IR 05000382/1999006
| ML20206U794 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 05/18/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20206U790 | List: |
| References | |
| 50-382-98-201, 50-382-99-06, 50-382-99-6, NUDOCS 9905260016 | |
| Download: ML20206U794 (37) | |
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ENCLOSURE U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
l Docket No.:
50-382 l
License No.:
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Report No.:
50-382/99-06 Licensee:
Entergy Operations, Inc.
Facility:
Waterford Steam Electric Station, Unit 3 l
Location:
Hwy 18 Killona, Louisiana
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l Dates:
April 5 to 9,1999
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Team Leader:
C. J. Paulk, Senior Reactor Inspector Engineering and Maintenance Branch l
Inspector:
P. A. Goldberg, Reactor inspector
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Engineering and Maintenance Branch Accompanying B. R. Gupta, Consultant, Beckman & Associates Personnel:
D. Prevatte, Consultant, Beckman & Associates Approved By:
Dr. Dale A. Powers, Chief Engineering and Maintenance Branch Attachment:
SupplementalInformation
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5260016 990518 p
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K 050003e2 PDR
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-2 EXECUTIVE SUMMARY Waterford Steam Electric Station, Unit 3 NRC Inspection Report No. 50-382/99-06 This inspection was performed, primarily, to address the issue previously identified during an architect engineering inspection which was documented in NRC Inspection Report 50-382/98-201, in addition, other previously identified issues were reviewed.
Enaineerina A noncited violation of Technical Specification 3.3.3.6 was identified for the failure to
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have positive indication for the hydrogen recombiner analyzer containment isolation valve position (Section E8.3).
A noncited violation of Technical Specification 6.8.1 was identified for four examples of
inadequate procedures (Sections E8.4, E8.8, E8.14, and E.23). The first example was for failure to adequately address instrument uncertainties in the surveillance tests for chilled water outlet temperature. The second example was for a human error that resulted in steps being rearranged in Procedure OP-903-110,"RAB Fluid Systems Leak Test." The third example was for the failure to establish a procedure to demonstrate the requirements for ASME emergency feedwater check valve closure. The fourth example was for the failure to establish and implement procedures to assure that instrumentation with the appropriate total loop accuracy was used in the performance of inservice testing of safety-related pumps.
A noncited violation of Criterion lll of Appendix B to 10 CFR Part 50 was identified for
three examples of inadequate design control (Sections E8.5, E8.6, and E8.12). The first example was for the failure to maintain drawings to reflect actual plant configurations.
The second example was for the failure to provide adequate overpressure protection for the ASME Class lit portion of the nitrogen system. The third example was for the failure to translate the effects of condensate storage pool level instrument errors under dynamic conditions into the emergency operating procedures.
An unresolved item was identified concerning the ability to demonstrate that adequate
flows could be developed to meet design requirements when total loop uncertainties (e.g., process fluid density, system flow resistance, total instrument loop uncertainties, etc.) were considered for pumps in the following systems: high pressure safety injection, auxiliary component cooling water, component cooling water, chemical and volume control, essential chilled water, and emergency feedwater (Section E8.23).
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Report Details lil. Enaineerina
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E8 Miscellaneous Engineering issues (92903)
i E8.1 (Closed) Unresolved item 50 382/9725-01: high pressure safety injection and
containment spray systems' net-positive suction head inaccurately stated in the safety analysis report.
This it% was opened during the performance of a core inspection of engineering i
activities. The team noted that the licensee had identified these discrepancies, but failed to state that the discrepancies were identified during the review of Generic Letter 97-04," Assurance of Sufficient Net Positive Suction Head for Emergency Core Cooling and Containment Heat Removal Pumps." At the time of the previous inspection, the licensee was in the process of reviewing the generic letter, plant configurations, and design calculations.
During the reviews, the licensee identified the discrepancies discussed in NRC Inspection Report 50-382/97-25. At the time of the previous inspection, the licensee had not completed the reviews and was in communication with the Office of Nuclear Reactor Regulation regarding some of the findings.
This team reviewed License Document Change Request 97-0212, which was approved by the licensee's plant oversight review committee on July 29,1998. The team found that the safety evaluation performed for this change met regulatory and licensee requirements.
The team determined that the licensee was in the process of correcting discrepancies identified through generic communications. The team found that, while there were discrepancies in the safety analysis report, the discrepancies were minor and had no effect on safety.
E8.2 (Closed) Unresolved Item 50-382/9725-03: operability of feedwater isolation valves.
This item was opened because NRC inspectors questioned the practice of the licensee using an assumed valve factor friction coefficient of 0.31 to justify the operability of the feedwater isolation valves under a blow down condition. This questioning was based on data obtained during testing by other licensees and industry groups on motor-operated valves that indicated the valve factor friction coefficient should be approximately 0.4.
The team noted that the licensee had data from industry testing that had mixed results from the position taken by the previous intpectors. In the Electric Power Research Institute Report TR-103237-R2, " Method for Anchor / Darling Double Disk Gate Valves,"
the data agreed with the previous inspe-tors. In the Electric Power Research Institute Report TR 103229-R2," Gate Valve Report," Appendix E provides information that valves operating at higher temperatures exhibited significantly lower valve factor friction
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-4 coefficients. And, the Electric Power Research Institute Report TR-103119,"EPRI MOV Performance Prediction Program Friction Separate Effects Report," also indicated that valves with approximately the same stress, operating at, or above 97*C (206'F), also had significantly lower valve factor friction coefficients.
During discussions with licensee representatives, the team learned that, even though the licensee was confident in the operability of the feedwater isolation valves, changes were intended to be implemented during the next refueling outage that would result in the valves being capable of functioning with a valve factor friction coefficient of 0.4.
These actions included any or all of the following: rnodification of the actuator; performance of dynamic analysis; installation of a safety-related feed pump trip; reduction of system pressure; demonstration that shutoff head is not reached within 5 seconds of the accident; and requesting credit for the nonsafety-related reactor trip override signal.
The NRC team agreed with the licensee's position that there is no operability concern.
E8.3 (Closed) Licensee Event Reoort 50-382/97-031: hydrogen analyzer valve ;sosition indication.
Licensee Event Report 97-031, Revision 0, was prepared to report that the configuration of the limit switches for the hydrogen recombiner analyzer valves did not meet the requirements of Technical Specification 3.3.3.6 for containment isolation valve position indication. Hydrogen Recombiner Analyzer Valves 109A&B,110A&B, and 126A&B were containment isolation valves using one channel of indication for the Train A valves and one channel for the Train B valves.
A licensee engineer stated that the control wiring diagrams for the valves indicated that the limit switches were wired in series. This configuration provided indication when the first valve reached the open/close position and the other valves were still in travel. In addition, if any valve was fully open and another fully closed, then no lights would be illuminated. The licensee engineer stated that, to resolve the problem, the wiring was changed for the limit switches from series to parallel in order to provide positive indication when all three valves completed travel to the open/close position or when one valve was fully open and another fully closed.
The team reviewed Condition Report CR 97-2641, dated November 20,1997, which identified that the position indication for the hydrogen recombiner valves was faulty. In addition, the team reviewed Work Authorization WA01165734/Cl 313735, dated December 12,1997, which repaired the position indication for the valves by rewiring the
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limit switches from series to parallel. Technical Specification 3.3.3.6 requires positive indication of valve position. Additionally, the licensee committed to following the guidance of Regulatory Guide 1.97," Instrumentation for Light-Water-Cooled Nuclear
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Power Plants To Assess Plant and Environs Conditions During and Following an Accident," Revision 3, which states that containment isolation valves have positive valve position indication. By rewiring the limit switches in parallel, which would give a green light when all of the valves were closed, a red light when all of the valves were opened, and both red and green lights when the valves were in travel, there would always be a positive indication of valve position.
The team identified this as a violation of Technical Specification 3.3.3.6 for the failure to have positive indication for containment isolation valve position. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. The corrective actions were completed in Condition Report CR-97-2641 (50-382/9906-01).
E8.4 (Closed) Licensee Event Report 50-382/98-007: chilled water instrument uncertainty.
Licensee personnel discovered that no allowance for instrument uncertainty was included in the surveillance for chilled water outlet temperature. Technical Specification 4.7.12.1b. requires the essential chilled water outlet temperature to be s 5.6*C (42*F) at a flow 21892.7 Lpm (500 gpm). The temperatures were read from control board indicators whose instrument uncertainty was determined to be 2.68 C (4.83*F). A subsequent evaluation of previous data indicated the technical specification temperature limit had been exceeded for periods greater than the allowed outage time because the instrument loop uncertainty was not considered in the surveillance test.
Results of the evaluation showed that the temperature limit was exceeded for greater tha 172 hours0.00199 days <br />0.0478 hours <br />2.843915e-4 weeks <br />6.5446e-5 months <br /> on three separate occasions in 1997.
The temperature readings were being taken locally using instrumentation with an uncertainty of less than 0.33*C (0.6"F). The surveillance acceptance criteria has been adjusted to reflect this uncertainty to ensure the 5.6*C (42*F) limit is maintained.
The team noted that Repetitive Work Task 021438 did not support the surveillance
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requirement for Technical Specification 4.7.12.1b. to ensure the environmental temperature limits in areas containing safety-related equipinent were not exceeded.
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This repetitive task was initiated to support surveillance testing as required by Technical Specification 6.8.1. Technical Specification 6.8.1 requires, in part, that written procedures shall be established and implemented for the performance of surveillance and test of safety-related equipment.
The team reviewed the licensee's corrective actions that were discussed in the event report in its letter, W3F1-98-0051, dated April 16,1998. The team found the corrective actions to be appropriate to address the issue of instrument inaccuracies.
The failure to adequately address instrument uncertainties in surveillance tests was identified as an example of a violation of Technical Specification 6.8.1 for an inadequate procedure to (50-382/9906-02). This Severity Level IV violation is being treated as an exarnple of a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. The corrective actions have been complete.
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-6 E8.5 (Closed) Licensee Event Reoort 50-382/98-009: inadvertent engineered safety features actuation.
On April 15,1998, an inadvertent engineered safety feature actuation occurred. The actuation was initiated by electrical maintenance personnel who were replacing a relay.
During this activity, a wire was incorrectly lifted from a terminal point on the relay which caused another relay to deenergize and generate the engineered safety feature signal.
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The team reviewed the event report and discussed the event with a licensee representative. The team noted that the licensee had determined the root cause of the event to have been inadequate configuration controlin that the physicallocation of the relay wiring did not match the information shown on the plant drawing. The team found
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this root cause determination to have been of sufficient depth and detail as to support the licensee's conclusion.
l The team reviewed the licensee's corrective actions and found them to be appropriate to the significance of the event and complete. The team found the failure to maintain drawings to reflect actual plant configurations to have been a violation of Criterion lli of Appendix B to 10 CFR Part 50 (50-382/9906-03). Criterion ill requires, in part, that measures shall be established to assure that plant configuration be correctly translated into drawings. This Severity Level IV violation is being treated as an example of a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. The corrective actions have been completed.
E8.6 (Closed) Licensee Event Report 50-382/98-010: potential over pressurization of the nitrogen system.
(Closed) Unresolved item 50-382/98201-22: potential over pressurization of the nitrogen system.
The Emergency Feedwater Flow Control Valves EFW-223A&B, and EFW-224A&B, and Emergency Feedwater Isolation Valves EFW-228A&B and EFW-229A&B are controlled by instrument air and backed up by a nonsafety-related nitrogen supply system. The team identified that the failure of a nonsafety related pressure regulator in the nitrogen system could affect the safety-related function of both trains of the emergency feedwater system flow control and isolation valves since Relief Valve NG-149, used to protect the safety system, was nonsafety, noncode and undersized. The pressure rating of the safety-related ASME Class 3 components was 5515.8 kPa (800 psig). The nonsafety-related regulator reduced nitrogen pressure from 17236.9 kPa (2500 psig) to approximately 5171.1 kPa (750 psig), for delivery to multiple loads, including the safety-related air-operated valve accumulators for both trains. Failure of the pressure regulator with an undersized relief valve would cause the ASME Section lli components with the 5515.8 kPa (800 psig) design pressure to be exposed to the 17236.9 kPa (2500 psig).
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-7 The team reviewed Condition Report CR-98-0684, dated May 14,1998, which documented that no safety relief protection existed for the safety-related portion of the nitrogen system. Condition Report CR-98-0683, dated May 14,1998, documented that the existing nonsafety-related relief valve was undersized and could not provide adequate protection. The undersized relief valve was a design error from the original design.
The licensee's initial corrective action was to place Relief Valve NG-1506, an appropriately sized ASME Section Vill relief valve in a connecting line, in service.
However, the licensee did not realize that the isolation valve upstream of Relief Valve NG-1506 was a reduced-port valve and would restrict the flow, which could cause the pressure in the safety-related components to exceed design conditions.
The team reviewed Condition Report CR-98-0706, dated May 18,1998, which l
documented that the isolation valve was a reduced-port valve and would restrict the flow to the rdef valvc. The licensee's immediate corrective action was to remove the liquid nitrogen supply from service ar d align the nitrogen tube trucks for which the relief valve I
was adequate. The licensee's permanent corrective action was to add an appropriately sized ASME Section ill relief valve to the nitrogen supply line to implement a modifeilon to protect the ASME Section ill portion of the system. Relief Valve NG-1523 was added in September 1998. Until the ASME Section ill relief valve was added, there was no ASME Section 111 relief valve protecting the safety-related components, as required by the ASME Section lli code.
The team reviewed Calculation EC-P98-005, * Evaluation of Nitrogen System for Over Pressurization," Revision 0, which evaluated and qualified the lower pressure safety-related portions of the nitrogen system for a faulted pressure of 17409.3 kPa (2525 psig) for past operability. The team found that the assumptions in the calculation were in agreement with the requirements of the ASME Code, Section Ill.
The team identified the failure to provide adequate over pressure protection for ASME Section 111 components as a violation of 10 CFR Part 50, Appendix B, Criterion Ill, design control (50-382/9906-03). This Severity Level IV violation is being treated as another example of a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation was in the licensee's corrective action program as Condition Report CR-98-0706.
E8.7 (Closed) Unresolved item 50-382/98201-01: single failure analysis.
During the architect engineering inspection, the inspectors questioned the appropriateness of the licensee not evaluating three different functions for single failures. The first function was associated with a safety injection signal and the failure of a throttle valve to fail in the full-open position. The second function was associated with the recirculation actuation signal and the failure of a low pressure safety injection pump to trip. The third function was also associated with the recirculation actuation signal, but was for the failure of a containment sump isolation valve to ope '
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-8 The licensee responded to each of these issues in a letter dated October 27,1998, from Mr. C. M. Dugger, Vice President, Operations, Waterford 3, to the NRC Document Control Desk. This team reviewed the response letter and interviewed licensee personnel.
With respect to the first issue, the team noted that the licensee had performed a new calculation to determine the maximum expected low-pressure safety injection flow with the failure of a throttle valve. The team observed that the max mum low pressure flow used for the net-positive suction head calculation, the large break loss-of-coolant-accident analysis, and pump and motor sizing, bounded the expected flow with the throttle valve failed open. Therefore, the team found that this issue was not valid.
With respect to the second issue, the team noted that the licensee was preparing a j
calculation to determine the limits for the refueling water storage pool. Through discussions with a licensee engineer, the team leamed that the preliminary results j
indicated that the refueling water storage pool water level would not drop to the point where vortexing would occur if a low-pressure safety injection pump failed to trip.
The team noted that this analysis was conservative because it used a slower than actual stroke time for the sump isolation valves. It also contained conservatism in that there would be full flow through the sump isolation valve when the valve was approximately 50 percent open. Another factor the team noted was, at the time the recirculation actuation signal would be received, the containment pressure would be greater than the static head of the refueling water storage pool. This would result in water being drawn from the containment sump rather than from the refueling water storage pool.
Therefore, the team found this issue was not valid.
With respect to the third issue, the team learned that it had been evaluated during the licensing of the plant in NRC Ouestion 211.71.4. In the response to the question, the team noted that the single failure of the low-pressure safety injection pump would not
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affect the transfer criteria from the refueling water storage pool, but would affect the time when the recirculation begins.
Further, the response states that should a containment sump isolation valve fail to open, an alarm would annunciate in the control room and the operator could secure the respective emergency core cooling pumps to prevent damage. The tearn also found this issue was not valid.
E8.8 (Closed) Unresolved item 50-382/98201-02: emergency core cooling system leakage acceptance criteria.
During the architect engineering inspection, the inspectors identified a concern that as-found leakage was not being quantified prior to securing or reducing the leakage and, therefore, was not consistent with the safety analysi,
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-9 The team noted that the licensee acknowledged that a human error resulted in steps being rearranged in the procedure for performing leak tests. The team reviewed Procedure OP-903-110, "RAB Fluid Systems Leak Test," Revision 4, which corrected the error identified during the architect engineering inspection.
Technical Specification 6.8.1 requires, in part, that written procedures shall be established and implemented for the performance of surveillance and test of safety-related equipment. The failure to establish a procedure that would not meet the i
requirements of the technical specification surveillance was identified as another example of a violation of Technical Specification 6.8.1 (50-382/9906-02). This Severity Level IV violation is being treated as an example of a noncited violation, consistent ufith
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Appendix C of the NRC Enforcement Policy. The corrective actions have been completed.
E8.9 (Closed) Unresolved item 50-382-98201-03: dose consequences of refueling water storage pool back-leakage.
During the architect engineering inspection, the inspectors identified a concern that inappropriate design-basis assumptions were used for the determination of acceptable emergency core cooling system valve leakage limits. This concern was related to the licensee's consideration of the operation of the reactor auxiliary building ventilation system to maintain control room doses below regulatory limits.
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The team noted that the licensee revised the dose calculations for the control room, deleting the credit for the ventilation system. The team found the results to have been within regulatory requirements.
E8.10 (Closed) Unresolved item 50-382/98201-04: containment sump isolation valves leakage.
During the architect engineering inspection, the inspectors identified a concern that inadequate testing was being performed on containment sump isolation Valves SI-602A and B to assure that their seat leakage was within the allowable value, and that they were not being leak tested in the as-found condition. This team reviewed Calculation EC-S91-016, "SI-602 Leakage Study," Revision 0, which the licensee determined the maximum allowable air leakage of containment sump suction valves during the initial stages of a loss-of-coolant accident, before the containment sump would be filled above the suction inlets. The team noted that the allowable leakage, as defined by 10 CFR Part 50, Appendix J, was 15 times les than the amount of leakage necessary to impact pump operation. It was on this basis that the licensee categorized the sump isolation valves as Category B valves not requiring leak rate testing.
This team found th 1, because the sump isolation valves were Category B vaives, there was no regulatory requirement to perform as-found leak rate testing. The team noted that the repetitive work task that was used to replace the elastomer valve seat every third refueling outage specified that an as-left bubble test is to be performed. The acceptance criterion for this test was no leakage (i.e., no bubbles).
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-10 While questions arose with respect to the amount of leakage necessary to impact pump operation during both the injection phase and the recirculation phase, the team did not identify a safety concern. The team did note that, while the licensee's engineers had not analytically determined the critical amount of air, they did address the issue qualitatively.
j Specifically, the questions were related to the different combinations of valve leakage and the most limiting accident scenario. The team noted that there were three accident scenarios that would lead to filling the containment sump with water and pressurizing the
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containment. These scenarios were large and small break loss-of-coolant accidents i
and main steam line breaks inside containment. Neither the safety analysis nor the i
accident analysis discussed the need for using the recirculation mode of safety injection j
for main steam line breaks inside containment.
For a small break loss-of-coolant accident, the licensee may switch to the recirculation mode of safety injection if the plant cannot be maintained on shutdown cooling without the need for makeup (i.e., the leak has not been isolated). If this is the case, the flow rate of water through the sump suction line would be very low. This would allow any air in the line to escape into containment, where the pressure has dropped after the initial spike. It is only the large break loss-of-coolant accident that could have a negative
impact on safety injection or containment spray pump operation during both the injection and recirculation phases.
On the basis of the accident profile for a large break loss-of-coolant accident, the team
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found that the containment sump would submerge the sump suction line in
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approximately 28 seconds with a containment pressure of approximately 62 kPa
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(9 psig). Assuming that Valves 602 A(B) (sump suction butterfly valves) leaked, this containment pressure would not be enough to result in air between Valves SI-602A(B)
and SI 604A(B) (sump suction check valves) being forced into the water downstream of Valves SI-604A(B). Therefore, the team found that leakage of Valves 602A(B), alone, would not result in additional air being introduced.
Assuming that Valves 604A(B) leaked, as the water entered the area between the sump suction valves and the check valves, and the volume pressurized, the air in the space would be compressed to a pressure equal to the static head of the refueling water storage pool. When the sump suction valve would start to open, the air bubble would escape into containment since the pressure of the air bubble is approximately 75.8 kPa (11 psig), the containment is at approximately 62 kPa (9 psig), and the piping is sloped away from the suction valve. Therefore, the team found that this scenario would not result in additional air being introduced.
The last leakage scenario would be that both the butterfly valve and the check valve leak. Since the pressure downstream of the check valve is approximately 75.8 kPa (11 psig) during normal operation, water would leak into the space between the valves L
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-11 and pressurize the space. As the pressure in the space exceeded the containment pressure (during normal operation), the air in the space would be forced into the containment until all the air in the space was displaced by the water. Once the water filled the entire space, it would then leak past the butterfly valve and begin to fill the pipe until it spilled into the sump. Therefore, the team found that this scenario would not introduce air into the piping.
The team concluded that, since the plant was licensed with the air in the sump suction lines and there was no credible scenario for additional air to be introduced, the licensee's classification of the sump suction valves as Category B for testing was appropriate.
E8.11 (Closed) Unresolved item 50-382/98201-05: low-pressure safety injection pump minimum flow.
During the crchitect engineering inspection, the inspectors identified a concern related to the minimum flow for the low-pressure safety-injection pumps. NRC Bulletin 88-04, j
" Potential Safety-Related Pump Loss," addressed the potential for degradation of safety-related pumps due to inadequate design of system minimum-flow features.
The licensee's written response to the bulletin, letter W3P88-1840, dated November 1, 1988, stated that the low-pressure safety injection pump manufacturer's recommended minimum flow,378.5 Lpm (100 gpm), had been demonstrated by test, and no time restriction was associated with this condition. However, subsequent to the licensee's response, vendor Manual TD 1075.0045, "Ingersoll-Rand Low Pressure Safety injection Pumps Minimum Flow Evaluation," dated January 27,1989, stated that the 378.5 Lpm (100 gpm) limit w, ' only for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> or less of operation, and 7570 Lpm (2,000 gpm)
was required for more than 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> of operation.
The architect engineering inspectors were concerned that none of the licensee's procedures adequately reflected this higher minimum flow requirement for long-term operation. This was of particular concern for the situation where reactor coolant system pressure would be lower than shutoff head, but high enough to prevent achieving the 7570 Lpm (2,000 gpm) minimum flow requirement.
The licensee responded, to the architect engineering inspectors, that this same issue, but exclusively for low pressure safety injection pumps, was addressed in NRC Information Notice 93-08, " Failure of Residual Heat Removal Pump Bearings Due to High Thrust Loading." In response to this information notice, the licensee had prepared a detailed investigation of their pumps at flows less than 7570 Lpm (2,000 gpm). The licensee engineers concluded that operation below 7570 Lpm (2,000 gpm) may contribute to higher vibration and increased thrust bearing wear, but that such wear would not result in failure of the pumps to deliver the design flow rates. This was supported by the experience of 100 similar pumps in operation.
Licensee representatives presented, to this inspection team, correspondence from the pump manufacturer stating that operation at flow as low as 378.5 Lpm (100 gpm) for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> would not result in pump f ailure, only reduced bearing and seal life. The
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-12 licensee representatives also stated that the only time the pumps would be expected to be operated at this very low flow condition for extended periods would be for a small break loss-of-coolant accident. In that case, shutdown cooling would be initiated within approxirnately 12-16 hours of the start of the event, resulting in higher flows. Since this was less than the vendor-stated 24-hour limit, the team found that there would be an insufficient amount of time to cause damage that could prevent the pumps from performing their safety functions.
Licensee representatives also noted that a recommendation from their detailed investigation was to perforrn vibration testing and lubricant sampling as part of their quarterly inservice testing surveillance program to ensure that any abnormal bearing wear, as a result of low-flow operation, would be promptly identified and corrected. The team noted that these measures had been instituted. Additionally, the response pointed out that the inservice testing surveillances also included pump seal leakage inspections that would identify any seal degradation resulting from low-flow operation.
Licensee personnel initiated Condition Report CR-98-0850 to address the concerns of the architect engineering inspectors. The conclusion reached stated that existing programs and procedures were adequate, that there were no operability concerns, and that no corrective actions were required. These conclusions were based on the pump vendor's written statements that: the pumps would remain operable for at least 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at 378.5 Lpm (100 gpm); the licensee's evaluation that the pumps would be j
required to operate at very low flow conditions for at most only 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> during a small break locs-of-coolant accident; and the inservice testing program would detect and correct any degradation resulting from low-flow operation.
This team reviewed the referenced documents presented by the licensee representatives, including Condition Report CR-98-0850; the Ingersoll-Rand " Low Pressure Safety injection Pumps Minimum Flow Evaluation," TD 1075.0045; the licensee's internal Design Engineering Review of Information Notice 93-08, dated June 28,1994; Operational Experience Summary for Information Notice 93-08, dated March 10,1993; and Combustion Engineering's review letter of Information Notice 93-08, dated June 3,1994. The team also reviewed a change to Procedure OP-903-030, " Safety injection Pump Operability Verification," Revision 13, that inserted precautions regarding operation of the low-pressure safety injection pumps at less than 378.5 Lpm (100 gpm) for more than 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> in any 24-hour period.
The licensee representatives stated that all other procedures involving low-pressure safety injection pump operation nad been reviewed, and this was the only nonemergency procedure where the potential might exist for low-flow operation for extended periods. For procedures that might be used during emergency operations, such a precaution was not necessary because the expected worst-emergency case operating period with low flow would be acceptable, as previously described. Therefore, the operators should not be encumbered with a precaution that might improperly influence their operational decisions under these conditions.
This team found the licensee's positions on this issue to be adequate and concluded that the added procedural precaution regarding extended low-flow operation, the
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-13 surveillance testing requirements for these pumps that would reveal any unacceptable degradation, the operating experience with these and similar pumps, even under low flow conditions, and the pump vendor and nuclear steam system supplier's evaluations provided adequate assurance that these pumps could perform their design basis functions for all credible normal operating and accident conditions.
E8.12 (Closed) Unresolved item 50-382/98201-06: condensate storage poollevel measurement.
(Closed) Insoection Followuo item 50-382/98201-24: condensate storage pool water level.
During the architect engineering inspection, the inspectors identified a concern related to the ability of the level transmitters in the suction flow path associated with the emergency feedwater pumps to indicate correctly when exposed to flow conditions in the emergency feedwater suction pipe of the condensate storage pool. Since the level transmitters were installed in the suction side of the pump, when the pumps operated and water flowed through the pipe, the pressure read by the level transmitter was reduced by friction losses and by the velocity head.
Procedure OP-902-005," Loss of Offsite Power / Station Blackout Recovery Procedure,"
Revision 9, directed the operators to establish flow, but did not provide any instructions to the operators to monitor water level in the condensate storage pool. This condition was aggravated by the fact that accurate level monitoring was not possible during this operation because the level instrument would be biased with a large error indicating that the condensate storage pool level was higher than actual.
Also during the architect engineering inspection, the inspectors questioned the ability to indicate accurate levels in the condensate storage pool when emergency feedwater was established using water from the auxiliary component cooling water system. This condition would create an error in condensate storage pool level such that the indicated level would be lower than actual, if the operators did not monitor the water level, there was a potential for overfilling and damaging the condensate storage pool.
Licensee personnel initiated Condition Report 98-0735, dated May 22,1998, to address the location of the level transmitters and level monitoring of the condensate storage pool. The team reviewed the condition report and found that one of the licensee's corrective actions included relocation of the level transmitters to piping not affected by emergency feedwater flow.
The team reviewed Engineering Request ER-W3-98-0876, dated July 10,1998, which evaluated relocating the condensate storage pool level instruments to provide more accurate level indication. The team noted that the relocation of the level instruments would be completed during Cycle 10 prior to Refueling Outage 10.
The team reviewed Calculation EC-M98-013,"WCT (Wet Cooling Tower] Basin Flow to Condensate Storage Pool and EFW [ Emergency Feedwater] Pump Design Basis Review Calculation Upgrade Program Phase ll, Group 2," Rev'sion 0, which licensee
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-14 engineers performed to determine the minimum time required to isolate the condensate storage pool before it could overfill. The licensee engineers determined that the condensate storage pool would have to be isolated in 0.99 hours0.00115 days <br />0.0275 hours <br />1.636905e-4 weeks <br />3.76695e-5 months <br />, considering all scenarios, in order to avoid overfilling the pool. Based on this time, licensee personnel revised Appendix 10 of the emergency operating procedures to require that the appropriate valves are closed after 30 minutes had elapsed.
10 CFR Part 50, Appendix B, Criterion 111, " Design Contro!," requires, in part, that
"[m]easures shall be established to assure that applicable regulatory requirements and the design basis... are correctly translated into specifications, drawings, procedures, and instructions." The failure to translate the effects of the level error into the emergency operating procedures was identified as another example of a violation of design control (50-382/9806-03). This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. The corrective actions have been completed.
E8.13 (Closed) Inspection Followuo item 50-382/98201-07: steam generator level transmitter failure.
During the architect engineering inspection, the inspectors identified that failure of one steam generator level transmitter could cause the emergency feedwater secondary control valve to open fully and overfeed the steam generators. The excess water could go unnoticed in the control room until the water level in the affected steam generator reached 85 percent. This failure mode and effect had not been analyzed.
The team reviewed Engineering Request ER-W3-98-0764, dated June 12,1998. The team noted that this evaluation was performed to evaluate the effect of supplying full emergency feedwater flow to one steam generator upon receiving an emergency
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feedwater actuation signal. The evaluation was also pedormed to demonstrate that the operators would have sufficient time upon receipt of a high level steam generator alarm to secure ernergency feedwater prior to ovedilling the affected steam generator.
The licensee's engineers assumed a limiting scenario for emergency feedwater actuation, which entailed an event that caused the steam generator to decrease to the emergency feedwater actuation signal level and the lowest steam generator pressure possible. The team noted that the calculated time required to fill the steam generator volume from 27.4 percent narrow range level to 85.4 percent level was 4.53 minutes with an additional 8.26 minutes to fill from the 85.4 percent level to the steam generator
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outlet nozzle.
The licensee's engineers stated that ANSI /ANS-58.6-1994,"American National Standard Time Response Design Criteria for Nuclear Safety-Related Operator Actions,"
September 12,1984, provides guidance on the allowable operator-action times that may be credited during design basis accidents and states that, depending on operator and event specific information, the operator-action time after an alarm may range from 2 to l
6 minutes. The licensee's engineers concluded that the operators had sufficient time to
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operate the emergency feedwater isolation or control valves, based on the 8.26 minutes to fill the generator to the nozzle, after receiving a steam generator high level alarm.
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During the architect engineering inspection, the inspectors raised a concern about the failure to verify that check valves fully close in accordance with ASME Code requirements.
In the licensee's response of October 27,1998, the team noted that the licensee acknowledged that the test Procedures OP-903-014 " Emergency Feedwater Flow Verification," Revision 9, and OP-903-046," Emergency Feedwater Pump Operability Check," Revision 13, did not verify check valve closure in a manner that would satisfy ASME Code requirements. The team reviewed Procedure OP-903-014, " Emergency Feedwater Flow Verification, " Revision 10, and found that the licensee had addressed this concern such that the check valves will be tested in a manner that meets the requirements of the ASME Code.
The failure to establish a procedure to demonstrate the requirements of the ASME Code were met was identified as another example of a violation of Technical
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Specification 6.8.1 (50-362/9906-02). This Severity Level IV violation is being treated as f
another example of a noncited violation, consistent with Appendix C of the NRC j
Enforcement Policy. The corrective actions have been completed.
E8.15 (Closed) Unresolved item 50-382/98201-10: 10 CFR Part 21 reviews.
l During the architect engineering inspection, the inspectors identified a concern that the licensee had not performed an evaluation of defects and noncompliances identified pursuant to 10 CFR Part 21 for E7000 series Agastat relays and an additional 11 cases in accordance with Site Procedure W2.301, " Identification, Evaluation, and Reporting Process for 10 CFR Part 21 Compliance," Revision 2, and Licensing Procedure LP-122,
" identification, Evaluation, and Reporting of Defects and Noncompliances under 10 CFR Part 21," Revision 0. Licensee personnelinitiated Engineering Request ER W3-98-0819, to address programmatic concerns that 10 CFR Part 21 reviews were not performed, and Engineering Request ER-W3-98-0750, to evaluate the technical concerns associated with the 10 CFR Part 21 notification for Agastat E7000 timing relays.
By not performing the evaluation, the licensee had not determined if the condition identified in the notification presented a conditt a odverse to quality at the Waterford Steam Electric Station, Unit 3. The time periou associated with notifications related to the Agastat relays was July 1994 to June 1996.
Subsequent to the identification of this issue by the architect engineering inspectors, licensee personnel evaluated the subject notifications. This team found that the reviews were detailed and documented in Condition Report CR-98-0819. Licensee personnel
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conducted a review of 318 Class 1E applications of E7000/7000 series relays that were being used in direct current circuits. For the reviewed cases, the licensee engineers found that there were no cases where the relay contacts were required to switch state at more than 0.5 amperes direct current. The relay contacts had been tested to switch state at 4.6 amperes direct current successfully.
The team reviewed Procedure W2.301, Procedure LP-122, Condition Report CR-98-0819, and Detroit Edison's Deviation Event Report 94-0564 (dated October 17,1994), which documented the testing of Agastat relay contacts for make up at currents up to 4.6 amperes direct current. The team noted that the licensee engineers were taking credit for the testing performed by the Detroit Edison licensee.
The team also reviewed Agastat vendor Amerace's information notice (dated September 29,1994) to licensees; independent Technical Reviews98-046 through 056,
" Operational Experience Engineering Independent Technical Review"(all revision 0) for 11 10 CFR Part 21 cases; control wiring diagrams where relay contacts were used; and Engineering Request ER W3-98-0750.
The team noted that the licensee personnel had not identified any relays that were inoperable during the review of the 10 CFR Part 21 notifications. The team found that the licensee failed to properly implement its procedures for evaluation of 10 CFR Part 21 notifications. On the basis of the acceptable results from the evaluations performed subsequent to the identification of this shortcoming by the architect engineering inspection, the age of this issue, and the minor safety significance of this issue, no l
further review is necessary.
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E8.16 (Closed) Unresolved item 50-382/98201-11: unreviewed safety question and emergency diesel generator dynamic analysis.
During the architect engineering inspection, the inspectors identified a concern related to the sequentialloading of the emergency diesel generators. NRC Information Notice 92-53, " Potential Failure of Emergency Diesel Generators Due to Excessive Rate of Loading," dated July 29,1992, identified the potential emergency diesel generator failures if certain electrical loads were automatically started with other sequenced loads on the emergency buses. The engineered safety features actuation system loads could be started in a later time block if it received an actuation signal. Such loads include the containment spray pumps and the emergency feedwater pumps. The concern was that starting these loads in a later load block, either individually or at the same time, could exceed the diesel generator's capab;!ity.
At issue was the licensee's commitment to Regulatory Guide 1.9," Selection of Diesel Generator Set Capacity for Standby Power Supplies," 1971. The regulatory guide suggests that the emergency diesel generator frequency and voltage should not drop below 95 and 75 percent of nominal, respectively. The licensee's engineers evaluated NRC Information Notice 92-53 by way of Calculation 460000011, " Emergency Diesel l
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-17 Generator Units Dynamic Loading Study," Revision 0. The results of this calculation indicated that frequency would drop to 93.3 percent. As a result, the licensee changed l
the FSAR Section 8.3.1.2.4.c by Licensing Design Change Request 93-094, dated
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August 29,1994. Licences personnelinitiated Waterford Action Tracking System 88373
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and Condition Report CR-98-0791 to address emergency diesel generator loading concerns.
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The team reviewed Condition Report CR-98-0791. The team noted that the licensee engineers concluded that the emergency diesel generator load sequencing met the inters o! Pegulatory Guide 1.9 for the required sequence. In other words, the intent of the regulatory guide was to as.sure that emergency diesel generators could maintain
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greater than 95 percent nominal frequency and 75 percent nominal voltage during the application of the loads during the timed sequence.
The team further noted that the scenario proposed by the architect engineering inspectors was very improbable. This was because, for the scenario to occur, simultaneous receipt of a containment spray actuation signal, an emergency feedwater initiation signal, and a high component cooling water temperature condition would be required. Additionally, this assumes that the actuation signals were not present when the respective load block was actuated.
In Condition Report CR-98-0791, the licensee engineers indicated that one of the loads j
that may have been sequenced at a later time is no longer part of the load sequence.
As such, the minimum frequency approaches the guidance of the regulatory guide, even l
though the licensee had revised its commitment.
The architect engineering inspectors considered the inability to demenstrate compliance to the commitment to follow the guidance of Regulatory Guide 1.9 to have been a reduction in the margin to s4fety as described in the Final Safety Analysis Report and the technical specification bases. As such, the architect engineering inspectors expressed concern that e.n unreviewed safety question was not identified during the performance of a safety evaluation to change the commitment to follow the guidance to
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This team reviewed the technical specification bases for the emergency diesel generators. The team noted that the bases allow for deviation from the voltage and frequency limits established in the surveillance requirement. The bases discuss the need for the diesel generator to recover to a steady state condition. On this basis, this team concluded that there was no reduction in the margin to safety.
E8.17 (Closed) Unresolved item 50-382/98201-12: safety evaluation for battery modification.
During the architect engineering inspection, the inspectors identified concerns related to the safety evaluation performed for Design Change Package DC-3362 because the licensee personnel did not address the need to revise the technical specifications to
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-18 reflect the intercell connection resistance specified by the manufacturer. Also, the inspectors were concerned that the safety evaluation did not discuss the effect of decreasing the battery duty cycles. Finally, the inspectors expressed a concern that the calculations for the battery and battery charger need to be revised to reflect the changes which resulted from the implementation of Design Change Package DC-3362.
While the manufacturer of the replacement batteries may have specified a more conservative value for the intercell resistance, there were no regulatory requirements for the licensee to revise the technical specifications.
With respect to decreasing the battery duty cycle, the modification installed new batteries. As such, the load profiles depicted in the Final Safety Analysis Report were specific to the new batteries and were based on the current (at the time of the architect engineering inspection) safety analysis and station blackout requirements. This team noted that the prior battery profiles were not related to specific plant loads and operating conditions, nor were they consistent with the safety analysis.
The battery sizing calculations were based on either a loss-of-offsite power coincident with a loss-of-coolant accident or a loss-of-offsite power coincident with a main steam line break. Under either of these scenarios, the battery chargers would be shed from the electrical distribution system and the batteries would be required to support the safety-related loads. Once the emergency diesel generators started, two battery chargers would be automatically reenergized at approximately 17.3 seconds for the A and B batteries. For the AB battery, the load profile was reduced to 31 minutes to allow for bus transfer time. The team found the justification for the reduction in duty cycle times to be appropriate.
To address the architect engineering inspectors' concern related to the need for calculations to be revised, the licensee engineers were in the process of updating the calculations to account for battery loads that would discharge the batteries while the charger output is ramping up after reenergization.
E8.18 (Closed) Insoection Followuo item 50-382/98201-13: emergency diesel generator loading.
During the architect engineering inspection, the inspectors reviewed Calculation EC-E90-006 and determined that the calculation did not establish or document the maximum loading of the emergency diesel generators. This team noted that the architect engineering inspectors assumed that Calculation EC-E90-006 was to demonstrate the capability of a single emergency diesel generator to carry the maximum load. This is based on the architect engineering inspectors documentation in the report that discussed the use of maximum brake horsepower for the loads.
This team found that Calculation EC-E90-006 actually evaluated the dieselloading from a fuel oil consumption perspective. The limiting case for fuel oil consumption was with both emergency diesel generators operating to mitigate the consequences of an event.
The team noted that the issue of fuel oil consumption had been reviewed during an
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l electrical distribution system functional inspection documented in NRC Report 50-382/90-23.
With respect to the architect engineering inspectors * concern about maximum loading on the generators, this team noted that the licensee did not perform a calculation for abnormal pump operation, which would result in the maximum loading. Instead, a licensee representative stated that engineering judgement was used to demonstrate that the capability of the emergency diesel generators to supply the abnormal loads was within the design basis. The team found this position, although not documented, to be reasonable.
E8.19 (Closed) Unresolved item 50-382/98201-14: nonsafety load sequencing.
During the architect engineering inspection, the inspectors noted that the plant's normal computer, powered from 480 VAC Bus 3A31-S Cubicle 8C, tripped on loss-of-offs'te
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power but automatically sequenced to the satsiy-re!ated bus after 2 minutes. This automatic sequencing of non-safety loads was not in conformance with the Safety i
Analysis Report, Section 8.3.1.2.15(e)(7), which states that reconnection of nonessential I
loads can only be done manually under administrative control. Also, non-Class 1E loads (e.g., Diesel Generator 3A-S and Air Compressors 1 and 2) were powered from the Class 1E bus portion of Motor Control Center 3A312-S. These loads were not tripped or isolated during a loss-of voltage, as stated in the safety analysis report. The licensee initiated Condition Report CR-98-0763 to address above issue.
This team reviewed Condition Report CR-98-0763 and Section 8.3.1.2.13 of the safety analysis. The team verified emergency diesel generator bus loads accountaEnty for these nonsafety loads in Calculation EC-E90-006 and isolation from the s&ty-related buses. The team questioned the breaker coordination aspect for these ronsafety loads.
A licensee engineer produced NRC Inspection Report 50-382/93-01 whicn verified breaker coordination (see Section 2.1.2). The team also noted that the licensee indicated that a revision to the safety analysis report would be made to address the discrepancy between the report and the plant configuration.
Based on the facts that the nonsafety loads were accounted for in the emergency diesel generator bus load calculation for safety-related buses, there was acceptable isolation from safety buses, and breaker coordination existed, the team found that a minor discrepancy existed in the safety analysis report, which was to be corrected by the licensee in the next revision of the report. While the discrepancy existed, it was minor in nature and had no safety significance.
E8.20 (Closed) Unresolved item 50-382/98201-15: battery charger and inverter operation at degraded voltage.
During the architect engineering inspection, the inspectors noted that the voltages at the safety-related motor control centers powering the safety-related inverters and battery chargers could be less than the required minimum voltage of 432 Vac during a degraded grid voltage condition. As such, there would be insufficient ac voltage to operate the safety-related battery chargers and inverters. The inspectors were not
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-20 provided any analysis that could demonstrate that the safety-related de system would be capable of powering the safety-related 125 Vdc and 120 Vac loads, which were normally powered by the battery chargers and inverters.
l During a review of Calculation EC-E91-050," Degraded Voltage Relay Setpoint,"
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Revision 0, Change 3, this team determined that, during a degraded voltage condition, the voltage available at the safety-related motor control centers powering the Class 1E battery chargers and inverters ranged from 420 to 424 Vac for safety Train A and B motor control centers and 417 to 421 Vac for safety Train AB motor control centers.
This team noted that the licensee had briefed the operating pesonnel to ensure that they were aware of the particular operating concerns and verified that suitable alarms were asailable to alert the operators in advance of the potential for affecting the operability of the battery chargers and inverters. This team determined that there were no immediate safety concems since the licensee has established administrative controls in place.
This team noted that the vendor for the instrument static unlnterruptible power supplies stated that there would be no adverse effect on the operation of the sat 'ty-related instrument static uninterruptitds power supplies as a msult of the reduced voltage. The documer.tation was not inserted into Calculation EC-E91-050 or the vendor manual for the power cupplies. The team noted that the licensee had received further documentation indicating the safety-related battery chargers and instrumeat static uninterruptible power supplies units would function properly during the deDraded voltage j
conditions.
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The team found that biarmation was available, but not included in the licensee's documentation, to riemenstrate that the battery chargers and the inverters were capable of operating at the vc!! ages that would be experienced during a degraded grid condition.
l E8.21 (Closed) Inspection Followuo item 50-382/98201-16: emergency diesel generator load sequencing test procedure.
During the architect engineering inspection, the inspectors noted that certain Icads with
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separate timers from the load sequencer did not have the timing of the additio tal timers
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verified during the performance of Procedure OP-903-115," Train A Integrated Emergency Diesel Generator / Engineering Safety Features Test," Revision 4. The subject loads were battery Charger 3AB1-S, battery Charger 3AG2-S, the load supply to uninterruptible power Supply 3AB, and the essential chiller compressors and oil pumps.
These loads are shed and sequenced in load blocks 2a,6b, and 6d, as stated in Table 8.3-1 of the safety analysis report. Licensee personnelinitided Engineering Request ER-W3-98-0773 to determine whether actual timine M these load blocks thould be included in the above procedure.
This team reviewed Engineering Request ER-W3-98-077 3 and the licensee's October 27,1998, response letter, and interviewed licenste personnel. The team notad that Procedure OP-903-115 was an integrated test of the k ad sequencer. Its purpose was to verify the correct operation of the sequencer in ordet to comply with technical
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-21 specifications. The teem also noted that the timing of the individualloads during the load block was bounded by the emergency diesel generator loading calculation.
The team was informed by a licensee representative that, while the testing of the individual loads was not a technical specification requirement, the licensee considered it prudent to test these loads as part of the preventive maintenance program by way of repetitive work tasks. The team noted that the licensee had an internal completion date of September 30,1999, to issue the repetitive work tasks.
The team found the licensee's position and plan to address the issue to be appropriate to the circumstances.
E8.22 (Closed) Inspection Followuo item 50-382/98201-17: battery surveillance testing.
During the architect engineering inspection, the inspectors identified an issue that questioned the applicability of a battery test performed to meet the requirements of Technical Specification 4.8.2.1.d for Battery 3AB-S. In particular, the inspectors noted i
that the test performed on May 22,1997, used a load profile that, at the time interval of minute 30 to minute 31, the test current was 279 amperes. This did not appear to the inspectors to bound the design basis accident profile which required 382 amperes at that time interval.
This team reviewed the load profiles for both the station blackout scenario (the one tested on May 22,1997) and the design basis accident. The team found the load profile for the station blackout scenario bounded the design basis accident scenario.
E8.23 (Closed) Unresolved item 50-382/98201-18: instrument inaccuracies.
During the architect engineering inspection, the inspectors identified that the licensee was not using instruments with the required accuracy for inservice testing. This testing was to be performed during the licensee's second 10-year interval in accordance with ASME/ ANSI OMa-1988, Part 6, " Inservice Testing of Pumps in Light-Water Reactor
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Power Plants." THs document required that instrument accuracy be no worse than j
- 2 percent of the tull scale specified in Table 1 of Section 4.6.1.1. However, the inspectors discovered that flow and pressure instruments used for testing auxiliary component cooling water, component cooling water, low pressure safety injection, high pressure safety injection, and charging pump surveillance testing did not meet the i 2 percent full-scale, total loop accuracy requirements of ASME/ ANSI OM-6. The errors ranged between 0.95 percent and 2.34 percent above the 2 percent allowable.
As a result of this discovery, the inspectors also questioned the operability of pumps that had been tested and judged operable based on data from these instruments. In response, licensee personnel initiated Condition Report CR-98-0734.
The inspectors also noted that licensee personnel had written Engineering Request ER-W3-97-0390, dated August 14,1997, to evaluate the acceptability of these
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i instruments. Subsequent to this, licensee personnel had performed pump tests between February 25, through June 2,1998, but the validity of the tests with respect to
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I-22 the accuracy of these instruments had not been questioned by the licensee personnel until it was identified by the inspectors. Subsequent review of the test data by the licensee personnel and the inspectors confirmed that, with allowance for the actual instrument error, the pumps' performances were within the ASME Code,Section XI acceptable range, with no indications of degradation. Therefore, there were no operability concerns.
The licensee acknowledged, in its October 27,1998, letter, that testing of the auxiliary component cooling water, component cooling water, low pressure safety injection, high pressure safety injection, and charging pumps was not in compliance with the requirements of ASME/ ANSI OM-6 with respect to instrument accuracy for the second 10-year inservice testing interval during the period December 1,1997, through May 21,1998. Although this was discovered as a result of an architect engineering team question on May 13,1998, the licensee pointed out that Engineering Request ER-W3-97-0390 to evaluate this accuracy had been initiated earlier and was nearing completion at the time of the architect engineering team's question.
This team noted that the licensee provided the corrective actions that had been taken to address this issue. First, the licensee documented the concern in Condition Report CR-98-0734. Second, the engineering review for Engineering Request ER-W3-97-0390-00-00 was completed on June 5,1998. This team observed that the effects of the instrument inaccuracies were evaluated against the most recent surveillances, and the affected pumps' performances were found to remain within the acceptable range. Therefore, this nonconformance was not safety significant.
This team reviewed the referenced documents presented by the licensee. This included
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Condition Report CR-98-0734; Engineering Request ER W3-0390; and revised l
Inservice Testing Procedures OP-903-003," Charging Pump Operability Check,"
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Revision 10; Change 2, OP-903-030, " Safety Injection Pump Operability Verification,"
Revision 10, Change 2; and OP-903-050, " Component Cooling Water and Auxiliary Cooling Water Pump and Valve Operability Test," Revision 15, Change 2. Through review of these documents and conversations with the licensee's representative, the team agreed that when the instrument uncertainty of the nonconforming pumps was applied to the test results, the pumps' performances were still within the ASME Section XI requirements, and that the revisions to the nonconforming operability procedures had brought them into conformance with code requirements.
It should be noted that these procedure revisions required no hardware changes.
Whereas the previous procedure revisions had required taking readings from readout instrumentation that produced unacceptable uncertainties, the revisions required the readings to be taken from computer points in the same instrument loops which produced acceptable total loop accuracies at that point in the loops.
Technical Specification 6.8.1 requires, in part, that written procedures shall be established and implemented for the performance of surveillance and test of safety-related equipment. Criterion XI of Appendix B to 10 CFR Part 50 requires, in part, that adequate test equipment be used. As a result of the licensee's failure to assure that instrumentation with the specified total loop accuracy was used in the performance of l
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-23 inservice testing of safety-related pumps, the team identified this as another example of a violation of Technical Specification 6.8.1 for inadequate procedures (50-382/9906-02).
This Severity Level IV violation is being treated as another example of a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation has been corrected, as discussed above. The corrective actions have been completed.
During the review of the issue of instrument inaccuracies associated with inservice testing, the team questioned the adequacy of the licensee's surveillance program for demonstrating the operability of pumps when total loop uncertainties (e.g., process fluid density, system flow rettance, total instrument loop uncertainties, etc.) were considered. The licensee provided the team, subsequent to the exit meeting, Engineering Request ER-W3-99-0428, dated April 22,1999, to address this issue. The team determined that this issue was related to an ongoing enforcement action th was identified in NRC Ins, mtion Report 50-382/97-25.
Further NRC and licensee evaluation is necessary to determine the ability of the high
. pressure safety injection, auxiliary component cooling water, component cooling water, chemical and volume control, essential chilled water, and emergency feedwater pumps to provide adequate flows to meet design requirements. Therefore, this issue was identified as an unresolved item (URI 50-382/9906-04).
.8.24 (Closed) Insoection Followuo item 50-382/98201-19: ultimate heat sink basin capacity.
During the architect engineering inspection, the inspectors identified the fact that the discussion of water capacity and requirements for long-term cooling was confusing. In the licensee's 27,1998, response, the team noted that the licensee acknowledged that the documentation in the safety analysis was not clear. However, during this inspection, the team noted that licensee's engineers demonstrated that there was sufficient water inventory to provide long-term cooling. The licensee engineers stated that clarifications would be made as necessary to reflect the inventory requirements of the wet cooling tower basins for emergency feedwater usage.
E8.25 (Closed) Unresolved item 50-382/98201-20: procedure for spent fuel pool cooling.
l During the architect engineering inspection, the inspectors noted that the spent fuel pool heat rejection would be controlled as part of the emergency plan responsibilities by providing guidance to operators based on assessments of the meteorological conditions
' at the time of the event. The guidance provided by Procedure EP-002-100," Technical Support Center Activation, Operation, and Deactivation," Revision 26, indicated that fuel pool cooling should be restored before the fuel pool temperature exceeded 82.2*C (180* F) and that component cooling water flow through the standby spent f uel pool heat exchanger should be secured. The inspectors noted that there was no procedurel guidance or caution to restrict spent fuel pool heat loading on the ultimate heat Wik to 11.4 Btu /hr as used within the wet cooling tower and dry cooling tower capacity analysis and development of inputs for determination of the ultimate heat sink rejection water
. consumption.' Without the procedure restrictions, the needed volume for cool down c.f the facility could be lost by cooling down the spent fuel pool excessivel,. _
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-24 This team reviewed Procedure EP-002-100, Revision 28, and noted that instructions had been added to maintain the fuel pool at a constant temperature below 82.2*C (180*F). In addition, guidance was given to not commence cool down of the fuel pool until an evaluation could be performed based on available water inventory, current meteorological conditions, and actual condition of the ultimate heat sink to provide guidance to cool the fuel pool back to normal operating conditions. A licensee representative stated that a review of design information and a determination that the ultimate heat sink had the capacity to maintain the spent fuel pool temperature at the required limits, and could cool down the spent fuel pool, had been completed. In addition, the licensee representative stated that the technical support center would provide guidance for cooling down the spent fuel pool based on actual conditions during an event.
The licensee considered the change to Procedure EP-002-100, Revision 28, as additional guidance to the technical support center to evaluate current plant conditions and recommend the optimal time to restore cooling to the spent fuel pool. The team agreed that the procedure revision was an enhancement, and not a requirement.
E8.26 (Closed) Unresolved item 50-382/98201-21: spent fuel pool makeup requirements.
During the architect engineering inspection, the inspectors identified that the makeup sources and requirements for the spent fuel pool were inconsistent between the several licensing basis and design basis documents that addressed the subject. The inspectors were concerned that the volume of water available was inadequate for certain design basis events.
The licensee's response letter of October 27,1998, stated that the plant met the requirements of Standard Review Plan, Section 9.1.3, and Regulatory Guide 1.13,
" Spent Fuel Storage Facility Design Basis (for Comment)," (Draft CE 913-5, Proposed Revision 2, published December 1981), in that it had a Seismic Category I spent fuel pool makeup system and an onsite Seismic Category I water storage facility as a backup water source in addition to the refueling water storage pool and condensate storage pool described in the Final Safety Analysis Report. The licensee's letter also stated that, although Calculation EC-M97-006 had determined the wet cooling tower basins could be available for makeup to the spent fuel pool during a design basis accident while still satisfying the ultimate heat sink and emergency feedwater requirements, this capability was over and abovo that discussed in the Standard Review Plan, Section 9.1.3, and Regulatory Guide 1.13. The licensce's letter acknowledged that the calculation was not clear in its definition and presentation of the design requirements and capabilities for spent fuel pool makeup. The licensee intended to revise the calculation to clarify these points by May 1,1999.
This team reviewed the referenced documents and found that, although there were no signifi; ant discrepancies, as acknowledged by the licensee, the definition and presentation of the design requiremyss and capabilities for spent fuel pool makeup were not clear. From further discussions with licensee representatives, one of the main points of nonclarity was that these documents presented all of the water usage design basis event scenarios together, which, without clear explanation, could lead to the
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-25 inference that the requirements were all at the same time and, therefore, sufficient water was not available for spent fuel pool makeup. However, with examination of each event scenario separately it became clear that, for all events, adequate water was always available from qualified sources to supply the event's needs while at the same time providing the necessary spent fuel pool makeup. The licensee's intended revision to Calculation EC-M97-006 would clarify this and other points of confusion.
Based on the followup team's assessment that adequate makeup water was available from qualified sources to meet the requirements of all design basis event scenarios while at the same time providing the required rnakeup to the spent fuel pool, and the licensee's intention to revise Calculation EC-M97-006 to clarify the availability and utilization of this water, this concern was considered closed.
E8.27 (Closed) Unresolved item 50-382/98201-23: emergency feedwater pump room environment.
During the architect engineering inspection, the inspectors' review of Calculations MN(O)-9-3, " Ultimate Heat Sink Study," Revision 2, and MN(O)-9-17,
" Tornado Multiple Missile Protection of Cooling Towers," Revision 2, revealed that, for loss-of-coolant-accident and tornado events, the chilled water system temperature could rise above its 5.6*C (42*F) design temperature, to as high as 11.1 *C (52*F). However, Calculation 5-1, " Emergency Feedwater Pump Rooms," Revision 2, a calculation of the maximum temperatures in these rooms, had used a 5.6*C (42 F) chilled water temperature to the room coolers. The design temperature for these rooms was 40*C (104*F) based on this as the original pump motor qualification temperature. The room temperature recalculated by the licensee using the higher chilled water temperature was 47.2*C (117'F). Two other rooms where temperatures were recalculated as a result of this finding were the component cooling water pump rooms and the shutdown heat exchanger rooms where the temperatures could reach 46.7*C (116*F) and 42.2*C (108*F), respectively. Their design temperatures were also 40*C (104*F).
As a result of this finding, licensee personnel issued Condition Report CR-98-0852 and performed an immediate operability evaluation, which determined that the equipment could perform its safety function in temperatures up to 50*C (122*F). The licensee also responded that the original report finding had erred in citing Calculation 5-1 as the rcom temperature calculation; instead it was Calculation 5-W.
As a result of the licensee's review for Condition Report CR-98-0852, it was found that the equipment in the rooms was qualified for temperature excursions up to 50 C (122*F) using the Arrhenius methodology. This was documented in Memorandum EOP-82-9-131, dated September 29,1982, which was referenced in Calculation 5-W," Evaluation of Space Temperatures Following a Tornado," Revision 0.
Additional corrective actions documented by the condition report to assure that this issue would be fully addressed included revision of Calculation 5-W and re-evaluation and documentation of the safety-related equipment in the affected rooms for the J
elevated excursion temperatures, both to be completed by June 30,1999.
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-26 This team reviewed the referenced documents and engaged in several conversations with the licensee on this finding. These reviews verifiad that the licensee's actions to-date were adequate to assure the operability of the affected equipment, and ongoing actions to re-evaluate this concern should bring it to proper resolution.
Based on the existing Arrhenius-based evaluations showing the equipment in the affected areas are qualified for excursions to 50*C (122*F), and the license's internal
commitment to complete re-evaluations and revise Calculation 5-W by June 30,1999, this issue is considered closed.
E8.28 (Closed) Insoection Followuo item 50-382/98201-25: auxiliary component cooling water i
to emergency feedwater system suction path testing.
j During the architect onginecting inspection, the inspectors questioned the ability of the piping that connects the auxiliary component cooling water system to the emergency feedwater system to carry the design flow.
The team noted that the licensee's position regarding testing was that full flow testing of the cmergency feedwater suction flow path from the auxiliary component cooling water system was not practical. Such testing would unnecessarily expose the steam generators to biological contamination, which could have a long-term detrimental effect.
The team noted that, in lieu of full flow testing, the licensee periodically performs a back flush on the auxiliary component cooling water suction supply to the emergency
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feedwater pumps and manually exercises the isolation valves.
The team observed that the licensee had taken actions to minimize solids and biological growth in the wet cooling towers (the auxiliary component cooling water pump intake), in addition to the actions described above. The additional actions include the installation of a side stream recirculat:ap filtration system.
An inspscror performed a visualinspection of the wet cooling towers and observed that the water clarity was very good. The inspector was able to see to the bottom of the cooling tower. The filtration system was in operation at the time of the observation. The inspector also inspected the isolation valves. One, Valve ACC-1158, had recently experienced some refurbishment and looked good. The other had not been refurbished and was extremely rusty. The inspector reviewed the maintenance history of Loth valves and found that they had performed well during the 2-year period of review. The inspector noted that the auxiliary component coolire water system had not performed well and had goals and monitoring requirements established in accordance with 10 CFR 50.65," Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." The reason for the poor peiformance was not related to the valves.
The team found that the licensee's periodic actions were adequate to assure the ability of the auxiliary component cooling water system to supply the emergency feedwater syste p l:
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l E8.29 (Closed) Insoection Followuo item 50-382/98201-26: potential for wet cooling tower l _
basin and auxiliary component cooling water pump vortexing.
. During the architect engineering inspetbon, the inspectors identified that Calculation MN(Q)-9-38, " Capacity of Wet Cooling Towers," Revision 3, which was the basis for the wet cooling tower capacity at the -3.43 m (-9.86 ft) technical specification allowable minimum water level, was based on a full usable volume from this level down to the auxiliary component cooling water pump suction. No allowance was made for vortexing. This was consistent with Calculation EC-M95-012, " Minimum Pipe Submergence to Prevent Vortexing," Revision 1, which had not included the auxiliary component cooling water pump suctions based on the presence of vortex breakers that had been installed by Design Change Notice MP-0887 during initial plant startup.
However, the vortex breaker configuration was unconventional, located beneath the downward tumed pipe inlet, and no design basis or predicted hyuraulic performance had been included in the design package. Additionally, the auxiliary component cooling
= water pump preoperational testing had not documented the wet cooling tower levels.
Therefore, this test data did not demonstrate the hydraulic performance of the vortex breakers. As a result, the available usable volume in the wet cooling tower was called into question.
In response to the architect engineering team's finding, licensee engineers revised Calculation EC-M95-012, Revision 3, by adding a calculation of the vortex critical height for the wet cooling tower auxiliary component cooling water suction line, which was found to be 36.8 cm (14.5 in) above the pipe suction. Also added to the calculation was an evaluation of the bases for t.e 658669 L (174,002 gal) technical specification volume limit. This limit included a 5 percent allocation for solids in the water since the wet cooling tower basin was an open, outdoor basin, subject to solids accumulation.
However, the water losses commensurate with an accident would not deplete the solids inventory in the basin, which was calculated to represent 30.7 cm (12.1 in) of level.
Additionally, the level loss associated with 658669.26 L (174,002 gal) was recalculated
'to be 11.2 cm (4.4 in) above the pipe suction, rather than at the pump suction.
Together, these factors represented a final level 41.9 cm (16.5 in) above the pipe suction, which provided an approximate 5 cm (2 in) margin.
This team reviewed the documents associated with this finding including the revised calculation. Although no specific discrepancies were identified in the revised calculation, the team noted that one element of the architect engineering inspectors' finding was not addressed. That element was the fact that the installed vortex breaker was of unconventional design, below the pipe inlet, and that there was no empirical data on its hydraulic performance. Although the calculation used a conservative formula to determine the vortex critical height, it was a formula for typical conventional designs, and there was no data to show that the.small calculated margin was adequate to
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account for the probable perhaps effectiveness of the unconventional vortex breaker
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This team observed that the calculation had used the auxiliary component cooling water pumps' rated flow of 24,605 Lpm (6,500 gpm). However, Assumption 5.2 in the calculation had noted that at the point in time in an accident where the wet cooling tower L
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-28 basin level would be reduced to cause a vortexing concern, the flow would be, approximately 7,570 Lpm (2,000 gpm). The critical height was a direct function of the flow rate; therefore, the calculation contained this large conservatism. When this
conservatism was removed and the critical height was recalculated at this reduced flow, j
it was found to be 11.4 cm (4.5 in), providing a new calculated margin of 30.5 cm i
(12.0 in). The licensee's representative maintained that this additional margin plus the margin in the water loss calculations more than made up for any uncertainty of the unconventional vortex breaker design.
The team found the additional analysis demonstrated that adequate margin existed such that vortexing was not a concern.
E8.30 (Closed) Inspection Followuo item 50-382/98201-27: auxiliary component cooling water transfer and cross-connection.
During the architect engineering inspection, the inspectors were concerned that, for the case of a single failure of one auxiliary component cooling water train, the plant procedures provided insufficient guidance for the transfer of water from the idle cooiing tower basin to the in-service basin to assure that the required volume of water would be
available in the in-service basin to meet all of the design basis needs.
Licensee representatives initially responded that such water inventory management and cross-connected wet cooling tower basin operation were addressed in the Emergency Plan by Procedure EP-002-100, Revision 28. However, the architect inspectors were concerned that the procedure indicated that makeup to the in-service wet cooling tower basin from the idle basin should be established only when the operating basin level was less than 5 percent and the essential chiller was using auxiliary component cooling water for cooling. This would limit the makeup capacity from the idle wet cooling tower through the cross-connect such that the flow may not be sufficient to keep up with the potential rapid draw down as a result of water transfer to the condensate storage pool via the auxiliary component cooling water system. Additionally, the architect inspectors were concerned that there was insufficient procedural guidance for the wet cooling tower basin cross-connected operation.
This team noted that the licensee's response letter of October 27,1998, indicated that the Technical Support Center's procedures provided no specific guidance on when, during an accident, the cross-connected operation of the wet cooling tower basin could begin; rather that determination was made by the Technical Support Center's management team. The licensee's response letter also stated that a water usage analysis for the wet cooling towers would be developed to assure sufficient capacity and transfer capability, and that this analysis would confirm that the high usage rates of concern to the architect engineering inspectors, because of the potential for insufficient cross-connected flow rates, would not be applicable at the time when the basin would be down to the 5 percent level.
On the basis of the additional analysis, the team found that this issue was adequately accounted for by the license..
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-29 E8.31 (Closed) Unresolved item 50-382/98201-28: ultimate heat sink basin temperature.
During the architect engineering inspection, the inspectors identified a concern that the ultimate heat sink may not be capable of performing its intended function following a tornado.
The team reviewed Calculation MN(O)-9-17, " Tornado Multiple Missile Protection of UHS," Revision 2, which determined the performance of the ultimate heat sink during shutdown following a tomado scenario. Within the first 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of the event analysis, the dry cooling tower was not available, the wet cooling tower was in the natural draft mode and might not be capable of rejecting the entire heat load, and the remaining heat load was absorbed by the water volume of the wet cooling tower basin, which could result in a temperature rise above 40.6*C (105'F). The calculation maintained the assumption of the 40.6*C (105*F) temperature by considering the entire hest load to be absorbed by the wet cooling tower basin volume resulting in a 13.9'C (25'F)
i temperature rise from an initial temperature of 26.7*C to 40.6*C (80*F to 105"F).
Technical Specification 3/4.7.4 for the ultimate heat sink requires that the average basin water temperature be maintained less than or equal to 31.7*C (89*F). If the initial water basin temperature was assumed to be 31.7'C (89*F), the projected first 2-hour post tornado heat load would result in a cooling water temperature of 45.6*C (114*F) to the essential chillers.
Licensee representatives stated that the 36.7*C (80*F) temperature was used as an i
additional data point and was not used in any design basis calculation. The licensee representatives stated that it was not intended as an input to determine auxiliary component cooling water in!st temperature to the essential chiller temperature from the ultimate heat sink.
The team reviewed Calculation MN(Q)-9-17, Revision 2, and noted that the basin water could rise to a temperature of 45.6*C (114*F) based on data obtained from the ultimate heat sink test. The 45.6*C (114*F) ultimate heat sink temperature would support the technical specification average basin temperature of 31.7'C (89*F) plus the 13.9'C (25'F) temperature rise. The team determined that the design temperature of the ultimate heat sink during tornado conditions was specified as 45.6*C (114*F) in the calculation and concluded that the 26.7"C (80*F) specified in the calculation was simply a data point and not a design temperature.
The team determined that the calculation was slightly misleading but not incorrect.
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i V. Mansaement Meetinas X1 Exit Meeting Summary The team presented the inspection results to members of licensee management at the conclusion of the inspection on April 9,1999. The licensee acknowledged the findings piesente,
d-30 The team leader asked the representatives of the licensee's management whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
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ATTACHMENT SUPPLEMENTAL INFORMATION PARTIAL LIST OF PERSONS CONTACTED Licensee M. Brandon, Licensing Supervisor T. Brennan, Technical Support Coordinator, Design Engineering D. Dale, Design Engineer, Mechanical C. Dugger, Vice President, Operations P. Fresneda, Design Engineer, Mechanical R. Gilmore, Design Engineer, Mechanical P. Gropp, Manager, Electrical / Instrumentation and Controls Design Engineering j
J. Houghtaling, Technical Assistant A. Lewis, Licensing Engineer D. Marpe, Design Er,ginaar. Mechanical S. Matharu, Engineering Supervisor, Electrical Design Engineering P. Melancon, Programs Engineer, Design Engineering
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E. Perkins, Licensing Manager G. Pierce, Director, Quality L. Rushing, Manager, Mechanical / Civil Design Engineering G. Scott, Licensing Engineer D. Viena, Supervisor, Mechanical Design Engineering i
R. Williams, Licensing Engineer J
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A. Wrape, Director, Design Engineering NRC T. Famholtz, Senior Resident inspector J. Keaton, Resident inspector INSPECTION PROCEDURE USED IP 92903 Followup - Engineering i
ITEMS OPENED AND CLOSED Opened 50-382/9906-01 NCV Technical specification violation for inadequate valve position indication for hydrogen recombiner analyzer containment isolation valves (Section E8.3).
50-382/9906-02 NCV Four examples of inadequate procedures (Sections E8.4, E8.8, E8.14, and E.23).
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50-382/9906-03 NCV Three examples of inadequate design control (Sections E8.5, E8.6, and E8.12).
50-382/9906-04 URI Ability to demonstrate the adequate flow availability to meet design requirements for the high pressure safety injection, auxiliary component cooling water, component cooling water, chemical and volume control, essential chilled water, and emergency feedwater pumps (Section E8.23).
Closed 50-382/9725-01 URI High pressure safety injection and containment spray systems'
net-positive suction head inaccurately stated in the safety analysis report (Section E8.1).
50-382/9725-03 URI Operability of feedwater isolation valves (Section E8.2).
50-382/97-031 LER Hydrogen analyzer valve position indication (Section E8.3).
50-382/98-007 LER Chilled water instrument uncertainty (Section E8.4).
50-382/98-009 LER Inadvertent engineered safety features actuation (Section E8.5).
50-382/98-010 LER Potential over pressurization of the nitrogen system (Section E8.6).
50-382/98201-01 URI Single failure analysis (Section E8.7).
50-382/98201-02 URI Emergency core cooling system leakage acceptance criteria (Section E8.8).
50-382/98201-03 URI Dose consequences of refueling water storage pool back-leakagc (Section E8.9).
50-382/98201-04 URI Containment sump isolation valves leakage (Section E8.10).
50-382/98201-05 URI Low-pressure safety injection pump minimum flow (Section E8.11).
50-382/98201-06 URI Condensate storage pool level measurement (Section E8.12).
50-382/98201-07 IFl Steam generator level transmitter failure (Section E8.13).
50-382/98201-08 URI Emergency feedwater discharge check valve testing (Section E8.14).
50-382/98201-10 URI 10 CFR Part 21 reviews (Section E8.15).
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-3 50-382/98201-11 URI Unreviewed safety question and emergency diesel generator dynamic analysis (Section E8.16).
50-382/98201-12 URI Safety evaluation for battery modification (Section E8.17).
50-382/98291-13 IFl Emergency diesel generator loading (Section E8.18).
50-382/98201-14 URI Nonsafety load sequencing (Section E8.19).
50-382/98201-15 URI Battery charger and invertesr operation at degraded voltage (Section E8.20).
50-382/98201-16 IFl Emergency diesel generator load sequencing test procedure (Section E8.21).
50-382/98201-17 IFl Battery surveillance testing (Section E8.22).
50-382/98201-18 URI Instrument inaccuracies (Section E8.23).
50-382/98201-19 IFl Ultimate heat sink basin capacity (Section E8.24).
50-382/98201-20 URI Procedure for spent fuel pool cooling (Section E8.25).
50-382/98201-21 URI Spent fuel pool makeup requirements (Section E8.26).
50-382/98201-22 URI Potential over pressurization of the nitrogen system (Section E8.6).
50-382/98201-23 URI Emergency feedwater pump room environment (Section E8.27).
50-382/98201-24 IFl Condensate storage pool water level (Section E8.12).
50-382/98201-25 IFl Auxiliary component cooling water to emergency feedwater system suction path testing (Section E8.28).
50-382/98201-26 IFl Potential for wet cooling tower basin and auxiliary component cooling water pump vortexing (Section E8.29).
50-382/98201-27 IFl'
Auxiliary component cooling water transfer and cross-connection (Section E8.30).
50-382/98201-28 URI Ultimate heat sink basin temperature (Section E8.31).
50-382/9906-01 NCV Technical specification violation for inadequate valve position indication for hydrogen recombiner analyzer containment isolation valves (Section E8.3).
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v-4 50-382/9906-02 NCV. Four examples of inadequate procedures (Sections E8.4, E8.8, E8.14, and E.23).
50-382/9906-03 NCV Three examples of inadequate design control (Sections E8.5, E8.6, and E8.12).
LIST OF DOCUMENTS REVIEWED Procedures PROCEDURE.
TITLE REVISION NUMBER EP-002-100 Technical Support Center (TSC) Activati'
26 and 28 i
Operation, and Deactivation LP-122 Reporting of Defects and Noncompliar..
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10CFR21 ME-003-220 Station Battery Bank and Charger (18-Month)-
OP-100-002 Leak Reduction
OP-902-005 Loss of Offsite Power / Station Blackout Recovery
Procedure OP-902-022 Loss of Coolant Accident Recovery
OP-903-003 Charging Pump Operability Check 10, Change 2 OP-903-014 Emergency Feedwater Flow Verification 9 and 10 OP-903-030 Safety injection Pump Operability Verification
OP-903-033 Cold Shutdown IST Valve Tests
OP-903-035 Containment Spray Pump Operability Test 10, Change 4 OP-903-046 Emergency Feedwater Pump Operability Check
. OP-903-050 Component Cooling Water and Auxiliary Cooling 15, Water Pump and Valve Operability Test Change 2 OP-903-110 RAB Fluid Systems Leak Test 4.
OP-903-115 Train A Integrated Emergency Diesel
Generator / Engineering Safety Features Test OP-903-121 Safety Systems Quarterly IST Valve Tests
Change 2
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PROCEDURE TITLE REVISION NUMBER RWT021593 Safety injection Sump Outlet Header A Isolation W2.301 Identification, Evaluation and Reporting Process for
10CFR21 Compliance Calculations CALCULATION TITLE REVISION NUMBER 460000011 Emergency Diesel Generator Units Dynainic Loading
Study 5-1 Emergency Feedwater Pump Rooms
5-W Evaluation of Space Temperatures Following a O
Tornado 9-C-2-5-IV-W Evaluation of Space Temperatures Following Tornado O
C-PENG-CALC-015 -
Emergency Feedwater Usage
EC-192-015 Chiller Outlet Hoader Flow Instrumentation Loop
Uncertainty Calculation EC-192-016 Chilled Water Outlet Temperature instrumentation
Loop Uncertainty Calculation EC-98-001 Calculation of Maximum Allowable Battery Inter-cell O
Connection Resistance EC-E90-006 Diesel Generator Loading 3,
Change 7 EC-E91-016 Battery 3AB-S Cell Sizing -
EC-E91-050 Degraded Voltage Relay Setpoint 0,
Change 3 EC-E91-051 Battery Charger Size Verification 0,
Change 1 EC-E91-061 -
Battery 3A-S Cell Sizing
j EC E91-062 Battery 3B-S Cell Sizing
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-6 CALCULATION TITLE.
REVISION NUMBER EC-M95-012 Minimum Pipe Submergence to Prevent Vortexing
- EC-M97-006 Design Basis For CCW Makeup A
- EC-M98-013 WCT [ Wet Cooling Tower] Basin Flow to Condensate O
Storage Pool and EFW [ Emergency Feedwater] Pump Design Basis Review Calculation Upgrade Program Phase ll, Group 2 EC-M98-027.
Safety injection System - LPSI [ Low Pressure Safety
injection] Flowrate Calculation EC-S91-016 SI-602 Leakage Study
EC-P98-005 Evaluation of Nitrogen System for Over Pressurization
MN(Q)-9-3 Ultimate Heat Sink Study
MN(Q)-9-9.
Wet Cooling Tower Basin Losses 3,
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Change 3 MN(Q)-9-17 Calculation of WCT Water Losses
MN(Q)-9-38 Capacity of Wet Cooling Towers
MN(Q)-10-1 EFW System Flow 2,
Change 3 Drawinas DRAWING NUMBER-TITLE REVISION B-424 Sh. 2334S 3 Control Wiring Diagram - 4.16kV Bus 3A3-S TIE TO
BUS 3AB3-S G-160 Sh. 3 of 6
. Flow Diagram - Component Closed Cooling Water
System G-160 Sh.'1 of 6 Flow Diagram - Component Closed Cooling Water
l System G-160 Sh. 2 of 6 -
Flow Diagram - Component Closed Cooling Wat'er.
System G-160 Sh. 4 of 6 Flow Diagram - Component Closed Cooling Water
System
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-7 DRAWING NUMBER TITLE REVISION G-160 Sh. 5 of 6 Flow Diagram - Component Closed Cooling Water
System G-160 Sh. 6 of 6.
Flow Diagram - Component Closed Cooling Water
System LOU-1654 G 287 125 VDC and 120 VAC One Line Diagram
Sh.1 Condition Reports j
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97-1287 98-0683 98-0758 98-0819 98-0850
97-1844 98-0684 98-0763 98-0822 98-0852 97-2641 98-0706 98-0791 98-0844 98-0170 98-0734 98-0792 98-0848 Encineerina Reauests 98-0750 l-98-0773 98-1178 Licensina Document Chanae Reauegl 93-0094 97-0212 Deslan Chanae Packaaes DC-3362 MP-0887 Miscellaneous
- Detroit Edison DER No. 94-0564 (Agastat Relay Test Report), October 17,1994 Vendor Technical Manual for C&D, Inc., Revision 4, Change 10
' Agastat Relay Vendor (Amerace) Information Notice, September 29,1994 Ingersoll-Rand, Low Pressure Safety injection Pumps Minimum Flow Evaluation, TD 1075.0045
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