IR 05000271/1998008
| ML20236L355 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee  |
| Issue date: | 07/01/1998 |
| From: | Cowgill C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20236L331 | List: |
| References | |
| 50-271-98-08, 50-271-98-8, NUDOCS 9807100324 | |
| Download: ML20236L355 (44) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket N Licensee N DPR-28 Report N Licensee: Vermont Yankee Nuclear Power Corporation Facility: Vermont Yankee Nuclear Power Station Location: Vernon, Vermont Dates: May 3 - June 13,1998 Inspectors: Brian J. McDermott, Senior Resident inspector Edward C. Knutson, Resident inspector Roy L. Fuhrmeister, Senior Reactor Engineer William A. Maier, Emergency Preparedness Specialist Ronald L. Nimitz, Senior Radiation Specialist Douglas A. Dempsey, Reactor Engineer Approved by: Curtis J. Cowgill, Ill, Chief, Projects Branch 5 Division of Reactor Projects 9807100324 980701 7 PDR ADOCK 05000271 e G PDR 3
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l EXECUTIVE SUMMARY t
Vermont Yankee Nuclear Power Station NRC Inspection Report 50-271/98-08 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a six week period of resident -
inspection; in addition, it includes the results of announced inspections by a regional radiation protection specialist, a regional emergency preparedness specialist, and a regional fire protection programs specialis Operations
- Operators responded promptly and in accordance with applicable procedures to an unexpected loss of the "A" reactor recirculation pump on June 5. The shift supervisor conducted frequent briefings of the control room operators, and operator communications was a strength. Operator actions were successfulin causing the reactor to promptly exit the exclusion region of the power / flow operating curv (Section 01.1)
- Inadequacies in an electrical ground isolation procedure resulted in an unanticipated i closure of the "A" CS pump minimum flow valve. The lack of appropriate guidance in procedure OP-2145, concerning which systems and components would be l affected and how they should be restored, was a violation of 10 CFR 50, Appendix j B, Criterion V, instructions, Procedures, and Drawings. (Section 01.3)
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- - Operators failed to identify the "A" core spray (CS) loop recirculation valve closed during the electrical ground investigation, causing the CS loop to be out of its j normal alignment for over an hour before the condition was identified by an operations department supervisor. (Section 01.3)
- On two occasions, operations personnel were not rigorous in implement procedures with the potential to affect Technical Specification related equipment. On a third occasion, operations personnel proceeded with main turbine activities after
. procedure acceptance criteria were not met and no procedure change was initiate None of these issues presented a significant technical or operational concern. No violations occurred and these incidents were viewed as personnel performance weaknesses. (Section 04.1) 4 Maintenance
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- A closeout inspection of the torus found the overall cleanliness was very good, l particularly considering the scope of work performed during the refueling outage (grit-blasting and recoating of all underwater surfaces, and installation of new strainers on the residual heat removal and core spray system suctions). The housekeeping conditions in the drywell were also examined during final closeout, ii
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and were determined to be adequate to support reactor operations at powe (Section M1.1)
- - The "B" standby gas treatment system fan failed to start on demand due to an incorrect over-current trip setting on its supply breaker installation procedures for a 1992 modification failed to implement required design settings and this error is being cited as a violation of 10 CFR 50, Appendix B, Criterion lil, Design Contro (Section M2.1)
- A 4-hour WRC event notification for a discovery that could have prevented fulfillment of a safety function was delayed by 14 days due to inadequate reviews and delays in Event Report processing. Other recent examples indicate weaknesses exist in VY's process for evaluating potentially reportable events. The failure to make a required NRC notification within the time frame specified by 10 CFR 50.72(b)is being cited as a violation. (Section M2.1)
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- A failure of the "B" standby gas treatment system to start on demand was identified as a potential maintenance rule functional failure and is scheduled for evaluation. Appropriate goals for system monitoring have been established and there were no previous maintenance rule functional failures in the rolling three year period. (Section M2.1)
Enaineerina
- The licensee identified that the chamfers on the internal edges of five high energy line break containment isolation valves were inconsistent with those recorded in applicable work documents and procedure requirements. The correct chamfers -
were installed in the valves in May 1998, reducing the potential for valve damage under blowdown conditions. (Section E1.1)
- . A modification that upgraded the safety classification of release mechanisms for-two steam tunnel blowout panels adequately resolved an NRC-identified design inadequacy. (Section E2.1) .
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- ' Two weakness were identified during NRC review of VY's corrective action for steam tunnel blowout panels. ' The operability determination f ailed to address the impact of a lower relief pressure on the secondary containment design basis ano VY's walkdown of the steam tunnel failed to identify a missing pipe penetration -
seal. The penetration seal was replaced prior to plant start up. Pending VY's evaluation of the BMO weaknesses, secondary containment operability during previous operation, and review of reporting requirements, this issue will be tracked
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as an unresolved item. (Section 52.1)
Plant Support
- VY established and implemented good external and internal exposure controls, and implemented effective radioactive material and contamination controls during the cycle 20 refueling outage. VY met outage occupational exposure goals, L
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notwithstanding some early identified deficiencies involving torus work activitie (Section R1.1)
- Radiation protection requirements were effectively implemented for the June 9, 1998, reactor scram. High radiation area access controls were implemented in accordance with procedures. General radiation protection program practices and procedures (e.g., posting barricading and access controls) were appropriately implemented. (Section R1.2)
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- VY implemented its radioactive material and contamination control program in an effective manner. Station areas were generally clean with no significantly contaminated areas or abandoned areas identified. While the licensee's criteria for evaluation of removable alpha contamination for material was not consistent with NRC guidance, the licensee took immediate and effective action to correct procedures and communicate the change. (Section R3.1)
- VY established and imp;emented a sampling and analysis program in response to NRC Bulletin 80-10. The licensee is effectively investigating a condition involving trace tritium contamination identified in storm drains. Notwithstanding, the low-level materialis being effectively monitored and controlled in accordance with regulatory requirements. (Section R3.2)
- VY implemented generally effective self-assessments, surveillance, and audits of t radiation protection program activities. (Section R7)
- The licensee maintained the major onsite and offsite emergency facilities in an adequate state of readiness. Equipment readiness surveillance were routinely performed. (Section P2)
- The recent changes to the emergency plan and implementing procedures were made in accordance with NRC requirements. (Section P3)
- The EP training function has ensured that assigned responders were kept adequately trained as required by the emergency plan. However, the NRC concluded that the licensee's evaluation of training was generally informalin that the licensee did not have good tracking mechanisms to rnonitor completions of drill requirements and ,
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relied on oral feedback about course material. (Section PS)
The licensee's EP organization was adequately staffed to oversee the EP function at the site. There were indications of some comrnunications isued that had the potential to reduce overall effectiveness. The senior managers with responsibilities
- for oversight of EP maintenance were adequately informed of their duties. -The licensee was adequately maintaining the emergency response roster as well as the respirator qualifications of members of the emergency response organizatio (Section P6)
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- The 1997 annual audit of the EP program met all the requirements of Part 50.54(t)
of NRC regulations. The licensee did not provide copies of the audit to the local l
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offsite agencier, although they were available for review by these agencies. The contractor ore Wzation that performed the quality assurance audits was sufficiently independent frce" the cor. tractor support provided to the licensee's EP staff. The licensee's puwi oft corrective actions for identified problems was aggressive but not always v.W-documented. (Section P7)
- The failure to include a full discharge test in the post-installation testing of the new low pressure total flooding CO2 extinguishing system for the switchgear rooms, as specified in NFPA Standard 12, remains unresolved, pending NRC review of alternate test methodology. (Section F2.1)
- The failure to maintain fire barrier penetration seal 40-T10465in a configuration corresponding to the tested configuration is a violation of NRC requirements, which is not being cited since the condition was identified, and corrected, by V (Section F2.2)
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TABLE OF CONTENTS l
1 EX E C UTIV E S U M M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii TA B LE O F C O NTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vi Summary of Plant Status ............................................1 1. Operations ....................................................1 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 01.1 Recirculation Pump Trip During Power Ascension ............ 1 01.2 Reactor Scram due to Feedwater Regulating Valve Malfunction .. 2 03 Operations Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . 3 03.1 Core Spray Valve Realignment During DC Bus Ground investigation
...............................................3 04 Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . . 5 04.1 Operational issues Resulting From Procedure-Related Problems . . . 5 11. M a in t e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 i M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 I M1.1 Maintenance Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 M1.2 Surveillance Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 i M2 Maintenance and Material Condition of Facilities and Equipment . . . . . . . 9 l M2.1 Standby Gas Treatment System Breaker Settings . . . . . . . . . . . . 9 M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 M8.1 (Closed) Inspector Follow-Up Item (IFI) 9 5 2 5-03 . . . . . . . . . . . . 1 1 ;
111. E n g in e e ri n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 E1.1 Primary Containment isolation Valve Thrust Predictions . . . . . . . 12 E2 Engineering Support of Facilities and Equipment .................14 E (Closed) IFl 96-11-02: Main Steam Tunnel Blowout Panel Actuation Setpoint Variance .................................14 E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 E (Closed) IFl 9 7 -0 2 -0 8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 6 E8.2 (Closed) IFl 9 7-01 -0 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 6 E8.3 (Closed) IFl 9 7- 1 2-0 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 6 E8.4 10 CFR 50.72 Notification for Potential increase in Post-Accident Peak Drywell Pressure ..............................17 IV. Plant Support ................................................17 R1 Radiological Protection and Chemistry (RP&C) Controls . . . . . . . . . . . . 17
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R1.1 RFO 20 Radiation Protection Program Performance . . . . . . . . . . 17 I R1.2 Applied Radiological Controls .........................19 R3 RP&C procedures and Documentation . . . . . . . , . . . . . . . . . . . . . . . . 20 R3.1 Radioactive Material and Contamination Control . . . . . . . . . . . . 20 vi
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R3.2 IE Bulletin 8 0- 1 0 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 1
R7 Quality Assurance in RP&C Activities . . . . . . . . . . . . . . . . . . . . . . . . . 22 R8 Miscellaneous RP&C issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 R8.1 (Closed) Unresolved item (URI) 50-271/98-01-03 . . . . . . . . . . . 23 R8.2 (Closed) IFl 50-271/98-04-04 . . . . . . . . . . . . . . . . . . . . . . . . . 2 3 P2 Status of Emergency Preparedness (EP) Facilities, Equipment, and Resources
...................................................23 P3 EP Procedures and Documt.:1ation . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 P Staff Training and Qualification in EP . . . . . . . . . . . . . . . . . . . . . . . . . 24 P6 EP Organization and Administration . . . . . . . . . . . . . . . . . . . . . . . . . . 25 l
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P7 Quality Assurance in EP Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 P8 Miscellaneous EP Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 P8.1 (Closed) IFl 50-271/9 2-14-01 . . . . . . . . . . . . . . . . . . . . . . . . . 28 F2 Status of Fire Protection Facilities and Equipment ................ 29 F Switchgear Room Carbon Dioxide System Replacement . . . . . . . 29 F2.2 Fire Barrier Penetration Seals . . . . . . . . . . . . . . . . . . . . . . . . . . 30 l F2.3 Material Condition of Fire Protection Equipment . . . . . . . . . . . . . 31 F6 Fire Protection Organization and Administration . . . . . . . . . . . . . . . . . . 32 F6.1 Changes to Fire Protection Organization . . . . . . . . . . . . . . . . . . 32 l
F Quality 4,surance in Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . 32 F7.1 Fire Protection Program Audits . . . . ....................32 L V. Management Meetings ..........................................33 l X1 Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 3
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X2 Vermont Yankee Management Changes . . . . . . . . . . . . . . . . . . . . . . . 33 X3 Review of Updated Final Safety Analysis Report (UFSAR) . . . . . . . . . . . 33 ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 LIST OF ACRO NYM S U SED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 5 l
L ATTAC H M E NT A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 7 l
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Report Details l l
Summarvnf Plant Status At the beginning of the inspection period, Vermont Yankee (VY) was conducting their cycle
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20 refueling outage. Major outage activities included replacement of strainers on the I emergency core cooling system torus suction lines, shortening of the torus downcomers,
! refurbishment of the torus, internal coating, reactor refueling, in-vessel equipment inspections, replacement of four control blades and seven local power range monitor
' detector strings, inspection of the high pressure turbine, and installation of a no-load
- disconnect switch for the main generato Control rod withdrawal for reactor startup was commenced at 2:35 a.m. on June 1, and
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criticality was achieved at 3:50 a.m. The main generator was synchronized to the grid at j l 3:39 p.m. on June 3, and again decoupled from the grid at 9:10 p.m. for planned turbine l overspeed testing. At 11:55 p.m., the main generator was placed on-line for return to normal full power operation. This marked completion of the 75-day refueling outag )
On June 5, an unexpected trip of the ."A" reactor recirculation pump resulted in a power reduction to approximately 40 percent. Following restoration of two pump operation, I power escalation was resumed on June 6. Three days later, a high bearing temperature on one of the reactor recirculation pump motor generators forced another power reductio During this downpower, a malfunction of the "A" feedwater regulating valve caused a j reactor water level excursion and resulted in a reactor scram. Subsequent complications l while attempting to stabilize plant conditions led VY to proceed to cold shutdown for )
equipment repairs and event analysis. Plant restart was commenced on June 12, and I preparations to place the main generator on the grid were in progress at the close of the inspection perio l. Operations 01' Conduct of Operations'
01.1 Recirculation Pumo Trio Durina Power Ascension Inspection SGQpa (71707,93702)
The inspector observed the control room operator's response to a loss of the "A" reactor recirculation pump (RRP). The inspector reviewed VY's conformance to Technical Specification requirements for single loop operations, and reviewed aspects of the associated maintenance activities through restoration of two loop operation ' Topical headings such as 01, M8, etc., are used in accordance with the NRC standardized reactor inspection report outline. Individual reports are not expected to address all outline topic I
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! 2 l Observations and Findinas At 2:37 p.m. on June 5, an unexpected loss of the "A" RRP ou mrred due to a trip l-
of the associated motor generator (MG). The resultant core flow and reactor power
. reductions resulted in the reactor operating in the exclusion region of the power / flow operating curve. - Under conditions of relatively high reactor power with respect to core flow, BWRs may experience reactor power oscillation due to unstable thermal hydraulic conditions; the exclusion region is defined in the core
- - operating limits report, and establishes the power / flow relationships under which
[ this undesirable phenomenon may occur. Technical specification 3.6.J states that,
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"If the reactor has entered the power flow exclusion region, the operator shall immediately insert control rods and/or increase recirculation flow to establish operation outside of the region."
f: ' The inspector was in the control room when the "A" RRP tripped, and observed that i the operators immediately recognized the condition and took prompt action in l-accordance with procedure OT-3118,' Recirculation Pump Trip." Accordingly, the
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A" RRP discharge valve was immediately closed, the speed of the "B" RRP was l , increased to 70 percent, and reactor stability monitoring was initiated per procedure j ' OT-3117, " Reactor instability." Operators then commenced control rod insertion, h using the withdrawal sequence in reverse order, to further reduce power. Reactor I conditions were restored to within the normal region of the power / flow operating
! curve nine minutes after the RRP trip. Power reduction by insertion of control rods was continued until the reactor was'out of the adjacent five percent buffer region, as directed by OT-3117. The inspector reviewed computer data and confirmed that
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reactor conditions were within the normal region of the power / flow curve for the remaining period of single loop operation.
l Single RRP operation is allowed indefinitely, under the conditions established by I- Technical Specification 3.6.G, " Single Loop Operation." Troubleshooting of the "A" recirculation MG was commenced in parallel with preparations for continued single ,
RRP operation. The cause of the "A" RRP trip was determined to be a failed fuse in the MG lockout circuit. Following fuse replacement and verification of conditions to
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< support pump restart, the "A" RRP was successfully returned to service at 1:52 a.m.'on June . Conclusions b ,
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' Operators responded promptly and in accordance with applicable procedures to an j
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unexpected loss of the "A" RRP. The shift supervisor condu::ted frequent briefings i of the control room operators, and operator communications was a strengt Operator actions were successfulin causing the reactor to promptly exit the ] '
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J : exclusion region of the power / flow operating curv .2 Reactor Scram due to Feedwater Reaulatina Valve Malfunction (93702)
l At 12:05 a.m. on June 9, control room operators received indication of a high bearing temperature on one of the motor generators that power the reactor l u
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recirculation pumps. Recirculation flow reduction was initiated to reduce load on
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the affected motor generator. During the subsequent power reduction through control rod insertion (in preparation for establishing single loop operations), one of I the reactor feedwater regulating valves failed at approximately 42 percent open, I causing reactor water level to increase. Operators were unable to achieve further l l valve closure prior to water level reaching the high level reactor scram setpoint, and l l a scram occurred at 1:35 Several subsequent events complicated efforts to stabilize plant conditions and
- resulted in VY proceeding to cold shutdown to pursue corrective actions. In l response, the NRC dispatched a specialinspection team to examine the l circumstances surrounding the event. This event is discussed in detail in NRC Inspection Report No. 50-271/98-0 Operations Procedures and Documentation 03.1 Core Sorav Valve Realignment Durinn DC Bus Ground Investigation a. - Inspection Scoce (71707,93702)
l The inspector reviewed the circumstances surrounding the discovery by the licensee
- that the "A" loop core spray (CS) pump minimum flow valve was out of its normal position.
[ Observations and Findinas At 11:08 a.m. on June 3, control room operators received indication of a low i electrical ground on thu Division 11 safety-related 125VDC bus DC-2. Operators proceeded to attempt to e9olate the ground in accordance with procedure OP-2145,
" Normal 125VDC Operation " Ground isolation per this procedure is performed by cycling, open and closed, the associated distribution system circuit breakers, and noting when the ground indication clears. Operators did not identify the ground using this procedure, however, it was located at 4:30 a.m. the following day using a portable, non-intrusive ground detection device.
l l While the OP-2145 ground isolation procedure was in progress, an operations
! department supervisor toured the control room and noted the main control board i
indication for the "A" loop CS pump minimum flow valve showed it was close This valve (CS SA) is a normally open motor-operated valve. The supervisor pointed this out to the control room operators, and found that they had been unaware of the condition. The valve was promptly returned to its normal open condition it was noted that the procedure for a loss of DC-2 (procedure ON-3160) identifies that CS-5A will close on a loss of power. Therefore, it was concluded that the closure of CS-5A had been a normal response to the ground isolation procedure. A change to procedure OP-2145 was generated (Department Instruction DI 98 255) to note the expected operation of the CS minimum flow valve _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
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The inspector reviewed this event on June 4. The inspector found no logged indication that the "A" loop of CS had been inoperable, and no indication of how long CS-SA had been out of its required position. When questioned, the licensee could not positively determine when the valve had stroked closed. An entry was subsequently made in the operators log, noting that the "A" loop of CS had been inoperable from a point in the ground isolation procedure at which CS-5A was
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- 15 p.m.) until the valve was returned to its normal position at 2:25 p.m. (a period of just over an hour). This was within the seven day allowed outage time specified by Technical Specifications, and thus, in itself, did not constitute a violation of regulatory requirements.
! 1 l The inspector reviewed OP-2145 and determined that it contained inadequate detail on the effect that performing the procedure would have on safety equipment.
l Specifically, a caution in the portion of the procedure that caused CS-SA to close, stated only that, " Opening circuits 2,5,6,7, and 8 defeats valve interlocks and pump trip protection. Minimize the time that circuits are open." The specific l equipment / systems that are effected and the nature of the effects are not discussed. By reviewing the electrical schematic diagrams for the CS-SA control l circuit, the inspector confirmed that the valve had operated as designed in response to a loss of DC power. The inspector also confirmed that the valve would have opened, had the "A" CS pump started. The inspector determined that the event was not reportable under 10 CFR 50.72 as an unanticipated ESF actuation, since
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the valve operation was not the result of a primary containment isolation system (PCIS) signal, and since only a single component of an ESF system was affected, I l
Appendix B to 10 CFR 50, Criterion V, " Instructions, Procedures, and Drawings,"
states, in part, that, " Activities affecting quality shall be prescribed by . . .
procedures . . . of a type appropriate to the circumstances . . . Instructions . . .
shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisf actorily accomplished." The DC-2 ground isolation procedure contained in OP-2145 did not provide appropriate guidance concerning which specific safety systems and components would be !
affected during conduct of the procedure, nor did it provide appropriate guidance for l systems restoration upon completion of the procedure. As a result, the "A" core spray subsystem was made inoperable, unknown to the operators, for a period of one hour and ten minutes. The failure to provide appropriate guidance for performance of the ground isolation procedure was a violation of 10 CFR 50, Appendix B. (VIO 98-08-01)
The inspectors noted that operators have been slow to recognize unanticipated changes in the alignment of emergency systems on two other occasions within the last year. On August 16,1997, a lightning strike caused the high pressure coolant
' injection (HPCI) pump suction to switch from the condensate storage tank to the torus; this condition went unnoticed for approximately two and one-half hours. On August G,1997, the "A" residual heat removal (RHR) pump minimum flow valve was unknowingly repositioned shut during performance of a surveillance procedure, and the condition was not noticed until the subsequent crew turnover. Both of these events are described in further detail in inspection report 50-271/97-06.
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functions, the failure to promptly identify unanticipated changes in the alignment of safety systems is of concern to the NRC with respect to operator awareness of
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plant condition Conclusions
- Inadequacies in an electrical ground isolation procedure resulted in an unanticipated l closure of the "A" CS pump minimum flow valve. The lack of appropriate guidance
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in procedure OP-2145, concerning which systems and components would be affected and how they should be restored, was a violation of 10 CFR 50, Appendix l- B, Criterion V, instructions, Procedures, and Drawings.
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Operators failed to identify the "A" core spray (CS) loop recirculation valve closed during the electrical ground investigation, causing the CS loop to be out of its normal alignment for over an hour before the condition was identified by an operations department superviso Operator Knowledge and Performance L 04.1 Operational Issues Resultina From Procedure-Related Problems
- . Insoection Scoos (71707)
Over the inspection period, the inspector noted three operational issues that were the result of procedure use problem . Observations and Findinas
' The inspector reviewed the following issues:
1. Following electrical loading of the "A" emergency diesel generator (EDG) for an operability verification on May 27, control room operators noted that the speed l control was erratic. Investigation revealed that the governor speed droop had not (- been adjusted for parallel operation, as specified in the EDG startup procedur Following adjustment of the speed droop, the EDG operated properl . While performing the turbine chest warmup during startup of the main turbine on June 1, operators observed that the indications for the condenser low vacuum-group l isolation trip, as specified by the procedure, OP-0105, " Reactor Operations," did not agree with the existing plant indications. Investigation revealed that the previous page of the procedure was missing, and that the missing page included the step to restore the bypass switches for this function to norma Technical Specification table 3.2.2, note 10, states that the condenser low vacuum trip system logiu is permitted to be bypassed to enable plant startup and shutdown, provided that both turbine stop and bypass valves are closed. Since the problem was identified and corrected, prior to opening a turbine stop or bypass valve, no violation of Technical Specifications occurred.
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3. On June 3, after several hours of low power operation, the main generator was removed from the grid to perform turbine overspeed trip testing. The normal overspeed trip device actuated 5 rpm low outside of the acceptable band, and the backup trip device tested satisfactorily. Operators noted that the governing procedure, OP-0105, did not specify that the overspeed test needed to be completed satisfactorily to proceed, only that it needed to be completed. Given that the vendor representative indicated that the test result for the normal overspeed trip device was acceptable, the operators proceeded to return the turbine generator to servic The inspector considered the first two examples to be weaknesses in procedure use .
during TG related activities that were corrected while the activity was stillin !
progress, in the third example, a situation occurred that was not specifically 1 covered by the procedure. After a technical disposition was reached, the main i turbine work was allowed to continue but the procedure was not changed. These issues were characterized as personnel performance weaknesses and were I discussed with operations department management. VY acknowledge the inspectors concern j Conclusions On two occasions, operations personnel were not rigorous in implement procedures with the potential to affect Technical Specification related equipment. On a third occasion, operations personnel proceeded with main turbine activities after ,
procedure acceptance criteria were not met and no procedure change was initiate l None of these issues presented a significant technical or operational concern. No violations occurred and these incidents were viewed as personnel performance weaknesse I 11. Maintenance M1- Conduct of Maintenance M1.1 Maintenance Observations
. Inspection Scope (62707)
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The inspector observed portions of plant maintenance activities to verify that the
- correct parts and tools were utilized, the applicable industry code and Technical Specification requirements were satisfied, adequate measures were in place to ensure personnel safety and prevent damage to plant structures, systems, and components, and to ensure that equipment operability was verified upon completion of post maintenance testin . __ -__ _
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7 Observations. Findinas, and Conclusions The inspector observed all or portions of the following rnaintenance activities:
- Torus closecut inspection, performed May 24 The inspector accompanied VY during their closecut inspection prior to torus refil The inspector observed that the overall cleanliness of the torus was very good, particularly considering the scope of work that had been performed (grit-blasting and recoating of all underwater surfaces, and installation of new strainers on the residual heat removal (RHR) and core spray (CS) system suctions). The torus had been downgraded to a level 4 cleanliness area during the maintenance activities, and restoration of level 3 cleanliness at the conclusion of work was done by inspection. Level 3 cleanliness controls were in effect at the time of the closcout inspection, and the inspector observed that the FME log was prop..ly utilized when j logging into the clean are * Drywell closeout inspection, performed May 28 The inspector observed a temporary floor support beam installed between the lower
. level (238-foot elevation) and the next level up (252-foot elevation) and questioned whether it was supposed to be installed. VY investigated and determined that the support had been installed in the late 1980's to support a maintenance activity, and had inadvertently been left in place. The support was subsequently remove The inspector observed that the overall cleanliness of the drywell was good. The inspector concluded that the housekeeping conditions in the drywell were adequate to support reactor operations at powe * Control rod position indicating probe replacement, observed June 10 A problem was noted with position indication for rod 42-19 during the reactor startup on June 1. Specifically, the positions between steps 00 and 12 were not indicating properly; at positions outside this range, indication was normal. This problem was not an immediate concern because the rod was to be fully withdrawn for the entire operating cycle. The position indicating probe is located in a well at the center of the control rod drive unit and can be replaced with the drive installed; however, it is inaccessible during at-power operations. The forced outage of June 9-12 presented an opportunity to correct the problem. A drywell entry was conducted to support this, and several other, maintenance activities. The inspector observed no deficiencies in the conduct of this maintenanc * Intermediate range monitor (IRM) channel "C" detector troubleshooting, observed June 10 IRM "C" was observed to be spiking during the June 1 reactor startup, and was declared inoperable. During the June 912 forced outage, troubleshooting of the problem was performed. The inspector observed disassembly and inspection of the
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l 8 connection between the detector and the output cable. The technicians observed no problems in the connector that would result in erratic instrument output Pre-L installation testing of a replacement detector showed it also to be malfunctioning, ll and so replacement was deferred. The inspector observed no deficiencies in the
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conduct of this maintenance activity.
l l M1.2 Surveillance Observations i insoection Scoos (61726)
The inspector observed portions of surveillance tests to verify proper calibration of
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test instrumentation, use of approved procedures, performance of work by qualified personnel, conformance to Limiting Conditions for Operations (LCOs), and correct post test system restoration.
l Observations Findinas, and Conclusions t
u The inspectors observed portions of the following surveillance testing activities:
- Emergency Core Cooling System Integrated Automatic Initiation Test, l OP-4100, observed May 25 l
The inspector observed the pre-test brief conducted in the control room. A large number of people (over 40) were in attendance for the brief and had the potential to divert operator attention from monitoring the plant. Several equipment deficiencies occurred during the test but did not invalidate the test results. During restoration of
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ECCS equipment, the inspector noted a delay was caused by weak coordination L ' with a parallel service water test activity. These observations were discussed with VY management and no further NRC action is required.
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- Reactor Pressure Vessel Operational System Leakage Test, OP-4101,
. observed May 28 The inspector.noted that the procedure directed operators to increase reactor pressure and temperature but did not provide an upper temperature limit. Because of the test requirements, primary containment can not be established and therefore TSs require the reactor coolant temperature to be maintained below 212* Through discussions with on-shift operations personnel and attendance of shift turnover briefings, the inspector verified that operations personnel were fully aware of the requirement to maintain temperature less than 212* * ' Reactor Core Isolation Cooling (RCIC) Turbine Overspeed Test, section D of OP-4121, observed June 1 The inspector noted that the nrocedure did not establish a maximurn speed above l the high end of the acceptable band, at which the test should be terminated by 1 operator action. Through discussion with the control room operator who was !
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. performing this function, the inspector determined that appropriate care was being
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taken to increase speed gradually, and to trip the turbine as soon as it was identified that the maximum acceptabla trip speed had been exceeded.
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' * High Pressure Coolant Injection (HPCI) Turbine Overspeed Test, section D of OP-4120, observed June 1 l
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The HPCl overspeed test is performed at a steam pressure of less than 150 psig and the inspector observed that the turbine exhaust check valve slammed a number of '
times during the test. The inspector'noted that the emergency operating procedures reference HPCI operation at low steam pressure and note that damage may occur due to water hammer, The inspector discussed this caution and his observations j with the system engineor, The engineer did not consider the check valve slam to be ;
a problem for VY and indicated as-found inspections of the turbine exhaust check '
valve seat and disc did not show damage from previous tests. The check valve's -
! performance will be monitored by VY's Appendix J leak rate test program during l future outages, j
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M2 Maintenance and Material Condition of Facilities and Equipment
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M2.1 Standby Gas Treatment System Breaker Settinos I Inspection Scope (62707)
, On June 1, the "B" Standby Gas Treatment System (SGTS) fan failed to l , automatically start as expected during a High Pressure Coolant injection (HPCI)
surveillance test. Operators declared the "B" SGTS train inoperable, documented entry into TS 3.7.B.3.b, and initiated ER 98-1339 for further investigation. The inspector reviewed this event in order to assess the effectiveness of VY's corrective action and to verify implementation of Maintenance Rule (10 CFR 50.65)
requirements.
L Observations and Findinas During the initial investigation of ER 98-1339 on June 1, VY discovered the over-current setting for the "B" SGTS fan motor breaker was incorrect based on l~ controlled plant drawings. VY also determined the uncontrolled records in the Maintenance Planning And Control (MPAC) computer listed the incorrect set point for this breaker. After the breaker's trip setting was corrected, a post maintenance test was performsd and the "B" SGTS subsystem w ' as declared operabl On June 2, VY found the same discrepancy on the "A" SGTS fan motor breake The licensee initiated ER 98-1375 to capture this discrepancy but, no basis for operability was documented. After discussion with cognizant VY personnel, the inspector concluded there was a sufficient basis for VY's conclusion that the "A" SGTS remained operable. The "A" SGTS fan breaker setting was adjusted to its proper value on June J b
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. ER 98-1375 indicates the incorrect SGTS breaker settings existed since 1992.
! VY's review of work records found that the SGTS fan motors and their circuit breakers were replaced under modification EDCR 90-406in March 1992. The inspector observed that the installation procedure for this modification did not require setting or verification of the over-current set points for the new breaker Although the incorrect settings existed for both SGTS fans since 1992, the problem did not manifest itself until the "B" SGTS breaker was replaced in December 1997, with a breaker having less variation in its setpoint. The failure provide adequate measures to assure the design basis for the SGTS components were correctly 1 translated into procedures and instructions for implementation is a violation of !
'iO CFR 50 Appendix B, Critorion lil, Design Control. (VIO 98-08-02)
In response to the incorrect SGTS breaker settings, VY reviewed similar AC molded case circuit breakers and found 17 documentation discrepancies between MPAC
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records and controlled plant drawings. ERs were initiated to document and resolve actual discrepancies. The inspector noted interim measures were taken to ensure
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operability, the planned corrective action were appropriate, and the subsequent VY i engineering assessments determined there was no past impact on operability. VY's l review of similar DC breakers found no problems. On June 11, VY inspected a 10 percent sample of safety related breakers, which did not have document
- - discrepancies, and no problems were identified, i
l The potential for a common mode failure was first revealed during VY's
! ; investigation of the June 1, "B" SGTS fan failure. On June 2, VY identified the incorrect breaker setting also existed on the "A" SGTS train (ER 98-1375). Three l
days later, on June 5, the Shift Supervisor reviewed ER 98-1375 and determined it l was not reportable. On June 8, VY's ER screening meeting determined the two ERs L for these events should be administratively linked and evaluated together. On June i 11,' eight days after the second problem was identified, the combined event was re-screened as potentially reportable. On June 16,1998, VY made a 4-hour report to the NRC as required by 10 CFR 50.72(b)(2)(iii) after concluding incorrect SGTS breakers settings created a condition that could have prevented the fulfillment of a safety function.
! 10 CFR 50.72(b)(2)(iii), "Four-Hour Reports," requires licensee's to report, within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, any condition that alone could have prevented fulfillment of a safety function
>
of a system needed to control the release of radioactive material. On June 2, VY j discovered incorrect circuit breaker settings, resulting from maintenance activities, l
could have prevented operation of both standby gas treatment system fans. Initial reviews by shift supervision, and later by the ER screening meeting, failed to identify the event as a reportable condition. These errors were compounded by delays in processing of the ER and resulted in a required 4-hour NRC notification being made 14 days after the condition was discovered. The failure to make the required notification within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is considered a violation of 10 CFR 50.72(b).
(VIO 98 08-03)
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The inspector noted that VY's ER screening meeting initiated Maintenance Rule l review for the "B" SGTS fan failure. VY procedure AP 0009, " Event Reports,"
! requires a documented review of potential maintenance rule functional failures (MRFF), identified by the screening committee, during the event investigation. The inspector interviewed the responsible system engineer and reviewed a SGTS quarterly Maintenance Rule report. VY monitors MRFF for cach SGTS train and for the system, with performance goals of 2 and 3, respectively. A review of the system engineer's documentation found that there have been no MRFFs for SGTS during the rolling three year period.
l Conclusions
. The "B" standby gas treatment system fan failed to start on demand due to an incorrect over-current trip setting on its supply breaker. Installation procedures for a l 1992 modification failed to implement required design settings and this error is l being cited as a violation of 10 CFR 50 Appendix B Criterion lil, Design Control.
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) A 4-hour NRC event notification for a discovery that could have prevented l fulfillment of a safety function was delayed by 14 days due to inadequaie reviews I and delays in Event Report processing. Other recent examples indicate weaknesses r,xist in VY's process for evaluating potentially reportable events. The failure to l - make a required NRC notification within the time frame specified by l 10 CFR 50.72(b)is being cited as a violation.
i l A failure of the "B" standby gas treatment system to start on demand was L identified as a potential maintenance rule functional failure and is scheduled for L evaluation. Appropriate goals for system monitoring have been established and there were no previous maintenance rule functional failures in tha rolling three year perio l M8 Miscellaneous Maintenance issues
[. M8.1 (Closed) Insoector Follow-Up item (IFI) 95-25-03: Pumo suction or6.ssure evaluation
! durino surveillance L
in inspection report 50-271/95-03,the inspector noted that the acceptance criteria for pump suction pressure during ECCS pump surveillance would not provide indication of a loss of net positive suction due to strainer clogging.
L ' During the 1998 refueling outage, VY installed large capacity passive strainers on
! the RHR and CS torus suctions, in response to NRC Bulletin 96-03, " Potential Plugging of Emergencv Core Cooling Suction Strainers by Debris in Boiling Water Reactors." This action adequately addresses the earlier concern for strainer performance monitoring, and therefore, inspector follow-up item IFl 95-25-03 is close _ - _ - _ _ _ _ ___ ___-_____ - _ - _ - - _ _ - _ _ _ _ _ _ _ _ - _ - _ _ _ _ - _ _ _ - _ _ _ _ _ _ __- -
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111. Engineering l
E1 Conduct of Engineering ll E Primary Containment isolation Valve Thrust Predictions L I l Insoection Scooe )
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.On May 26,1998, the licensee reported to the NRC, pursuant to 10 CFR 50.72, ;
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that six primary containment isolation valves in the high pressure coolant injection L (HPCI), reactor core isolation cooling (RCIC), and reactor water cleanup (RWCU)
systems did not have the proper chamfering (i.e., beveled edges) of various required i
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internal surfaces. The condition could have prevented the valves from isolating a high energy line break (HELB) outside of the containment.
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The inspector discussed the licensee's disposition of steam line isolation valves in !
l the HPCI and RCIC systems and discussed two RWCU isolation valves with the
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licensee's motor-operated valve (MOV) program coordinator. . Work orders, maintenance procedures, design documents, and calculations were reviewed to assess chamfering requirements and the impact of the lack of chamfers on isolation l> valve operabilit Observations and Findinas On April 30,1998, during testing of a HPCI steam line isolation valve, unusual
. noises coming from the valve were noted by licensee test personnel. When the valve was disassembled and inspected to investigate the cause of the noise, the licenses found that the expected chamfers were not installed (although the body seats appeared to be rounded to some extent) on certain internal valve sliding surfaces.' However, ~a previous work order work order indicated that the internal surfaces of the valve had been chamfered in accordance with operating procedure OP 5201, " Safety System Valves," and form VYOPF 5201.04,"GL 89-10 Gate Valve inspection Sheet." Similar conditions subsequently were noted by the L licensee when the other five isolation valves were re-opened in May 1998. The i HELB isolation valves were worked by contractor valve technicians during refueling
. outages conducted in 1995 and 199 Because of the dynamic forces present under blowdown (HELB) conditions, and the
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attendant concern for disk tilt and other internal effects, the sharpness of the
. leading edges of valve body and disk seats and guides is important to functionality,
. since sharp edges can result in seat or guide damage and unpredictable l: performanc Valve Operability in May 1998, licensee maintenance personnel disassembled the other five isolation valves and installed (or verified) chamfers greater than or equal to the current requirements of procedure OP 5201.Thus, the inspector had no concerns regarding
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current valve capability. The inspector independently calculated the output capabilities of the six HELB isolation valves, using standard industry equations, to assess past valve operability. Acceptable margins were predicted above minimum
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thrust requirements. However, the standard industry equations do not account for potential change or unpredictable behavior under blowdown conditions. Therefore, prior to May 1998, with the internal edges of the VY HELB valves not properly chamfered or rounded, internal damage may have occurred under blowdown conditions due to the less than optimum surface conditions actually presen The fact that the 1998 as found chamfers were not consistent with work records and other design documents raised questions regarding adherence to maintenance procedures and oversight of contractor activities. This matter is unresolved pending l further NRC review. (URI 98-08-04)
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Other Safetv-Related Valves
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There are over 60 gate valves in the. Vermont Yankee GL 89-10 population. Edge treatment of gate valve internals is not normally critical for valves that must
. function under pumped flow (versus blowdown) conditions. The only safety-related gate valves at VY subject to blowdown flow are the six HELB valves in questio At the time of the inspection, the status of chamfering of the 50-some other gate valves was unknown. Therefore, the extent to which the licensee may have assumed incorrect or unverified internal dimensions in thrust requirement calculations is unresolve i The extent to which unverified or incorrect internal dimensions may have been used as inputs to the thrust requirement calculations of other safety-related gate valves also is unresolved. (URI 98-08-05) Conclusions The licensee identified that the chamfers on the internal edges of five high energy
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line break isolation valves were inconsistent with those recorded in applicable work documents and procedures. The correct chamfers were installed in the valves in May 1998, reducing the potential for valve damage under blowdown condition Two unresolved items were opened pending additional information on 1) adherence
- to maintenance procedures and oversight of contractor activities and 2) internal dimensions used in thrust calculations for other safety-related gate valves.
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E2 Engineering Support of Facilities and Equipment E (Closed) IFI 96-11-02: Main Steam Tunnel Blowout Panel Actuation Setoolnt
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Variance p 1 Insoection Scope (92903)
In December 1996, VY determined that blowout panels in the main steam tunnel l could cause reactor building temperatures to exceed equipment environmental qualifications during some high energy line break (HELB) scenarios. A basis for
' maintaining operation, BMO 96-18, " Main Steam Tunnel Blowout Panel," was ,
developed to verify that continued operation was ac::eptable, and to specify corrective actions and completion dates, in May 1998,the NRC observed that two of the blowout panels did not appear to I be safety class components (see NRC Inspection Report No. 50-271/98-04). During I this inspection, VY's progress towards resolution of this BMO was reviewed.' Observations and Findinas L1
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VY calculation VYC 1681, dated February 6,1997, identified the original blowout panels would relieve at approximately 0.04 psi, rather than the required 0.25 psi.
i -The original panel restraints, each consisting of a pulley and a 29 pound weight,
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were replaced during the refueling outage with Safety Class 2 restraints which use
. shear pins to set the relieving pressure. VY determined the new restraint design -
was necessary because a weight of approximately 400 pounds would be required to l achieve the desired blowout pressure using the old restraint desig FSAR section 5.3, " Secondary Containment System," indicates that the reactor
- building is designed to withstand an internal pressure of 0.25 psi without structural
' failure or pressure relief. This section also describes how SGTS functions with the secondary' containment to meet the reactor building safety design basi '
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tThe inspector's review of BMO 96-18 determined that '/Y did not address the-impact of the low blowout panel relief pressure on' operability of the secondary j containment. Prior to the 1998 refueling outage, VY had two opportunities to j identify the conflict between the calculated relief pressure and the FSAR d '
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- requirements for secondary containment. In November 1997, BMO 97-053 identified a qualification issue with the secondary containment airlock doors and i
specifically discussed the FSAR requirements but, no connection was made. A
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second opportunity to identify the issue was during VY's collective review of BMO However, BMO 97-053 was written after the October 1997 cumulative review and was closed prior to the'cumu!ative review performed during the refueling outag At present, the degraded condition has been corrected and the licensee has initiated ER 98-1495 to evaluete the BMO weakness identified by the inspector. Pending VY's evaluation of the BMG weaknesses, secondary containment operability during
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previous operation, and review of reporting requirements, this issue will be tracked as an unresolved item. (URI 98-08-06)
On May 24, the inspector observed that the HPCI steam line penetration through the steam tunnel floor provided an unobstructed path to the torus room. In contrast, a similar penetration for the RCIC steam line was sealed. The inspector discussed this disparity with VY management and the potential for this open path l was to impact the recently revised HELB analysis. VY subsequently determined the floor penetration was not accounted for in the HELB analysis and initiated a modification to seal the penetration. The modification was completed prior to plant restar As a result of additional analyses, VY discovered that smaller steam line breaks (such as HPCI and RCIC) were more limiting than a large main steam line break, because the smaller breaks do not immediately isolate. VY revised BMO 9818 to address this issue and compensatory measures for additional turbine building relief capability were implemented. At the close of the inspection period, BMO 96-18 remained open, pending development of additional (permanent) turbine building 3 venting capability, completion of final analyses, and update of EQ documentation.
I Permanent plant modifications have been installed to address the main steam tunnel blowout panel concerns. Modifications to permanently resolve the turbine building
. relief capability are being planned and VY is evaluating whether this installation can be made with the unit on line. Based on the status of corrective actions for BMO L 96-18, the inspector concluded that VY's completed and pending corrective actions j were adequate. Accordingly, inspector follow up item IFl 96-11-02is close ;
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C. Conclusions i
l- A modification that upgraded the safety classification of release mechanisms for two steam tunnel blowout panels adequately resolved an NRC-identified design inadequac Two weakness were identified during NRC review of VY's corrective action for steam tunnel blowout panels. The operability determination failed to address the impact of a lower relief pressure on the secondary containment design basis and i VY's walkdown of the steam tunnel failed to identify a missing pipe penetration {
seal. The penetration seal was replaced prior to plant start up. Pending VY's evaluation of the BMO weaknesses, secondary containment operability during previous operation, and review of reporting requirements, this issue will be tracked as an unresolved ite i I
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16 E8 Miscellaneous Engineering issues E (Closed) IFl 97-02-08: Station Service Water / Alternate Coolina System Eaulvalency n
in early.1997,'VY identified a discrepancy between Technical Specifications and the FSAR concerning the equivalency of the station service water system and the alternate cooling system. VY established administrative requirements for operation -
with degraded service water subsystems pending a change to the Technical Specification On April 23,1998, VY submitted Technical Specification proposed change no. 200,
" Revision to Station Service Water and Alternate Cooling System Requirements."
No further inspector follow-up of this issue is required, and therefore IFf 97-02-08is close E8.2 -(Closed) IFl 97-01-02: Potential to Exceed Containment Desian Pressure Durina EOP Implementation During the March 1997 emergency preparedness exercise, VY_ldentified a concern
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that containment flooding could cause the vent system rupture disc to actuate l before the EOPs direct containment venting. After considerable licensee and NRC review of this issue, VY submitted LER 98-10," Failure to foresee system
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interactions allows the installation of a wetwell. hardened vent system which presents conditions which challenge containment systems in the event of a postulated LOCA," dated May 28,1998.. This issue will be reviewed in conjunction
' with the LER and therefore the IFl is no longer necessary for tracking purposes. -
Accordingly, inspector follow-up item IFI 97-01-02 is administratively close E8.3 (Closed) IFl 97-12-03: BMOs Prooosed by VY to Remain Ooen Followina the 1998 Refuelina Outaae Early in 1998, VY indicated to the NRC that a number of BMOs would remain open
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. at the completion of the refueling outage. With respect to the timeliness of
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corrective action, Generic Letter 91-18, Revision 1, "Information to Licensees Regarding NRC Inspection Manual Section on Resolution of Degraded and Nonconforming Conditions," states,-"The NRC expects time frames longer than the next refueling outage to be explicitly justified by the licensee as part of the deficiencp tracking documentation." As a result, a meeting of VY and the NRC was held to discuss the situation. Subsequently, VY documented their justification for
- the BMOs that were to remain open, in correspondence to the NRC (letter BVY
- 98 61, dated May 1,1998, and letter BVY 98-78, dated May 28,1998). Based on .
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the licensee's submittals, and NRC reviews of the issues, administrative tracking of k this issue is no longer necessary. Inspector follow-up item IFl 97-12-03is close <
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E8.4 10 CFR 50.72 Notification for Potential increase in Post-Acc! dent Peak Drvwell l Pressure l On April 28, VY identified an operating condition that could potentially result in a peak drywell pressure, following a large break loss of coolant accident, that was greater than previously analyzed. The licensee discovered that operation at less J than 100 percent core flow while at 100 percent reactor power could result in a <
more limiting mass release inside containment during a design basis accident. This discovery was appropriately reported in accordance with 10 CFR 50.72. No problems were identified during initial NRC review of the licensee'n operability determination and this issue will be addressed in NRC Inspection Report 50-271/98 8 IV. Plant Support l
R1 Radiological Protection and Chemistry (RP&C) Controls ,
R1.1 RFO 20 Radiation Protection Proaram Performance Insoection Scope (83750) ,
The inspector reviewed external and internal exposure controls and ALARA program
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performance for the cycle 20 refueling outage (RFO20); evaluated the radiological controls provided for cleaning and painting of the torus; and reviewed ALARA performance for work activities with accumulated radiation exposure in excess of 5 person-re Relative to torus cleaning and painting activities, the following aspects were
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reviewed: airborne radioactivity sample results, whole body count results, personnel contamination reports, radioactive material intake assessments, and calculations of effective doses. Additionally, the effectiveness of airborne radioactive material controls, including use of respiratory protective equipment was examined. Airborne radioactivity controls for torus sandblasting, vacuuming of l
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HEPA ventilation system filters, and sandblasting support activities (e.g., " pot tending" to refill grit blasting supply containers) were also reviewed.
- , The review was against criteria contained in 10 CFR 20. The adequacy of pre-job p briefings of workers relative to requirements contained in 10 CFR 19 was examine !
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L Observation and Findina
. There were no unplanned external exposures during the outage and no individual sustained a deep dose equivalent in excess of 2 rem (1.2 rem maximum as of June' 1,1998). There were no neutron personnel exposures recorded at the station since June 1995. The total accumulated radiation exposure, based on electronic dosimeter readings, reasonably compared with that recorded by thermoluminescent dosimeter. Dosimetry anomalies were properly reviewed and evaluated. Personnel whole body dosimetry was accredited by the National Voluntary Laboratory
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Accreditation Program (NVLAP) for appropriate test categories specified in ANSI 13.11,1993. There were no exposures to the extremities in excess of 10%
of the 10 CFR 20 limit (50 rem). Extremity dosimetry was tested using standard techniques (e.g., bias and standard deviation).
As of June 1,1998,245 personnel contaminations were recorded resulting in 44 skin dose assessments. Of the 44 assessments only 5 warranted assignment of shallow dose equivalent (SDE). The maximum SDE (320 millirem) was less than 1 %
of the applicable 10 CFR 20 limit. VY used reasonable calculational methodology and assumptions to estimate shallow dose equivalent to the skin, i VY used engineering controls and provided respiratory protection equipment, when i needed, to minimize intakes of airborne radioactivity. There were 62 whole body l
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counts performed during the outage as a result of personnel contamination events, which resulted in 36 indications of potential intake of contamination. Appropriate dose assessments were performed for apparent intakes. Calculated committed i effective doses equivalents (CEDE) were low. The maximum CEDE assigned to an individual was 15 millirem CEDE.
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Overall, airborne radioactivity controls were good. Maximum airborne radioactivity concentrations (54 DAC) were encountered during sandblasting operations within the torus in preparation for torur repainting. Individuals associated with that work activity wore respiratory protective equipment and were selectively whole body counted. No significant internal exposures were identifie On April 10,1998, VY experienced a breakthrough of its temporary HEPA ventilation system for torus airborne radioactivity control. The system vented to the reactor building. The breakthrough was detected by radiation protection personnel and monitored with previously installed portable airborne radioactivity monitoring instrumentation. The installed instrumentation effectively measured radioactivity in the vicinity of the HEPA system exhaust. No significant airborne radioactivity was
' identified. VY used security access control records to identify workers who may have been in the area and provided whole body counts, as appropriate. Whole body count records for workers were readily available and indicated that no significant intakes of radioactive material occurred. Further, intercomparison of worker lead monitoring data and whole body count data did not indicate any anomalous result VY maintained 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> radiation protection access control to the torus and provided pre job briefings to workers. Enhanced work controls and oversight was provided for workers involved in torus cleaning and painting activities due to the presence of airborne lead during dust creating activities. Workers signed in on applicable radiation work permits indicating they read and understood their RW VY met its 1997 annul exposure goal and its 1998 RFO 20 outage exposure goal, and provided good exposure reduction initiatives for work tasks (e.g., shielding and ALARA in process reviews). VY identified weaknesses in planning and control of
- torus work activities. Specifically, weak project management and planning for the torus painting activities resulted in a delay in completion of the work activity and i
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. prompted the issuance of an Event Report. The delay was primarily associated with reduction in torus cleaning activities to minimize airborne radioactivity and filter I loading. Despite a significant delay in work completion, a lower effective dose rate for the work activity allowed the licensee to complete the task within its original I exposure estimate. Post-Job ALARA reviews for outage work activities were comprehensive and identified areas for program enhancement, Conclusion VY established and implemented good external and internal exposure controls, and implemented effective radioactive material and contamination controls during RFO 20. VY met outage occupational exposure goals, notwithstanding some early identified deficiencies involving torus work activities. No violations or safet concerns were note R1.2 'Apolied Radiological Controls
' Insoection Scope (83750)
l The inspector reviewed general radiological controls. The inspector toured various l portions of. the radiological controlled area, made independent radiation I measurements, rev!ewed radiological posting practices, and reviewed access control to high radiation ares: . . The inspector selectively reviewed control practices for i
. radioactive material and contamination during tours of the statio The inspector also evaluated VY's implementation of its radiation protection
. program following the June 9,1998, reactor scram. The inspector reviewed the licensee's external and internal exposure controls program performance relative to this event. The implementation of radiological controls during containment entries for under vessel work activities, conducted dusing the week of June 8,1998, were ;
aiso examine !
The reviews were against criteria containod in 10 CFR 20 and applicable station ;
procedures, Observations and Findinas VY implemented its radiation protection procedure requirements following the June 9,1998, reactor scram. Radiation and airborne radioactivity surveys were conducted as required by the licensee's procedures. Appropriate radiological controls were provided for personnel entry to the drywell to perform under vessel radiological work activities (position indicating probe repairs).
VY provided and posted proper warning signs for radiological controlled areas. High radiation areas were properly controlled, as were keys to locked high radiation ;
areas. Survey maps were current,' monitoring instruments were functional and in-
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calibration, and personnel were wearing the proper dosimetr 'I
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Personnel exiting the controlled areas were properly monitored for radioactive contamination. Contaminated equipment was appropriately labeled: and warning signs were properly posted for identifying potentially contaminated area Conclusion Radiation protection requirements were effectively implemented for the June 9, 1998, reactor scram. High radiation area access controls were implemented in accordance with procedures. General radiation protection program practices and procedures (e.g., posting barricading and access controls) were appropriately implemented. No violations or safety concerns were identifie R3 RP&C procedures and Documentation R3.1 Radioactive Material and Contamination Control Insoection Scope (83750)
i The inspector selectively reviewed VY's radioactive material and contamination control program. The inspector reviewed applicable procedures and discussed the program with cognizant VY personne Observations and Findinos The station areas examined reflected good contamination controls practices. The areas were generally clean, and equipment was neatly stored. The areas were generally accessible and none were significantly contaminated or considered as inaccessible locations. The station exhibited approximately 9% contaminated area within the radiological controlled area. Decontamination efforts to reduce contaminated areas to a minimum was ongoin VY established procedure guidance for survey and monitoring of material to be released from the restricted areas of the station. The procedures included specific guidance relative to the application and capabilities of the equipment used to monitor for fixed and removable contamination, including methods and technique However, the criteria for evaluation of removable alpha contamination, specified in VY procedure AP 0516, " Survey and Release of Materials, Vehicles, and Trash
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From the Restricted Area," was not consistent with the NRC guidance provided in NRC Circular 81-07, " Control of Radioactively Contaminated Material". Specifically, VY's procedures stated that materiallikely to be contaminated with alpha contamination was to be surveyed with instrumentation capable of detecting less than 100 dpm/100 cm of alpha contamination. The NRC guidance specified a value of 20 dpm/10 cm2 for removable contamination. Upon notification, VY initiated an immediate procedure change to address this matter, and also initiated training of appropriate personnel on the procedure change. VY reviewed this matter and concluded that it was unlikely that detectable alpha contamination was released from the station, due to the high beta / gamma to alpha ratios present at the station,
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the very low detection capability of instruments actually used for alpha monitoring, and the practice of not releasing material with any detectable alpha contaminatio VY adopted a 10% efficiency for its friskers (thin window GM tubes) used to survey potentially contaminated material for release form the restricted area. As part of its normal evaluation of sample results, the licensee identified an increase in the fractional abundance of difficult to detect radionuclides (i.e., CR-51) associated with turbir.e rotor work during RFO 20 and established special contamination controls for that work location. A preliminary evaluation of the actual efficiency of friskers, based on the analysis of smear samples collected at various locations within the radiological controlled area, indicated that the friskers exhibited a range of detector efficiencies. While the licensee did not identify an immediate need to modify general frisking practices, action was initiated to evaluate the adequacy of the contamination control program for the purpose of validating the quality and effectiveness of the monitoring practice During last winter's snow removal activities, VY had excavated some soil from within the protected area with trace levels of Cesium contamination. The soil had been scraped during snow removal activities and placed outside the protected are Subsequently, upon snow melt, VY sampled the residual dirt and identified trace contamination, having radioactivity below the lower limit of detection specified for environmental measurements, i.e., trace concentrations which could be attributable to normal background. Notwithstanding, initiated action to drum the soil residua
.(estimated to be about two 55 gallon drums) and return the material to the restricted area for dispositio Conclusions VY implemented its radioactive material and contamination control program in an effer o manner. Station areas were generally clean with no significantly contaminated areas or abandoned areas identified. While the licensee's criteria for il evaluation of removable alpha contarrination for material was not consistent with NRC guidance, the licensee took immediate and effective action to correct procedures and communicate the chang R3.2 IE Bulletin 80-10 Inspection Scooe (83 5Q).
ll The inspector selectively reviewed VY's sampling and analysis program established L
in response to NRC Bulletin 80-10," Contamination of Nonradioactive System and Resulting Potential for Unmonitored, Uncontrolled Release to Environment," dated May 6,1980. The NRC issued the bulletin to provide for monitoring of non-contaminated systems that interfaced with contaminated systems and to provide for prompt identification of cross-contamination between systems that could result in an unmonitored release of contamination to the environment.
Y_______-__--_-____-__-_-__-_-___-- - ._-
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22 Observations and Findinas VY had established a sampling and analysis program in response to NRC Bulletin 80-10. The program provided for sampling and analysis of systems that could result in potential unmonitored releases of radioactivity to the environmen As part of its routine NRC Bulletin 80-10 sampling and analysis program, VY periodically sampled and analyzed samples from onsite storm drains. VY had periodically detected trace tritium contamination and other particulate contamination in storm drains. The trace contamination was reported in the environmental i
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monitoring reports submitted to the NRC. The licensee was attempting to ascertain the source of the contamination. Possibilities considered include that the tritium resulted from condensation from station cooling systems as the consequence of air from the turbine building interfacing with air in the administration buildin Sampling and analyses of the condensate from portable dehumidifiers used to monitor the administration building revealed very low levels of tritium contamination. Subsequent personnel dose estimates as a result of the tritium indicated that there is no significant dose consequence associated with thL condition, i.e., the dose was calculated to be less than 1 millirem / yea ,
VY subsequently issued an Event Report for this condition. The licensee's efforts to l determine the source _and cause for the tritium contamination and the results of a j safety evaluation relative to NRC Bulletin 80-10 guidance, wil' be reviewed during a l
, 1 subsequent inspection (IFl 98-08-07). )
l l ; Conclusion
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VY established and implemented a sampling and analysis program in response to NRC Bulletin 80-10. The licensee is effectively investigating a condition involving trace tritium contamination identified in storm drains. Notwithstanding, the low-level materialis being effectively monitored and controlled in accordance v.ith regulatory requirements, j i
R7 Quality Assurance in RP&C Activities Insoection Scope The inspector reviewed VY, self-assessment, surveillance and audit program in the area of radiation protection performed during the refueling outage DFO 20).
. Observations and Findinas VY conducted comprehensive audits of the radiation protection program. Special assessments were conducted of selected areas where warranted. Supervisors were performing and documenting reviews of on-going activities. VY actively solicited areas for improvement from radiation protection personnel hired to supplement the ;
staff during outage '
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23 Conclusion i
- VY implemented generally effective self-assessments, surveillance, and audits of radiation protection program activitie f R8 Miscellaneous RP&C lesues -
if , , R8.1- (Closed) Unresolved item (URI) 50-271/98-01-03: Use of 9249 Cask Prior to Aoril 1.1996 and Trainina for User's Manual to Be Provided for Radwaste Comouter
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Proaram At the time of the use of the subject cask, VY met applicable exemptions for its use'
and was not required to be a registered user. VY had not used the cask when an ( exemption did not apply. VY initiated action to modify procedures to require <
verification of registration prior to use of casks. No violations of regulatory
- requirements were identifie l
- R8.2 -(Closed) IFl 50-271/98-04-04: Review Air Samoler Collection Efficiency I VY was not able to provide information as to the collection efficiency of an air l
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sampling media (cellulose ester) recently placed in service for airborne radioactivity sampling. VY evaluated this matter relative-to criteria contained in NUREG 1400, j
"" Air Sampling in the Work Place," and Regulatory Guide 8.25, " Air. Sampling in the '
- Work Place". VY had previously performed redundant air sampling using the ne media (cellulo'se ester) and its normal airbome radioactivity sampling media (# 25
- . glass fiber filter), and concluded that the new media exhibited relative officiency
- ~, . greater than that exhibited by the norrnal air' sampling media which exhibited a j p 99.9% collection efficiency. VY had previously arrived at this qualitative 6 conclusion, based on the redundant sampling, but did not have readily available 4 r
? quantitative information, for its normal sampling media. No immediate safety
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i . concerns were identified. VY provided the quantitative information for its normal i
- media, and' discontinued the use of the new media based on lack of complete filter )
l: collection efficiency for sampling combined industrial safety and radiological safety contaminants. This item is close ;
,
, P2 Status of Emergency Preparedness (EP) Facilities, Equipment, and Resources ,
i insoection Scone (82701)
The inspector toured the thre'e major onsite emergency response facilities, the I
/ Control Room (CR), the Technical Support Center (TSC), and the Operations ;
/ Support Center (OSC), as well as the Emergency Operations Facility (EOF), located '
in the licensee's Nuclear Training Center in Brattleboro,. Vermont. He performed spot checks of equipment operability at each of these facilities and reviewed completed equipment surveillance and locker inventorie , ' ' Observations and Findinas Using the licensee's' procedure OP 3506 (Emergency Equipment Readiness. Check)
as a guide, the inspector noted only a few minor discrepancies in the licensee's
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maintenance of supplies in the various emergency response facilities. Completed copies of OP 3506 were on file to show that the required surveillance were being performed. The licensee was using the Event Report process to correct a self-identified oversight relative to a monthly communication surveillance, Conclusions The licensee was maintaining the major onsite and offsite facilities in an adequate state of readiness. Equipment readiness surveillance were routinely being i performe P3 EP Procedures and Documentation Insoection Scope (82701)
The inspector reviewed several changes the licensee made to the emergency plan and implementing procedures. The inspector reviewed these changes in the NRC
- Region I office. He conducted this review to verify that the changes made to the emergency plan and implementing procedures were made in accordance with 10 CFR Part 50.54(q),i.e., that they did not decrease the effectiveness of the emergency plan. A list of emergency plan and implementing procedure changes reviewed is included as Attachment A to this report. While onsite, the inspector reviewed the effectiveness evaluation performed for one of these change Observations and Findinas Based on the licensee's determination that the changes to the documents listed in i Attachment A did not decrease the overall effectiveness of the emergency plan, and that it continued to meet the standards of 10 CFR 50.47(b) and the requirements of Appendix E to Part 50, NRC approval was not required for these change Conclusions The recent changes to the emergency plan and implementing procedures were made in accordance with NRC requirement P5 Staff Training and Qualification in EP Inspection Scope (82701)
The inspector reviewed documents governing the conduct of EP training including l the emergency plan, OP 3712 (Emergency Plan Training) and the Emergency Plan
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Training Program Description (EPTPD). Also, the inspector reviewed the training records for eight emergency responders and conducted interviews with licensee staff to determine if required training requirements had been met.
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!- 25 t , Observations and Findinos L i The inspector noted that the requirements of the above documents were being met with one exception.. Appendix B of the EPTPD specifies that personnel performing
.as Radiological Assistant (RA) or Radiological Coordinator (RC) in the EOF receive ~
annual retraining in emergency communications. Appendix A to the EPTPD, which
. lists the specific instructor guides for various training elements to be accomplished, did not include emergency communications as an applicable guide for these
- positions. ' It appeared communications training had not been given within the past year for one individual qualified as a RA/RC. The EP Supervitar agreed to review this matter.
t l'
1, LThe inspector also noted that the EPTPD stated a goal for continuous training in which all emergency response organization (ERO) members participated in an annual l- . drill, exercise or mini scenario to the extent practicable. However, the licensee had l: no tracking mechanism in place to either monitor the success of this goal or to plan 1
[ activities for accomplishing it. Therefore, the inspector could not assess the l licensee's effectiveness in meeting this goal. .
.
L The inspector also asked to see some critique forms from the classroom training b sessions for ERO personnel. ' None were available for review because, although the training feedback forms were continuously available in the classrooms, they were not explicitly distributed to the students. The EP Supervisor stated that the instructors usually relied on oral discussion as the medium for conveying feedback about course material.
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.The inspector noted that EP did not conduct quizzes or examinations of trainees.
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Rather, the training department administered informal take-home quizzes to emergency managers tasked with event classification, but these were used for
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subject matter familiarizanon rather than trainee evaluation.
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.. Conclusions t
The EP training function has ensured that assigned responders.were kept adequately
. trained as required by the emergency plan. However, the NRC concluded that the licensee's evaluation of training was generally informal in that the licensee did not have good tracking mechanisms to monitor completions of drill requirements and b relied on oral feedback about course material.
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P6 . EP Organization and Administration Insoection Scope (82701) The inspector interviewed the EP Supervisor and his staff to determine their
- experience and knowledge of their responsibilities. He also interviewed two senior managers and a shift supervisor to evaluate their knowledge of their duties and their
. interface with the licensee EP staff. He reviewed the licensee procedure for
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notification of the ERO and interviewed a Radiation Protection supervisor to determine the licensee's maintenance of respirator qualifications for the ER Observations and Findinas The EP staff had undergone a significant transition since the last EP program inspection in August,1996. The EP Supervisor, who was formerly the EP training coordinator had been in his new position for only five months and in the EP group for only four months before that. One member of his staff, the EP Coordinator, had been in the EP group for a year before this inspection. The licensee recognized the need to train these individuals in EP management and sent them to a professional training class in EP principles and management. The two remaining full-time members of the EP staff were the Offsite Emergency Planner and a contract engineer with ten and thirteen years experience, respectively, in the licensee's EP organization. Overall, the EP staff were knowledgeable in the conduct of their duties. The EP staff and supervisor were knowledgeable of their duties. However, the inspector noted through interviews, that there had been some intradepartmental and interdepartmental communications that had the potential to reduce overall effectivenes !
!
. The senior managers and the shift supervisor interviewed were knowledgeable of
' their duties as emergency responders, and they knew about EP issues that were affecting their organization The licensee conducted weekly tests of the emergency response pagers and annual off-site call-out notifications of the ERO. ERO members were not required to report
- to the site during the annual call-out drill, but they were asked to provide
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information about their' availability for duty and their approximate response time The licensee had taken action to achieve notification of the engineering support
!
organization, a' contract engineering group, directly from the licensee's paging l system. These support personnel were previously notified by a parallel network that relied on an additional phone notificatio The licensee required all emergency responders, with limited exceptions, to be
~ respirator-qualified. This requirement was recently formalized in a company policy statement. The inspector's spot check of emergency responders showed no examples of personnel unqualified in respiratory protection of which the licensee
- organization was unaware.
l' ! Conclusions l
b The licensee's EP organization was adequately staffed to oversee the EP function at the site. There were indications of some communications isued that had the potential to reduce overall effectiveness. The senior managers with responsibilities for oversight of EP maintenance were adequately informed of their duties. The licensee was adequately maintaining the emergency response roster as well as the respirator qualifications of members of the emergency response organization.
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P7 Quality Assurance in EP Activities
. insoection Scoce (82701)
The inspector reviewed the last annual Quality Assurance Services audit of the EP program (Audit Report No. VY-97-14) as well as the audit plan used for conducting i it. He also reviewed the audit plan for the upcoming annual audit and the results of three quality assurance surveillance performed in the EP area. He interviewed the Site Quality Assurance Supervisor and representatives of two local offsite response agencies. He also reviewed the EP group's commitment tracking files and discussed corrective actions of identified problems with the EP staf Observations and Findinas The licensee used the services of a contract organization to perform the quality assurance reviews of the EP program. This organization was the same as that which supplied the contract emergency planner to the licensee's EP organizatio The quality assurance group at the site was in a reporting chain that was sufficiently independent frnm tha group to which the contract emergency planner was assigne The quality assurance group used both in-house technical experts as well as some from outside utilities and organizations for their audits. The audits and sbrveillances used input from the audited organization, NRC requirements and industry-recognized good practices in selecting the areas on which to focu The portions of the audits dealing with the adequacy of interface with offsite were provided to the affected state agencies. These results were not provided to the local offsite agencies. Only one of two local offsite agency representatives interviewed was aware of the availability of this report. The inspector pointed this oversight out to the licensee. The licensee agreed to review its correspondence protocol for possible inclusion of the local offsite agencie The licensee aggressively worked the commitment tracking system to keep the backlog to a minimum. The event reports and recommendations from the last annual audit were all captured by the EP staff's tracking system and realistic dates assigned for closure. The inspector noted, however, that these corrective actions were not always clearly documented. He discussed the problem with this oversight
'
from an audit ability standpoint with the EP Supervisor, citing the need for good documentation of all stages of an issue resolution in order to achieve reliable trending of all related issues. The EP Supervisor acknowledged the inspector's concer Conclusions The 1997 annual audit of the EP program met all the requirements of Part 50.54(t)
of NRC regulations. The licensee did not provide copies of the audit to the local offsite agencies, although they were available for review by these agencies. The
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1 contractor organization that performed the quality assurance audits was sufficiently I independent from the contractor support provided to the licensee's EP staff. The licensee's pursuit of corrective actions for identified problems was aggressive but not always well-documented.
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- P8- Miscellaneous EP issues
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! P (Closed) IFl 50-271/92-14-01TSC/CR Ventilation Systems and TSC Shieldina inspection Scope (92904)
The inspector reviewed licensee and NRC safety evaluations and docketed correspondence on the above open item and interviewed licensee and NRC staff who were familiar with the issue, l Observations and Findinas This item was opened during NRC EP inspection 50-271/92-14, conducted in 199 The inspectors noted that the ventilation systems for the CR and TSC contained no filtration capability for fission products other than industrial roughing filters. Despite l the docketed approval of the designs for these two facilities, the inspectors felt i l additional review was warranted, i
NRC Region I referred the issue to NRC's Office of Nuclear Reactor Regulation (NRR)
for technical review. In the course of conducting that review, NRR requested
~ !
additional information from the licensee. The licensee provided this information in a i letter dated January 10,1994, i l
In that letter the licensee stated that with no credit for filtration of air in the TSC, j l the 30 day doses to emergency responders would be below the limits of I
.
Paragraph 8.2.1.f of NUREG-0737, Supplement 1 (Clarification of TMI Action Plan in Requirements - Requirements for Emergency Response Capability) for a Design Basis Acciden Conclusions
The inspector discussed this issue with licensee engineering representatives, NRC '
Region i staff, and NRC NRR staff. He determined that the TSC design is adequate to meet the regulatory requirements of NUREG-0737, Supplement ;
Based on acceptance of the control room ventilation system by previous NRC j analysis and evaluation, discussion with NRR staff members and the licensee's -
! certification of the ability to maintain both control room and TSC exposures below the limits specified in NRC requirements. The issue of control room and TSC accident exposure in inspection report 50-271/92-14 was close ]
Although the inspector was not able to close this item prior to his departure from I the site 'on May 22,1998, pending discussion with the NRR representative, he
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informed the licensee's Emergency Planning Supervisor of the closure of the item in a telephone conversation conducted on May 28,199 F2 . Status of Fire Protection Facilities and Equipment F Switchaear Room Carbon Dioxide System Replacement a'. Insoection Scope (64704)
The inspector reviewed Engineering Design Change Request (EDCR)96-417,
" Vermont Yankee Switchgear Room CO2 System Modifications," to evaluate the validity of design assumptions, design inputs, and post-modification testing. The inspector also reviewed National Fire Protection Association (NFPA) Standards 12,
" Carbon Dioxide Extinguishing Systems," and 12A, "Halogenated Fire Extir.guishing Agent Systems," to determine required design information and post-installation testing requirements, Observations and Findinas During September 1996, integrity testing was performed on the East and West Switchgear Rooms to evaluate the capabilities of the installed high pressure total flooding carbon dioxide (CO2 ) fire extinguishing systems. The testing consisted of door fan testing to determine the room's equivalent leakage area, and tracer gas testing to establish the air exchange rate for the room with no ventilation fans running and all dampers closed. The testing used the methods described in NFPA Standard 12A. VY performed calculations determined that the high pressure systems installed could not achieve the initial concentration requirement for the East Switchgear Room, or the soak time requirement for the West Switchgear Room. VY elected to replace the systems with low pressure systems rather than upgrade the existing high pressure system The low pressure system design is based on the equivalent leakage area and air exchange rate test results from the September,1996 testing. The system uses initial discharge headers to attain the required 50% minimum concentration of CO2, and smaller extended discharge headers to maintain the concentration for the minimum soak time by bleeding a small amount of gas into the associated room to
~
make up for leakage and dilution. The actuation circuits will also trip the exhaust fans for both rooms upon sensing a fire in either room. After the low pressure system is made operational, the high pressure system for the East Switchgear Room
.will be removed. The high Pressure System in the West Switchgear Room will remain in place to provide a "second shot" capability for the cable vaul Post installation testing of the low pressure system included circuit and logic testing of tne actuation circuitry, verification of proper operation of storage tank and control panel alarms, and " puff" testing of the initial and extended discharge headers to ensure the piping is unobstructed. Flow capacity of the piping and discharge nozzle orifice sizing were evaluated by hand calculations, performed in accordance with NFPA 12, to confirm the results of the vendor's computer calculations for piping l
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. l and orifice sizes. Full discharge testing was neither planned, nor conducted on the syste The 1993 edition of NFPA 12, Section 1-6.3, " Approval of Installations," lists the required testing to verify that CO2systems have been properly installed and will function as specified. Subsection (d) states "a full discharge test shall be performed
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on all systems. Where multiple hazards are protected from a common supply, then l ' a full discharge test shall be performed for each hazard." The failure to perform a l full discharge test, as specified in NFPA 12-1993, remains unresolved, pending NRC l- review of the acceptability of the alternative testing performed. (URI 98-08-08)
I c .- Conclusions The failure to include a full discharge test in the post-installation testing of the new i low pressure total flooding CO2 extinguishing system for the switchgear rooms, as ( specified in NFPA Standard 12, remains unresolved pending NRC review of alternate l test methodology.
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j F2.2 Fire Barrier Penetration Seals i
' Insoection Scone (64704)
!
l l During tours of the facility, the inspector observed the condition of the installed fire
! barrier penetration seals, and selected seals at random for evaluation of installe l configuration versus qualification test configuratio I Observations and Findinas The fire barrier penetration seals observed by the inspector in the plant were intact, L with no apparent separations or cracks in the material. The inspector selected seals L in the ceiling of the battery room for configuration review. Upon learning that these
seats were subject to a request to eliminate the control room floor as a rated fire barrier, the inspector selected a cable tray seal above the door between the West Switchgear Room and the Turbine Building, penetration seal 40-T1046 Penetration Seal 40-T10465is shown in the penetration seal database as a
" Typical B" seal, which corresponds to a minimum depth of five inches of General Electric (GE) 6428 room temperature vulcanizing (RTV) silicone elastomer. The j i
design configuration is shown on Drawing B191500, Sheet 4. The design L configuration corresponds to the configuration tested, as documented in Underwriters Laboratory (UL) test report for Project 77NK3180, dated November 25,1977. The data sheet for this penetration seal lists the depth as fourteen inches of RTV silicone elastomer. However, repair records show that this seal was repaired on October 17,1996, using RTV silicone foam. No test was
. performed on seals containing a combination of silicone elastomer and silicone I foam. As a result of this lack of acceptable test results, this seal has been declared j
' inoperable, and compensatory measures put in plac '
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The inspector reviewed the list of questionable seals developed as part of the penetration seal program. Penetration seal 40-T10465is listed as a seal'which requires additionalinformation, and will need to have cable tray covers and damming material removed from both sides of the seal to permit inspection and
. measurement to determine its configuration. Subsequent inspection by VY
. personnel determined that the silicone elastomer seal had been breached to pull a cable and repaired with silicone foam. The defective seal was removed and replaced, .and an Event Report initiated for evaluation of the condition and determination of the need for additional long-term corrective action This failure to maintain the fire protection features described in Section 3.1.8 of the facility's Safety Evaluation Report (SER) dated January 13,1978, was identified and corrected by VY. Accordingly, this non-repetitive, licensee-identified and corrected violation is being treated as a non-cited violation, consistent with section Vll.B.1 of the NRC Enforcement Policy. (NCV 98 08-09) Conclusions The failure to maintain fire barrier penetration seal 40-T10465in a configuration corresponding to the tested configuration is a violation of NRC requirements which is not being cited since the condition was identified and corrected by V F2.3 Material Condition of Fire Protection Eauioment
- Inspection 'Scoce (64704)
During tours of the facility, the inspector observed the condition of the installed hose reels, fire hoses, portable fire extinguishers, fire pumps, and fire brigade
, equipment lockers.
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' Observations and Findinas
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f Fire hoses installed on hose reels in the plant were in good condition, and were marked with hydrostatic test dates within the required interval. Portable fire extinguishers of the correct types were installed in appropriate locations in the plant. Fire brigade equipment in the fire brigade locker was stored in a neat and 3 orderly fashion, with each fire brigade member having their own individual set of turnout gear.
l The inspector also examined the diesel and motor driven fire pumps, and reviewed their annual capacity test results for the previous five years. The pumps showed no sign of degradation, and test results showed consistent performance, with no adverse trend Conclusions Based on the observed condition of the equipment in the plant, the inspector judged
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F8 Fire Protection Organization and Administration F _Chanaes to Fire Protection Organization Insoection Scope (64704)
The inspector reviewed Revision 14 to the Vermont Yankee Fire Protection Plan, dated June 6,1997, and discussed the current organizational structure with the Fire Protection Engineer and Fire Protection Coordinato Observations and Findinas
. VY made changes to the fire protection program in 1997 to improve the focus of the organization on fire protection issues, and to facilitate the identification and correction of deficiencies on a routine basis. Significant program changes include:
- The program responsibility for fire protection has been transferred from the Technical Support Group to the Project Engineering Grours
! * Full-time personnel have been hired to fill the positions of Fire Protection I
! Engineer, and Fire Protection Coordinato '
- - More program responsibility has been taken on by the onsite organization, and use of contractor expertise has been reduced to a case-by-case as- l needed basi I c . -- Conclusions Based on the review of the revised Fire Protection Plan, the inspector determined i f that the VY fire protection program meets the regulatory requirements.
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F7 Quality Assurance in Fire Protection F Fire Protection Proaram Audits Inspection Scone (64704)
l- The inspector reviewed the audits of the fire protection program conducted since the last inspection, to evaluate their quality, significance of their findings, and whether repeat findings were being identified, b.: Observations and Findinas ,
Audits of the fire protection program were conducted annually, as required by Technical Specifications. All the audits included experienced personnel from outside the VY organization. Audit findings were documented in the corrective action program, and tracked through to completion. Subsequent audits reviewed
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the resolution and closeout of the previous findings.
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e-l 33-q c .~ Conclusions Based on the audit reports reviewed, and the lack of repeat findings, the inspector determined that the program audits met regulatory requirements, and had been
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L V. Management Meetings X1 Exit Meeting Summary The results of the fire protection inspection were discussed at an exit meeting r
conducted onsite May 8,1998, and in a telephone call conducted May 27,199 The inspection findings were not contested at that time. No information reviewed during this inspection was identified as proprietar The resident inspectors met with licensee representatives periodically throughout i
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.the inspection and following the conclusion of the inspection on July 2,1998. At I l that time, the purpose and scope of the inspection were reviewed, and the :
L preliminary findings were presented. The licensee acknowledged the preliminary L inspection findings.
l X2i ' Vermont Yankee Management Changes I~
On May 29, Vermont Yankee Nuclear Power Corporation announced the following
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i management personnel changes effective on June 1,199 * Mr. Gregory Maret, the current Plant Manager, was named to be the Director of Operations. This new position will be functionally equivalent to the
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previous Vice President, Operations.
g * Mr. Michael Balduzzi, the current Operations Superintendent, was named to i p be the Plant Manage ,
i-l' ' *- Mr. Frank Helin, the current Technical Services Superintendent, was named to be the Operations Superintendent, and would remain as the acting . Technical Services Superintenden X3 Review of Updated Final Safety Analysis Report (UFSAR)
A recent discovery of a licensee operating their facility in a manner contrary to the ,
- Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a ?
. special focused review that compares plant practices, procedures and/or parameters to the UFSAR description.'. While performing the inspections discussed in this ,
report, the inspectors reviewed a sample of the applicable portions of the UFSAR that related to the area inspected. The inspectors verified that the UFSAR wording was consistent with the observed practices and procedures cnd/or parameters.
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- ITEMS OPENED, CLOSED, AND DISCUSSED OPEN j j 98-08-01 VIO Inadequate Procedure Guidance for DC Electrical Ground Investigation 98-08-02 VIO Design Settings Not Translated into Installation Procedures for SGTS I Breakers I 98-08-03 VIO Fourteen Day _ Delay in 4-hour Event Notification for Potential Common Mode Failure of SGTS 98-08-04 URI MOV concerns regarding procedure adherence and contractor oversight 98-08-05 URI Thrust calculations for safety-related MOVs 98-08-06 URI impact of Low Blowout Panel Set Point on Secondary Containment 98-08-07 IFl Storm Drain Contamination and Evaluation Per NRC Bulletin 80-10 98-08-08 URI Alternative Testing of CO2Fire Extinguishing System 98-08-09 NCV Failure to Maintain Fire Barrier in the As-tested Configuration CLOSED 92-14-01 IFl TSC/CR Ventilation Systems and TSC Shielding 95 25-03 IFl Pump Suction Pressure Evaluation During Surveillance 96-11-02 IFl Main Steam Tunnel Blowout Panel Actuation Setpoint Variance 97-01-02 IFl Potential to Exceed Containment Design Pressure During EOP Implementation 97-02-08 IFl Station Service Water / Alternate Cooling System Equivalency
- 98-01-03 URI Use of 9249 Cask Prior to April 1,1996 and Training for User's IAanual to Be Provided for Radwaste Computer Program 98-04-04 IFl Review Air Sampler Collection Efficiency i
f "' 97-12-03 IFl BMOs Proposed by VY to Remain Open Following the 1998 Refueling l Outage 98-08-09 NCV Failure to Maintain Fire Barrier in the As-tested Configuration i
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LIST OF ACRONYMS USED ALARA As Low As Reasonably Achievable ANSI American National Standards institute BMO Basis for Maintaining Operation CAM Continuous Air Monitor CFR Code of Federal Regulation i CR Control Room CS Core Spray 3 DAC Derived Air Concentration '
- EDCR Engineering Design Change Request '
EDG Emergency Diesel Generator EOF ' Emergency Operations Facility EP Emergency Preparedness !
EP Emergency Plan Training 1 EPTPD Emergency Plan Training Program Description ER Event Report
'ERO emergency response organization -
GE General Electric GL Generic Letter HEPA High Efficiency Particulate Air Filter HELB high energy line break HP Health Physics HPCI high pressure coolant injection IFl Inspector follow item I Information Notice I LCO Limiting Condition for Operation
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LER Licensee Event Report LPCI Low Pressure Coolant injection MCC Motor Control Center <
NFPA National Fire Protection Association NIST National Institute of Standards Technology NNS~ Non-nuclear safety -
NRC Nuclear Regulatory Commission NRR Office of Nuclear Reactor Regulation NVLAP National Voluntary Laboratory Accreditation Program OSC- Operations Support Center
'PORC Plant Operations Review Committee-QA Quality Assurance RCA ' Radiological Controlled Area RCIC Reactor Core isolation Cooling REMP Radiological Environmental Monitoring Program i'
RP Radiation Protection RP&C Radiological Protection and Chemistry RPM Radiation Protection Manager RWP- Radiation Work Permit i RWCU Reactor Water Cleanup i
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, RTV Room Temperature Vulcanizing SDE Shallow Dose Equivalent SER Safety Evaluation Report TLD Thermoluminescent Dosimeter TS Technical Specifications TSC Technical Support Center UFSAR Updated Final Safety Analysis Report ;
UL Underwriters Laboratories
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URI Unresolved item VY Vermont Yankee
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ATTACHMENT A j Emergency Response Plan and Implementing Procedures Reviewed '
DOCUMEN DOCUMENT TITLE REVISION NO(S).
AP 3125 Emergency Plan Classification and Action Level Scheme 16 l
AP 3532 Emergency Preparedness Organization 6 OP 3501 Alert 18
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OP 3502 Site Area Emergency 30 OP 3503 General Emergency 32 OP 3504 Emergency Communications 30 OP 3505 Emergency Preparedness Exercises and Drills 20 OP 3506 Emergency Equipment Readiness Check 35 OP 3508 On-site Medical Emergency 20 OP 3510 Off-site and Site Boundary Monitoring 22 :
. OP 3511 Off-site Protective Action Recommendations 11 OP 3513 Evaluation of Off-site Radiological Conditions 19 OP 3531 Emergency Call-in Method 11 OP 3532 Emergency Preparedness Organization 6 OP 3533 Post-Accident Sampling of the Reactor Coolant- 3 OP 3534 Post-Accident Sampling of Plant Stack Gaseous Releases 1
OP 3712 Emergency Plan Training 14 I
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