IR 05000528/1992035
| ML20125D772 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 12/01/1992 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML20125D761 | List: |
| References | |
| 50-528-92-35, 50-529-92-35, 50-530-92-35, NUDOCS 9212160024 | |
| Download: ML20125D772 (82) | |
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U.
S._ NUCLEAR REGVLATORY COMMISSION
REGION V
Reoort Nos.
50-528/92-35, 50-529/92-35, and,50-530/92-35 k
p_gL.gt_Nos, 50-528, 50-529, and 50-530 License Nos.
NPF-41, NPF-51, and NPF-74 Liq.tn11g Arizona Public Service Company P. O. Box 53999, Station 9012 Phoetilx, AZ 85072-3999 Facility Name Palo Verde Nuclear Generating Station Units 1, 2, and 3 Jnspection Conducted October 1 through November 2, 1992 J.ninectori J. Sloan, Senior Resident Inspector F. Ringwald, Resident Inspector D. Solario, ResidentInspector(SanOnofre)
A. M cDougall, Reacter Inspection, Region I
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4hm j/>/h 6poroved Bv
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Wong, (41ef (/
D Ta e Signed Reactor Projects Section 2 i
Inspection Summary:
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J!Lsite_Gtion on Ott_Qber )_through Novembar.1JJD2 (Report Numbers 50-528/92-3_5a _50-52975i2-35. and 50-530/92-35)
Areas insoected: Routine, onsite, regular and backshift inspection by the three resident inspectors, and a Region I inspector. Areas inspected included:
review of plant activities
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surveillance testing - Units 1, 2, and 3
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plant maintenance - Units 1, 2, and 3
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management meeting, ISE Review
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manual engineered safety feature actuation not reported - Unit 2
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diesel engine 5 yeTr inspection - Unit 3
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quality assurance program - Units 1, 2, and 3
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licensee response to Rosemount 10 CFR Part 21 - Units 1, 2, and 3
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followup on previously identified items - Units 1, 2, and 3
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During this inspection the following inspection procedures were utilized:
30702, 35701, 40500, 61726, 62703, 71707, 92700, 92701, and 93702.
Results: Of the nine areas inspected, no violations were identified.
9212160024 921201 PDR ADOCK 05000520-O PDR j
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General Conclusions and Specific Findinas:
Sionificant Safety Matters:
None Violations:
None Deviations:
None Open Items:
1 new item was opened, 6 items were closed, and 2 items were left open.
Strengths Notedi The response to the potential non-conservative calibration of transmitters affecting the core operating listit supervisory system represented conservative safety consciousness.
W aknesses Noted:
None J
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DETAILS.
1.
h rsons Contacted The below: listed technical and supervisory personnel were among those contacted:
Arizona Public Service Company (APS)
- R. Adney, Plant Manager, Unit 3 T. Bradish, Manager, Nuclear Regulatory Affairs
- R. Bnuquot, Supervisor, Quality Audits
- J. Dennis, Manager, Operations Standards
- C. Emmett, Senior Information Coordinator, Management Services
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- R. Flood, Plant Manager, Unit 2
- R. Fullmer, Manager, Quality Audits & Monitoring 5. Guthrie, Diret+or, Quality Assurance W. Ide, Plant Manager, Unit 1
- R. Kerwin, Manager, Maintenance Support
- D. Leech, Supervisor, Quality Audits & Monitoring
- J. Levine, Vice President, Nuclear ProdJction
- D. Mauldin, Director, Site Maintenance & Modifications
- J. Napier, Engineer, Nuclear Regulatory Affairs, Operations
- G. Overbeck, Director, Site Technical Support
- R. Roehler, Supervisor, Nuclear Regulatory Affairs, Operations
- A. Rogers, Technical Assistant, Regulatory & Industry Affairs
- R. Schaller, Assistant Plant Manager, Unit 1 T. Shriver, Assistant Plant Manager, Unit 2
- R. Smalley, Supervisor, Central Maintenance HVAC R. Stevens, Director, Regulatory & Industry Affairs Others
- J. Draper, Site Representative, Southern California Edison
- F. Gowers, Site Representative, El Paso Electric
- G.
Hammond, Supervisor, Onsite Licensing, Southern California Edison
- R. Henry, Site Representative, Salt River Project
- J. Jamerson, Senior Licensing Engineer, Southern California Edison
- Denotes personnel in attendance at the Exit meeting held with the NRC resident inspectors on November 2, 1992.
The inspectors also talked with other licensee and contractor personnel during the course of the inspection.
2.
Review of Plant Activities - Units 1. 2. and 3 (71707)
a.
Unit 1 The unit began the inspection period starting up from Mode 3, achieving 100% power on October 4, 1992. Power was reduced to 99.S%
on October 8,1992, as a result of concern over a 10 CFR Part 21 report affecting feedwater and steam flow Rosemount transmitters
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(Paragraph 9). The unit returned to 100% power on October 10, 1992.
A core operating limit supervisory system (COLSS) failure occurred on October 25, 1992, which resulted in a power reduction to 73% as required by Technical Specifications. The unit returned to 100%
power on October 26, 1992. On October 27, 1992, the unit detected a small primary to secondary leak in steam generator number 1 with an estimated leak rate of 0.1 gallons per day. The leak incrcased to approximately 1.3 gallons per day at the end of the reporting period. The unit ended the inspection period at 100% power.
b.
Unit 2 The unit operated at essentially 100% power throughout the inspection period. Several problems with the COLSS required power reductions to comply with Technical Specifications.
Power was reduced to 99.5% on October 8, 1992, as a result of concern over a 10 CFR Part 21 report affecting feedwater and steam flow Rosemount transmitters (Paragraph 9). The unit returned to 100% power on October 10, 1992.
c.
Unit 3 Unit 3 began this inspection period in Mode 6, with core offload in progress.
The offload was completed on October 3,1992. While defueled, the licensee performed significant planned outage maintenance. Outage activities progressed slightly ahead of schedule during this period. Core reload commenced on October 28 and was completed on October 30, 1992. The unit remained in Mode 6 at the end of the inspection period.
Two inadvertent Balance of Plant Engineered Safety Features Actuation System (BOP ESFAS) actuations occurred while defueled. On October 9, 1992, an operator intending to open one breaker unintentionally opened another, causing the first actuation. On October 14, another actuation unexpectedly occurred, apparently due to a procedural weakness and an operator not taking action implied by a caution in the procedure. The licensee is investigating both these events.
d.
Rijnt Tour N
The following plant areas at Units 1, 2, and 3 were toured by the inspector during the inspection:
o Auxiliary Building o
Control Complex Building o
Diesel Generator Building o
Fuel Building
Main Steam Support Structure Radwaste Building Technical Support Center Turbine Building
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o Yard Area and Perimeter o
Containment Building she following areas were observed during the tours:
(1) Operatino loas and Records - Records were reviewed against technical specifications and administrative control procedure requirements.
The inspector noted that the licensee discovered clerical errors in the updates to three emergency operating procedures (EOPs)inUnit2onOctober 13, 1992 which resulted in a large number of blank pages which should have contained procedural guidance. The inspector further noted that operations and operations standards took prompt and aggressive corrective action to identify and correct all E0P errors. The inspector concluded that this represented both inattention to detail with these very important procedures, and prompt and effective corrective action.
(2) tionitorinq_ Instrumentation - Process instruments were observed for correlation between channels and for conformance with technical specifications requirements.
The inspector noted that the licensee continued to experience problems with the reliability of the plant computer and core monitoring computer in Units 1 and 2, which resulted in the loss of the core operating limit supervisory system on several occasions. The inspector concluded that the licensee's response to these failures appeared appropriate.
(3) Shift Staffina - Control room nd shift staffing were observed forconformancewith10CFRPart50.54.(k), technical specifications, and administrative procedures.
(4) Eauipment Lineues - Various valves and electrical breakers were verified to be in the position or condition required by technical specifications and administrative procedures for the applicable plant mode.
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(5)
Eauipment Taaaina - 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.
(6) General Plant Eauipment Conditions - Plant equipment was observed for indications of syem leakage, improper u
lubrication, or other conditions that could prevent the systems from fulfilling their functional requirements.
The inspector observed that ;: art of the gasket was missing from l
a condulet box on the motor operator for Unit 3 valve l
35GE-HV-44, steam generator #2 blowdown isolation valve. This
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condition had been identified by the inspector during the last refueling. The inspector verified that there is no safety significance associated with the observed condition. However, the licensee had not initiated a work request to correct the deficiency when first identified. Following the identification of this deficiency during this refueling outage, the licensee initiated an appropriate work request. The inspector concluded
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that the licensee's current actions were appropriate.
v (7) Fire Protection - Fire fighting equipment and controls were observed for conformance with technical specifications and
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administrative procedures.
(8) Plant Chemistry - Chemical analysis results were reviewed for conformance with technical specifications and administrative control procedures.
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(9)
Security - Activities observed for conformance with regulatory requirements, implementation of the site security plan, and administrative procedures included vehicle and personnel access, and protected and vital area integrity.
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(10) Plant Housekeeoina - Plant conditions and material / equipment storage were observed to determine the general state of cleanliness and housekeeping..
The inspector._ observed two examples of housekeeping which had the potential for operational impact. The first involved rags and debris on the Unit I auxiliary building roof which blocked water.from draining. The second involved an-unrestrained scaffold cart in the Unit 2 control room near the engineered safety features cabinets. Both issues were promptly addressed by the licensee.
(11) Radiation Protection Controls - Areas observed included control point operation, records of licensee's surveys within the radiological controlled areas, posting of radiation and high radiation areas -compliance with radiation exposure.
permits, personnel monitoring devices being properly worn, and
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personnel frisking practices.
During an-insoection of the Unit 3 containment, the' inspector was given incorrect information regarding the area of high radiation in the 120 pressurizer cubicle. The area. posted as a high radiation area in the cubicle did not match the area described by the lead radiation protection (RP) technician.
The licensee determined that the reason for.the misinformation was that the RP technician was unaware of the posting change due to an omission in the shift turnover. The inspector determined that_the actual posting was accurate and concluded that the licensee was adequately addressing the turnover deficiency.
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5-(12) Shift-Turnover - Shift turnovers and special evolution briefings were observed for effectiveness and thoroughnsss.
No violations of NRC requirements or deviations were identified.
3.
Surveillance Testino - Units 1. 2. and 3-(617261 Selected surveillance tests required to be performed by the technical-specifications (TS) were reviewed on a sampling basis to verify that:surveillanc
technically adequate procedures existed for performance of the surveillance tests; 3) surveillance-tests had been performed at the frequency specified in the TS; and 4) test results satisfied acceptance
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criteria or were properly dispositioned.
l S)ecifically, portions of the following surveillances were observed by
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tie inspector during this inspection period'
Unit 1
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Proct J:
Description 32ST-9PK01
"7-Day Surveillance Test of Station' Batteries"
"PPS Functional Test - RPS/ESFAS Logic" 36ST-ISE03
"Excore Safety Linear Channel Quarterly Calibration" 72ST-95B01
"CPC/COLSS' Flow Verification" Unit 2 Etocedure Description 36ST-95B02
"PPS Bistable Trip Units Functional Test" Unit 3 Procedure Description 31ST-9DG02
" Diesel Engine S_ Year Inspection (DGB)"
No violations of NRC requirements or deviations were identified.
4.
Plant Maintenance - Units 1. 2. and 3 (627031 During the inspection period, the ins)ector observed and reviewed -
selected documentation associated wit) the maintenance and problem
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investigation activities listed below to verify compliance with regulatory _ requirements, compliance with administrative and maintenance procedures, required quality-assurance / quality control department k
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involvement, proper use of safety tags, proper equipment alignment and use of jumpers, personnel qualifications, and proper retesting.
The inspector witnessed portions of the fallowing maintenance activities:
Unit 1 o
Calibratio: of the generator stator water outlet temperature instrument o
Calibratior if the 'B" shutdown cooling heat exchanger outlet temperaturc instrument Unit 2 o
Application of monokote fire protection coating in the "B" essential (PK) battery room o
Calibration of the volume control tank temperature instrument o
Replacement of the charging motor on the "A" essential spray pond pump breaker o
Maintenance of safety-related Magneblast circuit breakers Unit 3 o
Clean and inspect the spray pond end bell of the EW "A" heat exchanger o
Plug 8 tubes in EW "A" heat exchanger o
Remove the feed screw & journal bearing from reactor coolant pump
"lB" o
Repair lifting device for "A" spray pond breaker o
Inspect and align load center L23 4160V feeder breaker o
Bearing inspection on essential chiller "B" o
"B" and "D" essential battery installations (DCP 3XE-PK-037)
o Retrieval of allen wrench from upper core support plate o
Installation of diverse auxiliary feedwater actuation system (DCP 3FJ-SB-064)
o Rework of "B" diesel cylinders 9-R and 10-L o
Disassemble, inspect and reassemble check valve DGB-V497 o
Post maintenance test run of "B" emergency diesel generator lifted Leads - Unit 1 On October 7,1992, the inspector observed calibration of turbine temperature monitoring instrumentation in Unit I which required the
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lifting of leads and noted that the leads had not been restrained nor insulated. The inspector further noted that one of the leads was in contact with a test probe, and was therefore electrically part of the test circuit. When the inspector questioned this condition, the technician promptly taped the lifted lead to-insulate it. A discussion with the I&C foreman confirmed that this was contrary to the newly established lifted lead policy and the 1&C technicia.n involved was counselled. Later in the inspection period the inspector observed several other I&C calibration and surveillance test activities which
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required the lifting of leads and noted that all other instances appeared to conform to the newly established lifted lead policy.
Circuit Breaker Failure - Unit 2 OnOctokt9,1992,theUnit2essentialspraypond(ESP) pump'A" breaker failed to close on demand as a result of a breaker failure. An immediate investigation revealed that the breaker charging spring motor had fallen off the breaker and was lying on the floor of the cubicle.
The inspector observed troubleshooting which identified that the bolts which secured the charging spring motor to the breaker frame were found to be completely loose. All expected loose hardware was located. The inspector observed the licensee install a replacement charging spring motor and retest the breaker satisfactorily. The licensee established a corrective action plan which included inspection of critical breakers for similar loose bolts and initiated a root cause of failure investigation for this breaker. The inspector concluded that the Itcensee activities appeared appropriate. At the exit meeting, the inspector encouraged the licensee to evaluate these breakers for other failure mechanisms which are not readily evident in light of this and other recently observed failures which were also not readily evident.
Cirguit Breaker Maintenance - Unit 2 On October 19, 1992, the inspector observed a portion 32HT-9ZZ34,
" Maintenance of Medium Voltage Circuit Breakers Type Ah-4.16-250," in the Unit 2 electrical maintenance shop. During the performance of section 4.17 Trip Latch Wipe, the inspector noted that the electricians measured the trip latch wipe by applying grease to the trip latch roller and measuring the width of the grease wiped off by the trip ' latch, rather than by applying grease to the trip latch and measuring the width of the grease wiped on the trip latch roller as specified by the procedure.
When the Quality Control (QC) inspector questioned this difference, the electricians explained that this is how they had been trained by a General Electric technical reposentative and how the procedure was written in the past. At the request of the QC inspector, the electricians repeated the measurement using the meethodology specified by the procedure, end obtained the same measurement as before. The QC inspector inserted a hold point in the procedure for an instruction change request (ICR) number to clarify low this measurement should be performed. The inspector concluded that since the measurement using both methodologies produ:ed identical results, there was little technical significance to the difference. The inspector further concluded that this did not follow management expectations for procedure use as expressed in " Principles of Maintenance Management" in that the electricians did not stop and question this difference prior to proceeding. The inspector also concluded that it was appropriate for the QC inspector to question this and initiate a hold point in the procedure for an ICR to clarify the procedure steps.
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fasential Coolina Water (EW) Heat Exchanaer Maintenance - Unit 3 The inspector observed the plugging of tubes in the Unit 3 EW 'A' heat exchanger per work order 575255. The faulty tubes were identified during the planned inspeciton of the heat exchanger. The mechanic doing the plugging appeared to carefully perform self-verification and no discrepancies were apparent to the inspector. However, the procedure did not require second party or independent verification that the correct tubes were plugged. This observation was discussed with the maintenance supervisor who stated that the intent was to have a second mechanic (lead or foreman) verify th. proper placement of the plugs. As a result, the Quality Contrel department verified the proper installation of plugs in one end of the heat exch.cger, but the other end had already been closed
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out and could not be verified. The inspector concluded that not having a procedural requirement to ensure that second party verification was conducted was a weakness in the work control process.
Work order 549842, for installation of the heat exchanger end bell gasket, did not specify how the gasket was to be installed. After questioning the maintenance personnel, it was determined that gaskets are generally installed with RTV or similar compcund that is compatible with the materiais involved.
In this instance, there was not a compatible compound and the gasket was held in place with metallic ta)e until the end bell cover plate was installed. The inspector noted 11at a potential for errors existed by requiring the technician in the field to determine the proper installation method if the work planner already had the needed information. The inspector also noted that the work order also had a pen-and-ink change wnich was not initialed and dated as specified in licensca procedures, though an Engineering Evaluation Request (EER)
supporting the change was included in the work package. The inspector concluded that improvements could be made to this work order, but that the maintenance was adequately performed.
Motor Ooerated Valve Maintenance - Unit 3
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The inspector obe.erved portions of the periodic inspection of safety injection valve 3SIA-UV-635 actuator using maintenance procedure 32MT-9ZZ48, " Maintenance of Limitorque Valve Motor Operators." The technicians identified a cracked end bell dog on the notor end bell and properly submitted a MNCR to evaluate the corrective action. The-inspector concluded that the technicians took the ap3ropriate aci.lon and properly documented the deficiency. The ins)ector o) served section 4.5.7 for limit switch grease inspection. The tecinicians n ra knowledgeable on what type of grease to expect and how to properly evaluate its condition. Appendix D to the procedure had detailed acceptance criteria for the grease inspection.
Both technicians observed the grease and determined that it was satisfactory. The inspector concluded that the procedure was effectively written, the technicians were properly trained, and that the actuator was properly inspected and maintained.
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Allen Wrench in Reactor Vessel - Unit 3 The inspector observed the retrieval of an allen wrench from inside the Unit 3 reactor vessel. The licensee found the wrench durina an inspection of the lower core support plate while the react was defueled. The licensee promptly planned and executed the trieval, which was accomplished smoothly using a mugnet suspended from a lanyard.
The licensee determined from radioactivity measurements that the wrench had been in the core for at least th9 last operating cycle. The inspector noted that the licensee has had deficiencies in foreign material exclusion (FME) area control in previous out ces, and observed f!.at FME controls in place for this outage appeared adequate. The licensee could not explain how the wrench got into 4 actor vessel.
The licensee evaluated the potential damam to fuel assemblies which were in the vicinity of the wrench during the iast cycle and determined that there was little potential for damage. The inspector noted that no fuel leakage was observed during the cycle, and concluded that the licensee'=
response to this issue appeared appropriate.
Essential Chiller Inspection - Unit 3 The inspector observed portions of the restoration from the bearing inspection performed on the "A" Essential Chiller per work order 564651.
The inspector noted that some M&TE information was not recorded in eppropriate blanks in the work order. Several completed steps did not have data recorded for the calibration due date and the range of the M&TE usec. although blanks were provided. Some steps also did not identify the M&TE used. At least one M&TE Usage Form was not found at the time, although it was required to be kept with the work ordtr.
It appeared that the work was satisfactorily completed. The licensee managed to fill in some of the blanks in the work order from M&TE Usage Forms that had been co@eted, but some information could not be readily obtained. The inspectoi concluded that the workers had not fulfilled their responsibilitu in completing required documentation of work activities as intended, b * d e the requirements of procedure 30AC-0ME01, " Measuring and Test Equy m (MATE) Users Administrative Requirements," had been mat. The licensee later located the missing M&TE usage forms elsewhere in the work order binder. Additionally, the workers were briefed on M&TE record requirements.
The licensee initiated Condition Report / Disposition Request (CRDR) 3-2-0460.
No violations of NRC requirements or deviations were identified.
5.
Management Meetina - (30702 and 40500)
On November 2,1 n'd, S. Guthrie and two members of the licensee's Independent Safe.
"ngineering (ISE) staff, and K. Hamlin, Manager, Nuclear Safety, n with regional management in the Region V Office.
Topics presented b, the licensee's staff included:
o Changes and enhancements from past ISE practices, o ISE accomplishments
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o ISE challenges The discussions included several key points:
o The licensee stated that improvements had occurred in their ISE program, including newly hired personnel on the ISE staff, which should make the organization more effective.
o Past practices of the ISE staff spending too much time at their desk and not out in the plant, was a recognized problem. Actions to encourage IEE activity in the plant included establishing satellite offices in each unit, assigning two ISE engineers to be accountable for monitoring daily activities at each unit, and management emphasis on keeping current en plant issues.
o The APS managers stated that the Quality Assurance and ISE functions still needed improvement to reach their expectations, but that they had seen significant improvements over the last few years. Several examples of improvements in the interface between other managers and the ISE staff were discussed.
o Recent events at another Region V utility identified that vendor Owner's Group information was not being effectively implemented by that licensee. The APS staff acknowledged that it was a challenge to review and act upon the very large amount of generic information received from the industry.
Othe discussion topics included ISE staffing and training levels, tracking of ISE action items, the Employee Concerns Program, and interfacing between the licensee's senior management, ISE, and Nuclear Safety. The presentation package provided by the licensee is included in this report as Enclosure 2.
6.
tLanual Enoineered Safety Feature (ESF) Actuation Not Reported - Unit 2 L92700)
In September 1992, the inspector received an inquiry by the licensee's Quality Audits and Monitoring (QA&M) departaent regarding the reportability of a December 23, 1991, event in which a high pressure safety injection (HPSI) pump was started to recover reactor coolant system (RCS) level due to a major leak from a stuck open relief valve in the shutdown cooling system. The licensee had used the HPSI pump after the leak was confirned to exceed the capacity of all three charging pumps. At the time of the event, Unit 2 was in Mode 5 at 380 psia.
At the time, the licensee initiated Condition Report / Disposition Request (CRDR) 2-1-0274, and determined that the event was not reportable to the l
NRC.
Subsequently, the QA&M department performed a reportability audit and initiated another CRDR upon its determination that the event was l
reportable due to its conclusion that the use of HPSI constituted a manual ESF actuation.
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During a meeting on September 3, 1992, the inspector became aware of the details of the event and noted that the licensee should have evaluated the event for emergency classification in accordance with the licensee's Emergency Plan. The licensee then initiated another CRDR to evaluate the emergency classification issue. The emergency classification issue was referred to Region V emergency preparedness personnel (see Inspection Report 50-528/92-34).
The inspector noted that HPSI was not required to operable in Mode S, and that Engineered Safety Features (ESF) logic was bypassed per procedures to enable Mode 5 operation. Additionally, the licensee stated that operating procedures allow the use of HPSI for normal RCS makeup.
Discussions were conducted with the NRC Office of Analysis and Evaluation of Operational Data (AE00) to determine if manually starting the HPSI pump to mitigate the leak constituted a manual ESF actuation, which would be reportable in accordance with 10 CFR 50.72 and 50.73. A September 7, 1990 NRC internal staff letter indicated that an ESF actuation occurs whenever an ESF component is caused to operate, for any reason except responses to testing. However, this position is not clearly supported in generic documents, including NUREG 1022, " Licensee Event Report System,"
or its supplements. Additionally, in a 1987 internal licensee memorandum, the licensee documented a March 20, 1987 telephone discussion in which an AE00 contact had stated that actuation of ESF components by something other than an ESF signal would not be reportable under the ESF requirements of 10 CFR 50.73. The AE0D contact was indicated to have stated the purpose of the requirement was to capture ESF system actuations, whether due to valid or invalid ESF signals. The inspector concluded that the licensee was not required to report this event to the NRC under ESF reporting criteria.
The inspector evaluated the safety significance of the event, noting that it occurred at the end of a refueling outage with a relatively cold core.
The inspector estimated the leak rate to be about 180 gallons per minute.
All HPSI pumps and charging pumps, and both trains of shutdown cooling, wera operable at the time. The licensee isolated the leak in approximately 30 minutes, and maintained pressurizer level above approximately 2M. The inspector concluded that the plant was not close to losing shutdown cooling, and that if shutdown cooling were lost, a significant margin of time to recover cooling flow existeu before boiling or core uncovery would occur. The inspector concluded that the significance of this specific event was low, but noted that the event would have been considerably more serious if the reactor had been recently shut down and if only the minimum equipment required by Technical Specifications were available.
No violations of HRC requirements or deviations were identified.
7.
Diesel Enaine 5 Year Inspection - Unit 3 (61726)
The inspector observed portions of the Diesel Engine 5 year inspection (procedure 31ST-9DG02) on the Unit 3 "A" emergency diesel generator. The
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inspector reviewed the procedure, interviewed personnel, and observed the post-maintenance engine analysis.
The licensee recently(Cooper-Bessemer) technical manual, C628-0001, revised the surveillance procedure to incorporate a change in the vendor section 15, maintenance guidelines. The new guidelines shifted the periodic maintenance emphasis from prescriptive tear down inspections to a predictive approach. The impact of this change was evaluated in Engineering Evaluation Request (EER) 92-DG-028. The evaluation included a discussion of the conceptual differences oetween the old and new maintenance guidance, identified new maintenance tasks and maintenance tasks that were no longer required, and summarized specific areas where procedural changes were required..As a result, the surveillance procedure was changed to perform a limited visual inspection and an engineering evaluation of various components (turbocharger, cylinder heads, engine lube oil pump, etc.) to determine if more detailed inspections were necessary.
During this surveillance, visual inspections and engineering reviews of performance data, documented in EER 92-DG-033, showed that equipment tear-downs were not required. However, injector fuel pump removal hnd dis-ssembly was performed on all 20 injectors as part of a separate work ordce to identify faulty injectors reported by the vendor under 10 CFR Part 21. The inspection found 11 injectors with lot numbers that were either defective or suspect. These injectors were subsequently replaced.
No other problems were noted during the disassembly which validated the engineering recommendation to not perform the periodic tear down of the injectors.
The inspector observed the setup and performance of the post-maintenance engine analysis. The data from the analysis was used to adjust the engine timing and to monitor cylinder pressures and engine horsepower.
The procedure was well written and the technicians were knowledgeable concerning the use of the equipment and interpretation of the data. For example, they identified a faulty pressure sensor due to unexpected changes in the peak cylinder pressures. The probe was changed and adjustments were made to the new fuel injectors which resulted in the average peak pressure being closer to the vendor recommended average peak pressure.
The inspector determined that a 10 CFR 50.59 screening was not conducted by the licensee supporting this procedure change. Administrative procedure OlAC 0AP02, " Review and Approval of Nuclear Administrative and Technical Pror w es," requires a 50.59 screening whenever a new procedure in' A ves an intent change. Paragraph 4.1.13, number 5, spec * ties an intent change exists if the acceptance criteria is alte'd but makes an exception if the char.ge was directed as part an approve'
design output document. The mainta ance standards group interpreted M 92-DG-028 to be a design output decement and therefore did not view it as an ir, tent change. However, the procedure for conducting a EER does not require a 50.59 screening for this particular evaluation even though the acceptance criteria for a satisfactory surveillance test had been
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changed. The inspector discussed the review process for new and revised vendor technical information with the licensee and determined that a 50.59 screening was not performed during that review. The inspector noted that vendor technical manuals are defined in licensee procedures as I
design output documents, and that the Output Document Change Request procedure requires a 50.59 screening, or a justification why one is not ne:essary. However, the licensee does not process vendor technical manuals as design output documents.
Licensee management acknowledged that a 50.59 screening should have been performed at some point in the processing of the technical manual or procedure change, and initiated Condition Report / Disposition Request (CRDR) 9-2-0635 to investigate the possible programmatic weakness. The inspector will review the licensee's evaluation (Followup Item 530/92-35-01).
The inspector concluded that the engineering analysis and change to the surveillance procedure were appropriately implemented, but that a 10 CFR 50.59 screening should have been performed addressing the change. The inspector further concluded that the engine inspection observed was adequately performed.
No violations of NRC requirements or deviations were identified.
G.
!LualitY Assurance Prooram - Units 1. 2. and 3 (35701)
The inspector reviewed Quality Assurance (QA) Audit Reports92-004,
" Refueling Operations," and 92-011
" Software Quality Assurance."
0A Audit 92-004. "Refuelino Operations" This audit was performed during the Unit 1 Spring 1992 refueling outage.
The scope of the audit included management expectations, organization, destack activities, fuel handling activities, foreign material exclusion Zone III control, radiological work centrols, training effectiveness, refueling technical specifications, contractor control, safety, and corrective action effectiveness.
Audit personnel naid particular note to communications and control issues as a result of significant deficiacies identified during the previous Unit 2 refueling (see Inspection Report 50-529/91-47). While the audit describes some problems identified by the working groups, QA personnel identified other items, including the inappropriate reliance on reactor engineers to ensure that various Technical Specification requirements were. complied with, without licensed operator direct oversight.
l QA personnel challenged a late-night decision by operations and l
engineering management regarding the interpretation of a procedure, l
demonstrating the resolve to tam a firm position.
The conclusions of the audit were clearly communicated. The conclusions related to specific events and observations. However, the audit report did not provide overall insights from the audit findings.
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The inspector concluded that the audit was adequate in scope and depth to accomplish its purpose.
0A Audit 92-011. " Software Oualit_v Assurance" This audit adequately addressed salient aspects of software QA, including management expectations, program adequacy and p ogram application, for both non-process and process software. The audit identified several strengths and weaknesses, resulting in the initiation of two new Quality Deficiency Reports (QDRs), an additional action for an existing QDR, and eight Quality Assurance Recommendations (QARs). Notable conclusions of the audit included:
1) motor operated valve test software was not in compliance with the program, 2) some non-process software had not been reviewed for compliance with the new procedure 01PR-0CQ01, " Software Quality Assurance (SQA) Program for Non-Process Computer Software," 3) an index of quality software indicating approved version level and qualification status does not exist, and 4) the boric acid blending option of the BORON code has not been validated.
The audit also noted that process computer software is excluded from the recently issued Operations QA Plan, Appendix G.
Additionally, procedure 77PR-90C01, " Process Computer Software Control Program," was found to be administratively out of date. Numerous problems with Core Operating Limit Supervisory System (COLSS) software have been experienced at Palo Verde, two of which are described in the audit. While COLSS is not classified by the licensee as Quality Software, the problems have highlighted the need for additional attention to the q)uality of process computer software (see Inspection Report 50-528/90-28.
The audit pointed out that the-licensee is developing a greater awareness of the need for quality assurance standards in software, though the applicability of specific standards has not been thoroughly addressed nor determined.
The inspector concluded that the audit was effective in identifying programmatic deficiencies, that it was adequate in scope and depth, and that it provided meaningful recommendations. The audit also summarized overall strengths and weaknesses to direct management attention appropriately. The inspector also noted that the licensee's intention of performing a similar audit next year is warranted.
Conclusion The inspector concluded that the audit program, as represented by the two audits reviewed, is being effectively implemented. The integration of audit results into plant activities will be addressed in a future inspection.
No violations of NRC requirements or deviations were identified.
9.
Licensee Response to Rosemount 10 CFR Part 21 - Units 1. 2. and 3 (92700)
On October 8, 1992, the licensee determined that a condition reported by Rosemount, concerning the span correction of _ some differential pressure transmitters, could affect the Core Operating Limit Supervisory System (COLSS) secondary calorimetric determination of power level. The Part 21 report affects 67 of 320 transmit *.ers installed at Palo Verde, but the only impact on safety <as determined by the licensee to be on the feedwater flow transantem The magnitude of the error potentially introduced by the reported condition was 0.19%, resulting in the COLSS calorimetric calculation indicating that reactor power was 100% when it was actually 100.19%.
Because the reported error is a bias in a specific direction, it was not bounded by the 2% uncertainty of the COLSS calculation. Upon being informed of this conclusion by the engineering staff, licensee management ordered that the two operating units decrease power to 99.5% indicated power level to ensure that 100% actual power level was not exceeded. Power was restored to 100% after a COLSS addressable constant was changed to include an appropriate penalty factor. These actions were considered temporary, pending adjustment of the transmitters when plant conditions allow. The inspector concluded that the licensee's actions demonstrated thoroughness of engineering review and appropriate conservatism in management response.
No violations of NRC requirements or deviations were identified.
10. Followup on Previously identified items - Units 1. 2. and 3 (92701 and 92702)
a.
_ Unit 1 (1)
.(0_ pen) Followup item 528/92-22-03. Reactor Trio Breaker (RTB)
Troubleshootina Activities - Units 1. 2. and 3 (92701)
This item involved the failure of a General Electric (GE) RTB to close as discussed in Inspection Report 50-528/529/530/92-15.
GE finalized their root cause of failure report on October 19, 1992, and concluded that shock generated during the closing cycle and transmitted to the trip shaft prevented the breaker from maintaining a fully latched position. This report did not contain corrective actions nor recommendations, and APS has not taken a final position on this issue. This item will remain open pending a review of the final APS position and actions.
b.
Unit 2 (1) LClosed) Followup Item 529/92-22-02. Reactor Trio Breaker (RTB)
Undervoltage Trio Assembly (UVTA) Issues - Units 1, 2. and 3 (92701)
This item involved the discovery of a deenergized UVTA armature in the mid-position, and not in the fully tripped position.
This item was opened to review the final root cause of failure
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report. The report was issued on September 9, 1992 and concluded that the root cause of failure was indeterminate.
The suggested probable cause was debris in the UV device armature spring. This report recommended enhancing RTB recordkeeping, inspection of RTBs for debris, and enhanced procedural guidance for performing required adjustments and checking settings.
ICRs have been submitted for all recommended procedural enhancements. Each GE AKR-30 breaker will be inspected for loose debris during the next scheduled maintenance. Training is evaluating changes to training to enhance instruction in adjusting the UV device. According to the plant engineer, the two year UVTA coil replacement will now require the replacement of the entire UVTA, and not just the UVTA coil.
Based on the above, this item is closed, c.
Unit 3 (1) LClosed) Violation 530/92-15-01. Reactor Trio Breaker (RTB)
Control of Troubleshootino - Unit 3 (92702)
This item involved the failure of the licensee to control troubleshooting on RTB "C" on March 31, 1992. This resulted in electricians cycling the breaker approximately 100 times without engineering involvement and may have resulted in the loss of some root cause of failure data. The licensee has expanded the requirements of procedure 700P-0EE01, " Equipment Root Cause of Failure," to more clearly define wh*n a quarantine is required. The Director, Site Technical Support, issued a letter to the plant managers and maintenance managers identifying situations which require early engineering involvement in troubleshooting activities.
In addition, a critical systems, components, and activities list has been developed by an APS task force. APS is also developing a sensitive issues awareness list..The inspector noted two examples where a system engineer and a shift supervisor were not familiar with the requirements of 70DP-0EE01 shortly after revision 2.00 was issued. After reviewing revision 2.00 of 70DP-0EE01 and the letter regarding situations requiring early engineering involvement, the inspector concluded that adequate procedural guidance exists to prevent recurrence. The inspector encouraged the licensee to ensure that all personnel involved in troubleshooting are familiar with these new requirements. The inspector will continue to evaluate troubleshooting on an ongoing basis.
Based on this review, this item is closed.
(2)
(Closed) Unresolved Item 530/92-31-04. Sorav Pond Pumo "B"Section XI Test Failure - Unit 3 (92701)
This item concerned the apparent failure o.f the licensee to determine or document the cause of the deviation following the failure of the ASME Section XI test of the Unit 3 "B" spray
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pond pump on September 10, 1992, prior to returning the pump to service on September 12, 1992.
Following a test in which the results are in the ' required action" range, Section IWP-3230 of the Code requires that the pump be taken out of service, and the cause of the deviation be identified and corrective action completed prior to returning the pump to service. The inspector determined that the licensee believed that pump performance had not changed, and that earliest test data on which the reference' differential pressure value was based was probably not determined under tightly controlled test conditions, as recent test data has been. Additionally, the licensee did not believe that the data from the failed test represented a pump performance change, but was the result of data scatter and an intentional increase in the flow rate for the test. The inspector noted that the licensee had not documented this understanding of the cause of the deviation, but had instead stated verbally, when asked, that the cause of the deviation was that the previous reference value was incorrect. The inspector also noted that the licensee initiated Condition Report / Disposition Request (CRDR)
3-2-0306 to document further evaluation of the test failure.
Discussions with NRR personnel confirmed that the Code requires that the licensee identify the cause of deviation of the failed data from the reference value. Simply stating that the reference value was incorrect does not address the intent of the Code to address the change in pump performance. The inspector noted that the licensee had not explicitly documented the cause of the deviation, hindering later verification of compliance with the Code. While the licensee's stated cause of the deviation was faulty, the inspector concluded that the licensee did have an understanding of the actual cause of the deviation. Additionally, the Code does not require the cause of the deviation to be documented. The inspector concluded that the licensee had satisfied all Code requirements, though documentation alone does not support the conclusion. The licensee agreed to review its administrative requirements to determine if changes were needed to ensure appropriate information is documented to support Code requirements.
Based on this review, this item is closed.
d.
Units 1. 2. and 3 (1)
(Closed) Followuo Item 528/90-25-06: EmerQencY liQhtinq Vendor Information - Units'l. 2. and 3 (92701)
The followup item addressed the maintenance of vendor technical manuals associated with emergency lighting.
The inspector discussed the current status of emergency lighting technical manuals with the licensee's Vendor Manual section of the Procurement Engineering department. This group is charged with developing and maintaining new manuals for all plant equipment. New manuals,= designated as Vendor Technical Manuals (VTMs), are being issued after all vendors are contacted to ensure that the licensee has the latest applicable vendor information for each plant component. Currently, three new emergency lighting vendor technical manuals have been issued:
VTM-D972-0001 Dual-Lite Issued June 29, 1992. A revision was in process, due October 21, 1992, to incorporate system engineer comments.
Output Document Change Requests were issued on October 12, 1992, addressing these comments. Also, two additional vendor documents will be incorporated.
VTM-H249-0001 Holophane According to the licensee, this was issued July 1, 1992.
A revision was in process, due October 15, 1992, to incorporate seven new vendor documents and to add new equipment identification numbers to the applicability list.
VTM-E355-0001 Exide Issued February 21, 1992. This manual includes the Emergency Lighting (QD) system.
Three additional new VTMs are due to be issued by the end of 1992. One of these will be for the QD system, taking information out of VTM-E355-0001. The other two address the Sure-Lite and Siltron lights.
The licensee stated that new vendor information is screened promptly upon receipt.
Information deemed to be very important to safety is incorporated within a few days. Other information is incorporated within either 30 or 60 days, dependent upon the screening results. The licensee stated that no backlog exists for any of the emergency lighting vendor manuals.
Vendor information received which applies to the old vendor manuals is incorporated in those manuals on the same schedule. However, the old manuals have not gone through the verification process to ensure all appropriate vendor information has been identified and incorporated.
The inspector reviewed the Exide and Dual-Lite VTMs in the licensee's technical library and found them to be administratively clean and professional. The Holophane VTM was in use at the time. The inspector found no indication of a backlog of vendor information which had not yet been incorporated in the manuals. Additionally, the inspector
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reviewed parts of the Station 'Information Management System (SIMS) database regarding technical manual information. The inspector reviewed a sample of equipment listed in the database and found that not all equipment had vendor manual information.
For those pieces of equipment selected by the inspector which had vendor information, the database showed that the information had been verified by licensee personnel. Some equipment ids (e.g., 1EQBND79 CKTBRK and 1EQBND84 5204 CKTBRK)
did not indicate the applicable technical manual. The SIMS database is updated after issuance of the VTM, so this appeared to be consistent with the status provided by the licensee.
The inspector concluded that the licensee's emergency lighting vendor manuals are being appropriately maintained, and that the Vendor Technical Manual project is progressing satisfactorily to complete the issuance of verified VTMs for emergency lights.
(2)
(0 pen) Unresolved item 529/92-22-01. Annunciator Jumpers -
Units 1 and 2 (92701)
This item involved a licensee program to interpret the work control and temporary modification procedures to permit the installation of temporary jumpers across inputs of defective field devices in the annunciator system without an engineering evaluation or 10 CFR 50.59 evaluation. The licensee extended the program to annunciators which had inappropriate setpoints and were therefore " nuisance" annunciators. The inspector noted a plant review board decision which required maintenance standards to incorporate this program in the nuclear administrative and technical manual as a procedure. The inspector further noted that maintenance standards was planning to only address the installation of jumpers for annunciators associated with inoperable equipment, and not those associated with " nuisance" annunciators. This item will remain open pending a review of the licensee program associated with
" nuisance" annunciators.
(3) 1 Closed) Information Notice 92-06. Reliability of ATWS Mitigation System and Other NRC Reauired Eauipment Not Controlled By Plant Technical Specifications - Units 1. 2. and 3 (92701)
The inspector reviewed the licensee's July 14, 1992, memorandum of recommended corrective actions to addiess the concerns of IN 92-06. Six actions were identified, as summarized:
Evaluate functional and surveillance tests to ensure NRC
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commitments are being met. Ensure test frequency is adequate to maintain the diverse auxiliary feedwater actuation system (DAFAS) and the diverse scram system (DSS) in a reliable configuration.
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Develop controls to ensure proper priority is applied to
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return out-of-service systems to service in a timely manner.
Develop a mechanism to ensure management is aware of
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anticipated transient without scram (ATWS) system status.
Consider actions similar to Limiting Conditions for Operation (LCO), and Technical Specification Component Condition Record (TSCCR) tracking.
Develop procedures to describe operations personnel
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responsibilities to control these systems, such as when they are placed in bypass.
Develop and implement training to ensure operations and
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maintenance personnel are trained on the procedural requirements initiated to control ATWS systems.
The response to items 1, 2, and 3 is due September 30, 1992.
Items 4 and 5 were addressed by requiring Plant Managers to report the DAFAS status to the Plant Review Board (PRB)
monthly, and by revising the alarm response procedure to require a Condition Report / Disposition Request (CRDR) to be initiated if DAFAS is in test, bypass, or out-of-servie.e for any reason other than an approved procedure, test, or approved work document.
Item 6 will be initiated when the procedure change. are issued to training for incorporation into the training change system.
The inspector concluded that the licensee's review to date of this issue is adequite to address the concerns of IN-92-06.
j (4)
(Closed) Followuo Item 529/92-27-02. Verification of Plant
Records - Units 1. 2. and 3 (TI 2515/115. 92701)
This item involved the review of the licensee's investigation
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of Auxiliary Operator (AO) logs in response to Corrective Action Report (CAR) 92-0104, to determine if the licensee's self-monitoring detects practices that might result in i
falsified logs.
l The licensee reviewed six logs for each of the 105 qualified A0s for inconsistencies with security access records. Although
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l-numerous discrepancies were identified, many were subsequently l
eliminated due to verifiable explanations. However, 27
individuals (7 from Unit 1,13 from Unit 2, and 7 from Unit 3),
i on one or more occasions, were determined to have made log I
entries without having made entries into the required areas, n
without acceptable explanations (e.g., another qualified
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operator made a verified entry). Examples of discrepancies are:
Failure to enter spray pond pump room when pump was known
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to be inoperable Failure to enter the Main Steam Support Structure
Failure to enter auxiliary feedwater pump room
Failure to enter pipe chase to obtain hold-up tank gas
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analyzer condensate pot sight glass level Each A0 with identified discrepancies was interviewed at least once. Several A0s complained of problems with the security systen, and these were each investigated by the licensee.
In general, such complaints were not substantiated.
The discrepancies were divided into two categories based on seriousness. The more serious category required the documenting of a reading on the log sheet. The less serious category required a checkoff on the logsheet for having toured a given room. The licensee disciplined the A0s involved in unexplained discrepancies. None of the discrepancies involved Technical Specification requirements or NRC-licensed individuals.
The licensee also evaluated the root cause of the observed performance deficiencies and found that in several cases neither the A0s nor their supervisors clearly understood the performance c ;,cda: ism s hnW, wpervisors were unaware of sne praitices used by the A0s, such as looking through grating to read a sight glass about 90 feet away. Additionally, procedural guidance was found not to be clear. The licensee revised appropriate procedures and took other measures to ensure that the expectations were explicitly understood.
The licensee's Quality Assurance department expects to perform
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some verification activities related to this issue on a periodic basis. Such a program was not in place prior to the emergence of this issue elsewhere in the industry earlier this year.
The inspector concluded that the licensee's investigation, and plans to continue to monitor these activities in the future, i
appeared appropriate.
l This followup item and this temporary instruction are closed.
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No violations of HRC requirements or deviations were identified.
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11.
Exit Meetina
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An exit meeting was held on November 2,1992, with licensee management and resident inspectors during which the observations and conclusions in this report were generally discussed. The licensee did not identify as proprietary any materials provided to or reviewed by the inspectors during the inspection.
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PALO VERDE INDEPENDENT SAFETY ENGINEERING PRESENTATION
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TO NRC. REGION V NOVEMBER 2,1992
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o-CHANGES / ENHANCEMENTS FROM PAST PRACTICES a
ACCOMPLISHMENTS
ASSESSMENTS COMPLETED, RESULTS AND
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RECOMMENDATIONS OBSERVATIONS / MINOR ASSESSMENTS COMPLETED,
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RESULTS AND RECOMMENDATIONS
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ASSESSMENTS PLANNED OR IN PROGRESS
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EMPHASIS ON TRAINING
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ACTIVITIES REQUESTED BY PVNGS SENIOR
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MANAGEMENT MANAGEMENT FEEDBACK AND ACTIONS
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CHANGES / ENHANCEMENTS FROM PAST PRACTICE INCREASED AWARENESS OF AND SENSITIVITY TO PLANT
ACTIVITIES INCREASED OVERVIEW OF FIELD ACTIVITIES
MORE THROUGH AND DOCUMENTED ' REVIEW OF NRC,
INDUSTRY AND IN-HOUSE OPERATING INFORMATION SCHEDULE FOR ASSESSMENTS
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AGGRESSIVE ASSESSMENT MANAGEMENT
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FORMAT OF ASSESSMENT REPORTS REVISED
IMPROVED COMMUNICATIONS WITH NRC RESIDENT'S
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OFFICE EMPHASIS ON " OPERATIONS ORIENTED" TRAINING AND
PERSONNEL WITH OPERATIONS EXPERIENCE EMPHASIS ON "TRUE INDEPENDENCE"'IN ISE ACTIVITIES
PERIODIC MEETINGS WITH PLANT MANAGEMENT
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ACCOMPLISHMENTS i
ASSESSMENTS COMPLETED
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MANAGEMENT FEEDBACK AND ACTIONS INITIATED OBSERVATIONS / MINOR ASSESSMENTS COMPLETED
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ACTIONS INITIATED OR TAKEN
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ACTIVITIES REQUESTED BY PVNGS SENIOR
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CHALLENGES /WAY WE DO BUSINESS CONTINUE TO REFINE PROCESS TO STAY ON TOP OF
EMERGING ISSUES TO ENSURE A PROACTIVE APPROACH, USE ERROR
MODES AND EFFECTS ANALYSIS TO REVIEW PLANS AND.
PROCEDURES FOR NON-ROUTINE /SPECIAL EVOLUTIONS BEFORE EXECUTION USE SSFI/ VERTICAL SLICE ASSESSMENT TECHNIQUES IN
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THE CONDUCT OF " MAJOR ASSESSMENTS"
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DEVELOP CRITERIA FOR QUICKLY DETERMINING
SIGNIFICANCE OF AND APPLICABIL1TY TO PVNGS OF EMERGING ISSUES AND INDUSTRY EVENTS (HANDBOOK;
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LIKE TMI)
STAFF COHESIVENESS (ROTATIONAL. ASSIGNMENTS)
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MAJOR ASSESSMENTS COMPLETED o
FIELD EVALUATION 92-17, EVALUATION OF DEBRIS POTENTIALLY ENTERING THE REACTOR VESSEL
e ASSESSMENT 92-21, INDEPENDENT REVIEW OF PVNGS RESPONSE TO NUMARC 91-06, " GUIDELINE FOR INDUSTRY ACTIONS TO ASSESS SHUTDOWN MANAGEMENT"
THE PRELIMINARY RESPGNSES WERE INADEQUATE AND
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TMIRTEEN AREAS WERE IDENTIFIED BY ISE WHERE NUCLEAR SAFETY IMPROVEMENTS COULD BE MADE e
ASSESSMENT 92-22, COMPARISON OF QUALITY AND NON-QUALITY WORK ACTIVITIES
NO PROCEDURAL DEFICIENCIES WERE IDENTIFIED.
THE SAME PROCEDURES APPLY TO BOTM Q AND NON-Q
' WORK. A " CULTURAL" DIFFERENCE IN TREATMENT OF Q AND NON-Q WORK WAS IDENTIFIED IN HOW THOSE
PROCEDURES ARE IMPLEMENTED
e ASSESSMENT 92-23, TECHNICAL SPECIFICATION VALVE ALIGNMENT e
TWO AREAS WERE IDENTIFIED WHERE THE TECHNICAL SPECIFICATION SURVEILLANCE TEST MAY NOT MAVE
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MET THE INTENT OF TECHNICAL SPECIFICATION SURVEILLANCE REQUIREMENT
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RECOMMENDATIONS MADE AS A RESULT OF ASSESSMENTS
AN EVALUATION BE CONDUCTED TO DETERMINE THE NEED FOR ACQUIRING VIDEO EQUIPMENT TO EXAMINE THE REACTOR VESSEL THROUGH THE LOWER CORE SUPPORT PLATE FOR DEBRIS ACCUMULATION DURING OPERATION AN EVALUATION BE CONDUCTED TO DETERMINE THE METHODS
AND TOOLS NEEDED FOR RETRIEVAL OF FOREIGN MATERIAL LOCATED BY THE VIDEO EQUIPMENT EVALUATE THE NECESSITY FOR:
PERIODICALLY VERIFYING SHUTDOWN COOLING SYSTEM o
RELIEF VALVES ARE ALIGNED PROPERLY WHILE IN MODES 4,
5, AND 6 AND IN STEADY STATE WITH REACTOR VESSEL HEAD TENSIONED IDENTIFY VALVE POSITION FOR SPA-HV-49A/B AND
HPB-HV-50A/B e
REVISE PROCEDURE 51PR-0ZZO1, dCOh3 JCT OF FORCED OUTAGES," TO INCLUDE THE RESPONSIBILITY OF THE UNIT MANAGER FOR THE REVIEW OF IMPACT OF FORCED OUTAGE WORK ACTIVITIES ON RCS PERTURBATIONS
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REVISE MAINTENANCE PROGRAMS AND PROCEDURES TO REQUIRE AN INCREASED LEVEL OF DETAIL FOR NON-
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QUALITY RELATED WORK PACKAGES.
- ESTABLISH, CLEARLY COMMUNICATE, AND CONSISTENTLY ENFORCE STANDAPDS AND EXPECTATIONS CONCERNING LEVEL OF DETAIL, CRAFTSMANSHIP, AND USE OF RESOURCES FOR QUALITY VS.
NON-QUALITY AND PRIORITY VS.
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OBSERVATION 92-0002 DOCUMENTED A REVIEW OF - THE LOOSE PARTS VIBRATION AND MONITORING SYSTEM IN UNIT 1.
A CRDR WAS ISSUED IDENTIFYING THAT THE DETECTORS / SENSORS MAY NOT BE POSITIONED AS REQUIRED -
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OBSERVATION 92-0004 DOCUMENTED A REVIEW OF THE UNIT
SHIFT SUPERVISOR's LOG AND RESULTED-IN THE ISSUANCE OF 2 QDRs IDENTIFYING THAT MNCRs WERE NOT-ISSUED IN A TIMELY MANNER FOR ARD RELAY DRAWING DISCREPANCIES.
- OBSERVATIONS 92-0005 THROUGH 92-0013 DOCUMENTED A REVIEW OF WORK CONTROL RELATED PROCE RES TO DETERMINE IF QUALITY AND NON-QUALITY WORK WAS HANDLED THE SAME. (SEE ASSESSMENT 92-22)
e OBSERVATION 92-0016 THROUGH 92-0033 AND 92-0035 T11 ROUGH 92-003 6 DOCUMENTED A REVIEW OF RESPONSES TO NUMARC 91-06 GUIDELINES.
THESE REVIEWS IDENTIFIED THAT SEVERAL RESPONSES WERE INADEQUATE.
(SEE ASSESSMENT AN 92-21)
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e OBSERVATION 92-0034 DOCUMENTED A REVIEW OF TECH SPEC VALVE POSITION SURVEILLANCE FOR THE EW SYSTEM.
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A CRDR WAS ISSUED AS A RESULT IDENTIFYING THAT ALL VALVE POSITIONS MAY NOT HAVE BEEN VERIFIED. (SEE ASSESSMENT AN 92-23)
e OBSERVATION 92-0037 DOCUMENTED A REVIEW OF AUDITS AND MONITORING ACTIVITIES TO DETERMINE WHY DEFICIENCIES IDENTIFIED IN LER 92-008, VALVE POSITION VERIFICATIONS, WERE NOT IDENTIFIED BY PREVIOUS AUDITS AND MONITORING. (SEE ASSESSMENT AN 92-23)
e OBSERVATION 92-0038 DOCUMENTED A REVIEW OF WORK l
CONTROL GUIDELINE FOR CONTROL OF CONTROL ROOM l
NUISANCE ALARMS. THE RESULTS INDICATED THAT YHIS l
GUIDELINE CONTAINS ALL NECESSARY CONTROLS AND l
SHOULD BE PROCEDURALIZED.
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OBSERVATION 92-0039 DOCUMENTED A
REVIEW OF DEFICIENCIES IDENTIFIED WITH ROSEMOUNT TRANSMITTERS l
IN MNCR 92-SG-9072 TO DETERMINE SAFETY SIGNIFICANCE l
e OBSERVATIONS 92-0040 THROUGH 92-0045, 92-0047 THROUGH 92-0050, AND 92-0052 THROUGH 92-0060 DOCUMENT REVIEWS OF UNIT 3-OUTAGE ACTIVITIES.
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REVIEW OF CORRECTIVE MAINTENANCE PERFORMED ON TRAIN A CEDM
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MOTOR GENERATOR SET WHICH INVOLVED WORK INSIDE AN ENERGIZED CABINET.
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- MAJOR RECOMMENDATIONS
RECOMMENDATIONS MADE AS A RESULT OF OBSERVATIONS:
o PROCEDURALIZE ADMINISTRATIVE CONTROLS FOR CONTAINMENT OPENINGS WHEN RCS LEVEL IS GREATER THAN 111 FEET.
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PROCEDURALIZE THE MINIMUM HEIGHT THE UPPER GUIDE STRUCTURE CAN BE WITHDRAWN TO ASSURE CLEARANCE OF THE REFUELING POOL "O-RING" SEAL
PROVIDE A LIFTING DEVICE FOR THE ADV VALVE BOARD e
LIGHTS SHOULD BE SCHEDULED TO BE INSTALLED IN THE UPPER GUIDE STRUCTURE STORAGE PIT PRIOR TO THE START OF THE REMOVAL EVOLUTION e
ISE INITIATED CRDR 3-2-0340 TO DOCUMENT THAT TEMPORARY POWER CABLING WAS UNDERSIZED AND THE OVERCURRENT PROTECTION WAS INADEQUATE.
e ISE OBSERVED THAT ELECTRICIANS WORKING NEAR ENERGIZED EQUIPMENT HAD OBJECTS STRAPPED AROUND.
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THEIR NECKS WHICH HAD METAL COMPONENTS WHICH COULD SWING OUT AND CONTACT ENERGIZED COMPONENTS.
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Schedule Name : ISE ASSESSMENT SCHEDULE - 1992/93 Responsible'
S.G.
PENICK As-of Date
- 26-Oct-92 Schedule File : C:\\TL3\\ DATA \\ISE3RD
93 Start End Jul hug Sep Oct NovDec Jan FebMar Apr Task Name Date Date
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1-ASSESSMENTS:
8-Jun-92 29-Oct-93 emmessemannensammannamenemessessammmmmens NUMARC 91-06 GUIDELINES 8-Jun-92 17-Aug-92
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SAFETY VS. NON-SAFETY WORK 22-Jun-92 22-Jul-92
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TECH SPEC VALVE SURVEILLANCES 20-Jul-92 31-Aug-92
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U3 SHUTDOWN RISK 31-Aug-92 27-Nov-92
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STATION BLACKOUT 3-Mar-93 3-May-93
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BACKLOG REVIEW.
6-Jul-93 31-Aug-93
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ALARMS - CONTINUOUS 15-Jul-93 30-Aug-93
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ATWS 7-Sep-93 29-Oct-93
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SOLENOID ACTUATED DEVICES 4-Jan-93 26-Feb-93
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ISE FIELD EVALUATION 9217
e-EVALUATION OF DEBRIS POTENTIALLY A
ENTERING TIIE REACTOR VESSEL EXECUTIVE SUMMARY
INTRODUCTION During a four month period from November 1991 through March 1992, -
four instances of metallic foreign material were doevuuted that entered the Unit 1 and 2 reactor vessels. Broken piec of the seal
>
and backup rings from SI 657 entered the Unit 2 reactor vessel and broken pieces from SI 657, St.658 and a " skyhook" inadvertently left in -
Steam Generator B tube sheet, entered the Unit 1 reactor vessel.
Systems Engineering and Nuclear Fuels Management verified that this
'
debris could have been small enough to have entered the core where fuel failure from fretting could not be ruled out. Ultrasonic testing performed on fuelin Units 1 and 3 during the last refueling outages-indicated 34 and 4 failed fuel pins in each unit respectively. Ultrasonie-and visual examination of the fuelindicated that two pins in Unit 3 and I pin in Unit I failed due to debris related fretting.
SCOPE This field evaluation was performed:
,
>
'
to confirm that foreign material which potentially damages fuel
,-
-
assemblies can accumulate in the reactor vessel despite controls
>
that are in place to eliminate its intrusion and to review the actions that are ongoing which will further help
-
reduce the intrusion of foreign material and enable the removal
-
from the reactor vessel.
.
RESULTS Strengths The field evaluation concluded that SED determined the size and -
shape of missing parts and concluded that they probably reside in the reactor vessel. The EERs, MNCRs and CRDRs associated with these parts provided detailed analyses, and_long term corrective actions for
specnic mstances of failed equipment. The 10 CFR 50.59 Safety l
Evaluations accurately concluded that there is no sately concern.
Areas for imprmement l
L Areas tot improvement include the need for deselopmes:t. e: the j
earanihty to detect and remme tereign material in the reactor sessel
'
lower area, under the cc e uprart plate. This is where det'ris would
- lceumulate t%er !We 1 P W IN\\ l1 I'rea di w f1 ';1lti \\lllall fleces.
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I ISE FIELD EVALUATION 9217 i
C EVALUATION OF DEBRIS POTENTIALLY
ENTERING THE RE".CTOR VESSEL I
These pieces could enter the core and potentially damage fuel
cladding.
RECOMM-It is recommended that:
ENDATIONS SED evaluate other valves similar to SI 657 and SI-658 to
-
determine if similar failures exist where the seal material has entered the RCS In keeping with the Fuel Reliability Program. Operations
-
Encmeermg Refueling should evaluate the need for acquiring video couipment to examine the reactor vessel throuch the
,
lower core support plate for debris accumulation during operation l
RP/Outace Planning evaluate methods and tools for retrieval of
-
foreicn material located by the video equipment, k
CATS Items ISE 001086. 001037 and 001085 hase been issued to the
-
'-
responsible orcanizations to address the above recommendation. SED is currently committed to inspecting the seats en valves similar to SI-
,
657 and S1658 in the (CT, EW, NC. DG. PW St. SP and TC) systems.
This program is tracked as CATS ltem 050706 t Partmon OER).
CONCLl*SIONS ISE concluded that forcien material has entered the reactor vessel.
The foreign material oricinated from componems in service and from personnel oversicht. Some of this foreien matenal is organic and it breaks down in the harsh environment of the reactor vessel and is removed by the CVCS system. Some of the foreign material may become lodged harmlessly below the fuel due to its dimensional charactenstics, and some of it may enter the fuel Dow channels, and potentially cause damage to the fuel. ISE is in agreement with the Nuclear Fuels Manacement in that.1) the missing stainless steel seal ring parts could continue to break up into small parts due to fatigue tracture, and 2) the small missing parts of the skvhook cauld l'e entrapped in the f uel. In both case.s. tuel tatlure trom trettmg cannet he ruled out.
- _ _ _ - _ _ _ - _ _ _ _ _ _ _ _ _ _ _
.
ISE ASSESSMENT NO. 92 21 (
INDEPENDENT REVIEW OF PVNGS RESPONSE TO
NUMARC 9106, GUIDELINES FOR INDUSTRY ACTIONS TO ASSESS SIIUTDOWN MANAGEMENT EXECUTIVE SUMMARY INTRODUCTION At the request of the Unit 3 Manager of Outage Planrting and Management (OPM), Independent Safety Engineering (ISE)
independently reviewed the PVNGS responses for NUMARC 9106,
" Guidelines for Industry Actions to Assess Shutdown Management."
ISE attended committee meetings starting on June 16,1992, and revieuw the available preliminary responses from August 4 through Aug M n "
SCOPE in res e.4,y N
ag.;n.cs. ISE evaluated whether the complete NUMAhC phne was addressed. whether the response answeied the guidance, whether the response provided sufficient detail and documentation to determine that the guideline is met, and if any areas existed which should be addressed to improve plan: satery.
.
(
RESULTS Strengths
.
Outace Planning Manacement took charge cf ensurmg NUMARC 91 On was apphed to 3R3
+
to the peatest extent possible even though the due date was December 31,1992.
requested independent ISE review for confidence in the quality
+
of the response and l
independently reahzed the inadequacies in the preliminary
+
responses and took netion for improvement in parallel with l
ISE's assessment.
Areas for imprmement i
+
A sieniticant number of the prelimmarv responses were superficially conducted. resultmg m incomplete or maecurate documentation (20 0167 responses), incompletely.iddressmg the NUMARC guidance (22 of 67), or either not addressme or beme mconsntent with the NUMARC guld.mee (22 of fi?).
tine reqvnse w.n comniete and accurate as suhmitted and had
!
-__
. _ _ _ _ - -. _
._
_ _. - _ _ _._ - _ _. _. _ _ _ _.
_
_ ___
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P ISE ASSESSMENT No. 92 21 (-
INDEPENDENT REVIEW OF PVNGS RESPONSE TO
!
NUMARC 9106, GUIDELINES FOR LNDUSTRY ACTIONS TO ASSESS SIIUTDOWN MANAGEMENT
'7 i
no ISE comments.
The significance of a commitment to NUMARC or a
NUMARC initiative has not been communicated to the working -
level.
The " Defense in Depth" concept of ' Technical Specifications
+
plus one" has not been adequately communicated from the
.
groups preparing the Shutdown Risk Assessment to those implementing the outage, in particular Operations.
!
Shutdown Risk Assessment Instruction Guide Appendix A does
+
not have a " Key Safety Function" for dilution (reduction of -
- Procedures, supporting calculations and training are (
concentrated on mid loop operations. There is significantlyless -
.
detail available and in some specific cases no coverace in these three areas for the transition from normalloops filled Mode 5 operations to mid loop operations (see Conclusions for details).
PVNGS procedures require containment closure on a loss of
+
shutdown cooling before core uncovery, which prevents any release of fission products. This is not consenative to the NUMARC guidance to use core boiling as the criteria. The use
,
of core boiling-- as a criteria addresses radiological and environmentalissues associated with the RCS steaming out the hot leg vent or refueling pool.'
CONCLUSIONS Detailed evaluation, comments, conclusions and recommendations to be used in improving the individual PVNGS responses are in ISE Observation Report Numbers 92 0003, 92 0016 through 42 0033. 92 0035 and 92 0036. These reports were provided to Ourage Planmng and Management on an as. completed basis during conduct of this ISE :
_
assessment to allow timely incorporation for the 3R3 outage.
The responses reviewed by ISE were the preliminary responses
-
prouded to OPM by the responsible orcanizations. OPM had not specitically screened them before ISii's review. Also, oniv a few weeks-m
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ISE ASSESS $1ENT NO. 92 21
(
INDEPENDENT REVIEW OF PVNGS RESPONSE TO NUhtARC 9106, GUIDELINES FOR INDUSTRY ACTIONS TO ASSESS SIIUTDOWN 51ANAGE> TEST had been provided for the development of the responses.
Not unexpectedly, the responses were generally superficial. incompletely documented, and frequently did not completely address the NUhiARC guidance.
The significance of a NUhiARC initiative or a commitment to NUhiARC has not been communicated to the working level. The need to respond to the initiative was not put into CATS for tracking when the initiative was received by APS. In addition to the quality of the responses already desenbed, in respondinc to the SUhiARC guidelines, one organization noted that work had to be done on a "not to interfere with scheduled work" basis and no commitment was made to a schedule for " enhancements."one orcamzation tound some specific items unaddressed and made no commitmant to address tnem. one organization took exception to guidance not already in place. and some
organizations committed to action past the NUhtARC implementation (
date.
.
The following are conclusions trom 15E's evalcanon wnich ISE considers siemficant and, when acted upen. >nouid resun in an improvement in nuclear safety.
The " Technical Specification plus one" philosepny is only
addressed as " Defense in Depth" in Appendtx A ci the Shutdown Risk Assessment Instruction Guide (i.e.. does not appear by name and does not appear m an NATN1 procedure).
The ' Technical Specification plus one" philosophy has not been adequately communicated to the groups implementing the outace, in particular Operanons (based on their response).
Provision of plant / equipment status tar outace persennes outsiJe
of the Control Room has not been procedurady prev'ded for.
+
Overtime policy emts ter Nuclear ProdueLc".
"J Site Technical Support personnel but u not proceduradv ec'.ered tar contractors performing satets related work and APS cerunnel not in Nuclear Prodoenon or Site rechnical Suppert er armmg wor k on saletv selated or "Kes Salety Funenon e.:uipment ie.g..
- he call out c:cw wi km.'
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_
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ISE ASSESSMENT NO. 92 21 h-INDEPENDENT REVIEW OF PVNGS RESPONSE TO
NUMARC 9106, GUIDELINES FOR INDUSTRY ACTIONS TO ASSESS SIIUTDOWN MANAGEMENT i
Unit 3 crane event).
Abnormal Operating Procedures (AOPs) are in place for
,
e emergency boration, loss of shutdowm cooling, loss of refueling pool / spent fuel pool level, and loss of AC power. No attempt has been made to match these to the Key Safety Functions developed and documented in Appendix A of the Shutdown -
'
Risk Assessment (SRA) Instruction Guide. An AOP should be available for loss of any Key Safety Function. In addition a Key
'
Safety Function addressing dilution (inadvertent reduction of the required boron concentration for shutdown margin) needs to be added to Appendix A of the SRA Instruction Guide.
+
Procedures, supporting calculations and-training are concentrated on reduced:-inventory operations and, more
(
specifically, mid loop operations. This addresses the worst case scenario and guidance from NRC Generic Letter 8817. Therc is significantly less detail available and in some specific cases no.
.
coverace between mid loop operations nnd reduced inventory
operations and between reduced inventory operations and.
normal operations.
For example: acceptable time to shut containment penetrationsis procedurallyaddressed forInid loop _
operations - but not reduced inventory operations: current supporting calculations for the procedures and core data books are only for mid loop operations with a hot leg vent installed -
(although considered bounding, reduced inventory operations without a hot leg vent have not been addressed); and currently
>
simulator training jumps from normal mode -5 to_ mid loop-operations when running the loss of shutdown cooling scenarios.
Currently PVNGS procedures require containmem closure for
+
mid loop operations before core uncovery (reduced inventory
_
canditions above mid loop currently have no procedural-requirement as noted above).- NUMARC guidance is to use L
core boiling when determining the-time for containment L
penetration closure. Core boiling is more conservative but automatically addresses radiologleal and. nvironmental issues
.
associated with the RCS steaimng out the hot leg sent or-
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i ISE ASSESSh1ENT NO. 92 21
(
INDEPENDENT REVIEW OF PVNGS RESPONSE TO NUh1 ARC 9106, GUIDELINES FOR INDUSTRY ACTIONS TO ASSESS SHUTDOWN 51ANAGEh!EST refueling pool. These issues are not currently addressed at PVNGS other than by personnel evacuation of containment.
The down side is that use of core boiling significantly reduces the time available for peiietration or hatch closure (by about a factor of 8).
The Shutdown Risk Assessment (SRA) currently does not
+
procedurally address fire and flooding hazards posed by plant activities, system interactions, impact of temporary installed equipment. "sincle failures." returninc equipment promptly to service, or use of periods of low decay heat, maximum inventory or defueled conditions. System interactions and temporarily installed equipment have been considered for the SRA but this is not in the instruction guide. Fire and flooding hazards were not considered in the past and the proposed schedule of 1R4 is not appropriate since this would leave 3R3 and 2R4 unreviewed. Per the response. " single failures" have not been
considered and no commitment was made to consider these.
Althouch sincie failures are partially addressed by the
" Technical Specification plus one"" Defense in Depth" process, this needs to be considered in properly developing "Contmgency Plans." No commitment was made in the response to minimize windows by returning equipment to service promptly.
No commitment was made in the response for use of periods oflow decay heat. maximum inv:ntory or defueled conditions (other than for 3R3) when coing to reduced inventotv conditions.
These items should, at a minimum, be in the instruction guide for the Shutdown Risk Assessment.
No connection is being made between Hieher Risk Evolutions
+
in the Shutdown Risk Assessment and Critical Evolutions in 40AC 90P02. " Conduct of Shift Operations." even though PVNGS is takine credit for the briefings and other actions associated with Critical Evolutions in meeting the NtfMARC cuidance concermne liigher Risk Evolutions.
Consider.iuon woulJ be made to expanding the disabhng of the
'
.
Shutdown Coohne imhition V.the interlock trom mid loop mperanom t. - ai reduced im entorv operations. PVNGS ha>
J
ISE ASSESSh!ENT NO. 92 21
{
(
INDEPENDENT REVIEW OF PVNGS RESPONSE TO m
\\
NUMARC 9106, GUIDELINES FOR INDUSTRY ACTIONS TO ASSESS SIIUTDOWN MANAGEMENT
'
-
had a loss of shutdown cooling (SDC) event due to inadvertent actuation of the SDC Isolation Valves at Unit 1 on May 23, 1989. A request for removal of the SDC isolation _ Valve Interlock from the TechnicalSpecifications is with the NRC. As
,
an interim action, expanding disabling of the interlock to all reduced inventory operations would result in a decrease in the risk of a loss of shutdown cooling due to inadvertent closure of :
'
the SDC isolation valves.
Or; a loss of shutdown cooling in mid loop or reduced inventory
+
operations. makeup using gravity feed from the RWT must be throttled so there is sufficient flow to prevent core boiling but
-
not so much that the RCS overfills and spills out into containment or the RWT prematurely empties. There is no procedural guidance or supporting calculations / testing on where to position the throttled valve (the LPSI pump suction gate (
valve). This weakness was recognized during the completion of ISE recommendations for FE 19 29 and is being pursued by Nuclear Fuels Management and Operations Standards.
The assumptions and initial conditions for the calculations
supporting mid-loop / reduced inventory operations and loss of shutdown cooling should be provided to and used by PRA in performing the Shutdown Risk Assessment to ensure that planned activities do not invalidate these assumptions and initial conditions, Equipment loss due to flooding from a loss of Refueling Cavity
+
seal was not addressed by the PVNGS response. While not considered a concern at PVNGS due to our low leakage rate, it needs to be addressed and documented since it has occurred at other plants and is part of the NUMARC guidance.
Currently spare high voltage transformers are stored in a renced
+
area adjacent to the switchyard and high voltage transmission lines. Cranes are needed for the movement of these beasy comporients.
Relocation of the spare transformers !.i a different storace area should be considered.
j
.._---_-.-. _ -
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-
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.
ISE ASSESSh!EST NO. 92 21
C INDEPENDENT REVIEW OF PVNGS RESPONSE TO NUh! ARC 9106, GUIDELINES FOR INDUSTRY ACTIONS TO ASSESS SHUTDOWN h!ANAGE> TEST
RECOhf51EN.
The following recommendations were discussed with the Unit 2 and 3 DATIONS hianagers of Outage Planning and hianagement and are assigned to
,
the Fall Outage hianager:
Provide the detailed comments and recommendations of ISE
+
Observation Reports 92 0003. 92 0016 through 92 0033,92 0035 and 92 0036 along with the NUhiARC 9106 response matrix to responsible department manacers, to be addressed and incorporated into the final PVNGS response to NUhiARC 91 06. Assign actions, on this basis, that will ensure comprehensive coverace of the guidelines, require specific documentation, and validation with specific due dates which are placed into CATS.
This action is being tracked under CATS item ISE 001090 Action 01, with a due date of 10/30:92.
-.
Develop a response for addressine the thirteen specifie ISE
.+
f
- conclusions for improsing nuclear safe:v in this assessment.
~ ~ -
This action is being tracked under CATS ::em ISE 001090
,
Action 02 with a due date cf 10 M92.
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ISE ASSESSMENT NO. 92 22
C COMPARISON OF QUALITY AND NON OUALITY RELATED WORK ACTIVITIES
.
EXECUTIVE SUMMARY Introduction At the request of the Vice President, Nuclear Production, an independent team was
formed to assess differences in quality related and non quality related work at j
The assessment was performed June 22 through July 17, 1992.
Independent Safety Engineering (ISE) was an active participant on that team.
Scope The assessment scope included addressing the following questtons asked by the Vice President:
Are there programmatic / procedural differences?
+
+
If so, what are the differences?
Based on how work is actually done, are we following the program.'
+
Are we interpreting too much into the program?
+
,
Is there a cuhme that people treat non. quality related work differently and
+
less significantly than quality work?
Results The independent review team's report is attached as Attachment A.
This ISE Assessment documents the independent review team effort for ISE. The results of the team effort are summarized below.
Weaknesses Non. quality related work is the first to be deterred Juring scheduitne cantitets.
+
Non-quality related work packaces are not alwa>s developed to the 3.ime ies el
of detail as quahty related pacLaces because of the room for interpretation alhmed by the procedures.
.-
.
--
-
.
.- - _ - _
_- - - -
. -.
- ~_
-
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t ISE ASSESSMENT NO,92 22
C COMPARISON OF QUALITY AND NON-QUALITY RELATED WORK ACTIVITirS There is not a clear, consistent message being sent down through the
+
organization as to the level of detail that is acceptable for non quality related work packages.
Conclusions A brief summary of the answers to the questions follows. See the ISE Assessment or team repon for greater detail.
Are thereprogrammatic/proceduraldifferences? Yes. The differences that exist
+
are those necessary for the proper inspection and documentation of quality class activities and those due to perceived importance. The same procedures are used for both quality and non quality related work activities and specified differences are few and narrow in scope.
/fso, what are the differences? ISE found seven procedural differences which
+
,
were not based on code or OA Program requirements. See the conclusions (
in this assessment or the team report for details.
Based on how work h actually done, are ne following the program? Yes. but
refer to the next question.
Are we interpretine too much into theprogram? Yes. The differences ISE and
+
the team observed in the field can be attributed to interpretation of the existing procedures. resuhing in a ditference in the level of detailin the work packages.
l l
ls there a cuhure that people treat non quality related work differently and less
+
'
significanth* than quality work? Yes. See discussion below.
Ahhough personnel perceive the work being done at PVNGS as being accomplished to a high standard of crattsmanship, work packaces are not always written with the same level of detail for similar quality related and non quality related jobs. Most craftsmen perform:ng the work generally believe there is no ditterence m how they accomplish the work. even thouch the instruenons inay ditfer. The same l'VNGS programs and procedures are used for quahty and non-quality work, but they.iilow for differences in how qualny related vs. non quality related work is accomphshed.
Differences between quahiy and non-quality work activities not drnen by the OA program. regr ations or codes should be minimued.
.
..
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_
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ISE ASSESSMENT NO. 92 22
COMPARISON OF QUAUTY AND C
NON OUALITY RELATED WORK ACTIVITIES Finally, the team noted instances where the field personnel took exception to OC involvement in non quality related work activities and did not understand or accept the fact that OC can be involved with non quality related work.
Recommendations Because the procedure differences were limited, the team did not see the procedural differences as a major concern and recommended that the programs and procedures not undergo extensive revisions, but more appropriately that standards and expectations be clearly communicated and consistently enforced throughout PVNGS.
The following specific recommendations were made within the body of the team report:
Revise maintenance programs and procedures to require an increased level
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of detail for non quality related work packages. Revising the seven specific procedural differences (identified by ISE) would enhance the quality of non-quality related work packages.
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If it is a good idea to perform an activity in quality related work it is a cood idea for all work unless the activity is based on codes, regulations or Quality Assurance progiam requirements. if there is a documented:venfied skill possessed by all personnel in a craft, then that skill applies to all their work.
Establish, clearly communicate, and consistently enforce standards and-
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expectations concerning level of detail, craftstnanship, and use of resources for quality vs. non-quality and priority vs. low pnority work.
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Ensure that the standards and expectations are clear, consistent and understood.
Ensure that planning and scheduling put the correct priority on all work.
- Ensure that.dl maintenance personnel are aware of the " graded" approach ta
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OC oversigat. Also ensure that they understand that QC is not limited as ta what they mspect. The message must be clear that we are only tmne to improve how we do business throuch our observations and our own ' critic.il
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k ISE ASSESSMENT NO. 92 22
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C COMPARISON OF QUALITY AND NON-QUALITY RELATED WORK ACTIVITIES i
i Resiew the differences between quality and non quality related engineering e
i work activities with the goal of reducing any differences not specifically required by codes or the QA Program.
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l ISE ASSESShtENT No. 92 23
C TECIINICAL SPECIFICATION SURVEILIANCE VALVE ALIGNh1ENT EXECUTIVE SUM 51ARY INTRODUCTION As a corrective action to address events similar to those identified in Licensee Event Report (LER) 92 008," Surveillance Requirement for Nonessential Auxiliary Feedwater Pump Not Performed," Unit 1, dated S/8/92, Independent Safety Engineering (ISE) performed an evaluation to verify that the Technical Specification (TS) surveillance procedures for valve alignment included all the valves required to be checked per the applicable TS surveillance requirements (SR). Additionally, ISE made a determination as to why previous audits and reviews of the TS surveillance program did not discover the problem addressed in the LER.
LER 9M03.Section IV. Previous Sirnilar Events states in part: * A review
...
will be conducted to verify that the TS surveillance testing procedures for sahe alignments include all the valves required to be checked in tbc applicable TS SRs.* and *. The review will abo attempt to ascertain why presious audits and reviews of the TS surveillance prograrn did not discover
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these ornasions.*
SCOPE A total of 47 Technical Specification suneillance requirements were iden ificd by ISE that require verification of proper valve alignment.
All 47 TS surveillance requirements were evaluated ngainst the applicable TS surveillance test procedures to verify the valve alignment met the intent of the TS surveillance requirements. Additionally,ISB cvaluated previous audits of the TS program and interviewed member.
of the Quality Audits and Monitoring Department.
RESULTS Areas fur improsement in general, the surveillance test program meets the technical specification surveillance requirements.
However, the established procram provides the minimum level ot' action necessary to meet the reculatory requirements. For example: palo Verde verifies only those vanes in a specific flow path to meet the inteni of a TS reqturement.
1511 belieses that not only should the flow path valves be scritied, but also the valves for components and subsptems that support the splem to ensure operanihtv.
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ISE ASSESSMENT No. 92 23 (
TECHNICAL SPECIFICATION SURVEILLANCE
VALVE ALIGNMENT CONCLUSIONS The assessment disclosed two areas where the TS surveillance test may not meet the intent of the TS surveillance requirements.
TS #4.7.3.a. and 4.7.6.1 require operability be verified by verifying valves servicing safety related equipment are in their correct position.
However, some valves in support or interface systems or components are not verified by the associated ST. To address this concern, CRDR
- 92 0472 was issued for TS #4.7.3.a and TS #4.7.6.1 was added later in the review. Operations took conservative action and verified the valves listed in the CRDR were in their correct position.
The preliminary response to the CRDR supcests that the ST is adequate to meet the intent of the TS. See Attachment B, CRDR #92 0472 and Attachment A. !' Observation Report 92 0034.
A detailed evaluation of the 47 surveillance requirements is on file and available from ISE.
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The assessment of the previous audits and reviews revealed that some technical problems have been identified: even thouch, the emphasis of
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past audits and reviews were on programmanc and pro:edural compliance. As an example, the problem addressed in LER 92 008 was identified by Ouality Audit and Monitoring (OA&51) personnel while reviewing a proposed revision to a suneillance test procedure.
Since the audit and monitoring activities review only a cross sect.a of an overall area, OA&M, as an oversight group. is not always in a position to identify problems in n.U programmatic and technical areas.
However, to enhance its abilities to identify technica' problems.
OA&M has emphasized hiring individuals with nuclear plant operating experience (RO/SRO). Additionally, the scope of future audits will be reduced to increase the level of detail fu the review.
RECOMM EN.
e ISE recommends a conservative approach to the issue DATIONS addressed in CRDR #92 0472. ISE believes that an associated systems or components must be available tor a system to be considered operable. Therefore, the boundary takes in.it are not verified in the current program and whme f unction a necessary should be included in the applicable stin eill.ince test.
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ISE ASSESSMENT No. 92 23
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TECHNICAL SPECIFICATION SURVEILLANCE
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VALVE ALIGNMENT -
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-t TS #4.4.8.3.1 requires each shutdown cooling system suction _
(SCS) line relief valve be verified to be aligned every eight
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hours to provide overpressure protection for the RCS when the RV head is installed and the RCS temperature T, <255'F.
during cooldown or <295'F during heatup. The only document that checks these valves is 40ST.9RC01, which requires the a
valves be checked every six hours during heatup and cooldown, i
Due to the significance of pressurized thermal shock (PTS)i plant parameters are to be maintained within the limits of TS- , 3.4.8.1; therefore, these SDC reliefs must be in senice when the l
reactor vessel head is installed to prevent exceeding the
pressure limitations at a low reactor coolant temperaturei Although not a TS requirement, to improve nuelcar safety ISE recommends periodic verification of these valves while at steady _
state, in. Modes 4, 5 and 6 when the reactor vessel head is j
installed.
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Sutveillance Requirement 4.4.8.3.1 has an approved change -
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effective September 16, 1992. The change has the shutdown
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cooling system suction line relief valve verified aligned once per 31 days when the pathway is provided by a locked open valve during cooldown 1214*F and heatup 5291'F with the reactor vessel head tensioned (12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> if the pathway valve is not locked).
In implementing the revised requirement ISE l
recommends conservatively including periodic verification of.
these valves while in steady state conditions with the reactor vessel head tensioned.
- TS #4.7.1.2.a.2 requires the Auxiliary Feedwater pump (AFP).
- associated flow path be verified every 31_ days, while in Modes 14. The valves in the Main Feedwater System that are in the -
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now path of the non essential AFP are not specifically checked in 4XST.XAF03, as referenced in 73DP.XZZ01, ' Technical Specification Surveillance Requirements Cross Reference. Unit -
X."
However, these valves are verified in 40ST 4AF00. ISE recommends that 73Dp.XZZ01 be reviewed to venfy the
proper ST procedures are referenced for TS #4.7.1.2.a.2.
.
Operaunns Standards was aware of this discrepancy and has t
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ISE ASSESSMENT No. 92 23
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TECHNICAL SPECIFICATION SURVEILLANCE VALVE ALIGNMENT-initiated documentation to resolve this recommendation. No further action is required.
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TS #4.7.4.2 requires two essential spray pond loops operable by--
verifying locked valves in their correct position once per 18 months during shutdown. The required position for SPA HV-
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49A/B and SPB.HV 50A/B is " Manual Handwheel Locked,"
which is not a valve position. ISE recommends identifying SPA -
HV.49A/B and SPB.HV 30A/B in an open or closed position for better control of the valve position.
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ISE MISSION STATEMENT ISE'S MISSION IS TO AlD IN THE IMPROVEMENT OF NUCLEAR SAFETY AT PALO VERDE BY PROVIDING RECOMMENDATIONS TO APPROPRIATE MANAGEMENT AND ADVISING MANAGEMENT ON THE OVERALL QUALITY AND SAFETY OF OPERATIONS.
TO PERFORM THIS MISSION ISE:
PERFORMS INDEPENDENT ASSESSMENTS OF PLANT ACTIVITIES INCLUDING OPERATIONS, MAINTENANCE. AND MODIFICATIONS:
MAINTAINS SURVEILLANCE OF PLANT OPERATIONS AND
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MAINTENANCE ACTIVITIES TO PROVIDE INDEPENDENT VERIFICATION THAT THESE ACTIVITIES ARE PERFORMED
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CORRECTLY AND THAT HUMAN ERRORS ARE REDUCED AS FAR AS PRACTICABLE. AND TO DETECT POTENTIAL NUCLEAR SAFETY HAZARDS:
EXAMINES NRC ISSUANCES, INDUSTRY ADVISORIES LICENSEE EVENT REPORTS, AND OTHER SOURCES OF PLANT DESIGN AND OPERATING ENPERIENCE INFORMATION INCLUDING PLANTS OF SIMILAR DESIGN. WHICH MAY INDICATE AREAS FOR IMPROVING PLANT SAFETY: AND AIDS IN Tile ESTABLISilMENT OF PROGRAMMATIC REQUIREMISTS FOR PLANT ACTIVITiliS.
JUNE 23.1992
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Arizona Public Senice Company COMPANY CCRRLsPONDENCE ID #:
023-03642-RNP Date:
October 13, 1992 To: -
ISE Staff Sua
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Concurrence:
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Ram N. Prabhakar
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Subject:
Management's Expectations for independent Safety Engineertne INTHODICTinN
You hase, from time to time, raised questions as to how-we can effccincly meet the intent of PVNGS Technical Specifications for !$E (Section 6.2.3), to the satisfaction of both PVNGS management and the NRC.
Another question you have asked is recarding the distinction between OA Monitoring and ISE roles when
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some of the activitics appear to usetlap. Another ongoing concern is the amount of time ISE engmeets are expected to spend in the field overviewine actmties as outlined in the Technical Specitications.
In this memo. I will attempt to answer your questions and also lay out some broad espectations tot the ISE group. If you still have questions on these or other related issues, please do not hesitate to contact me.
DISCI'SMION
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The ultimate measure of ef fettnencs, of an) usersight orcant/ation, su;h as ISE is to help run an operation where there are no incidents that create nuclear safety harards os contribute to situations that challenge safety
sptcms. Obviously, we all know that w hen humans and machinery are involsed. such incidents are unavoidable.
It would be great if we had a crutal ball which would tell us exactly where the next sately siemlicant event is poing '
Le place so that we can take approprute measures in advance to preclude the twcurrence of that cvent1
- r facility. Once aeain..ou and I both know that n unhtut thinkine. Die next best thing we can do, as an enersight oreara/ation n to hase or desclop the fore teht, wndom and the capability to evaluate incidenh that have happentd N!h at our plant as well as others, and to wme up with cifectne wan and means of presentine sut h inu icnh at our 1.wikis. Din n w nere ettion ti.'.' I et techmcal Speciucations somes into the pat ure. Tho.u i.on requires inat toli tunction to cuimne plani operatine i harasicraiin. N ac osuantes, industry ads nor u s. lActnce 1%cnt Ret' orb and other ouno os liiant desien and epciatine esperience inlormation. includine plarih et stimlar doien ums h in.n indnaie arc.n for unpros me plant victv.
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023-03M2.RNP October 13,1992 Page 2 Next, let us briefly examine the role of ISE and QA Monitoring and discuss how these functions are to be accomplished to avoid duplicallt,n of effort. ISE's role is one that should be 'proactive' in nature. The emphasis is on taking appropriate steps to preclude safety significant incidents trom occurring. In general, ISE's role should be 'real time', either forward or backward looking with great flexibility to look *into' issues anywhere they find them. ISE has a higher !cvel of oversight with greater responsibility. QA Monitoring's role, on the other hand,is not mandated by 'fbchnical specifications and is intended to be accomplished by a group of discipline experts who conduct their observations in the field, assessing performance against an established scope. With that distinction being made between ISE and QA Monitoririg's functions, ISE's activities should be geared towards reviewing up front, plans and procedures for plant evolutions and actidties that are either conducted infrequently or that are of a highly specialized nature, with the Intention of identifying procedural steps or activities that may compromise nuclear safety or cause human errors to be made. A technique that can be usef 'O employed here is the Error Modes and Effects Analpis, used during the Shutdown Risk assessment on Unit I conducted during the early part of the year. Again. this does not mean that the ISE '
Engineer is going to sit at his desk and perform all these reviews and issue reports. On a routine basis, ISE engineers should select high risk or non. routine evolutions in the operations, maintenance and modification areas for observation while they are being pertormed. Many times. this will be the only way to identify problems / inadequacies / deficiencies that may not be obvious to the performer or become apparent during up front reviews. When activitics are selected by ISE for observation, it is important that conimunications be established with OA Monitoring (and QC, where appropraalet to ensure no dupheation occurs.
Agai% as an oversight organization. it is of vitalimportance that we maintain independence of our actions and be obgctive in our evaluations and assessments. Guidance and expectations included in this memo are not to be considered allinclusive. Many times >ou w111 hase to go where your in:tincts lead you based on careful
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observation techniques.
t With this much as background material,let me lay out my expectations for the ISE >tatt.
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M mCDIENT EXPECT \\TIOW l.
By attendance at the Daily Plant Status Meetings, review of work actiuty schedules and discussion with plant staf f. identify key evolutions that may hase nuclear safety significance or has a potential for ercating human error during their execution. As part of this process. ISE >hould periodically look at the impact and significance on the plant of safety equipment taken out of <eruce and wheduling of high risk work activities. Another area worth pursuing is the scheduling of work actnity on energized electrical equipment to determine if a constmus determination has been made as 10 the need for performing that activity in that state and the consequences on plant >afety of any human crror. Also, as part of this process. I would e.tpect that at least one activity per week per unit well be selected for ob3ervation by the ISE engineers using the guidance I hase prouded under the Discunion part to ehminate duplication between ISE and QA Monitoring.
Another aspect that should not be ignored is she sele (Inc uscrucw on ti a kshif t acinitiet As esperience.
time and aeain has shown. : hat; when the most serious protWms appear to i.ike pixe :: nuclear power plJnt oper.itlem. I woubl 4 spect th.It e 14 h ISli encincer peri itm.iii.4cis 6 w sil.it k.ist oliv l'.n kshitt Allsity per Llu.irter.
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By review of unit outage schedules, determine key actMtics that will benefit from an ISE overview from the standpoint of precluding nuclear safety significant incidents. This should include operations, maintenance and modification activities. The emphasis here, as stated earlict, is for the ISE organization
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to take a proactive, forward looking role and review the plans and preparations for the evolution prior to execution, as against Monitoring's (or Quality contrct's) role, wh!ch is one of ensuring compliance using performance based techniques. For those evolutions, where it is desirable for both the ISE and the Monitoring organizations to be involved during their execution, agree up front with QA Monitoring (and OC Inspection, when applicable and necessary) a: to each organization's role, to avoid duplication of e!Iort.
>
Again,it is important to remember that during outages, although ISE's coverage of the outage t.ntt may
!
be rnore than that of the non-outage units, attention should continue to be given to the non outage units.
3.
The effective implementation ofitems I and 2 noted above will result in a significant amount of field time for the ISE staff. ISE's visibility and involvement with plant activities are important and fic!d time is an indication of that. Field time does not exclusnely include the time you spend overwcwing implementation of evolutions or work activities, but also includes the time you spend with the Operations and Maintenanc staff, reviewing plans, procedures, performing field walkdowns, cic. It is anticipated that actisities described in 1 and 2 above will result in a field time of anywhere Irom 30 !o 40G of each of your time.
4.
Proper and effective implementation of items I and 2 should result in ISE Observations documented as Minor Assessments. My expectation is that, on an average, a rninimum of four such Minor Assessments
.
per engineer should be completed during the month.
5.
Perform or participate in the performance of Major Assessments, as directed by ISE Superusion and
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Management. No more than four Major Assessments will be planned for during any calendar sear.
6.
Performar.cc of observations and assessments may, at times, result in the identification of unsatisfactory areas. A concern has been e.spressed as to ISE's role regarding identification of prontems and subsequent
'
tracking of their resolutions, as this process may take ISE's time away from a true osersight function. I do not believe there is any question in your minds as to the need for documenting issues and concerns -
via appropriate mechanisms, when they arise. I also do not believe that you uculd want to identify a problem and not be concerned with how it was resolved to ensure prevention of recurrence. You must -
therefore, plan and manage your activitics in such a way that you can allocate time for this important serification activity. You must make sure that this does not consume extensoe amounts of your time. If you have other suggestions, please discuss with me.
7.
Perform reviews of your awened industry, operating esperience information, clearly with the intent of flagging items of safety Aicnilicance basing impact on or applicabilitt to Palo Verde. As part of this process, ISE enginects will be espected to make recommendations ior enhancine nuclear sately at Paio Verde.
RNPAdd cc:
W. E Conway W2 S. G. Perm L 7W7 R. C. Fullmer 7W6 C.N.Ruwo -
W2 R. B. Cherba 7W5 T C. Stewart 79N)
M. D. Fereuson 6792 L
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nu 02 005 726 suenct INDEPENDENT SAFET.' ENGINEEltlNG ACTIVITY REPORT. JUNE 1992 Attached please find the Independent Safety Engineering (ISE) Actwiry Report for June 1992.
Any suggestions for improvement of format or content of this report are most welcome. Also if there are any questions on any aspects of the report, please contact cather mpell or Stese Penick at extension 6629.
o RNP/SGP/tes (
cc:
W. F. Conwey 9032 J. St. levine 7602
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R. J. Stes ens 7603 E. C. Simpson 7616 R. E. Gouge 7610
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August 31,1992
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klfi To:
Ram Prabhakar N
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Jim Levine
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in NUMARC 9106. The results of your review show that this was not an adequate effort at all on our part. The calv cood point is that it was caught Kk internally and with enough time left to fix it.
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I do have a question. however, on one statement in your report. At the top of
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page 3 vou state "..Not unexpectedly, the responses were generally superficial, k:
mcompletely documented cnd frequently did not completely address the
.% y NUMARC guidance."
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I am curious as to why you believe this is "not unexpectedly". My expectations.
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statement would lead me to believe that stiperficial work of this nature is
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A commonplace. Is this the case? If so, I would like to discuss other examples
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so that I can personal 1" address them with the appropriate individ@
k, Please respond by Sept 'er 15.1992.
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- t To:
Ram N. Prabhakar0NoAnnex20NoAnnex2 SSWGatc0Eerver 440 Servers (APSVMB60.SGUTHRIE)
Cc:
Ecc Fro 3:
Robert J. Adney, Subject:
ISEG Date:
Friday, September 11, 1992 at 12:47:00 pm Attcch:
Cartify:
N Forwarded by:
Ram N.
Prabhakar0NoAnnex20Nr/. inex 2
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _.
___________________
Comments by:
Ram II. Prabhakar0NoAnnex20NcAnnex2 Forwarded to:
Stephen G.
PenickONoAnnex20NoAnnex2 Comments:
FYI AS DISCUSSED. LET'S DISCUSS THIS TOMORROW. TX
[ Original Message)
To: RPRABHAK--BANYAN PRABilAKAR, RAM N.
cc: Z99652
--APSVMB60 GUTHRIE, STEPHEN C FROM:
Robert J.
Adney, U/3 Plant Manager ETA:
7394 JJT:
2520 Subject: ISEG RAM, I HAVE BEEN PONDERING THE CHANGES GOING O!! IN THE OVERSIGHT DEPTS. AND I BELIEVE THERE IS AN TREA T11AT WE AS AN ORGANIZATION SEEM TO OVERLOOK. WHEN EVER WE HAVE PROBLEMS WE SEEM TO NARROWLY FOCUS ON THE PIECE OF DOCUMENTATION, EQUIPME!IT, OR PART TilAT HAS A PROBLEM AND NOT ENOUGH ON THE OVERALL SAFETY OF Ti!E PLANT AS A WilOLE. I FEEL WE FIX ONE THING WHILE WE CREATE ANOTHER PROBLEM.
IT CAN BE CALLED RISK MANAGEMENT, BALANCING THE VARIOUS HAZARDS, HAZARD PREVENTION, ETC. FOR EXAMPLE WE HAD A RECOMMENDATION FROM ENG. TO CHANGE OUT A FWIV 4 WAY VALVE. TilEY WERE COMPLETING A ROOT CAUSE AND FELT THAT ONE OF OUR VALVES MAY BE UN-RELIABLE. Ili ORDER FOR US TO CHANGE OUT TilIS VALVE WE MUST ENTER A 4 HOUR ACTION STMT. AND THEN START A SHUTDOWN IF YOU CAN'T RESTORE OPERABILITY. WE FOCUSED ON Tl!E 4 WAY VALVE AND NOT ENOUGli ON WHAT I CALL A BALANCED APPROACH TO SAFETY. THERE WAS ANOTHER ISOLATION VALVE IN SERIESWITil THE VALVE IN QUESTION, ANY DOWN POWER MANEUVER WOULD CAUSE A COMPLETE SHUTDOWN BECAUSE OF OUR TIME IN LIFE. ANY TIME WE DRIVE THE PLANT DOWN WE RISK SOME TYPE OF TRANSIENT AND CHALLENGES TO OUR SYSTEMS. WE ALSO IIAD APPROX 10 DAYS LEFT TO OPERATE. IN BALANCE I BELIEVE WE WERE NOT MAKING THE BEST DECISION.
THE MOST COliSERVATIVE IN NOT ALWAYS THE BEST. IF THAT WAS Tile CASE WEWOULD NEVER ACTIVATE Ti!E CORE AND CREATE A POTENTIAL HAZARD, I KNOW TilAT TIIIS IS AN EXTREME EXAMPLE BUT WE MUST BE ABLE TO MAKE REASONABLE EVALUATIONS IN Tile WHOLE. I BELIEVE T!!AT YOU AND YOUR DEPT. CAN llELP US SEE THE FOREST TIIROUGli THE TREES. DURING YOUR DEPT. DAILY VISITS I WELCOME TilEM TO LISTEN FOR ISSUES TilAT TAKE SAFETY EQUIPMENT OUT OF SERVICE TO MAKE IT "BETTER" AND ADVISE ME OF THE WISDOM OF DOING SO. TliANKS FOR LISTING, BOB.
SAFETY - COST - PRODUCTION - PROFESSIONALISM i
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'To 2-Stephen G. Penick0NoAnnex29NoAnnex2
.Cc3-
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- Front '.
Robert J. Adney, (Subject:
ISE CUSTOMER QUESTIONS Dats: _
Sunday, October 18, 1992 at 12:27:00 pm Attach:
C rtify:
N Forwarded by:
j
____________________________________________________________________________
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Tot SPENICK --BANYAN PENICK, STEPHEN G.
FROM Robert J. Adney, U/7 Plant Manager STA:
7394 EXT:
2520 Subject: ISE CUSTOMER QUESTIONS
,
- HELLO STEVE, THAT'S FOR TAKING THE TIME TO INQUIRE ON YOUR PERFORMANCE.--I
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BELIEVE THAT YOUR GROUP IS HEADING IN THE RIGHT DIRECTION, THEY ARE GETTING'
- MORE INVOLVED IN: THE DAY TO DAY ACTIVITIES AND THE THOUGHT PROCESS THAT IS BEHIND THE DECISIONS. THE FORMAT OF THE REPORTS AND THE CONTENTS ARE
. APPROPRIATE AND OBJECTIVE. I BELIEVE THAT THE DEPT. NEEDS TO ESTABLISH A LINE OFfCOMMUNICATIONS WITH THE PLANT AND PERFORMANCE ENG. GROUPS.-THEY HAVE SET'
NEW GOALS FOR THEM SELVES AND I BELIEVE THAT A MUTUAL UNDERSTANDING OF MISSIONS AND GOALS IS'THE RIGHT THING TO DO..YOU MAY-ALREADY HAVE SET UP
DIALOGUE WITH THE ENG. ARM OF THE STATION, IF SO WELL_DONE. IF NOT-I RECOMMEND -
-THAT YOU DO.I WOULD LIKE YOU TO PERFORM AN EVALUATION OF.THE MOV PROGRAM._THIS:
.
PROGRAM HAS HAD A SIGNIFICANT AFFECT ON THE ENTIRE STATION AND ESPECIALLY.
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OUTAGES. I BELIEVE WE NEED A FRESH LOOK AT THE BASIS FOR OUR-PROGRAM, AND
.
.-QUESTION WHY-WE DO SOME OF THE THINGS AND IF IT IS THE MOST EFFECTIVE USE OF.
OUR RESOURCES. FOR EXAMPLE WE DO AN AS FOUND MOVAT SIGNATURE ON A VALVE THAT
~
WE KNOW WE WILL REPACK OR REBUILD. THIS INFORMATION MAY BE GREAT FOR A-DATA-BASE, BUT IT COSTS-SET UP TIME, HOLDS-THE SYSTEM OUT FROM DOING WORK, AND COSTS POTENTIALLY UN-NECESSARY--EXPOSURE. THIS IS-NO MINOR TASK,_ YOU MAY NEED TO SCHEDULE IT FOR A 1993 EVALUATION. HAVE A GOOD DAY, BOB.
SAFETY - COST - PRODUCTION - PROFESSIONALISM
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--Date-and. time 10/06/92J12:23300'
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' Frost Stephen G. Penic
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Ta -SGUTHRIE--APSVMD6 Gut 3rie, Stephen C.
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{,]l,SPENICK --BANYAN Penii:T, dEepnen.G.
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1 ubject: ISE CUSTOMER IOUT S
Ccaments by:
Stephen G.
PenickONoAnnex20NoAnnex2 Forwarded to:
Stephen C. Guthrie@NoAnnex20NoAnnex2
^ Comments:
For your info.
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STEV,
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IN ANSWER TO YOUR RECENT MEMO I PROVIDE THE FOLLOWING'INP'
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.1.
IN GENERAL ISE IS MEETING OUR EXPECTATIONS.
HOWEVER, IT.WOULD.BE
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VALUABLE TO US IF YOUR GROUPS SPENT MORE TIME IN ROUTINE OBSERV" ION AND IMMEDIATE FEEDBACK SUCH AS ROUTINE MONITOR WATCHES IN THE~ Ct ;4 TROL }
,
ROOM OBSERVING OPERABILITY CALLS, ST EVALUATIONS, WORK CONTROL ON
SHIFT, ETC.
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2.
SOME GOOD. ITEMS TO PROVIDE FEEDBACK ON ARE: INTERORGANIZATION COMMUNI-CATIONS, DECISION PROCESS ON SCHEDULING HIGH RISK UORK, RNOWLEDGE-OF WORKERS ON MATTERS OF MANAGEMENT INTEREST AND OTHER TOPICS PROVIDED BY THE PLANT MANAGER.
3.
THE MONTHLY REPORTS'ARE NOT SUCCINCT.
WE FREQUENTLY HAVE TO WADE THROUGH A LOT TO GET TO THE REAL MEAT OF THE REPORT.
THE SDIMARY-HELPS,JBUT THERE IS A LOT OF ROOM FOR IMPROVEMENT.
.
4.-
THE REPORT FORMAT IS ADEQUATE IF THE CONCERN IN NUMBER 3 ABOVE -IS ADDRESSED.
5.
REPORT DISTRIBUTION IS FINE.
j
- 6.
INTERFACES ARE NOT OPTIMAL.
TRY COMING TO DAILY STATUS MEETINGS A FEW TIMES A WEEK OR ATTENDING UNIT STAFF $4EETINGS' ON THURSDAY AFTERNOON ABOUT'
ONCE A MONTH TO OPEN UP MORE COMMUNICATION.
I THINK DILL IDE'S PRACTICE l
OF A MONTHLY MANAGEMENT MEETING IS HELPFUL.
'
I HOPE THESE COMMENTS ARE CONSTRUCTIVE AND IIELP YOU.
E'D BE HAPPY To MEET.
L WITH YOU AND ELABORATE ON THIS IF-NEEDED.
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From: Z20004
--APSVMB60 Date and time 10/14/92 19:01:21 To: 253314
--APSVMB60 IDE, WILLIAM E.
cc: SPENICK --BANYAN PENICK, STEPHEN G.
299652
--APSVMB60 GUTHRIE, STEPHEN C RPRABHAK--BANYAN PRABHAKAR, RAM N.
Z78795-APSVMB60 RIEDEL, FREDRICK K Z38847
--APSVMB60 GOUGE, RICHARD E.
Z32196
--APSVMB60 DENNIS, JOHN W.
From: R.
Schaller b
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Subject: ISE CONCERN REGARDING VALVE LINEUP ST'S di BILL, YOU ASKED ME TO SUMMARIZE HOW THE ISSUE OF ST ADEQUACY RAISED IN ISE ASSESS-MENT #92-23 WAS ADDRESSED.
AS YOU KNOW THERE WERE TWO CONCERNS:
1.
THERE ARE A NUMBER OF ESSENTIAL COOLING WATER VALVES WHOSE POSITIONS ARE NOT CHECKED MONTHLY AND ARE NOT LOCKED OR OTHERWISE SEALED.
WHY IS IT PROPER TO EXCLUDE THESE VALVES FROM THE MONTHLY VALVE LINEUP ST?
2.
WHY ARE THE NC/EW CROSS TIE VALVES TESTED ON THE 18 MONTH ST OF AUTO ACTUATED VALVES, BUT IT NOT CHECKED ON THE MONTHLY LINEUP?
THESE CONCERNS WERE DOCUMENTED ON CRDR 9-2-0472 WHICH WAS RESOLVED AND CLOSED OCTOBER 1 AFTER ISE REVIEW.
THE CRDR RESPONSE LOOKED AT TWO FACETS: WHAT IS LEGALLY REQUIRED BY THE TECH i
SPECS, AND WHAT MEASURES SHOULD WE PRUDENTLY REQUIRE TO ENSURE EW IS AVAILABLE TO COOL SAFETY EQUIPMENT.
THE LICENSING DEPARTMENT REVIEWED THE STANDARD TECH SPECS (NUREG 0212), PVNGS TECH SPECS AND THE PROOF AND REVIEW COPY OF NEW STANDARD TECH SPECS (NUREG
'
1432) BEFORE CONCLUDING THAT THE CURRENT ST LINEUP CHECK SATISFIES THE MINIMvM REQUIREMENT OF CHECKING VALVES WHICH PROVIDE AN EW COOLING FLOWPATH TO SAFETY RELATED EQUIPMENT.
THAT ENSURED WE LEGALLY MEET THE PVNGS TECH SPECS.
NEXT OPS STANDARDS LOOKED AT THE FUNCTION OF THE VALVES CALLED OUT BY ISE AND
+
DETERMINED WHETHER MISPOSITIONING OF THESE VALVES COULD REASONABLY GO UNDETECTED AND IMPAIR THE ABILITY OF EW TO COOL SAFETY LOADS.
IN EACH SCENARIO
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THEY DETERMINED THAT THE VALVE DID NOT DIRECTLY INTERRUPT THE FLOWPATH TO ANY SAFETY RELATED EQUIPMENT, AND EITHER HAD NO IMPACT ON THE SAFETY FUNCTION OF EW OR WOULD RESULT IN A MONITORED OUT OF SPECIFICATION READING (E.G. HIGH OR LOW EXPANSION TANK LEVEL) BEFORE COOLING ABILITY WAS IMPACTED.
SINCE THIS WAS THE CASE THE DETERMINATION WAS MADE THAT THE CURRENT ST'S ARE ADEQUATE BOTH FROM THE STANDPOINT OF MEETING LEGAL REQUIREMENTS AND IN MEETING THE PRACTICAL INTENT OF THE SPECIFICATION.
THE QUESTION OF WHETHER T!!E NC/EW CROSS TIE VALVES SHOULD BE MONITORED MONTHL IS ADDRESSED AS FOLLOWS.
T.S.
4.7.3.A ONLY REQUIRES MONTHLY TESTING OF VALVE IN THE COOLING FLOWPATH TO SAFETY RELATED EQUIPMENT.
THE X-TIES ARE NOT IN T.
SAFETY GRADE FLOWPATH TO COOLING ANY SAFETY RELATED EQUIPMENT (THEY PROVIDE A
'4EANS OF BACKING UP EW).
T.S..
4.7.3.B REQUIRES THAT VALVES WHICH SERVICE SAFETY EQUIPMENT AND RECEIVE AUTOMATIC SIGNALS DE TESTED EVERY
'3 MONTHS TO ENSURE THEY RESPOND TO THE SIGNALS.
EVEN THOUGH THE CROSS TIE VALVES DO NOT SERVICE SAFETY RELATED EQUIPMENT THEY DO RECEIVE A SIAS CLOSING SIGNAL WHICH UOULD SPLIT GUT EW FROM NC IN AN EMERGENCY, AND STANDARDS CONSIDERED IT PRUDENT TO CHECK THIS FEATURE Iss PART OF THE INTEGRATED RESPONSE TO A SIAS SIGNAL EVERY 18 MONTHS.
THESE RESOLUTIONS WERE REACHED ALTER EV ER A L " E ET ' ';GS ;iIH
- E,
'PS AND OPS STANDARDS.
MY INVOLVEMENT IN TilIS AROSE ~RCM "Y J::CERN HEN HEADING THE REPORT, AND I REQUESTED THAT ISE DISCUSS EN E * ; SUES JITH.HE JNIT OPS MGRS.
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lTHROUGHOUT THE RESOLUTION I FOUND ISE TO BE SENSITIVE TO ALL THE ISSUES AND IMPACTS.
STEVE PENICK DEVOTED A-LOT OF HIS TIME TO HELPING US RESOLVE THIS SUCCESSFULLY.
THESE WERE GOOD QUESTIONS TO ASK!
IF YOU NEED MORE INFORMATION PLEASE LET ME KNOW.
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NRC INSPECTION REPORT (IR) 50-306'92005 AUGNIENTED INSPECTION TEAM (AIT) INSPECTION OF PRAIRIE ISLAND NUCLEAR GENERATING STATION INIT 2 LOSS OF DECAY IIEAT RI310 VAL (DIIR) ON 2/20!92 EVALUATIONt
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The event was previously reviewed by ISE under NRC IN 92-16. Supplement 1 (ISE Document Evaluation Log #603004).
Prairie Island overdrained the Reactor Coolant System (RCS) while attempting 13 go to mid-loop operations, resulting in loss of DHR. The NRC sent an AIT to investigate ti e event and the AIT felt the following factors directly contributed to the cause of the event:
1.
The design of the electronic level measurement instruments was incompatible with the nitrogen pressure specified in the draindown procedure. The instruments were essentially unavailable during the entire draining process.
2.
The draindown procedure did not adequately describe the required processes to achieve a reduced inventory condition.
3.
The tmining and experience of the operators and suppon engmeering were insuff: cent to
perform the assigned tasks.
4.
The operators and senior operators did not exhibit a questioning attitude wnn regards to safety. With two out of three channels ofinstrumentation inoperable and concems over the behavior of the plant the operators continued draining the reactor coolant system.
6.
Management anention was inadequate in the areas of training human factors procedure and design reviews, and operator supervision.
It is ofinterest to note that they were entering mid-loop two days after shutdown (PVNGS was previously analyzed for 5 days and is now analyzed for 1 day).
_
PVNGS does not use an nitrogen overpressure on the RCS anymore. The typon tube, if used.
is a backup to the newly installed reactor vessel water level system at PVNGS. PVNGS had an event involving the new water level instruments being inaccurrate due to inadecuate venting by the technician, resuldng in vonexing of the shutdown cooling (SDC) pumps. Procedures u ere revised to more specifically describe the venting process. PVNGS has draindown and acnormal operating procedures in place (previously reviewed by ISE in FE 91-29). Note that ISE did find the RCS draindown procedure to be comphcated and made several recommendations for l
procedure changes which are partially incorporated at this time. As PVNGS is not gom; to perform mid loop operations with fuel in the core, tramine has not been performed. A lesson t
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plan is available for STA traming. NUMARC 01-oo. "Guidehnes for Industry Actions to Assess t
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NRC INSPECTION REPORT (IR) 50 306'92005 AUGh1ENTED INSPECTION TEAh! ( AIT) INSPECTION OF PRAIRIE ISLAND NUCLEAR GENERATING STATION L* NIT 2 LOSS OF DECAY IIEAT RE.\\10 VAL (DIIR) ON 2/20/92 EVALUATION (CONTINUED):
Shutdown hianagement," is being incorporated into the License Operator Initial Training by June 30,1993, and will be part of the first quaner 1993 Industy Events for non-licensed operators.
Heightened operator and management anention during off normal events was addressed in IhTO SOER 91-01, which was evaluated by ISE in FE 92-01. PVNGS management has also increased supervisory presence in the field for Operations and hiaintenance (see meeting notes for hTC and APS management meeting of 5/26!92). The findings of the Prairie Island AIT should not be a problem at PVNGS, given completion of existmg commitments.
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Docket No. 50-306 Northern States Power Company
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Mr. L. M' '
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Vice President, Nucle c f
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Minneapolis, MN 55401
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Dear Mr. Eliason:
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l, SUBJECT: NRCINSPE(TION EPORT 50 00 k
.
This refers to the special inspection conducted by the Nuclear Regulatory Cc:nmission Augmented Inspection Team (AIT) at your Prairie Island Nuclear Generating Plant during the period from February 21 through.25, 1992, concerning an interruption in decay heat removal during reouted inventory operations at Unit 2 which occurred on February 20, 1992.. At the conclusion y
C of the inspection, the findings were sumarized at a.public meeting' attenced by those memoers of your staff identified in the enclosed inspection report.
The enclosed copy of the AIT report identifies the areas examined during this.
inspection.
Within these areas, the inspection consisted of selective examinations of plant harc=are, procedurcs and other recorcs, interviews with personnel, and observation of activities in progress.
The AIT concluded that management had made a number of changes in the process for establishing stable reduced-inventory Conditions in the reactor Cooling system.
Although intended as improvements, these enanges were net Q1
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adeouatelv evaluated, either individually or'in the accrecate.
As a
'
consequence, a comoination et tactors, including inaceouate supervision, level
,
instrument design limitations, reduced engineering su;: port, proceoure
~
j ambiculties, and inaceouate _ training led to a conottion where the personnel who'were draining water' f rom the system believed they knew the current -water level.wnen, in fact, they did not.
Bv eroceeding cespite cuestions'about instrument and system benavior, operators 01c not exhibit an aggressive, l
questioning safety attituoe.
Water level went below that necessary for l
continued coeration of the.in-service cooling: pump, making it necessary.to l
shut off the pt.mp and interrupt operation of the restoual-heat -removal system
.
A review of the inspection findinos is continuing to determine whether the described activities violated NRC recuirements.
You will be advised by separate corresponcence of the results of our review of this matter, t
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Northern States
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Power company
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. In accordance with Section 2.790 of the NRC's " Rules of Practice," a copy of this letter and the enclosure will be placed in the NRC Pubite Document Room.
Should you have any questions concerning this letter, please contact us.
.
A. Bert Davis, Regional Administrator Enclosure:
HRC Inspection Report 50-306/92005 cc w/ enclosure:
E. L. Wat:1, site Manager,.
Prairie Island Site M. Sellman, Plant Hanager DCD/DCS (RIDS)
OC/LFDCS
,
Resident Inspector, RIII Honticello
'(
John W. Ferman, Ph.D.,
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Nuclear Engineer, MPCA o
State Liaison Officer, State of Minnesota Prairie Island, LPM, NRR Robert M. Thoroson, Administrator Visconsin Division of Emergency Government J. C. Partlow, NRR C. E. Rossi, NRR G. Holanan, NRR V. D. Lanning, NRR J. Zwollnski, NRR E. Jordan, AECD G. Grant, E00
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