IR 05000528/1999011
| ML17300B366 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 10/02/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17300B365 | List: |
| References | |
| 50-528-99-11, 50-529-99-11, 50-530-99-11, NUDOCS 9910120257 | |
| Download: ML17300B366 (95) | |
Text
0 ENCLOSURE U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos.:
License Nos.:
Report No.:
Licensee:
Facility:
Location:.
Dates:
Team Leader:
Inspectors:
50-528; 50-529; 50-530 NPF-41; NPF-51; NPF-74 50-528/99-11; 50-529/99-11; 530/99-11 Arizona Public Service Company Palo Verde Nuclear Generating Station, Units 1, 2, and 3 5951 S. Wintersburg Road Tonopah, Arizona June 14 through July 2, 1999.
Inoffice inspection continued until September 1, 1999, and supplemental onsite inspection occurred August 30 through September 2, 1999.
R. L. Nease, Senior Reactor Inspector Engineering and Maintenance Branch L. E. Ellershaw, Senior Reactor Inspector Engineering and Maintenance Branch P. A. Goldberg, Reactor Inspector Engineering and Maintenance Branch W. M. McNeill, Reactor Inspector Engineering and Maintenance Branch Accompanied By:
R. G. Quirk, Consultant, Beckman & Associates, Inc.
M. Shlyamberg, Consultant, NuEnergy, Inc.
Approved By:
Dr. Dale A. Powers, Chief Engineering and Maintenance Branch Division of Reactor Safety ATTACHMENT: Supplemental Information 99iQi20257 99i002 PDR ADQCK 05000528
-2-EXECUTIVE SUMMARY Palo Verde Nuclear Generating Station, Units 1, 2, and 3 NRC Inspection Report No. 50-528/99-11; 50-529/99-11; 50-530/99-11 This report documents the performance of a core safety system engineering inspection that was performed by four region-based inspectors and two consultants during two weeks onsite.
A supplemental onsite inspection was performed by one region-based inspector while on an unrelated inspection.
Inoffice review and inspection were performed by all inspection personnel during the week between the two onsite weeks.
Additional inoffice review and inspection were performed by certain inspection personnel following the onsite inspection period. This inspection was conducted to assess the effectiveness of the licensee's engineering program.
This report also documents the review and closure of violations, licensee event reports, and inspection followup items.
~En ineerin The team identified the following four examples of a violation of 10 CFR Part 50, Appendix B, Criterion III, each of which is described below. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as Condition Report/Disposition Requests 9-9-1012, 9-9-0763, 9-9-0771, 9-9-0778, and 9-9-0800.
None of these examples presented an operability concern.
On three occasions, licensee engineers failed to verify and check the adequacy of a design basis change, in that, (1) they revised the maximum refueling water tank temperature in Calculation 13-MC-SI-018, but failed to revise Calculation 13-MC-SI-220, which used the maximum refueling water tank temperature as an input; (2) they revised Calculation 13-MC-SI-018, which superseded portions of Calculation 13-MC-SI-309, but failed to revise Calculation 13-MC-SI-309 to identify the superseded sections; and (3) they revised Calculation 13-MC-SI-018, which established a new minimum containment sump level, but did not revise Calculation 13-MC-Sl-804 to reflect that a new minimum containment sump level was established in Calculation 13-MC-Sl-018 (Section E1.1).
2.'icensee engineers failed to verify and check the adequacy of Calculation 13-JC-SI-218, in that, the calculation referenced a nonconservative tolerance, and did not consider the specific-gravity for unborated water in the containment spray header.
In addition, the licensee failed to verify and check the adequacy of Calculation 13-JC-SI-215, in that, licensee engineers changed the flowrate in one section of Calculation 12-JC-SI-215, but failed to revise all affected sections of the calculation (Section E1.2).
3.
Licensee engineers failed to translate the corrected indicated containment spray flowrate from Calculation 12-JC-Sl-215 into Emergency Procedure 40EP-9EO03 (Section E1.2).
tr
-3-Licensee engineers prepared Modification Package PCWO 00771121, which installed Breaker 3EPKBD2218 and its associated circuit in Unit 3. The modification was canceled, the installed breaker and circuit was abandoned in place, and the breaker was labeled as spare and placed in the "off"position.
Most of the affected documents and data bases, which had already been revised to reflect the installed circuit and breaker in use, were not revised to reflect the canceled modification. Licensee engineers (1) failed to verify that Calculation 03-EC-PK-207 adequately reflected installed equipment, and (2) failed to accurately translate design change information from canceled Modification Package PCWO 00771121 (which installed Breaker 3EPKBD2218)
into design basis Calculation 03-E-HFB-004, Vendor Drawing E022-24-18, and the plant data management system to show the actual installed configuration (Section E1.4.2).
~
The environmental qualification for the containment sump wide range level transmitter Probes J-SIA-LE-0706A and J-SIA-LE-0707A (post-accident monitoring equipment) did not meet the requirements of 10 CFR 50.49 for post-accident monitoring, as described in Regulatory Guide 1.97 for long-term post-accident surveillance of containment sump water level, and committed to in the Updated Final Safety Analysis Report; The team identified this as a noncited violation of 10 CFR 50.49. This violation is in the licensee's corrective action program as Condition Report/Disposition Request 9-9-0730.
Subsequent to the team's identification, licensee engineers performed an operability determination and concluded that the level transmitter probes were qualified for long-term submergence (Section E1.2).
The team identified the following two examples of a noncited violation of 10 CFR 50.71(e) for failure to ensure that the Updated Final Safety Analysis Report was updated to reflect the latest information available.
This violation is in the licensee's corrective action program as Condition Report/Disposition Requests 9-9-0693, 9-9-1055, and 9-9-0956.
None of these examples presented an operability concern.
Licensee engineers failed to update the Updated Final Safety Analysis Report to reflect (1) the calibrated range of the refueling water tank level instrument as referenced in Calculation 13-JC-CH-209; (2) the appropriate "LO" refueling water tank level setpoints determined by Calculation 13-JC-CH-206; and (3) the appropriate "LO-LO"refueling water tank level setpoints determined by Calculation 13-MC-CH-201 (Section E1.2).
2.
Licensee engineers failed to revise the Updated Final Safety Analysis Report to reflect the actual installed configuration of the battery room exhaust ducts.
(Section E1.4.2).
The team identified the following three examples of a noncited violation of 10 CFR Part 50, Appendix B, Criterion V, for an inadequate procedure and failure to follow procedures.
This violation is in the licensee's corrective action program as Condition Report/Disposition Requests 9-9-0765, and 9-9-0699.
None of these
's l
examples presented an operability concern.
On three occasions in June 1999, licensee personnel used Operability Determination 183 as justification for not entering technical specification action statements while calibrating hot-leg high pressure safety injection flow transmitters.
The team found that Preventive Maintenance Task 038406 (used to calibrate these flowtransmitters) was inappropriate to the circumstances.
It did not satisfy the conditions in Operability Determination 183, to require technicians in attendance at the transmitter during calibration (Section E2.2.1).
Licensee operations personnel failed to make the proper entries in the unit logs, as required by Procedure 40DP-9OP26, when they used canceled operability determinations.
Specifically, on three occasions in June 1999, operations personnel used canceled Operability Determination 183'to justify calibrating high pressure safety injection flowtransmitters on line without entering technical specification action statement (Section E2.2.1).
Licensee personnel failed on 10 occasions to conduct and document justification reviews to determine whether safety-related temporary modifications were still necessary or if permanent plant design changes would be initiated.
In addition, licensee personnel failed on 11 occasions to distribute the justification review forms, as required by Procedure 81DP-ODC17 (Section E2.5).
-5-Re ort Details Summa of Plant Status Allthree units operated at 100 percent power during this inspection.
ill. En ineerin E1 Conduct of Engineering (93809)
Containment S ra S stem Descri tion The containment spray system consists of two trains each capable of discharging cool, borated water through spray nozzles to the upper regions of the containment to reduce containment pressure and temperature during either a toss-of-coolant accident or a large steam or feed line break inside containment.
The spray flow is provided by two containment spray pumps (one pump per train), which take suction from the refueling water tank during the injection mode and from the containment sump during the recirculation mode.
When low refueling water tank level is reached (approximately 7.4 percent), a recirculation actuation signal is generated, and the suction for the containment spray pumps is automatically transferred from the refueling water tank to the containment sump.
Operators are to manually isolate the refueling water tank after suction switch-over occurs.
The containment spray pumps provide containment spray flow through the shutdown heat exchangers to a dual set of spray nozzles located in the containment dome, just below the 140-foot elevation. The pumps start automatically on either a safety injection actuation signal or a containment spray actuation signal (i.e., high-high containment pressure).
Spray is delivered when the containment spray motor-operated flow control valves open, which only occurs on a containment spray actuation signal.
The containment spray pumps require 125Vdc Class 1E power for breaker control, and 4160Vac Class 1E power to run. The containment spray motor-operated flow control valves require 480Vac Class 1E power to operate.
Train A of the containment spray system is powered from Train A Class 1E power, and Train B of the containment spray system is powered from Train B Class 1E power.
In the event of a loss-of-ac power, the containment spray pumps are powered from the diesel generators.
Once the diesel generators reached proper speed and voltage, the pumps are loaded by the engineered safety features load sequencer.
E1.1, Containment S ra Desi n Review - Mechanical a.
Ins ection Sco e
The team reviewed mechanical calculations, drawings, procedures, test results, licensing and design bases information, other related documentation, and the as-installed plant condition to ascertain the consistency and accuracy of design information pertaining to the containment spray system and related support system Observations and Findin s In general, the team found that the design basis documents and information were consistent; however, the team identified a number of design control and configuration discrepancies involving design calculations, as discussed below. Unless stated, these items were not previously identified by the licensee.
Calculation 13-MC-SI-018 "Containment S ra S stem Interface Re uirements Calculation " Revision 3 The team reviewed Calculation 13-MC-SI-018, and found that licensee engineers failed to revise the following design basis calculations to reflect changes in Calculation 13-MC-SE-018.
Calculation 13-MC-SI-220, "CS Pump Full Flow Test Criteria Process Limit,"
Revision 00 - This calculation used, as input, a maximum refueling water tank temperature of 100'F from Calculation 13-MC-Sl-018; however, the maximum refueling water tank temperature in Calculation 13-MC-SI-018, Revision 5, was 120'F.
Furthermore, the technical specification limitfor the maximum refueling water tank temperature was also 120'F. The team found that licensee engineers failed to revise Calculation 13-MC-Sl-220 to reflect the revised input maximum refueling water tank temperature in Calculation 13-MC-SI-018. This issue was entered into the licensee's corrective action program as Condition ReporV Disposition Request (CRDR) 9-9-1012. The team determined that the error in Calculation 13-MC-Sl-220 did not have any analytical impact on the result of this calculation.
Calculation 13-MC-SI-309, "Emergency Sump Screen Blockage," Revision 2-In revising Calculation 13-MC-Sl-018 to establish a new value for the pressure loss across the sump screen, the licensee found that portions of Calculation 13-MC-SI-309 were superseded by Calculation 13-MC-SI-018.
Calculation 13-MC-Sl-309 was retained as a design basis calculation; however, the team found that the licensee failed to verify and check the adequacy of a change in the design basis, in that, licensee engineers revised Calculation 13-MC-SI-018, which superseded portions of Calculation 13-MC-SI-309, but did not revise Calculation 13-MC-Sl-309 to identify the superseded sections.
The team did not find any instances where the superseded portions of Calculation 13-MC-SI-309 were used as input to other calculations.
This issue was entered into the licensee's corrective action program as CRDR 9-9-1012.
Calculation 13-MC-SI-804, "Containment Building Water Level During LOCA,"
Revision 1: This calculation established minimum and maximum containment (sump) levels based on large break loss-of-coolant accident analysis.
The minimum sump level was used to ensure net-positive suction head for emergency core cooling pumps.
During the revision of Calculation 13-MC-SI-018, licensee engineers determined that the large break loss-of-coolant accident does not result in the minimum containment sump level. The new minimum containment sump
e-7-levels, based on accidents other than a large break loss-of-coolant accidents, were established by Calculation 13-MC-Sl-018. However, licensee engineers did not revise Calculation 13-MC-Sl-804 to reflect that the minimum level established, therein, was applicable only to large break loss-of-coolant accidents, or to reference Calculation 13-MC-SI-018 for minimum containment sump levels for accidents other than large break.
Criterion III of Appendix B to 10 CFR Part 50 requires, in part, that design control measures provide for verifying or checking the adequacy of design.
Criterion III further states that design changes shall be subject to design control measures commensurate with those applied to the original design.
The team found that on three occasions the licensee failed to verify the adequacy of a design basis change, in that, (1) licensee engineers revised the maximum refueling water tank temperature in Calculation 13-MC-SI-018, but failed to revise Calculation 13-MC-SI-220, which used the maximum refueling water tank temperature as an input; (2) licensee engineers revised Calculation 13-MC-SI-018, which superseded portions of Calculation 13-MC-SI-309, but failed to revise Calculation 13-MC-Sl-309 to identify the superseded sections; and (3) licensee engineers revised Calculation 13-MC-SI-018, which established a new minimum containment sump level, but did not revise Calculation 13-MC-SI-804 to reflect the new minimum containment sump level. This is a violation of 10 CFR Part 50, Appendix B, Criterion III (50-528; -529; -530/9911-01).
This Severity Level IVviolation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CRDR 9-9-1012.
Conclusions The team identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion III, for failure to verify the adequacy of changes to design basis Calculation 13-MC-SI-018, which resulted in the failure to revise three associated design basis calculations to reflect the change.
None of the discrepancies identified presented operability concerns.
E1.2 Containment S ra S stem Desi n Review - Electrical and Instrumentation and Control S stem Descri tion The onsite electric system, including power supplies, distribution equipment, and instrumentation and control supplies power to the containment spray components during startup, normal operation, and normal and emergency shutdown.
Critical instrumentation and control circuits receive 120Vac ungrounded uninterruptible power.
Upon loss of all ac power, six diesel generators (two per unit) provided power to containment spray safety-related equipment and equipment important to safety. This equipment included the containment spray pumps, which were sequenced onto emergency busses powered by emergency diesel generators after a loss-of-offsite powe e
-8-Various containment spray system temperatures, flows, pressures, and levels were monitored and most were available on control board indicators.
Others, such as containment spray header level, were provided on remote indicators, but were available to control room operators via process computers, such as, the emergency response facilitydata acquisition and display system.
Ins ection Sco e
The team reviewed electrical and instrumentation and control design documents associated with the containment spray system to determine the plant's conformance to its licensing and design bases.
This review included the UFSAR; the Combustion Engineering Standard Safety Analysis Report, the NUREG 0857, "Safety Evaluation Report for the Palo Verde Nuclear Generating Station, Units 1, 2, and 3," Supplement 7; Palo Verde Nuclear Generating Station, Units 1, 2, and 3, technical specifications; the design basis manual; design calculations, drawings, and engineering procedures.
Observations and Findin s The electrical, instrumentation, and control aspects of the containment spray system were,,in general, adequate to ensure that the design supported system operation during normal and accident conditions. The team, however, identified a number of errors in uncertainty calculations, as well as, discrepancies between calculations, the UFSAR, and emergency procedures.
Details of these discrepancies are discussed below.
Environmental Qualification of the Containment Sum Water Level Sensors Section 5.1 of Calculation 13-JC-SI-224, "Post Accident Monitoring Containment Water Level Instrument (SIA-L-706 & SIB-L-707) Uncertainty Calculation," Revision 4, included a statement that containment sump wide-range level Transmitter Probes J-SIA-LE-0706A and J-SIA-LE-0707A were qualified for 30 minutes of submergence subsequent to accidents occurring inside containment.
The team noted, however, that Section 18.II.F.1.5 of the UFSAR states that continuous control room indication of containment sump water level is provided by wide-range level instrumentation.
The UFSAR further stated that "this instrumentation is environmentally qualified to function in a post-LOCA environment in accordance with Regulatory Guide 1.89, and is designed to meet Regulatory Guide 1.97, Revision 2."
Table 2 of Regulatory Guide 1.97, "Instrumentation for Light-Water-Cooled Nuclear Power Plant to Assess Plant and Environs Conditions During and Following an Accident," Revision 2, defined the purpose of monitoring wide range containment sump water level to be, in part, for tong-term surveillance.
In Section 3.11.1(9) of NUREG 0857, "Safety Evaluation Report for the Palo Verde Nuclear Generating Station, Units 1, 2, and 3," Supplement 7, the NRC approved 182 days as the duration required for post-accident monitoring equipment to be operable.
Based on this, the team determined that the existing 30 minute submergence environmental qualification for the containment sump wide range level transmitter Probes J-SIA-LE-0706A and J-SIA-LE-0707A did not meet the UFSAR commitment to Regulatory Guide 1.97 for
-9-long-term surveillance of containment sump water level (i.e., submergence for 182 days).
Section (b)(3) of 10 CFR 50.49 requires, in part, that each holder of a license for a nuclear power plant establish a program for qualifying electric equipment important to safety for certain post-accident monitoring. A footnote to 10 CFR 50.49(b)(3) states that, "[s]pecific guidance concerning the types of variables to be monitored is provided in Revision 2 of Regulatory Guide 1.97." Section (e)(6) to 10 CFR 50.49 further requires that electrical equipment qualification must include and be based on submergence (if subject to being submerged).
The team found that the licensee's failure to qualify containment sump wide-range level Transmitter Probes J-SIA-LE-0706A and J-SIA-LE-0707A to be submerged for long-term post-accident monitoring was a violation of 10 CFR 50.49 (50-528; -529; -530/9911-02).
This Severity Level IVviolation is being treated as a noncited violation consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CRDR 9-9-0730 dated June 23, 1999.
In addition, licensee engineers performed Operability Determination 226, and concluded that the installed level instruments (Probes J-SIA-LE-0706A and J-SIA-LE-0707A) were qualified for long-term submergence, based on discussions with the vendor and the physical configuration of the instruments.
The team reviewed the operability determination and agreed with this conclusion.
Errors in Refuelin Water Tank Level Set pints The refueling water tank provides a volume of borated water (1) to accommodate two back-to-back cold shutdowns at 90 percent of life, and (2) as a source of borated water for engineered safety feature pump operation.
The engineered safety feature volume is based on a design basis requirement that the refueling water tank be designed to supply borated water for 20 minutes of pump operation assuming full flow conditions plus an additional 10 percent to account for instrument uncertainty.
Section 9.3.4.5.3. of the UFSAR references Section 9.3.4.5.3 of the Combustion Engineering Standard Safety Analysis Report that states that a "LO" level alarm (at 87 percent refueling water tank level) provides warning that the refueling water tank level is approaching the volume required for two back-to-back cold shutdowns.
The Combustion Engineering Standard Safety Analysis Report further states that a "LO-LO"level alarm (at 73 percent refueling water tank level) willtrip the boric acid makeup pumps, and provide warning to the operators that the refueling water tank level is approaching the volume required for engineered safety feature pump operation.
Technical Specification 3.5.5 requires that refueling water tank level be equal to or greater than a minimum specified in Technical Specification Figure 3.5.5-1. The technical specification minimum refueling water tank level varies with average reactor coolant temperature, and at normal average reactor coolant operating temperature, is required to be 600,000 gallons (approximately 80 percent).
This technical specification limitwas well above that required to support engineered safety feature pump operation.
The team noted that Row 49 of UFSAR Table 1.8-1, "PVNGS Compliance with Regulatory Guide 1.97 (Revision 2) Requirements," indicates that the refueling water tank level instruments sensed level from the bottom of the tank to the top of the tan However, Calculation 13-JC-CH-209, "Refueling Water Tank Level Instrument (Chx-L-203x, x=A, B, C, D) Setpoint and Uncertainty Calculation," indicates that the refueling water tank level instrument was calibrated to sense level from the top of the vortex breakers (50 inches above the tank bottom) to the bottom of the overflow nozzle (99 inches below the top of the tank.
In consultation with licensee engineers, the team determined that the UFSAR was in error, therefore this discrepancy between the UFSAR and the calculation did not present a safety concern.
Licensee representatives initiated CRDR 9-9-1055 to address not only this discrepancy, but to look for others in UFSAR, Table 1.8-1.
Refueling water tank level accuracy Calculations 13-JC-CH-206, "Setpoints and Total Loop Uncertainty for RWT Level Loops JCHALLOOP0200 and JCHBLLOOP0201," and 13-JC-CH-209, "Refueling Water Tank Level Instrument (Chx-L-203x, x=A, B, C, D)
Setpoint and Uncertainty Calculation," were under revision at the time of this inspection, as a result of CRDR 9-4-0678 written in 1994.
During this inspection, licensee engineers were completing the revisions to these calculations, and discovered the following additional discrepancies between the UFSAR and design basis calculations.
These issues are addressed in CRDR 9-9-0693.
The refueling water tank "LO"level alarm could come in after decreasing level entry into the volume designated for two back-to-back cold shutdowns.
Specifically, the "LO" level alarm setpoint of 87 percent refueling water tank level could not support the 88.44 percent refueling water tank level requirement from Calculation 13-JC-CH-206, Revision 3. This was not consistent with UFSAR, Section 9.3.4.5.3, which stated that an alarm was provided to warn the operator of entering the volume designated for two back-to-back cold shutdowns at 90 percent core life. This.volume provides a source of borated water to the charging system for makeup to the reactor coolant system to compensate for contraction due to plant cooldown, and is not required to be in the technical specifications.
It was included to provide operators with a single source of information on refueling water tank level. There was no impact on operability associated with this issue since this volume does not support a safety function.
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The refueling water tank "LO-LO"level alarm could come in after entry into the engineered safety feature pump reserve volume. Specifically, the
"LO-LO"alarm setpoint of 73 percent refueling water tank level could not support the 74.3 percent refueling water tank level, as required by Calculation 13-MC-CH-201, "Refueling Water Tank (RWT), Holdup Tank (HT),
and Reactor Makeup Water Tank (RMWT) Sizing," Revision 6. This was not consistent with Section 9.3 4.5.3 of the UFSAR, which states that an alarm was provided to warn operators prior to entering the volume required for engineered safety features pump operation.
The operability of the containment spray system or emergency core cooling system pumps was not affected by this issue because the revised volume required for these systems, 74.3 percent, was still; significantly less than the Technical Specification 3.5.5.2 requiremen I
C-11-Section (e) to 10 CFR 50.71, requires, in part, that each person licensed to operate a nuclear power reactor update, periodically, the final safety analysis report to assure that the information included, therein, contains the latest material developed.
Section (e) further states that the UFSAR shall be revised to include the effects of all changes made in the facilityor procedures described in the final safety analysis report.
The team found that licensee engineers failed to revise the UFSAR to reflect (1) the calibrated range of the Refueling Water Tank Level Instrument as referenced in Calculation 13-JC-CH-209; (2) the appropriate "LO"refueling water tank level setpoint determined by Calculation 13-JC-CH-206; and (3) the appropriate "LO-LO"refueling water tank level setpoints determined by Calculation 13-MC-CH-201. This is a violation of 10 CFR 50.71(e) (50-528; -529; -530/9911-03).
This Severity Level IVviolation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CRDR 9-9-0693 and CRDR 9-9-1055.
Errors in Desi n and Licensin Basis Uncertaint Calculations ht The team reviewed Procedure DSG-IC-0205, "Design Guide for Instrument Uncertainty and Setpoint Determination," Revision 8. The team noted that the design guide was well written and was consistent with industry standards, such as Regulatory Guide 1.105,
"Instrument Setpoints," Revision 1, and Independent Safety Analysis RP67.04, Part II,
"Methodologies for the Determination of Setpoints for Nuclear Safety-Related Instrumentation," September 1994.
In addition, the design guide provided technical information, which supported the methodology used by the licensee to determine instrument loop and setpoint uncertainties.
The team reviewed approximately 10 containment spray instrument loop uncertainty and setpoint calculations and found that they were performed in accordance with the guidance provided in Procedure DSG-IC-0205.
However, the team identified the following errors in design basis uncertainty calculations:
Calculation 13-JC-SI-218, "Containment Spray Header Water Level Loop J-SIN-L-0704/0705 Setpoint and Uncertainty Calculation," Revision 2, referenced a nonconservative tolerance (+/- 3.10 percent rather than the correct value of +/- 3.01 percent) to be used in calibrating the containment spray water level instruments.
Licensee engineers reviewed all completed calibration procedures for these instruments and found that the results were within
+/- 3.01 percent of the desired value; therefore, this error in the calculation did not affect equipment operability. The licensee initiated CRDR 9-9-0763 to correct this calculational error.
Calculation 13-JC-SI-218, "Containment Spray Header Water Level Loop J-SIN-L-0704/0705 Setpoint and Uncertainty Calculation," Revision 2, used the specific-gravity for borated water; however, the technical specification bases for Surveillance Requirement 3.6.6.2 included a statement that the header can be filled with unborated water. This error resulted in a miscalculation of approximately 2 inches in the containment spray header level in the conservative direction when the header was filled with demineralized water. This error could
-12-have resulted in inadvertent spillage out the spray headers when making up for system leakage and evaporation.
Furthermore, the licensee acknowledged that a small amount of spillage had occurred in the past.
Design Modification Work Order 870365 lowered the technical specification minimum level in the containment spray header from 115 feet to the current Technical Specification Surveillance Requirement 3.6.6.2 of 113 feet; therefore, this issue did not present a safety concern.
Licensee engineers revised Calculation 13-JC-SI-218 to address the boron concentration variation with respect to unborated water.
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The team identified an error in Calculation 13-JC-SI-215, Revision 4. This calculation evaluated instrument uncertainties to determine the indicated containment spray flow necessary to satisfy the design flow. Table 23, "Loop Uncertainty (indicated for a given actual flow)," of this calculation specified that to assure an actual containment spray flowof 3725 gpm, indicated flow could be as high as 4065 gpm. However, Section 2 and Table 27, "LimitingSetpoint," of this same calculation specified that to assure a flowof 3725 gpm, an indicated flow could be 3900 gpm. Therefore, Calculation 13-JC-Sl-215 was internally inconsistent.
Furthermore, Emergency Procedure 40EP-9EO03, "Loss of Coolant Accident," Revision 6, references the indicated containment spray flowrate of 3900 gpm. Licensee engineers stated that Revision 3 (dated March 1, 1996) of this calculation changed the flowrate in Table 23 to 4065 gpm, but Section 2 and Table 27 of the calculation were not changed.
In addition, Emergency Procedure 40EP-9EO03 was not revised to show the new indicated flowrate. Condition Report/Disposition Report 9-9-0771 was initiated to address these errors.
The values for total positive and random positive uncertainties for post-accident conditions provided in Table 23 of Calculation 13-JC-SI-215, "Containment Spray Pump Train A and B Discharge Flow Indication Loops (SIA-F-338 & SIB-F-348)
Uncertainty Calculation," Revision 4, were transposed.
The team understood that the correct values were used when determining the actual positive uncertainty; therefore, the error did not impact the conclusions in the calculation.
This issue was addressed in the licensee's corrective action program as CRDR 9-9-0771.
Criterion III of Appendix B to 10 CFR Part 50 requires, in part, that design control measures provide for verifying or checking the adequacy of design.
Criterion III further requires that design changes be subject to design control measures commensurate with those applied to the original design.
The team found that the licensee failed to verify the adequacy of Calculation 13-JC-SI-218, in that, the calculation referenced a nonconservative tolerance, and did not consider the specific-gravity for unborated water in the containment spray header.
In addition, the licensee failed to verify the adequacy of Calculation 13-JC-SI-215, in that, licensee engineers changed the flowrate in one section of Calculation 12-JC-SI-215, but failed to revise all affected sections of the
!
-13-calculation.
This is a violation of 10 CFR Part 50, Appendix B, Criterion III (50-528; -529; -530/9911-01).
This Severity Level IVviolation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CRDR 9-9-0763 and 9-9-0771.
Criterion III of Appendix B to 10 CFR Part 50 requires, in part, that design control measures be established to assure that the design basis is correctly translated into specifications, drawings, and procedures.
Criterion III further requires that design changes be subject to design control measures commensurate with those applied to the original design.
Licensee engineers failed to translate the corrected indicated containment spray flowrate from Calculation 12-JC-Sl-215 into Emergency Procedure 40EP-9EO03.
This is a violation of 10 CFR Part 50, Appendix B, Criterion III (50-528; -529; -530/9911-01).
This Severity Level IVviolation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CRDR 9-9-0771.
Conclusions The team concluded that although a number of errors and discrepancies were identified, none presented a safety or operational concern.
The engineering staff was able to quickly answer team questions, and when the team identified problems with the calculations, licensee representatives took appropriate action to resolve the issues.
In general, the team found that the uncertainty calculations for the containment spray system instrumentation and control equipment were technically adequate and consistent with design procedures.
However, the team identified two examples of a violation of 10 CFR Part 50, Appendix B, Criterion III, for failure to translate a design change into Emergency Procedure 40EP-9EO03, and for failure to ensure the adequacy of several design basis calculations; and a violation of 10 CFR 50.49 for failure to qualify containment sump wide-range level transmitters for 182 days of submergence to meet long-term post-accident monitoring requirements.
The team also identified a violation of Section (e) to 10 CFR 50.71 for failure to revise the UFSAR to reflect (1) the appropriate calibrated range of the refueling water tank level instrument referenced in Calculation 13-JC-CH-209, (2) the appropriate "LO" refueling water tank level setpoints determined by Calculation 13-JC-CH-206; and (3) the appropriate "LO-LO"refueling water tank level setpoints determined by Calculation 13-MC-CH-201.
Containment S ra S stem Walkdown Team members participated in a walkdown of the accessible portions of the Unit 3 containment spray system, including major mechanical, electrical, and instrumentation and control components.
In addition, the team observed containment spray system instrumentation and indication in the Unit 3 main control room and remote shutdown panel.
In general, the team found that the areas observed were adequately maintained and were consistent with design documents.
Housekeeping appeared to be very goo I
-14-E1.4 125Vdc Class 1E Electrical Power S stem E1 4.1 S stem Descri tion The 125Vdc Class 1E electrical power system supplies four channels of Class 1E switchgear, essential ac power inverters, and other engineered safety features and safety-related equipment.
The four channels are grouped into two independent and redundant safety-related electrical power subsystems, Train A,and B. Each train consists of two 125Vdc batteries (Batteries A and C in Train A, and Batteries B and D in Train B), and associated battery chargers for each battery. Class 1E Batteries A, B, C, and D are assigned identifiers E-PKA-F11, E-PKB-F12, E-PKC-F13, and E-PKD-F14, respectively.
Each Class 1E battery is located in a separate room of the control building and each room is equipped with a separate ventilation system.
Control room instrumentation for the battery includes voltage and current levels, bus undervoltage alarms, ground indication, and battery breaker operi alarms.
The batteries are sized for a minimum number of hours of operation without the support of a battery charger.
A nonsafety-related alternate ac power source consisting of two redundant gas turbine generators provides power to cope with a 4-hour station blackout event in any one nuclear unit. Each battery room has two 100 percent capacity exhaust fans, which exhaust directly to the atmosphere.
Battery room air is supplied through a transfer grill with a fire damper.
The batteries installed during original plant construction were manufactured by Yuasa-Exide, Incorporated.
Soon, thereafter, the licensee encountered reliability problems with these batteries, and in the 1992-1993 time frame, replaced the Exide batteries in all three units with high specific-gravity round cell batteries manufactured by American Telephone and Telegraph Bell Laboratories.
After installation, the licensee identified that the high specific-gravity round cell batteries were'exhibiting premature aging.
In addition, the vendor, American Telephone and Telegraph Bell Laboratories, decided to no longer support the use of the high specific-gravity round cell batteries in the nuclear industry. The licensee then decided to replace all of the high specific-gravity round cell batteries with low specific-gravity batteries manufactured by GNB Technologies, Incorporated.
The batteries in Unit 2 were replaced during the spring
.
1999 Unit 2 refueling outage.
Licensee engineers stated the batteries in Units 1 and 3 would be replaced during subsequent refueling outages E1.4.2 Desi n Review - Electrical ae Ins ection Sco e
The team reviewed 125Vdc power licensing and design bases documents including the UFSAR, technical specifications, Palo Verde Nuclear Generating Station Safety Evaluation Report, design basis manuals, design calculations, specifications, drawings,
.'ngineering procedures, and completed surveillance tests to determine the plant's conformance to the design basi e
-15-Observations and Findin s The team noted that Calculations 01-EC-PK-207, "DC Battery Sizing and Minimum Voltage," Revision 1; 02-EC-PK-207, "DC Battery Sizing and Minimum Voltage,"
Revision 3; and 03-EC-PK-207, "DC Battery Sizing and Minimum Voltage," Revision 1, met the licensing commitment to IEEE Standard 485-1983, "IEEE Recommended Practices for Sizing Large Lead Storage Batteries for Generating Stations and Substations."
Discre ancies Between Desi n Basis Calculation 03-EC-PK-207 and Desi n Drawin s Concernin S ared Breaker 3EPKBD2218 The team identified a discrepancy between an electrical calculation and an electrical drawing. Calculation 03-EC-PK-207, Section 4.4, "Component Resistances,"
assigned a load to Distribution Panel Breaker 3EPKBD2218; however, Drawing 03-EC-PKA-006,
"125V DC Class 1E Power Distribution Panel 1E-PKB-D22 Single Line Diagram,"
Revision 7, showed the same breaker as a spare.
Licensee engineers reviewed other documents associated with Breaker 3EPKBD221 8 and found that Drawing 03-E-HFB-004, "Fuel/Auxiliary Building Essential Exhaust, AFU3M-HFBJ01," Revision 9; Vendor Drawing E022-24-18 (wiring diagram for the relay cabinet); and the plant data management system showed that the circuit for the. breaker was in use.
Furthermore, licensee engineers found that the circuit and breaker were installed in Unit 3, the breaker was labeled as a spare and in the "off"position.
Licensee engineers determined that this error was introduced in Modification Package PCWO 00771121, which installed Breaker 3EPKBD2218 and the circuit in Unit 3. The modification was canceled, but most documents and databases had already been revised to reflect the installed circuit and breaker in use.
Only Drawing 03-EC-PKA-006 showed the correct installed configuration of the breaker.
The team noted that the error in Calculation 03-EC-PK-207 was conservative, in that the calculation included an additional load on the battery; therefore, these errors presented no operability concern with the batteries.
Criterion III of Appendix B to 10 CFR Part 50 requires, in part, that measures be established to assure that applicable regulatory requirements and the design bases are correctly translated into specifications, drawings, procedures, and instructions.
Criterion III further requires that design control measures provide for verifying or checking the adequacy of design, and states that design changes shall be subject to
. design control measures commensurate with those applied to the original design.
The team found that (1) the failure to verify that Calculation 03-EC-PK-207 adequately reflected installed equipment, and (2) the failure to accurately translate design change information to Design Basis Calculation 03-E-HFB-004, Vendor Drawing E022-24-18, and the plant data management system to show the actual installed configuration is a violation of 10 CFR Part 50, Appendix B, Criterion III (50-528; -529; -530/9911-01).
This Severity Level IV violation is being treated as a noncited violation consistent with
-16-Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CRDR 9-9-0778.
Desi n Basis for Batte Loadin in Calculations and the U dated Final Safet Anal sis
~Re ort The team identified discrepancies among battery loading calculations, the UFSAR, and the manner in which auxiliary feedwater isolation and regulating valves were used in emergency procedures.
Calculations 01-EC-PK-207, 02-EC-PK-207, and 03-EC-PK-207 (discussed above) stated that the batteries were sized to support the Train A auxiliary feedwater isolation and regulating valves being energized four times during a 2-hour duty cycle. This battery loading requirement was based on a letter from Combustion Engineering dated May 15, 1980, which stated, "[t]he auxiliary feedwater regulating and isolation valves (Train A) will be cycled open and closed twice during the two hour period following a complete loss of all AC power." This was consistent with Table 8.3-6, "Class 1E DC System Loads," of the UFSAR that indicated loads on the batteries that accommodated four strokes (two open and two closed) of each of the four Train A auxiliary feedwater regulating and isolation valves.
However, both Emergency Procedures 40EP-9EO03, "Loss of Coolant Accident," Revision 6, and 40EP-9EO08,
"Blackout," Revision 0, directed operators to maintain, ensure, or restore steam generator level between 40 and 60 percent.
It was not clear to the inspectors whether the load assumptions in the calculation or the loading requirements in the UFSAR
'nveloped potential operator manipulations required in the emergency procedures.
Licensee engineers stated that in maintaining steam generator level, as directed in the emergency procedures, operators leave the isolation valve open and adjust the regulating valve by small amounts, and the robust design of the batteries could accommodate these valve manipulations.
A corrective actions, licensee engineers proposed, in CRDR 9-9-0696, that a clarification be added to the calculations, "that although the calculation model does not precisely reflect the auxiliary feedwater valve cycling, the model conservatively envelopes the effect of valve cycling on the battery loading."
In addition Licensing Document Change Request 99-F049 was issued to clarify the basis for battery loading in the UFSAR. The team agreed that the installed batteries had ample additional capacity to meet this demand; therefore, the team did not consider this issue to be an operability concern.
Batte Room Ventilation Discre ancies Section 9.4.1.4.2 of the UFSAR states, "The battery room ventilation system is designed to maintain the combustible gas concentration in the battery rooms below the lower flammability limit of hydrogen.
To accomplish this, air in the battery rooms is exhausted to the outside atmosphere in order to continuously sweep combustible gases out of the battery rooms. The exhaust is located at the ceiling level." However, the team found that the normal and emergency battery exhaust fans took suction approximately two feet
~
from the ceiling level.
In NRC Inspection Report 50-528/88-01, the NRC identified that the location of the suction ducts for the exhaust fans in the Unit 1 battery room was not at the highest point in the room. This item was designated as an inspection followup
item (50-528/8801-04).
This item was subsequently closed in NRC Inspection Report 50-528/90-02, which, in part, was based on licensee test results that concluded that gas pocketing in battery rooms was not a problem. Therefore, the team agreed that this discrepancy was not an operability issue.
Section (e) to'10 CFR 50.71, requires, in part, that each person licensed to operate a nuclear power reactor shall update, periodically, the Final Safety Analysis Report to assure that the information included therein contains the latest material developed.
The team found that the licensee's failure to revise the UFSAR to reflect the actual installed configuration of the battery room exhaust ducts was a violation of 10 CFR 50.71(e)
(50-528; -529; -530/9911-03).
This Severity Level IV violation is being treated as a noncited violation consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CRDR 9-9-956.
Conclusions The team identified several calculation and configuration control errors, but none presented a operability concern.
The team identified a violation of 10 CFR 50.71(e) for failure to update the UFSAR to show actual battery room ventilation configuration.
In addition, a canceled modification resulted in a violation of Criterion IIIfor failure to verify that design basis Calculation 03-EC-PK-207, Drawing 03-E-HFB-004, and the plant data management system reflected actual installation. Neither of these violations affected system operability.
E1.4.3 Batte Surveillance Testin Ins ection Sco e
The team reviewed battery surveillance procedures to determine if they were consistent with vendor recommendations, technical specification surveillance requirements, and the design and licensing bases.
Observations and Findin s At the time of this inspection, the Class 1E batteries in Units 1 and 3 were high specific-gravity round cell batteries, manufactured by American Telephone and Telegraph.
As discussed above, in the spring 1999 Unit 2 refueling outage, the licensee replaced the high specific-gravity round cell batteries in Unit 2 with low specific-gravity batteries, manufactured by GNB Technologies, Incorporated.
Therefore, at the time of this inspection, the Class 1E batteries in Unit 2 were low specific-gravity batteries, whereas, the Class 1E batteries in Units 1 and 3 were high specific-gravity round cell batteries.
All Class 1E batteries were tested under two different technical specification surveillance tests, which implemented Technical Specification Surveillance Requirements SR 3.8.4.7, and SR 3.8.4.8.
Surveillance Requirement SR 3.8.4.7 required a service test at least once per 18 months to verify the battery capacity for the 2-hour design duty cycle, which included loads associated with starting and shutting the
-18-diesel generator output breaker at the end of the test. This service test requirement was implemented by Surveillance Test Procedure 32ST-9PK03, "18 Month Surveillance Test of Station Batteries," Revision 17. Surveillance Requirement, SR 3.8.4.8, required a performance test to verify that the low specific-gravity batteries could supply at least 80 percent of the manufacturer's rating, and that the high specific-gravity round cell batteries could supply least 90 percent of the manufacturer's rating. This performance test was implemented by Surveillance Test Procedure 32ST-9PK04, "60 Month Surveillance Test of Station Batteries," Revision 18. The performance test (Procedure 32ST-9PK04) was conducted using a greater load than that required during the service test (32ST-9PK03).
The team verified that the varying load values required by Surveillance Test Procedure 32ST-9PK03 were consistent with the battery loads in Calculations 01, 02, and 03-EC-PK-007, and met the requirements of Technical Specification SR 3.8.4.7.
The team also verified that the constant load tests required by Surveillance Test Procedure 32ST-9PK04 conservatively bounded the loads recommended by the battery vendors.
The team reviewed records of completed battery service and discharge test dates, and found that the test dates met test interval requirements for both the new improved technical specifications and the previous custom technical specifications.
The team noted a deficiency in the methodology prescribed in Procedures 32ST-9PK03 and 32ST-9PK04 used to measure 1E battery electrolyte temperatures.
These procedures direct licensee technicians to obtain temperature of the battery electrolyte fluid by measuring the temperature at the battery cell negative terminal. Licensee personnel stated that this was based on a letter from the vendor for the high specific-gravity round cell batteries, which approved obtaining the temperature of the electrolyte indirectly by measuring battery cell negative terminal temperature.
The team reviewed the vendor's letter and found that it specified that this technique would be valid "provided that there is no contribution to the terminal temperature due to IR [current times resistance] heating (i.e., less that 10 amperes of cell current in the string during the past two hours)." However, this prerequisite was not included in any of the battery surveillance procedures.
Licensee engineers stated that this caution statement was not necessary because heating of the battery terminals would result in a more conservative test.
The team agreed, but noted that the justification for not incorporating a vendor-recommended cautionary statement in surveillance procedures was not documented.
The team reviewed the vendor technical manual for the new Unit 2 low specific-gravity batteries and found it was silent concerning the validity of obtaining electrolyte temperature by measuring temperature at the negative terminals.
Upon questioning by the team, licensee engineers discussed with vendor personnel the acceptability of indirectly obtaining electrolyte fluid temperatures by measuring the temperature at the battery cell negative terminals.
Licensee engineers told the team that vendor personnel verbally stated that this method was acceptable, however, at the time of this inspection,;
they were waiting for written confirmatio Although the method for obtaining electrolyte fluid temperature indirectly at the negative battery terminals did not present an operability concern, the team noted that licensee engineers did not have a written justification for not including in surveillance procedures a caution received from the vendor of the high specific-gravity batteries.
In addition, the team noted that the licensee did not document the use of a method for indirectly obtaining electrolyte temperature that was not specifically approved by the vendor.
Conclusions The licensee's battery surveillance testing program met testing interval requirements in the technical specifications, and the test loads were consistent with the design and licensing bases.
However, the team noted that, although ultimately acceptable, the licensee did not obtain confirmation from the battery vendor before including in the battery surveillance test procedures steps to obtain battery electrolyte temperatures by measuring the temperature at the negative terminals.
E1 4.4 Class 1E 125Vdc Batte S stem Walkdown The team conducted a walkdown inspection of all four Class 1E battery and battery board rooms in both Units 1 and 2. The batteries and intercell connectors appeared to be in good visible condition. Electrolyte levels in the cells were adequate, and battery room temperatures were in the acceptable range.
As discussed in Section E1.4.2 of this report, the team noted that the installed suction for the battery room exhaust fans did not agree with the description'in the UFSAR.
E1.4.5 Modifications Ins ection Sco e
The team reviewed Design Modification Work Order (DMWO) 806536, "Replace 4 Class 1E Round Cell Batteries with Rectangular Batteries and New Racks," dated October 15, 1998, including the associated 10 CFR 50.59 Safety Evaluation 97-174.
Observations and Findin s The 10 CFR 50.59 safety evaluation screening and final evaluation supporting DMWO 806536 addressed the various aspects of the battery change including electrical and mechanical implications for electrolyte spills, fire hazard load changes, and seismic issues related with the battery rack replacements.
The team determined that the evaluation was adequate to determine that no unreviewed safety questions existed.
The team noted that the design change package included appropriate changes to the design basis manual, calculations, drawings, and plant equipment data bases.
Conclusions The team concluded that DMWO 806536, was technically adequate for controlling the installation and testing of the new low specific-gravity batteries in Unit E2 Engineering Support of Facilities and Equipment (93809)
E.2.1 Corrective Action and Condition Re ortin Documents Ins ection Sco e
The team reviewed Procedure 90DP-01P03, Condition Report Screening and Processing," Revision 16, and selected CRDRs associated with the safety injection system, containment isolation valves, and other containment systems.
The CRDRs reviewed are listed in the attachment to this report.
In addition, the team reviewed Procedure 30DP-9WP02, "Work Document Development and Control," Revision 26, which is part of the licensee's corrective action program.
The team assessed the effectiveness of the licensee's corrective actions and verified that the resulting changes preserved the existing design bases.
Observations and Findin s
~ Procedure 90DP-01P03 provided instructions for the screening, prioritizing, assignment, review, closeout, trend coding, and processing of CRDRs. The team noted that there were adequate procedural controls to assure that the design basis was considered when corrective actions affected design.
Procedure 30DP-9WP02 provided instructions for the implementation of the work process, including work order evaluation, development, review, completion, and closing. The team noted that the work control process was used for plant hardware and software.
The team found that the CRDRs reviewed were appropriately prioritized, technically adequate, and properly implemented.
The team did not identify any discrepancies.
Conclusions The team's review of a sample of corrective action documents indicated that, in general, the evaluations, technical adequacy, and implementation were good. The procedure was adequate to assure that the design basis was considered when corrective actions affected design.
E2.2 0 erabilit Determinations Ins ection Sco e
The team reviewed Procedure 40DP-BOP26, "Operability Determination," Revision 7, to ensure the guidance contained, therein, was commensurate with Generic Letter 91-18,
"Information to Licensees Regarding NRC Inspection Manual Section on Resolution of Degraded and Nonconforming Conditions." The team also reviewed selected operability determinations (listed in the attachment to this report) for technical adequacy, and to determine if they were performed in accordance with the procedur b.
Observations and Findin s The team found that Procedure 40DP-9OP26 was welf written and followed the guidance provided in Generic Letter 91-18, in that it delineated instructions for evaluating operability of systems, structures, and components, when a degraded or nonconforming condition was identified. The procedure established methods for documenting the operability decision, bases, and justification of the decision.
The team found that operability determinations reviewed were well organized, comprehensive, and technically sound, with the exception of the errors identified in Operability Determination 183, discussed in Section E2.2.1 of this report.
c.
Conclusions The methodology established in Procedure 40DP-9OP26 for documenting operability decisions, bases, and justifications was good. The team concluded that, with one exception discussed below, operability determinations and evaluations were well organized, comprehensive, and technically sound.
E2.2.1 0 erabilit Determination 183 - Emer enc Core Coolin S stem Flow Transmitters The team reviewed CRDR 2-7-0221, dated July 15, 1997, and associated Operability Determination 183, Revision 0.
In addition, the team reviewed the following:
Preventive Maintenance Task 038406, which licensee personnel used to calibrate the high pressure safety injection hot-leg flow; Emergency Operating Procedure 40EP-9EO03, "Loss-of-Coolant Accident,"
Revision 6, Appendix 100; Palo Verde Nuclear Generating Station Units 1, 2, and 3, Technical Specifications, Section 3.5.2, "ECCS Subsystems-Operating," and, Section 3.3.10, "Post Accident Monitoring Instrumentation";
Regulatory Guide 1.97, "Instrumentation for Light-Water-Cooled Nuclear Power Plant and Environs Conditions During and Following an Accident," Revision 2; and UFSAR Section 1.8 and Table 1.8.1.
b.
Observations and Findin s
Condition Report/Disposition Report 2-7-0221 and the associated Operability Determination 183 were initiated to permit the flow transmitters for the high pressure safety injection, the containment spray, and the low pressure safety injection systems to
.
-22-be removed from service for calibration without entering the associated technical specification action statement and declaring the respective train inoperable.
The high pressure safety injection system has two transmitters per train on the cold-leg and one flow transmitter per train on the hot-leg. The licensee's representative stated that the operability determination was used to avoid entering technical specification action statements, since entering action statements adversely affected performance indicators.
Operability Determination 183 concluded that the emergency core cooling system remained operable if only one of the high pressure cold-leg or hot-leg transmitters was removed from service.
Licensee engineers used, in part, the following as justification for removing these transmitters without entering the action statement for the high pressure safety injection system.
Operability Determination 183 stated that these instruments were qualified as Regulatory Guide 1.97, Category 2, Type D and provided information on variables that indicated the operation of individual safety systems and other systems important to safety.
The emergency core cooling system flowto each cold-leg was predetermined by system characteristics and adjustments made to the injection valves by the emergency core cooling system flow balance test.
For the high pressure safety injection system to remain operable with one hot-leg flowtransmitter taken out-of-service, credit must be taken for technician action to restore this indication to service within minutes of the initiation of a design basis accident.
The operability determination also stated that restoration, "can be accomplish'ed by one l&C technician, who willbe in attendance at the transmitter during calibration," and that "[c]ommunications shall be established between l&C and the control room."
Inade uate Work Instructions used to Calibrate Hi h Pressure Safet In'ection Flow Transmitters As stated above, the conclusion that the high pressure safety injection system was still operable with the hot-leg flow transmitter out-of-service was based on the ability of technicians to restore the flowtransmitter to service within minutes of a design basis accident occurring. The operability determination stated that restoration consisted of disconnecting the test equipment, relanding one wire, and restoring the instrument cover. The team reviewed Preventive Maintenance Task 038406 (which was used on June 9, 1999, to calibrate the Unit 2 high pressure safety injection hot-leg flovy transmitter), and found that Section 2.3 stated that when calibrating the flowtransmitter, the technician was required to maintain radio contact with the control room so that if an abnormal condition occurred, he could return the transmitter to service.
However, the maintenance task did not require the technician to be present at the transmitter.
The team found that this provision did not meet the conditions stated in Operability Determination 183 for calibrating a high pressure safety injection hot-leg transmitter without entering the associated technical specification action statemen II
-23-Criterion V of Appendix B to 10 CFR Part 50 states, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings.
The team found that Preventive Maintenance Task 038406 was not appropriate to meet the conditions in the Operability Determination 183.
It did not include explicit instructions for the technician to be present at the transmitter during calibration, as stated in Operability Determination 183. This is a violation of 10 CFR Part 50, Appendix B, Criterion V (50-528; -529; -530/9911-04).
This Severity Level IVviolation is being treated as a noncited violation consistent with Appendix C of the NRC Enforcement Policy. This violation is included in the licensee's corrective action program as CRDR 9-9-0765.
Failure to Follow Instructions in Procedure 40DP-9OP26 "0 erabilit Determination" The team reviewed Procedure 40DP-9OP26, "Operability Determination," Revision 7, which stated that to use a canceled operability determination, the operability determination must be reviewed to ensure the justification remains valid. The procedure further stated that when a canceled operability determination is used, operators must enter the number of the operability determination in the log and state that the justification for the operability determination remained valid. The team reviewed Operability Determination 183, Revision 4, and found that it was canceled on September 22, 1998.
On June 9, 1999, licensee technicians calibrated the Unit 2 hot-leg flowTransmitter 2JSIAFLOOP0393 while the reactor was operating, using the operability determination as justification for not entering the technical specification action statement for the high pressure safety injection system.
The team noted that the use of Operability Determination 183 was not entered in the unit log, and a statement that the justification remained valid was also not entered.
On June 23, 1999, licensee technicians calibrated the Unit 2 hot-leg flow Transmitter 2JSIBFLOOP0390 using Operability Determination 183 as justification for not entering the high pressure safety injection technical specification action statement.
The team noted that operations personnel entered Operability Determination 183 in the unit log; however, they did not enter the statement that the justification remained valid.
On the same day, licensee technicians calibrated the Unit 3 hot-leg flow Transmitter 3JSIBFLOOP0391 using Operability Determination 183 as justification for not entering the high pressure safety injection technical specification action statement.
Again, operations personnel entered the operability determination number in the unit log; however, they did not include a statement that the justification remained valid.
Criterion V of Appendix B to 10 CFR Part 50 states, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. The team found that, on three occasions (once on June 9, 1999, and twice on June 23, 1999) operations personnel failed to followinstructions in Procedure 40DP-9OP26 in using canceled Operability Determination 183 to calibrate high pressure safety injection flow transmitters on line without making the proper entries in the unit logs. This is a violation of 10 CFR 50,
e
-24-Appendix B, Criterion V (50-528; -529; -530/9911-04).
This Severity Level IVviolation is being treated as a noncited violation consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CR DR 9-9-0765.
c.
Conclusions The team identified two examples of a violation 10 CFR Part 50, Appendix B, Criterion V associated with Operability Determination 183, for (1) failure to implement the conditions of Operability Determination 183 into work instructions for calibrating high pressure safety injection flowtransmitters; and (2) failure (on three occasions) to follow procedural instructions for making entries into the control room logs when reusing Operability Determination 183 after it was canceled.
E2.3 10 CFR 50.59 Safet Evaluations The team performed a partial review of the licensee's safety evaluation program to determine if changes made under this program were in accordance with the requirements of 10 CFR 50.59. The team reviewed Procedure 93DP-OLC07,
"10 CFR 50.59 Screenings and Evaluations," Revision 2; several 10 CFR 50.59 engineering screenings; several 10 CFR 50.59 safety evaluations; and the training and qualification of personnel who performed the 10 CFR 50.59 screenings and evaluations.
Observations and Findin s The team found that the 10 CFR 50.59 screenings and evaluations reviewed were performed in accordance with procedures, and were comprehensive, of good quality, and technically adequate.
The team reviewed the training records of engineers who had either performed or reviewed the 10 CFR 50.59 screenings and safety evaluations and found that all were qualified.
Conclusions The team concluded that the licensee carried out an effective program for the sampled 10 CFR 50.59 evaluations.
The selected 10 CFR 50.59 evaluations were comprehensive, and of good quality.
In addition, the team determined that the engineers who performed the 10 CFR 50.59 safety evaluations were qualified to do s E2.4 Modifications a.
Ins ection Sco e
The team reviewed DMWO 870365, "Change Setpoint for Level Switches Identified in 13-JC-SI-218," which covered the containment spray systems in all three units, and modification Engineering Document Change EDC 99-00457 associated with Unit 2 high pressure safety injection system.
b.
Observations and Findin s The containment spray containment header level alarm setpoint was changed from 115 feet 6 inches to 114 feet under DMWO 870365. This modification resulted when the original Technical Specification 4.6.2.1.c requirement of 115 feet 6 inches was changed to the current Improved Technical Specification Surveillance Requirement 3.6.6.2 to ensure a level of at least 113 feet in the containment spray header.
The team found that DMWO 870365 was performed in accordance with procedures.
The team reviewed Engineering Document Change EDC 99-00457, which was classified as a "paper only" change to reflect the actual high pressure safety injection orifice bore size. The orifices were initiallysized and installed during plant startup testing to prevent cavitation near high pressure safety injection valves, and to ensure that the flow through the safety injection cold-legs was balanced.
The team found that Engineering Document Change EDC 99-00457 was performed in accordance with procedures.
c.
Conclusions The team determined that the reviewed modifications were adequate from a safety and licensing standpoint, and were performed in accordance with procedures.
E2.5 Tem ora Modifications a.
Ins ection Sco e
The team reviewed Procedure 81DP-ODC17, "Temporary Modification Control,"
Revision 5, and the selected temporary modifications listed in the attachment to assess the licensee's temporary modification program. This assessment included verifying that the licensee's configuration control process was effectively implemented for these temporary modifications to ensure that the impact of temporary modifications on surveillance test procedures and the design bases was considered.
In addition, the team inspected selected physical temporary modification installations in the plan Observations and Findin s The team requested a list of all temporary modifications initiated since January 1996 and any installed temporary modifications that were currently open, regardless of installation date.
The team found that 90 temporary modifications had been initiated since January 1996, but only 15 remained open.
The team reviewed 8 open temporary modification packages and inspected the existing installations.
In addition, the team verified that current temporary modification package information and temporary modification logs were maintained in the respective control rooms for all units.
Section 3.1 of Procedure 81DP-ODC17 states, "Justification reviews of TMODS
[temporary modificationsj installed in the plant are required to determine if the TMOD is still necessary or if a permanent plant design change should be initiated."
Nuclear information and records management personnel were required by Procedure 81DP-ODC17 to distribute the justification review forms semi-annually (May and November of each year) to the system engineer assigned responsibility for the system affected by the temporary modification. The responsible system engineer was required to provide a reason for any temporary modification to remain installed, and to verify that the 10 CFR 50.59 screening and evaluation were still valid for current plant conditions.
The responsible system engineer was also required to conduct a walkdown of the temporary modification to ensure that the configuration was still correct and that all required tags were legible and in place.
The procedure required that the system engineer document this information on the justification review form, and transmit it back to nuclear information and records management.
Nuclear information and records management personnel were then required to forward an "information only" copy of the completed justification review form to the respective control room.
The team reviewed documentation for the 15 currently open temporary modifications and found that licensee engineers had not performed, as required by Procedure 81DP-ODC17, 4 semi-annual justification reviews in May 1999 (Temporary Modifications 1-98-RC-003, 1-98-RC-008, 2-98-RC0-004, and 3-98-RC-001).
Furthermore, for the remaining 11 currently open temporary modifications which had received semi-annual justification reviews, nuclear information and records management personnel had not distributed the completed justification review forms to the respective control rooms. The team also reviewed documentation for semi-annual justification reviews which should have been performed since the temporary modifications were opened, and found that 5 semi-annual justification reviews had not been performed in May 1998 (Temporary Modifications (1-98-RC-003, 1-98-RC-008, 1-98-SH-009, 2-98-RC-004, and 3-98-RC-001), and 1 semi-annual justification review had not been performed in November 1997 (Temporary Modification A-97-NA-002).
Criterion V of Appendix B to 10 CFR Part 50 requires, in part, that activities affecting quality shall be prescribed and accomplished in accordance with documented instructions, procedures, or drawings. The team found that licensee personnel failed on 10 occasions to conduct and document justification reviews, and failed on 11 occasions to distribute the justification review forms, as required by Procedure 81 DP-ODC17. This is a violation of 10 CFR Part 50, Appendix B, Criterion V (50-528; -529; -530/9911-04).
-27-This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as CRDR 9-9-0699.
On June 17, 1999, licensee personnel performed the justification review on the four current temporary modifications.
The team conducted a walkdown of the currently-open temporary modifications and verified that their physical configurations were in accordance with the applicable temporary modification packages (i.e., work order and drawing or sketch).
Conclusions The team identified that on 10 occasions licensee personnel failed to conduct and document semi-annual temporary modification justification reviews, and on 11 occasions failed to distribute the justification review forms, as required by procedure.
This was identified as a noncited violation of 10 CFR Part 50;.Appendix B, Criterion V.
Surveillance Testin Ins ection Sco e
The team reviewed the licensee's surveillance test procedures (listed in the attachment to this inspection report) to assure that automatic power-operated containment isolation valves had been included for stroke-time testing in accordance with technical specification requirements.
In addition, the team reviewed surveillance test documentation for the containment spray pumps and the containment isolation valves.
Observations and Findin s Technical Specification Surveillance Requirement 3.6.3.5 required that the closure stroke time of each automatic power-operated containment isolation valve be verified within acceptable limits, and at a test frequency in accordance with the inservice testing program.
The team's review found that all UFSAR identified containment isolation valves requiring stroke-time testing were contained in the applicable surveillance test procedures.
Each procedure specified acceptance limits and test frequency.
The team noted that the licensee included the main steam safety valves as containment isolation valves, however, did not perform 10 CFR Part 50, Appendix J, leakage testing on the valves.
However, in lieu of Appendix J testing of the main steam safety valves, the licensee performed alternate and acceptable ASME,Section IX, set pressure testing on the valves.
The team reviewed the Unit 2 1997, 1998, and 1999 test data for opening and closing times of the containment isolation valves, and found that three valves had failed their stroke times.
In addition, the team reviewed the Unit 2 containment isolation valve test results for containment leakage Type B and C testing for 1997, 1998, and 1999 and found that 10 valves did not meet their leakage acceptance criteria. The team further noted that the total as-found containment leakage rate was only a small percentage of
I
/
0-
-28-the acceptable total leakage rate of 0.6L, (134,001SCCM) permitted by Technical Specification 3.6.1, "Containment," and Appendix J to 10 CFR Part 50, "Primary Reaotor Containment Leakage Testing for Water Cooled Power Reactors."
The team's review of the surveillance pump test procedures and selected results did not identify any discrepancies.
c.
Conclusions The team found that all automatic power-operated containment isolation valves were appropriately included in the applicable surveillance test procedures for stroke-time testing. The team concluded that the licensee's 1997, 1998, and 1999 leak rate testing of containment isolation valves was acceptable, and the as-found leakage was very low and well-within technical specification limits.
E3 Engineering Procedures and Documentation (93809)
E3.1 Calculational Revision Process The team reviewed the licensee's process for preparing, reviewing, and revising calculations described in Procedure 81DP-4CC04, "Calculations," Revision 11.
b.
Observations and Findin s Step 2.1.2.b of Procedure 81DP-4CC04, requires the responsible engineer to review interfacing documents including design input, design process, and output and licensing documents associated with a calculation to evaluate the impact of new or changed calculational results.
The team found that the licensee did not have a formal mechanism for tracking the interrelationships of calculations, assumptions, drawings, and procedures to aid engineers in identifying those that are interdependent.
There is, however, no regulatory requirement to have a formal mechanism; nevertheless, the team found that the licensee's reliance on knowledge-based reviews rather than a formal document or mechanism showing the interdependence of calculations, drawings, and procedures could have been partly responsible for some of the numerous design basis discrepancies and errors identified in this report.
E4 Engineering Staffing and Staff Knowledge (93809)
The team found the engineering staff to be talented, knowledgeable, and experienced.
Additionally, the licensee's engineering personnel exhibited a high level of professionalism during all interactions with the team.
The licensee's engineering workforce was robust enough to support having system teams comprised of dedicated:
multi-discipline design engineers, plant system engineers, and maintenance engineer =-29-E8 Engineering - Miscellaneous Issues (92903)
E8.1 En ineerin Backlo 93809 a.
Ins ection Sco'
The team reviewed the backlog of work assigned to the engineering organization, such as CRDR dispositions and CRDR action items, engineering document changes, deficiency work orders, safety evaluations, and design modification work, and discussed the backlog of tasks with licensee management.
The team reviewed a sample of overdue engineering document changes to determine if the delays had any safety impact.
Observations and Findin s The licensee's engineering organization consisted of seven departments:
(1) nuclear design; (2) systems engineering; (3) maintenance engineering; (4) fuel management; (5) speciality engineering; (6) records; and (7) steam generator projects.
In addition, information technology and the year 2000 project were matrixed (connected by a dotted line on the organizational chart) to the engineering organization.
The licensee established measures for evaluating engineering performance in performing CRDR evaluations, action items, engineering document changes, deficiency work orders, safety analysis basis documents, and modification turnovers.
Within each performance measure, the licensee established a system for establishing priority for completing open items. The engineering performance measures were issued monthly.
The team reviewed the latest performance measures from April and May of 1999, and found that the only current problems identified with engineering department performance indicators concerned deficiency work orders and design modification turnovers.
However, the team noted that these indicators were on an improving trend.
Only one engineering document change was late in the current history of the sampled systems and the team found that the untimeliness did not present a safety concern.
Conclusions The number of engineering backlog items was not excessive, indicating that the licensee was effective in managing the engineering backlog.
E8.2 U datedFinal Safet Anal sis Re ort UFSAR U date and Review Pro rams e
The team reviewed the licensee's program for reviewing and revising their design bases'ocuments including Procedures 93DP-OLC03, "Licensing Document Maintenance,"
Revision 6 (used to update the UFSAR); 81DP-OCC05, "Design and Technical
-30-Document Control," Revision 21 (used to revise the design basis manuals; and 05DP-ONF22, "NFM (Nuclear Fuel Management)," Revision 5, and 05TD-ONF05,
"SABD Maintenance," Revision 0 (used to revise the safety analysis basis document).
The team also reviewed selected UFSAR changes, and the licensee's progress in revalidating their design basis, as discussed in a letter to the NRC dated February 11, 1997.
Observations and Findin s The team found that licensee procedures had sufficient guidance and procedures to control changes to the UFSAR, the design basis manuals, and the safety analysis basis document, such that the design basis of the plant should be preserved.
In a letter dated October 9, 1996, the NRC requested information pursuant to 10 CFR 50.54(f) regarding the adequacy and availability of design bases information.
In their response letter of February 11, 1997, licensee management referred to their design bases and calculational reconstitution effort conducted from 1991 through 1995.
As a result of this effort, licensee personnel (1) developed design bases manuals for 57 systems; (2) developed 9 topical issues (design basis requirements that are common to a number of systems, such as seismic, medium and high energy line breaks, etc., or for a nonsystem-related plant area such as structures); (3) performed validations of the design basis manuals; and (4) reverified and/or reconstituted design calculations and instrumentation and control system setpoints.
Licensee management concluded in their response letter of February 11, 1997, that the configuration and performance of the as-built plant (Units 1, 2, and 3) were consistent with the design bases, and that their
, current processes and programs provided reasonable assurance that plant configuration
, would be maintained consistent with design bases.
In addition, the licensee, in conjunction with Asea Brown Boveri-Combustion Engineering, developed the Safety Analysis Basis Document which was a compilation of the detailed information that forms the bases of the Palo Verde safety analyses.
For the most part, this effort, completed in June 1996 with final revisions completed in October 1996, addressed (1) the sources of the accident analysis descriptions in UFSAR, Chapter 15; (2) detailed information about the primary computer code for modeling transient events; (3) the method for comprehensive design control of core reloads; and (4) emphasis on the control of safety analysis assumptions.
On October 18, 1996, the NRC published revisions to the "General Statement of Policy and Procedure for Enforcement Actions" (Enforcement Policy), that established a 2-year period of enforcement discretion to encourage voluntary industry re-examination of facilitylicense and design bases.
As a condition for enforcement discretion, licensees were required to notify the NRC, in writing, of the intent to conduct a voluntary review of the UFSAR to be completed prior to October 18, 1998.
In their response letter of February 6, 1997, licensee management committed to conduct a review of the UFSAR
.
that would verify plant design, operating, testing, and configuration information and descriptions contained in the USFAR against the as-built, as-operated, and as-tested plant, as well as, the reconstituted design basis.
This voluntary effort, license basis
validation project, was scheduled to be completed by October 1998, and any changes to the UFSAR, as a result of this effort, would be incorporated in the normal 10 CFR 50.71 (e) update of the UFSAR. Licensee personnel completed the license basis validation project on July 31, 1998, which resulted in the identification of outdated information, inconsistent data, and errors of fact, all of which were documented in the licensee's corrective action program as CRDRs (listed in the attachment to this report).
The team requested licensee personnel to conduct an electronic search for all CRDRs issued since completion of the license basis validation project that addressed UFSAR fidelityissues.
The team reviewed the six CRDRs that dealt with UFSAR fidelity issues, and found that two of the six CRDRs should have been detected during the license basis validation project.
However, there was no safety significance associated with either of these two discrepancies.
The team noted that certain sections in the UFSAR were written in the future tense, which implied that specific actions needed to be accomplished, even though it was verified that they had been already been performed.
For example:
Section 6.2.2.4, "Tests and Inspections," states, "As part of the overall testing program, hydraulic model tests willbe performed in order to determine the effect of the sump design on vortex phenomena and on entrance and line losses relative to the required NPSH for ESF pumps."
Section 6.3.1.4 stated, in part, that, "procedures willbe provided to cover operation of the diesel generators.
These procedures will ensure that the diesels are correctly loaded, including the event of loss of offsite power following an SIAS reset."
The team found that these types of statements in the UFSAR were confusing and made it difficultfor the team to understand the licensing and design bases of some of the systems reviewed.
Licensee representatives stated that these statements were most likely moved into the UFSAR from the Combustion Engineering Standard Safety Analysis Report, which was a generic Safety Analysis Report intended for use by numerous Combustion Engineering plants.
Conclusions From 1991 to 1996, licensee management and personnel expended considerable effort to assure the fidelity of the UFSAR through their design bases and calculational reconstitution program and through the development of their Safety Analysis Basis Document.
Despite errors found in the UFSAR, the team found that the licensee's UFSAR program review was effective in identifying discrepancies and initiating license document change requests to validate and correct the UFSAR. None of the errors identified by the team during this inspection as discussed above, and during the team's:
review of the licensee's program implementation, posed an operability concer t
-32-Closed Ins ection Followu Item 50-528/9815-02:
Review of Letdown Line Equipment Root Cause of Failure Report.
Closed Licensee Event Re ort 50-528/98-007-01 and -02: Letdown Line Break Due To Pressure Transients.
The licensee documented this event in Licensee Event Report 98-007, Revisions
and 2, as well as, in their corrective action program as CRDR 1-8-0322. The root-cause analysis of the event determined it was the result of an improperly loaded spring can hanger on the letdown line that in turn caused a fatigue failure of the line. A metallurgical analysis described the fatigue failure as due to reverse bending in the letdown line in the lateral direction. The improper loading of the spring can hanger was the result of vibration that loosened the adjusting nut.
The licensee took the following corrective actions:
(1) inspected Units 2 and 3 to determine susceptibility for the same failure; (2) modified Units 1,.2, and 3 to eliminate the spring can hanger, modified the affected piping, and added new supports; (3) performed a site-wide spring can transportability review to establish susceptibility of other spring can hangers to this problem; and (4) revised operating procedures to reduce or minimize hydraulic transients when putting the letdown line into service.
The team reviewed the final report of the root cause of the equipment failure in
"Equipment Root Cause of Failure Analysis," Revision 0. NRC Inspection Reporf 50-528/9815 also discussed this event was and the associated NRC enforcement actions taken.
Allunits have been modified and applicable procedures revised.
In the site-wide transportability review, the licensee found only two susceptible spring can supports that were modified or removed.
Closed Violation 50-528 -529'530/9814-06:
Five Examples of Failure to Meet Technical Specification 3.5.2.
This violation identified five examples where action was not taken to either restore the emergency core cooling system subsystems to an operable status or place the unit in the applicable mode in accordance with Technical Specification 3.5.2 or 3.0.3.
Each subsystem included one operable high pressure safety injection pump, one operable low pressure safety injection pump, and an independent operable flow path.
Licensee personnel documented this problem in CRDR 1-8-0238. The root cause of this violation was determined to be failure to recognize that a flow path was inoperable because the surveillance testing process was inadequate.
New requirements were developed to test the check valves properly. Action Item 4 of CRDR 1-8-0238 assured all other check valves were properly tested.
Action Item 6 of CRDR 1-8-0238 reviewed industry operating experience to see if other failure experiences were properly addressed by the licensee.
Based on a review of industry experience, licensee engineers concluded that the problem with the high pressure safety injection discharge pump check valves appeared to be an isolated event. The team verified the adequacy and completion of the action item Closed Violation 50-528 -529'530/9814-07:
Two Examples of High Pressure Safety Injection Pump Discharge Check Valves Condition Adverse to Quality.
This violation identified two examples where prompt actions were not taken to identify, correct, and preclude recurrence of significant conditions adverse to quality.
Specifically, on October 10 and 28, 1997, a cocked-open check valve caused an unexpected loss of inventory in the Unit 2 safety injection tank.
Final corrective actions.
were not completed until May 16, 1998. Additionally, on April 9, 1998, Check Valve 1PSIAV405 was improperly assembled, and this condition was not identified and corrected until May 15, 1998.
The licensee documented this problem in CRDR 2-7-0420.
In the root-cause analysis, the licensee established that engineers did not understand the significance of the reverse flow through the high pressure safety injection pump discharge check valve. As corrective actions, licensee personnel added a cautionary note to the operational procedure and to the assembly procedure of the valves in question.
Corrective actions included a generic review for transportability of this problem to other components.
The licensee found that this problem was limited to the 4-inch pressure seal check valves and, therefore, concluded that the problem was limited to the high pressure safety injection check valves. The team reviewed the licensee's corrective actions and found that they were adequate.
Closed Violation 50-528/9814-08:
Two Examples of Inadequate High Pressure Safety Injection Discharge Check Valve Procedures.
This violation identified two examples where Maintenance Procedure 31MT-9ZZ17,
"Disassembly and Reassembly of Borg-Warner Check Valves," was not appropriate to the circumstances.
The procedure did not ensure correct vertical alignment of check valve disassemblies and Surveillance Test Procedure 73ST-9X133, "HPSI Pump and Check Valve Full Flow Test," failed to include appropriate quantitative or qualitative acceptance criteria.
In response to this violation, the licensee initiated CRDR 1-8-0238, which revised procedures to include appropriate acceptance criteria.
In the root cause analyses, the licensee concluded that an error in assembly Procedure 31MT-9ZZ17, "Disassembly and Assembly of Borg-Warner Check Valves," Revision 6, resulted from inadequate vendor information. The error in Testing Procedure 73ST-9XI35, "HPSI Pump Discharge Check Valve Closed Exercise Test," Revision 6, resulted from inadequate testing conditions in the procedure that prevented back flow past the check valve from being detected.
As corrective action, licensee personnel revised the procedures so back flowwould be detected and evaluated assembly and testing for the high pressure safety injection pump discharge check valves.
Licensee personnel reviewed all check valves (101 valves per unit) that had a safety function to close in the inservice test program and the associated failure data on those valves (Action Item 5 to CRDR 1-8-0238).
-34-During review of the 101 valves, licensee personnel identified in CRDR 9-8-0862, one additional possibly inadequate procedure for testing Valve AFAV015. The licensee enhanced the testing procedure for that valve to include a better definition of testing conditions, test setup, etc.
Licensee personnel found the pressure seal design and failures identified in the violation and CRDR 1-8-0238 were limited or isolated to the high pressure safety injection pump discharge check valves.
In reviewing failure data (Action Item 5 to CRDR 1-8-0238), licensee personnel identified two valve failures attributable to disc cocking, a different failure mechanism.
It was concluded that the disc cocking would be detected by current testing procedures.
The team verified the licensee's close out and effectiveness of the Action Item 5 to CRDR 1-8-0238 and CRDR 9-8-0862.
E8.7
. Closed Violation50-528 -529 -530/9812-01:
Two Examplesof the Failure to Implement Corrective Action Procedure 90DP-OIP10.
This violation identified two examples of failure to implement corrective action Procedure 90DP-01PLO.
Specifically, a significant CRDR 2-7-0271 failed to identify a root cause and failed to identify a degraded condition for shift supervisor review.
The licensee documented the first example of this problem in CRDR 9-8-0338.
In the cause analysis, the licensee found the first example of this violation to be an isolated case of an inadequate root-cause investigation.
Corrective actions were to remove the individual from performing root-cause evaluations until additional training was completed on the requisite quality of root cause evaluations.
The licensee found that the second example of this violation occurred because personnel delayed issuance of a CRDR.
The second example was documented in CRDR 9-8-0160.
Corrective actions were to train the engineering staff on the need to be more timely in issuing CRDRs. The team reviewed the CRDRs and verified the corrective actions to be completed and adequate.
,, E8.8 Closed Violation 50-528 -529 -530/9812-04:
Failure to Perform Transportability Reviews.
This violation identified 27 failures of the free air regulators for the instrument air system that were not reviewed for transportability. The licensee documented this issue in CRDRs 9-8-0337, 9-8-0730, and 9-8-0406.
In the root-cause analysis of CRDR 9-8-0337, the licensee found that this violation occurred as a result of an inadequate procedure that did not provide guidance on how to handle trends.
Specifically, licensee personnel did not believe a CRDR was necessary, because the issue was already identified in a trend report. The licensee revised Procedure 30DP-9WP02, "Work Document Development and Control," Revision 24, to clarify when a transportability CRDR should be initiated. As corrective actions to CRDR 9-8-0337, the licensee revised Procedure 73DP-OZZ03, "System and Maintenance Engineering,";
Revision 9, to include additional guidance to system engineers on transportability in the case of a trend of poor performance.
The transportability review of the instrument air problems described in CRDR 9-8-0406 were included in the corrective actions for
J
-35-CRDR 9-8-0337.
The issues documented in CRDR 9-8-0730 were duplicative and the corrective actions were subsumed in the corrective actions for CRDRs 9-8-0337 and 9-8-0406.
The team reviewed all three CRDRs and verified the corrective actions to be complete and adequate.
E8.9 Closed Ins ectionFollowu Item 50-528 -529 -530/9719-01: Lackofa10CFR50.59 Safety Evaluation for the Use of the FATES Computer Code.
The licensee provided information on the approval of the FATES 3B computer code in the NRC's safety evaluation report for the Combustion Engineering Topical Report CEN-161.
In addition, FATES 3B was reviewed and approved when the NRC reviewed and approved the licensee's "Reload Analysis Methodology for the Palo Verde Nuclear Generating Station." Prior approval by NRC precluded the need for a 10 CFR 50.59 safety evaluation; therefore, the team concluded that the licensee was not required to perform a 10 CFR 50.59 evaluation" in implementing the FATES 3B computer code.
E8.10 Closed Ins ection Followu Item 50-528/9719-03:
Lack of a 10 CFR 50.59 Safety Evaluation for the Deletion of Approximately 80 Emergency Plan Commitments.
During resolution of Action Item 5 of CRDR 9-7-Q257, licensee personnel identified 82 emergency plant commitments, which could have been deleted in error. After further review, this number was reduced to 71, counting duplicates.
The licensee found that no commitments were deleted and no changes were made; therefore, it determined that 10 CFR 50.59 safety evaluations were not necessary.
The licensee issued CRDR 9-7-0749 to address the generic aspect of this issue.
In processing CRDR 9-7-0749, 58 commitments were found unconnected to their actions, however, their actions were still contained in implementing procedures.
Specifically, the data base that related a commitment to a procedure action was corrupted in such a way
, one could not connect a commitment with the procedure words that implemented the commitment.
The licensee's design basis validation program also discovered that 140 regulatory commitment tracking system items had no apparent connection to a procedure or program action. Condition Report/Disposition Request 9-7-0749 was opened, and only three items were identified which required a connection to a commitment.
V. Mana ement Meetin s XI Exit Meeting Summary e
The team presented the preliminary inspection results in an exit meeting to members of licensee management on July 2, 1999.
Licensee management acknowledged the findings presented, and stated that they did not agree with the team's position on a potential violation of Technical Specification Surveillance Requirement 4.6.2.1.c.
Upon further review of this issue, the team agreed with licensee management and this
-36-potential violation as discussed in the exit meeting was not included in this report. With respect to a number of examples of failure to update design bases calculations when interdependent and/or source calculations were revised, licensee management stated that many of these changes were not significant enough to warrant expending engineering resources to revise them, and that the NRC should accept engineering judgement in establishing the need to revise calculations.
Subsequent to the exit meeting on July 2, 1999, inoffice inspection continued until September 1, 1999.
During the inoffice portion of the inspection, frequent discussions were held on a daily and/or weekly basis concerning the licensee's resolutions to certain issues documented in CRDRs. A supplemental onsite inspection was performed August 30 through September 2, 1999. A followup exit meeting was conducted by the team leader and acting branch chief via teleconference on September 30, 1999.
During that exit meeting, licensee management again stated that minor changes to design basis calculations that do not change the conclusions do not necessarily warrant expending engineering resources to process formal revisions to calculations.
The team leader asked whether any materials examined during the inspection should be considered proprietary.
Licensee's management stated that no proprietary information was reviewed by the tea ATTACHMENT Licensee SUPPLEMENTAL INFORMATION PARTIALLIST OF PERSONS CONTACTED l
A. Abbate, Instrumentation and Control Design Engineer G. Andrews, Shift Technical Advisor, Section Leader J. Barleycorn, DC System Engineer S. Bauer, Licensing Section Leader B. Blackmore, Containment Spray System Engineer T. Bradish, System Engineering Section Leader J. Brown, Design Engineer R. Buzard, Senior Consultant, Regulatory Affairs B. Hansen, Engineer M. Hodge, Section Leader, Design Mechanical P. Paramithus, Section Leader, Design Electrical and Instrumentation and Control M. Powell, Design Engineering Department Leader M. Radspinner, Section Leader, Design Mechanical E. Rivera, Electrical Maintenance Engineer I
NRCt D. Carter, Resident Inspector J. Moorman, Senior Resident Inspector D. Powers, Branch Chief, Engineering and Maintenance Branch INSPECTION PROCEDURES USED 93809 92903 Safety System Engineering Inspection (SSEI)
Engineering Followup ITEMS OPENED AND CLOSED OPENED TYPE DESCRIPTION 50-528; -529;
-530/9911-01 50-528; -529;
-530/9911-02 NCV NCV Four examples of a violation of 10 CFR Part'50, Appendix B, Criterion III (Sections E1.1, E1.2, and E1.4.2)
Violation of 10 CFR 50.49 (Section E1.2)
50-528; -529;
-530/9911-03 NCV Two examples of a violation of 10 CFR 50.71(e)
(Sections E1.2 and E1.4.2)
-2-50-528; -529;
-530/9911-04 NCV Three examples of a Violation of Criterion V (Sections E2.2.1 and E2.5)
CLOSED'YPE DESCRIPTION 50-528; -529;
-530/9911-01 50-528; -529;
-530/9911-02 50-528; -529;
-530/9911-03 50-528; -529;
-530/9911-04 50-528/9815-02 NCV NCV NCV NCV IFI Four examples of a violation of 10 CFR Part 50, Appendix B, Criterion III (Sections E1.1, E1.2, and E1.4.2)
Violation of 10 CFR 50.49 (Section E1.2)
Two examples of a violation of 10 CFR 50.71(e)
(Sections E1.2 and E1.4.2)
Three examples of a Violation of Criterion V (Sections E2.2.1 and E2.5)
Review of the Report on the Root Cause of the Letdown Line Failure (Section E8.3)
50-528/9814-06 50-528/98-007-01 and -02 LER NOV Letdown Line Break Due To Pressure Transients (Section E8.3)
Five Examples of Failure to Meet TS 3.5.2 (Section E8.4)
50-528/9814-07 50-528/9814-08 50-528/9812-01 50-528/9812-04 50-528/9719-01 50-528/9719-03 NOV NOV NOV NOV IFI IFI Two Examples of HPSI Pump Discharge Check Valves Condition Adverse to Quality (Section E8.5)
Two Examples of HPSI Discharge Check Valve Procedures (Section E8.6)
Two Examples of the Failure to Implement Procedure 90DPOIP10 (Section E8.7)
Failure to Perform Transportability Reviews (Section E8.8)
Lack of a 10 CFR 50.59 Safety Evaluation for the Use of FATES Computer Code (Section E8.9)
Lack of a 10 CFR 50.59 Safety Evaluation for the Deletion of Approximately 80 Emergency Plan Commitments (Section E8.10)
-3-DOCUMENTS REVIEWED 05DP-ONF22 05TD-ONF05 NFM (Nuclear Fuel Management) Design Control SABD (Safety Analysis Bases Document) Maintenance 30DP-9WP02 Work Document Development and Control PROCEDURES NUMBER DESCRIPTION 05DP-ONF09 Nuclear Fuel Management Analyses Control REVISION Revision 08 Revision 05 Revision 00 Revision 24 31MT-9ZZ17 Disassembly and Assembly of Borg-Warner Check Valves Revision 06 32ST-9PK03 18 Month Surveillance Test of Station Batteries 32ST-9PK04 60 Month Surveillance Test of Station Batteries 40DP-9OP26 Operability Determination 40EP-9EO03 Loss of Coolant Accident 40EP-9EO05 Excess Steam Demand 40ST-9ZZ13 Containment Isolation Valves 73DP-OZZ03 System and Maintenance Engineering 73ST-9CL01 Containment Leakage Type 'B'nd 'O'esting 73ST-9SG01 MSIVS - Inservice Test 73ST-9SI06 Containment Spray Pump and Check Valves - Inservice Test 73ST-9SI15 Containment Spray Pump Full Flow - Inservice Test 73ST-9XI01 S¹1 Containment Isolation Valves - Inservice Test 73ST-9XI02 SG ¹2 Containment Isolation Valves'- Inservice Test 73ST-9XI05 AF and CT Valves - Inservice Test 73ST-9XI06 CH and SS Valves - Inservice Test 73ST-9XI07 GA, GR, RD, and WC Valves - Inservice Test 73ST-9XI08 HC & HP Valves - Inservice Test 73ST-9XI13 Train A HPSI Injection and Miscellaneous Sl Valves 73ST-9XI14 Train B HPSI Injection and Miscellaneous Sl Valves Revision 17 Revision 18 Revision 07 Revision 06 Revision 05 Revision 00 Revision 09 Revision 06 Revision 09 Revision 06 Revision 06 Revision 20 Revision 20 Revision 11 Revision 07 Revision 07 Revision 02 Revision 09 Revision 09
1'
-4-PROCEDURES NUMBER DESCRIPTION 73ST-9XI16 Economizer FWIVS - Inservice Test 73ST-9XI19 Downcomer FWIVS - Inservice Test 73ST-9XI21,Shutdown Cooling a'nd Miscellaneous Sl Valves 73ST-9XI22 CH Valves - Inservice Test 73ST-9XI23 CP, EW, IA, and NC Valves - Inservice Test REVISION Revision 10 Revision 04 Revision 18 Revision 08 Revision 04 73ST-9XI35 HPSI Pump Discharge Check Valve Closed Exercise Test Revision 06 74ST-9SS02 Post Accident Sampling System Leakage Monitoring 81DDP-OCC05 Design and Technical Document Control 81DP-4CC04 Calculations 81DP-ODC17 Temporary Modification Control e
81DP-OEE10 Plant Modifications 81DP-4CC04 Calculations 90DP-001P03 Condition Report Screening and Processing 93DP-OLC03 Licensing Document Maintenance 93DP-OLC07 10 CFR 50.59 Screenings and Evaluations Revision 12 Revision 21 Revision 12 Revision 05 Revision 03 Revision 11 Revision 16 Revision 06 Revision 02 DESIGN BASIS DOCUMENTS TYPE TITLE/DESCRIPTION REVISION Design Basis Manual Containment Integrity (Leakage and Isolation) Topical Revision 4 Design Basis Manual Containment Hydrogen Control System Revision 5 Design Basis Manual Design Basis Manual, "Safety Injection System" Revision 12
-5-CALCULATIONS NUMBER 13-JC-CH-206 13-JC-CH-209 01-EC-PK-207 02-EC-PK-207 03-EC-PK-207 13-EC-PK-203 13-JC-CH-215 13-JC-SB-202 13-JC-Sl-215 DESCRIPTION REVISION Setpoint and Total Loop for Uncertainty Refueling Water 3 and 4 Tank Level Loops JCHALLOOP0200 and JCHBLOOP0201 Refueling Water Tank Level Instrument (Chx-L-203x, x=A, 3 and 4 B, C, D) Setpoint and Uncertainty Calculation Unit 1 DC Battery Sizing and Minimum Voltage
Unit 2 DC Battery Sizing and Minimum Voltage Unit 3 DC Battery Sizing and Minimum Voltage Four Hour Battery Calculation Refueling Water Tank Temperature Instrument (CHN-T-200 & 201) Setpoint and Uncertainty Calculation Acceptance Criteria for RPS and ESFAS Response Time
Testing Containment Spray Pump Train A and B Discharge Flow
Indication Loops (SIA-F-338 & SIB-F-348) Uncertainty Calculation 13-JC-SI-218 13-JC-SI-224 13-JC-SI-228 13-JC-SI-229 13-MC-CH-201 13-MC-SI-015 13-MC-SI-018 Containment Spray Header Water Level Loop J-SIN-L-0704/0705 Setpoint and Uncertainty Calculation Post Accident Monitoring Containment Water Level Instrument (SIA-L-706 & SIB-L-707) Uncertainty Calculation Containment Sump Temperature Loop (13-J-SIN-T-LOOP-0712 & 0713) Setpoint and Uncertainty Calculation
Shutdown Cooling Heat Exchanger Outlet Temperature Instrument (SIA-T-303X; SIB-T-303Y) Uncertainty Calculation Refueling Water Tank (RWT), Hold-Up Tank (HT) and Reactor Makeup Water Tank (RMWT) Sizing Shutdown Cooling System Interface Requirements Containment Spray System Interface Requirements Calculation 1 and 2
-6-CALCULATIONS NUMBER 13-MC-SI-207 13-MC-SI-220 13-MC-SI-230 13-MC-SI-309 DESCRIPTION Containment Recirculation Sump & Screen Size CS Pump Full Flow Test Criteria Process Limit CSS Maximum Flow Rate Evaluation Emergency Sump Screen Blockage REVISION 13-MC-Sl-310
'ontainment Spray Header Piping Design Pressure
Temperature 13-MC-SI-804 13-NC-SI-202 SO-PEC-012 SP-PEG-135 SP-PEC-155 SP-PEC-160 SP-PEC-202 V-FS-C-049 V-PEG-130 V-PEC-234 V-PEG-241 V-PEG-242 Containment Building Water Level During LOCA Containment Spray System Response and Header Fill Time Minimum Required Throttled Valve Position for CVS, CSP,
SDC8 LP Throttling of SIS, SCS and CSS Valves and Cavitation Potential Containment Spray System Hydraulic Calculation
Containment Spray System Spray Distribution System Functional Survey for Iodine Removal System
Unit 3 LPSI and CS Pump Curves Based on Actual Testing
Containment Spray Header Delay Time CS Spray Nozzle Transients Unit 2 LPSI and CS Pump Curves Based on Actual Testing
CS Pump Performance for Unit 1 and TS for CSP Shutoff
Head DRAWINGS NUMBER 01-M-SIP-001 DESCRIPTION P & I Diagram Safety Injection & Shutdown Cooling System REVISION
-7-DRAWINGS NUMBER 01-M-CHP-001 01-E-PKA-001 01-E-PKA-002 01-E-PKA-003 01-E-PKA-004 01-E-PKA-005 01-E-PKA-006 01-E-PKA-007 01-E-CHB-029 Sh
01-E-CHB-029 Sh 2 01-E-SIB-017 Sh 2 01-E-SIB-020 Sh
01-E-SIB-020 Sh 2 01-E-SIB-021 Sh
01-E-SIB-021 Sh 2 01-E-SIB-022 Sh
01-E-SIB-022 Sh 2 J
01-E-SIB-024 Sh
01-E-SIB-024 Sh 2 01-E-SIB-025 Sh
DESCRIPTION P L I Diagram Chemical and Volume Control System 125V DC Class 1E and 120V AC Vital Instrument Power Main Single Line Diagram 125V DC Class 1E Power System DC Control Center 1E-PKA-M41 Single Line Diagram 125V DC Class 1E Power System DC Control Center 1E-PKA-D21 Single Line Diagram 125V DC Class 1E Powe'r System DC Control Center 1E-PKC-M43 Single Line Diagram 125V DC Class 1E Power System DC Control Center 1E-PKB-M42 Single Line Diagram 125V DC Class 1E Power Distribution Panel 1E-PKB-D22 Single Line Diagram 125V DC Class 1E Power System DC Control Center 1E-PKD-M44 Single Line Diagram Valve 1 J-CHB-HV-530 Elementary Diagram Valve 1 J-CHB-HV-530 Elementary Diagram Valve 1J-SIB-UV-665 Elementary Diagram Valve 1 J-SIB-UV-671 Elementary Diagram Valve 1 J-SIA-UV-672 Elementary Diagram Valve 1J-SIA-UV-673 Elementary Diagram Valve 1J-SIB-UV-675 Elementary Diagram Valve 1J-SIA-UV-674 Elementary Diagram Valve 1 J-SIB-UV-676 Elementary Diagram Valve 1 J-SIA-HV-687 Elementary Diagram Valve 1 J-SIA-HV-695 Elementary Diagram Valve 1 J-SIA-HV-684 Elementary Diagram REVISION
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-8-DRAWINGS NUMBER 01-E-SIB-025 Sh 2 13-J-041-145 DESCRIPTION Valve 1J-SIB-HV-665 Elementary Diagram Head-Type Primary Flow Elements REVISION P&ID Diagram 01-M-SIP-00 Safety Injection & Shutdown Cooling System
P&ID Diagram 01-M-SIP-003 Safety Injection & Shutdown Cooling System
OPERABILITYDETERMINATIONS NUMBER REVISION 017 Revision 2 020 Revision 0 072 Revision 2 078 Revision 2 085 Revision
091 Revision 0 098 Revision 0 113 Revision
124 Revision 0 126 Revision 0 129 Revision 0 132 Revision 0 133 Revision 2 160 Revision 2 161 Revision 0 162 Revision 0 180 Revision
183 Revision 0 and Revision 4
OPERABILITYDETERMINATIONS NUMBER REVISION 193 197 203 214 226 Revision
Revision 2 Revision 2 Revision 0 Revision 0 Revision 0 DESIGN CHANGES/MODIFICATIONS NUMBER DESCRIPTION REVISION/DATE 13-LE-SI-202 13-LJ-SI-204 1-LJ-SI-204 Delete Spray Chemical Addition System Removal of Auto-Close Interlock for Shutdown Cooling Removal of Auto Closure Interlock from SDC Suction
Valves (SIA-UV-651,655; SIB-UV-652, 656; SIC-UV-653; SID-UV-654)
EDC 99-00457 U2 Sl Installed Orifice Size Different From Design Drawings DMWO 806536 Vital Battery Replacement October 15, 1998 Amendments 1-7 EDC 99-00240 ModifyContainment Spray Header Level Low Alarm
Setpoint SAFETY EVALUATIONS NUMBER 99-00046 99-00041 DESCRIPTION LDCR 99-F018 Revision 13 to 40OP-9SI01 Containment spray header low water level alarm set point change (DMWO ff00870365)
DATE/REVISION March 26, 1999 March 31, 1999
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-10-SAFETY EVALUATIONS NUMBER DESCRIPTION DATE/REVISION 99-00021 98-00078 98-00043 Temporary power during the Class 1E, PK system battery and battery rack replacement T-Mods 1-98-CI-010, 2-98-CI-005, 3-98-CI-005 Temporary modification implemented via a Procedure 31 MT-9IA03 March 12, 1999 May 5, 1998 March 6, 1998 98-00017 LDCR 98-F004 98-00011 97-00274 T Mods 1-98-001, 2-98-CI-001, and 3-98-Cl-002 Reanalysis of ECCS and CSS NPSH and incorporation into PVNGS UFSAR February 11, 1998 January 24, 1998 October 18, 1998 97-00269 97-00238 97-00136 96-00258 97-00174 Revision of UFSAR Section 6.2.4.2 and Table 6.2.4-2, Containment Isolation System SARCN 3808 to PVNGS UFSAR and Technical Specification Bases for RWT ESF reserve volume Revise UFSAR to remove required performance test of Class 1E batteries during U2R7 Change to UFSAR Sections 3.1.36, 6,5.2.7(A)7.13.16, and 6.5.2.8(RA)7.13.16 per CRDR 960811 Replace Existing class 1E batteries (AT&Tround cells)
with rectangular cells in all 3 units December 19, 1997 November 14, 1997 June 27, 1997 July 10, 1997 Revision 3 ENGINEERING SCREENINGS FOR SAFETY EVALUATIONS DESCRIPTION A-36 tensile of battery rack Torque of valve bolts Install gasket to meet EQ Editorial changes to UFSAR Change stroke time on Valve 2JSGAUV0134A Repair valve Repair of MOV DATE/REVISION December 24, 1998 November 20, 1998 November 17, 1998 December 16, 1997 January 20, 1998 March 20, 1998 October 17, 1998
-11-Accept as is range of band settings Vendor document package revision UFSAR Revision 9 Cl Table 6.2.4-2 Change operator size October 8, 1998 October 1, 1998 August 5, 1997 October 2, 1997 TEMPORARY MODIFICATIONS NUMBER A-97-NA-002 1-98-RC-003 I-98-RC-008 I-98-SH-009 2-98-RC-004 3-98-FW-001, 3-98-RC-001 3-99-SC-003 REVISION October 23, 1997 February 9, 1998 April 18, 1998 April 23, 1998 April 2, 1998 January 17, 1998 January20, 1998 February 17, 1999 CONDITION REPORT/DISPOSITION REQUEST NUMBER DATE CRDR 2-5-0256 July 25, 1995 CRDR 3-7-0216 April29, 1997 CRDR 9-6-1303 November 8, 1996 CRDR 9-7-1899 December 10, 1997 CRDR 9-7-Q257 May 8, 1997 CRDR 9-7-0749 May 30, 1997 CRDR 2-7-0420 October 28, 1997 CR DR 1-8-0238 April 10, 1998 CRDR 9-8-0730 April 16, 1998
-12-CONDITION REPORT/DISPOSITION REQUEST NUMBER CR DR 9-8-1294 CRDR 9-8-1306 CRDR 9-8-1379 DATE August 17, 1998 August 18, 1998 August 27, 1998 CRDR 9-8-0160 February 3, 1998 CRDR 9-8-0337 CR DR, 9-8-0338 CRDR 9-8-0368 CR DR 9-8-0391 CRDR 9-8-0512 CRDR 9-8-0406 February 27, 1998 February 27, 1998 March 9, 1998 March 10, 1998 March 13, 1998, March 18, 1998 CRDR 9-8-0443 March 19, 1998 CRDR 1-8-0322 May 20, 1998 CRDR 9-8-0862 CRDR 9-8-1674 CRDR 9-8-1463 CRDR 9-8-1460 CRDR 9-8-1514 CRDR 2-9-0081 CRDR 9-9-Q037 CRDR 9-9-0778 CRDR 9-9-0776 CRDR 9-9-0672 CRDR 9-9-0673 CRDR 9-9-0693 CRDR 9-9-0696 May 29, 1998 September 2, 1998 September 9, 1998 September 11, 1998 September 23, 1998 April7, 1999 February 25, 1999 July 1, 1999 July 1, 1999 June 13, 1999 June 15, 1999 June 16, 1999 June 17, 1999
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-13-CONDITION REPORT/DISPOSITION REQUEST NUMBER CRDR 9-9-0699 DATE June 17, 1999 CRDR 9-9-0730 June 23, 1999 CRDR 9-9-0755 CR DR 9-9-0765 CR DR 9-9-0763 CRDR 9-9-0771 CRDR 9-9-0285 June 28, 1999 June 29, 1999 June 29,1999 June 30, 1999 March 16, 1999 CRDR 9-9-0275 March 16, 1999 CRDR 9-9-031 1 March 23, 1999 CRDR 9-9-0564 May 19, 1999 CRDR 9-9-0584 May 21, 1999 MISCELLANEOUS DOCUMENTS NUMBER DESCRIPTION REVISION/DATE DSG-IC-0205 Design Guide for Instrument Uncertainty and Setpoint Revision 8 Determination 13-JS-A65 Setpoint Project Final Report Revision
V-CE-10410 AuxiliaryFeedwater Actuation System Cycling NUREG 0857 Palo Verde Nuclear Generating Station Safety Evaluation Report May 15, 1980 Original with Supplements
through 12 Regulatory Guide 1.97 Instrumentation for Light-Water-Cooled Nuclear Power Plant and Environs Conditions During and Following an Accident Revision 2 ST-95-0536 ABB Combustion Engineering Nuclear Power Letter; September 15, Subject: Impact of Increased Containment Spray 1995 Flow on the PVNGS ECCS Performance Analysis
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e-14-MISCELLANEOUS DOCUMENTS NUMBER N/A N/A N/A N/A N/A N/A 038409 DESCRIPTION Palo Verde Nuclear Engineering Goal Summary for April and May 1999 Updated'Final Safety Analysis Report Technical Requirements Manual Palo Verde Nuclear Generating Station Units 1, 2, and 3, Technical Specifications Palo Verde Nuclear Generating Station, Units 1, 2, and 3, Technical Specifications Bases.
Palo Verde Engineering 1999 Strategic Plan Preventive Maintenance Task which was used on June 9, 1999, to calibrate the Unit 2 high pressure safety injection hot-leg flow transmitter REVISION/DATE N/A Revision 9 Revision 0 Amendment 117 Revision 0 N/A N/A
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