;
from fulfilling their functional requirements. ;
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(7) Fire Protection - Fire fighting equipment and controls were j
observed for conformance with Technical Specifications and ;
administrative procedures. j
(8) Plant Chemistry - Chemical analysis results were reviewed for l
conformance with Technical Specifications and administrative ,
control procedures. j
, (9) Security - Activities observed for conformance with regulatory I
requirements, implementation of the site security plan, and !
administrative procedures included vehicle and personnel ;
access, and protected and vital area integrity.
(10) Plant Housekeeping - Plant conditions and material / equipment l'
storage were observed to determine the general state of
, cleanliness and housekeeping..
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(11) Radiation Protection Controls - Areas observed included control l
point operation, records of licensee's surveys within the !
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radiological controlled areas, posting of radiation-and high !
radiation areas, compliance with radiation exposure j
, permits, personnel monitoring devices being properly worn, and '
personnel frisking practices, j
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(12) Shift Turnover - Shift turnovers and special evolution.
briefings were observed for effectiveness and thoroughness.
(13) Unit 2 Outace Operations - The inspector observed portions of
the following activities from the Unit 2 control room: reduced
inventory and mid-loop operations; reactor coolant system fill
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, and vent (drawing a pressurizer bubble and reactor coo.lant pump ,
sweeps); and Mode 4 and Mode 3 entry. The inspector concluded ;
, that operators did a good job controlling numerous evolutions ;
during a period of high activity. The operators kept their
focus en nuclear safety and demonstrated good communications
and self checking. For example, differential pressure testing
of auxiliary feedwater valves was stopped until an additional
operator was stationed in the control room to monitor the ,
evolution. l'
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(14) Offsite Safety Review Committee (OSRC) Meetina - The inspector i
reviewed the agenda and attended pertions of the OSRC meeting !
held on August II,1993. The OSRC members aggressively
discussed each issue that was presented. For example, the ;
committee was critical of the recent reactivity event in Unit 1
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caused by inadvertent addition of borated water to the primary :
from the volume control tank (see NRC Inspection Report 50- '
528/93-12). Although the OSRC stated that management's initial !
corrective actions were appropriate, they stressed the !
significance of the event and felt that management should l
remain vigilant concerning early detection of operator
complacency in this araa. The incpector concluded that the ,
committee activities were consistent with Technical l
Specification requirements and were appropriately focused on
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nuclear safety. i
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No violations of NRC requirements or deviations were identified. !
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3. Enoineered Safety Features (ESF) System Walkdowns - Units 1 and 3 (71710) ,
Selected engineered safety feature systems were walked down by the l
inspector to confirm that the systems were aligned in accordance with !
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. plant procedures. During this inspection period the inspectors walked
down accessible portions of the following systems: *
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Unit 1
Auxiliary Feedwater System
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Unit 3
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Auxiliary Feedwater System ;
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No violations of NRC requirements or deviations were identified. j
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4. Surveillance Testino - Units 1. 2. and 3 (61726)
Selected surveillance tests required to be performed by the Technical
Specifications were reviewed on a ' sampling basis to verify that: 1) the .
surveillance tests were correctly included on the facility schedule; 2) a !
technically adequate procedure existed for performance of the
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surveillance tests; 3) the surveillance tests had been performed at the ;
frequency specified in the. Technical Specifications; and 4) test results
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satisfied acceptance criteria or were properly dispositioned.
Specifically, portions of the following surveillances were observed by l
the inspector during this inspection period:
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Unit 1 !
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Procedure Description ,
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36ST-95B02 PPS Bistable Trip Units Functional Test j
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35ST-ISE02 Excore Linear Monthly Calibration i
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Main Steam Isolation Valves Surveillance 4.7.1.5
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41ST-1ZZ33 Mode 1 Surveillance Logs !
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36ST-9SB04 PPS Functional Test - RPS/ESFAS Logic l
Unit 2 !
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Procedure Description
35ST-9SB02 PPS Bistable Trip Units Functional Test j
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36ST-2SE06 Log Power Functional Test
Unit 3 :
Procedure Description -l
43ST-3AF03 Auxiliary Feedwater Pump AFB-P01 Operability Test l
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On July 21, 1993, the NRC inspector Lbserved a portion of surveillance ':
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test 36ST-9SB02, "PPS Bistable Trip Units Functional Test." The i
inspector noted that an unsatisfactory reading was documented and .-
appropriately annotated with the date of July 20, 1993, and yet no entry y
was in the surveillance test log as required by 73AC-9ZZO4, " Surveillance i
Testing." The inspector discussed this with licensee supervision and !
management. The licensee agreed that the test log entry should have been :
made as the unsatisfactory reading was identified, and counseled the ,
technicians.
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On August 5,1993, the NRC inspector observed portions of 41ST-ISG01, i
" Main Steam Isolation Valves Surveillance." During the partial close ;
stroke test both close and open indications were received for Main Steam .!
Isolation Valve (MSIV), SGE-UV-171. During efforts to correct the dual j
indication, the "B" train hydraulic actuator was given an open signal and i
the Auxiliary Operator observed the valve to move in the close direction
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to the 70% open position (the MSIVs have separate and redundant. hydraulic "
actuators powered from separate sources). .
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The Reactor Operator then gave the "B" train another open signal and the
valve returr.ed to the fully open position. The surveillance test was >
stepped and the system engineers contacted. The system engineers i
determined that the handswitch was most likely the cause of the event and ,
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a work request was generated to troubleshoot the stiffness .of the
handswitch springs (troubleshooting the switch had not started at the *
, close of this inspection period). The valve was then satisfactorily 'i
retested, which indicated that the event was not repeatable. The ;
operators then marked the surveillance test steps as satisfactory and l
continued with the surveillance test. i
The inspector reviewed the surveillance test procedure the following day l
and noted that this event had not been documented in the surveillance ;
test (ST) log as required by licensee procedure 73AC-9ZZO4, " Surveillance !
Testi ng. " The inspector discussed this with the Assistant Shift
Supervisor and the Assistant Shift Supervisor s',ated his expectation was i
that these types of anomalies would not be docimented in the ST log. The-
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inspector noted that the Assistant Shift Supervisor's expectation was
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contrary to that specified by procedure 73AC-9ZZO4. In later discussions
with the Snift Supervisor, it w&s concluded that the want sbuld 'ce
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documented in the ST log. ;
These are two additional examples of failure to document surveillance
- testing deficiencies identified in the Notice of Violation in NRC .
- Inspection Report 50-528/93-26. At the exit meeting, the licensee agreed l
! to incorporate these issues in its response to that Notice of Violation. :
- 5. Plant Maintenance - Units 1. 2. and 3 (62703) !
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During the inspection period, the inspector observed and reviewed i
selected documentation associated with maintenance and problem i
investigation activities listed below to verify compliance with
regulatory requirements, compliance with administrative and maintenance !
procedures, required quality assurance / quality control department l
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involvement, proper use of safety tags, proper equipment alignment and l
use of jumpers, personnel qualifications, and proper retesting. The i
inspector verified that reportability for these activities was correct. '
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Specifically, the inspector witnessed portions cf the following i
maintenance activities: ;
Unit 1
- "E" charging pump plunger / packing replacement
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- New fuel receipt !
- Calibration of the fuel / auxiliary building essential air' filtration
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unit charcoal differential temperature ;
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- Inspection of emergency diesel generator "B" rocker arms
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On July 22, 1993, the inspector observed a portion of the "E" charging
l pump plunger and packing replacement. The work proceeded in accordance
with the work instructions. Despite several distractions, the mechanics
were particularly meticulous in their cleaning and handling of
replacement parts, and used a high degree of care while reinstalling the
components. Communication was effective, and the work group supervisor
was directly involved in supervising the work without interfering. The
inspector concluded that this work was performed well.
Unit 2
- Motor operated valve testing of AFA-UV-35
Unit 3
- Steam Generator blowdown heat exchanger inspection
- Emergency diesel generator "B" rocker arm replacement
a CEDMCS CEA coil traces at power
$ violations of NRC requirements or deviations were identified.
6. Review of Quality Assurance (OM Audit Reoort 93-007. " Plant Ooerations"
- Units 1. 2. and 3 (40500) ,
The inspector reviewed a licensee's QA audit report (Audit 92-007).
Based on this review, the inspector determined that the audit was of
sufficient breadth and depth to reveal significant strengths and
weaknesses of operations activities. The audit revealed continuing I
weaknesses in three areas: performance of rounds by auxiliary operators
(A0s), use of the lamp reference index, and use of special variances,
indicating that corrective actions were not fully effective. The audit i
also revealed a deficiency related to independent verifications. Each of
the deficiencies was clearly communicated in the report, and appropriate
corrective action documents were initiated for the deficiencies.
The A0 rounds deficiencies identified in the report appeared to be less i
significant than the types of deficiencies observed by the licensee and i
documented in Corrective Action Report (CAR) 92-0104 and in NRC !
Inspection Report 50-528,529,530/92-35, Paragragh 10.d.(4). The notable 1
fact about the recent observations was that nine errors were identified i
during the observation of eight A0s performing Area 5 and Area 6 rounds. :
The audit report indicates that the errors were due in part to weaknesses !
in the A0 rounds procedure, which required checks to made of all fan
belts, even though the fan belt guards on some equipment prevented access l
to perform the checks. Most of the remaining errors involved a weakness !
in the understanding of performance expectations as documented in the i
procedure. In response to these findings, the licensee formed a task l
force to review and clarify the A0 rounds procedure, 40DP-90P20. Quality
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Deficiency Reports were also issued to the Operations Manager for each e
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unit to address the performance issues. .
The inspector concluded that the audit was effective in identifying
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significant weaknesses and in communicating the findings to appropriate r
, management for resolution. Additionally, the inspector concluded that I
continued management attention is warranted to address performance ;
deficiencies identified by the audit team. ,
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The licensee findings described in NRC Inspection Report j
50-528,529,530/92-35, Paragraph 10.d.(4) are being _further evaluated by .
the NRC; therefore, NRC Followup Item 50-529/92-27-02 is being reopened. i
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No violations of NRC requirements or deviations were identified. ;
7. Employee Concerns Procram Survev - Units 1. 2, and 3 (TI 2500/028)
The inspector reviewed licensee procedures and had discussions with the i
Palo Verde Employee Concern? Program manager. The results are documented i
in an attachment to this inspection report.
No violations of NRC requirements or deviations were identified. 3
8. Auxiliary Feedwater Valve Testino - Unit 2 (62703) j
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During the performance of the dynamic differential pressure testing on i
the auxiliary feedwater supply isolation valve to Steam Generator 22
(AF-35), torque switch " chatter" was observed. Troubleshooting was_ ,
performed to determine the cause of_ the " chatter" and to correct the !
anomaly. The torque switch and type of compression springs for the !
torque switch were replaced. Another anomaly was then identified in the i
relaxation of the spring pack allowing the torque switch contacts to i
reclose after opening. The spring pack was first replaced with a ;
" lighter" spring pack which would not permit the operator to generate the ,
required thrust. A new styl- " heavier" spring pack was then installed. '
Work Order 605526, Revision /G, did not have a step for reinstalling the i
torque switch after installing the spring pack. However, during previous
evolutions requiring the replacement of the. torque switch, covered under
other revisions to the work order, the work order required this evolution
to be performed per procedure 32MT-9ZZ46, " Disassembly / assembly of
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Limitorque type SMB/SB-0 thru SMB/SB-4 actuators," section 4.45. The
technician replaced the torque switch, yet there was no documentation
reflecting the performance of procedure 32MT-9ZZ46, Section _4.45,. for
this evolution.
After replacing the spring pack, the work order required an "as-left"
MOVATS " static" test be performed using procedure 32MT-9ZZ56, " Motor
operator testing using MOVATS series 3000/3386 systems," as applicable.
During the performance of this test the torque switch was damaged while
opening the valve.
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Troubleshooting revealed that the open torque switch adjusting screw was :
loose. The technician stated he had loosened the open adjusting screw
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. while setting the close adjusting screw and had failed to tighten the
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open adjusting screw prior to continuing with the test. Section'4.13 of
procedure 32MT-9ZZ56, delineates the steps to be performed when doing an '
"as-left" MOVATS static test. Steps 4.13.7 and 4.13.13 requirerl ,
adjusting the torque switch settings in accordance with Appendi: Q.
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Appendix Q required that the torque switch adjusting screw be tightened '
after adjusting the torque switch setting. The inspector concluded this
appears to be a failure of the technician to follow procedure 32MT-9ZZ50 ;
when adjusting the torque switch. Valve Services Management did not
agree and stated that the technician was using " skill of the craft" r
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rather than Appendix Q of procedure 32MT-9ZZ56 when the open torque
switch adjusting screw was loosened. I
The inspector will review the potential inadequacies of the work ;
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instructions and the potential failure of the technician to follow
procedures when adjusting the torque switch during a future inspection
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(Unresolved Item 50-529/93-35-01). !
No violations of NRC requirements or deviations were identified.
9. Steam Generator U-tube pluo Mis-insertion - Unit 2 (627031
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The inspector reviewed the occurrence of a steam generator U-tube
mechanical plug that was inserted into the wrong tube on July 10, 1993. l
The wrongly inserted plug was identified by the licensee during the (
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Quality Control (QC) phase of tha tube plugging process. Because the I
plug had not been mechanically f .ed in place (rolled), it was removed,
reinserted into the correct tube and its location was verified by a QC l
inspector. The mis-inserted plug was documented on Quality Deficiency
Report (QDR) 93-0120. The inspector reviewed the QDR and the tube
plugging process that led to the mis-inserted tube. ;
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Tube plugging was performed by a contractor using procedure 31CP-9RC01,
" Field Procedure for Rolled Plugging." Step 4.6.3 of the procedure
required that the tube to be plugged be located and verified. The tool
operator would typically locate the tube to be plugged using the
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manipulator mounted camera either by counting from a known location, by '.
using the manipulator's reference points, or by using both methods. i
Because the manipulators have some inaccuracy in positioning the plug,
counting tubes is the method preferred by the li:ensee. However, the :
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i location o# the manipulator sometimes precludes a direct view of the tube
to be plugged.
The tube located at row 68, line 41 was located as described above.- A ,
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plug was inserted and the task leader initia11ed Enclosure 1, " Rolled
plugging Checklist " that the tube was located and verified for plug -
insertion. However, the plug was discovered to have been inserted into
the tube at row 67, line 42 by the task leader and by a QC inspector
during video taping of the plugged tube locations. Because the video
taping using a bowl mounted camera (rather than the manipulator mounted ,
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camera) was performed after a group of plugs were inserted and the
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manipulator removed, it was difficult tc determine the exact ca'use of the !
mis-insertion. -The tool operator and the task leader did not remember !
how that particular tube had been located. The QDR concluded that the e
mis-insertion was caused by the task leader and the tool operator !
miscounting. Additionally,- the QDR concluded that the procedure was !
unclear and that the task leader incorrectly signed the work order '
following the plug insertion rather than following the completion of the- [
verification process. l
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The contractor has revised the tube plugging procedure to clarify ;
responsibilities and procedures and to add a signature block after tube f
insertion. The procedure clarifies that the task leader will verify the !
plugs' locations during video taping. A QC inspector will still be {
present during. video taping to ensure that the tape sufficiently '
identifies the plug's location. An independent verification using the :
video tape will be performed by another QC inspector. -
The inspector concluded that the original procedure could be strengthened
to define the task leader's responsibilities for plug verification and
that the task leader inappropriately initialled for plug verification-
after insertion. Similar problems may have caused a tube to .be mis- l
plugged and reported in NRC Inspection Report 50-529/93-11. ;
Additionally, the inspector concluded that the procedure could also mare f
fully describe some of the steps being performed (including the video
recording used for independent verification). Followup of the corrective
actions to the QDR will be performed as part of the routine inspections ;
conducted during the upcoming Unit I refueling outage.
4 No violations of HRC requirements of deviations were identified.
10. Proportional Heater Failure - Unit 2 (62703 and 71707) !
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While Unit 2 was filling the reactor coolant system (RCS) during ,
preparations to enter Mode 4, pressurizer p oportional heater B14 shorted ;
to ground. The licensee determined that the heater sheath most likely
had a pinhole leak causing the ground in the heater. This was of concern :
because this same type of problem occurred with heater B18 during the
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last operating cycle. During the current Unit 2 refueling outage, heater
B18 was inspected and was found to have a failed sheath the entire length :
of the heater. The splitting of the sheath was previously determined to= t
be caused by the magnesium oxide heater element changing to magnesium .
dioxide when exposed to water (see NRC Inspection Report 50-528/90-23). !
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This reaction caused the heater element to expand and split the sheath. ,
f This was significant because the failure of the sheath may induce enough :
stress in the heater sleeve to induce a crack in the sleeve. A crack in
the sleeve would subsequently provide a potential path for a RCS leak.
The licensee inspected the sleeve of heater B18 and found no evidence of
damage due to the failed sheath. Additionally, all the other heaters ,
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were examined and no other obvious problems were noted. ;
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_. The inspector reviewed the evaluations conducted to determine the i
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significance of this event and the corrective actions. The evalpations- {
were documented in Material Nonconformance Report 93-RC-2011 and ,
temporary modification 2-93-RC-014. The licensee concluded that the- i
heater could be electrically isolated and repaired during a mid-cycle i
outage scheduled by the licensee as a part of the steam generator tube .
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rupture corrective actions. The decision to defer the repair / replacement i
was based on the following: ,
- Heater B18 electrically failed and was left in place for an entire l
cycle (18 months) with no damage to the heater sleeve. ;
- Combustion Engineering and other vendor studies on pressurized water :
stress corrosion cracking of Inconel 600 material determined that :
the heater sleeve would not fail for one to two operating cycles *
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when subjected to the worse case stresses from a failed heater.
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- A failure of the heater sleeve would most likely be an axial crack ;
which would leak before break and not cause a catastrophic failur-. ,
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- If the heater sleeve were to crack any leakage would be readily
detectable using routine leak rate calculations and baron leakage -i
inspections. :
The inspector concluded that the licensee's justification for not :
repairing the heater was reasonable and demonstrated that leaving the j
, heater in service until the mid-cycle outage was not a safety concern. ;
No violations of NRC requirements or deviations were identified. [
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11. Steam Generator Tube Ruoture (SGTR) Followup Issues - Unit 2 (92700) i
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The inspectors performed followup inspections of selected issues i
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documented by the NRC Augmented Inspection Team (AIT) in NRC Inspection
Report 50-529/93-14, related to the March 14, 1993, SGTR event in Unit 2. !
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a. Pressure Transient
On March 4,1993, a pressurizer level transient occurred, resulting i
in reactor coolant system pressure increasing from approximately i
2230 psia to about 2274 psia in 20 minutes. Concurrent with this
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transient, radiation monitors alarmed, indicating a possible
increase in the primary-to-secondary leak rate. 0perators ,
recognized the potential meaning of these conditions, but took no i
further action, as the radiation levels subsequently diminished to a !
somewhat higher steady state level (the details will be described in ;
NRC Inspection Report 50-528,529,530/93-29). ;
The unit log indicated that the transient was due to performance of l
surveillance test procedure 42ST-2CH05, " Charging Pumps Operability i
Test." The inspector reviewed this procedure, which required !
operators to manually reduce letdown flow to 20-30 gpm during the ;
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time a single charging pump is in service. The inspector noted that !
pressurizer level increased to approximately 55% during the test, -!
slightly below the 56% limit of Technical Specification 3.4.3.
. Procedure 42ST-2CH06 had no precautions or limitations regarding
maximum pressurizer level. The surveillance procedure stated that
the purpose of reducing letdown flow was to reduce the risk of
letdown isolation due to high temperature. The inspector noted that >
procedure 420P-2CH01, "CVCS Normal Operations," allowed single i
charging pump operations with letdown flow balanced with charging
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flow (pressurizer level control in automatic). The inspector
discussed with the licensee the requirement for maintaining reduced :
letdown flow for the duration of the single pump operation, and [
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determined that the reduced flow was only necessary during the ;
transition to single pump operation, and that normally the j
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surveillance test was accomplished quickly enough to prevent !
exceeding any operational -limits.
The inspector concluded that operators followed their procedures -and
that no operational limits were exceeded during the transient. l
Additionally, the inspector concluded that operational limits could l
be exceeded during the performance of procedure 42ST-2CH05. l
The licensee acknowledged the inspector's concern and committed to l
review the procedure for appropriate enhancements. ;
b. Analysis of Mid-span Axial U-Tube Crack !
As described in NRC Inspection Report 50-529/93-14, Paragraph I.3.e, ,
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the licensee discovered seven axial indications in Steam Generator
22 during the third refueling outage in 1991. Six of the r
indications were at the first tube support plate while the seventh !
indication was mid-span between the ninth tube ~ support plate and the !
batwing support. The seventh indication was the most significant in !
that mid-span indications have not been seen before at Palo Verde.
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This indication was located at row 117, column 54 (R117/C54) (not
R117/C154 as identified in NRC Inspection Report 50-529/93-14). j
Although all the tubes with axial indications were believed to have i
been plugged (tube R17/C152 was improperly plugged - see NRC :
Inspection Report 50-528/93-11), no formal evaluation of the !
significance of these indications was performed. These cracks were ,
significant because of the apparent rapid rate of crack growth.
Three of the first tube support cracks grew to approximately 80% :
through-wall, and the mid-span crack grew to approximately 75% l
through-wall in one operating cycle. None of these tubes showed any >
detectable degradation during the previous cycle. Additionally, !
although the first tube support cracks may have occurred due to ,
concentrations of contaminants in the crevice between the tube and !
the support plate and was not unusual, the presence of a mid-span I
crack was not expected. !
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_ Technical Specification 6.5.3.4.f requires significant operating :
abnormalities or deviations from normal and expected performance of
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unit equipment that affect nuclear safety to be reviewed by the ,
Nuclear Safety Group (NSG) [now the Offsite Safety Review Committee
(OSRC)]. A formal safety review by the NSG/0SRC was not performed
for the abnormal crack growth rate nor for the axial crack located
in 'ne free span region of tube R117/C54. This is a violation of
NRC requirements (Violation 50-529/93-35-02).
The inspectors noted that in response to the AIT's findings, the -
OSRC has increased its efforts to become more closely monitor
significant issues while they are being actively address by the :
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licensee staff.
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c. Emeraency Doeratino Procedures (EOPs)
The AIT (NRC Inspection Report 50-529/93-14, Paragraph 3) determined
that E0Ps were deficient in several respects. The inspector
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reviewed the licensee's corrective actions for these deficiencies.
- The diagnostic logic tree (DLT) of emergency procedure 42EP-
2E001, " Emergency Operations," considered only radiation !
monitors in alarm at the time of the event diagnosis, and
failed to allow consideration of radiation trends or previous
radiation monitor alarms. ,
The licensee revised 42EP-2E001 in April 1993, so that the DLT
included a block advising operators to consider past and i
present radiation monitor alarms. Additionally, DLT blocks for
selected radiation monitors required operators to consider
trends. The DLT also required operators to look broadly at
radiation monitor indications in diagnosing events. .
- The alert and alarm setpoints for the condenser exhaust and
steam line radiation monitors were based on offsite release
limits, rather than being based on the identification of a SGTR ,
event. However, the DLT assumed the radiation monitors would "
alarm during a SGTR event.
The licensee revised procedure 74RM-9EF42, " Radiation l
Monitoring Alarm Setpoint Determination," to require the :
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condenser exhaust radiation monitor (RU-141) alert setpoint to
be initially set at four times the average reading and to
verify the setting monthly. The inspector confirmed
appropriate settings were implemented in all three units. The i
licensee stated its intention to verify the setting in Unit 2 >
periodically after restart until the average stabilizes.
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- The portien of 42EP-2R003, " Functional Recovery Procedure ,
(FRP)," for mitigation of a SGTR was based on evaluation of !
radiation monitor alarms at the point in time that the step was
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being performed, rather than being continuously applicable.
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This prevented the appropriate guidance in the FRP from being -!
performed when the radiation monitors alarmed about five .
minutes after the step was performed. l
The inspector confirmed that the licensee had revised the FRP
to make the step (3.21) continuously applicable. ;
- The FRP did not provide guidance on the amount of time to allow i;
the steam generator blowdown radiation monitor to respond after
steam generator blowdown was restored. Failure to allow .
adequate radiation monitor response time could mislead l
operators during event diagnosis, delaying the correct
diagnosis and mitigating actions. ;
Restoration of sampling was accomplished in step 3.6. The ;
diagnosis was part of step 3.21, which was made continuously i
applicable in the licensee's June 1993 revision. This resolved
the deficiency regarding response time.
- FRP Appendix FQ, " Pressure and Inventory Control," did not
establish a reactor coolant system (RCS) depressurization. RCS !
depressurization was not addressed until FRP Section 5, "Long
Term Actions," while performance of Appendix FQ is directed by
Section 3, " Event Control." The time required to complete
Section 3 and enter Section 5 may lengthen the time of the :
event, when in fact the depressurization may quickly assist in
completing Appendix FQ.
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The licensee made step 3.21 continuously applicable, so that j
following diagnosis, depressurization would be directed by step '
3.23.
10 CFR Part 50, Appendix B, Criterion V, requires that activities
affecting quality be prescribed be documented by instructions, -
procedures, or drawings of a type appropriate to the circumstances. .
The SGTR diagnosis and mitigation activities described above were ;
not adequately prescribed in the E0Ps, which is a violation of NRC
requirements (Vi01ation 50-529/93-35-03) . -
As described above, the licensee subsequently revised the E0Ps to
address these deficiencies. The inspector concluded that these :
corrective actions were adequate. ~
Two violations of NRC requirements were identified. -
12. Restart Issues - Unit 2 (37701. 71707 and 92700) l
Several items were reviewed by the NRC staff prior to restart of Unit 2 !
following the March 14, 1993, steam generator tube rupture (SGTR) event. I
The first two of these issues were identified by the NRC's Augmented
Inspection Team (AIT) and were documented in NRC Inspection Report 50-
529/93-14.
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. a. OSPDS "A" Core Exit Thermocouples (CETs) -
Channel "A" CET readings were about 25 degrees high, causing the ,
subcooled margin indication to read out as question marks. The :
licensee subsequently replaced several of the CETs and resolved the !
deficiency with all but two of the CETs. Troubleshooting to resolve !
these was in progress at the end of the inspection period. The "
licensee determined that the subcooled margin indication was
furetional despite the remaining deficiencies. The inspector :
concluded that the licensee's actions were appropriate and that this l
condition did not warrant delaying unit restart.
b. Control Element Drive Mechanism (CEDM) Undervoltaae Relay
The plant monitoring system indicated that one of the four CEDM l
undervoltage relays actuated 49 seconds after the others. The i
licensee determined that the relays are functioning. properly, and :
identified and corrected a com'puter alarm system hardware problem -l
which caused the erroneous indication of a delay. The inspector .
concluded that the licensee's actions were appropriate. l
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c. Emeroency Response Facilities Data Acouisition and Disolay System 1
(ERFDADS)
The licensee removed two 25-inch cathode ray tube displays from ;
control room boards B02 and B06, and installed 19 inch cathode ray :
tubes in their place as part of Design Change Package- (DCP) ;
02-PJ-SD-038. The displays which were removed normally displayed 30 i
minute trend information of primary and secondary plant parameters,
and were visible from at least 15 feet away, at the center console ~
in the at-the-controls area. The displays which replaced these also ;
had the capability of displaying these trends; however, with the !
smaller displays, the-trends were not readable beyond a few feet.
The inspector reviewed the human factors evaluations which were .
performed as a result of this change and noted that they did not i
identify the viewing distance which was used in evaluating these :
displays. The licensee stated that this viewing distance was :
38 inches. l
During verbal discussions, several operators expressed their >
concerns with the reduced size of these displays. These operator l
concerns were not documented, and Operations Management indicated ;
that these displays were considered to be adequate. As a result of '
operator comments at the time of the inspector's questions, the ;
screen design was changed to double the width of the trend line so i
the trend could be visible from approximately 15 feet. Other :
changes were also made to address operator concerns. The inspector :
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further noted that operator involvement in the design and design !
review process was evident. The inspector concluded that the human
factors evaluation was adequate, and met the licensee's commitment
for human factors design consideration during the engineering of all j;
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, plant modification since the completion of the detailed control room
design review. I
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No violations of NRC requirements or deviations were identified. j
13. Technical Soecification (TS) 4.0.4 Interpretation - Unit 2 (71707)
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On August 8,1993, during preparations to enter Mode 4 in Unit 2, a f
supervisor questioned whether it was appropriate to use the grace period
of 1.25 times the specified surveillance interval, defined in TS 4.0.2, .;
to delay completion of several TS surveillances until entering Mode 4- i
The licensee had been using the provision of TS 4.0.2 to schedule the j
surveillances when more favorable plant conditions existed to safely ;
conduct the tests. This was thought to meet the requirements of TS 4.0.4 !
which required all applicable surveillances for the next mode of
operation to be completed prior to entry into the next higher mode.
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Control room supervision immediately got management involved in resolving
this concern. During the review of the TS bases, the licensee-
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conservatively decided to delay entry into Mode 4 and begin efforts to ,
complete all the surveillances in question. 1
The licensee asked the NRC Office of Nuclear Reactor Regulation (NRR) to.
clarify whether it was appropriate to use the grace period defined in TS i
4.0.2 to meet the TS 4.0.4 requirements for a mode change. NRR responded j
by stating that as long as the surveillances for the next mode were not ;
overdue, it was acceptable to apply the grace period of TS 4.0.2. The >
licensee then suspended the surveillance tests in progress and proceeded- .{
into Mode 4 on August 9, 1993. i
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The inspector concluded that this was a good example of licensee i
personnel displaying a questioning attitude and a good example of i
addressing and resolving safety concerns. 1
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No violations of NRC requirements or deviations were identified. j
14. Steam Generator Blowdown Heat Exchancer (HX) Insoection - Unit 3 (62703) ;
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On July 28, 1993, the NRC inspector observed workers inspect the steam !
generator blowdown HX for potential tube fouling. During the job, one of j
the mechanics noted that the work order (WO) referenced procedure 30DP- ;
9MP02, " Fastener Instruction," for reinstallation of the HX end bell. A
page from the vendor technical manual (VTM) was included in.the WO that l
provided the required torque sequence and torque value for the end bell. i
Since there were two different fastener references, the worker questioned '
which torque specification and sequcnce was correct. The worker stopped- i
the job and verified that the required torque value and sequence in 30DP- !
9MP02 was the same as the value referenced in the VTM. After discussion !
with the work planner, the inspector concluded that the VTM should have '
been referenced in the procedure instead of 30DP-9MP02.
The worker also noted that the cleanliness requirements for the HX were-
not listed in the WO. The worker discussed this with the duty planner
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and determined that the open HX needed to be maintained to class "C" '
. cleanliness requirements. The inspector discussed the fact that the
cleanliness grade and method of cleaning were not specified in the WO i
with the planning supervisor who agreed that these instructions should
have been included in the WO. l
The inspector concluded that the worker demonstrated good attention to l
detail by identifying the errors in the procedure. Additionally, the ;
workers actions to immediately resolve the issue' demonstrated that !
management's expectations regarding a questioning attitude and procedure '
compliance were being met in the field. However, the WO did not provide
adequate guidance for the worker to properly complete _ the job. As a
result, work planning, as one of the first lines of defense in the proper !
completion of a maintenance activity, was not effective in this instance. l
No violations of fiRC requirements or deviations were identified. !
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15. Emeroency Diesel Generator (EDG) "B" Rocker Arm Failure - Unit 3 (62703 i
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and 71707)
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On July 28,1993, at 8:35 a.m., the Unit 3 "B" Emergency Diesel Generator
(EDG) was declared inoperable due to both the intake and exhaust rocker ,
arms failing on cylinder 6L. The failed rocker arms were discovered !
during a post-surveillance test engine analysis performed in conjunction !
with a surveillance test operability run. The diesel was manually 5
tripped at 8:41 a.m., and a detailed inspection and repair plan was ,
developed. '
There had been one previous failed rocker arm documented at the Palo
Verde site on January 4,1989, when the BL rocker arm of EDG "A" in
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Unit 3 failed due to a manufacturing defect. An initial inspection of i
the failed rocker arms determined that they were original equipment and :
did not have the manufacturing defect which caused the 1989 rocker arm i
failure. The other seven EDGs on site were examined and no visual i
defects of the rocker arms or other obvious discrepancies were !
identi fied. The root cause of failure was subsequently determined to be ,
from cyclic stresses coupled with a lower than expected material ;
strength. The licensee planned to conduct portable hardness testing of
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all the rockers arms in the seven other EDGs. This testing had not been i
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conducted at the end of this inspection period. The inspector concluded ;
that these actions were appropriate. "
The inspector observed the removal of the failed rocker arms, the
cylinder head removal, and portions of the head and rocker arm !
reassembly. The inspector noted that the mechanics were thorough and !
deliberate during the entire repair. There were lengthy discussions ;
concerning how to safely remove the cylinder head. These discussions ;
included determining the rigging requirements for removing the head j
because rigging instructions were not provided in the work order (W0). A !
mechanic took the initiative to determine the weight of the head so that ,
the proper size turnbuckle would be used to lift the head. This ;
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equipment safety. t
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The inspector concluded that actions by the operators when the problem }
with the EDG was ide.itified and the initial corrective actions were i
appropriate. The inspector also concluded that there was good teamwork i
displayed by the mechanical maintenance shop, engineering, and Unit 3 {
operations during the repair of.the EDG and that the workers were i
thorough and deliberate. However, the WO did not include rigging !
instructions which was another example of a WO not providing_ the .
necessary instructions for proper performance of the job. -!
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No violations of NRC requirements or deviations were identified j
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16. Followup on Previrusly Identified items - Units 1. 2. and 3 (927011
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a. (Closed) Unresolved Item 50-528/90-02-06. Emeroency Lichtina l
Illumination levels - Units 1. 2. and 3 ;
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This iter, involved a concern about the adequacy of emergency i
lighting illumination levels in the Control Room and at the Remote i
Shutdowo Panel. NRC Inspection Report 50-528/90-25, dated July 5, !
1990, closed this item following a May 1990 meeting during which 1
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licensee-engineering personnel stated that walkdowns of emergency
lighting had been performed in all areas required for safe shutdown,
using engineering and operations personnel, and APS had determined
that illumination levels were satisfactory for performance of
required safe shutdown activities without the use of additional
lighting.
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- An NRC inspector reopened this item to review the documentation
t associated with these walkdowns and to review the adequacy of
emergency lighting illumination levels with current licensee
operations personnel. !
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The inspector reviewed the 1989 emergency lighting walkdown
documents for each unit and noted that identified lighting '
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deficiencies for each safe shutdown area were assigned specific
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corrective actions (to be accomplished by design change packages).
The inspector confirmed, based on a sample review of the design
change packages for each unit, that the specific walkdown lighting
deficiencies had been corrected such that emergency lighting
illumination levels were adequate to allow licensee operations
personnel to accomplish required safe shutdown activities without
the use of additional lighting.- The inspector noted, however, that ;
the documented verification of post-modification illumination levels
for Unit 2 was not as quantitative or rigorous as .those associated
with Units 1 and 3, and consisted only of a single statement by the
system engineer that engineering and operations personnel had
verified that required safe shutdown equipment was sufficiently
illuminated to perform required operations. In contrast, the design
change closure documents for Units 1 and 3 included specific
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verification that pre-modification walkdown deficiencies had been ;
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individually corrected. The inspector noted, however, that the' i
licensee had performed additional walkdowns subsequent to the May i
1990 meeting with the NRC which thoroughly documented the adequacy 'i
of Unit 2 emergency lighting illumination levels. In addition, the
inspector questioned licensee operations personnel about the
adequacy of the current emergency lighting system to serve their s
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needs. The operations manager (or acting manager) for each unit
stated that he is satisfied that the emergency lighting system.is l
operating properly and is capable of providing adequate lighting to
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perform required safe shutdown activities in the event of a loss of
normal plant lighting systems. This item is closed. ~!
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b. (Closed) Violation 50-528/92-23-01. Containment Isolation Valve
Improperly Installed - Unit 1 [
This item pertained to a Unit I containment isolation check valve, ;
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SIE-V133, which was disassembled and subsequently returned to
service with the valve internals installed backwards. Significant
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factors in the improper valve assembly were the lack of' detailed
work order steps and the reliance on skill of the craft to assure ,
that the valve internals were properly or.iented. The licensee's
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response to the violation indicated that a maintenance procedure ,
would be developed for the specific valve design which would address ,
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valve disassembly / reassembly and provide for marking the valve to
depict proper orientation. The inspector reviewed procedure 31MT- *
92Z17, . " Disassembly and Assembly of Borg-Marner Check Valves." The ,
inspector noted that the procedure contained details for match
marking valves to depict proper orientation prior to disassembly. .
The procedure also included a verification that the match marks are !
properly aligned after reassembly. This item is closed based on a -
review of the maintenance procedure. [
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c. (Closed) Followup Item 50-528/93-04-01. Partial loss of Offsite
Power - Unit 1 :
This item involved the failure of a General Electric (GE)
Magne-Blast breaker which triggered a partial loss of offsite power. !
The licensee's root cause of failure (Condition Report / Disposition .
Request 1-3-0071) was inconclusive. The licensee questioned the
vendor, who provided Service Advice Letter 073 SPD 324.2 to the !
licensee which had initially only been issued to GE employees. This
Service Advice noted that some customers perform power factor -
testing of Magne-Blast breaker bushings, and if this test is
performed, data was provided recommending a test voltage and maximum
power factor for acceptable breakers. The Service Advice also '
stated that bushings with a power factor in excess of five percent
should be replaced. The licensee is now in the process of revising '
breaker overhaul. procedures to measure the power factor of all i
Magne-Blast breaker bushings during overhauls. The licensee is also i
pursuing efforts to obtain any additional information the vendor has
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which may provide additional assistance. The inspector concluded
- that this appeared adequate. This item is closed. -
d. (Closed) Followup Item 50-528/93-12-01. Improper Use of an
Enoineerina Evaluation Recuest (EER) by an Electrician in the Field
- Unit 1
This item involved an electrician's use of the " suggested
resolution" section of an EER, rather than the " engineering
guidance" section of an EER in the field. The licensee evaluated
this issue under CRDR 1-3-0281 and concluded that additional
training on the use of this EER would be conducted in upcoming shop
meetings. The inspector concluded that this appeared appropriate.
This item is closed.
e. (Closed) Followup Item 50-528/93-12-02. Maintenance Management
Expectations Not Incorporated into Plant Procedures - Units 1. 2.
and 3 _
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This item involved the failure of Maintenance Department Guideline
24 to incorporate all of the management expectations which were
announced in a Newsflash on September 17, 1992. Revision I to
Maintenance Department Guideline 24 was issued on August 4, 1993,
and contained all the significant guidelines from the Newsflash. *
The inspector concluded that this was appropriate. This item is
closed.
f. (Closed) Followup Item 50-528/93-12-03. Diverse Auxiliary Feedwater
System (DAFAS) Inoperable - Unit 1 *
This item involved the failure of operators and instrument and !
control technicians to restore the DAFAS following maintenance. The ;
licensee performed Incident Investigation 1-3-0256 which concluded
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that several factors contributed to this event including inadequate ,
self checking, inadequate communication, training and qualification, ,
interface design and managerial methods. Several corrective actions j
are underway to address these concerns including positive
discipline, evaluating training, evaluating a design modification to -
the system, revising the procedure, and the issuance of a night
order. The inspector concluded that the investigation was thorough
and adequately self critical, and that the corrective actions appear
appropriate. This item is closed.
g. (Closed) Followup Item 50-529/92-05-04. Essential Spray Pond Pump
Breaker Failed to Close on Demand - Unit 2
This item involved the failure of a GE Magne-Blast breaker to close
on demand. The licensee's evaluation concluded that dirty stabs on .
the auxiliary contact block had possibly caused the failure,
although this was not proven by licensee troubleshooting. This item ,
remained open pending a review of the licensee's plans for
functional testing requirements for safety-related breakers i
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. following racking operations. The licensee stated that the
management expectation is for breakers to be operated immediately
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following racking operations where practical. This expectation is .
not documented in plant procedures, but will be emphasized in -
operator initial and continuing training. The inspector concluded j
that this appeared to be adequate. This item is closed. l
h. (Closed) Unresolved Item 50-529/92-22-01. Annunciator Jumpers -
Units 1. and 2
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This item involved the use of temporary jumpers to disable i
annunciators. The item remained open while the licensee determined-
how the new policy would be applied to " nuisance" annunciators. The '
licensee determined that nuisance annunciators would be considered ,
inoperable equipment, and would therefore would have to meet the ,
same criteria as all other annunciator jumpers using the same new l
guidance which was incorporated into procedure 30DP-0AP01,
" Maintenance Instruction Writer's Guide." The inspector concluded .
that this was adequate. This item is closed. -
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f40 violations of f4RC requirements or deviations were identified. l
17. Review of Licensee Event Reports (LER) - Units 1 and 2 (90712) .
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a. The following LERs were closed based on in-office review.
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(1) Unit 1 ,
87-20 Revision 1 Inadvertent ESF Actuation due to
Spurious Equipment Operation !
93-07 Revision 0 Snubber Testing Was flot Inaccordance i
Revision 1 With Technical Specifications
(2) Unit 2 i
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93-01 Revision 1 Steam Generator Tube Rupture
fio violations of f4RC requirements or deviations were identified.
i 18. Exit Meetino (71707)
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An exit meeting was held on August 17, 1993, with licensee management and j
resident inspectors during which the observations and conclusions in this -l
report were discussed. The licensee had no additional comments. to the
inspectors' findings. The ~ licensee did not identify as proprietary any j
materials provided to or reviewed by the inspectors during the j
inspection. I
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. EMPLOYEE CONCERNS PROGRAMS . !
PLANT NAME: Palo Verde LICENSEE: Arizona Public Service (APS)
DOCKET #: 50-528, 529, 530 l
Note: Please circle yes or no if applicable and add comments in the space -l
provided. .
A. PROGRAM: l
1. Does the licensee have an employee concerns program? ;
Yes j
2. Has NRC inspected the program?
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Yes Although a formal evaluation of the program has not
been conducted, several reviews of Employee Concerns
Program (ECP) files have occurred during allegation
inspection activities. In general, these reviews
. were not formally documented to protect the identity .
of allegers. In one case, the NRC conducted a survey- i
to evaluate employee willingness to go to the ECP :
with safety concerns. This survey was documented in
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, NRC Inspection Report 50-528/92-33. ,
B. SCOPE:
1. Is it for: ,
a. Technical? Yes ,
b. Administrative? Yes ;
c. Personnel issues? Yes
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2. Does it cover safety as well as non-safety issues? Yes l
3. Is it designed for: i
a. Nuclear safety? Yes .
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b. Personal safety? Yes
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c. Personnel issues - including union grievances? Yes
4. Does the program apply to all licensee employees? Yes
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2500/028 Attachment A-1 Issue Date: 07/29/93 l
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5. Contractors? Yes
6. Does the licensee require its contractors and their subs to I
have a similar program? j
No Ho!ever, APS requires contractors comply with the APS ECP
program.
7. Does the licensee conduct an exit interview upon terminating
employees asking if they have any safety concerns?
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Yes Direct employees have a face-to-face interview; *
contractors fill out a form and may request a face-to-face '
interview.
C. INDEPENDENCE: i
1. What is the title of the person in charge?
Manager, Employee Concerns Program
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2. Who do they report to? l <
Director, Quality Assurance (QA) ;
3. Are they independent of line management? Yes
4. Does the ECP use third party consultants?
No The ECP occasionally may use a law firm to investigate !
legal matters, j
5. How is a concern about a manager or vice president followed up? ,
In general, these types of concerns are processed similar to :
other concerns regarding avoiding a conflict of interest. That l
is, if the line organization evaluates the concern, the ECP ,
staff will try to have the evaluation performed by someone at
least two levels above the person involved. This may require ,
going all the way up to the Board of Directors. The ECP staff
also has the option of performing the evaluation themselves or
have a different organization evaluate the concern.
D. RESOURCES- -
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1. What is'the size of staff devoted to this program?
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5 investigators (APS is in the process of hiring one more .
investigator), a manager, and one secretary. l
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2. What are ECP staff qualifications (technical training,
interviewing training, investigator training, other)? '
Technical training - varies based on previous experience. The
ECP staff has experience in the areas of human resources,
nuclear engineering, quality assurance, systems engineering,
and police investigation. No formal technical training is !
required for investigators once they are on the ECP staff. The ,
program relies on the expertise within the ECP staff and on -
other Palo Verde organizations. ,
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Baseline training - report writing, fraud seminar, ;
investigation seminar, legal issues seminar, interviewing
skills seminar. This training is not currently required for i
investigators, but may be given depending on the background of !"
the individual. However, there is not a formal qualification
card or certification to conduct investigations. !
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E. REFERRALS: .
I. Who has followup on concerns (ECP staff, line management, ,
other)?
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In general, the concern is given to line management if the ECP
staff feels there is not a possibility of revealing the
concerned person's identity or if there is not a conflict of ,
interest within line management. If these conditions can not t
be met, the ECP staff will process the concern. Occasionally, !
the ECP staff will use a third person outside of line ;
management.
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F. CONFIDENTIALITY:
1. Are the reports confidential? '
Yes Reports and names of people are handled on a "need to
know" basis. If the concern is substantiated the report
is submitted to the QA director for approval. If the i
report is unsubstantiated, the report remains in ECP. ,
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Additionally, all records are retained in the ECP office.
2. Who is the identity of the alleger made known to (senior
management,ECPstaff,linemanagement,other)? :
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The identity of the person is revealed on a "need to know" '
basis and depends on the issue and the organization performing
the evaluation. The evaluation is to focus on the issue and .
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not the person; therefore, the alleger's name is not considered
to be important. If there is a strict personnel issue, the l
2500/028 Attachment A-3 Issue Date: 07/29/93
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person's name could be importent and usually needs to be l
revealed.
3. Can employees be: :
a. Anonymous? Yes
b. Report by phone? Yes ;
G. FEEDBACK: ,
1. Is feedback given to the alleger upon completion of the
followup? i
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Yes The ECP staff attempts to perform a face-to-face
interview. If this is not practical, a letter is sent to '
the concerned individual. ;
2. Does program reward good ideas?
No Concerns provided to the ECP, even if determined to be
good ideas, are not publicized. Individuals can be
rewarded for good ideas provided through other licensee
programs. .
3. Who, or at what level, makes the final decision of resolution?
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The QA Director.
4. Are the resolutions of anonymous concerns disseminated? l
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No Concern resolutions, regardles.s of the source, are not i
disseminated. However, an anonymous caller is given a
file number so they can call' and determine the resolution ;
of their concern. i
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5. Are resolutions of valid concerns publicized (newsletter, a
bulletin board, all hands meeting, other)?
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No
H. EFFECTIVENESS:
1. How does the licensee measure the effectiveness of the program?
There is no formal mechanism or performance indicators used to
measure effectiveness. The ECP manager uses informal
indicators such as the number of repeat customers and
2500/028 Attachment A-4 Issue Date: 07/29/93
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referrals, although this information has not been recorded. l
The ECP staff attempted to survey a limited number of past
customers, but the response to the survey was poor. ;
2. Are concerns:
a. Trended?
Yes Trending is conducted by the type of concern '
(management / human resources, industrial safety, and
nuclear safety / quality), how the concern was
received, age of the concern, whether substantiated
or unsubstantiated, and the number of concerns for
the various departments. l
b. Used?
Yes Trending reports are issued to the managers of the
major organizations. There is no formal program for
use of the data.
3. In the last three years how many concerns were raised? 537
Closed? 444 What percentage were substantiated? 18%
4. How are followup techniques used to measure effectiveness
(random survey, interviews, other)? .
The ECP staff recently attempted to conduct a random survey of ,
previous customers. The staff did not obtain good response to
the survey and were unable to draw any major conclusions .from
data. Informal interviews with customers are performed but are
not documented.
5. How frequently are internal audits of the ECP conducted and by
whom?
They are not conducted. ,
I. ADMINISTRATION / TRAINING: ,
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1. Is ECP prescribed by a procedure? Yes
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2. How are employees, as well as contractors, made aware of this !
program (training, newsletter, bulletin board, other)? i
General employee training, posters. APS will initiate some new f
efforts in this area such as an advertising campaign (possibly I
using coffee cups) and a formal presentation to new hires, j
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ADDITIONAL COMMENTS: None.
NAME: Albert E. MacDougall TITLE: Resident Inspector
PHONE #: (602) 386-3638 DATE COMPLETED: 08/18/93
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2500/028 Attachment A-6 Issue Date: 07/29/93 !