IR 05000245/1999002
| ML20205J171 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 04/02/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20205J169 | List: |
| References | |
| 50-245-99-02, 50-245-99-2, 50-336-99-02, 50-336-99-2, 50-423-99-02, 50-423-99-2, NUDOCS 9904090206 | |
| Download: ML20205J171 (101) | |
Text
{{#Wiki_filter:r ^ U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket Nos: 50-245,50-336, 50-423 License Nos: DPR-21, DPR-65, NPF-49 Report Nos: 50-245/99-02, 50-336/99-02, 50-423/99-02 l Licensee: Northeast Nuclear Energy Company ' P.O. Box 128 I Waterford, CT 06385 i Facility: Millstone Nuclear Power Station, Units 1,2 and 3
Location: Waterford, CT Dates: January 12,1999 - March 1,1999 ' Inspectors: D. P. Beaulieu, Senior Resident inspector, Unit 2 A. C. Cerne, Senior Resident inspector, Unit 3 P. C. Cataldo, Resident inspector, Unit 1 S. R. Jones, Resident inspector, Unit 2 B. E. Korona, Resident inspector, Unit 3 F. Arner, Reactor Engineer, DRS J. Carrasco, Reactor Engineer, DRS S. Dembeck, Millstone 2 Project Manager, NRR J. Higgins, NRC Contractor, Brookhaven National Laboratory T. Hoeg, Resident inspector, Calvert Cliffs T. Kenny, Reactor Engineer, DRS K. Kolaczyk, Reactor Engineer, DRS N. McNamara, Emergency Preparedness Specialist, DRS M. Subudhi, NRC Contractor, Brookhaven National Laboratory J. Trapp, Senior Reactor Analyst, DRS C. Welch, Reactor Engineer, DRS Approved by: James C. Linville, Chief Millstone Inspections Branch, Region l l 9904090206 990402 - PDR ADOCK 05000245 h, .G PDR r;
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i TABLE OF CONTENTS PAGE EXECUTIVE SUM MARY..................................................... iv U2.1 Operations.......................................................... 1 U2 01 Conduct of 0perations... ............................:.. 1 ........... 01.1 General Comments and Review of Operational Events.................
01.2 !nadvertent Reactor Coolant System Water Level increase............. 2 U2 03 Operations Procedures and Documentation.............................. 5 03.1 Inadverteri Transfer of Water from the Unit 2 Spent Fuel Pool..........
U2 08 Miscellaneous Operations issues...................................... 8 t 08.1 (Open) URI 50-245, 336,423/97-01-03; Operator Licensing and Training; (Closed - Unit 2 Significant items List No.14, Confirmatory Action Letter 1-97-010, MC 0350 items C.3.1.e and C.3.3.c)......................... 8 08.2 (Closed) VIO 50-336/98-207-03: Failure to Establish Procedures for Draining Safety-Related Systems; (Closed - Unit 2 Significant items List 8.4)..... -.
U2.ll Maintenance........................ .20 ..................... ...... U2 M1 Conduct of Maintenance................. ......... 20 .. ........... M1.1 General Maintenance Observations........................... 20 M1.2 Integrated Test of Facility 1 Engineered Safety Features Components and Inadvertent Charging Pump Injection............ . .......... 21 U2. lli Engineering.......................................... ............,.24 U2 E8 Miscellaneous Engineering issues.................................... 24 E8.1 (Closed) VIO 01142 & VIO 03072 (eel 50-336/95-44-05); ice Blockage of Service Water Backwash Line; (Closed) Unit 2 Significant items , List No. 37).................................-................. 24 i E8.2 (Closed) URI 50-336/96-06-08; Resolution of Water Hammer issues; (Closed - Unit 2 Significant items List Nos. 8.5 and 25)....................... 26 E8.3 (Closed) VIO 01162 (eel 50-336/96-201-03) & VIO 01052 (eel 60-336/96-201-41): Failure to Meet Single Failure Criteria for Hydrogen Monitors and Adequately Evaluate the Installation of Electrical Jumpers (Closed - Unit 2 Significant items List Nos. 23.4 & 23.6).......................... 27 E8.4 (Closed) Vlos 04053 & 04043 (Eels 50-336/96-201-42 & 43); Material, Equipment, and Parts List Program (Closed - Unit 2 Significant items List No. 18)....................... ...... 29 .............. ii
l TABLE OF CONTENTS (CONT'D)
i l PAGE E8.5 (Closed) LER 50-336/97-23-00 & 01; Minimum High Pressure Safety injection Flow Used in Accident Analysis May Be Non-Conservative; (Closed - Unit 2 Significant items List N o. 5 5. 3)............................................................ 3 3 l E8.6 (Closed) URI 50-336/97-203-05; implementation of IE Bulletins 79-02 ' a nd 7 9-14................................................. 35 E8.7 (Clossd) LER 50-336/98-09-00; Large Break Loss of Coolant Accident Analysis indicates Peak Clad Temperature Could Exceed 2200 Degrees F. (Closed - Unit 2 Significant items List No. 54).................................... 38 E8.8 Control and Use of Vendor information; (Closed - Unit 2 Significant items List N o. 50)................................................... 4 0 E8.9 Inservice Test Program (Closed - Unit 2 Significant items List No. 49).....
U 3.1 0peration s....................................................... 44 U3 01 Conduct of 0perations............................................... 44 01.1 Reactor Coolant System Leakage Detection Systems...............
01.2 Unidentified Leakage increase and 3FWS*V164 Packing Leak........... 46 U3 02 Operational Status of Facilities and Equipment
................... ...... 02.1 Inadvertent Discharge of Carbon Dioxide into the Cable Spreading Room..
O2.2 Operability of Service Water System with MCC/RCA A/C Unit inoperable.
U3 08 Miscellaneous Operations issues...................................
U3 M 1 Conduct of Maintenance.............................................. 57 M1.1 Surveillance Observations........................................ 57 M1.2 Evaluation of Corrective Maintenance Activities...................... 58 U 3. Ill Engineering...................................................... 60 U3 E2 Engineering Support of Facilities and Equipment................... . 60 .... E2.1 Engineering Follow-up Activities related to the CO Event.
2 .............. U3 E8 Miscellaneous Engineering Issues...................................... 62 E8.1 Resolution of Open Engineering items............................. 62 iii ! l I l l
TABLE OF CONTENTS (CONT'D) PAGE P8 Miscellaneous Emergency Preparedness (EP) Issues....................... 64 P8.1 (Update) VIO 50-423/98-01-01: Failure to Maintain Unit 3 PASS Operational. 64 - V. M anagement Meetings.................................................... 65 X1 Exit Meeting Summary................................................. 65 X3 Management Meeting Summary........................................ 65 i ) . ! L
IV ) i
EXECUTIVE SUMMARY Millstone Nuclear Power Station , Combined Inspection 50-245/99-02; 50-336/99-02; 50-423/99-02 i Operations At Unit 2, several operational events occurred following the entry into operational e Mode 5, that raised concems regarding operator control of plant configuration. These events included an inadvertent addition of water from the safety injection tanks (SITS) to the reactor coolant system (RCS), an inadvertent loss of spent fuel pool water to the liquid radioactive waste system, and an inadvertent start of a charging pump with subsequent injection into the RCS. The NRC concluded that the licensee's self-i assessment that collectively evaluated these events made valid observations and proposed reasonable corrective actions which included improving processes to control the volume of work and the level of review applied to emergent work. (Section U2.01.1) At Unit 2, while in Mode 5, an inadvertent increase in reactor coolant system (RCS) level e of approximately 25 inches occurred when the safety injection tank (SIT) outlet motor . operated valves (MOVs) were opened to perform testing because operators failed to recognize the potential for a significant quantity of water in the SIT lower head and its injection piping to be present and drain to the RCS. Consequently, the operators did not request a procedure change to provide specific instructions and precautions for opening , the valves while in this plant condition. The water that was added had approximately the j same boron concentration as the RCS and water level remained several feet below the ' lowest open penetration in the reactor vessel head. The NRC concluded that the failure , to establish adequate procedural controls for operation of the SIT outlet MOVs constituted a violation of Technical Specification 6.8.1.a. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-336/99-02-01) consistent with Appendix C of the NRC Enforcement Policy, which permits closure of most Severity i Level IV violations based on their having been entered into their corrective action program. This violation is in the licensee's corrective action program as Condition Report M2-99-0268. (Section U2.01.2) i At Unit 2, the operating procedure that provides instructions for draining the refueling i e cavity was inadequate in that, at the completion of the draining evolution, the procedure failed to direct the isolation of the flow path to the liquid radioactive waste system.
Subsequently, the configuration established through use of this procedure led to the inadvertent loss of approximately 2 inches of spent fuel pool water level when about 2730 gallons of spent fuel pool water was transferred to the liquid radioactive waste system. However, performance of the plant equipment operator was good in promptly identifying and terminating the spent fuel pool water loss. The NRC concluded that the inadequate procedure constituted a violation of Technical Specification 6.8.1.a. This v
Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-336/99-02-02) consistent with Appendix C of the NRC Enforcement Poliev, which permits closure of most Severity Level IV violaticos based on their having been entered into their corrective action program. This violation is in the licensee's corrective action program as Condition Report M2-99-0304. (Section U2.03.1) 'e ~ At Millstone Units 1,2, and 3, the nine remaining items associated with the Confirmatory Action Letter (CAL) 1-97-010, dated March 7,1997, were found to be acceptably addressed and therefore, this CAL is considered closed. Based on this sampling review, the nuclear training program at Millstone has been notably improved with a revised systems approach to training. The two remaining operational units share the training program, with the exception of classroom plant specific instruction. Within the program, there is feedback / corrective action, remodeling through self-assessment with accountability, increased instructor staffing, intemal instructor continuing training, more complete and easier to understand direction, strengthened selection process for candidates to enter the program, improved procedures for NRC examination preparation, including submittal of pre-examination forms, and management's commitment to administer the program. Unresolved item (URI) 50-245,336,423/97-01-03, which is referenced in Unit 2 Significant items List item No.14, concerned inaccurate information that was provided in several Personal Qualification Statements (Form 398s) that were submitted to the NRC staff as an application an operator's license. NRC review in the historical aspects of the inaccurate Form 398s is ongoing and therefore, URI 50-245, 336,423/97-01-03 will remain open pending NRC completion of this review. However, because the licensee has implemented sufficient measures to ensure the couracy of future Form 398s, Unit 2 Significant items List item No.14 is considered clo.ed.
(Section U2.08.1) e' The inspector conciuded that Unit 3 has adequate and redundant systems to effectively monitor and identify reactor coolant system pressure boundary leakage into containment.
However, one issue was considered unresolved due to questions concerning the adequacy of the design basis of the containment radioactivity monitor, as well as its ability to actually perform its design basis function at current reactor coolant system activity concentrations. (Section U3.01.1) e The inspector concluded that the licensee's actions following the identification of on increase in unidentified leakage was acceptable and appropriate. In addition, tl.
inspector found the licensee's efforts in the health physics area, specifically in ovse minimization to address the packing leak on the "D" steam generator wide range level isolation valve in containment, was both appropriate and well planned. (Section U3.01.2) e-Operator actions taken in response to an inadvertent carbon dioxide discharge into the cable :preading room were good. The licensee's Event Response Team (ERT) was genet '.lly thorough. The ERT identified several deficiencies and recommended appropriate corrective actions. (Section U3.02.1) vi
I e The control room envelope was breached following an inadvertent carbon dioxide suppression system actuation when the nonsafety-related control building purge system was placed in service. When the control room envelope was breached, Technical Specification 3.7.7 required declaring both trains of control room filtration inoperable.
T.S. 3.0.3 required the plant to be placed in hot standby within 7 hours. Operators failed - to enter and comply with either T.S. due to an ambiguous statement in the bases section of T.S. 3.7.7 (NCV 50-423/99-02-06) (Section U3.02.1) )
The licensee's event review team for an inadvertent carbon dioxide actuation, identified that the review was response to NUREG 0737, item IllD.3.4 requirements and Regulatory Guide 1.78, was inadequate. The licensee had failed to consider carbon dioxide as a design input in the toxic chemical analysis for control room habitability.
(NCV 50 423/99-02-08) A subsequent operability determination concluded that with the cable spreading room carbon dioxide system locked out, the control room ventilation system remained operable and the fire safe shutdown analysis remained valid.
(Section U3.02.1) Maintenance At Unit 2, although the testing portion of the integrated test of the Facility 1 engineered e safety features components was well executed, the procedure instructions for restoration from the test were inadequately implemented. Steps to restore the "A" charging pump were performed in an inappropriate sequence, which resulted in the inadvertent start of the "A" charging pump. The subsequent injection of approximately 100 gallons of water from the volume control tank to the reactor coolant system (RCS) did not result in a reduction in RCS boron concentration. The NRC concluded that the surveillance procedure was weak in that, it allowed restoration steps to be performed out of sequence when the shift manager determined that the sequence of performance was unimportant and the procedure did not clearly identify mstoration steps where the sequence of performance was important. The failu:0 g viequately implement the surveillance procedure constituted a violation of Techma Specification 6.8.1.c. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-336/99-02-03) consistent with Appendix C of the NRC Enforcement Policy, which permits closure of most Severity Level IV violations based on their having been entered into the corrective action program. This violation is in the licensee's corrective action program as Condition Report M2-99-0442. (Section U2.M1.2) During the licensee planning and conduct of corrective maintenance activities, the
e inspector observed appropriate consideration for potential adverse impact upon safety-related components and functions. Questions raised by the inspector were satisfactorily resolved. Licensee conduct of the required maintenance was adequately controlled.
Where necessary, followup reviews of the maintenance activities were instituted by the . licensee to validate effectiveness, ensure operability, or improve the approach to the conduct of such needed work in the future. (U3.M1.2) vil
Engineering At Unit 2, the failure to maintain the design configuration of safety-related refueling water
storage tank (RWST) piping is a violation of 10 CFR 50, Appendix B, Criterion lil, " Design Control". However, the NRC concluded that the licensee had identified these configuration management deficiencies and took the proper corrective actions to restore the RWST piping and associated supports to their design basis configuration. Further, the licensee's actions to address URI 50-336/97-203-05, which concerned the adequacy of Millstone Unit 2's implementation of IE Bulletins 79-02 and 79-14, were complete and acceptable. Therefore, this licenseo-identified and corrected violation is being treated as a Non-Cited Violation (NCV 50-336/99-02-04) consistent with Section Vll.B.1 of the_N_RQ Enforcement Poliev. URI 50-336/97-203-05 is considered closed. (Section U2.E8.6) At Unit 2, the NRC concluded that the licensee effectively addressed the concerns
identified in LER 50-336/98-009-00, which involved excessive variability in the peak centerline temperature results from the approved large-break loss of coolant accident evaluation model. The NRC determined that the licensee's revised analysis meets the acceptance criteria listed in 10 CFR 50.46. The licensee also revised documents to incorporate changes to operating limits and analytical methodology related to this issue.
Therefore, LER 50-336/98-009-00 and Unit 2 Significant items List No. 54 are considered closed. (Section U2.E8.7) At Unit 2, based upon the sampled documents, the inspectors concluded the licensee's
revised inservice Test (IST) program was adequate. Program documents, and implementing procedures were revised, industry information had been factored into the program, and condition reports were properly resolved. No significant problems were identified when the inspectors reviewed the IST program for compenents in the chemical and volume control system and the boric acid system. Components were found to be properly tested and the program scope adequate. Based upon these findings, Significant items List No. 49 is considered closed. (Section U2.E8.9) The inspector determined that the licensee engineering staff had conducted an
assessment of the credible toxic gas pathways to the Unit 3 control room and had recommended appropriate compensatory measures to be implemented to maintain the control room and its ventilation system in an operable status. With regard to the licensee's capability to conduct a safe shutdown from nutside the control room, the inspector's review of the relevant EOP and FPER sections identified no inconsistencies.
The inspector also found no discrepancies in the licensee's conclusion that such an attemate shutdown could be safely conducted, given the corrective actions taken and compensatory measures implemented in response to both the carbon dioxide event on January 15,1999, and the subsequent issues identified in the reviewed CRs.
(Section U3.E2.1) viii
i Plant Support improvements continued to be made in the Unit 3 Post-Accident Sampling System e (PASS) Program since the previous inspection in June 1998. The licensee implemented a PORC approved, PASS Program Manual which described the program in detail and reinforced the overall maintenance and operation of the PASS program for ensuring functionality and reliability of the PASS. In addition, monthly surveillance tests were _ conducted in which water samples were successfully taken and analyzed, equipment failures were identified and immediately corrected and Technical Specifications and Updated Final Safety Analysis Report (UFSAR) commitments were met. However, the licensee continues to troubleshoot the method for retrieving and analyzing a total dissolved gas concentration and for measuring pH in a water sample. Until these issues are resolved NRC Violation 50-423/98-01-01 will remain open. (Section P8.1)
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Beport Details 1 Summarv of Unit 2 Statua Unit 2 entered the inspection period in operational Mode 6, refueling, with reactor vessel component reassembly in progress. During the inspection period;the licensee entered operational Mcde 5, cold shutdown, upon completion of reactor vessel head closure bolt tensioning on January 24,1999. At the completion of the inspection period, Unit 2 remained in operational Moda 5 with tne reactor coolant system partially filled.
' The unit was initially shut down on February 20,1996, to address containment sump screen concems and has remained shut down to address the problems outlined in the Restart Assessment Plan and a NRC Demand for Information [10 CFR 50.54(f)] letter requiring an assertion by the licensee that future operations be conducted in accordance with the - regulations, the license, and the Final Safety Analysis Report.
U2.1 Operations U2 01 Conduct of Operations 01.1 General Comments and Review of Operational Events a.
Inspection Scooe (71707) Using Inspection Procedure 71707, the inspector conducted frequent reviews of ongoing plant operations, including observations of operator evolutions in the control room; walkdowns of the main control boards; tours of the Unit 2 radiologically controlled area and other buildings housing safety-related equipment; and observations of several management planning meetings. The inspector also reviewed the licensee's self-assessment of operational events that occurred during the inspectir,n period, b.
Observations and Findinos The inspector observed operational preparations, procedural adherence, and the control of shutdown risk during the following evolutions: the completion of reactor vessel reassembly, the Facility 1 maintenance outage, the subsequent Facility 1 surveillance testing window, the transition to operation with Facility 1 systems and components protected, and the transition to operational Mode 5 (cold shutdown).
In general, the operators conducted the evolutions described above well. The inspectors j noted continued sensitivity to special conditions and equipment outages that affected i shutdown safety. However, several operational events occurred following the entry into operational Mode 5, that raised concems regarding the control of plant configuration.
These events included an inadvertent addition of water from the safety injection tanks (SITS) to the reactor coolant system (RCS), an inadvertent loss of spent fuel pool water j to the liquid radioactive waste system, and an inadvertent start of a charging pump with ' subsequent injection into the RCS, which are reviewed in Sections 01.2,03.1, and M1.2 of this inspection report, respectively.
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Following the inadvertent SlT injection and the inadvertent spent fuel pool water loss events, the unit director initiated an operations work stand-down to evaluate immediate actions to improve operations performance. As a result of this stand-down, the - ' operations department made a significant change in staffing by going from a five shift '- rotation to a four shift rotation, which released one crew of operators to enhance staffing in the work control office. Following this change, the inspectors noted a reduction in control room traffic and a reduction in activities distracting the shift manager from his oversight function.
In addition to the work stand-down, the operations department conducted a self-assessment to evaluate the three operational events. This self-assessment report noted that the high volume of work combined with an aggressive schedule contributed to insufficient review of evolutions. The report also noted that operators accepted the lack of definitive guidance and the limited knowledge of plant conditions to allow evolutions to continue to progress to operational events in addition to the specific corrective actions identified through the individual evaluations of the events, the operations department initiated three condition reports (CRs) to address an adverse condition and several areas for improvement identified by the self-assessment. The recommended corrective action to address the adverse condition involved improving processes to limit the volume of work and the level of review applied to emergent work.
c.
Conclusion Several operational events occurred following the entry into operational Mode 5, that raised concems regarding operator control of plant configuration. These evoats included an inadvertent transfer of water from the SITS to the RCS, an inadvertent transfer of - spent fuel pool water to the liquid radioactive waste system, and an inadvertent start of a charging pump with subsequent injection into the RCS. The NRC concludad that the licensee's self-assessment that collectively evaluated these events made valid observatbns and proposed reasonable corrective actions which included impoving processea to control the volume of work and the level of review applied to emergent work.
01.2 Inadvertent Reactor Coolant System Water Level Increase , i a.
Inspection Scooe (71707) ) ) The inspector reviewed the circumstances surrounding the inadvertent increase of reactor coolant system (RCS) water level by 25 inches (approximately 3300 gallons) on January 24,1999. Inspection activities included a review of operating procedures, automated work orders (AWOs) associated with the safety injection tank (SIT) outlet i I valves, and interviews with personnel in the licensee's operations department.
b.
Observations and Findinos The activities that led to this event began in February 1998, when the SIT outlet motor operated valves (MOVs) were worked, which required that the SITS be vented and drained. Subsequently, the licensee partially filled the SITS for flow testing of the outlet
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check valves in June 1998. ' The flow testing left the SIT water level within the indicating
range. However, in September 1998, while the core was still off-loaded to the spent fuel pool, the performance of the safety injection actuation signal (SlAS) manua! push button test resulted in the opening of the SIT outlet MOVs, which allowed SIT water level to decrease below the indicating range. The operators did not track that the SITS were in a partially drained condition below the indicating range by either logging their status or by , ! tagging the SIT outlet MOVs.
On January 24,1999, the plant entered operational Mode 5, cold shutdown. The RCS water level _was 73 inches above the centerline of the hot leg piping, which is l approximately the elevation of the reactor vessel flange. Work was in progress to l' closeout in-core instrumentation penetrations, and, therefore, there were openings in the l reactor vessel head.
Later that day, the operators conducted a pre-job brief for performance of post-maintenance testing of the No.1 and No. 2 SIT outlet MOVs (valves 2-St-614 and 2-SI- ! 624, respectively) to verify correct motor rotation following work affecting the motor electrical leads. The work was performed under AWO M2-98-09524 for the control leads and AWO M2-98-09528 for the power leads. The post-maintenance test involved manually opening each SIT outlet MOV to its mid position, remotely closing each valve from the control room to verify correct rotation of the motor, then fully stroking the valve open and closed to verify correct performance of the valve and correct indication. The post-maintenance test section of each AWO specified use of applicable sections of procedure SP2603C, " SIT Outlet Isolation Valve IST." This procedure stated in Step 3.1 of the precautions that, "to prevent SIT discharge to the RCS, RCS pressure must be maintained greater than 250 psig (265 psia)." This precaution could not be satisfied in the existing condition of the RCS. However, the licensee had issued Design Change Notice DM2-00-1874-98 on November 5,1998, which allowed operators to use applicable sections of any approved procedure to stroke MOVs for post-maintenance testing. Operations work control selected procedure MOV1220, "MOV Diagnostic Testing," to cycle the valves. However, procedure MOV1220 did not include specific prerequisites or precautions to ensure the associated systems were in a condition that supported valve operation. The SIT operating procedure, procedure OP2306, " Safety injection Tanks," also did not provide instructions for operation of the SIT outlet MOVs.
i ! The operators believed that the SITS were empty based on control room indications and l their knowledge that each valve had been worked earlier in the outage. The brief i established that an operator would manually open each valve without direction from the i control room and then request that the control room operators remotely close each valve.
When the operator in the field opened the first SIT outlet MOV, reactor vessel water level increased by 13 inches. Although water level for the SIT was below the indicating range, water that remained in the SIT lower head and its 12 inch diameter discharge pipe drained into the RCS and caused the reactor vessel level increase. Operators noted the s.
. level increase several minutes after the first valve was opened and began investigating the cause. However, the operators did not immediately recognize that the operation of the SIT outlet MOV was the cause. Shortly after the initial level increase was identified, l
, the second SIT outlet MOV was opened and reactor vessel level increased an additional j 12 inches to 98 inches above the centerline of the hot leg piping. The control room operators then correlated the reactor vessel level increases with the opening of each SIT outlet MOV.
The direct safety concerns associated with this event were the potential for a spill of radioactive liquid from the open reactor vessel head penetrations and the potential j dilution of RCS boron concentration. Although the event resulted in a substantial increase in reactor vessel water level, the water level remained several feet below the lowest open reactor vessel head penetration. Nevertheless, an operator was dispatched .to clear personnel from the head area until the situation could be evaluated. Chemistry sampled the RCS and determined that no dilution of boron concentration had occurred.
The licensee documented the event in condition report M2-99-0268 and initiated a formal root-cause investigation. The root cause investigation report dated February 11,1999, attributed the cause of the event to inadequate tracking of the partially drained cor dition of the SITS. Contributing factors identified in the report included: (1) inadequate verification of SIT status, (2) inadequate command and contrr.,1 of valve manipulations, (3) a high level of scheduled and emergent work distracting the shift manager and unit supervisor from their command and control functions, and (4) inadequate administrative controls addressing SIT outlet MOV operation.
The inspector found the root cause investigation thorough.
The root cause investigation recommendations included the following corrective actions: Brief operations department personnel on the results of the investigation.
- Revise the SIT operating procedure and other existing procedures to address
operation of the SIT outlet MOVs and the potential effect of this operation on the RCS.
Provide additional resources to the shift to support thorough planning for plant
evolutions.- increase management presence in the control room to minimize distracting ! e issues.
The inspector found the recommended corrective actions adequate to address the cause of the event and contributing factors.
i Unit 2 Technical Specification 6.8.1.a requires that written procedures be established,
implemented, and maintained for activities referenced in Appendix A of Regulatory Guide (RG) 1.33," Quality Assurance Program Requirements (Operation)." Appendix A of RG 1.33 states that instructions for changing modes of operation should be prepared for i various systems, including the emergency core cooling system. Procedure OP2306 was - Linadequate in that the procedure failed to provide controls for operation of the SlT outlet MOVs. This inadequacy was identified by the licensee.
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c.
Conclusions While in Mode 5, an inadvertent increase in RCS level of approximately 25 inches occurred when the SlT cutlet MOVs were opened to perform testing. The water that was added had approximately the same boron concentration as the RCS and water level remained several feet below the lowest open penetration in the reactor vessel head. The NRC concluded that the failure to establish adequate procedural controls for operation of the SlT outlet MOVs constituted a violation of Technical Specification 6.8.1.a. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV 50-336/99-02-01), consistent with Appendix C of the NRC Enforcement Policy, which permits closure of most Severity Level IV violations based on their having been entered into their corrective action process.' This violation is in the licensee's corrective action program as Condit:on Report M2-99-0268.
U2 03 Operations Procedures and Documentation O3.1 Inadvertent Transfer of Water from the Unit 2 Soent Fuel Pool a.
Insoection Scope (60705/60710) The inspector reviewed the circumstances surrounding the inadvertent reduction of spent fuel pool water level by 2 inches (approximately 2730 gallons) on January 28, 1999. Inspection activities included a review of operating procedures and interviews with . personnel in the operations department.
b.
Observations and Findinas The activities that led to this event began January 25,1999, when operators aligned the purification system to drain the refueling cavity saddles inside containment and transfer the water to the refueling water storage tank (RWST) for reuse. Late in the day shift on ~ January 27,1999, when the RWST was full, the operators realigned the purification system using Section 4.29 of procedure OP2305, " Spent Fuel Pool Cooling and Purification System," to transfer the remaining water to the liquid radioactive waste . ' system. While this water transfer continued, shift tumover was conducted, and the day shift operators verbally described the ongoing evolution to the night shift operators.
When the refueling cavity saddles were nearly empty, the night shift operators secured the water transfer as directed in Section 4.29 of procedure OP2305. This operating procedure directed that the operators stop the running purification system pump and j isolate the purification system suction path from the refueling cavity saddles. Although j the flow path to the RWST had previously been isolated, the procedure also directed ' operators to isolate the discharge from the purification system to the RWST. However, the procedure did not include specific steps to isolate the purification system discharge u to the liquid radioactive waste system (valve 2-RW-356) and the liquid radioactive waste system isolation (valve 2-LRR-424). The operators did not recognize that a discharge ' flow path to the liquid radioactive waste system was open and had not been isolated at the completion of the evolution.
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Later in the shift, the night shift operators held a brief to discuss realigning the purification system to clean the spent fuel pool water and reviewed the purification system piping diagram._ During the review of the piping diagram, the operators did not - -recognize that the flow path to the liquid radioactive waste system had been left open at the completion of the previous evolution. At the completion of the brief, the operators realigned the system to purify the spent fuel pool water using Section 4.13 of procedure OP2305. Although no entry conditions were specified, this section of the procedure was written to shift the purification system suction and discharge from purification of either the refueling cavity or the RWST to the spent fuel pool. Consequently, this section of the procedure also did not direct operators to verify that the purification system discharge to the clean liquid radioactive waste system was isolated. When operators opened the purification system discharge to the spent fuel pool cooling system (valve 2-RW-65), flow was diverted from the spent fuel pool cooling system through valves 2-RW-65 and 2-RW-356 to the liquid radioactive waste system. When operators started the purification system pump, the flow diversion continued, but the flow path changed such that flow passed through the purification system pump and valve 2-RW-356 to the liquid radioactive waste system.
Shortly after starting the purification system pump, a plant equipment operator (PEO) noted unexpected flow to the liquid radioactive waste system. The PEO secured the purification system pump, checked spent fuel pool water level, and noted that spent fuel pool water level had decreased by about 2 inches. The PEO then notified the control room of the condition and isolated the purification system pump suction valve. The performance of the PEO was good given that no alarm or annunciator had alerted him to the abnormal condition.
i Operators then noted that spent fuel pool level still appeared to be decreasing with the purification system pumps secured. The operators reviewed the piping diagram and identified the open flow path to the liquid radioactive waste system. The PEO isolated tha flow path to the clean liquid radioactive waste system by closing valves 2-RW-356 ' and 2-LRR-424. This action terminated the spent fuel pool level decrease. The licensee estimated that a total of 2370 gallons of spent fuel pool coolant inventory had been I transferred to the liquid radioactive waste system.
l Throughout the event, the spent fuel pool water level remained within the normal level I control band and above the spent fuel pool Ic V level alarm setpoint. Had the transfer of j water continued with no operator action, passive design features (i.e., the shallow location of the normal spent fuel pool cooling system suction pipe) would have ensured that adequate water remained in the spent fuel pool for cooling and shielding of the i stored fuel. Therefore, the safety significance of this event was minimal.
, The licensee documented the event in Condition Report M2-99-0304 and initiated a formal root-cause investigation. The root cause investigation report dated - - February 19c 1999c attributed the cause of the event to inadequate work practices during the last revision to procedure OP2305, which resulted in a deficient procedure that left the flow path to liquid radioactive waste open. The report identified contributing factors, ,
including the following: (1) a less than thorough tumover in that drawings were not reviewed to identify the flow path used for the reactor cavity draining evolution, and (2) a high level of scheduled and emergent work distracting the shift manager and unit supervisor from their command and control functions.
The inspector found the root cause investigation thorough.
The root cause investigation recommendations included the following corrective actions: 1) Improve the procedure revision, review, validation, and verification process.
2) Revise procedure OP2305 to provide adequate restoration steps to isolate the flow path to liquid radioactive waste.
3) Conduct an operations department stand-down for management evaluation of operational events.
4) Provide additional resources to the shift to support thorough planning for plant evolutions.
5) increase management presence in the control room to minimize distracting issues.
6) Brief operations department and central procedures group personnel on the results of the investigation.
The report noted that the procedure revision, review, validation, and verification process had been improved since the last revision to procedure OP2305. From January 27 to January 29, the operations department conducted a work stand-down, which is discussed in Section 01.1 of this report, to evaluate a series of operational events. The inspector noted that the licensee has changed procedure OP2305 to provide adequate restoration steps to isolate the flow path to liquid radioactive waste. The inspector found the recommended corrective actions adequate to address the cause of the event and contributing factors.
Unit 2 Technical Specification 6.8.1.a requires that written procedures be established, implemented, and maintained for activities referenced in Appendix A of Regulatory Guide (RG) 1.33," Quality Assurance Program Requirements (Operation)." Appendix A of RG 1.33 states that instructions for changing modes of operation should be prepared for various systems, including the fuel storage pool purification and cooling system.
Procedure OP2305 was inadequate in that, while changing the mode of operation of the purification system, the procedure failed to direct the isolation of an improper flow path to the liquid radioactive waste system. This inadequacy was identified by the licensee.
c.
Conclusions '- The operating procedure that provides instructions for draining the refueling cavity was inadequate in that, at the completion of the draining evolution, the procedure failed to _ direct isolation of the flow path to the liquid radioactive waste system. Subsequently, the configuration established through use of this procedure led to the inadvertent loss of approximately 2 inches of spent fuel pool water level when about 2730 gallons of spent fuel pool water was transferred to the liquid radioacfve waste system. However, performance of the PEO was good in promptly identifying and terminating the spent fuel
a
pool water loss. The NRC concluded that the inadequate procedure constituted a violation of Technical Specification 6.8.1.a. This Severity Level IV violation is being treated as a Non Cited Violation (NCV 50-336/99-02-02), consistent with Appendix C of the NRC Enforcement Policy, which permits closure of most Severity Level IV violations based on their having been entered into their corrective action program. This violation is in the licensee's corrective action program as Condition Report M2-99-0304.
U2 08 Miscellaneous Operations issues 08.1 (Ocen) URI 50-245. 336. 423/97-01-03: Ooerator Licensina and Trainina: (Closed - Unit 2 Sianificant items List No.14. Confirmatory Action Letter 1-97-010. MC 0350 items C.3.1.e and C.3.3.c) a.
Insoection Scooe (41500) The inspector used inspection procedure 41500 to address the licensee's actions regarding the Ccnfirmatory Action Letter 1-97-010 of March 7,1997, written to confirm ongoing efforts and commitments to evaluate and correct licensed operator training program problems found at Millstone and Haddam Neck. The inspector reviewed licensee correspondence, conducted interviews, and inspected corrective actions for the nine items noted in the letter. The inspector also reviewed the changes to the licensed operator initial / upgrade training (LOIT/ LOUT) programs to verify the changes conform l with established NRC requirements.
l b.
Observations and Findinas CAL ltem 1 CAL ltem 1, which was applicable to all units, was to: Submit the complete corrective action plan, including a schedule for addressing each of the identified Independent Review Team (IRT) weaknesses and review of the extent of the problems and root causes for the training area to the NRC staff by Apal 2,1997. As a part of the corrective action plan, clearly define roles and responsibilities for completing NRC form 398. [ Operator Qualification and License RenewalApplication] The licensee submitted the initial response and the corrective action plan (CAP) on March 31,1997. The letter identified the weaknesses and the extent of the problems including the root causes as determined by the IRT. Although the self-assessment was performed on the Unit 1 program, the licensee directed corrective actions toward all of the units referenced in the CAL. Using documents 10 CFR 55, NUREG 1021, Training Program Implementing Procedures, and Training Program Descriptions, the licensee conducted reviews of the LOIT/ LOUT programs to analyze, assess, and make recommendations for the deficiencies foun m
The licensee used the results of the self-assessment to develop an action plan that contained 72 corrective actions relating to the following categories: Management Oversight, involvement and Accountability; Recommendations for Self Improvement in Self-assessment and Corrective Actions Programs; Systems Approach to Training (SAT) j 1mprovements; Experience and Staffing; Selection Process and Criteria for Program l Entry and NRC Examination; Maintenance of Program and Student Records; and, l Training Materials, NRC Examination, and Review and Validation of NRC Examinations.
The licensee enlisted the help of five other utilities and several consultants to assist in . the corrective action process. As a result, the entire training program was substantially , ! amended for the Millstone and Haddam Neck units.
l ! Four of the originalitems were canceled due to duplication and nine were reviewed and closed in previous NRC reports. Regarding CAL ltem 1, eight corrective actions were ! not closed in the last letter to the NRC. The licensee's actions are addressed in the following paragraphs. The roles and responsibilities for completing NRC Form 398 is addressed in CAL ltem 3.6 of this report.
Corrective Action System Anoroach to Trainina (SAT) (SA-at This action was to review the SAT process within the nuclear training department including a review of the nuclear training manual (NTM) to include recommendations for improvement, including the review of the Operator Training Branch Instructions (OTBis). The nuclear training I documents (NTM and OTBI) were cumbersome to use because the procedures contained repetitive and conflicting information, referred the user to regulatory publications for guidance that resulted in differing interpretations, and contained out-of-date or incorrect information. In all,23 corrective actions involved changes to the existing procedures. Through discussions with licensee personnel and review of the nuclear training documents, the inspector determined that the documents were I reorganized and rewritten to reduce the above listed problems. The inspector noted that , since the implementation'date of July 10,1998, some of the documents were revised ' based on licensee self-assessment. The inspector reviewed current document change request forms noting the changes were the result of user feedback and/or self evaluations. The inspector found the documents followed 10 CFR 55.4 regarding l Systems Approach to Training. This action item is closed.
Corrective Action Maintenance of Proaram Student Records (MR-f) This action called for the development of a department procedure that detailed the records management practices applicable to the entire training department. The inspector reviewed nuclear training procedure (NTP) 148, " Training Documentation," Revision 1, that provided i instructions for the administrative control of training records. Records, such as instructor i training records, trainee evaluation records, and computer based training, now have . detailed instructions for the disposition within the records storage system. The inspector i found the procedure conformed with 10 CFR 55.59(c)(5), " Records." This action item is closed.
i ! i l b
Corrective Action Self-Assessment and Corrective Action Proaram (SC-e-4a&b).
Corrective action 4a was to perform a systematic review of outstanding Unit 2 training related commitments to verify closure, continued implementation or whether modification " was needed to improve regulatory compliance item 4b was to do the same on Unit 1.
The licensee searched the Unit 2 data base and found 2093 items related to training. A three member panel used a process designed to discriminate between actual commitments and those that had no validity. The final list contained 550 commitments.
The licensee was currently in the process of validating these commitments using procedure RAC 06 that contains instructions to assure the commitments are linked to procedures, policies, training procedures, training courses, lesson plans, etc. The process also evaluates whether the commitments are continuing or one time events.
The inspector reviewed a schedule for completion, noting this evaluation would be completed by the end of March 1999.
The inspector reviewed completed evaluations for Units 2 and 3 noting they listed how, why, and whr. method was being used to track, trend, or close the commitment. The licensee :.oarched the data base and assessed outstanding commitments for Unit 1, however, they have not started the validation process. This was scheduled to begin by mid-February. As documented below under CAL ltem 2, Unit 1 was shutdown and the above process may change because the commitments for an operating plant and a LOIT/ LOUT program may not apply.
Because the progress desc-ibed above is ongoing, being tracked by Action Request 97-00-8316, and the schedule has a defined completion date, these action items were closed.
Corrective Action Executive Summarv (ES-5a). This action was to track the corrective actions self-assessment items to completion. All of the corrective actions required by this item were closed and documented in letters to the NRC, except for actions SC-e-4a&b and noted above.
Corrective Action System Acoroach to Trainina (SA-b2). This action was to perform a regulatory compliance review of engineering support / professional development training program procedures. The licensee performed this task and reported it to the NRC in an early letter, however, the licensee added two additional areas; first line supervisor training program and generic fundamentals training. These came as a suggestion from the Millstone Oversight Group. The inspector reviewed a self evaluation report (SER) that provided an assessment of the first line supervisor training program. This self-assessment discussed how the program complied with the Final Safety Analysis Report (FSAR), ANSI-18.1, and 10 CFR 50.120(b)(1). The inspector determined that the program met these requirement i i l
The inspector reviewed another self-assessment performed after the changes were
made to the LOIT/ LOUT training program. This assessment discussed how the generic fundamentals of training are a integral part of the LOIT/ LOUT training program. The - inspector determined that the LOIT/ LOUT training program conformed with 10CFR 55.41, Written Examination," and NUREG 1021, Interim Rev. 8, ES 201,202,204 and 205 regarding the initial operator licensing examination process, preparing and reviewing operator licensing applications, and procedures for administering the generic fundamentals examination process. This item was closed.
Corrective Action System Anoroach to Trainina (SA-1). This action was to conduct an assessment to determine the effectiveness of completed corrective action plans ) developed in response to 11 Nuclear Training Department (NTD) condition reports (CRs) that were generated by a 1996 training program audit. The inspector reviewed Self-Assessment Report No. NTDSAG-96-F21, dated May 15,1998, and found the report was comprehensive and communicated findings of other assessments that had been previously performed in the training area. The report contained conditions adverse to quality, areas for improvement and recommendations for additional assessment. As a result of the self-assessment CR M3-98-2233 was written to include the additional items for resolution.
The inspector reviewed the assessment objectives, auditor notes, and the corrective actions for the original 11 NTD CRs and CR M3-98-2233. All of the 11 original CRs and most of CR M3-98-2233 actions were completed. The few remaining actions were being tracked for closure, however, the inspector reviewed these open items as described l-above. After reviewing the appropriate documentation, the inspector determined the ! self-assessment was adequately conducted and met the intentions of corrective action SA-J. This item is closed.
CAL ltem 2 CAL ltem 2, which was applicabk o Millstone Unit 1, was to: j l \\ Complete corrective actions for Millstone Unit 1 Licensed Operator i Initial / Upgrade Training (LOIT/ LOUT) program prior to restarting respective classes.
By_re9iew of licensee documents and interviews with licensee personnel the inspector determined the training programs were now fundamentally the same for Millstone Units 1, 2, and 3. The only difference was the actual classroom training that was plant i ' specific. The self-assessment process, corrective actions program, management oversight, SAT process, performance indicators, continuing instructor training on the SAT program, candidate selection process, maintenance of training files, and instruction j for NRC examination review and validation are the same for all of the units. Therefore, j ' . the corrective actions discussed in CAL ltem 3 also apply to CAL ltem 2 and 4.
)
i i
Unit 1 operations has been modified as docketed in a letter dated July 21,1998, " Certification for Permanent Cessation of Power Operations and The Fuel Has Been Permanently Removed From the Reactor." LOIT/ LOUT training was terminated, and the - submittal of certified fuel handling program was docketed in " Training Request for Approval of Certified Fuel Handler Training and Retraining Programs," dated December , 4,1998. The licensee is awaiting the NRC approval for the certified fuel handler program, similar to the program in use at Haddam Neck. The licensed operators were still attending LORT classos. This item was closed.
CAL ltem 3 CAL ltem 3, which was applicable to Unit 2, was to: Complete corrective actions for Millstone Unit 2 LOITprogram prior to restarting LOITclasses.
This CAL ltem, was ES-2d of CAL ltem 1, and was addressed in fifteen parts. The following paragraphs document the inspector's findings.
1.
Chief Nuclear Officer (CNO) Expectations for Trainina Oversiaht A memo to all training and line management, dated May 12,1997, discussed the shortcomings of the training at Millstone and discussed ways to address the problems. The memo discussed a newly established Executive Training Council j (ETC) made up of senior management including the CNO. This oversight group j set the following goals: Communicate management's commitment to safety, high standards, and effective
use of training to help improve worker performance.
Provide management oversight of the Millstone training programs accredited by
i the National Academy for Nuclear Power, thereby ensuring proper stewardship of the resources the company has provided.
Communicate management's commitment to high quality, perfem.ance-based e training utilizing a SAT approach to training, thereby directly contributing to nuclear safety while supporting the proper emphasis on improved achievement of i ' agreed upon schedules.
Establish and monitor site training goals and performance indicators, thereby e communicating the high standard necessary for safe, effective operations.
Review major changes to common site training programs.
i
,
I The inspector reviewed selected meeting minutes and determined that the ETC was meeting on a frequent t e $ (monthly, the charter is quarterly) and was reviewing problems brought aboui y self identification and the feedt:ack system. The inspector , - noted U;at responsible parties were assigned to follow the proposed corrective actions - that included a completion date. The open items list was reviewed at each meeting for disposition and closure of old items. The CNO memo also discussed a new Nuclear Training Depa:tment self-assessment process that was implemented. (Discussed in CAL ltem 7).
2.
Feedback Enhancement that ine,ludes a Trackina System The inspector reviewed procedure NTM 6.01, " Process Training Evaluation Data," as a part of the SAT process. The inspector noted the document provided direction for processing training evaluation forms, management evaluation forms, simulator crew observation forms and their use. The document also contained direction for the processing of industry events, plant operation and procedure changes and the use of the tracking system. The inspector reviewed feedback documents and determined the prccess was causing reasonable corrective actions to be taken. (Also discussed in CAL ltems 1,4 and 7).
3.
Curriculum Advisory Committees (CAC) / Trainina Advisory Councils (TAC) Roles and Responsibilities Clarified The inspector notec' the CACs were meeting weekly and were addressing identified training deficiencies. The TACs were meeting monthly to assess decisions made by the CACs.
, The inspector reviewed procedure TQ 1, " Personnel Qualification and Training," used by the committees and councils. The inspector noted the document described individua! eligibility, structure and hierarchy for program implementation rir d training for all parties on the committees. The inspector also noted that the document referenced regulatory guidance, such as 10 CFR I 50.120, " Training and qualification of Personnel at Nuclear Power Plants," 10 ! CFR 55 and 10 CFR 50, Appendix B, "QA Criteria for Nuclear Power Plants."
4.
Performance Indicators (PIs) on Manaaement Goservations and Trainino The inspector reviewed this area and determined that Pls were a part of the j feedback program. Currently the Unit Director, Operations Manager, Assistant i Operations Manager, and Shift Managers, perform observations of selected training activities. The inspector reviewed ten assessments of management observations and determined that they contained findings that were being incorporated to improve the training program with corrective actions. These - findings were also being trended via the key performance indicator (KPI) process, and were being distributed to the TAC and ETC.
- _ - _ _ _.
,
5.
Suoervisorv Trainina on the SAT Preman The inspector verified all training department personnel attended a training series - that focused on the SAT process for training operators. - All of the participants were required to pass a test following training; those that did not pass the test were remediated and took a second test. The inspector verified all instructors took the course. The inspector reviewed lesson plans used and determined that the training was structured to discuss the five elements of 10 CFR 55.4, " Systems Approach to Training." The licensee, through the instructor training program, has scheduled continuing training for all instructors. The training will be based on feedback obtained related to the SAT process.
The inspector interviewed two instructors from Unit 3, and three from Unit 2 to evaluate the effectiveness of the training. As a result of the interviews, the inspector concluded the instructors displayed a good knowledge of the SAT process as described in 10 CFR 55.4. The inspector also determined the instructor's experiences with the CAC and weekly management meetings conveyed they were getting good support for the training process from plant management.
6.
Audit Reauirements for License Ana!Wiens in the Ooerator Trainino Branch Instructions The inspector reviewed new procedure OTBI-7, " Operator License Applications," used to evaluate and provide guidance for the completion of NRC Form 398, " Operator Qualification and License Renewal Application," and Form 396, " Certification of Medical Examination by Facility Licensee."
The inspector reviewed revised procedure OTBI-2, " Operator License Correspondence," that describes the responsible parties, and additional reviews required for NRC Forms 398 and 396. The inspector also reviewed new - procedure MDI-12. " Operator License Submittals," that desenbes how the ! Medical Officer is to prepare Form 396s.
The inspector determined the above procedures were of sufficient detail to , evaluate an individual in order to complete NRC Forms 398 and 396 in
accordance with 10 CFR 55 and NUREG 1021, Interim Rev 8.
i ' 7.
Imoroved Nuclear Trainina Deced..ent Self-assessment Process l The inspector reviewed procedure NTDD-26, "Self-assessment," that is used to ! perform self-assessments within the training department. The inspector i determined the document provided direction and established requirements for I performing self-assessments. The document identified categories of assessments conducted, their frequency and focus, how to perform the self-assessment, how to report the results, and hovi to address the findings.
I _ _. _ _ _ _
i The inspector reviewed two self-assessments performed during the training program upgrade process. The inspector determined the findings were critical of the existing program and provided input for the changes made to the current program. A specific example was the audit of training records for Shift Managers.
This audit identified many clerical problems and filing mistakes within the records.
The problems were corrected and the input aided in the rewriting of procedure OTB-5 " Maintenance of Training Records and Files."
8.
Review the SAT Within the Nuclear Trainina Department See CAL ltem 1, Corrective Action SA-a.
9.
Continuina Instructor Trainina on the SAT Process See number 5 above.
10.
Nuclear Trainino Deoartment Comment Process Re-esta' lished to insure o Plant / Procedure Chanaes are included in Trainina Materials The inspector reviewed procedure NTM 1.04, "NTD Commitments," that provided ' the means to identify and track any item that could potentially change the nuclear training program. The procedure also provided guidance to document the disposition of the item. The inspector reviewed several commitment tracking forms and determined the system is being used to upgrade the training program.
11.
Trainina Proaram Based on SAT Process and Trainina Alianment Verification I The inspector reviewed proceduta NTM-5.05, " Conduct of Training," that outlines and provides instructions for the conduct of training for the classroom, simulator, and laboratory. The procedure also provides guidance regarding structured self-study and the administration of examinations. The inspector found that the ) instructions complied with good training practices.
.j 12.
Operator Trainina Branch Updated Staffina Analysis for Unit 2 This action is still in progress. The stafting level has been established at 17 experienced instructors certified on Unit 2. The current staffing level s 152 i including one full time and one half time person from operatior.:. Eight of the staff will be attending certification training in February and should be certified by the start of the next training class. Two more contractors are slated to be hired before the next training class. No obvious staffing problems were noted by the inspecto. Establish a Formal License Candidate Selection Progg ' The inspector reviewed procedure NTM-7.08, " Candidate Selection Process," I that provides the method for selecting candidates eligible for the reactor operator / senior reactor operator / instant senior reactor operator (RO/SRO/ISRO) training program. The inspector confirmed that the process outlined in the procedure followed 10 CFR 55 and NUREG 1021 guidelines.
14.
Maintenance of Trainina Proaram Records The inspector reviewed procedure OTB-5, " Maintenance of Training Records and Files" that establishes the guidelines for maintaining training records and files in the operator training branch. The inspector noted the document followed the guidelines of 10 CFR 55.59(c)(5), " Records."
15.
Instructions for NRC Examination Review and Validation The inspector reviewed procedure OTB-6, " Review and Validation of NRC Examinations," that provides guidance for the consistent pre-administration i review of NRC examinations by training personnel. The inspector noted that this document corresponded to 10 CFR 55 and NUREG 1021. Rev. Interim 8.
Based on the above discussion, this item is closed.
CAL ltem.4 '
CAL ltem 4, which was applicable to Millstone Unit 3, was to: Complete corrective actions for Millstone Unit 3 LOIT/LOUTprogram prior to NRC examinations of the current LOIT/ LOUT class.
! i This item was closed in NRC Combined Inspection Report 50-245/97-85; 50-336/97-85; ' and, 50-423/97-85.
The inspector noted since the last inspection (97-85), four RO candidates completed the necessary time on shift, with reactor power levels greater than 20%. They also completed the five required reactivity manipulations, and received their licenses.
l CAL ltem 5 ' CAL ltem 5, which was applicable to Millstone Unit 3, was to: , Conduct a review of the Millstone Unit 3 LOITprogram against the accredited i program requirements prior to submittel of the license applications to the NRC.
This item was closed in NRC Combined NRC Inspection Report 50-245/97-85; 50-336/97-85; and 50-423/97-85.
1-
CAL ltem 6 CAL ltem 6, which was applicable to all units, was to: Forward the scope of NRC Form 396 (medical certification) process review and its expected completion date for Millstone 1, 2, and 3 and the Haddam Neck (HN) plant by April 2,1997.
This item was closed in NRC Combined Inspection Report 50-245/97-85; 50-336/97-85; and 50-423/97-85.
CAL ltem 7 CAL ltem 7, which was applicable to Haddam Neck, was to: Submit the results of Haddam Neck data reviews of LOIT/ LOUT findings to the NRC by April 2,1997.
This item was linked to CAL ltem 8 by the licensee. See CAL ltem 8 for details.
CAL ltem 8 CAL ltem 8, which was applicable to all units, was to: Submit the results ofinitial reviews of additional classes on all the units to the NRC by March 15,1997.
The " initial reviews," delineated above, were of the candidates' qualifications to sit for a l NRC license, which basically consists of the data that is recorded on NRC Form 398.
This item was discussed in Combined NRC inspection Report 50-245/97-85; 50-336/97- ! ! 85; and 50-423/97-85. The report discussed the inspection of the licensee's review of training classes dating back to 1994. The inspector confirmed the items were resolved
with the exception of the requirement for the reactivity manipulations and on shift time greater than 20% The inspector confirmed the licensee submitted letters to the NRC with the results of their reviews.
On Unit 3, four of the licenses were administratively restricted pending the candidates completion of the requirements. The candidates completed the requirements and have been reinstated to operator status. See CAL ltem 4.
On Unit 2, four candidates that successfully passed the NRC examination and received a license were subsequently found to have performed less than the required five reactivity i manipulations. The candidates took credit for manipulations that werr in part, not _ clearly defined under the old training program. These individuals have been administratively restricted from all licensed duties until the reactivity manipulations have been completed. The individuals remained in the LORT progra The inspector reviewed the results of the licensee's initial reviews performed on Unit 1.
The 1993/94 class consisted of five ROs, one senior reactor operator upgrade (SROU), one SRO re-license and two SROls. The inspector found that one SROU license was made administratively inactive until the required time on shift at a power level greater than 20% was completed. This person was placed in the license operator retraining (LORT) program. All other requirements were satisfied.
The 1995 Unit 1 class consisted of four ROs, one SROU, and one ISRO. One Instant . SRO's license was made administratively inactive until the required time on shift at a power level greater than 20% was completed after plant startup. All other requirements were satisfied.
The 1996 Unit 1 class consisted of three SROs, three ISROs, and one SRO re-license.
All licenses were made administratively inactive until the required time on shift at a power level greater than 20% was completed after plant startup. There were also three candidates that did not complete the required five reactivity manipulations.
Based on the above discussion, this item is closed.
CAL ltem 9 ,
CAL ltem 9, which was applicable to Haddam Neck, was to: J Complete specific reviews of the Haddam Neck LORTprogram by April 4,1997.
The licensee's evaluation Haddam Neck LORT program identified 35 discrepancies. The inspector determined the discrepancies found were corrected by the licensee, except for those that could not be corrected due to the plant being shutdown and defueled. The inspector confirmed that the LORT program was in effect until the TS change in March 1998 when the fuel handler program began.
As described above, t' re are no longer licensed operators at Haddam Neck, therefore, there is no LORT program. The inspector reviewed the certified fuel handler program and determined the program used the SAT process to build the program for developing and retraining certifieKf fuel handlers.
Based on the above discussion, this item is closed.
c.
Conclusions The nine remaining items associated with the Confirmatory Action Letter (CAL) 1-97-010 dated March 7,1997, were found to be acceptably addressed and therefore, this CAL is considered closed. Based on this sampling review, the nuclear training program at < Millstone has been notably improved with a revised systems approach to training. The
two operational units share the training program, with the exception of classroom plant specific instruction. Within the program there is feedback / corrective action, remodeling through self-assessment with accountability, increased instructor staffing, intemal instructor continuing training, more complete and easier to understand direction,
I ' strengthened selection process for candidates to enter the program, improved procedures for NRC examination preparation including submittal of pre-examination
forms, and management's commitment to administer the program. Unresolved item -- (URI) 50-245, 336, 423/97-01-03, which is referenced in Unit 2 Significant Items List j No.14, concerned inaccurate information that was provided in several Personai Qualification Statements (Form 398s) that were submitted to the NRC staff as an application for an operator's license. NRC review into the historical aspects of the inaccurate Form 398s is ongoing and therefore, URI 50-245, 336,423/97-01-03 will remain open pending NRC completion of this review. However, because the licensee has implernented sufficient measures to ensure the accuracy of future Form 398s, Unit 2 Significant items List No.14 is considered closed.
08.2 (Closed) VIO 50-336/98-207-03: Failure to Establish Procedures for Drainino Safetv-Related Systems: (Closed - Unit 2 Sionificant items List 8.4) , a.
- Insoection Scooe (92901) j The inspector reviewed the licensee's cc79ctive actions in response to Violation 50-336/98-207-03, as well as licensee correct've actions following the issuance of a min'>r violation documented in NRC Inspection Report (lR) 50-336/98-05. These items were the result of NRC reviews of Unit 2 Significant items List No. 8.4, which involved ti;a failure to establish procedures required by Technical Specification (TS) 6.8.1.
b.
Observations and Flndinas Violation 50-336/98-207-03 involved the licensee's failure to establish procedures for draining various safety-related systems listed in Regulatory Guide (RG) 1.33, " Quality Assurance Program Requirements (Operation)," as required by TS 6.8.1. In response, the licensee provided training to Operations personnel, and revised Operating Procedure (OP) 2265, " Requirements for Draining and Filling Activities." The inspector determined that the procedure OP 2265 revision was adequate in that the procedure included appropriate controls to ensure a detailed procedure is developed prior to the performance of filling and draining evolutions for safety-related systems listed in applicable sections of RG 1.33.
The minor violation involved the failure of the licensee to establish a procedure to respond to a loss of containment integrity as listed in RG 1.33 and required by TS 6.8.1.
The issue was initially identified and documented as Unresolved item 50-336/97-203-04, and dispositioned as a minor violation in NRC IR 50-336/98-05. The inspector reviewed Abnormal Operating Procedure (AOP) 2515, " Loss of Containment Integrity," which was generated by the licensee following the issuance of the minor violation and determined that the AOP adequately addresses the event in all applicable modes of operation.
p .
'c.
Conclusions The NRC concluded that the licensee's corrective actions to address Violation 50-336/98-207-03, as well as the minor violation documented in NRC IR 50-336/98-05 were ~ acceptable. As a result, Violation 50-336/98-207-03 and Unit 2 Significant items List No.
8.4, which involved the failure to establish procedures required by TS 6.8.1, are considered closed.
U2.ll_ Maintenance U2 M1 Conduct of Maintenance M1.1 General Maintenance Observations a.
IDag-Mion Scooe (61726/62707) During routine plant inspection tours, the inspectors observed, on a random sampling basis, maintenance and surveillance activities to evaluate the propriety of the activities and the functionality of systems and components with respect to technical specifications and other requirements.
b.
Observations and Findinas The inspectors reviewed surveillance procedures and maintenance work orders and interviewed licensee field personnel to verify the adequacy of work controls. The inspector observed a portion of activities performed under the following procedure or work order: AWO M2-99-01493 Containment Valve Relocation to Address Post- = LOCA Flood Levels SP 2613J "B" Emergency DG Loss of Load Test i . The inspectors found the maintenance work was being performed in accordance with an approved work order present at the work site. A review of the work package found that it was complete with respect to work authorizations, procedures, and inspection and retest requirements. The surveillance test was well executed in accordance with an approved procedure.
c.
Conclusions The inspectors concluded that the work performed under this maintenance work order was adequate. The surveillance test as executed satisfied Technical Specification surveillance requirement l
M1.2. Intearated Test of Facility 1 Enaineered Safety Features Components and Inadvertent Charaina Pumo iniection a.
InsMion Scope (61726) The inspector reviewed observed performance of selected portions of procedure SP2613G, " Integrated Test of Facility 1 Components," which includes instructions for preparation for, pelformance of, and restoration from the test.. The inspector reviewed the surveillance procedure and interviewea licensee field personnel to evaluate the propriety of the activities and the functionality of systems and components with respect to technical specifications and other requirements. The inspector also reviewed the circumstances surrounding the inadvertent charging pump injection of approximately 100 gallons of volume control tsnk (VCT) water to the reactor coolant system (RCS) on February 9,1999, b.
Observations and Findinas ) The purpose of procedure SP2613G was to demonstrate, following a simulated loss of offsite power in conjunction with a safety injection actuation signal (SIAS), tne proper performance of the following automatic functions in accordance with Technical Specification (TS) 4.8.1.1.2.c.5: (1) deenergization of and load shed from the emergency buses, (2) starting of the associated emergency diesel generator (EDG) from ambient conditions, (3) reenergization of the emergency bus and the permanently connected loads from the associated EDG, and (4) sequenced reenergization of the automatically connected loads. The licensee also used this test to demonstrate the proper realignment and operation of various systems and components following a SlAS.
' The inspector noted that procedure SP2613G placed certain components in abnormal alignments for the test. Several days before the planned date of the test, the licensee identified a conflict between the specified configuration of the charging pumps in
procedure SP2613G and TS 3.1.2.3. The test procedure specified that the "A" and "B" charging pumps be aligned with their thermal overload devices removed and their -{ breakers closed. The initial closed position of the breakers allowed mNoring of the I breakers' response to test signals, and removal of the thermal overlot - Jevices prevented operation of the charging pumps. However, in operational Mode 5, cold shutdown, TS Surveillance Requirements 4.1.2.3.2 and 4.4.9.3.2 require that at least one citarging pump be demonstrated not capable of injecting into the RCS by verifying ' its breaker open, and TS 3.1.2.3 requires that at least one charging pump in the boron injection flow path be operable. With the "A" and "B" charging pumps disabled by removing their thermal overload devices and with their breakers closed for the test, the "C" pump breaker must be opened to satisfy TS Surveillance Requirements 4.1.2.3.2 and 4.4.9.3.2. To satisfy TS requirements and to achieve the specified test configuration, the licensee decided to enter TS Action Statement 3.1.2.3.a for the test.
This TS action statement specifies that, with no charging pumps operable, all operations ! involving core alterations or positive reactivity additions be suspended. The licensee revised the setup and performance sections of procedure SP2613G to ensn that no ' more than two charging pump breakers would be closed at any time. The iri. sector found that the licensee's approach to address the TS issue was acceptable, since the "C" charging pump could promptly be made available for boron injection if neede l To fully test the charging pump circuitry, the test procedure also specified installation of a jumper wire in the control circuits for the "A" and "B" charging pumps that inserted an automatic start signal. Because of the jumper's location, this jumper also bypassed the - - hand switch on the control panel and the low suction pressure trip for each of these pumps.
The inspector found that operations personnel executed the test well. The operations shift on-duty for the test had been selected for this evolution in advance and had prepared for the test using the ' Unit 2 simulator. The inspector verified that selected equipment responded properly to the test signals.
i Although the test was executed well, the "A" charging pump was inadvertently started while performing procedure SP2613G, Section 4.10, " Restoration of Equipment."
Section 1, " Purpose," of procedure SP2613G specified that steps in Section 4.10 of the procedure could be performed in parallel or out of sequence provided that the test - engineer, shift manager, or unit supervisor reviews the steps and determines that plant conditions or system alignments established by preceding steps are not required for performance of the step. The operator's priority was restoration of the "C" charging pump to establish a boration flow path and exit the TS action statement. To accomplish this action, the day-shift operators executed portions of Step 4.10.15 to open the breakers for the "A" and "B" charging pumps and Step 4.10.16 to close the "C" charging pump breaker. However, the jumpers that had been installed in the control circuits for the "A" and "B" charging pumps remained in place.
Shortly after restoration of the "C" charging pump, the day-shift conducted tumover to the night-shift. The night-shift was unfamiliar with the charging pump configuration, and the tumover brief did not provide complete information regarding the status of the charging pumps. In addition to testfestoration activities, the night shift supported other maintenance and testing activities. To make effective use of resources, the shift manager authorized installation of thermal overload devices for the "A" and "B" charging pumps, a5ng with other thermal overload devices removed for the test. The shift manager iWwed the inspector that he intended to perform steps in sequence, but he did not identify that the jumper wires installed in the "A" and "B" charging pump control circuits had not been removed in accordance with Steps 4.10.15.d and 4.10.15.e of procedure SP2613G. Factors contributing to this oversight included: (1) initials identifying that portions of Step 4.10.15 and Step 4.10.16 had been completed to restore the "C" charging pump and (2) the use of a marker identifying the work group responsible for jumper removal rcther than a line for initials adjacent to Steps 4.10.15.d and 4.10.15.e. Consequently, the shift manager concluded that the prerequisites were satisfied and authorized restoration of the "A" charging pump.
When the breaker for the "A" charging pump was closed in accordance with Step 4.10.16 of SP 2613G, the "A" charging pump started and injected water from the VCT into the RCS.,The installed jumper wire provided the start signal and prevented operators from immediately securing the pump by placing its control switch in pull-to-lock. The operators secured the pump after approximately two minutes of operation by opening the pump breaker. Approximately 100 gallons of water was injected from the VCT into the RC p
Chemistry sampled the RCS and determined that the RCS boron concentration had not measurably changed. However, the inspector was concemed that previous testing of the RCS makeup system could have resulted in VCT boron concentration below that of the RCS, because the VCT had not been sampled since this testing, and the large volume of the RCS could mask the addition of water at a much lower boron concentration. To resolve this issue, Chemistry obtained a VCT sample and determined that its boron concentration was essentially equal to the RCS concentration. Therefore, a dilution of the RCS boron concentration had not occurred.
The licensee documented the event in Condition Report M2-99-0442 and initiated a formal root-cause investigation. The root cause investigation report dated March 9, 1999, attributed the cause of the event to inadequate work planning and supervision.
Contributing factors identified in the report included inadequate quality and usage of procedure SP2613G, inadequate interface between the procedure steps and the associated work orders, and a high level.of scheduled and emergent work distracting the shift manager and unit supervisor from their command and control functions. The inspector found the root cause investigation thorough.
The root cause investigation recommendations included the following corrective actions: l 1) Brief operations department personnel on the results of the investigation, ) including procedure compliance and utilization.
2) Revise TS Surveillance Requirements 4.1.2.3.2 and 4.4.9.3.2.
3) Provide additional resources to the shift to support thorough planning for plant evolutions.
4) Revise procedure SP2613G to provide a more complete charging pump restoration section.
The inspector found the recommended corrective actions adequate to address the cause of the event and contributing factors.
Unit 2 Technical Specification 6.8.1.c requires that written procedures be established, j implemented, and maintained for surveillance testing. Section 1 of procedure SP2613G ! allowed steps in Section 4.10 of the procedure to be performed in parallel or out of sequence provided that the test engineer, shift manager, or unit supervisor reviews the steps and determines that plant conditions or system alignments established by preceding steps are not required for performance of the step. The shift manager failed to adequately implement procedure SP2613G in that he inappropriately performed steps i out of sequence by authorizing installation of the "A" charging pump thermal overload devices (Step 4.10.15.f) before removing the control circuit jumper for the "A" charging pump (Step 4.10.15.e). This inadequacy was identified by the licensee. The inspector considered procedure SP2613G to be weak in that it failed to clearly identify restoration steps where the sequence of performance was important.
l
24 c.
Conclusions ! Although the testing portion of the integrated test of Facility 1 engineered safety features components was well executed, the procedure instructions for restoration from the test were inadequately implemented. Steps to restore the "A" charging pump were . performed in an inappropriate sequence, which resulted in the inadvertent start of the "A" charging pump. The subsequent injection of approximately 100 gallons of water from the VCT to the RCS did not result in a reduction in RCS boron concentration. The NRC i concluded that the surveillance procedure was weak in that it allowed restoration steps to be performed out of sequence when the shift manager determined that the sequence of performance was unimportant and the procedure did not clearly identify restoration steps where the sequence of performance was important. In addition, the NRC concluded that the failure to adequately implement the surveillance procedure constituted a violation of Technical Specification 6.8.1.c. This Severity Level IV violation l is being treated as a Non-Cited Violation (NCV 50-336/99-0243), consistent with Appendix C of the NRC Enforcement Poliev. This violation is in the licensee's corrective action program as Condition Report M2-99-0442.
U2.lli Ennineering U2 E8 Miscellaneous Engineering lasues E8.1 (Closed) VIO 01142 & VIO 03072 (eel 50-336/95-44-05): Ice Blockaoe of Service Water l Backwash Line: (Closed) Unit 2 Significant items List No. 37) l a.
Inspection Scope (92903) The inspector reviewed the licensee's corrective actions to address Escalated Enforcement item (EEI) 50-336/95 44-05 (Violation 03072) which involved the failure to
declare the service water (SW) pumps inoperable and enter Technical Specification (TS) 3.0.3 when an ice blockage was discovered on the common backwash line for the three ' SW strainers. Violation 01142 was also issued to address an inadequate design modification of the SW strainer backwash line which made the line susceptible to freezing. Four Licensee Event Reports (LERs) were issued associated with this event: LER 50-336/96-002-00 addressed the loss of capability to backwash the SW strainers due to formation of an ice plug; L ER 50-33F/96-003-00/01 addressed the failure to enter TS 3.0.3 after discovering that the SW strainers were inoperable due to the ice blockage; i LER 50-336/96-004-00/01 addressed that the SW strainer backwash system was susceptible to freezing following a loss of intake structure non-vital heating; and, LER 50-336/96-005 4 jddressed the failure to enter the technical specification action statement during main 9 1ance and in service testing. These LERs were administratively closed in l NRC Inspection Report 50-336/96-06 because the resolution of the concems was being , tracked by eel 50-336/95-44-05.
I , ___m ~
b.
Observations and Findinos Three SW pumps (with one spare) are located in the Unit 2 intake structure building.
Each pump discharges to a self-cieaning strainer assembly which removes solids and automatically ejects the collec*ed material back to Long Island Sound via a common backwash header. On January 8,1996, with Unit 2 at 100% power, an ice plug at the discharge end of this header resulted in the inability to backwash the SW strainers. The _ ice plug was formed by the accumulation of leakage water through the strainer backwash isolation valves into a horizontal portion of the pipe header which was exposed to an unusually long period of sub-freezing outside temperatures. DLring the five hour period that the backwash line was found to be blocked, the "A" and "C" SW strainers reached the differerstial pressure setpoint for opening the backwash valves. However, this single failure vulnerability of the backwash system that could affect the operability of both SW trains was not considered credible and the Shift Manager failed to initiate an action within one hour to place the plant in hot standby in accordance to the plant Technical Specification 3.0.3.
As immediate corrective actions, maintenance personnel removed the ice plug and restored strainer backwash capability. A temporary procedure change to operations provided the guidance for monitoring the intake structure temperature. When the temperature was below 407, the strainers were manually backwashed every 4 hours, supplemented with building heating to prevent freezing of components within the intake structure.
l As a long term corrective action, Design Change Request M2-96018A was prepared to revise piping, valves, and supports, associated with the SW strainer backwash system.
This change eliminated the common header that ties into all three SW strainers
(including a spare SW pump and strainer system) and provides separate backwash lines for each SW strainer to eliminate the single failure vulnerability. In addition, the l backwash piping from the strainers to the first flanged connection downstream of the j j respective backwash valves has been upgraded to QA Category 1, Pipe Class JCD, l stainless steel and is seismically supported to meet Seismic Class 1 requirements. The l piping downstream of these flanges remain non-QA, Pipe Class JH, fiberglass reinforced l plastic. This non-QA piping was considered acceptable because a piping failure would j l still allow backwash water flow. Existing backwash valves located in the backwash lines for the strainers are QA Category 1.
L As discussed in LER 50-336/96-004-00/01, the licensee determined that following a loss l ! of intake structure non-vital heating, the backwash piping and differential pressure instrumentation tubing, which control backwash operation, could freeze under a sub-j freezing outside temperature condition. Design Change Request M2-96058 was _ prepared to install instruments to detect the onset of freezing cond;tions in the intake structure and automatically initiate the continuous backwash cycle 'of each operating i _ strainer to ensure SW system operability under all operating modes (until operator intervention). Temperature indicators and switches are installed inside the intake structure to provide alarms in the control room, allowing time for operators to install portable heaters, if necessary, if the intake structure area temperature were to fall below 407, procedures require operators to record the intake structure every 4 hours and check that equipment is functioning properly. The inspector performed a walkdown to ' I i
the Unit 2 intake structure building and verified the completion of all mechanical and electrical design modifications related to the SW strainer backwash system. Following restart, the licensee is planning a design enhancement to install new differential pressure indicators filled with silicone (instead of water) to prevent freezing. The inspector found the licensee's deferral of this modification to be acceptable.
Regarding the failure of operators to enter TS 3.0.3 when the ice blockage was identified, the licensee determined that the root cause was the failure to recognize that the strainer backwash is a support system that is necessary to main'ain operability of the SW system. As corrective actions, operators have been trained on this event. To reinforce this training, the SW pump inservice test procedures were revised to direct that the applicable TS action statement be entered prior to placing the SW control switch OFF. The inspector found these corrective actions to be acceptable, c.
Conclusions The licensee's corrective actions were found to be acceptable in addressing eel 50-336/95-44-05 (Violation 03072) and Violation 01142, which involved ice blockage on the common backwash line for the three SW strainerr. eel 50-336/95-44-05, Violation , 03072, Violation 01142, as well as, Unit 2 Significant items List No. 37 are considered closed.
E8.2 (Closed) URI 50-336/96-06-08: Resolution of Water Hammer issues: (Closed - Unit 2 Significant items List Nos. 8.5 and 25) a.
Insoection* Scope (92903) ' The inspector reviewed the licensee's actions to address unresolved item (URI) 50-336/96-06-08. This URI was opened because the licensee did not complete the root cause of the triggering mechanism of postulated water hammers at Millstone Unit 2.
During this inspection, the inspector reviewed the licensee's completed root cause analysis.
b.
Observations and Findinas The licensee conducted a walkdown of both trains of the RWST piping starting at the RWST connections just below the tank. As the walkdown proceeded, more damage became apparent. The damage was consistent with what would be expected from one or more water hammer events.
To assess the licensee's water hammer investigation, the inspector performed a review of the pertinent documentation, performed a series of interviews, and conducted a walkdown of the RWST piping supply to the emergency core cooling systems (ECCSs).
Based on the description of the damaged RWST suoply piping, the inspector agreed with - . the licensee's root cause conclusion. The conclusion was that both trains of the RWST supply piping downstream of the RWST motor-operated valves (MOVs) have been
l.
drained in the past to allow the inspection of check valves. The length of the drained l piping in either of the RWST trains may have been as much as 300 to 400 feet. At least i one water hammer scenario may have been the result of the subsequent opening of the MOV to refill the drained segment of pipe.
To address this scenario, the licensee revised the' pertinent operating procedures describing this evolution requiring the MOV to be opened manually to allow for a slower fill of the RWST piping. The inspector reviewed the computer models of the RWST piping which used time histories as forcing functions representing the full opening of the , i valve and the partial opening of the valve. The inspector noted that the computer model i showed that the piping stresses were lessened when the RWST outlet MOV was l gradually opened. To confirm these analytical results, the licensee filled the RWST i supply piping in each train by slowly opening the outlet MOV while monitoring pipe movement using lanyard transducers. The results showed the pipe movements were l very small and almost negligible.
c.
Conclusion I The NRC concluded that the root cause analysis which identified the operational deficiency that caused the water hammers on the RWST piping was adequate. Further, the inspector reviewed the extensive computeria.ed water hammer assessment which supports the triggering mechanism described in the root cause and found it acceptable.
No violations of NRC requirements were identified. Therefore, unresolved item 50-336/96-06-08 and Unit 2 Significant items List Nos. 8.5 and 25 are considered closed E8.3 (Closed) VIO 01162 (eel 50-336/96-201-03) & VIO 01052 (eel 50-336/96-201-41): Failure to Meet Sinale Failure Criteria for Hydrooen Monitors and Adeouatelv Evaluate the Installation of Electrical.)_umoers (Closed - Unit 2 Sianificant items List Nos. 23.4 & 23.6) a.
Inspection Scope (92903) The inspector reviewed the licensee's corrective actions to address Eels 50-336/96-201-03 & 41. The review included an inspection of the power supply modification for the containment isolation valves for the hydrogen monitor system and engineering training to improve safety evaluations.
b.
Observations and Findinas Eels 50-336/96-201-03 & 41 concerned the licensee's disposition of Licensee Event Report (LER) 50-336/95-038 which was issued in November 1995. This LER identified that following a loss of coolant accKient (LOCA) coincident with the loss of a DC bus, the hydrogen monitoring, containment radiation monitoring, and post accident sampling systems (PASS) flow path could not be established due to the power supply configuration for the associated containment isolation valves. The common suction line has the inside and outside containment isolation valves powered from separate facilities to meet containment isolation single failure requiremera However, this power supply arrangement also created a single failure vulnerability in that the loss of a DC bus would prevent opening the associated containment isolatior. valves to allow hydrogen monitor
and PASS sampling when required by emergency operating procedures. Instead of initiating a design change to eliminate this single failure vulnerability, the licensee
changed the hydrogen monitor operating procedure to install an electrical jumper to repower the deenergized valve from the other facilities' DC bus in the event of this incident. In NRC Inspection Report 50-336/96-201, the inspection team concluded that ) control measures were inadequate to assure that the design basis requirements for the j Unit 2 post accident hydrogen monitoring system were maintained (eel 50-336/96-201-41). The inspection team also concluded that the safety evaluation performed for the operations procedure change did not adequately assess the possibility of a malfunction , of a different type other than previously evaluated, as required by 10 CFR 50.59 (eel 50-336/96-201-03). Violations 01162 and 01052 were issued on December 10,1997, covering Eels 50-336/96-201-03 & 41, respectively.
The licensee determined the cause for inadequate design control measures associated with the hydrogen monitoring system to be an inadequate engineering design and configuration control program. The licensee utilized an electrical jumper device to meet the single failure criterion as a corrective action and did not perform a proper safety evaluation. The corrective actions stated in the violation response included: (1) modification of the hydrogen monitoring system power supplies to meet single-failure criterion; (2) Programmatic improvements to ensure compliance with design control and 10 CFR 50.59.
The inspector reviewed the Design Change Notice (DCN) associated with the re-powenng of the hydrogen monitoring system containment isolation valves. The inspector verified that the power supplies to the hydrogen monitor's outboard containment isolation valves were modified such that each containment isolation valve is now powered from the same facility as the associated hydrogen monitor. As a result, at least one monitor will be operable following a containment isolation signal (CIAS) in the event one of the dc power supplies is lost. In order to maintain single failure criterion for containment isolation, the opposite facility CIAS signal was installed on the outboard isolation supply , valves for the hydrogen monitors instead of the inboard valves to ensure single failure of ' the CIAS will not prevent containment isolation. The inspector verified the DCN work ( was completed by verifying the required verification signatures were included on the DCN package and a post maintenance test was satisfactorily performed. The inspector also walked down accessible portions of the system.
The inspector reviewed actions taken by the licensee to improve compliance with design control. As part of the Unit 2 restart readiness, the licensee developed a training module required to be attended by engineering personnel covering 10 CFR 50.59 safety evaluations. The instructional material reviewed by the inspector was accurate and clearly identified the requirements of 10 CFR 50.59. The material provided good design scenarios and realistic examples for the engineer to learn from. Approximately 1000 site employees have completed this training in 1997 and 199,,
c.
Conclusions .The NRC determined that the licensee's corrective actions were acceptable in - addressing Eels 50-336/96-201-03 & 41 which involved the failure to meet the single.
failure criteria for hydrogen monitors and the failure to adequately evaluate the . installation of electrical jumpers for the containment isolation valves. Violation 01162 ~ (eel 50-336/96-201-03) & Violation 01052 (eel 50-336/96-201-41), as well as Unit 2 Significant items List Nos. 23.4 and 23.6, are considered closed.
E8.4 -(Closed) VIOs 04053 & 04043 (Eels 50 336/96-201-42 & 43k Material. Eauioment. and Parts List Program (Closed - Unit 2 Significant items List No.18) a.
Inspection Scooe (92903) The inspector mviewed the licensee's corrective actions to address Escalated Enforcement items (Eels) 50-336/96-201-42 & 43, which concemed inadequacies with the Material, Equipment, and Parts List (MEPL) Program. These Eels have been previously reviewed in NRC Inspection Reports 50-336/97-202,97-203,97-207,97-208, 98-207, and 98-212. The licensee has provided an updated closure package, consisting of three volumes, for NRC review. This section provides an overview of past activities, a review of the currently submitted material, and a review of the current status of the MEPL Program for Unit 2.
b.
Observations and Findinos Background For structures, systems, components, and parts that are considered safety-related (SR), the procurement, tracking, storage, installation, and maintenance of replacement parts inust be accomplished in accordance with the requirements of 10 CFR 50 Appendir B.
A non-safety-related (NSR) item is generally one that does not perform a safety related function and whose failure would r:ot prevent the accomplishment of a safety-related function. At Millstone the designation of safety classification is performed through the MEPL Program in accordance with Specification 944. This includes the initial classification and changes in classification such as upgrades or downgrades.
In the above Eels and in the inspection reports noted in the scope, a number of problems were identified with the Unit 2 implementation of the MEPL program. This included the improper use of non-safety-related (NSR) parts in safety-related (SR) ' components and the improper completion of Nonconformance Reports (NCRs) to justify . the continued use of these NSR parts. Several previous reports, including the cover letter for NRC Inspection Report 50-336/97-208, highlighted these concems. As a result, on May 14,1998, the licensee submitted letter B17234 to the NRC. This letter presented . the licensee's plan regarding on-going activities associated with the MEPL program at + Unit 2.
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in the letter the licensee committed that four actions would be completed prior to startup of Unit 2, summarized as follows: 1.
Complete component level MEPL evaluations for each component in the Production Maintenance Management System (PMMS) database.
2.
Populate the PMMS database with MEPL numbers, nuclear indicators, and program indicators.
3.
Perform a work history review of QA category 1 components 4.
Ensure adequate MEPL-related programs for long term operation of Unit 2.
Activities to address B17234 ! The inspector met with licensee personnel and discussed the details of the MEPL program activitien to address letter B17234.
Relative to item No.1 of B17234, the inspector questioned whether all QA Category 1 components and all augmented quality components were contained in the PMMS . database. The licensee stated that all Category 1 and augmented quality components had been added to PMMS. Piping and structural type items are contained in the hard copy MEPL, which is separate from PMMS. These items are being moved to PMMS as resources permit. Also, the licensee noted that if ongoing maintenance were to identify a component that was not in PMMS that it would be promptly added. Engineering Record Correspondence (ERC) 2503-ER-98-0344, dated December 2,1998, documents that Unit 2 has completed MEPL evaluations for each component in the PMMS database.
Memo MP2-DE-98-0306 further documents that all components classified as nonsafety- , ' related have a supporting MEPL evaluation.
Regarding the parts within components, the licensee stated that not all parts would receive a part-specific MEPL, but where no part-level MEPL was performed, that part would assume the quality category of the parent component. If maintenance desires to install a NSR part into a SR component, there must be a MEPL that classifies the part as NSR.
Relative to item No. 2, the licensee completed populating the PMMS database with program indicators in October 1998 as documented in Engineering Record Correspondence 2503-ER-98-0265. ERC 2503-ER-98-0344 documents that the PMMS database has been populated with the correct nuclear indicators. The licensee stated that all MEPL numbers have been added to PMMS. The inspector performed a sampling j review and noted that to be the case.
. Relative to item No. 3, the licensee clarified that a work history review would be performed for.all QA category 1 components to ensure the adequacy of installed replacement parts. This would cover the time period from January 1988 to June 1998.
Because of problems at Unit 3, Unit 2 paid particular attention to find instances where . NSR parts were inappropriately used to replace non-ASME code parts in safety-related ASME components.
..._.
Work History Review During the summer of 1998, the licensee began the work history review process to - determine where NSR parts had been installed in SR components.- The licensee initially identiSd all components that were within the scope of the review to include: all CE qvy 1 components, all components that were classified as Undetermined in PMMS, . and 6 components that were classified as NSR in PMMS without a corresponding MEPL.' The selected period for the review was the 10 year period from January 1988 . through June 1998. The licensee justified this time period in Technical Evaluation, M2-EV-98-0216, " Acceptability of Installed Parts in QA Category l Components," dated November 17,1998. This time period was based on information in NRC Information Notice 88-95, " inadequate Procurement Practices imposed by Licensees on Vendors," and in Generic Letter 91-05, " Licensee Commercial-grade Procurement and Dedication Programs." Additionally, this period encompassed a thorough span of work activities, including: the ten year inservice inspection cycle, normal preventive maintenance cycles, major equipment overhauls, several refueling overhauls, and the steam generator replacement project. From a risk-informed standpoint, any equipment that was maintained prior to 1988 has operated satisfactorily since then and/or has been serviced by maintenance in the subsequent ten years. This is consistent with the guidance provided in NRC Generic Letter 91-05.
The work history review showed that 5375 components had been maintained during the time period. The licensee's review found 387 automated work' orders (AWOs), affecting 271 components, where there was insufficient documentation to confirm that SR parts
. had been installed. A total of between 400 and 500 parts were involved. The licensee j documented these findings in Condition Report (CR) M2-98-2289 and promptly prepared ' Operability Determination (OD) MP2-021-98 dated September 15,1998, that provided a basis for initial reasonable expectation of continued operability. Affected components in . CR M2-98-2289 were grouped into the following categories: bearings, emergency diesel generators, doors, electrical, fasteners, fuses, hangers, I&C, snubbers, valves,' and miscellaneous. The CR and Technical Evaluation M2-EV-98-0216 provided a full listing - of all affected e,emponents.
i Ooerability Determination (OD) Revision 1 to OD MP2-021-98 dated January 22.1999, provided a more detailed assessment of the affected components and concluded they were operable. Revision 1 of the OD divides the items into four Groups for evaluation. Attachment 1 of the OD provides a matrix for each item that provides: the Group, the safety function of the part and component, the AWO that replaced the part, the work description, and the basis for J . operability. Group 1 items are individually evaluated in the matrix, while Groups 2, 3 & 4 ' were each provided with generic evaluations that apply to the whole Group. The inspector reviewed the generic evaluations for Groups 2 through 4 and found them to be . acceptable. The inspector also reviewed selected individual evaluations for the items in Group 1, and identified a few questions for the licensee that required additional explanation. For two of these, the ' licensee provided a revised and updated evaluation that provided additional information and resolved the conce r
i The corrective action plan of the CR and the OD specify activities to restore full qualification to these components. The licensee also provided a 14-page table that l provided completed and planned actions to resolve the items, each of which is being
addressed via a Condition Report Engineering Disposition (CRED). (The licensee now utilizes CREDs rather than NCRs to disposition non-conforming parts that are already i installed in the plant.) For the total of 391 items, dispositions are as follows: 169 were determined not to be non-conforming and no further action is required; 115 were determined acceptable to "use-as-is"; and,105 were identified as needing rework to replace parts to restore full qualification. The inspector reviewed a sample of the CRED justifications to "use-as-is" and found them to be acceptable.
Regarding the 105 items that need rework, the inspector confirmed that they have appropriately been included on the deferred items list. Although each item has not been specifically scheduled, the licensee stated that some items would be replaced on line as part of a 12-week rolling schedule and that the remaining items would be completed during their next refueling outage. Because OD MP2-021-98 acceptably addresses these items, the inspector found the licensee's plans to rework these items to be acceptable. Upon completion of the corrective actions, this will resolve historical concerns with respect to the past parts installation practices.
NCR reviews NRC IR 50-336/97-208 discussed that the inspector reviewed a sample of the 91 NCRs J that had been written to address parts or components that had been upgraded to safety-related during the outage and found that there was insufficient technical justification to support the "use-as-is" disposition. As a result, the licensee prepared an engineering department instruction (EDI) to provide guidance for dispositioning NCRs generated from MEPL upgrades. In late 1997, the licensee began (but did not complete) a re-review of the 91 NCRs using the new guidance contained in the EDI. Further, a licensee self-assessment (PES-SA-09-010) identified a number of NCRs from early 1998 with similar problems. Technical Evaluation M2-EV-98-0216 dated November 17,1998, indicated that the reason the re-review of all suspect NCRs was not completed was that the 10-year work history review would encompass the parts and components contained in the suspect NCRs. However, the inspector found that not all NCRs, such as NCRs from MEPL upgrades on components that had no work performed, would be captured by the work history review. The licensee agreed this was a valid concern and subsequently determined that there were 102 NCRs from 1996,1997, and early 19% that were not captured by the work history review. The licensee reviewed the 102 aCRs and determined that 71 of them were acceptable while the remaining 31 NCRs did not provide sufficient technicaljustification to "use-as-is." The licensee generated a conditLn report to address the issue.
i As described above, the NRC found the licensee's di; esition of the NCRs that were i generated from their work history review to be acceptable. Because the licensee has l demonstrated the ability to adequately disposition NCRs, entering the 31 NCRs into the i corrective action process is sufficient to resolve NRC concerns in this are Onaoina Controls for Parts isstanta The licensee'has taken many actions over the last two years in order to ensure that parts of the correct quality have been and will be installed in Unit 2. Many of these are discussed in the earlier noted inspection reports where the MEPL program was reviewed More recently the licensee has implemented additional controls for . maintenance through a special MEPL engineering group called 2CONFIG. This group is patterned after a similar successful effort on Unit 3, called 3CONFIG and is outlined in EDI No. 30910, "2CONFIG Process," dated December 15,1998. Related activities have been reviewed by the ICAVP contractor, other NRC teams, and the resident inspectors.
The inspector had no further questions in this area.
c.
Conclusions ihe implementation of the MEPL Program at Unit 2 has significantly improved and was considered acceptable. The licensee's work history review of past activities was effective in identifying and correcting past instances where non-safety-related parts were installed in safety-related equipment. Viola + ions 04053 & 04043 (Eels 50-336/96-201-42 & 43) and Significant items List No.18 are considered closed.
E8.5 (Closed) LER 50-336/97-23-00 & 01: Minimum Hiah Pressure Safety Iniection Flow Used in Accident Analysis May Be Non-Conservative: (Closed - Unit 2 Sinnificant items List No.55.3) a.
Inspection Scope (92903) The inspector reviewed the licensee's corrective actions to address Licensee Event Report (LER) 50-336/97-23-00 & 01.
b.
Observations and Findinas During a review of the high pressure safety injection (HPSI) system technical specifications (TSs), the licensee identified that the actual HPSI system flow delivery to the reactor coolant system (RCS) may be less than the flow assumed in the loss of coolant accident (LOCA) and main steam line break (MSLB) accident analyses. The licensee initially reported this issue in LER 50-336/97-023-00, which was submitted on July 14,1997.
The licensee identified the following three assumptions used in the existing accident analyses as potentially non-conservative: 1) equal HPSI system flow distribution between the headers to each cold leg although significant differences in flow could exist between the headers based on ' technical specification limits 2).
~ flow instrument inaccuracy was not considered although the instrumentation used to verify adequate HPSI system flow had an inaccuracy of approximately 4 percent
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' 3) pump performance was based on the nominal manufacturer's curve without an allowance for degradation although testing had shown that the performance of the "A" HPSI pump was below the nominal curve in the high flow portion of the j curve ' The licensee performed revised analyses for the LOCA and MSLB accident considering ) these conditions. The licensee reported that these analyses were completed with acceptable results in LER 50-336/97-023-01, which was dated November 24,1998.
The inspector reviewed the revised sinail-break LOCA analysis summary and noted that the analysis assumed a symmetrical distribution of HPSI flow to the four cold legs. This assumption was contrary to the LER statement that an assumed equal HPSI flow distribution was non-conservative. To resolve this apparent discrepancy, the inspector discussed the basis for this assumption with representatives of the licensee's engineering department.
> The licensee had determined that, for Unit 2, the assumption of an approximately equal HPSI flow distribution between headers was appropriate. Many pressurized water - reactors have small diameter (e g., 3 in ses or less in diameter) safety injection headers.
A postulated double-ended break of this size safety injection header near the RCS would cause the pressure in the severed safety injection header to drop to containment pressure while the pressure cf other safety injection headers remained at the higher RCS pressure. This condition would result in an uneven distribution of safety injection flow, with flow to the broken header significantly greater than flow to any other header.
However, at Unit 2, the safety injection headers trem the check valve closest to the RCS to the point where the headers connect to the RCS cold leg pipe are 12 inches in diameter. Consequently, the Unit 2 HPSI system would respond differently to LOCAs than pressurized water reactors with smaller diameter injection headers. A postulated double-ended break in this section of pipe would constitute a large-break LOCA. For large-break LOCAs at Unit 2, the licensee determined that the RCS pressure would approximately equal the containment pressure by the time HPSI flow initiates for the most limiting caces where a loss of off-site power occurs coincident with the LOCA.
Although higher injection flow to the broken leg would reduce the time to initiation of sump recirculation, the limiting conditions are past and the analysis terminates well before sump recirculation initiation. Therefore, the inspector found that the assumption of an equal HPSI flow distribution was appropriate for the large-break LOCA analysis.
For small-break LOCAs (i.e., break sizes where RCS pressure remains above containment pressure for an extended time after break initiation) at Unit 2, the RCS pressure near the break would be approximately equal to the RCS pressure elsewhere in the system. This condition occurs because the system flow area would be large relative to the area of the break. Therefore, HPSI flow to each RCS cold leg would again be approximately equal. Also, the licensee determined that, for certain break locations, the additional cooling provided by a higher injection flow to the header closest to the break could result in better overall performance by causing a more rapid
depressurization of the RCS, which improves core cooling by achieving high core cooling flow earlier in the analysis. Consequently, the inspector found that the assumption of equal HPSI flow to each injection line was also appropriate for the small-break LOCA analysis, in order to evaluate the combined effects of HPSI pump degradetion and flo's instrument inaccuracy, the licensee developed a hydraulic model of the HPSI system. The licensee provided an allowance for pump degradation by using the nominal vendor curve of developed head (feet) versus flow rate (gallons per minute) and reducing the developed head by 98 feet at each flow rate value. This degraded curve was used to represent pump performance in the model. The licensee addressed the issue of flow instrument - inaccuracy by installing more accurate flow instruments and reducing the HPSI injection flow used in the model to account for instrument inaccuracy. The expected minimum injection flow for various conditions was calculated as a function of RCS pressure assuming that the injection valves were in their minimum flow positions and that pump performance was degraded. These minimum injection flows were then used in the accident analyses. Thus, a margin for instrument inaccuracy and pump degradation was provided. The inspector found that the margin provided for instrument inaccuracy and pump degradation and the method used to establish this margin were acceptable.
The inspector reviewed the summary reports for the LOCA and MSLB accident analyses.
These reports indicate that the revised minimum flows continue to provide adequate cooling to satisfy the emergency core cooling system acceptance criteria specified in 10 CFR 50.46. Therefore, the safety significance of the non-conservative assumptions was minimal, c.
Conclusions The NRC concluded that the licensee effectively addressed the concerns identified in LER 50-336/97-023-00, which involved potentially non-conservative assumptions used in existing LOCA and MSLB accident analyses relating to HPSI system injection flow The revised accident analyses, whbh were desuibed and reported as complete in I.ER 50-336/97-023-01, demonstrated acceptable results using calculated minimum HPSi system injection flow. The NRC found that the modeling and calculations that were performed to establish the minimum HPSI system injection flow were acceptable.
Therefore, LER 50-336/97-023-00 & 01 and Unit 2 Significant items List No. 55.3 are closed.
E8.6 (Closed) URI 50-336/97-203-05: Imolementation of IE Bulletins 79-02 and 79-14 a.
Inspection Scope (92903) The inspector reviewed the licensee's actions to address unresolved item (URI) 50-336/97-203-05. This URI questioned the adequacy of Millstone Unit 2's implementation of IE Bulletin 79-02, " Pipe Support Base Plate Design Using Concrete Expansion Anchor Bolts," and IE Bulletin 79-14, " Seismic Analysis for As-Built Safety-Related Piping Systems."
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Observations and Findinas Backaround On May 14,1995, with the plant shutdown, hydraulic snubber support assembly No.
402009 on the shutdown cooling system, between the Refueling Water Storage Tank (RWST) and the emergency core cooling system (ECCS) suction, was found with the rod on the extension piece of the snubber bent. The extension piece was replaced, and the snubber was restored to its original design condition. To evaluate the extent of condition, a nearby mechanical snubber, No. 402008, was functionally tested. This snubber failed the functional test and it was replaced. The licensee issued Licensee Event Report (LER) 50-336/95-019-02 in accordance with the reportability requirement to address this issue.
Previous Assessment Through review of the pertinent documentation, interviews with engineering personnel, and field verifications, the inspector made the following observations. The root cause analysis performed by the licensee revealed that the cause of the damage to hydraulic enubber 402009 was a water hammer To identify the full extent of the water hammer , damage, the licensee performed engineering walkdowns of both trains of the RWST supply piping on September 10,1996. Additional ASME Section XI inspections of selected piping and supports were completed on October 29,1996. These licensee walkdowns and inspections identified several degraded pipe supports (e.g., loose Hitti bolts, deformed or loose structural members of the supports). The inspector determined that these various as-found conditions were consistent with damage that would occur in a water hammer event and confirmed the accuracy of the root cause analysis.
i The licensee performed an operability determination of the as-found piping configuration and determined that both trains of the RWST supply piping remained operable. Although ~ the operability determination was found to be acceptable, the inspector still had concems regarding the as-found conditions.' While reviewing the corrective actions listed in LER 50-336/95-019-02, the inspector questioned the adequacy of the actions taken to address the actions requested by lE Bulletin 79-02, and IE Bulletin 79-14. This was considered unresolved (URI 50-336/97-203-05) pending the NRC review of the licensee's self-assessment of the implementation of these bulletins.
j Present Assessment Although, the licensee performed adequate repairs and modifications to restore the l degraded pipe supports to their design configuration, the inspector noted that during the licensee's walkdown and inspections of the RWST trains, numerous design documents ! did not reflect the as-built configuration. For example:
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i The ultrasonic testing (UT) examination of a Hitti concrete anchor bolt on one of the degraded RWST supports (Support No. 401032) indicated an unexpectedly low bolt length. During the' attempt to remove the bolt for further investigation, the bolt failed.
Metallurgical analysis indicated that the bolt had been flame cut and welded to the baseplate. The nut and the washer were then installed on the stub, concealing the l welded condition of the bolt. This as-built configuration was contrary to the design basis established in drawing No. 25203-22200, Revision 5.
Support 401107 on the RWST supply piping (documented in drawing No. 25203- . 22200-401107, Revision 4) was relocated during initial installation but piping stress analysis (No. 057-01653-C2, Revision 0), which is the analysis of record, was not revised to reflect the change either at the time of the original installation or on subsequent reanalysis efforts associated with IE Bulletin 79-14.
Consequently, the failure to maintain the design configuration of the safety-related piping system (s) is a violation of 10 CFR 50, Appendix B, Criterion Ill, Design Control.
However, this violation of NRC requirements is characterized as a Non-cited violation in I accordance with Section Vll.B.1 of the NRC Enforcement Policy because the l configuration control problems were self-identified, corrected, and the risk involved was minimal. Further, the licensee performed a satisfactory validation of the implementation of the lE Bulletins 7942 and 79-14, as documented below. (NCV 50-336/99-02-04) Assessment of the Validation of the IE Bulletin 79-02 Prooram l IE Bulletin 79-02, " Pipe Support Base Plate Design Using Concrete Expansion Anchor Bolts," requested each licensee to verify that pipe support base plates that use concrete expansion anchor bolts in Seismic Caiegory I systems satisfy their design basis.
Specifically, they were requested to verify that the concrete anchor bolts have an acceptable minimum factor of safety between the bolt design load and the bolt ultimate '! capacity determined from a static test that simulates the actual condition of installation.
l The effort associated with the validation of IE Bulletin 79-02 program is a part of the l corrective action to address the configuration discrepancies identified on the RWST-i l piping.
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l The inspector reviewed the Millstone Unit 2 technical evaluation for the validation of the , IE Bulletin 79-02 program. The licensee identified a population of 112 pipe supports as I part of the RWST inspection program. There were a total of 647 concrete anchor bolts on these 112 pipe supports and 617 were accessible for UT examinations. The results indicated that only two anchor bolts were ineffective.
To assess the extent of the problem, the licensee examined an additional 70 piping supports containing Hitti bolts from the following safety-related systems: high pressure j safety injection (HPSI), low pressure safety injection (LPSI), steam generator blowdown, ' main steam, main feedwater, auxiliary feedwater, reactor building closed cooling water, and service water. The inspector verified that this population was selected based on risk and safety significance. The inspector noted that the inspection attributes included appropriate length of bolts (by UT Measurements), torque (by load resistance), and other . attributes prescribed in IE Bulletin 79-02. Of the 70 supports that were selected, only one support had a deficient Hilti bol The inspector noted that none of the pipe supports required a design change in order for the support base plates to perform their intended function. The bolts required a hardware adjustment only. This clearly satisfied IE Bulletin 79-02.
B sw of the Validation of the IE Bulletin 79-14 Proaram IE Bulletin 79-14, " Seismic Analysis for As-Built Safety-Related Piping Systems," required each licensee to inspect selected systems for conformance to the seismic , ! analysis set forth in design documents, including pipe run geometry, support and restraint design, locations, pipe attachments, and valve locations and weights. The effort I associated with the validation of IE Bulletin 79-14 programs is a part of the corrective action prescribed in LER 95-019-02 to address the water hammer on the RWST piping.
The inspector reviewed Millstone Unit 2 technical evaluation for the validation of the IE Bulletin 79-14 program for qualification of pipe supports. Through field verifications and l interviews with technical personnel, the inspector determined that the portions of piping ' that were selected for review were acceptable. The scope selected was based on system safety function and risk. The selected systems were the RWST supply piping to LPSI, HPSI, containment spray, refueling pool drain lines, the fuel transfer tube, and LPSI discharge piping.
The licensee initiated adverse condition report (ACR) 8761 which describes deficiencies l with 70 pipe supports from which 53 were dispositioned as "use-as-is," 15 were reworked and two were repaired. The inspector found the walkdown scope and the implementation of the repairs and rework of pipe supports acceptable, c.
Conclusions l The failure to maintain the' design configuration of safety-related RWST piping is a violation of 10 CFR 50, Appendix B, Criterion Ill, " Design Control." However, the NRC concluded that the licensee had identified these corifiguration management deficiencies I and took the proper corrective actions to restore the RWST piping and associated supports to their design basis configuration. Further, the licensee's actions to address URI 50-336/97-203-05, which concemed the adequacy of Millstone Unit 2's implementation of IE Bulletins 79-02 and 79-14, were complete and acceptable.
Therefore, this 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 50-336/99-02 44) URI 50-336/97-203-05 is considered closed.
E8.7 (Closed) LER 50-336/98-09-00: Larae Break Loss of Coolant Accident Analysis Indicates Peak Clad Temoerature Could Exceed 2200 Deorees F. (Closed - Unit 2 Sinnificant Items List No. 54) , i a.
Insoection Scope (92700)
l The inspector reviewed the licensee's corrective actions to address Licensee Event ) Report (LER) 50-336/98-09-0 b.
Observations and Findinas On May 1,1998, Siemens Power Corporation (SPC) issued a report pursuant to 10 CFR Part 21, " Reporting of Defects and Noncompliance," conceming the excessive variability of peak clad temperature (PCT) results to small input changes to the RELAP4 blowdown portion of the approved large-break loss of coolant accident (LBLOCA) evaluation model - (EXEM/PWR-LBLOCA). This excessive variability error affected the Millstone Unit 2 LBLOCA analysis. Correction of the calculation errors in the EXEM/PWR-LBLOCA evaluation model resulted in an increase in the peak clad temperature above the 2200* F limit of 10 CFR 50.46. On May 28,1998, the licensee reported this condition in LER 50-336/98-009-00.
In the LER, the licensee committed to (1) revise the LBLOCA analysis to meet the 10 CFR 50.46 acceptance criteria using both the current code and corrected developmental code, and (2) update, as required, the Final Safety Analysis Report, the Core Operating Limits Report, and the Technical Specifications to document the analysis of record. Both of these commitments were to be completed prior to entering Mode 4 from the current outage. In a letter dated March 17,1998, SPC informed the NRC of the interim methodology to be used in the analyses to address the excessive variability concem.
Subsequently, in a letter dated December 21,1998, the licensee provided the NRC with the results of the revised analysis. This information was referred to the NRC's Office of Nuclear Reactor Regulation (NRR) for review.
The NRR staff completed its review of the interim Millstone Unit 2 LBLOCA analysis performed by SPC for Millstone Unit 2. The SPC interim methodology required SPC to evaluate the LBLOCA event with the approved EXEM/PWR-LBLOCA methodology and , the developmental SEM/PWR-98 methodology, which includes corrections for the excessive variability problem, in order to demonstrate that the EXEM/PWR-LBLOCA
methodology produces conservative results. Based on the NRR staff review of the material provided by the licensee, SPC completed the revised Millstone Unit 2 LBLOCA analysis in conformance with the methodology described in its March 17,1998, letter.
A reduction in the maximum Linear Heat Generation Rate from 15.1 kW/ft to 14.6 kW/ft was necessary to ensure that the approved uncorrected code results bounded the . corrected developmental code results. The revised LBLOCA analysis meets the acceptance criteria stated in 10 CFR 50.46. Therefore, the NRR staff found the revised analysis acceptable. The licensee provided the staff with information demonstrating that changes to the FSAR and Core Operating Limits Report relating to this issue were implemented and that changes to the Technical Specifications were not required.
b.
Conclusion The NRC concluded that the licensee effectively addressed the concems identified in LER 50-336/98-009-00, which involved excessive variability in the peak centerline temperature results from the approved large-break loss of coolant accident evaluation , model. The NRC determined that the licensee's revised analysis meets the acceptance criteria listed in 10 CFR 50.46. The licensee also revised documents to incorporate changes to operating limits and analytical methodology related to this issue. Therefore, LER 50-336/98-009-00 and Unit 2 Significant items List No. 54 are considered closed.
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E8.8 Control and Use of Vendor Information: (Closed - Unit 2 Sianificant items List No. 50) a.
Insoection Scope (92903) The inspector reviewed the status of the licensee's vendor interface program for Unit 2 in accordance with NRC Generic Letter (GL) 90-03, ' Vendor Interface for Safety-Related Components."
b.
Observations and Findinas The overall Millstone-site program for vendor interface was initially reviewed in NRC Inspection Report (IR) 50-336/97-203 and updated in NRC irs 50-336/98-207 and 208.
The review in NRC IR 50-336/97-203 was performed at both the site and individual unit levels in order to verify that appropriate policies and procedures are in place and are ' being effectively implemented. The basic guidance used for the review was NRC GL 90-03 and related documentation. Many aspects of the licensee programs to address the GL items were site level programs that are being applied to all units. All of the common site aspects and the Unit 3 specific aspects were reviewed, but the unit-specific aspects for Unit 2 were not all fully reviewed at that time, i The common site aspects were either reviewed and found acceptable in NRC IR 50-336/97-203 or when areas were noted to have problems, these areas were determined to be satisfactory in NRC IR 50-336/98-207.' NRC IR 50-336/98-208 stated that the contents of the Key Safety Related Equipment List (KSREL) for Unit 2 was found to be acceptable. The remaining areas of GL 90-03 that still needed review for Unit 2 were the implementation of procedure DC 16, ' Vendor Equipment Technical Information Program , (VETIP)," in the areas of: vendor contacts, vendor mar:ual updates, and procedure updates.
For Unit 2, the KSREL contains 11 equipment categories,23 plant systems, and 450 components. These are currently addressed by 28 vendor manuals. The licensee has issued Rev. 2 of the KSREL to cross reference the appropriate revised manuals, and to add support components that are related to other components already in the KSREL.
The licensee's procedure reviews against the 28 updated manuals by Operations, Maintenance, Instrumentation and Controls, and Generation Test Services were completed in February 1999. The procedure DC 16 forms were completed and inserted in each vendor manual that identifies tha; plant procedures that are pertinent to the manual.
When asked about the next cycle of vendor contacts, the licensee stated that they were planning on a triennial contact schedule. However, the inspector noted that the licensee had not changed the Unit 2 commitment to the NRC for annual vendor contacts. The inspector discussed the concern with the licensee who stated that they planned to submit a letter to the NRC ; hanging the commitment and until then, would observe the commitment for annual vendor contact c.
Conclusions The licensee's vendor interface program for Unit 2 is in accordance with NRC GL 90-03 for all areas reviewed. Unit 2 Significant items List No. 50 is considered closed.
E8.9 Inservice Test Proo am (Closed - Unit 2 Sianificant items List No. 49) ) ! a.
Inspection Scope (73756) eackaround This item documented a 1996 licensee discovery that the inservice Test (IST) program was inadequate. Specifically, plant components had been improperly excluded from the IST program. Further, components that had teen included, were not properly tested.
These and other program deficiencies were documented in Licensee Event Report (LER) 50-336/96-30, which was r,losed in NRC Inspection Report 50-336/96-08.
To determine the scope of the pmblem, th'.s licensee conducted several program reviews. These reviews uncovered 407 potential program deficiencies that required reso'ation. As part of the process for resolving the deficiencies, the licensee rewrote the IST program manual and all implementing pro::edures. A new IST basis document was prepared that outlined which components in safety-related applications were tested, why they were tested, and the applicable tests they should receive. To verify the revised program was acceptable, two separate third party reviews were performed. At the time of the inspection, twenty-one items were still open. The licensee indicated the corrective action for these items would be resolved prior to the plant entering Mode 4.
The licensee concluded there were two main causes for the program weaknesses, a lack of management oversight, and inadequate resources. To resolve these issues, an ' additional individual was assigned to the station IST program. This person's duties included verifying IST information was transferred between units. Further, the licensee , was in the process of centralizing the IST programs for Units 2 and 3 under one supervisor whose responsibilities would be largely limited to the IST program. This ' contrasts with the current organization, which has the station IST programs for all three units reporting to different supervisors.
Insoection Areas To assess the adquacy of the licensee's revised IST program, the inspectors examined seve al program attributes, includ ; how testing was conducted on the chemical and volume control system (CVCS) and the boric acid system with an emphasis placed en program scope, testing methods, and acceptance criteria. Additionally, the inspectors reviewed the licensee'c cssessment of NRC Information Notices (ins) that discussed IST related information, and examined be"IST deficiencies were dispositioned.
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Observations and Findinas The revised IST program documents and implementing procedures were user friendly arr) contained sufficient detail to understand the rational for performing certain tests.
There appeared to be a clear nexus between the information contained in Final Safety Analysis Report (FSAR), regulatory requirements, and procedure test criteria. The linkages established between FSAR and procedures appeared to be adequate to ensure the IST program verified components could meet their design requirements. For example, if a test procedure requirement was necessitated by a regulatory commitment, the commitment was referenced in the test procedure.
To ensure the program will remain current when changes are made to the physical plant and the supporting safety analysis, the licensee was modifying.ntemal processes that govemed preparation of design changes and performance of safety analysis. At the time of the inspection, the design change process had been revised to include a screening evaluation that prompted design engineers to consider how proposed plant changes could effect the IST program. The inspector determined this change was acceptable.
Process controls regarding the performance of safety analyses, were scheduled to be completed prior to the plant entering MODE 4.
The licensee was aware of industry developments in the IST area and had used the information to improve the quality of the IST program. For example, the licensee had properly evaluated NRC Information Notices that discussed IST related issues including NRC IN 89-23, " Surveillance Testing of Low Temperature Overpressure Protection Systems," and NRC IN 97-90, "Use of Nonconservative Acceptance Criteria in Safety-Related Pump Surveillance Tests," and had made appropriate changes to the program.
IST related information was being transferred between units. For example, a concern identified on Unit 3 regarding emergency core cooling system leakage had been i evaluated for applicability to Unit 2. Additionally, IST-related condition reports had been ) appropriately dispositioned.
i With the exception of some minor editorial errors, the inspectors did not identify test I concerna, or scope errors, when they compared the piping and instrumentation drawings (P&lD) for the CVCS and boric acid system to the IST program document. The errors concemed the omission of the second safety position for several valves in the i program document data tables. However, the IST Basis document had captured the information, and more importantly the program document contained the required testing i for both positions. The IST coordinator indicated he was aware of the editorial errors and , ' that they would be corrected in a planned revision.
The inspector reviewed a sample of surveillance procedures for the CVCS and boric acid systems found them to be adequate in that the acceptance criteria, where applicable, . assured the component was capable of meeting its design safety requirements as
identified in the FSAR and technical specifications. An error, minor in nature and
conservative in direction, was noted by the inspector in surveillance procedure data j package " OPS FORM 2604X-26," which specified an incorrect accumulator volume when determining the leakage rate. The licensee indicated the error world be corrected in a forthcoming change to the procedure.
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Conclusions Based upon the sampled documents, the inspectors concluded the licensee's revised IST program was adequate. Program documents, and implementing procedures were revised, industry information had been factored into the program, and CRs were properly resolved. No significant problems were identified when the inspectora reviewed the IST program for components in the CVCS and Boric Acid systems. Components were found to be properly tested and the progiam scope was adequate. Based upon these findings, Unit 2 Significant Iterns List No. 49 is considered closed.
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Report Details Summarv of Unit 3 Status Unit 3 began the inspection period operating at approximately 100% power. On February 10, operators reduced power to approximately 95% to troubleshoot control problems wit, the 1 A feedwater heat exchanger normal level control valve and a moisture separator reheater trip valve. Following the repair of the valves, power was returned to 100% on February 11, where it remained throughout the rest of the inspection period.
On January 15, the cable spreading room cart >on dioxide system was inadvertently actuated by a plant equipment operator trainee. Control room operators donned self contained breathing apparatus (SCBA) equipment approximately two hours after the actuation, when carbon dioxide levels in the control room rose to greater than 5000 gpm. Operators remained in the SCBAs for j approximately six hours, until carbon dioxide was purged from the control room on January 16.
- < This event is discussed in Section O2.1 of this report.
On February 11, Michael Wilson assumed the position of Unit 3 operations manager.
Mr. Wilson was previously the operations manager at Unit 2. The former operations manager, Barry Pinkowitz, was assigned to assist in the planning and coordination of refueling outage six (RF06), which is scheduled to commence on May 1,1999.
' On February 12, NRC Commissioners Greta Dicus and Jeffrey Merrifield visited the site to tour Units 2 and 3 and meet with licensee senior management, NRC staff, and licensee plant personnel. The Commissioners told a press conference following their site visit. The licensee's slides used during the presentation made to the Commissioners are attached.
U3.1 Operations U3 01 Conduct of Operations 01.1 Reactor Coolant System Leakaoe Detection Systems-l a.
Inspedion Scoos (71707) The inspector reviewed the licensee's administrative controls and applicable systems used for detecting identified and unidentified leakage consistent with technical specification requirements.
b.
Observations and Findinos The inspector found that the control room staff relay on the reactor coolant system (RCS) water inventory balance as the primary method to ensure compliance with the identified operationalleakage requirements of Technical Specifications (TS) 3.4.6.2. The inventory balance is accomplished within the plant process computer (PPC) by a specific algorithm, the 3J3 program, which performs specific calculations that captures all known or expected RCS inventory transfers acros the RCS pressure boundary.-
The control room staff runs the 3J3 program and records the results in the control room l logs once every 14-hours, which is more frequent than the 72-hours required by the TS.
! The inspector reviewed a sample of the individual ca!culations contained within the
computer algorithm and found the methodology appropriate in each case. The inspector also reviewed the associated manual calculations that operators would perform in the event the PPC is unavailable. While a few inconsistencies were identified between the 3J3 algorithm and the manual calculations, the inconsistencies were based on manual l calculation limitations and do not impact the integrity of the calculations.
!- l Unidentified Leek== l The inspector found that control room staff relay on a number of different systems to ! monitor unidentified leakage. First, similar to the identified leakage, the staff utilize the l more accurate 3J3 inventory balance program as the primary method of compliance with l the unidentified operational leakage TS. And similar to the identified leakage results, the unidentified leakage from 3J3 is performed once every 24-hours and is recorded in the control room logs. Other methods to identify leakage utilize combinations of (1) the . unidentified leakage sump pump and its controls, and associated sump level l instruments, and (2) the containment drain sump pump and its controls, and associated l sump level instruments. Different combinations of pump run times, as well as monitored j level during specific time intervals when the pumps are not running, all provide input into specific computer points of the PPC. As a result, the control room staff have a number of priority alarms and other indications that are adequate to alert them to an increase in unidentified leakage. Such an increase in unidentified leakage was identified by the control room staff in January 1999, which is detailed later in this report (Section 01.2). In addition to the 3J3 results, the operators also calculate and record the flowrate from the , containment drain sump three times daily, such that any significant increase would be I investigated as a possible increase in unidentified leakage.
Another method of leakage detection utilized by the control room staff is the monitoring of the containment atmosphere radioactivity monitor. The moniter wnsists d two independent channels that provide the operators with indications of airbome particulate radioactivity, as well as airbome gaseous radioactivity levels inside containment. The control room staff monitor for abnormal trends in radioactivity levels from both channels at least three times daily, and record the results in the control room logs.
The inspector found that the licensee had identified a number of issues within the last few years conceming the containment radioactivity monitor,3 CMS *RE22A&B. For example, Licensee Event Report (LER) 50-423/98-009-00 was issued by the licensee in March 1998. The LER documented that the alarm setpoints of CMS *22 were set too high to meet the commitment to Regulatory Gukie (RG) 1.45, " Reactor Coolant Pressure Boundary Leakage Detection Systwa," as detailed in the Unit 3 Final Safety Analysis Report (FSAR). The licensee subsequently issued a design change to provide the - appropriate design basis to support the setpoint changes, as well as to establish compliance with RG 1.45, as committed to by the licensee in the FSA. I
The inspector determined that the design change incorporate RCS activity limits based upon the Unit 3 Environmental Report issued in 1985. The inspector questioned whether the use of these activity levels were realistic, in that typical RCS activity levels are about , ! - a factor of 100 below those values assumed in the design change. While RG 1.45 provides guidance that " expected values used in the plant environmental report would be acceptable," RG 1.45 also states that a " realistic primary coolant radioactivity concentration assumption should be used." In addition, the licensee's current practice is , l to adjust the setpoints of CMS *22 to a value of 2X the background for the ALERT setpoint, and to a value cf 4X the background for the ALARM setpoint. However, due to the high ambient background in the Unit 3 containment, due to radon from the l containment structure and other noble gases from reactor operations, the inspector ' questioned whether CMS *22 could potentially be unable to detect a 1 gpm RCS leak l within 1-hour, as specified in RG 1.45.
, While CMS *22 could potentially be unable to perform the full function as detailed in RG 1.45, the inspector determined that the immediate safety impact is mitigated by the i ! number of redundant systems utilized by the licensee to identify leakage inside . containment. However, the adequacy of CMS *22 and its ability to perform its design l basis function relative to RG 1.45 is questionable. Therefore, pending licensee resolution of the functional capability of CMS *22, as well as an NRC review of the applicable RG 1.45 guidelines and LER 98-009, this issue will be tracked as an inspector followup item. (IFl 50-423/99-02-05) c.
Conclusion i The inspector concluded that Unit 3 has adequate and redundant systems to effectively ' monitor and identify reactor coolant system pressure boundary leakage into containment.
However, one issue was considered unresolved due to questions conceming the adequacy of the design basis of the containment radioactivity monitor, as well as its ! ability to actually perform its design basis function at current reactor coolant system activity concentrations.
O1.2 Unidentified Leakaae increase and 3FWS*V184 Packina Leak a.
Insoection Scope (71750. 92901) , The inspector observed licensee actions in response to both an increase in unidentified l leakage and the subsequent identification of a valve packing leak inside containment.
I
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) l l b.
Observations arZ Findinas , On January 21,1999, the inspector conducted control room observations and discussed the licensee's identification of an increase in identified leakage. The inspector found that -
the licensee had preliminary determined that the leak was not reactor coolant system (RCS) leakage based on the following: Initial chemical analysis of unidentified sump samples indicated the leak was not . RCS due to the low levels of boric acid in the sample, and that no chlorides or hydrazine were found. Also, the licensee identified high levels of ethanolamine i (ETA) in the sump water. ETA is used as a chemical additive for pH control in the secondary system, therefore, the licensee determined that the presence of ETA ! in the sump was a pretty strong indicator of secondary water leakage. Periodic l follow-up tests for ETA in the condensate from containment area coolers, a known water so'Jrce of the unidentified sump, also indicated the present of ETA.
RCS inventory balance (3J3 computer program) had an indicated unidentified - leak rate of 0.141 gpm (limit of 1.0 gpm), and an identified leakage of 0.139 gpm (limit of 10 gpm), levels that are well below TS action requirements.
CMS-22, the containment particulate and gaseous radioactivity monitor, did not
indicate an RCS leak.
Containment pressure, temperature, and humidity detectors did not indicate any
trends to support an RCS leak.
The "CMT UNIDENT LEAKAGE TROUBLE" annunciaf or had previously alarmed - on the main control board, which indicated increased operation of the unidentified leakage sump pump (3DAS-P10) greater than preset limits. Also, computer points (i.e., CVLKR2) had indicated an increased leak rate that had tracked in the 0.8 to 0.95 gpm range. Based on discussions with the Unit Supervisor, if the control room receives the CVLKR2 priority alarm (alarm setpoint of 1.0 gpm), the licensee would have to enter the applicable technical specification action statement.
The licensee had also identified during a previous containment entry that a packing leak had developed on valve 3FWS*V164, the "D" Steam Generator (S/G) Wide Range level Isolation Valve. The packing leak was significant for two reasons. First, in August 1994, the licensee had entered containment to backseat the same valve, and minimized a similar packing leak. To limit the current packing leak, and to determine the leak's contribution to the increase in unidentified leakage, the licensee planned to perform a similar backseat evolution on 3FWS*V164.
On January 21,1999, the inspector was briefed by both the Unit 3 ALARA Coordinator and the Health Physics Supervisor conceming both the leak from V164, and the l licensee's proposed action. The proposed action was to be similar to an evolution that ha.d occurred in August 1994, where V1G4 was backseated and torqued with the use of a special tool extension. The inspector determined that the licensee's approach to this evolution was a good starting point, especially due to the high dose levels that are
, ,
present in the vicinity of V164. For example, the August 1994 evolution yielded approximately 422 millirem (mR) total exposure, and health physics had estimated that a 100 mR/ min dose rate was expected at the 24' railing where the valve backseat and torque evolution will occur.
The inspector reviewed the ALARA review for the current evolution, and found that the ALARA review and job scope was adequate and appropriate for the evolution. In addition, the inspector found that the job scope was appropriate in that the use of two mechanics to minimize and equalize dose was a good strategy by the health physics . department. The inspector also observed a valve mockup assembly utilized by the . licensee, and determined that the mockup adequately prepared the two mechanics for the valve backseat and torque evolution. Specifically, the mockup provided the mechanics with: (1) a useful opportunity to become familiar with the tool extension used for the backseat and turque evolutions; and (2) an adequate representation of the physical arrangement of V164, and the "D" SG loop area railing where the evolutions were performed. The inspector also attended the pre-job brief, and determined that all appropriate licensee personnel were present, and that the brief included the appropriate discussions. The inspector also noted that the licensee displayed a good questioning attitude during the brief based on the amount and type of questions raised, such as expected actions if unexpected conditions with the valve manipulation had occurred during the evolution.
The inspector was briefed by the health physics supervisor following performance of the evolution. The actual radiation exposurs received by the personnel who had performed the V164 evolution, was -130 mR, well below the pre-job estimate and the 430 mR received during the August 1994 evolution. Also, the leak from V164 was minimized from the ~203 feet plume and audible noise, down to two wisps (with no pressure) and no audible noise, and the unidentified leak rate had decreased by a small amount.
The licensee had indicated that future containment entries were planned in an effort to quantify the unidentified leakage contribution from the non-RCS sources, i.e., secondary { _ sources, in addition, following the V164 backseat operation, the licensee had identified I steam generator manway leakage (discussed further in section M1.2 of this inspection report) that was likely one source of the increased unidentified leakage.
c.
Conclusions The inspector concluded that the licensee's actions following the identification of an increase in unidentified leakage was acceptable and appropriate. In addition, the , inspector found the licensee's efforts in the health physics area, specifically in dose ' minimization to address the packing leak on the "D" steam generator wide range level isolation valve in containment, was both appropriate and well planned.
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U3 01 Operational Status of Facilities and Equipment t l 02.1 Inadvertent Discharae of Carbon Dioxide into the Cable Soreadina Room a.
Inspection Scope (71707. 92901) The inspectors assessed the quality of the licensee response to a January 15,1999, inadvertent carbon dioxide discharge into the cable spreading room. The inspectors also reviewed the root cause investigation conducted by the licensee's Event Review Team (ERT) to verify that appropriate root causes and corrective actions had been identified.
b.
Observations and Findinas ,
Description of Circumstances On January 15,1999, at 17:53 hours, with the plant at full powe.r, an inadvertent discharge of the carbon dioxide (CO ) fire suppression system occurred in the Millstone
Unit 3 cable spreading room (CSR). The actuation occurred when a plant equipment
operator trainee blew dust off a printed circuit board installed in the cable spreading ) room CO panel which is located in the Service Building. There were no plant personnel
in the CSR at the time of the discharge. Shortly following the discharge, CO was
l identifie > have migrated down into the east and west switchgear rooms located directly : aw the CSR. The concentration of CO in the northwest Control Building
stairwell, niiich allows access to the control room, cable spreading room and switchgear , rooms, was in excess of the portable CO meter (>50,000 parts per million) and the area '
was declared uninhabitable. Approximately two hours following the CO discharge,
operators aligned the Control Building purge system to remove CO from the switchgear
rooms. The switchgear rooms were selected for purging first because they contained important plant equipment such as the auxiliary shutdown panel and transfer panels.
The purge system is a nonsafety-related system designed to remove CO / smoke from
various Control Building areas. Placing the pury system in service diverted air from the
control room to the switchgear rooms causing a ucreased pressure in the control room.
I This allowed CO to migrate from the CSR up through penetrations into the control
room. The concentration of CO in the control room reached a level (~17,000 parts per
million) where the operators chose to wear self contained breathing apparatus (SCBA).
The operators remained in SCBA for approximately six hours until the CO, was successfully purged frnm the control building.
Operator Event Response The plant operators responded appropriately to the discharge of CO into the CSR. The
operators fo' lowed the appropriste plant procedures and engaged support from other plant staff. The effective operator response was conducted in spite of several licensee identified procedural weaknesses. Operators responded well to the increasing levels of CO in the control room and safely maintained the plant while operating with SCBAs.
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Technical Soecifications During the first hour following post accident operations, the Millstone Unit 3 control room - pressurization system creates and maintains a positive pressure in tl:e control room envelope in accordance with Technical Speci6 cation (T.S.) 3.7.8 requirements. This ' system consists of two banks of air bottles with associated piping, instrumentation and controls. After the first hour, the control room emergency ventilation system will be placed in service in either the 100% recirculation mode or the filtered pressurized mode (to maintain a positive pressure).
" The control room envelope was breached at 19:35 hours on January 16,1999, when the nonsafety-related control building purge system was placed in service. Opening of individual room supply and exhaust purge dampers, which have no automatic isolation . capabilities, extended the pressurization zone, creating a boundary not previously tested for leak-tight integrity. The licensee appropriately entered T.S. Limiting Condition for Operation 3.7.8 for the control room envelope pressurization system. However, the inspectors determined that the licensee failed to recognize the requirement to also enter T.S. 3.7.7 for the control room emergency vsntilation system.
TS 3.7.7 requires "Two independent control room emergency air filtration systems to be operable." An associated surveillance requirement,4.7.7.e.2, requires that the system maintain the control room at a positive pressure of greater than 1/8" water gauge at less than or equal to a pressurization flow of 230 cfm. Furthermore the basis for this ' requirement states that..."The intent of this surveillance is to verify the ability of the control room emergency air filtration system to maintain a positive pressure while running in the filtered pressurization mode. Thb capability is independent from the requirements regarding the control room pressurization system contained in TS 3/4.7.8."
The inspectors noted that the failure to enter T.S. 3.7.7 was due to an ambiguous bases statement that was incorporated in 1997. - The bases section of T.S. 3.7.7 stated that the integrity of the contro! room boundary (i.e., walls, floors, ceilings, duct work, and access doors) is covered by Limiting Condition for Operation 3.7.8. The licensee believed, at the time of the event, that it was in compliance with T.S. 3.7.7 because of this statement.
In retrospect, this determination was incorrect. To correct this condition, the bases for T.S. 3.7.7 and 3.7 8 will be revised to reflect appropriate actions when the control room boundary is breached.
Operation of the purge system required declaring both trains of control room ventilation inoperable, which would have required the plant to be shutdown in accordance with TS 3.0.3. This resulted in a non-repetitive and corrected violation of TS 3.0.3 requirements on January 16,1999 at 02:35 hours. (NCV 50-423/99-02-06) This is violation of TS 3.0.3 requirements is being treated as a Non-Cited violation consistent with Appendix C of the NRC Enforcement Policy. The licensee documented the root i cause and corrective actions for this Non-Cited violation in LER 99-02 and in their - . . corrective action program as Condition Report M3-99-0271. The inspectors noted that the risk significance of having a breach in the control room boundary integrity while
- purging for approximately 10 bcurs was minimal. General Design Criteria 19 has very conservative dose requirements for operators in the control room Therefore, the risk associated with this con dition was insignifican F
. In response to this finding, the licenses has taken steps to ensure that operations - personnel are cognizant that breaching the control room pressure envelope via use of the purge system, requires entry into both the pressurization specification 3.7.8, and the control room emergency air filtration specification 3.7.7. Additionally, the licensees event review team concluded that additional training on ventilation systems should be considered fnr operations personnel.
Post Fire Sqfe Shutdown Analysis The Standard Review Plan Branch Technical Position 9.5-1, cable spreading area fire safe shutdown analysis, assumes that the east and west switchgear rooms remain habitable following a cable spreading room fire with CO suppression discharge. A fire
in the cable spreading room may render equipment in the control room inopeiable, and therefore, an attemate remote shutdown method was provided via equipment in the switchgear rooms. The licensee was reviewing the accuracy of this analysis based on the results observed during the fire suppression actuation event on January 15,1999.
The determination of whether this event had placed the plant in a condition outside the design basis of the plant is an Unresolved item and was under investigation by the licensee as of the end of the inspection period. (URI 50 423/99-02-07) The' auxiliary shutdown panel, located in the west switchgear area had become uninhabitable following the CO discharge in the room above (cabie spreading room). Troubleshooting was on-
going at the end of this inspection period to determine the cause of the elevated levels of CO in this area. The licensee prepared an operability determination, MP3-003-99,
which concluded that maintaining the cable spreading area carbon dioxide system secured during a fire event will ensure that habitability at the auxiliary shutdown panel will be maintained.
As part of their corrective actions, the licensee bred locked out the carbon dioxide capability to the cable spreading room to ensure the current analysis supporting safe shutdown from the switchgear rooms remained viable. The inspectors determined that appropriate contingency actions have been established in accordance with the Millstone 3 Technical Requirements Manual, which requires establishment of a continuous firewatch in the area when the automatic suppression capabilities have been defeated.
The carbon dioxide system will remain in this status while further investigation and , troubleshooting continues to determine the cause of the CO migration to adjacent areas i
at higher than expected concentration levels. Additionally, all operations personnel serving on shift have been qualified to wear SCBAs. The licensee was evaluating a long term solution which may consist of revising the licensing basis to delete the automatic carbon dioxide suppression system. Based on the continuous firewatch established and operability determination performed, the inspectors had no further concerns regarding j the affect on the safe shutdown analysis Control Room Habitability The licensees ERT identified that a 1981 calculation developed in response to NUREG 0737, item lilD.3.4 and Regulatory Guide 1.78, was inadequate. NUREG 0737 and Regulatory Guide (RG) 1.78 required licensees to evaluate the potential impact of toxic gases stored on or near the plant site on control room habitability. RG 1.78 states that the effects of CO, including fire protection system actuations, should be evaluated.
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Carbon dioxide had not been previously identified for its potential to adversely affect control room habitaoility. Engineering had performed a safety evaluation in 1994 which concluded that self contained oreathing apparatus (SCBA) would not be required for the operators to mitigate design basis accidents. This evaluation focused on radiological conditions along with chlorine gas, but failed to evaluate carbon dioxide. Based on this review, operators wero no longer required to maintain their SCBA qualifications and SCBAs were not required to be stored in the control room area. Additionally, references to SCBA requirements were removed from section 6.4 of the Final Safety Analysis Report (FSAR).
Although startup testing of the CO system identified that cable spreading room
discharges resulted in only slight levels in the control room, this event demonstrated that the potential for carbon dioxide migration into the control room area requires further evaluation in accordance with the regulatory guide. After the event, the licensee performed a preliminary analysis, which identified other hazardous chemicals not previously considered in addition to carbon dioxide. With regard to carbon dioxide, the . operability determination concluded that with carbon dioxide currently locked out to the cable spread;ng room, the control room ventilation system was operable and the fire safe shutdown analysis remained valid. The inspectors agreed with this conclusion. The licensee also recognized the need to update the FSAR to address all toxic hazards and their impact on control room habitability. The failure to adequately consider and evaluate carbon dioxide in the toxic chemical analysis for control room habitability, constituted a non-repetitive, licensee-identified and corrected violation of 10 CFR Part 50, Appendix B, Criterion Ill, design control requirements. This is being treatad as a Non-Cited violation, consistent with section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-423/99-02-08) Personnel Safety Concems The licensee's ERT documented that a security guard had been sent to check a cable spreading room door alarm with instructions not to open the door after the initial CO, discharge. While ascending the northeast stairwell of the control building, the guard had stated that he was in a CO, white-out condition near the door and did not proceed to ! check the door, instead deciding to evacuate to an outside door. The ERT concluded i that inadequate security policy and training existed and resulted in a near miss.
Event Review Team v i The licensee's ERT did a thorough job identifying root causes and recommending j corrective actions in response to this event. The ERT report clearly articulated the c.3quence of events, root causes, and recommended corrective actions. With the exception of the technical specification issue, the inspectors did not identify any notable issues not previously identified by the ERT.
c.
- Conclusions The operator actions taken in response to an inadvertent carbon dioxide discharge into the cable spreading room were good. The licensee's ERT was generally thorough. The i . ERT identified several deficiencies and recommended appropriate corrective action The control room envelope was breached following an inadvertent carbon dioxide suppression system actuation when the nonsafety-related control building purge system was placed in service. When the control room envelope was breached, TS 3.7.7 required declaring both trains of control room filtration inoperable. T.S. 3.0.3 required the plant to be placed in hot standby within seven hours. Operators failed to enter and comply with either T.S. due to an ambiguous statement in the bases section of T.S.
3.7.7. (NCV 50-423/99 02-06) l The fire protection evaluation report does not assume that operators will be required to wear self contained breathing apparatus (SCBA) to safely shutdown the plant from outside the control room. An inadvertent CO discharge event in the cable spreading
room demonstrated that CO will migrate between separate fire zones in the control
building. During this event, CO migrated into the switchgear room where the attemate
safe shutdown panel is located. The licensee identified that the fire safe shutdown analysis may require revision based on the results of continued troubleshooting to determine the cause of elevated CO levels during this event. This item remains open
pending the results of this investigation. (URI 50-423/99-02-07) The licensees event review team identified that their review and response to NUREG 0737, item lilD.3.4 requirements and Regulatory Guide 1.78, was inadequate. The licenses had failed to consider carbon dioxide as a design input in accordance with 10 CFR 60, Appendix B, Criterion ill, in the toxic chemical analysis for control room habitability. (NCV 50-423/99-02-08) A subsequent operability determination concluded that with the cable spreading room carbon dioxide system locked out, the control room i ventilation system remained operable and the fire safe shutdown analysis remained valid.
j O2.2 Ooerability gf Service Water System with MCC/RCA A/C Unit inoperable i s.
Inspection Scope (92901. 92903) At the beginning of this inspection period, the inspector noted that the licensee had identified a leak in the piping downstream of the "A" Motor Control Center (MCC)/ Rod Control Area (RCA) air conditioning (A/C) unit. The licensee entered the technical j requirements manual (TRM) for the resultant inoperable A/C unit, but did not enter any i TS action statements for service water. The inspector reviewed the Unit 3 TRM, TS, i service water design bases summary document, NRC special inspection report 96-201, and an operability determination ;nd associated CRs to determine whether appropriate ] actions were taken with respect to equipment operability.
b.
Observations and Findinos ' The normal cooling water to the MCC/RCA A/C units is nonsafety-related chilled water.
Upon a loss of this rystem, MCC/RCA booster pumps are provided in the safety-related service water system to supp;y the additional head required to circulate service water to , these A/C units when they are running. The booster pumps automatically start in the event of high temperature in the return duct to the associated air handling unit or a loss of offsite powe There is no specific TS for the MCC/RCA A/C units or hnoster pumps. Because the booster pumps support area temperature for the MCC/RCA areas, the related TS is 3.714, " Area Temperature Monitoring." The limit on these areas is 120 degrees Fahrenheit or 140 degrees for less than eight hours. An inoperable air conditioning unit is covered by TRM 7.4.1, " Fire related safe shutdown components." This TRM requires action within 14 days if operability isn't restored.
Upon the identification of a leak in this portion of the service water piping, the licensee appropriately isolated the leak from the rest of the service water system to effect repairs.
Because this piping was isolated, it could not divert flow, through the leak, from the service water system. Therefore, the service water system remained operable and a TS i entry was not required. The inspector discussed the identified leak and repair plan with the system engineer and observed portions of the work in the field and confirmed proper isolation and effective foreign material exclusion control. In addition, as verified through discussion with operators and review of operator logs, operators were aware of the plant condition and affect on operability and the appropriate TRM section was entered.
While reviewing operability related to the MCC/RCA A/C units, the inspector noted that an operability determination (OD), OD MP3-123-98, was written to address possible air accumulation in the booster pump piping, which could potentially affect the safety-related MCCs and rod control equipment. The inspector determined that the OD conclusion that the system was operable after service water pump starts or swaps and before piping venting was reasonable, considering field testing which shows slow temperature increases with design heat input. Therefore, implemented procedural revisions, which require venting after pump starts / swaps should be sufficient to support the safety-related equipment operability.
The inspector also reviewed a past inspection report, which identified an improperly evaluated temporary modification which, in part, defeated portions of the automatic initiation and alignment of the booster pumps. The licensee's response to the associated violation stated that the temporary modification was removed and a permanent - modification was made to the plant which restored automatic initiation of the system.
The inspector confirmed these actions were taken and had no further questions in this area.
c.
Conclusions The inspector reviewed issues related to MCC/RCA cooling system operability including a piping leak, review of a previous temporary modification and a recent operability determination associated with potential air accumulation in service water booster pump piping. The licensee addressed each issue properly and complied with associated technical requirements manual and technical specifications section U3 08 Miscellaneous Operations issues 08.1 (Uodate) URI 50-423/97-83-08: RHR Heat Exchanoer Leak Rate a.
. Insoection Scope (92901) . The inspector reviewed the licensee's actions in response to Unresolved item (URI) 50-423/97-83-08, which addressed post-accident equipment leakage relative to technical specification requirements.
b.
Observations and Findinas . URI 97-83-08 was initiated following the Unit 3 Operational Safety Team inspection (OSTI) that was performed in April 1998, and documented in NRC Inspection Report (IR) .50-423/97-83. The team found that the licensee had not fully addressed the effect of possible post-accident water leakage from the recirculation spray system (RSS) into, and from, the residual heat removal (RHR) system components that had been known to leak during unit cooldown operations, in addition, the team questioned if the leakage had been both accounted for in the assessment of possible offsite doses, and minimized in accordance with the requirements of Technical Specification (TS) 6.8.4.a, " Primary Coolant Sources Outside Containment."
< As a result, the licensee monitored and measured the RHR heat exchanger and pump mechank:al seals during a cooldown from Mode 4 to Mode 5 in May 1998. The licensee drafted a memorandum based on the results of the leakage monitoring, and concluded that: (1) the observed leakage was almost non-existent for one RHR pump, and within the 20 cc/hr leakage requirements of the design calculation that supports TS 6.8.4 requirements; and (2) while the heat exchanger leak rates were strongly temperature ' - related and moderately pressure related, at post-accident RSS pressures and temperatures, there would be minimal, if not zero leakage.
. The memorandum included an attachment that detailed some of the data collected during the monitoring period, and the observed leakage is detailed below:
m RHR System Leakage Observed "A" RHR Pump Sel l 0 - 8 cc/hr "B" RHR Punir
- , l 0 - 45,000 cc/hr "A" RHR Hx "B" RHR Hx l 456 cc/hr The licensee concluded that the observed leakage occurred at conditions far in excess of what would be experienced in an actual event. Specifically, the licensee assumed a post-accident RSS pressure of 135 psig, but that the 350 psig pressures that existed during the leakage monitoring were still far in excess of the assumed RSS pressure.
Therefore, the licensee concluded that less leakage would be observed due to the lower pressure. In addition, the licensee utilized a differential test pressure methodology from
the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section IWV-3423e, which is applicable to valve differential test pressures.
Specifically, the licensee applied the valve differential pressure methodology to the "B" RHR heat exchanger observed leakage of 456 cc/hr, and attempted to approximate the post-accident leakage at the previously assumed RSS post-accident pressure of 135 psig. As a result, the licensee calculated a leakage of 283 cc/hr and determined that this value was closer to a realistic leak rate, but still considered higher than what would actually be observed in the post-accident environment. The memorandum also detailed a recommendation that the use of a conservative value of 300 cc/hr be utilized in the leak monitoring program until the licensee could evaluate the issue further.
The inspector reviewed the licensee's data and results, and determined that the conclusions were not adequately supported by the data or the discussion contained in the memorandum. For example: 1) The conclusion stated that the heat exchanger leak rates were "strongly temperature related and moderately pressure related," yet, the memorandum provided a basis for the conclusion of less leakage due only to the lower pressures that would exist post-accident, and did not contain any temperature- . related arguments.
2) While the licensee determined that the pressure / temperature correlation of the "B" RHR heat exchanger provided a better representation of leakage than the "A" heat exchanger, the substantial leak rate (0 - 45,000 cc/hr) associated with the "A" RHR heat exchanger was not directly mitigated by any engineering analysis or other discussions that could have supported any of the licensee's conclusions.
3) The licensee's use of a valve differential test pressure methodology to estimate heat exchanger gasket leaks in a post-accident environment is considered adequate. However, the calculated result of 283 cc/hr, as well as the recommended 300 cc/hr is much higher than the 140 cc/hr leakage (per heat exchanger) assumption contained within calculation P(R)-746, ECCS System Leakage Outside Containment," which is the basis for the requirements contained in TS 6.8.4.a. In addition, the licensee has not acted on the recommendation that more evaluation was needed.
The licensee's use of 135 psig RSS pressure and 98*F RSS temperature, is not consistent with post-accident conditions that have been previously calculated and detailed in the Unit 3 Final Safety Analysis Report (FSAR). In addition, no effort was made by the licensee to estimate the pressures and temperatures that could be present at the RHR pumps and heat exchangers during the cold-leg recirculation phase of a design basis accident, which would support or refute the conclusions that leakage would be " minimal, if not zero."
c.
Conclusions The inspector concluded that the licensee has not yet adequately addressed the ' potential residual heat removal system leakage documented in URI 50-423/97-83-08.
The licensee plans to perform a technical evaluation to address the leakage issue, including a response to the NRC issues identified above. Therefore, since the potential for such leakage has not been adequately dispositioned by the current licensee analysis, i URI 50-423/97-83-08 will remain open pending NRC review of the licensee's technical evaluation.
U3.11 Maintenance U3 M1 Conduct of Maintenance M1.1 Surveillance Observations i I a.
Inspection Scope (61726_) The inspector observed portions of selected surveillance and preventive maintenance (PM) activities to verify proper calibration of test equipment, use of approved procedures, conformance with technical specification limiting conditions for operation, and correct system restoration following testing. Portions of the following activities were observed:
SP 3446B11 Train A Solid State Protection System Operational Test EN 31084 Operating Strategy for Service Water System at Millstone e Unit 3
SP 3448E41 Train B Diesel Sequencer Actuation Logic Test e SP 3646A.2-1 Emergency Diesel Generator B Monthly Test b.
ObseNations and Findinos Activities were performed by knowledgeable operators, instrumentation & control (l&C) technicians, and engineering personnel in accordance with approved procedures. Test equipment was verified to be calibrated. The inspector independently verified completion of procedure steps, parameter readings, valve positions, and annunciator receipt.
Proper dual verification by l&C technicians and peer checking by operations personnel were also observed. Effective communication was noted among operations, l&C, engineering and maintenance personnel.
The inspector discussed the observed activities with operations personnel, reviewed operator logs, confirmed operators were aware of the ongoing tests, and logged into and out of appropriate associated technical specifications.
. The inspector verified systems were retumed to their normal configurations after testing.
- In addition, reviews of completed surveillance forms confirmed that as-left parameters were acceptabl. c.
Conclusions Observed surveillance and preventive mainiencnce tasks were performed by - knowledgeable operations, instrumentation and control; and engineering personnel in accordance with approved procedures and work orders. Effective communication was noted among responsible organizations and PM work and surveillance test results were properly documented.
M1.2 Evaluation of Corrective Maintenance Activities a.
Insoection Scooe (62707. 92902) The inspector attended maintenance planning meetings, observed ongoing and completed field work, and evaluated the licensee's scope of work control for several emergent conditions during this inspection period that required immediate management attention and corrective maintenance response. Dudng the field inspections, the inspector also raised some questions regarding the operability status and tagging controls of certain safety-related components.
b Observations and Findinas The inspector specifically assessed maintenance activities and overall licensee control of and response to the following equipment problems that emerged during this inspection i period: steam leaks identified on the secondary-side manways of the "A", "B, and "C" e steam generators (S/Gs); The inspector evaluated the licensee's consideration of this leakage within containment with respect to the technical specification requirements for control of unidentified reactor coolant system leakage; (note: such leakage criteria and measurement system capabilities are discussed further in Section U3 01.1 of this inspection report). The inspector also reviewed the temporary modification (TM 3-99-005, through change 2) for the installation of clamps on the leaking S/G manways, and the injection of leak sealant into the clamps (twice on S/G "A", once on S/G "B", and no injection into the S/G "C" clamps). Accountability of the leak sealant material was maintained within the calculated volume limits, preventing the introduction of sealant into the secondary side of any steam generators. Good coordination with the leak sealant contractor was in evidence, to include follow-up activities by the contractor to mock-up and test a better . sealant mixture and injection controls, if needed in the future.
The licensee established personnel safety (e.g., containment stay times due to _ .. heat constraints) and ALARA controls and goals. Planning was initiated to coordinate work activities with other work requiring containment entries, but the commencement of work was delayed and overall duration of activities extended because of some planning inadequacies and unforseen equipment problems. A good questioning attitude was noted on the part of the licensee team supervising - these activities. NRC questions regarding the impact of unconfined sealant on l l
safety related components and systems inside containment, as well as the potential for missile hazards resulting from the unsealed SIG "C" clamps, were adequately reviewed and answered by cognizant licensee personnel. The inspector examined the leak sealant components (e.g., clamps), reviewed licensee decisions regarding revisions to engineering criteria (e.g., sealant injection pressure), and interviewed maintenance, engineering, and management personnel, as necessary, to determine the adequacy of the overall control of this activity. While the S/G manway leakage was not completely stopped, the extent of this leakage was reduced by these temporary modifications.
ventilation problems in the intake structure, resulting in elevated circulatin.9 water . pump stator temperatures; The inspector reviewed the licensee repair plans, including contingency actions to provide immediate cooling to the area. The licensee prioritized the efforts to restore and intake exhaust fan, which had been damaged, to service; and assigned damper inspection and filter replacement work to the maintenance 'Tix-it-now" (FIN) team to maximize cooling to the pump areas. The inspector questioned and verified that the safety-related service water pumps and supporting equipment, also located in the intake structure, were not adversely affected by these ventilation problems.
containment penetration questions involving an isolat: 1 valve with a packing
gland leak and instrument tubing to a containment pressure instrument, affixed with a reject tag; The inspector identified the above conditions in the auxiliary building during an inspection-tour of containment penetrations. Both component issues were discussed with the cognizant licensee in-service testing (IST) engineer in the case of the packing leak on a closed safety injection valve,3SlH*CVCv34, a trouble report and automated work order (AWO) had been generated for repair during the next refueling outage, RFO 6. From the AWO paperwork, the
inspector determined that the IST engineer had visually inspected the leak and decided that additional local leak rate testing of the valve was not required.
Discussion with the IST engineer identified a need for the station 10 CFR 50, Appendix J program to define a methodology and criteria for handling small leaks. The inspector had no further questions regarding this particular containment isolation valve, and viewed any Appendix J program enhancement with respec'.to such small packing leaks as an improvement that was prudent for j the IST program engineer to further evaluate.
With regard to the reject tag on an instrument tubing support for a test header pressure indicator, 3SlH-P1929, the inspector was provided evidence that the ' source of the discrepancy had been repaired.. Although this pressure instrument - provides a nonsafety-related function, the inspector verified that the pressure boundary is safety-related. Therefore, the tubing run and the pressure indicator i are rated as quality assurance (QA) CAT 1 components, and are seismically mounted.
failure of a backdraft damper to open sufficiently to achieve flow during a e surveillance test of the supplemental leak collection and release system (SLCRS); The inspector reviewed an operability determination (OD MP3-001-99), and discussed the repair activities and the conduct of additional testing with the Operations Manager. The subject damper was exercised and flow subsequently j measured to be acceptable. After measurements were taken, the SLCRS train was shut down and the damper allowed to retum to its normally closed position.
SLCRS was then restarted and an acceptable flow measurement was recorded.
Lubrication of the damper was completed and the linkage inspected under " minor maintenance" controls. Given the successful completion of the surveillance testing and the performance of the required corrective maintenance, the operability of this SLCRS damper was verified.
i c.
, Conclusions i During the licensee's planning an conduct of corrective maintenance activities, as described above, the inspector observed appropriate consideration for potential adverse impact upon safety-related components and functions. Questions raised by the inspector were satisfactorily resolved. Licensee conduct of the required maintenance was adequately controlled. Where necessary, follow-up reviews of the maintenance activitie-s were instituted by the licensee to validate effectiveness, ensure operability, or improve the approach to the conduct of such needed work in the future.
U3.Ill Enoineerina U3 E2 Engineering Support of Facilities and Equipment E2.1 Enaineerina Follow-up Activities related to the CO, Event a.
Inspection Scope (40500.92903) As documented in Section U3 O2.1 of this inspection report, the inspectors assessed the quality of the licensee response to the inadvertent discharge of carbon dioxide into the cable spreading room on January 15,1999. Subsequent to this event and in parallel with the licensee's event review team investigation, certain condition reports (CRs) were initiated to evaluate other means of CO migration into the Unit 3 control room. The
inspector evaluated immediate licensee actions in response to these CRs, and also conducted a review of the Unit 3 procedure controlling licensee activities for plant shutdown from outside the control room.
b.
Observations and Findinas CR M3-99-0273 was initiated on January 27,1999 to document an inadequacy in the Unit 3 toxic chemical analysis for failing to adequately address an onsite bulk carbon dioxide storage system failure or the potential for an internal building toxic gas release.
j The inspector observed the plant operations review committee (PORC) meeting (number 3-99-009) held on January 29, ;999, which discussed the acceptability of the operability
. . . . . .
l
l determination (OD) addressing the concems raised in CR M3-99-0273. Control room habitability and safe shutdown capabilities were determined to be operable with I , l compensatory measures in place, but not fully qualified. The inspector reviewed the l- ~ preliminary OD, MP3-003-99, and evaluated both the immediate corrective actions (e.g., >
l tagout of the cable spreading area carbon dioxide fire suppression system to preclude
l discharge) and the engineering analysis for a carbon dioxide storage tank (3FPL-TK1) l rupture. The engineering judgement used to determine that control room operations would not be adversely affected by the postulated failures, given current compensatory measures, appeared to be reasonable.
L Another CR, M3-99-0438, was initiated on February 8,1999 to evaluate other credible CO transport pathways to the Unit 3 control room ventilation system. In particular,
l certain plant areas that are protected against fire by a carbon dioxide suppression ! capability have overpressure protection systems that could disperse the CO near the
l control room fresh air intake. A preliminary OD (MP3-005-99) was written on February
l 10,1999, which concluded that the control room operators would not be adversely i affected by such hypothesized discharges, but recommended as a prudent action that l carbon dioxide concentrations in the control room be periodically monitored during any l purging activities that could result in discharges to the control building roof area. The inspector noted that additional CO, protected areas were assessed as potential sources of smoke or other habitability hazards to the control room; and this OD resulted in a continued operable determination.
Because design basis considerations require the capability of the operators to shutdown the reactor and place the plant in hot standby (mode 3) conditions from outside the control room, the inspector reviewed emergency operating procedure, EOP 3503 (Revision 12), describing the " Shutdown Outside Control Room". The inspector conducted a walkdown inspection of the transfer switch panels, auxiliary shutdown panel and fire transfer switch panel located in the east and west switchgear rooms. The inspector also assessed the shutdown actions and system capabilities, delineated in EOP 3503, against the description of the attemative shutdown capability documented in section 8 of the Unit 3 Fire Protection Evaluation Report (FPER), as resolution of the safe shutdown evaluation problem areas.
c.
Conclusions . The inspector determined that the licensee engineering staff had conducted an assessment of the credible toxic gas pathways to the Unit 3 control room and had recommended appropriate compensatory measures to be implemented to maintain the control room and its ventilation system in an operable status. With regard to the licensee's capability to conduct a safe shutdown from outside the control room, the inspector's review of the relevant EOP and FPER sections identified no inconsistencies.
The inspector also found no discrepancies in the licensee's conclusion that such an-altemate shutdown could be safely conducted, given the corrective actions taken and " compensatory measures implemented in response to both the CO event on
January 15,1999, and the subsequent issues identified in the CRs discussed abov U3 E8 Miscellaneous Engineering issues E8.1 Resolution of Open Enaineerina items j (Closed) LER 50-423/96-09-01, " Inoperable Shutdown Margin Monitors from Low Count j Rate, Due to inadequate Design Control" j ! (Closed) LER 50-423/96-34-01, " Residual Heat Removal Pump Suction Relief Valve Setpoint Not in Accordance with Technical Specifications"
(Closed) IFl 50-423/97-201-01, " Items not available for review during NRC ICAVP implementation inspection" (Closed) IFl 50-423/97 202-10, " Engineering support of fire protection program" a.
Inspection Scope (90712. 92903) l During this inspection period, the inspector reviewed the open item list report for the J Millstone Urpt 3 docket and identified certain older issues that appeared to have been previously inspected and documented in other inspection reports. The status of these open items was further evaluated, particularly with regard to the question of whether the i existing inspection record adequately resolved the remaining engineering issues.
b.
Observations and Findinas LER 96-09-00 was reviewed and closed during the inspection period documented in inspection report (IR) 50-423/96-05. Subsequently, a supplement to this LER (96-09-01) was issued, which corrected an error in the original text, but made no new commitments and did not revice the substance of the technical issues or the stated corrective actions.
The inaccurate statement that was removed in the corrected LER supplement was based upon an inaccurate assumption, which itself was the subject of a separate LER (97-07-00). This latter LER was reviewed for closure during an inspection documented in IR 50-423/97-203. The issues involved with the original LER have been previously reviewed, along with the technical inaccuracy that required the supplement to LER 96-09 to be issued. This item is therefore considered to be closed.
LER 96-34-00 was reviewed and closed during the inspection documented in IR 50-423/97-202; and supplement 1 (96-34-01) was inspected and closed in IR 50-423/98-207. During the current inspection, supplement 2 (96-34-02) to this LER was reviewed. The inspector determineo that the regulatory commitments had not changed from the previous LER supplement, except for the notation in the earlier version that the investigation had not yet been completed. The corrective actions, related to the specific relief valve setpoint discrepancies identified and reported, remained the same as those p- -inspected and documented in the closure of LER 96-34-01.-One additional corrective action, involving programmatic assurances of adequate interdepartmental interfaces, was instituted within the framework of the licensee's corrective action program. After . completion of the event investigation, a more detailed explanation of the cause of the
deficiency was documented in LER 96-34-02; however, neither the resulting technical information, nor the specific corrective actions previously evaluated, were altered by the revised LER text. Therefore, the actions previously inspected remain valid, and the supplement to this LER is hereby closed.
During an inspection of the Independent Corrective Action Verification Program (ICAVP) contractor activities, the NRC inspection team was unable to assess the effectiveness in several areas beause of the lack of completed work. An inspector follow-up item, IFl 50-423/97-201-01, was opened to track progress in these areas for future evaluation.
Subsequent to the completion of the inspection activities documented in IR 50-423/97-201, four additional NRC team inspections of the ICAVP were conducted and documented in separate NRC inspection reports. On June 17,1998, the Director of the ! Office of NRR issued a letter to the licensee indicating that the ICAVP had been i completed to the satisfaction of the NRC, as required by Section IV.1 of the j August 14,1996 Confirmatory Order for Millstone Unit 3. As documented in IR 50-423/98-208, significant items list (SIL) issue 43, addressing the ICAVP Order, was closed, indicating satisfactory evaluation results and corrective actions for all ICAVP areas. This included those areas identified for further tracking by IFl 50-423/97-201-01.
Therefore, this item is also considered to be closed.
During an inspection of the fire protection program, as documented in IR 50-423/97-202, an inspector follow-up item (IFl 97-202-10) was identified to track the effectiveness of the engineering support for the station fire protection program. At that time, it was noted that the acceptability of the licensee's corrective actions would be used to substantiate closure of SIL issue 42 (" Fire Protection / Appendix R Programs") for Millstone Unit 3.
Subsequently, the NRC conducted two team inspections of the Unit 3 fire protection program, as documented in irs 50-423/ 97-84 & 98-81. SIL item 42 was inspected and closed in the latter of these two team inspections. Therefore, the issues being tracked by IFl 97-202-10 have already been inspected with respect to the adequacy of the fire protection program at Millstone Unit 3; this item is hereby closed.
c.
Conclusions Review and further evaluation of the Unit 3 open item list report identified four issues that had been the subject of previous inspection and were considered to have been adequately addressed in previous inspection reports, as discussed above. As a result of this review and assessment, the inspector concluded that licensee actions for the ] identified discrepancies noted in LER supplements,50 423/96-09-01 and 96-34-02, ' and inspector follow-up items, IFl 50-423/97-201 and 97-202-10, have been acceptably completed; and these open items are hereby ck. sed.
s
P8 Miscellaneous Emergency Preparedness (EP) issues P8.1 (Uodate) VIO 50-423/98-01-01: Failure to Maintain Unit 3 PASS Operational a.
- Insoection Scooe (82701)
Post Accident Sampling System (PASS) inspections were conducted in both May and j June 1998 (Inspection Report 50-423/98-208) to review the adequacy of the licensee's i corrective actions with regard to an NRC Severity Level lli Violation (Inspection Report 50-423/98-01) for failure to maintain an adequate PASS program. Based on sample results and operation of the system, it was determined that the corrective actions were. sufficient to provide reasonable assurance that the PASS system would be available to assist in the assessment of core damage, given a significant transient or accident.
However, the licensee was not able to determine the causes for not meeting the agreement criteria for determining a total dissolved gas (TDG) concentration and for measuring pH in a water sample. Therefore, NRC Violation No. 50-423/98-01-01 J remained open. During the period of February 1-4,1999, a follow-up inspection was conducted to assess the licensee's ongoing corrective actions in response to the violation. The inspection included a review of generated Condition Reports (CRs) and the associated corrective actions, surveillance records, laboratory data and discussions relative to the ongoing TDG and pH investigation. Also, the inspector reviewed the licensee's initiatives to repair and upgrade the Unit 2 PASS prior to restart.
b.
. Observations and Findinas During the time period of July 24,1998 to January 14,1999,11 surveillance tests were performed and 23 CRs were generated for maintenance items and system enhancements. The surveillance tests and equipment maintenance were performed in accordance with Technical Specification 6.8.4.d,- Millstone Unit 3 PASS, and the Millstone Unit 3 Maintenance Rule Action Plan. The inspector reviewed the CRs and determined there were no repeat items that were identified prior to restart and deficiencies were immediately corrected. However, the licensee continued to have difficulty not meeting the agreement criteria for measuring pH and determining TDG concentrations.
The licensee has explored potential causes of the problems associated with performing these analyses and in fact, performed a successful test on January 5,1999. However, the licensee wasn't able to duplicate these results in a subsequent test. The licensee has obtained assistance from the system's vendor and continues to troubleshoot these issues for resolution. Until that time, NRC Violation 50-423/98-01-01 will remain open.
The inspector noted several improvements to the program since the previous inspection . In June 1998 which included excellent teamwork and continued management support.
One of the noted improvements was the implementation of a newly developed PORC n . approved PASS Program Manual which described system operations, corrective and preventive maintenance, testing, system design modifications, system responsibilities, training requirements, and technical and regulatory requirements. Also, the manual
included a Work Plan outlining open items and the licensee's plans for a routine , l scheduled maintenance program. The inspector determined that the addition of the Program Manual reinforced the overall maintenance and operation of the PASS program for ensuring functionality and reliability of the PASS.
The inspector reviewed the Unit 2 PASS esign diagrams and held discussions with the Unit 2 PASS support team members. The Unit 2 PASS was and continues to be upgraded and system testing was expected to begin in February 1999.
i c.
Conclusions. Improvements continued to be made in the Post Accident Sampling System (PASS) Program since the previous inspection in June 1998. The licensee implemented a l PORC approved, PASS Program Manual which described the program in detail and I reinforced the overall maintenance and operation of the PASS program for ensuring j functionality and reliability of the PASS. In addition, monthly surveillance tests were l conducted in which water samples were successfully taken and analyzed, equipment ' failures were identified and immediately corrected and Technical Specifications and Updated Final Safety Analysis Report (UFSAR) commitments were met. However, the licensee continues to troubleshoot their method for retrieving and analyzing a total dissolved gas concentration and for measuring pH in a water sample. Until these issues are resolved, NRC Violation 50-423/98 01-01 will remain open.
V. Management Meetings X1 Exit Meeting Summary , ! l The inspectors presented the inspection results to members of licensee management at l separate meetings in each unit at the conclusion of the inspection. The licensee acknowledged l the findings presented.
X3 - Management Meeting Summary On January 11,1999, a public meeting was held at Millstone Station between NU and the NRC to discuss Unit 2 Restart status and Unit 3 performance. Slides from the meeting are attached to this report.
During a February 12,1999 Millstone visit by Commissioners Dicus and Merrifield, as noted in the summary of Unit 3 Status, the Commissioners met with licensee management. Slides from this meeting are attached to this repor INSPECTION PROCEDURES USED IP 40500 Licensee Self-Assessments Related to Safety lasues inspections IP 41500 Training and Qualification Effectiveness IP 60705 Preparation for Refueling IP 60710 Refueling Activities IP 61726 Surveillance Observations ' IP 62707 Maintenance Observations IP 71707 Plant Operations IP 71750 Plant Support Activities IP 73756. Inservice Testing of Pumps and Valves IP 82701 Operational Status of the Emergency Preparedness Program IP 90712 in-Office Review of Written Reports of Nonroutine Events at Power Reactors IP 92700 _ Onsite follow-up of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92901 Follow-up Plant Operations IP 92903 Follow-up Engineering ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-336/99-02-01 NCV Inadvertent Reactor Coolant System Water Level increase (U2 01.2) 50-336/99-02-02 NCV Inadvertent Transfer of Water from the Unit 2 Spent Fuel Pool (U2 03.1) 50-336/99-02-03 NCV inadvertent Charging Pump Injection (U2 M1.2) 50-336/99-02-04 NCV Failure to Maintain Design Configuration (U2 E8.6) 50-423/99-02-05 IFl Containment Radiation Monitor Design Basis Function (U3 01.1) 50-423/99-02-06 NCV TS 3.0.3, Control Room Filtration System (U3 O2.1) 50-423/99-02-07 URl Fire Safe Shutdown Analysis Design Bases Control Room Habitability (U3 02.1) ' 50-423/99-02-08_ NCV Control Room Habitability (U3 O2.1) Closed 50-336/99-02-fM NCV Inadvertent Reactor Coolant System Water Level Increase (U2 O1.2) 50-336/99-02-02 NCV - Inadvertent Transfer of Water from the Unit 2 Spent Fuel Pool (U2 03.1) ' 50-33f/99-02-03 NCV inadvertent Charging Pump injection (U2 M1.2) 50-3?a/99-02-04 NCV Failure to Maintain Design Configuration (U2 E8.6) 50-423/99-02-06 NCV.TS 3.0.3, Control Room Filtration System (U3 O2.1)
50-423/99-02-08 NCV Control Room Habitability (U3 O2.1) ' 50-336/96-207-03 VIO Failure to Establish Procedures for Draining Safety-Related System (U2 08.2) _ j 01142 & 03072 VIO Ice Blockage of Service Water Backwash Line (U2 E8.1) i (eel 50-336/95-44-05) j i_
50-336/96-06-08 URI Resolution of Water Hammer Issues (U2 E8.2) 01162 VIO Failure to Meet Single Failure Criteria for Hydrogen Monitors (U2 E8.3) (eel 50-336/96-201-03 01052 VIO Failure to Adequately Evaluate the Installation of Electrical Jumpers (U2 E8.3) (eel 50-336/96-201-41) 04053 VIO Failure to implement Adequate Design Controls for MEPL - (U2 E8.4) (eel 50-336/96-201-42) 04043 VIO Failure to Establish Adequate Measures to Control Nonconforming Materials (U2 E8.4) (eel 50-336/96-201-43) 50-336/97-203-05 URI implementation of IE Bulletins 79-02 and 79-14 (U2 E8.6) 50-423/97-201-01 IFl items not available for review during NRC lCAVP implementation inspection (U2 E8.1) 50-423/97-202-10 IFl Engineering support of fire protection program (U3 E8.1) Discussed 245,336,423/97-01-03 URI Operator Licensing and Training (U2 08.1) 50-423/97-83-08 URI RHR Heat Exchanger Leak Rate (U3 08.1) 50-423/98-01-01 VIO Failure to Maintain PASS Operational (P8.1) LERs Closed 50-336/97-23-00&O1 LER Minimum High Pressure SI Flow Used in Accident Analysis May j be Non-Conservative (U2 E8.5) ' 50-336/98-09-00 LER Large Break LOCA Analysis Indicates Peak Clad Temperature Could Exceed 2200 Degrees Fahrenheit 50-423/96-09-01 LER Inoperable Shutdown Margin Monitors from Low Count Rate Due to Inadequate Design Control (U3 E8.1) 50-423/96-34-02 LER Residual Heat Removal Pump Suction Relief Valve Setpoint Not in Accordance with TS (U3 E8.1)
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_ - - , a I I i Northeast Utilities Briefing for the NRC Opening Remarks Restart Assessment Panel Lee Olivier Senior Vice President & Millstone Station
Chiet Nuclear OtRcer y,, gg gyyy -- 's _ u,&.n s z.,
i l l Northeast Utilities Agenda Northeast Utilities Agenda (continued)
- Unit 2 Recovery e Unit 3 Performance-Overview Mike Brothers-Overview Mike Brothers
- Operational Readiness Alan Price-Operational Performance Chris Schwarr
-Regulatory Readiness Marty Bowling Assessment ress on Key Technical Mike Ahern nhan m nt trategy f -
- ""
- "
-Oversight Assessment Ray Nocci-Backlog Management Mike Brothers i-Milestone Schedule Mike Brothers Performance-Oversight Assessment RayNecci
- Closing Remarks Lee Olivier
Natunn suk-tum l
naru nsauasarur l - i s Unit 2 Recovery: Unit 2 Recovery: Overview OperationalReadiness Mike Brothers Alan Price Vice President, Nuclear Operations Unit Director l e.-- . c.
_ _ _ _ - b l Page 1
l
I l l . Milestones for Mode 6 Met Mode 5 Readiness ! Assessment Scheduled Actual
- System Readiness l
Activltv Dat8 Daft , Operating Experience i Z5 Window Closure 11/6/98 10/29/98 Facility 2 phys. work 12/22/98 12/22/98
- AWOs and Modifications Loss of Normal Power 12/28/98 12/28/98
- Programs Core On-load Start 12/30/98 12/31/98
- Cornmitments and AITTS Open items Core On-load Finish 1/6/98 1/6/98
, Training '
l Anra,-, Aui,, r.,rr l-j an,a,., aus,., r.,,rr l - l l Mode 5 Readiness Mode 4 / OSTI Readiness
- Activities remaining
- Procedure revisions
- AITTS ossignments
- Corrective actior assignments
- Facility 1 work
- Modifications
- Facility 1 surveillances and testing
- Maintenance activities
- Organizational Readiness
' - a,,,- am+, t.,rr l - A,,*, , A-1,, r,,rr l Millstone 2 Performance Human Performance ! Annunciator Panel Millstone 2 3rd 1998 Quarter Results
,,,,,,,,,,,,,,,,,, % :- :; - ~ ~ e.. mr ec l ' - 6.- 8 _ -. B,,,,,,,,,, g,=j-l m. _, e. - e -. . l e- - m-m- - + g ; _ _, j _+ _,, __ ?: ~ TK'~TT21.~L 7.g;, ~ 'u H X,.,CRi6r [ ,, l Page 2
i l
. Procedure Compliance Operator Workarounds Millstone 2 Millstone 2 Progress: Satisfactory Progress: Tracking to satisfactory y M --* ^ ^ *, ;< lllllll l' - - . g } l., _ - i t imm e '
..,,,,,,,,.,,.,,.. g.- -- ._-----i r-..----.-.-.--> " " H harrhemerNwhar,acrr, l-j AarrAnmerhusesrinarrv l Temporary Modifications Unit 2 Milestone Schedule Millstone 2 Progress Tracking to satisfactory e Mode 6 1/22/99
- Mode 4 2/18/99
" g~ , , j
- Mode 3 2/26/99
= - ., , g
- Mode 2 3/24/99 L..
~ ' -... ~ _, .. l .-... .
r- - ---. - - - - -a "a d 'a - x., u.a,,.,,,, l A.r,.,,A.,,,,,,,, l Tasks Remaining for Restart Restart Modifications Millstone 2 Millstone 2 Progress: Tracking to satisfactory Progress: Tracking to satisfactory . . . ! l \\ ,, ens J !
., L ..! l j , y . , . s \\ e w a ,_;$;.._ _ N.
\\ = ' ............ <- -+ +-. -- rA . p ed es sese . ~~ ~- ~ ~ ~ ~ ~ - ~ ~ e-.---____ . e.
.
% Aartheast Nadeur emergy l-H Aarthreat Asd,ar Larrgy l ! Page 3 j >
l
f ] - l Procedure Revisions Startup Work Order Status l Millstone 2 Millstone 2 ' Progress: Tracking to saUsfactory Progress: Unsatisfactory f . -s ~ FW1 rs~} V i s - ,_ ]:::: 'N l i (-
, ";. - - - -... 'u . . -. lillillillii
- TT:.-
. ' 77: : : ::: t-- .. g F.-.-~ . % M,,u, u.s,.,1,,,y,
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We Have Completed Several Major Modifications Completed Significant Activities for MP2 for MP2 Operational Readiness Operational Readiness (as discussed during last RAP) (as discussed duringlast RAP)
- Boric acid / primary water makeup
- MSSv talfpipe modifications i
- EDG slow start
- Auxiliary steam support modifications
' Fire water crosstie to EDG cooling
- Facility 1 & 2 SW coating upgrades
- AFW cavitating venturis
- Installation of safety relate. :oolers to l
'RCP seal package change out to support MCC B51 & B61 HWCD
- Replacement of turbine building batteries
- 100% Rx head penetration inspection and charger
' A & B SW header inspection & tupair ' 'n " - s.a,., u.a, 1,,,,,
, s.,u.,, s,u, a,, : Testing linspections Completed We Have Completed Several for MP2 Operational Readiness Slgnificant Activities for MP2 (as discussed duringlast RAP) Since the Last RAP
- RBCCW flow balance testing
- Enclosure building blowout panels
- ECCS flow tesFng
'RBCCW relief valve replacement l
- Aux. feedwater head curve testing
- Reg Guide 1.97 upgrades
- A & B EDG 18 month inspections
- Additional Appx. R emergency lights
'
- 89-10 MoV program c'ose-out inspections
- Repair of 16 containment isolation valves
' Rerouted charging pump cables 'H2 monitors replaced r__._ _ _.. . c_ _ _ _ _ _ _ _ _ _ _ _ _ b M b88dM NfPI, hW,M, bM8,M 1MP Page 4
. . MP2 Corrective Actions are Tracking to Satisfactory - . - - - - - "~ """~ Unit 2 Recovery: a ~ """ 7 EL B = D "" B ~ ~. ;=~' Regulatory Readiness
w-- m u s.- w ::. m :,_ ~ Marty Bowling s'.*" 8':ll'**"" 8-:::'" w.i Recovery Officer
g- - g.~ . 7,. . s. c=c ... 7,-- " ~ Nm8 hem, N. dew Energr l n MP2 Key issues are Tracking to 40500 Readiness Satisfactory for Restart Millstone 2
- Self Assessment sewactory
- Assessments Completed
- Corrective Action Tracung to satisthero,y
- Management review
- Operational Readiness
- Oversight review
- Work Control and
~'"*E***'"
- P "
- * ' " " ' *
, Planning - Readiness letter sent January 4,1999
- Procedure Quality and Adherence o
- Engineering Quality
H 3,.n , u.a., r.,rr l " - N. *<== ^='en E=rr l License Amendment Status: Significant item List Status: Progress is on schedule Progress is on schedule
- 26/28 changes submitted
- 54 of 77 completed
+ 14 have been approved and 12 implemented
- 14 of 23 remaining are tied to
- Remaining to Submit:
physical modifications-Hydrogen Purge. Deletion from T.S.
- Projected schedule completion (1115/99)
date is February 16,1999-Enclosure Building Filtration System Bypass leakage (1/24/99) - u,e,., A s., raarr l -
" " A-3 ~ E=rr l Page 5
.. .
- NRC Open items for Restart: Progress is on Schedule MP2 ICAVP is Nearing Completion 'ICAVP reviews are confirming
- 105 items remain open eNectiveness of MP2 effort to restore DB /
-49 LER assignments LB compliance-56 other assignments
- No confirmed Level 1 or 2 DRs (e.g., Violations, IFis, URis)
'ICAVP results used by MP2 to expand scope of DBiLB reviews and to make program enhancements l '78% of the 75 Level 3 DR corrective j action assignments are complete " y umw.,unsws, l - A.rew., unear s-, l , MP2 DB/LB Review Scope MP2 identified the Safety Expansions Provide Additional Significant items (f/96-12/98) Assurance of Effectiveness m m.
um -
- Lessons learned from Unit 3 CMP
- Self identified 105-integrated system reviews-low gy-operational experience-modwese s-dose analysis review-high
-Tech Spec. Section 6 and NUREG 0737
- lCAVP-Identified
- Technical Requirements Manual-resulWng flrom NRC f
- Single-failure review-from ons
- Plant interface with safety analysis-high safetysignincance 0
~
- smu-o n-ra, zu, l - nmuna n-o,- sa, l Organization and Process in Place ICAVP Corrective Actions to Maintain Compliance With DBlLB
- Progress is on schedule
- Configuration Control Programs are in-as of 443 restart assignments from NRC place inspection Report remain open (85% complete)
- Permanent Configuration Management-163 of 687 restart assignments from DRs organization has been formed remain open (1s% complete)
e " Owners" established for each
- Completed 43% of non-restart ICAVP Configuration Management process and assignments and 76% of non-restart NRC inspection Report items program
- CM and 50.59 training provided
' Ready to support Pansons visits
- Performance is being monitored
- Ready for follow-up NRC inspection 2/22/99
[AAAs. sd ; ' AAA-s.- s-, j ' " - " _ Page 6
' . . , J NRC Submittals NRC Submittals (continued)
- Completed since last RAP meeting:
- To Be Submitted in January 1999:
- 50,54(f) Q 1&2 update-ICAVP Closure (1124/99) - 50.54(f) Q3 update < - 50.54(f) Q 4 (1/24199) j - Operational Readiness Plan - Remaining LARs (1115199 and ' - Power Ascension Plan 1/24/99) - BackloO Management Plan - Ready for 40500 Inspection + s u n.m.s.,,
-l%u., s.+. in.,,
' ' " = l - __ l Key Technical issues Unit 2 Recovery: ' Pmgress supports restart schedule ' Progress on-pr gramissues n schedule i ~ * ' " * ' ' ' * " " ' * * ' " * ' * * * " * ' * ' * * Kev TechnicalIssues
s - key modifications on schedule
i Mike Ahern Manager, Unit 2 Design Engineering l "
- naruarsar zaagr l naru.r nase-sa nr l ~ ! Engineering Quality issues Continue to Key Modifications Receive Management Attention
- On Schedule for Restart
- Enginedng Quauy Revkw Board continues to guide overall improvement strategy-Cable separation resolutions
- Unit 2/3 Quality Review Boards continue to
- AFW pump single failure elimination assure outgoing quauty i - Containment spray pump runout
- Continuing training was held in December to j
prevention addrus mwork causes {
- Curmnt focus amas:
! - SIT single failure elimination ~'*d"C*'***'" - Enclosure Building single failure mitigation-reinforce independent reviewer role-strengthen safety analysis interface - . - e....-- ~ ~ ~E hm1Fwast NNelde EnegF j f Notk.t NMlem EneTgv l
l Page 7
' , I Nuclear Oversight NOVP - MP2 Unit 2 Recovery: ) Oversight Assessment Ray Necci Vice President, Nuclear Oversight and RegulatoryAWales _ 'a q 3 , u.a-,,, l m-- -- Unit 2 Milestone Schedule .
- Mode 5 1122/99 l
Unit 2 Recovery: + Mode 4 2itales l Milestone Schedule
- Mode 3 212sies
- Mode 2 3/24199 Mike Brothers Vice President, Nuclear Operations
' ' = ~ - s , u.a.a,, : - n.~ > - s-,,
Unit 3 Performance: Unit 3 Performance: OperationalPerformance Overview Assessment Mike Brothers Chris Schwarz Vice President, Nuclear Operations MIIIstone Station Director NTAa n.a-s.ax, l + xawa,s 5 t.ex, l
Page 8
. Operational Performance Assessment
- Operational expectations not met
- 3.0.3 common cause showed no Unit 3 Performance:
- * * * * " * ' *
OperationalFocus
- 3.0.3 / reactor trip common cause inadequate scope of control, inadequate Enhancement Strategy risk management
- Focus and prioritization by management not consistent with continued, event-free operation
% saaearsusarz erv l + smaa sauw zm, l j l i Short Term Strategy Short Term Strategy
- Reduce operator challenges and
- Communications for Enhanced improve operational focus Focus
- 0800 Operational Focus Leadership
- Shift Manager's Retreat Meedng
,12 Week Schedule Review - Aggregato impact on Plant Operat.*ns Indicator i " - Netheet haclear Enery l - Nedenst Nulew Enery l l , Long Term Strategy Long Term Strategy + Operations Leadership
- Unit Leadership-Operations AlignmentTeam
- Increased communications - New Manager team benchmarking - Leaders meetings - On-line schedule ownership - Improve leadership I coaching-Industry participation
- 1mprove station culture continuously
- Operations Rescurces
- Human Performance Focus
- Operatier.a Human Performance YAA~.,*-u.a.$ ;
' k a s, C L t ,y l " 'a Page 9
. i i l I l Outage Readiness l
Um.t 3 Performance:
- Milestone dates impacted by reactoridp, l
Outage Readiness + engineering resource.ioaded i schedule developed i
- SG inspection and refueling services contracts being awarded
! - , . i - - 8 -.-- - : + x- --, : . - ! Post Restart Backlog Status na ma ma
- Corrective Action Assignmente 3915 2626 2114
, Um.t 3 Performance: ) .c,,ecove.eintenence Awoe 3 m 31.
Backlog Management ""pa=v "ad"'ca"a"* '2 '2 '
- Operstor Work Arounds it
14 Performance . cont, Room oonci.new . i o
- Non Conformance Reports
35
Mike Brothers + connguration u mnt Discovery as4 sos 4e2 o Vice President, Nuclear Operations
- Engineering Backlog ss7 sos s1s
'ICAVP DR Corrective Actions 838 676 4 53
- Operability Determinations
24
" Narrhe. N.de E rtr l - es i , Nuclear OversightVerification Plan Results Millstone 3 i.ca s rauana.:.a;ar:;.n ,- c.u.i.a==u=- . . ..... . . . . Unit 3 Performance: ..E;.w..: : h.im. x
. . . . . Oversight Assessment .3.r.i.mt.......... L... . - - __ i.
i i .: . . Y..O.,,irn O1 0. ~ ~~'. ' . . . . . Ray Necci 7.p*
- &
"
" ' Vice President, Nuclear Oversight and "gjjj=^ . -y-. j Regulatory A(Talts w gmw m gwm-. j , -.. m gy -, -, - - -. myw , . - - - - < - --.---.-.-- -
n u u.s-un : a un.,no e.,,,,,
- Page 10
}
) , .: , ) Closing Remarks Lee Olivier ) \\ '., A s ~ s.s s n ; i t i , -, t I
4 l ! ii Page 11
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