IR 05000416/1997005
| ML20148E244 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 05/29/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20148E230 | List: |
| References | |
| 50-416-97-05, 50-416-97-5, NUDOCS 9706030042 | |
| Preceding documents: |
|
| Download: ML20148E244 (51) | |
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ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION-i
REGION IV
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I Docket No.-
50-416
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License No.:
j Report No.:
50-416/97-05 l
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Licensee:
Entergy Operations, Inc.
Facility:
Grand Gulf Nuclear Station i
Location:
Waterloo Road Port Gibson, Mississippi
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Dates:
March 10-27,1997
Inspectors:
Linda Smith, Reactor Inspector, Engineering Branch j
Paul Eshelman, Consultant
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Don Prevatte, Consultant Approved By:
Chris VanDenburgh, Chief, Engineering Branch
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Division of Reactor Safety i
1 ATTACHMENT:
Supplemental Information j
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i 9706030042 970529 PDR ADOCK 05000416 G
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SUMMARY
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Grand Gulf Nuclear Station
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NRC Inspection Report 50-416/97-05 Inspection Scope
On April 28 through May 2,1997, a team comprised of one member of the NRC Region IV
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staff and two contractor representatives, conducted an engineering inspection at Grand
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gulf Nuclear Station. The primary objective of this inspection was to conduct an abbreviated safety system functional review of the standby service water and the high
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pressure core spray service water systems. The inspection team evaluated related license
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basis controls, planned corrective actions, and the translation of design requirements into plant procedures. The team also reviewed open items from other systems.
The conduct of engineering activities was considered to be generally good. Aspects of good engineering practices included highly motivated and knowledgeable design and system engineering personnel and a minimum engineering backlog. However, the lack of rigor in the implementation of the test program detracted some from this performance. In addition, the licensee did not recognize their responsibility to develop the design basis for cooling water systems considering the worst case assumptions. There also were instances, which were not indicative of current performance, where design requirements were not incorporated into plant operating procedures, and where Final Safety Analysis Report updates were not completed effectively.
Ooerations The licensee failed to correctly update the setpoints for two types of standby
service water alarms: low pump discharge pressure and high system leakage.
These failures constituted two examples of a violation ot 10 CFR Part 50, Appendix B, Criterion ill (Section 03.1).
Enaineerina Notwithstanding, the technical discrepancies identified, the inspectors concluded
that the design and testing of the service water systems indicated that their design was relatively robust, with large safety margins in most areas and parameters (Section E1.1).
The licensee had not correctly identified the worst-case design basis accident
scenario with respect to heat rejection rate and water inventory for the ultimate heat sink. This constituted one example of a violation of 10 CFR Part 50, Appendix B, Criterion 111 (Section E1.2).
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The licensee had not recognized that excessive leakage through safety-related to
nonsafety-related system interf ace valves (i.e., standby service water system to the component cooling water system) could result in the ultimate heat sink being j
outside of its design basis. As a result, the licensee had not established leak tests at either the system level or for the affected individual interf ace valves. This item is
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unresolved (Section E1.3).
The inspectors concluded that the licensee's method for performing uncertainty
calculations was acceptable for calculation development and was consistent with
current industry standards (Section E1.4).
j In general, system design criteria were implemented with respect to electrical and
instrumentation and control requirements (Section E1.5).
The inspectors concluded the licensee had not effectively maintained the design
basis of protecting the electrical equipment in the standby service water pumphouse from room flooding. This constituted one example of a violation of 10 CFR Part 50, Appendix B, Criterion ill (Section E2.1).
The inspectors identified several Updated Final Safety Analysis Report errors, which
constituted a violation of 10 CFR 50.71(e) (Sections E2.1 and E3.5).
The corrective actions taken or planned for condition reports appeared acceptable.
- However, in one case, the licensee had not developed effective corrective actions related to identified cold weather preparation weaknessra (Section E2.2).
The inspectors identified one test control violation (10 CFR Part 50, Appendix B,
Criterion XI) with several examples related to pump performance testing and heat exchanger performance testing (Sections E3.2, E3.3).
The licensee failed to maintain the fuel pool cooling and cleanup heat exchanger
heat transfer capabilities as committed in the licensing submittal which was the basis for a Technical Specification amendment (Section E3.4) The inspectors concluded this failure was caused by the test control violation described in Section E3.3.
The inspectors concluded that the current engineering drawing backlog was
reasonable and provided updated engineering and construction reference materials in a timely manner (Section E6.1).
The licensee had not established adequate contrct of the issuance of design
calculations to assure that obsolete design calculttions were clearly identified. The inspectors concluded this was a design control waakness (Section E7.1).
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Report Details 1. Operations
Operations Procedures and Documentation 03.1 Inadeauatellocorrect Alarm Response Procedures a.
Inspection Scope (93801. 37550)
The inspectors reviewed the standby service water and high pressure core spray service water system design basis to ensure that it had been correctly translated into the plant procedures and alarm response procedures. The inspectors reviewed approximately ten different types of alarms associated with the standby service j
water system and the associated Division i alarm response procedures. The inspectors also evaluated the associated Divirion Il alarm response procedures when problems were identified.
b.
Observations and Findinas The inspectors did not identify any weaknesses related to seven of the alarms.
However, three of the alarms did involve a weakness or a discrepancy.
Standbv Service Water Coolina Tower Fan A Trio - Alarm Response
Instruction 04-1-02-1H13-P870-1 A-B1, "SSW [ Standby Service Water] Clg Twr Fan A Trip," Revision 100, provided the instructions for operator action following a trip of cooling tower Fan A. Step 4.2 stated, " Perform the following steps as necessary to reduce the heat load to maintain SSW Pump A discharge temperature below 90 F." Step 4.2.1 stated, "If Loop A is supplying RHR [ residual heat removall operation, shift RHR operations to RHR Loop B or C and SSW Loop B."
Although the residual heat removal system was capable of meeting its loss-of-coolant-accident design basis with only one loop in operation, the inspectors were concerned that removing Loop A from service, as mandated by this step, would not be necessary or even desirable. On the loss of cooling tower Fan A, the Standby Service Water Loop A cooling capability would be reduced to its natural draft capacity, but not totally lost. The standby service water and residual heat removal system Loop A could still be retained in service at a lower heat removal rate, thereby, maintaining the maximum overall residual heat removal system cooling capability, redundancy, and flexibility. This could be accomplished by throttling the residual heat removal system flow through the "A" residual heat removal system heat exchanger, to maintain the standby service water temperature
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less than 90 F. This residual heat removal system throttling technique is
commonly used during normal plant shutdowns to limit the cooldown rate of the reactor vessel, therefore, this operation would not be contrary to the operators' training and experience.
l This weakness was discussed with the licensee, and they stated that they planned to correct the procedure,
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Standbv Service Water Pump A Discharae Pressure Low - Alarm Response
Instruction 04-1-02-1H13-P870-1 A-D1, "SSW Pmp A Disch Pres Lo,"
Revision 100, and Alarm Response Instruction 04-1 -02-1 H 13-P870-7 A-D 1,
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"SSW Pmp B Disch Pres Lo," Revision 100, indicated that the low discharge l
pressure setpoint was 81 psig. Discussions with the licensee revealed that this was the setpoint that corresponded to the original standby service water
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pumps that were replaced before the original plant startup by Design Change
Package 82/5020. Design Change Package 82/5020 increased the pump j
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capacity and raised system pressure.
The setpoint had originally been selected to alert operators that pump j
discharge pressure was below the pressure necessary to accomplish the
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system's safety function. When the licensee determined it was necessary to raise system pressure and replace the pumps, the alarm setpoint was not
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revised to correspond with the new analysis. The new pumps required a l
significantly higher setpoint. The inspectors had not determined by the end
of the inspection if an updated setpoint had been included in the original design change package and not actually implemented, or if the licensee had failed to include this design change in the design change package, in either case, the alarrn setpoint was not updated when the system pressure was raised.
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l 10 CFR Part 50, Appendix B, Criterion Ill, " Design Control," requires that J
measures shall be established to assure that applicable regulatory j
requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. The licensee's failure to correctly
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update the alarm setpoint is the first example of a violation of 10 CFR Part
50, Appendix B, Criterion 111(50-416/9705-01).
Hiah Standbv Service Water Looo Lea _ka_ge - Alarm Response
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l Instructions 04-1-02-1H13-P870-1 A E1, "SSW Loop A Leak Hi,"
l Revision 100, and 04-1-02-1 H13-P87.0-7A-E1, "SSW Loop B Leak Hi,"
l Revision 100, indicated that the high loop leakage setpoint was a standby l
service water loop discharge flow rate that was 950 gpm greater than the return flow. The licensee indicated that the instrument setpoint had been changed to 1,200 gpm by Design Change Package 81/5015 to correspond to the replacement of the original standby service water pumps with higher
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performance pumps. However, the design change package did not include direction to change the alarm response procedures.
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The licensee's failure to update this alarm response procedure is the second example of a violation of 10 CFR Part 50, Appendix B, Criterion lil
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(50-416/9705-01).
c.
Conclusions
The licensee failed to correctly update the setpoints in four alarm response
procedures after the standby service water system was modified to incorporate higher performance pumps. These failures are two examples of a violation of 10 CFR Part 50, Appendix B, Criterion Ill.
lli. Enaineerina E1 Conduct of Engineering i
j E1.1 Overall Desian Caoability of Standbv Service Water and Hiah Pressure Core Sorav Service Water Systems
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a.
Inspection Scone (93801,37550)
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During the review of the individual components and parameters associated with the i
standby service water and high pressure core spray service water systems, the
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inspectors identified a number of poor engineering practices, which are documented i
in later sections of this inspection report (Sections E1.2, E1.3, E3.1, E3.2, E3.3 and E3.4). To understand the immediate safety implications of these practices, the inspectors assessed the overall capabilities of these systems, the safety margins that were included in their designs, and in the testing procedures.
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b.
Observations and Findinas
i The inspectors found large safety margins in several aspects of the design and testing of the standby service water and high pressure core spray service water
systems. The following are descriptions of the more significant areas and parameters observed by the inspectors:
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The design calculations and testing assured that the systems would produce
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their full design flow even after 30 days into an accident event when the
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standby service water basin would be at its minimurn level. Since the standby service water heat loads would continuously decrease after the
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initial accident spike (from approximately 200 million BTU /hr on the first day to approximately 98 million BTU /hr on the 30th day), the actual required j
flow to meet the design accident heat loads would also be substantially j
reduced. Therefore, from the beginning of an accident the system was
analyzed to deliver more than the required flow to handle the accident heat loads.
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The licensee had designed the safety-related roorn coolers to ensure that with design basis heat loads the room temperatures would be well below the actual design environmental qualification temperatures for the rooms.
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The licensee had ensured that the actualloads for the diesel generators was significantly less than the diesel generator's capacity. Therefore, the diesel generator heat load on the standby service water system was significantly less than design.
4.
The licensee had not taken credit for water makeup to the standby service water basin during the design basis accident duration of 30 days. However, it was reasonable to expect that makeup could and would be provided during that period because multiple sources would be available.
5.
The licensee had not taken credit in the accident analyses for the sensible heat sink of the concrete in the cooling tower, the standby service water basin, the earth around the basin, the system hardware, or by the heatup of the water in the basin from ambient temperature to the design basis 90 F.
6.
The accident analysis used a design basis maximum fuel pool cooling heat load with a full fuel pool, at the shortest allowable outage duration. These assumptions were combined with the worst, end-of-core-life decay heat from i
the reactor, which could not exist at the time of restart after an outage.
Similarly, at the actual end of core life, just before a refueling outage, the
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fuel pool heat load cannot be at its design basis maximum because even the i
hottest stored fuel would have decayed for approximately 18 months.
Therefore, the heat loads used in the analysis are very conservative.
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The licensee assumed a cooling tower drift rate in the safety analyses that was significantly higher than rates that have been actually observed in tests.
c.
Conclusions The inspectors concluded that the overall design and testing of the standby service water and high pressure core spray service water systems indicated that their design was relatively robust, with large safety margins in most areas and parameters.
E1.2 Nonconservative Standbv Service Water Basin Water Inventorv Calculation a.
insoection Scope (93801, 37550)
The inspecto.s reviewed the expected performance of the standby service water system with respect to its ultimate heat sink function. This included the ability of the system to transfer the anticipated accident heat loads to the atmosphere through the cooling towers without exceeding the maximum allowable system temperatures. It also included verifying that the system was capable of performing
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this function, in accordance with General Design Criterion 44, " Cooling Water,"
over the full 30-day duration for the design basis accident.
Calculation MC-Q1P41-86007, Revision 0, dated July 25,1986, " Standby Service Water Ultimate Heat Sink Performance," was the licensee's analysis that addressed j
these parameters for the worst 30-day event. The following are concerns identified by the inspectors with this analysis.
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Observations and Findings
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Updated Final Safety Analysis Report Section 9.2.1.3, "lStandby Service Water
System] Safety Evaluation," contained a lengthy discussion of the performance of the ultimate heat sink based on the above cited calculation. Included was the expected water inventory loss over the 30-day accident period due to evaporation and drift from the cooling towers. The discussion concluded that at the end of the 30 days there would be approximately 2.5 million gallons of usab/e water left in the cooling tower basins, even when accounting for 300,000 gallons that would be required to assure adequate submergence of the standby service water pumps to prevent vortexing and/or cavitation. The inspectors calculated that this margin would allow up to approximately 58 gpm of additional water loss due to leakage from the systems that was not specifically addressed in the calculation or the Updated Final Safety Analysis Report discussion.
Calculation MC-Q1P41-86007 was based on what was considered at the time to be the worst-case accident scenario [i.e., loss-of-coolant-accident coincident with a loss-of-offsite-power, and the worst single active failure (the loss of the A standby diesel)). The Updated Final Safety Analysis Report safety evaluation discussion also stated that these and the accompanying assumptions would "... result in the greatest heat rejection rate for the ultimate heat sink..,," and that, "All other modes [ events, conditions) are less severe with respect to heat rejection from the ultimate heat sink and are considered to be enveloped by this analysis."
The inspectors questioned if this would actually be the worst-case accident scenario, particularly with respect to heat transfer and water inventory loss. For example, a more conservative scenario appeared to be a loss-of-coolant-accident coincident with loss-of-offsite power, without a single f ailure. In this scenario, all of the standby service water and high pressure core spray service water pumps and other plant pumps and equipment would continue to operate. This would cause considerably more heat load to be applied to the heat sink over the 30-day period.
Additionally, the operation of all the service water pumps would increase the drift loss from the cooling towers.
in response to the inspectors's questions, the licensee performed an informal assessment of the more conservative scenario (i.e., loss-of-coolant-accident coincident with a loss-of-offsite power, without a single f ailure) that indicated that with the additional water losses there still be adequate submergence for the standby service water pumps with margin. However, this margin would be significantly reduced. The reduced margin would allow only approximately 20 gpm of system leakage.
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General Design Criterion 44, " Cooling Water," states,
"A system to transfer heat from structures, system, and components important to safety to an ultimate heat sink shall be provided. The system safety function shall be to transfer the combined heat load of these structures, systems, and components under normal operating and accident conditions.
Suitable redundancy in components and features and suitable interconnections, leak detection, and isolation capabilities shall be provided to assure that, for onsite electrical power system operation (assuming offsite power is not available) and for offsite power operation (assuming onsite power is not available), the system safety function can be accomplished, assuming a single failure."
Updated Final Safety Analysis Report, Section 3.1.2.4.15, " Criterion 44 - Cooling Water, Discussion," included the licensee's commitment to the specific safety functions discussed in General Design Criterion 44.
10 CFR 50.2, " Definitions," states,
"As used in this part, Design Bases means that information which identifies the specific functions to be performed by a structure, system or component of a facility, and the specific values or ranges of values chosen for controlling the design.
10 CFR Part 50, Appendix B, Criterion 111, " Design Control," states that,
" Measures shall be established to assure that applicable regulatory requirements and the design basis, as defined in
[Section) 50.2 and as specified in the license application, for those structures systems and components to which this appendix applies are correctly translated into specifications, drawings, procedures and instructions... The design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods or by the performance of a suitable testing program."
The inspectors determined that the licensee had not identified the worst-case,
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design basis condition that would o are that the standby service water system's safety function would be accomplished. As a result, the licensee had not established design control measures which assured that the specific functions described in General Design Criterion 44 were correctly translated into specifications, drawings, procedures and instructions. The inspectors concluded the f ailure to analyze the worst case from the perspective of the cooling water safety function was a third example of a violation of 10 CFR Part 50, Appendix B, Criterion ill (50-416/9705-01).
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The licensee stated that in general they were not required to identify the worst-case single failure from the perspective of safety functions like heat transfer for the standby service water system. They believed the single failure was predetermined
in the accident analysis performed to ensure containment pressures remained
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acceptable. This concerned the inspectors. Based on the informal analysis
'I described above, the inspectors believed that, for the standby service water system, the actual design is likely acceptable. However, this design philosophy
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could have been applied to other safety functions listed in the general design criteria, where the design does not have as much inherent margin.
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c.
Conclusions
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The licensee had not correctly identified the most conservative design basis j
accident scenario with respect to heat rejection rate and water inventory for the ultimate heat sink. The inspectors concluded the failure to analyze the worst case l
l from the perspective of the cooling water safety function was a design control violation.
E1.3 Failure to Perform Svstem Leakane Testina a.
Inspection Scope (93801. 37550)
As described in Section E1.2 above, limiting the leakage of the standby service water and high pressure core spray service water systems was critical to assuring that the system could perform its design basis function for the full 30-day period without makeup as described in Updated Final Safety Analysis Report, Section 9.2.1, " Standby Service Water System." Therefore, the inspectors reviewed the licensee's activities to translate this aspect of the design basis into the plant's procedures and practices, b.
Observations and Findinas The inspectors observed that the licensee's plant staff or engineering personnel had not generally recognized that there was a limit on the standby service water and high pressure core spray service water system leakage that could be tolerated without rendering these systems inoperable with respect to the 30-day basin inventory requirement. In general, periodic leakage tests were not being performed for these systems or the valves that formed the boundaries between these systems and the nonsafety-related systems with which they interf aced (i.e., the component cooling water, plant service water, and turbine building closed cooling water systems). As an exception, the licensee was routinely measuring the seat leakage i
for the check valves that had previously been discovered to be significant leakers.
Additionally, the licensee had not considered this potential leakage to be significant since the allowable leakage seemed relatively large, there were perceived normai-operating system leakage indicators, other testing was adequate to identify such leakage, and the operators would take whatever actions were necessary to provide makeup.
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The inspectors did not agree with the licensee's position for the following reasons:
(1)
Even at the originally understood maximum allowable system leakage rate of approximately 58 gpm, the potential existed that total valve leakage could easily degrade to this value considering the number of potential leakage paths and the sizes of some of these paths, if they were not tested.
(2)
The primary normal-operating leakage indicator (i.e., system makeup tank
level) was not a reliable indicator for two reasons:
There were double isolation valves at the system boundaries to
provide single-failure protection; however, if one valve had an unacceptable leakage rate and the other did not leak, there would be
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no perceived leakage through that boundary.
If there were leakage at more than one boundary, with one of the
boundaries leaking into the standby service water system, the measured leakage (i.e., the net difference between the inleakage and j
the outleakage) would be small.
(3)
While the other testing (i.e., valve stroke testing and VOTES testing) could
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provide indicators of the leakage potential of globe and gate valves, this
testing would not provide a reliable indicator of the leakage potential of the
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several butterfly valves in the system.
(4)
Some of the valves were normally open; therefore, there would be no normal operating indicators of their leakage characteristics.
(5)
Although the operators would take action to provide makeup in an actual accident, these actions were outside the system licensing / design basis, which was system operability for 30-days without additional makeup.
The inspectors maintained that such testing should be performed in accordance with the American Society of Mechanical Engineers (ASME) Boiler and Pressure Code, Se'ction XI, " Rules for Inservice inspection of Nuclear Power Plant Components,"
which includes a valve testing program. Specifically, Article IWV-3421, required
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Category A valves (i.e., those for which seat leakage was limited to a specific maximum amount in the closed position to fulfill their function) to be periodically leak tested.
The licensee disagreed with this position and cited an NRC staff statement found in NUREG-1482, " Guidelines for Inservice Testing at Nuclear Power Plants,"
page A-17, that, "When a [ check] valve has a safety related function to close to
prevent diversion of flow between trains of a system, there may be a leakage limit based on total system requirements. The Code does not specifically require that
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these valves be Category A." The licensee concluded that the valves were not d
required to be classified as ASME Category A valves since, in this case, there was a
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" total system limit" as opposed to " individual valve limits."
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The inspectors believed that the licensee had misapplied the NRC staff's statement to this case. The statement was applicable to check valves and none of the valves questioned were check valves. The statement was also applicable to " diversion of
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flow" situations (i.e., gross leakage). This was not the concern in this case because the leakage that would render this system inoperable, with regard to inventory loss, would be insignificant with regard to diversion of flow. Therefore, the statement was not applicable to this case.
i The licensee also cited other internal NRC evaluations to support their position.
Based on these evaluations the licensee expressed the position that since the leakage limit was a " system limit" as opposed to an " individual valve limit", the i
ASME Code was not applicable. Therefore, the valves were not required to be leak
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tested. However, there is ample precedent for requiring individual valve leakage testing where overall system limits exist (e.g., the leakage testing requirements of 10 CFR Part 50, Appendix J). For such cases, the licensee should assign individual
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valve limits consistent with the overall limit, and the number and size of the potential leakage paths. Additionally, the question of whether these vaives should
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be leak tested individually or as part of overall system integrated le akage testing was considered by the inspectors to be essentially academic: A testing program j
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that would test overall integrated systerr leakage, with the inboard and outboard
valves pressurized separately, would be just as effective at demonstrating the
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system's 30-day inventory capability without makeup as would individual valve j
testing. The inspectors noted the licensee had not established a testing program that would test overall system integrated leakage.
At the conclusion of the inspection, the following boundary valves had been identified by the inspectors as likely potential leakage paths requiring testing:
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Component Coolina Water (CCW) Svstem Interfaces
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i Valve Number Description
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Q1P42F105 10" CCW supply viv to Fuel Pool Cooling and Cleanup (FPCC) hx's a
Q1P42F205 10" CCW return viv from FPCC hx's
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l Q1P42F032B 8" FPCC hx return CCW-to-SSW x-conn. viv.
Q1P42F204 8" FPCC hx return CCW-to-SSW x-conn. viv,
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i Q1P42F028B 8" FPCC hx supply CCW-to-SSW x-conn. viv.
j Q1P42F203 8" FPCC hx supply CCW-to-SSW x-conn. viv.
Q1P42F200A 8" SSW supply viv. to FPCC hx's Q1P42F200B 8" SSW supply viv. to FPCC hx's j
Q1P42F201A 8" SSW return viv. from FPCC hx's
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Valve Number Descriotion Q1P42F201B 8" SSW return viv. from FPCC hx's
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Plant Service Water System interfaces Valve Number Descriotion Q1P44F054 8" SSW supply to drywell chillers Q1P44F042 8" SSW supply to drywell chillers Q1P44F067 8" SSW return from drywell chillers
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Q1P44F052 8" SSW return to drywell chillers in addition, General Design Criterion 46, " Testing of Cooling Water System," states that, "The cooling water system shall be designed to permit appropriate periodic pressure and functional testing to assure (1) the structural and leaktight integrity of its components." In Updated Final Safety Analysis Report, Section 3.1.2.4.17, the licensee committed to General Design Criterion 46.
Considering the relatively small allowed system leakage rate, the inspectors determined that, in the absence of system leak testing, it was appropriate to individually test to assure the leaktight integrity of these components. Cumulative leakage above 58 gpm, would result in the ultimate heat sink being outside of its reported design basis. Cumulative leakage in excess of 20 gpm, would result in the ultimate heat sink being outside of its actual design basis (See Section E1.2).
Excessive leakage could prevent the standby service water and high pressure core spray service water systems from performing their safety functions.
10 CFR 50.55a, " Codes and standards," Section (g)(4), required that, "Throughout the service life of a boiling or pressurized water-cooled nuclear power facility, components (including supports) which are classified as ASME Code Class 1, Class 2, and Class 3 shall meet the requirements... set forth in Section XI.... "
Under Article IWV 3421 of the Code, Category A valves (those for which seat leakage was limited to a specific maximum amount in the closed position to fulfill their function) were required be leak tested. Whether or not the failure to establish -
the above listed safety-related to nonsafety-related systems interface valves as Category A valves and perform the required leak tests,is unresolved pending further evaluation by the Office of Nuclear Reactor Regulation (50-416/9705-02).
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c.
Conclusions
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The licensee had not recognized that excessive leakage through safety-related to nonsafety-related system interf ace valves could result in the ultimate heat sink
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being outside of its design basis. As a result, : hey had not established leak tests at
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either the system level or for the affected individuai interf ace valves. This issue remains unresolved pending further NRC review.
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l E1.4 Setooint Calculation Proaram Review for Standbv Service Water Instrumentation
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a.
Insocction Scope (93801. 37550)
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l The inspectors reviewed instrumentation and Control Standard GGNS-JS-09, i
" Methodology for the Generation of Instrument Loop Uncertainty & Setpoint Calculations," Revision 0, dated March 23,1993, and Performance and System Engineering Instruction 17-S-01-10, " Instrument Scaling Program," Revision 0, dated October 23,1993. The inspectors also reviewed two standby service water setpoint calculations and the corresponding surveillance procedures.
b.
Observations and Findinas The inspectors found that Standard GGNS-JS-09 was consis'ient with current industry practice. The inspectors noted that the standard recommended the use of the " square root of the sum of the squares" method as the means of collecting the instrument drift uncertainty effects. The inspectors noted that this method is acceptable as long as the instrument drift effects of the instrument data are random. However, in discussion with the system engineer for the standby service water system the inspectors noted that the licensee had made no effort to confirm the data as random, even though the data was readily available in a data base. As of the end of the inspection, the licensee had no plans to address this issue. The inspectors considered this to be a weak response to this technical concern.
The inspectors noted that the instruction 17-S-01-10 provided administrative controls for the instrument scaling program, but did not provide technical guidance.
The licensee planned to upgrade the instruction later this year.
The inspectors did not identify any technical errors in the calculations reviewed.
One minor weakness related to the control of reference data and superseded calculation parameters was discussed with the licensee.
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Conclusions The inspectors concluded that the licensee's method for performing uncertainty calculations was adequate for calculation development and was consistent with current industry standards. The inspectors noted minor reference and updating problems. In addition, the inspectors noted the licensee was not verifying that instrument drifts that were assumed to be random in the setpoint calculations actually were measured to be random.
E1.5 System Desian Criteria Reauirements for Standbv Service Water System a.
Inspection Scoce (93801, 375501 The inspectors's review of the systern design criteria identified specific instrumentation requirements for monitoring the standby service water status and performance. The standby service water electricalinterfaces to other plant systems was reviewed by the inspectors to assure system availability could not be affected by other system failures. The logic diagrams used to describe the control and operating functions of the standby service water were reviewed to verify functional conformance with the requirements of the system design criteria and Updated Final Safety Analysis Report.
b.
Observations and Findinas b.1. Standbv Service Water oH Alarm The inspectors determined that the system design criteria document included a requirement to provide an alarm for standby service water pH in the control room.
However, the inspectors found that this alarm had not been included in the facility design. The inspectors noted that this alarm was not required by either the Updated Final Safety Analysis Report or the Technical Specifications. The licensee issued Condition Report GGCR1997024000 to remove the design requirement from the system design criteria.
b.2. Standby Service Water System Electrical Interf ace The inspectors selec " one electricalisolator for detailed review to confirm that the isolator met the applL.n.e design criteria. The inspectors confirmed that the isolator provided accepcable protection from the maximum creditable fault voltages available to the standby service water system cables.
b.3. Review of Loaic Diaarams for Standbv Service Water Control and Operation The inspectors reviewed several logic diagrams and electrical schematics to confirm implementation of the design criteria. The inspectors did not identify any inconsistencies or conflicts. There were several functionally insignificant drawing errors, which the licensee planned to correct as the drawings were updated.
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Conclusic"ts
l Although some minor errors were identified and resolved, the licensee had properly l
implemented the system design critena with respect to electrical and instrumentation and control requirements.
E2 Engineering Support of Facilities and Equipment
l E2.1 Nonconformance of Standbv Service Water Pumohouse Flood Protection Sealina l
a.
Inspection Scope (93801. 37550)
The inspectors performed several inspections of the physical hardware and spaces i
associated with the standby service water and high pressure core spray service water systems. In tiie course of these inspections, the following nonconformance l
was identified.
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l b.
Observations and Findinas i
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l b.1 Standby Service Water Pumos Not Sealed at Pumo Base Drawing C-17368, " Units 1 & 2 SSW Cooling Tower Basin Misc & Embedded Steel Sections & Details," Revision 8, January 29,1986, specified that a continucus l
bead of silicone sealant be applied around the bases of the standby service water l
pumps. During a plant tour, the inspectors discovered that this particular feature
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had not been installed in either pumphouse.
l The inspectors reviewed the Updated Final Safety Aralysis Report to determine the safety significance of this observation. The inspectors found that the seal was included in the design to prevent basin water, whose level could be the same as the flood level, from entering the pump houses. Updated Final Safety Analysis Report Section 2.4.2, " Floods," described the most severe flooding condition for the l
j standby service water pump houses. The rooms were designed for localintense j
precipitation that would cause surface water buildup to exceed the floor elevation of l
the pump houses,130 feet. In accordance with this description, such a storm l
could cause flooding at the pump houses as high as 133.22 feet and water surface l
elevations above 133 feet for as long as 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />.
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Updated Final Safety Analysis Report Section 2.4.10, " Flooding Protection f
Requirements," stated, l
"It was also determined that water (from such a flood] entering the standby service water pump houses through doorways, equipment hatches, and various floor penetrations could affect floor mounted safety-related electrical equipment." It also
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stated that "Several modifications to the floor, exterior walls, and doors in the form of seals, penetration sleeves, toe plates, and curbs were provided to provent water from reaching the floor mounted safety-related equipment and to assure safe plant operation."
The licensee showed that, since the time of the Updated Final Safety Analysis Report description, the drainage topography of the site had been improved and
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l reanalyzed. The reanalysis showed that for this most severe event the water level l
would no longer reach the elevation of the pump houses.
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The inspectors concluded that the seal was needed to implement the safety basis l
described in the Updated Final Safety Analysis Report, however, the safety analysis l
report had not been updated when the drainage was reanalyzed. Therefore, there l
appeared to be no actual safety significance associated with the missing pump base seal.
10 CFR 50.71(e) requires that the licensee periodically update the Final Safety
Analysis Report, originally submitted as part of the application for an operating l
license, to assure that the information included in the Final Safety Analysis Report l
contains the latest material developed. The failure to update the safety analysis report when the drainage was reanalyzed was the first example of a violation of 10 CFR 50.71(e) (50-416/9705-03).
l b.2 Inadeauate Pumo Shaft Leakaae Drain Desian
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l Upon re-inspection of the installation of the missing pump base seal, the inspectors identified another potential concern. At the "A" stsndby service water pump, the l
inspectors observed that water was leaking from the pump shaft seal (a normal and expected condition) onto the floor and puddling from a pump leakoff connection that was not connected to any piping. The inspectors noted that the "B" pump had
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l the same configuration, but it was not leaking.
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Prior to correcting the above described nonconformance, this leakage drained to the l
basin through the unsealed gap between the pump base and the floor. The inspectors were concerned that pump shaft sealleaks could have the same potential to cause failure of the electrical equipment in the room as water from a design basis rainstorm. The inspectors concluded that the design basis requirement to prevent water from reaching the floor mounted safety-related equipment, as discussed in Updated Final Safety Analysis Report Section 2.4.10, " Flooding Protection Requirements," was not adequately implemented iri the current design.
10 CFR Part 50, Appendix B, Criterion Ill, requires that the design basis as specified in the license application is correctly translated into drawings. The failure to design f
drains for a normal and expected source of water is fourth example of a violation of 10 CFR Part 50, Appendix B, Criterion 111(50-416/9705-01).
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c.
Conclusions The inspectors concluded the licensee had not effectively maintained the design basis of protecting the electlical equipment in the standby service water pumphouse from room flooding. The current design required a pump base seal that was not installed. The seal was not needed because site drainage had been improved.
However, the Updated Final Safety Analysis Report was not updated when the drainage was improved and the flooding was reanalyzed. Finally, the current design did not include provisions for draining pump shaft sealleakage, a normal and expected condition which could cause room flooding.
E2.2 Review of Licensee Identified Condition Reports a.
Insoection Scoce (93801. 37550)
The inspectors reviewed five condition reports associated with the standby service water system to verify adequacy of interim corrective measures and long-term corrective action plans.
b.
Observations and Findinas The inspectors found corrective actions for four of the condition reports to be acceptable. The fourth condition report, (GGCR1996-0553-00) was initiated by the licensee to identify potential freezing and icing concerns related to the ultimate heat sink cooling tower. The inspectors were concerned that the compensatory measures developed for this condition were not implemented.
On December 5,1996, the licensee identified that inadequate cold weather plans had been developed for sleet and ice storms. The licensee was concemed that ice could collect on the standby service water system cooling tower fan blades or fan shafts resulting in fan imbalance and possible blade / shaft damage For sleet and ice storms, the licensee was also concerned that ice could collect on the 1-inch missile gratings resulting in clogged gratings. In the same condition report, the licensee also identified that heat tracing was not installed on the standby service water 24-inch riser piping or on the 6-inch high pressure core spray riser piping which supplies the cooling tower basin.
The licensee concluded the best way to protect the fans during sleet and ice storms was to turn them on without initiating standby service water flow whenever
weather conditions existed that could result in icing. Operations planned to monitor ice accumulation if significant accumulation was noted then standby service water system flow would be initiated (with the fans stopped) to remove the accumulated
ice. During periods of extreme cold weather, the operators planned to monitor the j
surface of the cooling tower basin for freezing, if surface freezing was identified
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then the licensee planned to initiate standby service water flow without turning on
the fans. Once the ice was cleared, the standby service water flow would be I
i secured.
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Subsequent to the development of these interim measures, an ice storm occurred and the licensee determined that the interim measures were unrealistic.
Specifically, the site safety officer did not allow the inspection of the fan blades and l
motor bearings for personnel safety reasons.
The inspectors were also concerned that adequate cold weather plans had not been developed for all anticipated weather conditions. The licensee planned to minimize ice forming on the blades by running the fans during the ice storm. However, operation of the fans could cause cooling and freezing on the surface of the basin.
Current temporary procedures then require stopping the fan and circulating the basin water until the ice is gone at the tower base. During the period of stopped fans the inspectors was concerned the fan blades would then collect ice from freezing rain, resulting in possible blade and shaft damage.
The licensee stated that plans were in place to develop improved freeze protection prior to next winter. Additional inspection is planned to confirm the adequacy of l
these corrective action measures. This inspection will be tracked as an inspection
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followup item (50-416/9705-04).
i c.
Conclusions The corrective actions taken or planned for condition reports appeared acceptable.
However, in one case, the licensee had not developed effective corrective actions related to identified cold weather preparation weaknesses.
E3 Engineering Procedures and Documentation E3.1 Standbv Service Water Pumo Curves Discreoancv
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a.
Inspection Scoce (93801. 37550)
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The inspectors reviewed the ASME Code,Section XI, pump testing addressed in l
Surveillance Procedures 06-OP-1P41-0-0004, " Standby Service Water Loop A l
Valve and Pump Operability Test," Revision 102, dated August 16,1996, 06-OP-1P41-O-0005, " Standby Service Water Loop B Valve and Pump Operability Test," Revision 102, dated January 23,1997, and 06-OP-1 P41-O-0006, "HPCS l
Service Water System Valve and Pump Operability Test," Revision 102, dated j
l December 13,1996.
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b.
Observations and Findinas
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l The inspectors reviewed the pump curves that were the bases for the acceptance criteria of the surveillance procedures. The inspectors discovered that tha "A" and
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"B" pump curves were based on testing that the licensee had performe'.i onsite that iridicated performances significantly above the vendor test curves mvided in the
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Goulds Pumps, Inc., vendor manual dated June 8,1994.
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This discrepancy originated before initial plant startup. The licensee had determined that the original "A" and "B" standby service water pumps had inadequate
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performance to meet the accident analyses requirements. In 1982, this l
performance was upgraded before the pumps were shipped from the vendor by l
installing larger diameter impellers and drive motors. The pumps were then tested by the vendor, with the results documented by the above described vendor curves.
The pumps were subsequently disassembled, shipped to the site, reassembled,
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installed, and retested by site personnel. However, these tests yielded significantly l
higher performance curves than had been observed by the vendor's tests.
Specifically, the pump curve for the "A" pump was approximately 11 percent higher
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and the "B" pump was approximately 13 percent higher at the 10,500 gpm test
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point. These higher curves were adopted as the inservice test reference curves, with no credible explanation provided for the apparent performance increases.
l Based on this concern, the inspectors attempted to determine the explanation for
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l this discrepancy. The test procedure steps and formulas for calculating basin level, developed head, and pump flow were reviewed detail-by-detail, with no discrepancy
found. The vendor's testing methods and setups were also discussed with the vendor, and, likewise, no discrepancy could be identified. The calibration records
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for some of the instruments were also reviewed. Although the calibration records included some relatively large as-found errors in the installed plant instrumentation
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l used in test performance, this condition did not appear to be the discrepancy source since the errors in the as-left condition were much smaller and, therefore, would not account for the discrepancy magnitudes. Additionally, the initial preoperational l
tests had been performed with very accurate test instrumentation rather than the l
installed plant instruments, and those results had indicated the same discrepancies between the vendor curves and the site generated curves.
The inspectors considered that the most like'y explanation for this discrepancy lay in an unidentified instrumentation problem. One possibility that could not be explored during the inspection was the possible incorrect installation of the flow orifices used for the testing. Due to their location inside the full-flow recirculation i
piping, which was underwater in the standby service water cooling tower basins, these orifices could not be inspected while the plant was in operation. The possibility existed that they could either be the incorrect size, installed incorrectly l
(in backwards), or some other installation error. Another possible explanation involved the location of the test flow instruments (01P41-Fi-R009A and B) relative
I to the flow orifices. These instruments were located several feet above the flow orifices and the surface of the cooling tower basins. Since there were no feature or l
procedural step to assure that the instruments were properly filled and vented for l
the tests, the potential existed for the instruments to be partially filled with air, which could skew their readings.
Although the high pressure core spray service water pump had not undergone the same upgrades as the standby service water pumps before plent startup, the inspectors noted that its developed head reference value (baseline data measured onsite and included in the inservice test procedure) was also approximately 5 percent above the manuf acturer's curve at the test point of 700 gpm.
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This potential discrepancy could not be resolved at the end of the inspection. The discrepancy was significant because if the vendor curves were correct, then the bases for the pLrformance testing acceptance criteria since plant startup would have been nonconservative. Additionally, any performance degredation from the curves used for the surveillance testing acceptance criteria could be important since the vendor's curves were the performance bases for the plant accident analyses.
Further inspection is planned of the licensee's investigation to determine the cause of the pump curve discrepancy. This inspection will be tracked as an inspection followup item (50-416/9705-05).
c.
Conclusions The inspectors concluded that identified pump performance curve discrepancies had not yet been explained. The inspectors was concerned about these discrepancies, i
because if the pump vendor curves were correct, the current pump performance for l
Standby Service Water Pumps A and B and the high pressure core spray pump
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would be below the performance credited in the accident analyses.
E3.2 Standbv Service Water /Hiah Pressure Core Sorav Service Water Systems' Pumo Surveillance Testina a.
Insoection Scoce (93801,37550)
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The inspectors reviewed the standby service water and high pressure core spray service water systems and the equipment inservice testing procedures to verify their correctness, adequacy, and completeness. Samples of the most recent test results l
were also reviewe ' to verify that the actual system and equipment performances were within acceptable values.
i b.
Observations and Findinas In April of 1996, the standby service water pumps were rebuilt to repair damage caused by contact between the impeller and other components due to the
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degradation of washers made of improper material that had been used in their assembly. After the rebuild, the pumps were retested, and the Pump A curve was found to be approximately 5 percent less than the previous reference curve.
I Although no credible reason was ever determined for the magnitude of the change, l
the new differential pressure (i.e., developed head) of 131.9 psid at the test point j
(10,500 gpm) was incorporated into the inservice test procedure as the reference l
value. This process was documented in Engineering Request 96/0215.
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With the 10 percent degradation allowed by ASME Code,Section XI, the resultant new lower action range acceptance criteria for the developed head (118.8 psid) was l
less than the vendor curve at this flow (124.0 psid). Since the plant accident l
analysin was based on the vendor curves, the new acceptance criteria was less
than the performance required to satisfy the accident analyses. The inspectors
otPJ that the "B" pump acceptance criteria was not changed; therefore, it i 2mained above the vendor curve and the accident analyses.
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As discussed in Section E3.1, the developed head reference value (i.e., the baseline data measured onsite and included in the inservice test procedure) for the high pressure core spray service water pump was also approximately 5 percent above the manufacturer's curve at the test point of 700 gpm. The inservice test l
procedare allowed the developed head to degrade approximately 10 percent (or as l
low as 81.9 psid) at the reference flow rate (i.e.,700 gpm) without the pump being l
considered inoperable. However, the pump manufacturer's curve, which was used to prepare the accident analyses, indicated a developed head of 83.8 psid at 700 gpm. Therefore, the high pressure core spray pump inservice test procedure would also have allowed performance below the levels credited in the accident analyses without the pump being considered inoperable.
Although the instrumentation used for these tests met the requirements of ASME l
Code,Section XI, the inspectors determined that the procedures acceptance criteria contained no factors to account for the instrument error when comparing the test l
results against the minimum acceptable pump performances to meet the accident l
analyses requirements. The inspectors also observed that there was a flow l
tolerance of 100 gpm for the "A" and "B" pumps and 5 gpm on the high
pressure core spray service water pump. Both of these factors (i.e., instrument i
error and flow tolerances) would have allowed the actual performance to be somewhat less than that indicated by the raw test data.
The inspectors also reviewed that latest actual test data to determine if any performance of the pumps had actually dropped below the vendor curves. The raw l
data indicated that all of the subject pumps performed above vendor curves and, l
therefore, the accident analyses values. However, since the instrument error and i
flow tolerance effects described above had not been included, it was not determined if any of the performances, when corrected for these factors, would have been below the vendor curves.
l The inspectors noted that Surveillance Procedures 06-OP-1P41-Q-0004, " Standby Service Water Loop A Valve and Pump Operability Test," and 06-OP-1P41-O-0006,
"HPCS Service Water System Valve and Pump Operability Test," appeared to meet all of the requirements for inservice testing specified by ASME Code,Section XI.
However, the inspectors found that while the procedures included purpose
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l statements, "To demonstrate the operability of the Div 1 (2) SSW pump...," they did not demonstrate that the pumps would perform in service at or above the acceptance limits contained in the plant accident analyses. The inspectors also noted that, within the context of relief requests, NUREG-1482, " Guidelines for Inservice Testing at Nuclear Power Plants," page 5-4, indicated that it was the NRC staff's expectation that pump performance acceptance criteria be established that do not conflict with operability criteria for flow rate and differential pressure in the Technical Specifications or the Safety Analysis Report.
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10 CFR Part 50, Appendix B, Criterion XI, " Test Control," required that,
"A test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily inservice is identified and performed per te'st procedures which incorporate the requirements and acceptance limits contained in the applicable design documents."
The licensee's failure to ensure that Surveillance Procedures 06-OP-1P41-O-0004 and 06-OP-1 P41-0-0006 included acceptance limits, which factored in instrument error, and would assure performance at the levels assumed in the accident analysis is the first example of a violation of 10 CFR Part 50, Appendix B, Criterion XI (50-416/9705-06).
The licensee disagreed with this conclusion. Their view was that other testing performed on the systems approximately once every 3 years at alternate outages (discussed in the next section of this report) demonstrated that the pumps could deliver this minimum required performance. The inspectors noted that since these performance values were not incorporated into the acceptance criteria for inservice test procedures, the potential also existed that between these 3-year interval tests the pumps could have had less than acceptable performance and still have been considered operable in accordance with the inservice test procedures.
The inspectors also noted that this testing was safety-related and as such was l
required to meet 10 CFR Part 50, Appendix B, as well as, the ASME Code,Section XI, requirements.
c.
Conclusions The inspectors concluded the licensee had not included appropriate acceptance criteria in the inservice testing for the "A" standby service water pump or the high pressure core spray pump, which would assure performance assumed in the accident analysis. In addition, the licensee had not considered instrument error when comparing the performance of any of the service water pumps to the assumptions of the accident analysis.
l E3.3 Standbv Service Water System Thermal Performance Testina Controls l
a.
Inspection Scoce (93801, 37550)
l l
The inspectors reviewed the thermal performance testing performed on the standby service water and high pressure core spray service water systems. This testing was directed and recorded in accordance with performance and system engineering procedures. Initially, the licensee flow balanced the system, collected thermal i
performance data, and performed a calculation to evaluate the results of the thermal performance testing in accordance with a design standard. Following each test i
performance, this calculation determined the actual heat transfer capability of each
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heat exchanger. The results of the calculation were then attached to the test procedure documentation. The inspectors reviewed the performance test
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documentation including the completed test procedure, the standard used as a basis
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for the evaluation, and documentation of the calculations that were performed, t
These were the procedures, referenced in Section E3.2 above, that were performed
approximately every 3 years at every second refueling outage, which the licensee j
maintained were the only procedures required to actually demonstrate the ability of the pumps to meet the accident analyses performance requirements, b.
Observations and Findinas b.1. Test Documentation i
The thermal perforrnance testing performed on the standby service water and high pressure core spray service water systems was recorded in Performance and System Engineering Procedures 17-S-06-22, "SSW "A" Performance," Revision 4, dated April 19,1995, and 17-S-06-23, "SSW "B" Performance," Revision 4, dated September 28,1995. The final test data package included the licensee's determination of the current heat transfer rate for most heat exchangers. The licensee recorded the actual heat exchanger performance in the test documentation a id they stated that they evaluated the thermal performance by comparing the final determination of the heat transfer rate with design heat loads specified in the standard. However, the completed test documentation did not contain acceptance limits for any heat exchanger or a clear determination that the measured heat transfer rates were acceptable for any heat exchanger. In addition, the inspectors noted that the data sheet did not provide space or criteria for evaluating the data for the drywell purge compressor lube oil cooler and after cooler, the control room air conditioner, or the residual heat removal system pump seal coolers.
10 CFR Part 50, Appendix B, Criterion XI, " Test Control," states that " Test results shall be documented and evaluated to assure that test requirements have been satisfied.." The inspectors determined that Performance and System Engineering Procedures 17-S-06-22, "SSW "A" Performance," and 17-S-06-23, "SSW "B" Performance," did not provided adequate documentation that the results were evaluated to assure that test requirements have been satisfied. The failure to meet the quality assurance requirements of 10 CFR Part 50, Appendix B, Criterion XI is the second example of a violation of NRC requirements (50-416/9705-06).
b.2. Pumo Flow and Flow Balance Test Criteria The inspectors noted that the performance and system engineering procedures did contain data sheets that gave the appearance of containing pump flow acceptance criteria. For example, Data Sheet il of Attachment I contained a compilation of all of the heat exchangers served by the standby service water system, with one column labeled " Desired Flow" and another labeled " Min Flow". However, neither column contained the required " design flow under LOCA case load conditions." Of
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the 16 heat exchangers addressed in the table,10 had " Desired Flow" values
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different from the " nominal design flow" listed in Updated Final Safety Analysis
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l Report, Table 9.2-16. In addition the minimum acceptable flow as implied by the l
column labeled " Min Flow" was also not the minimum required flow to meet loss of coolant accident load conditions.
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As stated above, the licensee credited this testing with demonstrating that pump j
performance was acceptable. The inspectors concluded that adequate acceptance criteria had not been developed to use this test to determine the acceptability of l
pump performance.
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b.3. Heat Transfer Test Criteria Engineering Standard GGNS-MS-39.0, " Mechanical Standard for Thermal Performance Testing of Safety-Related Standby Service Water Heat Exchangers,"
Revision 0, dated February 26,1992, was the standard that the licensee intended to provide the requirements and methods for testing the heat exchangers cooled by l
the standby service water and high pressure core spray service water systems.
This standard included a description of the two computer programs that were to be used to calculate the various heat exchanger characteristics for the test conditions l
and the characteristics, including predicted performance, under design basis accident conditions. The standard also included instructions on how to adjust the
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data to compensate for the reduction in flow through the systems that would occur
as the basin levels dropped during the accident and instructions on the required compensation of the results to account for instrument error.
The inspectors noted that this standard provided the design basis heat loads for most heat exchangers. in addition, some of the data sheets were marked to
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indicate that a different heat removal capability was to be verified during
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performance testing. The inspectors reviewed this standard and found that two of I
the design basis heat loads against, which the heat exchangers were required to be evaluated, appeared to be nonconservative with respect to values found in other design or licensing basis documents.
Fuel Pool Coolina and Cleanuo Heat Exchanaer_ - The inspectors noted that Amendment 113 to the Technical Specifications removed the limit on the number of spent fuel assemblies that may be stored in the spent fuel pool pending licensee verification of the adequacy of spent fuel pool heat removal capability. Prior to removing the limit, the NRC requested and received flow rate verification for the increased standby service water and fuel pool cooling and cleanup system flows required by the one pump, two heat exchanger mode of operation. The inspectors determined that the heat removal capacity of this heat exchanger was a key in the NRC's determination to grant the license amendment.
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In the Equipment DescripGon Section and in Attachment 1 of Engineering l
l Standard GGNS-MS-39.0, the fuel pool cooling and cleanup heat exchangers were required to be capable of removing 7.45E6 BTU /hr at the design conditions of 90 F standby service water inlet temperature,140 F fuel pool cooling and cleanup
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inlet temperature, and 1100 gpm fuel pool cooling and cleanup flow. However, this was the design basis heat load prior to the installation of the high density fuel storage racks. In a November 1,1991, submittal (Entergy to
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USNRC, GNRO-91/00145) related to the rerack and a request to remove spent fuel pool capacity restrictions, the licensee claimed that 26.2E6 Btu /hr could be
removed by two fuel pool cooling and cleanup heat exchangers using one standby service water pump and one fuel pool cooling and cleanup pump. This heat removal rate was based on 1600 gpm fuel pool cooling and cleanup flow (800 per heat exchanger) and 1254 gpm standby service water system flow per heat exchanger, i
The inspectors noted that licensee's request to remove the spent fuel pool capacity restrictions was approved with Technical Specification Amendment 113.
The inspectors concluded that the 7.45E6 Btu /hr specified in Engineering
Standard GGNS-MS-39.0 should have been updated when the design basis for the fuel pool cooling and cleanup heat exchanger was updated with Amendment 113.
(See Section E3.4 of this inspection report for an additional discussion of
i this amendment.)
10 CFR Part 50, Appendix B, Criterion XI, " Test Control," requires that
"A test program shall be established to assure that all testing t
required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified j
and performed per written test procedures which incorporate
the requirements and acceptance limits contained in applicable design documents."
The licensee's failure to use current design basis requirements as the basis for acceptance limits for the fuel pool cooling and cleanup heat exchanger is a third example of a violation of 10 CFR Part 50, Appendix B, Criterion XI (50-416/9705-06).
The licensee disagreed with this violation. Their view was that to be acceptable,
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the heat exchanger performance acceptance criteria for the fuel pool cooling and l
cleanup heat exchanger only had to bound the current operating cycle. The inspectors agreed that, pursuant to 10 CFR 50.59, the licensee could update the design to specify heat transfer requirements for a specific cycle, which were consistent with the assumptions in the Technical Specification amendment i
submittal. However, the inspectors noted that the licensee had not developed a
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program for this type of design update nor had the licensee performed an analysis
and a 10 CFR 50.59 evaluation to confirm that the value being used was acceptable for the current cycle.
Control Room Air Conditioner - The inspectors also found that the control room air conditioner condensers were evaluated against a heat load of 651,845 BTU /hr; however, Updated Final Safety Analysis Report, Table 9.2-17, indicated that the correct heat load was 970,000 BTU /hr. At the conclusion of the inspection, the basis for this difference and the actual control room condenser performance had not
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been determined by the inspectors. However, this may be another example of a
failure to use current design basis requirements as the basis for acceptance limits.
The licensee will be requested to generically address the failure to establish acceptance limits consistent with design basis requirements in response to the previously described violation involving the Fuel Pool Cooling and Cleanup Heat Exchangers.
b.4. Test Instrumentation Controls The inspectors noted that the design standard required that instrument error adjustment be applied only to the air-to-water heat exchangers, such as the emergency core cooling system pump room coolers. The inspectors believed that this adjustment should have been required of all heat exchangers to assure that they j
had the required design basis performance.
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in Section 6.0, " Instrumentation Desenption," Subsection D, " Bimetallic Thermometers," the design standard states that the standby service water inlet temperatures were read from bimetallic thermometers installed in the auxiliary building main standby service water headers. However, in discussion with the responsible system engineer, the inspectors learned that in actual practice these locations were deemed to be not necessarily representative of the true inlet temperatures. Therefore, these temperatures were no longer used to calculate the
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performance of the heat exchangers. Instead, the inlet temperatures were calculated from other measured parameters. Specifically, the temperatures were measured at the inlets with a contact pyrometer to be used or:ly as reference values to test the validity of the calculations. Although this appeared to be an improved practice, it was not reflected in the design standard.
The inspectors also noted that Section E, Page 18 of the design standard described capillary tube thermometers that were no longer being used.
At several places the design standard referred to Calculation MC-Q1P41-90186,
" Determination of the Thermal Performance of Standby Service Water System Heat Exchangers (Loops A & C)," Revision 0, dated August 15,1991, as the example to be used in performing the heat exchanger data evaluation calculations. The inspectors reviewed this calculation and found that it contained several errors and was not truly representative of some of the practices currently being used to perform and evaluate these heat exchangers as follows:
On page 4, item 2.a discussed one of the instrument uncertainties (i.e.,
repeatability). The discussion appeared to equate repeatability with accuracy when these are two completely different inherent characteristir:s of instruments. Depending on a particular application of an instrunent, one or the other might be the appropriate characteristic to consider in determining the uncertainty. This incorrect discussion also appeared on page 12 in item II.A.2. (in spite of the incorrect discussion, it appeared that in actual practice these parameters were being correctly applied.)
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l On page 5, item 8 discussed how the air-to-water heat exchangers air flow
i rates and fouling factors were calculated. There appeared to be an error in the logic described. When the responsible engineer was asked about this
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i technique, he revealed that it was no longer used and that the flow was now
measured directly using a traverse. -The inspectors agreed with the new i
technique, but this calculation was no longer a correct example for this case.
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Beginning on page 9, calculations were performed on the data for various j
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j-heat exchangers to adjust the allowable minimum flow at the minimum basin l
level to the minimum allowable test flow at full-basin conditions. Since it
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was assumed (based on another calculation) that the enveloping flow
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reduction due to the drop in basin level over the 30-day accident would be
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10 percent, the minimum allowable flow at low basin level condition was
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multiplied by 1.1 to make this adjustment. This was an arithmetic error;it I
would only provide 1.1 x 90 percent of the low level flow or 99 percent of
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the required test flow; in order to get 100 percent of the required flow, the i
t correct adjustment would have been to divide by 0.9.
Instrument error adjustments were not made to the water-to-water heat
l cxchanger data.
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1C CFR Part 50, Appendix B, Criterion XI, " Test Control," required that
- A test program shall be established to assure that all testing
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required to demonstrate that structures, systems, and
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components will perform satisfactorily inservice is identified j
j and performed per test procedures which incorporate the
requirements and acceptance limits contained in the applicable j
l design documents." It further required that, " Test procedures i
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shall include provisions for assuring that... adequate test instrumentation is available and used."
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The inspectors concluded that the licensee did not have appropriate requirements j
for all of the instrumentation to be used for this thermal performance testing and
that the licensee did not have appropriate instructions for adjustment of the data for the instrument errors for the water-to-water heat exchangers. The f ailure to include provisions for assuring that adequate test instrumentation is available and used to assure that acceptance limits are adjusted for instrument error is the fourth example of a violation of 10 CFR Part 50, Appendix B, Criterion XI (50-416/9705-06).
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l b.5. Administrative Controls The inspectors noted that Engineering Standard GGNS-MS-39.0, " Mechanical Standard for Thermal Performance Testing of Safety-Related Standby Service Water i
Heat Exchangers," Revision 0, dated February 26,1992, did not require that the j
heat exchanger test data evaluation calculations be performed in accordance with l
the administrative controls specified in Nuclear Plant Engineering Administrative Procedure 305, " Engineering Calculations." This administrative procedure is applicable to all engineering calculations prepared by nuclear plant engineering
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personnel. In f act, the licensee had not performed a formal heat transfer calculation
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according to these administrative requirements, even though they had been performed on several occasions since 1991.
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Although no specific documentation was required by the design standard, the documentation generated consisted of attaching the calculation computer program
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i printouts to the test work order data sheet. Although the data sheets were signed
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by the calculation performer and a checker, they did not undergo the formal scrutiny required by Administrative Procedure 305. The inspectors concluded that this was a weakness in the performance of the design calculations.
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Conclusions The inspectors concluded that with respect to flow balance and thermal
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performance testing, the licensee had not established and implemented a quality assurance program which met the testing control requirements of 10 CFR Part 50,
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Appendix B, Criterion XI.
E3.4 Hiah Density Fuel Storaae Licensina Submittal Reauirements
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a.
insoection Scope (93801. 37550)
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During normal operation, the spent fuel pool cooling and cleanup system heat exchangers were cooled by the nonsafety-related component cooling water system.
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However, under accident conditions, these heat exchangers could be cooled by
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standby service water in the event component cooling water was not available. In 1991, the licensee submitted a letter to the NRC describing the capabilities and l
operation of the standby service water system in this function with respect to the newly added design heat loads in the fuel pool as a result of the high density fuel
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storage rack modification. The inspectors reviewed this submittal and what was
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described by the licensee as the supporting Calculation MC-Q1G41-89005, " Fuel Pool Cooling and Cleanup System Heat Removal Capacities," Revision 1, dated
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April 27,1989, to verify that the standby service water system could indeed I
perform this function as described.
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b.
Observations and Findinas in accordance w;in the calculation, the worst-case normal spent fuel decay heat load at 35 days after shutdown was 13.27 million BTU /hr. However, this value was somewhat different fmm Figure 3 of the submittal, which showed that at day 35 the decay heat was approximately 13.9 million BTU /hr.
In accordance with the calculation and the submittal, the capacity of the fuel pool cooling system using one fuel pool cooling train (i.e., one fuel pool cooling pump and heat exchanger) cooled by the standby service water system at 90*F was 13.39 million BTU /hr at day 37. Therefore, in accordance with the submittal in this one-train configuration, the plant could be restarted 37 days after shutdown (not 35 days as described in the calculation) and the necessary cooling for the spent fuel pool could be provided without exceeding its 140 F design temperature and without dependence on the residual heat removal system in the fuel pool cooling mode.
The submittal also stated, that, "If excessive fouling occurs, periodic heat exchanger performance monitoring required per Generic Letter 89-13 willidentify this condition and appropriate action will be taken."
The calculation showed that the total fouling factor assumed in determining the capacity of the fuel pool heat exchangers was 0.00012. However, the most recent testing showed that, even before adjustment for instrument error, the actual fouling factors were 0.00350 and 0.00057 for the "A" and "B" heat exchangers, respectively (i.e., 29 times and 5 times the assumed value, respectively). Adjusted for instrument error, the values were 0.00412 and 0.00113 (i.e.,34 times and 9 times the assumed value respectively). At these values, and at design basis conditions described in the submittal, the capacities of the heat exchangers were only 9.86 million BTU /hr and 12.94 million BTU /hr respectively, which are significantly less than the capacity described in the submittal. Contrary to the.
commitments in the submittal, the licensee had not identified this conditions as noncomplying and, therefore, had not taken action to restore compliance.
The safety significance of this observation is minimal at this time because of the actual number of fuel assemblies in the spent fuel pool. However, the issue is significant from a regulatory perspective, in that, the NRC granted a Technical Specification amendment to remove the restrictions on the number of fuel assemblies in the spent fuel based on the licensee's commitments for maintaining the performance of the fuel pool cooling and cleanup heat exchangers, if the plant were to restart after an outage based on the heat exchanger capacity stated in the submittal, the potential existed that it would be incapable of maintaining the fuel pool within its design temperature limit without reliance on residual heat removal in
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the fuel pool cooling mode. The inspectors determined that this f ailure to meet the commitments in the November 1,1991, licensing submittal was caused by the previously identified failure to update the heat exchanger performance acceptance criteria, which was identified as a violation of 10 CFR Part 50, Appendix B, Criterion XI in Section E3.3. As a result, the inspectors did not identify this example as an additional violation of 10 CFR Part 50, Appendix B, Criterion XVI,
" Corrective Action."
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Conclusions The licensee failed to correctly translate the requirements stated in their high density fuel storage rack transmittal to the NRC into the test procedures, which control allowable fouling for the fuel pool cooling and cleanup heat exchangers.
E3.5 !!pdated Final Safety Analysis Report Errors a.
Insoection Scope (93801, 37550)
The inspectors reviewed sections of the Updated Safety Analysis Report related to the standby service water system and the high pressure core spray service water
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system to determine if the information in the Updated Safety Analysis Report was consistent with the information in design documentation. The inspectors expanded this scope to include licensing documentation related to installation of the high
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density fuel racks after identifying that not all of the Updated Final Safety Analysis Report tables, which describe standby service water cooling capability related to the fuel pool cooling and cleanup system, had been updated consistently.
b.
. Observations and Findinas
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The inspectors identified the following discrepancies during the review of the
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Updated Final Safety Analysis Report The next to last item in Table 9.2-2, " Standby Service Water System Active
Failure Analysis," states that for a cooling tower f an f ailure, the redundant cooling tower will meet cooling requirements. This statement is not complete, in that if the fan f ailure were on Basin A, which also serves the
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high pressure core spray service water system, the basin temperature may exceed the design temperature of 90 F without operator action to reduce
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the heat load on the Standby Service Water Loop A. This is due to the
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reduction in evaporative cooling with the Standby Service Water Loop A
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operating only with natural convection cooling, i
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Table 9.2-3, " Standby Service Water System Loads for Nominal Flow
Conditions," incorrectly listed the loads on each of the heat exchangers served by the standby service water system. The design heat load tabulated for the fuel pool heat exchangers was 7.45 million BTU /hr at 30 days after shutdown. However, in accordance with Table 9.2.17, " Time Dependent Standby Service Water System Cooling Duty Loads Following a DBA (LOCA With a Loss of Offsite Power and Single Active Failure)," this value was 13.13 million BTU /hr. Further, the licensee's high density fuel licensing submittal of November 1,1991, described this load as 13.39 million BTU /hr at 37 days after shutdown.
Table 9.2-16, " Standby Service Water System Cooling Duty Loads Following
a DBA (LOCA With Loss of Offsite Power and Failure of Standby Diesel Generator A)," also listed the fuel pool heat load as 7.45 million BTU /hr and the associated note stated the load as 13.13 million BTU /hr. This note also incorrectly stated that the 13.13 million BTU /hr was based on 18 core
' off-loads. The licensee subsequently indicated that with the extended fuel cycle, only 12 of the larger offloads would fill the spent fuel pool. Therefore, the correct basis for the 13.13 million BTU /hr value was 12 core offloads.
As discussed in Section E3.5.b.2, the correct value current licensing basis heat load was 13.39 million BTU /hr at 37 days after shutdown. Therefore, it appears that both the heat load and the attendant fuel-cycle basis were incorrect.
Table 9.2-17, " Time Dependent Standby Service Water System Cooling Duty
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Loads Following a DBA (LOCA With a Loss of Offsite Power and Single
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Active Failure)," listed the fuel pool heat load as 13.13 million BTU /hr and the associated note incorrectly stated that it was based on 18 core off-loads as described above. As described above, the current licensing basis heat load was 13.39 million BTU /hr at 37 days after shutdown, and the basis was 12 of the extended cycle offloads.
Figures 9.2-5, " Total Heat Rejection Rate, Basin A (Unit 2 Loop A and Unit 1
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Loop C), Time Period 0 to 30 Days," and 9.2-6, " Total Heat Rejection Rate, Loop B (Unit 1 Loop B and Unit 2 Loop B), Time Period - O to 30 Days,"
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incorrectly showed 2-unit heat loads; however, the facility is a single-unit plant.
I Figure 9.2-6a, " Total Heat Rejection Rate, Basin B, Loop B and Loop C, Time
Period - O to 30 Days," incorrectly showed the peak heat rate to be approximately 27 million BTU /hr (74 thousand BTU /sec). However, in accordance with Calculation MC-01P41-86054, " Standby Service Water Ultimate Heat Sink Performance," Revision 0, dated July 25,1986, Figure 6, the peak heat load was approximately 23 million BTU /hr. The Updated Final Safety Analysis Report figure appeared to be incorrect.
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10 CFR 50.71, " Maintenance of Records, Making of Reports," Section E, requires that "Each person licensed to operate a nuclear power reactor shall... assure that the information included in the FSAR contains the latest material developed." The failure to assure'that the Updated Final Safety Analysis Report contained the latest correct material as detailed above is a violation of NRC requirements
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(50-416/9705-03).
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The NRC considered use of discretion for this violation in accordance with the
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guidance in NRC Enforcement Guidance Memorandum 96-005. The inspector noted
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the licensee had docketed a plan to review selected systems / sections of the Final Safety Analysis Report for consistency with supporting documents. The scope of I
the licensee's initiative was docketed in their 10 CFR 50.54(f) response dated i
February 6,1997. ' Based on a review of this initiative, the inspectors could not
conclude that it was likely that the licensee would have identified these specific examples. As a result, enforcement discretion in accordance with Section Vll.B.3 of the Enforcement policy was not used for these Final Safety Analysis Report
discrepancies.
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Conclusions l
The inspectors identified several Updated Final Safety Analysis Report j
discrepancies. Most of the examples were related to the change to the T9chnical-l.
Specification limit on the number of spent fuel assemblies in the spent fuel pool.
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E4 Engineering Staff Knowledge and Performance (93801,37550)
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a.
Inspection Scoce
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During the inspection the team questioned staff engineers on knowledge of their j
assigned areas and conducted system walk-downs with the system and design j
engineers.
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Observations and Findinos The team found a strong questioning attitude, and a sense of ownership among design and system engineers. System and design engineers were knowledgeable with their assigned systems and duties. Additionally, engineers were familiar with-the associated engineering backlog, deficiencies, operator work arounds, and emergent maintenance on their assigned systems. The team found that engineers were aware of the risk significance of their assigned and interfacing systems.
The team's overall evaluation of engineering performance was good. All of the engineers encountered seemed motivated, capable, and well qualified, with a strong sense of ownership in the plant and in their individual responsibilities. During the team's review of materials and interviews the engineering staff appeared attentive to detail and demonstrated a comprehensive understanding of overall plant operations, engineering principals, and regulatory requirements.
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l Engineers were motivated, well qualified, and f amiliar with their assigned and supporting systems.
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E6 Engineering Organization and Administration
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E6.1 Drawina Backloa i
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a.
Insoection Scoce (93801,375501
j The inspectors reviewed the current backlog of engineering drawings during the j.
inspection.
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b.
Observations and Findinas
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The inspectors found that the licensee did not have a drawing update backlog for
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i drawings use.d by the operations department in day-to-day activities. Each discipline had a drawing update backlog of about 100 for drawing updates and
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corrections not in active modification packages. The inspectors noted that the licensee' drawing control proccss allowed up to three changes to be controlled
through addenda, without formally correcting the affected drawing, unless the
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document is part of an active modification package.
f The licensee stated that the vendor manual update to assure latest version with
. corrected page references was complete for the station. Cataloging of the manuals into a database reference for easy access was stillin process and scheduled for
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completion later this year.
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Conclusions t
The inspectors concluded that the current engineering drawing backlog is reasonable at this time and provides updated engineering and construction reference materials in a timely manner.
E7 Quality Assurance in Engineering Activities E7.1 Obsolete Calculations Not Properly Superseded a.
inspection Scoce (93801. 37550)
In the process of reviewing the design calculations associated with the standby service water and high pressure core spray service water system, the inspectors identified several calculations that contained obsolete information, (i.e., subsequent calculations had been performed that generated new information that rendered
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incorrect some of the information contained in the older calculations). The inspectors reviewed Nuclear Plant Administrative Procedure 305, " Engineering Calculations," Revision 14, dated February 3,1992, to determine the licensee's administrative controls related to superseded calculations. The inspectors also interviewed licensee personnel to determine current licensee practices.
b.
Observations and Findinas The inspectors found that Procedure 305 included instructions for superseding or cancelling calculations, but did not specifically require that calculations be superseded.
l The licensee indicated that one of the reasons for this condition was that, even though the older calculations did contain obsolete information, they also sometimes contained other information that was correct and useful. With their current design control procedures, superseding such calculations would remove them from active status and, thereby, render any information contained therein unusable for subsequent design activities. Rather than lose that information, the licensee had made a conscious decision to retain such calculations in active status even though some information was obsolete. The licensee also indicated that there were other calculations with the same condition for the same reason.
During the other inspection activities described in this report, the inspectors did not identify any instances where superseded information caused an incorrect technical evaluation. However, the inspectors was concerned that this document control
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system could allow engineering personnel to inadvertently use superseded
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information in current calculations.
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c.
Conclusions I
The licensee had not established adequate control of the issuance of design calculations to assure that obsolete design calculations were clearly identified.
While the inspectors did not identify any examples where use of superseded information caused an incorrect technical evaluation, this appeared to reflect a weakness in the design control procedures.
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E8 Miscellaneous Engineering issues
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E8.1 (Closed) Inspection Followuo item 50-416/9514-03: Corrective Actions To Eliminate Ooerator Work-Around Durina Surveillance Testina of The Leak Detection System.
The leakage detection system (E31) had been identified as a malfunctioning system since 1985. Spurious valve isolations had been associated with the leakage detection system since installation. The licensee had determined the isolations were
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caused by inductive electrical spikes associated with Riley temperature switches.
To prevent spurious isolations, the licensee was placing the leakage detection system in a bypass mode during plant surveillance testing, calibration and during
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operator rounds, while operators record temperatures.
l The inspectors found that the licensee had taken several corrective actions to j
resolve the problem. Initially they implemented modifications to the power supplies
and corrected shield and ground problems. However, these actions did not eliminate the problem. The licensee also replaced some of the Riley Model 86A switches with a later model,86B units. The spurious failures also occurred with the later model, so the licensee began bench testing new units prior to installation to i
ensure units susceptible to infant mortality were not installed in the plant. The licensee determined that this combination of corrective actions improved reliability some, but not enough to change their practice of bypassing the leakage detection
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system during sensitive activities.
The licensee is evaluating a design change to change the leakage detection system to an alarm only system. While reliability improvements have been achieved, the licensee had not determined the final solution to the current operator work-around.
Further, the inspectors found that the issue had not been formally identified as an operator work-around as of the time of this inspection. Although the licensee had not fully resolved this issue, the inspectors concluded that this was not a significant operational problem, because the licensee had initiated action to improve the system's reliability and planned further action to eliminate the problem. This item is closed.
E8.2 (Closed) Licensee Event Reoort 50-416/96-04-00: Manual Reactor Scram Due To Multiole Safety Relief Valve Lifts.
NRC inspection associated with this licensee event report was documented in NRC Inspection Report 50-416/96-11. The inspectors reviewed the licensee event report and determined the only outstanding issue was identified as inspection Followup Item 50-416/9611-01, described below. This licensee event report was closed.
E8.3 (Ocent insoection Followuo item 50-416/9611-01: Review of Updated Final Safety Analysis Reoort Descriotion of Safety Relief Valve Loaic.
The low-low set logic is designed to protect containment from excessive loads by ensuring that no more than one relief valve reopens subsequent to the first full blowdown on an isolation event. During NRC inspection 50-416/96-011, it was noted that the licensee's commitment related to designing the low-low set logic in accordance with single failure criteria was not clear. The inspectors reviewed the two Updated Final Safety Analysis Report references identified in NRC inspection Report 50-416/96-11, Sections 7.1.1.1.4.'i 2.3 and 7.1.1.1.4.12.9, ard determined that the first section was applicable to the safety relief valve initiation logic and the second section was applicable to the low-low set logic. These Updated Final Safety Analysis Report sections stated the following:
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The safety / relief valve logic is designed such that no single failure will
prevent safety / relief valve actuation or cause more than one safety relief
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valve to actuate.
The low-low set logic is designed such that no single electrical failure will:
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(1) cause inadvertent seal-in of low-low set logic or (2) prevent any low-low set valve from opening. Updated Final Safety Analysis Report Section 7.3.1.1.1.4.12.9 further states that upon a single electrical failure, more than one valve may inadvertently open or stick open; however, the probability of this happening is less that 104/ year.
In Licensee Event Report 50-416/96-04, the licensee noted that a single failure had resulted in 20 safety relief valves receiving a momentary open signal (200 milliseconds). Six of these safety relief valves rcmained open because of the seal-in feature of the low-low set logic. In addition, the licensee noted that 16 similar failurea have occurred since 1987. This equipment performance appeared inconsistent with the claims made in the Updated Final Safety Analysis Report.
The licensee's initial view was that the power supplies were not considered a part of the logic. If the power supplies were neglected, then the licensee concluded the logic met the single failure commitments. However, during this inspection, the inspectors notified the licensee that the NRC did not accept this view.
In the licensee event report, the licensee acknowledged that the Updated Final Safety Analysis Report description of the low-low set function could be misinterpreted, but referred to NUREG-0802 as evidence that, during licensing, the NRC clearly uriderstood that the low-low set logic was not single failure proof. In addition, the licensee stated at the exit meeting, the failure which occurred was bounded by other analysis. NUREG-0802, Section 3.4.2, " Instrumentation and
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Control Logic," indicated that,
"In its review, the [NRC] staff determined that the instrumentation and control portions of the design satisfy the single-failure criterion as relatcd to opening valves when required. However, the design does not satisfy the single-failure criterion with respect to preventing one additional valve from opening at the time only one valve is permitted to open (on second and subsequent valve actuations). Inherent in the design of the safety relief valve system in plants utilizing relay logic as well as in those with sold state logic are single failure points which could result in the inadvertent opening of a second valve. A second valve opening could also be caused by mechanical failure of the remaining valves. As a result of this finding, the staff requested the Grand Gulf applicant and General Electric Company to demonstrate that the present design is adequate."
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The inspectors concluded that the NRC had previously reviewed the design of the
low-low set logic used at Grand Gulf with respect to single failure criteria.
However, due to time constraints, the inspectors were not able to determine if this
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previous review had identified the bounding failure.
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NUREG-0802 consistently discusses a possible single failure which allows one additional safety relief valve to reopen. In Section 3.4.3, the staff concludes that i
"Even if application of the single-failure criterion will result in consecutive
-actuations of two safety relief valves, the loads on the affected structures, piping, j
and equipment are bounded by other more severe load cases which have already
- been included in the design evaluation. Based on these evaluations, the staff
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concludes that the low-low set relief logic proposed by GE to be used for plants with Mark 111 containment and quencher devices is acceptable."
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As noted in NRC Inspection Report 50-416/96-11, the actual event was bounded by i
other analysis. However, the inspectors noted that a similar power supply failure at j
the time when only one valve is permitted to be open (on second and subsequent
valve actuations) may not be bounded by evaluations in NUREG-0802, because six l
valves would open, not two. This item will remain open pending further discussion
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with the Office of Nuclear Reactor Regulation on whether or not a power supply j'
failure could have resulted in an event which was not bounded by the previous f
accident analysis.
l The inspectors noted that interim steps have been taken to protect against the i
inadvertent trip of one channel of low-low trip logic causing the lifting of the safety j
relief valves. The safety trip channels had been powered from a single power i
supply even though the remaining circuit elements were independent. The common j
mode failure of a single power supply resulted in the instantaneous error signal at all i
the trip channels connected to the power supply. The licensee has since
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reconnected the trip channels so that two divisions are not coupled by common j
power supply connections.
l E8.4 (Closed) Licensee Event Report 50-416/96-05-00: Low Pressure Coolant Iniection
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Valve Motor Pinion Kev Failure.
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While onsite for the performance of NRC Inspection 50-416/97-01, NRC personnel expert in implementation of the Maintenance Rule, determined that the failure
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described in this licensee event report was not a maintenance preventable functional j
failure. During this inspection, the NRC inspectors determined the corrective l
actions were appropriate, given the failure data at the site. Further, the licensee
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stated that all potentially defective motor pinion keys have been replaced. This j
licensee event report was closed.
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V. Manaaement Meetings I
X1 Exit Meeting Summary
The inspectors discussed the progress of the inspection on a daily basis and presented the inspection results to rnembers of licensee management at the conclusion of the inspection on March 27,1997. The licensee did not agree to all of the findings which were
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presented. As discussed in the inspection report, the licensee did not agree with j
Violation A, example 3; or Violation C, examples 1 and 3.
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ATTACHMENT 1 SUPPLEMENTAL INFORMATION
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PARTIAL LIST OF PERSONS CONTACTED _
Licensee l
D. Bost, Director, Design Engineering G. Broadbent, Design Engineering W. Cade, Operations
i K. Christian, Systems Engineering
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B. Eaton, General Manager R. Fuller, Design Engineering
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R. Ingram, Supervisor Nuclear Safety Analysis E. Harris, Superintendent, Systems Engineering W. Hughely, Director, Nuclear Safety and Regulatory Affairs A. Kassam, Design Engineering M. Locke, Design Engineering
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J. Malone, Inservice Testing Engineering
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M. McDr.,well, Operations
B. McCain, Mechanical Engineering L. Moulder, Superintendent, Instrumentation and Electrical Maintenance J. Owens, Nuclear Safety and Regulatory Affairs
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M. Renfroe, inservice Testing Engineering S. Saunders, Manager, Electrical Instrumentation and Control i
L. Speyerer, SSW System Engineer l
F. Titus, Vice President Engineering, B. Warren, Design Engineering l
J. Wright, Supervisor, Nuclear Plant Engineering C. Williamson, Design Engineering
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D. Wilson, Design Engineering l
M. Withrow, Engineering Analysis NRC P. Harrell, Chief, Division of Reactor Projects Branch D K. Weaver, Resident inspector i
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INSPECTION PROCEDURES USED 37550 Engineering 93801 Safety System Functional Inspection ITEMS OPENED, CLOSED, AND DISCUSSED Ooened 50-416/9705-01 VIO Design control issues related to: (1) alarm response procedure updates, (2) analysis of the cooling water safety -
function and, (3) ensuring adequate drain path for normal
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and expected standby service water pump shaft seal I
leakage (Sections 03.1, E1.2, and E2.1).
50-416/9705-02 URI Lack of leak tests for nonsafety-related to safety-related system interface valves (Section E1.3).
50-416/9705-03 VIO Failure to update the Final Safety Analysis Report with the latest material developed related to: (1) the reanalysis of site drainage, (2) incomplete cooling tower failure analysis, (3) fuel pool heat load increases due to reracking the spent fuel pool, (4) change from 2-unit to 1-unit facility, (5)
inaccurate figure with respect to peak heat rate for the ultimate heat sink (Sections E2.1, and E3.5).
50-416/9705-04 IFl Adequacy of long term freeze protection measures (Section E2.2).
50-416/9705-05 IFl Unexplained pump performance curve discrepancies (Section E3.1).
50-416/9705-06 VIO Test control deficiencies related to 1) inadequate acceptance limits and 2) control of test instrumentation (Sections E3.2 and E3.3).
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50-416/9514-03 IFl Corrective actions to eliminate operator work around during surveillance testing of the leak detection system, 50 416/96-04-00 LER Manual. reactor scram due to multiple safety relief valve lifts.
50-416/96-05-00 LER Low pressure coolant injection valve motor pinion key failure.
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Discussed 50 416/96011-01 IFl Review of Updated Final Safety Analysis Report description-of safety relief valve low-low set logic.
DOCUMENTS REVIEWED Licensina Documents Updated Final Safety Analysis Report:
Appendix 3A, "Conformance with NRC Regulatory Guides" Table 6.2-2, " Engineered Safety Systems Information for Containment Response Analysis" Section 6.2.2, " Containment Heat Removal System Section 7.3.1.1.7.10, "SSW pH Control System" Section 7.6.1.2, " Process Radiation Monitoring System - Instrumentation and Controls" Section 9.1.3, " Fuel Pool Cooling and Cleanup System," and associated figures and tables Section 9.2.1, " Standby Service Water System," and associated figures and tables Section 9.2.2, " Component Cooling Water System," and associated figures and tables Section 9.2.5, " Ultimate Heat Sink," and associated figures and tables Section 9.2.8, " Plant Service Water System," and associated figures and tables Section 9.2.10, " Plant Service Water Radial Well System," and associated figures and tables Section 9.2.11, "Drywell chilled Water System," and associated figures and tables Table 9.5-3, " Diesel Generator Cooling Water System Component Data" Section 11.5, " Process and Effluent Radiological Monitoring and Sampling Systems" Technical Soccification:
3.7.1, " Standby Service Water (SSW) System and Ultimate Heat Sink (UHS)," and Bases 3.7.2, "High Pressure Core Spray (HPCS) Service Water System (SWS)," and Bases
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3.7.1, " Standby Service Water (SSW) System and Ultimate Heat Sink (UHS) - Shutdown" j
3.7.2, "High Pressure Core Spray (HPCS) Service Water System (SWS) - Shutdown Safety Evaluation Report Section 9.2.1, " Station Service Water System (Standby Service Water System)"
Drawinas 272A8638, " Isolator Application Dwg," Revision 7 865E592-003, " Electrical Device List, Div 1 Engineering Safeguard Features Relay VB;1H13-P871," Revision 2 A-0200, " Stand By Service Water Pump House Plans & Elevations," Revision 7, March 4, 1985 C-1730, "SSW Cooling Tower Basin Reinforced Concrete Base Mat Plans and Sections,"
Revision 11, June 1,1988 C-1731, "SSW Cooling Tower Basin Reinforced Concrete Plan @ El 107'-6"," Revision 8, October 5,1978 C-1734, "SSW Cooling Tower Basin Reinforced Concrete Wall Sections and Details,"
Revision 13, October 10,1985 C-1736B, " Units 1 & 2 SSW Cooling Tower Basin Misc. & Embedded Steel Sections &
Details," Revision 8, January 29,1986 E-0001, " Main One Line Drawing," Revision 21 E-0118-014, " Schematic Diagram, Heat Tracing Diesel Generator Bldg, Sprinklers Unit 1,"
Revision 4 E-1030-016, " BOP Power Panel 14P12 MCC 14B12, (Heat Tracing)," Revision 13 E 1120-004, "R21 Load Shedding & Sequencing Sys LSS Table 21H22-P332 (Div 2)
Part 2," Revision 13 E-1225-01, " Schematic Diagram, SSW Control System A Unit I," Revision 12 E-1225-018, " Schematic Diagram, SSW System A A/C Unit & ESF SWGR RM CLR ISLN MOV F066A-A," Revision 7 E-1225-019, " Schematic Diagram, SSW System A to PSW Intertie MOV F125-A,"
Revision 8
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E-1225-021, " Schematic Diagram, SSW System A Inlet MOV F064A to Cont A/C,"
Revision 9 E-1225-42, " Schematic Diagram, SSW Motor Space HTR for C001 A-A Unit I," Revision 6 E-1225-043, " Schematic Diagram, P41 Stdby SSW ESF SWGR RM Coolers to PSW Cross Tie Viv F239 Unit 1," Revision 6
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E-1225-63, " Schematic Diagram, SSW Cooling Tower Fan C003C Unit I," Revision 0 E-1225-071, " Schematic Diagram, SSW System A Inlet MOV F237 to ESF SWGR RM Coolers," Revision 2 M-1061 A, " Standby Service Water System P&lD," Revision 44, dated November 8,1996 l
M-10618, " Standby Service Water System P&lD," Revision 38, October 30,1996 l
M-1061C, " Standby Service Water System P&lD," Revision 31, October 30,1996 l
M-1061D, " Standby Service Water System P&lD", Revision 28, January 9,1997
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J-0666, " Level Setting Diagram," Revision 4 J-1221-014, " Logic Diagram Standby Service Water System, SSW A to ESF SWGR Room Coolers MOVs F237-A and F238-A," Revision 4 J-1221-026, " Logic Diagram Standby Service Water System, PSW to ESF SWGR Room Coolers MOVs F239 and F240," Revision 1 J-1321-002, " Loop Diagram P41 Standby Service Water Loop A Leak Detection,"
Revision 10 J-1321-004, " Loop Diagram P41 SSW Pressure Basin Level and Temperature," Revision 6 J-1321-005, "Lcop Diagram P41 SSW Pressure Basin Level and Temperature," Revision 7 J-1321-008, " Loop Diagram P41 Standby service Water Computer Interf ace," Revision 7 l
l SSW Logic Diagram Nos 000 thru 034, latest revisions
SSW System Schematics Nos 000 thru 050 latest revisions i
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Procedures and instructions Administrative Procedure 01-S-07-8, " Control of Permanent Plant I & C Equipment Calibration," Revision 8, dated October 27,1989 Alarm Response Instruction 04-1-02-1 H13-P870-7A-A1, "SSW Pmp B Trip," Revision 100 Alarm Response instruction 04-1-02-1 H13-P870-7A-A2, "SSW Div 2 Oper," Revision 100 Alarm Response instruction 04-1 -02-1 H 13-P870-7 A-B1 'SSW Clg Twr Fan C Trip,"
Revision 100 Alarm Response Instruction 04-1-02-1 H13-P870- /A-B2, "SSW Cig Twr Fan D Trip,"
l Revision 100 l
l Alarm Response Instruction 04-1-02-1 H13-P870-7A-C1, "SSW Pmp B Overld,"
l Revision 100 Alarm Response Instruction 04-1-02-1 H13-P870-7A-C2, "SSW Div 2 OOSVC,"
Revision 100 Alarm Response Instruction 04-1-02-1 H13-P870-7A-D1, "SSW Pmp B Disch Press Lo,"
Revision 100 Alarm Response Instruction 04-1-02-1H13-P870-7A-D2, "SSW Div 2 MOVs in Test Mode," Revision 33, i
Alarm Response instruction 04-1-02-1 H13-P870-7A-E1, "SSW Loop B Leak Hi,"
Revision 100 i
Alarm Response Instruction 04-1-02-1 H13-P870-7A-E2, "SSW Div 2 Trip Unit Trouble,"
Revision 100 Alarm Response Instruction 04-1-02-1H13-P870-7A-F1, "SSW Basin B Lvl Hi/Lo,"
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Revision 100 Alarm Response instruction 04-1-02-1 H13-P870-1 A-A1, "SSW Pmp A Trip," Revision 100 l
Alarrn Response !nstruction 04-1-02-1 H13-P870-1 A-A2, "SSW Div 1 Oper," Revision 100 j
Alarm Response Instruction 04-1-02-1H13-P870-1 A-B1, "SSW Cig Twr Fan A Trip,"
l Revision 100 Alarm Response Instruction 04-1-02-1 H13-P870-1 A-B2, "SSW Clg Twr Fan B Trip,"
l Revision 100
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Alarm Response Instruction 04-102-1 H13-P870-1 A-C1, "SSW Pmp A Overld,"
Revision 100
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l Alarm Response Instruction 04-1-02-1 H13-P870-1 A-C2, "SSW Div 1 Oosvc,"
Revision 100 Alarm Response Instruction 04-1-02-1 H13-P870-1 A-D1, "SSW Pmp A Disch Press Lo,"
Revision 100 Alarm Response instruction 04-1-02-1 H13-P870-1 A-D2, "SSW Div 1 MOVs in Test Mode," Revision 33 Alarm Response Instruction 04-1-02-1 H13-P870-1 A-E1, "SSW Loop A Leak Hi,"
Revision 100 l
Alarm Response Instruction 04-1-02-1 H13-P870-1 A-E2, "SSW Div 1 Trip Unit Trouble,"
Revision 33 Alarm Response instruction 04-1-02-1 H13-P870-1 A-F1, "SSW Besin A Lvl Hi/Lo,"
Revision 100 Alarm Response instruction 04-1-02-1 H13-P870-1 A-F2, "SSW Fill Tk Lv' rii/Lo,"
Revision 100 Loop Calibration Instruction 07-S-53-P41-10, " Standby Service Water Basin Level Indication," Revision 6 i
Maintenance Procedure 07-S-03-30, " Calibration of Plant l&C Equipment," Revision 3 l
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Performance and System Engineering Instruction 17-S-01-10, " Scaling Program,"
Revision O l
Performance and System Engineering Procedure 17-S-06-22, "SSW "A" Performance,"
Revision 4 Performance and System Engineering Procedure 17-S-06-23, "SSW "B" Performance,"
l Revision 4 l
Surveillance Procedure 06-IC-1D17-A-101, " Standby Service Water System Radiation l
Monitor Channel A Calibration," Revision 100 Surveillance Procedure 06-OP-1P41-O-0004, " Standby Service Water (SSW) Loop A Valve l
and Pump Operability Check," Revision 101 l
Surveillance Procedure 06-OP-1P41-O-OOO4, " Standby Service Water Loop A Valve and Pump Operability Test," Revision 102 Surveillance Procedure 06-OP-1P41-Q-0005, " Standby Service Water Loop B Valve and Pump Operability Test, Revision 102 i
Surveillance Procedure 06-OP-1P41-0-0006 "HPCS Serece Water System Valve and
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Pump Operability Test," Revision 102 Surveillance Procedure 06-OP-1P41-M-0001, "HPCS Service Water Operability Check,"
l Revision 100 i
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System Operating Instruction 04-1-01-P41-1, " System Operating l
Instruction Standby Service Water System," Revision 104 l
l Calculations
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l 2.2.11, "SSW System - NPSH Requirements for SSW Pumps," Revision E, dated July 19, 1984 2.2.19A, "SSW System Makeup Flow Requirements," Revision A, dated September 6, 1974
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l 2.2.33, "SSW Cooling Tower Heat Rejection Loads," Revision 0, dated May 27,1981 2.2.82-O, "SSW Flow & Inventory Study - FHA," dated July 1,1987 and Bechtel j
Response Tasks 1 and 2 JC-01E38-N600-1, " Instrument Loop Uncertainty and Setpoint Determination for The Feedwater Leakage Control System High Pressu'e Trip," Revision 0 l
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MC-Q1P41-86130, " Evaluation of the Effect of SSW Basin Water Elevation Change on l
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Total System Design Flow Rate," Revision 0, datad November 14,1986
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l MC-Q1P41-90186, " Determination of the Therma' Performance of Standby Service Water l
System Heat Exchangers (Loops A & C)," Revision 0, dated August 15,1991 MC-Q1P41-87224, " Evaluation of SSW Flow Variataon (200 gpm) to the Residual Heat l
Removal Heat Exchanger," Revision 0, dated December 31,1987 l
MC-Q1P41-86007, " Standby Service Water Ultimate Heat Sink Performance," Revision 0, dated April 30,1986 l
MC Q1P41-88007, " Evaluation of MWO #80092 Test Rasults," Revision 0, dated l
February 16,1988
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MC-Q1P41-90138, "SSW Loop "C" Restricting Orifice Calculation," Revision 0, dated September 6,1990 MC-Q1P41-86054, " Standby Service Water Heat Sink Performance, devision 0, dated i
July 25,1986 l
SC-1E22-PT-N052, "HPCS Pump Suction Pressure Instrument Scaling Calculation (E22),"
Revision 0
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SC-1N32-PS-N075 " Scaling Calculation for Auxiliary Starting Fluid Pressure Switches 1N32-PS-N075 and 1N32 PS-N076," Revision O Modification Packanes DCP 90/0551, " Install Flow Restricting Orifices in the HPCS Service Water to HPCS Diesel Generator Jacket Water Heat Exchangers," Revision 1, dated September 17,1990 Condition Reports and Nonconformance Evaluations l
GGCR1996-0044-00, "With the Space Heater inoperable, will the SSW A pump motor operate as designed under all accident conditions?" initiated September 17,1996 GGCR1996-0553, " Freezing /lcing Concerns of the UHS Cooling Tower" ini iated j
December 18,1996 and revised January 12,1997
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l GGCR1997-0101, " Sink-Hole by SSW A Pumphouse due to apparent erosion of Backfill,"
l initiated January 29,1997 t
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GGCR1997-0131, " Radiation Monitor Skid Mounting' Seismic Requirements," initiated
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February 6,1997 l
GGCR1997-0226, " Potential for Limit Switch Settings to Conflict with Electrical l
Standards," initi:
d March 7,1997 l
l MNCR 0202-85, "SSW Pump B Failed to Meet IST Requirements," initiated April 8,1985 l
l MNCR -100 88, "SSW Pump B Failed IST Vibration Requirements," initiated April 15,1988
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Root Cause Analysis Report, RCDL #93-47 & 48, " Spurious RCIC Div i isolations Due to l
Suspected Riley Temperature Switch Failures, incident Report: 93-07-06, 7/21/96,"
l dated February 22,1996 i
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Root Cause Analysis Report, " Spurious initiation of Low-Low Set logic Because of l
Suspected Static Electricity, GGCR1996-0606-00," dated February 26,1997 with l
enclosures
Miscellaneous l
Engineering Request 96/0505, " Establish New HPCS Service Water Pump IST Vibration Reference Values in Association with Installation of New Instrumentation," dated August 8,1996 l
j Engineering Request 96/0516, " Establish New HPCS Service Water Pump IST Performance l
Reference Values in Association with Pump Rebuild," dated August 10,1996 Engineering Request 96/0215, " Subject: SSW Pump A Rebuild Performance," Revision 0, dated June 19,1996
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Engineering Request 96/1022, " Interim Disposition instruction for GGCR1996-0553-00,"
Revision 1 Engineering Standard GGNS-JS-09, " Methodology for the Generation of Instrument Loop Uncertainty & Setpoint Calculations," Revision 0, dated March 23,1993
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Engineering Standard GGNS-MS-39.0, " Mechanical Standard for Thermal Performance l
Testing of Safety-Related Standby Service Water Heat Exchangers," Revision 0, l
dated February 26,1992 GE DRF File AOO-314, " Analog Input and Output Isolator Card" l
GE Vendor Manual Description of Analog Output Isolator 204B6220AAG1, G2; l
Gek-73518B and Analog Input Isolator 20486208AA G1, G2 GEK-73511B l
l Goulds Pumps, Inc. vendor manual for the A and B SSW pumps, dated June 8,1994 i
Goulds Pumps, Inc. vendor manual for the HPCS service water pump, dated l
October 10,1994 Outside Rounds Sheet page 13 of 18, "SSW Cold weather checks," Revision 84 Service Water System Operational Performance inspection (SWSOPI) Report No. EOI-471, dated February 8,1995 l
l Specification 9645-M-087 0, " Vertical Centrifugal Pumps (ASME Section Ill)," Revision 9 l
l Standing Order No. 96-0020, " Cold weather action for SSW f an operation," dated December 19,1996 System Design Criteria, " Standby Service Water System (P41)," Revision 0, dated December 31,1991 l
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