IR 05000271/1993029
| ML20058E392 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee File:NorthStar Vermont Yankee icon.png |
| Issue date: | 11/18/1993 |
| From: | Eugene Kelly NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20058E391 | List: |
| References | |
| 50-271-93-29, NUDOCS 9312060302 | |
| Download: ML20058E392 (5) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
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Report No.
93-21 Docket No.
50-271 Licensee No.
DPR-28 Licensee:
Vermont Yankee Nuclear Power Corporation RD 5, Box 169 Ferry. Road
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Brattleboro, VT 05301 Facility:
Vermont Yankee Nuclear Power Station Vernon, Vermont Inspection Period:
November 8-10, 1993 Inspector:
Paul W. Harris, Resident Inspe tor
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12 hf ll (S N Approved by:
Eugene M@elly, Chief
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Date
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Reactor Projects Section 3A Scope:
Special safety inspection to assess licensee evaluations of and corrective actions for three previously identified issues: 1) safeguards class 1E electrical buses being in a degraded operability state because of insufficient seismic attachments, 2)
alternate cooling tower subsystem being inoperable because of an accumulation of an excessive amount of silt in the cooling tower basin, and 3) core spray system being inoperable because of undersized pump suction stminers.
Findings:
The events reported in LERs 93-13,93-14 and 93-15 describe licensee identified violations of NRC regulations concerning system operability, design control and test acceptance criteria. The analysis provided in the Licensee Event Reports failed to more fully present the impact on plant safety caused by the deficiencies, in some cases the corrective actions were narrowly focused, and none of the LERs addressed the common thread of previous industry experience and why it had not been more effectively consulted and utilized.
Further, original installation drawings or other such formally verified design basis documentation do not apparently exist for equipment affected by these deficiencies. This resulted in the use of, for example, notes on data sheets as estimates for design basis information.
9312060302 931118 PDR ADOCK 05000271
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DETAILS 1.0 REVIEW OF WRITTEN REPORTS The inspector reviewed the Licensee Event Reports (LERs) submitted to the NRC concerning three issues that were identified as unresolved in NRC Inspection Report 50-271/93-21. The licensee had not completed the engineering and safety analysis of these issues prior to the end of the previous inspection period. The following reports were reviewed to verify accuracy, description of cause, and adequacy of corrective actions. The inspector considered the need for further information, possible generic implications, and whether the event warranted further on site followup. The LERs were also reviewed with respect to the requirements of 10 CFR 50.73 and the guidance provided in NUREG 1022.
LER 93-13, Safety Related Switchgear Foimd to have Less Anchorage than Required by
the Original Plant Design, dated October 18,1993
LER 93-14, Inoperable Alternate Cooling Tower Subsystem due to inadequate Inspection / Acceptance Criteria, dated October 22,1993 LER 93-15, Low Pressure Core Spray Suction Strainers Found to be of Different Size
than Previously Assumed, dated November 8,1993 1.1 Seismic Qualification of Electrical Switchgear Licensee personnel identified deficiencies in the as-built seismic anchorage of safeguards class 1E electrical switchgear on September 18, 1993 during field walkdown for the Seismic Qualification Up Grade Program. Following the initial discovery of construction deficiencies concerning the 4160 volt safeguards electrical bus number 4 on that date, similar problems were identified during subsequent inspections of the redundant 4160 volt bus number 3 and with 480 volt safeguards buses 8 and 9 made through September 20. The 4160 volt switchgear was designed to be welded or bolted to embedded floor channel and the 480 volt switchgear bolted to similar floor embedments. The equipment was purchased with a seismic loading specification; however, there have been no installation drawings located that specify the required attachments.
The licensee's immediate corrective actions included welding the internal frame of bus 3 and 4 switchgear and bolting the frame of bus 8 and 9 switchgear to the embedded channel. This work was completed on September 22 during the plant refueling outage. Additionally, the licensee confirmed that none of the other plant switchgear were designed to be anchored to embedded channel. The licensee has not determined the effect of a design basis seismic event upon the improperly installed switchgear. As described in NRC Inspection Report 93-21, previous industry experience (Information. Notice 80-21) existed, but was not acted upon by the licensee until recently.
The safeguards electrical buses appear to have been in a degraded operability status since plant construction; this is an apparent violation of the following NRC requirements: (1) Technical Specification 3.10. A.3 requires that these four electrical buses be operable and energized for the
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reactor to be in the startup or run modes; (2) the Final Safety Analysis Report (FSAR) 8.4.7 Safety Evaluation of Station Auxiliary Power, establishes a requirement for the electrical switchgear to withstand a design basis seismic event; and (3) 10 CFR Part 50, Appendix B, Criterion Ill, Design Control, requires that the design basis be correctly translated into specifications and design documents.
1.2 Silt Accumulation in the Alternate Cooling Tower Subsystem Deep Basin
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Licensee personnel discovered in September 1993 that the Alternate Cooling Tower (ACT)
subsystem of the service water system was potentially degraded because of accumulation of an excessive amount of silt in the West cooling tower basin. The ACT subsystem is a backup mode of operation for the service water system in the event that water can not be drawn from the
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Connecticut River by the service water pumps. It makes use of a large volume of water stored in the basin of the West cooling tower and a recirculation path to the suction of the RHR service l
water pumps. Those pumps recirculate water through critical plant components such as the emergency diesel generators and RHR heat exchangers, which is then pumped back to the cooling tower.
On September 24,1993, the licensee determined that the ACT system was inoperable based on the amount of silt found in the tower basin and particularly in the pump suction pit. The RHR service water pumps draw water from the bottom of that pit through a twenty-four inch horizontal pipe. The licensee found that silt had accumulated to a depth of four and one-half feet in the five foot deep pit; additionally, they found an accumulation of over eight inches (nominal depth) silt over the bottom of the basin. The licensee concluded that the ACT subsystem was inoperable due to the significant amount of silt covering the suction line inlet.
The licensee's analysis also determined that the severe silting could have existed as far back as late 1989. The silt accumulates over time as plant discharge circulating and service water flows through the cooling tower. The last time the tower basin was entirely cleaned, including the suction pit, was during the Spring 1989 outage. Limited inspections in 1990 and 1992 resulted in the cleaning of only one section of the basin. During this period, the service water system has been in its normal mode of operation, that is, the service water pumps supplying critical plant components including the suction of the RHR service water pumps. Water and therefore i
the accompanying silt, had not been pumped from the West cooling tower basin as part of periodic testing.
I The displacement of stored water from the basin and pump suction flow restrictions were analyzed by the licensee to determine their effect on ACT operability. Neither the volume of water displaced from the cooling tower basin by the accumulation of silt, nor the approximate one inch thick corrosion products found on the inside surface of the RHR pump suction supply line, were concluded to have degraded the system's design basis performance. Although the licensee calculated that the corrosion thickness was not restrictive to reduce pump net positive suction head (NPSH), the pump suction piping was cleaned during the refueling outage along its entire length from the cooling tower basin to the system isolation valves located in the reactor building. The licensee concluded that the roo 4: of this event was a lack of understanding
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of the subsystem and inadequate inspection acceptance criteria. Although partial inspections were performed once per cycle since 1989, there was no formal or documented acceptance criteria within the preventive maintenance program. There were, however, no discussions in LER 93-14 regarding past NRC concerns regarding test and maintenance practices (unresolved item 91-21-02). This item addressed questions originally raised after an April 1991 loss of offsite power event, wherein the design basis performance of the ultimate heat sink (Cell No.
1 in the West Cooling Tower) was indeterminant. NRC inspection finding 91-21-02 remains unresolved today, leaving unanswered questions regarding service water operational capability, and the licensee's own understanding (and documentation) of its design basis.
This misunderstanding of design basis was the stated root cause in LER 93-14.
The ACT subsystem appears to have been inoperable due to silt obstructing the RHR service water pump suction line for an undetermined time since the Spring of 1989; this is an apparent violation of the following NRC requirements: (1) Technical 3.5.D, Station Service Water and Alternate Cooling Tower Systems, requires both service water loops and the alternate cooling tower to be operable with fuel in the reactor vessel and reactor coolant temperaturc greater than 212 degrees Fahrenheit; and (2) 10 CFR Part 50 Appendix B, Criterion XI, Test Control, requires that test procedures incorporate the requirements and acceptance limits of applicable design documents.
1.3 Degradation of the Core Spray System The licensee discovered that the core spray system pump suction strainers were of a smaller size than that assumed in Emergency Core Cooling System (ECCS) performance calculations on October 8,1993. The strainers were replaced with a larger size on October 14, prior to completion of the refueling outage. The Ecensee made a special as-built inspection of the strainers, which are located in the suppression chamber, in response to a request for information by the Boiling Water Reactor Owners Group in early October 1993. Following that inspection, the licensee discovered that the strainers were smaller than assumed in system performance
calculations.
Although the core spray system originally met its design basis with these strainers, the strainer minimum acceptable size was re-evaluated in 1986 in conjunction with a pipe insulation modification. The original metallic mirror insulation on the recirculation and residual heat removal systems was replaced with a commercial product made of low density fiberglass wool with a woven fiberglass cover. The concern with this material is that fibrous debris, formed during a loss-of-coolant accident, may buildup on the ECCS pump suction strainers. In 1986, a surface area of 9.8 square foot for each core spray pump suction strainer was calculated using
an incorrect strainer diameter. This size was obtained from original plant drawings; with no detailed as-built information available. The need to obtain this information was not clearly communicated from the engineering groups to the construction installation department; the strainer size was not verified until October 1993. That inspection determined the strainer surface area to be 7.8 square foot for each core spray pump suction containment penetration. The licensee determined that area allowed for sufficient pump NPSH when the strainers were clean, I
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but were less than the 9.0 square foot minimum required for the assumed debris loading.
Installation of the larger suction strainers, with a surface area of 24.4 square foot for each core spray pump suction penetration, was completed on October 14, 1993.
The low pressure coolant injection (LPCI) system pump suction strainers were replaced with larger strainers in 1986, but the reasons for that change were not described in LER 93-15. The LPCI strainers were apparently known to have been undersized in 1986; but, the subject core spray strainers were assumed at that time to have been adequate. This represents a missed opportunity to have found the current problem. Further, the licensee also inspected strainers for both the high pressure coolant injection and reactor core isolation cooling systems, and found the actual as-built con 6gurations to be accurate with respect to original calculations for NPSH, although the LER does not address these. LER 93-15 longer-term corrective actions were narrowly focused upon discussions with engineering personnel and a revision to calculational procedures regarding the verification of input data. These actions were committed to be
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completed within six months.
Left unanswered are questions about what other as-built
information (prior to November 1993) may have been inappropriately verified or used in calculations.
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The core spray system appears to have been in a degraded operability status since pipe insulation was replaced in 1986; this is an apparent violation of the following NRC requirements:
(1) Technical Speci5 cation 3.5. A requires the core spray system to be operable prior to a reactor startup; and (2) 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires that the design basis be correctly translated into specifications and design documents.
2.0 ADMINISTRATIVE 2.1 Preliminary Inspection Findings A meeting was held with licensee management representatives at the conclusion of the inspection on November 10 to discuss the preliminary findings. No proprietary information was identified as being included in this report.
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