ML20058D357
| ML20058D357 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 10/15/1993 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML20058D309 | List: |
| References | |
| 50-528-93-40, 50-529-93-40, 50-530-93-40, NUDOCS 9312030137 | |
| Download: ML20058D357 (59) | |
See also: IR 05000528/1993040
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~ . .. . . . . . . , -U. S. NUCLEAR REGULATORY COMMISSION REGION V Report Nos. 50-57t/93-40, 50-529/93-40, and 50-530/93-40 Docket Nos. 50-528, 50-529, and 50-530 License Nos. NPF-41, NPF-51, and NPF-74 Licensee: Arizona Public Service Company P. O. Box 53999, Station 9082 Phoenix, AZ 85072-3999 l Facility Name: Palo Verde Nuclear Generating Station ! Units 1, 2, and 3 Inspection Conducted: August 17 through September 20, 1993 Inspection l Location: Wintersburg, AZ Inspectors: J. Sloan, Senior Resident Inspector i l H. Freeman, Resident Inspector l A. MacDougall, Resident Inspector l F. Ringwald, Resident Inspector B. Olson, Project Inspector . T. Alley, Department of Energy Inspector l
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Approved By: r M HJ Wong, Chief (/ Date Signed Reactor Projects Section II Summary: Areas Inspected: Routine, announced, resident inspection of: the review of plant activities
engineered safety features walkdowns - Unit 2 e surveillance testing - Units 1 and 2 )
! plant maintenance - Units 1 and 2 e simulator scenario observation - Unit 1
main steam safety valve testing - Unit 1
l unlatched core element assembly - Unit 1 l
valve SGA-UV-134A dual position indication - Unit 1 '
reactor coolant pump seal controlled bleedoff flow meters - Unit 2
steam generator tube rupture corrective actions - Unit 2
reactor coolant pump speed probe modification - Unit 3
loss of letdown, charging, and seal injection flow - Unit 3 l
i overtime limits - Units 1, 2, and 3 l
followup on previously identified items - Units 1, 2, and 3 '
review of Licensee Event Reports - Unit 2
l gj2030137933g,, G ADOCK 05000528 PDR,
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During this inspection the following inspection procedures were utilized: 37700, 40500, 41500, 60710, 61726, 62703, 71707, 71710, 90712, 92700, 92701, 92702, and 93702. Safety Issues Manaaement System (SIMS) Items: None. Results: General Conclusions and Specific Findinos: Strengths: Plant engineering showed good initiative and developed a comprehensive
action plan to address concerns with main steam safety valve testing (Paragraph 7). Response to an unlatched core element assembly (CEA) during the removal
of the upper guide assembly in Unit I was good, and the retrieval of the CEA was conducted in a safe and controlled manner. (Paragraph 8).- Licensee actions in response to increased hydrogen leakage from the Unit
I main generator were good (Paragraph 2.a). . < Operator response to a loss of letdown, charging and seal injection flow
in Unit 3 was good (Paragraph 13). i Weaknesses: Operators did not properly mark unsatisfactory data and conduct an
appropriate retest during the performance of a surveillance test in Unit 2 as required by procedures (Paragraph 10). An individual exceeded overtime limits during the 2R3 refueling outage in
Unit 2, and additional discrepancies of overtime limits were identified by the licensee's Quality Assurance program (Paragraph 15.b). The work order for testing of an auxiliary feedwater valve in Unit 2 did
not have adequate instructions for installing the torque switch. In addition, the worker did not follow the procedure for adjusting the torque switch open setting (Paragraph 15.c). The Plant Review Board's recommendation and licensee management's
, conclusion that all the main steam safety valves in Unit I were operable after most of the valves tested had failed could not be supported logically and was inconsistent with the actions to suspend testing and reducepower(Paragraph 7). A Unit 2 reactor operator did not know why a significant annunciator was -
in alarm (Paragraph 2.e). 2 . -- . _ . . . . . .
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. ,. . . ... .. .. _ . .. , . .. . . .. . . . . . . . - . . The licensee did not initiate timely action to evaluate cleanliness of
the Unit 1 ADV nitrogen system after an inspector identified that a cleanliness cover was missing (Paragraph 5). l The breaker trip setpoints for auxiliary feedwater valve AFB-HV-30 were
' incorrectly set which contributed to the failure of the valve to open in Unit 3 (Paragraph 15.a). Some communications deficiencies were observed during observation of
simulator scenarios (Paragraph 6). Sionificant Safety Matters: None. l ' Summary of Violations: Of the 15 areas inspected, three cited violations were ' identi fied. One violation involved exceeding Technical Specification overtime limitations. The second violation in Unit 2 involved the failure to properly mark unsatisfactory data during a surveillance test. The third violation in Unit 2 involved the failure to provide instructions for installing a torque switch in the work order. Two non-cited violations were identified involving the failure to follow procedures during the setting of a torque switch in Unit 2 and the failure to follow procedures for controlling relay setting sheets in Unit 3. Summary of Deviations: None. , Unresolved Items: One item remained unresolved pending an investigation of the root cause of an unlatched control element assembly in Unit 1 and the potential safety consequences of the event (Paragraph 8). t a 3
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. . . ' . _.; < .,. ';.. . _ . , .... ...;..,7 . . . , . .. . . . . . , . - . . , DETAILS 1. Persons Contacted - The below listed technical and supervisory personnel were among those contacted: Arizona Public Service Comoany (APS) R. Adney, Plant Manager, Unit 3 J. Bailey, Assistant Vice-President, Nuclear Engineering & Projects R. Bernier, Supervisor, Nuclear Regulatory Affairs Technical
R. Bouquot, Supervisor, Quality Audits and Monitering
T. Bradish, Manager, Nuclear Regulatory Affairs R. Cherba, Manager, Quality Systems P. Coffin, Engineer, Nuclear Regulatory Affairs J. Dennis, Manager, Operations Standards / Plant Support R. Flood, Plant Manager, Unit 2 R. Fountain, Supervisor, Quality Audits and Monitoring
R. Fullmer, Manager, Quality Audits and Monitoring
D. Gouge, Director, Plant Support
B. Grabo, Supervisor, Nuclear Regulatory Affairs
D. Hettick, Supervisor, Station Operating Experience Department W. Ide, Plant Manager, Unit 1 ~ D. Leech, Supervisor, Quality Audits and Monitoring
i J. Levine, Vice President, Nuclear Production
D. Mauldin, Director, Site Maintenance and Modifications W. Montefour, Senior Coordinator, Management Services
G. Overbeck, Director, Site Technical Support
R. Prabhakar, Manager, Independent Safety and Quality Engineering F. Riedel, Manager, Operations, Unit 1
C. Russo, Manager, Quality Control
R. Schaller, Assistant Plant Manager, Unit 1 J. Scott, Assistant Plant Manager, Unit 3
C. Seaman, Director, Quality Assurance and Control
M. Shea, General Manager, Radiation Protection P. Wiley, Manager, Operations, Unit 2
Others l J. Draper, Site Representative, Southern California Edison
F. Gowers, Site Representative, El Paso Electric
' j R. Henry, Site Representative, Salt River Project
Denotes personnel in attendance at the exit meeting held with the
NRC resident inspectors on September 22, 1993.
. s. . . . ,. ;. . .:r ;.> .. ...- .;s..~ ,... ; r '. >.. . .: : .~ e . v- v .p ; - h.. . .- .. .. . . 2. Review of Plant Activities - Units 1. 2. and 3 (71707) a. Unit 1 - Unit I began the inspection period in an end-of-cycle coastdown with reactor power being maintained at 72%. On August 23, 1993, seven main steam safety valves were declared inoperable when they were tested and reset and power was reduced to 65% in accordance with , Technical Specification requirements (see Paragraph 7). On August 29,1993, a 8100 standard cubic feet per day (SCFD) main generator i hydroger leak was identified from the T-6 neutral overcurrent ' bushing. Blowers were installed to minimize the potential buildup of hydrogen and generator pressure was lowered which reduced the l leak rate to 3500 SCFD. The inspector concluded that these actions were prudent. On September 4, 1993, the reactor was shut down and Mode 3 entered . for the start of refueling outage IR4. The Unit entered Mode 6 on September 12, 1993. On September 15, 1993, during removal of the upper guide structure (UGS) in preparation for core off-loading, CEA 1
- 34 (12-finger) was found to be unlatched and in the fully inserted
position (see Paragraph 8). The unit ended the inspection period with the core off-loaded. b. Unit 2 " nit 2 began this inspection period in Mode 5 near the end of the 2R4 refueling outage. The Confirmatory Action Letter, issued on June 4,1993, as a result of the March 14, 1993, steam generator tube rupture event, was lifted on August 19, 1993. The unit was restarted, entering Mode 2 on August 28, 1993, and Mode 1 the following day. The main generator was connected to the grid on September 1, 1993, and power ascension testing was performed. On September 5,1993, during Unit 2 power plateau testing at 70% power, the licensee noted unexpected differences between the core operating limit supervisory system (COLSS) detailed report and the i i CECOR core analysis program output, primarily in the calculations of the relative power. The licensee declared COLSS inoperable and determined that core parameters were within Technical Specification limits, averting a downpower. The licensee further determined that three of six COLSS databases contained data for Cycle 4 instead of Cycle 5. Cycle 5 data was then loaded, and COLSS was declared operable on September 6,1993. Condition Report / Disposition Request (CRDR) 2-3-0531 was initiated. The inspector will review the licensee's CRDR evaluation following completion (Followup Item , 50-529/93-40-01). j . Power was increased to 100% on September 6, 1993, but was reduced to 80% on September 10 to allow more efficient cleanup of radioactivity in secondary systems. The licensee subsequently decided to limit power to 89% to improve the steam generator life, and increased 2
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.. . . , ,, , power t'o 89% on September 13, 1993. Additionally, reactor coolant , system (RCS) cold leg temperature was reduced from 565 *F to 562 *F
on September 14, 1993, to achieve a lower RCS hot leg temperature.
Operation at 89% power continued for the remainder of the inspection period.
' c. Unit 3 Unit 3 operated at essentially 100% power throughout the inspection ' ' period. On September 9,1993, emergency diesel generator (EDG) "A" failed to achieve rated frequency s 10 seconds during surveillance
testing. A faulty air start valve was replaced and the EDG was ' , retested satisfactorily. On September 11, 1993, power was reduced
to 98% to conduct surveillance tests on steam bypass control valves , and on atmospheric dump valves. Power was returned to 100% on l , September 13, 1993, after completing moderator temperature ' coefficient tests. On September 17, 1993, the failure of a power distribution module caused a temporary loss of letdown, charging, and reactor coolant pump seal injection (see Paragraph 13). The - unit ended the period at 100% power. d. Plant Tour
The following plant areas at Units 1, 2, and 3 were toured by the - inspector during the inspection: Auxiliary Building
, Control Building
Diesel Generator Building
Fuel Building
Main Steam Support Structure i
Radwaste Building i
Technical Support Center
, Turbine Building
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Yard Area and Perimeter Containment Building
The following areas were observed during the tours: (1) Ooeratino loos and Records - Records were reviewed against Technical Specifications and administrative control procedure requirements. During a review of the Unit 2 Control Room logs for September 16 and 17, 1993, the inspector noted several deficiencies in the equipment status section. The Assistant Shift Supervisor stated the deficiencies were due to an oversight by the reactor operator and lack of consistency in understanding the terms > used in the equipment status section. A request was submitted by the Assistant Shift Supervisor for the terms to be defined in a procedure revision. The inspector concluded that the. licensee's actions were appropriate. 3 i , . , -. - . - -.- ., .
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.: . _ . . . . . . s. .. .. ., . . . . . (2) Monitorino Instrumentation - Process instruments were observed i , for correlation between channels and for conformance with 4 Technical Specifications requirements. i ' (3) Shift Staffino - Control room and shift staffing were observed for conformance with 10 CFR Part 50.54.(k), Technical Specifications, and administrative procedures. (4) Eouipment Lineups - 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. (5) Eouipment Taccino - 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 Eouipment Conditions - Plant equipment was observed for indications of system leakage, improper lubrication, or other conditions that could prevent the systems from fulfilling their functional requirements. The inspector observed a small welding machine tied off to large safety injection system piping and a large pipe support in the Unit 140' auxiliary building pipe chase. While this is contrary to license procedures and expectations, the inspector concluded that this was an isolated example. The licensee acknowledged the comment and corrected the discrepancy. (7) Fire Protection - Fire fighting equipment and controls were observed for conformance with Technical Specifications and administrative procedures. (8) Plant Chemistry - Chemical analysis results were reviewed for . conformance with Technical Specifications and administrative control procedures. (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. . (10) Plant Housekeepino - Plant conditions and material / equipment storage were observed to determine the general state of cleanliness and housekeeping. (11) Radiation Protection Contro1s - 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, hnd personnel frisking practices. 4 __ -_ ._. - _ _ _ . . - ~ - - -
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- . . , . _ , On September 16, 1993, in Unit 2, the inspector observed a cigarette butt on the auxiliary building roof and a paper drinking cup on the main steam support structure roof, both in the radiologically controlled area (RCA). The licensee initiated a Condition Report / Disposition Request (CRDR) to evaluate the materials, which are prohibited in the RCA. The ' licensee indicated that paper cups similar to the one found had been used for mixing grout in the area, which could explain why the cup was in the RCA. The inspector concluded that these were isolated examples of low significance and that the licensee's response was appropriate.
On August 10, 1993, the licensee identified an a1 parent sleeping / resting area in the RCA of Unit 1, in tie Radwaste Building on the 110' elevation above valve gallery R-124. The Plant Manager stated that this was inappropriate and that efforts were continuing in trying to identify those i responsible. CRDR 1-3-0395 was initiated. The inspector noted , that the licensee had identified previous examples of potential sleeping areas (see NRC Inspection Report 50-528/93-26, i ! Paragraph 2.f.) and concluded that the licensee's actions were appropriate. (12) Shift Turnover - Shift turnovers and special evolution briefings were observed for effectiveness and thoroughness. e. Operator Unfamiliar with an Annunciator - Unit 2 On August 31, 1993, in response to the inspector's question, the reactor operator who was on shift did not know why annunciator IB10A,"13.8/4.16 Kv BUS XFR NOT-IN-AUTO," was in alarm. After- several minutes, two reactor operators were able to determine that the cause was that the unit was shutdown and the buses were not powered by the auxiliary transformer. The inspector concluded that this represented inadequate reactor operator familiarity with , current plant status. The Unit 2 Operations Manager agreed, and stated that this problem would be addressed promptly. The inspector J further concluded that licensee's subsequent corrective actions were appropriate. No violations of NRC requirements or deviations were identified. 3. Enaineered Safety Features (ESF) System Walkdown - Unit 2 (71710) A selected engineered safety feature system was walked down by the inspector to confirm that the system was aligned in accordance with plant procedures. During this inspection period the inspectors walked down accessible portions of the Unit 2 Auxiliary Feedwater System. No violations of NRC requirements or deviations were identified. 5
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. _ , . . . . , , 4. Surveillanc Testina - Unit 1 (61726) Selected surveillance tests required to be performed by the Technical Specifications were reviewed on a sampling basis to verify that: 1) the surveillance tests were correctly included on the facility schedule; 2) a technically adequate procedure existed for performance of the surveillance tests; 3) the surveillance tests had been performed at the frequency specified in the Technical Specifications; and 4) test results satisfied acceptance criteria or were properly dispositioned. i Specifically, portions of the following surveillances were observed by , the inspector during this inspection period: Unit 1 Procedure Description 73ST-9ZZl8 Main Steam Safety Valve Pressure Verification No violations of NRC requirements or deviations were identified. 5. Plant Maintenance - Units 1 and 2 (62703) During the inspection period, the inspector observed and reviewed selected documentation associated with maintenance and problem investigation activities listed below to verify compliance with regulatory requirements, compliance with administrative and maintenance procedures, required quality assurance / quality control department involvement, proper use of safety tags, proper equipment alignment and use of jumpers, personnel qualifications, and proper retesting. The inspector verified that reportability for these activities was correct. i Specifically, the inspector witnessed portions of the following maintenance activities: , Unit 1 Corrective maintenance of valve SGA-UV-134A (see Paragraph 9) e High pressure safety injection (HPSI) "A" pump seal replacement e On September 8,1993, the inspector oaserved portions of the "A" HPSI pump seal replacement. The work was being performed in a contaminated area (CA) and a worker outside the CA was reading the procedure, but did not feel he had the authority to sign off for the work. The foreman had arrived shortly before the inspector and identified that the preceding work had been performed without initialing the steps as the work was performed. The foreman assured the inspector that this did not meet his expectations for procedure use and that in the future he would provide a " field copy" of the procedure for use in the CA, if necessary. The inspector concluded 6
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(ADVs)
On September 16, 1993, the inspector observed a portion of the design modification to the ADV nitrogen accumulators. The inspector
noted a cleanliness cover was missing from an open nitrogen supply line (1" line). A worker immediately replaced the cover, but the i condition was not documented End no action was taken to initiate an evaluation of the system cleanliness until the inspector discussed , this issue with licensee management. A boroscope inspection was
! performed to ensure the cleanliness class was not degraded. The results were negative. A Condition Report / Disposition Request
' (CRDR) was written to evaluate the human performance aspect of the l cover being left off. The inspector concluded that the licensee's actions were appropriate. i Reactor vessel head removal !
j Upper guide structure removal
e Core off-load 1 Unit 2 Eddy current inspection of EW heat exchanger "A"
Eddy current inspection of EW heat exchanger "B"
Replacement of cracked crosshead on charging pump "A"
Packing replacement on steam bypass control valve SGN-PV-1002
No violations of NRC requirements or deviations were identified. 6. Simulator Scenario Observation - Unit 1 (41500) l On August 27, 1993, the inspector observed a Unit 1 evaluated simulator scenario. The scenario was a small break loss of coolant accident. The inspector noted several examples of less than formal verbal communications involving incorrect repeat backs. The inspector noted l that control room briefings were good. However, the Shift Supervisor downplayed their importance by not paying visible attention.and by l placing a telephone call to the shift technician (an administrative ' assistant) during one control room briefing. No A0 briefings occurred. The inspector also noted that the R0 did not announce a planned reactor l trip to all plant personnel until prompted by the control room supervisor (CRS). In addition, the CRS had to direct the secondary operator (S0) to monitor Tave and Tref more closely after giving the direction that the 50 was responsible for maintaining Tave and Tref within 2 *F. The shift l 7 ._ . __ _ ~ . _~ __.
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~ ' - technical advisor (STA) also had to prompt the 50 to announce B07 l annunciator 783B, "CTMT sumps Excess Leakage." l l The inspector also noted that the Shift Supervisor was involved for r approximately three minute: personally making the site public address announcements for the site alert status. The inspector questioned i whether this task could be delegated or not. The instructors stated that I this is how they train shift supervisors. Late in the scenario, the l inspector observed the STA evaluator pass a note containing a suggestion to the Shift Supervisor. The inspector concluded that this action inappropriately interfered with the training scenario. These concerns were identified by the NRC inspector during the l observation of the simulator scenario and the inspector noted that licensee training personnel did not mention the issues dfring the brief critique held by the instructors / evaluators immediately following the i scenari o. The inspector concluded that despite the identified I weaknesses, the operators maintained good control of the plant and appropriately followed their emergency operating procedures. The j inspector issues were discussed with training personnel and the comments
acknowledged by licensee management. l No violations of NRC requirements or devictions were identified. ' 7. Main Steam Safety Valve (MSSV) Testina - Unit 1 (40500 and 71707) l On August 21, 1993, Unit I suspended testing of the MSSVs because 8 out , ! of 9 valves tested at that time had setpoints that were outside the * 1% Technical Specification limit. The testing of the MSSVs was being l conducted using the "Trevitest" method by Furmanite. This test involves i attaching a test rig to tk MSSV and determining the force required to " pop" the valve. This frece is then converted to a lift pressure using an appropriate valve seat area. Each unit has a total of 20 MSSVs,10 ' per steam generator, manufactured by Dresser, with setpoints of 1250,
1295, and 1315 psia. i The licensee questioned the test results using the Trevitest because all the failures were below the setpoint (the failures ranged from 1.8% to 5.4% l ow) . This was not expected because at Palo Verde the setpoint historically drifts high. Additionally, all the MSSVs in Unit I were tested and lift setpoints established during the last outage with live '
steam at the Westinghouse test facility. The valves were thought to be in the best possible condition; therefore, the large number of failures, especially low setpoints, was unexpected. l The Unit 1 Plant Manager called for a meeting of the Plant Review Board ' (PRB) on August 23, 1993, in response to the questions concerning the I ' Trevitest method. After a lengthy discussion concerning the technical aspects of the testing, the PRB members discussed the operability of the MSSVs. The PRB decided that the seven valves that failed and had their setpoints reset using the Trevitest were operable (one valve that failed cnd was not reset was concluded to be inoperable). This determination 8 l i
. M . 3 . . ~. L. .., [ l: . .. : l. . . . , 3. .. ; .. " .:. 5;+,. .. . . , .a ~, .: , . : . , , . : . ., , _ ) , was based on the fact that the Trevitest method was an industry-accepted j method and there was not enough data to invalidate the testing method. 1 Additionally, the PRB concluded that the eleven valves that were not tested were operable based on satisfactory Westinghouse tests during the i previous outage. The licensee suspended the testing because of the questions concerning how to properly interpret the Trevitest results when the setpoints were previously set using the Westinghouse method. Because of these , ' uncertainties, there was a possibility that the seven valves whose setpoints were reset using the Trevitest method may have had their setpoints inappropriately raised. As a compensatory measure, the Plant
Manager decided to take the Technical Specification (TS) actions for i 2 having four MSSVs inoperable rcr steam generator, and plant power was reduced to 65%. However, the MSSVs were not declared inoperable. The inspector attended the PRB meeting and noted that the PRB attempted to reach a conclusion without either declaring the test method invalid or declaring the valves inoperable. The inspector also pointed out to the PRB that a decision concerning operability needed to be made using the information available at that time. It appeared that since the licensee had sufficient uncertainty concerning the actual setpoint of the valves to justify taking the required TS actions, then the valves should have been declared inoperable. After a conference call with NRC Region V management, the licensee decided to declare the seven valves that were reset using Trevitest inoperable. Although the inspector concluded that the actions taken by the licensee were conservative with an appropriate level of concern for safety, the inspector concluded that the PRB's ' recommendation and management's decision to declare all the MSSVs operable was an incompatible position for the valves which had been tested and those which had not been tested and was inconsistent with the licensee's actions to suspend testing and reduce power. On August 25 through August 27, 1993, engineers tested three MSSVs at the Westinghouse test facility using both the Westinghouse live steam test and the Furmanite "Trevitest." The tests were conducted using MSSVs that had been previously tested by Westinghouse and stored in the Palo Verde { warehouse. The purpose of the tests was to determine if there was an ' offset between the two test methods that would account for the large number of failures using the Trevitest. Based on the data collected from these tests, the licensee concluded that even though there was an offset between the two test methods, the data from the two methods generally correlated and both methods appeared to be acceptable. The inspector concluded that the action plan developed by plant engineering to resolve this issue was comprehensive and was a good initiative. i The licensee planned to remove all twenty MSSVs from Unit I during the current refueling outage and conduct similar tests with both the , Westinghouse and Furmanite test methods. This will be done to see if the MSSVs setpoints are actually drifting and to gaantify the apparent offset between the test methods. The inspector will review the tasting results as part of the review of LER 50-528/91-005. 9 - .
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.. , , 3 , . . . .. . No violations of NRC requirements or deviations were identified. - 8. Unlatched Core Element Assembly (CEA) - Unit 1 (62703 and 71707) _ At approximately 4:30 a.m. (MST) on September 15, 1993, during removal of the upper guide structure (UGS) in preparation for core off-loading,12- finger CEA #34 was found to be unlatched and in the fully inserted The licensee halted the UGS removal operation, leaving the UGS position. The CEA suspended over the core about two feet above the vessel flange. extension shaft was observed to be moving which indicated that the CEA Based on the location of the UGS relative to the was clear of the core. reactor vessel flange, the licensee calculated that the lower end of the CEA was about two feet above the core. The UGS is normally removed by installing the UGS lift rig and then lose"ing the upper plate of the UGS lift rig over the CEA extension shafts. At this point self-latching mechanisms (SLM) installed on the upper plate should engage the CEA extension shafts. A pin is then manually installed in the SLM to prevent unlatching, then the upper plate is lifted, withdrawing all the CEAs from the core and into the UGS simultaneously. The UGS lift rig is then lifted, removing the UGS and the CEAs from the reactor vessel. The licensee determined that CEA #34 had not been latched and that In this event, the personnel had failed to properly verify the latching. pin that was installed in the SLM was erroneously inserted in the " locked disengaged" position which prevented the SLM from latching the CEA. , Additional checks, including visual inspection with binoculars, failed to recognize that the extension shaft for CEA #34 was not raised. The inspector observed the licensee's retrieni of CEA #34 into the UGS, which was successfully accomplished about 8:00 p.m. on September 15, 1993. The licensee used a special tool to hook a J-slot in the end of the extension shaft, and pulled the CEA up. .The tool was then tied off and was used to hold the CEA instead of the normal SLM during the rest of the UGS removal operation. The licensee then stored the UGS in the UGS The inspector observed that the workers attempted to minimize their pit. exposures by remaining in low dose areas as much as possible. One exception was noted when two workers assigned to withdraw the CEA with the chain fall climbed on the upper guide structure prior to fully extending the chain fall. This required the workers to spend ) approximately five extra minutes in a high radiation area while they extended the chain. The inspector concluded that the response to this event was good. The licensee appropriately stopped the lifting evolution and conducted a - thorough evaluation of the situation before attempting to retrieve the CEA. The retrieval of the CEA was conducted in a safe and controlled The inspector noted that the polar crane had the UGS completely manner. supported during the time the UGS was suspended over the core and there However, the shift was little risk of the UGS falling into the core. supervisor was concerned about the remote possibility of the UGS falling 10 - ,
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... . , .. , r, . . . .. . . - . . .. . . . . . . f . . . into the core and a briefing on containment evacuation was conducted as a contingency action. The inspector concluded that these actions were - appropriate. _ i ) The licensee initiated Condition Report / Disposition Request (CRDR) 1-3- - ' 0479 to conduct an investigation of the root cause of the mis-inserted pin in the SLM and the potential safety consequences of having an i unlatched CEA while the UGS was lifted. The results of the. investigation will be reviewed in a future inspection report (Unresolved Item l 50-528/93-40-02). ,
No violations of NRC requirements or deviations were identified. Valve SGA-UV-134A Dual Position Indication - Unit I (62703 and 92701) i 9. l On August 25, 1993, control room operators.noted that SGA-UV-134A, steam i I l bypass valve to the turbine driven auxiliary feedwater (AFW) pump, had a dual position indication. The valve and the turbine-driven AFW pump were 625578 was written to correct the
declared inoperable and Work Order problem. The inspector observed the maintenance and noted that the
problem was caused by a cracked terminal block in the solenoid valve,
manufactured by Target Rock. The terminal block was replaced and the valve was satisfactorily tested. The inspector concluded _that the I operators were attentive to their indications and that the licensee i appropriately conducted the maintenance activity. The inspector also noted that the cracked terminal block would not have prevented the valve , from opening and performing its intended safety function. 2 The inspector noted that the other units have had problems with these ', l solenoid valves which are in a high temperature environment in the main steam support structure. Additionally,- the inspector noted that in l I Unit 1 there were numerous problems with SGA-UV-134A during the last two ' The inspector also determined that there were not any routine years. On preventative maintenance activities performed on these valves. August 27, 1993, the inspector noted that a Condition Report / Disposition ) Request (CRDR) had not been written to evaluate the failure of SGA-UV- i 134A. After the Shift Supervisor and the Shift Technical Advisor were- questioned by the inspector, CRDR 1-3-0427 was initiated. The inspector concluded operations personnel did not thoroughly evaluate the significance of this event and initiate a CRDR. The inspector discussed this with the operations manager who agreed with the inspector's observation. The inspector discussed the EQ life of these valves with the EQ The life of the valves was based on an analysis performed by engineers. Target Rock for both the energized and deenergized solenoid valves. Based on this study, the life of the coil in the deenergized valve was The forty years and in the energized valve it was about five years. engineer was not aware of any coil failures in-the deenergized application similar to SGA-UV-134A. However, based on the number problems with these valves, CRDR 9-3-0456 was written to evaluate the adequacy of a forty-year EQ life. The inspector also determined that the 11
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' . . . , , . . , . . . reliability of the Target Rock solenoid valves was being evaluated by the valve services engineers in CRDR 1-1-0055. This evaluation has been ongoing and a final report was due to be issued on October 29, 1993. - The inspector concluded that the licensee appropriately documented the overall issue concerning the reliability of Target Rock solenoid valves. The inspector will review the results of the evaluations in CRDRs 9-3- 0456 and 1-1-0055 in a future inspection (Followup Item 50-528/93-40-03). 1 No violations of NRC requirements or deviations were identified. 10. Reactor Coolant Pumo (RCP) Seal Controlled Bleedoff Flow Meters - Unit 2 (61726 and 71707) On August 14,1993, Unit 2 was in Mode 3 when operators noted that during the performance of surveillance test 42ST-2CH04, " Boron Injection Flow Test " the RCP seal controlled bleedoff flow indication used to perform the surveillance test, was not indicating properly. Therefore, the operators were unable to calculate the boron injection flow to the reactor coolant system as necessary to satisfy the Technical i Specification (TS) requirement and demonstrate that the boron injection flow paths were operable. At approximately 4:15 a.m. control room personnel entered TS Limiting Condition for Operation 3.0.3 and began a plant cooldown. At 9:00 a.m. the unit entered Mode 4 and at 10:00 a.m. operators exited TS 3.0.3 when the bleedoff flow indication was restored. The inspector concluded that the actions by the operators were appropriate. , On August 25, 1993, the meters were again not functioning properly and strap-on ultrasonic flowmeters were installed using temporary l modification (TMOD) 2-93-RC-018. On August 27, 1993, surveillance test 42ST-2CH04 was performed to verify the reliability of the flow meters after the installation of the TMOD. The data collected from the flow meters resulted in a calculated boron injection flow of 25.8 gpm, just below the acceptance criteria of 26 gpm. At that time the operators went back to verify the recorded values of bleedoff flow and found that they had changed. The operations supervisor was consulted and directed the flow meters be observed and then the data retaken. The flow meters were observed for four hours and the fluctuations continued. The data was ' retaken and the previous data was lined out. The new data resulted in a flow of 26.8 gpm. No entries of these conditions were made in the surveillance test (ST) log during this period. The following morning the operations manager reviewed the actions by the crew and directed the operators to perform the alternate method for determining the operability of boron injection flow paths in Appendix "A" to 42ST-2CH04. This method used a flow balance of the volume control tank to determine RCP bleedoff flow instead of the installed meters. The appendix was developed as an alternate method of performing the surveillance if the installed meters were unavailable. The inspector , questioned the operations manager concerning the. performance of the surveillance test and the lack of an entry in the ST log. The operations 12
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, , , , manager indicated that he had already directed that a late entry be made in the ST log explaining the situation and the actions taken. . . The inspector concluded that the actions to line out the first set of data was contrary to 73AC-9ZZO4, " Surveillance Testing," in that unsatisfactory data was not circled and the proper retest using a white copy of the procedure was not conducted. This is an apparent violation of TS 6.8.1 (Violation 50-529/93-40-04). The inspector noted that the safety significance of this error was minimal. The retest using the more accurate method in Appendix "A" was performed satisfactorily. Additionally, the technical basis for the 26 gpm requirement could not be found. However, the error was another example of a failure to follow surveillance test procedures (see Inspection Reports 50-528/93-26, j Paragraph 3, and 50-528/93-35, Paragraph 4) and demonstrated an apparent lack of procedural compliance by operations personnel. This violation ' would have been considered a non-cited violation but for the fact that two recent NRC inspection reports have~ also identified deficiencies in this area. One violation of NRC requirements was identified. 11. Steam Generator Tube Ruoture (SGTR) Corrective Actions - Unit 2 (92700 and 92702) The inspector reviewed licensee actions related to the SGTR event of March 14, 1993 in order to determine whether the licensee had accomplished its commitments. The licensee's commitments were documented in the NRC Safety Evaluation Report dated August 19, 1993. Specifically, the following documents were reviewed: 72AC-95B01, Rev. 05.03 Initiating / Processing Changes to CPC/CEAC Type II Addressable Constants and Reload Data Block Constants 74AC-9CYO4, Rev. 05.18 Systems Chemistry Specifications 74DP-9ZZ05, Rev. 02.07 Abnormal Occurrence Checklist 74CH-9ZZ66, Rev. 04.00 Determination of Primary to Secondary 1.eak Rate 74CH-9XC16, Rev. 07.11 Sampling and Analytical Schedule 74RM-9EF42, Rev. 00.10 Radiation Monitor Alarm Setpoint Determination j a. The licensee committed to move the steam generator blowdown sample radiation monitor (RU-4 and RU-5) sample points from the hot leg blowdown to the downcomer area of the steam generators. The inspector reviewed procedure 74DP-9ZZ05, Appendix D, which states that these monitors should be lined up to the downcomer sample point. Additionally, the inspector disce.ssed the lineup with i operations and effluents personnel, who affirmed that the monitors were lined up to the downcomer. The inspector concluded that the licensee's actions were adequate. b. The licensee committed to reduce the alert setpoint of the condenser vacuum exhaust radiation monitor (RU-141) to provide earlier alarm , to operators. The inspector reviewed procedure 74RM-9EF42, which 13
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a a . , .. . . . . . . . , . . . ... .. . i states that the RU-141 alert setpoint should be set initially to four time.c the average reading. Additionally, the setpoint must be - verified at least monthly to be three to five times the average - value for the evaluation period. The inspector verified the setpoints and averages displayed by the radiation monitoring system computer in all three units and verified the setpoints were reduced. The licensee justified and implemented a more conservative setpoint in Unit 3 (less than three times the average), based on the very low primary activity in Unit 3, in order to further increase the sensitivity to primary-to-secondary leakage. At the time of the inspection, Unit 2 was in Mode 5 (condenser not in service), making the actual average value meaningless. However, the calibration record indicated that the alert setpoint was set to four times the average value for the last operational period. The inspector concluded that the licensee's actions were adequate. c. The licensee committed to increase'the leak monitoring frequency for primary-to-secondary leakage as leakage increases. The inspector confirmed that procedure 74DP-9ZZ05, Appendix D, required the frequency to be increased to once per day if leakage is determined , to be increasing, but is less than 10 gallons per day (gpd), and to - monitor shiftly if the leak rate is determined to be greater than 10 gpd. The licensee committed to perform a formal evaluation for continued operation if the leak rate is greater than 10 gpd and increases by more than 50% in a 24-hour period, or if the leak rate exceeds 25 1 gpd. Additionally, the licensee committed to perform a plant shutdown if leakage exceeds 50 gpd. The inspector confirmed that ' procedure 74DP-9ZZ05 contains these requirements, and concluded that the licensee's actions were adequate. d. The licensee committed to reduce the core protection calculator , (CPC) variable overpower trip setpoint from 10% to 8%. The inspector reviewed the completed Appendi'i A to procedure 72AC-9SB01 for each unit, and verified that the setpoint changes had been implemented in the CPCs in all three units. The inspector concluded that the licensee's actions were adequate. e. The licensee committed to administrative 1y limit primary c)olant iodine activity to 0.6 pCi/gm (steady state) and 12 pCi/gm (peak). The inspector verified these limits were in procedure 74AC-9CYO4, and concluded that the licensee's actions were adequate. f. The licensee committed to perform the following additional actions by October 31, 1993. These actions will be verified by the resident inspectors during a future inspection (Followup Item 50-529/93-40-05): Modify SGTR procedures to transfer secondary system sump
discharge promptly to liquid radwaste. 14
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- auxiliary steam source to an unaffected unit. - . Modify SGTR procedures to allow main feedwater system
operation, to allow the continued use of steam generator i blowdown demineralizers. Modify SGTR procedures to allow main feedwater and condensate l
! system operation throughout recovery from a SGTR event. Modify the Safety Function status check of the Excess Steam
Demand Procedure to guide operators to exit the Functional Recovery Procedure (FRP) based on indications of a Main Steam Line Break /SGTR event. Broaden status checks within the FRP for indications of a
possible SGTR to include checks' consistent with the Excess Steam Demand Procedure ststus checks. . g. The inspector reviewed primary-to-secondary leakrate monitoring actions following unit restart. The licensee shifted its primary focus to RU-141 as this monitor became more sensitive than tritium monitoring. The inspector also noted that the licensee experienced difficulty in placing RU-4 and RU-5 in service because of contamination in the sample lines which saturated the monitors. Therefore, the monitors were not in service at the end of the inspection period. Following discussions with the licensee regarding efforts to restore the monitors to service, the inspector concluded that the licensee's actions were appropriate. At the end of the inspection period, the licensee stated that it was capable of detecting primary-to-secondary leakage as low as about 3.5 gpd. No violations of NRC requirements or deviations were identified. 12. Reactor Coolant Pumo (RCP) Speed Probe Modification - Unit 3 (37700)
i On August 29, 1993 Temporary Modification (TMOD) 3-93-RC-009, , " Temporarily Connect Core Operating Limit Supervisory System back-up ' speed sensor #155 from Reactor Coolant Pump (RCP) '1A' to replace failed Core Protection Calculator (CPC) channel 'B' speed sensor #113B," was installed in Unit 3. The output from speed sensor #113B was degraded and was causing spurious low departure from nucleate boiling trips on CPC J "B." Previous attempts to correct the problem were unsuccessful and CPC "B" was declared inoperable on August 20, 1993. The inspector revi;wed ' the completed work package and TMOD and concluded that the modification and 10 CFR 50.59 evaluation were appropriately conducted. No violations of NRC requirements or deviations were identified. 15
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. . . .. 13. Loss of Letdown. Charoina and Seal In.iection Flow - Unit 3 (93702) On September 17, 1993, a power distribution module failed in a Foxboro instrument rack which powered the letdown heat exchanger outlet control. This failure resulted in the loss of letdown, the running charging pumps, and reactor coolant pump seal injection. After assessing reactor safety, the licensee investigated the malfunction and replaced the failed module. . Subsequently, the chemical and volume control system was restored to its normal operating condition. The inspector observed the licensee's actions from immediate response through system restoration. The inspector noted the appropriate use of the alarm response procedures by the operators. Additionally, the inspector noted that the appro)riate amount of emphasis was placed on safety, and that the crew quic(ly determined the cause of the failure. The inspector concluded that the event was handled well by the licensee. No violations of NRC requirements or deviations were identified. 14. Overtime Limits - Units 1. 2. and 3 (71707) ' In response to an NRC request, the licensee performed a review of access control records and time sheets which resulted in a determination that one individual had exceeded the work hour limitations of Technical Specification (TS) 6.2.2.1.b during Unit 2 refueling outage 2R3. Specifically, the licensee found a violation of the TS had occurred when the individual worked more than 16 hours straight, excluding shift turnover time, on one occasion on December 31, 1991, through January 1, 1992. The same individual also worked more than 72 hours in a 7-day period, excluding shift turnover time, between December 25,1991 and ' January 13, 1992. This is a violation of HRC requirements _ (Violation 50-528/93-40-06). The licensee concluded that the cause of the violation was a misunderstanding of the proper accounting of work hours not directly ! associated with safety-related work. In addition, the licensee concluded that a procedure was ambiguous regarding the amount of time that should be allocated for shift turnover. As corrective actions, the individual i and his supervisor reviewed the relevant guidance and procedure and were counseled on Palo Verde overtime limitations. Procedure 02AC-0EM01, " Overtime Limitations," was also revised to more clearly and comprehensively provide guidelines for the amount of time devoted to shift turnover, and guidance was given regarding time sheet recording. i The inspector reviewed licensee documentation of oversight activities related to overtime limitations: , Quality Audit 91-012, " Maintenance and Inspection," resulted in
Corrective Action Report 91-0027 being written due to the identification of 19 personnel who had worked more than 72 hours in a 7-day period. 16
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reviewed a sample of 30 out of 267 operations personnel for the month of May 1991, did not identify any TS non-compliance. Quality Audit 91-018, " Corrective Actions," reviewed eight Condition
Report / Disposition Requests (CRDRs) documenting possible violations of overtime limitations. Seven of the eight possible violations were substantiated by the audit team. One of the CRDRs repeated the deficiency identified in an NRC Notice of Violation on this topic, regarding routine assignment of radiation protection personnel to excessive work hours (see NRC Inspection Report 50-530/91-04, Paragraph 12). Quality Deficiency Report (QDR) 92-0097, resulting from deficiencies
identified during Quality Assurance Audit 92-004 (Refueling Operations) performed in early 1992, documents deficiencies in seven Overtime Limitation Exception Reports issued during the two months prior to April 15, 1992. None of the exceptions were pre-approved as required, and two were inadequately justified. Corrective action consisted of minor procedural changes and retraining of managers authorized to approved exceptions. Quality Monitoring Reports 92-1801, 92-1804, and 92-1886, in which
the licensee reviewed compliance with the overtime limitations policy for the Operations Departments in Units 1, 2, and 3, respectively, for the month of September 1992, indicated that the licensee evaluated compliance for each individual whose name appeared on the licensee's Time / Activity Reporting System Excess Hours Report. The licensee concluded that all individuals were in compliance in Units 1 and 2, but that seven individuals in Unit 3 I exceeded the limits without proper authorization. Four of these individuals had been authorized with inadequate justifications, and three worked the excess hours without authorization. All seven individuals were assigned to Work Control. The licensee initiated Condition Report / Disposition Request (CRDR) 3-2-0465 to document the oversights. The inspector noted compliance with overtime limitations was incorporated in the scoping document for inclusion in the biennial Plant Operations audits. The inspector concluded that the licensee's Quality Assurance program encompassed compliance with overtime limitations, but that ' frequent discrepancies of minimal safety significance were identified. ' However, the continued nature of the problem throughout 1991 and 1992 indicates that additional management attention is warranted to resolve this problem. This issue would have been considered a non-cited violation had your corrective actions precluded repetition of the i overtime violations. t l One violation of NRC requirements was identified. ! 17 l l
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. . . ; ..- s.:. i. . ...; .: .:. . - . . . .. . , _ 15. Followup on Previously Identified items - Units 1. 2. and 3 (92701 and 92702) a. Closed) Unresolved item 50-528/93-04-04. Auxiliary Feedwater (AFW) Valve AFB-HV-30 Evaluation - Units 1. 2. and 3 (92701) This item involved the failure of AFB-HV-30 (AFW pump "B" discharge isolation valve to Steam Generator 31) to open during the February 4,1993, reactor trip in Unit 3. During the event, the valve circuit breaker tripped after the valve opened to less than 5% + in response to an AFW actuation signal. Initial troubleshooting , i identified a problem with the breaker magnetic relay trip setpoints being set too low, based on the breaker nameplate locked rotor ' current value. However, the licensee determined that the low trip setpoint would not have caused the breaker to trip because the valve had already started open and peak in-rush currents would not have been present. No other problems were noted with the breaker or the motor-operated valve (MOV) motor. Both these components were replaced and the valve was satisfactory stroked and diagnostic tested weekly for ten weeks after the event to gain confidence that there were no other problems. ' The inspector reviewed the. final root cause of failure report. After the MOV motor was replaced it was analyzed using a surge , tester. This test indicated that there was either a turn-to-turn or coil-to-coil fault in the "C" phase of the motor that was cauting current leakage to the motor casing. The licensee sent the motor to an independent lab who confirmed the existence of the fault. The licensee concluded that an intermittent fault internal to the motor together with the lower than required breaker trip setpoints was the cause of the failure. The inspector also reviewed Condition Report / Disposition Request (CRDR) 9-3-0129 to determine the extent of the problem with i incorrectly set breaker trip setpoints. The evaluation determined that the cause of the incorrect relay setpoints was personnel error in failing to control the relay setting sheets (RSS) per 73AC-0DC01, " Relay Setting Sheet Control." Specifically, the RRS for the circuit breaker to AFB-HV-30 was revised for the new motor but not filed, which resulted in a lack of configuration control for the setpoint. The inspector concluded that there was a high probability that AFB- HV-30 would perform its intended safety function since both the breaker and motor were replaced and the root cause of the failure was determined to be an intermittent problem with the old motor. However, the failure to follow procedure 73AC-0DC01 is a violation of NRC requirements. The failure to follow plant procedures is not being cited because the criteria specified in Section VII.B of the enforcement policy were satisfied (NCV 50-530/93-40-07). Although this error 18
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f, . , contributed to the failure of AFB-HV-30 to open, the licensee conducted an extensive root cause of failure analysis which identified the problem with the incorrect relay setpoints. The relay setpoints were changed and improvements were made in the control of the RSS to prevent improper relay setpoints in the field. Specifically, procedure 73AC-0DC01 and the nuclear engineering department procedure were combined into a new procedure 81AC-0EE01, " Relay Setting Sheets." In the new procedure the RSS are controlled as design output documents. This item is closed. One non-cited violation of NRC requirements was identified, b. (Ocen) Deviation 50-528/93-26-02. Designation of Enaineer-in-Charge - Units 1. 2. and 3 (92702) This violation occurred when the licensee designated managers in its design organization as Engineer-in-Charge, even though they were not in a functional position to be cognizant of complex problems emerging from plant operations. Therefore, the oversight intended l by ANSI /ANS 3.1-1978, regarding determining when consultants are needed to support licensee engineering capabilities to resolve any such issues, was not provided. The licensee attributed the deviation to differing opinions regarding the meaning of " complex problems," resulting in the - conclusion that any such problems would be design-related, which would be addressed by the design crganization. The licensee's corrective action was to designate the Assistant Vice President of Engineering and Projects as Engineer-in-Charge, after first , completing a 10 CFR Part 50.59 evaluation of a change to its commitment to ANSI /ANS-3.1 so that this individual would meet the qualification requirements. The changed commitment allows personnel with any baccalaureate degree and either 10 years of nuclear power experience or a current or previous NRC senior operator license to fill the Engineer-in-Charge position. However, the licensee's Quality Assurance plan also commits to ANSI /ANS 3.1-1978, and the plan requires NRC approval prior to revision. The licensee had not , submitted a revision to the Quality Assurance plan as of the end of' this inspection period, and has not yet changed its commitment in the Updated Final Safety Analysis Report. The inspector also noted that licensee administrative procedure 01AC-0EM06, " Experience and Education Verification," Revision 00.01, j includes a matrix educational and experience requirement for positions described in ANSI /ANS-3.1, Technical Specifications, and the Updated Final Safety Analysis Report (UFSAR). The matrix shows no educational requirements for the Engineer-in-Charge position, , which conflicts with ANSI /ANS-3.1. The matrix also indicates that ' educational requirements for independent review personnel may be substituted, and does not' indicate the educational requirements specified in ANSI /ANS-3.1 (1978). The inspector concluded that this 19
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OlAC-0EM06 was inaccurate. This item will remain open pending resolution of the deviation. j
c. (Closed) Unresolved Item 50-529/93-35-01. Auxiliary Feedwater Valve Testino - Unit 2 (627031 This item involved the differential pressure testing of the auxiliary feedwater supply isolation valve to Steam Generator 22 (AF-UV-35). The inspector reviewed the completed work package (Work Order 605526). The inspector noted that the work order did not have steps directing reinsta11ation of the torque switch. The omission . of the steps led the worker to replace the torque switch without . i using the applicable procedure, 32MT-9ZZ46, " Disassembly / Assembly of , Limitorque Type SMB/SB-0 thru SMB/SB-4 Actuators," for this work l activity. .The inspector concluded that the failure to have adequate work instructions to replace the torque switch in Revisions 6F and 7G of the work order was a violation of 10 CFR Part 50, Appendix B, Criterion V (Violation 50-529/93 .40-08). This was another example _ of work orders not providing the necessary(instructions for proper performance of the maintenance activities see NRC Inspection 50-528/93-35, Paragraphs 14 and 15, and 50-528/93-12,
Reports " Paragraph 6); however, in this instance the worker did not identify the deficiencies and continued the work. l The inspector evaluated the work instructions related' to tightening the open torque switch screw. Work Order 605526, Revision 7G, Step G12, states " Perform an 'as left' MOVATS ' static' test using 32MT-9ZZ56 as applicable." Procedure 32MT-9ZZ56, " Motor Operator Testing Using M0 VATS Series 3000/3386 Systems,"' states in the "As Left Thrust Verification and Spring Pack Calibration" section, Step 4.13.7, " Adjust open TSS [ torque switch set screw] as necessary to achieve acceptable thrust / torque values IAW [in accordance with] Appendix Q." Appendix Q, Section 2.0, " Adjusting Limitorque Torque Switches using M0 VATS," states, in part, to tighten the adjusting i screw using good mechanical judgement once the-torque switch set- screw is adjusted. The technician failed to follow the Appendix Q instructions for adjusting the torque switch setting prior to l stroking the valve open, which was a violation of Technical ! Specification 6.8.1. This failure resulted in the torque switch being damaged during testing. The torque switch was replaced. This violation is not being cited because the criteria specified in ' Section VII.B of the Enforcement Policy were satisfied (NCY 50-529/93-40-09). This problem was promptly brought to management's attention by the worker and had low safety significance due to the self revealing nature of the problem during retest. The technician . . 20 . T FM - M *- en v.,. g .
i r 1 . :t.... g 3 :p.w . .; k;;:: ) .:;...l.k,.w::.-(:#dh:::c:i.q.{.;;.:.h,..v: . . , . . . . . . . .. . procedure, which is used by supervisors as the basis for criteria
for experience and educational requirements, was inaccurate. ' The inspector concluded that the licensee's corrective actions were incomplete and that the deviation still existed, and that procedure i 01AC-0EM06 was inaccurate. This item will remain open pending l resolution of the deviation. l l c. (Closed) Unresolved Item 50-529/93-35-01. Auxiliary Feedwater Valve i Testino - Unit 2 (62703)_ i This item involved the differential pressure testing of the ,~ auxiliary feedwater supply isolation valve to Steam Generator 22 (AF-UV-35). The inspector reviewed the completed work package (Work i Order 605526). The inspector noted that the work order did not have steps directing reinsta11ation of the torque switch. The omission of the steps led the worker to replace the torque switch without using the applicable procedure, 32MT-9ZZ46, " Disassembly / Assembly of
l Limitorque Type SMB/SB-0 thru SMB/SB-4 Actuators," for this work l activity. The inspector concluded that the failure to have edequate i j l work instructions to replace the torque switch in Revisions 6F and 7G of the work order was a violation of 10 CFR Part 50, Appendix B, l ' ) l Criterion V (Violation 50-529/93 40-08). This was another example of work orders not providing the necessary(instructions for proper performance of the maintenance-activities see NRC Inspection l ' 50-528/93-35, Paragraphs 14 and 15, and 50-528/93-12,
Reports Paragraph 6); however, in this instance the worker did not identify the deficiencies and continued the work. , The inspector evaluated the work instructions related to tightening , the open torque switch screw. Work Order 605526, Revision 7G, Step G12, states " Perform an 'as left' MOVATS ' static' test using 32MT-9ZZ56 as applicable." Procedure 32MT-9ZZ56, " Motor Operator Testing Using MOVATS Series 3000/3386 Systems," states in the "As 1 Left Thrust Verification and Spring Pack Calibration" section. Step 4.13.7, " Adjust open TSS [ torque switch set screw] as necessary to achieve acceptable thrust / torque values IAW [in accordance with] Appendix Q." Appendix Q, Section 2.0, " Adjusting Limitorque Torque Switches using M0 VATS," states, in part, to tighten the adjusting screw using good mechanical judgement once the torque switch set screw is adjusted. The technician failed to follow the Appendix Q instructions for adjusting the torque switch setting prior to i stroking the valve open, which was a violation of Technical Specification 6.8.1. This failure resulted in the torque switch ' being damaged during testing. The torque switch was replaced. This violation is not being cited because the criteria specified in Section VII.B of the Enforcement Policy were satisfied (NCV 50-529/93-40-09). This problem was promptly brought to management's attention by the worker and had low safety significance due to the self revealing nature of the problem during retest. The technician 20
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i d. (Closed) Violation 50-530/92-19-01. Control of Work on Enercized Electrical Eauipment - Unit 3 (92702) e This violation occurred when licensee personnel failed to take ' i appropriate precautions and lost control of a lifted lead, resulting
in the loss of. control room annunciators. The licensee determined that the electrician had relied on a capture ' screwdriver to control the lead, and that this was inadequate. Additional precautions, such as use of electrically insulated blankets, were not used because the electrician underestimated the risk associated with the task. - The licensee revised procedure 30DP-9MP01, " Conduct of Maintenance,"
to specifically require that lifted leads be positively controlled- ! I to prevent accidental damage or accidental removal of equipment from ' service. More specific. guidance was issues in Maintenance l Department Guideline (MDG) 24. " Policy and Checklists for Working on Energized Equipment," and MDG 25, " Risk Assessment of Work on Energized Equipment." These MDGs were reviewed in NRC Inspection Reports 50-528/93-12, Paragraph 4, and 50-528/93-35, Paragraph 16.e. . i The licensee noted continued problems with control of lifted leads. l i These problems are discussed in NRC Inspection Report 50-528/93-12, Paragraph 14.c.(1). A inspection followup item was opened in that report to address the licensee's future actions.- Based on the above review, the inspector concluded that the J licensee's corrective actions were appropriate and that licensee management attention was being directed toward resolution of the continued problems. This item is closed, q i One violation and two non-cited violations of NRC requirements' were l identified. l 16. Review of ticensee Event Reports (LER) - Unit 2 (92712) The following LER was closed based on in-office review. Unit 2 93-003 Revision 0 Technical Specification 3.0.3_ Entry - No violations of NRC requirements or deviations were identified. j 17. Manacement Meetina On September 16, 1993, Messrs. Bert Simpson, Ronald Stevens,'and Craig Seaman met with Region V personnel in the regional office and presented 21 ! -- - ~ _ , _ , _ ,
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. . , ., information on the APS Reengineering Program, regulatory commitments, and the APS Quality Assurance Program. Handout material used in the APS presentation is attached to this report. i Mr. Simpson provided information about the reengineering program that was bcing implemented at Palo Verde and throughout APS. Through rcengineering, processes are being analyzed and redesigned to achieve improvements in cost, quality and efficiency. Mr. Simpson stated that the complete reegineering program may take two or more years to complete. He described the activities associated with the program and indicated that dedicated teams were utilized in the analysis and redesign of Seven processes at Palo Verde were selected for processes. l reengineering, and two processes, control of work and modifications, were currently being reengineered. Mr. Simpson described the potential benefits that may be attained with the reengineered processes and indicated that implementation may begin in the second quarter of 1994. Mr. Stevens indicated that Palo Verde was reviewing commitments made to the NRC as part of industry and NRC initiatives to reduce the burden of i He indicated that APS was working with other regulatory requirements. utilities to determine generic commitments, and a utility group (NUMARC) would work with the NRC to address those commitments. Mr. Stevens indicated that APS would hold discussions with the Office of Nuclear , ' Reactor Regulation for those commitments specific to Palo Verde. Mr. Seaman, who was recently appointed as Director, Quality Assurance, briefly discussed his observations of the organization. He indicated that APS was implementing a new program to make personnel aware of the Employee Concerns Program. At the end of the presentations, Mr. Perkins thanked the APS personnel for providing the information to the NRC. Mr. Perkins indicated that when the reengineering process at Palo Verde had progressed to reach decisions on the what the reengineered processes would be like, another presentation should be made to Region V and NRR personnel. This meeting 1 could occur perhaps in early December 1993. 18. Exit Meetina (71707) An exit meeting was held on September 22, 1993, with licensee management ' and resident inspectors during which the observations and conclusions in this report were discussed. The licensee had no additional comments to .' the inspectors' findings. The licensee did not identify as proprietary any materials provided to or reviewed by the inspectors during the inspection. 1 22 , l i
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. 4 , Over the Same Time Period the Snan of Contrds.. s r . w. . Has Narrowed Ao., A - .. s. a. - ': r .% . . ?*kk. n yp, c- . . . ;,:/.Q ' 394.' +; 79;N A y!;29tw 19fm g - - my - . . . 1.M;ey;3 yo:pervis,.or to~E. hlployee R.atio* g6- ~c- . . m; f', J Manage. r,< totEmplo,y. ;, # a .sa +. s -
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- .)? ..
s 1 Manager -
, .: a: - m. - - A. - . . up_ , , _ . - ' - w- xm , w ',-@,y .,. 1993 1993 . . y 3 YQ;,p$k ' e - .. .. . . la u . ~. .s. . ta N. !I.. s , s'- L: wp v . j. , ,n,- n - - < ~, w 1 Supervisor c.+v- . . - - u 43 ~s ,a x
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- Includes contract labor
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N .** * . .r Source: PVNGS Human Resources; PVNGS Dudgets and Costs l ... .--+-,--v , w -- _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ . , -__ -_ m. -
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_ _m _ _ ,_ r; z. .. s c .I ' LF dd NN ! ' b dild. / Ut.NN*A,' [[ [S h[p -g ; y , q.3 . . * a. . . - . . i Palo Verde is Caught in a Circle . i)R . 3 2.ne
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and Control %._,$!Qx
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. - mm'e . t*. $ [..d t 6.; p *t., i 4. Ie iji , %*'5' ' N Expensive modifications .
. S[- " ' , ' Duplicate work
&#' Prioritization and Overly Complex Process v.%
c ! scheduling issues
- yy
' ^4D, i A. sW Excessive handoffs P*
W Low-value tasks IMi
. If,e
Review steps
Long cycle times .?4-
Additionaldepartmo $[f
.a , Departmentalized
- <. 4
. ~ Information e-
- 's
- . . .
? .it . tih Workload not balanced < $. '
- hE-
at the site level r .-) p. s , ,,ff.- Delays in the field Multiple Departments
Low productivity , gji)
' Complex coordination . .i.'g
Unclear accountability T:, ' - , a .' !(N'
- 1.-
! Low productivity - P ';t..:. 7.. n. . c
!
- - . .- . - - . ~ .-- . . . - - - - - - . - - - . . - - - . . . - _ . . . - _ . , . .,
- _ _ _ _ _ _ _ .- _ . _ - _ __ _ _ _ _ __ . gp~ 'Ij ' p -r, > Trm7 ; y'y T ' ~ " " - ~ T ~ .:,3 g - ' eswmouwnene,en.
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~u ..u . . - . . . , Best Practice Plants Use a Different ApproacM..t6.. .. J8.g@ Modifications... . . . . h ${ -Modification , u e rPalo Verdei ~ P Y N lBes,t(Practice ' - - , Philosophy Limited installation resources force Limited Engineering resources forc'eQ g . .(. .} tradeoffs tradeoffs
- Team-based approach for design 5h
. . Approach
- Discipline-based approach for design
P# and implementation implementation ' $;: . Approval Process
- Plant Modification Committee (PMC)
- Plant Modification Committee (PMC)S.(r,
~ , meets every six months;if you meets overy 30 days PMC, you must wait six months
- M
- Only 38% of all modifications are
formally reviewed by the PMC Every modification must be formallyi.Sf reviewed by either the PMC or the.njifi$, .4~k ,. :j ?. PMC - ~.. Minor Changes to the
- Addressed by a complex process (600-
Addressed by a simple process (20 J Design 800 generated per outage) generated per outage) .j'y ~ l-l f Backlog
- 600 modifications have been designed
. Fewer than 50 modifications have bh' p. . . but not installed for all 3 units designed but not installed \\
- C:
...3 . . . 4A Review of Old + 266 modifications were cancelled, but Moratorium placed on new modificatiQjib Modifications more than 600 are still open during backlog review gfA : i
- 600 modifications reduced to fewer th$F
50
- . ;i
- Currently, if a minor modificatio
.. 3 installed within 1 year, it is cancelletINE source: Reengineering Team Best Practice visits, slMs, PvNGs Human Resources, Electric utility Group Database . . :;:fgg,. - . k2. , . . . - - . . . _. _ -
I gy .2 f m - my my n. - g h. ,awww.aos2 y. . ce_ecm._ um .< ma . . r, y . ...And Control of Work .$, ., . aff .:-:R '. .' a *,e ?*!R9 C< $- -
- Control lof WorkkiMQi EPalogerdepWV
- @@@p; 4@id$$ (BesQractice?,'
""g , i .ij ,, Philosophy Maintenance support groups created to Maintenance technicians are given flyl- h'. ensure that maintenance technicians necessary training, tools and .f . . , . perform the proper work responsibility to perform the proper' L'. %-- Approach Specialized discipline-based approach Cross-trained, cross-discipline tea based approach M
- As.
Work Orders Less than 10% of corrective Approximately 90% of corrective 4,h~-2. . ~ - maintenance Work Orders ar maintenance work orders are based on maintenance instructions D..tv maintenance instructions . -;j, - Procedures are written by m'aintenan. , Procedures Procedures are written by a separate maintenance support function technician or by responsible compond@at .. system eng.ineer y, . , .t . g.g_ Backlog 2,224 open Priority 3 work orders are 215 open Priority 3 work orders arepi, der older than 90 days than 90 days fe.'+$ 9, - - Cost (1992) $2,137 per work order $1,725 per work order 3., J. -.- " .- . (Total Maintenance Budget Cost /
/ Total Number of Completed Work %a.' y Orders) , . .~.} . . . . .; x . , ..( source: Reengineering Team Best Practice visits, stMs, PVNGs Human Resources, Electric utility cost Group Database ,-
.:: i - - _ . - - - . - .1-
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W : h ~ % w M :_ n G M : To Achieve This, Palo Verde Needs . Focused Set of Operating Principles... ,g . . .n.- .~ ..? ? r ~ w'rierslii[*% #
- Provide employees the training and resources
,: - lO necessary to instill ownership and accountability N;,.l '~ ^ .- - Train employees beyond a single discipline or a -l[$. specialized set of tasks - Give employees the capability to solve their own
- {,,
problems 5. ,,. - - Motivate and provide incentives for performance .,fp .~- .l.:L/. ' .gs. Weirns%O. pf Wherever possible, work groups are'self-sufficient, -lh_ - wd. n organized around clear, measurable outcomes ~ , - m r 3 .
- :
Work Groups: .S<..: - include support functions .. j.- . ,: .. - Are mobilized around what is import nt (e.g., .-i ,,:.. .T 3 - critical success indicators) - - Are held accountable to measurable targets .;,i ' s. e' - e
- ' Y. * ,N *.# .
- .- .
- - - - - . ~ .. - , - --- - . - . , . . , . . - - - . . . - . - - -
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s _w a. n u. m_ = m y - . n. ga - % e. .m ~ cs,o,_cm ,,_ , wn twwwx&su mn, neww usam w a.m.ou,w.m s% u.i u .. .. , .. g.s'. w . . ...That Will Drive a New Approach Toward All .yy, Work and Management Activities .d. w .~ i$s,.(. . - .. n 1Enip*owerrhsntO, Those who know best determine priorities,
- ?gd'
. ' ^ ~ ^ ' ' " * commitments and workload .i - .4 . - Those who are most qualified to perform the task . Qy . should write the instructions
- ._ l
- i:: . - Those closest to the work decide the appropriate , , g .' sf?s level of work .u - The role of support groups is to support, not .::i ;<. - p control ")2 .;. 'shs5iie % Resource allocations, solutions and priorities should
- , -r
iip $lbsdh@{~hy;u f;l be oriented at the site level . . ,
- . m
4. . ' ,l / ' .~ - Deploy resources flexibly based on workload and - priority 9, , - - Ensure solutions and approaches are consistent ' @,, . .Y;{ across the plants - Set priorities centrally to optimize safety, .N production and costs across the site .: .ijd - .m - . 4 :g . .- . 99e . _. _ _ _ . . - - . - - , . _ _ - . , - . - _ - . . _ . _ _ , - - _ . . . . . . , _ - . _ . - - - - - , , , . m . .
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, :m_ac w~.- ~ . ... How To Organize...... 'y' Adoption of These Principles Leads to Two Fundamental Questions: . .se- .. 49 . . . ,: = ,g,p- t N'ig.h.$ ' A
- O
I d yaiith d s: ~ ' iDese@tioni *
- 16
"U (Alternallye ' ' ' " , , ' f; ;),.. ... Cross-Discipline Teams Organize multiple disciplines + Overcome departmental .: . into teams (e.g., site fragmentation and handoffs ,- ' ' engineering, instrument and , . :. , control technicians, mechanics, * Builds ownership and .s@ ..'lM. and radiation protection) accountability
.. .n
.
- . + ,, .
I w.:. . ff.f[ ' ' Disciplines Organize around disciplines Allows flexible allocation of c-l 2. ,- , (e.g., instrument and control or resources .1 c$. ' }l.5.f,f mechanical) ff- .
- Increases discipline expertise
,. gge ,
- Low-risk, traditional
9*- management structure and ',$' k:l. career progression j {, ' .e . ,. , '.~e ' ' . ?.$$ - .. . I;. 4 . :. ; n ,. . W: - - . ., . - - - - - - - -
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- !
Develop consistent site wide critical systems (safety and + production) approach Qi: Create clear ownership and , :;.y,g - ' ' ' ' accountability around critical .. systems i, Effective allocation of . . - -
. resources across units -; . ~.' #1T ~ .<$ " - Pride in the unit . j!$ Unit Approach Teams organized around each - - Unit control over critical 3~. unit
.9% resources .q .. . . 6 4 Develop consistent site-wide ,, ,Q.i ' Centralized Approach Teams organized around site
approach .gg, Allocates resources most ..M .-
effectively across the site df# . ??)
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In the Control of Work Process, Working in Cross-} 4 Functional Teams and Using Pre-Approved Work.$ Orders Will Minimize Delays... sEl . .ii,.,p hfl ' 66 $$ <"W dffdPY # UslrfgKsainsk 1%g.l~VWQ &%$QR5p,id;Wo,rk,Q'rdefRroce_ss . ' . /j{- ^' , . . . . Support b '"'** ) ' ' Shops -YiM*. . . ' - Field Technician 2.# informs the 5 '*py , ) I Team . ?..%..$e. ,- a. RP N" ' r = .- . . /[ Jh , Shops Reps . r. A, H. _ /
_' . EC16f! ' R'P*5 ' E -wl f h h. .m
nirraw r
- - ,:
z ggy n -n - Engineering < ?"fyi$ & ., -;M. 5Y XMsapad -& . 3 . Central 75% of Field Technician Field Technic
Corrective. finds unplanned prints new- ( , ' Scheduler Maintenance problem while maintenanc Scheduling is centralized across the site
Work Orders are doing other work instructions, '{ The team is held accountable for their set of work orders and pre-approved fixes the *, !
Team members are cross-trained to handle the " simple' work of review - equipment :N,, measured for their performance and require no s- j
other disciplines and support groups ( l.e., QC and RP) -' . ' - Work order tumaround is done in minutes,
- ,'
' .s. .' . The team will overcome the separation of frontline and support
I'~ a ham functions .. -
- -
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ygc "QQ ..c g ' <> , '#Nf
~ ' ~ Wg g h *, M ' ""~ est0100 DLANRChes BW Pwn h ,p j$ ' y.y , , k b ' e Md VNm , b.Nb $hDhb HMb 4, 5 ~
- * * *
,; , , _* " ...And Will Improve Work Quality
- .
.+ d '.?.S ..;yr. . .;,.W ' Setting WorkLLsveist - - Writing Mainteriance Iristrdctloris
- (Plann_ing: Work Packag65YJ
4 '
- t.$
~ . f . . th5y , p- ,. f h /~ .f',g- I 4 w 9 -- 4 . . .- . PM experts assist craftsman to optimize Craftsmen are trained and assigned 75% of Corrective Maintenance Ord ,j-
PM levels for components and systems responsibility for maintenance instructions are pre-approved and include a list ofg,g ,' Qualified Field Technicians rota necessary parts ~ Maintenance instructions encompass PMs, Trained craftsmen help set the PM basis
,,,,
.!y and hours required for the PM task cms and MTs
Maintenance instructions are linked to between planning and field work
- 4af *
.
equipment tags and BOMs
- i,h.'
'4^) th the help of an expert, I help set the PM basis for my equipment at the right frequency." ~ , . *,
- ! have pre-approved maintenance instructions for most of my work. No more waiting. I just
. 1,%. a print the package and start working. If I find a problem with the instructions, I call the J.' ,,, craftsman assigned and I get a response immediately." 'g; , "If a BOM has a problem, I work with an system expert to get it fixed immediately." '4 + . "I spent 12 months writing complex maintenance instructions in a rotational assignment. By -[4 - ' , ciding what task needs to be done, I leamed more about my equipment and the systems." .I; dit ?y n .. . -
1 j a ..: .. + vs f.'. - - - - - . - .
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$ ' a r-- 3' m . u i: s a w a+ 1 a - n s u m m L J Aa m w., m u e _ m b .. A w ;. M.. . i f. - The Next Steps Are To Start Redesigning the 5'If ' 1L Modifications and Control of Work Processes.P. - .a . . 1% ~ ?h:
- hid.-
i4 ~ . . h-+ } Activity .. fft ,)Ql/ ww i. .anmv m a. > ;. : v --t , z > , w , g n , : , : ~, s . rts . m ganize Phase 11.4;. > M Probe:ss;V,%m> > - pg/f;Blu,eprinting 10 V W > <g% Release Pla,nning : aOr Modeling . - yg ygiy q ;c ~', y. ,y. gynggy
- & ~ - nwyngg
' . .
- 'f
Determine Use brainstorm + Evaluate theimpact Organize and train + +
team members techniques to create of new processes on: requirements for . .
detail process flows - Organizations / piloting ,r , ' Communicate Phase i Jobs .. -
Lay out high-level "Ni Estimate time - Management results to PV and APS + + ,, ,,h.A(
Employees intervals systems pilot and . - Culture / Values implementation plan r ... . /., Document integration Help organize early
- g;g
+ . Determine schedule Evaluate ifr start initiatives and dependency + + .t ;p8 issues requirements of results
,, . v. o .
- V C'
Estimate cost and 4g,: . . Produce a layout of a
processes benefits of proposed . -yE . - Flows changes % 7- - Decision points - ,w ig% til . "N . ~6 . <**h* ., . . . . , ,- .
- ),
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,_ . . CS10100-DLA-NnCF'res493 ihm -r ..a , r -. ._.m_, . ...c... < m mm - ...Which Will Be Completed in November... @k.. . .. S > T .h? ' .'.?u.V.o. . .: f <a?. s , iSeptember? ' - si - tN . ' Octoberi ~ , -r ...a , . . . ,'s , 7 > November . Q m.. , m, g ..- ~ W r '* " ' . ,. .. 7,g - - . . . a .. . , . - . , t. s . , %'. ' .. 30-3 0-10 13-17 20-24 27-1 4-0 11-15 18-22 25-29 1-5 0-12 15-19 22-20 *i-*% ,' W.
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Organize Phas$ 11 A- - - p; p
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i Estimate Cost and Benefits : ' c. .- . ..o - .. . ~ $. .-N- s '5 l<?, . ' Develop Release 3 .-g'- . ' Ii'. [ Pilot Plans?7. . "'
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. <- . . A A A A A A A .R 1st 9th 23rd 5th 21st 4th 18th '4 ' !:..?M ~ [-[. ' d Palo Verde Advisory Group Meeting , . wh 1 . APS Senior Management Meeting ' '.P:4' . . t ,,
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4 s , ,A ._ m, 11. u ,7 , t m, . . n , bu ,NEW .OAW eda ;_EnRifdd/,- I,41$y-diedad2%Q w+.d%A* h ' s to;#& iQ Ndi '. > ., . os , .. .n ...Anci To Kick-off Early Start Initiatives and ~*&*.: Preh. .minary Wave II w f.5iC 2,r - .u . ..,pg' June September December March June September December 1993 1993 1993 1994 1994 1994 1994 4.8, a i l l l l l j.[**: . . . . . { 7 . Mn n E 'r yw. . M' I~. = . tivo l fy ' 'N . M' c WaveI Case for Action / O.M 4r A - - - i Redesign Develop < gg- vision A,#. Wgsg gBuild Majory:p gimptomentC anges\\ 4-:,9,- t h, w Ptol(s)gN*%!mplemeniattonme e *W. ' :/ Y -- :- MPotentiaEK
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pPlan m . Management - 1,. Z+1% f(W5($s'[I[il[lil)$ l Wavd's? '$ i ' j 'l p'
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Wave III case sor net on/ 'g;v er a w ><.: Impl(( y g,. A-b_ Redesign Develop , Vision ., g gj. 3 , Chang'iq ~ - u,p l9 sPotentJaljg ;dPilo!(s)g , 4. f ' . '
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} , 4, . 7* Wave II Will include Oversight, Corrective Actih. , . Programs and Commitments 'Js - - lD.:. $ f5IIssibiif ] Q X
- Develop processes / programs that make Palo Verde an industry
f.- leader in addressing regulatory commitments, corrective actions . tq" - t programs, and independent oversight.
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- Develop a coordinated, consistent approach to regulators
':h - Review of outstanding, external commitments W dl@,[ - Review of internal commitments . (* 1 - '- . - Develop a process for making future commitments- .'.g,i' , , ~I[h..
- Develop a coordinated approach, with feedback loops for our
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corrective action program ""Jh.( %' - Analyze and simplify the process ... w.m . - Eliminate duplication and unnecessary work activities (g!.- - Review resource deployment to ensure appropriate resources are '.'i,$I- . applied to problems investigation and resolution based on the ,.:( - - safety significance and history of the issue . ,.j, ... - .: .- - ..
- Develop a coordinated approach to independent oversight
,7f.- . - Review industry best practices (including utilities, NRC and other 416.' industries) 'g. . . - Eliminate duplication ,4ge OM M: -. -- . .
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...Which Will Provide Several Benefits - @g . .. . . - hy, :
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Establish priorities correctly 3p ne . ':r ',19;. . Build a formal feedback loop
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a ,, , , . vr Preliminary Schedule . $.. ' . . m yf. ,p . g, . . . . v . . ' f.M. - dN, ovember - ,- ~ i.:j .;g],.%. D.ec. ember - , - . ~ , ; October : ' o 4 e 9,,. , . .. .: . / J* . ..e 4-B 11-15 10-22 25-29 1-5 0-12 15-19 22-20 29-3 6-10 13-17 20-24 27-31.' . ..'-h.* * - - ^ *Q, W" . . . vat, . .'!8* - Osyanlie Tearn* : .<r . i,:h. ~7
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D. Smyers (30%) TR ' - /if:ph - K. Dougherty C. Winters
C. Churchman (20%) +
J. Fogarty (30%) I.- D. Henry M. Karbassian (50%)
B. Junas (50%) .h " - .o.: - . Overs,ight/g .g,, .g- WWN,pgu %n .. . . . . - . -- . c . ,n_ - yy . wp-.a.. _ ,u g.w, yp ~ . - xe . , . . Correctiv%e%
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['[. ..J,' ' - 1 Reg. Affairs M. Karbassian (50%) - 2 Maintenance Techs. = - 1 STS - 2 Design Eng. - 2 Planners
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